National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, 9304-9513 [2012-806]
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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 60 and 63
[EPA–HQ–OAR–2009–0234; EPA–HQ–OAR–
2011–0044, FRL–9611–4]
RIN 2060–AP52; RIN 2060–AR31
National Emission Standards for
Hazardous Air Pollutants From Coaland Oil-Fired Electric Utility Steam
Generating Units and Standards of
Performance for Fossil-Fuel-Fired
Electric Utility, Industrial-CommercialInstitutional, and Small IndustrialCommercial-Institutional Steam
Generating Units
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
On May 3, 2011, under
authority of Clean Air Act (CAA)
sections 111 and 112, the EPA proposed
both national emission standards for
hazardous air pollutants (NESHAP)
from coal- and oil-fired electric utility
steam generating units (EGUs) and
standards of performance for fossil-fuelfired electric utility, industrialcommercial-institutional, and small
industrial-commercial-institutional
steam generating units (76 FR 24976).
After consideration of public comments,
the EPA is finalizing these rules in this
action.
Pursuant to CAA section 111, the EPA
is revising standards of performance in
response to a voluntary remand of a
final rule. Specifically, we are amending
new source performance standards
(NSPS) after analysis of the public
comments we received. We are also
finalizing several minor amendments,
technical clarifications, and corrections
to existing NSPS provisions for fossil
fuel-fired EGUs and large and small
industrial-commercial-institutional
steam generating units.
Pursuant to CAA section 112, the EPA
is establishing NESHAP that will
require coal- and oil-fired EGUs to meet
hazardous air pollutant (HAP) standards
reflecting the application of the
maximum achievable control
technology. This rule protects air
quality and promotes public health by
reducing emissions of the HAP listed in
CAA section 112(b)(1).
DATES: This final rule is effective on
April 16, 2012. The incorporation by
reference of certain publications listed
in this rule is approved by the Director
of the Federal Register as of April 16,
2012.
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SUMMARY:
The EPA established two
dockets for this action: Docket ID. No.
ADDRESSES:
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EPA–HQ–OAR–2011–0044 (NSPS
action) or Docket ID No. EPA–HQ–
OAR–2009–0234 (NESHAP action). All
documents in the dockets are listed on
the https://www.regulations.gov Web
site. Although listed in the index, some
information is not publicly available,
e.g., confidential business information
or other information whose disclosure is
restricted by statute. Certain other
material, such as copyrighted material,
is not placed on the Internet and will be
publicly available only in hard copy
form. Publicly available docket
materials are available either
electronically through https://
www.regulations.gov or in hard copy at
EPA’s Docket Center, Public Reading
Room, EPA West Building, Room 3334,
1301 Constitution Avenue NW.,
Washington, DC 20004. This Docket
Facility is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding
legal holidays. The telephone number
for the Public Reading Room is (202)
566–1744, and the telephone number for
the Air Docket is (202) 566–1741.
FOR FURTHER INFORMATION CONTACT: For
the NESHAP action: Mr. William
Maxwell, Energy Strategies Group,
Sector Policies and Programs Division,
(D243–01), Office of Air Quality
Planning and Standards, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711; Telephone number: (919) 541–
5430; Fax number (919) 541–5450;
Email address: maxwell.bill@epa.gov.
For the NSPS action: Mr. Christian
Fellner, Energy Strategies Group, Sector
Policies and Programs Division, (D243–
01), Office of Air Quality Planning and
Standards, U.S. Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711; Telephone
number: (919) 541–4003; Fax number
(919) 541–5450; Email address:
fellner.christian@epa.gov.
SUPPLEMENTARY INFORMATION:
The information presented in this
preamble is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this
document?
C. Judicial Review
D. What are the costs and benefits of these
final rules?
II. Background Information on the NESHAP
A. What is the statutory authority for this
final NESHAP?
B. What is the litigation history of this final
rule?
C. What is the relationship between this
final rule and other combustion rules?
D. What are the health effects of pollutants
emitted from coal- and oil-fired EGUs?
III. Appropriate and Necessary Finding
A. Overview
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B. Peer Review of the Hg Risk TSD
Supporting the Appropriate and
Necessary Finding for Coal and Oil-Fired
EGUs and EPA Response
C. Summary of Results of Revised Hg Risk
TSD of Risks to Populations With High
Levels of Self-Caught Fish Consumption
D. Peer Review of the Approach for
Estimating Cancer Risks Associated With
Cr and Ni Emissions in the U.S. EGU
Case Studies of Cancer and Non-Cancer
Inhalation Risks for Non-Mercury Hg
HAP and EPA Response
E. Summary of Results of Revised U.S.
EGU Case Studies of Cancer and NonCancer Inhalation Risks for Non-Mercury
Hg HAP
F. Public Comments and Responses to the
Appropriate and Necessary Finding
G. EPA Affirms the Finding That It Is
Appropriate and Necessary To Regulate
EGUs To Address Public Health and
Environmental Hazards Associated With
Emissions of Hg and Non-Mercury Hg
HAP From EGUs
IV. Denial of Delisting Petition
A. Requirements of Section 112(c)(9)
B. Rationale for Denying UARG’s Delisting
Petition
C. EPA’s Technical Analyses for the
Appropriate and Necessary Finding
Provide Further Support for the
Conclusion That Coal-Fired EGUs
Should Remain a Listed Source Category
V. Summary of the Final NESHAP
A. What is the source category regulated by
this final rule?
B. What is the affected source?
C. What are the pollutants regulated by this
final rule?
D. What emission limits and work practice
standards must I meet?
E. What are the requirements during
periods of startup, shutdown, and
malfunction?
F. What are the testing and initial
compliance requirements?
G. What are the continuous compliance
requirements?
H. What are the notification, recordkeeping
and reporting requirements?
I. Submission of Emissions Test Results to
the EPA
VI. Summary of Significant Changes Since
Proposal
A. Applicability
B. Subcategories
C. Emission Limits
D. Work Practice Standards for Organic
HAP Emissions
E. Requirements During Startup,
Shutdown, and Malfunction
F. Testing and Initial Compliance
G. Continuous Compliance
H. Emissions Averaging
I. Notification, Recordkeeping and
Reporting
J. Technical/Editorial Corrections
VII. Public Comments and Responses to the
Proposed NESHAP
A. MACT Floor Analysis
B. Rationale for Subcategories
C. Surrogacy
D. Area Sources
E. Health-Based Emission Limits
F. Compliance Date and Reliability Issues
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A. Executive Order 12866, Regulatory
Planning and Review and Executive
Order 13563, Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act as Amended
by the Small Business Regulatory
Enforcement Fairness Act (RFA) of 1996
SBREFA), 5 U.S.C. 601 et seq.
D. Unfunded Mandates Reform Act of 1995
E. Executive Order 13132, Federalism
F. Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045, Protection of
Children From Environmental Health
Risks and Safety Risks
H. Executive Order 13211, Actions
Concerning Regulations That
G. Cost and Technology Basis Issues
H. Testing and Monitoring
VIII. Background Information on the NSPS
A. What is the statutory authority for this
final NSPS?
B. What is the regulatory authority for the
final rule?
IX. Summary of the Final NSPS
X. Summary of Significant Changes Since
Proposal
XI. Public Comments and Responses to the
Proposed NSPS
XII. Impacts of the Final Rule
A. What are the air impacts?
B. What are the energy impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits of this final rule?
XIII. Statutory and Executive Order Reviews
9305
Significantly Affect Energy Supply,
Distribution, or Use
I. National Technology Transfer and
Advancement Act
J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
K. Congressional Review Act
I. General Information
A. Does this action apply to me?
The regulated categories and entities
potentially affected by the final
standards are shown in Table 1 of this
preamble.
TABLE 1—POTENTIALLY AFFECTED REGULATED CATEGORIES AND ENTITIES
Category
Industry .................................................................
Federal government ..............................................
2 221122
State/local/tribal government ................................
2 221122
221112
921150
1 North
Examples of potentially
regulated entities
NAICS code 1
Fossil fuel-fired electric utility steam generating units.
Fossil fuel-fired electric utility steam generating units owned by the federal government.
Fossil fuel-fired electric utility steam generating units owned by states,
tribes, or municipalities.
Fossil fuel-fired electric utility steam generating units in Indian country.
American Industry Classification System.
state, or local government-owned and operated establishments are classified according to the activity in which they are engaged.
2 Federal,
This table is not intended to be
exhaustive, but rather is meant to
provide a guide for readers regarding
entities likely to be affected by this
action. To determine whether you, as
owner or operator of a facility,
company, business, organization, etc.,
will be regulated by this action, you
should examine the applicability
criteria in 40 CFR 60.40, 60.40Da, or
60.40c or in 40 CFR 63.9981. If you have
any questions regarding the
applicability of this action to a
particular entity, consult either the air
permitting authority for the entity or
your EPA regional representative as
listed in 40 CFR 60.4 or 40 CFR 63.13
(General Provisions).
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B. Where can I get a copy of this
document?
In addition to being available in the
dockets, an electronic copy of this
action will also be available on the
Worldwide Web (WWW) through the
Technology Transfer Network (TTN).
Following signature by the
Administrator, a copy of the action will
be posted on the TTN’s policy and
guidance page for newly proposed or
promulgated rules at the following
address: https://www.epa.gov/ttn/oarpg/.
The TTN provides information and
technology exchange in various areas of
air pollution control.
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C. Judicial Review
Under CAA section 307(b)(1), judicial
review of this final rule is available only
by filing a petition for review in the U.S.
Court of Appeals for the District of
Columbia Circuit by April 16, 2012.
Under CAA section 307(d)(7)(B), only
an objection to this final rule that was
raised with reasonable specificity
during the period for public comment
(including any public hearing) can be
raised during judicial review. This
section also provides a mechanism for
the EPA to convene a proceeding for
reconsideration, ‘‘[i]f the person raising
an objection can demonstrate to the
Administrator that it was impracticable
to raise such objection within [the
period for public comment] or if the
grounds for such objection arose after
the period for public comment (but
within the time specified for judicial
review) and if such objection is of
central relevance to the outcome of the
rule[.]’’ Any person seeking to make
such a demonstration to us should
submit a Petition for Reconsideration to
the Office of the Administrator,
Environmental Protection Agency,
Room 3000, Ariel Rios Building, 1200
Pennsylvania Ave. NW., Washington,
DC 20004, with a copy to the person
listed in the preceding FOR FURTHER
INFORMATION CONTACT section, and the
Associate General Counsel for the Air
and Radiation Law Office, Office of
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General Counsel (Mail Code 2344A),
Environmental Protection Agency, 1200
Pennsylvania Ave. NW., Washington,
DC 20004. Note, under CAA section
307(b)(2), the requirements established
by this final rule may not be challenged
separately in any civil or criminal
proceedings brought by EPA to enforce
these requirements.
D. What are the costs and benefits of
this final rule?
Consistent with Executive Order (EO)
13563, ‘‘Improving Regulation and
Regulatory Review,’’ we have estimated
the costs and benefits of the final rule.
This rule will reduce emissions of HAP,
including mercury (Hg), from the
electric power industry. Installing the
technology necessary to reduce
emissions directly regulated by this rule
will also reduce the emissions of
directly emitted PM2.5 and sulfur
dioxide (SO2), a PM2.5 precursor. The
benefits associated with these PM and
SO2 reductions are referred to as cobenefits, as these reductions are not the
primary objective of this rule.
The EPA estimates that this final rule
will yield annual monetized benefits (in
2007$) of between $37 to $90 billion
using a 3 percent discount rate and $33
to $81 billion using a 7 percent discount
rate. The great majority of the estimates
are attributable to co-benefits from
reductions in PM2.5-related mortality.
The annual social costs, approximated
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by the sum of the compliance costs and
monitoring and reporting costs, are $9.6
billion (2007$) and the annual
quantified net benefits (the difference
between benefits and costs) are $27 to
$80 billion using a 3 percent discount
rate or $24 to $71 billion using a 7
percent discount rate. It is important to
note that the PM2.5 co-benefits reported
here contain uncertainty, due in part to
the important assumption that all fine
particles are equally potent in causing
premature mortality and because many
of the benefits are associated with
reducing PM2.5 levels at the low end of
the concentration distributions
examined in the epidemiology studies
from which the PM2.5-mortality
relationships used in this analysis are
derived.
The benefits of this rule outweigh
costs by between 3 to 1 or 9 to 1
depending on the benefit estimate and
discount rate used. The co-benefits are
substantially attributable to the 4,200 to
11,000 fewer PM2.5-related premature
mortalities estimated to occur as a result
of this rule. The EPA could not
monetize some costs and important
benefits, such as some Hg benefits and
those for the HAP reduced by this final
rule other than Hg. Upon considering
these limitations and uncertainties, it
remains clear that the benefits of this
rule, referred to in short as the Mercury
and Air Toxics Standards (MATS), are
substantial and far outweigh the costs.
TABLE 2—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE FINAL RULE IN 2016
[Billions of 2007$] a
3% Discount rate
Total Monetized Benefits b .............................................................................................
Partial Hg-related Benefits c ...........................................................................................
PM2.5-related Co-benefits b ............................................................................................
Climate-related Co-Benefits d ........................................................................................
Total Social Costs e .......................................................................................................
Net Benefits ...................................................................................................................
Non-monetized Benefits ................................................................................................
7% Discount rate
$37 to $90 .......................... $33 to $81.
$0.004 to $0.006 ................ $0.0005 to $0.001.
$36 to $89 .......................... $33 to $80.
$0.36 .................................. $0.36.
$9.6 .................................... $9.6.
$27 to $80 .......................... $24 to $71.
Visibility in Class I areas.
Other neurological effects of Hg exposure.
Other health effects of Hg exposure.
Health effects of ozone and direct exposure to SO2 and
NO2.
Ecosystem effects.
Health effects from commercial and non-freshwater fish
consumption.
Health risks from exposure to non-mercury HAP.
a All
estimates are for 2016, and are rounded to two significant figures.
total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5. The reduction in premature fatalities each year accounts for over 90 percent of total monetized benefits. Benefits in this table are nationwide and are associated with directly
emitted PM2.5 and SO2 reductions. The estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon,
discussed further in chapter 5 of the RIA. Mercury benefits were calculated using the baseline from proposal. The difference in emissions reductions between proposal and final does not substantially affect the Hg benefits.
c Based on an analysis of health effects due to recreational freshwater fish consumption.
d This table shows monetized CO co-benefits that were calculated using the global average social cost of carbon estimate at a 3 percent dis2
count rate. In section 5.6 of the Regulatory Impact Analysis (RIA) we also report the monetized CO2 co-benefits using discount rates of 5 percent, 2.5 percent, and 3 percent (95th percentile).
e Total social costs are approximated by the compliance costs for both coal- and oil-fired units. This includes monitoring, recordkeeping, and
reporting costs.
b The
For more information on how EPA is
addressing EO 13563, see the EO
discussion in the Statutory and
Executive Order Reviews section of this
preamble.
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II. Background Information on the
NESHAP
On May 3, 2011, the EPA proposed
this rule to address emissions of toxic
air pollutants from coal and oil-fired
electric generating units as required by
the CAA. The proposal explained at
length the statutory history and
requirements leading to this rule, the
factual and legal basis for the rule and
its specific provisions, and the costs and
benefits to the public health and
environment from the proposed
requirements.
The EPA received over 900,000
comments from members of the public
on the proposed rule, substantially more
than for any other prior regulatory
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proposal. The comments express
concerns about the presence of Hg in the
environment and the effect it has on
human health, concerns about the costs
of the rule, how challenging it may be
for some sources to comply and
questions about the impact it may have
on this country’s electricity supply and
economy. Many comments provided
additional information and data that
have enriched the factual record and
enabled EPA to finalize a rule that
fulfills the mandate of the CAA while
providing flexibility and compliance
options to affected sources—options
that make the rule less costly and
compliance more readily manageable.
This rule establishes uniform
emissions-control standards that sources
can meet with proven and available
technologies and operational processes
in a timeframe that is achievable. They
will put this industry, now the single
largest source of Hg emissions in the
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United States (U.S.) with emissions of
29 tons per year, on a path to reducing
those emissions by approximately 90
percent. Emissions of other toxic metals,
such as arsenic (As) and nickel (Ni),
dioxins and furans, acid gases
(including hydrochloric acid (HCl) and
SO2) will also decrease dramatically
with the installation of pollution
controls. And the flexibilities
established in this rule along with other
available tools provide a clear pathway
to compliance without jeopardizing the
country’s energy supply.
This preamble explains EPA’s
appropriate and necessary finding, the
elements of the final rule, key changes
the EPA is making in response to
comments submitted on the proposed
rule, and our responses to many of the
comments we received. A full response
to comments is provided in the response
to comments document available in the
docket for this rulemaking.
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A. What is the statutory authority for
this final rule?
Congress established a specific
structure for determining whether to
regulate EGUs under CAA section 112.1
Specifically, Congress enacted CAA
section 112(n)(1).
Section 112(n)(1)(A) of the CAA
requires the EPA to conduct a study to
evaluate the remaining public health
hazards that are reasonably anticipated
to occur as a result of EGUs’ HAP
emissions after imposition of CAA
requirements. The EPA must report the
results of that study to Congress, and
regulate EGUs ‘‘if the Administrator
finds such regulation is appropriate and
necessary,’’ after considering the results
of that study. Thus, CAA section
112(n)(1)(A) governs how the
Administrator decides whether to list
EGUs for regulation under CAA section
112. See New Jersey v. EPA, 517 F.3d
574 at 582 (D.C. Cir. 2008) (‘‘Section
112(n)(1) governs how the
Administrator decides whether to list
EGUs; it says nothing about delisting
EGUs.’’).
As directed, the EPA conducted the
study to evaluate the remaining public
health hazards and reported the results
to Congress (Utility Study Report to
Congress (Utility Study)).2 We discuss
this study below in conjunction with
other studies that CAA section 112(n)(1)
requires concerning EGUs. See also 76
FR 24982–24984 (summarizing studies).
Once the EPA lists a source category
pursuant to CAA section 112(c), the
EPA must then establish technologybased emission standards under CAA
section 112(d). For major sources, the
EPA must establish emission standards
that ‘‘require the maximum degree of
reduction in emissions of the hazardous
air pollutants subject to this section’’
that the EPA determines are achievable
taking into account certain statutory
factors. See CAA section 112(d)(2).
These standards are referred to as
‘‘maximum achievable control
technology’’ or ‘‘MACT’’ standards. The
MACT standards for existing sources
must be at least as stringent as the
average emission limitation achieved by
the best performing 12 percent of
existing sources in the category (for
which the Administrator has emissions
information) or the best performing 5
sources for source categories with less
1 ‘‘Electric utility steam generating unit’’ is
defined, in part, as any ‘‘fossil fuel fired combustion
unit of more than 25 megawatts that serves a
generator that produces electricity for sale.’’ See
CAA section 112(a)(8).
2 U.S. EPA. Study of Hazardous Air Pollutant
Emissions from Electric Utility Steam Generating
Units—Final Report to Congress. EPA–453/R–98–
004a. February 1998.
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than 30 sources. See CAA section
112(d)(3)(A) and (B), respectively. This
level of minimum stringency is referred
to as the ‘‘MACT floor,’’ and the EPA
cannot consider cost in setting the floor.
For new sources, MACT standards must
be at least as stringent as the control
level achieved in practice by the best
controlled similar source. See CAA
section 112(d)(3).
The EPA also must consider more
stringent ‘‘beyond-the-floor’’ control
options. When considering beyond-thefloor options, the EPA must consider the
maximum degree of reduction in HAP
emissions and take into account costs,
energy, and non-air quality health and
environmental impacts when doing so.
See Cement Kiln Recycling Coal. v. EPA,
255 F.3d 855, 857–58 (D.C. Cir. 2001).
Alternatively, the EPA may set a
health-based standard for HAP that have
an established health threshold, and the
standard must provide ‘‘an ample
margin of safety.’’ See CAA section
112(d)(4). As these standards could be
less stringent than MACT standards, the
Agency must have detailed information
on HAP emissions from the subject
sources and sources located near the
subject sources before exercising its
discretion to set such standards.
For area sources, the EPA may issue
standards or requirements that provide
for the use of generally available control
technologies or management practices
(GACT standards) in lieu of
promulgating MACT or health-based
standards. See CAA section 112(d)(5).
As noted above, CAA section 112(n)
requires completion of various reports
concerning EGUs. For the first report,
the Utility Study, Congress required the
EPA to evaluate the hazards to public
health reasonably anticipated to occur
as the result of HAP emissions from
EGUs after imposition of the
requirements of the CAA. See CAA
section 112(n)(1)(A). The EPA was
required to report results from this
study to Congress by November 15,
1993. Id. Congress also directed the EPA
to conduct ‘‘a study of mercury
emissions from [EGUs], municipal waste
combustion units, and other sources,
including area sources’’ (Mercury
Study). See CAA section 112(n)(1)(B).
The EPA was required to report the
results from this study to Congress by
November 15, 1994. Id. In conducting
this Mercury Study, Congress directed
the EPA to ‘‘consider the rate and mass
of such emissions, the health and
environmental effects of such emissions,
technologies which are available to
control such emissions, and the costs of
such technologies.’’ Id. Congress
directed the National Institute of
Environmental Health Sciences (NIEHS)
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to conduct the last required evaluation,
‘‘a study to determine the threshold
level of mercury exposure below which
adverse human health effects are not
expected to occur’’ (NIEHS Study). See
CAA section 112(n)(1)(C). The NIEHS
was required to submit the results to
Congress by November 15, 1993. Id. In
conducting this study, NIEHS was to
determine ‘‘a threshold for mercury
concentrations in the tissue of fish
which may be consumed (including
consumption by sensitive populations)
without adverse effects to public
health.’’ Id.
In addition, Congress, in conference
report language associated with the
EPA’s fiscal year 1999 appropriations,
directed the EPA to fund the National
Academy of Sciences (NAS) to perform
an independent evaluation of the
available data related to the health
impacts of methylmercury (MeHg) (NAS
Study or MeHg Study). H.R. Conf. Rep.
No 105–769, at 281–282 (1998).
Specifically, Congress required NAS to
advise the EPA as to the appropriate
reference dose (RfD) for MeHg. 65 FR
79826. The RfD is the amount of a
chemical which, when ingested daily
over a lifetime, is anticipated to be
without adverse health effects to
humans, including sensitive
subpopulations. In the same conference
report, Congress indicated that the EPA
should not make the appropriate and
necessary regulatory determination for
Hg emissions until the EPA had
reviewed the results of the NAS Study.
See H.R. Conf. Rep. No 105–769, at 281–
282 (1998).
As directed by Congress through
different vehicles, the NAS Study and
the NIEHS Study evaluated the same
issues. The NIEHS completed the
NIEHS Study in 1995,3 and the NAS
completed the NAS Study in 2000.4
Because NAS completed its study 5
years after the NIEHS Study, and
considered additional information not
earlier available to NIEHS, for purposes
of this document we discuss the content
of the NAS Study as opposed to the
NIEHS Study.
The EPA conducted the studies
required by CAA section 112(n)(1)
concerning utility HAP emissions, the
Utility Study and the Mercury Study,5
and completed both by 1998. Prior to
issuance of the Mercury Study, the EPA
3 NIEHS Study, August 1995; EPA–HQ–OAR–
2009–3053.
4 National Research Council (NAS). 2000.
Toxicological Effects of Methylmercury. Committee
on the Toxicological Effects of Methylmercury,
Board on Environmental Studies and Toxicology,
National Research Council.
5 Mercury Study Report to Congress, December
1997; EPA–HQ–OAR–2009–0234–3054.
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engaged in two extensive external peer
reviews of the document.
On December 20, 2000, the EPA
issued a finding pursuant to CAA
section 112(n)(1)(A) that it was
appropriate and necessary to regulate
coal- and oil-fired EGUs under CAA
section 112 and added such units to the
list of source categories subject to
regulation under CAA section 112(d). In
making that finding, the EPA considered
the Utility Study, the Mercury Study,
the NAS Study, and certain additional
information, including information
about Hg emissions from coal-fired
EGUs that the EPA obtained pursuant to
an information collection request (ICR)
under the authority of CAA section 114.
65 FR 79826–27.
B. What is the litigation history of this
final rule?
Shortly after issuance of the December
2000 finding, an industry group
challenged that finding in the Court of
Appeals for the D.C. Circuit (D.C.
Circuit). Utility Air Regulatory Group
(UARG) v. EPA, 2001 WL 936363, No.
01–1074 (D.C. Cir. July 26, 2001). The
D.C. Circuit dismissed the lawsuit
holding that it did not have jurisdiction
because CAA section 112(e)(4) provides,
in pertinent part, that ‘‘no action of the
Administrator * * * listing a source
category or subcategory under
subsection (c) of this section shall be a
final agency action subject to judicial
review, except that any such action may
be reviewed under section 7607 of (the
CAA) when the Administrator issues
emission standards for such pollutant or
category.’’ Id. (emphasis added).
Pursuant to a settlement agreement,
the deadline for issuing emission
standards was March 15, 2005.
However, instead of issuing emission
standards pursuant to CAA section
112(d), on March 29, 2005, the EPA
issued the Section 112(n) Revision Rule
(2005 Action). That action delisted
EGUs after finding that it was neither
appropriate nor necessary to regulate
such units under CAA section 112. In
addition, on May 18, 2005, the EPA
issued the Clean Air Mercury Rule
(CAMR). 70 FR 28606. That rule
established standards of performance for
emissions of Hg from new and existing
coal-fired EGUs pursuant to CAA
section 111.
Environmental groups, states, and
tribes challenged the 2005 Action and
CAMR. Among other things, the
environmental and state petitioners
argued that the EPA could not remove
EGUs from the CAA section 112(c)
source category list without following
the requirements of CAA section
112(c)(9).
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On February 8, 2008, the D.C. Circuit
vacated both the 2005 Action and
CAMR. The D.C. Circuit held that the
EPA failed to comply with the
requirements of CAA section 112(c)(9)
for delisting source categories.
Specifically, the D.C. Circuit held that
CAA section 112(c)(9) applies to the
removal of ‘‘any source category’’ from
the CAA section 112(c) list, including
EGUs. The D.C. Circuit found that, by
enacting CAA section 112(c)(9),
Congress limited the EPA’s discretion to
reverse itself and remove source
categories from the CAA section 112(c)
list. The D.C. Circuit found that the
EPA’s contrary position would ‘‘nullify
§ 112(c)(9) altogether.’’ New Jersey v.
EPA, 517 F.3d 574, 583 (D.C. Cir. 2008).
The D.C. Circuit did not reach the
merits of petitioners’ arguments on
CAMR, but vacated CAMR for existing
sources because coal-fired EGUs were
already listed sources under CAA
section 112. The D.C. Circuit reasoned
that even under the EPA’s own
interpretation of the CAA, regulation of
existing sources’ Hg emissions under
CAA section 111 was prohibited if those
sources were a listed source category
under CAA section 112.6 Id. The D.C.
Circuit vacated and remanded CAMR
for new sources because it concluded
that the assumptions the EPA made
when issuing CAMR for new sources
were no longer accurate (i.e., that there
would be no CAA section 112 regulation
of EGUs and that the CAA section 111
standards would be accompanied by
standards for existing sources). Id. at
583–84. Thus, CAMR and the 2005
Action became null and void.
On December 18, 2008, several
environmental and public health
organizations filed a complaint in the
U.S. District Court for the District of
Columbia.7 They alleged that the
Agency had failed to perform a
nondiscretionary duty under CAA
section 304(a)(2), by failing to
promulgate final CAA section 112(d)
standards for HAP from coal- and oilfired EGUs by the statutorily-mandated
deadline, December 20, 2002, 2 years
after such sources were listed under
6 In CAMR and the 2005 Action, EPA interpreted
section 111(d) of the Act as prohibiting the Agency
from establishing an existing source standard of
performance under CAA section 111(d) for any HAP
emitted from a particular source category, if the
source category is regulated under CAA section 112.
7 American Nurses Association, Chesapeake Bay
Foundation, Inc., Conservation Law Foundation,
Environment America, Environmental Defense
Fund, Izaak Walton League of America, Natural
Resources Council of Maine, Natural Resources
Defense Council, Physicians for Social
Responsibility, Sierra Club, The Ohio
Environmental Council, and Waterkeeper Alliance,
Inc. (Civ. No. 1:08–cv–02198 (RMC)).
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CAA section 112(c). The EPA settled
that litigation. The consent decree
resolving the case requires the EPA to
sign a notice of proposed rulemaking
setting forth the EPA’s proposed CAA
section 112(d) emission standards for
coal- and oil-fired EGUs by March 16,
2011, and a notice of final rulemaking
by December 16, 2011.8
C. What is the relationship between this
final rule and other combustion rules?
1. CAA Section 111
The EPA promulgated revised NSPS
for SO2, nitrogen oxides (NOX), and PM
under CAA section 111 for EGUs (40
CFR part 60, subpart Da) and industrial
boilers (IB) (40 CFR part 60, subparts Db
and Dc) on February 27, 2006 (71 FR
9866). As noted elsewhere, in this
action we are finalizing certain
amendments to 40 CFR part 60, subpart
Da. In developing this final rule, we
considered the monitoring, testing, and
recordkeeping requirements of the
existing and revised NSPS to avoid
duplicating requirements to the extent
possible.
2. CAA Section 112
The EPA has previously developed
other non-EGU combustion-related
NESHAP under CAA section 112(d).
The EPA promulgated final NESHAP for
major source industrial, commercial and
institutional boilers and process heaters
(IB) and area source industrial,
commercial and institutional boilers on
March 21, 2011 (40 CFR part 63, subpart
DDDDD, 76 FR 15608; and subpart JJJJJJ,
76 FR 15249, respectively), and
promulgated standards for stationary
combustion turbines (CT) on March 5,
2004 (40 CFR part 63 subpart YYYY; 69
FR 10512). In addition to these three
NESHAP, on March 21, 2011, the EPA
also promulgated final CAA section 129
standards for commercial and
institutional solid waste incineration
(CISWI) units, including energy
recovery units (40 CFR part 60, subparts
CCCC (NSPS) and DDDD (emission
guidelines); 76 FR 15704); and a
definition of non-hazardous secondary
materials that are solid waste (Nonhazardous Solid Waste Definition Rule
(40 CFR part 241, subpart B; 76 FR
15456)). Electric generating units and IB
8 The consent decree originally required EPA to
sign a notice of final rulemaking no later than
November 16, 2011; however, on October 21, 2011,
pursuant to paragraph 6 of the consent decree, the
parties agreed to a 30-day extension of the final rule
deadline. As stated in the stipulation memorializing
the extension, the parties agreed to the extension of
30 days because EPA provided an additional 30
days for public comment and the time was
necessary to respond to comments submitted on the
proposed rule.
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that combust fossil fuel and solid waste,
as that term is defined by the
Administrator pursuant to the Resource
Conservation and Recovery Act (RCRA),
see 76 FR 15456, will be subject to
standards issued pursuant to CAA
section 129 (e.g., CISWI), unless they
meet one of the exemptions in CAA
section 129(g)(1). Clean Air Act section
129 standards are discussed in more
detail below.
The two IB (Boiler) NESHAP, the CT
NESHAP, and this final rule will
regulate HAP emissions from sources
that combust fossil fuels for electrical
power, process operations, or heating.
The differences among these rules are
due to the size of the units (megawatt
(MW), megawatt-electric (MWe), or
British thermal unit per hour (Btu/hr)),
the boiler/furnace technology, and/or
the portion of their electrical output (if
any) for sale to any utility power
distribution systems.
Pursuant to the CAA, an EGU is ‘‘any
fossil fuel fired combustion unit of more
than 25 megawatts that serves a
generator that produces electricity for
sale. A unit that cogenerates steam and
electricity and supplies more than onethird of its potential electric output
capacity and more than 25 megawatts
electrical output to any utility power
distribution system for sale shall be
considered an electric utility steam
generating unit.’’ CAA section 112(a)(8).
We consider all of the MW ratings
quoted in the final rule to be the original
rated nameplate capacity of the unit. We
consider cogeneration to be the
simultaneous production of power
(electricity) and another form of useful
thermal energy (usually steam or hot
water) from a single fuel-consuming
process.
We consider any combustion unit,
regardless of size, that produces steam
to serve a generator that produces
electricity exclusively for industrial,
commercial, or institutional purposes
(i.e., makes no sales to the national
electrical distribution grid) to be an IB
unit. We do not consider a fossil fuelfired combustion unit that serves a
generator that produces electricity for
sale to be an EGU under the final rule
if the size of the combustion unit is less
than or equal to 25 MW. Units that are
25 MW or less are likely subject to one
of the two Boiler NESHAP.
Because of the combustion technology
of simple-cycle and combined-cycle
stationary CTs (with the exception of
integrated gasification combined cycle
(IGCC) units that burn gasified coal or
petroleum coke synthesis gas/syngas),
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we do not consider these CTs to be
EGUs for purposes of this final rule.9
The December 2000 listing discussed
above did not list natural gas-fired
EGUs. Thus, this final rule does not
regulate a unit that otherwise meets the
CAA section 112(a)(8) definition of an
EGU but that combusts natural gas
exclusively or natural gas in
combination with another fossil fuel
where the natural gas constitutes 90.0
percent or more of the average annual
heat input during any 3 consecutive
calendar years or 85.0 percent or more
of the annual heat input in one calendar
year. We consider such units to be
natural gas-fired EGUs notwithstanding
the combustion of some coal or oil (or
derivative thereof) and such units are
not subject to this final rule.
The CAA does not define the terms
‘‘fossil fuel-fired’’ and ‘‘fossil fuel.’’ In
this rule, we are finalizing definitions
for both terms for purposes of this rule.
The definition of ‘‘fossil fuel-fired’’ will
help determine the applicability of the
final rule to combustion units that sell
electricity to the utility power
distribution system. The definition of
‘‘fossil fuel-fired’’ establishes the
amount of fossil fuel combustion
necessary to make a unit ‘‘fossil fuelfired’’ and hence potentially subject to
this final rule. These definitions will
help determine applicability of the final
rule to units that primarily fire nonfossil fuels (e.g., biomass) but generally
start up using either natural gas or
distillate oil and may use these fuels (or
coal) during normal operation for flame
stabilization.
In addition, the EPA is finalizing in
the definition of ‘‘fossil fuel-fired’’ that,
among other things, an EGU must fire
coal or oil for more than 10.0 percent of
the average annual heat input during
any 3 consecutive calendar years or for
more than 15.0 percent of the annual
heat input during any one calendar year
after the applicable compliance date in
order to be considered a fossil fuel-fired
EGU subject to this final rule. The EPA
has based these threshold percentage
values on the definition of ‘‘oil-fired’’ in
the Acid Rain Program (ARP) found at
40 CFR 72.2. Though the EPA does not
have annual heat input data for, for
example, biomass co-fired EGUs
because their use is not yet
commonplace, we believe this
definition accounts for the use of fossil
fuels for flame stabilization use without
inappropriately subjecting such units to
this final rule.
9 The CT NESHAP regulates HAP emissions from
all simple-cycle and combined-cycle stationary CTs
producing electricity or steam for any purpose.
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9309
Units that do not meet the EGU
definition will in most cases be
considered IB units subject to one of the
two Boiler NESHAP. Thus, for example,
a biomass-fired EGU, regardless of size,
that utilizes fossil fuels for startup and
flame stabilization purposes only (i.e.,
less than or equal to 10.0 percent of the
average annual heat input in any 3
consecutive calendar years or less than
or equal to 15.0 percent of the annual
heat input during any one calendar
year) is not considered to be a fossil
fuel-fired EGU under this final rule.
A cogeneration facility that sells
electricity to any utility power
distribution system equal to more than
one-third of its potential electric output
capacity and more than 25 MW will be
considered an EGU if the facility is
fossil fuel-fired as that term is defined
in the final rule.
We recognize that different CAA
section 112 rules may impact a
particular unit at different times. For
example, the Boiler NESHAP may cover
some cogeneration units. Such a unit
may decide to increase or decrease the
proportion of production output it
supplies to the electric utility grid, thus
causing the unit to meet the EGU
cogeneration criteria (i.e., greater than
one-third of its potential output capacity
and greater than 25 MW). A unit subject
to one of the Boiler NESHAP that
increases its electricity output and
meets the definition of an EGU would
be subject to the final EGU NESHAP.
Another rule intersection may occur
where one or more coal- or oil-fired
EGU(s) share an air pollution control
device (APCD) and/or an exhaust stack
with one or more similarly-fueled IB
unit(s). To demonstrate compliance
with two different rules, either the
emissions would need to be apportioned
to the appropriate source or the more
stringent emission limit would need to
be met. Data needed to apportion
emissions are not currently required by
this final rule or the final boiler
NESHAP and are not otherwise
available. Therefore, the EPA is
finalizing the requirement to comply
with the more stringent emission limit.
3. CAA Section 129
Clean Air Act section 129 regulates
units that combust ‘‘non-hazardous
secondary materials,’’ as that term is
defined by the Administrator under the
Resource Conservation and Recovery
Act (RCRA), that are ‘‘solid wastes.’’ On
March 21, 2011, the EPA promulgated
the final Non-Hazardous Solid Waste
Definition Rule (76 FR 15456). Any EGU
that combusts any solid waste as
defined in that final rule is a solid waste
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incineration unit subject to emissions
standards under CAA section 129.
In the Non-Hazardous Solid Waste
Definition Rule, the EPA determined
that coal refuse from current mining
operations is not considered to be a
‘‘solid waste’’ if it is not discarded. Coal
refuse that is in legacy coal refuse piles
is considered a ‘‘solid waste’’ because it
has been discarded. However, if
discarded coal refuse is processed in the
same manner as currently mined coal
refuse, the coal refuse would not be
considered a solid waste but instead
would be considered a product fossil
fuel. Therefore, the combustion of such
material by a combustion unit would
not subject that unit to regulation under
CAA section 129. Instead, the unit
would be subject to this final rule if it
meets the definition of EGU. In the
proposed rule, we assumed that all units
that combust coal refuse and otherwise
meet the definition of a coal-fired EGU
are in fact combusting newly mined coal
refuse or coal refuse from legacy piles
that has been processed such that it is
not a solid waste. We did not receive
any information since proposal that
would cause us to revise this
determination in the final rule.
Further, CAA section 129(g)(1)(B)
exempts from regulation
‘‘* * * qualifying small power production
facilities, as defined in section 796(17)(C) of
Title 16, or qualifying cogeneration facilities,
as defined in section 796(18)(B) of Title 16,
which burn homogeneous waste * * * for
the production of electric energy or in the
case of qualifying cogeneration facilities
which burn homogeneous waste for the
production of electric energy and steam or
forms of useful energy (such as heat) which
are used for industrial, commercial, heating
or cooling purposes * * *’’
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If the ‘‘homogeneous waste’’ material
that such facilities combust is also a
fossil fuel, and those facilities otherwise
meet the definition of an EGU under
CAA section 112(a)(8), then those
facilities are exempt from regulation
under CAA section 129 but covered
under this final rule. For example, a
qualifying small power production
facility or cogeneration facility
combusting only coal refuse that is a
solid waste and a ‘‘homogenous waste,’’
as that term is defined in the final CAA
section 129 CISWI standards, would be
subject to this final rule if the unit also
met the definition of EGU.
D. What are the health effects of
pollutants emitted from coal- and oilfired EGUs?
This final rule protects air quality and
promotes public health by reducing
emissions of some of the HAP listed in
CAA section 112(b)(1). Utilities are by
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far the largest anthropogenic source of
Hg in the U.S. In addition, EGUs are the
largest source of HCl, hydrogen fluoride
(HF), and selenium (Se) emissions, and
a major source of metallic HAP
emissions including As, chromium (Cr),
Ni, and others. The discrepancy is even
greater now that almost all other major
source categories have been required to
control Hg and other HAP under CAA
section 112. In 2005, U.S. EGUs emitted
50 percent of total domestic
anthropogenic Hg emissions, 62 percent
of total As emissions, 39 percent of total
cadmium (Cd) emissions, 22 percent of
total Cr emissions, 82 percent of total
HCl emissions, 62 percent of total HF
emissions, 28 percent of total Ni
emissions, and 83 percent of total Se
emissions.10 Exposure to these HAP,
depending on exposure duration and
levels of exposures, is associated with a
variety of adverse health effects. These
adverse health effects may include
chronic health disorders (e.g., irritation
of the lung, skin, and mucus
membranes; detrimental effects on the
central nervous system; damage to the
kidneys; and alimentary effects such as
nausea and vomiting). Two of the HAP
are classified as human carcinogens (As
and CrVI) and two as probable human
carcinogens (Cd and Ni). See 76 FR
25003–25005 for a fuller discussion of
the health effects associated with these
pollutants.
III. Appropriate and Necessary Finding
A. Overview
In December 2000, the EPA issued a
finding pursuant to CAA section
112(n)(1)(A) that it was appropriate and
necessary to regulate coal- and oil-fired
EGUs under CAA section 112 and added
such units to the list of source categories
subject to regulation under section
112(d). The EPA found that it was
appropriate to regulate HAP emissions
from coal- and oil-fired EGUs because,
among other reasons, Hg is a hazard to
public health, and U.S. EGUs are the
largest domestic source of Hg emissions.
The EPA also found it appropriate to
regulate HAP emissions from EGUs
because it had identified certain control
options that would effectively reduce
HAP emissions from U.S. EGUs. The
EPA found that it was necessary to
regulate HAP emissions from U.S. EGUs
under section 112 because the
implementation of other requirements
under the CAA will not adequately
address the serious public health and
environmental hazards arising from
HAP emissions from U.S. EGUs and that
10 From 2005 National-Scale Air Toxics
Assessment (NATA), available at https://
www.epa.gov/ttn/atw/nata2005/.
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CAA section 112 is intended to address
HAP emissions. See 76 FR 24984–20985
(for further discussion of 2000 finding).
Because several years had passed
since the 2000 finding, the EPA
performed additional technical analyses
for the proposed rule, even though those
analyses were not required. These
analyses included a national-scale Hg
risk assessment focused on populations
with high levels of self-caught fish
consumption, and a set of 16 case
studies of inhalation cancer risks for
non-Hg HAP. The analyses confirm that
it remains appropriate and necessary to
regulate U.S. EGUs under section 112.
In the preamble to the proposed rule,
the EPA reported the results of those
additional technical analyses. Those
analyses confirmed the 2000 finding
that it is appropriate to regulate U.S.
EGUs under section 112 by
demonstrating that (1) Hg continues to
pose a hazard to public health because
up to 28 percent of watersheds were
estimated to have Hg deposition
attributable to U.S. EGUs that
contributes to potential exposures above
the reference dose for methylmercury
(MeHg RfD), a level above which there
is increased risk of neurological effects
in children, (2) non-Hg HAP emissions
pose a hazard to public health because
case studies at 16 facilities
demonstrated that lifetime cancer risks
at 4 of the facilities exceed 1 in 1
million, and (3) U.S. EGUs remain the
largest domestic source of Hg emissions
and several HAP (e.g., HF, Se, HCl), and
are among the largest contributors for
other HAP (e.g., As, Cr, Ni, HCN). Thus,
in the preamble to the proposed rule,
the EPA found that Hg and non-Hg HAP
emissions from U.S. EGUs pose hazards
to public health, which confirmed the
2000 finding and demonstrated that it
remains appropriate to regulate U.S.
EGUs under section 112.
In the preamble to the proposed rule,
the EPA also found that it is appropriate
to regulate U.S. EGUs because (1) Hg
emissions pose a hazard to the
environment and wildlife, adversely
impacting species of fish-eating birds
and mammals, (2) acid gas HAP pose a
hazard to the environment because they
contribute to aquatic acidification, and
(3) effective controls are available to
reduce Hg and non-Hg HAP emissions
from U.S. EGUs.
The additional analyses reported in
the preamble to the proposed rule also
confirmed that it remains necessary to
regulate U.S. EGU under CAA section
112. These analyses demonstrated that
(1) Hg emissions from U.S. EGUs
remaining in 2016 are reasonably
anticipated to pose a hazard to public
health after imposition of other CAA
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requirements, such as the Cross-State
Air Pollution Rule (CSAPR); (2) U.S.
EGUs are reasonably anticipated to
remain the largest source of Hg in the
U.S. and thus contribute to the risk
associated with exposure to MeHg; (3)
Hg emissions from U.S. EGUs after
imposition of the requirements of the
CAA were projected to be 29 tons per
year in 2016, similar to levels of Hg
emitted today, indicating that further
substantial reductions in Hg emissions
are not reasonably anticipated without
federal regulations on Hg from U.S.
EGUs; (4) we cannot be certain that the
identified cancer risks attributable to
non-Hg emissions from U.S. EGUs will
be addressed through imposition of the
requirements of the CAA because
companies can use compliance
strategies for criteria pollutants that do
not achieve HAP co-benefits (e.g.,
purchasing allowances in a trading
program); and (5) we cannot ensure that
Hg and non-Hg HAP emissions
reductions achieved since 2005 would
be permanent without federally binding
regulations for Hg from U.S. EGUs.
Since issuance of the proposed rule,
the EPA has conducted peer reviews of
the national-scale Hg risk assessment
(Hg Risk TSD) and the approach for
estimating chromium and nickel
inhalation cancer risk in the case
studies.11 12 The peer review of the Hg
Risk TSD was conducted by EPA’s
independent Science Advisory Board
(SAB). The SAB stated that it ‘‘supports
the overall design of and approach to
the risk assessment and finds that it
should provide an objective, reasonable,
and credible determination of the
potential for a public health hazard from
mercury emitted from U.S. EGUs.’’ 13
SAB recommended several
improvements to the data, methods and
documentation of the analyses, which
EPA has fully addressed in the revised
Hg Risk TSD.
As described in the revised Hg Risk
TSD, after addressing comments from
11 U.S. EPA. 2011a. National-Scale Assessment of
Mercury Risk to Populations with High
Consumption of Self-caught Freshwater Fish In
Support of the Appropriate and Necessary Finding
for Coal- and Oil-Fired Electric Generating Units.
Office of Air Quality Planning and Standards.
November. EPA–452/R–11–009.
12 U.S. EPA. 2011b. Supplement to Non-mercury
Case Study Chronic Inhalation Risk Assessment for
the Utility MACT Appropriate and Necessary
Analysis. Office of Air Quality Planning and
Standards. November.
13 U.S. Environmental Protection Agency-Science
Advisory Board (U.S. EPA–SAB). 2011. Peer Review
of EPA’s Draft National-Scale Mercury Risk
Assessment. EPA–SAB–11–017. September.
Available on the Internet at https://yosemite.epa.gov/
sab/sabproduct.nsf/
BCA23C5B7917F5BF8525791A0072CCA1/$File/
EPA-SAB-11-017-unsigned.pdf.
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the peer review, the revised results
show that up to 29 percent of modeled
watersheds are estimated to have Hg
deposition attributable to U.S. EGUs
that contributes to potential exposures
above the MeHg RfD, an increase of one
percentage point from the results
reported in the proposed rule. We
conclude that Hg emissions from EGUs
pose a hazard to public health based on
the total of 29 percent of modeled
watersheds at risk. Our analyses show
that of the 29 percent of watersheds
with population at-risk, in 10 percent of
those watersheds U.S. EGU deposition
alone without considering deposition
from other sources would lead to
potential exposures that exceed the
MeHg RfD, and in 24 percent of those
watersheds, total potential exposures to
MeHg exceed the RfD and U.S. EGUs
contribute at least 5 percent to Hg
deposition.14 15 Each of these results
independently supports our conclusion
that Hg emissions from EGUs pose
hazards to public health.
The peer review of the approach to
estimate Ni and Cr cancer risk in the
case studies also supported EPA’s
assessment. The EPA enhanced this
analysis in response to the peer review
and public comments. The results of
those revised analyses show that 6 of 16
modeled facilities have lifetime cancer
risks greater than 1 in a million, thus
confirming that non-Hg HAP emissions
from U.S. EGUs remain a hazard to
public health. Given Congress’
determination that categories of sources
that emit HAP resulting in a lifetime
cancer risk greater than 1 in a million
should not be removed from the CAA
section 112(c) source category list and
should continue to be regulated under
CAA section 112, the EPA concludes
that risk above that level represents a
hazard to public health.
Based on our consideration of the
peer reviews, public comments, and our
updated analyses, we confirm the
findings that Hg and non-Hg HAP
emissions from U.S. EGUs pose hazards
to public health and that it remains
appropriate to regulate U.S. EGUs under
14 Because some watersheds with exposures
sufficient to exceed the RfD with Hg deposition
from U.S. EGUs alone without considering
deposition from other sources also have U.S. EGU
contributions of more than 5 percent of total Hg
deposition, there is some overlap between the two
risk metrics. This explains why the total percent of
watersheds exceeding either risk metric is less than
the sum of the individual risk metrics.
15 Requiring at least a 5 percent EGU contribution
is a conservative approach given the increasing
risks associated with incremental exposures above
the RfD. Because we are finding 24 percent of
watersheds with populations potentially at risk
even using this conservative approach, we have
confidence that emissions of Hg from U.S. EGUs are
causing a hazard to public health.
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CAA section 112. We also conclude that
it remains appropriate to regulate U.S.
EGUs under CAA section 112 because of
the magnitude of Hg and non-Hg
emissions, environmental effects of Hg
and certain non-Hg emissions, and the
availability of controls to reduce HAP
emissions from EGUs.
In addition, we conclude that the
hazards to public health from Hg and
non-Hg emissions from U.S. EGUs are
reasonably anticipated to remain after
imposition of the requirements of the
CAA. The same is true for hazards to the
environment. Thus, we confirm that it is
necessary to regulate U.S. EGUs under
CAA section 112.
B. Peer Review of the Hg Risk TSD
Supporting the Appropriate and
Necessary Finding for Coal and OilFired EGUs and EPA Response
In the preamble to the proposed rule,
the EPA stated that ‘‘in making the
finding that it remains appropriate and
necessary to regulate EGUs to address
public health and environmental
hazards associated with emissions of Hg
and Non-Hg HAP from EGUs, the EPA
determined that the Hg Risk TSD
supporting EPA’s 2011 review of U.S.
EGU health impacts should be peerreviewed.’’ 16 We also indicated that due
to the court-ordered schedule for the
final rule, we planned to conduct the
peer review as expeditiously as possible
after issuance of the proposed rule, and
that the results of the peer review and
any EPA response would be published
before the final rule. Due to the
extension of the public comment period
and the volume of public comments
received on the analyses supporting the
proposed rule, we were unable to
publish EPA’s response prior to
signature of the final rule.
The EPA’s response to the peer review
the Hg Risk TSD is fully documented in
the revised Technical Support
Document (TSD): National-Scale
Assessment of Hg Risk to Populations of
High Consumption of Self-Caught Fish
In Support of the Appropriate and
Necessary Finding for Coal and OilFired Electric Generating Units.17 The
following sections describe the peer
review process that we followed,
provide the peer review charge
questions presented to the peer review
panel, summarize the key
recommendations from the peer review,
and summarize our responses to those
recommendations.
16 76
FR 25012.
EPA, 2011a.
17 U.S.
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1. Summary of Peer Review Process
Peer review is consistent with EPA’s
open and transparent process to ensure
that the Agency’s scientific assessments
and rulemakings are based on the best
science available. This regulatory action
was supported by the Hg Risk TSD,
which is a highly influential scientific
assessment. Therefore, the EPA
conducted a peer review in accordance
with OMB’s Final Information Quality
Bulletin for Peer Review 18 as described
below. All the materials related to the
peer review, including the SAB’s final
report, can be found in the docket for
this rulemaking.
The EPA commissioned the peer
review through EPA’s SAB, which
provides independent advice and peer
review to EPA’s Administrator on the
scientific and technical aspects of
environmental issues. The SAB
convened a 22-member peer review
committee. The SAB process for
selecting the panel began with two
Federal Register Notices requesting
nominations for the Mercury Review
Panel.19 Based on nominations received,
a list of potential panel members, along
with bio-sketches, was posted for public
comment on the SAB Web site on April
15, 2011. The members of the Mercury
Review Panel were announced on May
24, 2011. The membership of the panel
included representatives of 16 academic
institutions, 4 state health or
environmental agencies, 1 federal
agency, and 1 utility industry
organization.20 The panel held a public
meeting in Research Triangle Park, NC,
on June 15–17, 2011, which included
the opportunity for public comment on
the Hg Risk TSD and the peer review
process.21 At the June 15–17 public
meeting, the panel completed a draft
peer review report. The minutes of that
meeting and the draft peer review report
were posted to the SAB public Web site
within the public comment period for
the proposed rule. The panel discussed
18 Office of Management and Budget (OMB). 2004.
Final Information Quality Bulletin for Peer Review.
December. Available on the Internet at https://
www.whitehouse.gov/omb/
memoranda_fy2005_m05-03.
19 76 FR 10896 and 76 FR 17649. The first notice
requested nominations to a Clean Air Scientific
Advisory Committee (CASAC) panel. Upon review
of the scope of the CASAC charter (resulting from
a public comment received in response to the first
notice), the SAB determined that it would be more
appropriate to form a panel under the SAB, rather
than CASAC. The second notice announced this
change and requested nominations for the SAB
panel.
20 The full list of panel members is documented
at https://yosemite.epa.gov/sab/sabproduct.nsf/0/
9F048172004D93BB8525783900503486/$File/
Determination%20memo%20with%20addendum05.24.11.pdf.
21 76 FR 29746.
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the draft report at a public
teleconference on July 12, 2011, during
which additional opportunities for
public comment were provided,22 and
submitted a revised draft for quality
review by the Chartered SAB before the
end of the public comment period on
the rule. The Chartered SAB held a
public teleconference on September 7,
2011, to conduct a quality review of the
draft report; this teleconference also
included a final opportunity for public
comment.23 The SAB submitted its final
report to EPA on September 29, 2011.24
Notice of all the meetings was published
in the Federal Register and all of the
materials discussed at the SAB
meetings, including technical
documents, presentations, meeting
minutes, and draft reports were posted
for public access on the SAB Web site 25
and were added to the docket for the
final rule on October 14, 2011.
2. Peer Review Charge Questions
The EPA asked the SAB to comment
on the Hg Risk TSD, including the
overall design and approach and the use
of specific models and key assumptions.
The EPA also asked the SAB to
comment on the extent to which
specific facets of the assessment were
well characterized in the Hg Risk TSD.
The specific charge questions are listed
below:
Question 1. Please comment on the
scientific credibility of the overall
design of the mercury risk assessment as
an approach to characterize human
health exposure and risk associated
with U.S. EGU mercury emissions (with
a focus on those more highly exposed).
Question 2. Are there any additional
critical health endpoint(s) besides IQ
loss, which could be quantitatively
estimated with a reasonable degree of
confidence to supplement the mercury
risk assessment (see section 1.2 of the
Mercury Risk TSD for an overview of
the risk metrics used in the risk
assessment)?
Question 3. Please comment on the
benchmark used for identifying a
potentially significant public health
impact in the context of interpreting the
IQ loss risk metric (i.e., an IQ loss of 1
to 2 points or more representing a
potential public health hazard). Is there
any scientifically credible alternate
decrement in IQ that should be
considered as a benchmark to guide
interpretation of the IQ risk estimates
(see section 1.2 of the Mercury Risk TSD
22 76
FR 39102.
FR 50729.
24 U.S. EPA–SAB, 2011. Peer Review of EPA’s
Draft National-Scale Mercury Risk Assessment.
25 See https://yosemite.epa.gov/sab/sabpeople.nsf/
WebCommittees/BOARD.
23 76
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for additional detail on the benchmark
used for interpreting the IQ loss
estimates)?
Question 4: Please comment on the
spatial scale used in defining
watersheds that formed the basis for risk
estimates generated for the analysis (i.e.,
use of 12-digit hydrologic unit code
classification). To what extent do
[Hydrologic Unit Code] HUC12
watersheds capture the appropriate
level of spatial resolution in the
relationship between changes in
mercury deposition and changes in
MeHg fish tissue levels? (see section 1.3
and Appendix A of the Mercury Risk
TSD for additional detail on specifying
the spatial scale of watersheds used in
the analysis).
Question 5: Please comment on the
extent to which the fish tissue data used
as the basis for the risk assessment are
appropriate and sufficient given the
goals of the analysis. Please comment on
the extent to which focusing on data
from the period after 1999 increases
confidence that the fish tissue data used
are more likely to reflect more
contemporaneous patterns of Hg
deposition and less likely to reflect
earlier patterns of Hg deposition. Are
there any additional sources of fish
tissue MeHg data that would be
appropriate for inclusion in the risk
assessment?
Question 6: Given the stated goal of
estimating potential risks to highly
exposed populations, please comment
on the use of the 75th percentile fish
tissue MeHg value (reflecting targeting
of larger but not the largest fish for
subsistence consumption) as the basis
for estimating risk at each watershed.
Are there scientifically credible
alternatives to use of the 75th percentile
in representing potential population
exposures at the watershed level?
Question 7: Please comment on the
extent to which characterization of
consumption rates and the potential
location for fishing activity for high-end
self-caught fish consuming populations
modeled in the analysis are supported
by the available study data cited in the
Mercury Risk TSD. In addition, please
comment on the extent to which
consumption rates documented in
Section 1.3 and in Appendix C of the
Mercury Risk TSD provide appropriate
representation of high-end fish
consumption by the subsistence
population scenarios used in modeling
exposures and risk. Are there additional
data on consumption behavior in
subsistence populations active at inland
freshwater water bodies within the
continental U.S.?
Question 8: Please comment on the
approach used in the risk assessment of
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assuming that a high-end fish
consuming population could be active
at a watershed if the ‘‘source
population’’ for that fishing population
is associated with that watershed (e.g.,
at least 25 individuals of that
population are present in a U.S. Census
tract intersecting that watershed). Please
identify any additional alternative
approaches for identifying the potential
for population exposures in watersheds
and the strengths and limitations
associated with these alternative
approaches (additional detail on how
EPA assessed where specific highconsuming fisher populations might be
active is provided in section 1.3 and
Appendix C of the Mercury Risk TSD).
Question 9: Please comment on the
draft risk assessment’s characterization
of the limitations and uncertainty
associated with application of the
Mercury Maps approach (including the
assumption of proportionality between
changes in mercury deposition over
watersheds and associated changes in
fish tissue MeHg levels) in the risk
assessment. Please comment on how the
output of CMAQ [Community
Multiscale Air Quality] modeling has
been integrated into the analysis to
estimate changes in fish tissue MeHg
levels and in the exposures and risks
associated with the EGU-related fish
tissue MeHg fraction (e.g., matching of
spatial and temporal resolution between
CMAQ modeling and HUC12
watersheds). Given the national scale of
the analysis, are there recommended
alternatives to the Mercury Maps
approach that could have been used to
link modeled estimates of mercury
deposition to monitored MeHg fish
tissue levels for all the watersheds
evaluated? (additional detail on the
Mercury Maps approach and its
application in the risk assessment is
presented in section 1.3 and Appendix
E of the Mercury Risk TSD).
Question 10: Please comment on the
EPA’s approach of excluding
watersheds with significant non-air
loadings of mercury as a method to
reduce uncertainty associated with
application of the Mercury Maps
approach. Are there additional criteria
that should be considered in including
or excluding watersheds?
Question 11: Please comment on the
specification of the concentrationresponse function used in modeling IQ
loss. Please comment on whether EPA,
as part of uncertainty characterization,
should consider alternative
concentration-response functions in
addition to the model used in the risk
assessment. Please comment on the
extent to which available data and
methods support a quantitative
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treatment of the potential masking effect
of fish nutrients (e.g., omega-3 fatty
acids and selenium) on the adverse
neurological effects associated with
mercury exposure, including IQ loss
(detail on the concentration-response
function used in modeling IQ loss can
be found in section 1.3 of the Mercury
Risk TSD).
Question 12: Please comment on the
degree to which key sources of
uncertainty and variability associated
with the risk assessment have been
identified and the degree to which they
are sufficiently characterized.
Question 13: Please comment on the
draft Mercury Risk TSD’s discussion of
analytical results for each component of
the analysis. For each of the
components below, please comment on
the extent to which EPA’s observations
are supported by the analytical results
presented and whether there is a
sufficient characterization of
uncertainty, variability, and data
limitations, taking into account the
models and data used: Mercury
deposition from U.S. EGUs, fish tissue
MeHg concentrations, patterns of Hg
deposition with HG fish tissue data,
percentile risk estimates, and number
and frequency of watersheds with
populations potentially at risk due to
U.S. EGU mercury emissions.
Question 14: Please comment on the
degree to which the final summary of
key observations in Section 2.8 is
supported by the analytical results
presented. In addition, please comment
on the degree to which the level of
confidence and precision in the overall
analysis is sufficient to support use of
the risk characterization framework
described on page 18.
3. Summary of Peer Review Findings
and Recommendations
The SAB was generally supportive of
EPA’s approach.26 The SAB concluded,
‘‘[i]n summary, based on its review of
the draft Technical Support Document
and additional information provided by
EPA representatives during the public
meetings, the SAB supports the overall
design of and approach to the risk
assessment and finds that it should
provide an objective, reasonable, and
credible determination of the potential
for a public health hazard from mercury
emitted from U.S. EGUs.’’ 27 The SAB
further concluded, ‘‘[t]he SAB regards
the design of the risk assessment as
suitable for its intended purpose, to
inform decision-making regarding an
‘appropriate and necessary finding’ for
regulation of hazardous air pollutants
26 U.S.
PO 00000
from coal and oil-fired EGUs, provided
that our recommendations are fully
considered in the revision of the
assessment.’’ 28
The SAB report contained many
recommendations for improving the Hg
Risk TSD, which the SAB organized into
three general themes: (1) Improve the
clarity of the Hg Risk TSD regarding
methods and presentation of results, (2)
expand the discussion of sources of
variability and uncertainty, and (3) deemphasize IQ loss as an endpoint. In the
following subsection, we provide EPA’s
response to these recommendations.
4. The EPA’s Responses to Peer Review
Recommendations
In response to the peer review, the
EPA has substantially revised the Hg
Risk TSD. The revised Hg Risk TSD
addresses all of the recommendations
from the SAB and includes a detailed
list of the specific revisions made to the
Hg Risk TSD. Revisions in response to
the main recommendations are
summarized below. Italicized
statements are the SAB’s
recommendations, which are followed
by EPA’s response.
• The watershed-focus of the Hg Risk
TSD should be clearly stated early in the
introduction to the document. We have
stated clearly in the introduction to the
revised Hg Risk TSD that the focus of
the analysis is on scenarios of high fish
consumption by subsistence level
fishing populations, assessed at
watersheds where there is the potential
for such subsistence fishing activity.
Specifically, we modeled risk for a set
of subsistence fisher scenarios at those
watersheds where (a) we have measured
fish tissue Hg data and (b) it is
reasonable to assume that subsistencelevel fishing activity could occur. We
emphasize the point that the analysis is
not a representative populationweighted assessment of risk. Rather, it is
based on evaluating these potential
exposure scenarios.
• Because IQ does not fully capture
the range of neurodevelopmental effects
associated with Hg exposure, analysis of
this endpoint should be deemphasized
(and moved to an appendix) and
primary focus should be placed on the
MeHg RfD-based hazard quotient
metric. We modified the structure of the
revised Hg Risk TSD accordingly.
• Clarify the rationale for using a
Hazard Quotient (HQ) at or above 1.5 as
the basis for selecting potentially
impacted watersheds. The SAB fully
supported using HQ as the risk metric,
but we revised the discussion in the Hg
Risk TSD to clarify why we selected 1.5
EPA–SAB, 2011.
27 Id.
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as the benchmark. We clarified that
exposures above the RfD (i.e., an HQ
above one) represent increasing risk of
neurological health effects.29 We further
clarified that the HQ is calculated to
only one significant digit, based on the
precision in the underlying RfD
calculations. As a result, rounding
convention requires that any values at
or above 1.5 be expressed as an HQ of
2, while any values below 1.5 (e.g., 1.49)
be rounded to an HQ of 1. Thus, MeHg
exposures leading to an HQ at or above
1.5 for pregnant women are considered
above the RfD and are associated with
increased risk of neurological health
effects in children born to those
mothers.
• Regarding the fish tissue dataset
used in the Hg Risk TSD, clarify which
species of Hg is reflected in the
underlying samples and discuss the
implications of differences across states
in sampling protocols in introducing
bias into the analysis. We clarified that
in most cases, the fish tissue is
measured for total Hg. Furthermore,
based on the scientific literature,30 it is
reasonable to assume that more than
90 percent of fish tissue Hg is MeHg.
Therefore, we incorporated an Hg
conversion factor 31 into our exposure
calculations to account for the fraction
of total Hg that is MeHg in fish. We also
expanded the discussion of uncertainty
to address the potential for different
sampling protocols across states to
introduce bias into the Hg Risk TSD.
• Additional detail should be
provided on the characteristics of the
fish tissue Hg dataset, including its
derivation and the distribution of
specific attributes across the dataset
(e.g., number of fish tissue samples and
number of different waterbodies in a
watershed, number of species reflected
across watersheds). We included
additional figures and tables describing
the derivation of the watershed-level
fish tissue Hg dataset, including the
filtering steps applied to the original
water body level data and the additional
steps taken to generate the watershedlevel fish tissue Hg percentile estimates.
In addition, we included tables
summarizing key attributes of the
29 As stated in the preamble to the proposal,
based on the current literature, exposures above the
RfD contribute to risk of adverse effects.
30 See the literature summary in Chapter 4 of U.S.
EPA. 2000. Guidance for Assessing Chemical
Contaminant Data for Use in Fish Advisories. Office
of Science and Technology, Office of Water,
Washington, DC EPA 823–B–00–007.
31 In the Hg Risk TSD accompanying the proposed
rule, we assumed that 100 percent of Hg in fish was
MeHg. We derived the 0.95 conversion factor for the
revised Hg Risk TSD to reflect that most studies
show that more than 90 percent of total Hg in fish
is MeHg. See Chapter 4 of U.S. EPA, 2000.
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dataset (e.g., distribution of fish tissue
sample size and number of species
across the watershed-level estimates).
• Determine whether there is
additional (more recent) fish tissue data
for key states including Pennsylvania,
New Jersey, Kentucky and Illinois where
U.S. EGUs Hg deposition may be more
significant. We expanded the fish tissue
dataset by incorporating additional fish
tissue data from the National Listing of
Fish Advisories (NLFA), which
included additional data for four states
(MI, NJ, PA, and MN). We also obtained
additional data for Wisconsin. These
additional data expanded the number of
watersheds in the analysis from 2,317 to
3,141, an increase of 36 percent. The
additional watersheds improve coverage
in areas with high levels of U.S. EGUattributable Hg deposition, and thus
increase our confidence in the overall
results of the Hg Risk TSD.
• Include additional discussion of the
potential that the low sampling rates
reflected across many of the watersheds
may low-bias the 75th percentile fish
tissue Hg estimates used in estimating
potential exposures. In addition,
include a sensitivity analysis using the
50th percentile estimates to provide a
bound on the risk. The SAB expressed
support for the use of the 75th
percentile fish tissue Hg value in the Hg
Risk TSD, while recommending
additional discussion of the issue. We
provided additional description of the
fish tissue dataset, including
distribution of sample sizes and fish
species across the watersheds, and an
improved discussion of uncertainty and
potential low bias resulting from
estimation of the 75th percentile fish
tissue levels. We also included a
sensitivity analysis that used the 50th
percentile watershed-level fish tissue Hg
level. This sensitivity analysis showed
that using the 50th percentile estimates
resulted in a decrease in the number
and percentage of modeled watersheds
with populations potentially at-risk
from U.S. EGU-attributable MeHg
exposures, from 29 percent of
watersheds exceeding either risk metric
(i.e., MeHg exposure from U.S. EGUs
alone exceeds the RfD or total MeHg
exposure exceeds the RfD and U.S.
EGUs contribute at least 5 percent) in
the revised Hg Risk TSD to 26 percent
in the sensitivity analysis in the revised
Hg Risk TSD.
• Expand the discussion of caveats
associated with the fish consumption
rates used in the analysis. The SAB was
generally supportive of the consumption
rates used, while recommending
additional discussion of caveats. We
expanded the discussion of uncertainty
related to the fish consumption rates to
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address the caveats identified by the
SAB. The uncertainty discussion now
explains (1) that high-end consumption
rates for South Carolina reflect small
sample sizes, and therefore may be more
uncertain, (2) that the consumption
surveys underlying the studies are older
(i.e., mostly based on survey data from
the 1990s) and behavior may have
changed (i.e., consumption rates may
have changed since the surveys were
conducted), and (3) that consumption
rates used in the Hg Risk TSD are
annualized rather than seasonal rates
and thus contribute little to overall
uncertainty. None of these sources of
uncertainty is associated with a
particular directional bias (e.g., neither
systematically higher nor lower risk).
• Verify whether the consumption
rates are daily values expressed as
annual averages and whether they are
‘‘as caught’’ or ‘‘as prepared.’’ We
carefully reviewed the studies
underlying the fish consumption rates
used in the Hg Risk TSD and verified
that the rates are annual averages of the
daily consumption rates and that they
represent as prepared estimates. We also
expanded the explanation of the
exposure calculations to describe more
completely the exposure factors and
equation used to generate the average
daily MeHg intake estimates for the
subsistence scenarios.
• Explain the criteria for exclusion of
fish less than 7 inches in length from
analysis. We provided the rationale for
the 7-inch cutoff for edible fish used in
the Hg Risk TSD. Seven inches
represents a minimum size limit for a
number of key edible freshwater fish
species established at the state level. For
example, Pennsylvania establishes 7
inches as the minimum size limit for
both trout and salmon (other edible fish
species such as bass, walleye and
northern pike have higher minimum
size limits). The impact of the 7-inch
cutoff is likely to be quite small, as only
6 percent of potential fish samples were
excluded due to this criterion.
• Identify the number of watersheds
excluded from the analysis due to the
criterion for excluding watersheds with
less than 25 members of a source
population. The SAB was generally
supportive of the approach used for
identifying watersheds with the
potential for subsistence activity, while
recommending additional information
on the results of applying the approach.
We added a figure to illustrate the
number of watersheds with fish tissue
Hg data used to model risk for each of
the subsistence fishing scenarios. For all
scenarios except the female subsistence
fishing scenario, the exposure scenarios
significantly limited the number of
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watersheds. Because the female
subsistence fishing scenario does not
differentiate with regard to ethnicity or
socio-economic status (SES), we applied
this scenario to all regions of the
country and to all watersheds with fish
tissue Hg data. This reflects our
assumption that, given the generalized
nature of the female subsistence fishing
scenario, it is reasonable to assume that
it could potentially occur at any
watershed with fish tissue Hg data. The
female subsistence fishing scenario
included in the revised risk assessment
is similar to the high-consuming female
scenario included in the Hg Risk TSD.32
However, the female subsistence fishing
scenario is applied to all watersheds,
while in the scenario for the highconsuming low-income female angler,
we only evaluated watersheds with a
population of at least 25 low-income
females. The female subsistence fishing
scenario provides greater coverage
geographically than the high-consuming
low-income female scenario. As
described in the revised Hg Risk TSD,
the EPA made this change in response
to SAB’s concerns regarding the
potential exclusion of watersheds with
fewer than 25 individuals and regarding
coverage for high-end recreational fish
consumption.33
• Enhance the discussion of the
assumption of a linear relationship
between changes in Hg deposition and
changes in fish tissue Hg at the
watershed level, including providing
citations to more recent studies
supporting the proportional relationship
between changes in Hg deposition and
changes in MeHg fish tissue levels. The
SAB supported the assumption of a
linear relationship between changes in
Hg deposition and changes in fish tissue
Hg at the watershed level, while
recommending additional supporting
language. We expanded our discussion
of the scientific basis for the
proportionality assumption and added
citations for the more recent studies
supporting the assumption. We also
expanded the discussion of
uncertainties associated with this
assumption, including uncertainties
related to the potential for sampled fish
tissue Hg level to reflect previous Hg
deposition, and the potential for non-air
sources of Hg to contribute to sampled
fish tissue Hg levels. Each of these
32 In the Revised Hg Risk TSD, this population is
also referred to as the ‘‘typical female subsistence
consumer.’’
33 This change led to a very small increase in the
number of watersheds with populations potentially
at-risk. In the Hg Risk TSD accompanying the
proposed rule, approximately 4 percent of modeled
watersheds were excluded based on the SES-based
filtering criteria.
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sources of uncertainty may result in
potential bias in the estimate of
exposure associated with current
deposition. If the fish tissue Hg levels
are too high due to either previous Hg
deposition or non-air sources of Hg,
then the absolute level of exposure
attributed to both total Hg deposition
and U.S. EGU-attributable Hg deposition
will be biased high. However, the
percent contribution from U.S. EGUs
will not be affected as it depends
entirely on deposition. The EPA took
steps to minimize the potential for these
biases by (1) only using fish tissue Hg
samples from after 1999, and (2)
screening out watersheds that either
contained active gold mines or had
other substantial non-U.S. EGU
anthropogenic emissions of Hg. The
SAB concluded that the EPA’s approach
to minimizing the potential for these
biases to affect the results of the Hg Risk
TSD is sound. In addition, we
conducted several sensitivity analyses
to gauge the impact of excluding
watersheds with the potential for nonEGU Hg loading. We found that the
estimates of the percent of modeled
watersheds with populations potentially
at-risk were largely insensitive to these
exclusions, suggesting that any potential
biases from including watersheds with
potential non-air Hg loadings are likely
to be small.
• Additional sources of variability
should be discussed in terms of the
degree to which they are reflected in the
design of the risk assessment and the
impact that they might have on risk
estimates. These include: (1) The
geographic patterns of populations of
subsistence fishers, including how this
factor interacts with the limited
coverage we have for watersheds with
our fish tissue Hg data, (2) the protocols
used by states in collecting fish tissue
Hg data, (3) body weights for
subsistence fishing populations and the
impact that this might have on exposure
estimates, and (4) preparation and
cooking methods which affect the
conversion of fish tissue Hg levels (as
measured) into ‘‘as consumed’’ values.
We expanded the discussion of sources
of variability in the revised Hg Risk TSD
to more fully address these sources of
variability. The Hg Risk TSD
quantitatively reflected many aspects of
variability, including spatial and
temporal variability in Hg emissions, Hg
deposition, fish tissue Hg levels, and
subsistence behavior. After evaluating
the aspects of variability assessed
qualitatively in the Hg Risk TSD such as
temporal response in fish tissue, we do
not believe that quantitatively
incorporating any of these aspects
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would substantially change the risk
results given the stated goal of the
analysis to identify watersheds where
potential exposures to MeHg from selfcaught fish consumption could exceed
the RfD.
• Additional sources of uncertainty
should be discussed in terms of their
potential impact on risk estimates.
These include: (1) Emissions inventory
used in projecting total and U.S. EGUattributable Hg deposition, including
the projection of reductions in U.S. EGU
emissions for the 2016 scenario, (2) air
quality modeling with CMAQ including
the prediction of future air quality
scenarios, (3) ability of the Mercury
Maps-based approach for relating Hg
deposition to MeHg in fish to capture Hg
hotspots, (4) the limited coverage that
we have with fish tissue Hg data for
watersheds in the U.S. and implications
for the Hg Risk TSD, (5) the preparation
factor used to estimate ‘‘as consumed’’
fish tissue Hg levels, (6) the
proportionality assumption used to
relate changes in Hg deposition to
changes in fish tissue Hg levels at the
watershed-level, (7) characterization of
the spatial location of subsistence fisher
populations (including the degree to
which these provide coverage for highconsuming recreational fishers), and (8)
application of the RfD to low SES
populations and concerns that this
could low-bias the risk estimates. We
expanded the discussion of sources of
uncertainty presented in the revised
TSD to address more fully these sources
of uncertainty and the potential impact
on risk estimates. Regarding these eight
additional sources of uncertainty, we
have (1) evaluated the uncertainties in
the emissions and determined that
while an important source of
uncertainty, we are not able to quantify
emissions uncertainty in the risk
analysis, but have determined that the
emissions inventories and emissions
models represent the best available
methods for predicting Hg emissions in
the U.S., (2) evaluated the uncertainties
in the Hg deposition predictions and
determined that while an important
source of uncertainty, we are not able to
quantify uncertainty in Hg deposition in
the Hg Risk TSD. Moreover, the CMAQ
model used to estimate deposition is
based on peer reviewed science and
represents the best available method for
predicting Hg deposition in the U.S., (3)
evaluated the ability of the Mercury
Maps-based approach for relating Hg
deposition to MeHg in fish to capture
Hg hotspots and determined that while
finer resolution deposition modeling
might reveal additional areas with
elevated deposition, the 12 kilometer
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(km) deposition modeling matches well
with the watershed size selected for the
analysis, and thus the use of 12 km
deposition estimates with the Mercury
Maps based approach will not be a large
source of uncertainty, (4) evaluated the
limited coverage that we have with fish
tissue Hg data for watersheds in the U.S.
and implications for the Hg Risk TSD
and based on the SAB’s
recommendations, we supplemented the
coverage of watersheds by obtaining
additional fish tissue Hg samples for
areas heavily impacted by U.S. EGU
deposition, thus reducing the
uncertainty in the analysis, (5)
evaluated the uncertainty in the
preparation factor and determined that
the level of uncertainty is low, and as
such would have minimal impact on the
risk estimates, (6) evaluated the
uncertainty resulting from the
proportionality assumption used to
relate changes in Hg deposition to
changes in fish tissue Hg levels at the
watershed-level, and determined, based
both on quantitative sensitivity analyses
and qualitative assessments, that this
source of uncertainty is not likely to
greatly influence the results, and is not
likely to have a specific directional bias,
(7) evaluated the uncertainty related to
characterization of the spatial locations
of subsistence populations and
determined that uncertainty could be
reduced by focusing the risk estimates
on female subsistence fishing
populations, which are assumed to have
the potential to fish in all watersheds,
in response to SAB’s concerns regarding
potential exclusion of watersheds with
fewer than 25 individuals and (8)
evaluated the potential impact of the
uncertainty in application of the RfD to
low SES populations. The EPA
determined that due to the method used
in calculating the RfD, we have
confidence that the RfD provides
protection for low SES populations.
• Expand the sensitivity analyses
(over those included in the original risk
assessment) to address uncertainty
related to the use of the 75th percentile
fish tissue Hg value (at each watershed)
as the core risk estimate. Based on the
SAB’s recommendation, we added a
sensitivity analysis using the median
fish tissue Hg estimate (at the watershed
level). This sensitivity analysis showed
that use of the median fish tissue Hg
concentration instead of the 75th
percentile resulted in a relatively small
decrease (i.e., 10 percent) in the
estimates of watersheds with
populations potentially at-risk, and did
not substantially change the conclusions
of the risk assessment.
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C. Summary of Results of Revised Hg
Risk TSD of Risks to Populations With
High Levels of Self-Caught Fish
Consumption
Based on the recommendations we
received from the SAB, we revised the
quantitative analysis of risk to
subsistence fishing populations with
high levels of fish consumption. Our
revision to the quantitative risk results
reflects three key recommendations
from the SAB, including (1) addition of
824 watersheds based on additional fish
tissue Hg sample data we obtained from
states and the National Listing of Fish
Advisories, (2) application of a 0.95
adjustment factor to the reported fish
tissue Hg concentrations to account for
the fraction that is MeHg, and (3)
inclusion of all watersheds with fish
samples that meet the filtering criteria 34
in representing potential exposures
associated with increased risk of
neurologic health effects for female
subsistence fishing populations.
Based on these revisions, our
estimates of the number and percent of
modeled watersheds with populations
potentially at-risk from exposure to
EGU-attributable MeHg changed from
those presented in the preamble to the
proposed rule.35 For the 99th percentile
consumption scenario, the number of
watersheds with fish tissue Hg samples
where subsistence fishing populations
may be at-risk from exposure to EGUattributable MeHg increased from 672 to
917 (an increase of 36 percent). For this
same scenario, the total percent of
modeled watersheds with populations
potentially at-risk from either risk
metric (i.e., MeHg exposure from U.S.
EGUs alone exceeds the RfD or total
MeHg exposure exceeds the RfD and
U.S. EGUs contribute at least 5 percent)
increased from 28 percent estimated at
proposal to 29 percent after addressing
SAB recommendations. The increase in
34 The watersheds were filtered to exclude
watersheds that: (a) Were not freshwater, (b) did not
have fish sampling data since 2000, (c) did not have
fish larger than 7 inches in length, (d) contained
active gold mines or (e) had substantial non-air Hg
loading.
35 Since the time of the analyses conducted in
support of the proposed rule, the EPA updated IPM
modeling to reflect the most recently available
information, including public comments and the
final CSAPR (see IPM Documentation for further
details on these updates, which is available in the
docket). Compared to the modeling conducted at
proposal, these updates are projected to result in
greater reductions in criteria pollutants, and also to
have a slightly greater impact on U.S. EGU Hg
emissions. Based on the revised projection for 2016,
the EPA estimates that U.S. EGUs would emit 27
tons of Hg, as compared to the 29 tons we modeled
for the Hg Risk TSD. We do not expect this 2 ton
difference to substantially change the mercury risks
reported in the preamble to the proposed rule, as
this represents less than a 10 percent reduction in
Hg emissions.
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the total percent of modeled watersheds
with populations potentially at-risk
using the expanded geographic coverage
of watersheds provides additional
confidence that emissions of Hg from
U.S. EGUs pose a hazard to public
health. For the 99th percentile
consumption scenario, the percent of
modeled watersheds with populations
potentially at-risk from total potential
exposures to MeHg that exceed the RfD
and U.S. EGUs contribute at least 5
percent increased from 22 percent to 24
percent. For the 99th percentile
consumption scenario, the percent of
modeled watersheds with populations
potentially at-risk based on Hg
deposition from U.S. EGUs alone
decreased from 12 percent to 10 percent.
The additional sensitivity analyses
conducted in response to the SAB peer
review showed that the estimates of the
percent of modeled watersheds with
populations potentially at-risk are
robust to alternative assumptions about
both the watersheds included in the
analysis and the selection of the 50th
percentile or 75th percentile fish tissue
Hg level. Sensitivity analyses excluding
entire states with the potential for
historical loadings of Hg from non-air
sources 36 resulted in an increase from
29 percent to 33 percent in the total
percent of modeled watersheds with
populations potentially at-risk
exceeding either risk metric (i.e., U.S.
EGUs alone or total potential exposures
to MeHg exceed the RfD and U.S. EGUs
contribute at least 5 percent). Including
only watersheds in the top 25th
percentile of U.S. EGU deposition
resulted in an increase in the total
percent of modeled watersheds with
populations potentially at-risk
exceeding either risk metric, from 29
percent to 30 percent. Using the 50th
percentile fish tissue Hg level resulted
in a decrease in the total percent of
modeled watersheds with populations
potentially at-risk exceeding either risk
metric, from 29 percent to 26 percent.
On balance, these sensitivity analyses
do not substantially reduce the percent
of modeled watersheds with
populations potentially at-risk, and thus
confirm the finding that Hg emissions
from U.S. EGUs pose a hazard to public
health. In fact, given the broader
coverage of modeled watersheds in the
revised analysis, we have even greater
confidence in our finding that Hg
36 The SAB noted that areas with substantially
elevated fish tissue Hg levels could also be
characterized by lakes and rivers with high natural
methylation rates, and thus some of the states we
excluded for this sensitivity analysis might not have
fish tissue Hg levels that reflect non-U.S. EGU Hg
loadings.
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emissions from U.S. EGUs pose a hazard
to public health.
D. Peer Review of the Approach for
Estimating Cancer Risks Associated
With Cr and Ni Emissions in the U.S.
EGU Case Studies of Cancer and NonCancer Inhalation Risks for Non-Hg
HAP and EPA Response
As explained in the preamble to the
proposed rule, the EPA submitted for
peer review its characterization of the
chemical speciation for the emissions of
Cr and Ni used in the non-Hg HAP
inhalation risk case studies. The
remaining aspects of the non-Hg HAP
case study risk assessments used
methods that were previously peer
reviewed. Specifically, the
methodologies used to conduct the nonHg case studies are consistent with
those used to conduct inhalation risk
assessments under EPA’s Risk and
Technology Review (RTR) program.
Because the RTR assessments are
considered to be highly influential
science assessments, the methodologies
used to conduct them were subject to a
peer review by the SAB in 2009. The
SAB issued its peer review report in
May 2010.37 The report endorsed the
risk assessment methodologies used in
the program, and made a number of
technical recommendations for EPA to
consider as the RTR program evolves.
The EPA’s case studies identified Cr
and Ni emissions as the key drivers of
the estimated inhalation cancer risks for
EGUs. Because these results hinged on
specific scientific interpretations of data
used to characterize EGU emissions of
Cr and Ni, the EPA conducted a letter
peer review of its analysis and
interpretation of those data relative to
the quantification of inhalation risks
associated with Cr and Ni emissions
from U.S. EGUs. The following sections
describe the peer review process,
enumerate the peer review charge
questions presented to the peer review
panel, summarize the key
recommendations from the peer review,
and summarize our responses to those
recommendations.
1. Summary of Peer Review Process
The EPA asked three independent,
external peer reviewers representing
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37 U.S.
Environmental Protection Agency—
Science Advisory Board (U.S. EPA–SAB). 2010.
Review of EPA’s draft entitled, ‘‘Risk and
Technology Review (RTR) Risk Assessment
Methodologies: For Review by the EPA’s Science
Advisory Board with Case Studies—MACT I
Petroleum Refining Sources and Portland Cement
Manufacturing’’. EPA–SAB–10–007. May. Available
on-line at: https://yosemite.epa.gov/sab/
sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPASAB-10-007-unsigned.pdf.
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government, academic and the private
sector to review of the methods for
developing inhalation cancer risk
estimates associated with emissions of
Cr and Ni compounds from coal- and
oil-fired EGUs in support of the
appropriate and necessary finding. The
approaches and rationale for the
technical and scientific considerations
used to derive inhalation cancer risks
were summarized in the draft document
entitled, ‘‘Methods to Develop
Inhalation Cancer Risk Estimates for
Chromium and Nickel Compounds.’’
The peer reviewers received several
charge questions (three questions on Cr
and two questions on Ni, which are
provided below) on the technical and
scientific relevance of the approaches
used to develop the inhalation unit risk
estimates. The EPA also provided
information on Cr speciation profiles for
different industrial sources, as well as
information on the Ni speciation of PM
from oil-fired EGUs.
2. Peer Review Charge Questions
Below, we present the charge
questions posed to the peer reviewers to
help guide their review and
development of recommendations to
EPA on key issues relevant to the
characterization of risks from EGU
emissions containing either Cr or Ni
compounds.
The EPA asked three questions
regarding Cr and Cr compounds:
Question 1: Do EPA’s judgments
related to speciated Cr emissions
adequately take into account the
available Cr speciation data?
Question 2: Has EPA selected the
species of Cr (i.e., hexavalent Cr, Cr(VI))
that accurately represents the toxicity of
Cr and Cr compounds?
Question 3: Are the assumptions used
in past analysis scientifically defensible,
and are there alternatives that EPA
should consider for future analysis?
The EPA asked two questions
regarding Ni and Ni compounds:
Question 1: Do EPA’s judgments
related to speciated Ni emissions
adequately take into account available
speciation data, including recent
industry spectrometry studies?
Question 2: Based on the speciation
information available and on what we
know about the health effects of Ni and
Ni compounds, and taking into account
the existing Unit Risk Estimates (URE)
values (i.e., values derived for EPA’s
Integrated Risk Information System
(IRIS), California Environmental
Protection Agency (Cal EPA) and Texas
Commission on Environmental Quality
(TCEQ)), the EPA has provided several
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9317
approaches 38 to derive unit risk
estimates that may be more
scientifically defensible than those used
in past analyses. Which of the options
presented would result in more accurate
and defensible characterization of risks
from exposure to Ni and Ni compounds?
Are there alternative approaches that
EPA should consider?
3. Summary of Peer Review Findings
and Recommendations
Regarding Cr and Cr compounds, all
three reviewers considered Cr(VI) as the
species likely to be driving cancer risks
based on solid evidence from the health
effects database for Cr and Cr
compounds. All three authors also
considered EPA’s use of the average of
the range of the available speciation
data (i.e., 12 percent and 18 percent
Cr(VI) contained in coal- and oil-fired
EGUs, respectively) as a reasonable
approach for the derivation of default
speciation profiles to be used when
there is no speciation data available. All
reviewers agreed that there is high
uncertainty associated with the
variability in the speciation data
available for Cr (e.g., range of
approximately 4 to 23 percent Cr(VI)
from coal-fired units). One of the
reviewers recommended several
additional studies for EPA’s
consideration; the EPA considered these
in finalizing the report.
Regarding Ni and Ni compounds, the
reviewers agreed with the views of the
international scientific bodies, which
consider Ni compounds carcinogenic as
a group. One reviewer recommended
that the EPA review several additional
Ni speciation data that suggests that
sulfidic Ni compounds (which the
reviewer considered as the most potent
carcinogens within the group of all Ni
compounds) are present at low levels in
emissions from EGUs. In addition, this
reviewer pointed out that there is a
recently proposed model that may
explain the differences in carcinogenic
potential across Ni compounds.
4. The EPA’s Responses to Peer Review
Recommendations
We summarize EPA’s basic responses
to the peer review comments below,
first for Cr-related issues, and second for
Ni-related issues, which are reflected in
the revised document.39
38 See section 3.3 of U.S. Environmental
Protection Agency (U.S. EPA). 2011c. Methods to
Develop Inhalation Cancer Risk Estimates for
Chromium and Nickel Compounds. Office of Air
Quality Planning and Standards. October.
39 U.S. EPA, 2011c.
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a. Cr and Cr Compounds
In agreement with the peer reviewers
and based on the health effects
information available for Cr, the EPA
assigns high confidence in the
assumption that Cr(VI) is the
carcinogenic species driving the risk of
Cr-emitting facilities. In agreement with
the reviews, the EPA considers
derivation of default speciation profiles
based on the mass of Cr(VI) a reasonable
approach. As suggested by one of the
reviewers, the EPA reviewed two
potentially relevant studies, one of
which showed coal combustion
emissions containing as much as 43
percent Cr(VI),40 which suggests that the
EPA’s quantitative approach could
actually underestimate Cr(VI) inhalation
risks. However, the other study
reviewed by EPA on speciation of Cr in
coal combustion showed Cr(VI)
percentage levels close to detection
limits (i.e., 3 to 5 percent of total Cr,
which was close to the limit of detection
in this study).41 Thus, the more recent
speciation data available is unlikely to
reduce the uncertainty of the Cr
speciation analyses used by EPA as the
bases for risk characterization analysis.
In agreement with the peer reviewers,
the EPA also recognizes that the
confidence in the default speciation
profiles is low because the profiles are
based on a limited data set with a wide
range of percentages of Cr(VI) across the
different samples.
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b. Ni and Ni Compounds
Based on the views of the major
scientific bodies mentioned above and
the peer reviewers that commented on
EPA’s approaches to risk
characterization of Ni compounds, the
EPA considers all Ni compounds to be
carcinogenic as a group and the EPA
does not consider Ni speciation or Ni
solubility to be strong determinants of
Ni carcinogenicity. These scientific
bodies also recognize that based on the
data available, the precise Ni
compound(s) responsible for the
carcinogenic effects in humans is not
always clear, and that there may be
differences in the potential toxicity and
carcinogenic potential across Ni
compounds. Nevertheless, studies in
humans indicate that various mixtures
of Ni compounds (including Ni sulfate,
sulfides and oxides, alone or in
combination) encountered in the Ni
40 Galbreath KC, Zygarlicke CJ. 2004. ‘‘Formation
and chemical speciation of arsenic-, chromium-,
and nickel-bearing coal combustion PM2.5,’’ Fuel
Process Technol 85:701–726.
41 Huggins FE, Najih M, Huffman GP. 1999.
‘‘Direct speciation of chromium in coal combustion
by-products by X-ray absorption fine structure
spectroscopy,’’ Fuel Process Technol 78:233–242.
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refining industries may cause cancer in
humans, and there is no reason to
expect anything different from this for
mixtures of Ni compounds from other
emission sources. One of the reviewers
suggested we consider views by some
authors that believe that water soluble
Ni, such as Ni sulfate, should not be
considered a human carcinogen. This
view is based primarily on a negative Ni
sulfate 2-year rodent bioassay by the
National Toxicology Program (NTP)
(which is different from the positive 2year NTP bioassay for Ni
subsulfide).42 43 44 One review article
identifies the discrepancies between the
animal and human data (i.e., from
studies of cancers in workers inhaling
certain forms of Ni versus inhalation
studies suggesting different carcinogenic
potential in rodents with different Ni
compounds) and states that the
epidemiological data available clearly
support an association between Ni and
increased cancer risk, although the
article acknowledges that the data are
weakest regarding water soluble Ni. In
addition, the EPA identified a recent
review 45 that highlights the robustness
and consistency of the epidemiological
evidence across several decades
showing associations between exposure
to Ni and Ni compounds (including Ni
sulfate) and cancer.
Regarding the second charge question
on Ni compounds, two reviewers
suggested using the URE derived by the
TCEQ 46 for all Ni compounds as a
group, rather than the one derived by
the Integrated Risk Information System
(IRIS, 1991) 47 specifically for Ni
subsulfide. The third reviewer did not
comment on an alternative approach.
Considering this, to develop our
primary risk estimate, the EPA decided
42 Oller A. 2002. ‘‘Respiratory carcinogenicity
assessment of soluble nickel compounds.’’ Environ
Health Perspect. 110:841–844.
43 Heller JG, Thornhill PG, Conard BR. 2009.
‘‘New views on the hypothesis of respiratory cancer
risk from soluble nickel exposure; and
reconsideration of this risk’s historical sources in
nickel refineries.’’ J Occup Med Toxicol. 4:23.
44 Goodman JE, Prueitt RL, Thakali S, and Oller
AR. 2011. ‘‘The nickel iron bioavailability model of
the carcinogenic potential of nickel-containing
substances in the lung.’’ Crit Rev Toxicol 41:142–
174.
45 Grimsrud TK and Andersen A. ‘‘Evidence of
carcinogenicity in humans of water-soluble nickel
salts.’’ J Occup Med Toxicol. 2010. 5:1–7. Available
online at https://www.ossup-med.com/content/5/1/7.
46 Texas Commission on Environmental Quality
(TCEQ). 2011. Development Support Document for
nickel and inorganic nickel compounds. Available
online at https://www.tceq.state.tx.us/assets/public/
implementation/tox/dsd/final/june11/
nickel_&_compounds.pdf.
47 U.S. EPA, 1991. Integrated Risk Information
Service (IRIS) assessment for nickel subsulfide.
Available at: https://www.epa.gov/iris/subst/
0273.htm.
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to use a health protective approach by
applying 100 percent of the current IRIS
URE for Ni subsulfide, rather than
assuming that 65 percent of the total
mass of emitted Ni might be Ni
subsulfide, as used in previous analyses.
We used the IRIS URE value because
IRIS values are preferred given the
conceptual consistency with EPA risk
assessment guidelines and the level of
peer review that such values receive.
We used 100 percent of the IRIS value
because of the concerns about the
potential carcinogenicity of all forms of
Ni raised by the major national and
international scientific bodies, and
recommendations of the peer reviewers.
Nevertheless, taking into account that
there are potential differences in
toxicity and/or carcinogenic potential
across the different Ni compounds, and
given that two URE values have been
derived for exposure to mixtures of Ni
compounds that are two to three fold
lower than the IRIS URE for Ni
subsulfide, the EPA also considers it
reasonable to use a value that is 50
percent of the IRIS URE for Ni
subsulfide for providing an estimate of
the lower end of a plausible range of
cancer potency values for different
mixtures of Ni compounds.
Although this report focused
primarily on cancer risks associated
with emissions containing Ni
compounds, it is important to note that
comparative quantitative analyses of
non-cancer toxicity of Ni compounds
indicate that Ni sulfate is as toxic or
more toxic than Ni subsulfide or Ni
oxide which does not support the
notion that the solubility of Ni
compounds is a strong determinant of
its toxicity.48 49
E. Summary of Results of Revised U.S.
EGU Case Studies of Cancer and NonCancer Inhalation Risks for Non-Hg
HAP
Based on the results of the peer
review and public comments on the
non-Hg case study chronic inhalation
risk assessment, we made several
changes to the emissions estimates,
dispersion modeling, and risk
characterization for the modeled case
study facilities. Key changes include (1)
changes in emissions, (2) changes in
stack parameters for some facilities
based on new data received during the
48 Haber LT, Allen BC, Kimmel CA. 1998. ‘‘NonCancer Risk Assessment for Nickel Compounds:
Issues Associated with Dose-Response Modeling of
Inhalation and Oral Exposures.’’ Toxicol Sci.
43:213–229.
49 National Toxicology Program (NTP). 1996.
Technical Report Series No. 454, Toxicology and
carcinogenesis studies of nickel sulfate
hexahydrate. July. Available online at https://
ntp.niehs.nih.gov/ntp/htdocs/LT_rpts/tr454.pdf.
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public comment period, (3) use of
updated versions of AERMOD and its
input processors (AERMAP,
AERMINUTE, and AERMET), and (4)
use of 100 percent of the current IRIS
URE for Ni subsulfide to calculate Niassociated inhalation cancer risks
(rather than assuming that the Ni might
be 65 percent as potent as Ni
subsulfide).
Based on estimated actual emissions,
the highest estimated individual
lifetime cancer risk from any of the 16
case study facilities was 20 in a million,
driven by Ni emissions from the one
case study facility with oil-fired EGUs.
Of the facilities with coal-fired EGUs,
five facilities had maximum individual
cancer risks greater than one in a
million 50 (the highest was five in a
million), with the risk from four due to
emissions of Cr(VI) and the risk from
one due to emissions of Ni.51 There
were also two facilities with coal-fired
EGUs that had maximum individual
cancer risks equal to one in a million.
All of the facilities had non-cancer
Target Organ Specific Hazard Index
(TOSHI) 52 values less than one, with a
maximum TOSHI value of 0.4 (also
driven by Ni emissions from the one
case study facility with oil-fired EGUs).
Since these case studies do not cover
all facilities in the category, and since
our assessment does not include the
potential for impacts from different EGU
facilities to overlap one another (i.e.,
these case studies only look at facilities
in isolation), the maximum risk
estimates from the case studies likely
underestimates true maximum risks for
the source category.
Based on the fact that six U.S. EGUs
were estimated to meet or exceed the
CAA section 112(c)(9) criterion of one in
a million, EGUs cannot be removed
from the list of source categories to be
regulated under CAA section 112.
50 A risk level of 1 in a million implies a
likelihood that up to one person, out of one million
equally exposed people would contract cancer if
exposed continuously (24 hours per day) to the
specific concentration over 70 years (an assumed
lifetime). This would be in addition to those cancer
cases that would normally occur in an unexposed
population of one million people.
51 When the lower end of the cancer potency
range for Ni was used to develop risk estimates, 5
of the 16 facilities had maximum cancer risks
exceeding 1 in a million, and the maximum
individual cancer risk for any single facility fell to
10 in a million.
52 The target-organ-specific hazard index (TOSHI)
is a metric used to assess whether there is an
appreciable risk of deleterious (noncancer) effects to
a specific target organ due to continuous inhalation
exposures over a lifetime. If a TOSHI value is less
than or equal to one, such effects are unlikely. For
TOSHI values greater than one, there is an
increased risk of such effects.
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F. Public Comments and Responses to
the Appropriate and Necessary Finding
1. Legal Aspects of Appropriate and
Necessary Finding
a. History of Section 112(n)(1)(A)
Comment: One commenter provided a
detailed history of EPA’s regulatory
actions concerning EGUs and
implementation of CAA section
112(n)(1)(A). The same commenter
implies that the EPA’s 2000 appropriate
and necessary finding and listing of
EGUs was flawed because the Agency
did not comply with CAA section
307(d) rulemaking process. The
commenter sought review of the 2000
notice in the U.S. Court of Appeals for
the District of Columbia Circuit, which
was dismissed by the D.C. Circuit.
Utility Air Regulatory Group v. EPA, No.
01–1074 (D.C. Cir. July 26, 2001). The
commenter then characterizes at length
the 2005 EPA action that revised the
interpretation of CAA section
112(n)(1)(A) and, which the D.C. Circuit
concluded illegally removed EGUs from
the CAA section 112(c) list of sources
that must be regulated under CAA
section 112. See New Jersey v. EPA, 517
F.3d 574 (D.C. Cir. 2008). The
commenter notes that the D.C. Circuit
did not rule on the legal correctness or
the sufficiency of the factual record
supporting EPA’s 2000 listing decision
or on the factual correctness of EPA’s
later decision to reverse its CAA section
112(n)(1)(A) determination. The
commenter noted further that the D.C.
Circuit indicated that the listing
decision could be challenged when the
Agency issued the final CAA section
112(d) standards pursuant to CAA
section 112(e)(4). The commenter
concluded by asserting that the Agency
could not ignore the history associated
with the regulation of EGUs under
section 112 and that two earlier
dockets—Docket ID. No. A–92–55 and
Docket ID. No. EPA–HQ–OAR–2002–
0056—are also part of this long
rulemaking effort and must be
accounted for in conjunction with
Docket No. EPA–HQ–OAR–2009–0234
if all pertinent material and comments
are to be part of the rulemaking record.
Response: The commenter
characterizes the regulatory history of
the rule EPA proposed on May 3, 2011.
To the extent that characterization is
inconsistent with the lengthy regulatory
history EPA provided in the preamble to
the May 3, 2011 rule, we disagree. We
address several of the statements in
more detail below.
First, the commenter makes much of
the fact that the EPA did not go through
CAA section 307(d) notice and comment
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rulemaking when making the
appropriate and necessary finding and
listing decision in 2000. However, the
commenter’s complaint is without
foundation. The CAA does not require
CAA section 307(d) rulemaking for
listing decisions. In fact, CAA section
112(e)(4) specifically provides that
listing decisions may only be challenged
‘‘when the Administrator issues
emission standards for such * * *
[listed] category.’’ Second, the
commenter challenged the listing
decision in the U.S. Court of Appeals for
the District of Columbia Circuit (Court)
and, on July 26, 2001, the Court granted
EPA’s motion to dismiss that action
based on the plain language of CAA
section 112(e)(4). Moreover, in addition
to the 2000 notice, the EPA clearly
articulated its basis for listing EGUs in
this proposed rule, which is consistent
with CAA section 307(d), and the
commenter was provided an ample
opportunity to comment. Finally, the
commenter asserts that the rulemaking
docket for this action is incomplete
because the Agency did not include two
earlier dockets—Docket ID. No. A–92–
55 and Docket ID. No. EPA–HQ–OAR–
2002–0056—for the Section 112(n)
Revision Rule, 70 FR 15994 (March 29,
2005), and the reconsideration of the
Section 112(n) Revision Rule, 71 FR
33388 (June 9, 2006), respectively. The
commenter is incorrect because EPA
incorporated by reference the two
dockets at issue. See EPA–HQ–OAR–
2009–0234–3056.
Comment: One commenter stated that
the EPA has assessed the public health
risks posed by HAP emissions from
coal- and oil-fired EGUs for the last 40
years. According to the commenter,
throughout that time, the EPA has come
to a single repeated conclusion that
HAP emissions from EGUs pose little or
no risk to public health. Based on this
conclusion, the EPA has properly
chosen not to require EGUs to install
expensive, new pollution control
equipment to control HAP emissions.
The commenter asserts that, in this
proposed rule, the EPA shifts its
opinion on the health impacts of EGU
HAP emissions 180 degrees and now
seeks to impose sweeping regulatory
requirements on all power plants.
According to the commenter, the EPA’s
newfound concern about HAP
emissions from EGUs is not based on
new and different assessments of the
public health consequences of EGU
HAP emissions but instead on health
benefits from the reduction of nonhazardous air pollutants, primarily PM,
which the Agency is required to regulate
under other provisions of the CAA. One
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commenter stated that for decades, the
EPA set primary ambient air quality
standards that protect public health
with an adequate margin of safety, CAA
section 109(b)(1), and set secondary
standards that are [sic] ‘‘requisite to
protect the public welfare from any
known or anticipated adverse effects
associated with the presence of such air
pollutant in the ambient air,’’ CAA
109(b)(2). The commenter notes that
even if EPA now views those past PM
standards as inadequate, the EPA has
ongoing regulatory proceedings in
which it can address any perceived
health concerns. The commenter
concludes that regulation of EGU HAP
emissions under CAA section 112 is an
unlawful way to address those concerns.
Response: The commenter is incorrect
in its assertion that the Agency has
consistently concluded that HAP
emissions from EGUs do not present a
hazard to public health. In the 2000
finding, the Agency concluded that HAP
emissions from coal- and oil-fired EGUs
do pose a hazard to public health and
determined that it was appropriate and
necessary to regulate such units under
CAA section 112. As a result of that
finding, the EPA added coal- and oilfired EGUs to the CAA section 112(c)
list of source categories for which
emission standards are to be established
pursuant to CAA section 112(d).
Further, in support of the proposed rule,
the EPA conducted additional extensive
quantitative and qualitative analyses,
which confirm that it remains
appropriate and necessary to regulate
EGUs under CAA section 112. Among
other things, those analyses demonstrate
that emissions from coal- and oil-fired
EGUs continue to pose a hazard to
public health. The commenter also fails
to note that the EPA found that HAP
emissions from EGUs pose a hazard to
the environment as well.
The commenter seems confused about
the basis for the Agency’s appropriate
and necessary finding because it
maintains that the EPA made the
appropriate and necessary finding based
on the health co-benefits attributable to
PM reductions that will be achieved as
a result of the Agency’s regulation of
HAP emissions from EGUs. Nowhere in
the May 2011 proposal does EPA state
that it based the appropriate and
necessary finding on hazards to public
health attributable to PM emissions. The
commenter’s allegation lacks
foundation. The appropriate and
necessary finding unmistakably focuses
on the hazards to public health and
hazards to the environment associated
with HAP emissions from EGUs.
Comment: One commenter stated that
CAA section 112 required EPA to make
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a risk-based determination in order to
regulate HAP. According to the
commenter, the EPA may regulate
substances ‘‘reasonably * * *
anticipated to result in an increase in
mortality or increase in serious illness’’
to a level that protects public health
with an ‘‘ample margin of safety.’’
According to the commenter, the EPA
has regulated a number of HAP emitted
from industrial source categories other
than EGUs.
As for EGUs, according to the
commenter, the EPA found that the
combustion of fossil fuels produces
extremely small emissions of a broad
variety of substances that are present in
trace amounts in fuels and that are
removed from the gas stream by control
equipment installed to satisfy other
CAA requirements. The commenter
stated that the EPA, in past reviews,
found that these HAP emissions did not
pose hazards to public health. See 48 FR
15076, 15085 (1983) (radionuclides). the
commenter further stated that ‘‘[i]n the
case of Hg specifically, the EPA found
that ‘‘coal-fired power plants * * * do
not emit mercury in such quantities that
they are likely to cause ambient mercury
concentration to exceed’’ a level that
‘‘will protect public health with an
ample margin of safety.’’ 40 FR 48297–
98 (October 19, 1975) (Hg); 52 FR 8724,
8725 (March. 19, 1987) (reaffirming Hg
conclusion).
According to the commenter, in the
late 1980s, the EPA was concerned that
its prior risk assessments of individual
HAP emissions from fossil-fuel-fired
power plants may not reflect the total
risks posed by all HAP emitted by those
sources. The commenter states that the
EPA modeled the risks posed by all
HAP emitted by power plants (very
much like the analyses the Agency
would conduct for the Utility Study ten
years later). The commenter asserts that
the modeling again failed to identify
threats to public health that warranted
regulation under an ‘‘ample margin of
safety’’ test.
Response: The commenter’s
statements concerning the pre-1990
CAA are not relevant to the current
action. Congress enacted CAA section
112(n)(1) as part of the 1990
amendments to the Act. That provision
requires, among other things, that the
Agency evaluate the hazards to public
health posed by HAP emissions from
fossil-fuel fired EGUs. Had Congress
concluded, as commenter appears to
assert, that HAP emissions from EGUs
did not pose a hazard to public health
or the environment, it defies reason that
Congress would have required EPA to
conduct the three studies at issue in
CAA section 112(n)(1) (titled ‘‘Electric
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utility steam generating units’’) and
regulate EGUs under section 112 if the
Administrator determined in her
discretion that it was appropriate and
necessary to do so. The Agency
complied with the statutory mandates in
CAA section 112(n)(1) in conducting the
studies and reasonably exercised its
discretion in making the appropriate
and necessary finding.
We acknowledge that Congress treated
radionuclide emissions from EGUs
differently. For radionuclides from
EGUs (and certain other sources),
Congress included CAA section
112(q)(3), which authorizes but does not
require the Agency to maintain the
regulations of radionuclides in effect
prior to the 1990 amendments. The fact
that Congress made an exception for
radionuclides and no other HAP from
EGUs further demonstrates that the
HAP-related actions EPA took with
regard to EGUs prior to the 1990
amendments to the CAA are not
germane.
As for the commenter’s statements
about Hg emissions from EGUs, we find
their conclusions wholly inconsistent
with CAA section 112(n)(1). That
provision is titled ‘‘Electric utility steam
generating units,’’ and it directs EPA to
conduct two Hg-specific studies. See
CAA sections 112(n)(1)(B) and
112(n)(1)(C). The commenter’s
suggestion that the EPA could or should
rely on assessments of Hg from EGUs
conducted prior to the 1990
amendments is not tenable.
Finally, the commenter stated that the
EPA conducted a risk assessment of all
HAP from EGUs prior to the 1990
amendments and that the Agency did
not identify any HAP that failed the
‘‘ample margin of safety’’ test. The
commenter did not cite the study or
provide any information to support the
statements so we are unable to respond
to the alleged study directly; however,
the risk assessments conducted in
support of the appropriate and
necessary finding, as well as the 2000
finding, demonstrate that HAP
emissions from EGUs pose hazards to
public health and the environment.
b. Interpretation of ‘‘Appropriate’’ and
‘‘Necessary’’
Comment: One commenter stated that
in the preamble to the proposed rule,
the EPA sets out its ‘‘interpretation of
the critical terms in CAA section
112(n)(1),’’ arguing that this latest
interpretation is ‘‘wholly consistent
with the CAA’’ and with the Agency’s
earlier ‘‘2000 finding.’’ See 76 FR 24976,
24986 (May 3, 2011). The commenter
stated that throughout the proposal EPA
tries to suggest that it is returning to
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some earlier, ‘‘correct’’ interpretation of
CAA section 112(n)(1) set forth in its
2000 action. See, e.g., 76 FR 24989
(‘‘The Agency’s interpretation of the
term ‘appropriate’ * * * is wholly
consistent with the Agency’s
appropriate finding in 2000’’); id. at
24992 (‘‘Our interpretation of the
necessary finding is reasonable and
consistent with the 2000 finding’’).
According to the commenter, the EPA
did not provide in 2000 any
interpretation of what it now
characterizes as the ‘‘critical terms’’ of
section 112(n)(1). See, e.g., 70 FR 15999
n.13 (the ‘‘2000 finding does not
provide an interpretation of the phrase
‘after imposition of the requirements of
the Act’ ’’); id. at 16000/2 (in 2000, the
EPA ‘‘did not provide an interpretation
of the term ‘appropriate’ ’’); 76 FR 24992
(the ‘‘Agency did not expressly interpret
the term necessary in the 2000
finding’’). The commenter believes that
for that reason alone, it is impossible to
credit EPA’s assertion that it
‘‘appropriately concluded that it was
appropriate and necessary to regulate
hazardous air pollutants * * * from
EGUs’’ in 2000, and that it is today
merely ‘‘confirm[ing] that finding and
conclud[ing] that it remains appropriate
and necessary to regulate these
emissions.* * *’’ 53
Response: The commenter disagrees
with certain statements in the preamble
to the proposed rule that provide that
the Agency’s interpretation of CAA
section 112(n)(1) is reasonable and
consistent with the 2000 finding. It is
difficult to decipher the exact complaint
that the commenter has with EPA’s
proposed rule in this regard, but the
commenter does assert that ‘‘the Agency
did not provide in 2000 any
interpretation of what it now
characterizes as the ‘‘critical terms’’ of
CAA section 112(n)(1).’’ The
commenter’s assertion lacks foundation.
Although the 2000 finding did not
provide detailed interpretations of the
regulatory terms at issue, it discussed
the types of considerations relevant to
the appropriate and necessary inquiry.
For example, it is clear that in 2000, the
Agency was concerned with the then
current hazards to public health and the
environment when assessing whether it
was appropriate to regulate EGUs under
section 112.54 In addition, when
evaluating whether it was necessary to
regulate utilities, the Agency stated that
it was necessary to regulate HAP
emissions from U.S. EGUs under section
112 because the implementation of the
other requirements of the Act would not
53 Id.
54 65
at 24,977/3.
FR 79830.
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adequately address the serious public
health and environmental hazards
arising from HAP emissions from EGUs.
The Agency also specifically noted that
‘‘section 112 is the authority intended to
address’’ hazards to public health and
the environment posed by HAP
emissions. Id.
The detailed interpretation set forth in
the preamble to the proposed rule is
consistent with the 2000 finding, but
EPA does not assert that the
interpretation is in any way necessary to
support the factual conclusions reached
in the 2000 finding. Instead, we noted
in the preamble to the proposed rule
that our interpretation is consistent with
the 2000 finding because in 2005 we
interpreted the statute in a manner that
was not consistent with the 2000
finding. The commenter has provided
no legal support for its position that the
Agency erred in interpreting the statute
in a manner that is consistent with a
prior factual finding.
Comment: Several commenters assert
that in the 1990 amendments to the
Clean Air Act, Congress directed the
EPA to base its determination regarding
regulation of fossil-fuel-fired generating
units on consideration of any adverse
public health effects identified in the
study mandated by the first sentence of
section 112(n)(1)(A) and that Congress
did not dictate in section 112(n)(1)(A)
that the EPA must regulate electric
utility steam generating units under
section 112.
According to the commenters the
sponsor of the House bill that became
section 112(n)(1)(A) provides an
explanation that contradicts the EPA’s
approach to regulating EGUs:
Pursuant to section 112(n), the
Administrator may regulate fossil fuel fired
electric utility steam generating units only if
the studies described in section 112(n)
clearly establish that emissions of any
pollutant, or aggregate of pollutants, from
such units cause a significant risk of serious
adverse effects on the public health. Thus,
* * * he may regulate only those units that
he determines—after taking into account
compliance with all provisions of the act and
any other Federal, State, or local regulation
and voluntary emission reductions—have
been demonstrated to cause a significant
threat of serious adverse effects on the public
health.
136 Cong. Rec. H12,934 (daily ed. Oct.
26, 1990) (statement of Rep. Michael
Oxley).
The commenters stated that the EPA
position is premised on the assumption
that ‘‘regulation under section 112’’
necessarily means ‘‘regulation under
112(d)’’ and falsely premised on the
assumption that source categories listed
by operation of section 112(n)(1)(A)
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cannot be regulated differently. The
commenters conclude that the language
of section 112(n)(1)(a) reflects Congress’
intent that ‘‘regulation of HAP from
EGUs was not intended to operate under
section 112(d) but was instead intended
to be tailored to the findings of the
utility study mandated by section
112(n)(1)(A).’’
Response: The commenters maintain
that the Agency’s interpretation of CAA
section 112(n)(1) is flawed in many
respects. The primary support for one
commenter’s arguments against EPA’s
interpretation, including in the
comment above, is legislative history in
the form of statements from one
Congressman, Representative Oxley.
The Supreme Court has repeatedly
stated that the statements of one
legislator alone should not be given
much weight. See Brock v. Pierce
County, 476 U.S. 253, 263 (1986)
(finding that ‘‘statements by individual
legislators should not be given
controlling effect, but when they are
consistent with the statutory language
and other legislative history, they
provide evidence of Congress’ intent.’’)
(emphasis added) (citation omitted);
Garcia, et al., v. U.S., 469 U.S. 70, 78
(1984), citing Zuber v. Allen, 396 U.S.
168, 187 (1969) (reiterating its prior
findings, the Court indicated that
isolated statements ‘‘are ‘not impressive
legislative history.’ ’’); Weinberger, et al.,
v. Rossi et al., 456 U.S. 25, 35 (declining
to make a ruling based on ‘‘one isolated
remark by a single Senator’’); Consumer
Product Safety Comm., et al. v. GTE
Sylvania, Inc., et al., 447 U.S. 102, 117–
118 (1980) (declining to give much
weight to isolated remarks of one
Representative); Chrysler Corp. v.
Brown, et al., 441 U.S. 281, 311 (1979)
(finding that ‘‘[t]he remarks of a single
legislator, even the sponsor, are not
controlling in analyzing legislative
history.’’); Zuber, 396 U.S. at 186
(concluding that ‘‘[f]loor debates reflect
at best the understanding of individual
Congressmen.’’); and U.S. v. O’Brien,
391 U.S. 367, 384 (1968) (in evaluating
the statements of a handful of
Congressmen, the Court concluded that
‘‘[w]hat motivates one legislator to make
a speech about a statute is not
necessarily what motivates scores of
others to enact it. * * *.’’). As these
cases show, the Supreme Court does not
give weight to the statements of an
individual legislator, except when the
statements are supported by other
legislative history and the clear intent of
the statute. The commenters cited no
case law that would support reliance on
such limited legislative history.
The commenter has not cited any
other legislative history to support
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Representative Oxley’s statement, and
the lack of additional support makes the
statement of little utility or import
under the case law. In fact, there does
not appear to be anything in the House,
Senate, or Committee Reports that
supports Oxley’s statement. The lack of
support for Oxley’s statement in the
Committee Report is particularly telling
since, as the commenter notes, the
House and Senate bills required
different approaches to regulating EGUs
under section 112, with the Senate bill
requiring EGUs be regulated prior to the
Utility Study. In fact, legislative
statements from Senator Durenberger, a
supporter of the Senate version,
demonstrate that others would almost
certainly not have agreed with Oxley’s
interpretation. For example, Senator
Durenberger stated, ‘‘It seems to me
inequitable to impose a regulatory
regime on every industry in America
and then exempt one category,
especially a category like power plants
which are a significant part of the air
toxics problem.’’
Senator Durenberger discussed the
negotiations with the Administration
and the industry push to avoid
regulation, including industry
arguments for not regulating Hg from
U.S. EGUs:
The utility industry continued to
adamantly oppose [regulation under section
112]. First, they argued that mercury isn’t
much of an environmental problem. But as
the evidence mounted over the summer and
it became clear that mercury is a substantial
threat to the health of our lakes, rivers and
estuaries and that power plants are among
the principal culprits, they changed their
tactic. Now they are arguing that mercury is
a global problem so severe that just cleaning
up U.S. power plants won’t make enough of
a difference to be worth it. They’ve gone from
‘we’re not a problem’ to ‘you can’t regulate
us until you address the whole global
problem.’ Recasting an issue that way is not
new around here. So, it is not a surprise. But
it does suggest the direction in which this
debate will be heading in the next few years.
136 Cong. Rec. 36062 (October 27,
1990).
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Senator Durenberger also explained
why the House version was adopted:
Given that a resolution of the difficult
issues in the conference were necessary to
conclude work on this bill, the Senate
proposed to recede to the House provision
which was taken from the original
administration bill. It provides for a 3-year
study of utility emissions followed by
regulation to the extent that the
Administrator finds them necessary.
Id.
Senator Durenberger’s statements
indicate that it is unlikely that he would
agree with Oxley’s interpretation of
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CAA section 112(n)(1), a provision that
provides the Agency with considerable
discretion, and nothing indicates that
others in the Senate (or for that matter
anyone else in the House) would agree
with that interpretation. Given the
Supreme Court’s views on the use of
such limited legislative history, the EPA
reasonably declined to consider (or even
discuss) the legislative history in the
preamble to the proposed rule and we
believe it would be improper to ascribe
Representative Oxley’s statements to the
entire Congress.
Moreover, Representative Oxley’s
statement directly conflicts with the
statutory text. Representative Oxley
stated that ‘‘[the Administrator may
regulate only those units that he
determines—after taking into account
compliance with all provisions of the
act and any other Federal, State, or
local regulation and voluntary emission
reductions—have been demonstrated to
cause a significant threat of serious
adverse effects on the public health.’’
136 Cong. Rec. H12934 (daily ed. Oct.
26, 1990), reprinted in 1 1990 Legis.
Hist. at 1416–17 (emphasis added).
However, the Utility Study required
under CAA section 112(n)(1)(A) directs
the Agency to consider the hazards to
public health reasonably anticipated to
occur after ‘‘imposition of the
requirements of [the Clean Air Act].’’
EPA was not required to consider state
or local regulations or voluntary
emission reduction programs in the
Utility Study, and that study is the only
condition precedent to making the
appropriate and necessary finding.55
The legislative history the
commenters rely on is not controlling.
The Agency believes that it has
reasonably interpreted section
112(n)(1)(A), for all the reasons
described herein and in the proposal.
The commenters also cite
Representative Oxley’s statements as
support for alternative interpretations of
CAA section 112(n)(1). We believe that
any arguments that rely on such limited
legislative history are without merit.
Comment: One commenter stated that
the EPA does acknowledge that, in
many significant respects, its new
interpretation of CAA section 112(n)(1)
‘‘differs from that set forth’’ in the
Agency’s 2005 rulemaking, but argues
55 In addition, the EPA only considered CAA
requirements in the Utility Study and this was the
correct approach because Congress knew how to
require consideration of non-Federal requirements
when directing EPA to conduct a study or
assessment. See CAA section 112(n)(5) (Congress
required EPA to conduct an assessment of hydrogen
sulfide from oil and gas extraction activities and
provided that the assessment ‘‘shall include review
of existing State and industry control standards,
techniques and enforcement.’’).
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that its change of position is
permissible. See 76 FR 24988/1 (‘‘[T]o
the extent our interpretation differs from
that set forth in the 2005 Action, we
explain the basis for that difference and
why the interpretation, as set forth in
this preamble, is reasonable.’’). In
support, commenters note that the EPA
cites National Cable &
Telecommunication Ass’n v. Brand X
Internet Services, 545 U.S. 967 (2005).
The commenters agree that it is true
that, in Brand X Internet Services, the
Supreme Court explained that, if an
agency ‘‘adequately explains the reasons
for a reversal of policy,’’ such change is
‘‘not invalidating,’’ since the ‘‘whole
point of Chevron is to leave the
discretion provided by the ambiguities
of a statute with the implementing
agency.’’ 545 U.S. at 981 (internal
quotations omitted). The commenters
maintain that all Brand X Internet
Services was saying is that ‘‘[a]gency
inconsistency is not a basis for declining
to analyze the agency’s interpretation
under the Chevron framework.’’ Id.
According to the commenter, it is not
enough that the EPA has purported to
‘‘explain’’ why it has abandoned the
interpretation of CAA section 112(n)(1)
adopted in 2005. The commenter states
that under the first step of Chevron, the
Agency’s latest interpretation must still
be consistent with congressional intent.
See Chevron v. NRDC, 467 U.S. at 842–
43. The commenters state that under the
second step of Chevron, if there is
discretion for EPA to exercise in
interpreting the ‘‘critical terms’’ of CAA
section 112(n)(1), the Agency must
properly define the range of that
discretion and then act reasonably in
exercising that discretion. See Chevron,
467 U.S. at 843; see also Village of
Barrington, Ill. v. Surface
Transportation Bd., No. 09–1002 (D.C.
Cir. Mar. 15, 2011).The commenters
allege that the EPA failed to properly
define and exercise the scope of its
discretion. In each instance, the
commenter maintains that the Agency
has departed from the correct
interpretation of CAA section 112(n)(1)
that it adopted in 2005, seizing instead
upon a new approach that is contrary to
the plain language of the CAA itself, as
interpreted after considering the
statements of Representative Oxley.
Response: The commenter appears to
argue that the EPA’s interpretation of
CAA section 112(n)(1) is not consistent
with the plain language of the statute,
implying that the statute is clear and
must be evaluated under step one of
Chevron. See Chevron v. NRDC, 467
U.S. 837 842–42 (1984) (finding that
when the legislative intent is clear no
additional analysis is required).
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However, as noted above, much of the
commenter’s argument that the plain
language of the statute precludes EPA’s
interpretation is based on the
unpersuasive legislative history
discussed above. As explained in the
preamble to the proposed rule, the
statute directs the Agency to determine
whether it is appropriate and necessary
to regulate EGUs under section 112. As
the D.C. Circuit has held, the terms
‘‘appropriate’’ and ‘‘necessary’’ are very
broad terms. Because these terms are
broad they are susceptible to different
interpretations. We believe we have
reasonably interpreted the appropriate
and necessary language in section
112(n)(1)(A). To the extent that
interpretation differs from the one set
forth in 2005, we have fully explained
the basis for such changes. See 76 FR
24986–24993 (setting forth the Agency’s
interpretation of section 112(n)(1)).
Furthermore, we properly considered
the scope of our discretion in
interpreting the statute as explained in
detail in the preamble to the proposed
rule. We believe the interpretation set
forth in the preamble to the proposed
rule is consistent with the Act and,
therefore, the Agency should be
afforded deference pursuant to National
Cable & Telecommunication Ass’n v.
Brand X Internet Services, 545 U.S. 967
(2005).
Comment: A number of commenters
agreed with the Agency’s interpretation
of section 112(n)(1) and the terms
appropriate and necessary. The
commenters also agreed that the EPA’s
interpretation of that provision was
reasonable and consistent with the
statute.
Response: We agree with the
commenters and appreciate their
support.
Comment: One commenter asserts
that the EPA’s ultimate motivation for
rejecting its prior interpretation of CAA
section 112(n)(1) and embracing this
flawed new approach is made clear from
the very outset of the proposal.
According to the commenter, the EPA
touts the fact that ‘‘one consequence’’ of
the MACT rule would be that the
‘‘market for electricity in the U.S. will
be more level’’ and ‘‘no longer skewed
in favor of the higher polluting units
that were exempted from the CAA at its
inception on Congress’ assumption that
their useful life was near an end.’’ See
76 FR 24979/2. The MACT rule would
‘‘require companies to make a
decision—control HAP emissions from
virtually uncontrolled sources’’ or else
‘‘retire these sometimes 60 year old
units and shift their emphasis to more
efficient, cleaner modern methods of
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generation, including modern coal-fired
generation.’’ Id.
The commenter stated that this
remarkably forthright statement
establishes that the underlying basis for
EPA’s proposal to regulate EGUs under
CAA section 112 is not to address any
‘‘hazards to public health’’ that might be
attributed to the emission by EGUs of
HAP listed under CAA section 112(b).
Rather, according to commenter, the
EPA is utilizing the regulation of EGUs
under CAA section 112 as a means to an
entirely different end: To force the
imposition of controls that will also
have the result of reducing non-HAP
emissions (primarily PM) or force the
shutdown of those units for which the
cost of such controls would be
prohibitive. At the same time, according
to commenter, the EPA tacitly
acknowledges that it cannot hope to
make out a case that the regulation of
EGU HAP emissions is ‘‘appropriate and
necessary’’ within the meaning of CAA
section 112(n)(1). The commenter
asserts that the only HAP whose healthrelated benefits EPA quantifies is Hg.
Elsewhere, the commenter stated that
the EPA contends there are ‘‘additional
health and environmental effects’’
attributable to HAP other than Hg, but
admits that it has ‘‘not quantified’’ those
risks due supposedly to ‘‘insufficient
information.’’ See 76 FR 24999/2. With
respect to Hg the commenter stated that
the benefits are so questionable and
miniscule, some $4 million to $6
million (given a 3 percent discount
rate), that compared to the total social
costs of the rule (i.e., nearly $11 billion)
the rule cannot be justified were EPA
properly to interpret CAA section
112(n)(1) and undertake the sort of
regulatory analysis Congress intended.
The commenter stated that the reason
that the EPA touts in this rulemaking
the health benefits EPA attributes to the
reduction of non-hazardous air
pollutants (again, primarily PM), the
regulation of which is authorized under
provisions of the CAA apart from CAA
section 112, is to elide the inconvenient
truth regarding the truly trivial nature of
the benefits attributable to HAP
regulation itself. The commenter
concludes that the EPA distorts CAA
section 112(n)(1)(A) ‘‘beyond all
recognition.’’
One commenter stated that the EPA is
directed by CAA section 112(n)(1)(A) to
study the ‘‘hazards to public health
anticipated to occur as a result of
emissions’’ by EGUs of ‘‘pollutants
listed under subsection (b) of this
section’’—i.e., HAP and HAP alone.
Thereafter, the EPA is authorized to
regulate EGU HAP emissions if, and
only if, they determine that ‘‘such
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regulation’’ of HAP emissions is
‘‘appropriate and necessary’’ to address
the ‘‘hazards to public health’’ that may
be attributable to HAP emissions.
According to the commenter, by
contrast, in this rulemaking, the EPA
has seized upon the fact that the control
of EGU HAP emissions will also control
non-HAP (such as PM), and then seeks
to justify the regulation of HAP
emissions based almost entirely on the
health benefits of the reductions in nonHAP emissions that would be
coincidentally achieved. The
commenter believes that this
‘‘regulatory sleight-of-hand’’ runs afoul
of congressional intent and is unlawful.
Response: The commenter alleges that
the health-related benefits to regulating
HAP emissions from EGUs are
‘‘questionable and miniscule,’’ and that
the only real benefits stem from nonHAP emissions, such as PM. The
commenter also implies that regulation
of HAP is nothing more than a straw
man and that the Agency’s ultimate goal
is to regulate other pollutants, and
specifically PM. These allegations are
wholly without merit. The Agency has
conducted comprehensive technical
analyses that confirm that HAP
emissions from EGUs pose a hazard to
public health. The analyses are
discussed at length elsewhere in this
final rule, and a review of the proposed
and final rules utterly refutes
commenter’s assertion that PM
reductions form the basis for the
appropriate and necessary finding. In
addition, the commenter appears to
ignore the Agency’s findings concerning
the hazards to public health and the
environment posed by HAP emissions
simply because the Agency is not able
to quantify many of the benefits
associated with reductions of HAP
emissions from EGUs or because the
estimated HAP benefits that are
quantified are small in relation to the
co-benefits achieved through reductions
in non-HAP air pollutants, such as PM
and SO2, which are surrogates for
certain HAP. The Agency is regulating
EGUs pursuant to section 112(d) for all
of the reasons explained in the preamble
and discussed elsewhere in this
response to comments. The commenter
fails to recognize that the statute neither
requires a cost-benefit analysis prior to
finding it appropriate and necessary to
regulate EGUs, nor requires such
analysis prior to setting emission
standards. Indeed, Congress expressly
precluded consideration of costs when
setting MACT floors. As explained
below, the EPA does not believe that it
is appropriate to consider costs when
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determining whether to regulate EGUs
under CAA section 112.
Comment: One commenter stated that
the EPA has ignored the language and
intent of CAA section 112(n)(1)(A), as
interpreted based on Representative
Oxley’s statements, and that the
Agency’s interpretation of this provision
violates step one of Chevron. Under
Chevron where the ‘‘intent of Congress
is clear,’’ that is the ‘‘end of the matter,’’
for both the implementing agency and a
reviewing court ‘‘must give effect to the
unambiguously expressed intent of
Congress.’’ Chevron, 467 U.S. at 842–43.
The commenter asserts that the
legislative history of CAA section
112(n)(1)(A) ‘‘sheds considerable light
on Congress’ unique approach to
regulation of EGUs under CAA § 112.’’
According to the commenter, on April 3,
1990, the Senate passed S. 1630. The
Senate bill would have required EPA to
list EGUs under CAA section 112(c) and
to regulate them under the MACT
provisions of CAA section 112(d). See S.
1630 section 301, 3 1990 Legis. Hist. at
4407. Thereafter, the House of
Representatives passed a modified
version of S. 1630 on May 23, 1990.
This House version substantially
changed the provisions of CAA section
112 as they applied to EGUs. See 1 1990
Legis. Hist. at 572–73. The House
version was virtually identical to the
current CAA section 112(n)(1)(A), and
was ultimately adopted by the
conference committee, enacted by
Congress and signed into law.
According to the commenter, Congress
expressly rejected the ‘‘list-under-(c)and-regulate-under-(d)’’ approach that
S. 1630 would have applied to EGUs,
and that Congress did choose to apply
to other source categories. The
commenter stated that the EPA’s
interpretation that the Agency is
‘‘required to establish emission
standards for EGUs consistent with the
requirements set forth in section 112(d)’’
(Id. at 24,993/3) fails to take the
legislative history into account, and in
a footnote, the commenter states that the
Agency erred by not addressing the
legislative history as it did in the 2005
action.
Response: For the reasons stated
above, we believe commenter’s reliance
on the single statement of one legislator
is flawed. In addition, in a footnote the
commenter stated that the EPA
recognized ‘‘that it had to address’’ the
legislative history in its 2005 action, and
that the EPA erred in this case because
we did not address the legislative
history. The commenter cites no case
law to support its contention that an
Agency must ‘‘address’’ unpersuasive
legislative history. Further, in the 2005
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action, the EPA relegated to a footnote
the Oxley statement that commenter
relies on so heavily even though the
statement supported the interpretation
we provided in that rule. We recognized
then what the commenter fails to
recognize now, which is that the Agency
cannot argue that the meaning of CAA
section 112(n)(1)(A) is clear based on
the statements of one legislator.
Furthermore, the Agency’s
interpretation does not violate Chevron
Step 1. The terms ‘‘appropriate’’ and
‘‘necessary’’ are ambiguous. The
statements of a lone legislator do not
transform those ambiguous words into a
Chevron Step 1 situation.
Moreover, the commenter’s assertion
that Congress unambiguously defined
the factors to consider in making the
appropriate determination is without
merit. We fully explain in the preamble
to the proposed rule the basis for the
Agency’s interpretation, and we are not
revising that interpretation based on the
comments received.
Finally, the EPA notes that the
sentence concerning regulation under
CAA section 112(d) that the commenter
quotes from the preamble states, in full:
‘‘Congress did not exempt EGUs from
the other requirements of section 112
and, once listed, the EPA is required to
establish emission standards for EGUs
consistent with the requirements set
forth in section 112(d), as described
above.’’ 76 FR 24993 (emphasis added).
The EPA discusses requirements to
regulate section 112(c) listed sources
under section 112(d) in response to
other comments.
c. Consideration of Both Environmental
Effects and Health Effects From Other
Sources
Comment: Several commenters stated
that the EPA acts contrary to
congressional intent when the Agency
considers itself ‘‘thereby authorized to
consider ‘environmental effects’ and the
effects of HAP emissions from non-EGU
sources, in making its ‘appropriate and
necessary’ finding under subparagraph
(n)(1)(A).’’
Commenters assert that the EPA
misreads CAA section 112(n)(1)(B) and
(C) to inject environmental effects in the
CAA section 112(n)(1)(A)
determination. According to one
commenter the plain language of CAA
section 112(n)(1) establishes that
regulation of EGUs is to be predicated
solely on ‘‘hazards to public health’’
attributable to HAP emissions. The
legislative history providing that the
EPA ‘‘may regulate [EGUs] only if the
studies described in section 112(n)
clearly establish that emissions of any
pollutant * * * from such units cause
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a significant risk of serious adverse risk
to the public health’’ confirms that plain
language. See Oxley Statement at 1416–
17. The commenter further stated that
nothing on the face of CAA section
112(n)(1)(A) indicates that Congress
intended that the EPA should (or must)
take into account any additional
information that might be developed
through the other studies mentioned in
subparagraphs (n)(1)(B) and (C) (i.e., the
Mercury Study 56 and the NAS
Study 57), such as HAP emissions from
non-EGU sources. The commenter also
identified other provisions of section
112 that specifically require
consideration of environmental effects
and states that Congress would have
requires such consideration in CAA
section 112(n)(1) if it had wanted EPA
to consider environmental effects.
The commenter makes a related
assertion that the EPA acts contrary to
congressional intent by assuming
authority to assess the ‘‘‘hazard to
public health or the environment [from]
HAP emissions from EGUs alone’ or the
‘result of HAP emissions from EGUs in
conjunction with HAP emissions from
other sources’’’ (citing 76 FR at 24,988/
1). According to the commenter, the
only evident basis for the Agency’s
interpretation that, in making its
‘‘appropriate and necessary’’ finding,
the EPA can (and should) take into
account HAP emissions from sources
other than EGUs, is that the Mercury
Study authorized by CAA 112(n)(1)(B)
references ‘‘mercury emissions from
* * * municipal waste combustion
units, and other sources, including area
sources,’’ in addition to EGUs. The
commenter asserts, however, that
subparagraph (n)(1)(A) identifies the
Utility Study as the sole study to inform
EPA’s ‘‘appropriate and necessary’’
finding. The commenter states that if
Congress had intended that the EPA
take into account information developed
through the Mercury Study, Congress
‘‘would not have specified that the EPA
was to predicate its ‘appropriate and
necessary’ finding on the ‘results of the
study required by this subparagraph’
(n)(1)(A).’’
Commenter also cites to a number of
other section 112 provisions that
expressly address environmental effects
and the commenter states the only
conclusion to draw from the inclusion
in those provisions and the absence of
such language in section 112(n)(1)(A) is
that Congress intended public health to
be the only basis for the appropriate and
necessary finding.
56 U.S. EPA. 1997. Mercury Study Report to
Congress. EPA–452/R–97–003. December.
57 NAS, 2000.
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Response: The commenter again relies
in part on the statements of one
legislator to attack EPA’s reasoned
interpretation of an ambiguous statute.
To the extent the commenter’s
arguments rely on this limited evidence,
we refer to the response above. As we
stated above, CAA section 112(n)(1) is
an ambiguous statutory provision; thus,
the EPA’s interpretation, not
commenter’s, is entitled to considerable
deference if it is a reasonable reading of
the statute. Chevron, 467 U.S. at 843–44.
For the reasons described herein and in
the proposal, we believe that we have
reasonably interpreted the statutory
terms at issue here. The Agency directs
attention to section III.A. of the
proposed rule, which includes a
thorough discussion of the Agency’s
interpretation of the relevant statutory
terms. To the extent the commenters
disagree with EPA’s interpretations, the
EPA refers back to its discussion in the
proposal and responds to the comments
as follows.
The commenter appears to maintain
that the EPA must interpret the scope of
the appropriate and necessary finding
solely in the context of the CAA section
112(n)(1)(A) Utility Study, such that
only hazards to public health and only
EGU HAP emissions may be considered.
The commenter incorrectly conflates the
requirements for the Utility Study with
the requirement to regulate EGUs under
CAA section 112 if EPA determines it is
appropriate and necessary to do so. The
commenter concedes that the Agency
may consider information other than
that contained in the Utility Study, but
only to the extent it relates specifically
to hazards to public health directly
attributable to HAP emissions from
EGUs. We agree that we may consider
additional information other than that
contained in the Utility Study, as we
stated in the preamble to the proposed
rule, because courts do not interpret
phrases like ‘‘after considering the
results of’’ in a manner that precludes
the consideration of other information.
See United States v. United
Technologies Corp., 985 F.2d 1148, 1158
(2nd Cir. 1993) (‘‘based upon’’ does not
mean ‘‘solely); 58 see also 76 FR 24988.
We further explained in the preamble to
the proposed rule that it was reasonable
to interpret the scope of the appropriate
58 Several commenters have taken issue with our
citation to United States v. United Technologies
Corp. because the language at issue in that case was
‘‘based upon’’ and the language of section
112(n)(1)(A) is ‘‘after considering the results of.’’
We believe that, if anything, ‘‘based upon’’ is more
prescriptive than ‘‘after considering the results of’’
such that the case supports the Agency’s
interpretation that additional information other
than the Utility Study may be considered in making
the appropriate and necessary finding.
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and necessary finding in the context of
all three studies required under CAA
section 112(n)(1) because the provision
is title ‘‘Electric utility steam generating
units.’’ 59 The commenter has provided
little more than unpersuasive legislative
history to support its restrictive
interpretation of our authority. Id.
The commenter also argues that the
statute clearly prohibits the Agency
from considering adverse environmental
effects or the cumulative effects of HAP
emissions from EGUs and other sources
based on its claim that the statute is
clear when one properly considers the
legislative history. Again, the
commenter has provided no support for
its contention other than the statements
of one Representative and the improper
conflation of the CAA section
112(n)(1)(A) direction on the conduct of
the Utility Study and the appropriate
and necessary finding. Congress left it to
the Agency to determine whether it is
appropriate and necessary to regulate
EGUs under CAA section 112 and the
statute does not limit the Agency to
considering only hazards to public
health and only harms directly and
solely attributable to EGUs.
The commenter stated that Congress
specifically told EPA when it wanted
EPA to consider adverse environmental
effects in CAA section 112 and cites to
several provisions of the Act that
require consideration of adverse
environmental effects. The commenter
ignores CAA section 112(n)(1)(B), which
directs the Agency to consider adverse
environmental effect. In any event, even
were we to view section 112(n)(1)(A) in
isolation, as the commenter suggests, we
still maintain that we can consider
adverse environmental effects under
112(n)(1)(A). Nothing in section
112(n)(1)(A) precludes consideration of
environmental effects. Congress
required the Agency to assess whether
it is appropriate and necessary to
regulate EGUs under section 112. We
believe that adverse environmental
effects can be considered in the
appropriate analysis. Congress
specifically directed the Agency to
consider adverse environmental effects
when delisting source categories
pursuant to section 112(c)(9), and thus
we believe it is reasonable to consider
such effects when determining whether
it is appropriate to regulate such units
under section 112, especially given that
Congress did not limit our appropriate
and necessary inquiry to the Utility
Study. See CAA section 112(c)(9)(B)(ii).
Moreover, the other provisions of
CAA section 112 that specifically
discuss environmental effects have
59 76
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purposes that are distinguishable from
CAA section 112(n)(1), and we do not
believe one can reasonably draw the
conclusion that the commenter does
when comparing those provisions to
CAA section 112(n)(1)(A). The lack of a
requirement to consider environmental
effects in CAA section 112(n)(1)(A) does
not equate to a prohibition on the
consideration of environmental effects
as the commenter concludes. The EPA
maintains that it reasonably concluded
that we should protect against identified
or potential adverse environmental
effects absent clear direction to the
contrary.
Concerning the consideration of the
cumulative effect of HAP emissions
from EGUs and other sources, we
provided a reasonable interpretation of
the statute and noted that our
interpretation, unlike commenters, does
not ‘‘ignore the manner in which public
health and the environment are affected
by air pollution. An individual that
suffers adverse health effects as the
result of the combined HAP emissions
from EGUs and other sources is harmed,
irrespective of whether HAP emissions
from EGUs alone would cause the
harm.’’ 60
d. Finding for All HAP To Be Regulated
Comment: Several commenters stated
that for those EGU HAP for which the
Agency makes no CAA section
112(n)(1)(A) determination, their
regulation under CAA section 112 is not
authorized. For example, one
commenter maintains that the Agency
could regulate HAP emissions from
EGUs under CAA section 112(n).
Accordingly, to the extent that the EPA
reads CAA section 112, as construed by
National Lime Ass’n, as compelling it to
regulate all HAP emitted by EGUs,
should the Agency make an
‘‘appropriate and necessary’’
determination under CAA section
112(n)(1)(A) with respect to a single
HAP (e.g., Hg), the EPA stands poised to
commit a fundamental legal error that
will condemn the final rule on review.
Cf., e.g., PDK Laboratories, Inc., 362
F.3d at 797–98; Holland v. Nat’l Mining
Ass’n, 309 F.3d at 817 (where an agency
applies a Court of Appeals
‘‘interpretation * * * because it
believed that it had no choice’’ and that
it ‘‘was effectively ‘coerced’ to do so,’’
then the agency ‘‘cannot be deemed to
have exercised its reasoned judgment’’).
Response: We do not agree with the
commenter’s assertion that Congress
intended EPA to regulate only those
EGU HAP emissions for which an
appropriate and necessary finding is
60 76
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made, and the commenter has cited no
provision of the statute that states a
contrary position. The EPA reasonably
concluded that we must find it
‘‘appropriate’’ to regulate EGUs under
CAA section 112 if we determine that a
single HAP emitted from EGUs poses a
hazard to public health or the
environment. If we also find that
regulation is necessary, the Agency is
authorized to list EGUs pursuant to
CAA section 112(c) because listing is
the logical first step in regulating source
categories that satisfy the statutory
criteria for listing under the statutory
framework of CAA section 112. See New
Jersey, 517 F.3d at 582 (stating that
‘‘[s]ection 112(n)(1) governs how the
Administrator decides whether to list
EGUs. * * *’’). As we noted in the
preamble to the proposed rule, D.C.
Circuit precedent requires the Agency to
regulate all HAP from major sources of
HAP emissions once a source category
is added to the list of categories under
CAA section 112(c). National Lime
Ass’n v. EPA, 233 F.3d 625, 633 (D.C.
Cir. 2000). 76 FR 24989.
The commenter does not explain its
issues with our interpretation of how
regulation under section 112 works—i.e.
making a determination that a source
category should be listed under CAA
section 112(c), listing the source
category under CAA section 112(c),
regulating the source category under
CAA section 112(d), and conducting the
residual risk review for sources subject
to MACT standards pursuant to CAA
section 112(f). Instead, it asserts that our
decision is flawed because the
interpretation we provided does not
account for all the alternatives for
regulating EGUs under section 112, and
that we have not properly exercised our
discretion leading to a fatal flaw in our
rulemaking.
The commenter also ignores the
language of section 112(n)(1)(A). As
explained in the proposed rule, the use
of the terms section, subsection, and
subparagraph in section 112(n)(1)(A)
demonstrates that Congress was
consciously distinguishing the various
provisions of section 112 in directing
EPA’s action under section 112(n)(1)(A).
Congress directed the Agency to
regulate utilities ‘‘under this section,’’
not ‘‘under this subparagraph,’’ and
accordingly EGUs should be regulated
under section 112 in the same manner
as other categories for which the statute
requires regulation. Furthermore, the
D.C. Circuit Court found that section
112(n)(1) ‘‘governs how the
Administrator decides whether to list
EGUs’’ and that once listed, EGUs are
subject to the requirements of section
112. New Jersey, 517 F.3d at 583.
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Indeed, the D.C. Circuit Court expressly
noted that ‘‘where Congress wished to
exempt EGUs from specific
requirements of section 112, it said so
explicitly,’’ noting that ‘‘section
112(c)(6) expressly exempts EGUs from
the strict deadlines imposed on other
sources of certain pollutants.’’ Id.
Congress did not exempt EGUs from the
other requirements of section 112, and
once listed, the EPA is reasonably
regulating EGUs pursuant to the
standard-setting provisions in section
112(d), as it does for all other listed
source categories.
The commenter provided no
alternative theory for regulating EGUs
under CAA section 112, other than to
state that the EPA could regulate under
CAA section 112(n)(1). However, even
assuming for the sake of argument, that
we could issue standards pursuant to
CAA section 112(n)(1), we would
decline to do because there is nothing
in section 112(n)(1)(A) that provides any
guidance as to how such standards
should be developed. Any mechanism
we devised, absent explicit statutory
support, would likely receive less
deference than a CAA section 112(d)
standard issued in the same manner in
which the Agency issues standards for
other listed source categories. We would
also decline to establish standards
under section 112(n)(1) because
Congress did provide a mechanism
under CAA sections 112(d) and (f) for
establishing emission standards for HAP
emissions from stationary sources and it
is reasonable to use that mechanism to
regulate HAP emissions from EGUs.
e. Considering Costs in Finding
Comment: Several commenters assert
that the EPA must consider costs in
assessing whether regulation of EGUs is
appropriate under CAA section
112(n)(1)(A). Commenters posit that the
EPA’s position that ‘‘the term
‘appropriate’ * * * does not allow for
the consideration of costs in assessing
whether hazards * * * are reasonably
anticipated to occur based on EGU
emissions,’’ 76 FR at 24,989/1, does not
withstand scrutiny. According to the
commenters, the treatment of ‘‘costs’’
under section 112(c) does not support
the Agency’s position, and the process
by which sources may be ‘‘delisted’’
under section 112(c)(9), including no
consideration of costs, sheds no light on
the circumstances under which it may
be ‘‘appropriate’’ to regulate EGUs
under section 112(n)(1)(A).
Commenters characterize as
‘‘unintelligible’’ the EPA’s position that
it is ‘‘reasonable to conclude that costs
may not be considered in determining
whether to regulate EGUs’’ when
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‘‘hazards to public health and the
environmental are at issue (citing 76 FR
at 24989). ‘‘Two commenters stated that
a natural reading of the term
‘‘appropriate’’ would include the
consideration of costs. According to the
commenters, something may be found to
be ‘‘appropriate’’ where it is ‘‘specially
suitable,’’ ‘‘fit,’’ or ‘‘proper.’’ See
Webster’s Third New International
Dictionary at 106 (1993). The term
‘‘appropriate’’ carries with it the
connotation of something that is
‘‘suitable or proper in the
circumstances.’’ See New Oxford
American Dictionary (2d Ed. 2005).
Considering the costs associated with
undertaking a particular action is
inextricably linked with any
determination as to whether that action
is ‘‘specially suitable’’ or ‘‘proper in the
circumstances.’’ One commenter notes
that in 2005 (70 FR 15994, 16000; March
29, 2005) the EPA used the dictionary
definition of ‘‘appropriate,’’ as being
‘‘especially suitable or compatible’’ and
that it would be difficult to fathom how
a regulatory program could be either
‘‘suitable’’ or ‘‘compatible’’ for a given
public health objective without
consideration of cost.
One commenter asserts that on the
face of CAA section 112(n)(1)(A), it is
clear that the EPA is expected to
consider costs. According to the
commenter, that Congress intended that
the EPA investigate and consider
‘‘alternative control strategies’’ for
emissions as part of the section 112
(n)(1) Utility Study when making the
‘‘appropriate and necessary’’
determination refutes the notion that the
Agency can, and indeed must, disregard
the cost of regulation in making that
determination, because the cost of a
given emission ‘‘control strategy’’ is a
central factor in any evaluation of
‘‘alternative’’ controls.
Further, according to commenters, it
is well-settled that CAA regulatory
provisions should be read with a
presumption in favor of considering
costs (citing Michigan v. EPA, 213 F.3d
663, 678 (D.C. Cir. 2000)), and the
legislative history of section
112(n)(1)(A) confirms that Congress
intended EPA to consider costs (citing
Oxley Statement at 1417).
Commenters also assert that the EPA
falsely represents that it ‘‘did not
consider costs when making the
‘‘appropriate’’ determination in the
EPA’s December 2000 notice (76 FR at
24,989/2).
Response: The commenters first take
issue with EPA’s explanation of why the
Agency determined that costs should
not be considered in making the
appropriate determination. What
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commenters do not identify is an
express statutory requirement that the
Agency consider costs in making the
appropriate determination. Congress
treated the regulation of HAP emissions
differently in the 1990 CAA
amendments because the Agency was
not acting quickly enough to address
these air pollutants with the potential to
adversely affect human health and the
environment. See New Jersey, 517 F.3d
at 578. Specifically, following the 1990
CAA amendments, the CAA required
the Agency to list source categories and
nothing in the statute required us to
consider costs in those listing decision,
and we have not done so when listing
other source categories. Thus, it is
reasonable to make the listing decision,
including the appropriate
determination, without considering
costs.
The commenters next argue that the
Agency is compelled by the statute to
consider costs based on a dictionary
definition of ‘‘appropriate’’ and the CAA
section 112(n)(1)(A) direction to
consider alternative control strategies
for regulating HAP emissions in the
Utility Study.
Concerning the definition of
‘‘appropriate’’, commenters stated:
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Not only is it ‘‘reasonable’’ for EPA to
consider costs in determining whether it is
‘‘appropriate’’ to regulate EGU HAP
emissions, a natural reading of the term
indicates that excluding the consideration of
costs would be entirely unreasonable.
Something may be found to be ‘‘appropriate’’
where it is ‘‘specially suitable,’’ ‘‘fit,’’ or
‘‘proper.’’ See Webster’s Third New
International Dictionary at 106 (1993). The
term ‘‘appropriate’’ carries with it the
connotation of something that is ‘‘suitable or
proper in the circumstances.’’ See New
Oxford American Dictionary (2d Ed. 2005) at
76. Considering the costs associated with
undertaking a particular action is
inextricably linked with any determination
as to whether that action is ‘‘specially
suitable’’ or ‘‘proper in the circumstances.’’
The EPA believes the definition of
‘‘appropriate’’ that the commenters
provide wholly support its
interpretation and nothing about the
definition compels a consideration of
costs. It is appropriate to regulate EGUs
under CAA section 112 because EPA
has determined that HAP emissions
from EGUs pose hazards to public
health and the environment, and section
112 is ‘‘specially suitable’’ for regulating
HAP emissions, and Congress
specifically designated CAA section 112
as the ‘‘proper’’ authority for regulating
HAP emissions from stationary sources,
including EGUs. Section 112 of the CAA
is ‘‘suitable [and] proper in the
circumstances’’ because EPA has
identified a hazard to public health and
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the environment from HAP emissions
from EGUs and Congress directed the
Agency to regulate HAP emissions from
EGUs under that provision if we make
such a finding. Cost does not have to be
read into the definition of ‘‘appropriate’’
as commenter suggests. In addition, as
stated elsewhere in response to
comments, the Agency does not
consider costs in any listing or delisting
determinations, and the EPA maintains
that it is reasonable to assess whether to
list EGUs (i.e. the appropriate and
necessary finding) without considering
costs.
The commenters’ argument that costs
must be considered based on the CAA
section 112(n)(1)(A) requirement to
‘‘develop and describe alternative
control strategies’’ in the Utility Study
is equally flawed. The argument is
flawed because Congress did not direct
the Agency to consider in the Utility
Study the costs of the controls when
evaluating the alternative control
strategies. In addition, the EPA did not
consider the costs of the alternative
controls in the Utility Study, as implied
by the commenter. Thus, even viewing
section 112(n)(1)(A) in isolation, there is
nothing in that section that compels
EPA to consider costs. For the reasons
described herein, we do not believe that
it is appropriate to consider costs in
determining whether to regulate EGUs
under section 112.
Additionally, one commenter
attempts to refute EPA’s statement in
the preamble to the proposed rule that
the EPA did not consider costs in the
2000 finding by pointing to the only two
mentions of cost in that notice.
However, the EPA did not say that costs
were not mentioned in the 2000 finding
and a review of the regulatory finding
will show that costs were not
considered in the regulatory finding. 65
FR 79830 (December 20, 2000) (‘‘Section
III. What is EPA’s Regulatory
Finding?’’).
f. Considering Requirements of the CAA
in ‘‘Necessary’’
Comment: Several commenters
disagree with EPA’s position that it
need consider ‘‘only those requirements
that Congress directly imposed on EGUs
through the CAA as amended in 1990,’’
for which ‘‘EPA could reasonably
predict HAP emission reductions at the
time of the Utility Study.’’ According to
the commenters, the statutory language
of CAA section 112(n)(1) requires that
the EPA consider the scope and effect of
EGU HAP emissions after the
imposition of all of the ‘‘requirements’’
of the CAA, not just the Acid Rain
program. The commenter maintains that
it would have been easy enough for
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Congress in subparagraph 112(n)(1)(A)
to specify ‘‘after imposition of the
requirements of Title IV of this
chapter,’’ but Congress did not. The
commenters further add that the
legislative history confirms that
Congress meant something much
broader than that, providing that the
EPA is authorized to regulate EGUs
under CAA section 112 only after
‘‘taking into account compliance with
all provisions of the act and any other
Federal, State, or local regulation and
voluntary emission reductions.’’ The
commenters stated that the CAA’s
‘‘requirements’’ include the submission
by states of ozone and fine PM
attainment demonstrations, as well as
SIP provisions needed to reach
attainment of the NAAQS because such
provisions could include controls on
EGUs to reduce SO2 and NOX, which
controls could also result in a reduction
in Hg emissions.
Response: The commenter’s
characterization of the facts is flawed
and its reliance on legislative history
that is in direct conflict with the express
terms of the statute is unpersuasive.
On the facts, the EPA explained in the
preamble to the proposed rule its
interpretation of the phrase ‘‘after
imposition of the requirements of [the
Act]’’ as it related to the conduct of the
Utility Study.61 We reasonably
concluded that, since Congress only
provided 3 years after enactment to
conduct the study, the phrase referred to
requirements that were directly imposed
on EGUs through the CAA amendments
and for which the Agency could
reasonably predict co-benefit HAP
emission reductions. Id. The EPA did
not state that the phrase only applied to
the Acid Rain program, as commenter
asserts, and the Utility Study in fact
discussed other regulations, including
the NSPS for EGUs and revised NAAQS.
With regard to the latter, the EPA
ultimately determined that it could not
sufficiently quantify the reductions that
might be attributable to the NAAQS
because states are tasked with
implementing those standards. See
Utility Study, pages ES–25, 1–3, 2–32.
Conversely, commenter’s position is
that the EPA must consider
implementation of all the requirements
of the CAA, but it does not indicate how
in conducting the Utility Study the
Agency could have possibly considered
co-benefit HAP reductions attributable
to all future CAA requirements. The
Agency appropriately considered the
other requirements of the Act in the
Utility Study and considered those
requirements in determining that it was
61 76
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necessary to regulate coal- and oil-fired
EGUs in December 2000.
Although not required, the Agency in
the preamble to the proposed rule
conducted further analyses in support of
the 2000 finding. In doing so, we
considered a number of requirements
that far exceed what Congress
contemplated when enacting CAA
section 112(n)(1)(A)), and our analyses
still show that it remains necessary to
regulate coal- and oil-fired EGUs under
section 112. 76 FR 24991.
We maintain that we have reasonably
interpreted the requirement to consider
the hazards to public health and the
environment reasonably anticipated to
occur after imposition of the
requirements of the Act as explained in
the preamble to the proposed rule.62 In
addition, as stated above, we also
believe it would be reasonable to find it
necessary to regulate HAP emissions
from EGUs based on our finding that
such emissions pose a hazard to public
health and the environment today
without considering future reductions
that we currently project to occur as the
result of imposition of CAA
requirements that are not yet effective
(e.g., CSAPR).
Moreover, Representative Oxley’s
statement cited by the commenter is not
consistent with the express terms of
CAA section 112(n)(1)(A) on this issue.
Representative Oxley stated that the
EPA was to take ‘‘into account
compliance with all the provisions of
the act and any other Federal, State, or
local regulation and voluntary emission
reductions,’’ but CAA section
112(n)(1)(A) directs the Agency to
consider ‘‘imposition of the
requirements of this chapter,’’ which
means the CAA. The Agency reasonably
focused on the requirements of the
Clean Air Act, which are federally
enforceable, and declined to include
potential future reductions that may be
attributable to voluntary emission
reduction programs or state and local
regulations that have no basis in the
Clean Air Act and are not federally
enforceable. In addition to the statutory
direction not to consider such
requirements, the EPA believes it is
reasonable not to include potential
reductions attributable to such
requirements because the Agency
cannot assure that such requirements
and the attendant HAP reductions will
remain absent regulation under section
112. Finally, the commenter implies
that EPA’s position is that the Agency
will only consider requirements of the
Act that directly regulate HAP
emissions. The EPA never stated or
62 76
FR 24990.
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suggested that interpretation and a fair
reading of the proposed rule will
demonstrate that EPA considered
requirements that achieve co-benefit
HAP emission reductions, for example
the Transport Rule (known as CSAPR).
Comment: One commenter stated that,
under CAA section 112, regulating
EGUs is permissible only insofar as it is
focused, targeted, and predicated on
concrete findings by the Agency that
such regulation is indeed ‘‘necessary.’’
According to the commenter, the EPA
construes CAA section 112(n)(1)(A) as
permitting it to find that it is
‘‘necessary’’ to regulate EGUs even
where the Agency does not actually
know whether it is ‘‘necessary’’ to
regulate EGUs. Citing the D.C. Circuit,
the EPA suggests that ‘‘‘there are many
situations in which the use of the word
‘necessary,’ in context, means
something that is done, regardless of
whether it is indispensible,’’’ in order to
‘‘‘achieve a particular end.’’’ 76 FR
24990, quoting Cellular
Telecommunications v. FCC, 330 F.3d
502, 510 (D.C. Cir. 2003). The
commenter stated that in the ‘‘context’’
of CAA section 112(n)(1)(A), as
informed by the relevant legislative
history from Representative Oxley, it is
clear that regulation of EGU HAP
emissions can be considered
‘‘necessary’’ only if EPA were to
‘‘clearly establish’’ that such regulation
was effectively ‘‘indispensible’’ to
address the identified harm. As EPA
concedes that it has made no such
determination here, its proposal is
fatally flawed for that reason alone.
The commenter further asserts that
the EPA erred when it concluded that it
may ‘‘ ‘determine it is necessary to
regulate under section 112’ when the
Agency is ‘uncertain whether
imposition of the requirements of the
CAA will address the identified
hazards’’’ (citing 76 FR at 24,991/3).
According to the commenter, the EPA
‘‘cannot take refuge in its own
‘uncertainty’ to support a finding that it
is ‘necessary’ to regulate EGUs under
section 112, and the Act precludes the
EPA from ‘‘‘err[ing] on the side of
regulation’’’ in face of uncertainty (id.).
The commenter also implies that the
finding was based on non-HAP
emissions.
Response: The commenter again relies
on the legislative statements of one
Representative and asserts that the
statements are controlling. The EPA
disagrees with commenter and
maintains that its interpretation of the
term ‘‘necessary’’ is reasonable. 76 FR
24990–92 (Section III.A.2.b of the
preamble to the proposed rule contains
the EPA’s interpretation of the term
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‘‘necessary’’.) 76 FR 24990–92 (Section
III.A.2.b of the proposed rule contains
EPA’s interpretation of the term
‘‘necessary’’.) The commenter also, in a
footnote, implies that EPA based the
appropriate and necessary finding on
non-HAP air pollution. The commenter
is wrong as explained in more detail
above.
As an initial matter, this comment is
only addressing one aspect of the
Agency’s interpretation of the term
necessary. As EPA stated at proposal:
If we determine that the imposition of the
requirements of the CAA will not address the
identified hazards, EPA must find it
necessary to regulate EGUs under section
112. Section 112 is the authority Congress
provided to address hazards to public health
and the environment posed by HAP
emissions and section 112(n)(1)(A) requires
the Agency to regulate under section 112 if
we find regulation is ‘‘appropriate and
necessary.’’ If we conclude that HAP
emissions from EGUs pose a hazard today,
such that it is appropriate, and we further
conclude based on our scientific and
technical expertise that the identified
hazards will not be resolved through
imposition of the requirements of the CAA,
we believe there is no justification in the
statute to conclude that it is not necessary to
regulate EGUs under section 112.
76 FR 24991.
The EPA has determined that the
imposition of the requirements of the
CAA will not address the hazards to
public health or hazards to the
environment that EPA has identified;
therefore, it is necessary to regulate
EGUs under CAA section 112.
The EPA further interpreted the
statute to allow the Agency to find that
it is necessary to regulate EGUs under
other circumstances, and it is with one
of our additional interpretations that
commenter takes issue. Specifically, the
commenter argues that EPA’s
interpretation authorizes the Agency to
find it necessary to regulate EGUs when
we are uncertain it is necessary, but that
misconstrues our interpretation and the
record. At proposal, the EPA stated:
In addition, we may determine it is
necessary to regulate under section 112 even
if we are uncertain whether the imposition of
the requirements of the CAA will address the
identified hazards. Congress left it to EPA to
determine whether regulation of EGUs under
section 112 is necessary. We believe it is
reasonable to err on the side of regulation of
such highly toxic pollutants in the face of
uncertainty. Further, if we are unsure
whether the other requirements of the CAA
will address an identified hazard, it is
reasonable to exercise our discretion in a
manner that assures adequate protection of
public health and the environment.
Moreover, we must be particularly mindful of
CAA regulations we include in our modeled
estimates of future emissions if they are not
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final or are still subject to judicial review
([e.g.], the Transport Rule). If such rules are
either not finalized or upheld by the Courts,
the level of risk would potentially increase.
Id.
The CAA requires EPA to exercise its
discretion in determining whether
regulation under section 112 is
necessary, and the D.C. Circuit has
stated that ‘‘there are many situations in
which the use of the word ‘necessary,’
in context, means something that is
done, regardless of whether it is
indispensible, to achieve a particular
end.’’ See Cellular Telecommunications
& Internet Association, et al. v. FCC, 330
F.3d 502, 510 (D.C. Cir. 2003). The
EPA’s interpretation of ‘‘necessary’’ is
reasonable in the context of CAA
section 112(n)(1)(A).
The commenter stated that EPA
concedes that the Agency has not
‘‘clearly established’’ that regulation of
HAP emissions under CAA section 112
is ‘‘indispensible.’’ The EPA has
conceded nothing but, more
importantly, the supposed standard that
the commenter presents for evaluating
whether it is necessary to regulate HAP
emissions from EGUs is not required by
the statute. Even the limited legislative
history on which the commenter
incorrectly relies does not espouse such
a standard. The commenter specifically
takes issue with EPA’s statement that
the Agency may find it is necessary to
regulate EGUs under CAA section 112 if
we are ‘‘uncertain whether imposition
of the other requirements of the CAA
will sufficiently address the identified
hazards.’’ 76 FR at 24990. The
commenter has again misinterpreted the
Agency’s position by stating that ‘‘EPA
construes CAA section 112(n)(1)(A) as
permitting it to find that it is
‘‘necessary’’ to regulate EGUs even
where the Agency does not actually
know whether it is ‘‘necessary’’ to
regulate EGUs.’’ Instead, the EPA
maintains that it may be necessary to
regulate EGUs under CAA section 112 if
we identify a hazard to public health or
the environment that is appropriate to
regulate today and our projections into
the future do not clearly establish that
the imposition of the requirements of
the CAA will address the identified
hazard in the future. Making a
prediction about future emission
reductions from a source category is
difficult for statutory provisions that do
not mandate direct control of the given
source category or pollutants of concern.
We maintain that erring on the side of
caution is appropriate when the
protection of public health and the
environment from HAP emissions is not
assured based on our modeling of future
emissions.
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Furthermore, as we stated in the
preamble to the proposed rule, we
believe it would be reasonable to find it
appropriate and necessary to regulate
EGUs under section 112 today based on
a determination that HAP emissions
from EGUs pose a hazard to public
health and the environment without
considering future HAP emission
reductions. 76 FR 24991, n.14. We
maintain this is reasonable because
‘‘Congress could not have contemplated
in 1990 that EPA would have failed in
2011 to have regulated HAP emissions
from EGU’s where hazards to public
health and the environment remain.’’ Id.
The phrase ‘‘after imposition of the
requirements of [the Act]’’ as
contemplated CAA section 112(n)(1)(A)
could be read to apply only to those
requirements clearly and directly
applicable to EGUs under the 1990 CAA
amendments, all of which have been
implemented and still hazards to public
health and the environment from HAP
emissions from EGUs remain.
g. Listing EGUs Under 112
Comment: One commenter stated that
even if EPA were to establish under
CAA section 112(n)(1)(A) that it is
‘‘appropriate and necessary’’ to regulate
HAP emissions from EGUs, regulating
those emissions in the form of a MACT
standard established pursuant to CAA
section 112(d) is contrary to the plain
language of the Act. According to the
commenter, if EPA proceeds to finalize
the proposal and adopts such a
standard, the rule will for this reason
alone be ‘‘dead-on-arrival’’. According
to the commenter, the EPA apparently
believes that its only option in
regulating EGU HAP emissions is
establishing a MACT standard under
CAA section 112(d). In the preamble to
its proposal, the commenter states that
EPA contends that, ‘‘once the
appropriate and necessary finding is
made,’’ EGUs are then ‘‘subject to
section 112 in the same manner as other
sources of HAP emissions’’—i.e., by
‘‘listing’’ EGUs under CAA section
112(c) and adopting a MACT standard
under CAA section 112(d). See 76 FR
24993/2 (emphasis added). The
commenter further stated that, given
that Congress ‘‘directed the Agency to
regulate utilities ‘under this section’
[i.e., CAA section 112],’’ EPA continues,
it follows that ‘‘EGUs should be
regulated in the same manner as other
categories for which the statute requires
regulation.’’ Id. (emphasis added). The
commenter asserts that as EPA sees it,
because ‘‘Congress did not exempt EGUs
from the other requirements of section
112,’’ once EGUs were ‘‘listed’’ under
CAA section 112(c), the Agency was
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‘‘required to establish emission
standards for EGUs consistent with the
requirements set forth in section
112(d).’’ Id. at 24,993/3 (emphasis
added).
The commenter stated that, in support
of this reading of the CAA, the EPA
invokes the decision of the U.S. Court
of Appeals for the D.C. Circuit in New
Jersey v. EPA, 517 F.3d 574 (D.C. Cir.
2008). The commenter further alleged
that, according to EPA, the D.C. Circuit
has ‘‘already held that section 112(n)(1)
‘governs how the Administrator decides
whether to list EGUs.’ ’’ See 76 FR
24993/2–3, quoting 517 F.3d at 583. The
commenter stated that EPA construes
that holding as indicating that, ‘‘once
listed, EGUs are subject to the
requirements of section 112’’—
including, the EPA presumes, CAA
section 112(d). Id. The commenter
stated that elsewhere, the EPA construes
CAA section 112(n)(1) (A) as
‘‘govern[ing] how the Administrator
decides whether to list EGUs for
regulation under section 112,’’ and
quotes the D.C. Circuit’s observation in
New Jersey that ‘‘Section 112(n)(1)
governs how the Administrator decides
whether to list EGUs; it says nothing
about delisting EGUs.’’ See 76 FR
24981/2, quoting 517 F.2d at 582.
The commenter asserts that EPA
misinterprets the ‘‘under this section’’
language of CAA section 112(n)(1);
overstates the significance of the New
Jersey decision; and, as a consequence,
misapprehends the scope of its own
discretion to formulate regulatory
standards for EGUs under CAA section
112. In light of these errors, the
commenter maintains that EPA should
withdraw the proposed MACT rule.
One commenter stated that if
Congress had intended that EPA
regulate EGU HAP emissions only
through a MACT standard, Congress
could have—and presumably would
have—directed the Agency to regulate
EGU emissions ‘‘under CAA section
112(d).’’ Thus, the commenter
maintained that EPA’s authority to
regulate EGU HAP emissions is not
derived from any particular subsection
of CAA section 112. Rather, the
commenter stated that EPA is
authorized to regulate ‘‘under this
section’’—i.e., CAA section 112
generally—as may be ‘‘appropriate and
necessary.’’ The commenter stated that
there is nothing on the face of CAA
section 112(n)(1)(A) that specifies that
regulation of EGUs must occur under
CAA section 112(d). To the contrary,
according to the commenter, a plain
reading of CAA section 112(n)(1)(A), as
interpreted based on the Oxley
statement, indicates that establishing a
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MACT standard for EGUs under CAA
section 112(d) is not what Congress had
in mind at all.
Response: We do not agree with the
commenter. The EPA interpreted CAA
section 112(n)(1)(A) in a manner that
gives meaning to all the words used in
the provision. See NRDC v. EPA, 489
F.3d 1364, 1373 (D.C. Cir. 2007)
(admonishing EPA for an interpretation
of CAA section 112(c)(9) that ignored
certain words and the context in which
they were used. The Court stated that
‘‘EPA’s interpretation would make the
words redundant and one of them ‘mere
surplusage,’ which is inconsistent with
a court’s duty to give meaning to each
word used by Congress.’’) (citing TRW
Inc. v. Andrews, 534 U.S. 19, 31, 122 S.
Ct. 441, 151 L. Ed. 2d 339 (2001)).
Specifically, in the preamble to the
proposed rule, we stated:
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The statute directs the Agency to regulate
EGUs under section 112 if the Agency finds
such regulation is appropriate and necessary.
Once the appropriate and necessary finding
is made, EGUs are subject to section 112 in
the same manner as other sources of HAP
emissions. Section 112(n)(1)(A) provision
provides, in part, that: ‘[t]he Administrator
shall perform a study of the hazards to public
health reasonably anticipated to occur as a
result of emissions by electric utility steam
generating units of pollutants listed under
subsection (b) of this section after imposition
of the requirements of this chapter. * * *
The Administrator shall regulate electric
utility steam generating units under this
section, if the Administrator finds such
regulation is appropriate and necessary after
considering the results of the study required
by this subparagraph.’’ Emphasis added.
In the first sentence, Congress
described the study and directed the
Agency to evaluate the hazards to public
health posed by HAP emissions listed
under subsection (b) (i.e., CAA section
112(b)). The last sentence requires the
Agency to regulate under this section
(i.e., CAA section 112) if the Agency
finds such regulation is appropriate and
necessary after considering the results of
the study required by this subparagraph
(i.e., CAA section 112(n)(1)(A)). The use
of the terms ‘‘section’’, ‘‘subsection’’,
and ‘‘subparagraph’’ demonstrates that
Congress was consciously
distinguishing the various provisions of
CAA section 112 in directing the
conduct of the study and the manner in
which the Agency must regulate EGUs
if the Agency finds it appropriate and
necessary to do so. Congress directed
the Agency to regulate utilities ‘‘under
this section,’’ and accordingly EGUs
should be regulated in the same manner
as other categories for which the statute
requires regulation. See 76 FR 24993.
We maintain that our interpretation of
the statute gives meaning to all the
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words, and the commenter’s
interpretation does not give any
particular meaning to the requirement to
‘‘regulate under this section [112]’’. The
commenter is correct that Congress
could have in CAA section 112(n)(1)(A)
directed EPA to regulate HAP from
EGUs under CAA section 112(d) after
making the appropriate and necessary
finding, but the commenter presumes
too much when it stated that Congress
would have directed the Agency to
regulate HAP emissions from EGUs in
such a manner if that is what Congress
wanted, simply by including the phrase
‘‘regulate under this paragraph’’ or
‘‘regulate under this subparagraph’’
instead of directing the Agency to
‘‘regulate under this section’’. It did not
do so.
As we explained in the section II.A.
of the proposed rule, CAA section 112
establishes a mechanism to list and
regulate stationary sources of HAP
emissions. 76 FR 24980–81. Regulation
under CAA section 112 generally
requires listing under CAA section
112(c), regulation under CAA section
112(d), and, for sources subjected to
MACT standards, residual risk
regulations under CAA section 112(f) (as
necessary to protect human health and
the environment with an ample margin
of safety). A determination that EGUs
should be listed once the prerequisite
appropriate and necessary finding is
made is wholly consistent with the
language of section 112(n)(1)(A), and
listed sources must be regulated under
CAA section 112(d). See CAA section
112(c)(2); see also New Jersey, 517 F.3d
at 583 (112(n)(1)(A) ‘‘governs how the
Administrator decides whether to list
EGUs’’).
As noted above, Congress used the
terms section, subsection, and
subparagraph in section 112(n)(1)(A).
The use of these three terms
demonstrates that Congress was
consciously distinguishing between the
various provisions of section 112.
Congress directed the Agency to
regulate utilities ‘‘under this section,’’
and accordingly EGUs should be
regulated in the same manner as other
categories for which the statute requires
regulation.
Furthermore, the flaws in the
commenter’s interpretation are
highlighted by other CAA section 112
provisions wherein Congress provided
specific direction as to the manner of
regulation. For example, CAA section
112(m)(6) requires the Administrator to
determine ‘‘whether the other
provisions of this section [112] are
adequate’’ and also indicates that ‘‘[a]ny
requirements promulgated pursuant to
this paragraph * * * shall only apply
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to the coastal waters of the States which
are subject to [section 328 of the CAA].’’
(emphasis added).
In addition, CAA section 112(n)(3)
provides that when the Agency is
‘‘promulgating any standard under this
section [112] applicable to publicly
owned treatment works, the
Administrator may provide for control
measures that include pretreatment of
discharges causing emissions of
hazardous air pollutants and process or
product substitutions or limitations that
may be effective in reducing such
emissions.’’ Finally, CAA section
112(n)(5) directs the Agency to assess
hydrogen sulfide emissions from oil and
gas extraction and ‘‘develop and
implement a control strategy for
emissions of hydrogen sulfide to protect
human health and the environment
* * * using authorities under [the CAA]
including [section 111] of this title and
this section [112].’’ (emphasis added).
We believe these provisions provide
ample evidence that Congress knew
how to alter or caveat regulation under
CAA section 112 when that was its
intent. For these reasons, we believe
commenter’s argument is without merit.
Comment: Two commenters stated
that CAA section 112(n)(1)(A) does not
specify that regulation of EGUs must
proceed under CAA section 112(d).
According to the commenter, an
argument could be made, therefore, that
the CAA accords EPA with the
discretion to regulate EGUs using
strategies other than emission standards
in CAA section 112(d). The commenters
also state that section 112(n)(1)(A) of the
CAA requires that EPA ‘‘develop and
describe’’ alternative control strategies
for emissions which may warrant
regulation under CAA section 112.
According to the commenters if
Congress meant for EPA to have one
sole regulatory option, i.e., regulation of
EGUs only under CAA section 112(d),
then the development of alternative
control strategies would be rendered
meaningless because under CAA section
112(d)(3), the EPA is required to
determine the level of control that is
achieved by the best performing existing
units for which it has data and then to
impose that level of control on all
existing units. The commenter further
states that the development of
‘‘alternative control strategies’’ has no
role to play in this process. One
commenter does note that the
consideration of ‘‘alternative’’ controls
becomes relevant, if at all, only in those
circumstances where EPA might seek to
establish a ‘‘Beyond-the-Floor’’ MACT
standard pursuant to CAA section
112(d)(2).
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Response: The commenters are correct
that CAA section 112(n)(1)(A) directed
the Agency to develop and describe in
the Utility Study report to Congress
alternative control strategies for HAP
emissions from EGUs that may warrant
regulation in the Utility Study, but the
commenters’ interpretation of and
conclusion based on that language are
both factually and legally inaccurate.
The commenters appear to interpret
the word ‘‘alternative control strategies’’
to mean something other than the
traditional control technologies and
control measures that are used to
control HAP emissions from EGUs. We
do not believe that is a reasonable
interpretation of the statute, and the
Agency did not interpret the statute in
that manner when it conducted the
Utility Study. In Chapter 13 of the
Utility Study, the EPA considered a
range of control measures that would
reduce the different types of HAP
emitted from EGUs. https://
www.epa.gov/ttn/atw/combust/utiltox/
eurtc1.pdf. The EPA considered precombustion controls such as coal
washing, fuel switching, and
gasification; combustion controls such
as boiler design; post-combustion
controls such as fabric filters, scrubbers,
and carbon absorption; and alternative
controls strategies such as demand-side
management, energy conservation, and
use of alternative fuels (e.g., biomass) or
renewable energy. The options
discussed in the Utility Study for
controlling HAP emissions from EGUs
are almost universally available to
comply with a CAA section 112(d)
standard.
Given the manner in which the
Agency conducted the Utility Study, the
EPA interpreted the statutory direction
as a requirement to set forth the
potential alternative control options
available to EGUs to comply with CAA
section 112 standards in the event the
Agency determined regulation under
section 112 was appropriate and
necessary. The EPA’s development and
discussion in the Utility Study of
alternative control strategies for
complying with the standards would
help prepare EGUs to comply with the
standards if promulgated. Thus, the EPA
interpreted the direction to address
control strategies in the Utility Study as
a request to identify the controls
available to EGUs for addressing HAP
emissions, and such information would,
of course, be relevant if EPA determined
that such emissions warranted
regulation under section 112.
Furthermore, the EPA establishes
CAA section 112(d) standards for
stationary sources and it is the
responsibility of the sources to comply
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with the standards using any
mechanism available, including precombustion and post-combustion
measures. Also, the establishment of a
MACT standard under CAA section
112(d)(2) and (3) is a two-step process.
In the first step, the Agency establishes
a floor based on the performance of the
best controlled unit or units. See CAA
section 112(d)(3). In the second step, the
Agency must consider additional
measures that may reduce HAP
emissions and adopt such measures if
reasonable after considering costs and
non-air quality health and
environmental effects. See CAA section
112(d)(2). Under the second step, the
Agency can consider any measure that
reduces HAP emissions even if no
source in the category is employing the
option under consideration. So, even
under the commenter’s flawed
interpretation of ‘‘alternative control
strategies’’, the direction in CAA section
112(n)(1)(A) is not a ‘‘pointless
exercise’’ for the development of CAA
section 112(d) standards as the Agency
considers relevant technologies and
HAP emission reduction approaches in
evaluating whether to set a more
stringent beyond the floor standard.
Comment: One commenter points to
CAA section 307(d)(1)(C) and notes that
CAA section 112(n) is listed among the
provision for which the rulemaking
requirements of CAA 307(d) apply.
Commenter maintains that this
inclusion creates an expectation under
the statute that EPA may establish
regulatory standards under CAA 112(n).
The commenter points to CAA sections
112 (n)(1), (n)(3), and (n)(5) and states
that those provisions specifically
discuss regulation under CAA section
112 and that EPA must explain why
CAA 307(d)(1)(C) states ‘‘any regulation
under’’ CAA 112(n) to defend regulation
of utilities under section 112(d). The
commenter then implies that EPA erred
by not even mentioning this provision at
proposal.
The commenter also takes issue with
EPA’s statement in the proposed rule
that ‘‘use of the terms section,
subsection, and subparagraph’’
‘‘demonstrates that Congress was
consciously distinguishing the various
provisions of section 112 in directing
the conduct of the study and the manner
in which the Agency must regulate
EGUs,’’ if EPA determines that it is
appropriate and necessary to regulate
EGUs. See 76 FR at 24,993/2.
One commenter does not agree with
the EPA’s finding that the word
‘‘subsection’’ in the first sentence of
CAA section 112(n)(1)(A) demonstrates
that Congress was consciously
distinguishing between the various
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9331
provisions of CAA section 112 in
directing the conduct of the study and
the manner in which the Agency must
regulate EGUs,’’ were the EPA to ‘‘find[ ]
it appropriate and necessary to do so.’’
See 76 FR 24993/2. According to the
commenter, the only evident reason that
the word ‘‘subsection’’ is used in the
first sentence of CAA section
112(n)(1)(A) is because the reference is
made to the ‘‘pollutants’’ which the
Utility Study is to address—i.e., the
‘‘pollutants’’ that are emitted by EGUs
and which are ‘‘listed under subsection
(b)’’ of CAA section 112. Similarly, the
word ‘‘subparagraph’’ is used in the last
sentence of CAA section 112(n)(1)(A) to
identify ‘‘the study’’ which the EPA is
directed to undertake by subparagraph
(A) of CAA section 112(n)(1)—i.e., the
Utility Study. That the last sentence of
subparagraph (n)(1)(A) also states that
EPA ‘‘shall regulate electric utility
steam generating units under this
section’’ does not even imply—much
less expressly communicate—that
regulation ‘‘under this section’’ must
mean ‘‘regulation under section 112(d).’’
The commenter stated that Congress
was ‘‘consciously distinguishing’’
between the ‘‘various provisions of
section 112’’ for the sake of clarity in the
drafting of CAA section 112(n).
The commenter also asserts that the
EPA mistakenly relies on section
112(c)(6) when the EPA states that
‘‘ ‘where Congress wished to exempt
EGUs from specific requirements of
section 112, it said so explicitly.
Congress did not exempt EGUs from the
other requirements of section 112,’ ’’ and
thus the Agency is ‘‘ ‘required to
establish emission standards for EGUs
consistent with the requirements set
forth in section 112(d)’ ’’ (citing 76 FR
at 24,993 (internal quotation omitted)).
According to the commenter, nothing
in section 112(c)(6) indicates how (or
even whether) EGU HAP emissions
should be regulated under section 112;
paragraph (c)(6) serves only to reiterate
that the regulation of such emissions is
to occur (if at all) as is provided by
section 112(n)(1). The commenter also
asserts that the EPA mistakenly relies on
New Jersey. According to the
commenter, the D.C. Circuit in that case
did not indicate that the language of
section 112(c)(6) should, or could, be
construed to mean that EGUs must be
regulated under a MACT standard
adopted pursuant to section 112(d).
Response: The commenter makes a
number of arguments that appear to take
issue with the EPA’s determination that
EGUs should be regulated under CAA
section 112(d) if the Agency determines
that regulation of HAP emissions from
such units is appropriate and necessary.
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The commenter implies that the EPA
erred because alternative mechanisms
for regulation of EGUs under CAA
section 112 might exist. We do not
agree.
The commenter’s argument that the
EPA erred because we did not explain
why section CAA section 307(d)(1)(C)
contemplates regulations under CAA
section 112(n) is without merit. It is
correct that the Agency believes EGUs
should be regulated in the same manner
as other sources if the appropriate and
necessary finding is made because of the
structure of CAA section 112. Nothing
in CAA section 112(n)(1) requires or
implies that the Agency should or must
establish standards for EGUs under that
provision. Furthermore, unlike CAA
sections 112(n)(3) and 112(n)(5) that
commenter cites, CAA section
112(n)(1)(A) does not provide any
guidance concerning the manner in
which EPA is authorized or required to
regulate sources under CAA section 112.
See CAA section 112(n)(3) (specifically
authorizing identified control measures
and other requirements for
consideration in issuing standards
under CAA section 112); see also CAA
section 112(n)(5) (directing the Agency
to develop and implement a control
strategy for emissions of hydrogen
sulfide using any authority available
under the CAA, including sections 112
and 111, if regulation is appropriate).
For these reasons, we disagree that any
error occurred because we did not
specifically discuss in this proposed
rule whether we could or should
regulate EGUs under CAA section
112(n)(1) instead of CAA section
112(d).63 The Agency validly listed
EGUs in 2000 and listed sources must
be regulated pursuant to CAA section
112(d).
Even if we agreed that regulation
under CAA section 112(n)(1) was a
viable option for EGUs, we would still
have listed and regulated EGUs like
other sources because CAA section
112(d) provides a statutory framework
for regulating HAP emissions from
sources and CAA section 112(n)(1) does
not. We believe that even if CAA section
63 We note that in our January 2004 proposed
rule, we solicited comment on whether section
112(n)(1)(A) provided independent authority to
regulate EGUs. We received several comments on
this issue, and we rejected the concept after
reviewing the comments and further considering
the language of section 112(n)(1)(A) and the
structure of section 112. As such, we proposed and
are finalizing that once the Agency determines that
it is appropriate and necessary to regulate EGUs
under section 112, those sources are listed pursuant
to subsection 112(c), as we did in December 2000,
and the Agency must set standards for those sources
pursuant to section 112(d). See section 112(c) and
(d)(1) (requiring establishment of 112(d) standards
for listed source categories).
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112(n)(1) were available to regulate
EGUs, there would be sufficient
uncertainty about the legal vulnerability
of such an approach to caution against
employing it. This legal uncertainty
would be particularly troubling in light
of the fact that we have identified
hazards to public health and the
environment from HAP emissions from
EGUs that warrant regulation, and these
regulations are long overdue.
The commenter also takes issue with
our statement in the preamble to the
proposed rule that the use of the words
‘‘section’’, ‘‘subsection’’, and
‘‘subparagraph’’ in CAA section
112(n)(1)(A) ‘‘demonstrates that
Congress was consciously
distinguishing the various provisions of
section 112 in directing the conduct of
the study and the manner in which the
Agency must regulate EGUs.’’ See 76 FR
24993. The commenter appears to make
much of our use of the word ‘‘must’’ in
that sentence and also states that our
interpretation of the significance of the
use of the three terms in CAA section
112(n)(1)(A) is flawed because Congress
only used the three terms for purposes
of clarity. The commenter is incorrect
on both points. With respect to the
commenter’s concern regarding the use
of the word ‘‘must’’ in the sentence
quoted above, we note that in the next
sentence we stated that ‘‘Congress
directed the Agency to regulate utilities
‘under this section,’ and accordingly
EGUs should be regulated in the same
manner as other categories for which the
statute requires regulation.’’ Id.
(emphasis added). We were not
foreclosing the possibility of any
alternative interpretation and our use of
the term ‘‘must’’ should not detract from
the point we were trying to make.
Specifically, we believe that Congress
would have directed us to regulate
EGUs under CAA section 112(n)(1)(A) if
that was its intent and, absent that
mandate, the better reading of the
statute is the one provided in the
preamble to the proposed rule, which is
that EGUs should be listed pursuant to
CAA section 112(c) and subject to CAA
section 112(d) emission standards.
The commenter also stated that the
EPA relied on CAA section 112(c)(6) to
support a conclusion that EGUs must be
regulated under CAA section 112(d).
The commenter takes the EPA’s
statements out of context. The statement
in whole read:
Furthermore, the D.C. Circuit Court has
already held that section 112(n)(1) ‘‘governs
how the Administrator decides whether to
list EGUs’’ and that once listed, EGUs are
subject to the requirements of CAA section
112. New Jersey, 517 F.3d at 583. Indeed, the
D.C. Circuit Court expressly noted that
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‘‘where Congress wished to exempt EGUs
from specific requirements of section 112, it
said so explicitly,’’ noting that ‘‘section
112(c)(6) expressly exempts EGUs from the
strict deadlines imposed on other sources of
certain pollutants.’’ Id. Congress did not
exempt EGUs from the other requirements of
CAA section 112, and once listed, EPA is
required to establish emission standards for
EGUs consistent with the requirements set
forth in CAA section 112(d), as described
below. See 76 FR 24993.
As can be seen from this passage, the
Court cited section 112(c)(6) as an
example of Congress’ intent regarding
regulating EGUs under CAA section
112. The commenter cited the last
clause of the last sentence of the
paragraph quoted above without
including the prefatory clause ‘‘once
listed,’’ and, without that clause, the
statement is not fairly characterized.
The point the EPA was making in that
paragraph is that EGUs are a listed
source category and listed sources must
be regulated under CAA section 112(d)
unless the EPA delists the source
category.
Comment: One commenter stated that
EPA overstates the significance of the
D.C. Circuit’s holding in New Jersey by
suggesting that the decision mandates
EGU regulation under CAA section
112(d) because EGUs ‘‘remain listed’’
under CAA section 112(c), See New
Jersey, 517 F.3d at 582. According to the
commenter, the court declined to
address the lawfulness of EPA’s having
‘‘listed’’ EGUs under CAA section
112(c), leaving that matter to be decided
if and when EPA adopted standards for
EGUs under CAA section 112. Nowhere
in the decision did the D.C. Circuit
indicate that EPA must regulate EGUs
under CAA section 112(d).
According to the commenter, the EPA
must consider both whether the
regulation of EGUs is ‘‘appropriate and
necessary’’ under section 112(n)(1) and
address anew whether the Agency is
authorized by section 112 to list EGUs
under section 112(c) at all. The
commenter asserts that on the face of
the proposal, the EPA has not revisited
the question whether the ‘‘listing’’ of
EGUs under section 112(c) is consistent
with congressional intent.
Response: The commenter’s
arguments are circular and it is difficult
to fully determine exactly what its issue
is with EPA’s listing; however, it
appears that the commenter believes
that EPA incorrectly relied on the New
Jersey decision to justify the listing of
EGUs. The commenter also appears to
argue that the Agency has never
explained why it has the authority to
list EGUs at all. We disagree.
As stated in the preamble to the
proposed rule, CAA section 112(n)(1)(A)
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requires EPA to conduct a study of HAP
emissions from EGUs and regulate EGUs
under CAA section 112 if we determine
that regulation is appropriate and
necessary, after considering the results
of the study. 76 FR 24981, 24986, and
24998. The only condition precedent to
regulating EGUs under CAA section 112
is a finding that such regulation is
appropriate and necessary (after
conducting and considering the Utility
Study), and once that finding is made
the Agency has the authority to list
EGUs under CAA section 112(c) as the
first step in the process of establishing
regulations under section 112. The D.C.
Circuit agrees with that interpretation of
the statute as evidenced by its statement
in New Jersey that ‘‘section 112(n)(1)(A)
governs how the Administrator decides
whether to list EGUs for regulation
under section 112,’’ 517 F.3d at 582, and
the Court’s statement directly
contradicts the commenter’s position.
The EPA did not rely on the New
Jersey decision to justify the appropriate
and necessary finding as the commenter
suggests. We based the finding in 2000
on the extensive information available
to the Agency at the time, and we
confirmed the finding in the preamble
to the proposed rule based on new
information. The commenter had ample
opportunity to comment on the
appropriate and necessary finding, and
it may challenge the basis of the listing
(i.e. the appropriate and necessary
finding) when EPA issues the final
standards.
Comment: One commenter believes
that the D.C. Circuit will condemn the
final rule as a result of EPA’s
‘‘misapprehension’’ that upon making
an ‘‘appropriate and necessary’’ finding,
the Agency is compelled by the CAA to
adopt a regulatory standard for EGUs
under CAA section 112(d). According to
the commenter, a regulation will be
invalid if the regulation ‘‘ ‘was not based
on the [agency’s] own judgment’ ’’ but
‘‘ ‘rather on the unjustified assumption
that it was Congress’ judgment that such
[a regulation] is desirable’ or required.’’
See Transitional Hospitals Corp. v.
Shalala, 222 F.3d 1019, 1029 (D.C. Cir.
2000), quoting Prill v. NLRB, 755 F.2d
941, 948 (D.C. Cir. 1985). The
commenter further notes that the D.C.
Circuit has held that, where an agency
wrongly construes a judicial decision as
compelling a particular statutory
interpretation, and thereby unduly
limits the scope of its own discretion,
the agency’s action cannot be sustained.
See, e.g., Phillips Petroleum Co. v.
FERC, 792 F.2d 1165, 1171 (D.C. Cir.
1986). The commenter believes the rule
is bound to be rejected and that the EPA
should ‘‘reconsider the legal
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interpretations on which it purports to
base its rule.’’
Response: We do not agree that we
have improperly interpreted the statute
as limiting our discretion in the manner
suggested by the commenter. The
commenter makes only one specific
allegation in this comment and that
concerns the Agency’s conclusion that it
must establish CAA section 112(d)
standards for EGUs in light of the New
Jersey decision. The commenter does
not explain why that conclusion is
incorrect. As we state above and in the
preamble to the proposed rule, because
EGUs are a CAA section 112(c) listed
source category, the Agency must
establish CAA section 112(d) standards
or delist EGUs pursuant to CAA section
112(c)(9). See New Jersey, 517 F.3d at
582–83 (holding that EGUs remain
listed under section 112(c)); see also
CAA section 112(c)(2) (requiring the
Agency to ‘‘establish emission standards
under subsection [112] (d)’’ for listed
source categories and subcategories); 76
FR 24998–99. We concluded in the
preamble to the proposed rule that we
could not delist EGUs because our
appropriate and necessary analysis
showed that EGUs did not satisfy the
CAA section 112(c)(9)(B)(i) delisting
criteria. Id. We did not address in the
preamble to the proposed rule whether
EGUs satisfied the CAA section
112(c)(9)(B)(ii) criteria because EGUs
failed the first prong of the delisting
provisions. Id. We reach the same
conclusion in the final rule and also
address the delisting petition submitted
by this commenter. Because we cannot
delist EGUs, we must regulate them
under CAA section 112(d). The
commenter has provided no legitimate
argument to rebut this conclusion. See
also previous responses regarding
regulation under section 112(n)(1)(A).
Comment: One commenter alleges
that EPA impermissibly relied on CAA
section 112(c)(9) to interpret ‘‘hazards to
public health’’, and argues that the
‘‘residual risk’’ provisions in CAA
section 112(f)(2) are more appropriate
for the establishment of standards for
EGUs. The commenter stated that by
using CAA section 112(c)(9)(B)(i) in
defining ‘‘hazards to public health’’, the
Agency has seized on the one
interpretation of the phrase that is
surely contrary to congressional intent
and, thus, falls outside the permissible
range of its interpretative discretion.
The commenter maintains that the
‘‘delisting’’ criteria of CAA section
112(c)(9) are simply irrelevant to the
decision whether EGU HAP emissions
will present any ‘‘hazards to public
health’’ sufficient to warrant regulation
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of those emissions under CAA section
112.
The commenter also argues that
Congress intended that EGUs be treated
differently from all other ‘‘major
sources’’ to which the ‘‘delisting’’
provisions of CAA section 112(c)(9), and
the standard-setting provisions of CAA
section 112(d) necessarily and
automatically apply. Therefore,
according to the commenter, the EPA’s
proposal to utilize the criteria of CAA
section 112(c)(9) to inform its findings
under CAA section 112(n)(1)(A) treats
EGUs exactly the same as all other major
source categories, is contrary to
congressional intent, and thus unlawful.
The commenter goes on to state that in
exercising its discretion to define
‘‘hazards to public health’’ as the phrase
is used in CAA section 112(n)(1)(A), the
EPA would be better served to consider
the ‘‘residual health risk’’ provisions of
CAA section 112(f)(2). Those provisions
provide a better analogy to the
establishment of standards for EGUs
under CAA section 112 than do the ‘‘delisting’’ criteria of CAA section
112(c)(9).
The commenter believes the categoryspecific criteria of paragraph (c)(9) are a
poor fit for an evaluation of ‘‘hazards to
public health’’ that should reasonably
include such factors as the affected
population, the characteristics of
exposure, the nature of the health
effects, and the uncertainties associated
with the data. The commenter states
that, while CAA section 112(n)(1)(A)
does not expressly include any
requirement that EGU emissions be
regulated with an ‘‘ample margin of
safety,’’ that standard is more
appropriate than the ‘‘one-in-a-million’’
cancer risk standard of CAA section
112(c)(9)(B)(i) that EPA proposes to
employ.
Response: The commenter
acknowledges that EPA has broad
discretion to interpret the phrase
‘‘hazard to public health’’ but argues
that the one thing we cannot do is use
the CAA section 112(c)(9)(B) delisting
provisions as a benchmark in making
that interpretation. The commenter
asserts that the use of the delisting
standard is clearly contrary to
Congressional intent but it does not
provide any substantive rebuttal to our
conclusion that the CAA section
112(c)(9) standards reflects the level of
hazard which Congress concluded
warranted continued regulation.
Instead, the commenter reverted to its
argument that the statute treated EGUs
differently. The EPA views the disparate
treatment of EGUs in a different light
than commenter. While it is true that
Congress established a different
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statutory provision governing whether
to add EGUs as a regulated source
category under section 112, we do not
interpret CAA section 112(n)(1)(A) as
providing Congressional license to
ignore risks that Congress determined
warranted regulation for all other source
categories. Because CAA section
112(c)(9) defines that level of risk, it is
reasonable to consider it when
evaluating whether EGU HAP emissions
pose hazards to public health.
The commenter also suggests that the
‘‘ample margin of safety standard’’ of
CAA section 112(f)(2) is a better fit than
the one-in-a-million standard set forth
in CAA section 112(c)(9)(B)(1) for
evaluating hazards to public health. The
commenter asserts that an evaluation of
‘‘hazards to public health’’ should
include such factors as the affected
population, the characteristics of
exposure, the nature of the health
effects, and the uncertainties associated
with the data. However, the EPA did not
rely solely on the delisting provisions
for evaluating hazards to public health
as commenter suggests. In fact, the EPA
considered all of the factors the
commenter suggests in making our
finding.64 Thus, we decline to adjust our
approach to evaluating hazards to
public health and the environment
based on the comments.
h. 2000 Finding (and 2005 Delisting)
Comment: Several commenters
generally support EPA’s 2000 finding
that regulating HAP emissions from
EGUs under CAA section 112 is
‘‘appropriate and necessary.’’ According
to the commenters, the 2000 finding was
proper under the CAA and within EPA’s
discretion, well-supported based on
sound science available to the Agency at
the time on the harm from HAP emitted
by EGUs, and no additional information
makes the finding invalid. Several
commenters cited the conclusions of the
Utility Study 65 and Mercury Study,66
which they assert supported the finding
and satisfied the only prerequisite for
the finding. One commenter specifically
asserted that the 2000 finding was wellsupported by the Utility Study’s
conclusions that (1) there was a link
between anthropogenic Hg emissions
and MeHg found in freshwater fish, (2)
Hg emissions from coal-fired utilities
were expected to worsen by 2010, and
(3) MeHg in fish presents a threat to
public health from fish consumption.
One commenter noted that the CAA
64 76
FR 24992.
EPA 1998. Study of Hazardous Air
Pollutant Emissions from Electric Utility Steam
Generating Units—Final Report to Congress. EPA–
453/R–98–004a. February.
66 U.S. EPA, 1997.
65 U.S.
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does not require a conclusive link
between HAP emissions and harm. One
commenter stated that the CAA grants
the Administrator discretion in her
finding, and that discretionary decision
should not be overly scrutinized, citing
court opinion.67 In support of the
finding, one commenter stated that it
would not make sense for Congress to
limit HAP emissions from small
businesses such as dry cleaners but to
exempt U.S. EGUs, which are the largest
sources of many HAP emissions. One
commenter agreed that finding was
further supported because numerous
control options were available to reduce
HAP emissions. One commenter agreed
with the 2000 finding that the Agency
lacked sufficient evidence to conclude
that non-Hg HAP from EGUs posed no
hazard.
The commenters who generally
supported the 2000 finding also
commented on specific aspects of the
finding. Several commenters asserted
that while the evidence on Hg alone
supports the finding, the potential harm
from non-Hg HAP further supported the
2000 finding. Several commenters noted
that new science continues to support
the 2000 finding. Several commenters
also stated that the ‘‘appropriate’’
finding was further supported because
numerous control options were
available at the time of the finding that
would reduce HAP emissions. One
commenter concurred with EPA that
regulating natural gas-fired EGUs was
not appropriate and necessary because
the impacts due to HAP emissions from
such units are negligible based on the
results of the Utility Study.
Several commenters addressed the
2005 reversal of the 2000 finding.
Several commenters specifically
supported the vacatur of the 2005
action. Other commenters asserted that
the 2005 action was proper, and that
EPA reverted back to the 2000 finding
in the proposed rule without adequate
explanation or support. Several
commenters cited the 2005 action as
invalidating the 2000 finding,
specifically noting that EPA concluded
that ‘‘no hazards to public health’’
remained after accounting for emission
reductions under CAIR. These
commenters assert that EPA’s current
position is illegal because EPA took the
exact opposite position on the
interpretation of the term ‘‘necessary’’ in
67 ‘‘Where a statute is precautionary in nature, the
evidence difficult to come by, uncertain, or
conflicting because it is on the frontiers of scientific
knowledge, the regulations designed to protect the
public health, and the decision that of an expert
administrator, [courts] will not demand rigorous
step-by-step proof of cause and effect.’’ Ethyl Corp.
v. EPA, 541 F.2d 1, 28 (Ct. App. D.C. Circ. 1978).
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its 2005 reversal, and, thus, deserves no
judicial deference. One commenter
stated that in 2005 EPA recognized the
potential for excessive regulation
created by CAA section 112 and
determined that the 2000 finding lacked
foundation.
Several commenters generally
disagreed with the 2000 finding, with
two commenters stating that EPA did
not have a rational justification for it
and another claiming that it was fraught
with misinformation and overestimating
assumptions. One commenter claimed
that EPA did not explain the terms
‘‘appropriate’’ and ‘‘necessary’’ in the
2000 finding and that the emission
control analysis was inadequate. Two
commenters stated that the 2000 finding
was based on data that was more than
10 years old, which causes serious
concern regarding the validity of the
findings because technology, the
regulatory environment, and the
economic climate have evolved.
Furthermore, because the Utility Report
underestimated emissions controls that
EGUs would install by 2010 and
additional controls that would be later
required by the CSAPR, the basis for
EPA’s 2000 finding has changed.
Several commenters stated that a
‘‘plausible link’’ between anthropogenic
Hg and MeHg in fish is not an adequate
reason for the 2000 finding. Several
commenters claim that EPA only
identified health concerns for Hg (and
potentially Ni) but not other HAP from
coal-fired EGUs in the 2000 finding,
and, thus, cannot regulate HAP other
than Hg because the 2000 finding
authorizes only the regulation of Hg.
One commenter questioned the Hg
emissions underlying the 2000 finding,
specifically the fraction of total
deposition attributable to U.S. EGUS
and the fact that EPA projected an
increase in U.S. EGU emissions from
1990 to 2010 though emissions actually
declined.
Several commenters raised procedural
issues related to the 2000 finding.
Several commenters stated that the 2000
finding failed to provide public notice
and comment. According to the
commenters, the CAA requires that any
decision made under CAA section
112(n) must go through public notice
and comment. The commenters further
stated that the failure to provide public
notice and comment means that this
MACT is outside EPA’s statutory
authority. One commenter stated that
because the 2000 finding was never
‘‘fully ventilated’’ in front of the D.C.
Circuit, the EPA’s authority to regulate
EGUs under CAA section 112(d) is
directly at issue. The commenters claim
that specific issues did not undergo
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public notice and comment, including
least-cost regulatory options, the impact
of regulation on electricity reliability,
and EPA’s interpretation of the
requirements under CAA section
112(n)(1)(A). One commenter claims
that EPA attempted to provide after-thefact support for its 2000 finding with
new legal analysis and new factual
information, contrary to New Jersey v.
EPA that held that EPA may not revisit
its 2000 finding except through delisting
under CAA section 112(c)(9). One
commenter stated that EPA’s 2000
finding should be reviewed when EPA
issues the actual NESHAP.68 One
commenter stated that the 2000 finding
ignored EO 12866.
Response: EPA agrees with the
commenters that the 2000 finding was
reasonable and disagrees with the
commenters asserting that the 2000
finding was unreasonable or failed to
follow proper procedural requirements.
The EPA agrees that reviewing courts
defer to the reasoned scientific and
technical decisions of an Agency
charged with implementing complex
statutory provisions such as those at
issue in this case. As EPA stated in the
preamble to the proposed rule, the EPA
maintains that the 2000 finding was
reasonable and based on well-supported
evidence available at the time, including
the Utility Study, the Mercury Study,69
and the NAS study,70 which all showed
the hazards to public health and the
environment from HAP emitted from
EGUs. New technical analyses
conducted by EPA confirm that it
remains appropriate and necessary to
regulate HAP emissions from EGUs.
Furthermore, the EPA agrees with the
commenters on several points raised,
specifically that EGUs were and remain
the largest anthropogenic source of
several HAP in the U.S., that risk
assessments supporting the 2000 finding
indicated potential concern for several
non-Hg HAP, and that several available
control options would effectively reduce
HAP emissions from U.S. EGUs.
The EPA agrees with the commenters
that Congress did not exempt EGUs
from section 112(d) HAP emission
limits while simultaneously limiting
emissions at other sources with less
HAP emissions. Congress simply
provided EPA with a separate path for
listing EGUs by requiring that the
Agency evaluate HAP emissions from
EGUs and determine whether regulation
under CAA section 112 was appropriate
and necessary. Since 1990, the EPA has
promulgated regulations requiring the
use of available control technology and
other practices to reduce HAP emissions
for more than 170 source categories.
U.S. EGUs are the most significant
source of HAP in the country that
remains unaddressed by Congress’s air
toxics program. The EPA listed EGUs in
2000 because the considerable amount
of available data supported the
conclusion that regulation of EGUs
under CAA section 112 was appropriate
and necessary. That finding was valid at
the time, and EPA reasonably added
EGUs to the CAA section 112(c) list of
sources that must be regulated under
CAA section 112.
The EPA acknowledges that we did
not expressly define the terms
appropriate and necessary in the 2000
finding, but the finding is instructive in
that it shows that EPA considered
whether HAP emissions from EGUs
posed a hazard to public health and the
environment and whether there were
control strategies available to reduce
HAP emissions from EGUs when
determining whether it was appropriate
to regulated EGUs.71 When concluding
it was necessary, the Agency stated that
imposition of the requirements of the
Act would not address the identified
hazards to public health or environment
from HAP emissions and that section
112 was the proper authority to address
HAP emissions.72 The EPA explained in
the preamble to the proposed rule its
conclusion that the 2000 finding was
fully supported by the information
available at the time,73 and EPA stands
by the conclusions in that notice.
Furthermore, the EPA provided an
interpretation of the terms appropriate
and necessary that is wholly consistent
with the 2000 finding. The EPA does
not agree with the commenters that a
quantification of emissions reductions
or a specific identification of the
available controls was necessary to
support the 2000 finding and listing.
The EPA considered the Utility Study
when making the finding, and that
study clearly articulated the various
alternative control strategies that EGUs
could employ to control HAP
emissions.74 As to emission reductions,
the EPA cannot estimate the level of
HAP emission reductions until the
Agency proposes a CAA section 112(d)
standard after a source category is listed.
The EPA disagrees with commenters
that suggest it was not ‘‘rational’’ to
determine that it was appropriate to
71 65
68 See
UARG v. EPA, 2001 WL 936363, No. 01–
1074 (D.C. Cir. July 26, 2001).
69 U.S. EPA, 1997.
70 NAS, 2000.
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FR 79830.
72 Id.
73 65
FR 24994–24996.
Chapter 13 of the Utility Study (U.S. EPA,
regulate HAP emissions from EGUs due
to the cancer risks identified in the
Utility Study or the potential concerns
associated with other HAP emissions
from EGUs. Nothing in CAA section
112(n)(1)(A) suggests that EPA must
determine that every HAP emitted by
EGUs poses a hazard to public health or
the environment before EPA can find it
appropriate to regulate EGUs under
CAA section 112. In fact, the EPA
maintains that it must find it
appropriate and necessary to regulate
EGUs under CAA section 112 if it
determines that any one HAP emitted
from EGUs poses a hazard to public
health or the environment that will not
be addressed through imposition of the
requirements of the Act. The EPA
disputes the commenters’ conclusion
that the 2000 finding was limited to Hg
and Ni emissions, but, even if it were,
the EPA reasonably concluded that
EGUs should be listed pursuant to CAA
section 112(c) based on the Hg and Ni
finding. As stated in the 2000 finding,
cancer risks from some non-Hg metal
HAP (including As, Cr, Ni, and Cd) were
not low enough to be to eliminate as
potential concern.75 Source categories
listed for regulation under CAA section
112(c) must be regulated under CAA
section 112(d), and the D.C. Circuit has
stated that EPA has a ‘‘clear statutory
obligation to set emission standards for
each listed HAP’’. See Sierra Club v.
EPA, 479 F.3d 875, 883 (D.C. Cir. 2007),
quoting National Lime Association v.
EPA, 233 F.3d 625, 634 (D.C. Cir. 2000).
Therefore, even if EPA concluded that
CAA section 112(n)(1) authorized a
different approach for regulating HAP
emissions from EGUs, the chosen course
which is supported by the CAA (i.e.,
listing under CAA section 112(c))
requires the Agency to regulate under
CAA section 112(d) consistent with the
statute and case law interpreting that
provision.
The EPA disagrees that there is any
concern regarding the validity of the
2000 finding or that the emissions
information provided in the 2000
finding makes the finding
‘‘questionable’’ as stated by some of the
commenters. The EPA maintains that
the 2000 finding was sound and fully
supported by the record available at the
time, including the future year
emissions projections. Therefore, the
listing of EGUs is valid based on that
finding alone. Even though Hg
emissions have decreased since the
2000 finding instead of increasing as
projected, the new technical analyses
confirm that Hg emissions from EGUs
continue to pose hazards to public
74 See
75 76
1998).
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health and the environment. The EPA
also indicated potential concern for
several non-Hg HAP in the 2000 finding.
It is well established that even small
amounts of HAP can cause significant
harm to human health and the
environment.
The EPA agrees with the commenters
who assert that the 2005 action was in
error and disagrees with the
commenters that the 2005 action
invalidated the 2000 finding. As fully
described in the preamble to the
proposal, the EPA erred in the 2005
action by concluding that the 2000
finding lacked foundation. The 2005
action improperly conflated the
‘‘appropriate’’ and ‘‘necessary’’ analyses
by addressing the ‘‘after imposition of
the requirements of the Act’’ in the
appropriate finding as well as the
necessary finding. The EPA also
indicated that it was not reasonable to
interpret the necessary prong of the
finding as a requirement to scour the
CAA for alternative authorities to
regulate HAP emissions from stationary
sources, including EGUs, when
Congress provided section 112 for that
purpose. The EPA asserts that the 2000
finding was sound and fully supported
by the record available at the time for all
the reasons stated in this final rule and
the proposed rule. The 2005 action
interpreted the statute in a manner
inconsistent with the 2000 finding and
attempted to delist EGUs without
complying with the mandates of CAA
section 112(c)(9)(B). See New Jersey, 517
F.3d at 583 (vacating the 2005
‘‘delisting’’ action). In the preamble to
the proposed rule, the EPA set forth a
revised interpretation of CAA section
112(n)(1) that is consistent with the
statute and the 2000 finding. The EPA
also explained in the preamble to the
proposed rule why the 2005 action was
not technically or scientifically sound.
The EPA specifically addressed the
errors associated with the 2005 action in
the preamble to the proposed rule, and
commenters’ assertions do not cause us
to revisit these issues. The commenter is
also incorrect in suggesting that a
change in interpretation is per se invalid
and provided no support for that
position. See National Cable &
Telecommunications Ass’n, et al., v.
Brand X Internet Services, et al., 545
U.S. 967, 981 (discussing the deference
provided to an Agency changing
interpretations, the Court stated ‘‘change
is not invalidating, since the whole
point of Chevron deference is to leave
the discretion provided by ambiguities
of a statute with the implementing
Agency.’’) (Internal citations and
quotations omitted).
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The EPA disagrees with the
commenters who raise concerns about
the validity of the 2000 finding because
the data on which that finding was
based were more than 10 years old. The
EPA made the finding at that time based
on the scientific and technical
information available, and the finding is
wholly supported by that information.
In addition, even though not required to
do so, the EPA has since conducted new
technical analyses utilizing the best
information available in 2010 as several
years have passed since the 2000
finding. These new analyses confirm
that HAP emissions from EGUs continue
to pose a hazard to public health and
the environment, even after taking into
account emission reductions that have
occurred since 2000 from promulgated
rules, settlements, and consent decrees.
See 76 FR 24991.
Contrary to the commenter’s
assertion, the EPA did not violate CAA
section 307(d) by not providing a notice
and comment opportunity before
making the December 2000 appropriate
and necessary finding. One commenter
challenged EPA’s 2000 finding and
listing on the same grounds, and the
D.C. Circuit dismissed the case because
CAA section 112(e)(4) clearly states that
listing decisions cannot be challenged
until the Agency issues final emission
standards for the listed source category.
See UARG v. EPA, 2001 WL 936363, No.
01–1074 (D.C. Cir. July 26, 2001). The
EPA has provided the public an
opportunity to comment on both the
2000 finding and the 2011 analyses that
support the appropriate and necessary
determination as part of the proposed
rule, and anyone may challenge the
listing in the D.C. Circuit in conjunction
with a challenge to this final rule. The
commenters could have also
commented on the CAA section
112(n)(1) (e.g., the Utility Study and the
Mercury Study) studies in 2000 as they
were included in the docket, but EPA is
not aware of any comments on those
studies. In any case, these studies were
peer reviewed and considered the best
information available at that time. The
EPA has fully complied with the
rulemaking requirements of CAA
section 307(d).
The EPA also disagrees with the
commenters’ characterization of the
New Jersey case. The D.C. Circuit did
not say, as one commenter suggested,
that EPA is not able to consider
additional information that is collected
after the 2000 finding; instead, the Court
stated that EPA could not revise its
appropriate and necessary finding and
remove EGUs from the CAA section
112(c) list without complying with the
delisting provisions of CAA section
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112(c)(9). See New Jersey, 517 F.3d at
582–83. The EPA also disagrees with the
commenter’s assertion that EPA
disregarded EO 12866 when making the
2000 finding. As stated in the Federal
Register notice, the 2000 finding did not
impose regulatory requirements or costs
and was reviewed by the Office of
Management and Budget (OMB) in
accordance with the EO.76
2. New Technical Analyses
a. General Comments on New Technical
Analyses
Comment: Several commenters stated
that the new analyses, including the risk
assessments and technology
assessments, confirm that it remains
appropriate and necessary to regulate
U.S. EGU HAP under CAA section 112.
These commenters stated that the new
analyses provide even more support
than the risk and technology
information available at the time the
2000 finding was made, including
information on further developed
emissions control technology, proven
and cost-effective control of acid gases
using trona and dry sorbent injection,
stabilized natural gas prices that makes
fuel switching and switching dispatch
to underutilized combined cycle plants
more feasible, more information on
ecosystem impacts from HAP,
‘‘hotspots’’ from the deposition of Hg
around EGUs, the potential for reemission of Hg, updated emissions data
and future projections of HAP
emissions, and modern air pollution
modeling tools. One commenter states
affordable control technology has been
in use in this sector for 10 to 40 years,
and studies on EGU-attributable Hg
hazard has undergone two in-depth EPA
reviews, as well as a review by the NAS.
Several commenters claimed that
regulating U.S. EGUs is appropriate and
necessary to protect public health based
on information provided in the new
technical analyses. These commenters
acknowledged the substantial
reductions in HAP from recent
regulations and new studies that
confirm serious health risks from HAP
exposure. One commenter stated that
new studies show higher risks to fetuses
than previously estimated, increasing
the potential for neurodevelopmental
effects in newborns. One commenter
noted that EGUs are a major source of
HAP, including HCl, HF, As, antimony,
Cr, Ni, and selenium, all of which
adversely affect human health. The
commenter stated that because of these
health effects, the EPA has ample
evidence to support a determination
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that non-Hg HAP emissions present a
risk to human health.
Other commenters disagreed that the
new analyses confirm that it remains
appropriate and necessary to regulate
U.S. EGUs. One commenter claims that
EPA tried to use the new technical
analyses to provide retroactive
justification for the 2000 finding, which
only found ‘‘plausible links’’ of health
effects and ‘‘potential concerns’’ of
health effects of certain metal emissions,
dioxins and acid based aerosols. The
commenter also asserted that none of
these new analyses demonstrate that
EGU regulation under section 112 is
necessary and appropriate.
One commenter agreed that EPA may
supplement its finding with new
information, analyses and arguments to
reaffirm the 2000 finding up until EPA
issues final emissions standards. The
commenter noted that the CAA does not
freeze the finding. However, another
commenter argued that EPA does not
have the authority to rely on new
technical analyses because the CAA
requires EPA to make the finding on the
basis of the Utility Study alone.
According to that commenter, the EPA
unreasonably stretched the language of
CAA section 112 by considering new
technical analyses.
Citing a report from Dr. Willie Soon
that was submitted to the SAB, one
commenter stated that the new technical
analyses supporting the proposed rule
do not conform to the Information
Quality Act, which requires that
information relied on by EPA be
accurate, reliable, unbiased, and
presented in a complete and unbiased
manner.
Response: The EPA agrees with the
commenters that state that the new
technical analyses (e.g., the risk
assessments and technology assessment)
confirm the 2000 finding and disagrees
with the commenters that state
otherwise. The EPA also agrees with the
commenters that the 2000 finding was
valid at the time it was made based on
the CAA section 112(n)(1) studies and
other information available to the
Agency at that time. Furthermore, the
EPA agrees with commenters that the
final rule will lead to substantial
reductions in HAP emissions from
EGUs, that control of the HAP is
estimated to lead to public health and
environmental benefits as discussed in
the RIA, that Hg emissions from U.S.
EGUs pose a hazard to public health,
and that non-Hg HAP emissions from
EGUs pose a hazard to public health.
Although these new analyses were not
required, the EPA agrees with the
commenters that stated that EPA is
authorized to conduct additional
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analyses to confirm the 2000 finding.
The EPA disagrees with the
commenter’s assertion that the Agency
is not authorized to consider new
information and at the same time unable
to use the information available in 2000
because, according to the commenter,
that information is ‘‘stale.’’ Under this
theory, the Agency could not ever make
an appropriate and necessary finding
prospectively, thereby excusing the
Agency from its obligations to protect
public health and the environment
because it did not diligently act in
undertaking its statutory responsibility
to establish CAA section 112(d)
standards within two years of listing
EGUs. See CAA section 112(c)(5). This
is an illogical result that finds no basis
in the statute. The EPA also disagrees
with the commenter’s assertion that
EPA may not consider new analyses
conducted after the Utility Study in
determining whether it is appropriate
and necessary to regulate EGUs under
section 112 for the reasons set forth in
the preamble to the proposed rule.77
The EPA disagrees with the
commenter’s implication that EPA
conducted the new analyses because of
alleged flaws in the 2000 finding. As
explained in detail in the preamble to
the proposed rule, the 2000 finding was
wholly valid and reasonable based on
the information available to the Agency
at that time, including the Utility Study.
Further, the EPA maintains that had it
complied with the statutory mandate to
issue CAA section 112(d) standards
within two years of listing EGUs, the
EPA would likely have declined to
conduct new analyses. The EPA
conducted new analyses because over
10 years had passed since the 2000
finding, and EPA wanted to evaluate
HAP emissions from U.S. EGUs based
on the most accurate information
available, though the Agency was not
required to reevaluate the 2000 finding.
In conducting the new analyses, the
EPA used this updated information to
further support the finding.
The EPA strongly disagrees with the
commenter that stated that EPA failed to
conform to the Information Quality Act.
The EPA used peer reviewed
information and quality-assured data in
all aspects of the technical analyses
used to support the appropriate and
necessary finding supporting this
regulation. In addition, the EPA
submitted the Hg Risk TSD to the SAB
for peer review, which ‘‘supports the
overall design of and approach to the
risk assessment and finds that it should
provide an objective, reasonable, and
credible determination of the potential
for a public health hazard from mercury
emitted from U.S. EGUs.’’ 78 The SAB
received the comments from Dr. Willie
Soon, and had those comments
available for consideration in their
deliberations regarding the Hg risk
analysis. The SAB specifically
supported elements of the analysis
criticized by Dr. Willie Soon regarding
the use of the EPA RfD as a benchmark
for risk and the connection between Hg
emissions from U.S. EGUs and MeHg
concentrations in fish. In addition, the
risk assessment methodology for the
non-Hg case studies is consistent with
the methodology that EPA uses for
assessments performed for Risk and
Technology Review rulemakings, which
underwent peer review by the SAB in
2009. 79 During the public comment
period, the EPA also completed a letter
peer review of the methods used to
develop inhalation cancer risk estimates
for Cr and Ni compounds, and those
reviews were generally supportive. See
above description of this peer review.
For the final rulemaking, the EPA
revised both risk assessments consistent
with recommendations from the peer
reviewers. The EPA relies on the SAB’s
review of the quality of the information
supporting the analytical results.
Accordingly, contrary to the
commenters’ assertions, the EPA acted
consistently with the Information
Quality Act as well as EPA’s and OMB’s
peer review requirements.
b. Hg Emissions Estimates
1. Hg Emissions From EGUs
Comment: The commenters addressed
the 2005 and 2016 emissions estimates
for Hg and expressed concern that
inaccuracies in these emissions
estimates result in overestimates of risks
from Hg deposition. Further,
commenters compared EPA’s 2010
estimate and 2016 estimate, and stated
that it is not possible for 29 tons to be
a correct inventory total for Hg
emissions in both years given expected
reductions from CSAPR. In addition,
commenters specifically commented on
assumptions included in the Integrated
Planning Modeling (IPM), including a
concern that Hg speciation factors used
by IPM overestimate emissions in 2016.
Other commenters noted that EGU
sources are the predominant source of
U.S. anthropogenic Hg emissions,
particularly the oxidized and particulate
forms of Hg that are of primary concern
for Hg deposition.
Response: The EPA disagrees with
commenters’ assertions that the EPA’s
78 U.S.
77 76
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emissions estimates overestimate risk.
While EPA agrees that the 2005 Hg
emissions may be overestimated, such
an overestimate in 2005 would actually
lead to an underestimate of risk in 2016
and not an overestimate of risk, as
claimed by the commenter, because the
ratio approach used by EPA to scale fish
tissue data would underestimate risk if
2005 Hg estimates were overestimated.
Since the 2005 emissions are not used
as a starting point for 2016 emissions
from IPM, any 2005 overestimate does
not affect the 2016 emissions levels. The
2016 emissions are computed by IPM
based on forecasts of demand, fuel type,
Hg content of the fuel, and the
emissions reductions resulting from
each unit’s configurations. See IPM
Documentation for further information,
which is available in the docket. No
commenter has provided any evidence
that the IPM 2016 emissions projection
methodology resulted in an
overestimate.
The EPA acknowledges that the
current Hg emissions estimate would
not be the same as the 2016 Hg
emissions estimate given that
compliance with CSAPR is anticipated
to have some Hg co-benefits. For this
reason, the EPA reflected emission
reductions anticipated from CSAPR in
the Hg deposition modeling for 2016 in
the Hg Risk TSD. In the final rule, the
EPA revised the estimate of Hg
emissions remaining from U.S. EGUs in
2016, which includes additional
emission reductions anticipated from
the final CSAPR. The revised estimate
shows that U.S. EGUs would emit 27
tons of Hg in 2016. Although EPA does
not use the current Hg emissions
estimates in any of the risk calculations,
the EPA estimates that current Hg
emissions are 29 tons. Conclusions
about the trend between current
emissions and emissions in 2016 are
limited by the fact that different
methods were used to compute the two
estimates, as fully explained in the
revised Emissions Overview memo in
the docket.
The EPA disagrees with the
commenter’s assertion that incorrect Hg
emission factors result in incorrect 2016
emissions. The 2016 projected Hg
emissions are not based on emissions
factors. The 2016 Hg emissions are
computed by the IPM based on forecasts
of demand, fuel type, Hg content of the
fuel, and the emissions reductions
resulting from each unit’s
configurations. The speciation factors
referenced by the commenter provide a
basis for the speciation of total projected
Hg emissions into particulate, divalent
gaseous, and elemental species, and do
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not impact the total amount of Hg
emissions.
The EPA agrees with commenters
who noted that EGU sources are the
predominant source of U.S.
anthropogenic Hg emissions, and in
particular the oxidized and particulate
forms of Hg that are of primary concern
for Hg deposition.
2. Global Hg Emissions
Comment: Several commenters stated
that predicted Hg deposition relies
heavily on the amount of gaseous
elemental Hg used to define the
boundary and initial conditions of a
model, e.g., the Hg that enters the U.S.
from outside the U.S. boundaries. The
commenters asserted that this is
especially important because Hg
emissions from Asia—the region
immediately upwind of North America
that affects U.S. Hg deposition
significantly and also affects it the most
compared to other regions—are
expected to continue to
increase.80 81 82 83 84 85 According to the
commenter, this would affect the
amount of Hg in the boundary and
initial conditions. The commenters
claim that EPA’s modeling did not
account for these emission changes,
thus leading to an overestimate of U.S.
EGU-attributable deposition in 2016.
Several commenters noted that Hg
emissions from U.S. EGUs are small
when compared to global Hg emissions
totals and natural sources within the
U.S. These commenters used a variety of
information to support alternative
conclusions about the necessity to
control U.S. EGU emissions to reduce
Hg risk: global Hg emissions
80 Jaffe D., Prestbo E., Swartzendruber P., WeissPenzias P., Kato S., Takami A., Hatakeyama S., Kajii
Y., 2005. ‘‘Export of Atmospheric Mercury From
Asia,’’ Atmospheric Environment, 39, 3029–3038.
81 Jaffe D., Strode S., 2008. ‘‘Fate and Transport
of Atmospheric Mercury From Asia,’’
Environmental Chemistry, 5, 121.
82 Pacyna E.G., Pacyna J.M., Sundseth K., Munthe
J., Kindbom K., Wilson S., Steenhuisen F., Maxson
P., 2010. ‘‘Global Emission of Mercury to the
Atmosphere From Anthropogenic Sources in 2005
and Projections to 2020,’’ Atmospheric
Environment, 44, 2487–2499.
83 Pirrone N., Cinnirella S., Feng X., Finkelman
R.B., Friedli H.R., Leaner J., Mason R., Mukherjee
A.B., Stracher G.B., Streets D. G., Telmer K., 2010.
‘‘Global Mercury Emissions to the Atmosphere
From Anthropogenic and Natural Sources,’’
Atmospheric Chemistry and Physics, 10, 5951–
5964.
84 Streets, D.G., Zhang, Q., Wu, Y., 2009.
‘‘Projections of Global Mercury Emissions in 2050.’’
Environmental Science & Technology 43, 2983–
2988.
85 Weiss-Penzias P., Jaffe D., Swartzendruber P.,
Dennison J.B., Chand D., Hafner W., Prestbo E.,
2006. ‘‘Observations of Asian Air Pollution in the
Free Troposphere at Mt. Bachelor Observatory in
the Spring of 2004,’’ Journal of Geophysical
Research, 110, D10304.
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inventories, global and regional
photochemical modeling research, and
observation-based assessments. A
commenter stated that EPA has not
acknowledged the dramatic decline in
Hg emissions from U.S. EGUs since the
late 1990s (approximately 50 percent) to
the current level or consider the relative
magnitude of Hg emissions from U.S.
EGUs compared to other sources,
natural (such as fires) and humancaused.
Response: The EPA disagrees that
boundary and initial conditions used in
modeling Hg deposition need
adjustment for several reasons. First, the
EPA does not use the first 10 days of the
modeling simulation in the analysis,
which is more than sufficient to remove
the influence of initial conditions on Hg
deposition estimates.86 Second, it is
difficult to accurately characterize the
speciation of Hg that flows into the U.S.
from other countries due to the lack of
data near the boundaries of the
modeling domain. Third, the boundary
inflow for the CMAQ Hg modeling used
in the Hg deposition modeling are based
on a global model GEOS–CHEM
simulation using a 2000 based global
inventory.87 A recently published
comparison of global Hg emissions by
continent for 2000 and 2006 found that
total Hg emissions from Asia (and
Oceania) total 1,306 Mg/yr in 2000 and
1,317 Mg/yr in 2006.88 The EPA has
determined that because the Asian Hg
emissions estimated in this study are
nearly constant between 2005 and 2006,
any adjustments to the boundary
conditions or adjustments to modeled
Hg deposition would be invalid and
inappropriate. Recent research has
shown that ambient Hg concentrations
have been decreasing in the northern
hemisphere since 2000.89 Because
emissions from Asia have not
appreciably changed between 2000 and
2006 and ambient Hg concentrations
have been decreasing, ENVIRON’s
analysis contains incorrect assumptions
and we need not address them further.
For these reasons and the large
uncertainties surrounding projected Hg
86 Pongprueksa, P., Lin, C.J., Lindberg, SE., Jang,
C., Braverman, T., Bullock, O.R., Ho, T.C., Chu,
H.W., 2008. ‘‘Scientific Uncertainties in
Atmospheric Mercury Models III: Boundary and
Initial Conditions, Model Grid Resolution, and Hg
(II) Reduction Mechanism.’’ Atmospheric
Environment 42, 1828–1845.
87 Selin, NE., Jacob, D.J., Park, R.J., Yantosca,
R.M., Strode, S., Jaegle, L., Jaffe, D. 2007. ‘‘Chemical
Cycling and Deposition of Atmospheric Mercury:
Global Constraints From Observations.’’ Journal of
Geophysical Research-Atmospheres 112.
88 Streets et al., 2009.
89 Slemr, F., Brunke, E.G., Ebinghaus, R., Kuss, J.,
2011. ‘‘Worldwide Trend of Atmospheric Mercury
Since 1995.’’ Atmospheric Chemistry and Physics
11, 4779–4787.
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global inventories, the EPA concludes
that the most appropriate technical
choice is to keep the Hg boundary
conditions the same between the 2005
and 2016 simulations.
The EPA also disagrees with the
commenters’ assertion that EPA has not
acknowledged the decline in Hg
emissions for the U.S. EGUs since the
late 1990s. The EPA analyzed historical,
current, and future projected Hg
emissions from the power generation
sector, as cited in the preamble to the
proposed rule. The EPA also disagrees
with the commenters’ assertions that
EPA failed to consider the relative
magnitude of Hg emissions from U.S.
EGUs compared to other sources. As
noted in the Hg Risk TSD, the EPA
modeled Hg emissions from U.S. and
non-U.S. anthropogenic and natural
sources to estimate Hg deposition across
the country. The EPA also determined
the contribution of Hg emissions from
U.S. EGUs to total Hg deposition in the
U.S. by running modeling simulations
for 2005 and 2016 with Hg emissions
from U.S. EGUs set to zero. Based on the
Hg Risk TSD, Hg emissions from U.S.
EGUs pose a hazard to public health
based on the total of 29 percent of
modeled watersheds potentially at-risk.
Our analyses show that of the 29
percent of watersheds with population
at-risk, in 10 percent of those
watersheds U.S. EGU deposition alone
leads to potential exposures that exceed
the MeHg RfD, and in 24 percent of
those watersheds, total potential
exposures to MeHg exceed the RfD and
U.S. EGUs contribute at least 5 percent
to Hg deposition.
The commenters suggest that Hg
emissions from U.S. EGUs represent a
limited portion of the total Hg emitted
worldwide, including anthropogenic
and natural sources. While EPA
acknowledges that Hg emissions from
U.S. EGUs are a small fraction of the
total Hg emitted globally, it views the
environmental significance of Hg
emissions from U.S. EGUs and other
domestic sources as a more germane
consideration. Mercury is emitted from
EGUs in three forms. Each form of Hg
has specific physical and chemical
properties that determine how far it
travels in the atmosphere before
depositing to the landscape. Although
gaseous oxidized Hg and particle-bound
Hg are generally local/regional Hg
deposition concerns, all forms of Hg
may deposit to local or regional
watersheds. U.S. coal-fired power plants
account for over half of the U.S.
controllable emissions of the quickly
depositing forms of Hg. Although
emissions from international Hg sources
contribute to Hg deposition in the U.S.,
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the peer reviewed scientific literature
shows that Hg emissions from U.S.
EGUs in the U.S. significantly enhance
Hg deposition and the response of
ecosystems in the U.S. 90 91 92 93
c. Hg Deposition Modeling
1. General Comments on Deposition
Modeling
Comment: Several commenters stated
that according to the ENVIRON report,
the EPA overestimated U.S. EGUattributable Hg deposition by 10 percent
on average (and up to 41 percent in
some areas). The commenters claim this
overestimation is the result of boundary
condition treatment, the exclusion of
U.S. fire emissions,94 and Hg plume
chemistry approach. In addition, one
commenter referenced the same
ENVIRON report and stated that before
implementation of controls required by
the proposed rule, areas with relatively
high EGU-attributable Hg deposition
(one-fifth or more of total deposition) in
2016 constitute less than 0.25 percent of
the continental U.S. area, and only three
grid cells have EGU contributions
exceeding half of total deposition.
Another commenter suggested that
current research shows that models of
Hg atmospheric fate and transport
overestimate the local and regional
impacts of some anthropogenic sources,
such as U.S. EGUs. Thus, according to
the commenter, calculated contributions
to Hg deposition and fish tissue MeHg
levels from these sources represent
upper bounds of actual
contributions,95 96 and EPA should
90 Caffrey
et al., 2010.
C. T., Han, Y.-J., Chen, C. Y., Evers,
D. C., Lambert, K. F., Holsen, T. M., et al., (2007).
‘‘Mercury Contamination in Forest and Freshwater
Ecosystems in the Northeastern United States.’’
BioScience, 57(1).
92 Keeler, G.J., Landis, M.S., Norris, G.A.,
Christianson, E.M., Dvonch, J.T., 2006. ‘‘Sources of
Mercury Wet Deposition in Eastern Ohio, USA.’’
Environmental Science & Technology 40, 5874–
5881.
93 White, E.M., Keeler, G.J., Landis, M.S., 2009.
‘‘Spatial Variability of Mercury Wet Deposition in
Eastern Ohio: Summertime Meteorological Case
Study Analysis of Local Source Influences.’’
Environmental Science & Technology 43, 4946–
4953.
94 Finley, B.D., Swartzendruber, P.C., Jaffe, D.A.,
2009. ‘‘Particulate Mercury Emissions in Regional
Wildfire Plumes Observed at the Mount Bachelor
Observatory.’’ Atmospheric Environment 43, 6074–
6083.
95 Seigneur, C., Lohman, K., Vijayaraghavan, K.,
Shia, R.L., 2003. ‘‘Contributions of global and
regional sources to mercury deposition in New York
State.’’ Environmental Pollution 123, 365–373.
96 Seigneur, C., Vijayaraghavan, K., Lohman, K.,
Karamchandani, P., Scott, C., 2004. ‘‘Modeling the
atmospheric fate and transport of mercury over
North America: power plant emission scenarios.’’
Fuel Processing Technology 85, 441–450.
97 Kolker, A., Olson, M.L., Krabbenhoft, D.P.,
Tate, M.T., Engle, M.A., 2010. ‘‘Patterns of mercury
91 Driscoll,
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9339
present results as estimates of lower and
upper bound limits.
Response: The EPA disagrees with the
information presented by ENVIRON.
The ENVIRON report is based on the
misapplication of multiple
incommensurate modeling studies and
false premises which include the
incorrect notion that the boundary
conditions are over-estimated and the
idea that EPA should use in-plume
chemistry that has not been explicitly
characterized and peer reviewed.
Reactions that may reduce gas phase
oxidized Hg in plumes have not been
explicitly identified in literature. Recent
studies in central Wisconsin and central
California suggest the opposite may
happen; elemental Hg may be oxidized
to Hg(II) in plumes.97 98 Better field
study measurements and specific
reaction mechanisms need to be
identified before making conclusions
about potential Hg in-plume chemistry
or applying surrogate reactions in
regulatory modeling. The possibility
that Hg(0) is oxidized to Hg(II) in
plumes suggests coal-fired power plant
Hg contribution inside the U.S. may be
underestimated in EPA modeling.
The EPA asserts that the numbers
suggested by the commenter are
inaccurate, as it is not appropriate to
adjust EPA’s deposition estimates based
on previous Hg modeling done with
older Hg chemistry, in-plume reactions
that have not been explicitly identified,
and erroneous adjustments to Hg
boundary inflow. Recent research has
shown that ambient Hg concentrations
have been decreasing in the northern
hemisphere since 2000.99 The EPA
declines to revise this analysis as
commenter suggests for several reasons,
including available evidence indicates
that emissions from China have not
appreciably changed between 2000 and
2006 100 and ambient Hg concentrations
have decreased, the commenter
inappropriately comingled out–of-date
Hg modeling simulations with EPA
results, and ENVIRON’s analysis has not
undergone any scientific peer review
and presents information with incorrect
assumptions as noted in this response.
The EPA also disagrees with the
commenter’s interpretation of the
applicability of wildfire Hg emissions to
dispersion from local and regional emission
sources, rural Central Wisconsin, USA.’’
Atmospheric Chemistry and Physics 10, 4467–4476.
98 Rothenberg, SE., McKee, L., Gilbreath, A., Yee,
D., Connor, M., Fu, X.W., 2010. ‘‘Wet deposition of
mercury within the vicinity of a cement plant
before and during cement plant maintenance.’’
Atmospheric Environment 44, 1255–1262.
99 Slemr et al., 2011.
100 Streets et al., 2009.
101 Finley et al., 2009.
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this assessment. Finley et al., (2009) 101
suggests caution when using their field
data to make assumptions about Hg(p)
emissions from wildfires; the estimated
particulate Hg emissions from wildfires
is based on one field site with a limited
sample size, and the assumptions made
(such as the observed Hg(p) to carbon
monoxide ratios at this location) may
not be valid on a broader scale.102
Mercury emissions from wildfires are a
re-volatilization of previously deposited
Hg.103 Given that electrical generating
power plants are currently and
historically have been among the largest
Hg-emitting sources, the inclusion of
wildfire emissions in a modeling
assessment would necessarily increase
the contribution from this emissions
sector.
The EPA disagrees with the assertion
that EPA failed to consider the relative
magnitude of Hg emissions from U.S.
EGUs compared to other sources and
disagrees with the interpretation of EGU
deposition presented in the ENVIRON
report. As noted in the Hg Risk TSD, the
EPA modeled Hg emissions from U.S.
and non-U.S. anthropogenic and natural
sources to estimate Hg deposition across
the country. The EPA also determined
the contribution of Hg emissions from
U.S. EGUs to total Hg deposition in the
U.S. by running modeling simulations
for 2005 and 2016 with Hg emissions
from U.S. EGUs set to zero. Hg
emissions from U.S. EGUs pose a hazard
to public health based on the total of 29
percent of modeled watersheds
potentially at-risk. Our analyses show
that of the 29 percent of watersheds
with population at-risk, in 10 percent of
those watersheds U.S. EGU deposition
alone leads to potential exposures that
exceed the MeHg RfD, and in 24 percent
of those watersheds, total potential
exposures to MeHg exceed the RfD and
U.S. EGUs contribute at least 5 percent
to Hg deposition. The ENVIRON report
provides no risk analysis of EGU
contribution.
The EPA disagrees that research 104 105
presented by the commenter shows that
U.S. EGU impacts are over-estimated.
The commenter’s references do not
support this statement. The references
provided by the commenter are based
on Hg modeling that uses models that
are no longer applied and that are based
on out-dated Hg chemistry and
deposition assumptions. Given the
advances in Hg modeling since the early
2000s, the EPA does not believe an
upper and lower bound estimate is
necessary.
100 Streets
101 Finley
et al., 2009.
et al., 2009.
102 Id.
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2. Chemical Reactions
Comment: Several commenters stated
that the CMAQ modeling fails to
account for the chemical reduction of
gaseous ionic Hg to elemental Hg that
may occur in EGU plumes. The
commenters noted that EPA did not use
the Electric Power Research Institute’s
(EPRI) Advanced Plume-in-Grid
Treatment, which includes a surrogate
reaction to reduce gaseous ionic Hg to
elemental Hg inside plumes. Multiple
commenters claimed that the reduction
of reactive gaseous Hg to gaseous
elemental Hg has been reported in
power plant plumes and that supporting
data include atmospheric
concentrations of speciated Hg
measured downwind of power plant
stacks at ground-level monitor sites and
dispersion model predictions.106 107 A
detailed description of various plume
measurement studies is provided in
EPRI Comments, Section 3.4: Plant
Bowen, Georgia, Plant Pleasant,
Wisconsin, and Plant Crist, Florida. One
commenter believed the impact of grid
resolution (12 km sized grid cells) on
the CMAQ modeling was not
appropriately addressed by EPA. Their
concerns due to grid resolution include
the notion that a source’s emissions will
be averaged over the entire grid cell.
According to the commenter, such
averaging causes an artificially fast
dilution that smoothes out areas of high
and low deposition, which may limit
the ability of the model to simulate
smaller areas of localized high
deposition. This commenter believed
that using the APT would address these
issues.
Response: The EPA disagrees with the
commenters’ claims that oxidized Hg
chemically reduces to elemental
mercury within the plume. There is no
evidence of these chemical reactions in
the scientific literature. The references
cited by the commenters are from nonpeer reviewed reports and conference
proceedings. The EPA does not consider
information presented at conferences or
industry reports to be peer reviewed
literature, and consideration of oral
presentation material would be
inappropriate. Further, even these cited
references do not provide sufficient
information for incorporating the
supposed reactions into the modeling
(e.g., specific chemical reactions,
reaction rates, etc.); rather, the cited
references only suggest that oxidized gas
phase Hg could be reduced and
postulate a possible pathway.
Recent studies in central Wisconsin
and central California suggest the
opposite may happen; elemental Hg
may be oxidized to Hg(II) in
plumes.108 109 Better field study
measurements and specific reaction
mechanisms need to be identified before
making conclusions about potential Hg
in-plume chemistry or applying
surrogate reactions in regulatory
modeling. Currently, models such as
Advanced Plume Treatment (APT) use a
surrogate reaction for the potential
reactive gas phase Hg reduction that
may or may not occur in plumes.110
Reactions that may reduce gas phase
oxidized Hg in plumes have not been
explicitly identified in literature. The
application of potentially erroneous inplume chemistry that is a fundamental
component of APT would be
inappropriate. In addition, the APT is
not available in the most recent version
of CMAQ. It would be inappropriate for
EPA to apply an out of date
photochemical model with in-plume
chemistry that has not been shown to
exist.
The EPA agrees with the commenter
that the CMAQ modeling with 12 km
grid resolution may provide a lower
bound estimate on EGU contribution as
higher impacts using finer grid
resolution are possible. The
commenter’s assertion that EGU impacts
are likely higher further supports the
final conclusions of the exposure
modeling assessment. The EPA notes
that the application of a photochemical
model at a 12 km grid resolution for the
entire continental U.S. is more robust in
terms of grid resolution and scale that
anything published in literature and
represents the most advanced modeling
platform used for a national Hg
deposition assessment.
3. Modeled Deposition Compared to
Measured Deposition
Comment: Multiple commenters
expressed dissatisfaction related to
EPA’s model performance evaluation of
CMAQ estimated Hg deposition. The
commenters stated that EPA failed to
evaluate the CMAQ model against realworld measurements and that EPA fails
to provide first-hand information on wet
and dry deposition processes. The
commenters also stated that EPA needs
108 Kolker
et al., 2010.
et al., 2010.
110 Vijayaraghavan, K., Seigneur, C.,
Karamchandani, P., Chen, S.Y., 2007.
‘‘Development and application of a multipollutant
model for atmospheric mercury deposition.’’
Journal of Applied Meteorology and Climatology 46,
1341–1353.
109 Rothenberg
103 Wiedinmyer,
C., Friedli, H., 2007. ‘‘Mercury
emission estimates from fires: An initial inventory
for the United States.’’ Environmental Science &
Technology 41, 8092–8098.
104 Seigneur et al., 2003.
105 Seigneur et al., 2004.
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to assess how predicted values of
deposition compare to Mercury
Deposition Network (MDN) data and
how predicted values of ambient
speciated Hg concentrations compare to
measurement networks like AMNet and
SEARCH. In addition, commenters
stated that EPA used highly aggregated
performance metrics comparing model
estimates to observations that they
believe result in a degraded and lenient
operational evaluation of the modeling
system. A commenter suggested that
EPA’s model performance provides no
confidence for the intended purpose of
estimating deposition near point
sources. One commenter simply noted
that EPA’s model over-estimated total
Hg wet deposition at MDN monitors.
Finally, several commenters noted that
EPA presented a negative modeled wet
deposition total in the Air Quality
Modeling TSD, which is physically
impossible.
Response: EPA agrees with the
commenters that the negative estimate
for wet deposition in the Air Quality
Modeling TSD was an error. This error
reflected an incorrect calculation in the
post-processing of model and
observation pairs that only influenced
the calculation of model performance
metrics. The error has been fixed, and
the model performance metrics in the
revised Air Quality Modeling TSD have
been updated. This error did not affect
Hg deposition. In response to
comments, the EPA provided additional
model performance evaluation by
season to the revised Air Quality
Modeling TSD. In addition, in response
to comments, the EPA also included
model performance evaluation for total
Hg wet deposition for the 36 km
modeling domain in the revised Air
Quality Modeling TSD.
The EPA disagrees that it did not
conduct an assessment comparing
CMAQ total Hg wet deposition
estimates to MDN data. The Air Quality
Modeling TSD clearly shows a
comparison of CMAQ estimated total Hg
wet deposition with MDN data for the
entire length of the modeling period.
The CMAQ wet deposition of Hg has
been and will continue to be extensively
evaluated against MDN sites.111 There is
no dry deposition monitoring network,
which precludes evaluating CMAQ dry
deposition processes. The EPA disagrees
that an evaluation of ambient speciated
111 Bullock, O.R., Atkinson, D., Braverman, T.,
Civerolo, K., Dastoor, A., Davignon, D., Ku, J.Y.,
Lohman, K., Myers, T.C., Park, R.J., Seigneur, C.,
Selin, NE., Sistla, G., Vijayaraghavan, K., 2009. ‘‘An
analysis of simulated wet deposition of mercury
from the North American Mercury Model
Intercomparison Study.’’ Journal of Geophysical
Research-Atmospheres 114.
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Hg against routine monitor networks
such as AMNet or SEARCH would be
useful for this particular modeling
application. The AMNet Hg network did
not exist in 2005, which is EPA’s
baseline model simulation time period,
and the SEARCH network started
making preliminary measurements of
Hg at one or two sites in 2005. In
addition, measurement artifacts related
to gaseous oxidized Hg are difficult to
quantify and make direct comparison to
model estimates problematic.112
Considering the problems associated
with TEKRAN measurements of ambient
Hg and the sparse nature of routine
measurements in the U.S., the EPA did
not compare ambient Hg against model
estimates.
The EPA disagrees that the model
performance presented in the air quality
TSD is insufficient. The EPA asserts that
the model performance evaluation is
generally similar to the level of model
performance presented in literature.
One commenter presented the results of
several Hg modeling studies as
providing information that the
commenter believes to be relevant for
this assessment in terms of model
performance metric estimation and the
level of model performance evaluation
shown for assessments modeling Hg
near point sources. For example, one
cited study titled ‘‘Modeling Mercury in
Power Plant Plumes’’ models nearsource Hg chemistry from U.S. EGUs,
but provides absolutely no information
about model performance evaluation.113
Another commenter identified two
studies as supposedly having Hg
modeling results that are applicable to
EPA’s analysis.114 115 These studies
present similar model performance
metrics as EPA. The EPA disagrees that
the Agency used ‘‘highly aggregated
performance metrics’’ that result in
degraded and lenient model evaluation.
The studies presented 116 117 as relevant
112 Lyman, S.N., Jaffe, D.A., Gustin, M.S., 2010.
‘‘Release of mercury halides from KCl denuders in
the presence of ozone.’’ Atmospheric Chemistry and
Physics 10, 8197–8204.
113 Lohman et al., 2006.
114 Seigneur, C., Lohman, K., Vijayaraghavan, K.,
Jansen, J., Levin, L., 2006. ‘‘Modeling atmospheric
mercury deposition in the vicinity of power
plants.’’ Journal of the Air & Waste Management
Association 56, 743–751.
115 Vijayaraghavan, K., Karamchandani, P.,
Seigneur, C., Balmori, R., Chen, S.–Y., 2008.
‘‘Plume-in-grid modeling of atmospheric mercury.’’
Journal of Geophysical Research-Atmospheres 113.
116 Seigneur, C., Lohman, K., Vijayaraghavan, K.,
Jansen, J., Levin, L., 2006. ‘‘Modeling atmospheric
mercury deposition in the vicinity of power
plants.’’ Journal of the Air & Waste Management
Association 56, 743–751.
117 Vijayaraghavan, K., Karamchandani, P.,
Seigneur, C., Balmori, R., Chen, S.-Y., 2008.
‘‘Plume-in-grid modeling of atmospheric mercury.’’
Journal of Geophysical Research-Atmospheres 113.
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for point source mercury modeling use
an approach to aggregate the operational
performance metrics across many
monitor locations as did EPA; however,
these articles calculate long term annual
averages of modeled and observed total
Hg wet deposition before estimating
performance metrics. It is common
practice to pair modeled estimates and
observations in space and time (weekly
in this case) and estimate performance
metrics, then average all the metrics
together. The latter is the approach
taken by the EPA and should have been
taken by the studies presented by the
commenter. The EPA used a more
stringent approach to match
observations and predictions and
aggregation of operational model
performance. The EPA agrees that the
commenter accurately restated total wet
deposition model performance
information provided by the EPA in the
Air Quality Modeling TSD. To provide
context, other Hg modeling studies
show a positive bias for annual total Hg
wet deposition.118 119 An annual Hg
modeling application done by
ENVIRON 120 and the Atmospheric and
Environmental Research for Lake
Michigan Air Directors Consortium
show seasonal average normalized bias
between 70 and 158 percent and
seasonal average normalized error
between 72 and 503 percent.121 These
results indicate a very large overestimation tendency. The model
performance shown by EPA is
consistent with other long-term Hg
modeling applications.
4. Excess Local Deposition From Hg
Emissions From U.S. EGUs (Deposition
Hotspots)
Comment: One commenter stated that
reducing Hg will benefit local
environments. The commenter stated
that a 2007 study confirmed the
presence of Hg ‘‘hotspots’’ downwind
from coal-fired power plants and
confirmed that coal-fired power plants
within the U.S. are the primary source
of Hg to the Great Lakes and the
Chesapeake Bay.122 The commenter also
stated that the study is consistent with
a major Hg deposition study conducted
118 Id.
119 Vijayaraghavan
et al., 2007.
G, Lau, S., Jia, Y., Karamchandani,
P., Vijayaraghavan, K. 2003. Final Report: Modeling
Atmospheric Mercury Chemistry and Deposition
with CAMx for a 2002 Annual Simulation. Prepared
for Wisconsin Department of Natural Resources.
https://www.gypsymoth.wi.gov/air/toxics/mercury/
hg_X97579601_appB.pdf.
121 Yarwood et al., 2003.
122 Evers, David C. et al., 2007. ‘‘Biological
Mercury Hotspots in the Northeastern United States
and Southeastern Canada,’’ Bioscience. Vol. 57 No.
1. p. 29.
120 Yarwood,
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by the EPA and the University of
Michigan that concluded that
approximately 70 percent of Hg wet
deposition resulted from local fossil fuel
emissions in the region.123
One commenter agreed with the
Agency’s assessment of the potential for
deposition ‘‘hotspots’’ that shows that
Hg deposition near EGUs can be three
times as large as the regional average.
The commenter stated that this excess
Hg deposition would substantially
increase the health and environmental
risks associated with emissions at these
sites. The same commenter also stated
that EPA applied a conservative
methodology to quantify near-source Hg
deposition. The commenter stated that
maximum excess local Hg deposition
may be significantly underestimated by
averaging high deposition sites
downwind of an EGU in the direction of
prevailing winds with lower excess
deposition at locations close to but
frequently upwind of the facility. The
same commenter suggests that had EPA
used CMAQ and individual 12x12 km2
grid cells to quantify local deposition,
the model could increase the excess Hg
deposition at these locations
significantly and place them at even
greater risk of adverse health and
environmental effects of HAP from U.S.
EGUs.
One commenter stated that the
Hubbard Brook Research Foundation
issued a report in 2007 that identified
five Hg hotspots, one of which was in
the Adirondack Park, along with four
suspected hotspots.124 The commenter
stated that this study also provides a
good description of the impacts of Hg on
the Common Loon, which is a symbol
of a healthy Adirondack environment.
One commenter stated that there is
there is no evidence of Hg hotspots due
to local deposition associated with coalfired power plants. According to the
commenter, the EPA’s use of a 50 km
radius to calculate hotspots is flawed.
The commenter stated that modeling
studies show that deposition of Hg
emitted from power plants is not
confined to a 50-km radius around the
plants and that most emissions from
power plants travel beyond 50 km.125
Several commenters stated that the
EPA does not adequately define
123 Cohen, et al., 2004. ‘‘Modeling the
Atmospheric Transport and Deposition of Mercury
to the Great Lakes,’’ Environmental Research 95,
(247–265).
124 Driscoll, C.T., D. Evers, K.F. Lambert, N.
Kamman, T. Holsen, Y-J. Han, C. Chen, W. Goodale,
T. Butler, T. Clair, and R. Munson. Mercury
Matters: Linking Mercury Science with Public
Policy inthe Northeastern United States. 2007.
Hubbard Brook Research Foundation. Science Links
Publication. Vol. 1, no. 3.
125 Seigneur et al., 2006.
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hotspots in this proposed rule. Those
same commenters cited a previous EPA
definition of hotspots as ‘‘a waterbody
that is a source of consumable fish with
MeHg tissue concentrations, attributable
solely to utilities, greater than EPA’s
MeHg water quality criterion of 0.3 mg/
kg’’ (milligrams per kilogram).126 The
same commenters stated that it is
unclear why EPA changed from defining
a hotspot by fish tissue MeHg
concentration to defining a hotspot by
depositional excess. Two commenters
suggested that a Hg hotspot is a specific
location that is characterized by
elevated concentrations of Hg exceeding
a well-established criterion, such as a
reference concentration (RfC) when
compared to its surroundings. Those
same commenters stated that identifying
Hg hotspots should not be constrained
to locations where concentrations can
be attributed to a single source or
sector.127 One of those two commenters
noted that others have defined
‘‘hotspots as a spatially large region in
which environmental concentrations far
exceed expected values, with such
values (i.e. concentrations) being 2 to
three standard deviations above the
relevant mean.’’ 128
One commenter stated that Hg
concentrations are not always highest at
sites closest to a major source. The
commenter referred to a study 129 that
demonstrated that concentrations of
atmospheric reactive gaseous Hg,
gaseous elemental Hg, and fine
particulate Hg were lower when
measured 25 km from a 1,114 MW coalfired EGU than when measured 100 km
away. The commenter stated that these
findings contradict the idea, implicit in
EPA’s hotspot analysis, that reactive
gaseous Hg decreases with distance
from a large point source.
One commenter provided information
from a non-peer reviewed report with
wet Hg deposition measurements
downwind from the coal-fired power
plant Crist in Pensacola, FL. The
commenter stated that using the same
data from these same wet deposition
sites, one study 130 found that Hg wet
126 U.S. EPA, 2005. 40 CFR Part 63 [OAR–2002–
0056; FRL–7887–7] RIN 2060–AM96. Revision of
December 2000 Regulatory Finding on the
Emissions of Hazardous Air Pollutants From
Electric Utility Steam Generating Units and the
Removal of Coal- and Oil-Fired Electric Utility
Steam Generating Units From the Section 112(c).
Final rule, March 29.
127 Evers et al., 2007.
128 Sullivan T., 2005. ‘‘The Impacts of Mercury
Emissions from coal-fired Power Plants on Local
Deposition and Human Health Risk.’’ Presented at
the Pennsylvania Mercury Rule Workgroup
Meeting, October 28.
129 Kolker, et al., 2010.
130 Caffrey, J.M., Landing, W.M., Nolek, S.D.,
Gosnell, K.J., Bagui, S.S., Bagui, S.C., 2010.
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deposition and concentrations did not
differ in a statistically significant
manner among these three sites and that
the concentrations values were similar
to those from Mercury Deposition
Network (MDN) sites that are more than
50 km away from Plant Crist located
along the Northern Gulf of Mexico coast.
Another commenter stated that Plant
Crist installed a wet scrubber and has
operated that scrubber continuously
since December 2009. The commenter
stated that the scrubber reduces total Hg
emissions by about 70 percent and
reduces emissions of reactive gaseous
Hg by about 85 percent. The commenter
cited a non-peer reviewed conference
presentation 131 that reported changes in
Hg wet deposition relative to historic
measurements. The commenter stated
that, taken collectively, these findings
show that increased local total Hg
deposition, possibly due to EGUs, and
deposition changes due to changes in
EGU emissions, are small.
Two commenters stated that a study
by the Department of Energy (DOE) that
collected and analyzed soil and
vegetation samples for Hg near three
U.S. coal-fired power plants—one in
North Dakota, one in Illinois, and one in
Texas—found no strong evidence of
‘‘hotspots’’ around these three plants.
Two commenters stated that analysis
of long-term trends in Hg emissions
from coal-fired EGUs and wet
deposition in Florida concluded that
statistical analysis does not show
evidence of a significant relationship
between temporal trends in Hg
emissions from coal-fired EGUs in
Florida and Hg concentrations in
precipitation during 1998 to 2010.
Two commenters stated that the Hg
Risk TSD presents no information,
summary statistics, and/or actual
calculations showing how excess
deposition within 50 km of an EGU
source is obtained. The commenters
stated that by assessing only Hg
deposition attributable to EGUs, the
EPA fails to provide a context for all
other sources of Hg deposition. The
commenters stated that the Agency does
not explain why deposition from the top
10 percent of EGU Hg emitters does not
decline, despite substantial reductions
in modeled Hg emissions from those
sources between 2005 and 2016.
‘‘Atmospheric deposition of mercury and major
ions to the Pensacola (Florida) watershed: spatial,
seasonal, and inter-annual variability.’’
Atmospheric Chemistry and Physics 10, 5425–5434.
131 Krishnamurthy N., Landing W.M, Caffrey J.M.,
2011. ‘‘Rainfall Deposition of Mercury and Other
Trace Elements to the Northern Gulf of Mexico.’’
Presented at the 10th International Conference on
Mercury as a Global Pollutant, Halifax, Nova Scotia,
Canada, July 27.
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According to the commenters this
implies that the top 10 percent EGUs
may have approximately as much of a
regional effect as a local effect.
Two commenters stated that the
CMAQ model has limitations when
used to predict local deposition and
tends to overestimate local deposition.
The commenters stated that modeling
studies using either a plume model or
an Eulerian model predict that 91 to 96
percent of the Hg emitted by an EGU
travels beyond 50 km.132
Response: The EPA agrees with the
commenters that stated that Hg
emissions from EGUs deposit locally
and regionally and contribute to excess
local deposition near U.S. EGUs. The
EPA acknowledges additional
studies 133 cited by those commenters
that corroborate EPA’s conclusions.
However, the EPA disagrees with those
commenters’ characterization of the
methodology used to calculate the
potential for excess local deposition. In
response, the EPA has clarified the
methodology in the new TSD entitled
‘‘Technical Support Document:
Potential for Excess Local Deposition of
U.S. EGU Attributable Mercury in Areas
near U.S. EGUs,’’ which is available in
the docket.
The EPA agrees that there is no
generally agreed-upon definition of
‘‘hotspot.’’ As discussed in the preamble
and TSD, for the purposes of the
appropriate and necessary finding, the
EPA determined that information on the
potential for excess deposition of Hg in
areas surrounding power plants would
be useful in informing the finding. The
EPA disagrees with some commenters
who misinterpreted the intent of the Hg
deposition hotspot analysis.
Specifically, the analysis is not of ‘‘Hg
hotspots’’, which are often defined as
high Hg concentration in fish, but rather
of Hg deposition hotspots, defined as
excess local Hg deposition around U.S.
EGUs, as clarified in the new Local
Deposition TSD. Because EPA did not
identify ‘‘Hg hotspots’’ of high Hg
concentrations in fish, the EPA’s MeHg
water quality criterion of 0.3 mg/kg is
irrelevant to EPA’s analysis of excess
local Hg deposition for this rule.
The EPA disagrees that the analysis
assumes that deposition of Hg is
confined to a 50-km radius around
power plants. The purpose of the EPA’s
analysis was to evaluate whether there
existed ‘‘excess deposition of Hg in
nearby locations within 50 km of EGUs
that might result in Hg deposition
‘hotspots’.’’ As explained further in the
new TSD, the EPA calculated the
132 Edgerton
133 Driscoll
et al., 2006.
et al., 2007.
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average EGU-attributable deposition
(based on CMAQ modeling of Hg
deposition) in the area 500 km around
each plant and the average EGUattributable deposition in the area 50 km
around each plant. The difference
between those two values is the excess
local deposition around the plant. The
EPA does not suggest Hg emissions from
power plants stop at 50 km from the
source. Some portion of EGU emissions
deposit before 50 km, and some portion
travels beyond 50 km. In addition, Hg
disperses as it transports, so the average
EGU contribution can be lower in areas
beyond 50km relative to areas within
50km even though Hg emissions from
EGUs are depositing into U.S.
watersheds.
The EPA disagrees with some
commenters’ interpretation of the
analysis as being focused on local
deposition from all sources. In fact, the
focus was on excess local deposition,
rather than all local deposition. The
EPA has clarified the purpose of the
excess local deposition analysis in the
new TSD. The EPA agrees that all EGUs
add to local deposition, however, not all
EGUs have local deposition that greatly
exceeds regional deposition, which is
the relevant question. The EPA
disagrees that the DOE study referenced
by the commenters attempted to assess
the same analytical question as EPA’s
analysis. The DOE study focused on
comparisons of total deposition near
and far from power plants. The EPA’s
analysis did not focus on total Hg
deposition, because as EPA
acknowledges throughout its analysis,
global sources of Hg deposition account
for a large percentage of total Hg
deposition. In addition, including global
sources of Hg deposition would obscure
the comparison of local and regional
U.S. EGU-attributable Hg deposition.
Because of regional deposition from
both domestic and global sources of Hg,
total Hg deposition at any location is
unlikely to be highly correlated with
local sources. The EPA’s analysis
focused on U.S. EGU-attributable Hg
deposition and demonstrates that for
some plants (especially those with high
Hg emissions), there is local deposition
of Hg that exceeds the average regional
deposition around the plant.
The EPA’s analysis shows
heterogeneity in the amount of excess
local deposition around plants. The new
Local Deposition TSD shows that some
plants can have local deposition that is
less than the regional average
deposition, suggesting that most of the
Hg from those plants is transported
regionally or that other EGUs in the
vicinity of those plants dominate the
deposition of Hg near the plants. This
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does not detract from the overall finding
that around some power plants with
high levels of Hg emissions excess local
deposition is on average three times the
regional EGU-attributable deposition
around those plants.
The EPA disagrees that the Hg Risk
TSD did not provide sufficient
information regarding the excess local
deposition calculation. Nonetheless, the
EPA has further clarified the
methodology in the new Local
Deposition TSD, including further
descriptions of the method used to
calculate the local and regional
deposition around power plants along
with maps and tables of results.
The EPA disagrees with the
commenters that stated that the
discussion of local deposition in the Hg
Risk TSD did not demonstrate that Hg
deposition from the top 10 percent of
EGU Hg emitters declines. Table 1 of the
new Local Deposition TSD clearly
shows that mean local deposition
(within 50km of a plant) for the top 10
percent of emitters declines from 4.89
micrograms per cubic meter (mg/m3) to
1.18 mg/m3. What does not change is the
percent local excess for EGUattributable Hg deposition. This implies
that while Hg deposition from EGUs is
declining, there is still an excess
contribution to local deposition relative
to regional deposition; e.g., because of
dispersion, the contribution to average
deposition outside 50 km from the plant
is lower than the contribution to average
deposition within 50 km of the plant.
The EPA disagrees that the
information 134 provided by the
commenter regarding the Crist plant and
other coal-fired power plants in Florida
is relevant to EPA’s analysis of excess
local deposition from U.S. EGUs
because it is based on measurements of
wet Hg deposition without
consideration of dry Hg deposition,
which can be a significant component of
Hg deposition.
The EPA disagrees with the
commenter regarding the interpretation
of the literature related to the spatial
extent of deposition of Hg emitted by
U.S. EGUs. The EPA also disagrees that
the peer-reviewed CMAQ model has
limitations for this application or
overestimates local deposition. The
commenter does not provide any
credible support for the assertion that
grid-based models typically
overestimate local deposition
surrounding EGUs. The EPA maintains
that the CMAQ photochemical model
represents the best science currently
available in simulating atmospheric
134 EPRI,
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chemistry, transport, and deposition
processes.
The study 135 cited by the commenter
to support the notion that 91 to 96
percent of Hg emitted from power plants
travels beyond 50 km is based on a
photochemical transport model (the
TEAM model) that does not employ
current state-of-the-science and is not
actively developed or updated.
Furthermore, the modeling is based on
grid cells that are 20 km in size, which
limits generalizability to EPA modeling
performed at 12 km grid resolution
using a state of the science
photochemical grid model. The cited
modeling study ignores dry deposition
of elemental Hg from all sources, an
assumption that clearly limits the
regional impacts from sources.136 The
methodology of this study cited by the
commenter is critically flawed in that it
presents no results where individual Hg
emission sources are removed and the
difference between the zero out
simulation (where emissions from U.S.
EGUs are set to zero) and the baseline
model simulations are directly
compared. Finally, the modeling study
cited by the commenter presents an
illustration of gridded total annual Hg
deposition from the TEAM model for
the eastern U.S. that clearly shows
elevated annual total Hg deposition in
the vicinity of coal-fired power plants in
the Ohio River Valley and northeast
Texas.
srobinson on DSK4SPTVN1PROD with RULES2
d. Hg Risk TSD
1. Assumption of Linear Proportionality
in Relationship Between Changes in Hg
Deposition and Changes in Fish Tissue
Hg Concentrations (Mercury Maps)
Comment: Several commenters
criticized EPA’s assumption that
changes in deposition resulting from
U.S. EGU emissions of Hg will result in
proportional changes in fish tissue Hg
concentrations at the watershed level, as
supported by the Mercury Maps
modeling exercise. According to one
commenter, the Mercury Maps model
has limited capability to adequately
determine bioaccumulation in fish. The
same commenter stated that the
Mercury Cycling Model (MCM)
developed by EPRI is a more rigorous
model that was developed expressly to
evaluate the relationship between
changes in atmospheric Hg deposition
to waterbodies and changes in fish
tissue MeHg levels.
Several commenters stated that the
Mercury Maps model has many
deficiencies. Those commenters stated
that Mercury Maps is a static model
135 Seigneur
et al., 2006.
136 Id.
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unable to account for the dynamics of
ecosystems that affect Hg
bioaccumulation in fish, cannot
consider non-air Hg inputs to
watersheds, and assumes reductions in
airborne Hg lead to proportional
reductions in fish MeHg concentrations.
Another commenter claimed that data
that demonstrate a steady-state linear
reduction in fish tissue MeHg in
response to a reduction in atmospheric
Hg deposition within watersheds do not
exist and provided several references
that they claimed show non-linear
responses to changes in Hg
deposition.137 138
The same commenter disagreed with
EPA’s interpretation of Figure 2–17 in
the March TSD and stated that a U.S.
Geological Survey national waterway
study 139 showed that sheet flow and
drainage, not deposition, dominated
input to the waterbodies it surveyed.
The commenter stated that sheet flow
and drainage could contain Hg and thus
complicate the relationship that EPA
asserts is linear and direct. Another
commenter cited Figure 2–17 in the Hg
Risk TSD as showing that there is no
well-defined relationship between Hg
deposition and MeHg concentrations in
fish tissue on a national basis.
Several commenters provided
comments related to the assumption
that fish tissue Hg levels used in the
analysis represent a steady-state. One
commenter stated that given the
demonstrated lag time in response to
deposition change, it is logical to
conclude that a lag time needs to be
incorporated in Mercury Maps to adjust
the estimation of how much fish tissue
MeHg levels decrease in response to
decreases in Hg deposition attributable
to U.S. EGUs. According to the same
commenter, the METAALICUS study
shows that there is a lag time (and a
non-proportional response) after 3–4
years. The same commenter noted that
there are numerous factors that
influence lag time including (1)
watershed characteristics,140 (2) the fact
that watersheds may act as legacy
sources releasing Hg when disturbed,141
(3) the magnitude of emission
reductions and subsequent changes in
atmospheric deposition need to be
weighed against the amount of Hg
already in an ecosystem,142 (4) the
distance of an ecosystem from Hg
sources,143 and (5) the fact that Hg
deposited to aquatic ecosystems
becomes less available for uptake by
biota over time.144 Another commenter
stated that additional Mercury Maps
assumptions do not allow for
considerations of lag in response to
changes in: (1) Deposition, (2) legacy
sources of Hg such as mining, (3)
historical Hg deposition, (4) natural Hg
levels in fish, (5) ecosystem dynamics
over time, or (6) the relative source
contributions over time. Another
commenter stated that lag times need to
be included in the modeling and be able
to vary from watershed to watershed
and sometimes even from waterbody to
waterbody within a watershed. Several
commenters stated that the emission
rates of Hg due to U.S. sources have
been decreasing for more than a decade,
while emissions due to sources outside
the U.S. have been increasing. For this
reason, the commenter asserted that the
system is not at steady-state, a basic
premise of the model. Another
commenter stated that while the time
lag for deposition to reach a waterbody
is mentioned in the Hg Risk TSD, there
is no discussion of the fact that a
137 Harris., R.C., John W.M. Rudd, Marc Amyot,
Christopher L. Babiarz, Ken G. Beaty, Paul J.
Blanchfield, R.A. Bodaly, Brian A. Branfireun,
Cynthia C. Gilmour, Jennifer A. Graydon, Andrew
Heyes, Holger Hintelmann, James P. Hurley, Carol
A. Kelly, David P. Krabbenhoft, Steve E. Lindberg,
Robert P. Mason, Michael J. Paterson, Cheryl L.
Podemski, Art Robinson, Ken A. Sandilands,
George R. Southworth, Vincent L. St. Louis, and
Michael T. TateRudd, J. W.M., Amyot M., et al.,
Whole-Ecosystem study Shows Rapid Fish-Mercury
Response to Changes in Mercury Deposition.
Proceedings of the National Academy of Sciences
Early Edition, PNAS 2007 104 (42) pp. 16586–
16591; (published ahead of print September 27,
2007).
138 Orihel D.M., Paterson M.J., Blanchfield P.J.,
Bodaly R.A., Gilmour C.C., Hintelmann H., 2007.
‘‘Temporal Changes in the Distribution,
Methylation, and Bioaccumulation of Newly
Deposited Mercury in an Aquatic Ecosystem,’’
Environmental Pollution, 154, 77–88.
139 Scudder B.C., Chasar L.C., Wentz D.A., Bauch
N.J., Brigham M.E., Moran P.W., Krabbenhoft D.P.,
2009. Mercury in fish, bed sediment, and water
from streams across the United States, 1998–2005:
U.S. Geological Survey Scientific Investigations
Report 2009–5109, 74 p.
140 Grigal D.F., 2002. ‘‘Inputs and Outputs of
Mercury from Terrestrial Watersheds: A Review,’’
Environmental Review, 10, 1–39.
141 Yang H., Rose N.L., Battarbee R.W., Boyle J.F.,
2002. ‘‘Mercury and Lead Budgets for Lochnagar, a
Scottish Mountain Lake and Its Catchment,’’
Environmental Science & Technology, 36, 1383–
1388.
142 Krabbenhoft D.P., Engstrom D., Gilmour C.,
Harris R., Hurley J., Mason R., 2007. Monitoring and
Evaluating Trends in Sediment and Water
Indicators. In Harris R., Krabbenhoft D., Mason R.,
Murray M.W., Reash R., Saltman T. (Eds.),
Ecosystem Responses to Mercury Contamination:
Indicators of Change. New York: Society of
Environmental Toxicology and Chemistry (SETAC)
North America Workshop on Mercury Monitoring
and Assessment, CRC, pp. 47–87.
143 Lindberg S. et al. 2007. ‘‘A synthesis of
progress and uncertainties in attributing the sources
of mercury in deposition.’’ Ambio 36(1): 19–32.
144 Orihel D.M., Paterson M.J., Blanchfield P.J.,
Bodaly R.A., Hintelmann H., 2008. ‘‘Experimental
Evidence of a Linear Relationship between
Inorganic Mercury Loading and Methylmercury
Accumulation by Aquatic Biota,’’ Environmental
Science & Technology, 41, 4952–4958.
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portion of the deposition is unlikely to
reach the water at all.
One commenter believes EPA
incorrectly implied that its EGU risk
estimates using Mercury Maps are
underestimated because they do not
account for legacy EGU-attributable
deposition, which EPA assumes to be
higher.
One commenter stated that while EPA
properly screened out watersheds with
significant current non-air sources of
Hg, the EPA did not adequately screen
out watersheds with significant Hg
contributions from non-air sources,
specifically watersheds with historic Hg
or gold mining or other industrial Hg
discharges. The same commenter stated
that EPA’s study was not geographically
balanced and was dominated by rivers
in the coastal region of the southeast
that has numerous wetlands, which are
favorable locations for methylation and
have conditions that are not typical of
much of the rest of the U.S.
Response: The EPA disagrees with the
commenters who challenged the
assumption of a linear proportional
relationship between changes in U.S.
EGU deposition and fish tissue Hg
levels. The EPA specifically asked the
SAB to evaluate EPA’s assumption of
linear proportionality in the
relationship between Hg deposition and
fish tissue MeHg concentrations,
supported by the Mercury Maps
analysis. The SAB peer review
committee provided the following
overall response, which generally
supports EPA’s approach:
The SAB agrees with the Mercury Maps
approach used in the analysis and has cited
additional work that supports a linear
relationship between mercury loading and
accumulation in aquatic biota. These studies
suggest that mercury deposited directly to
aquatic ecosystems can become quickly
available to biota and accumulated in fish,
and reductions in atmospheric mercury
deposition should lead to decreases in
methylmercury concentrations in biota. The
SAB notes other modeling tools are available
to link deposition to fish concentrations, but
does not consider them to be superior for this
analysis or recommend their use. The
integration of Community Multiscale Air
Quality Modeling System (CMAQ) deposition
modeling to produce estimates of changes in
fish tissue concentrations is considered to be
sound. Although the SAB is generally
satisfied with the presentation of
uncertainties and limitations associated with
the application of the Mercury Maps
approach in qualitative terms, it recommends
that the document include quantitative
estimates of uncertainty available in the
existing literature.145
The SAB peer review committee
specifically addressed the MCM
145 U.S.
EPA–SAB, 2011.
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suggested by the commenter and had
the following response:
The SAB agrees with the application of
Mercury Maps in this assessment. There are
other modeling tools capable of making a
national scale assessment, such as the
Regional Mercury Cycling Model (R–MCM).
However, the R–MCM is more data intensive
and the results produced by the two model
approaches should be equivalent.
The R–MCM, a steady-state version of the
time-dependent Dynamic Mercury Cycling
Model, has been publicly available to and
used by the EPA (Region 4, Athens,
Environmental Research Laboratory) for a
number of years. R–MCM requires more
detail on water chemistry, methylation
potential, etc., and yields more information
as well. Substantial data support the Mercury
Maps and the R–MCM steady-state results, so
that the results of the sensitivity analysis and
the outcomes from using the alternative
models would be equivalent between the two
modeling approaches. Though running an
alternative model framework may provide
additional reassurance that the Mercury
Maps ‘‘base case’’ approach is a valid one, it
is unlikely that substantial additional insight
would be gained with the alternative model
framework.146
In addition, the SAB stated, ‘‘Since
the Mercury Maps approach was
developed, several recent publications
have supported the finding of a linear
relationship between mercury loading
and accumulation in aquatic
biota.147 148 149 These studies suggested
that mercury deposited directly to
aquatic ecosystems can become quickly
available to biota and accumulated in
fish, and that reductions in atmospheric
mercury deposition should lead to
decreases in methylmercury
concentrations in biota. These results
substantiate EPA’s assumption that
proportionality between air deposition
changes and fish tissue methylmercury
level changes is sufficiently robust for
its application in this risk
assessment.’’ 150
Based on the responses of the SAB
peer review committee, the EPA’s use of
the linear proportionality assumption,
supported by the Mercury Maps
analysis, is well-supported.
The EPA also disagrees with
commenters’ interpretation of Figure 2–
17. As stated in the Hg Risk TSD, while
this figure is useful to demonstrate the
lack of correlation across watersheds
between total deposition of Hg and
MeHg concentrations in fish tissue, it is
not indicative of the likely correlation
between changes in Hg deposition at a
given watershed and changes in MeHg
EPA–SAB, 2011.
et al., 2007.
148 Orihel et al., 2008.
149 Harris et al., 2007.
150 U.S. EPA–SAB, 2011.
concentrations in fish tissue from that
watershed. The SAB agreed with this
interpretation, noting the importance of
Figure 2–17 demonstrating that ‘‘spatial
variability of deposition rates is only
one major driver of spatial variability of
fish methylmercury and that variability
of ecosystem factors that control
methylation potential (especially
wetlands, aqueous organic carbon, pH,
and sulfate) also play a key role.’’ 151
In response to recommendations from
the SAB, the EPA expanded the
discussion of uncertainties associated
with the linearity assumption, including
uncertainties related to the potential for
sampled fish tissue Hg level to reflect
previous Hg deposition and the
potential for non-air sources of Hg to
contribute to sampled fish tissue Hg
levels. Each of these sources of
uncertainty may result in potential bias
in the estimate of exposure associated
with current deposition. The EPA took
steps to minimize the potential for these
biases by (1) only using fish tissue Hg
samples from after 1999, and (2)
screening out watersheds that either
contained active gold mines or had
other substantial non-U.S. EGU
anthropogenic emissions of Hg. The
SAB commented that EPA’s approach to
minimizing the potential for these
biases to affect the results of the risk
analysis appears to be sound and that
additional criteria that could be applied
are unlikely to substantially change the
results. As a result, the EPA disagrees
with the commenter that EPA’s
screening process is inadequate. In
addition, we conducted several
sensitivity analyses to gauge the impact
of excluding watersheds with the
potential for non-EGU Hg emissions,
and found that the results were robust
to these exclusions.
In response to specific comments
regarding the use of the Mercury Maps
model, the EPA clarifies that the Hg
Risk TSD did not directly use the
Mercury Maps model. Instead, the EPA
applied an assumption of linear
proportionality between changes in Hg
deposition and changes in MeHg
concentrations in fish that is supported
by the Mercury Maps modeling. By
assuming steady-state conditions in
apportioning fish tissue Hg levels and
risk, the EPA does not attempt to project
lag times. Recent research cited by the
SAB 152 153 154 identifies relatively rapid
response of fish tissue Hg to changes in
Hg loading, which suggests that fish
tissue Hg levels could react more
146 U.S.
147 Orihel
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EPA–SAB, 2011.
et al., 2007.
153 Orihel et al., 2008.
154 Orihel et al., 2007.
152 Orihel
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quickly to reductions in Hg deposition
than previously thought. This finding
reduces concern that fish tissue Hg
levels could be linked to older patterns
of Hg deposition and strengthens the
approach used in the revised Hg Risk
TSD. While fish tissue may respond
rapidly to changes in Hg loading, this
does not change the fact that previously
emitted Hg from U.S. EGUs can be reemitted and re-deposited, and thus
affect Hg concentration in fish.
2. Characterization of Subsistence
Fishing Populations and Exposure
Scenario
Comment: Several commenters stated
that EPA provides no clear definition of
subsistence, near subsistence, or highend fish consumption, instead assuming
that poverty is a direct indication of
subsistence fishing and high-end fish
consumption. One commenter stated no
documentation exists to supports these
assumptions. Another commenter stated
that EPA’s definitions of subsistence
fishers in the Hg Risk TSD are not
consistent with earlier EPA documents
and are used inconsistently throughout
the Hg Risk TSD. Several commenters
stated that while subsistence fishing can
be associated with poverty, poverty does
not indicate subsistence fishing. One
commenter stated that by including
watersheds with as few as 25 members
of individuals living in poverty, the EPA
overstates risks.
One commenter stated that it is
unclear what literature the Agency says
‘‘generally supports the plausibility of
high-end subsistence-like fishing * * *
to some extent across the watersheds’’
and stated that if other studies exist, the
EPA should provide the values for
comparison.
One commenter stated that EPA
combined two parameters with differing
scales to establish the geographic unit
used in the Hg Risk TSD risk
assessment. The HUC watersheds are
based on average about 35 square miles
in size, while U.S. census tracts used to
identify watersheds relevant for
subpopulations of interest—cover a few
tenths to hundreds of square miles.
Several commenters stated that it is
unclear how the analysis handled
differences in geographic resolution
between watersheds and census tracts
were.
One commenter stated that the
procedure for assigning census tracts
could bias exposure outcomes. For
example, the commenter stated that a
single influential census tract in a
watershed could drive risk, even if the
watershed had only a minimal number
of fish samples. The commenter stated
that this possibility is a concern in
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urban areas, which account for the
majority of census tracts, because these
census tracts are more likely to be
included in a risk analysis because they
have more than 25 people living in
poverty. The commenter stated that
these census tracts may drive the
extremes of the distribution without
regard to the actual number of highlevel, self-caught fish consumers within
their boundaries. The commenter stated
that they could not assess the potential
bias and noted that EPA did not test the
bias by sensitivity analyses.
Several commenters stated that EPA
was not clear whether the poverty
criteria were applied in all scenarios or
just for the high-end female fish
consumer scenario. One commenter
stated that EPA should apply the
minimum 25 source population criteria
only to populations of women of
childbearing age. One commenter stated
that EPA’s assumption would result in
any densely populated urban census
tract with a single fish tissue sample
being assigned to a modeled watershed
with populations potentially at-risk,
regardless of the actual degree of
recreational or subsistence fishing
taking place there.
Response: The EPA agrees with the
comments that subsistence fish
consumption was not clearly defined,
and we have provided a clearer
definition in the revised Hg Risk TSD,
however, this clarification does not
result in any changes to the quantitative
analysis. In the revised Hg Risk TSD, the
EPA clarifies that ‘‘subsistence fishers’’
are defined as individuals who rely on
noncommercial fish as a major source of
protein.155 This definition is reflected in
the range of fish consumption rates used
in estimating risk. The likely presence
of this type of subsistence fish consumer
is supported by available peer reviewed
literature (see Table 1–5 of the revised
Hg Risk TSD). These studies clearly
show that a subset of surveyed fishers
consumes self-caught fish at the rates
cited in the Hg Risk TSD. The SAB peer
review concluded that the consumption
rates and locations for fishing activity
are supported by the data presented in
the Hg Risk TSD, and are generally
reasonable and appropriate given the
available data.156
The EPA notes that there is some
confusion in the comments related to
the size of the watersheds modeled.
155 U.S. EPA, U.S. Environmental Protection
Agency. 2000. Guidance for Assessing Chemical
Contaminant Data for Use in Fish Advisories,
Volume 3: Overview of Risk Management. Office of
Science and Technology, Office of Water, U.S.
Environmental Protection Agency, Washington, DC
EPA 823–B–00–007.
156 U.S. EPA–SAB, 2011.
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Several commenters stated that HUC
watersheds are 35 km on a side. The
commenters appear to be referring to
HUC8 classifications. The HUCs are
defined for varying spatial resolutions.
The geographic unit used as the basis
for generating risk estimates is HUC12,
which are watersheds about 10 km on
a side, which is comparable with the
size of the 12 km2 grid cells in CMAQ,
which are 12 km2. The EPA has also
clarified that the specific unit of
analysis for this assessment is at the
watershed, not enumerated
subpopulations.
The EPA only used the U.S. Census
tracts to determine whether there are
populations in the vicinity of a given
watershed, which could increase the
potential for a category of subsistence
fishers to be active at that watershed. In
the revised Hg Risk TSD, the EPA
modified the female subsistence
scenario to apply equally to all
watersheds with fish tissue Hg data
based on the likelihood that these
populations have the potential to fish at
most watersheds. As described in the
revised Hg Risk TSD, the EPA made this
change in response to SAB’s concerns
regarding the potential exclusion of
watersheds with fewer than 25
individuals and regarding coverage for
high-end recreational fish
consumption.157 Thus, concerns
regarding the use of census data to
select watersheds with the potential for
subsistence fishing no longer apply to
this scenario. However, for the
remaining subsistence scenarios, the
EPA continues to use U.S. Census tractlevel data to evaluate the presence of a
‘‘source population’’ in the vicinity of
the watershed being modeled for risk. In
this context, the EPA uses the U.S.
Census data to assess whether a
socioeconomic status (SES)differentiated group similar to the
particular type of subsistence fisher
being modeled (e.g., poor Hispanics) are
located in the vicinity of the watershed.
If a source population is nearby, then
this increases the potential that
subsistence fishing activity could occur
for that population scenario.
The EPA continues to model risk for
white and black subsistence fishers
active in the southeast and for Hispanics
assessed nationally. In this case, the
EPA links poverty with subsistence
fishing, as EPA only modeled locations
with poor source populations. However,
in modeling these three populations, the
157 This change led to a very small increase in the
number of watersheds with populations potentially
at-risk. In the Hg Risk TSD accompanying the
proposed rule, approximately 4 percent of modeled
watersheds were excluded based on the SES-based
filtering criteria.
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EPA asserts that the presence of a poor
source population indicates the
potential for subsistence fishing activity,
rather the presence of such activity. The
linkage between poverty and higher
rates of subsistence fish consumption is
supported by the Burger et al. study,158
which identified substantially higher
consumption rates for poor individuals
(see Table 5 of the study). The EPA
acknowledges that subsistence fishing
activity by specific subpopulations
might only be present across a subset of
the watersheds EPA modeled for risk.
However, given the stated goal of the
analysis to determine the percent of
watersheds where the potential exists
for exposures to U.S. EGU-attributable
Hg to represent a public health hazard,
identifying a set of watersheds with the
potential for the type of high fish
consumption that leads to high Hg
exposure is appropriate. The EPA notes
that relatively few watersheds (less than
4 percent) have fish tissue Hg data, and,
thus, can be included in the risk
assessment. Consequently, while there
is the potential for including some
watersheds in the analysis that may not
have currently active subsistence fishing
activity, it is likely that EPA excluded
other watersheds from the analysis
where this type of subsistence fishing
activity occurs due to a lack of fish
tissue Hg data.
While EPA agrees with the comment
that it is likely that exposure to total
MeHg through commercial fish
consumption represents a more
significant risk for the general
population than consumption of
freshwater fish obtained through selfcaught fishing activity, exposure to total
MeHg through self-caught fish
consumption is the most significant risk
for subsistence fishing populations and
high-end recreational fishers. For the
subset of these populations that focus
their fishing activity in freshwater
streams and lakes, it is also the case that
they will experience a higher fraction of
MeHg exposure attributable to U.S. EGU
Hg emissions. As a result, the EPA
focused the risk assessment on
subsistence fishers active at inland
freshwater watersheds because they are
likely to experience the highest levels of
individual risk as a result of exposure to
U.S. EGU-attributable Hg.
3. Cooking Loss Adjustment Factor
Comment: Several commenters stated
that EPA did not justify the selection of
a cooking loss factor of 1.5 that,
158 Burger,
J., 2002. ‘‘Daily Consumption of Wild
Fish and Game: Exposures of High End
Recreationists,’’ International Journal of
Environmental Research and Public Health, 12 (4),
343–54.
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according to one commenter, increases
estimated intake by 50 percent, thus
increasing the daily MeHg intake rate by
a constant factor of 33 percent and also
increasing any resulting (HQ) risk
estimate by a similar factor. Several
commenters stated that the source of
EPA’s selected loss factor 159 reported a
range of cooking losses from 1.1 to 6.
Several commenters cite several studies
that report no or highly variable changes
in MeHg levels as a result of cooking
fish.160 161 162 163 164 One commenter
suggested that EPA’s cooking loss
adjustment factor of 1.5 is at the highend of the values supported by the
literature. Another commenter stated
that EPA has used other adjustment
factors in previous documents, and that
the adjustment factor should not be
fixed across different populations given
potential differences in cooking
practices. Several commenters noted
that the cooking loss adjustment factor
should only be applied to estimates of
consumption rates for prepared fish,
and that some sources of consumption
rates are based on raw fish.
Response: The EPA disagrees with the
commenters that the selection of the
cooking loss factor of 1.5 is not justified
by the literature. The EPA also disagrees
with the comment that the cooking loss
adjustment factor of 1.5 is at the highend of the range of values in the
literature. The EPA selected the Morgan
study 165 as the basis for the food
preparation/cooking adjustment factor
because it focused on the types of
freshwater fish species representative of
what might be consumed by subsistence
fishing populations (i.e., walleye and
159 Morgan, J.N., M.R. Berry, and R.L. Graves.
1997. ‘‘Effects of Commonly Used Cooking Practices
on Total Mercury Concentration in Fish and Their
Impact on Exposure Assessments.’’ Journal of
Exposure Analysis and Environmental
Epidemiology 7(1):119–133.
160 Armbruster G., Gerow K.G., Lisk D.J., 1988.
‘‘The Effects of Six Methods of Cooking on Residues
of Mercury in Striped Bass,’’ Nutrition Reports
International, 37, 123–126.
161 Gutenmann, W.H. and Lisk D.J., 1991. ‘‘Higher
Average Mercury Concentration in Fish Fillets after
Skinning and Fat Removal,’’ Journal of Food Safety,
11, 99–103.
162 Farias L.A., Favaro, D.I., Santos J.O.,
Vasconcellos M.B., et al., 2010. ‘‘Cooking Process
Evaluation on Mercury Content in Fish,’’ Acta
Amazonia, 40 (4), 741–748.
163 Perello G., Martı-Cid R., Llobet J.M., Domingo
´
´
J.L., 2008. ‘‘Effects of Various Cooking Processes on
the Concentrations of Arsenic, Cadmium, Mercury,
and Lead in Foods,’’ Journal of Agricultural and
Food Chemistry, 156 (22), 11262–11269.
164 Torres-Escribano S., Ruiz A., Barrios L., Velez
´
D., Montoro R., 2011. ‘‘Influence of Mercury
Bioaccessibility on Exposure Assessment
Associated with Consumption of Cooked Predatory
Fish in Spain,’’ Journal of the Science of Food and
Agriculture, 91 (6), 981–6.
165 Morgan et al., 1997.
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9347
lake trout). This study 166 provides a
range of adjustment factors for each fish
type including 1.1 to 1.5 for walleye and
1.5 to 2.0 for lake trout. Given these two
ranges, the EPA determined it to be
reasonable to take an intermediate value
between the two ranges (i.e., 1.5), rather
than focus on either the highest or
lowest values, which is not the most
conservative assumption that the EPA
could have made. This study 167 also
explains that preparation/cooking of
fish results in an increase in MeHg
levels per unit fish because Hg
concentrates in the muscle, while
preparation/cooking tends to reduce
non-muscle elements (e.g., water, bone,
fat).
Regarding the alternative studies
identified by the commenters, the EPA
disagrees that these studies considered
collectively contradict the cooking loss
factor in the analysis. Specifically, the
first study 168 may have included
measurement of non-fish components
added to dishes (e.g., onions, heavy
breading etc.), which could dilute the
post-cooking Hg measurements and give
the appearance of a cooking loss even as
actual fish tissue Hg levels could have
increased. In the second study,169 the
fish species are saltwater and not
freshwater, and the authors note that the
reduction of water and fat could
increase in the Hg concentration
without changing absolute content. The
third study focused on measurement of
bioaccessible Hg in raw and cooked
fish.170 However, available information
currently allows us to specify the risk
model in terms of total Hg intake, not
bioaccessible Hg, thus, this article is
potentially informative for guiding
future research and methods
development, not the current risk
assessment. The fourth study 171 found
a modest but statistically insignificant
increase in Hg levels for most of the
cooking methods assessed, which is
directionally consistent with EPA’s
cooking loss adjustment. The fifth
study 172 only addressed the issue
qualitatively, thus cannot be used for
the cooking loss factor. When
considered collectively, the EPA
disagrees that the additional studies
identified by the commenter contradict
the cooking loss factor used in the risk
assessment and maintains that the
Morgan study 173 remains the most
166 Id.
167 Id.
168 Farias
et al., 2002.
et al., 2008.
170 Torres-Escribano et al., 2011.
171 Armbruster et al., 1988.
172 Gutenmann et al., 1991.
173 Morgan et al., 1997.
169 Perello
´
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applicable for characterizing cooking/
preparation effects on Hg concentrations
in fish.
The EPA agrees that application of the
cooking loss adjustment factor is
appropriate if the fish consumption
rates are for as cooked or as consumed
and not for raw fish. Careful review of
the three studies used in the risk
assessment to identify subsistence fisher
consumption rates suggests that all three
represent annual-average daily intakes
(g/day) of as consumed or as cooked
fish. One study stated that they used
models of portion or meal size servings
(the size of the serving the respondent
regularly eats).174 Therefore, the EPA
interprets the fish consumption rates
provided in this study 175 as
representing as cooked/prepared and
not for raw fish and for that reason,
application of a preparation/cooking
adjustment factor is required. Another
study 176 used different sized models of
cooked fish filets and therefore these
consumption rates are also interpreted
as represented as cooked/prepared and
not raw fish. One study 177 178 queried
survey responders for meal portion or
serving size and therefore, the
consumption rates do represent as
cooked/prepared. Because all three
studies provide consumption rates
based on as cooked/prepared or as
consumed, it is appropriate to apply the
cooking loss adjustment factor in
modeling exposure.
4. Fish Consumption Rates and Fish
Tissue Hg Characterization
Comment: One commenter stated that
in the past the Agency has
recommended various default
consumption rates (in the general range
of 130 to <150 g/day) to provide default
intakes for subsistence fishers under the
Risk Assessment Guidance for
Superfund (RAGS) or the Fish Advisory
Guidance.179 180 The commenter stated
that these default consumption rates are
derived from various studies and
generally are based on 90th or 99th
174 Burger
et al., 2002.
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175 Id.
176 Shilling, Fraser, Aubrey White, Lucas Lippert,
Mark Lubell (2010). Contaminated fish
consumption in California’s Central Valley Delta.
Environmental Research 110, p. 334–344.
177 Dellinger JA. 2004. ‘‘Exposure assessment and
initial intervention regarding fish consumption of
tribal members of the Upper Great Lakes Region in
the United States.’’ Environ Res 95:325–340.
178 Personal communication, Dr. Dellinger,
September 27, 2011.
179 U.S. EPA. 1991. Risk Assessment Guidance for
Superfund (RAGS). Part C 1991 EPA/9285.7–01C.
October.
180 U.S. EPA. 2000. National Guidance: Guidance
for Assessing Chemical Contaminant Data for Use
in Fish Advisories, Volume 2. EPA 823–B–00–008,
November.
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percentile distribution estimates.
Another commenter stated that EPA’s
use of the 99th percentile fish
consumption for its risk analysis is
inconsistent with the Agency’s risk
assessment guidelines, which
recommend evaluating a reasonable
maximum exposure (‘‘RME’’)
scenario,181 which equates to about a
95th percentile fish consumption value.
The same commenter stated that EPA
applied the 99th percentile to a ‘‘small
survey of 149 South Carolina female
anglers’’ to calculate an ingestion rate of
373 grams per day (g/day). The
commenter stated that if the 95th
percentile is used the ingestion rate
would be 173 g/day and if the default
ingestion rate for determining ambient
water standards is used the ingestion
rate would be 142 g/day.
Several commenters stated that EPA
based its fish consumption rates used in
the risk analysis on a limited number of
studies and that those studies are poorly
documented.
Another commenter stated that EPA
should summarize available supporting
studies by basic study content,
characteristics, design, size,
demographics, dietary recall period, and
fish intake rates by demographic
variables. According to the commenter,
this summary would support the
scientific validity of the assessment and
better illustrate the potential variability
and uncertainty involved in
extrapolating data from small
populations to the national-scale. The
commenter also noted that the three
studies actually used to provide
subsistence population estimates, which
were extrapolated to the national-scale,
included a limited number of
individuals living in diverse and
localized areas.
One commenter stated that the
assumption with the greatest impact on
risk is the fish consumption rate. That
same commenter stated that using 99th
percentile ingestion rate dramatically
increases HQ and IQ loss compared to
the 50th percentile ingestion rate. The
commenter stated that when an estimate
of the 95th percentile ingestion rate of
the 15 to 44 year old female population
is considered, the HQ is a tenth of the
value computed with the 99th
percentile high-end female fisher.
One commenter stated that EPA
provides broad summary statistics of its
fish tissue data in Table 5–2 of the
Regulatory Impact Analysis (RIA), but
the summary does not allow an
assessment of the representativeness
and robustness of the underlying data
181 U.S. EPA. 1989. Risk Assessment Guidance for
Superfund (RAGS). EPA/540/1–89/002. December.
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for the risk assessment, especially at the
tails of the distribution. The commenter
stated that the table does not include a
median statistic and does not provide
any information on the number of lakes
and river segments in each watershed.
According to the commenter, an
analysis of EPA’s database by the SAB
indicated that 60 percent of the
watersheds with fish Hg data from rivers
have risks calculated based upon a
sample size of one or two fish. The
commenter stated that it is not
reasonable to base a significant policy
and regulation decision on watersheds
where exposure is based on a single fish
sample in a single water body within it.
Several commenters criticized EPA’s
use of the 75th percentile fish tissue
MeHg level in a watershed. One
commenter stated that EPA provided no
rationale for its decision to choose the
highest of the 75th percentile for fish Hg
levels among rivers and lakes within the
HUC. Several commenters stated that
subsistence fishers are less likely to
target larger fish relative to recreational
fishers. Several commenters suggested
that EPA include a sensitivity analysis
using the mean or median fish MeHg
level in a watershed. One commenter
also stated that EPA arbitrarily inflated
the risk estimates by assuming
consumption of only fish greater than 7
inches and choosing the largest of the
75th percentile of fish Hg levels from
these larger fish (i.e., larger than 7
inches) for rivers and lakes. That same
commenter suggested using the median
of all size fish, not just those over 7
inches.
One commenter stated that EPA
should quantify adverse effects from the
ingestion of MeHg in seafood in
addition to ingestion of MeHg from selfcaught freshwater fish. According to the
commenter, recent studies demonstrate
that were EPA to take into account
consumption of seafood, MeHg
consumption in the U.S. is of even
greater concern.
Response: The EPA acknowledges
that the focus of the Hg Risk TSD is
characterizing risk for the groups likely
to experience the greatest U.S. EGUattributable Hg risk, which are
subsistence fishing populations active at
inland freshwater lakes and rivers.
Specifically, within that subsistence
fishing population, the EPA is interested
in those individuals who are most atrisk, which includes those who
consume the most fish. For that reason,
the EPA considered a range of high-end
fish consumption rates including the
99th percentile representing the most
highly-exposed individuals. In
responding to the SAB peer review, the
EPA clarified this focus in the
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introduction to the revised Hg Risk TSD
and changed the full title to revised
Technical Support Document: NationalScale Assessment of Mercury Risk to
Populations with High Consumption of
Self-caught Freshwater Fish.
The EPA agrees that the fish
consumption rate is an important factor
in calculating risk from exposure to
MeHg in fish. The EPA acknowledges
that the distribution of fish
consumption rates is positively skewed,
which means that at higher percentiles
(e.g., 90th, 95th, and 99th) there is a
substantial increase in ingestion rates
relative to the mean or median. The
revised Hg Risk TSD includes a
reasonableness check on the amount of
fish consumed (as a daily value)
reflected in the different rates. While the
99th percentile consumption rates for
the subsistence female fisher (373 g/day)
is substantially higher than the 90th or
95th percentile values (123 and 173 g/
day respectively), the 99th percentile
value translates into a 13-ounce meal.
While this represents a large serving, it
is still reasonable if representing an
individual who receives all of their meat
protein from self-caught fishing, and the
13 ounces per day do not have to be
eaten all at one meal. The higher
consumption rates (i.e., greater than 250
g/day) are supported by all three studies
used in the risk assessment, and
therefore, there is support across studies
near the upper bound of likely
consumption rates in this range. The
EPA acknowledges uncertainty
associated with estimating high-end
percentile values in these studies due to
relatively low sample sizes for some
population groups. However, even if a
few individuals reported these high selfcaught fish consumption rates, making
it difficult to characterize the
population percentiles they represent,
the values still suggest that these levels
of high fish consumption exist among
surveyed individuals. To determine
whether a public health hazard could
exist, the EPA asserts that it is
reasonable to include these
consumption rates as representative of
the most at-risk populations. In these
cases, however, the EPA acknowledges
that it is important to highlight
uncertainty associated with
characterizing the specific population
percentile that these ingestion rates
represent, and EPA has done so in the
revised Hg Risk TSD.
The EPA disagrees with the comment
that high consumption rates are poorly
documented. Evidence of these high fish
consuming populations can be found in
surveys 182 and specialized
182 Burger
et al., 2002.
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studies.183 184 185 186 187 Several studies
identified additional fishing
populations with subsistence or near
subsistence consumption rates,
including urban fishing populations
(including low-income
populations),188 189 190 Laotian
communities,191 and Hispanics. The
EPA participated in 1999 in a project
investigating exposures of poor,
minority communities in New York City
to a number of contaminants including
Hg, which found these populations can
have very high fish consumption
rates.192 The SAB concluded that the
consumption rates and locations for
fishing activity are supported by the
data presented in the Hg Risk TSD, and
are generally reasonable and appropriate
given the available data.193
The EPA agrees that the Hg Risk TSD
would be improved by clarifying that
the literature review focused on
identifying studies that characterize
subsistence fish consumption for groups
active at freshwater locations within the
U.S., and EPA has revised the Hg Risk
TSD accordingly. In the Hg Risk TSD,
the EPA summarized important study
attributes for the source studies used to
obtain fish consumption rates. This
information was provided in Table C–1
in an appendix. To improve clarity, the
EPA moved the summary table to the
main body in the revised Hg Risk TSD.
In identifying these studies, the EPA
focused on surveys for subsistence
fishers that were applicable at the
broader regional or national level. In the
Hg Risk TSD, the EPA acknowledged
the smaller sample sizes for some of the
183 Burger, J., K. Pflugh, L. Lurig, L. Von Hagen,
and S. Von Hagen. 1999a. ‘‘Fishing in Urban New
Jersey: Ethnicity Affects Information Sources,
Perception, and Compliance.’’ Risk Analysis 19(2):
217–229.
184 Burger, J., Stephens, W. L., Boring, C. S.,
Kuklinski, M., Gibbons, J. W., Gochfeld M. 1999b.
‘‘Factors in Exposure Assessment: Ethnic and
Socioeconomic Differences in Fishing and
Soncumption of Fish Caught along the Savannah
River.’’ Risk Analysis, Vol. 19, No. 3, p. 427.
185 California Environmental Protection Agency
(CalEPA). 1997. Chemicals in Fish Report No. 1:
Consumption of Fish and Shellfish in California
and the United States Final Draft Report. Pesticide
and Environmental Toxicology Section, Office of
Environmental Health Hazard Assessment, July.
186 Tai, S. 1999. ‘‘Environmental Hazards and the
Richmond Laotian American Community: A Case
Study in Environmental Justice.’’ Asian Law Journal
6: 189.
187 Corburn, J. 2002. ‘‘Combining communitybased research and local knowledge to confront
asthma and subsistence-fishing hazards in
Greenpoint/Williamsburg, Brooklyn, New York.’’
Environmental Health Perspectives 110(2).
188 Burger et al., 1999a.
189 Burger et al., 1999b.
190 CalEPA, 1997.
191 Tai, 1999.
192 Corburn, 2002.
193 U.S. EPA–SAB, 2011.
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subsistence fisher groups, and in several
cases the EPA did not use the 99th
percentile consumption rates because
the sample sizes were too low to
support this level of resolution. This
decision did not affect EPA’s finding of
a hazard to public health, which is
based on the results for the female
subsistence fishing population, which
has an estimate of the 99th percentile
consumption rate that is supported by
an adequate sample size.
The EPA disagrees with the comment
that it did not provide a rationale for
choosing the 75th percentile fish tissue
concentration across lakes and rivers in
a watershed. However, the EPA
modified the methodology based on
evaluation of the number of samples
within each watershed (responding to a
recommendation from the SAB). In the
revised methodology, the EPA computes
the 75th percentile value at each
sampling site within a watershed. The
EPA then computed the average of the
site-specific 75th percentile fish tissue
Hg values within a given watershed.
This approach does not differentiate
between rivers and lakes and reflects an
improved treatment of behavior,
allowing for fishers to choose among
multiple fishing sites within a
watershed.
The EPA generally agrees with the
comment that some fraction of
subsistence fishers likely consume fish
without consideration for size (given
dietary necessity), however, the EPA
considers it reasonable to assume that a
subset of subsistence fishers could target
larger fish in order to maximize the
potential consumption per unit of
fishing effort. The EPA uses this subset
of subsistence fishers targeting larger
fish, which is represented by the 75th
percentile fish tissue value, in the risk
assessment. In addition, including the
female subsistence fishing population in
the analysis also provides coverage for
high-end recreational anglers who target
larger freshwater fish. The SAB
commented that: ‘‘Using the 75th
percentile of fish tissue values as a
reflection of consumption of larger, but
not the largest, fish among sport and
subsistence fishers is a reasonable
approach and is consistent with
published and unpublished data on
predominant types of fish
consumed.’’ 194 The SAB suggested that
EPA include a sensitivity analysis based
on use of the median value, and EPA
has done so in the revised Hg Risk TSD.
This sensitivity analysis showed that
using the median estimates had only a
small impact on the number and percent
of modeled watersheds with
194 U.S.
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populations potentially at-risk from U.S.
EGU-attributable MeHg exposures. In
the revised Hg Risk TSD, the EPA
clarified that the 7-inch cutoff
represents a minimum size limit for a
number of key edible freshwater fish
species established at the State-level.
For example, Pennsylvania establishes 7
inches as the minimum size limit for
both trout and salmon (other edible fish
species such as bass, walleye and
northern pike have higher minimum
size limits).195
The EPA disagrees with the comment
that it is not reasonable to use
watersheds where only a single fish
sample is available. Although it is
generally preferred to have multiple
samples, the SAB noted that using a
single sample is likely to underestimate
the 75th percentile fish MeHg
concentration and is, therefore, likely to
underestimate the risk estimates for
those watersheds. The SAB suggested
that EPA conduct additional analyses of
the fish tissue MeHg data, which EPA
has done and included in the revised Hg
Risk TSD. The revised Hg Risk TSD
includes information on the number of
watersheds modeled in the risk
assessment with various fish tissue Hg
samples sizes (e.g., 1, 2, 3–5, 6–10 and
>10 measurements).
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5. Reference Dose (RfD) for MeHg and
Hg Health Effects Studies
Comment: Several commenters stated
that EPA’s RfD 196 is based on sound
science, which was supported by the
findings of the NAS Study,197 and that
EPA appropriately applied the RfD in
the Hg risk assessment. The commenters
also stated that recent studies find clear
associations between maternal blood Hg
levels and delayed child development
and cardiovascular effects, as well as
potential for effects due to exposure to
pollutant mixtures including lead.
However, many commenters
expressed concerns regarding EPA’s use
of the MeHg RfD as a benchmark for
health risk. Several commenters raised
concerns claiming that EPA has not
incorporated the best available Hg
toxicological data into the RfD, which
results in a flawed analysis and an
overestimate of the impact of Hg
emissions on human health.
Several commenters stated that, when
deriving the RfD, the EPA relied on the
195 Pennsylvania
Fish and Boat Commission.
2011. Summary Book: 2011 Pennsylvania Fishing
Laws & Regulations available at: https://
fishandboat.com/fishpub/summary/inland.html.
196 U.S. Environmental Protection Agency—
Integrated Risk Information System (U.S. EPA–
IRIS). 2001. Methylmercury (MeHg) (CASRN
22967–92–6). Available at https://www.epa.gov/iris/
subst/0073.htm.
197 NAS, 2000.
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flawed Faroe Islands’ children study
and ignored the Seychelles Islands
study,198 which did not confirm any
harm on children due to MeHg
exposure. According to the commenters,
application of the Faroe Island study is
suspect because (1) the raw data from
the study have never been made
available for independent analysis and
scrutiny, (2) there is potential for
confounding by polychlorinated
biphenyls (PCBs) and lead, (3)
population exposure to MeHg was
through consumption of highly
contaminated pilot whale meats and
blubbers, and (4) exposure levels in the
U.S. remain lower than those observed
in the primary study. One commenter
also notes that (1) Seychelles Islanders
consume far more fish than Americans
do; (2) the amount of MeHg in the U.S.
population is much lower than the
Seychelles Islanders; and (3) all ocean
fish contain about the same amount of
MeHg, so MeHg intake per fish meal is
similar between Americans and
Seychelles Islanders. However, another
commenter stated that industry
arguments against using the Faroe
Islands study fail to acknowledge that
the study results were consistent with
studies in the Seychelles Islands, New
Zealand,199 and Poland.200
One commenter criticized EPA for
using a linear dose-response model for
the RfD-based HQ metric and the IQ
metric. Another commenter stated that
the RfD assumes a threshold dose below
which an appreciable risk of adverse
effects is unlikely, and NAS did not
evaluate whether MeHg exposure data
were better fit by a linear or non-linear
model or by a threshold or nonthreshold model.
Several commenters stated that EPA’s
MeHg RfD is more conservative than
‘‘safe’’ levels determined by other
federal agencies and claim that EPA
assigned unusually high uncertainty
factors. Several commenters stated that
EPA’s use of the 1999 National Health
and Nutrition Examination Survey
(NHANES) blood Hg levels show a
downward trend since 1999, and the
levels have been below the RfD since
2001.
198 Budtz-Jorgensen E, Debes F, Weihe P,
Grandjean P. 2005. ‘‘Adverse Mercury Effects in 7–
Year-Old Children Expressed as Loss in ‘‘IQ’’.’’
EPA–HQ–OAR–2002–0056–6046.
199 Kjellstrom, T; Kennedy, P; Wallis, S; et al.
1986. Physical and mental development of children
with prenatal exposure to mercury from fish. Stage
1: Preliminary test at age 4. Natl Swed Environ
Protec Bd, Rpt 3080 (Solna, Sweden).
200 Wieslaw Jedrychowski et al. 2006. ‘‘Effects of
Prenatal Exposure to Mercury on Cognitive and
Psychomotor Function in One-Year-Old Infants:
Epidemiologic Cohort Study in Poland,’’ 16 Annals
of Epidemiology 439.
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One commenter stated that a study by
Texas Department of State Health
Services (DSHS, 2004) 201 determined
that among subsistence fishers who eat
fish from Caddo Lake with elevated
MeHg, women of child-bearing years
did not have blood Hg levels greater
than the RfD. Thus, according to the
commenter, the connection between
MeHg in fish and adverse health effects
in the U.S. is not fully understood and
could involve other factors, including
the protective effects of fatty acids and
selenium in fish, which EPA did not
taken into account.
Two commenters claim that EPA uses
the RfD as if it were an absolute
threshold for health risk in the risk
assessment even though the RfD
methodology is a screening tool for
deciding when risks clearly do not exist.
Several commenters recommended
adding qualitative discussions to the Hg
Risk TSD regarding several aspects of
uncertainty, including uncertainty in
the RfD, uncertainty in extrapolating a
dose-response relationship between
MeHg exposure and change in IQ,
uncertainty in extrapolating the doseresponse relationship from marine fish
and marine mammals to freshwater fish,
and uncertainty due to potential
confounding by PCBs in marine species.
Several commenters raised concerns
regarding the relationship between
MeHg exposure and IQ loss. Two
commenters stated that changes in IQ
are not a well-defined health
consequence of MeHg exposure. One
commenter stated that the SAB had
reservations about EPA’s use of IQ loss.
Two commenters questioned whether
IQ impacts would even occur because in
Japan and Korea, where the maternal
blood Hg levels are higher than in the
U.S., there is no evidence of adverse
effects. Another commenter cited a
study202 that found verbal IQ scores for
children from mothers with no seafood
intake were 50 percent more likely to be
in the lowest quartile. One commenter
questions using an IQ risk metric
threshold of >1 or >2 points because
variation in IQ measures and the intraindividual variation in IQ are higher
than the threshold.
Several commenters question the
relationship between cardiovascular
effects and MeHg exposure. Two
201 DSHS. 2005. Health Consultation: Mercury
Exposure Investigation Caddo Lake Area-Harrison
County Texas. Agency for Toxic Substances and
Disease Registry. https://www.tceq.state.tx.us/assets/
public/comm_exec/pubs/sfr/085.pdf.
202 Hibbeln JR, Davis JM, Steer C, Emmett P,
Rogers I, Williams C, et al., 2007. ‘‘Maternal seafood
consumption in pregnancy and
neurodevelopmental outcomes in childhood
(ALSPAC study): an observational cohort study. ’’
Lancet 369:
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commenters cited studies examining the
relationship between MeHg exposure
and cardiovascular
effects,203 204 205 206 207 208 but concluded
that it seems premature to use these
studies to establish a dose-response
relationship.
Several commenters assert that the
risks from eating seafood are low
relative to the benefits, that fish
advisories can limit the beneficial
aspects of fish consumption, and that
fish advisories are often unsuccessful in
changing behavior.209 210 One
commenter noted the important
protective role of dietary selenium
against MeHg toxicity because the
binding affinity of Hg to Se is much
higher than binding to sulfur.
Response: The EPA agrees with
commenters that state the MeHg RfD is
the appropriate health value for
determining elevated risks from MeHg
exposure and disagrees with
commenters that state otherwise. At this
time, the EPA is neither reviewing nor
revising its 2001 RfD for MeHg. The
2001 RfD for MeHg is EPA’s current
peer-reviewed RfD, which is the value
EPA uses in all its risk assessments. The
EPA’s RfD is based on multiple
benchmark doses, and RfDs were
calculated on various endpoints using
the three extant large studies of
childhood effects of in utero exposure:
Faroe Islands, New Zealand, and an
integrative measure including data from
Seychelles. The EPA did not choose to
base the MeHg RfD solely on results
from the Seychelles Islands, as both the
NAS 211 and an independent scientific
review panel convened as part of the
´
203 Roman HA, Walsh TL, Coull BA, Dewailly E,
Guallar E, Hattis D, et al., 2011. Evaluation of the
Cardiovascular Effects of Methylmercury
Exposures: Current Evidence Supports
Development of a Dose–Response Function for
Regulatory Benefits Analysis. Environ Health
Perspect 119:607–614.
204 Guallar E, Sanz-Gallardo MI, van’t Veer P, et
al., 2002. ‘‘Mercury, fish oils, and the risk of
myocardial infarction.’’ N Engl J Med.;347:1747.
205 Virtanen JK, Voutilainen S, Rissanen TH, et
al., 2005. ‘‘Mercury, fish oils, and risk of acute
coronary events and cardiovascular disease,
coronary heart disease, and all-cause mortality in
men in eastern Finland.’’ Arterioscler Thromb Vasc
Biol. 2005;25:228.
206 Yoshizawa, Rimm, Morris, Spate, Hsieh,
Spiegelman, Stampfer, Willett. ‘‘Mercury and the
Risk of Coronary Heart Disease in Men,’’ N Engl J
Med 2002; 347:1755–1760.
207 Hallgren CG, Hallmans G, Jansson JH, et al.,
2001. Markers of high fish intake are associated
with decreased risk of a first myocardial infarction.
Br J Nutr: 86:397.
208 Mozaffarian, Dariush. 2011. ‘‘Mercury
Exposure and Risk of Cardiovascular Disease in
Two U.S. Cohorts,’’ N Engl J Med 364: 1116–1125.
209 Hibbeln et al., 2007.
210 Mozaffarian, et al., 2011.
211 NAS, 2000.
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IRIS process 212 advised strongly against
using results from a study that at the
time had not shown an association
between MeHg exposure and adverse
effects. Further, the EPA disagrees with
comments stating that EPA based the
MeHg RfD solely on results from the
Faroe Islands population and disagrees
that the information underlying the RfD
is ‘‘poorly explained’’. The EPA has
provided detailed documentation for the
choices underlying calculation of the
RfD.213 214 215 To correct a
misunderstanding by the commenter,
the data underlying the Faroe Islands
study have been previously published
in the peer reviewed literature.
The EPA disagrees that it did not
incorporate the latest Hg data to support
the appropriate and necessary finding. It
is the policy of EPA to use the most
current peer reviewed, publicly
available data and methodologies in its
risk assessments. However, the EPA
noted in the preamble to the proposed
rule that ‘‘data published since 2001 are
generally consistent with those of the
earlier studies that were the basis of the
RfD, demonstrating persistent effects in
the Faroe Island cohort, and in some
cases associations of effects with lower
MeHg exposure concentrations than in
the Faroe Islands. These new studies
provide additional confidence that
exposures above the RfD are
contributing to risk of adverse effects,
and that reductions in exposures above
the RfD can lead to incremental
reductions in risk.’’ However, the EPA
has not completed a comprehensive
review of the new literature, and as
such, it would be premature to draw
conclusions about the overall
implications for the RfD.
The EPA agrees that EPA’s RfD is not
the same as the levels used by other
federal agencies. In their advice to the
EPA on the appropriate bases for a
MeHg RfD, NAS specifically
recommended that EPA use neither the
study nor the uncertainty factor
employed by the Agency for Toxic
Substances Disease Registry (ATSDR) in
the calculation of the minimal risk
level.216
9351
The EPA disagrees that the
uncertainty factor is ‘‘unusually high’’.
The uncertainty factor used in
calculation of EPA’s peer-reviewed RfD
is small (10 fold); half of this factor is
to account for measured variability in
human pharmacokinetics, which is
based on advice of the NAS 217 and an
independent panel of scientific peer
reviewers convened as part of the IRIS
process.218
The IRIS makes this statement
regarding a threshold for MeHg, ‘‘It is
also important to note that no evidence
of a threshold arose for methylmercuryrelated neurotoxicity within the range of
exposures in the Faroe Islands study.
This lack [of a threshold] is indicated by
the fact that, of the K power models, K
= 1 provided a better fit for the endpoint
models than did higher values of K.’’ 219
The EPA disagrees that it is using the
MeHg RfD as an absolute bright line for
health effects in the risk assessment. As
stated in the preamble to this proposed
rule, the RfD is an estimate of a daily
exposure to the human population that
is likely to be without an appreciable
risk of deleterious effects during a
lifetime. The EPA also stated that no
RfD defines an exposure level
corresponding to zero risk. Because
mercury is a cumulative neurotoxin, it
is important to distinguish health effects
from public health hazard. Within the
context of the appropriate and necessary
finding, we interpret a public health
hazard as risk, rather than certain
occurrence of health effects.
The EPA disagrees that exposure
levels in the U.S. are lower than those
in the Faroe Islands study. Exposure to
MeHg in the U.S. has been reported at
the same levels as those published in
the Faroe Islands.220 One study notes
that in the NHANES data (1999 to 2004),
the highest five percent of women’s
blood Hg exceeded 8.2 microgram per
liter (mg/L) in the Northeast U.S. and 7.2
mg/L in coastal areas.221 Higher levels
have been reported among subjects
known to consume fish. For example,
one study reported mean blood Hg for
adult women to be 15 mg/L; range for
217 Id.
212 U.S.
EPA. 2001b. Responses to Comments of
the Peer Review Panel and Public Comments on
Methylmercury. Available on the Internet at https://
www.epa.gov/iris/supdocs/methpr.pdf.
213 U.S. EPA, 2001a. Water Quality Criterion for
the Protection of the Human Health:
MethylmercuryEPA–823–T–01–001, available at
https://water.epa.gov/scitech/swguidance/standards/
criteria/aqlife/pollutants/methylmercury/index.cfm.
214 U.S. EPA–IRIS, 2001.
215 Rice D, Schoeny R, Mahaffey K. 2003.
‘‘Methods and Rationale for Derivation of a
Reference Dose for Methylmercury by the U.S.
EPA.’’ Risk Analysis 23(1)107–115.
216 NAS, 2000.
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218 U.S.
EPA, 2001b.
EPA–IRIS, 2001.
220 Schober Susan E, Sinks Thomas H, Jones
Robert L, Bolger P Michael, McDowell Margaret,
Osterloh John, Garrett E Spencer, Canady Richard
A, Dillon Charles F, Sun Yu, Joseph Catherine B,
Mahaffey Kathryn R. Blood mercury levels in U.S.
children and women of childbearing age, 1999–
2000. JAMA. 2003 Apr 2; 289(13): 1667–1674.
221 Mahaffey, K.R., R.P. Clickner and R.A. Jeffries.
2009. Adult Women’s Blood Mercury
Concentrations Vary Regionally in the U.S.:
Association with Patterns of Fish Consumption
(NHANES 1999–2004). Environ. Health Perspect.,
117: 47–53.
219 U.S.
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men and women was 2 to 89.5 mg/L.222
Note that some publications have
reported Hg effects in U.S. populations
at or below the current U.S. RfD.223 224
Also, the EPA disagrees with the
commenter stating all ocean fish
throughout the world contain about the
same amount of MeHg. Marine fish in
commerce differ widely in Hg
concentration by species, and fish
within the same species but caught at
different locations have variable
amounts of Hg in their tissues.225 226
The EPA disagrees that there is a
statistically discernible downward trend
in the NHANES data on blood Hg. The
EPA is unaware that a formal statistical
analysis for temporal trends has been
completed for NHANES data on blood
Hg levels for the period 1999 to 2008.
Mahaffeyet al., evaluating NHANES
data collected 1999 to 2004 for women
at child-bearing age, could ‘‘not support
the conclusion that there was a general
downward trend in blood Hg
concentrations over the 6-year study
period.’’ 227 However, the same
publication noted that ‘‘there was a
decline in the upper percentiles
reflecting the most highly exposed
women’’ having blood Hg concentration
greater than established levels of
concern. Visual observations of the data
show a slight decrease in Hg blood level
concentrations from 1999–2008 at the
geometric mean, but this decrease may
not be statistically significant. The EPA
remains concerned that substantial
numbers of women of childbearing age
in the U.S. may have blood Hg levels
that are equivalent to exposures at or
222 Hightower Jane M, Moore Dan. Mercury levels
in high-end consumers of fish. Environ Health
Perspect. 2003 Apr; 111(4): 604–608.
223 Oken, E., Radesky, J.S., Wright, R.O.,
Bellinger, D.C., Amarasiriwardena, C.J., Kleinman,
K.P., Hu, H., Gillman, M.W. 2008. Maternal fish
Intake during Pregnancy, Blood Mercury Levels,
and Child Cognition at Age 3 Years in a U.S.
Cohort. American Journal of Epidemiology, 167(10),
1,171–1,181.
224 Lederman, Sally Ann Robert L. Jones,
Kathleen L. Caldwell, Virginia Rauh, Stephen E.
Sheets, Deliang Tang, Sheila Viswanathan, Mark
Becker, Janet L. Stein, Richard Y. Wang, and
Frederica P. Perera. 2008. Relation between Cord
Blood Mercury Levels and Early Child Development
in a World Trade Center Cohort. Environmental
Health Perspectives 118(8) 1085–1091.
225 Hisamichi Y, Haraguchi K, Endo T. 2010.
‘‘Levels of mercury and organochlorine compounds
and stable isotope ratios in three tuna species taken
from different regions of Japan.’’ Environ Sci
Technol 44(15): 5971–8.
226 Sunderland EM. 2007. ‘‘Mercury exposure
from domestic and imported estuarine and marine
fish in the U.S. seafood market.’’ Environ Health
Perspect. 115(2): 235–42. Epub 2006 Nov 20.
227 Mahaffey, K.R., R.P. Clickner and R.A. Jeffries.
2009. Adult Women’s Blood Mercury
Concentrations Vary Regionally in the U.S.:
Association with Patterns of Fish Consumption
(NHANES 1999–2004). Environ. Health Perspect.,
117: 47–53.
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above the RfD. While mean and 95th
percentiles from recent NHANES data
are below the blood Hg concentration
equivalent to the RfD, blood levels for
some portions of the population (high
consumers of fish, for example) show
exposures above this level. One study
estimated very high blood Hg levels at
the 99th percentile for females of childbearing age.228 Other published studies
have shown that various population
groups can have high blood Hg
levels.229 230 231 232 233 For example, one
study found that 83 percent of the
NHANES Asian population exceeded
the RfD-equivalent blood mercury
level.234
The EPA disagrees with the
commenter regarding confounding by
PCBs and lead. Exposure to MeHg in the
Faroe Islands was largely from
consumption of pilot whale meat;
exposure to PCBs was found in the
portion of the population who also
consume whale blubber. Numerous
analyses have shown neurobehavioral
effects of PCBs; however, the effects of
MeHg and PCB in the Faroe Islands
study are separable.235 The EPA also
documented the independence of PCB
and MeHg effects in the Faroe Islands
population.236 The National Institute of
Environmental Health Sciences (NIEHS)
concluded that both PCB and Hg had
adverse effects.237 The NAS concluded
that there was no empirical evidence or
theoretical mechanism to support the
opinion that in utero Faroese exposure
to PCBs exacerbated the reported MeHg
effect.238 A second set of analyses found
that the effect of prenatal PCB exposure
was reduced when the data were sorted
228 Tran, N.L., L. Barraj, et al., 2004. ‘‘Combining
food frequency and survey data to quantify longterm dietary exposure: a methyl mercury case
study.’’ Risk Anal 24(1): 19–30.
229 Id.
230 Miranda, M.L., S. Edwards, et al., 2011.
‘‘Mercury levels in an urban pregnant population in
Durham County, North Carolina.’’ Int J Environ Res
Public Health 8(3): 698–712.
231 Hightower and Moore, 2003.
232 Hightower, J.M., A. O’Hare, et al., (2006).
‘‘Blood mercury reporting in NHANES: identifying
Asian, Pacific Islander, Native American, and
multiracial groups.’’ Environ Health Perspect
114(2): 173–175.
233 McKelvey, W., R.C. Gwynn, et al., 2007. ‘‘A
biomonitoring study of lead, cadmium, and
mercury in the blood of New York city adults.’’
Environ Health Perspect 115(10): 1435–1441.
234 Hightoweret al., 2006.
235 NAS, 2000.
236 U.S. EPA, 2001a.
237 National Institute of Environmental Health
Sciences (NIEHS). 1998. Scientific issues relevant to
assessment of health effects from exposure to
methylmercury. Workshop organized by Committee
on Environmental and Natural Resources (CENR)
Office of Science and Technology Policy (OSTP),
The White House, November 18–20, 1998, Raleigh,
NC.
238 NAS, 2000.
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into tertiles by cord PCB
concentrations.239 These analyses
support a conclusion that there are
measurable effects of MeHg exposure in
the Faroese children that are not
attributable to PCB toxicity. We also
note that there was no report of lead
exposure in the Faroe Islands
population.
The EPA disagrees with the
commenter’s assertion that the
connection between MeHg in fish and
observed health effects is not
understood due to evidence from the
cited Texas study.240 This is an
exposure study rather than a study on
measures of neurobehavioral or any
other health endpoint. TCEQ noted that
none of the Caddo Lake study
participants had blood Hg levels above
the benchmark dose level (BMDL) of 5.8
mg/L (one of the several used by EPA in
the calculation of the MeHg RfD). The
BMDL is not a ‘‘no effect’’ level. Rather
it is an effect level for a percentage of
the population. The EPA has noted in
correspondence with TCEQ that, as an
exposure study, the Caddo Lake study
may be representative of the
surrounding population; however, the
sample size is very small. It is not
appropriate to extrapolate from Caddo
Lake to larger regional or national
populations.
The EPA is aware of the possibility of
both interactions among environmental
contaminants and cumulative effects of
pollutants that produce the same
adverse endpoint. The EPA guidance
exists for dealing with such
scenarios.241 242 243 244 The Agency’s
concern with the likelihood of human
exposure to multiple contaminants is
239 Budtz-J<rgensen, E., N. Keiding, and P.
Grandjean. 1999. Benchmark modeling of the
Faroese methylmercury data. Final Report to U.S.
EPA.
240 DSHA, 2005.
241 U.S. EPA. 1986. Guidelines for the Health Risk
Assessment of Chemical Mixtures. U.S.
Environmental Protection Agency, Office of
Research and Development, Washington, DC
September. EPA/630/R–98/002. Available at https://
cfpub.epa.gov/ncea/cfm/
recordisplay.cfm?deid=2256.
242 U.S. EPA. 1999. Guidance for Performing
Aggregate Exposure and Risk Assessments. U.S.
Environmental Protection Agency, Office of
Pesticide Programs, Washington, DC October.
Available at https://www.pestlaw.com/x/guide/1999/
EPA-19991029A.html.
243 U.S. EPA. 2000a. Supplementary Guidance for
Conducting Health Risk Assessment of Chemical
Mixtures. U.S. Environmental Protection Agency,
Risk Assessment Forum, Washington, DC EPA/630/
R–00/002. Available at https://www.epa.gov/ncea/
raf/pdfs/chem_mix/chem_mix_08_2001.pdf.
244 U.S. EPA. 2003a. Framework for Cumulative
Risk Assessment. Risk Assessment Forum, U.S.
Environmental Protection Agency. Washington, DC
EPA/630/P–02/001F. EPA/600/P–02/001F.
Available at https://cfpub.epa.gov/ncea/cfm/
recordisplay.cfm?deid=54944.
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reflected in the multi-chemical scope of
the rulemaking. However, the EPA
focused the technical analyses
supporting the proposed regulation on
effects of individual pollutants rather
than cumulative effects.
The EPA disagrees with commenters
suggesting that the RfD-based HQ is
inappropriate. The SAB ‘‘agreed that
EPA’s calculation of a hazard quotient
for each watershed included in the
assessment is appropriate as the primary
means of expressing risk,’’ and that
‘‘because the RfD from which the HQ is
calculated is an integrative metric of
neurodevelopmental effects of
methylmercury, it constitutes a
reasonable basis for assessing risk.’’ 245
The SAB also recommended that EPA
revise the Hg Risk TSD to include
additional qualitative discussion about
uncertainty in the revised Hg Risk TSD.
Specifically, the SAB recommended that
EPA revise the Hg Risk TSD ‘‘to better
explain the methods and choices made
in the analysis, and analytical results,
and where the uncertainties lie.’’ The
SAB noted several uncertainties related
to the RfD. The EPA agrees with this
recommendation and included a more
complete discussion of these
uncertainties in the revised Hg Risk
TSD.
The EPA disagrees that the IQ metric
threshold is questionable. The SAB
concluded that it was reasonable to
consider a loss of >1 or >2 IQ points a
public health concern. The SAB stated,
‘‘The Panel agreed that if IQ loss is
retained in the risk assessment despite
these reservations, a loss of one or two
points would be an appropriate
benchmark.’’ 246 The SAB further
comments in their report: ‘‘The
consensus is that if IQ were to be used,
then a loss of 1 or 2 points as a
population average is a credible
decrement to use for this risk
assessment. This metric seems to be
derived from the lead literature and was
peer reviewed by the Clean Air
Scientific Advisory Committee (U.S.
EPA CASAC 2007).247 Although its
applicability to methylmercury is
questionable, the size of the decrement
is justified based on the extensive
analyses available from the literature
reviewed by CASAC.’’ 248 As noted in
245 U.S.
EPA–SAB, 2011.
EPA–SAB, 2011.
247 U.S. Environmental Protection Agency—
Science Advisory Board (U.S. EPA–SAB). 2007.
Clean Air Scientific Advisory Committee’s (CASAC)
Review of the 1st Draft Lead Staff Paper and Draft
Lead Exposure and Risk Assessments. EPA–
CASAC–07–003. March. Available on the internet at
https://yosemite.epa.gov/sab/sabproduct.nsf/
989B57DCD436111B852572AC0079DA8A/$File/
casac-07–003.pdf.
248 U.S. EPA–SAB, 2011.
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other studies,249 250 a decrease of 1–2
points at the mean results in a much
larger decrease in those with IQs that
are much lower or higher than the
mean.
Although EPA disagrees that the IQ
results are too uncertain to rely upon,
the EPA acknowledges that IQ is not the
most sensitive neurodevelopmental
endpoint affected by MeHg exposure, as
also noted by the SAB. The SAB
recommended that the IQ analyses be
retained but be de-emphasized in the
documentation underlying the final
regulation. The SAB concluded, ‘‘The
Panel does not consider it appropriate to
use IQ loss in the risk assessment and
recommended that this aspect of the
analysis be de-emphasized, moving it to
an appendix where IQ loss is discussed
along with other possible endpoints not
included in the primary assessment.
While the Panel agreed that the
concentration-response function for IQ
loss used in the risk assessment is
appropriate, and no better alternatives
are available, IQ loss is not a sensitive
response to methylmercury and its use
likely underestimates the impact of
reducing methylmercury in water
bodies.’’ 251 The EPA is following the
SAB’s recommendation by
deemphasizing the IQ analysis and
placing that analysis in an appendix to
the revised Hg Risk TSD.
The SAB, however, supported the use
of the IQ dose-response function
calculated by EPA in the Hg Risk TSD.
The SAB noted, ‘‘The function used
came from a paper by Axelrad and
Bellinger (2007) that seeks to define a
relationship between methylmercury
exposure and IQ. A whitepaper by
Bellinger (Bellinger, 2005) 252 describes
the sequence of steps in relating
methylmercury exposure to maternal
hair mercury and then that to IQ. The
Mercury Risk TSD furthers notes that IQ
has shown utility in describing the
health effects of other neurotoxicants.
These are appropriate bases for
examining a potential impact of
reducing methylmercury on IQ, but the
SAB does not consider these compelling
reasons for using IQ as a primary driver
of the risk assessment.’’ 253
249 Axelrad, D. A.; Bellinger, D. C.; Ryan, L. M.;
Woodruff, T. J. 2007. ‘‘Dose-response relationship of
prenatal mercury exposure and IQ: An integrative
analysis of epidemiologic data.’’ Environmental
Health Perspectives, 115, 609–615.
250 Bellinger DC. 2005. Neurobehavioral
Assessments Conducted in the New Zealand, Faroe
Islands, and Seychelles Islands Studies of
Methylmercury Neurotoxicity in Children. Report to
the U.S. Environmental Protection Agency. EPA–
HQ–OAR–2002–0056–6045.
251 U.S. EPA–SAB, 2011.
252 Bellinger, 2005.
253 U.S. EPA–SAB, 2011.
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The EPA disagrees that the Agency
has overstated or failed to review the
scientific literature on cardiovascular
effects from MeHg exposure. As
summarized in the preamble to the
proposal, the EPA stated that the NAS
study concluded that ‘‘Although the
data base is not as extensive for
cardiovascular effects as it is for other
end points (i.e., neurologic effects) the
cardiovascular system appears to be a
target for MeHg toxicity in humans and
animals.’’ 254 The EPA also stated that
additional cardiovascular studies have
been published since 2000. The EPA did
not develop a quantitative dose
response assessment for cardiovascular
effects associated with MeHg exposures,
as there is no consensus among
scientists on the dose-response
functions for these effects, and there is
inconsistency among available studies
as to the association between MeHg
exposure and various cardiovascular
system effects. In the future, the EPA
may update the MeHg RfD and will
review all of the relevant scientific
literature available at that time,
including data on all relevant
endpoints, and weight of evidence for
likelihood that MeHg produces specific
effects in humans.
The EPA acknowledges the research
regarding the effectiveness of fish
advisories. However, the proposed
regulation does not address the subject
of fish advisories, consumer advice on
fish or efficacy of such advice. The EPA
rejects the commenter’s speculation
regarding whether the estimated IQ
impacts for the regulation are real.
Adverse effects of in utero Hg exposure
have been reported in populations in
the U.S.255 256 In another study on
neurobehavioral effects of prenatal
exposure to MeHg through maternal
consumption of seafood, adverse effects
are observed for MeHg even without
controlling for fish consumption.257
That study suggests that at normal
Japanese dietary intake of MeHg and
fish nutrients, the overall effect is
adverse. While Japanese fish
consumption and Hg exposure are both
somewhat higher than the mean U.S.
exposure, these levels are still within
the distribution of U.S. consumers.
254 76
FR 25001.
et al., 2008.
256 Lederman et al., 2008.
257 Suzuki, K., Nakai, K., Sugawara, T.,
Nakamura, T., Ohba, T., Shimada, M., Hosokawa,
T., Okamura, K., Sakai, T., Kurokawa, N., Murata,
K., Satoh, C., and Satoh, H. 2007. ‘‘Neurobehavioral
effects of prenatal exposure to methylmercury and
PCBs, and seafood intake: neonatal behavioral
assessment scale results of Tohoku study of child
development.’’ Environ Res 110, 699–704.
255 Oken
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Moreover, many studies show that
beneficial effects of fish on both
cardiovascular and neurodevelopmental
health are decreased by concomitant
exposure to MeHg. Several studies
describe one or more aspects of
exposure to fish nutrients and
MeHg.258 259 260 261 262 263 264 Recent
studies 265 266 267 and analyses indicate
the potential for nutrients in fish
(particularly marine fish) to mask some
of the observed adverse effects of MeHg.
Because EPA did not adjust for potential
confounding by nutrients in marine fish
and mammals, the benchmark doses
used in the RfD derivation may be
underestimated.
The EPA recognizes the potential for
confounding of the effects of Hg on the
developing nervous system by a range of
nutrients and discusses this uncertainty
in the revised Hg Risk TSD. Regarding
selenium, the SAB commented that
‘‘one SAB member suggests the use of
blood markers of selenium-dependent
enzyme function, noting that
methylmercury irreversibly inhibits
selenium-dependent enzymes that are
required to support vital-but-vulnerable
metabolic pathways in the brain and
endocrine system. Impaired
selenoenzyme activities would be
observed in the blood before they would
be observed in brain, but the effect is
also expected to be transitory. The use
of these measures is a minority view
among the SAB members.’’ 268 The SAB
did not express a consensus
recommendation on adjustments to the
risk estimates for exposure to selenium
or other nutrients, noting that ‘‘there is
not enough known about their
258 Grandjean P, Bjereve K, Wihe P, and
Sterewald u. 2001a. ‘‘UBirthweight in a fishing
community: significance of essential fatty acids and
marine food contaminants.’’ In. J. Epidemiol.
30:1272–1278.
259 Budtz-Jorgensen, E.; Grandjean, P.; Weihe, P.
2007. ‘‘Separation of risks and benefits of 16
seafood intake.’’ Environmental Health
Perspectives. Vol. 115, 323–327.
260 Choi et al., 2008a.
261 Choi et al., 2008b.
262 Oken et al., 2008.
263 Strain, J.J. et al., 2008. Associations of
maternal long chain polyunsaturated fatty acids,
methyl mercury, and infant development in the
Seychelles Child Development Nutrition Study.’’
Neurotoxicology. 29(5): 776–782.
264 Suzuki, et al., 2007.
265 Oken et al., 2008.
266 Choi AL, Cordier S, Weihe P, Grandjean P.
2008a. ‘‘Negative confounding in the evaluation of
toxicity: the case of methylmercury in fish and
seafood.’’ Crit Rev Toxicol. 2008;38(10):877–93.
267 Choi AL, Budtz-J<rgensen E, J<rgensen PJ,
Steuerwald U, Debes F, Weihe P, Grandjean P.
2008b. ‘‘Selenium as a potential protective factor
against mercury developmental neurotoxicity.’’
Environ Res. May;107(1):45–52. Epub 2007 Sep 12.
268 U.S. EPA–SAB, 2011.
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quantitative impact to support a
recommendation of a re-analysis.’’ 269
6. General Comments on Hg Risk
Assessment
Comment: Several commenters
generally supported the Hg risk
assessment, but several other
commenters generally disagreed with
the Hg risk assessment. One supporter
stated that EPA reasonably determined
that Hg emissions pose a public health
hazard, correctly requested peer review
of Hg risk analysis and correctly
concluded EGU-attributable MeHg poses
a hazard to public health at watersheds
when considering all sources of Hg
deposition and U.S. EGUs alone. Two
commenters noted that the contribution
of U.S. EGUs to total Hg deposition can
significantly contribute to hundreds of
watersheds, and U.S. EGU deposition
alone may endanger sensitive
populations near many of these
watersheds.
Several commenters claimed that
overly conservative assumptions in the
risk analysis render the results flawed
and unreliable, including using CMAQ
to model deposition, Mercury Maps,
fish consumption rate and fish MeHg
concentrations, overly stringent RFD,
national-scale model, using poverty as a
surrogate for subsistence fishing,
assuming a subsistence fisher resides in
most watersheds with fish tissue data,
fishers only eat larger fish with high Hg
concentrations, cooking loss adjustment,
unrealistically high fish ingestion rates
(a large fish meal every day), focused on
the extremes of the distributions, cast
many assumptions as an underestimate
of the effect despite evidence to the
contrary, and created inappropriate
metrics for risk that show no
improvement despite significant Hg
emissions reductions in the U.S.
Several commenters cite Tetra Tech’s
analysis that assessed Hg risk using
different consumption rates, cooking
factor, mean fish tissue concentrations,
and EGU-attributable Hg deposition
only, which showed considerably fewer
watersheds that exceed an HQ of 1 at
2016 deposition levels.
Several commenters claim that this
regulation would not significantly
reduce Hg exposure via fish
consumption because EGU-attributable
deposition is a small fraction of total
deposition. One commenter stated that
EPA’s data shows Hg emissions from
U.S. EGUs have little influence on fish
Hg concentrations despite a reduction of
41 tons of Hg in the U.S. between 2005
and 2016. One commenter requested
that EPA accurately describe the low
269 Id.
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health risks posed by utility hazardous
air pollutant emissions. One commenter
stated that EPA did not consider
scientific information showing that
there is no straightforward connection
between Hg emissions from U.S. EGUs
to the Hg level in fish, which is
dependent upon many environmental
factors, such as sunlight and organic
matter, pH, water temperature, sulfate,
bacteria, and zooplankton present in the
ecosystem. One commenter stated that
there is not any demonstrable evidence
that anyone in the U.S. has suffered
adverse health problems as a result of
Hg emissions from coal-fired EGUs. One
commenter stated that EPA’s findings
are similar to the 2000 findings where
EPA found a plausible link between
anthropogenic emissions of Hg from
sources in the U.S. and MeHg in fish,
and ‘‘plausible’’ is a euphemism for
unproven.
Several commenters had
recommendations for the Hg risk
analysis. One commenter stated that
more data from Florida should have
been included because Florida is known
to have a rich data set on fish Hg
concentrations. One commenter stated
that EPA should characterize general
recreational angler fishers instead of
subsistence fishers. One commenter
claims that EPA made math errors in the
Hg Risk TSD regarding the deposition in
watersheds at specific percentiles. One
commenter questioned EPA’s policy
metrics used to characterize Hg risk.
Several commenters stated that the Hg
TSD is unclear and lacks detail, as noted
by the SAB. One commenter stated that
the SAB is critical of EPA’s efforts,
stating that the SAB found it difficult to
evaluate the risk assessment based
solely upon Hg Risk TSD and
recommended that EPA transparently
explain the methods and uncertainties.
One commenter stated that because of
insufficient review time and the lack of
detail in the Hg Risk TSD, they could
not assess key questions, such as the
nation-wide representativeness of the
fish tissue data.
One commenter stated the subset of
watersheds considered in the analysis
(i.e., with fish tissue data) have clearly
higher U.S. EGU-attributable deposition
than the distribution of all watersheds.
One commenter stated EPA’s
reporting of IQ point loss is erroneous
and not relevant to informing policy,
and the U.S. EGU contribution to risk is
marginal as evidenced by the null
values for the 50th percentile
watershed.
One commenter notes that U.S. EGUattributable emissions of Hg have
decreased significantly between 2005
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and 2016, but claims that this decrease
does not appear to affect the risk results.
Response: The purpose of the Hg risk
assessment is not to assess the
magnitude of risk reduction under the
proposed rule, but rather to estimate the
magnitude of absolute risk attributable
to U.S. EGUs currently and following
implementation of other applicable
CAA requirements. That said, any
potential risk reductions following
implementation of the MACT rule itself
would likely reflect a number of factors
besides the national average U.S. EGU
deposition value cited by the
commenter. These additional factors
include: (a) Spatial gradients in the
magnitude of absolute U.S. EGUattributable Hg deposition, (b) spatial
gradients in the magnitude of reductions
in Hg deposition linked to the rule, (c)
availability of measured fish tissue Hg
levels in the vicinity of U.S. EGUs
experiencing larger Hg emission
reductions to support risk modeling,
and (d) the potential for subsistence
fishing activity at watersheds in the
vicinity of U.S. EGUs experiencing
larger reductions in Hg emissions (also
required to support risk modeling). It is
also important to point out that while
the national average U.S. EGUattributable Hg deposition (for the 2016
scenario—see revised Hg Risk TSD) is
two percent, values range up to 11
percent for the 99th percentile
watershed. This illustrates the
substantial spatial variation in U.S.
EGU-attributable Hg deposition, which
translates into spatial variation in the
magnitude of U.S. EGU-attributable
subsistence fisher risk.
The SAB conducted a comprehensive
peer review of all of EPA’s assumptions
in the Hg Risk TSD, and concluded that
‘‘the SAB supports the overall design of
and approach to the risk assessment and
finds that it should provide an objective,
reasonable, and credible determination
of the potential for a public health
hazard from Hg emitted from U.S.
EGUs.’’ 270 Furthermore, the SAB
concluded, ‘‘The SAB regards the design
of the risk assessment as suitable for its
intended purpose, to inform decisionmaking regarding an ‘‘appropriate and
necessary finding’’ for regulation of
hazardous air pollutants from coal and
oil-fired EGUs, provided that our
recommendations are fully considered
in the revision of the assessment.’’ 271
Although the SAB did indicate
difficulty in evaluating the risk
assessment based solely on the Hg Risk
TSD, the panel obtained additional
information from EPA through the peer
270 U.S.
EPA–SAB, 2011.
272 Id.
271 Id.
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review process and determined that
‘‘the SAB supports the overall design of
and approach to the risk assessment and
finds that it should provide an objective,
reasonable, and credible determination
of the potential for a public health
hazard from mercury emitted from U.S.
EGUs.’’ 272 The primary advice of the
SAB panel was that EPA should ‘‘revise
the Technical Support Document to
better explain the methods and choices
made in the analysis, and analytical
results, and where the uncertainties
lie.’’ 273 The EPA has revised the Hg
Risk TSD as part of the final rulemaking
to address the SAB’s recommendations
and has made that revised Hg Risk TSD
available in the rule docket.
The SAB concurred with EPA’s
analytical assumptions and overall
study design for the Hg Risk TSD,
including the RfD-based HQ approach,
fish tissue data, 75th percentile size
fish, Mercury Maps assumption, and
consumption rates. Based on the SAB
peer review, the EPA strongly disagrees
with commenter statements that the
results reported in the Hg Risk TSD are
unreliable, overly conservative, extreme,
inconsistent with EPA risk guidelines,
or severely overstate risk based on the
stated objectives of the analysis. The
EPA has specifically addressed each of
these assumptions in the previous
sections of the preamble, and thus, does
not repeat those responses here. Based
on the review by the SAB, the EPA has
accurately described the health risks
posed by utility hazardous air pollutant
emissions and disagrees with the
commenter’s statement that EPA has not
provided any demonstrable evidence to
show that adverse health risks exist. The
EPA has applied peer reviewed
modeling to estimate the deposition of
Hg attributable to U.S. EGUs. The EPA
asserts that these metrics demonstrate a
clear hazard to public health from Hg
emissions from U.S. EGUs.
The EPA thoroughly evaluated the
Tetra Tech analysis. The EPA does not
agree that the analysis by Tetra Tech
uses assumptions that are ‘‘more
reasonable’’, and the SAB agreed that all
of EPA’s assumptions in the Hg Risk
TSD are reasonable and appropriate.
The EPA asserts that Tetra Tech’s
analysis does not fully cover subsistence
fishers likely to experience elevated
U.S. EGU-related Hg exposure.
Specifically, the risk estimate cited in
the comment reflects application of a
number of behavioral assumptions that
provide significantly less coverage for
higher risk subsistence fishers. Fish
consumption surveys cited in the
273 Id.
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revised Hg Risk TSD suggest that higher
percentile subsistence fishers eat more
than twice the level of fish assumed by
Tetra Tech. Tetra Tech’s analysis also
used the median fish tissue levels, but
it is reasonable to assume that
subsistence fishers would target
somewhat larger fish to maximize the
volume of edible meat per unit time
spent fishing. Tetra Tech’s analysis also
assumed that cooking fish did not
concentrate Hg, but a number of studies
discussed in the revised Hg Risk TSD
explicitly provide adjustment factors
involving a higher unit concentration
following preparation. Taken together,
Tetra Tech’s analysis does not address
the stated goal of the risk assessment to
assess the nature and magnitude of risk
for those individuals likely to
experience the greatest risk associated
with exposure to U.S. EGU-attributable
Hg.
The EPA disagrees with the
commenter’s assertion that this rule will
not affect risks associated with Hg
exposure. Hg from U.S. EGUs
contributes to the levels of MeHg in fish
across the country and consumption of
contaminated fish can lead to increased
risk of adverse health effects. The EPA
has shown in the RIA (Chapter 5) that
this rule will reduce Hg levels in fish.
The EPA acknowledges that U.S.
EGUs contribute only a small fraction of
total Hg deposition in the U.S. However,
U.S. EGUs remain the largest emitter of
Hg in the U.S., and the revised Hg Risk
TSD shows that U.S. EGU-attributable
Hg deposition results in up to 29
percent of modeled watersheds with
populations potentially at-risk. Our
analyses show that of the 29 percent of
watersheds with population at-risk, in
10 percent of those watersheds U.S.
EGU deposition alone leads to potential
exposures that exceed the MeHg RfD,
and in 24 percent of those watersheds,
total potential exposures to MeHg
exceed the RfD and U.S. EGUs
contribute at least 5 percent to Hg
deposition. Mercury risk is increasing
for exposures above the RfD, and as a
result, any reductions in Hg exposures
in locations where total exposures
exceed the RfD can result in reduced
risks. While these reductions in risk
may be small for most populations and
locations, in some watersheds and for
some populations, reductions in risk
may be greater.
The SAB also directly addressed the
question of the nation-wide
representativeness of the fish tissue
MeHg data in the national Hg risk
assessment. The SAB concluded,
‘‘Although the SAB considers the
number of watersheds included in the
assessment adequate, some watersheds
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in areas with relatively high mercury
deposition from U.S. EGUs were undersampled due to lack of fish tissue
methy[l]mercury data. The SAB
encourages the Agency to contact states
with these watersheds to determine if
additional fish tissue methylmercury
data are available to improve coverage
of the assessment.’’ 274 In response to
the SAB’s recommendations, the EPA
obtained additional fish tissue sample
data from several states, particularly
Pennsylvania, Wisconsin, Minnesota,
New Jersey, and Michigan. This
additional data increased the total
number of watersheds assessed in the
analysis by 33 percent nationally. In
Florida, the EPA assessed the Hg-related
health risk for 40 watersheds. Because
EPA did not find any additional fish
tissue data for watersheds in Florida
that could be incorporated into the
analysis, the total number of watersheds
in Florida assessed in the revised Hg
Risk TSD remains the same as the Hg
Risk TSD at proposal.
The EPA disagrees with the
commenter that there were errors in the
Hg Risk TSD. Instead, the commenter
has misinterpreted how EPA calculated
the percentiles. The percentile (and
mean) values presented in Table ES–1
for total and U.S. EGU-attributable Hg
deposition are not matched by
watershed. In other words, the EPA
queried for the percentiles (and mean)
provided for total Hg deposition and
presented those percentiles and then
separately estimated the percentiles for
U.S. EGU-attributable Hg. Therefore, the
total and U.S. EGU-attributable values
for the 99th percentile do not
necessarily occur at the same watershed.
The EPA has provided additional
clarification in the revised Hg Risk TSD.
The EPA agrees with the commenter
that MeHg levels in fish depend on a
complicated set of environmental
factors, and EPA acknowledged this in
the revised Hg Risk TSD. Furthermore,
the EPA acknowledges that total Hg fish
tissue levels are not correlated with
levels of total Hg deposition when
looking across watersheds because this
relationship is highly dependent on the
methylation potential at the specific
waterbody, which is affected by pH,
sulfate deposition, turbidity, etc.
However, several recent studies 275 276 277
show, and the SAB agrees, that it is
appropriate for EPA to assume that
changes in Hg deposition are linearly
associated with changes in fish tissue
concentration. In addition, the EPA
274 U.S.
EPA–SAB, 2011.
et al., 2007.
276 Orihel et al., 2008.
277 Harris et al., 2007.
275 Orihel
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agrees that the subset of watersheds in
the risk analysis have somewhat higher
U.S. EGU deposition than the
distribution of all watersheds, but EPA
disagrees that oversampling of high
deposition watersheds is inappropriate.
The EPA does not agree that there is
no improvement in fish Hg
concentrations between 2005 and 2016,
or that there will be no further
improvement from decreasing Hg
emissions from U.S. EGUs from the
baseline in 2016. Although total risk
from all Hg exposures will remain
elevated in much of the U.S., much of
that risk is associated with global, nonU.S. Hg emissions. U.S. EGUs remain
the largest source of Hg emissions in the
U.S., and reductions in those emissions
will result in reduced Hg deposition in
many highly impacted watersheds. As
shown in the revised Hg Risk TSD,
average U.S. EGU-attributable fish tissue
Hg concentrations is estimated to
decrease by 44 percent between 2005
and 2016. Although we did not remodel
risk for the 2005 scenario in the revised
Hg Risk TSD, we estimated at proposal
that the total percent of modeled
watersheds with populations potentially
at-risk from Hg emissions from U.S.
EGUs exceeding either risk metric (i.e.,
U.S. EGUs alone or total potential
exposures to MeHg exceed the RfD and
U.S. EGUs contribute at least 5 percent)
would decline from 62 percent in 2005
to 28 percent in 2016. This projected
decline is primarily due to a
combination of additional pollution
control technologies installed to comply
with federal regulations, such as
CSAPR, and changing fuels, such as the
shift to natural gas.
The EPA disagrees that IQ loss is
erroneous or irrelevant to informing
policy, but EPA has moved that analysis
to an appendix in the revised Hg Risk
TSD, per the SAB’s recommendation.
The EPA disagrees that the IQ effects at
the 50th percentile watershed are useful
in determining that there is not a hazard
to public health because EPA’s stated
goal of the risk assessment was to focus
on populations likely to experience
relatively higher exposures to U.S. EGUattributable Hg.
We also disagree with those
commenters that point to the SAB’s
statements concerning the clarity of the
Hg Risk TSD to suggest that the public
did not have an ample opportunity to
comment on the Hg risk assessment.
Although it is correct that the SAB said
the Hg Risk TSD was difficult to
evaluate until EPA staff explained it at
the public meeting in June 2011, we
note that the commenters that assert that
this issue amounts to a violation of CAA
section 307(d) notice requirements
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made detailed technical comments,
including many of the same comments
as the SAB. Furthermore, the EPA
provided notice of the peer review in
the preamble to the proposed rule and
a number of Federal Register notices
advised the public of the peer review
process and all the meetings were open
to the public for comment and
participation and the minutes of those
meetings were posted on the SAB Web
site. The minutes for the June 2011
meeting, during which EPA provided
clarifying information, were available
well within the public comment period
for the proposed rule. For these reasons,
we maintain that the public was
provided an adequate opportunity to
comment on the Hg risk assessment.
e. Non-Hg HAP Case Studies
1. Emissions for Non-Hg Case Studies
Comment: The commenters raised
concerns about a wide variety of aspects
of EPA’s approach for emissions used
for the non-Hg case studies, including
the use of an arithmetic mean for
computing emission factors for
representing emissions of untested
units, the suggestion of statistical
outliers in the Cr test data, the claim
that metals content of the fuel is an
indicator of flawed test data, the
statistical approaches used by EPA to
create emission factors, the absence in
EPA’s approach of an equation that
commenters claim better represents
emissions values, that EPA’s approach
to estimate Cr(VI) is flawed, and the lack
of coal rank as a delineating factor for
emission factor calculation. The
commenters also suggested that EPA
should revise stack parameters used for
the case studies based on better
available data.
Response: In response to the
comments on the emission factors, the
EPA has undertaken additional analysis
to address all commenter concerns. The
EPA disagrees with commenter’s
criticisms of emission factors based on
arithmetic means, and EPA
demonstrates that the use of an
arithmetic mean provides the most
representative result. The EPA analysis
has found that the geometric mean
approach recommended by the
commenter always under predicts actual
emissions by an average of more than
seventy percent. The EPA agrees with
commenters’ recommendations to use
statistical outlier tests, but has applied
tests different from those suggested by
the commenters. As further explained in
the response to comments document in
the docket, this approach did not
eliminate the Cr test data from the Cr
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emission factors used for some of the
case study emissions.
The EPA disagrees with commenters’
assertions that the metal content of the
coal is a basis for invalidating the test
results of high Cr emissions. The
identification of sources whose
measured emissions do not match the
commenters’ preconceived idea of
emissions behavior is not surprising.
There are many possible explanations
for these differences. For example, the
inconsistency between the test data and
the coal analysis could be due to any
number of reasons including
unrepresentative coal sampling, control
device problems, degradation of the
refractory, or sampling contamination.
The idea that test data should be
discarded because it does not match
initial expectations is unfounded.
The EPA disagrees with the
commenter recommendations for using
an equation from AP–42, developed in
part by the commenters. Based on
analyses of metal emissions measured at
the site compared to statistically
predicted estimates, the EPA concluded
that measured emissions test data better
predict actual emissions, and emission
factors based on the arithmetic mean are
a reasonable method to estimate
emissions when test data are not
available. The EPA analysis of the ICR
data has found that the emissions
equation recommended by the
commenter is not a good predictor of
actual EGU emissions. The EPA also
disagrees with commenters’ concerns
about the assumption that 12 percent of
the Cr will be Cr(VI) for every coal-fired
unit, which was specifically supported
by the peer review on the approach for
estimating cancer risks associated with
Cr and Ni emissions. The EPA disagrees
with the commenter’s assertion that any
impact of scrubbers will impact the case
study analyses. In EPA’s revised case
study analysis, 6 facilities have risk
greater than 1 in a million, and of these,
four facilities have Cr as the risk driver
(James River, Conesville, TVA Gallatin,
and Dominion—Chesapeake Bay). For
these facilities, none of the units
contributing the bulk of the Cr
emissions have scrubbers according to
the data provided to EPA by those
facilities, so scrubber impacts on Cr
speciation is not relevant to EPA’s
conclusions based on the non-Hg case
studies. In any case, the EPA disagrees
with the commenter’s conclusions about
the impacts of scrubbers on Cr
speciation and provides evidence that
impacts of scrubbers on Cr speciation
can have the opposite effect on Cr(VI)
fractions, concluding that EPA’s 12
percent assumption is somewhat
conservative.
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The EPA also disagrees that coal rank
must be a factor in computing Cr
emission factors for use in the case
studies. The EPA’s analysis has
demonstrated that coal rank appears to
play no role in non-Hg metals
emissions. The EPA’s newly revised
emissions factor development
procedures can isolate and compare
subgroups based on control device type
or coal rank; the ICR data were
subjected to these tests and no statistical
significance was found between coal
rank groups.
Finally, the EPA agrees with one
commenter’s recommendations on
revised stack parameters for the case
studies and has included these revisions
in the case study modeling for the final
rule.
2. General Comments on Non-Hg Risk
Case Study
Comment: One commenter stated that
EPA’s case study assessment reaffirms
the need to regulate HAP emitted by
both coal and oil-fired EGUs. The
commenter noted that over 40 percent of
the case studies conducted by EPA to
quantify health hazards associated with
the inhalation of non-Hg HAP indicated
a cancer risk greater than or equal to the
one in a million threshold level required
to delist a source category under CAA
section 112.
One commenter stated that EPA’s case
study assessment might be flawed by
the use of ‘‘beta’’ tests versions of the
AERMOD meteorological preprocessors
(AERMINUTE and AERMET). The
commenter obtained from EPA the
meteorological data used for EPA’s
assessment of the Conesville facility and
processed these data with EPA’s current
regulatory versions of these
preprocessors, which differ from the
beta version. According to the
commenter, a comparison of the hourly
wind speed and hourly wind direction
data produced by the beta preprocessor
and by current EPA preprocessors
revealed numerous and often substantial
disparities.
One commenter stated that EPA’s
finding that only three coal-fired
facilities and one oil-fired facility out of
roughly 440 coal-fired facilities and 97
oil-fired facilities in the U.S. indicated
risk greater than one-in-a-million
supports a finding that it is
‘‘appropriate’’ to regulate those four and
not the other 537. Another commenter
stated that EPA found only a ‘‘few’’
facilities that have estimated maximum
cancer risks in excess of one in a
million, and that this does not justify
regulating all non-Hg HAP for all
sources in this category.
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One commenter stated that EPA’s
discussion in the preamble to the
proposed rule misleads the reader into
believing that non-Hg HAP emissions
from EGUs are associated with serious
human health effects. According to the
commenter, the EPA’s discussion of the
effects associated with excessive
exposure to an individual HAP would
lead the reader to believe that those
effects inevitably occur from EGU
emissions because EGU emissions have
trace amounts of non-Hg HAP.
One commenter stated that with the
assumptions in the Utility Study, both
in terms of conservative scientific
estimates and overestimated amounts of
oil burned by these units, the EPA
concluded that the risks from oil-fired
units would result in only one new
cancer case every 5 years. The
commenter does not believe that this
level of risk warrants regulation under
CAA section 112(n)(1)(A).
Several commenters stated that even
if the additional studies EPA performed
were accurate, they hardly demonstrate
that it is necessary and appropriate to
regulate coal-fired EGU HAP under CAA
section 112 because three sites
nationwide show risks greater than one
in a million, with the highest at eight in
a million.
One commenter stated that the
highest cancer risk estimated for coalfired EGUs is still within the acceptable
range used by EPA in other programs
and is also far less than the background
exposure risks the average person
experiences. The background risk of
developing cancer in a lifetime is
approximately one in three (0.33).
According to EPA’s own data, the
predicted added cancer risk of exposure
to HAP from U.S. EGUs would change
the background risk from 0.33 to
0.330001. This level of change is so
minimal that it could not be observed in
any health effects study that might be
conducted.
One commenter stated that EPA
conducted a health risk assessment on
a limited number of facilities and found
a ‘‘few’’ facilities that have estimated
maximum cancer risks in excess of one
in a million. The commenter stated that,
based on this limited health risk
assessment, the EPA apparently decided
that they were justified to regulate all
non-Hg HAP for all sources in this
category.
Several commenters stated that EPA’s
assumption implies that a person stays
exactly at the center of a census tract for
70 years and that a unit will operate in
exactly the same manner for 70 years is
unrealistic. The commenters suggest
that Tier 3 risk assessment is warranted
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or a lifetime exposure adjustment is
needed.
One commenter asserts that because
the alleged health benefits are derived
from total exposure, the EPA should
explain how its numerical emission
limit units, which would not directly
restrict total exposure if heat inputs
increase, redress this health concern. In
its preamble, the EPA simply notes that
its emission limit units are consistent
with, and allow for simple comparison
to, other regulations.
One commenter questioned whether
acid gas emissions limits for oil-fired
units are ‘‘appropriate’’ or ‘‘necessary’’
because EPA’s new technical analyses
do not indicate a health concern from
acid gas emissions from oil-fired units.
According to the commenter, the EPA
identifies Ni as the main HAP of
concern from oil-fired units, even
though cancer-related inhalation risks
were well below the RfCs and EPA
states that significant uncertainty
remains as to whether those emissions
present a health concern.
Response: The EPA agrees with the
commenter that the non-Hg HAP risk
assessment confirms the appropriate
and necessary finding.
The EPA disagrees that EPA’s case
study assessment is flawed by the use of
beta versions of AERMINUTE and
AERMET. The EPA remodeled the case
study facilities using the current
versions of AERMINUTE (version
11059), AERMET (version 11059), and
AERMOD (version 11103). Although
there were differences in the number of
calm and missing winds in the current
AERMINUTE/AERMET output
compared to the beta version, the
resulting risks differed by less than two
percent, on average. For Conesville,
which had the largest difference in
calms between the beta and current
versions of AERMINUTE/AERMET, the
risks differed by three percent. For the
final rule, the case study facilities have
been modeled with the current available
versions of AERMINUTE, AERMET, and
AERMOD.
The EPA disagrees with the
commenter that having only a few case
study facilities exceeding one in a
million risk invalidates the ‘‘appropriate
finding’’. The 16 facilities EPA selected
as case studies for assessment may not
represent the highest-emitting or
highest-risk sources. Although case
study facility selection criteria included
high estimated cancer and non-cancer
risks using the 2005 NEI data, high
throughput, and minimal emission
control, another necessary criterion was
the availability of Information
Collection Request (ICR) data for the
EGUs at those facilities (or for similar
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EGUs at other facilities). Because the
ICR data were collected for the purpose
of developing the MACT standards, the
ICR was targeted towards better
performing sources for non-Hg metal
HAP, acid gas HAP, and organic HAP,
with a smaller set of random recipients.
Therefore, facilities for which ICR data
were available may not represent the
highest-emitting sources. The EPA’s
assessment of the case study facilities
for the proposed rule concluded that
three coal-fired facilities and one oilfired facility had estimated lifetime
cancer risks greater than one in a
million. For the final rule, revisions
were made to the 16 case studies based
on comments received, and the results
indicate that 5 coal-fired facilities and 1
oil-fired facility had estimated lifetime
cancer risks greater than 1 in a million.
The EPA maintains that its finding that
more than 30 percent of the case study
facilities had a cancer risk greater than
one in a million is sufficient to support
the appropriate finding.
The EPA disagrees with the
commenter’s assertion that the health
effects associated with exposures to
non-Hg HAP from U.S. EGUs are
mischaracterized in the preamble to the
proposed rule. The discussion of the
health effects of non-Hg HAP provided
in the preamble includes general
information on the potential health
effects associated with a broad range of
exposure concentrations (from low to
high levels) of the various non-Hg HAP
(some of which have been determined to
be carcinogenic to humans) based on
peer reviewed scientific information
extracted from priority sources such as
IRIS, Cal EPA and ATSDR health effects
assessments.
The EPA disagrees with the
commenter’s characterization of the
Utility Study. The Utility Study
represented the highest-quality factual
record of information available at the
time regarding EGU emissions and risks.
Further, the EPA’s revised risk
assessments of 16 case studies,
performed with more recent data and
refined scientific methods, indicate that
there are six U.S. EGU facilities that
pose estimated inhalation cancer risks
greater than 1 in a million. The EPA
maintains that the findings of the case
studies are one element that
independently supports our
determination that it remains
appropriate and necessary to regulate
EGUs under CAA section 112.
The EPA does not agree with the
commenter who suggested that EPA
should interpret the results of the nonHg HAP risk analysis in the context of
background cancer risk. As explained in
the preamble to the proposed rule, the
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EPA reasonably looked to the cancer
risk threshold established under CAA
section 112(c)(9)(B)(1) for delisting a
source category as an indicator of the
level of cancer risk that was appropriate
to regulate under CAA section 112. The
commenters comparison of the cancer
risk from EGUs as compared with the
risk of contracting cancer from
unknown sources is not the standard
Congress established for evaluating HAP
emission risk and the commenter has
provided no support for its contention
that the Agency should evaluate risk in
that manner. The EPA maintains that
the analysis was reasonable.
The EPA does not agree with the
commenter’s implication that EPA must
make a facility-specific finding for each
HAP for each source and then only
regulate individual EGU facilities for the
individual HAP that identified as
causing an identified hazard to public
health or the environment. That
approach is not required under CAA
section 112(n)(1) or anywhere under
CAA section 112, and it would be
virtually impossible to undertake such
an effort. For these reasons, the EPA
does not agree with the commenter and
maintains that the appropriate and
necessary finding is reasonably
supported by the record and consistent
with the statute for all the reasons set
forth in the preamble to the proposed
rule and this final action.
The EPA disagrees that an exposure
adjustment is needed to account for
conditions changing over 70 years
because it runs counter to the longstanding approach that EPA has taken to
estimate the maximum individual risk,
or MIR. The MIR is defined by EPA’s
Benzene NESHAP regulation of 1989 278
and codified by CAA section 112(f) as
the lifetime risk for a person located at
the site of maximum exposure 24 hours
a day, 365 days a year for 70 years (e.g.,
census block centroids). The MIR is the
metric associated with the
determination of whether or not a
source category may be delisted from
regulatory consideration under CAA
section 112(c)(9). The MIR is the risk
metric used to characterize the
inhalation cancer risks associated with
the case study facilities. The EPA used
the annual average ambient air
concentration of each HAP at each
census block centroid as a surrogate for
the lifetime inhalation exposure
concentration of all the people who
reside in the census block. The EPA has
used this approach to estimate MIR
values in all of its risk assessments to
278 54
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support risk-based rulemakings under
CAA section 112 to date.
The EPA disagrees with the
commenter’s assertion that the
numerical emission limits being
promulgated in today’s final rule must
be justified on their ability to redress the
health concerns that were identified as
the basis for regulating EGUs. The
emission limits in today’s rule are
technology-based, as prescribed under
CAA section 112, and do not need to be
justified based on their ability to protect
public health. Regarding potential
health concerns, the EPA has up to 8
years after the promulgation of the
technology-based emission limits for
EGUs to determine whether the
regulations protect public health with
an ample margin of safety. If the
regulations do not, the CAA directs EPA
to promulgate additional more stringent
standards (within the prescribed 8
years) to achieve the appropriate level of
public health protection.
Furthermore, the EPA reasonably
concluded that it was appropriate and
necessary to regulate oil-fired EGUs in
2000, and EPA confirmed that
conclusion was proper with the analysis
set forth in the preamble to the
proposed rule. Certain commenters
question the determination based on
their views of how the Agency can and
should exercise its discretion. The EPA
disagrees with these commenters and
stands by the determination for the
reasons set forth in the preamble to the
proposed rule. The EPA also stands by
the determination that the maximum
cancer risks posed by emissions of oilfired EGUs are greater than one in a
million, due primarily to emissions of
Ni compounds. Based on our analysis,
we are unable to delist oil-fired EGUs.
3. Ni Risk
Comment: Several commenters stated
that the assumptions regarding the
speciation and carcinogenic potential of
Ni compounds used in EPA’s inhalation
risk assessment of the case study
facilities are overly conservative and
likely to overstate the risks. With
respect to Ni speciation, the
commenters stated that there are
substantial uncertainties regarding the
species of Ni being emitted and the risk
of such emissions, and that EPA has
made ultraconservative assumptions
aimed at overestimating the risk. The
commenters stated that assigning the
same carcinogenic potency of Ni
subsulfide to other forms of Ni is overly
conservative and inconsistent with the
best available evidence.
Response: The EPA disagrees with the
commenters’ assertion that it is
impossible to give an accurate
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assessment of the risks to human health
from Ni emissions from EGUs, and
maintains that its assessment of the
potential inhalation risks from EGU
emissions of Ni compounds is
scientifically valid, reasonable, and
based on the best-available current
scientific understanding. To that end, in
July 2011, the EPA completed an
external peer review (using three
independent expert reviewers) of the
methods used to evaluate the risks from
Ni and Cr compounds emitted by
EGUs.279 There were two charge
questions relating to Ni in that review.
First, do EPA’s judgments related to
speciated Ni emissions adequately take
into account available speciation data,
including recent industry spectrometry
studies? Second, based on the
speciation information available and
what is known about the health effects
of Ni compounds, and taking into
account the existing URE values (i.e.,
values derived by the Integrated Risk
Information System,280 California
Department of Health Services,281 and
the Texas Commission on
Environmental Quality 282), which of the
following approaches to derive unit risk
estimates would result in a more
accurate and defensible characterization
of risks from exposure to Ni
compounds?
1. To continue using the same
approach as that developed for use in
the 2000 NATA, which consists of using
the IRIS URE for nickel subsulfide and
assuming that nickel subsulfide
constitutes 65 percent of the mass
emissions of all Ni compounds.
2. To consider a more healthprotective approach, based on the
consistent views of the most
authoritative scientific bodies (i.e., NTP
in their 12th ROC, IARC, and other
international agencies) that consider Ni
compounds to be carcinogenic as a
group.
3. To make the same assumptions as
in option 2, but considering alternative
UREs derived by the CDHS or TCEQ.
In responding to these peer review
questions, two of the reviewers agreed
with the views of the most authoritative
scientific bodies, which consider Ni
279 U.S.
EPA, 2011c.
EPA, 1991.
281 California Department of Health Services
(CDHS) 1991. Health Risk Assessment for Nickel.
Air Toxicology and Epidemiology Section,
Berkeley, CA. Available online at https://
oehha.ca.gov/air/toxic_contaminants/html/
Nickel.htm.
282 Texas Commission on Environmental Quality
(TCEQ), 2011. Development Support Document for
nickel and inorganic nickel compounds. Available
online at https://www.tceq.state.tx.us/assets/public/
implementation/tox/dsd/final/june11/
nickel_&_compounds.pdf.
280 U.S.
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9359
compounds carcinogenic as a group.
These reviewers, therefore, did not
focus on the availability of Ni speciation
profile data. The third reviewer
recommended that EPA review several
manuscripts on Ni speciation profiles
showing that sulfidic Ni compounds
(which the reviewer considered as the
most potent carcinogens) are present at
low levels in emissions from EGUs.
Nickel and Ni compounds have been
classified as human carcinogens by
national and international scientific
bodies including the IARC,283 the World
Health Organization,284 and the
European Union’s Scientific Committee
on Health and Environmental Risks.285
In their 12th Report of the Carcinogens,
the NTP has classified Ni compounds as
known to be human carcinogens based
on sufficient evidence of carcinogenicity
from studies in humans showing
associations between exposure to Ni
compounds and cancer, and supporting
animal and mechanistic data. More
specifically, this classification is based
on consistent findings of increased risk
of cancer in exposed workers, and
supporting evidence from experimental
animals that shows that exposure to an
assortment of Ni compounds by
multiple routes causes malignant
tumors at various organ sites and in
multiple species. The 12th Report of the
Carcinogens states that the ‘‘combined
results of epidemiological studies,
mechanistic studies, and carcinogenesis
studies in rodents support the concept
that Ni compounds generate Ni ions in
target cells at sites critical for
carcinogenesis, thus allowing
consideration and evaluation of these
compounds as a single group’’.286
Although the precise Ni compound (or
compounds) responsible for the
carcinogenic effects in humans is not
always clear, studies indicate that Ni
sulfate and the combinations of Ni
sulfides and oxides encountered in the
Ni refining industries cause cancer in
humans. There have been different
views on whether or not Ni compounds,
as a group, should be considered as
carcinogenic to humans. Some authors
283 International Agency for Research on Cancer
(IARC), 1990. IARC monographs on the evaluation
of carcinogenic risks to humans. Chromium, nickel
and welding. Vol. 49. Lyons, France: International
Agency for Research on Cancer, World Health
Organization Vol. 49:256.
284 International Labour Organization/United
Nations Environment Programme, World Health
Organization (WHO), 1991. Nickel. In
Environmental Health Criteria No 108 Geneva.
285 European Commission, Scientific Committee
on Health and Environmental Risks (SCHER), 2006.
Opinion on: Reports on Nickel, Human Health part.
SCHER, 11th plenary meeting of 04 May 2006
https://ec.europa.eu/health/ph_risk/committees/
04_scher/docs/scher_o_034.pdf.
286 NTP, 2011.
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believe that water soluble Ni, such as Ni
sulfate, should not be considered a
human carcinogen, based primarily on a
negative Ni sulfate 2-year NTP rodent
bioassay (which is different than the
positive 2-year NTP bioassay for Ni
subsulfide).287 288 289 Although these
authors agree that the epidemiological
data clearly supports an association
between Ni and increased cancer risk,
they sustain that the data are weakest
regarding water soluble Ni. A recent
review 290 highlights the robustness and
consistency of the epidemiological
evidence across several decades
showing associations between exposure
to Ni and Ni compounds (including Ni
sulfate) and cancer.
Based on the views of the major
scientific bodies mentioned above, and
those of expert peer reviewers that
commented on EPA’s approaches to risk
characterization of Ni compounds, the
EPA considers all Ni compounds to be
carcinogenic as a group and does not
consider Ni speciation or Ni solubility
to be strong determinants of Ni
carcinogenicity. With regards to noncancer effects, comparative quantitative
analysis across Ni compounds indicates
that Ni sulfate is as toxic or more toxic
than Ni subsulfide or Ni oxide.291 292
Regarding the second charge question,
two of the reviewers suggested using the
URE derived by TCEQ for all Ni
compounds as a group, rather than the
one derived by IRIS specifically for Ni
subsulfide. The third reviewer did not
comment on alternative approaches.
The EPA decided to continue using 100
percent of the current IRIS URE for Ni
subsulfide because IRIS values are at the
top of the hierarchy with respect to the
dose response information used in
EPA’s risk characterizations, and
because of the concerns about the
potential carcinogenicity of all forms of
Ni raised by the major national and
international scientific bodies.
287 Oller A. Respiratory carcinogenicity
assessment of soluble nickel compounds. Environ
Health Perspect. 2002, 110:841–844.
288 Heller JG, Thornhill PG, Conard BR. New
views on the hypothesis of respiratory cancer risk
from soluble nickel exposure; and reconsideration
of this risk’s historical sources in nickel refineries.
J Occup Med Toxicol. 2009, 4:23.
289 Goodman JE, Prueitt RL, Thakali S, and Oller
AR. The nickel iron bioavailability model of the
carcinogenic potential of nickel-containing
substances in the lung. Crit Rev Toxicol. 2011,
41:142–174.
290 Grimsrud TK and Andersen A. Evidence of
carcinogenicity in humans of water-soluble nickel
salts. J Occup Med Toxicol. 2010. 5:1–7. Available
online at https://www.ossup-med.com/content/5/1/7.
291 Haber LT, Allen BC, Kimmel CA. Non-Cancer
Risk Assessment for Nickel Compounds: Issues
Associated with Dose-Response Modeling of
Inhalation and Oral Exposures. Toxicol Sci. 1998.
43:213–229.
292 NTP, 1996.
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Nevertheless, taking into account that
there are potential differences in
toxicity and/or carcinogenic potential
across the different Ni compounds, and
given that there have been two URE
values derived for exposure to mixtures
of Ni compounds that are 2–3 fold lower
than the IRIS URE for Ni subsulfide, the
EPA also considers it reasonable to use
a value that is 50 percent of the IRIS
URE for Ni subsulfide for providing an
estimate of the lower end of a plausible
range of cancer potency values for
different mixtures of Ni compounds.
4. Cr Risk
Comment: One commenter stated
there are several problems with EPA’s
analysis related to the fact that Cr
emissions were evaluated as being
entirely Cr(VI). The commenter stated
that not all of the emitted Cr will remain
in the hexavalent form by the time it
reaches the target population, and that
some may be converted to the much less
toxic (and noncarcinogenic) trivalent
species. The commenter also stated that
the concentration levels considered in
the case study assessment are far below
occupational levels. The commenter
concluded that EPA’s cancer estimates
should, therefore, be looked on with
some skepticism. Another commenter
stated that EPA’s estimate of 12 percent
Cr(VI) from coal-fired EGUs is
unsupported, and that EPA failed to
recognize that Cr(VI) is highly watersoluble and is easily reduced to Cr(III)
in the presence of SO2 in a low pH
environment. The resulting Cr(III)
would be expected to precipitate out in
a FGD. The commenter stated that the
actual amount of Cr(VI) that would be
present in the emissions from an EGU
with a wet scrubber is likely to be far
lower than the 12 percent estimate made
by EPA.
Several commenters questioned the
validity of the chronic inhalation study
by EPA because of (1) the use of
surrogate speciated Cr emissions data
instead of actual emissions data, (2) the
assumption that units were run 100
percent of the time which is impossible,
(3) dispersion modeling was used that is
biased towards over predicting
downwind impacts, and (4) estimated
ambient concentrations were utilized as
substitutes for real exposure
concentrations for all people within a
census block.
Response: The EPA disagrees with the
commenters’ assertion that all Cr was
considered to be hexavalent. As
discussed in ‘‘Methods to Develop
Inhalation Cancer Risk Estimates for
Chromium and Nickel Compounds,’’ 293
293 U.S.
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existing test data for utility and
industrial boilers indicate that Cr(VI) is,
on average, 12 percent of total Cr from
coal-fired boilers. This document
underwent peer review by three external
reviewers, and all three reviewers
considered EPA’s use of the values to be
reasonable given the limited data
available for Cr speciation profiling. The
EPRI inhalation study for coal-fired
boilers also used the 12 percent value.
The EPA also disagrees that units
were assumed to operate 100 percent of
the time. The dispersion modeling
performed for the case study facilities
used hourly heat input as a
temporalization factor for estimating
hourly emissions, and in some cases
hourly heat inputs (and emissions) were
zero or very low. The commenter
provided no data or information to
support their claim that the dispersion
modeling EPA used is biased towards
overestimating downwind impacts.
The EPA disagrees with the
commenters’ assertion that ‘‘real
exposure concentrations for all people
within a census block’’ must be
considered because it runs counter to
the long-standing approach that EPA
has taken to estimate the maximum
individual risk, or MIR. The MIR is
defined by EPA’s Benzene NESHAP
regulation of 1989 294 and codified by
CAA section 112(f) as the lifetime risk
for a person located at the site of
maximum exposure 24 hours a day, 365
days a year for 70 years (e.g., census
block centroids). The MIR is the metric
associated with the determination of
whether or not a source category may be
delisted from regulatory consideration
under CAA section 112(c)(9). The MIR
is the risk metric used to characterize
the inhalation cancer risks associated
with the case study facilities. The EPA
used the annual average ambient air
concentration of each HAP at each
census block centroid as a surrogate for
the lifetime inhalation exposure
concentration of all the people who
reside in the census block. The EPA has
used this approach to estimate MIR
values in all of its risk assessments to
support risk-based rulemakings under
CAA section 112 to date.
5. Acid Gas Risk
Comment: One commenter stated that
acid gas emissions from oil-fired EGUs
are not of the magnitude that triggered
EPA’s decision to regulate EGUs in
general, raising the question of whether
reduction (or even total elimination) of
acid gas emissions from oil-fired EGUs
could have any significant effect on
EPA’s goals of reducing non-cancer
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health risk or acidification of sensitive
ecosystems in the U.S.
Several commenters stated that acid
gas concentrations estimated in the case
study facility assessment and the Utility
Study do not exceed human health
thresholds of concern. Two commenters
stated that HCl emissions are negligible
compared to other primary emissions
(such as SO2) that can lead to potential
acidification of ecosystems.
Response: We do not agree with
commenter’s implication that Congress
intended EPA to regulate only those
HAP emissions from U.S. EGUs for
which an appropriate and necessary
finding is made, and commenter has
cited no provision of the statute that
states a contrary position. The EPA
concluded that we must find it
‘‘appropriate’’ to regulate EGUs under
CAA section 112 if we determine that a
single HAP emitted from EGUs poses a
hazard to public health or the
environment. If we also find that
regulation is necessary, the Agency is
authorized to list EGUs pursuant to
CAA section 112(c) because listing is
the logical first step in regulating source
categories that satisfy the statutory
criteria for listing under the statutory
framework of CAA section 112. See New
Jersey, 517 F.3d at 582 (stating that
‘‘[s]ection 112(n)(1) governs how the
Administrator decides whether to list
EGUs * * *’’). As we noted in the
preamble to the proposed rule, D.C.
Circuit precedent requires the Agency to
regulate all HAP from major sources of
HAP emissions once a source category
is added to the list of categories under
CAA section 112(c). National Lime
Ass’n v. EPA, 233 F.3d 625, 633 (D.C.
Cir. 2000). 76 FR 24989. The EPA
discusses in the preamble to the
proposed rule and this final action its
concerns with HCl and other acid gas
HAP emissions from EGUs and the
Agency’s approach for establishing
section 112(d) standards for acid gas
HAP.
6. EPRI Risk Analysis
Comment: Two commenters stated
that a comprehensive tiered inhalation
risk assessment (the EPRI study) using
EPA-prescribed methods with improved
emission factors, fuel data, and
confirmed stack parameters did not
identify significant health risks (cancer
or non-cancer) among U.S. coal-fired
power plants (as they existed in 2007).
The commenters noted that these results
contrast with those presented by EPA
for its non-Hg case studies on 16 (15
coal-fired) power plants. The
commenters stated that several issues
appear to underlie these differences,
indicating the need for EPA to
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reevaluate its assessment and to
undertake more refined (Tier 3) risk
assessment for any facility of concern.
Several commenters stated that for nonHg HAP EPA produced one study on
chronic inhalation risk assessment that
identified three sites with cancer risks
greater that one in a million for Cr(VI),
which was authored by EPA staff and
not peer reviewed. One commenter
stated that EPA study is based on
misinformation and overestimates
assumptions, and that EPA has no data
demonstrating health impacts from EGU
emissions of non-Hg HAP, or the benefit
from reducing such emissions. Two
commenters stated that no benefits will
be derived from the non-Hg HAP
emission reductions associated with the
proposed rule because no non-Hg HAP
health risks were proven, and that no
showing was made that EGU non-Hg
HAP emission levels reach levels
associated with adverse health effects.
Another commenter stated that EPA
must complete a comparable and
separate national-scale risk assessment
for non-Hg metals in order to determine
appropriateness of proposing emissions
standards for non-Hg metals.
Response: The commenters are
incorrect in the assertion that EPA’s
case studies were performed with less
rigor than the EPRI analysis. The EPRI
analysis used a tiered approach to risk
assessment, beginning with Tier 1 using
EPA’s SCREEN3 dispersion model on all
470 coal-fired power plants in the U.S.,
and following with Tier 2 with EPA’s
Human Exposure Model (which uses the
AERMOD dispersion model) for plants
with higher risks from the Tier 1
modeling. Although tiered risk
assessment is an appropriate approach,
the Tier 2 modeling could have been
more refined. For example, more
meteorological data could have been
used and building downwash could
have been considered. The EPRI
analysis ostensibly concluded that the
Tier 2 modeling with HEM was
conservative, and that because the
modeled risks did not exceed certain
thresholds, no further refinement was
necessary. However, such refinements
could result in higher modeled risks
than those from the commenter’s Tier 2
modeling.
The EPA’s dispersion modeling of the
case study facilities was actually
performed with a greater degree of
refinement than the EPRI analysis, and
was consistent with EPA’s Guideline on
Air Quality Models.295
In contrast to the approach used in
the EPRI analysis, the EPA used:
295 Appendix
PO 00000
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9361
(1) 5 years of recent meteorological data
from the weather station nearest to each
facility, rather than one year of
meteorological data. This is more
representative of long-term (i.e., lifetime)
exposures and risks.
(2) Temporally-varying emissions based on
continuous emissions monitoring data, rather
than assuming a constant emission rate for
each facility throughout the entire
simulation.
(3) Building downwash, where
appropriate.
(4) The latest version of AERMOD [version
11103].
The EPA’s assessment of the case
study facilities for the proposed rule
concluded that three coal-fired facilities
and one oil-fired facility had estimated
lifetime cancer risks greater than one in
a million. For the final rule, revisions
were made to the case studies based on
comments received, and the results
indicate that five coal-fired facilities and
one oil-fired facility had estimated
lifetime cancer risks greater than one in
a million.
Regarding peer review, the risk
assessment methodology used by EPA
for the case studies was consistent with
the method that EPA uses for
assessments performed for Risk and
Technology Review rulemakings, which
underwent peer review by the Science
Advisory Board in 2009.296 The SAB
issued its peer review report in May
2010. The report generally endorsed the
risk assessment methodologies used in
the program. In addition, in July 2011,
the EPA completed a letter peer review
of the methods used to develop
inhalation cancer risk estimates for Cr
and Ni compounds.
f. Ecosystem Impacts From HAP
Comment: Two commenters assert
that EPA is not justified in regulating
acid gases based on concern about the
potential that acid gases contribute to
ecosystem acidification rather than
concerns about hazards to public health.
The commenters further claim that
HCl’s contribution to ecosystem
acidification is de minimis. The
commenters point out that EPA
acknowledges uncertainty in
quantification of acidification and EPA
relies on recently published research 297
that is irrelevant to the question since it
is based on research conducted in the
peat bog ecosystem in the United
Kingdom. Another commenter calls
attention to several new studies
published in a special issue of the
296 U.S.
EPA–SAB, 2010.
Chris D., Don T. Monteith, David
Fowler, J. Neil Cape, and Susan Brayshaw. 2011.
‘‘Hydrochloric Acid: An Overlooked Driver of
Environmental Change.’’ Environmental Science &
Technology 45 (5), 1887–1894.
297 Evans,
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journal Ecotoxicology devoted to the
effects of MeHg on wildlife.
Response: Although EPA agrees that
quantification of acidification effects
has remaining uncertainty, the science
and methodology has progressed in
recent years. Based on recent peer
reviewed research including Evans et
al.,298 acid gases can significantly
contribute to acidification. The EPA
published a comprehensive risk
assessment of acidification effects of
nitrogen and sulfur deposition 299 and a
policy assessment.300 Given the extent
and importance of the sensitive
ecosystems evaluated in the review of
nitrogen and sulfur deposition any
substance that contributes to further
acidification must be considered to be
affecting the public welfare. The EPA
disagrees that the peer reviewed study
mentioned by commenter by Evans et
al., (2011) is not relevant to U.S.
ecosystems. The paper presents
evidence that show (1) that HCl is
highly mobile in the environment,
transferring acidity easily through soils
and water, (2) that HCl can transport
longer distances than previously
thought (given its presence in remote
ecosystems, and (3) that it can be a
larger driver of acidification than
previously thought. The fact that this
study took place in the U.K. is itself
irrelevant. The chemical interactions of
HCl in water are the same the world
over and sensitive ecosystems exist in
the U.S. as well as in Europe as
illustrated in the ecological risk
assessment 301 for NOX and SOX.
Furthermore, the commenter is factually
incorrect that EPA is justifying that it is
appropriate and necessary to regulate
HAP emissions from EGUs based on this
one study. The EPA agrees with the
commenter that Hg exposure in wildlife
is responsible for various adverse health
effects in many species across the U.S.
and recognizes that research is ongoing
in this area. As discussed in the
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298 Id.
299 U.S. Environmental Protection Agency (U.S.
EPA). 2009. Risk and Exposure Assessment for
Review of the Secondary National Ambient Air
Quality Standards for Oxides of Nitrogen and
Oxides of Sulfur (Final). EPA–452/R–09–008a.
Office of Air Quality Planning and Standards,
Research Triangle Park, NC. September. Available
on the Internet at https://www.epa.gov/ttn/naaqs/
standards/no2so2sec/data/NOxSOxREASep2009
MainContent.pdf.
300 U.S. Environmental Protection Agency (U.S.
EPA). 2011d. Policy Assessment for the Review of
the Secondary National Ambient Air Quality
Standards for Oxides of Nitrogen and Oxides of
Sulfur. EPA–452/R–11–005a. Office of Air Quality
Planning and Standards, Research Triangle Park,
NC. February. Available on the Internet at https://
www.epa.gov/ttnnaaqs/standards/no2so2sec/data/
20110204pamain.pdf.
301 U.S. EPA, 2009.
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preamble to the proposed rule, the EPA
agrees that there are potential
environmental risks from exposures of
ecosystems through Hg and non-Hg
HAP deposition. The EPA cited relevant
articles from the special edition of
Ecotoxicology 302 mentioned by the
commenter in the ecosystem effects
section on Chapter 5 of the RIA for this
rule, which is available in the docket.
G. EPA Affirms the Finding That It Is
Appropriate and Necessary to Regulate
EGUs To Address Public Health and
Environmental Hazards Associated
With Emissions of Hg and Non-Hg HAP
From EGUs
In response to peer reviews of both
the Hg and non-Hg HAP risk analyses,
and taking into account public
comments, the EPA conducted revised
analyses of the risks associated with
emissions of Hg and non-Hg HAP from
U.S. EGUs. These revised analyses
demonstrated that the risk results
reported in the preamble to the
proposed rule are robust to revisions in
response to the peer reviews and public
comments.
Specifically, the revised Hg Risk TSD
shows that up to 29 percent of modeled
watersheds have populations potentially
at-risk from exposure to Hg from U.S.
EGUs.303 This 29 percent of watersheds
with populations potentially at-risk
includes up to 10 percent of modeled
watersheds where deposition from U.S.
EGUs alone leads to potential exposures
that exceed the MeHg RfD, and up to 24
percent of modeled watersheds where
total potential exposures to MeHg
exceed the RfD and U.S. EGUs
contribute at least 5 percent to Hg
deposition. Each of these results
independently supports our conclusion
that U.S. EGUs pose hazards to public
health.
In the preamble to the proposed rule
and in the 2000 finding, the EPA
explained at length the serious nature of
the health effects associated with Hg
exposures, and the persistent nature of
Hg in the environment. Congress
specifically recognized the significant
impacts of persistent bioaccumulative
pollutants, like Hg, when it enacted
section 112(c)(6), which requires the
EPA to subject source categories listed
pursuant to that section to MACT
standards. Congress also required
certain studies be conducted under CAA
section 112(n) regarding the health
effects of Hg. The EPA interprets CAA
section 112(n)(1), with regard to Hg, as
302 Ecotoxicology
17:83–91, 2008.
corresponds to 28 percent of modeled
watersheds with populations potentially at-risk in
the analysis reported in the preamble to the
proposed rule.
303 This
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intended to protect the public,
including sensitive populations, against
exposures to Hg from EGUs that would
exceed the level determined by the EPA
to be without appreciable risk, e.g.,
exposures that are above the RfD for
methylmercury (MeHg), or would
contribute additional risk in areas where
Hg exposures exceed the RfD due to
contributions from all sources of Hg.
Our recent technical analyses show that
98 percent of the watersheds for which
we had fish tissue data have total Hg
deposition such that potential exposures
exceed the MeHg RfD, above which
there is an increased risk of adverse
effects on human health. In these
watersheds, any reductions in exposures
to Hg will reduce risk, and thus the
incremental contribution to Hg exposure
from any individual source or group of
sources, such as EGUs, may reasonably
be anticipated to cause additional risk.
As we have explained, in calculating
the estimates described above, the EPA
has used peer-reviewed methods, and
focused on populations likely to be at
higher risk of exposure to Hg from U.S.
EGUs, e.g., female subsistence fishing
populations consuming at the 99th
percentile fish consumption rate. The
EPA did not, however, use the most
conservative assumptions that would
lead to upper bound risk estimates. As
discussed above and in the revised Hg
Risk TSD, we did not use the highest
fish tissue cooking loss adjustment
factor that was reported in the literature,
which, had we done so, would have
increased the estimates of Hg exposure
substantially. Thus, we believe our
analysis could understate risk to the
most exposed individual, noting that we
have focused on the 99th percentile
consumption rate in our estimates.
Further, we were able to assess
potential Hg exposures in only a small
subset of generally representative
watersheds in the U.S. because our
analysis was necessarily premised on
those water bodies for which we had
fish tissue Hg samples. Specifically, we
analyzed 3,141 of the approximately
88,000 watersheds in the United States.
This limited set of watersheds excludes
several of the watersheds with the
highest U.S. EGU attributable
deposition, and may also not have
included watersheds with the highest
sensitivity to Hg deposition, e.g., the
highest methylation rates (see above).
Nevertheless, our analysis of the subset
of watersheds we examined
demonstrates that almost one third of
the watersheds are estimated to have Hg
deposition attributable to U.S. EGUs
that contributes to potential exposures
above the MeHg RfD. The SAB
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confirmed that the subset of watersheds
we examined is sufficient.
Considering these points and the
information on Hg in the record, the
EPA believes that 10 percent of
watersheds with populations at risk due
to U.S. EGU emissions alone is
unacceptable, as is 24 percent of
watersheds with populations at risk due
to U.S. EGU contributions in
conjunction with total deposition from
other sources. Taking into account the
percentage of watersheds at risk, and the
potential for even higher percentages to
be at risk using more conservative risk
assumptions and a more complete
coverage of high U.S. EGU Hg
deposition watersheds, the EPA
concludes that Hg emissions from U.S.
EGUs pose a hazard to public health.
Given these findings, and considering
that (1) the revised risk analysis showed
the percent of modeled watersheds with
populations potentially at-risk increased
from 28 to 29 percent, and (2) the
revised analysis includes 36 percent
more watersheds, which significantly
expands the coverage in several states,
we conclude that the finding that
emissions of Hg from U.S. EGUs pose a
hazard to public health is confirmed by
the national-scale revised Hg Risk TSD.
As a result, we conclude that it remains
appropriate to regulate Hg emissions
from U.S. EGUs because those Hg
emissions pose a hazard to public
health.
With regards to the revised non-Hg
inhalation case studies, the highest
estimated individual lifetime cancer risk
for the one case study facility (out of 16)
with oil-fired EGUs is estimated to be 20
in a million, driven by Ni emissions. For
the facilities with coal-fired EGUs, there
were five (out of 16) with maximum
individual cancer risks greater than one
in a million (the highest was five in a
million), four of which were driven by
emissions of Cr(VI), and one of which
was driven by emissions of Ni.
Therefore, a total of six facilities exceed
the criterion for EGUs to be regulated
under CAA section 112. There were also
two facilities with coal-fired EGUs with
maximum individual cancer risks at one
in a million. In the preamble to the
proposed rule, we reported that the
maximum individual lifetime cancer
risk for the one facility with oil-fired
EGUs was estimated to be 10 in a
million, and that there were 3 coal-fired
EGU facilities with maximum
individual cancer risks greater than 1 in
a million (the highest was 8 in a
million), and 1 coal-fired EGU facility
with maximum individual cancer risks
equal to 1 in a million. Given that (1)
the lifetime cancer risk for the oil-fired
EGU facility has increased from 10 to 20
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in a million, (2) the number of coal-fired
EGU facilities with cancer risks greater
than 1 in a million has increased from
3 to 5, and (3) the highest risk coal-fired
facility still has cancer risks of 5 in a
million, which is above the 1 in a
million benchmark, we conclude that
the finding that emissions of non-Hg
HAP from U.S. EGUs pose a hazard to
public health is confirmed by the
revised non-Hg risk inhalation case
studies.
Moreover, some HAP emissions from
U.S. EGUs contribute to adverse
ecosystem effects. While we did not do
new analyses on these topics, we
reiterate that (1) Hg emissions from U.S.
EGUs pose a hazard to the environment,
contributing to adverse impacts on fisheating birds and mammals, (2) Hg is a
persistent bioaccumulative
environmental contaminant, and as a
result, failing to control Hg emissions
from U.S. EGU sources will result in
long-term environmental loadings of Hg,
above and beyond those loadings caused
by immediate deposition of Hg within
the U.S.; controlling Hg emissions from
U.S. EGUs helps to reduce the potential
for environmental hazard from Hg now
and in the future, and (4) it is
appropriate to regulate those HAP
which are not known to cause cancer
but are known to contribute to chronic
non-cancer toxicity and environmental
degradation, such as the acid gases. In
addition, we have identified effective
controls available to reduce Hg and nonHg HAP emissions.
In summary, we confirm the findings
that Hg and non-Hg HAP emissions
from U.S. EGUs each pose hazards to
public health and that it remains
appropriate to regulate U.S. EGUs under
CAA section 112 for those reasons. We
also conclude that it remains
appropriate to regulate EGUs under
CAA section 112 because of the
magnitude of Hg and non-Hg emissions
and the environmental effects of Hg and
some non-Hg emissions, each of which
standing alone, supports the appropriate
finding. The availability of controls to
reduce HAP emissions from EGUs only
further supports the appropriate finding.
Our revised analyses still show that in
2016 after implementation of other
provisions of the CAA, HAP emissions
from U.S. EGUs are reasonably
anticipated to pose hazards to public
health; therefore, it is necessary to
regulate EGUs under CAA section 112.
Moreover, HAP emissions from U.S.
EGUs are expected to continue to
contribute to adverse ecosystem effects.
In addition, based on evaluation of the
regulations required by the CAA,
including the recent CSAPR, it is
necessary to regulate U.S. EGUs under
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9363
CAA section 112 because the only way
to ensure permanent reductions in HAP
emissions from U.S. EGUs and the
associated risks to public health and the
environment is through standards set
under CAA section 112. While CSAPR
is projected to achieve some Hg
reductions due to co-control of Hg
provided by controls put in place to
achieve required reductions in SO2
emissions, the results of the revised Hg
Risk TSD indicate that an unacceptable
percentage of modeled watersheds have
populations potentially at-risk from U.S.
EGU-attributable Hg deposition would
remain after implementation of CSAPR.
While we modeled slightly higher Hg
emissions from U.S. EGUs (i.e., 29 tons
of Hg) in our risk analysis compared to
the most recent estimate of 27 tons, we
do not believe this 2 ton difference
would substantially change our finding
that Hg emissions from U.S. EGUs pose
a hazard to public health or the Hg risks
reported in the preamble to the
proposed rule, as this represents less
than a 10 percent reduction in Hg
emissions. In addition, the actual
reductions in Hg that will occur due to
application of controls to meet the SO2
emissions requirements of CSAPR may
differ from those projected to occur, due
to differences in the technologies that
individual EGU sources choose to
install. The only way to ensure
reductions in Hg, including those
modeled as resulting from the CSAPR,
is to directly regulate Hg emissions
under CAA section 112.
In summary, we confirm the findings
that it is necessary to regulate HAP
emissions from U.S. EGUs because
(1) the national-scale Hg Risk TSD
shows that the hazards to public health
posed by Hg emissions from U.S. EGUs
will not be addressed through
imposition of the CAA, (2) we cannot be
certain that the identified cancer risks
attributable to U.S. EGUs will be
addressed through imposition of the
requirements of the CAA, (3) the
environmental hazards posed by
acidification will not be fully addressed
through imposition of the CAA, (4)
regulation under CAA section 112 is the
only way to ensure that all HAP
emissions reductions that have been
achieved since 2005 remain permanent,
and (5) direct control of Hg emissions
affecting U.S. deposition is only
possible through regulation of U.S.
emissions as we are unable to control
global emissions directly. All of these
findings independently support a
finding that it is necessary to regulate
U.S. EGUs under CAA section 112.
Based on these findings, the Agency
affirms its finding that it remains
appropriate and necessary to regulate
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coal- and oil-fired EGUs under CAA
section 112, and maintains that the
inclusion of coal- and oil-fired EGUs on
the CAA section 112(c) list of source
categories regulated under CAA section
112 remains valid.
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IV. Denial of Delisting Petition
During the comment period on the
proposed rule, UARG submitted a
petition pursuant to CAA section
112(c)(9), asking the Agency to delete a
portion of the EGU source category from
the list of source categories to be
regulated under CAA section 112.
Specifically, UARG asks that EPA delist
coal-fired EGUs from the CAA section
112(c) source category list. A copy of
UARG’s petition has been placed in the
docket for today’s rulemaking, along
with the analysis conducted by EPRI
that UARG uses to support its petition
(hereinafter referred to as UARG’s
analysis). In support of its petition,
UARG asserts that: (1) No coal-fired
EGU or group of coal-fired EGUs will
emit HAP in amounts that will cause a
lifetime cancer risk greater than one in
one million; and (2) no coal-fired EGU
or group of coal-fired EGUs will emit
non-carcinogenic HAP in amounts that
will exceed a level which is adequate to
protect public health with an ample
margin of safety or cause adverse
environmental effects. We disagree with
UARG’s assertions and for the reasons
set forth below are denying UARG’s
petition to delist coal-fired EGUs from
the section 112(c) source category list.
A. Requirements of CAA Section
112(c)(9)
CAA section 112(c)(9)(B) provides
that ‘‘[t]he Administrator may delete
any source category’’ from the section
112(c) source category list if the Agency
determines that: (i) For HAP that may
cause cancer in humans, ‘‘no source in
the category (or group of sources in the
case of area sources) emits such
hazardous air pollutants in quantities
which may cause a lifetime risk of
cancer greater than one in one million
to the individual in the population who
is most exposed to emissions of such
pollutants from the source (or group of
sources in the case of area sources)’’;
and (ii) for HAP that may result in
human health effects other than cancer
or adverse environmental effects, ‘‘a
determination that emissions from no
source in the category or subcategory
concerned (or group of sources in the
case of area sources) exceed a level
which is adequate to protect public
health with an ample margin of safety
and no adverse environmental effect
will result from emissions from any
source.’’
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The EPA has the discretion to delete
a source category under CAA section
112(c)(9)(B), but only if EPA concludes
that the relevant requirements of CAA
section 112(c)(9)(B) have been met. HAP
emissions from EGUs present both
cancer risks, which implicate the
requirements of CAA section
112(c)(9)(B)(i), and non-cancer human
health effects or adverse environmental
effects, which implicate the
requirements of CAA section
112(c)(9)(B)(ii). As such, UARG bears
the burden of demonstrating that the
requirements of both clauses are met.
B. Rationale for Denying UARG’s
Delisting Petition
The EPA is denying UARG’s petition
to delist EGUs from the CAA section
112(c) source category list. UARG
improperly seeks to delist a portion of
a CAA section 112(c) listed source
category that emits carcinogens, which
is contrary to the plain language of CAA
section 112(c)(9). Even setting aside this
fundamental defect, UARG has failed to
meet the requirements of CAA section
112(c)(9)(B).
1. UARG’s Attempt to Delist a Portion
of a Listed Source Category Conflicts
With D.C. Circuit Precedent
In December 2000, the EPA listed
coal- and oil-fired EGUs as a single
source category. UARG asks the Agency
to delist a portion of that listed source
category: Coal-fired EGUs. UARG’s
request conflicts, however, with D.C.
Circuit precedent, which provides that
for categories, like EGUs, that pose
cancer risks, the EPA may not delist a
portion of a source category. NRDC v.
U.S. EPA, 489 F.3d 1364 (D.C. Cir.
2007). Specifically, in NRDC, the D.C.
Circuit held that the Agency’s attempt to
delist a ‘‘low-risk’’ subcategory was
‘‘contrary to the plain language of the
statute,’’ and that the statute only
authorized the agency to remove source
categories pursuant to section 112(c)(9).
Id. at 1373 (‘‘Because EPA’s
interpretation of Section 112(c)(9) as
allowing it to exempt the risk-based
subcategory is contrary to the plain
language of the statute, the EPA’s
interpretation fails at Chevron step
one.’’).
UARG’s request is indistinguishable
from the situation before the court in
NRDC. UARG does not seek to delist
coal- and oil-fired EGUs, which is the
source category that EPA listed, but
rather a portion of that category. UARG
also does not dispute that coal-fired
EGUs emit carcinogenic HAP. Because
UARG’s request to delist is contrary to
the plain language of CAA section
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112(c)(9)(B) and NRDC, we are denying
the delisting petition.
2. Even Assuming, for the Sake of
Argument, That EPA Could Delist a
Portion of a Source Category, UARG has
Failed to Meet the Requirements of CAA
Section 112(c)(9)
Even assuming, for the sake of
argument, that EPA could delist a
portion of a source category that emits
carcinogens, which it cannot, UARG has
failed to demonstrate that the
requirements for delisting in CAA
section 112(c)(9)(i) and (ii) have been
met. UARG contends that it used EPA’s
models and approaches, as well as the
most recent data. We have carefully
reviewed UARG’s analyses, however,
and found certain flaws that we believe
bias their risk results low. Specifically,
we identified flaws in emissions
estimation. UARG developed estimates
for all EGU facilities using data which
pre-date the 2010 ICR emissions
measurement data that EPA obtained to
support this rule. UARG also relied
upon an emissions equation developed
by EPRI and DOE to develop its metal
emissions estimates. With regard to that
approach, the EPA analysis of the ICR
data has found that the regression
approach is not a good predictor of
actual EGU emissions. Furthermore, we
found fault with their use of the
geometric mean and their outlier
analysis for computing emission factors.
The EPA analysis has found that the
geometric mean approach underpredicts
actual emissions by an average of more
than seventy percent. This had an
especially large impact on the arsenic,
chromium, and nickel emissions
estimates. These and other issues are
explained in further detail in the
response to comments document. As a
result, we believe the resulting risk
estimates in UARG’s analysis are biased
low. In addition, we note that there are
dispersion model refinements that are
not included in the UARG analyses, but
were included in EPA’s analysis. For
example, for the dispersion modeling of
the 16 non-Hg case studies, the EPA
considered building downwash and
used time-varying emissions, neither of
which were used in UARG’s analysis.
These factors could also bias the UARG
risk estimates low.
However, even taking UARG’s
analysis at face value and accepting, for
arguments’ sake, their assumptions and
emissions estimates, UARG’s own data
supports denial of the petition because
UARG itself identifies a maximum
individual cancer risk exceeding 1 in a
million, which is the statutory threshold
in CAA section 112(c)(9)(B)(i).
Specifically, UARG’s multi-pathway
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model plant ingestion risk analysis
concluded that adult anglers would face
cancer risks of 4 in a million. For this
reason alone, the petition should be
denied.
UARG dismisses the 4 in a million
cancer result, arguing that the refined
model plant multipathway risk
assessment that it conducted is ‘‘overly
conservative.’’ UARG conducted its
multi-pathway risk analysis to evaluate
the risks associated with ingesting
persistent and bioaccumulative HAP
which are emitted into the atmosphere
and subsequently deposit into the
environment and bioaccumulate in
animals which are eventually consumed
as food. Instead of conducting this
multipathway analysis for each EGU
facility, UARG instead analyzed multipathway risks by evaluating a single
model plant. Nothing in the record
indicates, however, that UARG’s model
plant represents the worst-case scenario
for cancer human health risks from any
EGU. Indeed, although UARG claims in
its petition that the site selected for its
case study is ‘‘likely as close to a worstcase scenario as is possible given the
numerous variables associated with
ingestion pathway risks’’ (UARG
petition at 12), the supporting
documentation for that case study
specifically acknowledges that its
fictional model plant scenario ‘‘is not
intended to represent the risk due to
emissions from an actual plant or the
highest level of risk that could be
associated with a coal-fired power plant
at any location’’ (EPRI at 1). The statute
requires that no source in the category
may cause a lifetime cancer risk greater
than one in one million to the most
exposed individual, and UARG has
failed to make this showing. UARG has
neither modeled multi-pathway risks for
a worst-case model facility, nor
evaluated the multipathway risks
associated with each individual EGU
facility. Accordingly, UARG has not
made the demonstration required by
CAA section 112(c)(9)(B)(i). But, even
focusing on the multi-pathway risk
analysis that UARG did conduct, which
admittedly does not represent a worstcase facility, UARG’s analysis still
shows cancer risks greater than one in
a million. Accordingly, UARG’s petition
must be denied.
Although it is not necessary to reach
the requirements of CAA section
112(c)(9)(B)(ii) that address non-cancer
human health risks, we note that UARG
has also failed to show that ‘‘emissions
from no source in the category * * *
exceed a level which is adequate to
protect public health with an ample
margin of safety.’’ Again, even
accepting, for argument’s sake, the
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conclusions in UARG’s analysis, UARG
only evaluated the non-cancer
inhalation risks associated with each
EGU facility. It did not conduct a
similar analysis to assess multipathway
risks for each EGU facility. Instead, it
conducted a model plant analysis and
admits that such model plant does not
represent the worst-case scenario for
noncancer human health risks from any
EGU. Thus, the analysis fails to fully
characterize noncancer multipathway
risks for the source category, and
UARG’s petition must be denied on this
basis as well.
Finally, UARG failed to meet its
burden of showing that ‘‘no adverse
environmental effect will result from
emissions from any source’’ pursuant to
CAA section 112(c)(9)(B)(ii). UARG
analyzed environmental effects only in
conjunction with its model plant.
Because UARG’s model plant does not
represent the worst-case scenario for
environmental effects, UARG’s analysis
falls short and fails to characterize fully
the potential environmental impacts,
and UARG’s petition must be denied.
For all of these reasons, the EPA
denies UARG’s petition to delist coalfired EGUs from the CAA section 112(c)
source category list.
C. EPA’s Technical Analyses for the
Appropriate and Necessary Finding
Provide Further Support for the
Conclusion That Coal-Fired EGUs
Should Remain a Listed Source
Category
The EPA reasonably concluded in
December 2000, based on the
information available to the Agency at
that time, that it was appropriate and
necessary to regulate coal- and oil-fired
EGUs under CAA section 112 and added
such units to the list of source categories
subject to regulation under CAA section
112(d). As discussed in section III
above, the EPA conducted additional,
extensive technical analyses based on
recent data that confirm it remains
appropriate and necessary to regulate
HAP from coal- and oil-fired EGUs,
because such EGUs continue to pose
hazards to public health. HAP emissions
from coal- and oil-fired EGUs also
continue to cause adverse
environmental effects. UARG advances
several arguments, challenging the
analyses the Agency completed in
support of the proposed rule. We
address those arguments in section III
above. The Agency’s analyses
supporting the appropriate and
necessary finding confirm that EGUs
cannot be delisted pursuant to CAA
section 112(c)(9).
Specifically, as explained further in
section III above, the EPA analyzed non-
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Hg inhalation risks from 16 EGU facility
case studies, including both coal- and
oil-fired EGUs, as part of its technical
analyses supporting the appropriate and
necessary finding. That analysis
demonstrates that there are 6 EGU
facilities (of the 16 that we analyzed)
with cancer risks exceeding one in one
million. These cancer risk levels exceed
the delisting criteria set forth in CAA
section 112(c)(9)(B)(i), and confirm that
EGUs must remain a listed source
category. As explained above, some
commenters assert that EPA’s analysis
of non-Hg inhalation risks from EGUs
conducted in support of the proposal for
this rulemaking overstated emissions
from, and risks associated with, EGUs.
These commenters argue that the
analysis supporting UARG’s petition
more appropriately assesses EGU risk.
The EPA disagrees with these comments
and addresses these comments in
section III above.
Significantly, the EPA based its
analysis of 16 case study EGUs directly
on the 2010 emissions test data from
EGUs obtained through the ICR. The
EPA’s 16 case study analysis used
emissions data either taken directly
from the 2010 emissions test data, or
derived using emissions factors based
on the 2010 data for similar EGU units.
The EPA also included dispersion
model refinements in its final case
studies, as noted above. Further, the
EPA re-analyzed the 16 case studies that
we conducted for the proposal and
revised those analyses consistent with
new non-Hg HAP emissions data and
corrected stack parameters provided by
commenters (including UARG) during
the comment period on the proposed
rule. The EPA received revised
information concerning emissions tests,
stack heights and stack diameters for
some of the case study EGU facilities.
The EPA incorporated all of these
corrections into our analysis and then
re-analyzed the risks for the 16 case
study facilities. When completed, the
EPA determined that the corrections
incorporated into the reanalysis had
little effect on the overall results. In the
final rule, the EPA concludes that the
maximum individual inhalation cancer
risks for 6 out of the 16 case study EGU
facilities are greater than 1 in a million.
These cancer risk levels confirm that
EGUs do not satisfy the delisting
criterion of CAA section 112(c)(9)(B)(i)
and thus should remain a listed source
category.
The EPA’s national-scale Hg Risk TSD
supporting the appropriate and
necessary finding also confirm that Hg
emissions from coal- and oil-fired US
EGUs are reasonably anticipated to pose
a hazard to public health. As discussed
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in section III above, the EPA interprets
CAA section 112(n)(1), with regard to
mercury, as intended to protect the
public, including sensitive populations,
against exposures to Hg from EGUs that
would exceed the level determined by
EPA to be without appreciable risk, e.g.,
exposures that are above the RfD for
methylmercury (MeHg), or would
contribute additional risk in areas where
Hg exposures exceed the RfD due to
contributions from all sources of Hg.
In order to determine whether EGU
Hg emissions pose a hazard to public
health, the EPA conducted a nationalscale Hg Risk TSD focused on
populations with high levels of selfcaught freshwater fish consumption.
The results of the Hg Risk TSD show
that 98 percent of modeled watersheds
have total exposures to MeHg that
exceed the MeHg RfD, above which
there is an increased risk of adverse
effects on human health. In these
watersheds, any reductions in exposures
to Hg will reduce risk, and thus the
incremental contribution to Hg exposure
from any individual source or group of
sources, such as EGUs, may reasonably
be anticipated to cause additional risk.
The Hg Risk TSD focused on those
watersheds that either exceeded the RfD
based on U.S. EGU attributable
deposition alone, without considering
other sources of deposition, or
watersheds that exceed the RfD due to
total Hg deposition and to which U.S.
EGUs contributed at least 5 percent of
the Hg deposition. The results of that
analysis show that up to 29 percent of
the modeled watersheds have
populations that are potentially at-risk
from exposure to Hg from U.S. EGUs,
including up to 10 percent of modeled
watersheds where deposition from U.S.
EGUs alone leads to potential exposures
that exceed the MeHg RfD, and up to 24
percent of modeled watersheds where
total potential exposures to MeHg
exceed the RfD and U.S. EGUs
contribute at least 5 percent to Hg
deposition. This approach to assessing
national risks from Hg deposition from
EGUs was supported by the
independent peer review conducted by
the Science Advisory Board, as
discussed fully in section III.
Finally, as discussed in section III,
based on this assessment, the EPA has
confirmed that Hg emitted from U.S.
EGUs pose a hazard to public health and
it is appropriate to regulate U.S. EGUs
under CAA section 112. This
determination and the confirmatory
assessments support our conclusion that
UARG’s delisting petition must be
denied.
UARG attempts to dismiss the results
of EPA’s national-scale Hg Risk TSD,
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arguing that EPA cannot consider the
risks posed by EGUs in conjunction
with any other risks, including those
from other source categories. Nothing in
CAA section 112(c)(9), however,
provides that the Agency cannot
consider background or emissions due
to other sources. CAA section
112(c)(9)(B)(ii) provides that ‘‘no source
in the category or subcategory
concerned (or group of sources in the
case of area sources) exceed a level
which is adequate to protect public
health with an ample margin of safety
and no adverse environmental effect
will result from emissions from any
source.’’ This language could be read to
provide that the Agency consider only
the risks associated with the source
category at issue, and ignore how those
risks fit with real-world exposures.304
However, the language could also be
read to provide that the Agency
consider the cumulative effect of HAP
emissions from the individual sources
in the category in conjunction with the
HAP emissions from other sources. The
latter is a reasonable interpretation,
especially when considering how the
public is exposed to HAP emissions.
Considering the individual sources in a
source category in isolation treats the
sources as if they exist in a vacuum,
which does not mirror reality. Such an
approach is particularly problematic for
environmentally persistent HAP that
bio-accumulate in the food chain, such
as mercury.305
Here, the record demonstrates that 98
percent of the watersheds EPA modeled
have total exposures to MeHg that
exceed the MeHg RfD, above which
there is increased risk of adverse effects
on human health, especially on the
304 The same is true with respect to section
112(c)(9)(B)(i).
305 In a prior rulemaking, EPA stated that the
language in section 112(c)(9)(B)(ii) ‘‘does not direct
EPA to extend its analysis to either emissions from
other sources in other categories or subcategories or
to non-attributable background concentrations.’’ 71
FR 8347 (Feb. 16, 2006). The preamble to that rule
repeatedly states that the ‘‘focus’’ of the delisting
determination in that rule was on emissions from
sources in the category under review. See 71 FR
8346–47. The preamble went on to compare section
112(c)(9)(B) to section 112(f)(2)(A) in a way that
suggested that EPA can consider risks presented by
sources other than the subject source category
under section 112(f)(2), but not under section
112(c)(9). We do not believe the language of section
112(c)(9) compels any different treatment. The
section 112(f) analysis occurs after a source category
has already complied with section 112(d) standards,
whereas, potential delistings under section
112(c)(9) may involve source categories unregulated
by section 112. A delisting decision is significant
in that the category that is delisted will no longer
be subject to HAP regulation under the Act. It is
difficult to justify why we would examine risks
from other sources under section 112(f), but not
under section 112(c)(9), where Congress established
such a specific test for delisting.
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developing nervous systems of children
during gestation. EGUs remain one of
the largest unregulated sources of Hg
emissions, and those emissions
continue to contribute to Hg exposures
and risk. UARG seeks to ignore the fact
that exposures above the RfD exist in
almost every watershed we modeled,
and instead focuses on the contribution
provided solely by EGUs. The EPA did
as UARG asked and found that up to 10
percent of modeled watersheds where
deposition from U.S. EGUs alone leads
to potential exposures that exceed the
MeHg RfD. Thus, even focusing on EGU
emissions in a vacuum, which we do
not believe is appropriate or required
under CAA section 112(c)(9), we still
found that up to 10 percent of the
watersheds exceed the RfD due to EGU
emissions even before taking into
account the numerous other sources of
Hg deposition, and we believe this to be
an unacceptable percentage of
watersheds above the RfD. Due to the
persistent, bioacccumulative nature of
Hg, among other factors, we believe it is
appropriate to consider the combined
impact of Hg emissions from EGUs and
other sources of Hg. Thus, we also
considered the 24 percent of modeled
watersheds where, even though U.S.
EGU emissions alone are not enough to
cause exposures that exceed the RfD,
those emissions contribute at least 5
percent of total exposures to MeHg that
exceed the RfD. The combined total of
29 percent of modeled watersheds
where U.S. EGUs cause or contribute to
MeHg exposures above the RfD is
clearly unacceptable and thus the UARG
petition to delist must be denied.
Thus, the technical analyses the
Agency conducted in support of the
appropriate and necessary finding
confirm that EGUs should remain a
listed source category.
V. Summary of This Final NESHAP
This section summarizes the
requirements of the final EGU NESHAP.
Section VI below summarizes the
significant changes to this final rule
following proposal.
A. What is the source category regulated
by this final rule?
This final rule affects coal- and oilfired EGUs.
B. What is the affected source?
An existing affected source under this
final rule is the collection of coal- or oilfired EGUs in a subcategory within a
single contiguous area and under
common control. A new affected source
is each coal- or oil-fired EGU for which
construction or reconstruction began
after May 3, 2011.
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CAA section 112(a)(8) defines an EGU as:
a fossil fuel-fired combustion unit of more
than 25 megawatts that serves a generator
that produces electricity for sale. A unit that
cogenerates steam and electricity and
supplies more than one-third of its potential
electric output capacity and more than 25
megawatts electrical output to any utility
power distribution system for sale shall be
considered an electric utility steam
generating unit.
If an EGU burns coal (either as a
primary fuel or as a supplementary fuel)
or any combination of coal with another
fuel (except for solid waste as noted
below) where the coal accounts for more
than 10.0 percent of the average annual
heat input during any 3 consecutive
calendar years or for more than 15.0
percent of the annual heat input during
any one calendar year after the
applicable compliance date, the unit is
considered to be coal-fired under this
final rule.
If a unit is not a coal-fired unit and
burns only oil or burns oil in
combination with a fuel other than coal
(except solid waste as noted below)
where the oil accounts for more than
10.0 percent of the average annual heat
input during any 3 consecutive calendar
years or for more than 15.0 percent of
the annual heat input during any one
calendar year after the applicable
compliance date, the unit is considered
to be oil-fired under this final rule.
As noted below, the EPA is finalizing
in this rule a definition to determine
whether the combustion unit is ‘‘fossil
fuel fired’’ such that it is considered an
EGU as defined in CAA section
112(a)(8) and, thus, potentially subject
to this final rule. In addition, using the
construct of the definition of ‘‘oil-fired’’
from the ARP, we are finalizing in this
rule a requirement that the unit fire coal
or oil (or natural gas), or any
combination thereof, for more than 10.0
percent of the average annual heat input
during any 3 consecutive calendar years
or for more than 15.0 percent of the
annual heat input during any one
calendar year to be considered a ‘‘fossil
fuel-fired’’ EGU as defined in CAA
section 112(a)(8). However, if a new or
existing EGU is not coal- or oil-fired,
and the unit burns natural gas
exclusively or burns natural gas in
combination with another fuel where
the natural gas constitutes 10 percent or
more of the average annual heat input
during any 3 calendar years or 15
percent or more of the annual heat input
during any 1 calendar year, the unit is
considered to be natural gas-fired EGU
and not subject to this final rule. As
discussed later, we believe that this
definition will address those situations
where an EGU co-fires limited amounts
of either coal or oil with natural gas or
other non-fossil fuels (e.g., biomass).
If an EGU combusts solid waste,
standards issued pursuant to CAA
section 129 apply to that EGU, rather
than this final rule.
C. What are the pollutants regulated by
this final rule?
For coal-fired EGUs, this final rule
regulates HCl as a surrogate for acid gas
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HAP, with an alternate of SO2 as a
surrogate for acid gas HAP for coal-fired
EGUs with FGD systems installed and
operational; filterable PM as a surrogate
for non-mercury HAP metals, with total
non-mercury HAP metals and
individual non-mercury HAP metals as
alternative equivalent standards; Hg;
and organic HAP. For oil-fired EGUs,
this final rule regulates HCl and HF;
filterable PM as a surrogate for total
HAP metals, with individual HAP
metals as alternative equivalent
standards; and organic HAP.
D. What emission limits and work
practice standards must I meet and
what are the subcategories in the final
rule?
We are finalizing the emission
limitations presented in Tables 3 and 4
of this preamble. Within the two major
subcategories of ‘‘coal’’ and ‘‘oil,’’
emission limitations were developed for
new and existing sources for seven
subcategories, two for coal-fired EGUs,
one for IGCC EGUs burning synthetic
gas derived from coal- and/or solid oilderived fuel, one for solid oil-derived
fuel-fired EGUs, and four for liquid oilfired EGUs, as described in more detail
below. The limited-use liquid oil-fired
subcategory, discussed elsewhere in this
preamble, is not presented in Table 3
because only work practice standards
apply to this subcategory.
TABLE 3—EMISSION LIMITATIONS FOR COAL-FIRED AND SOLID OIL-DERIVED FUEL-FIRED EGUS
Subcategory
Filterable particulate matter
Hydrogen
chloride
Mercury
Existing—Unit not low rank virgin coal ...............................................................................
3.0E–2 lb/
MMBtu.
(3.0E–1 lb/MWh)
3.0E–2 lb/
MMBtu.
(3.0E–1 lb/MWh)
2.0E–3 lb/
MMBtu.
(2.0E–2 lb/MWh)
2.0E–3 lb/
MMBtu.
(2.0E–2 lb/MWh)
4.0E–2 lb/
MMBtu.
(4.0E–1 lb/MWh)
8.0E–3 lb/
MMBtu.
(9.0E–2 lb/MWh)
7.0E–3 lb/MWh
7.0E–3 lb/MWh
7.0E–2 lb/MWh b
9.0E–2 lb/MWh c
2.0E–2 lb/MWh
5.0E–4 lb/
MMBtu.
(5.0E–3 lb/MWh)
5.0E–3 lb/
MMBtu.
(8.0E–2 lb/MWh)
4.0E–4 lb/MWh
4.0E–4 lb/MWh
2.0E–3 lb/MWh d
1.2E0 lb/TBtu.
(1.3E–2 lb/
GWh).
1.1E+1 lb/TBtu.
(1.2E–1 lb/
GWh).
4.0E0 lb/TBtu a.
(4.0E–2 lb/
GWh a).
2.5E0 lb/TBtu.
(3.0E–2 lb/
GWh).
2.0E–1 lb/TBtu.
(2.0E–3 lb/
GWh).
2.0E–4 lb/GWh.
4.0E–2 lb/GWh.
3.0E–3 lb/
GWh e.
2.0E–3 lb/GWh.
Existing—Unit designed low rank virgin coal .....................................................................
Existing—IGCC ...................................................................................................................
srobinson on DSK4SPTVN1PROD with RULES2
Existing—Solid oil-derived ..................................................................................................
New—Unit not low rank virgin coal ....................................................................................
New—Unit designed for low rank virgin coal .....................................................................
New—IGCC ........................................................................................................................
New—Solid oil-derived .......................................................................................................
4.0E–4 lb/MWh
Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input.
lb/TBtu = pounds pollutant per trillion British thermal units fuel input.
lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
a Beyond-the-floor limit as discussed elsewhere.
b Duct burners on syngas; based on permit levels in comments received.
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burners on natural gas; based on permit levels in comments received.
on best-performing similar source.
on permit levels in comments received.
d Based
e Based
TABLE 4—EMISSION LIMITATIONS FOR LIQUID OIL-FIRED EGUS
Subcategory
Filterable particulate
matter
Hydrogen
chloride
Existing—Liquid oil—continental ........................................................................
3.0E–2 lb/MMBtu ...
(3.0E–1 lb/MWh) ....
3.0E–2 lb/MMBtu ...
(3.0E–1 lb/MWh) ....
7.0E–2 lb/MWh ......
2.0E–1 lb/MWh ......
2.0E–3 lb/MMBtu ...
(1.0E–2 lb/MWh) ....
2.0E–4 lb/MMBtu ...
(2.0E–3 lb/MWh) ....
4.0E–4 lb/MWh ......
2.0E–3 lb/MWh ......
Existing—Liquid oil—non-continental .................................................................
New—Liquid oil—continental ..............................................................................
New—Liquid oil—non-continental .......................................................................
We are also finalizing alternate
equivalent emission standards (for
certain subcategories) to the final
surrogate standards in three areas: SO2
(for HCl), individual non-mercury
metals and total non-mercury metals
(for filterable PM) from coal- and solid
oil-derived fuel-fired EGUs, and
individual and total metals (for
filterable PM) from oil-fired EGUs. The
Hydrogen
fluoride
4.0E–4 lb/MMBtu.
(4.0E–3 lb/MWh).
6.0E–5 lb/MMBtu.
(5.0E–4 lb/MWh).
4.0E–4 lb/MWh.
5.0E–4 lb/MWh.
final alternate emission limitations are
provided in Tables 5 and 6 of this
preamble.
TABLE 5—ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND OIL-FIRED EGUS
Subcategory/Pollutant
Coal-fired EGUs
IGCC
Liquid oil, continental
Liquid oil, non-continental
SO2 .............................................
2.0E–1 lb/MMBtu ...
(1.5E0 lb/MWh) ......
5.0E–5 lb/MMBtu ...
(5.0E–1 lb/GWh) ....
8.0E–1 lb/TBtu .......
(8.0E–3 lb/GWh) ....
1.1E0 lb/TBtu .........
(2.0E–2 lb/GWh) ....
2.0E–1 lb/TBtu .......
(2.0E–3 lb/GWh) ....
3.0E–1 lb/TBtu .......
(3.0E–3 lb/GWh) ....
2.8E0 lb/TBtu .........
(3.0E–2 lb/GWh) ....
8.0E–1 lb/TBtu .......
(8.0E–3 lb/GWh) ....
1.2E0 lb/TBtu .........
(2.0E–2 lb/GWh) ....
4.0E0 lb/TBtu .........
(5.0E–2 lb/GWh .....
NA ..........................
NA ..........................
NA ..........................
NA ..........................
6.0E–5 lb/MMBtu ...
(5.0E–1 lb/GWh) ....
1.4E0 lb/TBtu .........
(2.0E–2 lb/GWh) ....
1.5E0 lb/TBtu .........
(2.0E–2 lb/GWh) ....
1.0E–1 lb/TBtu .......
(1.0E–3 lb/GWh) ....
1.5E–1 lb/TBtu .......
(2.0E–3 lb/GWh) ....
2.9E0 lb/TBtu .........
(3.0E–2 lb/GWh) ....
1.2E0 lb/TBtu .........
(2.0E–2 lb/GWh) ....
1.9E+2 lb/MMBtu ...
(1.8E0 lb/MWh) ......
2.5E0 lb/TBtu .........
(3.0E–2 lb/GWh) ....
NA ..........................
3.5E0 lb/TBtu .........
(4.0E–2 lb/GWh) ....
5.0E0 lb/TBtu .........
(6.0E–2 lb/GWh) ....
6.5E0 lb/TBtu .........
(7.0E–2 lb/GWh) ....
2.2E+1 lb/TBtu .......
(3.0E–1 lb/GWh) ....
8.0E–4 lb/MMBtu ...
(8.0E–3 lb/MWh) a ..
1.3E+1 lb/TBtu .......
(2.0E–1 lb/GWh) ....
2.8E0 lb/TBtu .........
(3.0E–2 lb/GWh) ....
2.0E–1 lb/TBtu .......
(2.0E–3 lb/GWh) ....
3.0E–1 lb/TBtu .......
2.0E–3 lb/GWh) .....
5.5E0 lb/TBtu .........
(6.0E–2 lb/GWh) ....
2.1E+1 lb/TBtu .......
(3.0E–1 lb/GWh) ....
8.1E0 lb/TBtu .........
(8.0E–2 lb/GWh) ....
2.2E+1 lb/TBtu .......
(3.0E–1 lb/GWh) ....
2.0E–1 lb/TBtu .......
(2.0E–3 lb/GWh) ....
1.1E+2 lb/TBtu .......
(1.1E0 lb/GWh) ......
3.3E0 lb/TBtu .........
(4.0E–2 lb/GWh) ....
6.0E–4 lb/MMBtu ...
(7.0E–3 lb.MWh) a ..
2.2E0 lb/TBtu .........
(2.0E–2 lb/GWh) ....
4.3E0 lb/TBtu .........
(8.0E–2 lb/GWh) ....
6.0E–1 lb/TBtu .......
(3.0E–3 lb/GWh) ....
3.0E–1 lb/TBtu .......
(3.0E–3 lb/GWh) ....
3.1E+1 lb/TBtu .......
(3.0E–1 lb/GWh) ....
1.1E+2 lb/TBtu .......
(1.4E0 lb/GWh) ......
4.9E0 lb/TBtu .........
(8.0E–2 lb/GWh) ....
2.0E+1 lb/TBtu .......
(3.0E–1 lb/GWh) ....
4.0E–2 lb/TBtu
(4.0E–4 lb/GWh).
4.7E+2 lb/TBtu .......
(4.1E0 lb/GWh) ......
9.8E0 lb/TBtu .........
(2.0E–1 lb/GWh) ....
Total non-mercury metals ..........
Antimony, Sb ..............................
Arsenic, As .................................
Beryllium, Be ..............................
Cadmium, Cd .............................
Chromium, Cr .............................
Cobalt, Co ..................................
Lead, Pb .....................................
Manganese, Mn .........................
Mercury, Hg ...............................
Nickel, Ni ....................................
Selenium, Se ..............................
Solid oilderived
3.0E–1 lb/MMBtu.
(2.0E0 lb/MWh).
4.0E–5 lb/MMBtu.
(6.0E–1 lb/GWh).
8.0E–1 lb/TBtu.
(8.0E–3 lb/GWh).
3.0E–1 lb/TBtu.
(5.0E–3 lb/GWh).
6.0E–2 lb/TBtu.
(6.0E–4 lb/GWh).
3.0E–1 lb/TBtu.
(4.0E–3 lb/GWh).
8.0E–1 lb/TBtu.
(2.0E–2 lb/GWh).
1.1E0 lb/TBtu.
(2.0E–2 lb/GWh).
8.0E–1 lb/TBtu.
(2.0E–2 lb/GWh).
2.3E0 lb/TBtu.
(4.0E–2 lb/GWh).
NA.
9.0E0 lb/TBtu.
(2.0E–1 lb/GWh).
1.2E0 lb/TBtu.
(2.0E–2 lb/GWh).
NA = Not applicable.
a Includes Hg.
TABLE 6—ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS
srobinson on DSK4SPTVN1PROD with RULES2
Subcategory/Pollutant
Coal-fired EGUs
IGCC a
Liquid oil,
continental,
lb/GWh
Liquid oil,
non-continental,
lb/GWh
SO2 .............................................
Total non-mercury metals ..........
Antimony, Sb ..............................
Arsenic, As .................................
Beryllium, Be ..............................
Cadmium, Cd .............................
Chromium, Cr .............................
Cobalt, Co ..................................
Lead, Pb .....................................
Mercury, Hg ...............................
Manganese, Mn .........................
4.0E–1 lb/MWh ......
6.0E–2 lb/GWh ......
8.0E–3 lb/GWh ......
3.0E–3 lb/GWh ......
6.0E–4 lb/GWh ......
4.0E–4 lb/GWh ......
7.0E–3 lb/GWh ......
2.0E–3 lb/GWh ......
2.0E–3 lb/GWh ......
NA ..........................
4.0E–3 lb/GWh ......
4.0E–1 lb/MWh ......
4.0E–1 lb/GWh ......
2.0E–2 lb/GWh ......
2.0E–2 lb/GWh ......
1.0E–3 lb/GWh ......
2.0E–3 lb/GWh ......
4.0E–2 lb/GWh ......
4.0E–3 lb/GWh ......
9.0E–3 lb/GWh ......
NA ..........................
2.0E–2 lb/GWh ......
NA ..........................
2.0E–4 lb/MWh b ....
1.0E–2 ...................
3.0E–3 ...................
5.0E–4 ...................
2.0E–4 ...................
2.0E–2 ...................
3.0E–2 ...................
8.0E–3 ...................
1.0E–4 ...................
2.0E–2 ...................
NA ..........................
7.0E–3 lb/MWh b ....
8.0E–3 ...................
6.0E–2 ...................
2.0E–3 ...................
2.0E–3 ...................
2.0E–2 ...................
3.0E–1 ...................
3.0E–2 ...................
4.0E–4 ...................
1.0E–1 ...................
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Solid
oilderived
4.0E–1
6.0E–1
8.0E–3
3.0E–3
6.0E–4
7.0E–4
6.0E–3
2.0E–3
2.0E–2
2.0E–3
7.0E–3
lb/MWh
lb/GWh
lb/GWh
lb/GWh
lb/GWh
lb/GWh
lb/GWh
lb/GWh
lb/GWh
lb/GWh
lb/GWh
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
9369
TABLE 6—ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS—Continued
Subcategory/Pollutant
Coal-fired EGUs
IGCC a
Liquid oil,
continental,
lb/GWh
Liquid oil,
non-continental,
lb/GWh
Nickel, Ni ....................................
Selenium, Se ..............................
4.0E–2 lb/GWh ......
6.0E–3 lb/GWh ......
7.0E–2 lb/GWh ......
3.0E–1 lb/GWh ......
9.0E–2 ...................
2.0E–2 ...................
4.1E0 .....................
2.0E–2 ...................
Solid
oilderived
4.0E–2 lb/GWh
6.0E–3 lb/GWh
srobinson on DSK4SPTVN1PROD with RULES2
NA = Not applicable.
a Based on best-performing similar source.
b Includes Hg.
As noted elsewhere in this preamble,
we are finalizing a requirement to use
filterable PM as a surrogate for the nonmercury metallic HAP and HCl as a
surrogate for the acid gas HAP for all
subcategories of coal-fired EGUs and for
the solid oil derived fuel-fired EGUs.
For all liquid oil-fired EGUs, we are
finalizing a requirement to use filterable
PM as a surrogate for the total metallic
HAP, and we are finalizing HCl and HF
limits.
In addition, we are finalizing
alternative standards for certain HAP for
some subcategories. The alternative
pollutants and subcategories are as
follows: (1) SO2 as a surrogate to HCl for
all subcategories with add-on FGD
systems (except liquid oil-fired
subcategories as there were no existing
units from which to base an alternate
SO2 limit); (2) individual non-mercury
metallic HAP as an alternate to filterable
PM for all subcategories (except that it
includes Hg for liquid oil-fired
subcategories); and (3) total nonmercury metallic HAP as an alternate to
filterable PM for all subcategories
(except that it includes Hg for liquid oilfired subcategories). These alternative
standards are discussed elsewhere in
this preamble.
We are finalizing a beyond-the-floor
standard for Hg only for all existing
coal-fired units designed for low rank
virgin coal based on the use of activated
carbon injection (ACI) for Hg control, as
described elsewhere in this preamble.
The EPA has determined that this
beyond-the-floor level is achievable
after considering the relevant CAA
section 112(d)(2) provisions.
As noted elsewhere in this preamble,
we are also finalizing a compliance
assurance option that would allow you
to monitor liquid oil fuel moisture to
demonstrate that fuel moisture content
is no greater than 1.0 percent. Provided
that demonstration is made, you will
not have to conduct additional testing
and monitoring to demonstrate
compliance with the HCl and HF
emission limits for units in both liquid
oil subcategories (i.e., continental and
non-continental).
Pursuant to CAA section 112(h), we
are finalizing a work practice standard
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for organic HAP, including emissions of
dioxins and furans, for all subcategories
of EGUs. The work practice standard
being finalized requires the
implementation of periodic burner tuneup procedures described elsewhere in
this preamble. We are finalizing work
practice standards because the
significant majority of data for measured
organic HAP emissions from EGUs are
below the detection levels of the EPA
test methods, even when long duration
(around 8 hour) test runs are
considered. As such, we consider it
impracticable to measure emissions
from these units. As discussed at
proposal, we believe the inaccuracy of
a majority of measurements, coupled
with the extended sampling times used,
allow a work practice standard under
CAA section 112(h) to apply to these
HAP.306 We believe that a work practice
standard will lead to a better
environmental outcome than would be
obtained through a requirement to
measure a pollutant for which results
may or may not be obtained. We believe
that the work practice standard will
result in actions being taken that will
reduce emissions of these HAP.
In addition, as discussed below, we
are creating a subcategory for limited
use liquid oil-fired electric utility steam
generating unit with an annual capacity
factor of less than 8 percent of its
maximum or nameplate heat input and
we are establishing work practice
standards applicable to such units
pursuant to CAA section 112(h).
We are finalizing that new or existing
EGUs are ‘‘coal-fired’’ if they combust
coal more than 10 percent of the average
annual heat input during any 3
consecutive calendar years or for more
than 15 percent of the annual heat input
during any one calendar year and meet
the final definition of ‘‘fossil fuel-fired.’’
We are finalizing that an EGU is
considered to be in the coal-fired ‘‘unit
designed for coal greater than or equal
to 8,300 Btu/lb’’ subcategory if the EGU:
306 We would also note that the EPA, as a part of
the Industrial Boiler MACT reconsideration
proposal that was signed on December 2, 2011, is
proposing to establish work practice standards for
control of dioxins and furans from industrial
boilers.
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(1) meets the final definitions of ‘‘fossil
fuel-fired’’ and ‘‘coal-fired electric
utility steam generating unit;’’ and (2) is
not a coal-fired EGU in the ‘‘unit
designed for low rank virgin coal’’
subcategory.
We are finalizing that the EGU is
considered to be in the ‘‘unit designed
for low rank virgin coal’’ subcategory if
the EGU: (1) meets the final definitions
of ‘‘fossil fuel-fired’’ and ‘‘coal-fired
electric utility steam generating unit;’’
and (2) is designed to burn and is
burning nonagglomerating virgin coal
having a calorific value (moist, mineral
matter-free basis) of less than 19,305 kJ/
kg (8,300 Btu/lb) and that is constructed
and operates at or near the mine that
produces such coal.307
We are finalizing that the EGU is
considered to be an IGCC unit if the
EGU: (1) Combusts a synthetic gas
derived from gasified coal or solid oilderived fuel (e.g., petroleum coke, pet
coke), (2) meets the final definition of
‘‘fossil fuel-fired,’’ and (3) is classified
as an IGCC unit. We are not
subcategorizing IGCC EGUs based on
the source of the syngas used (e.g., coal,
petroleum coke). Based on information
available to the Agency, although the
fuel characteristics of coal and petcoke
are quite different, the syngas products
from both feedstocks have similar HAP
content and similar HAP emissions
characteristics that can be controlled in
a similar manner.308
We are finalizing that the EGU is
considered to be in the ‘‘Continental
liquid oil-fired’’ subcategory if (1) meets
the final definitions of ‘‘oil-fired electric
utility steam generating unit’’ and
‘‘fossil fuel-fired;’’ and (2) is located in
the continental United States (U.S.).
We are finalizing that the EGU is
considered to be ‘‘Non-continental
liquid oil-fired’’ subcategory if (1) meets
the final definitions of ‘‘oil-fired electric
utility steam generating unit’’ and
307 ASTM Method D388–05, ‘‘Standard
Classification of Coals by Rank’’ (incorporated by
reference, see § 63.14).
308 U.S. Department of Energy, Wabash River Coal
Gaification Repowering Project. Project
Performance Summary; Clean Coal Technology
Demonstration Program. DOE/FE–0448. July 2002.
EPA–HQ–OAR–2009–0234–2933.
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‘‘fossil fuel-fired;’’ and (2) is located
outside continental U.S.
We are finalizing that the EGU is
considered to be ‘‘solid oil-derived fuelfired’’ if (1) the EGU is not a coal-fired
EGU and burns solid oil-derived fuel
(e.g., petroleum coke, pet coke); and (2)
meets the final definitions of ‘‘oil-fired
electric utility steam generating unit’’
and ‘‘fossil fuel-fired.’’
We are finalizing that the EGU is
considered to be a ‘‘limited-use liquid
oil-fired’’ if (1) the EGU meets the final
definitions of ‘‘oil-fired electric utility
steam generating unit’’ and ‘‘fossil fuelfired;’’ and (2) has an annual capacity
factor of less than 8 percent of its
maximum or nameplate heat input,
whichever is greater, averaged over a 24month block contiguous period
commencing.
srobinson on DSK4SPTVN1PROD with RULES2
E. What are the requirements during
periods of startup, shutdown, and
malfunction?
As discussed below in section VI.E.,
for startup and shutdown, the
requirements have changed since
proposal. For periods of startup and
shutdown, the EPA is finalizing work
practice standards in lieu of numeric
emission limits. Numeric emission
limits apply for all other periods for all
pollutants, except organic HAP. For
malfunctions, the EPA is finalizing an
affirmative defense for exceedances of
the numerical emission limits that are
caused by malfunctions.
F. What are the testing and initial
compliance requirements?
We are requiring that you, as an
owner or operator of a new or existing
coal- or oil-fired EGU, must conduct
performance tests to demonstrate
compliance with all applicable emission
limits. For units using certified
continuous emissions monitoring
systems (CEMS) that directly measure
the regulated pollutant under final 40
CFR part 63, subpart UUUUU (e.g., Hg
CEMS, HCl CEMS, HF CEMS, SO2
CEMS (where an SO2 limit applies as
the alternative equivalent standard)), or
sorbent trap monitoring systems, the
initial performance test consists of all
valid data recorded with the certified
monitoring system in the first 30 boiler
operating days of data collected with the
certified monitoring system prior to the
initial compliance demonstration date
specified in § 63.10005. A source may
also elect to use a PM CEMS to
demonstrate compliance with the
filterable PM emission limit. If this
option is selected, then the same
provisions as noted above for other
CEMS will apply. (Note that EPA
anticipates that the PM monitoring
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device that may most often will be used
is a PM continuous parameter
monitoring system (CPMS) in
conjunction with an operating limit, as
more fully described below.) For units
and pollutants not being monitored via
CEMS, the owner or operator of an
affected unit must perform the initial
performance testing in accordance with
established EPA reference test methods
or the voluntary consensus standard
methods incorporated by reference.
You, as the owner or operator of an
affected unit, must conduct the
following compliance tests where
applicable:
(1) For coal-fired units, IGCC units,
and solid oil-derived fuel-fired units, if
you elect to comply with the filterable
PM emission limit, you must conduct
filterable PM emissions testing using
EPA Method 5 from Appendix A to part
60 of chapter 40 to determine initial
compliance. Alternatively, if you elect
to comply with the total non-mercury
HAP metals emission limit or the
individual non-mercury HAP metals
emissions limits, you must conduct
HAP metals testing using EPA Method
29 from Appendix A to part 60 of
chapter 40. Note for this rule that the
filter temperature for each Method 5 or
29 emissions test must be maintained at
160° ± 14 °C (320 ° ± 25 °F), and the
material in Method 29 impingers must
be analyzed for metals content.
Whenever metals testing is performed
with Method 29, you must report the
front half and back half analytical
fractions separately.
(2) For coal-fired, IGCC, and solid oilderived fuel-fired units, you must use a
Hg CEMS or a sorbent trap monitoring
system for both initial compliance and
continuous compliance using the
continuous Hg monitoring provisions of
Appendix A to 40 CFR part 63, subpart
UUUUU, except where the low emitting
EGU (LEE) requirements apply (see
below). The initial performance test
consists of all valid data recorded with
the certified Hg monitoring system in
the 30 boiler operating days of data
collected with the certified monitoring
system by the initial compliance
demonstration date specified in
§ 63.10005.
(3) For coal-fired and solid oil-derived
fuel-fired units and new or
reconstructed IGCC units that employ
FGD technology and elect to meet the
alternative SO2 limit in place of the HCl
limit, you need not conduct an initial
stack test for HCl or SO2. Instead, the 30
boiler operating days of data collected
with the certified SO2 CEMS by the
initial compliance demonstration date
specified in § 63.10005 are used to
determine initial compliance, and the
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SO2 CEMS is used thereafter to
demonstrate continuous compliance. If
you instead opt to meet the HCl limit
and use an HCl CEMS for compliance,
you need not conduct an initial stack
test for HCl. Instead, the 30 boiler
operating days of data collected with the
certified HCl CEMS by the initial
compliance demonstration date
specified in § 63.10005 are used to
determine initial compliance. For units
not using the SO2 or HCl CEMS options,
you must conduct an initial stack test
for HCl using EPA Method 26, 26A, or
320 from Appendix A to part 60 of
chapter 40. You may use EPA Method
26 or 320 or ASTM Method D6348–03
(Reapproved 2010) with additional
quality assurance if no entrained water
droplets exist in the exhaust gas, but
you must use Method 26A if entrained
water droplets exist in the exhaust gas.
(4) For liquid oil-fired units, you must
conduct initial performance testing as
follows. If you elect to meet the
filterable PM limit instead of the nonmercury metals limit (total or
individual), then use Method 5 with the
filter material maintained at 160° ± 14°C
(320° ± 25°F). Alternatively, you may
use a PM CEMS as discussed elsewhere
in this preamble. If you elect to meet
either the total or individual HAP
metals limit, you will use Method 29 for
all non-mercury HAP metals. For Hg,
conduct emissions testing using EPA
Method 29 or 30B from Appendix A to
part 60 of chapter 40, or ASTM Method
D6784–02 (Reapproved 2008). For acid
gases, conduct HCl and HF testing using
EPA Method 26A, 320, or 26; or you
may elect to comply by using an HCl
CEMS and/or an HF CEMS; or under
certain conditions you may choose to
demonstrate compliance by measuring
fuel moisture to demonstrate that
moisture content is no greater than 1.0
percent. You must measure daily if fuel
is delivered continuously or per
shipment if fuel is delivered on a batch
basis, or you may use a fuel moisture
content certification provided by your
fuel supplier. If you use a CEMS, then
use the 30 boiler operating days of data
collected with the certified monitoring
system by the initial compliance
demonstration date specified in
§ 63.10005 to determine initial
compliance.
(5) For the required performance stack
tests, if you are demonstrating
compliance with a heat-input based
standard, you must conduct concurrent
O2 or carbon dioxide (CO2) emission
testing using EPA Method 3A or 3B
from appendix A to part 60 of chapter
40 or ANSI/ASME PTC 19.10–1981 and
then use an appropriate equation,
selected from among Equations 19–1
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through 19–9 in EPA Method 19 from
appendix A to part 60 of chapter 40, to
convert measured pollutant
concentrations to lb/MMBtu values.
Multiply the lb/MMBtu value by one
million to get the lb/TBtu value (where
applicable). If you choose to meet an
electrical output-based emissions limit,
you must also collect concurrent stack
gas flow rate and electrical production
data.
(6) For an existing unit that you
believe will qualify as LEE for Hg, you
must conduct an initial Method 30B test
over 30 days and follow the calculation
procedures in the final rule to document
a potential to emit less than 10 percent
of the applicable Hg emissions limit or
less than 29 pounds of Hg per year. If
your unit qualifies as a LEE for Hg, you
must conduct subsequent performance
tests on an annual basis to demonstrate
that the unit continues to qualify. For all
other pollutants, you must conduct the
initial compliance test, and then all
other required tests over a 3-year period,
and in all such tests, your emission
results must be less than 50 percent of
the applicable emission limit. If you
qualify as a LEE on that basis, you must
conduct subsequent performance tests
every 3 years to demonstrate that the
unit continues to qualify.
(7) You may use results from tests
conducted no earlier than 12 months
before the compliance date of this rule
as the initial performance test for an
applicable pollutant, provided that:
a. You certify and keep records
demonstrating that no significant
changes have occurred,
b. Tests were conducted using
methods allowed in this rule in
accordance with § 63.10007 and Table 5,
c. You have records of all parameters
needed to convert results to units of the
standard for the entire period, and
d. For a CEMS-based performance
test, you have all the required data for
the entire 30-boiler operating day rolling
average period.
Operating Limit for PM CEMS
Under the final rule, you may elect to
comply continuously with an operating
limit, established during the initial
performance test, to demonstrate
continuous compliance with the
filterable PM, total non-mercury HAP
metals, or individual non-mercury HAP
metals limit. You will use a PM CPMS
to monitor compliance with the
operating limit. The PM CPMS
operating principle must be based on instack or extractive light scatter, light
scintillation, beta attenuation, or mass
accumulation detection of the exhaust
gas or representative exhaust gas
sample. The reportable measurement
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output from the PM CPMS may be
expressed as milliamps, stack
concentration, or other raw data signal.
Meeting the operating limit serves as
your demonstration of continuous
compliance with the filterable PM, total
non-mercury HAP metals, or individual
non-mercury HAP metals limit. As
mentioned earlier, if you use this
method to demonstrate continuous
compliance, you must install a PM
CPMS and establish the operating limit
during the initial compliance test for
filterable PM, total non-mercury HAP
metals, or individual non-mercury HAP
metals. As noted below, when you use
this operating limit, you can reduce
stack testing frequency to demonstrate
ongoing compliance. You may also opt
to install and operate a PM CEMS
certified in accordance with
Performance Specification 11 and
Procedure 2 of 40 CFR part 60,
Appendices B and F, respectively. If you
elect to use this option, then the
requirements for quarterly testing with
Method 5, or annual testing and use of
a PM CPMS, are no longer applicable.
Dioxins/Furans and Non-Dioxin/Furan
Organic HAP
For dioxins and furans and nondioxin/furan organic HAP, you must
submit documentation that you have
conducted a combustion process tuneup, a thorough equipment inspection,
and an optimization to minimize
generation of CO and NOX, all meeting
the requirements of this final rule. The
work practice standard involves
maintaining and inspecting the burners
and associated combustion controls,
tuning the specific burner type to
optimize combustion, obtaining and
recording CO and NOX values before
and after burner adjustments, keeping
records of activity and measurements,
and submitting a report for each tuneup conducted. You must collect CO and
NOX data and may use portable
analyzers (which include handheld or
similar devices) to monitor and verify
the results. The specific details are
addressed in 40 CFR 63.10021 of the
final rule.
This same work practice standard also
applies in place of any emission limits
for Hg, non-mercury metals HAP, acid
gas HAP, dioxins and furans, and nondioxin/furan organic HAP from a
limited-use, liquid oil-fired EGU (i.e., a
unit that has an annual capacity factor
on oil of less than 8 percent of its
maximum or nameplate heat input,
whichever is greater). The EPA
established this subcategory in response
to comments and a further analysis of
the units within this subcategory in the
ICR database. For these units, EPA
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believes that the required work practice
standards are appropriate and consistent
with the requirement of CAA section
112(h).
G. What are the continuous compliance
requirements?
To demonstrate continuous
compliance with the emission
limitations, the final rule includes the
following requirements:
(1) Use of CEMS. Where a CEMS or a
sorbent trap monitoring system is used
for demonstrating initial compliance,
you also must use the CEMS or sorbent
trap monitoring system on a continuous
basis to demonstrate ongoing
compliance with the numerical
emission limits. CEMS or sorbent trap
monitoring system data are not used to
determine compliance with the work
practice standards applicable during
periods of startup and shutdown, but
sources that install a CEMS or a sorbent
trap monitoring system to demonstrate
compliance with the numerical
emission limits must operate the system
at all times, as EPA intends to evaluate
the continuous monitoring data from
start-up and shutdown periods as
discussed below. You must calculate a
rolling average for each successive 30boiler operating day rolling average
period. All valid data collected during
each successive period will be used to
demonstrate compliance, except for data
collected during periods of startup and
shutdown; during those periods, the
owner or operator must meet work
practice requirements instead of the
numerical emission limits. There is no
numerical minimum data availability
required to constitute a valid 30-boiler
operating day rolling average; however,
you must monitor at all times that the
process is in operation (including
during startups and shutdowns,
although emissions during these periods
are not included in the 30-boiler
operating day average). You must
operate, maintain, and quality-assure
the CEMS or sorbent trap monitoring
systems in accordance with the
provisions in 40 CFR 63.10010 and
Appendix A and B of the final rule (for
Hg, HCl, and HF CEMS), in accordance
with Performance Specification 11 in
Appendix B to 40 CFR part 60 and
Procedure 2 in Appendix F to part 60
(for PM CEMS used for direct
compliance), or in accordance with 40
CFR part 75 (for SO2 CEMS, and certain
ancillary monitors such as a diluent or
moisture monitor).
For each unit using HCl, HF, SO2, PM,
or Hg CEMS or a sorbent trap
monitoring system for continuous
compliance, you must install, certify,
maintain, operate and quality-assure the
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additional CEMS (e.g., CEMS that
measure O2 or CO2 concentration, stack
gas flow rate, and, if default moisture
values are not used, moisture content)
needed to convert pollutant
concentrations to units of the emission
standards or operating limits. Where
appropriate, you must certify and
quality-assure these additional CEMS
according to 40 CFR part 75.
For HCl and HF CEMS, the EPA is
adding monitoring provisions as
Appendix B to 40 CFR part 63, subpart
UUUUU. Appendix A references
performance specification (PS) 15 of
Appendix B to 40 CFR part 60 for
Fourier Transform Infrared (FTIR)
CEMS for procedures to certify and
conduct ongoing quality assurance on
these FTIR CEMS. In addition, we
expect to publish a PS specific to HCl
CEMS in the near future (prior to the
compliance date of this rule). In the
meantime, you may petition the
Administrator under the procedure
given in 40 CFR 63.7(f) for an alternative
approach to compliance monitoring or
testing for HCl or any other regulated
pollutant.
When using a sorbent trap monitoring
system, you may use each pair of
sorbent traps to collect Hg samples for
no more than 15 boiler operating days.
Under the general duty to monitor at all
times, you must replace traps in a
timely manner to ensure that Hg
emissions are sampled continuously.
For Hg monitoring, the EPA is adding
Hg monitoring provisions as Appendix
A to 40 CFR part 63, subpart UUUUU,
and requiring use of these provisions to
document continuous compliance with
the rule for coal-fired, IGCC, and solid
oil derived-fired units that cannot
qualify as LEEs. Appendix A
consolidates all Hg monitoring
provisions.
Today’s rule provides two basic Hg
continuous monitoring options: Hg
CEMS and sorbent trap monitoring
systems. Appendix A requires initial
certification and periodic quality
assurance (QA) testing of the Hg CEMS
and sorbent trap monitoring systems.
The certification tests required for the
Hg CEMS are a 7-day calibration error
test; a linearity check, using NISTtraceable elemental Hg standards; a 3level system integrity check (similar to
a linearity check), using NIST-traceable
oxidized Hg standards; a cycle time test;
and a relative accuracy test audit
(RATA). Table A–1 of Appendix A
summarizes the performance
specifications for the required
certification tests. For ongoing QA of the
Hg CEMS, Appendix A requires daily
calibrations, weekly single-point system
integrity checks, quarterly linearity
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checks (or 3-level system integrity
checks), and annual RATAs. Table A–2
in Appendix A summarizes these
ongoing QA test requirements and the
applicable performance criteria for Hg
CEMS, which are consistent with those
published in support of CAMR and are,
thus, familiar to the industry.
For sorbent trap monitoring systems,
a RATA is required for initial
certification, and annual RATAs are
required for ongoing QA. The
performance specification for these
RATAs is the same as for the RATAs of
the Hg CEMS. Bias adjustment of the
measured Hg concentration data is not
required. For day-to-day operation of
the sorbent trap system, Appendix A
requires you to follow the procedures
and QA/QC criteria in PS 12B in
Appendix B to 40 CFR part 60. PS 12B
is nearly identical to the Appendix K to
40 CFR part 75, published in support of
CAMR and with which the industry is
familiar. The 40 CFR part 75 concepts
of:
a. Determining the due dates for
certain QA tests on the basis of ‘‘QA
operating quarters’’ and
b. Grace periods for certain QA tests
apply to both Hg CEMS and sorbent trap
monitoring systems. Mercury
concentrations measured by Hg CEMS
or sorbent trap systems are used
together with hourly flow rate, diluent
gas, moisture, and electrical load data,
to express the Hg emissions in units of
the rule, on an hourly basis (i.e., lb/TBtu
or lb/GWh). Section 6 of Appendix A
provides the necessary equations for
these unit conversions.
For HCl and HF CEMS, the EPA is
adding monitoring provisions as
Appendix B to 40 CFR part 63, Subpart
UUUUU. Appendix A references
performance specification (PS) 15 of
Appendix B to 40 CFR part 60 for
Fourier Transform Infrared (FTIR)
CEMS for procedures to certify and
conduct ongoing quality assurance on
these FTIR CEMS. In addition, we
expect to promulgate a generic PS
specific to HCl CEMS prior to the
compliance date of this rule. In the
meantime, you may petition the
Administrator under the procedure
given in 40 CFR 63.7(f) for an alternative
approach to compliance monitoring or
testing for HCl or any other regulated
pollutant.
(2) Use of stack tests. If you
demonstrate initial compliance on the
basis of a stack test, you must
demonstrate continuous compliance by
conducting periodic stack tests on a
quarterly basis. This includes filterable
PM (or non-mercury HAP metals) and
HCl from coal-fired and solid oilderived fuel-fired EGUs, and filterable
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PM (or HAP metals) and HCl and HF
from liquid oil-fired EGUs with the
following exceptions:
a. If you use a PM CPMS and
associated operating limit, you may
conduct the applicable Method 5 or
Method 29 test once annually rather
than quarterly, in which case you must
re-establish the operating limit during
each performance test. A PM CPMS
does not need to meet the requirements
for a PM CEMS under PS 11. The final
rule includes basic quality checks that
the PM CPMS must meet and a
requirement for you to develop and
follow a site-specific monitoring plan to
be approved by the delegated authority.
You must demonstrate compliance with
the operating limit by using all valid
hourly data collected during each
successive 30-boiler operating day
period rolled daily. The 30-boiler
operating day rolling average is
calculated by all of the valid hourly
average PM CPMS output values
collected for the 30 boiler operating
days (excluding hours of startup and
shutdown; see section V.E. of this
preamble).
b. If you combust liquid fuels and if
your fuel moisture content is no greater
than 1.0 percent, you may demonstrate
ongoing compliance with HCl and HF
emissions limits by:
i. Measuring fuel moisture content of
each shipment of fuel if your fuel
arrives on a batch basis;
ii. Measuring fuel moisture content
daily if your fuel arrives on a
continuous basis; or
iii. Obtaining and maintaining a fuel
moisture certification from your fuel
supplier.
Should the moisture in your liquid
fuel be more than 1.0 percent, you must
i. Conduct HCl and HF emissions
testing quarterly and establish sitespecific monitoring to demonstrate
continued acid gas control performance
between periodic tests, or
ii. Use an HCl CEMS and/or HF
CEMS.
c. If your existing unit qualifies as an
LEE for Hg, you must conduct another
30-day Method 30B performance test on
your unit once per year to reestablish
that the unit continues to qualify as a
LEE for Hg. If the results of the LEE test
show that the unit exceeds 10 percent
of the emissions limit or exceeds the
potential to emit 29 pounds of Hg per
year, you will lose LEE status for the
unit. You can regain LEE status for that
unit if every required performance test
for a 3-year period shows that emissions
from the unit did not exceed the LEE
limit. If LEE status is lost for a solid fuel
unit, you must commence quarterly
performance testing until you install,
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certify, and operate a Hg CEMS or a
sorbent trap monitoring system, and you
must complete the installation and
certification within 6 months of losing
LEE status; for a liquid fuel unit, you
must commence quarterly performance
testing.
d. If a liquid oil-fired EGU has an
annual capacity factor on oil of less than
8 percent of its maximum or nameplate
heat input, whichever is greater, you
must demonstrate continuous
compliance with the applicable work
practice standard by conducting at least
once every 36 calendar months (48
calendar months if a neural network is
employed) a combustion process tuneup, a thorough equipment inspection,
and an optimization to minimize
generation of CO and NOX, all meeting
the requirements of this final rule. You
must maintain and inspect the burners
and associated combustion controls,
tuning the specific burner type to
optimize combustion, obtaining and
recording CO and NOX values before
and after burner adjustments, keeping
records of activity and measurements,
and submitting a report for each tuneup conducted. You must collect CO and
NOX data using portable analyzers
(which typically include handheld or
similar devices). Specific details are
addressed in 40 CFR 63.10021 of the
final rule. In addition, you must record
boiler operating hours, by fuel type, in
each calendar quarter.
e. The rule allows a grant of LEE
status to existing units with test results
that show a history of low, non-mercury
emissions. As mentioned earlier, LEE
status reduces testing frequency for
units. After a 3-year period during
which every emissions test for a specific
pollutant shows emissions no greater
than 50 percent of the emissions limit,
you may reduce the emissions testing
frequency for that specific non-mercury
pollutant to once every 36 months. If
any subsequent emissions test for that
pollutant exhibits emissions greater
than 50 percent of the emissions limit,
you must revert to the original
emissions testing frequency until you
re-establish a 3-year period of very low
emissions no greater than 50 percent of
the standard.
f. For liquid oil-fired units that
demonstrate continuous compliance
with quarterly performance tests for HCl
and HF emission limits rather than
through use of HCl and HF CEMS, the
final rule requires a site-specific
monitoring plan in addition to the
quarterly tests. For these pollutants,
there is unlikely to be any existing
underlying monitoring (such as
compliance assurance monitoring) that
serves as an additional tool to ensure
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the source’s operations remain
consistent with operating conditions
during a recent successful performance
test. The requirement for a site-specific
monitoring plan fills this gap and
ensures that in between tests, the source
continues to operate in a manner
designed to maintain HCl and HF
emissions in compliance with the
emission limits under this rule. The
appropriate parameters to monitor will
depend on the compliance strategy
employed by a specific source, and thus
EPA is enabling the monitoring
approach to be established on a case-bycase basis. Given the relatively small
number of these units and the other
compliance options available, we
anticipate that this approach will apply
to a small set of units. The monitoring
plan will identify the parameters
monitored, the monitoring methods, the
QA/QC elements that apply, and the
data reduction elements (including
appropriate averaging periods, as
applicable). See 40 CFR
63.10000(c)(2)(ii).
(3) Work practice standard. For the
performance tune-up work practice
requirements, you must demonstrate
continuous compliance by conducting
the work practice at least once every 36
calendar months (48 calendar months if
a neural network is employed). The
work practice involves maintaining and
inspecting the burners and associated
combustion controls, tuning the specific
burner type, as applicable, to optimize
combustion, obtaining and recording CO
and NOX values before and after burner
adjustments, keeping records of activity
and measurements, and submitting a
report for each tune-up conducted. A
combustion tune-up will involve
optimizing combustion of the unit
consistent with manufacturer’s
instruction as applicable, or in
accordance with best combustion
engineering practice for that burner
type.
H. What are the notification,
recordkeeping and reporting
requirements?
All new and existing sources in all
subcategories must comply with certain
requirements of the General Provisions
(40 CFR part 63, subpart A), which are
identified in Table 9 of this final rule.
The General Provisions include specific
requirements for notifications,
recordkeeping, and reporting. You must
submit a notification of compliance
status report for each unit, according to
the schedule required by 40 CFR 63.9(h)
of the General Provisions, including a
certification of compliance.
Except for units that use CEMS for
continuous compliance, under this rule
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you must provide semiannual
compliance reports, as required by 40
CFR 63.10(e)(3) of subpart A, that
indicate whether a deviation from any
of the requirements in the rule occurred
and whether or not any process changes
occurred and compliance certifications
were reevaluated. As discussed below,
we are finalizing a requirement to use
the 40 CFR part 75-based Emissions
Collection and Monitoring Plan System
(ECMPS) for reporting emissions and
related data for units using CEMS for
most pollutants. Also, as discussed
below, for the PM CPMS, PM CEMS,
and performance test results, we require
you to use EPA’s WebFIRE 309 database
for reporting.
This rule requires you to keep certain
records to demonstrate compliance with
each emission limit and work practice
standard. The General Provisions to 40
CFR part 63 specify these recordkeeping
requirements (see Table 9 to this
subpart). Among other specific records,
you must keep the following:
(1) All reports and notifications
submitted to comply with this rule.
(2) Continuous monitoring data as
required in this rule.
(3) Each instance in which you did
not meet an emission limit, work
practice requirement, operating limit, or
other compliance obligation (i.e.,
deviations from this rule).
(4) Daily hours of operation by each
unit.
(5) As part of the general duty to keep
all monitoring data, fuel moisture
content of liquid fuel, if you elect to
demonstrate compliance using that
information.
(6) A copy of the results of all
performance tests, monitor
certifications, performance evaluations,
or other compliance demonstrations
conducted to demonstrate initial or
continuous compliance with this rule.
(7) A copy of your site-specific
performance evaluation test plans
developed for this rule as specified in
40 CFR 63.8(e), if applicable.
(8) A copy of your acid gas control
system parameter monitoring plan
under 40 CFR 63.10000(c)(2)(ii).
You also must submit the following
additional notifications:
(1) Notifications required by the
General Provisions.
(2) Initial Notification no later than
120 calendar days after you become
subject to this subpart.
309 WebFIRE is the Internet version of FIRE. The
Factor Information Retrieval (FIRE) Data System is
a database management system containing EPA’s
recommended emission estimation factors for
criteria and HAP. It includes information about
industries and their emitting processes, the
chemicals emitted, and the emission factors
themselves.
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(3) Notification of Intent to conduct
performance tests and/or compliance
demonstration at least 60 calendar days
before the performance test and/or
compliance demonstration is scheduled.
(4) Notification of Compliance Status
60 calendar days following completion
of the performance test and/or
compliance demonstration.
Electronic reporting is becoming a
common element of modern life (as
evidenced by electronic banking and
income tax filing), and the EPA is
beginning to require electronic
submittal of environmental data.
Electronic reporting is already common
in environmental data collection and
many media offices at EPA are reducing
reporting burden for the regulated
community by embracing electronic
reporting systems as an alternative to
paper-based reporting.
One of the major benefits of reporting
electronically is standardization, to the
extent possible, of the data reporting
formats that provides more certainty to
users of what data are required in
specific reports. For example, electronic
reporting software allows for more
efficient data submittal and the
software’s validation mechanism helps
industry users submit fewer incomplete
reports. This alone saves industry report
processing resources and reduces
transaction times. Standardization also
allows for development of efficient
methods to compile and store much of
the documentation required to be
reported by this rule.
Use of Electronic Reporting System
We are requiring that you submit
certain reports electronically. In
addition to supporting regulation
development, control strategy
development, and other air pollution
control activities, having an electronic
database populated with these reports
will save industry, state, local, tribal
agencies, the public, and the EPA
significant time, money, and effort
while also improving the transparency
and quality of emission inventories and,
as a result, air quality regulations.
The reports to be submitted
electronically include all performance
test reports, notification of compliance
status reports, compliance, and
continuous monitoring data summaries
specified in 40 CFR 63.10031 of this
rule. Performance tests are required to
be conducted as described in 40 CFR
63.7 of the General Provisions. The data
that must be submitted as the
performance test report are also
described in 40 CFR 63.7. These data
must be submitted (except in limited
cases) to EPA’s WebFIRE database by
using the electronic reporting tool (ERT)
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and the Compliance and Emissions Data
Reporting Interface (CEDRI) that is
accessed through EPA’s Central Data
Exchange (CDX), as described below.
The data requirements for the
notification of compliance status and
compliance reports are described in
detail in the regulatory text (40 CFR
63.10031) of this rule, but they
essentially mirror the requirements in
40 CFR 63.6 of the General Provisions.
These reports will also be submitted to
WebFIRE using an electronic form
found in CEDRI and through the CDX as
described below. As required in 40 CFR
63.10031(f)(2) of the final rule, the
continuous monitoring summaries are
required to be submitted quarterly. The
quarterly reports must include all of the
calculated 30-boiler operating day
rolling average values derived from the
PM CPMS. These reports will also be
submitted to WebFIRE using an
electronic form found in CEDRI and
through the CDX, as described below.
This same approach will apply if a
source elects to use a PM CEMS or
receives approval to use a HAP metals
CEMS as an alternative monitoring
method.
The availability of electronic
reporting for sources subject to the
Subpart UUUUU will provide
efficiency, improved services, better
accessibility of information, and more
transparency and accountability.
Additionally, submittal of these
required reports electronically provides
significant benefits for regulatory
agencies, industry, and the public. The
compliance data electronic reporting
system (CEDRI and CDX) is being
developed such that once a facility’s
initial data entry into the system is
established and a report is generated,
subsequent data submittal will only
consist of electronic updates to existing
information in the system. Such a
system will effectively reduce the
burden associated with submittal of data
and reports by reducing the time, costs,
and effort required to submit and update
hard copies of documentation. State,
local, and tribal air pollution control
agencies will also benefit from having
access to the more streamlined and
accurate electronic data submitted to the
EPA. Electronic reporting will allow for
an electronic review process rather than
a manual data assessment, making
review and evaluation of the sourceprovided data and calculations easier
and more efficient. Electronic reporting
will also benefit the public by
generating a more transparent review
process and increasing the ease and
efficiency of data accessibility.
Furthermore, electronic reporting will
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reduce the burden on the regulated
community by reducing the effort
involved in data collection and
reporting activities. In the future, we
anticipate there will be fewer and less
substantial data collection requests in
conjunction with prospective required
residual risk assessments or technology
reviews. Electronic reporting will
substantially reduce this burden,
because the EPA will already have these
data available and consolidated in an
electronic database named WebFIRE.
We anticipate that using electronic
reporting for the required reports will
result in an overall reduction in
reporting costs; for a discussion of the
economic and cost impacts of electronic
reporting, see section XII.D. of this
preamble.
Another benefit of electronic data
submittal is that these data will greatly
improve the overall quality of existing
and new emissions factors by
supplementing the pool of emissions
test data for establishing emissions
factors and by ensuring that the factors
are more representative of current
industry operational procedures. A
common complaint heard from industry
and regulators is that emission factors
are outdated or not representative of a
particular source category. With timely
receipt and incorporation of data from
most performance tests, the EPA will be
able to ensure that emission factors,
when updated, represent the most
current range of operational practices.
Data entry of these electronic reports
will be through the CEDRI that is
accessed through EPA’s CDX
(www.epa.gov/cdx). Data submitted
electronically through CEDRI will be
stored in CDX as an official copy of
record.
Once you have accessed CEDRI, you
will select the applicable subpart for the
report that you are submitting. You will
then select the report being submitted,
enter the data into the form, and click
on the submit button. In some cases,
such as with submittal of a notification
of compliance status report, you will
select the report icon, enter basic facility
information, and then upload the report
in a specified file format.
In addition, we believe that there will
be value in allowing other reporting
forms to be developed and used in cases
where the other reporting forms can
provide an alternate electronic file
consistent with EPA’s form output
format. This approach has been used
successfully to provide alternatives for
other electronic forms (e.g., income tax
submittal).
In cases where performance test data
are to be submitted to the EPA, you
must enter the performance test data
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and information into the electronic
reporting tool (ERT) which can be
accessed at https://www.epa.gov/ttn/
chief/ert/. In CEDRI, the user
must then upload the ERT file. CEDRI
submits a copy of the ERT project data
file directly to WebFIRE where the data
are made available. Where performance
test reports are submitted, WebFIRE
notifies the appropriate state, local, or
tribal agency contact that an ERT project
data file was received from the source.
Submitting performance test data
electronically to the EPA will apply
only to those performance tests
conducted using test methods that will
be supported by the ERT. The ERT
contains a specific electronic data entry
form for most of the commonly used
EPA reference methods. A listing of the
pollutants and test methods supported
by the ERT is available at the ERT Web
site listed above.
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I. Submission of Emissions Test Results
to the EPA
The EPA has determined that
harmonization of the monitoring and
reporting requirements of this final rule
with 40 CFR part 75 is appropriate,
where the affected industry already has
a well-defined system for continuous
monitoring and reporting of emissions
under that part. Therefore, the Agency
is finalizing monitoring and reporting
requirements for most CEMS that are
consistent with 40 CFR part 75. You
must report CEMS data (other than PM
CEMS data or data from alternative
monitoring subject to site-specific
approval such as a HAP metals CEMS)
to the EPA electronically, on a quarterly
basis, using the ECMPS.
The ECMPS process divides
electronic data into three categories, the
first of which is monitoring plan data.
You must maintain the electronic
monitoring plan separately and can
update it at any time if necessary. The
monitoring plan documents the
characteristics of the affected units (e.g.,
unit type, rated heat input capacity, etc.)
and the monitoring methodology used
for each parameter (e.g., CEMS). The
monitoring plan also describes the type
of monitoring equipment used
(hardware and software components),
includes analyzer span and range
settings, and provides other useful
information. Nearly all coal-fired EGUs
are subject to the ARP and thus have
established electronic monitoring plans
that describe their required SO2, flow
rate, CO2 or O2, and, in some cases,
moisture monitoring systems. The EPA
will adjust the ECMPS monitoring plan
format to accommodate this same type
of information for Hg, HCl, and HF
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CEMS, with the addition of a few codes
for the new parameters.
The second type of data collected
through ECMPS is certification and QA
test data. These data include data from
linearity checks, RATAs, cycle time
tests, 7-day calibration error tests, and a
number of other QA tests that are
required to validate the emissions data.
You may submit the results of these
tests to the EPA as soon as you obtain
the results, with one notable exception.
Daily calibration error tests are not
treated as individual QA tests, due to
the large number of records generated
each quarter. Rather, these tests must be
included in the quarterly electronic
reports, along with the hourly emissions
data. The ECMPS system is set up to
receive and process certification and QA
data from SO2, CO2, O2, flow rate, and
moisture monitoring systems that are
installed, certified, maintained,
operated, and quality-assured according
to 40 CFR part 75. EGUs routinely
submit these data to the EPA under the
ARP and other emissions trading
programs.
To accommodate the certification and
QA tests for Hg CEMS, other CEMS, and
sorbent trap monitoring systems, the
structure and functionality of ECMPS
needs relatively few changes, because
most of the tests are the same as those
required for other gas monitors. For
reporting Hg, HCl, SO2, and HF CEMS
data under this rule, we are disabling
ECMPS’ 40 CFR part 75 bias test (which
is required for certain types of monitors
under the EPA’s SO2 and NOX
emissions trading programs). The bias
adjustment of the data from these
monitors is unnecessary for compliance
with the rule.
The third type of data collected
through ECMPS is the hourly emissions
data, which, as previously noted, is
reported on a quarterly schedule. You
must submit reports within 30 days after
the end of each calendar quarter. The
emissions data format requires hourly
reporting of all measured and calculated
emissions values, in a standardized
electronic format. You must report
direct measurements made with CEMS,
such as gas concentrations, in a Monitor
Hourly Value (MHV) record. A typical
MHV record for gas concentration
includes data fields for:
(1) The parameter monitored (e.g.,
SO2);
(2) The unadjusted and bias-adjusted
hourly concentration values (note that if
bias adjustment is not required, only the
unadjusted hourly value is reported);
(3) The source of the data, i.e., a code
indicating either that each reported
hourly concentration is a quality
assured value from a primary or backup
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monitor, or that quality-assured data
were not obtained for the hour; and
(4) The percent monitor availability
(PMA), which is updated hour-by-hour.
This generic record structure could
easily accommodate hourly average
measurements from CEMS used under
this rule.
The ECMPS reporting structure is
quite flexible, which makes it useful for
assessing compliance with various
emission limits. The Derived Hourly
Value (DHV) record allows calculations
of a wide variety of quantities from the
reported hourly emissions data. For
instance, if an emission limit is
expressed in units of lb/MMBtu, the
DHV record can be used to report hourly
pollutant concentration values in these
units of measure, since the lb/MMBtu
values can be derived from the hourly
pollutant and diluent gas (CO2 or O2)
concentrations reported in the MHV
records. The ECMPS can also
accommodate multiple DHV records for
a given hour in which more than one
derived value is required to be reported.
The system will support reporting
hourly data in the units of the emission
standards (e.g., lb/MMBtu, lb/TBtu, lb/
GWh, etc.) when hourly Hg
concentration data are reported through
ECMPS using the DHV record, in
conjunction with the appropriate
equations and auxiliary information
such as heat input and electrical load
(all of which are reported hourly in the
emissions reports).
One change in this rule from standard
40 CFR part 75 emissions data reporting
is elimination of the requirement to
provide substitute data calculations
within ECMPS. The ARP and other
emissions trading programs that report
emissions data to the EPA using 40 CFR
part 75 require provision of a complete
data record. Emissions data are required
to be reported for every unit operating
hour. When CEMS are out of service,
substitute data must be reported to fill
in the gaps. However, for the purposes
of compliance with a NESHAP,
reporting substitute data during monitor
outages is not necessary, as
quantification of total mass emissions is
not the focus of the rule. Hours when a
monitoring system is out of service
would be counted as hours of monitor
down-time and may be a deviation from
the monitoring requirements of this rule
unless the rule provides an exception,
as it does for routine quality control and
maintenance activities.
In contrast to the CEMS-related data
that would be submitted through
ECMPS, you must submit reports of
performance tests and PM CPMS data to
EPA’s WebFIRE database by using
CEDRI that is accessed through EPA’s
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CDX (www.epa.gov/cdx). You must
submit performance test data in the file
format generated through use of EPA’s
ERT (see https://www.epa.gov/ttn/chief/
ert/) within 60 days of
performance test completion. Electronic
data submittal requirements are
described in section V.H. of this
preamble.
Other notifications and reports not
currently accepted by the electronic
reporting system will be submitted in
hardcopy form at this time.
VI. Summary of Significant Changes
Since Proposal
The previous section described the
requirements that EPA is finalizing in
this rule. This section will discuss in
greater detail the key changes EPA is
making from the proposed. These
changes result from EPA’s review of the
additional data and information
provided to us and our consideration of
the many substantive and thoughtful
comments submitted on the proposal.
While our approach and methodology to
establishing the standards remain the
same, the changes make the final rule
more flexible and cost-effective, reduce
reliability concerns and improve clarity,
while fully preserving, or improving,
the public health and environmental
protection required by the CAA.
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A. Applicability
Since proposal, the EPA has made
certain changes to the applicability
provisions of the final rule to provide
clarity. These changes do not change the
universe of sources subject to the rule.
The EPA is revising a number of the
proposed definitions and adding a
definition for ‘‘natural gas-fired electric
utility steam generating unit’’ in the
final rule to provide clarity to the
regulated community concerning the
standards applicable to coal- and oilfired EGUs.
In the proposed rule, the EPA defined
‘‘[e]lectric utility steam generating unit’’
consistent with the CAA section
112(a)(8) definition:
A fossil fuel-fired combustion unit of more
than 25 megawatts electric (MWe) that serves
a generator that produces electricity for sale.
A fossil fuel-fired unit that cogenerates steam
and electricity and supplies more than onethird of its potential electric output capacity
and more than 25 MWe output to any utility
power distribution system for sale is
considered an electric utility steam
generating unit.
40 CFR 63.10042.
We also indicated how we would
determine whether units were coal-fired
or oil-fired fired EGUs: ‘‘If an EGU burns
coal (either as a primary fuel or as a
supplementary fuel), or any
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combination of coal with another fuel
(except solid waste as noted below), the
unit is considered to be coal fired under
this proposed rule. If a unit is not a coalfired unit and burns only oil, or oil in
combination with another fuel other
than coal (except as noted below), the
unit is considered to be oil fired under
this proposed rule.’’ 76 FR 25020.
We proposed a definition for the term
‘‘fossil fuel-fired’’ because that term was
not defined in the statute and we
wanted to clarify the level of fossil fuel
combustion necessary to satisfy the
CAA section 112(a)(8) definition of
EGU. The definition focused on coal
and oil combustion because the EPA
was only regulating coal- and oil-fired
EGUs in this final rule. The proposed
definition contained two primary
elements: (1) the unit must be capable
of combusting sufficient amounts of coal
or oil to generate the equivalent of 25
megawatts electrical output; and (2) the
unit must have fired coal or oil for more
than 10.0 percent of the average annual
heat input during the previous 3
calendar years or for more than 15.0
percent of the annual heat input during
any one of those calendar years. 76 FR
25025. We further stated that for a unit
to be ‘‘capable of combusting’’ coal or
oil the unit must have a permit that
authorized the combustion of coal or oil
and also have the appropriate fuel
handling facilities on-site. Id.
As explained in the proposed rule,
natural gas-fired EGUs were not
included in the December 2000 listing
so such units that otherwise met the
CAA section 112(a)(8) definition of EGU
because of natural gas combustion are
not subject to the final rule. In the
proposed rule, we stated that an EGU
that ‘‘combusts natural gas exclusively
or natural gas in combination with
another fuel where the natural gas
constitutes 90 percent or more of the
average annual heat input during the
previous 3 calendar years or 85.0
percent or more of the annual heat input
during any one of those calendar years’’
was not subject to the rule. Id. The
references to 90 percent natural gas
combustion over 3 years and 85 percent
natural gas combustion in any one year
were included to align with the
definitions of ‘‘fossil fuel-fired’’ so that
it would be clear that units combusting
primarily natural gas would not be
considered coal-fired, oil-fired, or IGCC
EGUs if they burned 10 percent or less
of coal, oil, or synthetic gas derived
from coal or solid oil over 3 years or 15
percent or less of such fuels in any one
year. We did not intend to suggest that
to be considered a fossil fuel-fired EGU
a natural gas-fired unit that is not a coalfired or oil-fired EGU would have to
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combust natural gas that exceeded the
10 percent/15 percent thresholds set
forth in the proposed rule. In fact, in 40
CFR 63.9983 of the proposed rule, we
stated that ‘‘[a]ny EGU that is not a coalor oil-fired EGU and combusts natural
gas more than 10.0 percent of the
average annual heat input during the
previous 3 calendar years or for more
than 15.0 percent of the annual heat
input during any one of those calendar
years’’ is not subject to this subpart.
We further explained that the
percentages included in the definition
of ‘‘fossil fuel-fired’’ would prevent
units that primarily combusted fuels
other than fossil fuels from being
subjected to the final rule:
Units that do not meet the definition of
fossil-fuel fired would, in most cases, be
considered IB units subject to one of the
Boiler NESHAP. Thus, for example, a
biomass-fired EGU, regardless of size, that
utilizes fossil fuels for startup and flame
stabilization purposes only (i.e., less than or
equal to 250 MMBtu/hr and used less than
10.0 percent of the average annual heat input
during the previous 3 calendar years or less
than 15.0 percent of the annual heat input
during any one of those calendar years) is not
considered to be a fossil fuel-fired EGU under
this proposed rule. The EPA has based its
threshold value on the definition of ‘‘oilfired’’ in the ARP found at 40 CFR 72.2. As
EPA has no data on such use for (e.g.)
biomass co-fired EGUs because their use has
not yet become commonplace, we believe
this definition also accounts for the use of
fossil fuels for flame stabilization use without
inappropriately subjecting such units to this
proposed rule. Id.
Thus, in the proposed rule, we
intended to create thresholds to
determine when a unit is fossil fuelfired and for which fossil fuel the unit
is fossil fuel-fired. We intended to
include a unit combusting more than
the defined amount of coal in one of the
coal-fired EGU subcategories. If a unit is
not coal-fired and it is combusting more
than the defined amount of oil, we
intended to include the unit in one of
the oil-fired EGU subcategories. We also
intended to make clear that EGUs that
are neither coal-fired nor oil-fired but
combust more than the defined amount
of natural gas are natural gas-fired EGUs
not subject to the final standards.
However, the definitions, as proposed,
were not sufficiently descriptive.
For example, we included a definition
for ‘‘coal-fired electric utility steam
generating unit’’ that did not include the
requirement that the unit must combust
coal for at least 10 percent of the heat
input over 3 years or 15 percent of the
heat input in any one year. Instead, in
the proposed rule we indicated that a
unit was coal-fired if it burned coal in
any amount. We did not intend to
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define a unit as coal-fired if it burned
coal that accounted for 10 percent or
less over 3 years or 15 percent of less
in any one year, as that would be
inconsistent with the definition of fossil
fuel-fired and the definitions for the oilfired EGU subcategories. Under the
proposed rule construct, a unit that
combusts mostly biomass and less than
10 percent coal over 3 years would not
be a coal-fired EGU because it would
not meet the ‘‘fossil fuel-fired’’
definition. But a unit burning mostly
petroleum coke and less than 10 percent
coal over 3 years might be considered a
coal-fired EGU because it would meet
the definition of ‘‘fossil fuel-fired’’ and
be burning some coal, even though that
level of coal combustion alone would
not be sufficient to make the unit ‘‘fossil
fuel-fired’’ for coal. That result is at
odds with our intent. The same would
hold true for an EGU that combusts
mostly natural gas and less than 10
percent synthetic gas derived from coal
over a 3-year period. Our proposal
preamble makes clear that we did not
intend this result because we
specifically stated that units burning 90
percent or more natural gas over a 3year period would be considered
natural-gas fired EGUs. 76 FR 25025.
In addition, we proposed to define
‘‘[u]nit designed to burn solid oil fuel
subcategory’’ to include any EGU that
burned a solid fuel derived from oil for
more than 10.0 percent of the average
annual heat input during the previous 3
calendar years or for more than 15.0
percent of the annual heat input during
any one of those calendar years, either
alone or in combination with other
fuels. We also included the 10 percent/
15 percent thresholds in the definition
for the liquid oil subcategory, but, as
stated above, we did not include the
thresholds in the definition of ‘‘coalfired’’ EGU. Therefore, there would be
some confusion for a source that
blended coal with solid oil derived fuel
(e.g., petroleum coke). For example, the
owner or operator of an EGU that
burned sufficient solid oil-derived fuel
that accounted for 80 percent of the heat
input in a given year and the remainder
of the fuel was coal would not be sure
which standard applied because the
definitions in the proposed rule were
internally inconsistent.
For these reasons, we are revising the
definitions for ‘‘coal-fired electric utility
steam generating unit,’’ ‘‘integrated
gasification combined cycle electric
utility steam generating unit,’’ and ‘‘oilfired electric utility steam generating
unit,’’ and we are adding a definition of
‘‘natural-gas fired electric utility steam
generating unit’’ as set out in 40 CFR
63.10042.
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In addition to these changes, we are
revising the definition of ‘‘fossil fuelfired’’ based on comments. We are
revising the definition to remove the
heat input equivalent of 25 MW because
commenters noted that the equivalency
used (taken from 40 CFR part 60,
subpart Da) could not be applied
consistently because of differing boiler
efficiencies. Commenters noted that
owners/operators were familiar with the
use of the ‘‘MW’’ term for the boilers
and boilers include nameplate
capacities that are readily identifiable.
We are also including a revision to the
definition so that the fossil fuel
combustion thresholds of 10 percent
over 3 consecutive years and 15 percent
in one year are evaluated after the
applicable compliance date of the final
rule on a rolling basis. Commenters
correctly noted that some existing coaland oil-fired EGUs will convert their
units to alternative fuels (e.g., natural
gas or biomass) and if the definition
were finalized as proposed such units
could be improperly subjected to the
final standards.
The new definition is set out in 40
CFR 63.10042.
For clarity, we are also removing the
definition of ‘‘[u]nit designed to burn
liquid oil fuel subcategory,’’ revising the
definition of ‘‘[u]nit designed to burn
solid oil fuel subcategory,’’ adding
definitions for the continental and noncontinental liquid oil-fired EGU
subcategories, and adding a definition of
a limited-use liquid oil-fired EGU as set
out in 40 CFR 63.10042.
In the proposed rule, we stated that
we believed EGUs may at times not
meet the definition of an EGU subject to
this subpart. For example, we explained
that there may be some cogeneration
units that are determined to be covered
under the Boiler NESHAP. Such unit(s)
may make a decision to increase the
proportion of production output being
supplied to the electric utility grid, thus
causing the unit(s) to meet the EGU
cogeneration criteria (i.e., greater than
one-third of its potential output capacity
and greater than 25 MW). In the
preamble to the proposed rule, we
indicated that a unit subject to one of
the Boiler NESHAP that increases its
electricity output and meets the
definition of an EGU would be subject
to the EGU NESHAP for the 6-month
period after the unit meets the EGU
definition.310 76 FR 25026. Assuming
the EGU did not meet the definition of
an EGU following that initial
310 Although we clearly stated the intent to
require sources to comply for 6 months after
meeting the definition of an EGU, we inadvertently
failed to include the provision in the proposed rule.
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occurrence, at the end of the 6-month
period it would revert back to being
subject to the Boiler NESHAP, or other
applicable standard. We solicited
comment on the extent to which
situations like this might occur, how the
EPA should address situations where
units change applicability, and whether
we should include provisions similar to
those included in the final CISWI (40
CFR 60.2145) to address such situations.
Id.
Several commenters asked the Agency
to include provisions in the final rule
that would address situations like the
ones described in the preamble to the
proposed rule. Because applicability to
the final rule is based in part on the
statutory definition of an EGU is CAA
section 112(a)(8), similar to the situation
with units combusting solid waste
under CAA section 129(g)(1) (e.g.,
CISWI Rule), we are adopting provisions
in the final rule that are based on the
fuel switching provisions of the final
CISWI Rule (See Final CISWI Rule, 40
CFR 60.2145). For example, a
cogeneration unit that did not
historically provide more than one third
of its potential electrical output capacity
to a power distribution system could
change its output and provide more
than 25 megawatts electrical output to
any power distribution system for sale.
Such units would be subject to MATS.
If the cogeneration unit later reduced its
output such that it no longer met the
definition of an EGU, that source would
nevertheless remain subject to MATS
for at least 6 months from the date that
the unit first qualified as an EGU.
In addition, we are finalizing a
provision whereby you may opt to
remain subject to the provisions of this
final rule, unless you combust solid
waste, in which case you are a solid
waste incineration unit subject to
standards under CAA section 129 (e.g.,
40 CFR part 60, subpart CCCC (New
Source Performance Standards (NSPS)
for Commercial and Industrial Solid
Waste Incineration Units), or subpart
DDDD (Emissions Guidelines (EG) for
Existing Commercial and Industrial
Solid Waste Incineration Units)). We
believe the provision to opt to remain
subject to this final rule will ameliorate
conditions where EGUs may potentially
move between NESHAP on a relatively
frequent basis. Notwithstanding the
provisions of this final rule, an EGU that
starts combusting solid waste is subject
to standards under CAA section 129,
and the unit remains subject to those
standards until the unit no longer meets
the definition of a solid waste
incineration unit consistent with the
provisions of the applicable CAA
section 129 standards.
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The changes to the definitions
described above provide clarity to
sources, permitting agencies, and the
public about the applicability of the rule
and help ensure that sources are
appropriately covered by the regulation.
B. Subcategories
In this final rule, the EPA is adding
subcategories for limited-use oil-fired
units and non-continental oil-fired units
and revising the definitions for the coalfired EGU subcategories.
The proposed rule subcategorized
EGUs burning coal into two
subcategories: EGUs designed for coal
≥8,300 Btu/lb and EGUs designed for
virgin coal <8,300 Btu/lb (low rank
virgin coal). We received a number of
comments indicating that the definition
of the low rank virgin coal subcategory
was technically deficient.
Under CAA section 112(d)(1), the
Administrator has the discretion to
‘‘* * * distinguish among classes,
types, and sizes of sources within a
category or subcategory in establishing
* * *’’ standards. The EPA maintains
that, normally, any basis for
subcategorization (i.e., class, type, or
size) must be related to an effect on HAP
emissions that is due to the difference
in class, type, or size of the units. See
76 FR 25036–25037. The EPA believes
it is not reasonable to exercise our
discretion without such a difference
because if sources can achieve the same
level of emissions reductions
notwithstanding a difference in class,
type, or size, the purposes of CAA
section 112 are better served by
requiring a similar level of control for
all such units in the category or
subcategory. See Lignite Energy Council
v. EPA, 198 F. 3d 930, 933 (D.C. Cir.
1999) (‘‘EPA is not required by law to
subcategorize—section 111[b][2] merely
states that ‘the Administrator may
distinguish among classes, types, and
sizes within categories of new sources’’’
(emphasis original)); see also CAA
section 112(d)(1) (containing almost
identical language to CAA section 111,
CAA section 112(d)(1) provides that
‘‘the Administrator may distinguish
among classes, types, and sizes of
sources within a category or subcategory
in establishing [ ] standards * * *’’).
Even if we determine that emissions
characteristics are different for units
that differ in class, type, or size, the
Agency may still decline to
subcategorize if there are compelling
policy justifications that suggest
subcategorization is not appropriate. Id.
When developing the proposed rule,
we examined the EGUs in the top
performing 12 percent of sources for Hg
emissions. We determined that:
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There were no EGUs designed to burn a
nonagglomerating virgin coal having a
calorific value (moist, mineral matter-free
basis) of 19,305 kJ/kg (8,300 Btu/lb) or less
in an EGU with a height-to-depth ratio of
3.82 or greater among the top performing 12
percent of sources for Hg emissions,
indicating a difference in the emissions for
this HAP from these types of units. The
boiler of a coal-fired EGU designed to burn
coal with that heat value is bigger than a
boiler designed to burn coals with higher
heat values to account for the larger volume
of coal that must be combusted to generate
the desired level of electricity. Because the
emissions of Hg are different between these
two subcategories, we are proposing to
establish different Hg emission limits for the
two coal-fired subcategories. For all other
HAP from these two subcategories of coalfired units, the data did not show any
difference in the level of the HAP emissions
and, therefore, we have determined that it is
not reasonable to establish separate
emissions limits for the other HAP. 76 FR
25036–67.
Based on this determination, we
proposed to establish two subcategories
with separate Hg limits. Comments on
the proposed rule indicate that we
correctly identified the EGUs that
should be included in each subcategory,
but the comments also demonstrated
that we made certain incorrect
conclusions that require us to revise the
definitions of our coal-fired EGU
subcategories. The revised definitions
ensure that the EGUs we identified at
proposal as having different Hg
emissions remain in one subcategory.
As stated above, we believed at
proposal that the boiler size was the
cause of the different Hg emissions
characteristics that led us to propose
subcategorization, but many
commenters indicated that it was not
the boiler size but the fact that the EGUs
burned a nonagglomerating virgin coal
having a calorific value (moist, mineral
matter-free basis) of less than 19,305 kJ/
kg (8,300 Btu/lb) (low rank virgin coal)
that causes the disparity in Hg
emissions. Several commenters
indicated that their EGUs were designed
to burn and burned low rank virgin coal
but the units did not meet the height-todepth ratio that EPA proposed. For
example, the height-to-depth ratio of
certain EGUs in this subcategory is in
fact 3.5, not 3.82. Further, there are
other EGUs in this subcategory that are
circulating fluidized bed (CFB)
combustion units which do not meet the
height-to-depth ratio parameters in the
proposed rule, nor are they anything
like the pulverized coal (PC) EGUs we
initially identified as having the 3.82
height-to-depth ratio.
In addition to the comments
concerning EGUs firing this coal, we
received comments from at least two
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commenters indicating that the EPA
should clarify in which subcategory a
unit belongs when it does not burn low
rank virgin coal but is designed to
combust low rank virgin coal and has a
height-to-depth ratio of greater than
3.82. Commenters also indicated that
CFB units that are burning coalrefuse 311 or other nonagglomerating
virgin coal having a calorific value
(moist, mineral matter-free basis) of
19,305 kJ/kg (8,300 Btu/lb) or greater are
‘‘designed to burn’’ any type of coal.
Owners of CFB units that are not firing
low rank virgin coal asked which
subcategory they belong to based on
their ability to burn any type of coal
(including low rank virgin coal) without
modification. These commenters also
indicated that some coal refuse that is
combusted has a heating value less than
8,300 Btu/lb but is not ‘‘virgin coal.’’ It
was unclear to which subcategory they
belonged since the proposed rule did
not in fact require the unit to burn any
specific coal, instead only requiring the
unit be ‘‘designed’’ to burn lower Btu
coal.
Based on the comments received, we
reevaluated the subcategory definitions
because we were concerned that the
definitions we proposed would
improperly categorize a number of the
EGUs in both subcategories. We
concluded that we should not maintain
the proposed definition for ‘‘[u]nits
designed for coal <8,300 Btu/lb’’ and
exclude the CFB units and PC EGUs
with a height-to-depth ratio less than
3.82 that combusted low rank virgin
coal.
We were equally concerned that the
subcategory definitions not be revised in
a manner that would move EGUs that
we believed the data show could
comply with a more stringent standard
into a subcategory with a less stringent
standard because, aside from the type of
EGUs we identified, all other classes,
types, and sizes of EGUs were
represented among the top performing
12 percent for Hg in the ≥8,300 Btu/lb
subcategory. We were particularly
concerned about the CFB units because
other CFB units are well represented
among the best performing EGUs for Hg
in the ≥8,300 Btu/lb subcategory, but the
CFB units burning low rank virgin coal
are not achieving the same levels of Hg
emissions control. Including the best
performing CFB units from the other
subcategory in the low rank virgin coal
subcategory would likely lead to a Hg
standard as stringent as the standard for
311 It is our understanding that no unit combusts
coal-refuse from nonagglomerating virgin coal
having a calorific value (moist, mineral matter-free
basis) of less than 19,305 kJ/kg (8,300 Btu/lb).
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EGUs in the ≥8,300 Btu/lb subcategory
because the CFB units from the other
subcategory would be used to establish
the floor. We believe that result would
be inconsistent with the intent of the
proposed rule. We were also concerned
about the information that some EGUs
that fired low rank virgin coal had a
height-to-depth ratio of 3.5, not 3.82,
and that some EGUs that fired other
ranks of coal had a height-to-depth ratio
greater than 3.82. For these reasons, we
did not revise the definition to include
CFB units and PC EGUs with a heightto-depth ratio greater than 3.5.
After fully considering the available
information, including the comments
received, we have concluded that it is
appropriate to continue to base the
subcategory definitions, at least in part,
on whether the EGUs were designed to
burn and, in fact, did burn low rankvirgin coal, but that it is not appropriate
to continue to use the height-to-depth
ratio criteria because that approach
would potentially exclude EGUs we
identified as having different Hg
emission characteristics and include
EGUs that did not have different
emissions characteristics. We recognize
that some commenters have taken the
position that it is unlawful to
subcategorize based on factors such as
fuel type but nothing in the statute
prohibits such an approach and the case
law supports this approach to the extent
courts have considered
subcategorization based on such factors.
See Sierra Club v. Costle, 657 F. 2d 298,
318–19 (D.C. Cir. 1981) (differing
pollutant content of input material can
justify a different standard based on
subcategorization authority to
‘‘distinguish among classes, types and
sizes within categories of new sources’’).
Furthermore, we believe had Congress
intended to prohibit the EPA from
subcategorizing based on an EGU being
designed to use and using a certain
material input (e.g., fuel) it would have
clearly stated such intent in the CAA.
However, we believe the Agency could
decline to exercise its discretion to
subcategorize even if the potential result
would be the prohibition of the use of
some materials if the circumstances
warranted. We note that even if we did
not subcategorize on the final basis
selected, the Hg emissions standard of
1.2E0 lb/Tbtu for the ‘‘unit designed for
coal ≥8,300 Btu/lb’’ would remain the
same.
We considered basing the subcategory
solely on an EGU being designed to
burn and burning low rank virgin coal.
We decided not to do so because we
were concerned that such a definition
would allow sources to potentially meet
the definition by combusting very small
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amounts of low rank virgin coal. For
example, an EGU on the east coast (or
any other region) that was not designed
to burn and did not routinely burn low
rank virgin coal could import one truck
full of low rank virgin coal and burn a
very small quantity of it periodically to
meet the subcategory definition. To
avoid creating this potential loophole,
we considered other characteristics that
would distinguish EGUs combusting
low rank virgin coal.
We determined that these EGUs are
universally constructed ‘‘at or near’’ a
mine containing low rank virgin coal
because it is not cost-effective to
transport large quantities of such fuel
long distances. Furthermore, we believe
that this subcategory of EGUs are almost
always built at a mine and limited
transportation of the coal is only
required as the mine face moves over
the course of time. Many such EGUs
construct dedicated rail lines, private
roads, or conveyor systems to transport
the coal to the EGU as the mine face
moves. We obtained information from
data acquired to develop the CSAPR
indicating that the longest distance any
EGU firing low rank virgin coal
transports that coal is 40 miles. We
believe that this distance is near the
outer limits for the transport of such
coal, but, even for those EGUs, the EGUs
were constructed closer to a now idle
mine or closer to the working face of a
mine that has now expanded away from
the EGU site. For these reasons, we are
including a requirement that the unit be
constructed and operated at or near a
mine containing the low rank virgin
coal it burns.
We are revising the coal-fired EGU
subcategory definitions as set out in 40
CFR 63.10042.
We believe the revised subcategory
definitions are reasonable for all the
reasons set forth above. The revised
definitions maintain the EGUs we
identified as having different Hg
emissions characteristics in one
subcategory and the definitions prevent
other EGUs that are not firing low rank
virgin coal from being required to
comply only with the less stringent Hg
emission standard.
As discussed in response to
comments, we do not believe that
additional subcategorization of other
coal-fired EGUs is reasonable or
appropriate. All other coal-fired EGUs
that are not designed to burn and are
burning low rank virgin coal are
represented among the best performing
sources for Hg, such that no argument
exists to support that the Hg emissions
from those EGUs are different. In any
case, even if emissions are somewhat
different as some commenters suggest,
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we would decline to exercise our
discretion because the data demonstrate
that the best performing EGUs designed
to burn and burning all other ranks of
coal are able to achieve the MACT level
of control using currently available
controls and other HAP emission
reduction mechanisms (e.g., coal
washing) for the ≥8,300 Btu/lb
subcategory.
A second issue related to
subcategorization concerns noncontinental liquid oil-fired EGUs. At
proposal, the EPA did not have
sufficient emissions data from noncontinental liquid oil-fired EGUs upon
which to base a subcategory and took
comment on the issue. The data have
since been provided in response to the
ICR and we received comments
suggesting that a non-continental
subcategory is appropriate based on the
location of such units, the limited
availability of alternative fuel sources,
and the fact that the emissions
characteristics of such units are distinct
from continental liquid oil-fired EGUs.
The EPA has evaluated the data and
comments and we agree that a
subcategory is warranted based for the
reasons suggested by the commenters.
Therefore, the Agency is finalizing the
liquid oil-fired EGU subcategories of
‘‘continental’’ and ‘‘non-continental.’’
Lastly, the EPA did not have
sufficient information on limited-use
liquid oil-fired EGUs upon which to
base a subcategory at proposal because
some sources required to test under the
ICR did not submit the data until after
proposal. We took comment on whether
a limited-use subcategory was
warranted. Commenters indicated that
their units were a different class and
type of units because many of them
were only called to service to address
reliability issues associated with, for
example, natural gas curtailments. The
commenters further indicated that their
units are different because of the
generally infrequent use and the
sporadic, and at times frequent, start-up
and shutdown periods (e.g., they are
often only required to run for a couple
of hours). These factors would lead to
differences in the emissions
characteristics for these units such that
a numeric standard based on base load
units would not likely be achievable
during the very limited times that these
limited use oil-fired units operate.
Based on comments received and our
own analysis, we are finalizing a
subcategory for limited-use liquid oilfired EGUs as discussed further
elsewhere in this preamble.
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C. Emission Limits
The proposed rule included
numerical emission limits for PM, Hg,
HCl, HF, SO2, total HAP metals, and
individual HAP metals, depending on
the subcategory and specific situation.
These proposed limits resulted from
calculations of MACT floors using
information and data available to the
Agency prior to proposal, as required by
CAA section 112. Based on information
and data received during the comment
period, we have made data and
calculation corrections where necessary
and then re-ranked the best performing
units in the MACT floor pools. Based on
the new ranking, a limited number of
the emission limits in the final rule have
changed from those proposed.
In addition to adjustments to the
emission limits themselves, we are
finalizing several other changes to the
emission standards that will simplify
and improve compliance for sources
without compromising the toxics
reductions achieved. One key change, as
discussed elsewhere in this notice, is
that we have changed the surrogate for
non-mercury metallic HAP from total
particulate matter (PM) to filterable PM
for coal-fired and solid oil-derived
EGUs. This change is based on
information provided in comments and
our own conclusion that measurement
of filterable PM provided assurance of
equivalent HAP emissions control. Most
of the non-mercury metal HAP, for
which PM is a surrogate, are filterable
PM and the one that is not (Se) is well
controlled by the limit on acid gases.
Using filterable PM as the surrogate will
allow us to use continuous PM
monitoring systems, which measure
filterable (but not total) PM, thereby
providing a more continuous measure of
compliance.
For liquid oil-fired EGUs, based on
comments received and corrections
made to the data submitted, we have
added a filterable PM limit in the final
rule as an alternative equivalent
standard for the total metal-HAP limit in
the proposed rule. In addition, as
discussed elsewhere in this notice, we
have added measurement of the
moisture content of the oil (with a 1
percent limit) as an alternate
compliance assurance measure for
liquid oil-fired EGUs for determining
compliance with the HCl and HF limits.
Direct measurement of HCl and HF
remains a compliance demonstration
method in the final rule. Finally, as
discussed in section VI.D of this notice,
the final work practice standard
consisting of burner tune-ups, much like
those required for organic HAP control,
for those limited-use liquid oil-fired
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EGUs whose annual capacity factor is
less than 8 percent.
D. Work Practice Standards for Organic
HAP Emissions
As noted earlier in section V.D., the
final rule includes a work practice
standard for organic HAP, including
dioxins and furans, applicable to all
EGUs. As noted in section V.D. above,
the majority of emissions of these
pollutants are below the detection levels
of EPA test methods and, therefore, are
impractical to measure. The work
practice standard, described below, is a
practical approach to ensuring that
equipment is maintained and run so as
to minimize emissions of dioxins and
furans, and we expect it to be more
effective than establishing a numeric
standard that cannot reliably be
measured or monitored. The work
practice also applies to the limited-use
liquid oil-fired subcategory included in
the final rule.
The work practice involves
maintaining and inspecting the burners
and associated combustion controls (as
applicable), tuning the specific burner
type to optimize combustion, obtaining
and recording CO and NOX values
before and after the burner adjustments,
keeping records of activity and
measurements, and submitting a report
for each tune-up conducted. In Table 3
of the final regulation, we have clarified
that this refers to performance tune-ups,
not tests, and have addressed the
frequency requirement as discussed in
response to comments about the
appropriateness of the 18-month
frequency. The provisions of 40 CFR
63.10006(h)(i) refer to 40 CFR
63.10021(e) for the specific steps
required to be part of the periodic tuneup. We have also adjusted the language
in the final rule to recognize the value
of automated boiler optimization tools
such as neural network systems.
Under the final rule, the tune-up must
be conducted at each planned major
outage and in no event less frequently
than every 36 calendar months, with an
exception that if the unit employs a
neural-network system for combustion
optimization during hours of normal
unit operation, the required frequency is
a minimum of once every 4 years (48
calendar months). Initial compliance
with the work practice standard of
maintaining burners must occur within
180 days of the compliance date of the
rule. The initial compliance
demonstration for the work practice
standard of conducting a tune-up may
occur prior to the compliance date of
the rule, but must occur no later than 42
months (36 months plus 180 days) from
the compliance date of the rule or, in
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the case of units employing neural
network combustion controls, 54
months (48 months plus 180 days). If
the tune-up occurs prior to the
compliance date of the rule, you must
maintain adequate records to show that
the tune-up met the requirements of this
standard.
We have made a number of specific
changes to address what to do for
repairs that may require longer term
corrective actions, additional methods
for evaluating combustion effectiveness,
and clarification on procedures for
recording CO and NOX information.
There were specific comments that
opposed the reference to manufacturer
specifications, if available. We retained
this language in the final rule, but note
that these specifications apply only to
the extent applicable. Specifically, if
manufacturer specifications only
address equipment or conditions that
are no longer present given current
boiler operations, then those
specifications are not applicable and
other combustion engineering best
practice procedures for that burner type
would apply. We have also clarified that
portable emission monitoring
equipment may be used to collect the
required emissions optimization data
regarding pre- and post-tune-up CO and
NOX emission levels.
E. Requirements During Startup,
Shutdown, and Malfunction
We proposed numerical emission
standards that would apply at all times,
including during periods of startup,
shutdown, and malfunction. Although
at proposal we stated that we were not
setting a different standard for startup
and shutdown, we did propose different
standards for startup and shutdown by
our inclusion of the default values
described below, which applied only
during startup and shutdown.
Specifically, we stated:
To appropriately determine emissions
during startup and shutdown and account for
those emissions in assessing compliance with
the proposed emission standards, we propose
use of a default diluent value of 10.0 percent
O2 or the corresponding fuel specific CO2
concentration for calculating emissions in
units of lb/MMBtu or lb/TBtu during startup
or shutdown periods. For calculating
emissions in units of lb/MWh or lb/GWh, we
propose source owners use an electrical
production rate of 5 percent of rated capacity
during periods of startup or shutdown. We
recognize that there are other approaches for
determining emissions during periods of
startup and shutdown, and we request
comment on those approaches. We further
solicit comment on the proposed approach
described above and whether the values we
are proposing are appropriate.
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We proposed application of the
respective emission limits during
periods of startup and shutdown and
use of default values to calculate the
emission limits. The standards that
apply at all times other than startup and
shutdown are production-based limits,
which is why we proposed the default
values. The default values were meant
to account for the fact that during
startup and shutdown events,
production (in this case the generation
of electricity) is by definition
nonexistent. Thus, in effect, we
proposed a separate standard to apply
during startup and shutdown.
We received a variety of comments on
the proposed standards that would
apply during startup and shutdown.
Many commenters pointed to the lack of
data in the record concerning emissions
that occur during periods of startup and
shutdown. They further asserted that
emissions during these periods can be
highly variable in light of the sequence
of events that occurs during the startup
and shutdown of an EGU. Although a
number of commenters supported the
use of the diluent factor approach,
including the default 5 percent of rated
capacity, during startup/shutdown
periods, other commenters questioned
the feasibility of collecting additional
data during such periods and had
concerns regarding the reliability of
measurements obtained from EGUs
during such periods.
In response to the Agency’s ICR to the
utility industry, seven owners or
operators indicated that they provided
startup and shutdown data for their
EGUs. These data were submitted in
response to the requirement in the ICR
to provide all available data from the 5
years prior to the date the ICR was
issued. Of these data, there were almost
no HAP data for startup and shutdown
periods and almost all of the data failed
to meet our data quality
requirements.312 Thus, we do not have
312 In response to the ICR, we also received SO
2
CEMS data and the Agency had additional SO2
CEMS data available through the CAMD ARP
database. We are not able to identify specific
periods of start-up and shutdown in either the ICR
CEMS data or the CAMD ARP data, and the ICR
respondents do not indicate that the ICR data
includes periods of startup and shutdown. We set
the emission limits for SO2 and HCl using the data
provided to the EPA from the 2010 ICR, not the
CAMD data, since those data were taken
concurrently under the same specified operating
conditions using the same fuel. We used the SO2
CEMS data that was submitted in response to the
ICR by converting it to single point data to correlate
to the data from units that did not provide CEMS
data from the relevant testing period. The emissions
limits for the NESHAP incorporated variability by
applying the 99 percent UPL to the average
emissions developed from the stack test data and
SO2 CEMS data that was converted to stack test
data. Thus, we did not have data on which to
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sufficient data on emissions that occur
during startup and shutdown on which
to set emission standards. We are
therefore establishing work practice
standards rather than numeric
emissions standards for periods of
startup and shutdown in the final rule.
Before we describe those work practices,
we first address what constitutes startup
and shutdown.
Several commenters had an expansive
view of what constitutes startup and
shutdown. We disagree with these
commenters that asserted that periods of
‘‘load swings’’ should be considered
‘‘startup’’ or ‘‘shutdown,’’ as they are
generally routine, normal operations
with production (i.e., generation of
electricity) taking place. We maintain
that the standards as promulgated
account for any variability in emissions
that may occur during these periods
over a 30-day averaging period, and
commenters have provided no data that
cause us to doubt that determination.
We have included definitions of startup
and shutdown in the final rule that are
consistent with the definitions in the
proposed rule. At proposal, we defined
startup as the setting in operation of an
affected source or portion of an affected
source for any purpose, and shutdown
as the cessation of operation of an
affected source or portion of an affected
source for any purpose.
Commenters sought more clarity
regarding the meaning of these terms as
applied to EGUs, so we are revising the
definitions in the final rule as set out in
40 CFR 63.10042.
These interpretations are tailored for
EGUs and are consistent with the
definitions of ‘‘startup’’ and
‘‘shutdown’’ contained in the 40 CFR
part 63, subpart A General Provisions.
We believe these revised definitions
address the comments and are rational
based on the fact that EGUs function to
provide electricity primarily for sale to
the grid but also at times for use on-site;
therefore, EGUs should be considered to
be operating normally at all times
electricity is generated. We further
believe these revised definitions address
what some commenters describe as
‘‘warm’’ and ‘‘hot’’ startups as long as
the EGU is shutdown (i.e., no fuel fired
and no electricity generation) prior to
the ‘‘warm’’ or ‘‘hot’’ startup period.
establish an SO2 standard during periods of startup
and shutdown and the numeric standards do not
apply to those periods in the final rule. In contrast,
the NSPS for SO2 is applicable during periods of
startup and shutdown since the long term CAMD
ARP CEMS data were used to determine the average
performance of the best demonstrated technology.
Those long term data were assumed to incorporate
process variability including that associated with
fuel and process/operational changes and periods of
startup and shutdown.
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As for the work practices, in this final
rule, the EPA is requiring sources to
operate using either natural gas or
distillate oil for ignition during startup.
The EPA also is requiring sources to
vent emissions to the main stack(s) and
operate all control devices necessary to
meet the normal operating standards
under this final rule (with the exception
of dry scrubbers and SCRs) when coal,
solid oil-derived fuel, or residual oil is
fired in the boiler during startup or
shutdown. It is the responsibility of the
operators of EGUs to start their dry
scrubber and SCR systems appropriately
to comply with relevant standards
applicable during normal operation.
The EPA carefully considered fuels
and potential operational constraints of
air pollution control devices (APCDs)
when designing its work practices for
periods of startup and shutdown. The
EPA notes that there is no technical
barrier to burning natural gas or
distillate oil for longer portions of
startup or shutdown periods, if needed,
at a boiler, and the HAP emission
reduction benefits warrant additional
utilization of such fuels until the
temperature and stack emissions
pressure is sufficient to engage the
APCDs. The EPA is aware that SCR
systems with ammonia injection need to
be operated within a prescribed and
relatively narrow temperature window
to provide NOX reductions. Further, the
EPA is aware that dry scrubbers also
need to be operated close to flue gas
saturation temperature. Because these
devices have specific temperature
requirements for proper operation, the
EPA notes in its work practices that it
is the responsibility of the operators of
EGUs to start their SCR and dry
scrubber systems appropriately to
comply with relevant standards
applicable during normal operation.
Some commenters have asserted that
firing of fuel oil during periods of
startup and shutdown constrains
operation of PM controls (ESPs and
baghouses) because under cooler
conditions, acids and tars can condense
on surfaces in these controls. The
commenters assert that such
condensation can cause detrimental
impacts on hardware and operation of
these controls, and could cause safety
concerns. The EPA understands that
concerns with acidic and tarry deposits
are related to firing of heavy (residual)
oil and not distillate oil. Accordingly,
with residual fuel oil firing, site-specific
flue gas temperature and oxygen (O2)
concentration thresholds may be
applicable to minimize condensation of
acids and tars and thereby minimize any
potential for detrimental impacts on
hardware and any safety concerns.
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However, the EPA notes that its work
practice requirements provide flexibility
to the operator to take appropriate sitespecific remedial measures, if needed.
The EPA further notes that boilers have
several options to prevent detrimental
impacts by: (1) Using startup fuels,
natural gas or distillate oil, until
appropriate flue gas conditions have
been reached and then fire residual oil;
(2) pre-coating the PM control
surfaces 313 with an alkaline powder
(e.g., limestone); (3) installing
chemically resistant bags 314 in
baghouses if applicable; and (4) using
low-sulfur oils. The EPA also notes that
currently the industry has many
operational residual oil-fired boilers that
are started up with either natural gas or
distillate fuel oil. At these boilers, the
transition from the startup fuel,
distillate oil or natural gas, to residual
oil is already being practiced without
unacceptable impacts on APCDs
including PM controls, which are
operated to meet applicable opacity
limits. Based on this experience and the
options described above, those boilers
where residual oil is used for either a
part of the startup period, or as the main
fuel, will also be able to operate their
PM controls to meet the work practice
requirements of the rule. Note that coal
firing is done at high enough
temperatures that concerns with
condensation are not relevant. None of
the commenters have specifically
commented on this aspect of coal firing.
The EPA is not aware of any
operational constraints applicable to
operation of wet scrubbers during
startup that could cause detrimental
impacts on wet scrubber hardware and
safety concerns and none of the
commenters have commented on this
aspect of wet scrubber operation.
Finally, the EPA notes that dry
sorbent injection (DSI) can be applied
across a very broad temperature range
and will be engaged when residual oil
or coal is fired in a boiler to comply
with HCl requirements. Again, no
comments have been received on this
aspect of DSI operation.
This final rule requires work practice
standards for emissions during startup
and shutdown, and the rule requires
sources to measure and report their
emissions at all times, including periods
of startup and shutdown, when
continuous monitoring is used to
demonstrate compliance. Data collected
313 Coal Power, May 1, 2007: https://
www.coalpowermag.com/plant_design/Coal-PlantO-and-M-River-Locks-and-Barges-Are-an-AgingWorkforce-Too 36.html.
314 Neundorfer: Lesson #r, p.4–7, Table 4–1:
https://www.neundorfer.com/FileUploads/CMSFiles/
Fabric%20Filter%2OMaterial [0].pdf.
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under this final rule will provide the
EPA with information to more fully
analyze this issue and address it during
the 8-year review established under
CAA section 112.
We now address malfunctions. In
contrast to the exclusion of startup and
shutdown period emissions from 30boiler operating day rolling average
emissions, the final rule requires
inclusion of emissions during periods of
source or APCD malfunction. We have
concluded that when combined with the
availability of an affirmative defense as
described below, this is an appropriate
and practical approach.
As mentioned earlier, periods of
startup, normal operations, and
shutdown are all predictable and
routine aspects of a source’s operations.
However, by contrast, malfunction is
defined as a ‘‘sudden, infrequent, and
not reasonably preventable failure of air
pollution control and monitoring
equipment, process equipment or a
process to operate in a normal or usual
manner * * *’’ (40 CFR 63.2). The EPA
has determined that CAA section 112
does not require that emissions that
occur during periods of malfunction be
factored into development of CAA
section 112 standards. Under CAA
section 112, emissions standards for
new sources must be no less stringent
than the level ‘‘achieved’’ by the best
controlled similar source and for
existing sources generally must be no
less stringent than the average emission
limitation ‘‘achieved’’ by the best
performing 12 percent of sources in the
category. There is nothing in CAA
section 112 that directs the Agency to
consider malfunctions in determining
the level ‘‘achieved’’ by the best
performing or best controlled sources
when setting emission standards.
Moreover, while the EPA accounts for
variability in setting emissions
standards consistent with the CAA
section 112 case law, nothing in that
case law requires the Agency to
consider malfunctions as part of that
analysis. Clean Air Act section 112 uses
the concept of ‘‘best controlled’’ and
‘‘best performing’’ unit in defining the
level of stringency that CAA section 112
performance standards must meet.
Applying the concept of ‘‘best
controlled’’ or ‘‘best performing’’ to a
unit that is malfunctioning presents
significant difficulties, as malfunctions
are sudden and unexpected events.
Further, accounting for malfunctions
would be difficult, if not impossible,
given the myriad different types of
malfunctions that can occur across all
sources in the category and given the
difficulties associated with predicting or
accounting for the frequency, degree,
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and duration of various malfunctions
that might occur. As such, the
performance of units that are
malfunctioning is not ‘‘reasonably’’
foreseeable. See, e.g., Sierra Club v.
EPA, 167 F. 3d 658, 662 (D.C. Cir. 1999)
(The EPA typically has wide latitude in
determining the extent of data-gathering
necessary to solve a problem. We
generally defer to an agency’s decision
to proceed on the basis of imperfect
scientific information, rather than to
‘‘invest the resources to conduct the
perfect study.’’). See also, Weyerhaeuser
v. Costle, 590 F.2d 1011, 1058 (D.C. Cir.
1978) (‘‘In the nature of things, no
general limit, individual permit, or even
any upset provision can anticipate all
upset situations. After a certain point,
the transgression of regulatory limits
caused by ‘uncontrollable acts of third
parties,’ such as strikes, sabotage,
operator intoxication or insanity, and a
variety of other eventualities, must be a
matter for the administrative exercise of
case-by-case enforcement discretion, not
for specification in advance by
regulation.’’). In addition, the goal of a
best controlled or best performing
source is to operate in such a way as to
avoid malfunctions of the source and
accounting for malfunctions could lead
to standards that are significantly less
stringent than levels that are achieved
by a well-performing nonmalfunctioning source. The EPA’s
approach to malfunctions is consistent
with CAA section 112, and we believe
it is a reasonable interpretation of the
statute. This approach to malfunctions
has been used consistently in CAA
section 112 and CAA section 129
rulemaking actions since the D.C.
Circuit’s decision in Sierra Club v. EPA,
551 F.3d 1019 (D.C. Cir. 2008) vacated
the SSM exemption contained in CFR
63.6(f)(1) and 40 CFR 63.6(h)(1). (See,
e.g., National Emission Standards for
Hazardous Air Pollutants From the
Portland Cement Manufacturing
Industry and Standards of Performance
for Portland Cement Plants, 75 FR 54970
(September 9, 2010); Standards of
Performance for New Stationary Sources
and Emission Guidelines for Existing
Sources: Sewage Sludge Incineration
Units; Final Rule, 76 FR 15372 (March
21, 2011).
In the event that a source fails to
comply with the applicable CAA section
112(d) standards as a result of a
malfunction event, the EPA would
determine an appropriate response
based on, among other things, the good
faith efforts of the source to minimize
emissions during malfunction periods,
including preventative and corrective
actions, as well as root cause analyses
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to ascertain and rectify excess
emissions. The EPA would also
consider whether the source’s failure to
comply with the CAA section 112(d)
standard was, in fact, ‘‘sudden,
infrequent, not reasonably preventable’’
and was not instead ‘‘caused in part by
poor maintenance or careless
operation.’’ 40 CFR 63.2 (definition of
malfunction).
Finally, the EPA recognizes that even
equipment that is properly designed and
maintained can sometimes fail and that
such failure can sometimes cause an
exceedance of the relevant emission
standard. (See, e.g., State
Implementation Plans: Policy Regarding
Excessive Emissions During
Malfunctions, Startup, and Shutdown
(Sept. 20, 1999); Policy on Excess
Emissions During Startup, Shutdown,
Maintenance, and Malfunctions (Feb.
15, 1983)). The EPA is therefore adding
to the final rule an affirmative defense
to civil penalties for exceedances of
emission limits that are caused by
malfunctions. See 40 CFR 63.10042
(defining ‘‘affirmative defense’’ to mean,
in the context of an enforcement
proceeding, a response or defense put
forward by a defendant, regarding
which the defendant has the burden of
proof, and the merits of which are
independently and objectively
evaluated in a judicial or administrative
proceeding). We also have added other
regulatory provisions to specify the
elements that are necessary to establish
this affirmative defense; the source must
prove by a preponderance of the
evidence that it has met all of the
elements set forth in 63.10001. (See 40
CFR 22.24). The criteria ensure that the
affirmative defense is available only
where the event that causes an
exceedance of the emission limit meets
the narrow definition of malfunction in
40 CFR 63.2 (i.e., sudden, infrequent,
not reasonable preventable and not
caused by poor maintenance and or
careless operation). For example, to
assert the affirmative defense
successfully, the source must prove by
a preponderance of the evidence that
excess emissions ‘‘[w]ere caused by a
sudden, infrequent, and unavoidable
failure of air pollution control and
monitoring equipment, process
equipment, or a process to operate in a
normal or usual manner * * *’’ The
criteria also are designed to ensure that
steps are taken to correct the
malfunction, to minimize emissions in
accordance with section 63.10001 and
to prevent future malfunctions. For
example, the source must prove by a
preponderance of the evidence that
‘‘[r]epairs were made as expeditiously as
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possible when the applicable emission
limitations were being exceeded * * *’’
and that ‘‘[a]ll possible steps were taken
to minimize the impact of the excess
emissions on ambient air quality, the
environment and human health * * *’’
In any judicial or administrative
proceeding, the Administrator may
challenge the assertion of the affirmative
defense and, if the respondent has not
met its burden of proving all of the
requirements in the affirmative defense,
appropriate penalties may be assessed
in accordance with CAA section 113
(see also 40 CFR 22.27).
The EPA is including an affirmative
defense in the final rule as we have in
other recent MACT rules so as to
balance the tension, inherent in many
types of air regulation, to ensure
adequate compliance while
simultaneously recognizing that despite
the most diligent of efforts, emission
limits may be exceeded under
circumstances beyond the control of the
source. The EPA must establish
emission standards that ‘‘limit the
quantity, rate, or concentration of
emissions of air pollutants on a
continuous basis.’’ 42 U.S.C. 7602(k)
(defining ‘‘emission limitation and
emission standard’’). See generally
Sierra Club v. EPA, 551 F.3d 1019, 1021
(D.C. Cir. 2008). Thus, the EPA is
required to ensure that section 112
emissions limitations are continuous.
The affirmative defense for malfunction
events meets this requirement by
ensuring that even where there is a
malfunction, the emission limitation is
still enforceable through injunctive
relief. While ‘‘continuous’’ limitations,
on the one hand, are required, there is
also case law indicating that in some
situations it is appropriate for the EPA
to account for the practical realities of
technology. For example, in Essex
Chemical v. Ruckelshaus, 486 F.2d 427,
433 (D.C. Cir. 1973), the D.C. Circuit
acknowledged that in setting standards
under CAA section 111 ‘‘variant
provisions’’ such as provisions allowing
for upsets during startup, shutdown and
equipment malfunction ‘‘appear
necessary to preserve the reasonableness
of the standards as a whole and that the
record does not support the ‘never to be
exceeded’ standard currently in force.’’
See also, Portland Cement Association
v. Ruckelshaus, 486 F.2d 375 (D.C. Cir.
1973). Though intervening case law
such as Sierra Club v. EPA and the CAA
1977 amendments calls into question
the relevance of these cases today, they
support the EPA’s view that a system
that incorporates some level of
flexibility is reasonable. The affirmative
defense simply provides for a defense to
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9383
civil penalties for excess emissions that
are proven to be beyond the control of
the source. By incorporating an
affirmative defense, the EPA has
formalized its approach to upset events.
In a Clean Water Act setting, the Ninth
Circuit required this type of formalized
approach when regulating ‘‘upsets
beyond the control of the permit
holder.’’ Marathon Oil Co. v. EPA, 564
F.2d 1253, 1272–73 (9th Cir. 1977). But
see, Weyerhaeuser Co. v. Costle, 590
F.2d 1011, 1057–58 (D.C. Cir. 1978)
(holding that an informal approach is
adequate). The affirmative defense
provisions give the EPA the flexibility to
ensure both that its emission limitations
are ‘‘continuous’’ as required by 42
U.S.C. 7602(k), and account for
unplanned upsets and thus support the
reasonableness of the standard as a
whole.
F. Testing and Initial Compliance
We have carefully evaluated the wideranging comments on testing,
continuous monitoring, and other
provisions regarding initial compliance
demonstrations, and we have made
adjustments intended to help streamline
implementation while still ensuring
adequate demonstration of compliance
with the emission limits and other
standards established under this final
rule. The significant changes include:
1. No Fuel Analysis Requirements
Apart from an alternative that allows
you to analyze fuel moisture for liquid
oil-fired EGUs rather than measuring
HCl and HF, the final rule does not
include any of the fuel analysis
requirements that were in the proposed
rule, either as part of initial compliance
demonstrations or ongoing compliance
demonstrations. In reviewing the results
of the fuel analyses and the expected
range of results that would be received
from laboratories conducting the
proposed analyses, we determined that
too many results would be returned as
‘‘below detection level’’ and, thus,
provide little information to assist with
rule implementation and compliance
oversight. Given the costs and efforts
involved, we determined that the
proposed fuel analysis requirements
would not be an effective compliance
monitoring tool for this final rule.
2. Clarification of Testing
We have clarified that where options
for emission limits apply (such as
filterable PM versus non-mercury HAP
metals, or SO2 versus HCl), you need
only perform stack testing to
demonstrate compliance with the
selected emission limit. For example, if
you elect to meet the individual non-
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mercury HAP metals standards, you
must conduct the Method 29 test for the
metals, and you do not have to conduct
a Method 5 test for PM.
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3. Low Emitting EGU Qualification
We have significantly modified the
proposed requirements to qualify as a
LEE unit for a pollutant other than Hg
based on an initial performance test.
Under the proposed rule, the operating
limit monitoring provided additional
assurance of compliance for a source
qualified for non-mercury LEE status
based on an initial compliance
demonstration. Under the final rule, to
qualify for LEE status for pollutants
other than Hg, a unit must meet the LEE
criteria for a series of performance tests
over a 3-year period to demonstrate that
the unit continues to perform well
below the standard for which the source
has obtained LEE status.
G. Continuous Compliance
The most significant changes to the
testing and monitoring requirements
involve the procedures for
demonstrating continuous compliance.
The proposed rule contained different
options involving CEMS, periodic stack
tests, fuel analysis, and various PM and
control device operating limits. The
final rule greatly simplifies the
requirements and provides two basic
approaches for most situations: use of
continuous monitoring (either CEMS or
PM continuous parametric monitoring
system, CPMS) or periodic quarterly
testing. The final rule does not contain
the proposed fuel analysis requirements.
For periodic testing, the proposed rule
required testing every month or every 2
months. For those EGU owners or
operators who choose to use emissions
testing to demonstrate compliance, the
final rule requires quarterly filterable
PM or non-mercury metals HAP,
whether individual or total metals,
testing for coal- and liquid oil-fired
units. The rule requires quarterly HCl
testing for coal-fired units and quarterly
HCl and HF testing, along with sitespecific monitoring for liquid oil-fired
units to ensure compliance with the HCl
and HF standards. The final rule also
has a separate compliance
demonstration for those liquid oil-fired
EGUs that have an annual capacity
factor of less than 8 percent (emission
limits do not apply, just the tune-up
work practice standard). For those EGU
owners or operators who choose to use
emissions testing to demonstrate
compliance, the final rule requires
quarterly filterable PM or non-mercury
metals HAP, whether individual or total
metals, testing for coal- and liquid oilfired units; quarterly HCl testing for
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coal-fired units and quarterly HCl and
HF testing, along with site-specific
parameter monitoring for liquid oil-fired
units to ensure compliance with the HCl
and HF standards.
The continuous monitoring options
remain generally intact from the
proposed rule, with relatively minor
clarifications concerning calculation of
30-boiler operating day averages and QA
requirements.
The final rule eliminates all operating
limits for PM except for the use of a PM
CPMS. For the PM CPMS, the final rule
clarifies procedures for setting this
operating limit and how it is distinct
from the PM emission limit. The PM
CPMS will not be correlated as a PM
CEMS under PS 11 and will produce
data in terms of a signal you define.
That signal could be milliamps, stack
concentration, or other output signal
instead of PM emissions in units of the
standard. The operating limit will be set
using the highest hourly average
obtained from the PM CPMS during the
performance test. Compliance with the
limit is based on a 30-boiler operating
day rolling average basis. However, the
final rule also does provide for the use
of a PM CEMS to determine compliance
with the filterable PM emission limit if
the source elects to use this approach.
The EPA believes that some sources
may be interested in adopting this direct
approach, and so has included that
option in the final rule. If this approach
is selected, the PM CEMS is used as the
direct method of compliance and no
additional testing is required other than
tests that are required as part of the QA
requirements in PS 11 and Procedure 2.
To use this option, the source must elect
to meet the filterable PM standard, and
not one of the HAP metals standards.
Apart from the operating limit for sitespecific monitoring associated with
liquid oil-fired EGUs, we removed the
other operating limits for control
devices based on a review of the
comments, after considering other
programs in place to ensure proper
operations of controls at EGUs. Those
other programs include compliance
assurance monitoring under part 64,
part 70, and New Source Review permit
conditions, and other SIP and NSPS
requirements for operating and
maintaining equipment in accordance
with good air pollution control
practices. Those requirements, in
combination with the CEMS, PM CPMS,
and frequent periodic testing provisions
under the final rule, will enhance the
monitoring of continuous compliance
with the requirements of this rule.
Because the EPA is concerned that
there will be little or no monitoring in
these underlying applicable
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requirements for acid gases at liquid oilfired EGUs, the final rule requires a sitespecific monitoring plan for those units
in this subcategory that demonstrate
compliance with the HCl and HF
standards through quarterly
performance tests. With the exception
for limited-use liquid oil-fired EGUs and
other monitoring options available (such
as fuel moisture monitoring or HCl/HF
CEMS), the EPA believes this provision
will apply to few units. The owner or
operator will submit the site-specific
plan to identify appropriate parameters
that ensure that the operations of the
unit critical to meeting the HCl/HF
emission limits remain consistent with
conditions during performance testing.
This will be approved similarly to an
alternative monitoring request. The plan
should include the parameters,
monitoring approach, QA/QC elements,
and data reduction (including averaging
period) elements. Like the PM CPMS
operating limit, the operating limit for
acid gas control devices on liquid oilfired EGUs will be set using the highest
hourly average obtained during the HCl
and HF performance tests. Compliance
with the limit is based on a 30-boiler
operating day rolling average basis.
Finally, we have changed the
continuous compliance requirements for
the performance tune-up work practice
standard since the proposal. Our intent
was that this work practice standard
could be performed in conjunction with
routine maintenance operations at a
facility and be a logical extension of
routine best practices for boiler
inspection and optimization. Based on
the comments received, we have
reduced the required frequency for this
inspection to every 3 years and
provided incentives for neural network
combustion management and
optimization practices by providing a
longer interval of 4 years between
inspections when such systems are in
use at a given EGU.
H. Emissions Averaging
We are finalizing that owners and
operators of existing affected sources
may demonstrate compliance by
emissions averaging for existing EGUs
that are located at the same facility that
are within a single subcategory and that
rely on emissions testing as the
compliance demonstration method. In
response to our request for comments on
the suitability of emissions averaging
and need for a discount factor, we
received a range of suggestions,
including requests for clarification
regarding eligibility, points for and
against the need for a discount factor,
and suggestions to ease implementation.
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As we noted at proposal, part of the
EPA’s general policy of encouraging the
use of flexible compliance approaches
where they can be properly monitored
and enforced is to include emissions
averaging. Emissions averaging can
provide sources the flexibility to comply
in the least costly manner while still
maintaining a regulation that is
workable and enforceable. Emissions
averaging would not be applicable to
new affected sources and could only be
used between EGUs in the same
subcategory at a particular facility. Also,
owners or operators of existing sources
subject to the EGU NSPS (40 CFR part
60, subparts D and Da) would be
required to continue to meet the PM
emission standard of that NSPS
regardless of whether or not they are
using emissions averaging (i.e., an EGU
subject to 40 CFR part 60, subpart D or
Da must meet its applicable NSPS
filterable PM emission limit even if it is
included in a 40 CFR part 63, subpart
UUUUU, emissions averaging group for
filterable PM).
Emissions averaging allows owners
and operators of a facility that includes
existing EGUs within a subcategory to
demonstrate that the source complies
with the proposed emission limits by
averaging the emissions from an
individual affected EGU that is emitting
above the proposed emission limits with
other affected EGUs at the same facility
that are emitting below the proposed
emission limits and that are within the
same subcategory. Although some
commenters note that the MACT limits
are low, based on the data available to
the Agency, we believe that dozens of
existing EGUs are achieving all of the
limits and, thus, emissions averaging is
a possible approach.
The final rule includes an emissions
averaging compliance alternative
because emissions averaging 315
represents an equivalent, more flexible,
and less costly alternative to controlling
certain emission points to MACT levels.
We have concluded that averaging in
the proposed rule could be
implemented and that it would not
lessen the stringency of the MACT floor
limits and would provide flexibility in
compliance, cost and energy savings to
owners and operators. We also
recognize that we must ensure that any
emissions averaging option can be
implemented and enforced, will be clear
to sources, and most importantly, will
be no less stringent than unit-by-unit
315 As long as required emission rates are
designed to account for factors such as changes in
averaging times.
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implementation of the MACT floor
limits.
In the final rule, the EPA is providing
that sources may average emissions
from existing EGUs at the same facility
and within the same subcategory.
Further, for Hg emissions only from
existing EGUs within the same
subcategory, such EGUs in an emissions
averaging plan may use an alternate
compliance approach consisting of a 90boiler operating day rolling average
emission limit of 1.0 lb/TBtu or 1.1E–2
lb/GWh.
In the memo entitled ‘‘The Impact of
Emission Averaging Time on the
Stringency of an Emission Standard’’ in
the docket, we have illustrated why a
longer-term average results in a lower
limit. In essence, longer-term averages
allow particularly high (or low)
measurements to be averaged with many
more measurements closer to the mean.
This results in the highest averages from
a longer-term averaging period (e.g., 90
days) being lower than the highest
averages in a shorter term averaging
period (e.g., 30 days).
We have illustrated this concept by
taking Hg CEMS data and calculating
rolling 30-day averages and rolling 90day averages. The 30-day averages have
greater variability and, thus, higher
peaks and valleys. The 90-day average
has less variability; therefore, the same
unit is able to meet a tighter 90-day
limit.
The EPA is providing this alternate
90-day rolling average compliance
approach for Hg only. A 90-day rolling
average is appropriate for Hg, and only
for Hg, because the health and
environmental impacts associated with
Hg are related to environmental loading
rather than shorter term inhalation or
other acute exposure, as is the case with
HCl and PM. We believe that this
alternative compliance approach will
provide at least the same level of
environmental protection while
allowing companies greater flexibility to
use emissions averaging. For example,
such an approach would allow for the
averaging of an infrequently operated
unit that is operating slightly above the
standard with a more frequently
operated unit that is operating below the
standard in the instances when the more
frequently operated unit is in a multiday or multi-week maintenance outage.
The EPA has concluded that it is
permissible to establish within a
NESHAP a unified compliance regimen
that permits averaging within the same
facility across individual existing EGUs
subject to the same standards under
certain conditions. As mentioned
earlier, individual EGUs within an
emissions averaging group would be
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allowed to have emissions greater than,
less than, or equivalent with the
emissions limit for their subcategory,
provided that the average emissions
comprised from individual EGU
emissions do not exceed the emissions
limit for their subcategory. Averaging
across affected units is permitted only if
it can be demonstrated that the total
quantity of any particular HAP that may
be emitted by that portion of a
contiguous major source that is subject
to the same standards in the NESHAP
will not be greater under the averaging
mechanism than it could be if each
individual affected EGU in the
subcategory complied separately with
the applicable standard. Under this test,
the practical outcome of averaging is
equivalent to compliance with the
MACT floor limits by each discrete
EGU, and the statutory requirement that
the MACT standard reflect the
maximum achievable emissions
reductions is, therefore, fully
effectuated.
As noted in the proposal preamble, in
past rulemakings, the EPA has generally
imposed certain limits on the scope and
nature of emissions averaging programs.
These limits include: (1) No averaging
between different types of pollutants; (2)
No averaging between sources that are
not part of the same affected source; (3)
No averaging between individual
sources within a single major source if
the individual sources are not subject to
the same NESHAP; and (4) No averaging
between existing sources and new
sources.
The final rule fully satisfies each of
these criteria. First, emissions averaging
would only be permitted between
individual existing sources at a single
stationary source (i.e., the facility), and
would only be permitted between
individual sources in the same
subcategory in the final EGU NESHAP.
Further, emissions averaging would not
be permitted between two or more
different affected sources. Finally, new
affected sources could not use emissions
averaging. Accordingly, we have
concluded that the averaging of
emissions across affected units in the
same existing source subcategory is
consistent with the CAA. In addition,
the final rule requires each facility that
intends to utilize emissions averaging to
develop an emissions averaging plan,
which provides additional assurance
that the necessary criteria will be
followed. In this emissions averaging
plan, the facility must include the
identification of: (1) All units in the
averaging group; (2) the control
technology installed; (3) the process
parameter that will be monitored; (4) the
specific control technology or pollution
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prevention measure to be used; (5) the
test plan for the measurement of the
HAP being averaged; and (6) the
operating parameters to be monitored
for each control device. A state, local, or
tribal regulatory agency that is delegated
authority for this rule could require the
emissions averaging plan to be
submitted or even approved before
emissions averaging could be used.
Upon receipt, the regulatory authority
would not be able to approve an
emissions averaging plan differing from
the eligibility criteria contained in the
rule.
The final rule excludes new affected
sources from the emissions averaging
provision. The EPA does not believe the
statute authorizes emissions averaging
for new affected sources. One reason we
allow emissions averaging is to give
existing sources flexibility to achieve
compliance at diverse points with
varying degrees of add-on control
already in place in the most costeffective and technically reasonable
fashion.
With the monitoring and compliance
provisions that are being finalized, there
is additional assurance that the
environmental benefit will be realized.
Further, the emissions averaging
provision would not apply to individual
EGUs if the EGU shares a common stack
with units in other subcategories,
because in that circumstance it is not
possible to distinguish the emissions
from each individual unit.316
The rule allows EGUs that rely on
CEMS for compliance demonstrations to
be able to participate in emissions
averaging and the emissions limits are
not subject to a discount. The EPA
believes that the data certainty provided
by units that use CEMS would be ideal
for emissions averaging and the
flexibility and cost-effectiveness it
offers. Given the homogeneity of fuels
within the rules subcategories, along
with other emissions averaging criteria,
the Agency believes use of a discount
factor to be unwarranted for this rule.
The emissions averaging provisions in
this final rule are based in part on the
emissions averaging provisions in the
Hazardous Organic NESHAP (HON).
The legal basis and rationale for the
HON emissions averaging provisions
were provided in the preamble to the
final HON.317 We do not believe that we
have the authority to provide for
emissions averaging among EGUs in
316 The EPA has reviewed monitoring data
submitted to the Agency under the Title IV Acid
Rain Program. Based on that review, the EPA is
unaware of any coal- and oil-fired units that share
a common stack.
317 Hazardous Organic NESHAP (59 FR 19,425;
April 22, 1994).
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different subcategories or among EGUs
not physically located at the same
affected facility.
I. Notification, Recordkeeping, and
Reporting
Compared to the proposed rule, the
reduced continuous compliance
requirements in the final rule—
primarily reduced testing frequencies
and removal of fuel analyses and control
device or fuel operating parameter
monitoring—considerably reduces the
overall burden associated with
recordkeeping and reporting. Based on
evaluation of the comments received,
we have established a provision in the
final rule for submission of most CEMS
data (including monitoring plan,
emissions data, and QA data) through
ECMPS, so that the affected industry
uses a common reporting tool for
submitting CEMS data.
For data other than most CEMS data,
the final rule requires electronic
reporting of certain data, including
performance test reports, PM CPMS
data, PM CEMS data, and, if approved
as part of an alternative monitoring
request, HAP metals CEMS data. Other
reports, such as notifications, must be
submitted in hard copy format or in
accordance with the procedures
established by state and local agencies
that receive delegation for implementing
this rule. In the proposed rule, we took
comment on these approaches and
stated our anticipation of adopting these
approaches. In the final rule, we have
extended the ECMPS reporting to most
CEMS data to promote harmonization
for CEMS data from the industry, while
leaving reporting of non-CEMS data in
a separate reporting system.
J. Technical/Editorial Corrections
In this final action, we are making a
number of technical corrections and
clarifications to 40 CFR part 63, subpart
UUUUU. These changes clarify
procedures for implementing the
emission limitations for affected
sources. We are also clarifying several
definitions to help affected sources
determine applicability of this rule. We
have modified some proposed
regulatory language based on public
comments. In addition, in response to
comments received (including the May
2010 notice from the Utility Air
Regulatory Group (UARG) of calculation
errors in the proposed Hg MACT floor
limits), we have checked all calculations
and made corrections where necessary.
In several places throughout the
subpart, including the associated tables,
we have corrected the cross-references
to other sections and paragraphs of the
subpart.
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VII. Public Comments and Responses to
the Proposed NESHAP
A. MACT Floor Analysis
1. New Data/Technical Corrections to
Old Data
Comment: Many commenters
identified errors in the emissions
database compiled through information
provided by industry in response to the
2010 information collection request
(ICR) that supported development of
this rule. Commenters submitted
corrections to the EPA during the public
comment period.
Response: The EPA has incorporated
technical corrections and new data
submitted prior to the end of the
comment period. The corrections and
new data are described in detail in a
memorandum in the docket. The EPA
re-ranked the sources in the MACT floor
pools to the extent necessary based on
the new or corrected data, and we
recalculated the MACT floors as
necessary based on the re-ranking of
sources. The revised MACT floors were
established using the same methodology
set forth in the proposed rule.
2. Pollutant-by-Pollutant Approach
Comment: Many commenters raised
concerns about the way the EPA
determined the MACT floors using a
pollutant-by-pollutant approach.
Commenters contended that such a
methodology produced limits that are
not achievable in combination, and as
such, the limits do not comport with the
intent of the statute or the recent court
decision (NRDC v. EPA, 2007).
Commenters further added that the CAA
directs the EPA to set standards based
on the overall performance of ‘‘sources’’
and CAA sections 112(d)(1), (2), and (3)
specify that emissions standards be
established on the ‘‘in practice’’
performance of a ‘‘source’’ in the
category or subcategory. Commenters
stated that if Congress had intended for
the EPA to establish MACT floor levels
considering the achievable emission
limits of individual HAP, it could have
worded CAA section 112(d)(3) to refer
to the best-performing sources ‘‘for each
pollutant.’’ Many commenters added
that the EPA’s discretion in setting
standards is limited to distinguishing
among classes, types, and sizes of
sources. Commenters contend that
although Congress limited the EPA’s
authority to parse units and sources
with similar design and types, it does
not allow the EPA to ‘‘distinguish’’ units
and sources by individual pollutant as
proposed in this rule (Sierra Club v.
EPA, 551 F.3d 1019, 1028 (D.C. Cir.
2008)). By calculating each MACT floor
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independently of the other pollutants,
commenters contend that the
combination of HAP limits results in a
set of standards that only a hypothetical
‘‘best performing’’ unit could achieve.
Response: We disagree with the
commenters who believe MACT floors
cannot be set on a pollutant-by pollutant
basis. Contrary to the commenters’
suggestion, CAA section 112(d)(3) does
not mandate a total facility approach. A
reasonable interpretation of CAA
section 112(d)(3) is that MACT floors
may be established on a HAP-by-HAP
basis, so that there can be different
pools of best performers for each HAP.
Indeed, as illustrated below, the total
facility approach not only is not
compelled by the statutory language but
can lead to results so arbitrary that the
approach may simply not be legally
permissible.
Clean Air Act section 112(d)(3) is not
explicit as to whether the MACT floor
is to be based on the performance of an
entire source or on the performance
achieved in controlling particular HAP.
Congress specified in CAA section
112(d)(3) the minimum level of
emission reduction that could satisfy
the requirement to adopt MACT. For
new sources, this floor level is to be
‘‘the emission control that is achieved in
practice by the best controlled similar
source.’’ For existing sources, the floor
level is to be ‘‘the average emission
limitation achieved by the best
performing 12 percent of the existing
sources’’ for categories and
subcategories with 30 or more sources,
or ‘‘the average emission limitation
achieved by the best performing 5
sources’’ for categories and
subcategories with fewer than 30
sources. Commenters point to the
statute’s reference to the best performing
‘‘sources,’’ and claim that Congress
would have specifically referred to the
best performing sources ‘‘for each
pollutant’’ if it intended for the EPA to
establish MACT floors separately for
each HAP.
The EPA disagrees. The language of
the Act does not address whether floor
levels can be established HAP-by-HAP
or by any other means. The reference to
‘‘sources’’ does not lead to the
assumption the commenters make that
the best performing sources can only be
the best-performing sources for the
entire suite of regulated HAP. Instead,
the language can be reasonably
interpreted as referring to the source as
a whole or to performance as to a
particular HAP. Similarly, the reference
in the new source MACT floor provision
to ‘‘emission control achieved by the
best controlled similar source’’ can
mean emission control as to a particular
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HAP or emission control achieved by a
source as a whole.
Commenters also stressed that CAA
section 112(d) requires that floors be
based on actual performance from real
facilities. The EPA agrees that this
language refers to sources’ actual
operation, but again the language says
nothing about whether it is referring to
performance as to individual HAP or to
single facility’s performance for all
HAP. Industry commenters also said
that Congress could have mandated a
HAP-by-HAP result by using the phrase
‘‘for each HAP’’ at appropriate points in
CAA section 112(d). The fact that
Congress did not do so does not compel
any inference that Congress was subsilentio mandating a different result
when it left the provision ambiguous on
this issue. The argument that MACT
floors set HAP-by-HAP are based on the
performance of a hypothetical facility,
so that the limitations are not based on
those achieved in practice, just
reiterates the question of whether CAA
section 112(d)(3) refers to whole
facilities or individual HAP. All of the
limitations in the floors in this rule
reflect sources’ actual performance and
were achieved in practice. As to
commenters’ claims that standards set
in this manner cannot be met by any
actual sources, we have determined that
there are approximately 69 existing
coal-fired EGUs that meet all of the final
existing source MACT emission limits
(out of 252 EGUs that reported data for
Hg, PM, and HCl in the 2010 ICR) and
at least one EGU that meets all of the
final new source MACT emission limits.
Commenters also point to the EPA’s
subcategorization authority, and claim
that because Congress authorized the
EPA to distinguish among classes, types,
and sizes of units, the EPA cannot
distinguish units by individual
pollutant, as they allege the EPA did in
the proposed rule. However, that
statutory language addresses the EPA’s
authority to subcategorize sources
within a source category prior to setting
standards, which the EPA has done for
certain EGUs. The EPA is not
distinguishing within each subcategory
based on HAP emitted. Rather, it is
establishing emissions standards based
on the emissions limits achieved by
units in each subcategory. Therefore, the
EPA’s subcategorization authority is
irrelevant to the question of how the
EPA establishes MACT floor standards
once it has made the decision to
distinguish among sources and create
subcategories.
The EPA’s long-standing
interpretation of the Act is that the
existing and new source MACT floors
are to be established on a HAP-by-HAP
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basis. One reason for this interpretation
is that a whole plant approach could
yield least common denominator
floors—that is, floors reflecting limited
or no control, rather than performance
which is the average of what best
performers have achieved. See 61 FR
173687 (April 19, 1996); 62 FR 48363–
64 (September 15, 1997) (same approach
adopted under the very similar language
of CAA section 129(a)(2)). Such an
approach would allow the performance
of sources that are outside of the bestperforming 12 percent for certain
pollutants to be included in the floor
calculations for those same pollutants,
and it is even conceivable that the worst
performing source for a pollutant could
be considered a best performer overall,
a result Congress could not have
intended. Inclusion of units that are
outside of the best performing 12
percent for particular pollutants would
lead to emission limits that do not meet
the requirements of the statute.
For example, if the best performing 12
percent of facilities for HAP metals were
also the worst performing units for acid
gas HAP and the best performers for
acid gas HAP were the worst performers
for HAP metals, the floor for acid gases
or metals would end up not reflecting
best performance. In such a situation,
the EPA would have to make a value
judgment as to which pollutant
reductions were most critical to decide
which sources are best controlled.318
Such value judgments are antithetical to
the direction of the statute at the MACT
floor-setting stage.
Commenters suggested that a multipollutant approach could be
implemented by weighting pollutants
according to relative toxicity and
calculating weighted emissions totals to
use as a basis for identifying and
ranking best performers. This suggested
approach would require the EPA to
essentially prioritize the regulated HAP
based on relative risk to human health
of each pollutant, where risk is a
criterion that has no place in the
establishment of MACT floors, which
are required by statute to be based on
technology.
The central purpose of the amended
air toxics provisions was to apply strict
technology-based emission controls on
HAP. See, e.g., H. Rep. No. 952, 101st
Cong. 2d sess. 338. An interpretation
that the floor level of control must be
limited by the performance of devices
318 See Petitioners Brief in Medical Waste
Institute et al. v. EPA, No. 09–1297 (D.C. Cir.)
pointing out, in this context, that ‘‘the best
performers for some pollutants are the worst
performers for others’’ (p. 34) and ‘‘[s]ome of the
best performers for certain pollutants are among the
worst performers for others.’’
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that only control some of these
pollutants effectively guts the standards
by including worse performers in the
averaging process, whereas the EPA’s
interpretation promotes the evident
Congressional objective of having the
floor reflect the average performance of
best performing sources. Because
Congress has not spoken to the precise
question at issue, and the Agency’s
interpretation effectuates statutory goals
and policies in a reasonable manner, its
interpretation must be upheld. See
Chevron v. NRDC, 467 U.S. 837
(1984).319
The EPA notes, however, that if
optimized performance for different
HAP is not technologically possible due
to mutually inconsistent control
technologies (for example, if metals
performance decreased as organics
reduction is optimized), then this would
have to be taken into account by the
EPA in establishing a floor (or floors).
The Senate Report indicates that if
certain types of otherwise needed
controls are mutually exclusive, the
EPA is to optimize the part of the
standard providing the most
environmental protection. S. Rep. No.
228, 101st Cong. 1st sess. 168 (although,
as noted, the bill accompanying this
Report contained no floor provisions). It
should be emphasized, however, that
the D.C. Circuit has stated that ‘‘the fact
that no plant has been shown to be able
to meet all of the limitations does not
demonstrate that all the limitations are
not achievable.’’ Chemical
Manufacturers Association v. EPA, 885
F. 2d at 264 (upholding technologybased standards based on best
performance for each pollutant by
different plants, where at least one plant
met each of the limitations but no single
plant met all of them).
All available data for EGUs indicate
that there is no technical problem
achieving the floor levels contained in
this final rule for each HAP
simultaneously, using the MACT floor
technology. Data demonstrating a
technical conflict in meeting all of the
limits have not been provided, and, as
stated above, based on the available
data, there are approximately 64 EGUs
that meet all of the final existing source
emission limits and at least one EGU
that meets all of the final new source
emission limits.
319 Because industry commenters argued that the
statute can only be read to allow floors to be
determined on a single source basis, commenters
offered no view of why their reading could be
viewed as reasonable in light of the statute’s goals
and objectives. It is not evident how any statutory
goal is promoted by an interpretation that allows
floors to be determined in a manner likely to result
in floors reflecting emissions from worst or
mediocre performers.
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3. Minimum Number of EGUs To Set
Floors
Comment: Many commenters
indicated that CAA section 112 requires
that data from a minimum of 5 units are
required to set MACT floors for existing
sources. Commenters noted that the
EPA’s use of less than 5 units for
subcategories with greater than 30 units
is a legalistic reading of CAA section
112 that could result in such absurd
results as using 5 units to set MACT
floors for a subcategory with 29 units
and data for only 10 units, but using a
single unit to set MACT floors for a
subcategory with 31 units and data for
only 10 units.
Response: The EPA does not agree
that CAA section 112(d)(3) mandates a
minimum of 5 sources in all instances,
notwithstanding the incongruity of
having less data to establish floors for
larger source categories than is
mandated for smaller ones. The literal
language of the provision appears to
compel this result. CAA section
112(d)(3) states that for categories and
subcategories with at least 30 sources,
the MACT floor for existing sources
shall be no less stringent than the
average emission limitation achieved by
the best-performing 12 percent of the
sources for which the Administrator has
emissions information. The plain
language of this provision requires the
use of fewer data points for large source
categories than for small source
categories where the Administrator only
has emissions information on a small
number of units for categories and
subcategories with 30 or more sources.
Furthermore, commenters contend that
Congress could not have intended the
floors for a subcategory with 29 sources
to be based on 5 sources and a
subcategory with 31 sources to be based
on less than that number; but we
maintain this contention is without
merit because 12 percent of 31 is 3.72
(rounded to 4) so the EPA would not
base standards for a subcategory with 31
sources on 5 sources even if we had data
on all 31 sources in the subcategory. For
these reasons, we decline to adopt
commenters’ position and continue to
adhere to the clear statutory directive.
4. Treatment of Detection Levels
Comment: Commenters stated that
when setting the MACT floors, nondetect values are present in many of the
datasets from best performing units.
Commenters provided input on how
these non-detect values should be
treated in the MACT floor analysis.
Some commenters agreed that it is
appropriate to keep the detection levels
as reported, while certain commenters
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suggested that the detection levels
should be replaced using a value of half
the method detection limit (MDL). Many
other commenters stated that data that
are below the detection limit should not
be used in setting the floors, and these
data should be replaced with a higher
value including either the MDL, limit of
quantitation (LOQ), practical
quantitation limit (PQL), or reporting
limit (RL) for the purposes of the MACT
floor calculations. Other commenters
stated all non-detect values should be
excluded from the floor analysis, or all
values should be treated as zero.
Some commenters stated it is
necessary to keep the data as reported
because changing values would lead to
an upward bias. Additional commenters
agreed with this basic premise, but
suggested that replacing non-detect data
with a value of half the MDL is
appropriate while still minimizing the
bias. They noted that treating
measurements below the MDL as
occurring at the MDL is statistically
incorrect and violates the statute’s
‘‘shall not be less stringent than’’
requirement for MACT floors. One
commenter also provided a reference for
a statistical method based on a lognormal distribution of the data which
estimated the ‘‘maximum likelihood’’ of
data values; this result is slightly higher
than half the MDL.
Some commenters stated that it is
necessary to substitute the MDL value
when performing the MACT floor
calculations. With MDL defined as the
lowest concentration that can be
distinguished from the blank at a
defined level of statistical significance,
this is an appropriate value. If MDL
values are not reported, one commenter
suggested an approach for estimating an
MDL equivalent value, but recognized
that the background laboratory and test
report files may not be available to the
EPA in order to derive these estimates.
Most commenters representing
industry and industry trade groups
argued that either LOQ or PQL values
should replace non-detects. The LOQ is
defined as the smallest concentration of
the analyte which can be measured.
These commenters contended that the
LOQ leads to a quantifiable amount of
the substance with an acceptable level
of uncertainty. A few commenters
provided calculations showing some of
the proposed MACT floors were below
the LOQ. Additionally, some of these
commenters stated that using LOQ or
PQL values also incorporates additional
sources of random and inherent
sampling error throughout the testing
process, which is necessary. These
errors occur during sample collection,
sample recovery, and sample analysis;
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MDL values only account for method
specific (e.g., instrument) errors. These
commenters contended that the three
times the MDL approach discussed in
the proposal accounts for some
measurement errors but does not
account for these unavoidable sampling
errors. The commenters also noted that
an LOQ is calculated as 3.18 times the
MDL, and PQL is calculated as 5 to 10
times the MDL. Many of the
commenters in support of using either
an LOQ or PQL value ultimately
believed a work practice is more
appropriate where a MACT floor limit is
below either of these two values. They
cited CAA section 112(h)(1) which
allows work practices under CAA
section 112(h)(2) if ‘‘the application of
measurement methodology to a
particular class of sources is not
practicable due to technological and
economic limitations’’. These
commenters stated that the inability of
sources to accurately measure a
pollutant at the level of the MACT floor
qualifies as such a technological
limitation that warrants a work practice
standard.
Commenters stated that where the
proposed MACT floor is below the LOQ
or PQL then that source category has a
technological measurement limitation.
A few commenters suggested RL values
should be used when developing the
floor limits. They stated that the RL is
the lowest level at which the entire
analytical system gives reliable signals
and includes an acceptable calibration
point. They added that use of an
acceptable calibration point is critical in
showing that numbers are real versus
multiplying the MDL by various factors.
Several commenters stated that all
non-detect values should be excluded
from MACT floor calculations. They
believed that excluding all non-detect
values would eliminate any potential
errors or accuracy issues related to
testing for compliance. Due to
inconsistencies of the MDL value
reported for non-detect data, one
commenter suggested treating all such
values as zero. This would provide a
consistent approach for setting the floor
as well as determining compliance.
Several commenters provided input
on the EPA’s proposed method of three
times the MDL as an option for setting
limits. A few commenters in support
noted that this approach provided a
reasonable method to account for data
variability as it took into account more
than just analytical instrument
precision. Many other commenters
argued that this method results in limits
which are too low, namely that it is still
lower than the LOQ value which they
are in favor of as a substitute for any
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reported non-detect data. Other
commenters disagreed with this method
and claimed that it would lead to results
which introduce a high bias in the floor
setting process. A few contended that
multiplying by 3 would introduce a 300
percent error into the floor, resulting in
a floor that is less stringent than
required by the Act. Others suggested
that the MDL values are antiquated and
already too high and thus it is not
appropriate to multiply them by three.
Also, a few commenters suggested
multiplying the MDL by three would
not reflect the actual lower emissions
achieved by any source and as such is
unlawful under CAA section 112(d).
Response: We agree with many of the
comments related to treatment of data
reported as detection limit values in the
development of MACT floors and
emissions limits. As we noted at
proposal, the statistical probability
procedures applied in calculating the
floor or an emissions limit inherently
and reasonably account for emissions
data variability including measurement
imprecision when the database
represents multiple tests from multiple
emissions units for which all of the data
are measured significantly above the
method detection level. That is less true
when the database includes emissions
occurring below method detection
capabilities regardless of how those data
are reported.
The EPA’s guidance to respondents
for reporting pollutant emissions used
to support the data collection specified
the criteria for determining test-specific
method detection levels. Those criteria
ensure that there is only about a 1
percent probability of an error in
deciding that the pollutant measured at
the method detection level is present
when in fact it was absent. (Reference:
ReMAP: PHASE 1, Precision of Manual
Stack Emission Measurements;
American Society of Mechanical
Engineers, Research Committee on
Industrial and Municipal Waste,
February 2001.) Such a probability is
also called a false positive or the alpha,
Type I, error. This means specifically
that for a normally distributed set of
measurement data, 99 out of 100 single
measurements will fall within ±2.54 ×
standard deviation of the true
concentration. The anticipated range for
the average of repeated measurements
comes progressively closer to the true
concentration. More precisely, the
anticipated range varies inversely with
the square root of the number of
measurements. Thus, for a known
standard deviation (SD) of anticipated
single measurements, the anticipated
range for 99 out of 100 future triplicate
measurements will fall within ±2.54 SD/
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√3 of the true concentration. This
relationship translates to an expected
measurement imprecision for an
emissions value occurring at or near the
method detection level of about 40 to 50
percent.
By assuming a similar distribution of
measurements across a range of values
and increasing the mean value to a
representative higher value (e.g., 3 times
minimum detection level or 3xMDL),
we can estimate measurement
imprecision at other levels. For an
assumed 3xMDL, the estimated
measurement imprecision for a three
test run average value would be on the
order 10 to 20 percent. This is about the
same measurement imprecision as
found for Methods 23 and 29 indicated
in the ASME ReMAP study for the
sample volumes prescribed in the final
rule (e.g., 4 to 6 dscm) for multiple tests.
Analytical laboratories often report a
value above the method detection limit
that represents the laboratory’s
perceived confidence in the quality of
the value. This independently adjusted
value is expressed differently by various
laboratories and is called LOQ, PQL, or
RL. In many cases, the LOQ, PQL, or RL
is simply a multiplication of the method
detection limit. Commonly used
multipliers range from 3 to 10. Because
these values reflect individual
laboratories’ perceived confidence, and,
therefore, could be viewed as arbitrary,
we decline to adopt the LOQ, PQL, or
RL because such approaches in our view
would inappropriately inflate the MACT
floor standards. Our alternative to those
inconsistent approaches is discussed
below.
Consistent with findings expressed in
reports of emissions measurement
imprecision and the practices of
analytical laboratories, we believe that
using a measurement value of 3 times a
representative method detection limit
established in a manner that assures 99
percent confidence of a measurement
above zero will produce a representative
method reporting limit suitable for
establishing regulatory floor values.
On the other hand, we also agree with
commenters that an emissions limit set
from a small subset of data or data from
a single source may be significantly
different than the actual method
detection levels achieved by the best
performing units in practice. This fact,
combined with the low levels of
emissions measured from many of the
best performing units, led the EPA since
proposal to review and revise the
procedure intended to account for the
contribution of measurement
imprecision to data variability in
establishing effective emissions limits.
In response to the comments about the
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quality of measurements at very low
emissions limits especially for new
sources, we revised the procedure for
identifying a representative method
detection level (RDL).
The revised procedure for
determining an RDL starts with
identifying all of the available reported
pollutant-specific method detection
levels for the best performing units
regardless of any subcategory (e.g.,
existing or new, fuel type, etc.). From
that combined pool of data, we calculate
the arithmetic mean value. By limiting
the data set to those tests used to
establish the floor or emissions limit
(i.e., best performers), which in this case
is a larger data set than normally
available for establishing NESHAP, we
believe that the result is representative
of the best performing testing companies
and laboratories using the most
sensitive analytical procedures. We
believe that the outcome should
minimize the effect of a test(s) with an
inordinately high method detection
level (e.g., the sample volume was too
small, the laboratory technique was
insufficiently sensitive, or the procedure
for determining the minimum value for
reporting was other than the detection
level). We then call the resulting mean
of the method detection levels the
representative detection level (RDL)
because it is characteristic of accepted
source emissions measurement
performance.
The second step in the process is to
calculate 3xRDL to compare with the
calculated floor or emissions limit. This
step is similar to what we have used for
other NESHAP including the Portland
Cement rule. As outlined above, we use
the multiplication factor of 3 to reduce
the imprecision of the analytical method
until the imprecision in the field
sampling reflects the relative method
precision as estimated by the ASME
ReMAP study. That study indicates that
such relative imprecision remains a
constant 10 to 20 percent over the range
of the method. For assessing the
calculated floor results relative to
measurement method capabilities, if
3xRDL were less than the calculated
floor or emissions limit (e.g., calculated
from the upper predictive limit, UPL),
we would conclude that measurement
variability was adequately addressed
with the initial floor calculation. The
calculated floor or emissions limit
would need no adjustment. If, on the
other hand, the value equal to 3xRDL
were greater than the UPL, we would
conclude that the calculated floor or
emissions limit did not account entirely
for measurement variability. Where
such was the case, we substituted the
value equal to 3xRDL for the calculated
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floor or emissions limit (UPL) which
results in a concentration where the
method would produce measurement
accuracy on the order of 10 to 20
percent similar to other EPA test
methods and the results found in the
ASME ReMAP study.
We determined the RDL for each
pollutant using data from tests of all the
best performers for all of the final
regulatory subcategories (i.e., pooled
test data). We applied the same
pollutant-specific RDL and emissions
limit assessment and adjustment
procedures to all subcategories for
which we established emissions limits.
We believe that adjusting emissions
limits in this manner, which ensures
that measurement variability is
adequately addressed relative to
compliance determinations, is a better
procedure than the one applied at
proposal, which was based on more
limited data. We also believe that
currently available emissions testing
procedures and technologies provide
the measurement certainty sufficient for
sources to demonstrate compliance at
the levels of the revised emissions
limits.
5. Basis for New Source MACT
Comment: Several commenters stated
that the proposed limits set for new
EGUs do not represent the best
performing EGU. The commenters state
that the EPA has chosen the strictest
limit irrespective of the EGU and that
limits for new EGUs should be
achievable. According to the
commenters, no existing EGU is
currently meeting the proposed limits,
which will result in a moratorium on
the construction of new coal-fired EGUs.
Further, commenters state that another
result of the EPA’s flawed approach is
that the proposed standards for new
EGUs are so low that adequate test
methodologies to demonstrate
compliance do not exist. Without
accurate testing methodologies,
commenters assert that contractors will
not guarantee that potential emission
control technologies will meet the
proposed standards. Without accurate
test methodologies and vendor
guarantees, commenters believe that
financing of new facilities will be
virtually impossible to secure which
will, in turn, effectively preclude the
construction of any new coal-based
EGUs.
Commenters also stated that the EPA
failed to address cumulative effects of
using multiple pollution control devices
in determining MACT levels applicable
to PM levels. In proposing total PM as
a surrogate, commenters believe that the
EPA failed to consider or address the
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antagonistic effects that adding multiple
pollution control devices can have on
an EGU’s HAP emissions. Commenters
indicated that EGUs would not be able
to comply with the proposed new
source HCl limit without adding a
scrubber or some type of sorbent
injection to control HCl emissions.
Adding these HCl control technologies
will increase the total PM emissions of
these units. According to commenters,
because a fabric filter-alone
configuration (the basis for the new
source PM limit) would not meet all
MACT limits, these units may not be the
best-performing units.
Response: The EPA disagrees with the
commenters’ statements that no existing
unit is currently meeting the new source
limits. The EPA established the new
source limits based on data from
existing EGUs and there is at least one
EGU, based on the data available, that
is meeting all three final HAP limits and
at least eight EGUs that are meeting one
or more of the new source limits. As a
result of comments received on the full
body of data, the EPA has re-ranked the
best performing EGUs and reviewed the
new source limits based on the reranking where appropriate. Based on the
revised ranking, the best performing
source for PM has changed and that
source now forms the basis for the new
source filterable PM limit in the final
rule. The source is a coal-fired EGU that
includes the entire suite of controls that
would likely be required on a new coalfired source constructed prospectively
(i.e., it is a unit with SCR, dry FGD, and
FF). Thus, the commenters’ concerns are
no longer relevant as they relate to PM
emissions from coal-fired EGUs.
The EPA also believes that the EGUs
serving as the basis for the new source
Hg and HCl limits in the final rule are
representative of what a new coal-fired
EGU would look like to meet all of the
requisite regulations applicable to EGUs
(e.g., NSPS and the CSAPR) as they also
include the entire suite of controls that
would likely be required on a new coalfired source constructed prospectively.
The EPA has also taken into account the
ability of the various test methods to
accurately measure emissions at the
levels being demonstrated by the EGUs
in the top performing 12 percent in
establishing the final limits, and we
have determined that there are adequate
test methods to measure the regulated
HAP at the new source levels.
6. Achievability of Limits
Comment: A number of commenters
state that the EPA has chosen the
strictest limit irrespective of the unit
and that limits for new EGUs should be
achievable. According to the
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commenters, no existing unit is
currently meeting the proposed new
source limits, which will result in a
moratorium on the construction of new
coal-fired units. The commenters state
that this regulation goes beyond
protecting public health and will impact
the country’s choice of fuel for energy
production. Other commenters state that
another result of the EPA’s flawed
approach is that the proposed standards
for new units are so low that adequate
test methodologies to demonstrate
compliance do not exist. Without
accurate testing methodologies,
commenters allege that contractors will
not guarantee that potential emission
control technologies will meet the
proposed standards. Without accurate
test methodologies and vendor
guarantees, commenters believe that
financing of new facilities will be
virtually impossible to secure, and that
this in turn will effectively preclude the
construction of any new coal-based
units. Commenters maintain that
adopting standards effectively banning
new coal units amounts to a momentous
change in national energy policy
without discussion or analysis and far
exceeds the EPA’s authority.
Some commenters add that the
proposed new source MACT standards
do not represent rates that have been
achieved in practice and are orders of
magnitude lower than any of the CAA
section 112(g) case-by-case MACT limits
established for the most advanced units
in the U.S. coal fleet by multiple state
agencies.
Other commenters stated that the
synergistic impact of multiple controls
has not been taken into account in the
proposed rules. Commenters argue that
circumstances exist with respect to the
control of acid gases, which will require
scrubbers or other SO2 controls that add
particulate to the flue gas stream, and
that added particulate must be removed
by PM control devices along with the
particulate added to the flue gas for
EGUs that need to install ACI for Hg
control. Because particulate devices
provide a fixed percent reduction of
particulate, commenters assert that it is
mathematically certain that PM
performance will decrease because
control of both acid gases and Hg would
add PM to the flue gas stream which
would in turn decrease performance of
the PM control on the relevant mass
metric. As a consequence, commenters
allege that there is no assurance that
sources can meet the EPA’s ‘‘cherrypicked’’ floors for acid gases and for Hg
by ‘‘optimizing’’ these systems to meet
the performance of the floor units
because to do so would impact their
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ability to meet the EPA’s similarly
‘‘cherry-picked’’ total PM floor standard.
The commenters state that, for
existing sources as with the new source
standard-setting approach, a pollutantby-pollutant approach does not consider
what the top performing 12 percent
achieve in practice for all pollutants and
does not consider the antagonistic
effects of the concurrent use of various
control technologies. For example, one
commenter states that 47 of the 131
sources used to calculate the existing
source total PM limit only had PM
control but no acid gas or Hg controls
that could emit additional PM.
According to the commenter, the CAA
is clear that standards must be based on
actual sources and not the product of a
pollutant-by-pollutant determination
resulting in a set of composite standards
that do not necessarily reflect the
overall performance of any actual
source. To address these issues, the
commenter recommends that the EPA
use an approach that more accurately
reflects what actual best performing
sources achieve.
Response: The EPA disagrees with the
commenters’ contention that the
pollutant-by-pollutant approach to
establishing MACT floors is inconsistent
with the CAA for the reasons set forth
in the response to comments on the
EPA’s MACT floor setting process. In
addition, the EPA established the
proposed new source limits based on
data from existing EGUs, and there are
EGUs that are able to meet the new
source limits. To the extent the
commenters are concerned that no
existing source is simultaneously
meeting all of the new sources limits,
we note that the EPA has revised the
new source standards based on
comments and data corrections that
industry made to data it incorrectly
provided in response to the utility ICR.
We have identified at least one source
that is meeting all of the new source
MACT limits in the final rule.
We disagree with commenters that
suggest the proposed new source
standards are invalid because they are
more stringent than CAA section 112(g)
case-by-case MACT limits established
by state agencies. As commenters note,
states, not the EPA, established the CAA
section 112(g) standards, and they did
so based on the information available to
them. The EPA likewise must establish
CAA section 112(d) standards based on
the available data. We have considered
the available data and information,
including the 2010 ICR data, and
complied with the requirements of CAA
section 112(d) in establishing the
standards in this final rule. That the
final standards are more stringent than
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CAA section 112(g) standards issued by
certain state agencies has no bearing on
the legitimacy of the standards at issue
here.
The EPA agrees with commenters that
the SO2 and some Hg controls may add
to the PM loading and that it is
reasonable to establish the new source
standard based on an EGU that has a
suite of controls that will be required of
any new source. For example, new coalfired EGUs will be required to comply
with the utility NSPS and may have to
comply with the CSAPR and other
requirements (e.g., SIP or state-only
requirements). Commenters are also
correct that the proposed new source
PM surrogate standard was based on a
source that is not like a coal-fired EGU
that would be constructed today (i.e., an
EGU with only PM control and no SO2
controls).
The final standard is not based on the
source used to establish the proposed
limit. As stated above, industry
commenters provided data corrections
and new data and the EPA considered
that new and revised data in
establishing the final standards. We reranked all the coal-fired EGUs based on
the new data. The new ranking of coalfired EGUs resulted in a change of the
source we used to establish the new
source PM surrogate standard for nonmercury metal HAP. The basis for the
new source limit in the final rule is a
unit that has a full suite of controls
similar to what would be required for
any new coal-fired EGUs (i.e., it is a unit
with SCR, dry FGD, and FF). The EPA
has identified at least one EGU meeting
all of the final new source limits; thus,
the EPA does not believe that it is
finalizing standards that ‘‘ban’’ new
coal-fired generation as indicated by the
commenter.
The EPA also disagrees that the final
new source standards are so stringent
that there are not adequate test methods
available to determine compliance with
the standards. The EPA has taken into
account the ability of the various test
methods to accurately measure
emissions at the levels being
demonstrated by the best performing
EGUs in establishing the final limits.
This has been done through use of the
3XRDL (discussed elsewhere in this
preamble and the Response to
Comments document) and through
adjustments to the sampling time
requirements for certain of the HAP.
7. Comments on Technical Approaches
Comment: Commenters disagreed
with the EPA’s use of data from
multiple units exhausting through a
common stack and argued that the EPA
unreasonably treated data from multiple
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units exhausting through a single stack
as multiple data points in establishing
the MACT floors. The commenters
believe it is improper to count a single
data point from a multiple-unit common
stack as multiple data points. The
commenters state that where two units
exhaust through a common stack, the
performance is not that of two sources,
but only one. The commenters indicate
that emissions performance that is
actually achieved reflects combined
operation, which cannot rationally be
split into two parts (data points) because
this emissions performance was not
achieved by two separate sources.
Commenters assert that although it may
be acceptable for the EPA to surmise
that the combined performance of
multiple EGUs and pollution control
devices represents an emissions control
strategy that could be a best performer,
thereby entitling the Agency to use the
data at all, the fact is there is only one
performer not two. Commenters contend
that apart from being inconsistent with
applicable MACT case law, counting
combined stack emissions as two or
more data points is unreasonable
because it dampens variability and overrepresents the emissions data by
creating multiple ‘‘performers’’ or
sources when there is in fact only one.
Commenters note that in the majorsource Industrial Boiler NESHAP, the
EPA argued its approach of creating two
data points from a single combined
stack data point is reasonable because it
cannot separate the comingled fraction
of the emissions from the different
emission points. Commenters state that
this is irrelevant, believing that there is
no basis to separate these emissions
because the MACT floor is based on best
performing sources and there is only a
single source.
According to commenters, the EPA
cannot determine what amount of the
overall performance of a combined stack
data point is the specific result of the
combination. Commenters assert that
the EPA also argues that applying the
emissions equally to multiple units
exhausting through a single stack
‘‘accurately represents the emissions of
those units on average.’’ Commenters
believe that is simply not correct and
there is no plausible factual basis for
that statement, believing that there is no
unit that ‘‘achieved’’ those emissions.
Rather, the data represent the combined
weighted average of two units, without
knowing how either unit actually
performed. One commenter also stated
that in several instances when a facility
operated tandem or multiple EGUs but
only submitted a single stack
measurement, the EPA used the single
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stack measurement to represent Hg
emissions from the facility’s other
stacks.
Response: The EPA disagrees with
commenters. As in the major-source
Industrial Boiler NESHAP, the EPA
continues to believe that the emissions
from the common stack represent the
average emissions of the EGUs
exhausting to the common stack and are
representative of both EGUs.
Commenters have provided no data to
support the contention that this
assumption is false. In addition,
commenters’ contention that distinct
EGUs (i.e., boilers) are one source if they
emit out of a common stack is not
consistent with the CAA section
112(a)(8) definition, which clearly
applies to the individual boiler units
with a capacity of more than 25 MW. It
would not be reasonable in light of that
definition to consider the emissions
from two boilers to a common stack as
the emissions of one EGU. The EPA
only used data from combined stacks
where both EGUs were operating or
where the owner/operator certified that
no air leakage could occur. The EPA
expects that companies will comply
with the final rule by conducting testing
at the common stack as that is usually
where the sampling locations are (rather
than in the intermediate ductwork) and
will report the results as being for each
EGU.
The EPA has reviewed the data based
on comments received and does not
believe that there are any
inconsistencies in the data set used for
the final rule. In the MACT floor
analysis, the EPA only used data from
stacks that were tested or for which test
data were provided. These stack
measurements were not used to
represent emissions from other, nontested, stacks in the MACT analysis.
8. Alternative Units for Emission Limits
Comment: Several commenters
submitted a variety of alternatives to the
input- or output-based MACT floor
limits as means of establishing the
MACT floors. Some commenters
suggested emission reductions or
removal efficiencies. These commenters
suggest that a percent reduction MACT
metric be considered as an alternative,
and not a substitute, to some of the
proposed MACT numerical limits,
particularly those that appear too
problematic to meet in reality. A
necessary data format and protocol
could be developed for some HAP, such
as Hg, that would allow an appropriate
percent reduction alternative to be
developed. Commenters believe that the
Brick MACT decision stands for the
proposition that a MACT level cannot
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be based on a specific technology;
commenters are advocating that a
percent reduction format would specify
the level or reduction but would not
dictate any specific control or
methodology.
Comments were also received that
some state programs contain Hg
emission limits that are more stringent
than the EPA’s proposed emission
limits. The programs of Connecticut,
Massachusetts, New Hampshire, New
Jersey, and New York were noted.
Commenters provided information on
these states’ Hg emission limits, which
often are in the form of either a lb/TBtu
format or a percent reduction.
Commenters noted that EGUs in these
states were in compliance with the state
regulations and, therefore, the EPA’s
emission limits should be more
stringent.
Response: The EPA disagrees with the
commenters’ suggestion that a percent
reduction standard should be included
in the final rule. The EPA notes that the
inability to account for Hg removed
from the coal prior to combustion was
not the only reason provided for not
using a percent reduction format. As
noted in the proposal preamble (76 FR
25040), we did consider using a percent
reduction format for Hg. We determined
not to propose a percent reduction
standard for several reasons. The
percent reduction format for Hg and
other HAP emissions would not have
addressed the EPA’s desire to promote,
and give credit for, coal preparation
practices that remove Hg and other HAP
before firing because we did not have
the data to account for those practices.
Specifically, to account for the coal
preparation practices, sources would be
required to track the HAP
concentrations in coal from the mine to
the stack, and not just before and after
the control device(s). Such an approach
would be difficult to implement and
enforce. Moreover, we do not have the
data necessary to establish percent
reduction standards for HAP at this
time. Depending on what was
considered to be the ‘‘inlet’’ and the
degree to which precombustion removal
of HAP was desired to be included in
the calculation, the EPA would need
(e.g.) the HAP content of the coal as it
left the mine face, as it entered the coal
preparation facility, as it left the coal
preparation facility, as it entered the
EGU, as it entered the control devices,
and as it left the stack to be able to
establish percent reduction standards.
We do not have this type of information.
The EPA believes that an emission
rate format allows for, and promotes, the
use of pre-combustion HAP removal
processes because such practices will
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help sources assure they will comply
with the proposed standard. A percent
reduction requirement would likely
limit the flexibility of the regulated
community by requiring the use of a
control device. In addition, as discussed
in the Portland Cement NESHAP (75 FR
55002; September 9, 2010), the EPA
believes that a percent reduction format
negates the contribution of HAP inputs
to EGU performance and, thus, may be
inconsistent with the D.C. Circuit’s
rulings as restated in the Brick case (479
F.3d at 880) which say, in effect, that it
is the emissions achieved in practice
(i.e., emissions to the atmosphere) that
matter, not how one achieves those
emissions.
The 2010 ICR data confirm that plant
inputs likely play a role in emissions to
the atmosphere. These data indicate that
some EGUs are achieving lower Hg
emissions to the atmosphere at a lower
Hg percent reduction (e.g., 75 to 85
percent) than are other EGUs with
higher percent reductions (e.g., 90
percent or greater). However, we are not
sure whether these data accurately
reflect the total percent reduction mineto-stack because we do not have all the
data necessary to make that
determination. Thus, we proposed to
establish numerical emission standards
for Hg HAP emissions from EGUs and
we are finalizing numerical emission
standards. The same issues prevent us
from considering percent reduction
standards for the other HAP emitted
from EGUs.
With regard to the comments relating
to some state programs being more
stringent than the EPA’s proposed
limits, the EPA would note that many of
the programs identified by one
commenter have an ‘‘either/or’’ format
for their Hg standards. That is, an EGU
can either meet an emission limit (e.g.,
lb/TBtu) or achieve a percent reduction.
The commenter did not note which
form of the standard the EGUs were
meeting so it is unclear whether the
standards are in fact more stringent. In
any case, CAA section 112(d) does not
mandate that federal standards be more
stringent than state requirements for
HAP emissions. Furthermore, states are
authorized to establish standards more
stringent than this final NESHAP so
promulgation of this rule will in no way
affect a source’s responsibility to
comply with an otherwise applicable
state Hg or other HAP standard.
9. Beyond-the-Floor
Comment: Several commenters stated
that the proposed beyond-the-floor Hg
limit for low rank coal EGUs is based on
too little data and is technically and
economically unattainable, noting that
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the EPA’s proposed beyond-the-floor
limit is based on only three samples
from a single test held at only one EGU,
which is not enough data to develop
such a limit, especially as more data
were available for this EGU in the
database. Commenters noted that
although this one EGU may have been
able to achieve the proposed limit
during this one test, the three samples
are not adequate to demonstrate the
long-term ability of this EGU to meet
that limit consistently, let alone the
long-term abilities of the top 12 percent
of all low rank coal EGUs to meet that
limit consistently. Given Texas lignite’s
particularly high rates of variability of
Hg concentration, and the inability to
minimize this variability, the
commenters believe that the EPA is
obliged to have more, not less, data to
support the proposed beyond-the-floor
Hg limit for low rank coal EGUs. One
commenter added that the EPA’s
decision to require a beyond-the-floor
limit for the low rank virgin coal
subcategory does not comply with CAA
section 112(d)(2). Some commenters
also contended that the EPA failed to
include the cost of a baghouse in its
beyond-the-floor analysis. They note
that, according to the EPA, in order to
comply with the proposed EGU MACT
rule, units will either fuel switch to a
lower Hg fuel or retrofit air pollution
controls.
Response: The EPA notes that all of
the low rank virgin coal-fired EGUs for
which data were submitted in response
to the 2010 ICR were meeting the Hg
floor limit (11 lb/TBtu). Four of the
EGUs have ACI systems installed and
three of the four EGUs tested were also
meeting the beyond-the-floor Hg
emission limit of 4.0 lb/TBtu. Those
three units were achieving control levels
of greater than 95 percent (fuel to stack).
The other low rank virgin coal-fired
EGUs that are not currently meeting the
beyond-the-floor emission limit do not
have installed Hg-specific controls. An
analysis of the Hg content of the fuel
used during the 2010 ICR testing
suggests that control in the range of 80
to 90 percent (fuel to stack) would be
needed to meet the beyond-the-floor
limit of 4.0 lb/TBtu. One low rank virgin
coal-fired EGU achieved 75 percent
control with no Hg-specific control
technology (e.g., ACI).
The EPA believes that its beyond-thefloor analysis is appropriate, including
the costs analyzed. The EPA’s cost
analysis is meant to serve as an average
for all sources in the subcategory
recognizing that some EGU’s costs will
be more and some less; EGUs whose
costs are higher are not exempted from
the regulation. Further, five EGUs in the
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subcategory are meeting the final
beyond-the-floor limit based on
available data (see the MACT Floor
analyses in the docket), and, in any
case, CAA section 112(d) does not
require that a specified percentage of
sources in a category or subcategory be
able to meet the MACT standard that is
established. This is even truer for
beyond-the-floor standards which are
set at levels beyond what the average of
the best performing sources are
achieving in practice and instead based
on what is achievable. Commenters
have failed to provide any data that
supports the contention that some EGUs
in the subcategory will not be able to
achieve the standards with additional
controls.
Comment: Commenters indicated that
the EPA has not justified a beyond-thefloor limit for Hg for new IGCC units.
The EPA’s choice of the beyond-thefloor Hg limit for new IGCCs is not
derived from IGCC test data from the
2010 ICR and commenters allege that
the EPA has not provided adequate
justification for its decision from a
technology capability assessment.
Commenters note that ACI for Hg
treatment of coal-derived syngas is not
in use in any operating IGCC plant
today, nor can it be used in the same
fashion as it is used at conventional
coal-fired EGUs. Commenters assert that
the EPA also lacks data with respect to
new IGCC units, yet the EPA proposed
beyond-the-floor MACT limits for new
IGCC sources. The commenters assert
that the EPA’s limits for new IGCC
sources are based on beliefs,
predictions, projections and design
target assumptions. The limits from the
2007 DOE Report referenced in the
preamble are based on environmental
target assumptions. These IGCC
environmental targets were chosen to
match Electric Power Research Institute
(EPRI) design basis from their Coal Fleet
for Tomorrow Initiative. Commenter
states that EPRI notes that these were
design targets and were not to be used
for permitting values. Commenters
assert that the EPA has simply not
justified its process for going beyondthe-floor for new IGCC units and that,
without sufficient justification, the EPA
actions are unsupported.
Two commenters provided permit
information, based on IGCC units
currently under construction, for PM
and Hg emissions. One commenter
requested that the proposed new MACT
floor limit for PM be modified to
address the two scenarios for duct
burners at IGCC plants, syngas-fired and
natural-gas-fired. The commenter
requested the 0.050 lb/MWh limit be
increased to at least 0.068 lb/MWh
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based on gross energy output from the
combined cycle generating unit when
operated with duct burners fired with
syngas. The 0.068 lb/MWh value is
consistent with the calculated emission
ceiling for its permit to construct for this
operating scenario. According to the
commenter, there is not sufficient
experience with syngas turbines for
manufacturers to guarantee performance
in the 0.050 lb/MWh range. The
0.0681b/MWh performance basis
proposed by the commenter was
calculated based on the emission
guarantees that the commenter was able
to obtain for a turbine fired on the
syngas. The commenter also requested
that the 0.050 lb/MWh limit be
increased to 0.083 lb/MWh based on
gross energy output from the combined
cycle unit when operated with duct
burners fired by natural gas. The
commenter indicated that, depending
on market conditions, the syngas
produced at an IGCC may have more
value as a raw material for producing
co-products than it would have as duct
burner fuel. Where that is the case, the
economic viability of an IGCC would be
enhanced by firing the duct burners on
natural gas and diverting that syngas to
manufacture of a co-product. The
commenter’s air permits are currently
based on the use of syngas as duct
burner fuel; however, the commenter is
currently examining an alternative
operating scenario that may result in
amendments to the air permits to
authorize firing natural gas in the duct
burners. Commenter states that
preliminary calculations indicate that
the PM limit would need to be set at
0.083 lb/MWh gross energy output
when operated with duct burners fired
with natural gas.
The commenter also noted that there
is not sufficient test data to precisely
predict the Hg emissions performance of
even the best-controlled IGCC units,
other than that IGCC Hg emissions are
expected to be much less than those for
EGUs that directly burn coal. In its
permit application, the commenter
proposed to establish a new standard for
Hg removal in IGCC units by treating the
syngas in catalytic reactors. The
catalytic reactor system is expected to
achieve greater than 95 percent Hg
removal using either sulfur-impregnated
activated carbon or alumina catalyst. In
the absence of actual stack test data, the
commenter has had to estimate expected
emissions based on engineering
estimates of how much Hg may arrive in
the syngas routed to the catalytic
reactors. Based on these engineering
estimates and 95 percent Hg removal in
the catalytic reactors, the commenter
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believes that the resulting Hg emission
limit for a state-or-the-art IGCC unit
would be 0.003 lb/GWh, which is much
less than the Hg emissions for EGUs that
directly burn coal.
The commenter notes that IGCC units
are still in their infancy. Funding for
them will be very difficult or
unavailable if there is a regulatory limit
below the level that can be supported by
vendor guarantees. Given the important
role that IGCC units may have in
meeting global energy and climate
stability goals, the commenter believes
it would be a mistake to erect barriers
to the implementation of this
technology. The commenter stated that
the EPA can reevaluate the appropriate
levels for future IGCC units after
demonstration units which incorporate
effective controls have been built and
tested.
Response: The EPA is not finalizing
the proposed new source standards for
IGCC units. As commenters noted, EPA
proposed beyond-the-floor limits for
IGCC units based on the performance of
PC-fired EGUs and solicited data from
IGCC units that would represent what a
new IGCC could achieve. We received
information that there are new IGCC
units permitted and under construction.
The EPA believes one IGCC unit under
construction for which permit data were
provided is representative of both
current technologies and of IGCC units
that will be built in the near-term future.
Therefore, the EPA believes these
permit levels should be the basis of the
new source IGCC emission limits and
the Agency is finalizing the PM and Hg
limits on that basis, as that source will
be required to comply with its permitted
limits once constructed and it is a
similar source. However, permit limits
were only provided for PM and Hg;
therefore, the EPA is finalizing the new
source limits for acid gas HAP based on
data from the best-performing of the
existing IGCC units for the respective
HAP.
B. Rationale for Subcategories
Many commenters stated that the EPA
should have proposed more
subcategories, while others believed that
too many subcategories were proposed.
Many different issues were raised by
commenters, and some of the key issues
that were considered in the final rule
(some of which led to changes in the
final rule) include: the technical
deficiencies in the definition for the
low-Btu coal subcategory; additional
subcategorization of the coal-fired EGU
population; the need for
subcategorization of distillate vs.
residual oil-fired EGUS; the need for a
limited-use subcategory for EGUs that
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operate for only a small percentage of
hours during a year; and the need for a
non-continental liquid oil subcategory
for island units that have limited fuel
options and other unique
circumstances. The comments and the
EPA responses are provided below.
In general, the EPA has reviewed the
data provided and continues to believe
that the coal-fired EGU subcategories
proposed are the only ones supported
by the data, though we have revised the
basis for EGUs designed to burn low
rank virgin coal as discussed above. The
EPA may not subcategorize by air
pollution control technology type as
requested by a few commenters.
Further, the EPA has reviewed the other
suggested coal-fired subcategories and
finds no basis for further
subcategorization (e.g., based on boiler
design, boiler size, or duty cycle).
1. Coal Subcategories
Comment: Commenters noted that
although other subcategories had been
evaluated, including subcategorization
of other coal ranks, no other coal rank
subcategorization was proposed.
Commenters submit there should be
subcategories for the coal ranks of
bituminous, subbituminous, and lignite.
The commenters noted that such
treatment would be consistent with past
practice (e.g., CAMR where the
differences in the type of emissions of
Hg due to the different chemical
properties of coal within differing fuel
ranks was discussed). Commenters note
that activated carbon has been shown to
be very effective when used in
combination with low chlorine coals
(such as western subbituminous coals);
however, activated carbons can suffer
from poor performance when used with
high sulfur coals. Commenters indicate
that firing high sulfur coals (especially
when an SCR is also used) can result in
sulfur trioxide (SO3) vapor in the flue
gas stream. The SO3 competes with Hg
for binding sites on the surface of the
activated carbon (or unburned carbon)
and limits the effectiveness of the
injected activated carbon. But another
commenter noted that an SO3 mitigation
technology, such as dry sorbent
injection (DSI, e.g., trona or hydrated
lime), applied upstream of the ACI can
minimize this effect.
Commenters also stated that without
further subcategorization the economic
impacts on individual Midwestern
states will be particularly acute as huge
segments of the U.S. coal reserve will be
disenfranchised by this rule. According
to the commenters, the EPA did not
even attempt to legitimately analyze this
issue and, thus, in their opinion the
Agency’s proffered rationale for
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declining to further subcategorize based
on the acid gas standard is belied by the
record. The commenters believe that the
EPA needs to better align this rule with
its previous position in CAMR and
further subcategorize based on coal
type.
Other commenters are opposed to any
further subcategorization based on coal
rank. Because many sources blend
several ranks of coal on a regular basis,
commenters believe that establishing
coal rank subcategories would create
numerous opportunities for sources to
game the regulations and substantially
increase emissions. Commenters stated
that there is no need for such an
approach since modern pollution
controls can accommodate a wide range
of coals. These commenters believe that
EGUs firing different ranks of coal are
not fundamentally different in size,
class, or type in a way that impacts
emissions or that limits the availability
of controls. The commenters believe
that emissions of fuel-dependent HAP
can be controlled by either changing the
fuel prior to combustion or by removing
the HAP from the flue gas after
combustion. Commenters state that ACI
systems, DSI controls, and PM controls
are available for installation at units
firing sub-bituminous coal and are
equally available for units firing
bituminous, anthracite, or lignite coal.
These commenters also believe that as
long as a control option is commercially
available, the cost for a particular EGU
is irrelevant to the EPA’s development
of emission standards based on MACT.
Commenters stated that subcategories
based on coal rank would make a
meaningful consideration of fuel
switching impossible, contrary to the
judicial mandate to consider
substitution of materials in setting the
floor and the statutory mandate to
consider substitution of materials in the
beyond-the-floor analysis.
One commenter stated that although
they previously supported the
subcategorization of coal-fired units on
the basis of coal rank, they no longer
object to grouping units that burn
bituminous and subbituminous coals in
a single category because the prior basis
for subcategorization no longer exists.
The commenter indicated that at the
time of CAMR, it was widely recognized
that although coal-fired units
combusting bituminous coal, with its
higher concentration of chlorine and,
therefore, ionic Hg, could effectively
limit Hg emissions by utilizing existing
control technologies such as scrubbers,
units burning subbituminous coal could
not do so with the same controls
because of the coal’s higher levels of
elemental Hg. The commenter stated
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that activated carbon was only a
fledgling and unproven technology at
the time; today, however, activated
carbon has been proven, and units
burning bituminous and subbituminous
coal can achieve the same levels of
emissions for Hg and other HAP.
Consequently, the commenter believes
the prior basis for subcategorization no
longer exists and the commenter,
therefore, agrees that coal-fired EGUs
burning bituminous and subbituminous
coals ought to be grouped in a single
category.
Response: The EPA disagrees with
commenters that additional coal-fired
subcategories are warranted and has not
provided any in the final rule.
Commenters are correct that additional
subcategorization was proposed in
January 2004. Whether or not such
subcategorization was warranted at that
time, the EPA believes that the current
conditions are such that, even if
appropriate at that time, such further
subcategorization is not appropriate at
this time.
When all of the factors noted by
commenters have been reviewed, with
the exception of Hg for certain units, as
discussed above, the EPA does not
believe that the HAP emissions to the
atmosphere are sufficiently different
from coal-fired EGUs to warrant further
subcategorization. There are EGUs firing
bituminous, subbituminous, and coal
refuse among the top performing units
for Hg and EGUs firing bituminous,
subbituminous, lignite, and coal refuse
are all among the top performers for the
acid gas HAP and non-mercury metallic
HAP indicating that the MACT floor
limits established based on these units
are achievable by units burning all ranks
of coal.
As noted by commenters, ACI, not
fully developed in 2004, is now able to
effect Hg control levels on
subbituminous coals such that similar
emissions to the atmosphere may be
achieved as those achieved by higherchlorine bituminous coals when FGD
systems are used or by coal refuse EGU
with less controls. Thus, in looking at
the total system, similar emissions to
the atmosphere are achieved by all of
these coal ranks. The EPA has addressed
elsewhere in this document its rationale
for not subcategorizing by coal chlorine
content. The EPA does not believe that
any fundamental discrimination
between coal ranks will occur as a result
of the final rule, though clearly some
sources will be required to install
greater controls to comply with the final
standard. We maintain that such result
is consistent with the intent of CAA
section 112 standards, which are not
intended to have an outcome whereby
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9395
all sources can comply with final
standards without any action.
The EPA agrees, in theory, that EGUs
are designed around a basic set of coal
characteristics. However, the 1999 ICR
demonstrated that numerous EGUs have
conducted trial burns and gained
sufficient experience such that co-firing
blends of various coal ranks is now
common practice. In fact, the EPA
believes that such blends may be
modified daily, depending on the
characteristics of the coal being burned
and on the level of generation needed.
The extent of blending, and the ability
to switch the blends on short notice,
does not lend itself (or, in fact, argue
for) additional subcategorization.
The EPA disagrees with any assertion
that the EPA ignored possible
subcategorization approaches or that it
has insufficient data upon which to base
or evaluate various subcategories. The
EPA fully examined the record, which
demonstrates that coal-fired EGUs, with
the exception of certain units for Hg,
have similar HAP emissions profiles
and that similar control approaches are
available to such EGUs. Although
commenters suggested additional
subcategories were warranted, they
failed to provide sufficient data to
support their proposed alternative
subcategories. As noted elsewhere, the
EPA does not disagree with commenters
that there are some differences in EGUs.
However, the EPA does disagree with
commenters that those differences result
in differences in emissions to the
atmosphere such that additional
subcategorization is justified.
Failing to demonstrate that coal-fired
EGUs are different based on emissions,
the commenters turn to economic
arguments, asserting that failing to
subcategorize will impose an economic
hardship on certain sources. Congress
precluded consideration of costs in
setting MACT floors, and it is not
appropriate to premise
subcategorization on costs either. See S.
Rep No. 101–228 at 166–67 (5
Legislative History at 8506–07)
(rejecting the implication that separate
categories could be based on ‘‘assertions
of extraordinary economic effects’’); see
also NRDC v. EPA 489 F.3d 1364 (D.C.
Cir. 2007) (holding that EPA properly
declined to create a subcategory for a
particular source and rejecting the
argument that the source may have to
incur more costs to comply with the
rule without such subcategory).
The final limits are based on EGUs
currently operating with available
controls. As noted above, the record
shows that the various types of EGUs
are represented in the floors, with the
exception of certain units for Hg, which
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indicates that the levels are achievable
by such units. Thus, the data actually
show that the MACT standards are
achievable for a wide variety of EGUs.
In addition, the EPA believes it has
fulfilled the CAA section 112(c)(l)
directive that ‘‘[t]o the extent
practicable, the categories and
subcategories listed under this
subsection shall be consistent * * *’’
with those of CAA section 111,
notwithstanding commenters assertion
to the contrary. The decision on
whether to directly align CAA sections
112 and 111 subcategories is
discretionary and EPA has reasonably
exercised its discretion in declining to
create additional subcategories for coalfired EGUs based on the record, with the
exception of certain sources for Hg.
Finally, the EPA disagrees with the
commenters that suggest that EPA lacks
the legal authority to consider material
inputs when considering subcategories.
We agree, however, that material inputs
must be considered when establishing
MACT standards for the subcategories
that are established. We also believe a
meaningful consideration of fuel
switching can occur even if sources are
subcategorized based on fuel inputs
because EPA considers fuels switching
in evaluating potential beyond-the-floor
alternatives.
Comment: One commenter stated that
the EPA should establish an existing
source acid-gas subcategory for high
sulfur or high chlorine coals because the
same factors that the EPA relied on to
support a low rank virgin coal
subcategory for Hg are also present in
the high sulfur or high chlorine coal
context. The commenter stated that the
data indicate that even well-controlled
units burning high sulfur coals would
not be in the top performers for acid
gases even at removal rates of 95 or 96
percent. The commenter added that
absent such a subcategory, about 12
percent of coal deliveries (2005 data),
and the vast majority of coal shipped
from the states of Indiana, Ohio, and
Illinois (2008 data), would become
unusable. The commenter expressed
support for the alternative SO2 standard
for units unable to meet the HCl
standard; however, the commenter also
believed that it is appropriate to
establish a coal chlorine or sulfur
content-based subcategory for the
alternative SO2 standard. The
commenter stated that coal testing data
indicate a clear break in chlorine
concentrations in the coals burned by
EGUs, as well as in sulfur content. The
commenter indicated that there are
factors supporting a high sulfur or high
chlorine coal subcategory that are
similar to those that the EPA relied
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upon to support a Hg subcategory for
low rank virgin coal. According to the
commenter, the EPA’s key rationale for
a Hg subcategory for low rank virgin
coal was that no low rank virgin coalfired unit appeared in the ‘‘top
performing 12 percent of sources,
indicating a difference in the emissions
for this HAP from these types of units.’’
The EPA did not establish other
subcategories because ‘‘the data did not
show any difference in the level of HAP
emissions and, therefore, we have
determined that it is not reasonable to
establish separate emissions limits for
other HAP.’’ The commenter indicated
that the EPA does not need emissions
data to know that even well-controlled
units burning higher sulfur coals would
be unable to meet the alternative SO2
emissions rate, and would therefore also
not appear in the top 12 percent of
performing units.
Response: The EPA disagrees with
commenters that subcategories should
be established for high sulfur and high
chlorine coals. It appears from the
comments that it is not in fact the
chlorine content that is at issue but the
sulfur content of the coal. Commenters
state that they are unable to meet the
HCl limit, but they only provide
information indicating it would be
difficult to meet the alternative
equivalent SO2 limit. In fact, our data
show that coals with chloride contents
as high as 2,100 ppm (0.16 lb/MMBtu)
were burned by EGUs making up the
MACT floor pool of sources for the final
HCl emission limit and that the bestperforming unit was burning coal with
a maximum chloride content of 1,200
ppm. The median chloride level for
bituminous coals identified from data
submitted through the 1999 ICR was
1,030 ppm so we believe that the coals
represented in the MACT floor pool
indicate that the final limits are
achievable with high-chlorine coals. We
have determined that HCl removal is
very effective using a number of
different types of FGD systems. Absent
information demonstrating that sources
are unable to meet the proposed HCl
limit due to the chlorine content of the
coal, we believe it is unnecessary and
inappropriate to consider
subcategorizing based on chlorine
content in the coal.
In addition, as noted above, the SO2
limit is an alternative equivalent
standard that is available to sources that
have an SO2 control and CEMS and
operate the controls at all times. The
EPA did not provide the alternative
equivalent standard for sources that
could not meet the HCl limit as one
commenter suggests; instead, we
provided the standard as a convenience
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and cost saving measure to EGUs with
installed FGD systems because we
recognize that many EGUs have SO2
CEMS. Sources are required to comply
with the HCl limit as a surrogate for all
the acid gas HAP or the SO2 limit as an
alternate equivalent standard.
Commenters have not demonstrated that
they are unable to meet the HCl
standard and our data show that the
standard is achievable even for high
chlorine coals.
Comment: Several commenters
supported the development of a separate
subcategory for fluidized bed
combustors (FBC) or circulating
fluidized bed (CFB) EGUs. The
commenters encouraged the Agency to
consider subcategorization of FBC EGUs
for Hg emissions noting that the
industry has long contended that the
design, construction, and operation of
FBCs are different than conventional
boilers and that FBCs employ
fundamentally different processes than
conventional PC-fired EGUs. The
selection of an FBC unit over a
conventional PC boiler is driven in large
part by fuel characteristics. The
commenters assert that, as a result, the
emissions profile of FBC units generally
differ from conventional PC boilers
because FBC units more advantageously
combust waste coals, as well as coal
blends with other carbonaceous
material. The commenters stated that
the EPA did not discuss the design
differences between FBC units and PC
units in the preamble to this proposed
rule unlike what the Agency did when
it previously proposed Hg MACT limits
in January 2004. Commenters state that,
for these reasons, FBC units can be
considered a distinct type of boiler.
The commenters noted that an
examination of the 40 ‘‘best performing’’
units for Hg emissions in the proposed
MACT floor spreadsheet showed that 14
of those units are FBC units. The
commenters maintained that had FBC
units performed as well as conventional
PC boilers, 2 units would have been
expected to be in the top 40. The
commenters allege that the far higher
percentage of FBCs in the top 40 leads
to the conclusion that these units are
different from conventional PCs with
regard to Hg emissions and, as a result,
should have been placed in their own
subcategory. Further, commenters noted
that the largest FBC has a nameplate
capacity of about 300 MW while the
largest conventional boilers have
nameplate capacities of around 1,300
MW.
The commenters stated that FBCs
combust relatively large coal particles in
a bed of sorbent or inert material at a
lower degree of combustion efficiency.
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Fluidized bed units operate at less than
half of the temperature of a
conventional boiler and have much
longer fuel residence times.
Conventional boilers pulverize coal to a
very fine particle size to maximize
combustion efficiency and minimize
unburned carbon. As a result, the
commenters noted that FBCs typically
have higher levels of unburned carbon
present in the ash, which behaves much
like activated carbon and helps promote
more efficient Hg removal. Accordingly,
commenters maintain that Hg emissions
of FBC boilers and PC boilers are
statistically different, with emissions
from FBCs significantly lower than
those from PC boilers. According to
commenters, this statistically significant
difference in the Hg emissions profiles
for these two distinct boiler
technologies argues in favor of the
creation of a separate subcategory for
FBCs, as there is no control technology
that PCs could install that would result
in emissions reductions similar to those
achieved by FBCs. The active quantity
of calcium oxide (lime-CaO) available in
a FBC boiler is also orders-of-magnitude
greater than compared to a PC boiler,
whose alkalinity is derived solely from
the coal’s mineral content. Significantly
higher CaO can alter the process
chemistry in the boiler, including the
oxidation levels of Hg.
One commenter stated that the EPA
properly declined to subcategorize units
based on design type where there is no
indication that any physical distinctions
among unit designs have a meaningful
and substantial impact on HAP
emissions. The commenter indicated
that it would be inappropriate to
subcategorize FBCs because there is no
evidence to support a determination
that FBC design is responsible for a unit
falling in or out of the top 12 percent for
a particular HAP.
Response: The EPA acknowledges
that there are design and operation
differences between conventional PCfired EGUs and FBC/CFB EGUS;
however, the commenters are incorrect
in asserting that the HAP emissions
levels and characteristics are
sufficiently distinct from other coalfired EGUs to support subcategorization.
Further, commenters fail to note that
FBC EGUs were not subcategorized in
CAMR even though, as commenters
note, such design and operation
differences were cited there. The fact
that FBC units operate at lower
temperatures is of no consequence as
they still operate at temperatures high
enough to vaporize Hg.
Commenters assert that FBC units are
disproportionately represented among
the best performers, with the inference
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being that they were selected to test in
the 2010 ICR because of their boiler
design. However, FBC EGUs were not
specifically selected as best performers
for Hg, as EPA did not select any EGUs
based on a determination that they were
best performers for Hg (as noted
elsewhere, we had no basis for selecting
EGUs as being best performers for Hg),
and to the extent CFB units were
selected in the 2010 ICR, they were
selected because we determined they
were best performers for non-mercury
metallic HAP, acid gas HAP, or organic
HAP or because they were randomly
selected among the non-best performers
for those three HAP groupings. Thus,
the CFBs were selected for testing under
the 2010 ICR based not on their boiler
design but, rather, based on the age and
on their PM and FGD control systems
(as noted in the Supporting Statement
for the 2010 ICR). As many FBC EGUs,
including CFB EGUs, are relatively new,
they were included in the non-mercury
metallic HAP group selected for testing
(because their PM controls were among
the 175 newest), the acid gas HAP group
selected for testing (because FBC was
considered to be an FGD system and the
units were among the 175 newest), and
organic HAP testing (because they were
among the newest and, thus, determined
to be among the most efficient).
The effect on Hg emissions is not
what commenters suggest because,
although, as noted by commenters, FBC
units may be found among the better
performers (among the top 10 EGUs) on
the Hg MACT floor spreadsheet, they
are also found in the range of 221 to 226
EGUs (of 393 data points). The fact that
FBC units have ‘‘vastly dissimilar ash
properties’’ that may contain higher
levels of lime or unburned carbon in the
fly ash than conventional PC EGUs does
not indicate that the overall system
behaves any differently with regard to
emissions to the atmosphere (the key
metric) than a conventional PC EGU
with add-on controls. The asserted
higher levels of unburned carbon result
in a range of effectiveness of Hg control
that is similar to that of ACI found on
PC EGUs; such ACI control may be
found on EGUs that are among the better
performers as well as on EGUs as low
as 369 on the list of data points. Thus,
the EPA disagrees that FBC units are
disproportionately represented in the
Hg floor and that their inclusion is
somehow inappropriate or leads to
skewing of the analysis.
All types of coal-fired EGUs other
than those we subcategorized are
represented in the MACT floors for Hg
and all types of EGUs are represented in
the floors for the non-mercury HAP.
Fluidized bed combustion EGUs are not
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9397
an exception and such EGUs are found
across the range of top performing EGUs
for all of the HAP categories: Acid gas,
non-mercury metallic, and Hg. In
addition, any assertion that non-FBC
EGUs are unable to meet the final
standards because FBC EGUs are
included in the same subcategory (or
vice versa) is plainly refuted by the fact
that EGUs of all types are currently
meeting one or more of the final
standards. Thus, the EPA finds no basis
for subcategorizing FBC EGUs.
Further, as noted below, the EPA does
not believe there is a basis for
subcategorizing small EGUs, either FBC
or PC. In addition, the data have been
re-evaluated based on comments
received and an FBC unit is not the
basis for the new source Hg MACT floor.
Comment: Many commenters stated
that the EPA should have considered
additional subcategorization schemes,
including one based on EGU size.
Commenters noted that one of the
factors that the Administrator can
consider under CAA section 112(d)(1) in
making subcategorization decisions is
unit size. Commenters stated that an
analysis of the 2010 ICR data showed a
statistical difference between EGUs with
a capacity of 100 MW or less and EGUs
above 100 MW; other commenters
suggested that the cut-off range should
be 125 MW. Although large in number
(about 27 percent) of all EGUs, these
small EGUs only comprise about 5
percent of the coal-fired capacity in the
U.S. Thus, commenters assert that if
different MACT limits are set for this
subcategory of EGUs, it will not have a
significant impact on the health effects
of HAP emissions. Commenters noted
that although emission rates from such
small EGUs are greater than those found
in the large unit fleet, their contribution
to the total EGU emissions is not
significant. The costs associated with
coming into compliance with the
proposed rule by installing new controls
would be proportionally much higher
for these small EGUs than larger EGUs
according to the commenters. The
commenters allege that this would force
the retirement of generation capacity
and threaten electrical reliability
without appreciable benefit to the
environment.
One commenter stated that in general,
the nature of many public power
facilities differs from the general
population of coal-fired power plants.
Public power units tend to be smaller in
size, and are often space-constrained by
growth in the community surrounding
the generating unit since its initial
construction. These limitations restrict
the ability of these EGUs to achieve the
same performance levels of larger,
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unconstrained EGUs; and, for those
EGUs that can comply with the
proposed standards, the installation of
controls sharply increases the cost of
compliance. The commenter stated that
the EPA did not adequately
subcategorize to accommodate many
small- and medium-sized public power
utilities. In particular, the EPA did not
avail itself of the opportunity to use a
public power electric utility
subcategory, rural subcategory, or fuel
type subcategories. Other commenters
endorsed the establishment of a less
than 100 MW subcategory that would
reduce the costs of the proposed rule
significantly, but only affect 5 percent of
the total electric utility sector, and help
minimize retirement of uneconomical
plants.
One commenter stated that the EPA
properly recognized that subcategories
based on unit size would be
inappropriate because the proposed
emission limits are in terms of lb/
MMBtu or lb/TBtu and noting that an
EGU’s total nameplate capacity is
wholly unrelated to its ability to achieve
the proposed limits. Another
commenter opposed any proposal to
subcategorize units below 100 MW. The
proposed rule does not apply to units
less than or equal to 25 MW, and this
commenter believed that this is a
sufficient threshold for applicability.
One commenter stated that the EPA
could establish subcategories for the
purpose of temporarily exempting, for
example, a subcategory of utilities that
meet the definition of small entity for
purposes of the proposed rule. The
temporary exemption would sunset on a
date certain (e.g., 3 years from the
effective date of the rule) at which point
the sources in the subcategory would
become subject to the rule, and a
compliance timetable would start to
run. The commenter believed that this
time-staged promulgation and
compliance proposal would greatly
increase the chance that the control
measures could be added in an orderly
and efficient manner with minimal
disruption to power markets and grid
reliability.
Response: The EPA agrees with
commenters who stated that an EGU’s
size is totally unrelated to its ability to
comply with the final concentrationbased limits. The EPA examined the
size of units within the respective
MACT floor pools of sources and found
units ranging in size from 25 to 1,320
MW in the HCl floor pool, from 25 to
869 MW in the non-mercury metallic
floor pool, and from 47 to 544 MW in
the Hg floor pool. Thus, we find no
more difference between a 25 MW EGU
and (e.g.) a 500 MW EGU than we do
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between a 500 MW EGU and a 1,300
MW EGU and reaffirm our position that
the MW capacity of the EGU is not a
determining factor in its emissions.
Further, the EPA believes that units of
all sizes are owned by both large and
small entities.
The EPA examined the effect if EGUs
less than 125 MW were subcategorized
for Hg. The resultant MACT floor for
these EGUs would be 1.0 lb/TBtu on a
30-boiler operating day rolling average,
a level more stringent than that
developed for the >8,300 Btu
subcategory as a whole. We do not
believe that this is what commenters
envisioned when suggesting such a
subcategory but we believe it confirms
our analysis of the data that indicates,
as noted, these units are controlled in
the same manner as other, larger EGUs,
such that additional subcategorization is
not necessary or reasonable. Further,
based on the number of EGUs less than
125 MW in the HCl and PM MACT floor
pools, we believe that a similar analysis
for HCl and PM would lead to similar
or more stringent standards than
without the additional subcategory.
Thus, units of all sizes are capable of
achieving the proposed limits and the
EPA is not finalizing a subcategory
based on unit size in the final rule.
The CAA authorizes EPA to
subcategorize based on ‘‘classes, types,
and sizes of sources.’’ The EPA does not
believe that this provision permits
subcategorizing sources based solely on
their status as small entities for several
reasons. As a threshold matter,
commenters provided no information to
suggest that EGUs at small entities are
different from EGUs owned by other
entities. Instead, the commenters’
justification for such a subcategory was
that the costs to comply with the
standards make it more difficult for
small entities; thus, the basis is
essentially a cost basis and we do not
think that is consistent with the statute.
Moreover, the legislative history of CAA
section 112(d) supports EPA’s
interpretation that subcategories cannot
be based on the cost of compliance. See
S. Rep No. 101–228 at 166–67 (5
Legislative History at 8506–07)
(rejecting the implication that separate
categories could be based on ‘‘assertions
of extraordinary economic effects’’).
In addition, the EGUs owned by small
entities use the same type of fuel as
other units, have the same type of
combustor designs, and can use the
same types of controls, and so there is
no difference in the HAP emissions
from such units. So, even if we believed
a subcategory based on small entities
was consistent with the statute, we
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would decline to include such a
subcategory.
Therefore, given the language of CAA
section 112(d), the legislative history,
and the available information, EPA is
not creating a separate subcategory for
EGUs owned by small entities.
In addition, the D.C. Circuit has
clearly stated that the EPA does not
have the statutory authority under CAA
section 112 to extend compliance dates
past the 3-year maximum compliance
time authorized in CAA section
112(i)(3)(A) except consistent with CAA
sections 112(i)(3)(B) and 112(i)(4). See
NRDC v. EPA, 489 F.3d 1364, 1374 (D.C.
Cir. 2007) (finding that ‘‘Congress
enumerated specific exceptions to the 3year maximum, which indicates that
Congress has spoken on the question
and has not provided the EPA with
authority under subsection 112(i)(3)(B)
to extend the compliance date * * *’’)
(citing also CAA section 112(i)(4)). The
EPA may not alter the compliance date
based on size or ownership
considerations and, thus, we are not
providing a separate compliance date
for different groups of EGUs in the final
rule.
Comment: One commenter stated that
the EPA should establish a subcategory
consisting of EGUs that had received air
construction permits but had not yet
commenced construction as of the date
of the EPA’s proposed rule. The
commenter believed that such a
category would be justified because a
substantial amount of time, money, and
effort has been invested in these units.
The commenter asserted that imposing
new source standards on these EGUs for
which the EPA’s proposed rule had not
been anticipated during their permit
consideration would unreasonably and
arbitrarily impose additional costs and
burdens on these projects and would
likely threaten the viability of many of
them. The standards for this subcategory
would be based on the anticipated
performance of these units (as reflected
by the permitted case-by-case emission
levels), ensuring a reasonable and
appropriate level of HAP control
without unreasonably and arbitrarily
interfering with the development of
these units.
Response: Clean Air Act section
112(a)(4) defines a new source as ‘‘a
stationary source the construction or
reconstruction of which is commenced
after the Administrator first proposes
regulations under this section
establishing an emission standard
applicable to such source.’’ The EPA’s
regulations implementing the CAA
section 112 General Provisions define
‘‘commenced’’ to mean ‘‘with respect to
construction or reconstruction of an
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affected source, that an owner or
operator has undertaken a continuous
program of construction or
reconstruction or that an owner or
operator has entered into a contractual
obligation to undertake and complete,
within a reasonable time, a continuous
program of construction or
reconstruction.’’ See 40 CFR 63.2.
The EPA is constrained by the
definition of ‘‘new source’’ such that
any source that ‘‘commenced’’
construction after the May 3, 2011,
proposal date is considered a new
source under the statute and the source
must comply with the new source
standards even if the source received a
final and legally effective CAA section
112(g) permit before proposal. It is
unclear from the comments whether the
sources identified in the comments have
commenced construction as defined in
the regulations; however, the identified
sources are existing sources, not new
sources, under the final rule if
construction was commenced prior to
the proposal date.
Under the final rule, new sources
must comply with the standards on the
date of promulgation or at startup,
whichever is earlier, and existing
sources have 3 years to come into
compliance with the final standards.
Pursuant to the EPA’s regulations at 40
CFR 63.44(b)(1), however, we may
provide in a final CAA section 112(d)
standard a specific compliance date for
those sources that obtained a final and
legally effective CAA section 112(g)
case-by-case MACT standard and
submitted the information required by
40 CFR 63.43 to the Agency before the
close of the comment period. The EPA
does not believe it has received such
information during the comment period
and we are not establishing a separate
specific compliance period for sources
that obtained final and legally effective
CAA section 112(g) standards prior to
promulgation of the final rule. In the
absence of EPA action on this issue,
state Title V permitting authorities are
required to ‘‘establish a compliance date
in the [title V] permit that assures that
the owner or operator shall comply with
the promulgated standard [ ] as
expeditiously as practicable, but not
longer than 8 years after such standard
is promulgated * * *’’ 40 CFR
63.44(b)(2). Sources with final and
legally effective section 112(g) standards
should work with their permitting
authorities to determine the appropriate
compliance date consistent with the
EPA regulations.
Comment: One commenter stated that
in accordance with CAA section
112(d)(l), based on the government-togovernment relationship of the Navajo
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Nation and the U.S. government, and
consistent with the right of sovereignty
and self-determination of the Navajo
Nation, it may be appropriate to classify
EGUs on tribal lands in a different
subcategory from those on non-Indian
lands. The commenter stated that in
accordance with the distinctive status of
Indian lands, based on principles of
tribal sovereignty and selfdetermination, the government-togovernment relationship, and the
flexibility of federal agencies mandated
under E.O. 13175, the EPA should
classify sources on tribal lands as a
unique subcategory of EGUs for which
emission standards for NESHAP should
be set pursuant to CAA section
112(d)(3).
Response: Pursuant to CAA section
112(d)(1), the EPA may subcategorize
sources based on differences in class,
type, or size. In the preamble to the
proposed rule, the EPA further explains
that any basis for subcategorizing (e.g.,
class) must be related to an effect on
emissions, rather than some difference
which does not affect emissions
performance. The EPA does not agree
that a subcategory based on location on
Tribal lands is consistent with the
statutory authority to subcategorize, and
commenters do not explain why
emissions would be different for EGUs
located on Tribal lands. Absent that
showing, EPA believes it would not be
appropriate to subcategorize units even
if we believed such a subcategory is
consistent with the statute. CAA section
112 imposes specific requirements with
respect to the methodology that the EPA
must use in establishing emission
standards for HAP, including Hg
emissions from EGUs. Pursuant to CAA
section 112(d)(1), the EPA may
subcategorize sources based on
differences in class, type, or size. The
EPA believes, that any basis for
subcategorizing (e.g., class) must be
related to an effect on emissions, rather
than some difference which does not
affect emissions performance.
However, the EPA is sensitive to the
commenters’ concerns and particularly
recognizes the significance of Navajo
Generating Station to the Central
Arizona Project and the water delivery
to tribes. As a result, EPA has been
consulting with affected Indian tribes
and working closely with other federal
agencies, including the Department of
the Interior, on these issues and intends
to work with tribal and other authorities
to ensure a smooth transition and
address specific issues as they arise.
2. Oil Subcategories
Comment: Several commenters stated
that distillate oil, and in particular ultra-
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low sulfur diesel (ULSD) oil, has fuel
characteristics closer to that of pipeline
gas than to residual oils. The metals, as
well as the ash and nitrogen content, of
distillate oils are very low, and the
sulfur content of ULSD is approximately
the same as that of pipeline natural gas.
The commenters state that distillate oil
is a more refined product than residual
oil and, thus, burns cleaner. According
to commenters, separating liquid oilfired EGUs into two subcategories
(distillate and residual oil) would be
consistent with the discussion of
subcategory differentiation in the rule’s
preamble which indicates that the
division of a category into subcategories
is justified if the two subcategories have
very different emissions, which is true
for distillate vs. residual oils. Distillate
and residual oils are also differentiated
by their operating requirements. Some
commenters stated that as a
consequence of the mechanical
differences between boilers designed for
residual oil vs. distillate oils, and
between the fuel-handling requirements
for the different fuels, it is not possible
to interchange oil types without
significant modifications to the oil
storage tanks, transfer pumps, piping
and valves, flow control systems,
burners, and burner control systems.
Commenters also noted that some of the
EGUs in the EPA’s liquid oil-fired
database were mischaracterized with
regard to the type of oil burned during
the 2010 ICR testing.
Some commenters alleged that by
combining distillate and residual oil
into a single MACT category, the
resultant MACT standards cannot be
satisfied by a boiler firing residual oil
without substantial add-on controls.
The commenters asserted that creation
of separate subcategories for liquid oilfired units that distinguish between
residual and distilled oil would render
the standards more achievable for
distinct subcategories of EGUs and
reduce the number of potential plant
closures while still advancing the goal
of reducing overall emissions. These
commenters contend that MACT floors
should not be used to eliminate whole
classes of existing EGUs through
mathematical floor calculations based
on data from uncontrolled units and
combining boiler subcategories that are
not capable of accommodating a
different fuel.
One commenter stated that the EPA
should not subcategorize liquid oil-fired
EGUs based upon different grades of
liquid oil. Although different grades of
liquid oil may vary in their heat
contents or viscosities, the commenter
maintained that there is no indication in
the rulemaking record that any physical
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distinction among units burning
different grades of liquid oil affects the
nature or characteristics of emissions in
a way that impacts the availability of
controls. According to the commenter,
both distillate and residual oil-fired
units can apply similar control
technologies to reduce HAP emissions,
and EGUs firing these fuels do not have
physical distinctions that prevent
controls from operating effectively. The
commenter believes that fuel switching
is an appropriate control technology and
is available for liquid oil-fired sources.
Residual fuel oil contains higher levels
of contaminants, including HAP, than
distillate oil, and because a regulated
entity can readily burn cleaner distillate
oil in lieu of residual oil, it is
inappropriate to subcategorize based on
the distillation fraction of the liquid oil.
Thus, according to the commenter, the
grade of liquid-oil fuel does not provide
a reasonable basis for subcategorizing
various groups of liquid oil-fired EGUs.
Another commenter alleges that the EPA
did not list distillate oil-fired EGUs in
the 2000 Finding.
Response: The EPA has reviewed the
data and determined that it is not
necessary to subcategorize distillate vs.
residual oil. Commenters had noted that
the EPA’s MACT Floor Analysis
spreadsheet at proposal had erroneously
assigned the oil type used during testing
for some boilers. The EPA reviewed the
data and determined that the submitting
companies had entered the data
incorrectly, or had indicated that two
types of oil were fired in different parts
of the 2010 ICR responses. The EPA
contacted all of the companies with oilfired EGUs in the 2010 ICR to confirm
the oil used during testing. Upon review
of these data, it became apparent that
units using residual oil with ESPs or
distillate oil without control were the
best-performing oil-fired EGUs for PM
and the HAP metals. Further, although
emissions of HAP from distillate oilfired EGUs are generally lower than
those from residual oil-fired EGUs,
EGUs burning distillate oil appeared to
have higher emissions of some HAP but
lower emissions of others.
In addition, the EPA does not agree
that distillate oil-fired EGUs were not
listed in the 2000 Finding. We believe
it is inappropriate to exclude distillate
oil-fired EGUs from regulation under the
final rule because the Agency did not
make a distinction when listing the oilfired units.
The EPA also disagrees with
commenters that by providing the
distillate vs. residual oil subcategories
as requested, the resultant standards
would be more achievable. Were the
EPA to subcategorize distillate oil from
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residual oil, the users of distillate oil
would have no means of compliance
other than obtaining ‘‘compliance’’ oil
from their distributor (which was not
indicated as an option by any
commenter) or converting to natural gas
and being removed from the
subcategory. With no further
subcategorization, oil-fired EGUs have
the option of installing an ESP or
converting to distillate oil for
compliance. Commenters did not
contend that it was impossible to
convert to distillate oil, only that it
would require plant modifications.
Installing controls would also require
plant modifications so sources will be
able to evaluate the options and
determine the most cost-effective option
to comply with the final rule. CAA
section 112 is intended to be a
technology-forcing statute, and, because
both distillate oil- and residual oil-fired
EGUs were among the best performing
sources in the floor and both types are
meeting the final standards, we cannot
reasonably conclude that the HAP
emissions characteristics of these
similar types of units are distinct.
Therefore, the EPA is not establishing
separate subcategories for distillate and
residual oil-fired units in the final rule.
3. Limited-Use Subcategory
Comment: Several commenters stated
that EPA should establish a limited-use
subcategory for liquid oil-fired EGUs
that are required to burn oil during
periods of natural gas curtailment. One
commenter stated that under New York
State Reliability Council Rules, their
facility is required by the New York
Independent System Operator (NYISO),
for reliability purposes, to maintain the
capability to burn oil and actually burn
oil, from time to time, at varying load
levels to help avoid or avert potential
natural gas shortages in New York City.
The requirements to burn oil under this
program are mandatory and are not
within the commenter’s discretion. The
reliability rules require that the
commenter’s EGUs maintain their cofiring capability to respond to
unplanned, emergency scenarios by
operating on oil during required
minimum oil burn periods, typically 25
percent oil/75 percent natural gas. The
commenter noted that operation using
oil at other times or on 100 percent oil
during reliability operation periods
occurs very infrequently; with natural
gas expected to become more available
in future years, such an operating
scenario will become less likely.
However, while the reliability rules
remain in place and commenter’s
boilers are required to operate under his
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regimen, the commenter believed that it
is essential that it be able to do so.
Other commenters noted that
requiring installation of emission
controls on oil-fired units that operate at
a 10 percent oil-fired capacity factor or
less is nonsensical and will result in
little environmental benefit.
Commenters contend that low-capacity
factor units emit significantly less HAP
than even well-controlled oil-fired units
with much higher capacity factors. In
addition, commenters allege that stacktesting at such units would be equally
impractical and, in addition, would
likely require the unit to operate on oil
(and emit HAP just for the test) when it
would otherwise be off-line or operating
on natural gas.
Response: As stated above, after
considering comments received, we are
establishing a limited-use subcategory
for liquid oil-fired EGUs with an annual
fired capacity factor of less than 8
percent averaged over each 24-month
block period after the compliance date.
At proposal, we solicited comment on
establishing a limited-use subcategory
for liquid oil-fired EGUs:
EPA is also considering a limited-use
subcategory to account for liquid oil-fired
units that only operate a limited amount of
time per year on oil and are inoperative the
remainder of the year. Such units could have
specific emission limitations, reduced
monitoring requirements (limited operation
may preclude the ability to conduct stack
testing), or be held to the same emission
limitations (which could be met through fuel
sampling) as other liquid oil-fired units. EPA
solicits comment on all of these proposed
subcategorization approaches.
As stated above, the EPA did not have
sufficient information on limited-use
liquid oil-fired EGUs upon which to
base a subcategory at proposal. Some
sources required to test under the ICR
did not submit the data until after
proposal. Commenters indicated that
their units are different because many of
them are only called to service to
address reliability issues associated
with, for example, natural gas
curtailments. The commenters further
indicated that their units are different
because of the generally infrequent use
and the sporadic, and at times frequent,
start-up and shutdown periods (e.g.,
they are often only required to run for
a couple of hours). These factors would
lead to differences in the emissions
characteristics for these units such that
a numeric standard based on base load
units would not likely be achievable
during the very limited times that these
limited use oil-fired units operate.
Based on comments received and our
own analysis, we are finalizing a
subcategory for limited-use liquid oil-
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fired EGUs as indicated elsewhere in
this preamble. We find that these units
constitute a different class and type of
units because they are generally only
used to address reliability issues
associated with, for example, natural gas
curtailments, and because they in fact
only run for very limited periods in a
year on a seasonal basis.
Although some commenters indicated
a prevalence of natural gas/oil co-fired
EGUs, the EPA also understands that
there are other liquid oil-fired EGUs that
do not co-fire natural gas but that could
be subject to mandatory operation
during periods of natural gas
curtailment in their operating area if
sufficient non-natural gas capacity is not
available. Based on a review of units
that report oil use to EPA, in 2010 there
were 228 liquid oil-fired EGUs with a
capacity factor of less than 5 percent
and an additional 10 units with a
capacity factor of between 5 percent and
10 percent. Only 2 of these units have
capacity factors between 5 percent and
8 percent. This subcategory applies only
to oil-fired EGUs that operate on oil
alone and act as peaking units, as they
generally address reliability issues. We
are establishing the capacity factor
threshold of 8 percent averaged over
each 24-month block period after the
compliance date.320 In addition, as
discussed below, we are establishing
work practice standard for this
subcategory in lieu of numeric emission
standards.
Commenters that requested a
subcategory for these units noted the
dichotomy of establishing a NESHAP to
reduce emissions of HAP to the
environment while at the same time
requiring an EGU to run for the sole
purpose of conducting emissions testing
and thereby emitting those same HAP.
Because the operation of these units is
infrequent and unpredictable,
performing testing to demonstrate that
emission limits are being met requires
the sources to be scheduled to be
operated merely for the purpose of
performing testing. We realize that
similar situations occurred in the
gathering of emissions data through the
2010 ICR. However, unlike the case of
one-time testing on a limited number of
these units, such testing would be
mandatory on a yearly basis for all of
the EGUs upon the effective date of the
final rule. Because requiring testing
under this rule would in many cases
require operators of these EGUs to
schedule operation of these EGUs at
320 Units that co-fire oil and natural gas where the
oil combustion comprises 10 percent or less of the
capacity factor are natural gas-fired EGUs that are
not subject to this final rule.
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times they would not otherwise run, it
would result in both extra cost related
to the testing as well as extra emissions;
therefore, the Agency believes that it is
technically and economically
impracticable to monitor emissions for
these EGUs, and that they should be
subject to work practice standards that
would not require emissions
monitoring.
The annual average capacity factor
would be calculated on a 24-month
block period, commencing with the
compliance date of the final rule. For
example, assuming a March 1, 2015,
compliance date, the first 24-month
block would commence on March 1,
2015, and end on February 28, 2017,
with the next 24-month block averaging
period commencing on March 1, 2017.
We believe the 24-month averaging
period is reasonable to account for the
fact that units needed to address
reliability issues (e.g., natural gas
curtailment periods) will be called to
service sporadically. A 24-month
averaging period provides flexibility to
ensure that these units can run if there
are large periods when natural gas is
unavailable. As explained above, the
data shows that most of these units
operate for less than 8 percent of the
time, and in fact it is usually less than
5 percent. Therefore, when considering
whether these units would be able to
perform stack testing, in many cases this
will be for units that in fact operate
significantly less than 8 percent of the
time. In these cases, the EPA does not
want to require the units to operate
more just for the purpose of running a
stack test resulting in additional
pollution and cost. With projections for
rising oil prices relative to natural gas
prices, we expect this trend to continue.
Liquid oil-fired EGUs subject to this
subcategory would be required to
conduct the same initial and periodic
tune-up as all other affected units, but
would have no other emission limit or
work practice requirements.
Although the EPA believes that the
ability to burn oil up to 8 percent of the
time should address concerns about
units that may need to operate using oil
during gas curtailments. The EPA
recognizes that if there were a period
where gas use was more severely
limited, such units might need the
flexibility to operate for more than 8
percent in one year and less in the next,
which is why we are providing the 2year period; however based on the data
we do not think EGUs in this
subcategory will exceed even the 5
percent capacity factor that the data
indicate is the average level for these
sources.
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4. Non-Continental Units
Comment: Commenters from affected
island EGUs requested that noncontinental EGUs be subcategorized
from continental EGUs based on their
lack of access to natural gas. The
commenters urged the EPA to include a
‘‘non-continental liquid oil’’
subcategory in the final rule. According
to the commenters, establishing a
subcategory for non-continental units is
consistent with the approach the EPA
has taken in past rulemakings, including
the final Industrial Boiler NESHAP.
Non-continental EGUs have little or no
access to natural gas, minimal control
over the quality of available fuel, and
disproportionately high operational and
maintenance costs. All oil-fired EGUs
operating in Hawaii, Guam, and Puerto
Rico combust residual fuel oil
exclusively and all are limited by the
crude slates of their fuel suppliers.
Island utilities can contract with
suppliers for certain fuel specifications,
such as sulfur content, pour point, flash
point, API gravity and viscosity, which
the refiners are able to meet primarily
by blending and some sulfur removal
during the refining process. However,
the commenters state that the suppliers
do not and cannot economically control
for metal content. The crude slate
feeding the refinery determines the HAP
metal content of the residual oil
produced according to the commenters.
Because island utilities are dependent
on local sources of fuel, they are equally
limited by these factors.
Two commenters believe that the
separate non-continental subcategory
should be expanded to include
continental areas that are not
interconnected with other utilities and
have limited compliance options due to
remote locations (e.g., Alaska).
Response: The EPA agrees that the
unique considerations faced by noncontinental EGUs warrant a separate
subcategory for these units and the data
show that the difference in location
causes a difference in emissions
apparently due to the fuel that is
available for such units; thus, the
Agency has included such a subcategory
in the final rule. At proposal, the EPA
did not have all of the data from liquid
oil-fired units in non-continental areas
(e.g., Guam, Puerto Rico) and solicited
comment on whether a subcategory
should be established, based on the data
to be received, for non-continental oilfired EGUs. The EPA has now received
these late data and, based on those data,
is finalizing a non-continental
subcategory for liquid oil-fired EGUs in
Guam, Hawaii, Puerto Rico, and the U.S.
Virgin Islands. The EPA is not aware of
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any liquid oil-fired EGUs in any of the
other U.S. territories that meet the CAA
section 112(a)(8) definition but, if there
are such units, they would also be part
of the non-continental subcategory.
The EPA agrees that the unique
considerations faced by non-continental
refineries, including a limited ability to
obtain alternative fuels that lead to
different emissions characteristics,
warrant a separate subcategory for these
EGUs. The EPA believes that units in
this subcategory will comply through
the use of cleaner oils or, for PM,
through the installation of an ESP. The
EPA finds no merit in the comment that
Alaska should be included in this noncontinental subcategory because utilities
in Alaska are not faced with the same
access issues affecting island-based
facilities.
C. Surrogacy
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1. Filterable PM vs. Total PM
Comment: Numerous commenters
strongly objected to the use of total PM
as the surrogate standard for nonmercury HAP metals. They argued that
filterable PM is a better surrogate,
especially given EPA’s intent to use a
PM CEMS for continuous compliance
demonstration. Other commenters
argued that we should not use a
surrogate and instead should require
direct compliance with a non-mercury
HAP metals standard.
Response: We have decided to use a
filterable PM limit for the PM surrogate
emission limit in the final rule.
Although the objective of the
emission limits we are establishing is to
reduce the risks associated with HAP
emissions, the limits are based in part
upon the demonstrated capabilities of
control technologies which are installed
on existing sources. Except for Hg, the
best PM controls provide the best
controls of metal emissions. Emissions
measurements of either filterable
particulate, total particulate, individual
metals, or total metals provide
comparable indications that the best
level of control is achieved. We can find
no significant difference in the
emissions that would be achieved by
using any one of these emissions
measurements.
We re-assessed the relationships
between individual metal emissions,
filterable PM emissions, total PM
emissions, and total PM2.5 emissions
based on the test results provided
through part III of the 2010 ICR. We
compared the measured emissions of
metals and PM with the uncontrolled
emissions estimates and found that
control of PM was indicative of the
control of metals emissions. In addition,
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we compared the correlations associated
with non-mercury HAP metal emissions
and the three forms of PM and found
that no specific particulate form
provided a consistently superior
indicator of better metals control.
Although control of filterable PM
provided the best indicator of
performance for control of some HAP
metals, control of total particulate or
total PM2.5 was nearly as good as an
indicator. For control of other HAP
metals, total PM measurement provided
the best indicator of control
performance because it included the
vapor-phase metal HAP, although,
measurement of the control of filterable
particulate was nearly as good an
indicator. In addition, certain data
analyzed by our Office of Research and
Development indicate that a vaporphase metal, such as Se, can be present
as an acid gas and reduced significantly
using acid gas technologies (wet and dry
scrubbing). Given that the rule also
provides for acid gas control
monitoring, and the general equivalency
of the different indicators, we have
concluded that use of a filterable PM
limit as the PM surrogate emission limit
is appropriate.
2. Moisture Content of Oil
Comment: A number of commenters
stated that studies suggest that chloride
in fuel oil can result from contamination
during transportation and processing of
crude oils and then be emitted as HCl
during combustion. For example, the
commenters asserted that the chloride
contamination of crude oils can occur as
a result of the ballasting of tanker ships
with seawater. However, the Oil
Pollution Act of 1990 requires all new
oil tankers to be double hulled and
establishes a phase out schedule (by the
middle of the decade) for existing single
hulled tankers with un-segregated
ballasts. Because of the role of seawater
contamination in introducing
contaminants into the oil, the
commenters suggest that the EPA set a
percent water content limit for fuel oil
at a level of 1.0 percent, rather than
setting HCl and HF emissions limits.
This would encourage handling and
transport practices to limit salt water
contamination. One commenter
recommended a standard of 1.0 percent
water because several of the lowest HCl
and HF emitting units currently require
percent water (or water and sediment)
specifications between 0.5 percent and
1.0 percent.
Response: The EPA is providing the
alternative compliance assurance
approaches in the final rule for liquid
oil-fired EGUs of demonstrating
compliance through either specific HCl
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or HF measurements or by
demonstrating that the moisture content
in the fuel oil remains at a level no more
than 1.0 percent.
The EPA is not aware of any FGD
systems installed on oil-fired EGUs.
Thus, it is only the quality of the oil,
and the level of HAP constituents
contained therein, that can be relied
upon for ensuring compliance.
In the proposal preamble, we stated:
We believe that chlorine may not be a
compound generally expected to be present
in oil. The ICR data that we have received
suggests that in at least some oil, it is in fact
present. EPA requests comment on whether
chlorine would be expected to be a
contaminant in oil and if not, why it is
appearing in the ICR data. To the extent it
would not be expected, we are taking
comment on the appropriateness of an HCl
limit. See 76 FR 25045.
Commenters refer to certain studies
that provide a plausible reason for the
chloride/fluoride contamination of fuel
oils. We found this reason persuasive
and accordingly are providing
alternative compliance approaches in
the final rule to demonstrate compliance
with the acid gas HAP standards.
Specifically, sources can demonstrate
compliance through either specific HCl
or HF measurements or by
demonstrating that the moisture content
in the fuel oil remains at a level no more
than 1.0 percent.
D. Area Sources
Comment: Numerous comments were
received both in support of and in
opposition to the establishment of
generally available control technology
(GACT) standards for area source EGUs.
Several commenters in opposition to
area source standards stated that the
EPA properly established emissions
limitations based upon the performance
of all EGUs, rather than distinguishing
between major sources and area sources.
The commenters believe that Congress
did not intend the EPA to distinguish
between ‘‘major source’’ EGUs and ‘‘area
source’’ EGUs in determining whether
and how to regulate EGUs under CAA
section 112. These commenters
indicated that differentiating major
source and area source EGUs for
purposes of setting emissions standards
is inappropriate in light of the 2000
Finding regarding the threat posed by
the absence of regulation of HAP
emissions from EGUs. The 2000 Finding
was based upon studies whose
conclusions regarding the impacts from
EGU emissions did not depend upon
any relevant distinction between major
source and area source EGUs. The
commenters note that segregating
‘‘major source’’ and ‘‘area source’’ EGUs
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would have the perverse effect of
eliminating some of the best performing
sources from the MACT pool of sources
that constitute the ‘‘best performing’’ 12
percent. Many of the best performing
sources have employed control
technology that brings their emissions
below the major source threshold,
despite the fact that they are larger
units. As a result, the commenters
believe that if the EPA created standards
for ‘‘major source’’ EGUs based only
upon those units, the MACT standards
for ‘‘major source’’ EGUs would be less
stringent for each of the pollutants than
proposed in this Rule. At the same time,
the less polluting sources, the ‘‘area
source’’ EGUs, could face limits more
stringent than those proposed in the
Rule. Commenters also note that after
reviewing the substantial record in this
rulemaking, they believe that the EPA
has correctly determined that major and
area source EGUs greater than 25 MW
have similar HAP emissions and use the
same control technologies and
techniques to reduce HAP emissions.
Thus, the commenters asserted that the
record demonstrates that there is no
technical basis for distinguishing
between major and area source EGUs for
purposes of establishing HAP emission
control standards under CAA section
112(d).
Many commenters in support of an
area source designation for EGUs stated
that the EPA has promulgated area
source limits for many source categories
of HAP emissions, including most
recently industrial boilers and note that
GACT controls have been used
successfully in many other EPA MACT
rules, including rules for iron & steel
foundries, electric arc steelmaking,
coatings operations, clay ceramics
manufacturing, glass manufacturing,
and secondary nonferrous metals
manufacturing, in order to reduce costs
and regulatory burdens. The
commenters state that Congress has
given the EPA the ability to
subcategorize area sources because of
their low HAP emissions and low
potential impact on human health and
that, contrary to the plain language of
CAA section 112 and its legislative
history, the EPA made no attempt in the
proposed rule to distinguish between
major sources and area sources for
purposes of listing or setting standards.
The commenters indicated that where
Congress was concerned about the
health impacts of specific pollutants
from specific sources, it knew how to
specify that MACT limits be
promulgated (e.g., CAA section
112(c)(6)). The commenters state that
area source rules would lessen the
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regulatory burden of a CAA section 112
EGU rule on many small entities
(arguing that many EGUs owned by
small public power entities are area
sources) and that as many as 12 percent
of the EGU population could qualify as
area sources. A number of commenters
pointed out that the small entity
representatives (SER) on the SBREFA
panel suggested that the EPA establish
separate emission standards for EGUs
located at area sources of HAP and that
the standards be based on GACT as
allowed under CAA section 112(d)(5).
Specifically, the SERs recommended
that the EPA establish management
practice standards for area source EGUs.
Response: The EPA is not establishing
an area vs. major source distinction in
the final rule.
The CAA section 112(a)(8) definition
of EGU does not distinguish between
major and area sources, and we
maintain that EGUs are a single source
category that contains both major and
area sources. The EPA proposed to
regulate five subcategories of EGUs
without distinguishing between major
and area sources for purposes of
establishing the standards for the
different subcategories. Our approach is
wholly consistent with the statutory
definition of EGU and reasonable.
Nevertheless, the Agency did examine
whether to set separate standards for
area source EGUs, because we do not
believe that the statute prohibits the
Agency from exercising its discretion to
establish GACT standards for area
sources pursuant to CAA section
112(d)(5) if we determine such
standards are appropriate. The EPA is
not required, however, to establish
GACT standards for area sources, and
we believe it may even be unreasonable
to do so under the circumstances we
identified in the proposed rule as
supported by the record of this final
rule.
At proposal, we determined that it
was not appropriate to establish
separate standards for major and area
source EGUs, and even if we had
exercised our discretion to set separate
standards, we would have likely
declined to exercise our discretion to set
GACT standards for area source EGUs
given our appropriate and necessary
finding and the fact that a potentially
large number of area source EGUs are in
fact large well controlled units.
Some commenters note that there
could be as many as 12 percent of the
total population that could be classified
as area sources. We are not sure of the
commenters’ point in regard to this
statement. As to commenters’
statements that many of the area sources
are municipal utilities, our information
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shows that many rather large EGUs (e.g.,
hundreds of MW) are also area sources,
and the commenters have not provided
any justification for establishing GACT
standards for large synthetic area
sources.
Commenters did not provide an
evaluation of the health and
environmental impacts of the area
sources and simply presume that the
risks from such sources are lower, even
though many of the same commenters
noted that these smaller EGUs are often
located in densely populated areas
where populations are more likely to
have adverse health effects from the
HAP emissions. Furthermore, other
commenters, including some industry
commenters, noted that the vast
majority of these potential area sources
meet the criteria due to the installation
of emission controls installed to meet
other requirements. According to these
commenters, these synthetic area
sources would likely be able to meet the
limits of this rulemaking and imposition
of this rule would not appear to result
in the installation of additional controls
in a number of cases. We do not know
if this assertion is correct but we
determined approximately 69 coal-fired
EGUs will be able to meet the existing
source MACT standards with their
current control configuration (out of 252
EGUs that reported data for Hg, PM, and
HCl in the 2010 ICR).
Commenters also note that the Agency
has exercised its discretion in other
NESHAP rulemakings to establish area
source limits. Although true, the fact
that the EPA has established area source
limits in some source categories is
irrelevant to similar decisions for
different source categories. Commenters
have not shown that the circumstances
applicable to those other source
categories are similar to the
circumstances identified for major and
area source EGUs (e.g., similar controls,
similar emission characteristics, large
number of synthetic minor area
sources). Further, those other source
categories are not statutorily defined in
a manner that includes both area and
major sources. EGUs are the only source
category defined in CAA section 112
and, in establishing the definition of an
‘‘electric utility steam generating unit’’
under CAA section 112(a)(8), Congress
included in the EGU source category
both area and major sources. Thus, it is
reasonable to regulate the EGU category
in the manner Congress defined the
category. Commenters have provided no
legal support for the contention that the
EPA must regulate area and major
sources in the same category in separate
rulemakings, and the EPA has in fact
regulated both major and area sources in
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the same rulemaking even absent a
statutory definition that includes both
major and area sources. (See National
Emission Standards for Hazardous Air
Pollutants From the Portland Cement
Manufacturing Industry and Standards
of Performance for Portland Cement
Plants; 75 FR 54970; September 9,
2010.)
The EPA considered the totality of the
circumstances when determining
whether to set separate area and major
source standards for EGUs and also
considered whether it would be
reasonable to establish GACT standards
for areas sources. We reasonably
considered whether emissions
characteristics of major and area sources
are different when determining whether
to establish GACT standards,
notwithstanding commenters’ assertion
that such consideration is not correct.
That we also consider emission
characteristics in subcategorization
decisions is of no consequence for area
source decisions. Given that the
statutory definition of EGUs contains
both major and area sources, it was
reasonable to evaluate whether there
were sufficient differences between area
and major sources when deciding
whether to exercise our discretion to set
separate area and major source
standards.
In addition, we find commenter’s
point concerning CAA section 112(c)(6)
odd because EGUs emit several of the
CAA section 112(c)(6) HAP (e.g., lead,
Hg). Although EGUs were exempted
from that provision, the fact that they
emit some of the HAP called out for
MACT control supports our decision to
not establish GACT standards for any
EGUs. CAA section 112(d)(5) leaves it to
the Agency’s discretion to determine
whether GACT standards should be
established for area sources, and the
statute does not require GACT standards
or even indicate that such standards are
to be the default regulatory approach for
area sources. See 76 FR 25021. Instead,
the statute provides the Agency with
discretion and we have exercised it
reasonably in this case.
Commenters indicate that many EGUs
owned by small entities are potential
area sources. However, commenters fail
to note that there are also EGUs owned
by small entities that are not potential
area sources, and, thus, would not
accrue any ‘‘lessened regulatory
burden’’ benefit from a decision by the
EPA to establish area source standards.
Some commenters state that the EPA’s
mere assertion that there would be no
difference between GACT and MACT to
justify an area source finding does not
provide sufficient documentation for the
decision. But EPA did not say there
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would be no difference between MACT
and GACT. Instead, it stated that it
would be difficult to make a distinction
given the similarities between the EGUs
and major and area source facilities.
Specifically, as noted by other
commenters, and observable by a review
of the MACT Floor Analysis
spreadsheets, potential area sources
range in size from units near the CAA
section 112(a)(8) defined lower size
limit to units of hundreds of megawatts.
Further, these larger area source units
are, for the most part, controlled with
the full suite of emission control
technologies available (e.g., fabric
filters, scrubbers).
In addition, the data that were
available in the docket for the proposed
rule show that there is little difference
between major and area source EGUs
individually, and that generally the
driver for whether a utility facility is a
major or area source depends on the
number of EGUs located at a facility
(almost exclusively one or two EGUs
located at area sources), not on any
inherent difference between the EGUs
themselves. See ‘‘Evaluation of Area
Source EGUs’’ TSD, Docket EPA–HQ–
OAR–2009–0234. In fact there are a
number of EGUs that are quite large that
are area sources and others that are
small that are major sources. Id. This is
the case because the acid gas HAP
emissions are what drive EGUs to have
HAP emissions exceeding the major
source threshold. With a few
exceptions, the EGUs located at area
sources have FGD or other acid gas
controls that reduce the acid gas HAP to
area source levels. Id. Thus, the majority
of sources that currently qualify as area
sources were, in fact, major sources
prior to installing controls. The
exceptions are those units that would
likely be able to achieve the MACT level
of control for acid gas with minimal use
of DSI at a reasonable cost. Id.
In addition, the data show that a
number of area sources for which we
have data are high emitters of Hg and
non-Hg metal HAP. Id. Pursuant to our
appropriate and necessary finding, these
HAP pose a significant threat to human
health. Thus, even were we to
distinguish between major and area
sources, which we do not believe is
appropriate given the similarities
between such sources, we would still
decline to set GACT standards, and as
such we maintain that MACT standards
are appropriate. Moreover, for acid gas
HAP, as discussed above, the data
indicate that the level of control would
likely be the same even if we did
establish GACT standards under CAA
section 112(d)(5).
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We fully evaluated the nature of
EGUs, and we do not see a basis on
which to distinguish these sources for
purposes of setting standards. Thus, we
maintain that we reasonably exercised
the discretion afforded the Agency
under the statute and declined to set
separate standards for area source EGUs.
E. Health-Based Emission Limits
Comment: Many commenters noted
that in the proposed rule the EPA
considered whether it was appropriate
to exercise its discretionary authority to
establish health-based emission limits
(HBEL) under CAA section 112(d)(4) for
HCl and other acid gases and proposed
not to adopt such limits, citing, among
other things, information gaps regarding
facility-specific emissions of acid gases,
co-located sources of acid gases and
their cumulative impacts, potential
environmental impacts of acid gases,
and the significant co-benefits estimated
from the adoption of the conventional
MACT standard. Comments were
received both supporting this position
and refuting it. Several commenters
suggested legal, regulatory and scientific
reasons for why HBEL for HCl might be
appropriate for this MACT standard.
With respect to legal concerns, some
commenters indicated that CAA section
112(d)(4) establishes a mechanism for
the EPA to exclude facilities from
certain pollution control regulations and
circumstances when these facilities can
demonstrate that emissions do not pose
a health risk. Commenters cited a Senate
Report that influenced development of
CAA section 112(d)(4), where Congress
recognized that, ‘‘For some pollutants a
MACT emissions limitation may be far
more stringent than is necessary to
protect public health and the
environment.’’ (Footnote: S. Rep. No.
101–128 (1990) at 171.) Commenters
also cited regulatory precedent for
addressing HCl as a threshold pollutant,
including the Hazardous Waste
Combustors and the Chemical Recovery
Combustion Sources at Kraft, Soda,
Sulfite, and Stand-Alone Semichemical
Pulp Mills NESHAP. Commenters
requested that the EPA incorporate the
flexibility afforded by CAA section
112(d)(4) and allow sources reasonable
means for demonstrating that their
respective emissions do not warrant
further control. The commenters also
cited the 2004 vacated Boiler MACT as
precedent for HBEL for HCl. The
commenters contended that the EPA
failed to explain why the health-based
emissions limitations it established in
the 2004 Boiler MACT and the
justification provided for those
limitations could not be used in this
case. The commenters also cited a 2006
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court briefing where the EPA vigorously
defended the HBEL included in the
2004 Boiler rule when it was challenged
in the D.C. Circuit (Final Brief For
Respondent U.S. Environmental
Protection Agency, D.C. Cir. Case No.
04–1385 (Dec. 4, 2006) at 59–65, 69).
Other commenters stated that on
August 6, 2010, the EPA adopted a
NESHAP for Portland Cement plants
that specifically rejected adoption of
risk-based exemptions or HBEL for HCl
and manganese (Mn). These
commenters argue there are no
differences sufficient to warrant a
reversal of that decision in the EGU
MACT standard. The commenters raised
concerns that health risk information
cited by the EPA for HCl, HF, and
hydrogen cyanide (HCN) does not
establish ‘‘an ample margin of safety’’
and, therefore, no health threshold
should be established. The commenters
believe risk-based exemptions at levels
less stringent than the MACT floor are
prone to lawsuits that could potentially
further delay implementation of the
EGU MACT.
Some commenters disagreed with
using a hazard quotient (HQ) approach
to establish a risk-based standard
because the HQ would not account for
potential toxicological interactions. The
commenter noted that an HQ approach
incorrectly assumes the different acid
gases affect health through the same
health endpoint, rather than assuming
that the gases interact in an additive
fashion. This commenter suggested that
a hazard index approach, as described
in the EPA’s ‘‘Guideline for the Health
Risk Assessment of Chemical Mixtures,’’
would be more appropriate.
Some commenters dispute that
emissions from other EGUs or source
categories should be considered when
developing an HBEL and they argued
that Congress expected the EPA to
consider the effect of co-located
facilities during the CAA section 112(f)
residual risk program instead of under
CAA section 112(d). Commenters added
that there is no prior EPA precedent for
considering co-located facilities from a
different source category during the
same CAA section 112 rulemaking.
Several commenters disputed the
EPA’s consideration of non-HAP
collateral emissions reductions in
setting MACT standards. They
contended that the EPA’s sole support
for its ‘‘collateral benefits’’ theory is
legislative history—the Senate Report
that accompanied Senate Bill 1630 in
1989 and noted that the D.C. Circuit
rejected this use of this theory since the
Senate Report referred to an earlier
version of the statute that was
ultimately not enacted. Instead
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commenters suggested that other
components of the CAA, such as the
National Ambient Air Quality Standards
(NAAQS), are more appropriate avenues
for mitigating emissions of criteria
pollutants.
Several other commenters suggested it
is impossible to assess an established
health threshold for HCl such that a
CAA section 112(d)(4) standard could
be set without evaluating the collateral
benefits of a MACT standard. And, as
described in the recently finalized
cement kiln MACT rule, setting
technology-based standards for HCl will
result in significant reductions in the
emissions of other pollutants, including
SO2, Hg, and PM. The commenter added
that these reductions will provide
enormous health and environmental
benefits, which would not be
experienced if CAA section 112(d)(4)
standards had been finalized. These
commenters contended that HCl and
other dangerous acid gases produced by
EGUs pose substantial risks to industrial
workers, as well as surrounding
communities, and must be limited by
the strict conventional MACT standards.
Several commenters indicated that the
current economic climate requires the
EPA to balance economic and
environmental interests and indicated
that HBEL would help target
investments into solving true health
threats where limits are no more or less
stringent than needed to protect public
health. Many commenters provided
estimates of compliance cost savings if
an HBEL is included in this final rule.
Some commenters stressed the
importance of an HBEL for small
entities affected by the regulations.
Several other commenters suggested
that the EPA should estimate the costs
and environmental effects of the HBEL
option compared to a conventional
MACT standard in order to make an
informed decision on the adoption of
HBEL.
Response: After considering the
comments received, the EPA has
decided not to adopt an emissions
standard based on its authority under
CAA section 112(d)(4) for all the reasons
set forth in the proposed rule.
The EPA notes that the Agency’s
authority under CAA section 112(d)(4)
is discretionary. That provision states
that the EPA ‘‘may’’ consider
establishing health thresholds when
setting emissions standards under CAA
section 112(d). By the use of the term
‘‘may,’’ Congress clearly intended to
allow the EPA to decide not to consider
a health threshold even for pollutants
which have an established threshold. As
explained in the preamble to the
proposed rule, it is appropriate for the
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EPA to consider relevant factors when
deciding whether to exercise its
discretion under CAA section 112(d)(4),
and, notwithstanding commenters’
assertions to the contrary, the
considerations we include in our
analysis are reasonable. The EPA has
considered the public comments
received and is not adopting an
emissions standard under CAA section
112(d)(4) for the reasons set forth in the
proposed rule and explained below. We
note that this action is consistent with
EPA’s recent decisions not to develop
standards under CAA section 112(d)(4)
for the Industrial, Commercial and
Institutional Boilers and Process Heaters
and the Portland Cement source
categories.
As explained in the preamble to the
proposed rule, the EPA continues to
believe that the potential cumulative
public health and environmental effects
of all acid gas HAP emissions, not just
HCl emissions, from EGUs and other
acid gas sources located near EGUs
supports the Agency’s decision not to
exercise its discretion under CAA
section 112(d)(4). Additional data for all
acid gas emissions were not provided
during the comment period, and the
data already in hand regarding these
emissions are not sufficient to support
the development of emissions standards
for EGUs under CAA section 112(d) that
take into account the health threshold
for acid gas HAP, particularly given that
the Act requires the EPA’s consideration
of health thresholds under CAA section
112(d)(4) to protect public health with
an ample margin of safety. We note here
that EPA agrees with the commenter
who pointed out that a better way to
evaluate the potential health impact
interactions of all acid gases would be
to use the approach in EPA’s ‘‘Guideline
for the Health Risk Assessment of
Chemical Mixtures’’ rather than a
simple evaluation of individual HQ
values for each acid gas, but we further
note that use of such an approach
requires a substantially greater
knowledge of acid gas emissions than is
currently available. We further note
that, even if cost were a relevant factor
in setting standards under CAA section
112(d)(4), since the data are not
available that would allow us to develop
an acid gas HBEL appropriate to protect
public health with an ample margin of
safety, we cannot determine whether
such standards would have any cost
savings associated with them or not. In
addition, the concerns expressed by the
EPA in the proposal regarding the
potential environmental impacts and
the cumulative impacts of acid gases on
public health were not assuaged by the
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comments received because no
significant data regarding these impacts
were received.
The EPA also received comments
recommending not only that the EPA
establish emissions standards for acid
gases pursuant to CAA section
112(d)(4), but that it do so by excluding
specific facilities from complying with
emissions limits if the facility
demonstrates that its emissions do not
pose a health risk. The EPA does not
believe that a plain reading of the
statute supports the establishment of
such an approach. Although CAA
section 112(d)(4) authorizes the EPA to
consider the level of the health
threshold for pollutants which have an
established threshold, that threshold
may be considered ‘‘when establishing
emissions standards under [CAA section
112(d)].’’ Therefore, the EPA must still
establish emissions standards under
CAA section 112(d) even if it chooses to
exercise its discretion to consider an
established health threshold. A sourceby-source standard is not mandated as
some commenters seem to imply, and
we are unsure how we could reasonably
implement such an approach even if we
determined such an approach was
legally available. For these reasons
alone, we concluded it was not
appropriate to exercise our discretion to
establish section 112(d)(4) standards for
acid gas HAP emissions.
In addition, as explained in the
preamble to the proposed rule, the EPA
also considered the co-benefits of setting
a conventional MACT standard for HCl.
The EPA considered the comments
received on this issue and continues to
believe that the estimated co-benefits
are significant and provide an
additional basis for the Administrator to
conclude that it is not appropriate to
exercise her discretion under CAA
section 112(d)(4). The EPA disagrees
with the commenters who stated that it
is not appropriate to consider non-HAP
benefits in deciding whether to invoke
CAA section 112(d)(4). Although MACT
standards may directly regulate only
HAP and not criteria pollutants,
Congress did recognize, in the
legislative history to CAA section
112(d)(4), that MACT standards would
have the collateral benefit of controlling
criteria pollutants as well and viewed
this as an important benefit of the air
toxics program. See S. Rep. No. 101–
228, 101st Cong. 1st sess. at 172. The
EPA consequently does not accept the
argument that it cannot consider
reductions of criteria pollutants in
determining whether to take or not take
certain discretionary actions, such as
whether to adopt an HBEL under CAA
section 112(d)(4). There appears to be
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no valid reason that, in situations where
the EPA has discretion in what type of
standard to adopt, the EPA must ignore
controls which further the health and
environmental outcomes at which CAA
section 112(d) is fundamentally aimed
because such controls not only reduce
HAP emissions but emissions of other
air pollutants as well. Thus, the issue
being addressed is not whether to
regulate non-HAP under CAA section
112(d) or whether to consider other air
quality benefits in setting CAA section
112(d)(2) standards—neither of which
the EPA is doing—but rather whether
EPA may exercise its discretion to
regulate certain HAP based on the
MACT approach and consider collateral
health and environmental benefits when
choosing whether to exercise that
discretion. The EPA believes there is no
legal principle that precludes it from
doing so and commenters have not
provided one.
F. Compliance Date and Reliability
Issues
Comment: Multiple commenters
asked that the compliance date be
clearly stated as soon as possible, as
well as that guidance be provided for
utilities unable to comply with the
stated timelines, to allow time for
utilities to prepare for compliance.
Commenters also asked that any
decisions or policies on extensions be
published in a rulemaking. In addition,
commenters requested that the EPA
establish, streamline, and simplify the
process of applying for the 1-year
extension under CAA section 112(i)(3).
Multiple commenters offered
suggestions on methods for allowing
more time for compliance, including
EPA’s authority under CAA section
112(n)(1)(A); state authority under CAA
section 112(i)(3); Presidential authority
under CAA section 112(i)(4); categorical
extensions for publicly-owned or
governmental facilities according to EO
13132, 13563, and UMRA of 1995; statedesigned programs under the delegation
provisions of CAA section 112; various
Consent Decrees; Administrative Orders
of Consent (AOCs); temporary waiver
mechanisms; and adoption of MACT
compliance schedules through minor
permit modifications of a source’s Title
V federal operating permits. Absent
such considerations for additional
compliance time, many commenters
suggested that the reliability of the
nation’s electric grid would be
jeopardized as utility companies were
forced to retire EGUs because they could
not install the needed controls in the
requisite time.
Compliance times requested by
commenters ranged from 1 additional
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year (4 years total) to 6 additional years
(9 years total). Multiple commenters
requested that a utility be required to
demonstrate good faith progress toward
compliance to get any extension. Some
commenters suggested that the EPA
require utilities to submit a notice
concerning which EGUs will be
retrofitted or retired within 1 year of the
effective date; that the compliance date
align with the Power Year used by
RTOs; and that the EPA clarify that
retirement and any clean replacement
power that complies with the NESHAP
rule, including off-site combined heat
and power and waste heat recovery, can
be deemed ‘‘controls’’ under the CAA.
Commenters noted the specific
situations related to small entities and
their inability to compete with the
larger, investor-owned utilities for
financing and engineering and technical
labor as well as the different process
they need to follow for capital
improvements. Multiple commenters
asked that the EPA consider other
simultaneous rulemakings (e.g., Cooling
Water Intake Structures; Coal
Combustion Residuals; CSAPR, etc.) and
extend the compliance period. Many
commenters noted these other
requirements and suggested that
installation of the necessary controls
could not be completed within the
compliance period allowed under CAA
section 112, even if a fourth year were
to be granted by the permitting
authority, citing examples of the times
necessary for installation of various
pieces of control equipment or
replacement power.
Some commenters pointed to existing
state programs (e.g., Colorado, Oregon,
Washington) and indicated that if states
can demonstrate that overall emissions
reductions would be equivalent or
greater than those that would be
achieved by the proposed rule, the EPA
should delegate the CAA section 112
program to these states, even if the state
emissions reductions would not
necessarily occur on the same schedule
(many state programs call for retirement
of EGUs in years beyond the CAA
section 112 compliance date). The
commenters did not want the
promulgation of the final rule to
undermine the significant amount of
work that may have been invested in
creating state-specific programs to curb
emissions within a reasonable
timeframe. The commenters seek to
make use of temporal flexibility,
authorized under CAA section 112(i)(3),
in obtaining delegation of the final rule
to preserve the hard-negotiated
comprehensive state-specific programs
designed to yield greater emission
reductions than the MATS alone.
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Other commenters requested that no
additional time be granted for
compliance. These commenters
reference a number of reports (e.g., by
the URS Corporation, by M.J. Bradley &
Associates and the Analysis Group, and
by the Bipartisan Policy Center) to
indicate that not only is technology
readily available, but that the
technology can typically be installed in
less than 2 years and that the electric
industry is well-positioned to comply
with the EPA’s proposed air regulations
without threatening electric system
reliability. Commenters assert that, if
electric system reliability were to be
threatened in local areas as a result of
the rule, the EPA has the statutory
authority to grant, on a case-by-case
basis, extensions of time to complete the
installation of pollution control systems.
One commenter stated that no
additional controls would need to be
installed in many cases and any coal
unit should be able to comply with all
of the standards. Another commenter
noted that utilities that failed to plan
ahead ‘‘should not be permitted to use
their own inaction to justify more time.’’
Commenters noted that several major
utility companies have anticipated the
EPA’s rules and are already taking
action to ensure a reliable supply of
electricity in their service territory and
beyond. Other commenters agree that
there is significant excess generation
capacity in the country and reliability
will not be threatened by the rule.
According to one commenter,
companies are already preparing for a
2015 compliance date, factoring in the
capital expenditures required to comply
and delays would undermine decisions
that have already been made.
Commenters cite, for example, recent
electricity forward capacity market
auctions in the PJM market for the
period of 2014 and 2015 that indicate
that the capacity markets cleared with
electricity reserve margins of 20 percent;
this is in excess of the default reliability
targets used by the North American
Electric Reliability Corporation (NERC)
for the year 2015. One commenter
quoted NERC, stating that NERC does
not see impacts from proposed climate
legislation or anticipated EPA regulation
as a reliability concern. Another
commenter noted that the Building and
Construction Division of the AFL–CIO
has stated that there is no evidence to
suggest that the availability of skilled
manpower will constrain pollution
control technology installation. In fact,
according to the commenter, given the
high levels of unemployment in the
construction sector, these jobs are much
needed.
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A number of commenters expressed
concern that the time frame for
compliance with a regulation under
CAA section 112(d) was too short for
this industry and would result in
compromising the reliability of
electricity supply. Commenters asserted
that reliability would be compromised
in several ways: (1) EGUs might have to
temporarily close if the owner or
operator is unable to install controls on
the unit within the 3-year time frame or
3 years plus one; (2) the timing of
outages to install controls will cause
short term closures that could threaten
grid stability; (3) owner/operators may
shut down EGUs rather than invest in
retrofits to keep them running and that
these closures may cause a loss of
critical generation; and (4) the
construction of replacement generation
or implementation of other measures to
address reliability concerns due to plant
retirements could take longer than 3
years, and that units slated for closure
may be necessary beyond the 3-year
compliance period but will be unable to
run because they have not installed the
necessary controls.
Response: Clean Air Act section 112
specifies the dates by which affected
sources must comply with this rule.
New or reconstructed units must be in
compliance immediately upon startup
or the effective date of this rule,
whichever is later. Existing sources may
be provided up to 3 years after the
effective date to comply with the final
rule; if an existing source is unable to
comply within 3 years, a permitting
authority has the ability to grant such a
source up to a 1-year extension, on a
case-by-case basis, if such additional
time is necessary for the installation of
controls.
As is explained earlier in this
preamble, the 3-year compliance
window is based on the date that is 60
days after publication of this rule in the
Federal Register. Because publication
doesn’t occur until several weeks after
the rule is signed by the Administrator,
the earliest required date for compliance
would be sometime in March 2015.
Because the last stage of control
installations usually needs to occur
when the unit is off-line and because
scheduled outages are usually
scheduled for the spring or fall months
when peak electric demand is lower,
this additional time is significant as it
provides companies an additional
outage period, the spring of 2015, to
install controls.
The EPA has considered the concerns
raised by commenters and has
concluded that given the flexibilities
further detailed in this section, the
requirements of the final rule for
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existing sources can be met by most
sources without adversely impacting
electric reliability. In particular, EPA
believes that the flexibility of permitting
authorities to allow a fourth year for
compliance should be available in a
broad range of situations (as discussed
below), and that this flexibility
addresses many of the concerns that
have been raised. Furthermore as
indicated below, in the event that an
isolated, localized concern were to
emerge that could not be addressed
solely through the 1-year extension
under CAA section 112(i)(3), the CAA
provides flexibilities to bring sources
into compliance while maintaining
reliability.
The EPA considered the impact that
potential retirements in response to this
rule will have on resource adequacy in
order to gauge the rule’s impact on
reliability. In considering these impacts,
the EPA considered both the analysis it
has conducted as well as analyses
conducted by a number of other groups.
The EPA’s analysis shows that the
expected retirements of coal-fueled
units as a result of this final rule (4.7
GW) are fewer than was estimated at
proposal and much fewer than some
have predicted.321 The net capacity
reductions projected by the EPA make
up less than one-half of one percent of
the total generating capacity in the U.S.
and about one and one-half percent of
U.S. coal capacity. Because concerns
have been raised that the use of DSI may
not be as prevalent as the Agency has
predicted and because this could lead to
more coal retirements, the Agency also
performed a sensitivity analysis in
which fewer DSI systems and more
scrubber systems were installed. In that
sensitivity, we see approximately 1
more GW of retirements. This small
change would have only a very small
potential impact on resource adequacy.
When considering the impact that one
specific action has on power plant
retirements, it is important to
understand that the economics that
drive retirements are based on multiple
factors including: expected demand for
electricity, the cost of alternative
generation, and the cost of continuing to
generate using an existing unit. The
EPA’s analysis shows that the lower cost
of alternative fuels, particularly natural
gas, as well as reductions in demand,
will have a greater impact on the
321 The EPA’s analysis also identifies a small
amount of capacity loss (less than 0.7 GW) due to
derating of certain units, as well as partially
offsetting reductions in non-coal retirements in
comparison with the base case. The net estimated
reduction in capacity, in comparison with the base
case, is estimated at less than 5 GW.
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number of projected retirements than
will the impact of this final rule.
The EPA’s assessment looked at the
capacity reserve margins in each of 32
subregions in the continental U.S.
Demand forecasts used were based on
EIA projected demand growth. The
analysis shows that with the addition of
very little new capacity, average reserve
margins are significantly higher than
required. The NERC assumes a default
reserve margin of 15 percent while the
average capacity margin seen after
implementation of the policy is nearly
25 percent. Although such an analysis
does not address the potential for more
localized reliability concerns associated
with transmission constraints or the
provision of location-specific ancillary
services (such as voltage support and
black start service), the number of
retirements projected suggests that the
magnitude of any local reliability
concerns should be manageable with
existing tools and processes.
Several outside analyses have reached
conclusions consistent with EPA’s
analysis. The DOE, in December 2011,
published a report that looked at
resource adequacy in the bulk power
system when faced with a stress test
which was a regulatory scenario far
more stringent than EPA’s
regulations.322 For this stress test, in
addition to CSAPR and MATS
requirements, each uncontrolled electric
generator is required to install both a
wet FGD system and a fabric filter to
reduce air toxics emissions. If such
installations are not economically
justified, this scenario assumes that the
plant must retire by 2015. In reality, as
discussed previously, power plant
owners will have multiple other
technology options to comply with the
regulations—options that typically cost
less than installations of FGDs and
fabric filters. The analysis finds that
target reserve margins can be met in all
regions, even under these stringent
assumptions. Moreover, in every region
but one (TRE), no additional new
capacity is needed. In TRE, the analysis
finds that less than 1 GW of new natural
gas capacity would be needed by 2015
beyond the additions already projected
to occur in the Reference Case. This
analysis also finds that the total amount
of new capacity that would be added by
2015 is less than the amount that is
already under development.
In June 2011, the Bipartisan Policy
Center issued a report analyzing
potential collective impacts of EPA’s
pending power sector rules and
322 U.S. Department of Energy, December 2011,
‘‘Resource Adequacy Implications of Forthcoming
EPA Air Quality Regulations.’’
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concluding that ‘‘scenarios in which
electric system reliability is broadly
affected are unlikely to occur.’’ 323
In August 2011, PJM
Interconnection—the Regional
Transmission Operator (RTO)
responsible for planning and reliable
operation of the bulk power system
serving all or portions of 13 states in the
Mid-Atlantic and Midwestern regions—
issued a report analyzing the impacts of
the CSAPR and the proposed MATS
rule.324 Although PJM’s analysis
assumes substantially more retirements
than EPA projects, it nevertheless
concludes that resource adequacy is not
threatened in the PJM region. This is
particularly significant, given that the
PJM region is one of the largest and
most heavily dependent on coal-fueled
generation in the country. The PJM
analysis notes, as EPA has
acknowledged, that even where there is
adequate generation capacity on a
regional basis, localized reliability
issues may emerge in connection with
retirements that may need to be
addressed.
The EPA has reviewed industry and
NERC studies suggesting, contrary to the
EPA’s and these other groups’ analyses,
that EPA rules affecting the power
sector (including this final rule, the
CSAPR, EPA’s proposed rule addressing
power plant cooling water intake
systems under section 316(b) of the
Clean Water Act (CWA), and EPA’s
proposed rule addressing coal
combustion residuals under the
Resource Conservation and Recovery
Act) will result in substantial power
plant retirements. Some of these studies
predict that such levels of retirements
will have adverse effects on electric
reliability in some regions of the
country. Although the specifics of these
analyses differ, in general they share a
number of serious flaws in common that
call their conclusions into question.
First, most of these studies make
assumptions about the requirements of
the EPA rules that are inconsistent with,
and dramatically more expensive than,
the EPA’s actual proposals or final rules.
For example, a large proportion of the
retirements projected by several of these
studies is attributable to their inaccurate
assumption that EPA’s cooling water
intake rule under CWA section 316(b)
would require all or virtually all
existing power plants to install cooling
323 Bipartisan Policy Center, June 2011,
‘‘Environmental Regulation and Electric System
Reliability.’’
324 PJM Interconnection, August 26, 2011, ‘‘ Coal
Capacity at Risk for Retirement in PJM: Potential
Impacts of the Finalized EPA Cross State Air
Pollution Rule and Proposed National Emissions
Standards for Hazardous Air Pollutants.’’
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towers. In one study, the reliability
effects reported are based on inaccurate
assumptions that all existing EGUs with
a capacity utilization factor of less than
35 percent would close, and that all inscope electric generators would be
required to install cooling towers within
5 years, whereas the not-selected
options with closed cycle cooling in
EPA’s proposal envisioned that permit
authorities could exercise discretion to
allow facilities 10 to 15 years’ time to
comply. In most cases, these analyses
were performed before the CWA section
316(b) rule or the MATS rule were even
proposed; even analyses subsequent to
the CWA section 316(b) proposal
continue to inaccurately portray EPA’s
proposed approach.
Second, in reporting the number of
retirements, many analyses fail to
differentiate between plant retirements
attributable to the EPA rules and
retirements of older, smaller, and less
efficient plants that are already
scheduled for retirement because
owners have made business decisions,
based in significant part on market
conditions, not to continue operating
them.
Third, most of these analyses fail to
account for the broad range of responses
available to address electric reliability
concerns associated with power plant
retirements, including upgrades to the
transmission system, construction of
new generation, and implementation of
demand-side measures. These measures
are discussed at greater length below.
As a preliminary matter, none of these
situations, either alone or in
combination, will necessarily lead to an
electric reliability problem. There is
excess generating capacity in the U.S.
today and in most cases an EGU that
closes, either temporarily until it comes
into compliance or permanently, will
not cause a reliability problem. As
explained above, our modeling of the
impact of this final rule at the regional
level projects retirements of less than
one percent of nationwide generating
capacity and confirms that there will
continue to be adequate capacity in all
32 subregions of the country as sources
comply with the rule.325 This analysis
shows that significantly less capacity
will close in response to the final rule
than might have under the proposal.
Moreover, the regional modeling of
retirements demonstrates that plants
that close in response to this rule are
spread out across the country rather
than clustered in one area.
Outside analyses have identified
many of the same flaws in studies
325 See Technical Support Document on Resource
Adequacy in this Docket.
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projecting large-scale retirements as a
result of EPA’s power sector rules. For
example, on August 8, 2011, the
Congressional Research Service
(CRS) 326 issued a report concluded that
studies that assert that EPA rules will
cause reliability problems, often make
assumptions about the requirements of
the rules that are inconsistent with, and
dramatically more expensive than, the
EPA’s actual proposals. The CRS further
noted that EPA’s rules will primarily
affect units that are more than 40-years
old, that have not yet installed state-ofthe-art pollution controls, and that are
inefficient. Many of these plants are
being replaced by combined cycle
natural gas plants, driven more my
lower gas prices than by EPA’s
regulations. The June 2011 Bipartisan
Policy Center report referenced above
likewise highlighted many of these same
shortcomings in the studies in
question.327
Although we do not expect to see any
regional reliability problems, we
acknowledge that there could be
localized reliability issues in some
areas—due to transmission constraints
or location-specific ancillary services
provided by retiring generation—if
utilities and other entities with
responsibility for maintaining electric
reliability do not take actions to mitigate
such issues in a timely fashion. There
are many potential actions that could be
taken to address this problem and
multiple safeguards to assure a reliable
electricity supply.
First, utilities can help to assure
reliability through proactive steps in
coordination with relevant planning and
regulatory authorities. As we said in the
proposal, early planning is key. The
industry has adequate resources to
install the necessary controls and
develop the new capacity that may be
required within the compliance time
provided for in the final rule.328
Although there are a significant number
of controls that need to be installed
across the industry, with proper
planning, we believe that the
compliance schedule established by the
CAA can be met. Many companies have
begun to do the detailed analysis and
engineering and are ahead of others in
their compliance strategy. There are
already tools in place (such as
326 James E. McCarthy and Claudia Copeland,
Congressional Research Service, August 8, 2011,
‘‘EPA’s Regulation of Coal-Fired Power: Is a ‘Train
Wreck’ Coming?’’.
327 Bipartisan Policy Center, June 2011,
‘‘Environmental Regulation and Electric System
Reliability.’’
328 As stated above, EPA has provided the
maximum compliance time authorized under CAA
section 112(i)(3)(A).
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integrated resource planning, and in
some cases, forward auctions for future
generating capacity) that ensure that
companies adequately plan for, and
markets are responsive to, future
requirements such as this final rule.
Second, companies that intend to
retire EGUs should formally notify their
RTO (or comparable planning authority
in the case of non-RTO regions), state
regulatory agencies, and regional
reliability entities as soon as possible of
their compliance plans, particularly
with regard to any planned unit
retirements. As we said before, in most
places a closing plant will not be a
cause for concern for reliability. The
same is true of any outages required for
retrofitting of units with controls. To the
extent there is concern, however, early
notification will provide an opportunity
for transmission planners, market
participants, and state authorities to
develop solutions to avoid a reliability
problem. In RTOs with forward capacity
markets, owner/operators that do not
bid generating capacity that they plan to
shut down will provide an advance
signal to market participants to take
action to assure adequate future
capacity. In all regions, early and public
notification will allow market
participants, planning coordinators and
state authorities, as appropriate and in
a timely fashion, to bring new
generation on line, put demand side
resources in place, and/or complete any
transmission upgrades needed to
circumvent a potential issue. Most RTOs
only require 45 to 120 days notification
of closure. In combined comments to
EPA, 5 RTOs suggested that such
notification should be made no later
than 12 months after this regulation is
final in order to allow a smooth
transitioning to action to avoid a
reliability problem. The EPA strongly
encourages sources to provide notice to
the RTOs as early as possible and
believes that responsible owner/
operators should and will do the early
planning for compliance and provide
early notification of their compliance
plans, especially where such plans
include retiring one or more units.
On the supply side, there are a range
of options including the development of
more centralized power resources
(either base-load or peaking) and/or the
development of cogeneration or
distributed generation. Even with the
current large reserve margins, there are
companies ready to implement supplyside projects quickly. For instance, in
the PJM region, there are over 11,600
MW of capacity that have completed
feasibility and impact studies; the units
representing this capacity could be on-
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9409
line by the third quarter of 2014.329 The
EPA notes, as well, that in the 3 years
from 2001 to 2003, industry brought
over 160 GW of generation on line.330
Demand side options include energy
efficiency as well as demand response
programs. These types of resources can
also be developed very quickly. In 2006,
PJM had less than 2,000 MWs of
capacity in demand side resources.
Within 4 years this capacity nearly
quadrupled to almost 8,000 MW of
capacity.331 In addition to helping
address reliability concerns, reducing
demand through mechanisms such as
energy efficiency and demand side
management practices has many other
benefits. It can reduce the cost of
compliance and has collateral air
quality benefits by reducing emissions
in periods where there are peak air
quality concerns.
With regard to transmission, recent
experience also shows that, in many
cases, transmission upgrades to address
reliability issues from plant closures can
be implemented in less than 3 years. For
instance, when Exelon notified PJM of
its intention to retire four units,332 it
was determined that transmission
upgrades necessary to allow retirement
of two units could be made within 6
months of notification, transmission
upgrades for the third unit would
require slightly over 1 year and
transmission upgrades to allow the
fourth unit to retire could be made in
approximately 18 months.333
The CAA allows CAA Title V
permitting authorities the discretion to
grant extensions to the compliance time
of up to one year if needed for
installation of controls. See CAA section
112(i)(3)(B)). If an existing source is
unable, despite best efforts, to comply
within 3 years, a permitting authority
has the discretion to grant such a source
up to a 1-year extension, on a case-bycase basis, if such additional time is
necessary for the installation of controls.
Id. Permitting authorities should be
familiar with the operation of the 1-year
329 Paul M Sotkiewicz, PJM Interconnection,
Presentation at the Bipartisan Policy Commission
Workshop Series on Environmental Regulation and
Electric System Reliability, Workshop 3: Local,
State, Regional and Federal Solutions, January 19,
2011, Washington, DC, https://
www.bipartisanpolicy.org/sites/default/files/
Paul%20Sotkiewicz-%20Panel%202_0.pdf, slide 6.
330 Form EIA–860 Annual Electric Generator
Report, https://www.eia.gov/cneaf/electricity/page/
eia860.html.
331 BPC slides cited above—slide 5.
332 https://www.exeloncorp.com/Newsroom/pages/
pr_20091202_Generation.aspx?k=eddystone.
333 Cromby Units 1 and 2 and Eddystone Units 1
and 2—Deactivation Study, Updated September 7,
2010—https://policyintegrity.org/documents/
20100907-cromby-and-eddystone-retirement-studyposting-update.pdf.
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extension provision because EPA has
established regulations to implement
the provision and the provision applies
to all NESHAP. See 40 CFR
63.6(i)(4)(A).
We believe that the permitting
authorities have the discretion to use
this extension authority to address a
range of situations in which installation
schedules may take more than 3 years
including: staggering installations for
reliability reasons or other site-specific
challenges that may arise related to
source-specific construction, permitting,
or labor, procurement or resource
challenges. Staggered installation allows
companies to schedule outages at
multiple units so that reliable power can
be provided during these outage
periods. It can also be helpful for
particularly complex retrofits (e.g.,
when controls for one unit need to be
located in an open area needed to
construct controls on another unit). The
additional 1-year extension would
provide an additional two shoulder
periods (i.e., seasons flanking annual
high-demand periods) to schedule
outages, thus enabling owners/operators
to gain the full benefit of staggering
outages in support of complex
installations. The EPA believes that
although most units will be able to fully
comply within 3 years, the fourth year
that permitting authorities are allowed
to grant for installation of controls is an
important flexibility that will address
situations where an extra year is
necessary. That fourth year should be
broadly available to enable a facility
owner to install controls within 4 years
if the 3-year time frame is inadequate for
completing the installation.
As we indicated at proposal, this
source category is unique due to the
large, complex and interconnected
nature of electrical generation,
transmission and distribution, and the
critical role of the electric grid in the
functioning of all aspects of the
economy. The grid functions as an
interconnected system that supplies
electricity to end users on a continuous
basis. Safe, reliable operation of the grid
requires coordination among actions
taken at individual units, including
timing of outages for the installation of
controls, derating, or deactivation. It
was for this reason that we specifically
addressed in the proposed rule
reasonable interpretations of the phrase
‘‘installation of controls’’ in CAA
section 112(i)(3)(B). We determined that
it was important to provide Title V
permit authorities with information that
might be useful if they were asked to
authorize a fourth year for specific
EGUs.
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The EPA took comment on whether
the construction of on-site replacement
power could be considered the
‘‘installation of controls’’ such that a
fourth year would be available while the
replacement unit is being completed for
a unit that is retiring (e.g., a case when
a coal-fueled unit is being shut down
and the capacity is being replaced onsite by another cleaner unit such as a
combined cycle or simple cycle gas
turbine). After reviewing the comments,
EPA believes that it is reasonable for
permit authorities to allow the fourth
year extension to apply to the
installation of replacement power at the
site of the facility. The EPA believes that
building replacement power constitutes
the ‘‘installation of controls’’ at a facility
to meet the regulatory requirements.
Commenters were generally
supportive of the proposed approach
described above, but a number of
commenters suggested several
additional situations that should be
considered as the ‘‘installation of
controls’’ such that it would be
appropriate for permitting authorities to
grant a 1-year extension beyond the 3year compliance time-frame. In
particular, commenters suggested that
the 1-year extension should be available
for a unit if a company’s compliance
choice was to retire that unit but doing
so within the 3-year time-frame caused
reliability problems for any of the
following reasons: (1) Generation from
the retiring unit is needed to maintain
reliability while other units install
emission controls; (2) new off-site
generation was being built to replace the
retiring unit, but the new generation
was not scheduled to be operational
within the 3-year time-frame and any
gap between the time the existing unit
retires and the new unit comes on line
would cause reliability problems; and
(3) transmission upgrades were needed
in order to maintain electric reliability
after the unit retired but could not be
completed within 3 years.
While the ultimate discretion to
provide a 1-year extension lies with the
permitting authority, EPA believes that
all three of these cases may provide
reasonable justification for granting the
1-year extension if the permitting
authority determines, for example,
based on information from the RTO or
other planning authority or other
entities with relevant expertise, that
continued operation of a particular unit
slated for retirement for some or all of
the additional year is necessary to avoid
a serious risk to electric reliability.
In a case where pollution controls are
being installed, or onsite replacement
power is being constructed to allow for
retirement of older, under-controlled
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generation, a determination that an extra
year is necessary for compliance should
be relatively straightforward. In order to
install controls, companies will have to
go through a number of steps fairly early
in the process including obtaining
necessary building and environmental
permits and hiring contractors to
perform the construction of the
emission controls or replacement
power. This should provide sufficient
information for a permitting authority to
determine that emission controls are
being installed or that replacement
power is being constructed. Because
companies will need to develop this
information early in the process and
because a determination can easily be
made as to whether the schedule will
exceed 3 years, the EPA believes that
Title V permitting authorities should be
able to quickly make determinations as
to when extensions are appropriate.
In the three cases related to retirement
of a unit without construction of onsite
replacement power, additional
information is needed. The Title V
permitting authority should request that
the affected company or companies
provide information, including, for
example, from the RTO or other
planning authority for the relevant
region, the state electric regulatory
agency, NERC or its regional entities,
and/or FERC or the DOE, demonstrating
that retirement of a particular unit
within the 3-year compliance period
would result in a serious risk to electric
reliability.
The first two situations involving a
retiring unit—where one or more related
existing units are upgrading pollution
controls or a new unit is being
constructed off-site—are similar to the
situation we discussed in the proposed
rule wherein a retiring unit at a facility
runs an additional year while a
replacement unit on the same site is
constructed. In each of these situations,
the retiring unit would be allowed to
run so a unit compliant with the rule
(either a retrofitted existing unit or a
new unit) can come on line. We believe
that these situations may, in the
appropriate circumstances, constitute
ones in which a 1-year extension for the
retiring unit is ‘‘necessary for the
installation of controls.’’ In these two
situations, however, we believe that it
would be appropriate for the Title V
permitting authority to consider
reliability concerns as a necessary factor
before granting the additional year
because continuing operation of the
retiring unit is only ‘‘necessary’’ to the
extent it is required for reliability. In
each of these situations, the permitting
authority should determine that the
retiring unit is necessary to maintain
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reliability until the new unit comes on
line or the other existing unit is
retrofitted. Title V permitting authorities
may determine that multiple retiring
units are available to maintain
reliability, but unless all the units are
necessary to address the issue, it would
likely be unreasonable to provide the
additional year for all the identified
units.
The third hypothetical situation
identified above is one in which
transmission upgrades are necessary to
address a reliability issue resulting from
the retirement of a unit in order to
comply with this rule, where the
upgrade cannot be completed by the 3year compliance date. In terms of the
functionality of the electric grid, this
situation has some similarity to those
discussed above. Here, it is the
completion of the transmission
upgrades, rather than bringing another
compliant (retrofitted or new) unit on
line, that would allow the retiring unit
to come into compliance (by retiring)
without threatening reliability. The
general objective and result is similar:
Reductions of the existing unit’s HAP
emissions (through retirement) while
maintaining electric reliability. If such
situations develop and the reliability
problem has been properly
demonstrated, permitting authorities
should consider whether an extension
under CAA section 112(i)(3)(B) may be
provided.
The EPA continues to believe, based
on the analysis discussed at the
beginning of this section, that most, if
not all, units will be able to comply
with the requirements of this rule
within 3 years. The EPA also believes
that making it clear that permitting
authorities have the authority to grant a
1-year compliance extension where
necessary, in the range of situations
described above, addresses many of the
other concerns that commenters have
raised. The EPA believes that the
number of cases in which a unit is
reliability critical and in which it is not
possible to either install controls on the
unit or mitigate the reliability issue
through construction of new generation,
transmission upgrades, or demand-side
measures, within 4 years, is likely to be
very small or nonexistent. This view is
consistent with statements from
commenters explicitly mandated with
ensuring grid reliability.
The EPA’s authority to provide relief
from the requirements of this final rule
beyond the fourth year is limited by the
statute. If reliability issues do develop,
however, the CAA provides
mechanisms for sources to come into
compliance while maintaining electric
reliability. One area where the EPA has
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some measure of flexibility is with
respect to the exercise of its
enforcement authorities. The Agency
has used such authority in the past to
bring sources into compliance with the
requirements of the CAA while
maintaining electric reliability, although
these authorities are not as flexible as
suggested by some commenters.
The EPA generally does not speak
publicly to the intended scope of its
enforcement efforts, particularly well in
advance of the date when a violation
may occur. In light of the importance of
ensuring electric reliability, however,
the Office of Enforcement and
Compliance Assurance will separately
publish a document that articulates our
intended approach with respect to
sources that operate in noncompliance
with this final rule to address a specific
and documented reliability concerns.
That document provides a pathway
for reliability critical units (as such
units are described in the document) to
achieve compliance within an
additional year. The result is that
qualifying reliability critical units may
come into compliance within up to 5
years. This pathway is structured to
maintain reliability, to ensure CAA
compliance and to increase certainty for
sources in planning by allowing a unit
owner/operator to determine whether it
qualifies for a compliance schedule well
in advance of the MATS compliance
deadline.
The EPA believes that there will be
few, if any, situations in which it will
be necessary to have recourse to the
processes discussed in the document
just described, and that there are likely
to be fewer, if any, cases in which it is
not possible to mitigate a reliability
issue within the further year
contemplated under that document.
However, there is always the possibility
that some unit owner/operator will be
unable to address its reliability issues
within 5 years and there is always the
possibility that a unit owner/operator
will be unable to timely comply with
the MATS for some other reason.
Consistent with its longstanding
historical practice under the CAA, the
EPA will address individual noncompliance circumstances on a case-bycase basis, at the appropriate time, to
determine the appropriate response and
resolution.
A number of commenters also raised
concerns about inconsistencies between
the compliance timelines under this
final rule and existing state agreements
with specific owners/operators to install
pollution control equipment and/or
retire EGUs. The EPA believes the
flexibilities provided in this discussion
allow for some discretion to address
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9411
those cases, but that they may not be
fully addressed. The EPA is supportive
of such efforts and believes they can
have important multi-pollutant health
and environmental benefits. To the
extent that the flexibilities discussed
here do not fully address a particular
situation, we encourage states and
sources to contact the EPA as early as
possible to discuss their individual
circumstances.
G. Cost and Technology Basis Issues
1. Dry Sorbent Injection
Comment: Several commenters stated
that there is limited commercial
operating experience in using DSI to
control acid gas emissions from coalfired boilers. They suggest that the
technology is not adequately proven for
use in this application.
Other commenters disagree with
statements made that DSI is not proven.
One commenter stated that DSI is a
mature technology. The commenter
indicated that DSI is well suited for
units that burn fuels with lower or midlevel sulfur contents, and is among the
viable options available for a number of
sources to achieve the proposed HCl
limits. Thus, the commenter believes
that DSI represents a real technology
control option for many units, and is
among the suite of technology options
that certain units will be able to employ
to meet the proposed HCl limit.
Response: As explained in this
response and elsewhere in this
preamble, the EPA agrees that DSI
technology is proven and ready for
commercial use in controlling acid gases
from coal combustion. One of the largest
coal-burning electric utilities in the U.S,
American Electric Power (AEP),
pioneered the practical use of DSI with
trona, a sodium-based sorbent, for SO3
mitigation. American Electric Power has
implemented trona injection for that
purpose across its entire bituminous
coal-fired fleet where both SCR and wet
FGD systems are in place.334 Examples
of coal-fired EGUs already using trona
DSI to control SO2 emissions include
NRG Energy’s Dunkirk Generating
Station Units 1–4 and CR Huntley Units
67 and 68 in New York.335 The Dunkirk
units range in size from 75 MW to 190
MW. Much larger units may also be
economic when using DSI for SO2
control, as suggested by Dominion
Energy’s studies of adding DSI on two
334 SO Control: AEP Pioneers and Refines Trona
3
Injection Process for SO3 Mitigation, Coal Power,
March 2007, https://www.coalpowermag.com/
plant_design/SO3-Control-AEP-Pioneers-andRefines-Trona-Injection-Process-for-SO3Mitigation_29.html.
335 NRG Energy letter to RGGI, Inc, November 22,
2010, https://www.rggi.org/docs/NRG_Nov_2010.pdf.
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625 MW units at the Kincaid plant in
Illinois.336 One of the largest suppliers
of air emission control systems in the
world, vouches that DSI is commercially
proven for acid gas control:337 338
Comment: Numerous comments were
received on EPA’s IPM modeling of DSI
in the MATS analysis. A few
commenters stated that DSI will not
work on bituminous coals. Some
commenters stated that DSI is only
suitable for use on low sulfur, low
chlorine western coals. Others stated
that DSI is only likely to be used on
relatively small units, and that larger
units would use scrubbers for acid gas
control. Several commenters expressed
the opinion that because there is little
commercial operating experience in
using DSI to control SO2 emissions from
coal-fired boilers, EPA’s IPM modeling
assumptions on the efficacy and cost of
the DSI control option are unjustifiably
optimistic. Some commenters believe
that DSI will not be as economic or as
widely applicable for either SO2 or HCl
control as projected by EPA’s IPM
modeling. Commenters observe that wet
or dry scrubbers for FGD, longerstanding control technologies for SO2
and HCl, are more complex systems
with a much higher capital cost than
DSI. These commenters argue that the
sector will need to retrofit many more
FGD scrubbers than projected by IPM
for MATS compliance and will therefore
experience a much higher overall cost of
compliance than projected by IPM, as
well as needing more time and
resources for retrofit construction. A few
commenters suggested that EPA should
base its MATS modeling on this more
conservative outlook. A few
commenters were concerned that EPA’s
DSI modeling assumptions relied on
performance data from only one DSI
vendor.
Some commenters were concerned
that fly ash currently sold for beneficial
uses will become unsalable because it
will be contaminated by injected
sodium-based DSI sorbents. Two
commenters argued that EPA’s IPM
analysis understates DSI cost by not
including the costs of foregone fly ash
sales revenue and contaminated fly ash
disposal. A few commenters observed
that landfilling of sodium-based DSI
solid wastes will produce leachate
336 Dominion
Energy, BART Analysis for the
Kincaid Power Plant, January 2009, https://
www.epa.state.il.us/air/drafts/regional-haze/bartkincaid.pdf.
337 Dry Sorbent Injection Systems for Acid Gas
Control, Babcock & Wilcox, 2010, https://
www.babcock.com/library/pdf/ps-451.pdf.
338 Technologies for Acid Gas Control, Babcck &
Wilcox, 2011, https://www.babcock.com/library/pdf/
ps-457.pdf.
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containing sodium and other
compounds that are challenging to
handle, thus requiring special landfill
designs and a high cost for landfill
disposal of DSI waste.
Response: The EPA believes that its
representation of DSI in MATS
compliance modeling is reasonable, is
properly limited to applications that are
technically feasible, and reflects a
conservative approach to modeling
future use of this technology.
The EPA disagrees that its IPM
modeling of DSI is overly optimistic and
therefore underestimates the costs of
MATS compliance. In its IPM modeling,
EPA restricts the availability of the DSI
option to only those units that use or
switch to relatively low sulfur coal: Less
than 2 lb SO2/MMBtu (see IPM
documentation in the docket). The
EPA’s IPM projections for MATS
compliance, therefore, already include
the costs of any additional FGD
scrubbers that are economically justified
and projected for use on units using
higher sulfur coals. The EPA models
DSI assuming fine-milled trona as the
injected sorbent. As mentioned by
several commenters, sodium
bicarbonate (SBC), which is processed
from trona, is also suitable for use with
DSI. Sodium bicarbonate is more
reactive with acid gases than trona. It
would require less tonnage of sorbent
and less tonnage of waste disposal than
trona for the same SO2 removal effect,
albeit at somewhat higher sorbent cost.
Non-sodium based sorbents such as
hydrated lime (calcium based) could
also be used. Therefore, EPA’s modeling
of DSI technology does not include the
full spectrum of sorbent choices that
real-world applications enjoy, meaning
that there may be opportunities for
lower-cost applications of DSI that are
not captured in EPA’s projections for
MATS. The EPA models DSI with trona
injection rates corresponding to 70
percent SO2 removal for all coals,
assuming that an equivalent amount of
sorbent is needed to provide 90 percent
HCl removal, regardless of the low
sulfur and chlorine content of western
coals.
Senior technical staff from the EPA
have carefully evaluated the key
assumptions regarding the cost and
operation of emission control
technologies. In general, these staff
believe that trona should have strong
HCl reaction selectivity and,
consequently, EPA’s assumed trona
injection rates may be overstated. The
extent to which this assumption may
actually overstate DSI control costs can
be observed through DSI pilot testing for
Solvay Chemicals by the Energy &
Environmental Research Center (EERC)
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Fmt 4701
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at the University of North Dakota.339
The EERC’s testing of trona DSI on a
central Appalachian bituminous coal
(1.3 lb SO2/MMBtu) substantiates the
strong HCl reaction selectivity of
sodium-based sorbents, including trona,
and calcium-based hydrated lime. The
EERC’s pilot testing shows that finemilled trona, when well mixed into 325
°F flue gas upstream of a FF, provides
90 percent HCl removal at a SO2
removal rate of less than 20 percent (as
compared to EPA’s modeling
assumption of aligning 90 percent HCl
removal with sorbent injection designed
to achieve 70 percent SO2 removal). The
data show that 95 percent or higher HCl
removal is readily obtained at somewhat
higher SO2 removal rates. Similarly
strong HCl selectivity results were
obtained using trona and an ESP at
650 °F. Test data from United
Conveyor 340 on full-scale units also
show these high HCl selectivity trends.
Overall, these test data from multiple
major vendors suggest that even if a SO2
removal rate of 30 percent were required
in order to obtain 90 percent HCl
removal in the imperfectly mixed flow
of a full-scale unit, it still appears that
EPA’s assumed trona injection rates may
be as much as twice as high as would
actually be needed in practice for
certain applications. It is apparent that
if EPA were to re-analyze MATS
compliance with DSI injection rates
reduced by 50 percent, there would be
a corresponding reduction in the
sorbent and related waste disposal costs
that constitute most of the cost of using
DSI.
Given the EERC test data, it is also
apparent that most units that have ESPs
and are burning low sulfur western coal
could meet the HCl limit using DSI
without the addition of a FF. If EPA
were to re-analyze MATS compliance
while allowing DSI use without the
need for a downstream FF, it is apparent
that there would be a very significant
reduction in the overall number of FF
retrofits projected, and a corresponding
reduction in annualized capital costs.
For the MATS proposal, the EPA
modeled DSI on the assumption that all
chlorine in coal converts to HCl, and
that DSI would be the only mechanism
by which the unit could prevent HCl
from being emitted. Based on public
339 Solvay Chemicals, Inc., HCl Removal in the
Presence of SO2 Using Dry Sodium Sorbent
Injection, https://www.solvair.us/SiteCollection
Documents/presentations/20111214_hcl_
presentation.pdf.
340 United Conveyor Corporation, Dry Sorbent
Injection for Simultaneous SO2, HCl, and Hg
Removal, October 2011, https://unitedconveyor.com/
uploadedFiles/Systems/Systems_Sub/
McIlvaine%20Multipollutant%20Removal
%20Oct%202011.pdf.
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comments and a more thorough review
of the ICR data, the EPA has introduced
in final MATS modeling a recognition
that the relatively high alkalinity of ash
from subbituminous and lignite coals
‘‘removes’’ much of the HCl that would
otherwise be emitted from combustion
of these particular coals. The 2010 ICR
data indicate that in some cases the ash
itself removes sufficient HCl from these
coals for MATS compliance; in effect,
these acid-gas emissions are absorbed by
coal ash and are captured by particulate
control devices instead of being emitted
in gaseous form. As a conservative
measure, EPA’s revised final MATS
modeling assumes that 75 percent of
HCl is removed by the ash for these
coals. In the event that ash capture in
practice is more effective than this 75
percent assumption, then EPA’s analysis
projects a conservatively higher level of
DSI installations (and, thus, compliance
cost) than would actually occur in
practice. In any case, it appears that
significantly less sorbent injection
would actually be required in practice
than assumed by EPA for these low
sulfur, low chlorine coals, and that the
IPM projected DSI operating costs are
likewise higher for these coals than
would be experienced in practice.
The EPA models DSI with sorbent
injection occurring downstream of an
existing electrostatic precipitator (ESP).
The existing ESP is assumed to remain
in service. The model adds a fabric filter
downstream of the DSI injection point
to capture the small amount of PM
passing through the ESP plus the
reacted and unreacted DSI sorbent. Most
of the DSI projected by IPM, therefore,
includes the costs of a retrofitted FF.
This modeled configuration allows fly
ash currently captured in ESPs to
remain uncontaminated by DSI sorbent
and, therefore, remain available for sale
and beneficial use. The EPA
conservatively models FF costs based on
an assumed full-size system with an airto-cloth ratio of 4.0. The FF costs could
be somewhat less in practice if a smaller
system (with an air-to-cloth ratio of 6.0)
were used for the reduced DSI dust
loading. The EPA observes that some of
the owners of units with ESPs may
chose to convert existing ESPs into
FFs,341 an option not modeled in IPM,
but that would likely have a lower
capital cost than a retrofitted FF. In the
MATS proposal EPA modeled DSI with
a waste disposal cost of $50/ton, based
on a Sargent & Lundy DSI cost model
341 TW Lugar, et al., The Ultimate ESP Rebuild:
Casing Conversion To a Pulse Jet Fabric Filter, a
Case Study, Electric Power Conference, May 2009,
https://www.cecoenviro.com/uploads/
ESP%20to%20Fabric%20Filter%20Baghouse%20
Conversion%20-%20Buell%20Case%20History.pdf.
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prepared for EPA (see proposal IPM
documentation in the docket). The EPA
has continued to model DSI at this
waste disposal cost for analysis of the
final rule. However, recent discussions
between senior technical staff from the
DOE and the EPA have suggested that in
some situations sodium sulfates, that
would be formed by the injection of
trona, could potentially leach out of the
fly ash/sorbent mixture on contact with
water. Although the technical staff
recognized that these concerns are more
relevant to bituminous coal-fired units
where ashes are not cementitious,
unless mixed with limestone or lime,
they suggested that the impacts of
potentially higher disposal costs be
evaluated. Based on public comments,
further investigations by Sargent &
Lundy, and suggestions from the EPA
and DOE technical staff, EPA’s analysis
of the final rule has included an IPM
sensitivity case using a DSI waste
disposal cost of $100/ton. The
sensitivity case indicates that a 100
percent increase in assumed DSI waste
disposal cost produces slightly less than
a 1 percent increase in the projected
cost of the rule.
Comment: A few commenters
expressed the concern that there is an
inadequate supply of trona to support
DSI operations at the levels projected by
the EPA for MATS compliance.
Response: The EPA projects that just
over 50 GW of coal-fired capacity might
retrofit with DSI for MATS compliance,
thus reducing SO2 emissions by about 1
million tons per year. Based on
conservatively high trona injection
rates, as discussed above, the EPA
estimates that the amount of trona
required to support DSI operations at
this level is about 4 million tons per
year. By comparison, the trona mining
industry in the U.S. has a demonstrated
production capacity of at least 18
million tons annually, and was running
well below that capacity (16.5 million
tons) in 2010.342 343 If the EPA’s
assumed trona injection rates are as
much as 50 percent greater than actually
needed for at least 90 percent HCl
control, as discussed above, and given
that some subbituminous coals will
apparently need little or no sorbent
injection for HCl control, there may
already be an adequate surplus of trona
production capacity to support DSI for
MATS compliance. The EPA, therefore,
concludes that trona supply for DSI is
either already adequate, or will require
342 https://www.wma-minelife.com/trona/
tronmine/tronmine.htm.
343 https://www.wma-minelife.com/trona/
TronaPage2/trona_production.htm.
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at most a small increase in production
capacity.
For all of these reasons, the EPA
believes that its representation of DSI in
MATS compliance modeling is
reasonable, is properly limited to
applications that are technically
feasible, and reflects a conservative
approach to modeling future use of this
technology.
2. Economic Hardship
a. Job Losses and Economic Impacts
Comment: Several commenters
indicated that they believe the proposed
rule will weaken industry, cause job
losses and hurt power consumers. One
commenter reported that the proposed
rule will affect 1,350 coal and oil-fired
units at 525 power plants and that
NERC reports that by 2018 nearly 50,000
MW of capacity will be retired by the
proposed rule. Many of these
commenters compared the cost
estimated by EPA to a variety of other
sources that estimate substantially
higher costs of the rule. The
commenters expressed concern that
electricity price increases are likely to
be up to 24 percent in some regions as
a result of the proposed rule. In addition
to the economic difficulty the proposed
rule could place on consumers, the
commenter believes that many in the
energy sector will lose their jobs due to
coal-fired capacity losses. The
commenters believe the effects on coalfired plants in the Southeast especially
will mean the loss of high-paying, highskilled jobs and drastic price increases
in energy costs. Additionally,
commenters expressed concern that
increased electricity and natural gas
prices would impact businesses in
multiple sectors across the country.
Response: The EPA disagrees with the
estimates presented by the commenters.
The EPA has updated its analysis to
reflect the final MATS. The Agency
estimates the annual costs of the final
rule in 2015 to be $9.6 billion in 2007
dollars. The estimate of early
retirements of coal-fired units due to
this rule is 4.7 GW, lower than the level
estimated at proposal. Both of these
estimates were prepared using the IPM,
a model that has been extensively
reviewed and has been utilized in
several rulemakings affecting the power
generation sector over the last 15 years.
The Agency’s analyses are credible and
accurate to the extent possible, and all
assumptions and data are made public.
Limitations and caveats to these
analyses can be found in the RIA for this
rule.
The EPA estimates that there will be
an increase of 3.1 percent in retail
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electricity price on average in the
contiguous U.S. in 2015 as an outcome
of this rule, with the range of increases
from 1.3 percent to 6.3 percent in
regions throughout the U.S. No region of
the U.S. is expected to experience a
double-digit increase in retail electricity
prices in 2015 or in any year later than
that, according to the Agency’s analysis,
as a result of this rule. To put this in
context, the roughly 3 percent
incremental increase in aggregate enduser electricity prices projected to occur
over the next 4 years is about the same
as the 3 percent absolute average change
in total end-user electricity prices
observed on an annual basis.344
Furthermore, the roughly 3 percent
incremental price effect of this rule is
small relative to the changes observed in
the absolute levels of electricity prices
over the last 50 years, which have
ranged from as much as 23 percent
lower (in 1969) to as much as 23 percent
higher (in 1982) than prices observed in
2010.345 Even with this rule in effect,
electricity prices are projected to be
lower in 2015 and 2020 than they were
in 2010.346
The Agency found that the readily
discernible impact on long-term
employment nationally within the most
directly affected sectors should be small
and the EPA also estimated that about
46,000 job-years 347 of one-time
construction labor could be supported
or created by this rule. This includes
jobs manufacturing steel, cement and
other materials needed to build
pollution control equipment, jobs
creating and assembling pollution
control equipment, and jobs installing
the equipment at power plants.
Potential job increases from increased
output by lower-emitting facilities (such
as increased generation from wellcontrolled coal-fired plants that replace
generation from older coal-fired plants)
are expected to partially or fully offset
potential job losses resulting from
reduced output from higher-emitting
facilities. The EPA analysis projects a
net change in the directly affected EGU
sector of between 15,000 net jobs lost to
344 EIA Annual Energy Outlook 2010 annual total
electricity prices from 1960 to 2010, Table 8–10.
345 Ibid, EIA AEO 2010, Table 8–10.
346 Ibid, EIA AEO 2010, Table 8–10 for price
levels; and Chapter 3 of the RIA for electricity price
differential.
347 A ‘‘job-year’’ is a combined measure of jobs
and job duration which is equivalent to one person
being employed for one year. For example, 2 jobyears could represent two years of employment for
one worker, one year of employment for two
workers, or 6 months of employment for four
workers. Estimates of employment changes that
involve non-permanent workers are usually
reported in job years to give a sense of the total
employment effects.
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30,000 net jobs gained on an annual
basis.348 See Chapter 6 of the RIA for
further details.
The EPA has also looked at the
possibility that changes in the price of
electricity may influence the levels and
geographic distribution of downstream
economic activities, and associated
employment. Projecting how potentially
higher electricity prices may affect
various downstream economic activities
in particular regions as a result of this
rule is challenging for several reasons:
(1) There are significant uncertainties
regarding projections of consumer- and
location-specific electricity price
changes in response to future firmspecific compliance strategies; (2) the
availability of competitively-priced
alternative energy sources (including
energy conservation) and less
electricity-intensive substitute goods
and services may significantly mitigate
potentially adverse economic
consequences resulting from projected
increases in electricity prices in ways
which are not captured effectively in
currently available models; and (3)
available modeling tools are not
configured to capture the effects over
time of economically significant effects
of cleaner air (e.g., reductions in
medical expenditures and
improvements in labor productivity
resulting from fewer lost work days)
achieved by rules evaluated using single
target year criteria pollutant and/or HAP
benefits projections. After considering
these methodological limitations, the
Agency concludes that there is not a
satisfactory methodology for projecting
the downstream economic (including
employment) effects of any changes in
electricity prices due to this rule.
We expect the downstream economic
effects of this rule to be small because
electricity is only a small factor in the
production of most goods and
services.349 A 3 percent increase in enduser electricity prices translates to a
much smaller effect on prices and
potential output of goods and services
from end-users of electricity. Over time,
the incremental effect of this rule on
electricity prices is projected to
diminish significantly; for example the
difference in expected prices is
projected to narrow from 3.1 percent in
348 It should be noted that if more labor must be
used to produce a given amount of output, then this
implies a decrease in labor productivity. A decrease
in labor productivity will cause a short-run
aggregate supply curve to shift to the left, and
businesses will produce less, all other things being
equal.
349 BEA. (2007b). Commodity-by-Industry Direct
Requirements after Redefinitions, 2002. Available
in: 2002 Summary Tables, 2002 Benchmark InputOutput Data. Retrieved from https://www.bea.gov/
industry/io_benchmark.htm#2002data.
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2015 to 2.0 percent in 2020 as shown in
Chapter 3 of the RIA.
Despite the absence of a satisfactory
methodology for quantifying the
potential economy-wide effects
(including employment) of any potential
increases in electricity prices resulting
from this rule, the EPA expects the
incremental effects of this rule on
electricity prices to be small given the
projected electricity price increases
relative to historical levels and volatility
in end-user electricity prices. Based on
these projections and contextual
information, the Agency believes that
the incremental effects on electricity
prices and economic activity of this rule
are likely to be small relative to other
factors influencing electricity prices,
overall employment, and other aspects
of economic activity.
Comment: Several commenters
considered the proposed rule to be a tax
on the American public, since utilities
implementing upgrades will pass the
costs on to the consumer. Commenters
questioned the preference of Americans
to subsidize renewable energy sources
and put money into the proposed rule
instead of other environmental
programs with greater benefits.
Commenters explained that the tax-like
price increase reduces income of energy
consumers and depresses business
development. The commenters used
California as an example of a state that
uses low rates of coal-based electricity
and cites companies that have left the
state as a result of substituting higher
cost forms of electricity for coal. A
commenter stated that coal-derived
energy will rapidly become more
expensive, especially in the ‘‘rust belt’’
and Southeast region, as can be seen by
the rate increase already requested in
Louisville. A commenter believes the
‘‘indirect taxation’’ limits the ability of
the economy to absorb the cost of
retrofitting and new capacity projects,
lowers discretionary spending and leads
to job losses and lost tax revenues, given
the restrictive timeframe for
compliance.
Response: The Agency does not agree
that this rule creates or alters any taxes
on affected sources required under this
rule to reduce their emissions of toxic
air pollutants, nor are taxes created or
altered or imposed on consumers of
electricity which is provided to the
market by affected sources. Moreover,
unlike a tax, this rule does not generate
government revenue. The rule does,
however, indirectly address the problem
of the ‘‘externality cost’’ of higher health
risks and other adverse effects on the
populations exposed to toxic air
pollution emissions from affected
sources. This rule may have the effect of
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reducing or eliminating a market
distortion that provides an implicit
subsidy to affected facilities. This
implicit subsidy results from the fact
that some facilities currently can avoid
the costs of toxic air pollution controls
by imposing higher health and other
costs on those who are exposed to
higher levels of toxic air pollution. The
Agency also disagrees with the
implication that the costs incurred by
less-controlled sources to bring their
toxic air emissions in line with their
better-controlled competitors will lead
to significant or debilitating changes in
market and economic conditions. The
Agency’s estimate of the potential
increase in retail electricity price is an
average of 3.1 percent in 2015, with a
range of increases by region from 1.3
percent to 6.3 percent. As shown in
Chapter 3 of the RIA, the higher rates of
potential electricity price increase tend
to occur in those regions where
electricity prices have been relatively
low, due to some extent to reliance on
coal-fired units which have been
cheaper to operate due to
underinvestment in toxic air pollution
controls.350 As shown in Chapter 3 of
the RIA, all regions with year 2015
projected percentage increases in retail
electricity prices above the contiguous
U.S. average are also projected to have
baseline retail electricity prices which
are below the contiguous U.S. average
price level in that year. In addition,
natural gas prices will only increase by
0.3 to 0.6 percent on average over the
time horizon of 2015 to 2030. As
discussed above, for consumers of
electricity in the commercial and
industrial sectors, electricity tends to be
a fairly small fraction of total costs of
production, implying that the average
projected electricity price increase of 3
percent will lead to only a small
fractional change in the costs of
providing goods and services to the
economy. While some residential
electricity consumers may similarly see
a small price increase in retail
electricity prices, it should be noted that
these consumers tend to reside in the
same area or region as the affected
facility and so will also experience the
improvement in air quality from the
reductions due to the rule. The
reduction in health risk and other
improvements to quality of life
associated with lower exposure to toxic
and other air pollutants achieved by this
rule will confer benefits on these
consumers which include lower risks of
premature mortality, lower morbidity,
and improved productivity and
350 https://www.epa.gov/airmarkets/images/
CoalControls.pdf.
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competitiveness of U.S. workers due to
reduction in work days lost to air
pollution-related illness. The benefits of
these improvements are projected to
exceed costs of compliance by affected
sources by at least six-fold. The
potential price increases in electricity
and natural gas should be considered in
light of the substantial health, welfare,
and economic benefits achieved by this
rule.
Comment: Many commenters
expressed support for the EPA’s impact
analysis and disputed claims by other
commenters that the projected rule will
harm economic growth. A number of
commenters mentioned testimonials by
power company CEOs stating that the
proposed rule will not affect the
economic health of the industry and a
survey showing nearly 60 percent of the
coal-fired units already comply with the
EPA’s proposed Hg standard, and
several other meaningful quotes from
utility executives. The commenters also
pointed out that 17 states already
require plants to address Hg pollution,
with some imposing more stringent
emission limits than the EPA proposes.
The commenters believe that utilities
use the threat of power plant closures
and lost jobs to delay Hg reductions
from coal-fired plants. Commenters also
believe that the rules will drive
innovation and job creation as new
technologies to reduce pollution are
created. Several commenters quoted the
Economic Policy Institute finding that
the proposed rule will increase job
growth by 28,000 to 158,000 jobs by
2015 (including approximately 56,000
direct jobs and 35,000 indirect jobs), the
University of Massachusetts study that
showed an increase 1.4 million jobs in
5 years, and the Constellation Energy
Group installation project that
employed nearly 1,400 skilled workers.
Commenters also cited the University of
Massachusetts study statement that a
net gain of over 4,200 long-term
operation and maintenance jobs will
result.
Several commenters observed that the
positive impacts of the rule strongly
favor its adoption. These commenters
stated that, contrary to the unfounded
assertions by critics of EPA and the rule,
EPA has conducted a technically sound
and conservative benefit-cost analysis
showing that the proposed rule’s
estimated benefits are at least five times
as high as its costs. One commenter
stated, ‘‘With sound, albeit unduly
conservative, econometric modeling,
EPA has also determined that the Toxics
Rule will promote economic growth and
create jobs in both the long and short
term.’’ Two commenters cited the EPA
impact analyses by Dr. Charles Cicchetti
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which confirm this finding and state
that the analysis underestimates the
rule’s net benefits and positive impacts
on the nation’s economy. By
considering some benefits not
monetized in the EPA analysis, Dr.
Cicchetti concludes that the proposed
rule will create $52.5 to $139.5 billion
in net benefits annually, create 115,200
jobs, generate annual health savings of
$4.513 billion, annual increases in GDP
of $7.17 billion and $2.689 billion in
additional annual tax revenues, and
spur innovation and modernization of
EGUs. The commenters state that the
study findings show no need to delay
implementation of the rule or needlessly
duplicate economic analyses already
completed.
Commenters reported that multiple
researchers confirmed that the EPA’s
estimates of economic stimulus are
conservative and that the proposed rule
will stimulate job growth. A commenter
quotes Dr. Josh Bivens of the Economic
Policy Institute, who also found that
EPA’s conclusions were conservative.
Dr. Bivens concluded, ‘‘The EPA RIA on
the proposed toxics rule makes a
compelling case that the rule passes any
reasonable cost-benefit analysis with
flying colors—the monetized benefits of
longer lives, better health, and greater
productivity dwarf the projected costs of
compliance * * * Whether regulation
in general and the toxics rule in
particular costs jobs is an empirical
question this paper attempts to answer.
In particular, this paper examines the
possible channels through which the
proposed toxics rule could affect
employment in the United States and
finds that claims that this regulation
destroys jobs are flat wrong: ‘‘The jobsimpact of the rule will be modest, but
it will be positive.’’ His report details
the following major findings:
1. The proposed rule would have a
modest positive net impact on overall
employment, likely leading to the
creation of 28,000 to 158,000 jobs
between now and 2015.
2. The employment effect of the
[MATS] on the utility industry itself
could range from 17,000 jobs lost to
35,000 jobs gained.
3. The proposed rule would create
between 81,000 and 101,000 jobs in the
pollution abatement and control
industry (which includes suppliers such
as steelmakers).
4. Between 31,000 and 46,000 jobs
would be lost due to higher energy
prices leading to reductions in output.
5. Assuming a re-spending multiplier
of 0.5, and since the net impact of the
above impacts is positive, another 9,000
to 53,000 jobs would be created through
re-spending.
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Response: The EPA thanks the
commenters for these observations. The
Agency’s estimates of employment
impacts, found in the RIA for the rule,
are smaller than those identified by the
some commenters, though the EPA uses
a different methodology that focuses on
impacts specific to the electric power
sector.
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b. Impacts on Low-Income Consumers
Comment: Commenters expressed
concern that the EPA’s overview of the
price increases does not consider the
hardships that will be the reality of
increased prices on low-income or
fixed-income households or small
businesses. The commenter reports
increases of $90 million in capital costs,
$11.4 million in annual operating costs
and $6.4 million in annual debt service
costs to achieve compliance, which will
lead to a 13 percent increase in rates for
the proposed rule, and a 41 percent
increase for all proposed and new
regulation compliance costs. The
commenter argues against the EPA’s
view that energy efficiencies will offset
rate increases, because low income
customers will need to use less
electricity due to economic necessity.
The commenter also sees large price
increases for customers if units are
converted to natural gas, which is
approximately 2.5 times more expensive
than the coal that the commenter
currently uses to generate electricity.
Response: The EPA’s estimates of
increase, relative to the baseline, in the
retail electricity price range from 1.3
percent to 6.3 percent regionally in
2015, with an average increase
nationwide of 3.1 percent in 2015. Lowincome households will thus see some
increase in electricity price, but this
increase should be modest. In addition,
the increase in the price of natural gas
as a result of this rule is expected to be
0.3 to 0.6 percent over a time horizon
of 2015 to 2030. This increase in price
is low enough that electricity customers
should not experience a major increase
in price resulting from any modest
changes to electricity generated by
natural gas. The roughly 3 percent
incremental price effect of this rule is
small relative to the changes observed in
the absolute levels of electricity prices
over the last 50 years, which have
ranged from as much as 23 percent
lower (in 1969) to as much as 23 percent
higher (in 1982) than prices observed in
2010.351
351 EIA
Annual Energy Outlook 2010 annual total
electricity prices from 1960 to 2010, Table 8–10.
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c. State or Regional Impacts
Comment: Multiple commenters
expressed concern over the impact of
the rule on electricity prices and
reliability in specific states or regions.
These commenters were concerned that
these impacts would adversely affect
specific industries such as construction
and manufacturing. One commenter
suggested the EPA consider regional
differences that will impact system
reliability and costs, such as the
increased impacts on regions relying
heavily on coal and oil and encourages
cooperation between the EPA and state
and federal energy and environmental
regulators.
Response: The Agency has studied
possible impacts on resource adequacy
as a result of this rule, and has
determined that these impacts should
not be significant. Furthermore,
industry, along with relevant federal
agencies, has the tools needed to
address any reliability concerns. The
Agency has prepared an updated
feasibility TSD in support of the final
rule, which is in the docket for this
rulemaking.352 The Agency has
considered impacts on a regional basis
as part of its overall analyses done using
the IPM; these results are documented
in the RIA for the rule and in the
feasibility TSD.
The EPA’s analysis shows that retail
electricity price increases will not fall
disproportionately on a specific region.
In fact, those regions experiencing the
largest change in prices are projected to
have retail electricity prices below the
national average both in the absence of
MATS and after the implementation of
MATS. In Chapter 3 of the RIA, the EPA
presents retail electricity prices by
region in 2015, for both the base case
and MATS policy case. The six regions
that are projected to have retail
electricity prices above the national
average price in 2015 in the absence of
MATS are projected to have increases
that are below the national average
increase following the implementation
of MATS. Those regions that have
projected retail electricity price
increases that are above the national
average are all projected to have retail
electricity prices below the national
average in the absence of MATS.
Comment: A commenter quoted
National Mining Association statistics
showing coal is responsible for $65.738
billion in annual economic activity,
produces 1,798,800 jobs and $36.345
billion in annual labor income. The
commenter reports that regions such as
352 See ‘‘An Assessment of the Feasibility of
Retrofits for the Mercury and Air Toxics Standards
Rule’’ in the docket.
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Appalachia, the Midwest and Rocky
Mountain West will be significantly
affected by the proposed rule, including
increased unemployment. Other
commenters stated that communities
near existing coal-fired generation units
will be especially hard-hit if the plants
are permanently retired. The
communities will suffer from job loss
and diminished tax revenue.
Response: The Agency’s analysis, as
found in the RIA, shows that impacts to
these regions are mixed. For
Appalachia, coal production is
projected to fall by 6 percent in 2015,
while the Western coal producing
region will experience a decrease of 3
percent in production in 2015. The
Interior region is projected to see a 9
percent increase in production. Retail
electricity prices are expected to
increase by 1.3 percent to 6.3 percent in
various parts of the country in 2015.
Also, the estimated number of early
retirements according to the Agency that
may result from this rule is 4.7 GW in
2015, or less than 2 percent of all U.S.
coal-fired capacity in that year. Thus,
there may be some negative impacts
from this rule in some regions, but these
same regions will also experience some
of the benefits, such as reduced
premature mortality from less exposure
to PM2.5 emissions as shown in Chapter
5 of the RIA. As discussed previously,
the EPA’s analysis shows that retail
electricity price increases will not fall
disproportionately on a specific region.
In fact, those regions experiencing the
largest change in prices are projected to
have retail electricity prices below the
national average both in the absence of
MATS and after the implementation of
MATS.
The results of the EPA’s employment
analysis, found in Chapter 6 of the RIA,
indicate that the final MATS has the
potential to provide significant shortterm employment opportunities,
primarily driven by the high demand for
new pollution control equipment. While
the employment gains related to the
new pollution controls are likely to be
tempered by some losses due to certain
coal retirements, some of these workers
who lose their jobs due to plant
retirements could find replacement
employment operating the new
pollution controls at nearby units.
Finally, job losses due to reduced coal
demand are expected to be offset by job
gains due to increased natural gas
demand, resulting in a small positive
net change in employment due to fuel
demand changes.
While shifts in employment are
difficult for those directly affected, and
the Agency remains concerned about
the challenges job shifts can bring to the
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individuals affected, Bureau of Labor
Statistics data indicate that compliance
with pollution control requirements is a
relatively very small contributor to
overall employment shifts in the U.S.
economy. Specifically, the main cause
of mass layoffs over the last four years
according to 2007 to 2011 Bureau of
Labor Statistics data is ‘‘lack of business
demand,’’ accounting for over 40
percent of the layoffs reported by
industry. In contrast, all types of
regulatory actions (including health,
safety, and environmental) by all levels
of government (Federal, State, local)
combined were cited as the primary
factor in only 0.2 percent of mass layoffs
over the same period.353
d. Retirements of Coal-Fired EGUs and
Shutdowns
Comment: A commenter discussed
the economic factors behind EGU
retirements. These factors include the
cost of alternative generation using
natural gas, the cost of implementing
demand response measures that can be
bid into capacity markets, and the cost
of continuing to generate power from an
existing unit. The commenter states that
regardless of the costs associated with
the Toxics Rule and other EPA electric
power industry regulations, some power
plants were already economically
unsustainable. The commenter quotes
M.J. Bradley, who points out, ‘‘[o]f the
122 coal units in PJM with capacity less
than or equal to 200 MW, 35 failed to
recover their avoidable costs and
another 52 were close to not recovering
those costs. Therefore, in PJM * * * in
addition to approximately 10 GW of
coal generation that has or will be
retired during the 7 years from 2004 to
2011, another 11 GW faces a troubling
economic outlook.’’ The commenter
provides confirmation of this by the
most recent PJM capacity auction,
where approximately 6.9 fewer GW of
coal-fired capacity cleared the auction
(1.85 fewer GW were offered) as
compared with the prior year’s auction,
and an additional 4.836 GW of new
demand response (energy efficiency)
resources cleared the auction. Thus, the
commenter states, some claims linking
retirements to the MATS are overstated
and misleading. The commenter gives
the example of the American Electric
Power attempt to link its planned plant
closures to the MATS, but those plants
already are slated to either close or to
upgrade controls to comply with
existing laws. The commenter goes on to
quote three independent studies that
353 U.S. Bureau of Labor Statistics, 2011.
Extended Mass Layoffs in 2010. https://www.bls.gov/
mls/mlsreport1038.pdf.
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support the finding that over 50 percent
of the fleet is equipped with scrubbers
and the number will increase to nearly
2⁄3 by 2015.
Response: The EPA agrees with the
findings of the independent studies
mentioned by the commenter.
e. Impacts on Mining
Comment: Multiple commenters
mention the proposed rule’s impact on
mining. One commenter mentioned
increasing energy costs for the U.S.
mining industry, resulting in fewer
projects and associated jobs, as well as
increasing dependence on foreign
mineral resources. Commenters see
mining impacts being disproportionally
large for lignite mines, which are
dependent on their co-located lignitefired power plants. The commenters
state that if the plant closes, there is no
market for the lignite and the mine will
also close, displacing plant workers.
These impacts are largest in Texas, the
largest coal consuming state and fifth
largest coal producing state, as well as
a deregulated electricity market. One
commenter pointed out that the Texas
coal market provided a buffer against
natural gas price volatility and in
particular believes the proposed rule
does not take into account the emission
reductions already achieved by industry
in general and their company in
particular. A commenter stated that
impacts will be magnified in Texas,
since it is the largest coal consuming
state and mines lignite. A commenter
indicated they believe it is unclear the
extent to which EPA includes the
impacts on the mining industry that will
result from this rule.
Response: The Agency presents
impacts on the coal mining sector from
this rule in the RIA. Given the modest
increase in coal and other energy costs
associated with the rule, the Agency
does not expect widespread impacts on
coal mining. The Agency’s modeling
accounts for all emission controls and
programs installed and/or implemented
up through December 2010, including
those in Texas.
f. Flexible Regulations
Comment: Several commenters
expressed concern over the potential
impacts of the regulation and believe
that the requirements should be more
flexible in order to mitigate these
impacts.
Response: The EPA believes the
requirements of the final rule have been
made as flexible as possible consistent
with the CAA. The final rule allows
some flexibility, including allowing
averaging across units in the same
subcategory at a facility, allowing for an
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option of an input or output standard
for existing units, and allowing for
alternative compliance options (e.g., for
coal, filterable PM or total non-mercury
metallic HAP or individual HAP
metals). In addition, the Agency is not
prescribing specific technologies as part
of this final rule, but instead requiring
emissions limitations be met. This
approach allows the industry to find the
most cost-effective approach to meeting
the requirements while ensuring
considerable public health benefits.
g. Temporary vs. Permanent Jobs
Comment: A commenter expressed
disagreement with the EPA prediction
of new jobs created, because the
commenter believes far more plants will
shut down than the EPA predicts,
resulting in higher job losses. The
commenter also pointed out that while
jobs running power plants are
permanent, the jobs predicted to be
created by the proposed rule are short
term construction jobs, and will all
occur in the same short timeframe for
compliance. The commenter also stated
that the EPA estimate does not include
the opportunity cost of lost construction
jobs due to new power plants that will
not be constructed due to the proposed
rules.
Response: The Agency believes that
the employment impacts of the final
rule will be small, as has been the case
historically with regards to
environmental regulation. The Agency
does provide an estimate of the longterm employment impacts to the electric
power sector in the RIA for the rule, and
that estimate shows a range of impacts
from 15,000 net jobs lost to 30,000 net
jobs gained (all annual), but also
recognizes important limitations to
these estimates. The Agency’s estimate
of impacts to short-term jobs, including
those in construction, accounts for both
losses and gains that result from the
rule. This is shown in Chapter 6 of the
RIA.
Comment: Commenters believe that
installation of new pollution controls
would be a job-growth opportunity in
their states because money spent on
controls for power plants creates highquality jobs in steel, cement and other
materials, as well as in the assembling
of the equipment as well as installing
and operating it. A commenter shares
the Alabama Fisheries Association
estimate that the water-based recreation
industry brings in over $1 billion per
year to the state’s economy though the
state ranks third for imperiled fish with
61 bodies of water cited for Hg
contamination. The commenter believes
the HAP accumulating in the waterways
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threatens the industry with permanent
job-losses and lost revenue.
Response: The Agency agrees with the
commenter that the reduction in HAP
that will take place as a result of the rule
over time will help to improve
waterways in Alabama and thus help
the water-based recreation in that state.
More information on the benefits of Hg
and other HAP reductions can be found
in Chapter 4 of the RIA for the rule. The
Agency also agrees with the commenter
that the addition of control equipment
for EGUs may stimulate employment in
a variety of industries.
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h. Natural Gas
Comment: A commenter states that
natural gas use is only an option in
places where infrastructure exists to
supply sufficient natural gas to the EGU
and other local needs and reports that
year-round reliable gas delivery is rare
due to requirements to meet the other
needs. The commenter says that gas
interruptions are prevalent in the
winter, but can happen year-round, and
the costs of establishing a natural gas
line to a power plant can be tens of
millions of dollars or more, and moving
a plant to a gas source can take many
years. The commenter describes the
options for a Norwalk Harbor plant, and
explains that the modifications are
costly and difficult even before
considering the modifications needed to
alter the boiler and fuel supply system
to allow natural gas combustion.
Response: The final rule does not
prescribe either pollution control
technologies to be used, nor does it
dictate the types of fuels that should be
burned. The requirements of the final
rule are designed to allow industry to
find the most cost-effective approach to
addressing harmful emissions that are
covered by this action. The Agency
believes that cost-effective technologies
exist today and have been deployed on
many power plants, and utilities will be
able to find intelligent solutions to
address harmful emissions. The EPA
has provided supporting information as
part of the preamble and RIA for this
rule, along with the feasibility TSD,
which demonstrate the availability and
performance of technologies to meet the
requirements of the final rule.
Comment: A commenter discusses the
factors that could lead to higher natural
gas prices not currently reflected in the
EPA impact projections, including
industrial load and demand not
rebounding to 2008 levels and the
influence of liquefied natural gas
exports. The commenter asks that the
EPA address a variety of factors related
to its natural gas assumptions.
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Response: The Agency has fully
documented its assumptions and
framework for modeling natural gas in
IPM for both the proposed and final
MATS. This information can be found
in Chapter 10 of the IPM documentation
(https://www.epa.gov/airmarkets/
progsregs/epa-ipm/docs/v410/
Chapter10.pdf). The documentation
provides a thorough overview of the
natural gas module, describes the very
detailed process-engineering model and
data sources used to characterize North
American conventional,
unconventional, and frontier natural gas
resources and reserves and to derive all
the cost components incurred in
bringing natural gas from the ground to
the pipeline. Also documented are the
resource constraints, liquefied natural
gas (LNG), demand side issues, the
natural gas pipeline network and
capacity, procedures used to capture
pipeline transportation costs, natural
gas storage, oil and natural gas liquids
(NGL) assumptions, and key gas market
parameters.
i. Compliance Timeline and General
Timeline
Comment: A commenter states that
the proposed rule will require costs be
passed on to consumers, meaning state
public utility commissions will be
flooded with requests for rate increases
from utilities trying to recover
expenditures. The short deadline will
also result in a large number of
extension requests made to state
permitting authorities, further
burdening them.
Response: The compliance date for
this rule for existing sources will be 3
years and 60 days after publication of
the final rule in the Federal Register, or
approximately March 2015. Thus, there
will be some time before the impacts of
this rule such as any increase in retail
electricity prices become a concern. It
also should be noted that increases in
retail electricity prices will be 3.1
percent on average in 2015, with a range
regionally from 1.3 percent to 6.3
percent.
Comment: A commenter reports that
they will need to install add-on
pollution controls to meet the proposed
emission standards as well as
implement other physical or operational
changes. The commenter expresses
concern about the number of preconstruction steps that would be
required, as well as the new
construction activities and the
challenges of scheduling sequence
relative to interconnections and other
tie-in considerations involved in
compliance.
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Response: The Agency has addressed
concerns with the feasibility and timing
of control installations in its report on
the subject (see feasibility TSD
contained in the docket for this rule).
Comment: Multiple commenters do
not believe that labor availability will
constrain control installation in the
required timeframe and cites an
Institute of Clean Air Companies (ICAC)
response that it will not for these
reasons:
1. The power sector has demonstrated
ability to install large number of systems
in short time period;
2. The majority of coal plans have
installed control systems already;
3. Fewer resource and labor-intensive
control options being used for
compliance; and
4. End users have utilized cost
reducing and implementation efficiency
strategies for efficient deployment of
technologies.
Another commenter states that a wide
range of technical and economically
feasible practices and technologies are
available currently to meet the emission
limits and are in use around the
country.
Response: These comments are
generally consistent with the
conclusions of the Agency’s analyses on
feasibility of control installations for
this rule as found in the feasibility TSD
in the docket for this rulemaking.
j. Burden Outweighs Environmental
Gain
Comment: Several commenters state
that the EPA has no data relating to
benefits from reducing non-mercury
HAP, so the costs of the proposed rule
exceed the HAP benefits by 29,000
times. One commenter states that the
impact analysis was largely focused on
Hg with little support for other HAP
reductions and failed to provide account
of true costs and benefits.
Response: While we are not able to
monetize the benefits from reductions of
non-mercury HAP that will take place,
these important effects are discussed
qualitatively in Chapter 4 of the RIA.
The quantified benefits of this rule
include the reductions in non-HAP
emissions such as SO2 and PM2.5 that
will occur as a co-benefit of this rule as
modeled by EPA. The total benefits are
estimated to outweigh the total annual
costs of the rule by a margin of either
3 to 1 or 9 to 1, depending on the
benefits estimate and discount rate
used. These reductions are credible and
are considerable in size. The estimates
of these benefits reflect the latest
scientific understanding on the subject.
More information on the estimates and
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the methodology for their preparation
can be found in the RIA for the rule.
Comment: Several commenters
consider the proposed rule to be the
most expensive clean air rule ever. They
point out the estimated $10.9 billion
annual cost in 2015 and approximate
1,200 existing coal-fired EGUs affected,
both of which were estimated by the
EPA. Commenters believe the EPA’s
estimates are incorrect and the true cost
will be far more, due to cumulative
effects of all proposed power sector
rules, and indirect costs from job losses,
reduced productivity and
competitiveness resulting from
electricity costs. They ask the EPA to
keep these high costs in mind when
evaluating impacts of the proposed rule
and consider the costs with respect to
the benefits. One commenter requests
that the EPA explain how its approach
utilized ‘‘the best available techniques
to quantify anticipated present and
future benefits and costs as accurately as
possible’’ and includes analyses by EIA,
EEI, NERC, NERA, Credit Suisse, ICF,
and Burns & McDonnell.
Response: As noted earlier, the
Agency did not prepare a cumulative
impact analysis to accompany the rule
for the following reasons: (1) The
various EO requirements that the
Agency must comply with require us to
estimate impacts specific to this rule; (2)
decisionmakers and the public need to
know the impacts specific to a
particular rule in order to judge the
merits of the regulation; and (3)
estimates specific to a particular rule are
more transparent than those from a
cumulative impact analysis. A
cumulative impact analysis lumps
several regulations together and can
potentially mask a high-cost/low benefit
regulation among other rules that may
have large net benefits. By analyzing
each regulation separately, EPA makes
clear statements about the impacts,
costs, and benefits that are estimated as
a result of this particular regulation.
This does not, however, mean EPA
has failed to incorporate these
regulations into this analysis. The
inclusion of CSAPR and other
regulatory actions (including federal,
state, and local actions) in the IPM base
case reflects the level of controls that are
likely to be in place in response to other
requirements apart from MATS. This
base case provides meaningful
projections of how the power sector will
respond to the cumulative regulatory
requirements for air emissions, while
isolating the incremental impacts of
MATS. These results are presented in
Chapter 3 of the RIA.
Additionally, the Agency does reflect
on the cumulative impacts of our
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regulations. In March 2011, EPA issued
the Second Clean Air Act Prospective
Report which assessed the benefits and
costs of regulations pursuant to the 1990
Clean Air Act Amendments. The study
examines the cumulative impact of
these regulations (found at https://
www.epa.gov/air/sect812/feb11/
summaryreport.pdf). As shown in the
report, the direct benefits from the 1990
Clean Air Act Amendments are
estimated to reach almost $2 trillion for
the year 2020, a figure that dwarfs the
direct costs of implementation ($65
billion). The full report is at https://
www.epa.gov/air/sect812/
prospective2.html.
The direct benefits of the 1990 Clean
Air Act Amendments and associated
programs are estimated to significantly
exceed their direct costs, which means
economic welfare and quality of life for
Americans were improved by passage of
the 1990 Amendments. The wide
margin by which benefits are estimated
to exceed costs, combined with
extensive uncertainty analysis, suggest
it is very unlikely this result would be
reversed using any reasonable
alternative assumptions or methods.
The analysis presented in the RIA for
the current regulation uses a similar
methodology.
The techniques employed by the
Agency for generating benefits and
costs, and consider the most recent and
complete data available to the Agency.
The EPA recognizes that the analyses
have caveats and limitations, and we
discuss our analyses and their caveats
and limitations in the RIA for the rule,
as well as in the benefits section of the
preamble. The Agency has also revised
the cost analyses for the final rule to
reflect data received in public
comments on the proposed rule, and
costs are lower than when the rule was
proposed.
k. Impact on State Regulators
Comment: Several commenters
expressed concern over the burden
imposed on state regulatory agencies by
the rule.
Response: The Agency has estimated
the costs of implementation of the rule
to states that own EGUs affected by the
rule, and has included this analysis in
the RIA. The Agency has updated this
analysis for the final rule and it is
included in the RIA. While the EPA has
not prepared an analysis of the impacts
of the rule on state programs, the
Agency does not believe the rule will be
unduly burdensome to the state
regulatory agencies. The EPA works
closely with state regulatory authorities
to ensure that the rules are implemented
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properly, and the Agency will continue
to do so in support of this final rule.
Comment: A commenter states that
the reductions in SO2 and PM2.5
required by the proposed rule will assist
state and local air pollution control
agencies to meet health-based air quality
standards, reduce haze and improve
visibility. The commenter points out
that substantial reduction in emissions
made by the very large sources under
the proposed rule will lead to fewer
pollution controls needed at smaller
sources to meet health-based ambient
air requirements. This is a far more costeffective approach than controls at
smaller facilities and is the lowest cost
path to improved public health and a
cleaner environment.
Response: The EPA acknowledges
that the HAP standards in this final rule
will lead to considerable co-benefit
reductions in PM and SO2.
l. Miscellaneous
Comment: A few commenters
discussed the impact of the rule on the
federal budget deficit. One commenter
points out that the proposed rule will
affect the federal budget in two ways:
1. Direct compliance costs to electric
generating units (EGUs) owned by
federal agencies; and
2. Pass-through compliance costs paid
in the form of higher prices for
electricity purchased by federal
agencies.
Response: The Agency estimates the
direct compliance costs to EGUs that are
federally owned as part of the overall
cost analysis completed for the proposal
and disclosed in the RIA for the rule.
The Agency does not provide an
estimate of the impact on federal
agencies from higher electricity prices
associated with the rule, however. This
type of analysis is not required under
EO 12866 and statutory requirements.
H. Testing and Monitoring
Comment: Commenters raised
numerous issues with the testing and
monitoring requirements for initial and
continuous compliance. The following
discussion highlights the comments and
responses to a number of the critical
issues and describe where the
comments have resulted in a significant
rule change or where we disagreed with
commenters’ suggestions of issues or
need for changes in the rule. Additional
comments and responses are addressed
in the Response to Comments document
included in the docket for the final rule.
Test Methods. A number of
commenters suggested that we should
allow for the use of Method 5B to
determine compliance with the PM
emission limit. In addition, a number of
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commenters objected to the frequency of
stack testing when used as the method
for demonstrating continuous
compliance. Commenters also objected
to the requirement for testing one
pollutant when the source was
complying with an optional surrogate
(or vice versa); for example, commenters
objected to testing for HCl if a unit was
complying with the optional SO2 limit,
or testing for metals if the unit was
complying with the optional PM limit.
Response: Although Method 5B is
specified for wet scrubber-controlled
utility boilers under 40 CFR part 60,
subparts D, Da and Db, we are excluding
Method 5B for demonstrating
compliance with the filterable PM
emissions standard in this final rule.
The extended high temperature heating
of the filters prior to weighing as
specified in Method 5B would introduce
differences between the compliance test
data and the data that underlie the
filterable particulate standard. Because
the test data that underlie and filterable
particulate standard are based primarily
on Method 29 and Method 5 data
collected at 320 °F or comparable
filterable particulate methods, we are
specifying those same methods for
determining compliance with the
standard.
For stack test frequency, we modified
the final rule to require quarterly testing
to demonstrate continuous compliance.
In addition, we agree that testing should
be required only for the emission limits
that your source is complying with, and,
thus, the final rule does not require
testing of both the pollutant and the
surrogate.
Comment: Fuel Analysis Methods. A
number of commenters raised various
concerns with the fuel analysis methods
specified in the proposed rule.
Response: Based on the comments
received and a further review of the
technical challenges associated with the
proposed fuel analysis requirements, we
have not finalized the proposed fuel
analysis requirements. As the rule no
longer requires operating limits based
on fuel content or fuel analysis, the
comments on this issue are largely
moot. For LEEs, we agree that the
proposed LEE ongoing eligibility
requirements were overly burdensome
and restrictive. As a result, existing
solid or liquid fired units that qualify
for Hg LEE status will be required to
conduct a 30-day test for Hg using
Method 30B each year. Neither fuel
analysis nor adherence to an operating
limit will be required. Should an annual
test show ineligibility for LEE status, the
source will revert to the requirements
for Hg monitoring using CEMS or
sorbent traps or, for oil-fired units,
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quarterly emissions testing. Existing
solid or liquid fired units that qualify
for non-mercury LEE status will be
required to conduct a stack test every 3
years, and neither fuel analysis nor
adherence to an operating limit will be
required. Should the stack test show
ineligibility for LEE status, the source
will revert to using CEMS or PM CPMS
or conducting quarterly emissions
testing.
Comment: Operating Parameter
Limits: Some commenters objected to
the use of enforceable operating
parameter limits, requested that the rule
be more consistent with the compliance
assurance monitoring program, and
raised specific objections to certain
parameters required for certain control
devices. Commenters also raised
concerns about a PM CEMS operating
limit establishing a de facto more
stringent PM emission limit than the
one being tested for under the total PM
standard in the proposal.
Response: We believe that continuous
monitoring in the form of CEMS,
sorbent trap monitoring systems, and
PM CPMS, or frequent stack emissions
testing are appropriate to ensure
ongoing compliance with this final rule.
We also agree with commenters that
some of the monitoring provisions in
the proposal may have been duplicative
and unnecessary. In order to provide
flexibility in the final rule, we have
retained a source’s ability to define an
operating limit and to monitor using a
PM CPMS as an option to periodic
filterable PM emissions testing.
The final rule establishes the PM
CPMS as an operating limit monitor and
not a direct filterable PM emission
monitoring requirement that meets PS
11 requirements. Although we recognize
the importance of continued control
device performance to ensure emissions
minimization, we also are aware that
other rules that apply to these units
including, but not limited to, the
Operating Permits rule, the Compliance
Assurance Monitoring rule, the ARP
rules, and the NSPS already require
continuous monitoring in most cases.
Those rules will remain in effect so the
need to impose additional operating
limits monitoring or CEMS on those
units is much reduced.
The final rule also provides for the
use of a PM CEMS to determine
compliance with the filterable PM
emission limit if the source elects to use
this approach. In that case, the PM
CEMS is used as the direct method of
compliance and no additional testing is
required other than tests that are
required as part of satisfying the
requirements in Performance
Specification 11 in Appendix B to 40
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CFR part 60 and Procedure 2 in
Appendix F to part 60. The EPA
provided this option in response to the
comments in order to provide a
straightforward direct measure of
compliance that some sources may want
to implement.
Comment: Hg CEMS. Commenters
raised a number of technical concerns
about Hg CEMS. Many commenters
requested modifications so that the
requirements would be more consistent
with 40 CFR part 75 monitoring
requirements. Some commenters
questioned the ability of the technology
to demonstrate compliance with
emission limits at very low levels
especially for new sources. Commenters
also opposed high data availability
requirements given that the technology
is new and difficult to operate and
maintain.
Response: We indicated in the
proposed rule the intent to adopt
CAMR-based requirements for Hg
monitoring in place of the general 40
CFR part 63 performance specifications
and QA requirements. With CAMR,
these operating and reporting
requirements for Hg CEMS went
through notice and comment
rulemaking for the same sources as
covered by this final rule. Although
CAMR was set aside on other grounds,
these technical specifications and QA
requirements reflect significant input
from stakeholders and analysis by the
EPA to establish an appropriate
foundation for Hg monitoring at electric
utilities under the CAA. For the final
rule, we have made conforming changes
to ensure that this intent is carried out
effectively throughout the rule text and
Appendix A, as well as including
certain additional clarifications based
on the input received in response to the
proposed rule. We have also removed a
cycle time test as unworkable for certain
types of Hg CEMS.
The final rule provides the option for
use of either Hg CEMS or sorbent trap
monitoring systems. We believe the
record clearly shows these to be proven
technologies each providing certain
advantages. For existing and some of the
new unit standards, the level of the
NIST-traceable Hg gas standards will be
adequate and consistent with existing
applications of Hg CEMS. For the lowest
limits and other applications where an
integrated sampling system offers
advantages, affected facilities may opt to
use sorbent trap monitoring systems to
comply. There are data in the recent
draft report entitled ‘‘Determining the
Variability Of CMMS At Low Hg
Levels,’’354 that demonstrate reasonable
354 https://www.icci.org/reports/10Laudal6A-1.pdf.
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performance of at least one Hg CEMS at
Hg levels below 1.0 microgram per
cubic meter (mg/m3) down to
approximately 0.1 mg/m3. Finally, there
is no specific minimum data availability
requirement for Hg CEMS (or any other
CMS required under this final rule).
This issue is discussed further below.
Comment: SO2 CEMS: Although
commenters were generally supportive
of the ability to use SO2 CEMS for units
with FGD installed to demonstrate
compliance with an alternate SO2
emission limit instead of the HCl
emission limit, there were some
concerns with aspects of the proposal.
Commenters requested that the SO2
monitoring requirements rely on 40 CFR
part 75 given that their sources were
already meeting those requirements and
that this rule not establish any new
requirements, especially a fourth
linearity level and the application of 7day calibration error tests for units with
low concentrations (where 40 CFR part
75 provides an exemption). Commenters
were also concerned that the rule
language only allows the option where
the FGD is operated ‘‘at all times’’
which seems to imply that the option is
not allowed if the source ever bypasses
the FGD for start-up, shutdown, or
malfunction reasons.
Response: After reviewing the
comments and assessing the need for an
additional calibration gas at the
emissions limit, we have removed this
requirement from the final rule while
retaining the requirement for a linearity
check even for SO2 monitors with low
span values (≤ 30 ppm). A source can
already report linearity tests for these
units within the context of the existing
ECMPS reporting without triggering any
critical errors. This test can be
accommodated within the current
framework without causing issues for 40
CFR part 75 reporting. The requirement
for a 7-day calibration error test is
removed. For the ‘‘at all times’’
language, we have clarified this in the
final rule. The intent is that the FGD be
operated during all routine boiler
operations, and not operated
intermittently, seasonally, or on some
other non-fulltime basis.
Comment: HCl CEMS. In general,
commenters argued that HCl CEMS do
not have an approved performance
specification and are not widely
demonstrated as a proven technology.
Those concerns were also mentioned for
HF CEMS.
Response: We disagree with
commenters’ contention that continuous
HCl monitoring is premature or not
available for the measurement at the
emission limits set in the final rule. HCl
CEMS are being used on source
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categories such as municipal waste
combustors and EGUs. We have
reviewed HCl CEMS vendor technology
claims and found sufficient capability to
support this rule requirement. We are
engaged with representative
stakeholders to develop a generic
performance specification for HCl CEMS
scheduled for completion in time to be
responsive to compliance with this rule.
The final rule provides several
options for HCl and/or HF monitoring
including:
(1) Using Fourier Transform Infrared
(FTIR)-based HCl CEMS and/or HF
CEMS complying with Appendix B to
the rule which relies on PS 15,
(2) Seeking approval for an alternative
HCl monitoring procedure through 40
CFR 63.7(f),
(3) Monitoring compliance
continuously with the alternate SO2
emission limit at coal-fired or other
solid fuel affected facilities equipped
with FGD technology for SO2, and
(4) Quarterly reference method
testing.
Including these options in the final
rule provides flexibility to adopt CEMS
monitoring options as the technology
continues to mature and the new, nontechnology-specific EPA performance
specifications becomes available.
Comment: Bypass Stacks. Several
commenters raised concerns about the
technical feasibility of monitoring
bypass stacks with a CEMS.
Response: We have modified the
bypass stack monitoring requirements.
Under 40 CFR part 75, we allow the use
of a maximum potential concentration
value for reporting when emissions are
vented to a bypass stack. That approach
works within the context of an
emissions trading program, but is not
appropriate when evaluating
compliance with a specific emission
limit. Thus, we have provided two other
options. One is to monitor the bypass
stack, consistent with the final rule. The
other is to treat any hours of bypass
stack emissions as periods of monitor
downtime and hours of deviation from
the monitoring requirements. Note that
a source’s units must continue to meet
their 30-boiler operating day emissions
limits during malfunction periods.
Comment: 40 CFR part 75 Issues.
There were a number of general
comments about the value of relying on
40 CFR part 75 requirements, including
elements such as conditional data
validation. The commenters generally
agreed that the 40 CFR part 75 bias test
and bias adjustment factor, and the 40
CFR part 75 substitute data provisions
should not apply. Instead of substitute
data, many commenters suggested that
we needed to clarify the valid reasons
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for monitor downtime and establish an
appropriate minimum data availability
requirement.
Response: We have attempted to
harmonize the CEMS requirements in
this final rule with those under 40 CFR
part 75 wherever appropriate. One of
those examples is the inclusion of
conditional data validation for Hg
CEMS. We disagree that this final rule
needs a minimum data availability
requirement. We have not included any
specific minimum data availability
requirement for CEMS or other
monitoring in this final rule nor do we
provide a specific tool for data
substitution. We believe that there are
other provisions in the final rule to
provide incentives to conduct
monitoring in a manner consistent with
good air pollution control practices and
to provide data sufficient to demonstrate
compliance with a relatively long-term
(30-boiler operating day) emissions rate
limit. We agree that data quality
certainty associated with any calculated
value decreases with the collection of
less data such as would occur with
extended periods of monitoring system
downtime. Even so, we believe also that
it is necessary and critical for
compliance with the regulation that a
source use all measured data collected
during an averaging period to assess
compliance regardless of any periods of
missing data. Sources should not
disqualify any data otherwise meeting
required data quality requirements
simply because there were data missing
for other hours or days of the averaging
period.
Instead of a minimum data
availability threshold that would
invalidate data collected for some
averaging periods because one did not
collect data for at least a specified
percent of an averaging time, the final
rule requires that a source report as
deviations to the rule failure to collect
data during required periods if these
deviations are not covered by
exceptions allowed in the final rule.
On the issue of applying a data
substitution procedure to represent
actual emissions or pollution control
performance, we are not requiring data
substitutions under this rule. We
believe, however, that defensibility
concerns make it incumbent on the
source to collect and evaluate other
information in accordance with 40 CFR
section 63.6(f)(3) during periods of
monitoring downtime to assure
compliance with the applicable
emissions limitations and standards.
We believe that enforcement
authorities also can and should
determine whether a source is meeting
any monitoring system operating
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requirements. Should the source or the
enforcement authority be concerned
about the representativeness of data
such as during periods of missing data,
either one may consider collecting
information through other means (e.g.,
supplemental emissions testing) to fill
data gaps not only because such gaps
are deviations from the rule but such
gaps can lead to uncertainty about
compliance status.
We further believe that the final rule
provides sufficient means to ensure
CMS performance and ongoing
compliance without specifying an
arbitrary numerical minimum data
availability or data substitution
requirement. We believe that specifying
failure to collect required or otherwise
excepted data as a deviation from the
rule will provide the necessary
incentive to collect data sufficient to
demonstrate compliance with the limits
in the final rule.
Comment: Recordkeeping. Several
commenters opposed the requirements
related to maintaining records on site
and for 5 years.
Response: We believe the
recordkeeping and retention
requirements are consistent with other
requirements already in place,
specifically 40 CFR 63.10 (b).
In addition, the 5-year retention
period is the general rule for all
recordkeeping for all sources under the
part 70 operating permits program.
Given that the General Provisions for 40
CFR part 63 and part 70 already
establish a 5-year retention period, we
believe it is justified in using those
precedents for the retention periods
under this subpart. If we stayed silent
on retention period in this subpart, the
General Provisions would provide for
the 5-year retention as would the part 70
requirements. Thus, this action does not
establish any new retention
requirements, but merely confirms that
the existing retention requirements
apply.
Comment: Electronic Reporting. In the
proposed rule, we requested comment
on using ECMPS for reporting under
this rule, as well as other options
including the ERT. Commenters
generally supported the use of ECMPS,
especially for CEMS data. Some
commenters requested an additional
rulemaking on the specific data
elements to be collected. There were
some concerns raised about the ERT
given experience during the 2010 ICR
process during the development of this
rule.
Response: We recognize that
emissions reporting for continuously
measured pollutants (SO2, NOX, etc.)
and for periodically measured
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pollutants (PM, HAP metals, etc.) have
different data demands. We recognize
that minor revisions of the ECMPS will
fulfill our data needs for most
continuously measured pollutants and
we will make these modifications for
receipt of the additional CEMS data. We
also recognize the need for substantial
modifications to the ECMPS to
accommodate the data needs for
periodically measured pollutants and
certain CEMS data such as PM CEMS
data and possibly HAP metals CEMS
data. Although major modifications of
the ECMPS would be required for
periodic compliance tests by isokinetic
and instrumental test methods (as well
as certain types of CEMS), only minor
revisions are required of the ERT to
receive these tests. We are
implementing the changes in the ERT
that are required to provide the software
tools to implement the delivery of these
performance test data to us.
The electronic submission of
compliance test reports to us through
the Central Data Exchange (CDX) is not
solely for the purpose of developing
improved emissions factors as some
commenters assert. Although populating
WebFIRE will allow us to improve
emissions factors, we intend to use data
stored in WebFIRE as the primary
location for compliance test reports for
use by regulatory authorities. The
electronic submission of compliance
test reports is a continuation of our
efforts to bring the submission and
sharing of environmental data into the
modern age. The storage of this
compliance data in our WebFIRE
provides a convenient location which is
already used to store source test data.
As federal and state and local
agencies’ data systems mature,
information provided through the ERT
will be used to populate these data
systems. We are currently upgrading the
AIRS Facility System and expect to
replace manually entered information
with electronic population from the
ERT. We are also working with several
state and local agencies to adopt the use
of the ERT for delivery of compliance
test reports. The ERT is also much
improved since the version used during
the 2010 ICR process, and there is no
expectation that the information to be
reported under this final rule will be as
extensive as some of the data reported
for the 2010 ICR purposes.
We disagree that a separate and
independent regulatory action is
required to implement electronic
reporting for selected regulated sources.
Each of these regulatory actions for
selected source categories provides
ample notice and the opportunity for
individuals to provide comment. We
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also disagree that the system to receive
the compliance data must be operational
prior to establishing the requirement for
regulated sources to submit compliance
data electronically. We are on track to
have the capability to receive electronic
compliance tests through our CDX in
sufficient time to receive all utility
source test reports required by this final
rule.
We do plan a separate and
independent regulatory action to
implement electronic reporting for
regulated entities which are covered by
past and future rules. Although we have
provided draft procedures for the
development of emissions factors, that
effort is an ancillary effort to the
electronic delivery of compliance test
reports. It is our intention to convert to
the electronic delivery and storage of all
air emissions compliance source test
data. With this transition, we believe
this valuable information will be more
readily available not only for
compliance purposes but also for a
variety of other uses.
I. Emissions Averaging
Comment: In response to our request
for comments on the suitability of
emissions averaging and need for a
discount factor, we received a range of
suggestions, including requests for
clarification regarding eligibility, points
for and against the need for a discount
factor, and suggestions to ease
implementation.
Response: We are finalizing that
owners and operators of existing
affected sources may demonstrate
compliance by emissions averaging for
EGUs at the affected source that are
within a single subcategory and that rely
on emissions testing as the compliance
demonstration method. See section VI of
thie preamble for a fuller discussion.
J. LEE Criteria
Comment: A commenter supported
the LEE provisions but believed one of
the LEE eligibility criteria should set at
29.0 lb/year, rather than 22.0 lb/year.
The commenter suggested 29.0 lb/year
to be an equally reasonable cut point,
especially since that value matches the
low mass emitter Hg monitoring cutoff
in CAMR and the low mass emitter Hg
monitoring cutoff that several states
have adopted, including Illinois, 35 Ill.
Admin. Code section 225.240(a)(4).
(See, e.g., Colorado (5 Colo. Code Regs.
section 1 00 1–8, Reg. No.6, part B,
Section VIII.B.l0); Michigan (Mich.
Admin. Code R. 336.2160); Montana
(Mont. Admin. R. 17.8771(12))). Further,
a LEE cutoff of 29.0 lb would eliminate
conflicts and confusion with low mass
emitter provisions in existing state Hg
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programs and significantly reduce
compliance costs and burdens for the
additional qualifying units without
adversely affecting compliance
assurance with the EGU NESHAP Hg
emission limits or materially increasing
the number of potential qualifying LEEs.
Given the many other costly burdens
that the rule would impose, the benefit
of LEE to a qualifying unit is not
insignificant.
Response: The Agency reviewed the
commenter’s suggestions, and one of the
LEE eligibility criteria in the rule has
been revised from 22.0 to 29.0 lb of Hg
per year. The Agency finds the result of
consistency with existing state
regulations outweighs the two percent
difference in nationwide Hg mass
emissions, from 5 percent to 7 percent,
for LEE eligibility.
VIII. Background Information on the
NSPS
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A. What is the statutory authority for
this final NSPS?
New source performance standards
implement CAA section 111(b), and are
issued for categories of sources which
cause, or contribute significantly to, air
pollution which may reasonably be
anticipated to endanger public health or
welfare. Section 111 of the CAA
requires that NSPS reflect the
application of the best system of
emissions reductions which (taking into
consideration the cost of achieving such
emissions reductions, any non-air
quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated. The level of
control prescribed by CAA section 111
historically has been referred to as ‘‘Best
Demonstrated Technology’’ or BDT. In
order to better reflect that CAA section
111 was amended in 1990 to clarify that
‘‘best systems’’ may or may not be
‘‘technology,’’ the EPA is now using the
term ‘‘best system of emission
reduction’’ or BSER. As was done
previously in analyzing BDT, the EPA
uses available information and
considers the emission reductions and
incremental costs for different systems
available at reasonable cost. Then, the
EPA determines the appropriate
emission limits representative of BSER.
Section 111(b)(1)(B) of the CAA requires
EPA to periodically review and revise
the standards of performance, as
necessary, to reflect improvements in
methods for reducing emissions.
B. What is the regulatory authority for
the final rule?
The current standards for steam
generating units are contained in the
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NSPS for EGUs (40 CFR part 60, subpart
Da), industrial-commercial-institutional
steam generating units (40 CFR part 60,
subpart Db), and small industrialcommercial-institutional steam
generating units (40 CFR part 60,
subpart Dc).
The NSPS for EGUs (40 CFR part 60,
subpart Da) were originally promulgated
on June 11, 1979 (44 FR 33580) and
apply to units capable of firing more
than 73 megawatts (MW) (250
MMBtu/h) heat input of fossil fuel that
commenced construction,
reconstruction, or modification after
September 18, 1978. The NSPS for EGUs
also apply to industrial-commercialinstitutional cogeneration units that sell
more than 25 MW and more than onethird of their potential output capacity
to any utility power distribution system.
The most recent significant amendments
to emission standards under 40 CFR
part 60, subpart Da, were promulgated
in 2006 (71 FR 9866) resulting in new
PM, SO2, and NOP2 limitations for 40
CFR part 60, subpart Da units.
The NSPS for industrial-commercialinstitutional steam generating units (40
CFR part 60, subpart Db) apply to units
for which construction, modification, or
reconstruction commenced after June
19, 1984, that have a heat input capacity
greater than 29 MW (100 MMBtu/h).
Those standards were originally
promulgated on November 25, 1986 (51
FR 42768) and also have been amended
since the original promulgation to
reflect changes in BSER for these
sources.
The NSPS for small industrialcommercial-institutional steam
generating units (40 CFR part 60,
subpart Dc) were originally promulgated
on September 12, 1990 (55 FR 37674)
and apply to units with a maximum
heat input capacity greater than or equal
to 2.9 MW (10 MMBtu/h) but less than
29 MW (100 MMBtu/h). Those
standards apply to units that
commenced construction,
reconstruction, or modification after
June 9, 1989.
IX. Summary of the Final NSPS
The final rule amends the emission
standards for SO2, NOP2, and PM in 40
CFR part 60, subpart Da. Only those
units that begin construction,
modification, or reconstruction after
May 3, 2011, will be affected by the
final rule. Compliance with the
emission limits of the final rule will be
determined using testing, monitoring,
and other compliance provisions similar
to those set forth in the existing
standards. In addition to the emissions
limits contained in the final rule, we
also are including several technical
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9423
clarifications and corrections to existing
provisions of the subparts.
A. What are the requirements for new
EGUs (40 CFR part 60, subpart Da)?
The filterable PM emissions standard
for new and reconstructed EGUs is 11
nanograms per joule (ng/J) (0.090 pound
per megawatt hour (lb/MWh)) gross
energy output regardless of the type of
fuel burned. The PM emissions standard
for modified EGUs is essentially
equivalent to the existing requirements
of 13 ng/J (0.015 lb/MWh) heat input
regardless of the type of fuel burned.
Compliance with this emission limit can
be determined using testing, monitoring,
and other compliance provisions similar
to those for PM standards set forth in
the existing rule. While not required,
PM CEMS may be used as an alternative
method to demonstrate continuous
compliance and as an alternative to
opacity and parameter monitoring
requirements.
The SO2 emission limit for new and
reconstructed EGUs is 130 ng/J (1.0 lb/
MWh) gross energy output or 97 percent
reduction regardless of the type of fuel
burned with one exception. The EPA
neither proposed to amended the SO2
standard for coal refuse-fired EGUs, not
reopened the issue of whether coal
refuse-fired EGUs is an appropriate
subcategory, and, therefore, that
emissions standard is unchanged. The
SO2 emission limit for modified EGUs
burning any fuel is 180 ng/J (1.4 lb/
MWh) gross energy output or 90 percent
reduction. Compliance with the SO2
emission limit is determined on a 30boiler operating day rolling average
basis using a CEMS to measure SO2
emissions and following the compliance
provisions in the proposed rule.
The NOX emission limit for new and
reconstructed EGUs is 88 ng/J (0.70 lb/
MWh) gross energy output regardless of
the type of fuel burned with one
exception. The exception is that for new
and reconstructed EGUs that burn over
75 percent coal refuse (by heat input),
the NOX emission limit is 110 ng/J (0.85
lb/MWh) gross energy output. The NOX
limit for modified EGUs is 140 ng/J (1.1
lb/MWh) gross energy output regardless
of the type of fuel burned in the unit.
Compliance with this emission limit is
determined on a 30-boiler operating day
rolling average basis using testing,
monitoring, and other compliance
provisions similar to those in the
proposed rule.
As an alternative to the NOX standard,
owners/operators of new and
reconstructed EGUs may elect to comply
with a combined NOX/CO standard of
140 ng/J (1.1 lb/MWh) with one
exception. The exception is that for new
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and reconstructed EGUs that burn over
75 percent coal refuse (by heat input) on
an annual basis, the NOX/CO emission
limit is 160 ng/J (1.3 lb/MWh) gross
energy output. Finally, owners/
operators of modified EGUs may elect to
comply with a combined NOX/CO
standard of 190 ng/J (1.5 lb/MWh).
B. Additional Amendments
See the Response to Comments
document.
X. Summary of Significant Changes
Since Proposal
A. Emission Limits
The proposal included a combined
(filterable plus condensable) PM
standard. The final standard is based
only on filterable PM. No standard is
being established for condensable PM.
The rationale for this is set forth in the
Response to Comments (RTC) document
for this final rule (the NSPS Final Rule
RTC).
The proposal requested comment on
whether the final standard should
include a stand-alone NOX standard or
a combined NOX/CO standard. In
response to comments we received and
our own further evaluation of the
situation, the final standard includes a
stand-alone NOX standard and an
optional, but not required, combined
NOX/CO standard as an alternative to
the amended NOX standard. Again, our
full rationale for this is set forth in the
NSPS Final Rule RTC. The proposal also
included a request for comment on
whether the standard should be based
on gross or net output. In response to
comments we received and our own
further evaluation of the situation, the
final standards are based on an
amended definition of gross output with
an optional net output-based standard.
This too is addressed more fully in the
NSPS Final Rule RTC.
The proposal included alternate
emission standards for commercial
demonstration projects. Proposed
commercial demonstrations included
pressurized fluidized beds, multipollutant control technologies, and
advanced combustion controls. The
final rule includes the commercial
demonstration permit exemption for
pressurized fluidized beds and multipollutant control technologies, but not
advanced combustion controls.
Advanced combustion controls are
applicable to existing facilities and the
exemption is not necessary to further
the development of the technology.
B. Requirements During Startup,
Shutdown, and Malfunction
For startup and shutdown, the
requirements for PM have changed since
proposal. For periods of startup and
shutdown, the EPA is finalizing work
practice standards for PM in lieu of
numeric emission limits. Emissions
incurred during periods of startup and
shutdown for PM are not used in
demonstrations of compliance with the
30-boiler operating day rolling average
period applicable for numeric emission
standards.
XI. Public Comments and Responses to
the Proposed NSPS
See the Response to Comments
document.
XII. Impacts of the Final Rule
The EPA anticipates significant public
health and environmental benefits from
the rule as a direct result of the
substantial reduction in the emissions of
several pollutants, including SO2, Hg,
acid gases and fine particles and metals.
For example, exposure to Hg can
damage the developing nervous system,
which can impair children’s ability to
think and learn, and fine particles can
cause adverse cardiovascular effects.
Further, reducing Hg deposition to
ecosystems will benefit wildlife
including fish, birds, and mammals.
Fish and fish-eating birds, such as the
common loon, and mammals suffer
reproductive, survival, and behavioral
impairments due to mercury exposure.
These effects have also been observed in
insect-eating and wading birds,
including egrets and white ibis.
Reductions of emissions targeted by this
rule also will slow acidification and
eutrophication of water bodies.
Additionally, the EPA anticipates
significant non-health, non-ecological
benefits from this rule. The fine particle
and SO2 emission reductions achieved
by this rule will improve visibility,
which is especially important for our
national parks. Emissions reductions
from this rule will also avoid an
estimated $360 million (in $2007) of
climate-related costs, such as
agricultural productivity and property
damage from increased flood risks.
A. What are the air impacts?
The EPA anticipates significant
emission reductions under the final rule
from coal-fired EGUs, which are of
particular interest due to their share of
total power sector emissions. In 2015,
annual HCl emissions are projected to
be reduced by 88 percent, Hg emissions
reduced by 75 percent, and PM2.5
emissions reduced by 19 percent from
coal-fired EGUs greater than 25 MW. In
addition, the EPA projects SO2 emission
reductions of 41 percent, and annual
CO2 reductions of 1 percent from coalfired EGUs greater than 25 MW by 2015,
relative to the base case. See Table 7.
TABLE 7—SUMMARY OF EMISSION REDUCTIONS FROM COAL-FIRED EGUS GREATER THAN 25 MW (TPY)
SO2
(million tons)
Base Case ...........
MATS ...................
Change .................
NOX
(million tons)
3.3
1.9
¥1.4
Mercury
(tons)
1.7
1.7
0.0
HCl
(thousand tons)
27
7
¥20
PM2.5
(thousand tons)
45
6
¥40
270
218
¥52
CO2
(million metric
tonnes)
1,906
1,882
¥23
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Note: Numbers may not add due to rounding.
The reductions in this table do not
account for reductions in other HAP
which will occur as a result of this rule.
For instance, the fine particulate
reductions presented above only partly
reflect reductions in many heavy metal
particulates, and the HCl reductions
above only partly reflect reductions of
all acid gases. This rule will also result
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in additional HAP reductions from oilfired EGUs, which are covered by the
rule but are not included in the EPA’s
analysis of emission reductions.
B. What are the energy impacts?
The EPA projects that approximately
4.7 GW of coal-fired generation (less
than 2 percent of all coal-fired capacity
and 0.5 percent of total generation
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capacity in 2015) may be uneconomic to
maintain and may be removed from
operation by 2015. These units are
predominantly smaller, less frequently
used, and are dispersed throughout the
country. If current forecasts of either
natural gas prices or electricity demand
were revised in the future to be higher,
that would create a greater incentive to
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make further investments in these
facilities and keep these units
operational.
The final rule has other important
energy market implications. Average
nationwide retail electricity prices are
projected to increase in the contiguous
U.S. by 3.1 percent in 2015. The average
delivered coal price is projected to
increase by less than 2 percent in 2015
as a result of shifts within and across
coal types. The EPA also projects that
electric power sector-delivered natural
gas prices will increase by between 0.3
and 0.6 percent over the 2015 to 2030
timeframe, on average, and that natural
gas use for electricity generation will
increase by less than 200 billion cubic
feet (BCF) in 2015. These impacts are
well within the range of price variability
that is regularly experienced in natural
gas markets. Finally, the EPA projects
coal production for use by the power
sector, a large component of total coal
production, will decrease by 10 million
tons in 2015 from base case levels,
which is about 1 percent of total coal
produced for the electric power sector
in that year.
C. What are the cost impacts?
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The power industry’s ‘‘compliance
costs’’ are represented in this analysis as
the change in electric power generation
costs between the base case and policy
case in which the sector pursues
pollution control approaches to meet
the MATS emission standards. In
simple terms, these costs are the
resource costs of direct power industry
expenditures to comply with the EPA’s
requirements.
The EPA projects that the annual
incremental compliance cost of MATS
is $9.6 billion in 2015 ($2007). The
annualized incremental cost is the
projected additional cost of complying
with the rule in the year analyzed, and
includes the amortized cost of capital
investment and the ongoing costs of
operating additional pollution controls,
needed new capacity, shifts between or
amongst various fuels, and other actions
associated with compliance.
The total incremental compliance cost
includes compliance costs modeled in
IPM of $9.4 billion, costs modeled
outside of IPM for oil-fired EGUs of $56
million, and monitoring, reporting, and
recordkeeping costs of $158 million.
D. What are the economic impacts?
For this final rule, EPA analyzed the
costs using the IPM. The IPM is a
dynamic linear programming model that
can be used to examine the economic
impacts of air pollution control policies
for a variety of HAP and other
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pollutants throughout the contiguous
U.S. for the entire power system.
Documentation for IPM can be found
in the docket for this rulemaking or at
https://www.epa.gov/airmarkets/
progsregs/epa-ipm/.
The EPA performed a screening
analysis for impacts on small entities by
comparing compliance costs to sales/
revenues (e.g., sales and revenue tests).
The EPA’s analysis can be found in
Chapter 7 of the RIA for this rule. The
EPA has also prepared a Final
Regulatory Flexibility Analysis (FRFA)
that discusses alternative regulatory or
policy options that minimize the rule’s
small entity impacts.
Although a stand-alone analysis of
employment impacts is not included in
a standard cost-benefit analysis, the
current economic climate has led to
heightened concerns about potential job
impacts. Executive Order 13563
specifically states that our ‘‘regulatory
system must protect public health,
welfare, safety, and our environment
while promoting economic growth,
innovation, competitiveness, and job
creation’’ (emphasis added).
Under conditions of full employment,
it is conventional to assume that
regulations will merely shift jobs from
one sector to another, without having a
material effect on employment levels.
Potential employment effects are of
greater concern in the current economic
climate, with high levels of
employment, because of the risk that
displaced workers may not find
alternative jobs. In addition, regulations
that result in firms hiring workers, in
order to ensure compliance, may have a
positive effect on employment.
During sustained periods of excess
unemployment, the opportunity cost of
labor required by regulated sectors to
bring their facilities into compliance
with an environmental regulation may
be lower than it would be during a
period of full employment (particularly
if regulated industries employ otherwise
idled labor to design, fabricate, or install
the pollution control equipment
required under this final rule).
Consistent with EO 13563, the EPA
includes estimates of job impacts
associated with the final rule. In the
electricity sector, the EPA estimates that
the net employment effect will range
from ¥15,000 to +30,000 jobs, with a
central estimate of +8,000. The EPA also
presents an estimate of short-term
employment effects as a result of
increased demand for pollution control
equipment.
The results of this analysis, found in
Chapter 6 of the RIA, indicate that the
final rule has the potential to provide
increases in short-term employment in
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9425
the environmental industry, primarily
driven by the high demand for new
pollution control equipment. Overall,
the results suggest that the final rule
could support a net of roughly 46,000
job years 355 in direct employment
impacts in 2015.
There are other employment effects
that cannot be estimated quantitatively
at this time. The employment gains
related to the new pollution controls are
likely to be tempered by some losses
due to certain coal retirements. On the
other hand, some of those workers who
lose their jobs due to plant retirements
could find alternative employment
operating the replacement electricity
generating equipment or new pollution
controls at nearby units. Finally, job
losses due to reduced coal demand may
be offset by job gains due to increased
natural gas demand, potentially
resulting in a positive net change in
employment due to fuel demand
changes.
The basic approach to estimate these
employment impacts involved using
IPM projections from the final rule
analysis, in particular the amount of
existing coal-fired capacity that is
projected to be retrofit with pollution
control technologies. These data, along
with data on labor and resource needs
of new pollution controls and labor
productivity from engineering studies
and secondary sources, are used to
estimate employment impacts for the
pollution control industry in 2015. For
more information, please refer to
Chapter 6 and appendix 6B in the RIA.
The EPA relied on Morgenstern, et al.,
(2002), to identify three economic
mechanisms by which pollution
abatement activities can influence jobs
in the regulated sector separately from
the short-term employment effects:
D Higher production costs raise market
prices, higher prices reduce
consumption, and employment within
an industry falls (‘‘demand effect’’);
D Pollution abatement activities
require additional labor services to
produce the same level of output (‘‘cost
effect’’); and
D Post-regulation production
technologies may be more or less labor
intensive (i.e., more/less labor is
required per dollar of output) (‘‘factorshift effect’’).
Using plant-level Census information
between the years 1979 and 1991,
355 Numbers of job years are not the same as
numbers of individual jobs, but represents the
amount of work that can be performed by the
equivalent of one full-time individual for a year (or
FTE). For example, 25 job years may be equivalent
to five full-time workers for five years, 25 full-time
workers for one year, or one full-time worker for 25
years.
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Morgenstern,et al., estimate the size of
each effect for four polluting and
regulated industries (petroleum, plastic
material, pulp and paper, and steel). On
average across the four industries, each
additional $1 million spent on pollution
abatement results in a small net increase
of 1.55 jobs; the estimated effect is not
a statistically different from zero. As a
result, the authors conclude that
increases in pollution abatement
expenditures may increase employment
in the relevant sectors and do not
necessarily cause economically
significant employment changes. The
conclusion is similar to that of Berman
and Bui (2001) who found that
increased air quality regulation in Los
Angeles did not cause large employment
changes.356 For more information,
please refer to Chapter 6 of the RIA for
this final rule.357
In the directly affected sector, the EPA
estimates that the net employment effect
will range from ¥15,000 to +30,000
jobs, with a central estimate of +8,000.
The ranges of job effects for the
electricity sector, as calculated using the
Morgenstern,et al., approach are listed
in Table 8.
TABLE 8—RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR
Estimates using Morgenstern, et al., (2001)
Demand effect
Change in Full-Time Jobs per Million Dollars of Environmental Expenditure a.
Standard Error ..........................................
EPA estimate for Final Rule b ...................
Cost effect
Factor shift
effect
Net
effect
¥3.56 ..........................
2.42 .............................
2.68 .............................
1.55.
2.03 .............................
¥39,000 to .................
+2,000 .........................
0.83 .............................
+4,000 to .....................
+21,000 .......................
1.35 .............................
+200 to ........................
+27,000 .......................
2.24.
¥15,000 to
+30,000.
a Expressed
in 1987 dollars. See footnote a from Table 6–2 of the RIA for inflation adjustment factor used in the analysis.
to the 2007 Economic Census, the electric power generation, transmission and distribution sector (NAICS 2211) had approximately
510,000 paid employees.
b According
E. What are the benefits of this final
rule?
srobinson on DSK4SPTVN1PROD with RULES2
1. Benefits of Reducing HAP Emissions
a. Human Health and Environmental
Effects Due to Exposure to MeHg. In this
section, we provide a qualitative
description of human health and
environmental effects due to exposure
to MeHg. The NAS Study (NRC, 2000)
provides a thorough review of the
effects of MeHg on human health. Many
of the peer-reviewed articles cited in
this section are publications originally
cited in the NAS Study. In addition, the
EPA has conducted literature searches
to obtain other related and more recent
publications to complement the material
summarized by the NAS in 2000.
b. Neurologic Effects of Exposure to
MeHg. In its review of the literature, the
NAS found neurodevelopmental effects
to be the most sensitive and best
documented endpoints and concluded
that they are appropriate for establishing
an RfD (NRC, 2000); in particular NAS
supported the use of results from
neurobehavioral or neuropsychological
tests. The NAS Study (NRC, 2000) noted
that studies in animals reported sensory
356 For alternative views in economic journals,
see Henderson (1996) and Greenstone (2002).
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effects as well as effects on brain
development and memory functions and
support the conclusions based on
epidemiology studies. The NAS noted
that their recommended
neurodevelopmental endpoints for an
RfD are associated with the ability of
children to learn and to succeed in
school. They concluded the following:
‘‘The population at highest risk is the
children of women who consumed large
amounts of fish and seafood during
pregnancy. The committee concludes
that the risk to that population is likely
to be sufficient to result in an increase
in the number of children who have to
struggle to keep up in school.’’
c. Cardiovascular Impacts of Exposure
to MeHg. The NAS summarized data on
cardiovascular effects available up to
2000. Based on these and other studies,
the NAS Study concluded that
‘‘Although the data base is not as
extensive for cardiovascular effects as it
is for other end points (i.e., neurologic
effects) the cardiovascular system
appears to be a target for MeHg toxicity
in humans and animals.’’ The report
also stated that ‘‘additional studies are
needed to better characterize the effect
of MeHg exposure on blood pressure
and cardiovascular function at various
stages of life.’’
Additional cardiovascular studies
have been published since 2000. The
EPA did not develop a quantitative
dose-response assessment for
cardiovascular effects associated with
MeHg exposures, as there is no
consensus among scientists on the doseresponse functions for these effects. In
addition, there is inconsistency among
available studies as to the association
between MeHg exposure and various
cardiovascular system effects. The
pharmacokinetics of some of the
exposure measures (such as toenail Hg
levels) are not well understood. The
studies have not yet received the review
and scrutiny of the more wellestablished neurotoxicity data base.
d. Genotoxic Effects of Exposure to
MeHg. The Mercury Study noted that
MeHg is not a potent mutagen but is
capable of causing chromosomal
damage in a number of experimental
systems. The NAS Study indicated that
evidence that human exposure to MeHg
causes genetic damage is inconclusive;
they note that some earlier studies
showing chromosomal damage in
lymphocytes may not have controlled
sufficiently for potential confounders.
One study of adults living in the
´
Tapajos River region in Brazil
(Amorimet al., 2000) reported a direct
relationship between MeHg
concentration in hair and DNA damage
in lymphocytes, as well as effects on
chromosomes. Long-term MeHg
exposures in this population were
believed to occur through consumption
of fish, suggesting that genotoxic effects
(largely chromosomal aberrations) may
result from dietary, chronic MeHg
exposures similar to and above those
357 It should be noted that if more labor must be
used to produce a given amount of output, then this
implies a decrease in labor productivity. A decrease
in labor productivity will cause a short-run
The EPA recognizes there may be
other job effects that are not considered
in the Morgenstern,et al., study.
Although EPA has considered some
economy-wide changes, we do not have
sufficient information to quantify other
job effects associated with this rule.
aggregate supply curve to shift to the left, and
businesses will produce less, all other things being
equal.
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seen in the populations studied in the
Faroe Islands and Republic of
Seychelles.
e. Immunotoxic Effects to Exposure to
MeHg. Although exposure to some
forms of Hg can result in a decrease in
immune activity or an autoimmune
response (ATSDR, 1999), evidence for
immunotoxic effects of MeHg is limited
(NRC, 2000).
f. Other Hg-Related Human Toxicity
Data. Based on limited human and
animal data, MeHg is classified as a
‘‘possible’’ human carcinogen by the
International Agency for Research on
Cancer (IARC, 1994) and in IRIS
(USEPA, 2002). The existing evidence
supporting the possibility of
carcinogenic effects in humans from
low-dose chronic exposures is tenuous.
Multiple human epidemiological
studies have found no significant
association between Hg exposure and
overall cancer incidence, although a few
studies have shown an association
between Hg exposure and specific types
of cancer incidence (e.g., acute leukemia
and liver cancer) (NAS, 2000).
Some evidence of reproductive and
renal toxicity in humans from MeHg
exposure exists. However, overall,
human data regarding reproductive,
renal, and hematological toxicity from
MeHg are very limited and are based on
studies of the two high-dose poisoning
episodes in Iraq and Japan or animal
data, rather than epidemiological
studies of chronic exposures at the
levels of interest in this analysis.
g. Ecological Effects of Hg. Deposition
of Hg to watersheds can also have an
impact on ecosystems and wildlife.
Mercury contamination is present in all
environmental media, with aquatic
systems experiencing the greatest
exposures due to bioaccumulation.
Bioaccumulation refers to the net uptake
of a contaminant from all possible
pathways and includes the
accumulation that may occur by direct
exposure to contaminated media as well
as uptake from food.
A review of the literature on effects of
Hg on fish 358 reports results for
numerous species including trout, bass
(large and smallmouth), northern pike,
carp, walleye, salmon, and others from
laboratory and field studies. The effects
of MeHg in fish are reproductive in
nature. Although we cannot determine
at this time whether these reproductive
deficits are affecting fish populations
across the U.S. it should be noted that
it would seem reasonable that over time
358 Crump, KL, and Trudeau, VL. Mercuryinduced reproductive impairment in fish.
Environmental Toxicology and Chemistry. Vol. 28,
No. 5, 2009.
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reproductive deficits would have an
effect on populations.
Mercury also affects avian species. In
previous reports 359 much of the focus
has been on large piscivorous species, in
particular the common loon. According
to Evers,et al., significant adverse effects
from Hg on breeding loons have been
found to occur, including behavioral
(reduced nest-sitting), physiological
(flight feather asymmetry) and
reproductive (chicks fledged/territorial
pair) effects and reduced survival.360
Additionally, Evers, et al., (see footnote
5), believe that the weight of evidence
indicates that population-level effects
occur in parts of Maine and New
Hampshire, and potentially in broad
areas of the loon’s range.
Recently, attention has turned to other
piscivorous species such as the white
ibis and great snowy egret. These
wading birds have a very wide diet
including crayfish, crabs, snails, insects
and frogs. White ibis have been
observed to have decreased foraging
efficiency361 and have been shown to
exhibit decreased reproductive success
and altered pair behavior.362 In egrets,
Hg has been implicated in the decline
of the species in south Florida,363 and
Hoffman364 has shown that egrets
359 U.S. Environmental Protection Agency (EPA).
1997. Mercury Study Report to Congress. Volume
V: Health Effects of Mercury and Mercury
Compounds. EPA–452/R–97–007. U.S. EPA Office
of Air Quality Planning and Standards, and Office
of Research and Development; U.S. Environmental
Protection Agency (U.S. EPA). 2005. Regulatory
Impact Analysis of the Final Clean Air Mercury
Rule. Research Triangle Park, NC., March; EPA
report no. EPA–452/R–05–003. Available on the
Internet at https://www.epa.gov/ttn/ecas/regdata/
RIAs/mercury_ria_final.pdf.
360 Evers, DC, Savoy, LJ, DeSorbo, CR, Yates, DE,
Hanson, W, Taylor, KM, Siegel, LS, Cooley, JH, Jr.,
Bank, MS, Major, A, Munney, K, Mower, BF, Vogel,
HS, Schoch, N, Pokras, M, Goodale, MW, Fair, J.
Adverse effects from environmental mercury loads
on breeding common loons. Ecotoxicology. 17:69–
81, 2008; Mitro, MG, Evers, DC, Meyer, MW, and
Piper, WH. Common loon survival rates and
mercury in New England and Wisconsin. Journal of
Wildlife Management. 72(3): 665–673, 2008.
361 Adams, EM, and Frederick, PC. Effects of
methylmercury and spatial complexity on foraging
behavior and foraging efficiency in juvenile white
ibises (Eudocimus albus). Environmental
Toxicology and Chemistry. Vol 27, No. 8, 2008.
362 Frederick, P, and Jayasena, N. Altered pairing
behavior and reproductive success in white ibises
exposed to environmentally relevant concentrations
of methylmercury. Proceedings of The Royal
Society B. doi: 10–1098, 2010.
363 Sepulveda, MS, Frederick, PC, Spalding, MG,
and Williams, GE, Jr. Mercury contamination in
free-ranging great egret nestlings (Ardea albus) from
southern Florida, USA. Environmental Toxicology
and Chemistry. Vol. 18, No. 5, 1999.
364 Hoffman, DJ, Henny, CJ, Hill, EF, Grover, RA,
Kaiser, JL, Stebbins, KR. Mercury and drought along
the lower Carson River, Nevada: III. Effects on blood
and organ biochemistry and histopathology of
snowy egrets and black-crowned night-herons on
Lahontan Reservoir, 2002–2006. Journal of
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9427
exhibit liver and possibly kidney effects.
Although ibises and egrets are most
abundant in coastal areas and these
studies were conducted in south Florida
and Nevada, the ranges of ibises and
egrets extend to a large portion of the
U.S.
Insectivorous birds have also been
shown to suffer adverse effects due to
Hg exposure. Songbirds such as
Bicknell’s thrush, tree swallows, and the
great tit have shown reduced
reproduction, survival, and changes in
singing behavior. Exposed tree swallows
produced fewer fledglings,365 had lower
survival rates,366 and had compromised
immune competence.367 The great tit
has exhibited reduced singing behavior
and smaller song repertoire in areas of
high contamination.368
In mammals, adverse effects have
been observed in mink and river otter,
both fish eating species. For otter from
Maine and Vermont, maximum
concentrations of Hg in fur nearly equal
or exceed a level associated with
mortality and concentration in liver for
mink in Massachusetts/Connecticut and
the levels in fur from mink in Maine
exceed concentrations associated with
acute mortality.369 Adverse sublethal
effects may be associated with lower Hg
concentrations and consequently may
be more widespread than potential
acute effects. These effects may include
increased activity, poorer maze
performance, abnormal startle reflex,
and impaired escape and avoidance
behavior.370
h. Methodology for Partial Hg Benefits
Estimation. The EPA has conducted a
national-scale analysis of the benefits to
recreational anglers of avoided IQ loss
related to reductions of Hg emissions
Toxicology and Environmental Health, Part A. 72:
20, 1223–1241, 2009.
365 Brasso, RL, and Cristol, DA. Effects of mercury
exposure in the reproductive success of tree
swallows (Tachycineta bicolor). Ecotoxicology.
17:133–141, 2008.
366 Hallinger, KK, Cornell, KL, Brasso, RL, and
Cristol, DA. Mercury exposure and survival in freeliving tree swallows (Tachycineta bicolor).
Ecotoxicology. Doi: 10.1007/s10646–010–0554–4,
2010.
367 Hawley, DM, Hallinger, KK, Cristol, DA.
Compromised immune competence in free-living
tree swallows exposed to mercury. Ecotoxicology.
18:499–503, 2009.
368 Gorissen, L, Snoeijs, T, Van Duyse, E, and
Eens, M. Heavy metal pollution affects dawn
singing behavior in a small passerine bird.
Oecologia. 145: 540–509, 2005.
369 Yates, DE, Mayack, DT, Munney, K, Evers DC,
Major, A, Kaur, T, and Taylor, RJ. Mercury levels
in mink (Mustela vison) and river otter (Lonra
canadensis) from northeastern North America.
Ecotoxicology. 14, 263–274, 2005.
370 Scheuhammer, AM, Meyer MW,
Sandheinrich, MB, and Murray, MW. Effects of
environmental methylmercury on the health of wild
birds, mammals, and fish. Ambio. Vol.36, No.1,
2007.
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and subsequent deposition that will be
achieved by this rule. Because the
primary measurable health effect of
concern—developmental neurological
abnormalities in children—occurs as a
result of in-utero exposures to Hg, the
specific population of interest in this
case is prenatally exposed children. To
identify and estimate the size of this
exposed population, the benefits
analysis focused on pregnant women in
freshwater recreational angler
households. Estimating Hg exposures
for this exposure pathway and
population of interest requires three
main components: (1) The size of the
exposed population of interest (annual
number of pregnant women in
freshwater angler households during the
year), (2) the average concentration of
MeHg in noncommercial freshwater fish
filets consumed, and (3) the average
daily consumption rate of
noncommercial freshwater fish. The Hg
concentrations of fish in the
waterbodies where the fish are caught
are modeled using Mercury Maps to
project the decline in concentrations
due to the rule. To approximate the
percentage of freshwater fishing trips
(and exposed individuals) from each
Census tract matched to each waterbody
type, the EPA used state-level averages.
These averages were calculated for each
state, based on the portion of residents’
freshwater fishing trips that are to each
waterbody type, based on 2001 National
Survey of Fishing, Hunting, and
Wildlife-Associated Recreation
(FHWAR) data.
Data from the 1994 National Survey
on Recreation and the Environment
(NSRE) were used to approximate the
percentage of freshwater fishing trips
(and exposed individuals) matched to
different distances from anglers’
residential location.
To determine an appropriate daily
fish consumption rate for the analysis,
the EPA conducted an extensive review
of existing literature characterizing selfcaught freshwater fish consumption.
Based on this review, it was decided
that the ingestion rates for recreational
freshwater fishers, specified as
‘‘recommended’’ in the EPA’s
‘‘Environmental Exposure Factors
Handbook’’ (EPA, 1997), represented the
most appropriate values to use in this
analysis.
Estimating the IQ decrements in
children that result from mothers’
prenatal ingestion of Hg from fish
required two steps. First, based on the
estimated average daily maternal
ingestion rate, the expected Hg
concentration in the hair of exposed
pregnant women was estimated.
Second, to estimate the expected IQ
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decrement in offspring, the following
dose-response relationship was
developed based on the summary
findings reported in Axelrad et al.,
(2007).
The valuation approach used to assess
monetary losses due to IQ decrements is
based on an approach applied in
previous EPA analyses (EPA, 2008). The
approach expresses the potential loss to
an affected individual resulting from IQ
decrements in terms of foregone future
earnings (net of changes in education
costs) for that individual.
The estimate for ‘‘Present Value of
Lifetime Earnings’’ is derived using
earnings and labor force participation
rate data from the Bureau of Labor
Statistics 2006 Current Population
Survey. Estimates of the average effect
of a 1-point increase in IQ on lifetime
earnings range from a 1.76 percent
increase (Schwartz, 1994) to a 2.379
percent increase (Salkever, 1995). The
percentage increases in the two studies
reflect both the direct impact of IQ on
hourly wages and indirect effects on
annual earnings as the result of
additional schooling and increased
labor force participation. The estimate
for years of additional schooling is
based on Schwartz (1994), who reports
an increase of 0.131 years of schooling
per IQ point.
In addition to this positive net effect
on earnings, an increase in IQ is also
assumed to have a positive effect on the
amount of time spent in school and on
associated costs. To incorporate (1)
uncertainty regarding the size of the
percentage change in future earnings
and (2) different assumptions regarding
the discount rate, the resulting value
estimates for the average net loss per IQ
point decrement are expressed as a
range. Assuming a 3 percent discount
rate, value IQ ranges from $8,013 (using
the Schwartz estimates) to $11,859
(using the Salkever estimates) in
increased earnings per year per 1-point
IQ increase. With a 7 percent discount
rate assumption, the value IQ estimates
range from $893 to $1,958 in increased
earnings per year per 1-point IQ
increase.
The EPA analyzed the aggregate
national IQ and present-value loss
estimates for two base case and three
emission control scenarios. The highest
losses are estimated for the 2005 base
case. For the population of prenatally
exposed children included in the
analysis (almost 240,000), Hg exposures
under baseline conditions during the
year 2005 are estimated to have resulted
in more than 25,500 IQ points lost.
Assuming a 3 percent discount rate, the
present-year value of these losses ranges
from $204.8 million to $292.5 million
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nationally.371 These losses represent
expected present value of declines in
future net earnings over the entire
lifetimes of the children who are
prenatally exposed during the year
2005. With a 7 percent discount rate, the
present-year value range is considerably
lower: $22.8 million to $50.0 million.
For this rule, the EPA generated
estimates of aggregate nationwide
benefits associated with reductions in
Hg exposures and resulting reductions
in IQ losses. Most importantly, the
benefits of the 2016 MATS scenario
(relative to the 2016 base case) are
estimated to range between $4 million
and $6 million (assuming a 3 percent
discount rate), because of an estimated
511 point reduction in IQ losses. The
EPA recognizes that these calculated
benefits are a small subset of the
benefits of reducing Hg emissions.
2. Health and Welfare Co-Benefits
Emission controls installed to meet
the requirements of this rule will
generate co-benefits by reducing criteria
pollutants including PM2.5 and SO2, as
well as CO2. For this rule, we were only
able to estimate the mortality benefits of
PM2.5 reductions due to changes in
emissions of SO2 and direct PM2.5 and
climate benefits resulting from CO2
reductions. Additional co-benefits may
result from decreases in PM2.5 morbidity
impacts, decreases in sulfur deposition
and direct health effects of SO2, and
improvements in visibility in national
parks and wilderness areas. Total cobenefits may be higher than the partial
estimates of co-benefits provided here.
Our best estimate of the monetized
health and climate co-benefits of this
rule in 2016 at a 3 percent discount rate
are $37 billion to $90 billion or $33
billion to $81 billion at a 7 percent
discount rate (2007$). Using alternate
relationships between PM2.5 and
premature mortality supplied by
experts, higher and lower health cobenefits estimates are plausible, but
most of the expert-based estimates fall
between these two estimates.372
a. Human Health Co-Benefits. To
estimate the human health co-benefits of
this rule, the EPA used benefit-per-ton
371 Monetized benefits estimates are for an
immediate change in MeHg levels in fish. If a lag
in the response of MeHg levels in fish were
assumed, the monetized benefits could be
significantly lower, depending on the length of the
lag and the discount rate used. As noted in the
discussion of the Mercury Maps modeling, the
relationship between deposition and fish tissue
MeHg is proportional in equilibrium, but the
Mercury Maps approach does not provide any
information on the time lag of response.
372 Roman, et al., 2008. Expert Judgment
Assessment of the Mortality Impact of Changes in
Ambient Fine Particulate Matter in the U.S.
Environ. Sci. Technol., 42, 7, 2268–2274.
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factors to quantify the changes in PM2.5related health impacts and monetized
benefits based on changes in SO2 and
direct PM2.5 emissions. These benefitper-ton factors were based on an interim
baseline and policy scenario for which
full-scale ambient air quality modeling
and air quality-based human health
benefits assessments were performed.
This general approach and methodology
is laid out in Fann, et al., (2009),373 but
for this rule the air quality modeling
used a better spatial representation of
the emission changes from EGUs. Using
a benefit-per-ton approach adds another
important source of uncertainty to the
benefits estimates. For more details on
the creation of the benefit-per-ton
factors and their application to emission
reductions under this rule, please refer
to the RIA for this rule in the docket.
Table 9 presents the estimates of
reduced annual incidence of PM2.5-
9429
related health effects in 2016 resulting
from this rule. Table 10 presents the
estimated annual monetary value of the
reduced incidence of quantified health
endpoints in 2016 resulting from this
rule.
The reduction in premature fatalities
each year accounts for between 93 and
97 percent of the estimated health cobenefits that were monetized.
TABLE 9—ESTIMATED REDUCTIONS IN INCIDENCE OF PM2.5-RELATED HEALTH EFFECTS IN 2016 a
Health effect
Number of reduced cases
Adult Premature Mortality
Pope et al., (2002) (age >30) .........................................................................................................................
Laden et al., (2006) (age >25) .......................................................................................................................
Infant Premature Mortality (<1 year) .....................................................................................................................
Chronic Bronchitis ..................................................................................................................................................
Non-fatal heart attacks (age >18) .........................................................................................................................
Hospital admissions—respiratory (all ages) ..........................................................................................................
Hospital admissions—cardiovascular (age >18) ...................................................................................................
Emergency room visits for asthma (age <18) .......................................................................................................
Acute bronchitis (age 8–12) ..................................................................................................................................
Lower respiratory symptoms (age 7–14) ...............................................................................................................
Upper respiratory symptoms (asthmatics age 9–11) ............................................................................................
Asthma exacerbation (asthmatics 6–18) ...............................................................................................................
Lost work days (ages 18–65) ................................................................................................................................
Minor restricted-activity days (ages 18–65) ..........................................................................................................
4,200.
(1,200 to 7,200).
11,000.
(5,000 to 17,000).
20.
(¥22 to 61).
2,800.
(88 to 5,600).
4,700.
(1,200 to 8,300).
830.
(330 to 1,300).
1,800.
(1,200 to 2,200).
3,100.
(1,600 to 4,700).
6,300.
(¥1,400 to 14,000).
80,000.
(31,000 to 130,000).
60,000.
(11,000 to 110,000).
130,000.
(4,500 to 450,000).
540,000.
(460,000 to 620,000).
3,200,000.
(2,600,000 to 3,800,000).
a Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reducing visibility impairment and ecosystem effects are not included here.
TABLE 10—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS IN 2016 a
Health effect
Monetized benefits
Adult Premature Mortality
Pope, et al., (2002) (age >30):
3% discount rate .............................................................................................................................................
7% discount rate .............................................................................................................................................
Laden, et al., (2006) (age >25):
3% discount rate .............................................................................................................................................
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7% discount rate .............................................................................................................................................
Infant Premature Mortality (<1 year) .....................................................................................................................
Chronic Bronchitis ..................................................................................................................................................
$34.
($2.6 to $100).
$30.
($2.4 to $92).
$87.
($7.5 to $250).
$78.
($6.8 to $230).
$0.2.
($¥0.2 to $0.8).
$1.4.
($0.1 to $6.4).
Non-fatal heart attacks (age >18):
373 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009.
‘‘The influence of location, source, and emission
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type in estimates of the human health benefits of
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reducing a ton of air pollution.’’ Air Qual Atmos
Health (2009) 2:169–176.
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TABLE 10—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS IN 2016 a—Continued
Health effect
Monetized benefits
3% discount rate .............................................................................................................................................
7% discount rate .............................................................................................................................................
Hospital admissions—respiratory (all ages) ..........................................................................................................
Hospital admissions—cardiovascular (age >18) ...................................................................................................
Emergency room visits for asthma (age <18) .......................................................................................................
Acute bronchitis (age 8–12) ..................................................................................................................................
Lower respiratory symptoms (age 7–14) ...............................................................................................................
Upper respiratory symptoms (asthmatics age 9–11) ............................................................................................
Asthma exacerbation (asthmatics 6–18) ...............................................................................................................
Lost work days (ages 18–65) ................................................................................................................................
Minor restricted-activity days (ages 18–65) ..........................................................................................................
$0.5.
($0.1 to $1.3).
$0.4.
($0.1 to $1.0).
$0.01.
($0.01 to $0.02).
$0.03.
(<$0.01 to $0.05).
<$0.01.
<$0.01.
<$0.01.
<$0.01.
<$0.01.
$0.1.
($0.1 to $0.1).
$0.2.
($0.1 to $0.3).
Monetized Health Co-Benefits
Pope, et al., (2002):
3% discount rate .............................................................................................................................................
7% discount rate .............................................................................................................................................
Laden, et al., (2006):
3% discount rate .............................................................................................................................................
7% discount rate .............................................................................................................................................
$36.
($2.8–$110).
$33.
($2.5–$100).
$89.
($7.7–$260).
$80.
($6.9–$240).
a Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reducing visibility impairment and ecosystem effects are not included here.
srobinson on DSK4SPTVN1PROD with RULES2
It is important to note that the
magnitude of the PM2.5 co-benefits is
largely driven by the concentration
response function for premature
mortality. Experts have advised the EPA
to consider a variety of assumptions,
including estimates based both on
empirical (epidemiological) studies and
judgments elicited from scientific
experts, to characterize the uncertainty
in the relationship between PM2.5
concentrations and premature mortality.
We cite two key empirical studies, one
based on the American Cancer Society
cohort study 374 and the other based on
the extended Six Cities cohort study.375
The analyses upon which this rule is
based were selected from the peerreviewed scientific literature. We used
up-to-date assessment tools, and we
believe the results are highly useful in
assessing this rule.
Every benefit analysis examining the
potential effects of a change in
environmental protection requirements
374 Pope et al., 2002. ‘‘Lung Cancer,
Cardiopulmonary Mortality, and Long-term
Exposure to Fine Particulate Air Pollution.’’ Journal
of the American Medical Association. 287:1132–
1141.
375 Ladenet al., 2006. ‘‘Reduction in Fine
Particulate Air Pollution and Mortality.’’ American
Journal of Respiratory and Critical Care Medicine.
173:667–672.
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is limited to some extent by data gaps,
model capabilities (such as geographic
coverage), and uncertainties in the
underlying scientific and economic
studies used to configure the benefit and
cost models. Gaps in the scientific
literature often result in the inability to
estimate quantitative changes in health
and environmental effects, or to assign
economic values even to those health
and environmental outcomes that can be
quantified. The uncertainties in the
underlying scientific and economics
literature (that may result in
overestimation or underestimation of
the co-benefits) are discussed in detail
in the RIA. Despite these uncertainties,
we believe the benefit analysis for this
rule provides a reasonable indication of
the expected health co-benefits of the
rulemaking in future years under a set
of reasonable assumptions.
When characterizing uncertainty in
the PM-mortality relationship, the EPA
has historically presented a sensitivity
analysis applying alternate assumed
thresholds in the PM concentrationresponse relationship. In its synthesis of
the current state of the PM science, the
EPA’s 2009 Integrated Science
Assessment for Particulate Matter
concluded that a no-threshold log-linear
model most adequately portrays the PM-
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mortality concentration-response
relationship.
In the RIA accompanying this
rulemaking, rather than segmenting out
impacts predicted to be associated with
levels above and below a ‘‘bright line’’
threshold, the EPA includes a ‘‘lowest
measured level’’ (LML) analysis that
illustrates the increasing uncertainty
that characterizes exposure attributed to
levels of PM2.5 below the LML of each
epidemiological study used to estimate
PM2.5-related premature death. Figures
provided in the RIA show the
distribution of baseline exposure to
PM2.5, as well as the lowest air quality
levels measured in each of the
epidemiology cohort studies. This
information provides a context for
considering the likely portion of PMrelated mortality benefits occurring
above or below the LML of each study;
in general, our confidence in the size of
the estimated reduction in PM2.5-related
premature mortality diminishes as
baseline concentrations of PM2.5 are
lowered.
Based on the modeled interim
baseline which is approximately
equivalent to the final baseline (see
Appendix A of the RIA), 11 percent and
73 percent of the estimated avoided
mortality impacts occur at or above an
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annual mean PM2.5 level of 10 mg/m3
(the LML of the Ladenet al., 2006
study)or 7.5 mg/m3 (the LML of the
Pope,et al., 2002 study), respectively.
Although the LML analysis provides
some insight into the level of
uncertainty in the estimated PM
mortality benefits, the EPA does not
view the LML as a threshold and
continues to quantify PM-related
mortality impacts using a full range of
modeled air quality concentrations. A
large fraction of the PM2.5-related
benefits occur below the level of the
National Ambient Air Quality Standard
(NAAQS) for PM2.5 at 15 mg/m3, which
was set in 2006. It is important to
emphasize that NAAQS are not set at a
level of zero risk. Instead, the NAAQS
reflect the level determined by the
Administrator to be protective of public
health within an adequate margin of
safety, taking into consideration effects
on susceptible populations. While
benefits occurring below the standard
may be less certain than those occurring
above the standard, EPA considers them
to be legitimate components of the total
benefits estimate.
It is important to note that the
monetized benefits include many but
not all health effects associated with
PM2.5 exposure. Benefits are shown as a
range from Pope, et al., (2002), to Laden,
et al., (2006). These studies assume that
all fine particles, regardless of their
chemical composition, are equally
potent in causing premature mortality
because there is no clear scientific
evidence that would support the
development of differential effects
estimates by particle type. Even though
we assume that all fine particles have
equivalent health effects, the benefitper-ton estimates vary between directlyemitted particles (carbonaceous and
crustal particles) and SO2 emissions that
form sulfate particles, based on the
location of emission changes and
magnitude of population exposure
changes. Regardless, however, the
assumption that all fine particles are
equally potent in causing premature
mortality adds uncertainty to the
benefits estimate.
b. Non-Climate Welfare Co-Benefits.
Emission controls installed to comply
with the requirements specified in this
rule will also generate co-benefits by
improving visibility. We anticipate that
improvements in visibility in Class I
areas as well as residential areas where
people live, work, and recreate could be
substantial. Because full-scale air
quality modeling was not performed for
this rule, we are unable to quantify
these visibility co-benefits for this rule.
However, the estimated value of
visibility benefits calculated from the
modeled interim baseline and policy
scenario was $1.1 billion (in 2007$).
These visibility benefits are not
included in the total co-benefits
estimate of the final policy scenario
used as a basis for this final rule. The
distribution of emission reductions did
not change substantially in the visibility
regions studied, therefore visibility
benefits of the final policy scenario are
likely to be of a similar magnitude.
Ecosystem and other welfare effects
include reduced acidification and, in
the case of NOX, eutrophication of water
bodies; possible reduced nitrate
contamination of drinking water; ozone
vegetation damage; a reduction in the
role of sulfate in Hg methylation; and
reduced acid and particulate deposition
that causes damages to cultural
monuments, as well as soiling and other
materials damage. To illustrate the
important nature of benefit categories
the EPA is currently unable to monetize,
we discuss the potential public welfare
and environmental impacts related to
reductions in emissions required by this
rule in the RIA, including reduced
visibility impairment, reduced effects
from acid deposition, reduced effects
from nutrient enrichment, and reduced
vegetation effects from ambient
exposure to SO2 and NO2.
c. Climate co-benefits. This rule is
expected to reduce CO2 emissions from
the electricity sector. The EPA has
assigned a dollar value to reductions in
CO2 emissions using recent estimates of
the ‘‘social cost of carbon’’ (SCC). The
SCC is an estimate of the monetized
damages associated with an incremental
increase in carbon emissions in a given
year or the per metric ton benefit
estimate relating to decreases in CO2
emissions. It is intended to include (but
is not limited to) changes in net
agricultural productivity, human health,
property damage from increased flood
risk, and the value of ecosystem services
due to climate change.
The SCC estimates used in this
analysis were developed through an
interagency process that included the
376 Docket ID EPA–HQ–OAR–2009–0472–114577,
Technical Support Document: Social Cost of Carbon
for Regulatory Impact Analysis Under Executive
Order 12866, Interagency Working Group on Social
Cost of Carbon, with participation by Council of
Economic Advisers, Council on Environmental
Quality, Department of Agriculture, Department of
Commerce, Department of Energy, Department of
Transportation, Environmental Protection Agency,
National Economic Council, Office of Energy and
Climate Change, Office of Management and Budget,
Office of Science and Technology Policy, and
Department of Treasury (February 2010). Also
available at https://epa.gov/otaq/climate/
regulations.htm.
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EPA and other executive branch
entities, and that concluded in February
2010. We first used these SCC estimates
in the benefits analysis for the final joint
EPA/DOT Rulemaking to establish
Light-Duty Vehicle Greenhouse Gas
Emission Standards and Corporate
Average Fuel Economy Standards; see
the rule’s preamble for discussion about
application of the SCC (75 FR 25324;
May 7, 2010). The SCC Technical
Support Document (SCC TSD) provides
a complete discussion of the methods
used to develop these SCC estimates.376
The interagency group selected four
SCC values for use in regulatory
analyses, which we have applied in this
analysis: $5.9, $24.3, $39, and $74.4 per
metric ton of CO2 emissions in 2016, in
2007 dollars. The first three values are
based on the average SCC from three
integrated assessment models, at
discount rates of 5, 3, and 2.5 percent,
respectively. Social cost of carbon
values at several discount rates are
included because the literature shows
that the SCC is quite sensitive to
assumptions about the discount rate,
and because no consensus exists on the
appropriate rate to use in an
intergenerational context. The fourth
value is the 95th percentile of the SCC
from all three values at a 3 percent
discount rate. It is included to represent
higher-than-expected impacts from
temperature change further out in the
extremes of the SCC distribution. Low
probability, high impact events are
incorporated into all of the SCC values
through explicit consideration of their
effects in two of the three values as well
as the use of a probability density
function for equilibrium climate
sensitivity. Treating climate sensitivity
probabilistically results in more high
temperature outcomes, which in turn
leads to higher projections of damages.
Applying the global SCC estimates
using a 3 percent discount rate, we
estimate the value of the climate related
benefits of this rule in 2016 is $360
million (2007$), as shown in Table 11.
See the RIA for more detail on the
methodology used to calculate these
benefits and additional estimates of
climate benefits using different discount
rates and the 95th percentile of the 3
percent discount rate SCC. Important
limitations and uncertainties of the SCC
approach are also described in the RIA.
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TABLE 11—ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS AND CLIMATE
BENEFITS IN 2016a
Effect
Monetized benefits
Monetized Health Co-Benefits
Pope, et al., (2002):
3% discount rate ...........................................................................................................................................................
7% discount rate ...........................................................................................................................................................
Laden, et al., (2006):
3% discount rate ...........................................................................................................................................................
7% discount rate ...........................................................................................................................................................
Climate-related Co-Benefits (3% discount rate) ..................................................................................................................
$36
($2.8–$110)
$33
($2.5–$100)
........................................
$89
($7.7–$260)
$80
($6.9–$240)
$0.36
Monetized Total Co-Benefits
Pope, et al., (2002):
3% discount rate ...........................................................................................................................................................
7% discount rate ...........................................................................................................................................................
Laden, et al., (2006):
3% discount rate ...........................................................................................................................................................
7% discount rate ...........................................................................................................................................................
........................................
$37
($3.2–$110)
$33
($2.9–$100)
........................................
$90
($8.0–$260)
$81
($7.3–$240)
a Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reducing visibility impairment and ecosystem effects are not included here.
Our best estimate for the monetized
total health and climate co-benefits of
this rule in 2016 at a 3 percent discount
rate is between $37 billion and $90
billion or between $33 billion and $81
billion (2007$) at a 7 percent discount
rate. These estimates account for the
quantified health and climate benefits
described in Table 11.
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XIII. Statutory and Executive Order
Reviews
A. Executive Order 12866, Regulatory
Planning and Review and Executive
Order 13563, Improving Regulation and
Regulatory Review
Under EO 12866 (58 FR 51735;
October 4, 1993), this action is an
‘‘economically significant regulatory
action’’ because it is likely to have an
annual effect on the economy of $100
million or more or adversely affect in a
material way the economy, a sector of
the economy, productivity, competition,
jobs, the environment, public health or
safety, or state, local, or tribal
governments or communities.
Accordingly, the EPA submitted this
action to the OMB for review under
Executive Orders 12866 and 13563 and
any changes in response to OMB
recommendations have been
documented in the docket for this
action. For more information on the
costs and benefits for this rule, please
refer to Table 2 of this preamble.
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When estimating the human health
benefits and compliance costs in Table
2 of this preamble, the EPA applied
methods and assumptions consistent
with the state-of-the-science for human
health impact assessment, economics
and air quality analysis. The EPA
applied its best professional judgment
in performing this analysis and believes
that these estimates provide a
reasonable indication of the expected
benefits and costs to the nation of this
rulemaking. The RIA available in the
docket describes in detail the empirical
basis for the EPA’s assumptions and
characterizes the various sources of
uncertainties affecting the estimates
below. In doing what is laid out above
in this paragraph, the EPA adheres to
EO 13563, ‘‘Improving Regulation and
Regulatory Review,’’ (76 FR 3821;
January 18, 2011), which is a
supplement to EO 12866.
In addition to estimating costs and
benefits, EO 13563 focuses on the
importance of a ‘‘regulatory system
[that] * * * promote[s] predictability
and reduce[s] uncertainty’’ and that
‘‘identify[ies] and use[s] the best, most
innovative, and least burdensome tools
for achieving regulatory ends.’’ In
addition, EO 13563 states that ‘‘[i]n
developing regulatory actions and
identifying appropriate approaches,
each agency shall attempt to promote
such coordination, simplification, and
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harmonization. Each agency shall also
seek to identify, as appropriate, means
to achieve regulatory goals that are
designed to promote innovation.’’ We
recognize that the utility sector faces a
variety of requirements, including ones
under CAA section 110(a)(2)(D) dealing
with the interstate transport of
emissions contributing to ozone and PM
air quality problems, with coal
combustion wastes, and with the
implementation of CWA section 316(b).
In developing today’s final rule, the EPA
recognizes that it needs to approach
these rulemakings in ways that allow
the industry to make practical
investment decisions that minimize
costs in complying with all of the final
rules, while still achieving the
fundamentally important environmental
and public health benefits that underlie
the rulemakings.
A summary of the monetized costs,
benefits, and net benefits for the final
rule at discount rates of 3 percent and
7 percent is in Table 2 of this preamble.
For more information on the analysis,
please refer to the RIA for this
rulemaking, which is available in the
docket.
B. Paperwork Reduction Act
The information collection
requirements in this rule have been
submitted for approval to the OMB
under the Paperwork Reduction Act, 44
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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
U.S.C. 3501 et seq. The Information
Collection Request (ICR) document
prepared by the EPA has been assigned
EPA ICR number 2137.06.
The information collection
requirements are not enforceable until
OMB approves them. The information
requirements are based on notification,
recordkeeping, and reporting
requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A),
which are mandatory for all operators
subject to national emission standards.
These recordkeeping and reporting
requirements are specifically authorized
by CAA section 114 (42 U.S.C. 7414).
All information submitted to the EPA
pursuant to the recordkeeping and
reporting requirements for which a
claim of confidentiality is made is
safeguarded according to Agency
policies set forth in 40 CFR part 2,
subpart B. This final rule requires
maintenance inspections of the control
devices but would not require any
notifications or reports beyond those
required by the General Provisions. The
recordkeeping requirements require
only the specific information needed to
determine compliance.
When a malfunction occurs, sources
must report them according to the
applicable reporting requirements of 40
CFR part 63, subpart UUUUU. An
affirmative defense to civil penalties for
exceedances of emission limits that are
caused by malfunctions is available to a
source if it can demonstrate that certain
criteria and requirements are satisfied.
The criteria ensure that the affirmative
defense is available only where the
event that causes an exceedance of the
emission limit meets the narrow
definition of malfunction in 40 CFR 63.2
(sudden, infrequent, not reasonable
preventable, and not caused by poor
maintenance and or careless operation)
and where the source took necessary
actions to minimize emissions. In
addition, the source must meet certain
notification and reporting requirements.
For example, the source must prepare a
written root cause analysis and submit
a written report to the Administrator
documenting that it has met the
conditions and requirements for
assertion of the affirmative defense.
For this rule, EPA is adding
affirmative defense to the estimate of
burden in the ICR. To provide the
public with an estimate of the relative
magnitude of the burden associated
with an assertion of the affirmative
defense position adopted by a source,
the EPA has provided administrative
adjustments to this ICR that shows what
the notification, recordkeeping, and
reporting requirements associated with
the assertion of the affirmative defense
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might entail. The EPA’s estimate for the
required notification, reports, and
records, including the root cause
analysis, associated with a single
incident totals approximately totals
$3,141, and is based on the time and
effort required of a source to review
relevant data, interview plant
employees, and document the events
surrounding a malfunction that has
caused an exceedance of an emission
limit. The estimate also includes time to
produce and retain the record and
reports for submission to EPA. The EPA
provides this illustrative estimate of this
burden, because these costs are only
incurred if there has been a violation,
and a source chooses to take advantage
of the affirmative defense.
The EPA provides this illustrative
estimate of this burden because these
costs are only incurred if there has been
a violation and a source chooses to take
advantage of the affirmative defense.
Given the variety of circumstances
under which malfunctions could occur,
as well as differences among sources’
operation and maintenance practices,
we cannot reliably predict the severity
and frequency of malfunction-related
excess emissions events for a particular
source. It is important to note that the
EPA has no basis currently for
estimating the number of malfunctions
that would qualify for an affirmative
defense. Current historical records
would be an inappropriate basis, as
source owners or operators previously
operated their facilities in recognition
that they were exempt from the
requirement to comply with emissions
standards during malfunctions. Of the
number of excess emissions events
reported by source operators, only a
small number would be expected to
result from a malfunction (based on the
definition above), and only a subset of
excess emissions caused by
malfunctions would result in the source
choosing to assert the affirmative
defense. Thus, we believe the number of
instances in which source operators
might be expected to avail themselves of
the affirmative defense will be
extremely small.
For this reason, we estimate no more
than two such occurrences for all
sources subject to 40 CFR part 63,
subpart UUUUU over the 3-year period
covered by this ICR. We expect to gather
information on such events in the
future, and will revise this estimate as
better information becomes available.
The annual monitoring, reporting, and
record-keeping burden for this
collection (averaged over the first 3
years after the effective date of the
standards) is estimated to be $207.6
million. This includes 700,296 labor
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9433
hours per year at a total labor cost of
$49.1 million per year, annualized
capital costs of $81.9 million, and
annual operating and maintenance costs
of $76.5 million. This estimate includes
initial and annual performance tests,
semiannual excess emission reports,
developing a monitoring plan,
notifications, and recordkeeping. All
burden estimates are in 2007 dollars and
represent the most cost effective
monitoring approach for affected
facilities. Burden is defined at 5 CFR
1320.3(b).
An Agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for our regulations are listed in
40 CFR part 9. When this ICR is
approved by OMB, the Agency will
publish a technical amendment to 40
CFR part 9 in the Federal Register to
display the OMB control number for the
approved information collection
requirements contained in this final
rule.
C. Regulatory Flexibility Act, as
Amended by the Small Business
Regulatory Enforcement Fairness Act of
1996 (SBREFA), 5 U.S.C. 601 et seq.
The Regulatory Flexibility Act (RFA)
generally requires an agency to prepare
a regulatory flexibility analysis of any
rule subject to notice and comment
rulemaking requirements under the
Administrative Procedure Act or any
other statute unless the agency certifies
that the rule will not have a significant
economic impact on a substantial
number of small entities. Small entities
include small businesses, small
organizations, and small governmental
jurisdictions.
For purposes of assessing the impacts
of today’s rule on small entities, small
entity is defined as: (1) A small business
that is an electric utility producing 4
billion kilowatt-hours or less as defined
by NAICS codes 221122 (fossil fuel-fired
electric utility steam generating units)
and 921150 (fossil fuel-fired electric
utility steam generating units in Indian
country); (2) a small governmental
jurisdiction that is a government of a
city, county, town, school district or
special district with a population of less
than 50,000; and (3) a small
organization that is any not-for-profit
enterprise which is independently
owned and operated and is not
dominant in its field.
Pursuant to RFA section 603, the EPA
prepared an initial regulatory flexibility
analysis (IRFA) for the proposed rule
and convened a Small Business
Advocacy Review Panel to obtain advice
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and recommendations of representatives
of the regulated small entities. A
detailed discussion of the Panel’s advice
and recommendations is found in the
Panel Report (EPA–HQ–OAR–2009–
0234–2921). A summary of the Panel’s
recommendations is presented at 76 FR
24975.
As required by RFA section 604, we
also prepared a final regulatory
flexibility analysis (FRFA) for the final
rule. The FRFA addresses the issues
raised by public comments on the IRFA,
which was part of the proposal of this
rule. The FRFA is summarized below
and in the RIA.
1. Reasons Why Action Is Being Taken
In 2000, the EPA made a finding that
it was appropriate and necessary to
regulate coal- and oil-fired EGUs under
CAA section 112 and listed EGUs
pursuant to CAA section 112(c). On
March 29, 2005 (70 FR 15994), the EPA
published a final rule (2005 Action) that
removed EGUs from the list of sources
for which regulation under CAA section
112 was required. That rule was
published in conjunction with a rule
requiring reductions in emissions of Hg
from EGUs pursuant to CAA section
111, i.e., CAMR, May 18, 2005, 70 FR
28606). The 2005 Action was vacated on
February 8, 2008, by the U.S. Court of
Appeals for the District of Columbia
Circuit. As a result of that vacatur,
CAMR was also vacated and EGUs
remain on the list of sources that must
be regulated under CAA section 112.
This action provides the EPA’s final
NESHAP and NSPS for EGUs.
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2. Statement of Objectives and Legal
Basis for Final Rules
The MATS will protect air quality and
promote public health by reducing
emissions of HAP. In the December
2000 regulatory determination, the EPA
made a finding that it was appropriate
and necessary to regulate EGUs under
CAA section 112. The February 2008
vacatur of the 2005 Action reverted the
status of the rule to the December 2000
regulatory determination. Section
112(n)(1)(A) of the CAA and the 2000
determination do not differentiate
between EGUs located at major versus
area sources of HAP. Thus, the NESHAP
for EGUs will regulate units at both
major and area sources. Major sources of
HAP are those that have the potential to
emit at least 10 tons per year (tpy) of
any one HAP or at least 25 tpy of any
combination of HAP. Area sources are
any stationary sources of HAP that are
not major sources.
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3. Summary of Issues Raised During the
Public Comment Process on the IRFA
The EPA received a number of
comments related to the Regulatory
Flexibility Act during the public
comment process. A consolidated
version of the comments received is
reproduced below. These comments can
also be found in their entirety in the
response to comment document in the
docket.
Comment: Several commenters
expressed concern with the SBAR
panel. Some believe Small Entity
Representatives (SERs) were not
provided with regulatory alternatives
including descriptions of significant
regulatory options, differing timetables,
or simplifications of compliance and
reporting requirements, and
subsequently were not presented with
an opportunity to respond. One
commenter believes the EPA’s formal
SBAR Panel notification and subsequent
information provided by the EPA to the
Panel did not include information on
the potential impacts of the rule as
required by CAA section 609(b)(1).
Additional commenters suggested that
the EPA’s rulemaking schedule put
pressure on the SBAR Panel through the
abbreviated preparation for the Panel.
Commenters also expressed concerns
that the EPA did not provide
participants more than cursory
background information on which to
base their comments. One commenter
stated that the EPA did not provide
deliberative materials, including draft
proposed rules or discussions of
regulatory alternatives, to the SBAR
Panel members. One commenter stated
the SBAR Panel Report does not meet
the statutory obligation to recommend
less burdensome alternatives. The
commenter suggested the EPA panel
members declined to make
recommendations that went further than
consideration or investigation of broad
regulatory alternatives, with the
exception of those recommendations in
which the EPA rejected alternative
interpretations of the CAA section 112
and relevant court cases. Two stated
that the EPA did not respond to the
concerns of the small business
community, the SBA, or OMB, ignoring
concerns expressed by the SER
panelists. One commenter believes the
EPA failed to convene required
meetings and hearings with affected
parties as required by law for small
business entities. One commenter stated
that the SERs’ input is very important
because more than 90 percent of public
power utility systems meet the
definition and qualify as small
businesses under the SBREFA.
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Response: The RFA requires that
SBAR Panels collect advice and
recommendations from SERs on the
issues related to:
—The number and description of the
small entities to which the proposed
rule will apply;
—The projected reporting,
recordkeeping and other compliance
requirements of the proposed rule;
—Duplication, overlap or conflict
between the proposed rule and other
federal rules; and
—Alternatives to the proposed rule that
accomplish the stated statutory
objectives and minimize any
significant economic impact on small
entities.
The RFA does not require a covered
agency to create or assemble
information for SERs or for the
government panel members. Although
CAA section 609(b)(4) requires that the
government Panel members review any
material the covered agency has
prepared in connection with the RFA,
the law does not prescribe the materials
to be reviewed. The EPA’s policy, as
reflected in its RFA guidance, is to
provide as much information as
possible, given time and resource
constraints, to enable an informed Panel
discussion. In this rulemaking, because
of a court-ordered deadline, the EPA
was unable to hold a pre-panel meeting
but still provided SERs with the
information available at the time, held
a standard Panel Outreach meeting to
collect verbal advice and
recommendations from SERs, and
provided the standard 14-day written
comment period to SERs. The EPA
received substantial input from the
SERs, and the Panel report describes
recommendations made by the Panel on
measures the Administrator should
consider that would minimize the
economic impact of the proposed rule
on small entities. The EPA complied
with the RFA. In addition, we met with
representatives of small businesses,
small rural cooperatives, and small
governments a number of times during
the regulatory development process to
discuss their issues and concerns
regarding the proposed MATS rule for
EGUs.
Comment: One commenter requested
that the EPA work with utilities such
that new regulations are as flexible and
cost efficient as possible.
Response: In developing the final
rule, the EPA has considered all
information provided prior to, as well as
in response to, the proposed rule. The
EPA has endeavored to make the final
regulations flexible and cost-efficient
while adhering to the requirements of
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the CAA. The final rule includes a
number of flexibilities, such as those
related to monitoring requirements, that
will lower costs and simplify
compliance for small businesses and
local governments.
Comment: One commenter was
concerned about the ability of small
entities or nonprofit utilities such as
those owned and/or operated by rural
electric co-op utilities, and municipal
utilities to comply with the proposed
standards within 3 years. The
commenter believes that the EPA
disregarded the SER panelists who
explained that under these current
economic conditions they have
constraints on their ability to raise
capital for the construction of control
projects and to acquire the necessary
resources in order to meet a 3-year
compliance deadline. Two commenters
expressed concern that smaller utilities
and those in rural areas will be unable
to get vendors to respond to their
requests for proposals, because they will
be able to make more money serving
larger utilities.
Response: The preamble to the
proposed rule (76 FR 25054; May 3,
2011) provides a detailed discussion of
how the EPA determined compliance
times for the proposed (and final) rule.
The EPA has provided pursuant to CAA
section 112(i)(3)(A) the maximum 3-year
period for sources to come into
compliance. Sources may also seek a 1year extension of the compliance period
from their Title V permitting authority
if the source needs that time to install
controls. See CAA section 112(i)(3)(B). If
the situation described by commenters
(i.e., where small entities or nonprofit
utilities constraints on ability to raise
capital for construction of control
projects and to acquire necessary
resources) results in the source needing
additional time to install controls, they
would be in a position to request the 1year extension.
Comment: Several commenters
believe the EPA did not adequately
consider the disproportionately large
impact on smaller generating units. The
commenters note the diseconomies in
scale for pollution controls for such
units. One commenter noted the rule
will create a more serious compliance
hurdle for small communities that
depend on coal-fired generation to meet
their base load demand. The commenter
notes that by not subcategorizing units,
the EPA is dictating a fuel switch due
to the disproportionately high cost on
small communities. The other
commenter believes the MACT and
NSPS standards are unachievable by
going too far without really considering
the impacts on small municipal units, as
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public power is critical to communities,
jobs, economic viability and electric
reliability. A generating and
transmissions electric cooperative
which qualifies as a small entity
believes the rule will ultimately result
in increased electricity costs to its
members and will negatively impact the
economies of the primarily rural areas
that they serve. Another commenter
believes there is no legal or factual basis
for creating subcategories or weaker
standards for state, tribal, or municipal
governments or small entities that are
operating obsolete units, particularly
given the current market situation and
applicable equitable factors. The
commenter suggests both the EPA’s and
SBA’s analyses focus exclusively on the
effects on entities causing HAP
emissions and primarily on those
operating obsolete EGUs, and fail to
consider either impacts on downwind
businesses and governments or the
positive impacts on small entities and
governments owning and operating
competing, clean and modern EGUs.
Response: The EPA disagrees with the
commenters’ belief that the impacts on
smaller generating units were not
adequately considered when developing
the rule. The EPA determined the
number of potentially impacted small
entities and assessed the potential
impact of the proposed action on small
entities, including municipal units. A
similar assessment was conducted in
support of the final action. Specifically,
the EPA estimated the incremental net
annualized compliance cost, which is a
function of the change in capital and
operating costs, fuel costs, and change
in revenue. The projected compliance
cost was considered relative to the
projected revenue from generation.
Thus, the EPA’s analysis accounts not
only for the additional costs these
entities face resulting from compliance,
but also the impact of higher electricity
prices. The EPA evaluated suggestions
from SERs, including subcategorization
recommendations. In the preamble to
the proposed rule, the EPA explains
that, normally, any basis for
subcategorizing must be related to an
effect on emissions, rather than some
difference which does not affect
emissions performance. The EPA does
not see a distinction between emissions
from smaller generating units versus
larger units. The EPA acknowledges the
comment that there is no legal or factual
basis for creating subcategories or
weaker standards for state, tribal, or
municipal governments or small entities
that are operating obsolete units.
Comment: One commenter notes that
the EPA recognizes LEEs in the rule
such that they should receive less
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onerous monitoring requirements;
however, the EPA does not recognize
that small and LEEs also need and merit
more flexible and achievable pollution
control requirements. The commenter
notes that the capital costs for emissions
control at small utility units is
disproportionately high due to
inefficiencies in Hg removal, space
constraints for control technology
retrofits, and the fact that small units
have fewer rate base customers across
which to spread these costs. The
commenter cites the Michigan
Department of Environmental Quality
report titled ‘‘Michigan’s Mercury
Electric Utility Workgroup, Final Report
on Mercury Emissions from Coal-Fired
Power Plants,’’ (June 2005). The
commenter notes that the EPA has
addressed such concerns previously,
citing the RIA for the 1997 8-hour ozone
standard. The commenter also suggests
smaller utility systems generally have
less capital to invest in pollution control
than larger, investor-owned systems,
due to statutory inability to borrow from
the private capital markets, statutory
debt ceilings, limited bonding capacity,
borrowing limitations related to fiscal
strain posed by other, nonenvironmental factors, and other
limitations.
Response: The EPA acknowledges
that the rule contains reduced
monitoring requirements for existing
units that qualify as LEEs. Although the
EPA does not believe that reduced
pollution control requirements are
warranted for LEEs, including small
entity LEEs, we believe that flexible and
achievable pollution control
requirements are promoted through
alternative standards, alternative
compliance options, and emissions
averaging as a means of demonstrating
compliance with the standards for
existing EGUs.
Comment: One commenter believes
that the EPA should develop more
limited monitoring requirements for
small EGUs. The commenter notes small
entities do not possess the monetary
resources, manpower, or technical
expertise needed to operate cutting-edge
monitoring techniques such as Hg
CEMS and PM CEMS. The commenter
notes the EPA could have identified
monitoring alternatives to the SER panel
for consideration.
Response: The EPA provided
monitoring alternatives to using PM
CEMS, HCl CEMS, and Hg CEMS in its
proposed standards and in this final
rule. The continuous compliance
alternatives are available to all affected
sources, including small entities. As
alternatives to the use of PM CEMS and
HCl CEMS, sources are allowed to
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conduct additional performance testing.
Sorbent trap monitoring is allowed in
lieu of Hg CEMS.
Comment: Several commenters
believe the EPA has not sufficiently
complied with the requirements of the
RFA or adequately considered the
impact this rulemaking would have on
small entities. One commenter believes
the EPA has not engaged in meaningful
outreach and consultation with small
entities and therefore recommends that
the EPA seek to revise the court-ordered
deadlines to which this rulemaking is
subject, re-convene the SBAR panel,
prepare a new initial regulatory
flexibility analysis (IRFA), and issue it
for additional public comment prior to
final rulemaking. The commenter
believes the IRFA does not sufficiently
consider impacts on small entities as
identified in the SBAR Panel Report.
The commenter believes it is not
apparent that the EPA considered the
recommendations of the Panel. The
commenter believes the description of
significant alternatives in the IRFA is
almost entirely quoted from the SBAR
Panel Report, which the commenter
does not believe is an adequate
substitute for the EPA’s own analysis of
alternatives. The commenter also notes
the EPA does not discuss the potential
impacts of its decisions on small entities
or the impacts of possible flexibilities.
Where the EPA does consider regulatory
alternatives in principle, the commenter
believes it does not provide sufficient
support for its decisions to understand
on what basis the EPA rejected
alternatives that may or may not have
reduced burden on small entities while
meeting the stated objectives of the rule.
Additionally, the commenter notes that
the EPA did not evaluate the economic
or environmental impacts of significant
alternatives to the proposed rule. One
commenter believes that the EPA’s
stated reasons for declining to specify or
analyze an area source standard are
inadequate under the RFA. The
commenter believes the EPA must give
serious consideration to regulatory
alternatives that accomplish the stated
objectives of the CAA while minimizing
any significant economic impacts on
small entities and that the EPA has a
duty to specify and analyze this option
or to more clearly state its policy
reasons for excluding serious
consideration of a separate standard for
area sources. A commenter believes the
EPA did not fully consider the
subcategorization of sources such as
boilers designed to burn lignite coals
versus other fossil fuels, especially in
regard to non-mercury metal and acid
gas emissions. The commenter
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references the SBAR Panel Report
suggestion provided in the preamble of
the proposed rule that the EPA consider
developing an area source vs. major
source distinction for the source
category and the EPA’s response.
Another commenter is concerned that
the recommendations made by the SER
participants were ignored and not
discussed in the rulemaking.
Specifically, the commenter notes the
EPA did not discuss subcategorizing by
age, type of plant, fuel, physical space
constraints or useful anticipated life of
the plant. Nor did the EPA establish
GACT for smaller emitters to alleviate
regulatory costs and operational
difficulties. A commenter believes it is
likely that different numerical or work
practice standards are appropriate for
area sources of HAP.
Response: The EPA disagrees with
one commenter’s assertion that the
agency has not complied with the
requirements of the RFA. The EPA
complied with both the letter and spirit
of the RFA, notwithstanding the
constraints of the court-ordered
deadline. For example, the EPA notified
the Chief Counsel for Advocacy of the
SBA of its intent to convene a Panel;
compiled a list of SERs for the Panel to
consult with; and convened the Panel.
The Panel met with SERs to collect their
advice and recommendations; reviewed
the EPA materials; and drafted a report
of Panel findings. The EPA further
disagrees with the commenter’s
assertion that the EPA’s IRFA does not
sufficiently consider impacts on small
entities. The EPA’s IRFA, which is
included in chapter 10 of the RIA for the
proposed rule, addresses the statutorily
required elements of an IRFA, such as
the economic impact of the proposed
rule on small entities and the Panel’s
findings.
The EPA disagrees with the comment
that recommendations made by the
SERs were not considered or discussed
in the proposed rulemaking such as
recommendations regarding
subcategorization and separate GACT
standards for area sources. The
preamble to the proposed standards
includes a detailed discussion of how
the EPA determined which
subcategories and sources would be
regulated (76 FR 25036–25037; May 3,
2011). In that discussion, the EPA
explains the rationale for its proposed
subcategories based on five unit design
types. In addition, the EPA
acknowledges the subcategorization
suggestions from the SERs and explains
its reasons for not subcategorizing on
those bases. The preamble to the
proposed standards also includes a
discussion of the SERs’ suggestion that
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area source EGUs be distinguished from
major-source EGUs and the EPA’s
reasons for not making that distinction
(76 FR 25020–25021; May 3, 2011).
The EPA also disagrees with the
suggestion that the Agency pursue an
extension of the timeline for final
rulemaking such that the SBAR Panel
can be reconvened and a new IRFA can
be prepared and released for public
comment prior to the final rulemaking.
The EPA entered into a Consent Decree
to resolve litigation alleging that the
EPA failed to perform a nondiscretionary duty to promulgate CAA
section 112(d) standards for EGUs. See
American Nurses Ass’n v. EPA, 08–2198
(D.D.C.). That Decree required the EPA
to sign the final MATS rule by
November 16, 2011, unless the agency
sought to extend the deadline consistent
with the requirements of the
modification provision of the Consent
Decree. The EPA and Plaintiffs
stipulated to a 30-day extension
consistent with the modification
provisions of the Consent Decree and
the rule must be signed no later than
December 16, 2011. If plaintiffs in the
American Nurses litigation objected to
an additional extension request, which
we believe would have been likely, the
Agency would have had to file a motion
with the Court seeking an extension of
the deadline. Consistent with governing
case law, the Agency would have been
required to demonstrate in its motion
for extension that it was impossible to
finalize the rule by the deadline
provided in the Consent Decree. See
Sierra Club v. Jackson, Civil Action No.
01–1537 (D.D.C.) (Opinion of the Court
denying EPA’s motion to extend a
consent decree deadline). The EPA
negotiated a 30-day extension and was
able to complete the rule by December
16, 2011; accordingly, the Agency had
no basis for seeking a further extension
of time.
A detailed description of the changes
made to the rule since proposal,
including those made as a result of
feedback received during the public
comment process can be found in
sections VI (NESHAP) and X (NSPS) of
this preamble. Changes explained in the
identified sections include those related
to applicability; subcategorization; work
practices; periods of startup, shutdown,
and malfunction; initial testing and
compliance; continuous compliance;
and notification, recordkeeping, and
reporting.
4. Description and Estimate of the
Affected Small Entities
For the purposes of assessing the
impacts of MATS on small entities, a
small entity is defined as:
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(1) A small business according to the
Small Business Administration size
standards by the North American
Industry Classification System (NAICS)
category of the owning entity. The range
of small business size standards for
electric utilities is 4 billion kilowatt
hours (kWh) of production or less;
(2) A small government jurisdiction
that is a government of a city, county,
town, district, or special district with a
population of less than 50,000; and
(3) A small organization that is any
not for profit enterprise that is
independently owned and operated and
is not dominant in its field.
The EPA examined the potential
economic impacts to small entities
associated with this rulemaking based
on assumptions of how the affected
entities will install control technologies
in compliance with MATS. This
analysis does not examine potential
indirect economic impacts associated
with this rule, such as employment
effects in industries providing fuel and
pollution control equipment, or the
potential effects of electricity price
increases on industries and households.
The EPA used Velocity Suite’s Ventyx
data as a basis for identifying plant
ownership and compiling the list of
potentially affected small entities. The
Ventyx dataset contains detailed
ownership and corporate affiliation
information. The analysis focused only
on those EGUs affected by the rule,
which includes units burning coal, oil,
petroleum coke, or coal refuse as the
primary fuel, and excludes any
combustion turbine units or EGUs
burning natural gas. Also, because the
rule does not affect combustion units
with an equivalent electricity generating
capacity up to 25 MW, small entities
that do not own at least one combustion
unit with a capacity greater than 25 MW
were removed from the dataset. For the
affected units remaining, boiler and
generator capacity, heat input,
generation, and emissions data were
aggregated by owner and then by parent
company. Entities with more than 4
billion kWh of annual electricity
generation were removed from the list,
as were municipal owned entities with
a population greater than 50,000. For
cooperatives, investor owned utilities,
and subdivisions that generate less than
4 billion kWh of electricity annually but
which may be part of a large entity,
additional research on power sales,
operating revenues, and other business
activities was performed to make a final
determination regarding size. Finally,
small entities for which the IPM does
not project generation in 2015 in the
base case were omitted from the
analysis because they are not projected
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to be operating and, thus, are not
projected to face the costs of compliance
with the rule. After omitting entities for
the reasons above, the EPA identified a
total of 82 potentially affected small
entities that are affiliated with 102
EGUs.
5. Compliance Cost Impacts
The number of potentially affected
small entities by ownership type and
potential impacts of MATS are
presented in Chapter 7 of the RIA and
summarized here. The EPA estimated
the annualized net compliance cost to
small entities to be approximately $106
million in 2015 (2007$).
The EPA assessed the economic and
financial impacts of the final rule using
the ratio of compliance costs to the
value of revenues from electricity
generation, and our results focus on
those entities for which this measure
could be greater than 1 percent or 3
percent. Of the 82 small entities
identified, The EPA’s analysis shows 40
entities may experience compliance
costs greater than 1 percent of base
generation revenues in 2015, and 35
may experience compliance costs
greater than 3 percent of base revenues.
Also, all generating capacity at 3 small
entities is projected to be uneconomic to
maintain. In this analysis, the cost of
withdrawing a unit as uneconomic is
estimated as the base case profit that is
forgone by not operating under the
policy case. Because 35 of the 82 total
units, or more than 40 percent, are
estimated to incur compliance cost
greater than 3 percent of base revenues,
the EPA has concluded that it cannot
certify that there will be no significant
economic impact on a substantial
number of small entities (SISNOSE) for
this rule. Results for small entities
discussed here do not account for the
reality that electricity markets are
regulated in parts of the country.
Entities operating in regulated or costof-service markets should be able to
recover all of their costs of compliance
through rate adjustments.
Note that the estimated costs for small
entities are significantly lower than
those estimated by the EPA for the
MATS proposal (which were $379
million). This is driven by a small group
of units (less than 6 percent) which
were projected to be uneconomic to
operate under the proposal (and hence
incurred lost profits due to lost
electricity revenues), but are now
projected to continue their operations
under MATS. In addition, the EPA’s
modeling indicates one unit that would
have operated at a low capacity factor
under the base case would find it
economical to increase its generation
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9437
significantly under MATS to meet
electricity demand in its region.
Excluding this unit, the total cost
impacts across all entities would be
roughly $175 million. Changes in
compliance behavior for this small
group of units, in particular the one unit
which operates at a higher capacity
factor, has a substantial impact on total
costs as their increased generation
revenues offsets a large portion of the
compliance costs.
The most significant components of
incremental costs to these entities are
changes in electricity revenues,
followed by the increased capital and
operating costs for retrofits. Capital and
operating costs increase across all
ownership types, but the direction of
changes in electricity revenues varies
among ownership types. All ownership
types, with the exception of private
entities, experience a net gain in
electricity revenues under the MATS,
unlike projections from the EPA’s
modeling during the proposal, where
only municipals benefitted from higher
electricity revenues. The change in
electricity revenue takes into account
both the profit lost from units that do
not operate under the policy case and
the difference in revenue for operating
units under the policy case. According
to the EPA’s modeling, an estimated 274
MW of capacity owned by small entities
are considered uneconomic to operate
under the policy case, resulting in a net
loss of $13 million (in 2007$) in profits.
On the other hand, many operating
units actually increase their electricity
revenue due to higher electricity prices
under MATS. In addition, as mentioned
above, the EPA’s modeling indicates one
unit finds it economical to increase its
capacity factor significantly under the
policy case which results in
significantly higher revenues offsetting
the costs.
6. Description of Steps To Minimize
Impacts on Small Entities
Consistent with the requirements of
the RFA and SBREFA, the EPA has
taken steps to minimize the significant
economic impact on small entities.
Because this rule does not affect units
with a generating capacity of less than
25 MW, small entities that do not own
at least one generating unit with a
capacity greater than 25 MW are not
subject to the rule. According to the
EPA’s analysis, among the coal- and oilfired EGUs (i.e., excluding combined
cycle gas turbines and gas combustion
turbines) about 26 potentially small
entities only own EGUs with a capacity
less than or equal to 25 MW, and none
of those entities are subject to the final
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rule based on the statutory definition of
potentially regulated units.
For units affected by the proposed
rule, the EPA considered a number of
comments received, both during the
Small Business Advocacy Review
(SBAR) Panel and the public comment
period. While none of the alternatives
adopted is specifically applied to small
entities, the EPA believes these
modifications will make compliance
less onerous for all regulated units,
including those owned by small entities.
a. Work practice standards. The EPA
proposed numerical emission standards
that would apply at all times, including
during periods of startup and shutdown.
After reviewing comments and other
data regarding the nature of these
periods of operation, the EPA is
finalizing a work practice standard for
periods of startup and shutdown. The
EPA is also finalizing work practice
standards for organic HAP from all
subcategories of EGUs. Descriptions of
the work practice requirements for
startup and shutdown, as well as
organic HAP and limited-use liquid oilfired EGUs, can be found in section
VI.D–E. of the preamble.
b. Continuous compliance and
notification, record-keeping, and
reporting. The final rule greatly
simplifies the continuous compliance
requirements and provides two basic
approaches for most situations: use of
continuous monitoring and periodic
testing. The frequency of periodic
testing has been decreased from
monthly in the proposal to quarterly in
the final rule. In addition to simplifying
compliance, the EPA believes these
changes considerably reduce the overall
burden associated with recordkeeping
and reporting. These changes to the
final rule are described in more detail in
Section VI.G–H of this preamble.
c. Subcategorization. The Small Entity
Representatives on the SBAR Panel
were generally supportive of
subcategorization and suggested a
number of additional subcategories the
EPA should consider when developing
the final rule. Although it was not
consistent with the statute to adopt the
proposed subcategories, the EPA
maintained the existing subcategories
and split the ‘‘liquid oil-fired units’’
subcategory into three subcategories—
continental, non-continental units, and
limited-use units.
d. MACT floor calculations. As
recommended by the EPA SBAR Panel
representative, the EPA established the
MACT floors using all the available ICR
data that was received to the maximum
extent possible consistent with the CAA
requirements. The Agency believes this
approach reasonably ensures that the
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emission limits selected as the MACT
floors adequately represent the level of
emissions actually achieved by the
average of the units in the top 12
percent, considering operational
variability of those units.
e. Alternatives not adopted. The EPA
did not adopt several of the suggestions
posed either during the SBAR Panel or
public comment period. The EPA did
not propose a percent reduction
standard as an alternative to the
concentration-based MACT floor. The
percent reduction format for Hg and
other HAP emissions would not have
addressed the EPA’s consideration of
coal preparation practices that remove
Hg and other HAP before firing. Also, to
account for the coal preparation
practices, sources would be required to
track the HAP concentrations in coal
from the mine to the stack, and not just
before and after the control device(s),
and such an approach would be difficult
to implement and enforce. Furthermore,
the EPA does not believe the percent
reduction standard is in line with the
Court’s interpretation of the CAA
section 112 requirements. Even if we
believed it was appropriate to establish
a percent reduction standard, we do not
have the data necessary to establish
percent reduction standards for HAP, as
explained further in the response to
comments document.
The EPA determined not to establish
GACT standards for area sources for a
number of reasons. The data show that
similar HAP emissions and control
technologies are found on both major
and area sources greater than 25 MW,
and some large units are synthetic area
sources. In fact, because of the
significant number of well-controlled
EGUs of all sizes, we believe it would
be difficult to make a distinction
between MACT and GACT. Moreover,
the EPA believes the standards for area
source EGUs should reflect MACT,
rather than GACT, because there is no
essential difference between area source
and major source EGUs with respect to
emissions of HAP.
The EPA determined not to exercise
its discretionary authority to establish
health-based emission standards for HCl
and other HAP acid gases. Given the
limitations of the currently available
information (e.g., the HAP mix where
EGUs are located, and the cumulative
impacts of respiratory irritants from
nearby sources), the environmental
effects of HCl and the other acid gas
HAP, and the significant co-benefits
from reductions in criteria pollutants
the EPA determined that setting a
conventional MACT standard for HCl
and the other acid gas HAP was the
appropriate course of action.
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As required by SBREFA section 212,
the EPA also is preparing a Small Entity
Compliance Guide to help small entities
comply with this rule. Small entities
will be able to obtain a copy of the
Small Entity Compliance guide at the
following Web site: https://www.epa.gov/
airquality/powerplanttoxics/
actions.html.
D. Unfunded Mandates Reform Act of
1995
Title II of the UMRA of 1995, Public
Law 104–4, establishes requirements for
federal agencies to assess the effects of
their regulatory actions on state, local,
and tribal governments and the private
sector. Under UMRA section 202, we
generally must prepare a written
statement, including a cost-benefit
analysis, for proposed and final rules
with ‘‘Federal mandates’’ that may
result in expenditures to state, local,
and tribal governments, in the aggregate,
or to the private sector, of $100 million
or more in any 1 year. Before
promulgating a rule for which a written
statement is needed, UMRA section 205
generally requires us to identify and
consider a reasonable number of
regulatory alternatives and adopt the
least costly, most cost-effective or least
burdensome alternative that achieves
the objectives of the rule. The
provisions of UMRA section 205 do not
apply when they are inconsistent with
applicable law. Moreover, UMRA
section 205 allows us to adopt an
alternative other than the least costly,
most cost-effective or least burdensome
alternative if the Administrator
publishes with the final rule an
explanation why that alternative was
not adopted. Before we establish any
regulatory requirements that may
significantly or uniquely affect small
governments, including tribal
governments, we must develop a small
government agency plan under UMRA
section 203. The plan must provide for
notifying potentially affected small
governments, enabling officials of
affected small governments to have
meaningful and timely input in the
development of regulatory proposals
with significant federal
intergovernmental mandates, and
informing, educating, and advising
small governments on compliance with
the regulatory requirements.
We have determined that this rule
contains a federal mandate that may
result in expenditures of $100 million or
more for state, local, and tribal
governments, in the aggregate, or the
private sector in any 1 year.
Accordingly, we have prepared a
written statement entitled ‘‘Unfunded
Mandates Reform Act Analysis’’ under
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UMRA section 202 that is within the
RIA and which is summarized below.
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1. Statutory Authority
As discussed elsewhere in this
preamble, the statutory authority for this
rulemaking is CAA section 112. Title III
of the CAA Amendments was enacted to
reduce nationwide air toxic emissions.
CAA section 112(b) lists the 188
chemicals, compounds, or groups of
chemicals deemed by Congress to be
HAP. These toxic air pollutants are to be
regulated by NESHAP.
CAA section 112(d) directs us to
develop NESHAP which require
existing and new major sources to
control emissions of HAP using MACTbased standards. This NESHAP applies
to all coal- and oil-fired EGUs.
In compliance with UMRA section
205(a), we identified and considered a
reasonable number of regulatory
alternatives. Additional information on
the costs and environmental impacts of
these regulatory alternatives were
presented in the RIA for the rulemaking.
The regulatory alternative upon
which this rule is based represents the
MACT floor for all regulated pollutants
for all but one EGU subcategory for all
but one regulated pollutant for that
subcategory. These MACT floor-based
standards represent the least costly and
least burdensome alternative. Beyondthe-floor emission limits for Hg are for
existing coal-fired EGUs in the
subcategory for low rank virgin coal
EGUs.
2. Social Costs and Benefits
The RIA prepared for this rule
including the Agency’s assessment of
costs and benefits is in the docket.
It is estimated that HAP would be
reduced by thousands of tons in 2015,
relative to the base case, including
reductions in HCl, HF, metallic HAP
(including Hg), and several other
organic HAP from EGUs. Studies have
determined a relationship between
exposure to certain of these HAP and
the onset of cancer; however, the
Agency is unable to provide a
monetized estimate of the HAP benefits
at this time. In addition, significant
reductions in PM2.5 and SO2 will occur,
including approximately 53 thousand
tons of PM2.5 and over 1 million tons of
SO2. These reductions will occur by
2016 and are expected to continue
throughout the life of the affected
sources. The major health effect
associated with reducing PM2.5 and
PM2.5 precursors (such as SO2) is a
reduction in premature mortality. Other
health effects associated with PM2.5
emission reductions include avoiding
cases of chronic bronchitis, heart
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attacks, asthma attacks, and work-lost
days (i.e., days when employees are
unable to work). Although we are
unable to monetize the benefits
associated with the HAP emissions
reductions other than for Hg or all
benefits associated with Hg reductions,
we are able to monetize the benefits
associated with the PM2.5 and SO2
emissions reductions. For SO2 and
PM2.5, we estimated the benefits
associated with health effects of PM but
were unable to quantify all categories of
benefits (particularly those associated
with ecosystem and visibility effects).
Our estimates of the monetized benefits
in 2016 associated with the
implementation of the final rule range
from $37 billion to $90 billion (2007
dollars) when using a 3 percent
discount rate or from $33 billion to $81
billion (2007 dollars) when using a 7
percent discount rate). Our estimate of
costs is $9.6 billion (2007 dollars). For
more detailed information on the
benefits and costs estimated for this
rulemaking, refer to the RIA in the
docket.
3. Future and Disproportionate Costs
The UMRA requires that we estimate,
where accurate estimation is reasonably
feasible, future compliance costs
imposed by this rule and any
disproportionate budgetary effects. Our
estimates of the future compliance costs
of this rule are discussed previously in
this preamble.
The EPA assessed the economic and
financial impacts of the rule on
government-owned entities using the
ratio of compliance costs to the value of
revenues from electricity generation,
and our results focus on those entities
for which this measure could be greater
than 1 percent or 3 percent of base
revenues. The EPA projects that 42
government entities will have
compliance costs greater than 1 percent
of base generation revenue in 2016, and
32 may experience compliance costs
greater than 3 percent of base revenues.
Overall, 6 units owned by government
entities are expected to retire. The most
significant components of incremental
costs to these entities are the increased
capital and operating costs, followed by
changes in electricity revenues. For
more details on these results and the
methodology behind their estimation,
see the results included in chapter 7 of
the RIA.
4. Effects on the National Economy
The UMRA requires that we estimate
the effect of this rule on the national
economy. To the extent feasible, we
must estimate the effect on productivity,
economic growth, full employment,
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9439
creation of productive jobs, and
international competitiveness of the
U.S. goods and services, if we determine
that accurate estimates are reasonably
feasible and that such effect is relevant
and material.
The nationwide economic impact of
this rule is presented in the RIA in the
docket. This analysis provides estimates
of the effect of this rule on some of the
categories mentioned above.
The results of the economic impact
analysis are summarized previously in
this preamble. The results show that,
relative to baseline, there will be an
average 3.1 percent increase in
electricity price on average nationwide
in 2016, with the range of increases
from 1.3 percent to 6.3 percent in
regions throughout the U.S., and a less
than 1 percent increase in natural gas
price nationwide in 2016. The roughly
3 percent incremental price effect of this
rule is small relative to the changes
observed in the absolute levels of
electricity prices over the last 50 years,
which have ranged from as much as 23
percent lower (in 1969) to as much as
23 percent higher (in 1982) than prices
observed in 2010.377 Power generation
from coal-fired plants will fall by about
2 percent nationwide in 2016. No region
of the U.S. is expected to experience a
double-digit increase in retail electricity
prices in 2015 or in any year later than
that, according to the Agency’s analysis,
as a result of this rule. To put the
electricity price effects in context, the
roughly 3 percent incremental increase
in aggregate end-user electricity prices
projected to occur over the next 4 years
is about the same as the 3 percent
absolute average change in total enduser electricity prices observed on an
annual basis.378 Furthermore, the
roughly 3 percent incremental price
effect of this rule is small relative to the
changes observed in the absolute levels
of electricity prices over the last 50
years, which have ranged from as much
as 23 percent lower (in 1969) to as much
as 23 percent higher (in 1982) than
prices observed in 2010.379 Even with
this rule in effect, electricity prices are
projected to be lower in 2015 and 2020
than they were in 2010.380
5. Consultation With Government
The UMRA requires that we describe
the extent of the Agency’s prior
consultation with affected state, local,
377 EIA Annual Energy Outlook 2010 annual total
electricity prices from 1960 to 2010, Table 8–10.
378 EIA Annual Energy Outlook 2010 annual total
electricity prices from 1960 t0 2010, Table 8–10.
379 Ibid.
380 Ibid., EIA AEO 2010, Table–10 for price levels;
and Chapterr 3 of the RIA for electricity price
differential.
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and tribal officials, summarize the
officials’ comments or concerns, and
summarize our response to those
comments or concerns. In addition,
UMRA section 203 requires that we
develop a plan for informing and
advising small governments that may be
significantly or uniquely impacted by a
regulatory action. Consistent with the
intergovernmental consultation
provisions of UMRA section 204, the
EPA initiated consultations with
governmental entities affected by this
rule. The EPA invited the following 10
national organizations representing state
and local elected officials to a meeting
held on October 27, 2010, in
Washington, DC: (1) National Governors
Association; (2) National Conference of
State Legislatures, (3) Council of State
Governments, (4) National League of
Cities, (5) U.S. Conference of Mayors, (6)
National Association of Counties, (7)
International City/County Management
Association, (8) National Association of
Towns and Townships, (9) County
Executives of America, and (10)
Environmental Council of States. These
10 organizations of elected state and
local officials have been identified by
the EPA as the ‘‘Big 10’’ organizations
appropriate to contact for purpose of
consultation with elected officials. The
purposes of the consultation were to
provide general background on the rule,
answer questions, and solicit input from
state/local governments. During the
meeting, officials asked clarifying
questions regarding CAA section 112
requirements and central decision
points presented by the EPA (e.g., use of
surrogate pollutants to address HAP,
subcategorization of source category,
assessment of emissions variability).
They also expressed uncertainty with
regard to how utility boilers owned/
operated by state and local entities
would be impacted, as well as with
regard to the potential burden
associated with implementing the rule
on state and local entities (i.e., burden
to re-permit affected EGUs or update
existing permits). Officials requested,
and the EPA provided, addresses
associated with the 112 state and local
governments estimated to be potentially
impacted by the rule. The EPA has not
received additional questions or
requests from state or local officials.
Consistent with UMRA section 205,
the EPA has identified and considered
a reasonable number of regulatory
alternatives. Because the potential
existed for a significant impact for
substantial number of small entities, the
EPA convened a SBAR Panel to obtain
advice and recommendation of
representatives of the small entities that
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potentially would be subject to the
requirements of the rule. As part of that
process, the EPA considered several
options, which are discussed previously
in this preamble. Those options
included establishing emission limits,
establishing work practice standards,
establishing subcategories, and
consideration of monitoring options.
The regulatory alternative selected is a
combination of the options considered
and includes provisions regarding a
number of the recommendations
resulting from the SBAR Panel process
as described below (see the Regulatory
Flexibility Act discussion in this section
of the preamble for more detail).
E. Executive Order 13132, Federalism
Under EO 13132, the EPA may not
issue an action that has federalism
implications, that imposes substantial
direct compliance costs, and that is not
required by statute, unless the federal
government provides the funds
necessary to pay the direct compliance
costs incurred by state and local
governments, or the EPA consults with
state and local officials early in the
process of developing the final action.
The EPA has concluded that this
action may have federalism
implications, because it may impose
substantial direct compliance costs on
state or local governments, and the
federal government will not provide the
funds necessary to pay those costs.
Accordingly, the EPA provides the
following federalism summary impact
statement as required by section 6(b) of
EO 13132.
Based on estimates in the RIA,
provided in the docket, the final rule
may have federalism implications
because the rule may impose
approximately $294 million in annual
direct compliance costs on an estimated
96 state or local governments.
Specifically, we estimate that there are
80 municipalities, 5 states, and 11
political subdivisions (i.e., a public
district with territorial boundaries
embracing an area wider than a single
municipality and frequently covering
more than one county for the purpose of
generating, transmitting and distributing
electric energy) that may be directly
impacted by this final rule. Responses to
the EPA’s 2010 ICR were used to
estimate the nationwide number of
potentially impacted state or local
governments. As previously explained,
this 2010 survey was submitted to all
coal- and oil-fired EGUs listed in the
2007 version of DOE/EIA’s ‘‘Annual
Electric Generator Report,’’ and ‘‘Power
Plant Operations Report.’’
The EPA consulted with state and
local officials in the process of
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developing the rule to permit them to
have meaningful and timely input into
its development. The EPA met with 10
national organizations representing state
and local elected officials to provide
general background on the rule, answer
questions, and solicit input. In the final
rule, EPA has provided flexibilities that
will lower compliance costs for these
entities. The EPA also recognizes that
municipalities may need a longer
compliance timeframe because of
required approval processes.
F. Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
Subject to EO 13175 (65 FR 67249;
November 9, 2000) the EPA may not
issue a regulation that has tribal
implications, that imposes substantial
direct compliance costs, and that is not
required by statute, unless the federal
government provides the funds
necessary to pay the direct compliance
costs incurred by tribal governments, or
the EPA consults with tribal officials
early in the process of developing the
proposed regulation and develops a
tribal summary impact statement.
Executive Order 13175 requires the EPA
to develop an accountable process to
ensure ‘‘meaningful and timely input by
Tribal officials in the development of
regulatory policies that have Tribal
implications.’’
The EPA has concluded that this
action may have tribal implications. The
EPA offered consultation with tribal
officials early in the regulation
development process to permit them an
opportunity to have meaningful and
timely input. Consultation letters were
sent to 584 tribal leaders and provided
information regarding the EPA’s
development of this rule and offered
consultation. At the request of the
tribes, three consultation meetings were
held: December 7, 2010, with the Upper
Sioux Community of Minnesota;
December 13, 2010, with Moapa Band of
Paiutes, Forest County Potawatomi,
Standing Rock Sioux Tribal Council,
and Fond du Lac Band of Chippewa;
January 5, 2011, with the Forest County
Potawatomi, and a representative from
the National Tribal Air Association
(NTAA). In these meetings, the EPA
presented the authority under the CAA
used to develop these rules and an
overview of the industry and the
industrial processes that have the
potential for regulation. Tribes
expressed concerns about the impact of
EGUs in Indian country. Specifically,
they were concerned about potential Hg
deposition and the impact on the water
resources of the tribes, with particular
concern about the impact on subsistence
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lifestyles for fishing communities, the
cultural impact of impaired water
quality for ceremonial purposes, and the
economic impact on tourism. In light of
these concerns, the tribes expressed
interest in an expedited implementation
of the rule. Other concerns expressed by
tribes related to how the Agency would
consider variability in setting the
standards, and the use of tribal-specific
fish consumption data from the tribes in
our assessments. They were not
supportive of using work practice
standards as part of the rule, and asked
the Agency to consider going beyond
the MACT floor to offer more protection
for the tribal communities.
In addition to these consultations, the
EPA also conducted outreach on this
rule through presentations at the
National Tribal Forum in Milwaukee,
WI; phone calls with the NTAA; and a
webinar for tribes on the proposed rule.
The EPA specifically requested tribal
data that could support the appropriate
and necessary analyses and the RIA for
this rule. In addition, the EPA held
individual consultations with the
Navajo Nation on October 12, 2011; as
well as the Gila River Indian
Community, Ak-Chin Indian
Community, and the Hopi Nation on
October 14, 2011. These tribes
expressed concerns about the impact of
the rule on the Navajo Generating
Station (NGS), the impact on the cost of
the water allotted to the tribes from the
Central Arizona Project (CAP), the
impact on tribal revenues from the coal
mining operations (i.e., assumptions
about reduced mining if NGS were to
retire one or more units), and the
impacts on employment of tribal
members at both the NGS and the mine.
More specific comments can be found in
the docket.
The EPA will continue to work with
these and other potentially affected
tribes as this final rule is implemented.
G. Executive Order 13045, Protection of
Children From Environmental Health
Risks and Safety Risks
This final rule is subject to EO 13045
(62 FR 19885; April 23, 1997) because
it is an economically significant
regulatory action as defined by EO
12866, and EPA believes that the
environmental health or safety risk
addressed by this action may have a
disproportionate effect on children.
Accordingly, we have evaluated the
environmental health or safety effects of
the standards on children.
Although this final rule is based on
technology performance, the standards
are designed to protect against hazards
to public health with an adequate
margin of safety as described in Section
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III of this preamble. The protection
offered by this rule is particularly
important for children, especially the
developing fetus. As referenced in
Chapter 4 of the RIA, ‘‘Mercury and
Other HAP Benefits Analysis,’’ children
are more vulnerable than adults to many
HAP emitted by EGUs due to
differential behavior patterns and
physiology. These unique
susceptibilities were carefully
considered in a number of different
ways in the analyses associated with
this rulemaking, and are summarized in
the RIA. We also estimate substantial
health improvements for children in the
form of 130,000 fewer asthma attacks,
3,100 fewer emergency room visits due
to asthma, 6,300 fewer cases of acute
bronchitis, and approximately 140,000
fewer cases of upper and lower
respiratory illness.
H. Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
Executive Order 13211 (66 FR 28355;
May 22, 2001) requires EPA to prepare
and submit a Statement of Energy
Effects to the Administrator of the Office
of Information and Regulatory Affairs,
OMB, for actions identified as
‘‘significant energy actions.’’ This
action, which is a significant regulatory
action under EO 12866, is likely to have
a significant adverse effect on the
supply, distribution, or use of energy.
We have prepared a Statement of Energy
Effects for this action as follows.
We estimate a 3.1 percent price
increase for electricity nationwide in
2016 and a less than 2 percent
percentage fall in coal-fired power
production as a result of this rule. The
EPA projects that electric power sectordelivered natural gas prices will
increase by about 0.6 percent over the
2015 to 2030 timeframe. For more
information on the estimated energy
effects, please refer to the economic
impact analysis for this final rule. The
analysis is available in the RIA, which
is in the public docket.
I. National Technology Transfer and
Advancement Act
Section 12(d) of the National
Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104–113;
15 U.S.C. 272 note) directs the EPA to
use voluntary consensus standards in its
regulatory activities unless to do so
would be inconsistent with applicable
law or otherwise impractical. Voluntary
consensus standards are technical
standards (e.g., materials specifications,
test methods, sampling procedures,
business practices) that are developed or
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adopted by voluntary consensus
standards bodies. The NTTAA directs
the EPA to provide Congress, through
OMB, explanations when the Agency
decides not to use available and
applicable voluntary consensus
standards.
This rulemaking involves technical
standards. The EPA cites the following
standards in the final rule: EPA
Methods 1, 2, 2A, 2C, 2F, 2G, 3A, 3B,
4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of
40 CFR part 60 and Method 320 of 40
CFR part 63. Consistent with the
NTTAA, the EPA conducted searches to
identify voluntary consensus standards
in addition to these EPA methods. No
applicable voluntary consensus
standards were identified for EPA
Methods 2F, 2G, 5D, and 19. The search
and review results have been
documented and are placed in the
docket for the proposed rule.
The three voluntary consensus
standards described below were
identified as acceptable alternatives to
EPA test methods for the purposes of
the final rule.
The voluntary consensus standard
American National Standards Institute
(ANSI)/American Society of Mechanical
Engineers (ASME) PTC 19–10–1981,
‘‘Flue and Exhaust Gas Analyses [part
10, Instruments and Apparatus]’’ is
cited in the final rule for its manual
method for measuring the O2, CO2, and
CO content of exhaust gas. This part of
ANSI/ASME PTC 19–10–1981 is an
acceptable alternative to Method 3B.
The voluntary consensus standard
ASTM D6348–03 (Reapproved 2010),
‘‘Standard Test Method for
Determination of Gaseous Compounds
by Extractive Direct Interface Fourier
Transform (FTIR) Spectroscopy’’ is
acceptable as an alternative to Method
320 and is cited in the final rule, but
with several conditions: (1) The test
plan preparation and implementation in
the Annexes to ASTM D6348–03,
Sections A1 through A8 are mandatory;
and (2) In ASTM D6348–03 Annex A5
(Analyte Spiking Technique), the
percent (%) R must be determined for
each target analyte (Equation A5.5). In
order for the test data to be acceptable
for a compound, %R must be 70% ≥ R
≤ 130%. If the %R value does not meet
this criterion for a target compound, the
test data are not acceptable for that
compound and the test must be repeated
for that analyte (i.e., the sampling and/
or analytical procedure should be
adjusted before a retest). The %R value
for each compound must be reported in
the test report, and all field
measurements must be corrected with
the calculated %R value for that
compound by using the following
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equation: Reported Result = (Measured
Concentration in the Stack × 100)/% R.
The voluntary consensus standard
ASTM D6784–02, ‘‘Standard Test
Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in
Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro
Method),’’ is an acceptable alternative to
use of EPA Method 29 for Hg only or
Method 30B for the purpose of
conducting relative accuracy tests of Hg
continuous monitoring systems under
this final rule. Because of the limitations
of this method in terms of total
sampling volume, it is not appropriate
for use in performance testing under
this rule. In addition to the voluntary
consensus standards the EPA used in
the final rule, the search for emissions
measurement procedures identified 16
other voluntary consensus standards.
The EPA determined that 14 of these 16
standards identified for measuring
emissions of the HAP or other
pollutants subject to emission standards
in the final rule were impractical
alternatives to EPA test methods for the
purposes of this final rule. Therefore,
the EPA did not adopt these standards
for this purpose. The reasons for this
determination for the 14 methods are
discussed below, and the remaining 2
methods are discussed later in this
section.
The voluntary consensus standard
ASTM D3154–00, ‘‘Standard Method for
Average Velocity in a Duct (Pitot Tube
Method),’’ is impractical as an
alternative to EPA Methods 1, 2, 3B, and
4 for the purposes of this rulemaking
because the standard appears to lack in
quality control and quality assurance
requirements. Specifically, ASTM
D3154–00 does not include the
following: (1) proof that openings of
standard pitot tube have not plugged
during the test; (2) if differential
pressure gauges other than inclined
manometers (e.g., magnehelic gauges)
are used, their calibration must be
checked after each test series; and (3)
the frequency and validity range for
calibration of the temperature sensors.
The voluntary consensus standard
ASTM D3464–96 (Reapproved 2001),
‘‘Standard Test Method Average
Velocity in a Duct Using a Thermal
Anemometer,’’ is impractical as an
alternative to EPA Method 2 for the
purposes of this rule primarily because
applicability specifications are not
clearly defined, e.g., range of gas
composition, temperature limits. Also,
the lack of supporting quality assurance
data for the calibration procedures and
specifications, and certain variability
issues that are not adequately addressed
by the standard limit the EPA’s ability
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to make a definitive comparison of the
method in these areas.
The voluntary consensus standard
ISO 10780:1994, ‘‘Stationary Source
Emissions—Measurement of Velocity
and Volume Flowrate of Gas Streams in
Ducts,’’ is impractical as an alternative
to EPA Method 2 in this rule. The
standard recommends the use of an Lshaped pitot, which historically has not
been recommended by the EPA. The
EPA specifies the S-type design which
has large openings that are less likely to
plug up with dust.
The voluntary consensus standard,
CAN/CSA Z223.2–M86 (1999), ‘‘Method
for the Continuous Measurement of
Oxygen, Carbon Dioxide, Carbon
Monoxide, Sulphur Dioxide, and Oxides
of Nitrogen in Enclosed Combustion
Flue Gas Streams,’’ is unacceptable as a
substitute for EPA Method 3A because
it does not include quantitative
specifications for measurement system
performance, most notably the
calibration procedures and instrument
performance characteristics. The
instrument performance characteristics
that are provided are non-mandatory
and also do not provide the same level
of quality assurance as the EPA
methods. For example, the zero and
span/calibration drift is only checked
weekly, whereas the EPA methods
require drift checks after each run.
Two very similar voluntary consensus
standards, ASTM D5835–95
(Reapproved 2001), ‘‘Standard Practice
for Sampling Stationary Source
Emissions for Automated Determination
of Gas Concentration,’’ and ISO
10396:1993, ‘‘Stationary Source
Emissions: Sampling for the Automated
Determination of Gas Concentrations,’’
are impractical alternatives to EPA
Method 3A for the purposes of this final
rule because they lack in detail and
quality assurance/quality control
requirements. Specifically, these two
standards do not include the following:
(1) Sensitivity of the method; (2)
acceptable levels of analyzer calibration
error; (3) acceptable levels of sampling
system bias; (4) zero drift and
calibration drift limits, time span, and
required testing frequency; (5) a method
to test the interference response of the
analyzer; (6) procedures to determine
the minimum sampling time per run
and minimum measurement time; and
(7) specifications for data recorders, in
terms of resolution (all types) and
recording intervals (digital and analog
recorders, only).
The voluntary consensus standard
ISO 12039:2001, ‘‘Stationary Source
Emissions—Determination of Carbon
Monoxide, Carbon Dioxide, and
Oxygen—Automated Methods,’’ is not
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acceptable as an alternative to EPA
Method 3A. This ISO standard is similar
to EPA Method 3A, but is missing some
key features. In terms of sampling, the
hardware required by ISO 12039:2001
does not include a 3-way calibration
valve assembly or equivalent to block
the sample gas flow while calibration
gases are introduced. In its calibration
procedures, ISO 12039:2001 only
specifies a two-point calibration while
EPA Method 3A specifies a three-point
calibration. Also, ISO 12039:2001 does
not specify performance criteria for
calibration error, calibration drift, or
sampling system bias tests as in the EPA
method, although checks of these
quality control features are required by
the ISO standard.
The voluntary consensus standard
ASTM D6522–00, ‘‘Standard Test
Method for the Determination of
Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions
from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers
and Process Heaters Using Portable
Analyzers’’ is not an acceptable
alternative to EPA Method 3A for
measuring CO and O2 concentrations for
this final rule as the method is designed
for application to sources firing natural
gas.
The voluntary consensus standard
ASME PTC–38–80 R85 (1985),
‘‘Determination of the Concentration of
Particulate Matter in Gas Streams,’’ is
not acceptable as an alternative for EPA
Method 5 because ASTM PTC–38–80 is
not specific about equipment
requirements, and instead presents the
options available and the pros and cons
of each option. The key specific
differences between ASME PTC–38–80
and the EPA methods are that the ASME
standard: (1) Allows in-stack filter
placement as compared to the out-ofstack filter placement in EPA Methods
5 and 17; (2) allows many different
types of nozzles, pitots, and filtering
equipment; (3) does not specify a filter
weighing protocol or a minimum
allowable filter weight fluctuation as in
the EPA methods; and (4) allows filter
paper to be only 99 percent efficient, as
compared to the 99.95 percent
efficiency required by the EPA methods.
The voluntary consensus standard
ASTM D3685/D3685M–98, ‘‘Test
Methods for Sampling and
Determination of Particulate Matter in
Stack Gases,’’ is similar to EPA Methods
5 and 17, but is lacking in the following
areas that are needed to produce quality,
representative particulate data: (1)
Requirement that the filter holder
temperature should be between 120°C
and 134°C, and not just ‘‘above the acid
dew-point’’; (2) detailed specifications
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for measuring and monitoring the filter
holder temperature during sampling; (3)
procedures similar to EPA Methods 1, 2,
3, and 4, that are required by EPA
Method 5; (4) technical guidance for
performing the Method 5 sampling
procedures, e.g., maintaining and
monitoring sampling train operating
temperatures, specific leak check
guidelines and procedures, and use of
reagent blanks for determining and
subtracting background contamination;
and (5) detailed equipment and/or
operational requirements, e.g.,
component exchange leak checks, use of
glass cyclones for heavy particulate
loading and/or water droplets, operating
under a negative stack pressure,
exchanging particulate loaded filters,
sampling preparation and
implementation guidance, sample
recovery guidance, data reduction
guidance, and particulate sample
calculations input.
The voluntary consensus standard
ISO 9096:1992, ‘‘Determination of
Concentration and Mass Flow Rate of
Particulate Matter in Gas Carrying
Ducts—Manual Gravimetric Method,’’ is
not acceptable as an alternative for EPA
Method 5. Although sections of ISO
9096 incorporate EPA Methods 1, 2, and
5 to some degree, this ISO standard is
not equivalent to EPA Method 5 for
collection of PM. The standard ISO 9096
does not provide applicable technical
guidance for performing many of the
integral procedures specified in
Methods 1, 2, and 5. Major performance
and operational details are lacking or
nonexistent, and detailed quality
assurance/quality control guidance for
the sampling operations required to
produce quality, representative
particulate data (e.g., guidance for
maintaining and monitoring train
operating temperatures, specific leak
check guidelines and procedures, and
sample preparation and recovery
procedures) are not provided by the
standard, as in EPA Method 5. Also,
details of equipment and/or operational
requirements, such as those specified in
EPA Method 5, are not included in the
ISO standard, e.g., stack gas moisture
measurements, data reduction guidance,
and particulate sample calculations.
The voluntary consensus standard
CAN/CSA Z223.1–M1977, ‘‘Method for
the Determination of Particulate Mass
Flows in Enclosed Gas Streams,’’ is not
acceptable as an alternative for EPA
Method 5. Detailed technical procedures
and quality control measures that are
required in EPA Methods 1, 2, 3, and 4
are not included in CAN/CSA Z223.1.
Second, CAN/CSA Z223.1 does not
include the EPA Method 5 filter
weighing requirement to repeat
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weighing every 6 hours until a constant
weight is achieved. Third, EPA Method
5 requires the filter weight to be
reported to the nearest 0.1 milligram
(mg), while CAN/CSA Z223.1 requires
reporting only to the nearest 0.5 mg.
Also, CAN/CSA Z223.1 allows the use
of a standard pitot for velocity
measurement when plugging of the tube
opening is not expected to be a problem.
The EPA Method 5 requires an S-shaped
pitot.
The voluntary consensus standard EN
1911–1,2,3 (1998), ‘‘Stationary Source
Emissions-Manual Method of
Determination of HCl-Part 1: Sampling
of Gases Ratified European Text-Part 2:
Gaseous Compounds Absorption
Ratified European Text-Part 3:
Adsorption Solutions Analysis and
Calculation Ratified European Text,’’ is
impractical as an alternative to EPA
Methods 26 and 26A. Part 3 of this
standard cannot be considered
equivalent to EPA Method 26 or 26A
because the sample absorbing solution
(water) would be expected to capture
both HCl and chlorine gas, if present,
without the ability to distinguish
between the two. The EPA Methods 26
and 26A use an acidified absorbing
solution to first separate HCl and
chlorine gas so that they can be
selectively absorbed, analyzed, and
reported separately. In addition, in EN
1911 the absorption efficiency for
chlorine gas would be expected to vary
as the pH of the water changed during
sampling.
The voluntary consensus standard EN
13211 (1998), is not acceptable as an
alternative to the Hg portion of EPA
Method 29 primarily because it is not
validated for use with impingers, as in
the EPA method, although the method
describes procedures for the use of
impingers. This European standard is
validated for the use of fritted bubblers
only and requires the use of a side
(split) stream arrangement for isokinetic
sampling because of the low sampling
rate of the bubblers (up to 3 liters per
minute, maximum). Also, only two
bubblers (or impingers) are required by
EN 13211, whereas EPA Method 29
require the use of six impingers. In
addition, EN 13211 does not include
many of the quality control procedures
of EPA Method 29, especially for the use
and calibration of temperature sensors
and controllers, sampling train assembly
and disassembly, and filter weighing.
Two of the 16 voluntary consensus
standards identified in this search were
not available at the time the review was
conducted for the purposes of the final
rule because they are under
development by a voluntary consensus
body: ASME/BSR MFC 13M, ‘‘Flow
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9443
Measurement by Velocity Traverse,’’ for
EPA Method 2 (and possibly 1); and
ASME/BSR MFC 12M, ‘‘Flow in Closed
Conduits Using Multiport Averaging
Pitot Primary Flowmeters,’’ for EPA
Method 2.
Finally, in addition to the three
voluntary consensus standards
identified as acceptable alternatives to
EPA methods required in the final rule,
the EPA is also specifying four
voluntary consensus standards in the
rule for use in sampling and analysis of
liquid oil samples for moisture content.
These standards are: ASTM D95–05
(Reapproved 2010), ‘‘Standard Test
Method for Water in Petroleum Products
and Bituminous Materials by
Distillation,’’ ASTM D4006–11,
‘‘Standard Test Method for Water in
Crude Oil by Distillation,’’ ASTM
D4177–95 (Reapproved 2010),
‘‘Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products,’’ and ASTM D4057–06
(Reapproved 2011), ‘‘Standard Practice
for Manual Sampling of Petroleum and
Petroleum Products.’’
Table 5, section 4.1.1.5 of appendix A,
and section 3.1.2 of appendix B to
subpart UUUUU, 40 CFR part 63, list
the EPA testing methods included in the
final rule. Under section 63.7(f) and
section 63.8(f) of subpart A of the
General Provisions, a source may apply
to the EPA for permission to use
alternative test methods or alternative
monitoring requirements in place of any
of the EPA testing methods,
performance specifications, or
procedures specified.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Executive Order 12898 (59 FR 7629;
February 16, 1994) establishes federal
executive policy on environmental
justice (EJ). Its main provision directs
federal agencies, to the greatest extent
practicable and permitted by law, to
make EJ part of their mission by
identifying and addressing, as
appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies, and activities on minority
populations and low-income
populations in the U.S.
The EPA has determined that this
final rule will not have
disproportionately high and adverse
human health or environmental effects
on minority, low income, and
indigenous populations because it
increases the level of environmental
protection for all affected populations
without having any disproportionately
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high and adverse human health or
environmental effects on any
population, including any minority, low
income, and indigenous populations.
This final rule establishes national
emission standards for new and existing
EGUs that combust coal and oil. The
EPA estimates that there are
approximately 1,400 units located at
600 facilities covered by this final rule.
This final rule will reduce emissions
of all the listed HAP that come from
EGUs. This includes metals (Hg, As, Be,
Cd, Cr, Pb, Mn, Ni, and Se), organics
(POM, acetaldehyde, acrolein, benzene,
dioxins, ethylene dichloride,
formaldehyde, and PCB), and acid gases
(HCl and HF). At sufficient levels of
exposure, these pollutants can cause a
range of health effects including cancer;
irritation of the lungs, skin, and mucous
membranes; effects on the central
nervous system such as memory and IQ
loss and learning disabilities; damage to
the kidneys; and other acute health
disorders.
The final rule will also result in
substantial reductions of criteria
pollutants such as CO, PM, and SO2.
Sulfur dioxide is a precursor pollutant
that is often transformed into fine PM
(PM2.5) in the atmosphere. Reducing
direct emissions of PM2.5 and SO2 will,
as a result, reduce concentrations of
PM2.5 in the atmosphere. These
reductions in PM2.5 will provide large
health benefits, such as reducing the
risk of premature mortality for adults,
chronic and acute bronchitis, childhood
asthma attacks, and hospitalizations for
other respiratory and cardiovascular
diseases. (For more details on the health
effects of metals, organics, and PM2.5,
please refer to the RIA contained in the
docket for this rulemaking.) This final
rule will also have a small effect on
electricity and natural gas prices but has
the potential to affect the cost structure
of the utility industry and could lead to
shifts in how and where electricity is
generated.
This final rule is one of a group of
regulatory actions that the EPA has
taken and will take over the next several
years to respond to statutory and
judicial mandates that will reduce
exposure to HAP and PM2.5, as well as
to other pollutants, from EGUs and
other sources. In addition, the EPA will
pursue energy efficiency improvements
throughout the economy, along with
other federal agencies, states and other
groups. This will contribute to
additional environmental and public
health improvements while lowering
the costs of realizing those
improvements. Together, these rules
and actions will have substantial and
long-term effects on both the U.S. power
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industry and on communities currently
breathing dirty air. Therefore, we
anticipate significant interest in many, if
not most, of these actions from EJ
communities, among many others.
1. Key EJ Aspects of the Rule
This is an air toxics rule; therefore, it
does not permit emissions trading
among sources. Instead, this final rule
will place a limit on the rates of Hg and
other HAP emitted from each affected
EGU. As a result, emissions of Hg and
other HAP such as HCl will be
substantially reduced in the vast
majority of states. In some states,
however, there may be small increases
in Hg and other HAP emissions due to
shifts in electricity generation from
EGUs with higher emission rates to
EGUs with already low emission rates.
Hydrogen chloride emissions are
projected to increase at a small number
of sources but that does not lead to any
increased emissions at the state level.
The primary risk analysis to support
the finding that this final rule is both
appropriate and necessary includes an
analysis of the effects of Hg from EGUs
on people who rely on freshwater fish
they catch as a regular and frequent part
of their diet. These groups are
characterized as subsistence level
fishing populations or fishers. A
significant portion of the data in this
analysis came from published studies of
EJ communities where people
frequently consume locally-caught
freshwater fish. These communities
included: (1) White and black
populations (including female and poor
strata) surveyed in South Carolina; (2)
Hispanic, Vietnamese and Laotian
populations surveyed in California; and
(3) Great Lakes tribal populations
(Chippewa and Ojibwe) active on ceded
territories around the Great Lakes. These
data were used to help estimate risks to
similar populations beyond the areas
where the study data were collected. For
example, while the Vietnamese and
Laotian survey data were collected in
California, given the ethnic (heritage)
nature of these high fish consumption
rates, we assumed that they could also
be associated with members of these
ethnic groups living elsewhere in the
U.S. Therefore, the high-end
consumption rates referenced in the
California study for these ethnic groups
were used to model risk at watersheds
elsewhere in the U.S. As a result of this
approach, the specific fish consumption
patterns of several different EJ groups
are fundamental to the EPA’s
assessment of both the underlying risks
that make this final rule appropriate and
necessary, and of the analysis of the
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benefits of reducing exposure to Hg and
the other HAP.
The EPA’s full analysis of risks from
consumption of Hg-contaminated fish is
contained in the RIA for this rule. The
effects of this final rule on the health
risks from Hg and other HAP are
presented in the preamble and in the
RIA for this rule.
2. Potential Environmental and Public
Health Impacts to Minority, Low
Income, or Tribal Populations
The EPA has conducted several
analyses that provide additional insight
on the potential effects of this rule on
EJ communities. These include: (1) The
socio-economic distribution of people
living close to affected EGUs who may
be exposed to pollution from these
sources; and (2) an analysis of the
distribution of health effects expected
from the reductions in PM2.5 that will
result from implementation of this final
rule (co-benefits).
a. Socio-Economic Distribution. As
part of the analysis for this final rule,
the EPA reviewed the aggregate
demographic makeup of the
communities near EGUs covered by this
final rule. Although this analysis gives
some indication of populations that may
be exposed to levels of pollution that
cause concern, it does not identify the
demographic characteristics of the most
highly affected individuals or
communities. Electric generating units
usually have very tall emission stacks;
this tends to disperse the pollutants
emitted from these stacks fairly far from
the source. In addition, several of the
pollutants emitted by these sources,
such as a common form of Hg and SO2,
are known to travel long distances and
contribute to adverse impacts on both
the environment and human health
hundreds or even thousands of miles
from where they were emitted (in the
case of elemental Hg, globally).
The proximity-to-the-source review is
included in the analysis for this final
rule because some EGUs emit enough
HAP such as Ni or Cr(VI) to cause
elevated lifetime cancer risks greater
than 1 in a million in nearby
communities. In addition, the EPA’s
analysis indicates that there are
localized areas with potential for
elevated levels of Hg deposition around
most U.S. EGUs.381
The analysis of demographic data
used proximity-to-the-source as a
surrogate for exposure to identify those
populations considered to be living near
affected sources, such that they have
notable exposures to current HAP
381 See Excess Local Deposition TSD for more
detail.
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emissions from these sources. The
demographic data for this analysis were
extracted from the 2000 census data
which were provided to the EPA by the
U.S. Census Bureau. Distributions by
race are based on demographic
information at the census block level,
and all other demographic groups are
based on the extrapolation of census
block group level data to the census
block level. The socio-demographic
parameters used in the analysis
included the following categories:
Racial (White, African American, Native
American, Other or Multiracial, and All
Other Races); Ethnicity (Hispanic); and
Other (Number of people below the
poverty line, Number of people with
ages between 0 and 18, Number of
people greater than or equal to 65,
Number of people with no high school
diploma).
In determining the aggregate
demographic makeup of the
communities near affected sources, the
EPA focused on those census blocks
within three miles of affected sources
and determined the demographic
composition (e.g., race, income, etc.) of
these census blocks and compared them
to the corresponding compositions
nationally. The radius of 3 miles (or
approximately 5 kilometers) is
consistent with other demographic
analyses focused on areas around
potential sources. In addition, air
quality modeling experience has shown
that the area within three miles of an
individual source of emissions can
generally be considered the area with
the highest ambient air levels of the
primary pollutants being emitted for
most sources, both in absolute terms
and relative to the contribution of other
9445
sources (assuming there are other
sources in the area, as is typical in
urban areas). Although facility processes
and fugitive emissions may have more
localized impacts, the EPA
acknowledges that because of various
stack heights there is the potential for
dispersion beyond 3 miles. To the
extent that any minority, low income,
and indigenous subpopulation is
disproportionately impacted by the
current emissions as a result of the
proximity of their homes to these
sources, that subpopulation also stands
to see increased environmental and
health benefit from the emissions
reductions called for by this rule. The
results of the EPA’s demographic
analysis for affected sources are shown
in the following table: 382 383
TABLE 12—COMPARATIVE SUMMARY OF THE DEMOGRAPHICS WITHIN 5 KM (3 MILES) OF THE AFFECTED SOURCES
[Population in millions] 382
African
American
White
Near Source
Total (3 mi)
% of Near
Source Total
National Total
% of National
Total ............
8.78
Native
American
2.51
Other and multiracial
0.10
Hispanic
2.52
Minority 383
2.86
5.13
Below poverty
line
2.43
63
215
18
35
1
2.49
18
33.3
21
39.1
37
70.8
17
37.1
75
12
1
12
14
25
13
382 Racial
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383 The
and ethnic categories overlap and cannot be summed.
‘‘Minority’’ population is the overall population (in the first row) minus white population (in the second row).
The data indicate that coal-fired EGUs
are located in areas where the minority
share of the population living within a
three mile buffer is higher than the
national average by 12 percentage points
or 48 percent. For these same areas, the
percent of the population below the
poverty line is also higher than the
national average by 4 percentage points
or 31 percent. These results are
presented in more detail in the ‘‘Review
of Proximity Analysis,’’ February 2011,
a copy of which is available in the
docket.
b. PM2.5 (Co-Benefits) Analysis. As
mentioned above, many of the steps
EGUs will take to reduce their emissions
of air toxics as required by this final rule
will also reduce emissions of PM and
SO2. As a result, this final rule will
reduce concentrations of PM2.5 in the
atmosphere. Exposure to PM2.5 can
cause or contribute to adverse health
effects, such as asthma and heart
disease, that significantly affect many
minority, low-income, and tribal
individuals and their communities. Fine
PM (PM2.5) is particularly (but not
exclusively) harmful to children, the
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elderly, and people with existing heart
and lung diseases, including asthma.
Exposure can cause premature death
and trigger heart attacks, asthma attacks
in children and adults with asthma,
chronic and acute bronchitis, and
emergency room visits and
hospitalizations, as well as milder
illnesses that keep children home from
school and adults home from work.
Missing work due to illness or the
illness of a child is a particular problem
for people who have jobs that do not
provide paid sick days. Low-wage
employees also risk losing their jobs if
they are absent too often, even if it is
due to their own illness or the illness of
a child or other relative. Finally, many
individuals in these communities lack
access to high quality health care to
treat these types of illnesses. Due to all
these factors, many minority and lowincome communities are particularly
susceptible to the health effects of PM2.5
and receive a variety of benefits from
reducing it.
We estimate that in 2016 the annual
PM-related benefits of the final rule for
adults include approximately 4,200 to
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11,000 fewer premature mortalities,
2,900 fewer cases of chronic bronchitis,
4,800 fewer non-fatal heart attacks,
2,600 fewer hospitalizations (for
respiratory and cardiovascular disease
combined), 3.2 million fewer days of
restricted activity due to respiratory
illness and approximately 540,000 fewer
lost work days. As described in EO
13045, Protection of Children from
Environmental Health Risks and Safety
Risks, we also estimate substantial
health improvements for children.
We also examined the PM2.5 mortality
risks according to race, income, and
educational attainment. We then
estimated the change in PM2.5 mortality
risk as a result of this final rule among
people living in the counties with the
highest (top 5 percent) PM2.5 mortality
risk in 2005. We then compared the
change in risk among the people living
in these ‘‘high-risk’’ counties with
people living in all other counties.
In 2005, people living in the highest
risk counties and in the poorest counties
had a substantially higher risk of PM2.5related death than people living in the
other 95 percent of counties. This was
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true regardless of race; the difference
between the groups of counties for each
race was large while the differences
among races in both groups of counties
was very small. In contrast, the analysis
found that people with less than high
school education had a significantly
greater risk from PM2.5 mortality than
people with a greater than high school
education. This was true both for the
highest-risk counties and for the other
counties. In summary, the analysis
indicates that in 2005, educational
status, living in one of the poorest
counties, and living in a high-risk
county are associated with higher PM2.5
mortality risk while race is not.
Our analysis demonstrates that this
final rule will significantly reduce the
PM2.5 mortality among all populations
of different races living throughout the
U.S. compared to both 2005 and 2016
pre-rule (i.e., base case) levels. The
analysis indicates that people living in
counties with the highest rates (top 5
percent) of PM2.5 mortality risk in 2005
receive the largest reduction in
mortality risk after this rule takes effect.
We also find that people living in the
poorest 5 percent of the counties receive
a larger reduction in PM2.5 mortality risk
than all other counties. More
information can be found in Section
7.11 of the RIA.
The EPA estimates that the benefits of
the final rule are distributed among
races, income levels, and levels of
education fairly evenly. However, the
analysis does indicate that this final rule
in conjunction with the implementation
of existing or final rules (e.g., the
CSAPR) will reduce the disparity in risk
between those in the highest-risk
counties and the other 95 percent of
counties for all races and educational
levels. In addition, in many cases
implementation of this final rule and
other rules will, together, reduce risks in
the highest-risk counties to the
approximate level of risk for the rest of
the counties as it existed before
implementation of the rule.
These results are presented in more
detail in Section 7.11 of the RIA.
3. Meaningful Public Participation
The EPA defines ‘‘environmental
justice’’ to include meaningful
involvement of all people regardless of
race, color, national origin, or income
with respect to the development,
implementation, and enforcement of
environmental laws, regulations, and
policies. To promote meaningful
involvement, the EPA publicized the
rulemaking via newsletters, EJ
listserves, and the internet, including
the Office of Policy’s (OP) Rulemaking
Gateway Web site (https://
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yosemite.epa.gov/opei/RuleGate.nsf/).
During the comment period, the EPA
discussed the proposed rule via a
conference call with communities,
conducted a community-oriented
webinar on the proposed rule, and
posted the webinar presentation online. The EPA also held three public
hearings to receive additional input on
the proposal.
There will continue to be
opportunities for public notice and
comment as the utilities move forward
with implementation of this rule. Once
the rule is finalized, affected EGUs will
need to update their Title V operating
permits to reflect their new emission
limits, any other new applicable
requirements, and the associated
monitoring and recordkeeping from this
rule. The Title V permitting process
provides that when most permits are
reopened (for example, to incorporate
new applicable requirements) or
renewed, there must be opportunity for
public review and comments. In
addition, after the public review
process, the EPA has an opportunity to
review the proposed permit and object
to its issuance if it does not meet CAA
requirements.
4. Additional Analysis
In addition to the previously
described assessment of EJ impacts, the
EPA conducted an analysis of subpopulations with particularly high
potential risks of Hg exposure due to
high rates of fish consumption. These
populations overlap in many cases with
traditional EJ populations and would
benefit from Hg reductions resulting
from this rule. The EPA also conducted
an analysis of the distribution of PM2.5related mortality risk according to the
race, income and education of the
population and how MATS changes this
distribution. These analyses can be
found in Section 7.12 of the RIA.
5. Summary
This final rule strictly limits the
emissions rate of Hg and other HAP
from every affected EGU. The EPA’s
analysis indicates substantial health
benefits, including for minority, low
income, and indigenous populations,
from reductions in PM2.5.
The EPA’s analysis also indicates
reductions in risks for individuals,
including for members of minority
populations, who eat fish frequently
from U.S. lakes and rivers and who live
near affected sources. Based on all the
available information, the EPA has
determined that this final rule will not
have disproportionately high and
adverse human health or environmental
effects on minority, low income, and
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indigenous populations. The EPA is
providing multiple opportunities for EJ
communities to both learn about and
comment on this rule and welcomes
their participation as implementation of
the rule proceeds.
K. Congressional Review Act
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the U.S. The EPA will submit a report
containing this rule and other required
information to the U.S. Senate, the U.S.
House of Representatives, and the
Comptroller General of the U.S. prior to
publication of the rule in the Federal
Register. A major rule cannot take effect
until 60 days after it is published in the
Federal Register. This action is a ‘‘major
rule’’ as defined by 5 U.S.C. 804(2). This
rule will be effective April 16, 2012.
List of Subjects
40 CFR Part 60
Environmental protection,
Administrative practice and procedure,
Air pollution control, Incorporation by
reference, Intergovernmental relations,
Reporting and recordkeeping
requirements.
40 CFR Part 63
Environmental protection,
Administrative practice and procedure,
Air pollution control, Hazardous
substances, Incorporation by reference,
Intergovernmental relations, Reporting
and recordkeeping requirements.
Dated: December 16, 2011.
Lisa P. Jackson,
Administrator.
For the reasons stated in the
preamble, title 40, chapter I, of the Code
of the Federal Regulations is amended
as follows:
PART 60—[AMENDED]
1. The authority citation for part 60
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
Subpart A—[Amended]
2. Section 60.17 is amended:
a. By redesignating paragraph (a)(93),
added March 21, 2011, at 76 FR 15750,
and delayed indefinitely at 76 FR 28664,
May 18, 2011, as paragraph (a)(96);
■
■
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b. By redesignating paragraphs (a)(91)
and (a)(92) as paragraphs (a)(94) and
(a)(95);
■ c. By redesignating paragraphs (a)(89)
and (a)(90) as paragraphs (a)(91) and
(a)(92);
■ d. By redesignating paragraphs (a)(54)
through (a)(88) as paragraphs (a)(55)
through (a)(89);
■ e. By adding paragraph (a)(54);
■ f. By adding paragraph (a)(90); and
■ g. By adding paragraph (a)(93) to read
as follows:
■
§ 60.17
Incorporations by reference.
*
*
*
*
*
(a) * * *
(54) ASTM D3699–08, Standard
Specification for Kerosine, including
Appendix X1, approved September 1,
2008, IBR approved for §§ 60.41b of
subpart Db of this part and 60.41c of
subpart Dc of this part.
*
*
*
*
*
(90) ASTM D6751–11b, Standard
Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels,
including Appendices X1 through X3,
approved July 15, 2011, IBR approved
for §§ 60.41b of subpart Db of this part
and 60.41c of subpart Dc of this part.
*
*
*
*
*
(93) ASTM D7467–10, Standard
Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including
Appendices X1 through X3, approved
August 1, 2010, IBR approved for
§§ 60.41b of subpart Db of this part and
60.41c of subpart Dc of this part.
*
*
*
*
*
Subpart B—[Amended]
3. Section 60.21 is amended as
follows:
■ a. By revising paragraph (a).
■ b. By revising paragraph (f).
■ c. By removing paragraph (k).
■
§ 60.21
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*
*
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(b) * * *
(1) Emission standards shall either be
based on an allowance system or
prescribe allowable rates of emissions
except when it is clearly impracticable.
Such cases will be identified in the
guideline documents issued under
§ 60.22. Where emission standards
prescribing equipment specifications are
established, the plan shall, to the degree
possible, set forth the emission
reductions achievable by
implementation of such specifications,
and may permit compliance by the use
of equipment determined by the State to
be equivalent to that prescribed.
*
*
*
*
*
Subpart D—[Amended]
5. The subpart heading for Subpart D
is revised to read as follows:
■
Subpart D—Standards of Performance
for Fossil-Fuel-Fired Steam Generators
6. Section 60.40 is amended by
revising paragraph (e) to read as follows:
■
§ 60.40 Applicability and designation of
affected facility.
*
*
*
*
*
(e) Any facility subject to either
subpart Da or KKKK of this part is not
subject to this subpart.
■ 7. Section 60.41 is amended by adding
the definition of ‘‘natural gas’’ in
alphabetical order to read as follows:
Definitions.
*
*
*
*
*
(a) Designated pollutant means any
air pollutant, the emissions of which are
subject to a standard of performance for
new stationary sources, but for which
air quality criteria have not been issued
and that is not included on a list
published under section 108(a) or
section 112(b)(1)(A) of the Act.
*
*
*
*
*
(f) Emission standard means a legally
enforceable regulation setting forth an
allowable rate of emissions into the
atmosphere, establishing an allowance
system, or prescribing equipment
specifications for control of air pollution
emissions.
*
*
*
*
*
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§ 60.24 Emission standards and
compliance schedules.
§ 60.41
Definitions.
*
4. Section 60.24 is amended as
follows:
■ a. By revising paragraph (b)(1).
■ b. By removing paragraph (h).
■
*
*
*
*
Natural gas means a fluid mixture of
hydrocarbons (e.g., methane, ethane, or
propane), composed of at least 70
percent methane by volume or that has
a gross calorific value between 35 and
41 megajoules (MJ) per dry standard
cubic meter (950 and 1,100 Btu per dry
standard cubic foot), that maintains a
gaseous state under ISO conditions. In
addition, natural gas contains 20.0
grains or less of total sulfur per 100
standard cubic feet. Finally, natural gas
does not include the following gaseous
fuels: landfill gas, digester gas, refinery
gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven
gas, or any gaseous fuel produced in a
process which might result in highly
variable sulfur content or heating value.
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*
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8. Section 60.42 is amended as
follows:
■ a. By revising paragraph (a)
introductory text.
■ b. By adding paragraph (d).
■ c. By adding paragraph (e).
■
§ 60.42
(PM).
Standard for particulate matter
(a) Except as provided under
paragraphs (b), (c), (d), and (e) of this
section, on and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases that:
*
*
*
*
*
(d) An owner or operator of an
affected facility that combusts only
natural gas is exempt from the PM and
opacity standards specified in paragraph
(a) of this section.
(e) An owner or operator of an
affected facility that combusts only
gaseous or liquid fossil fuel (excluding
residual oil) with potential SO2
emissions rates of 26 ng/J (0.060 lb/
MMBtu) or less and that does not use
post-combustion technology to reduce
emissions of SO2 or PM is exempt from
the PM standards specified in paragraph
(a) of this section.
■ 9. Section 60.45 is amended as
follows:
■ a. By revising paragraph (a).
■ b. By revising paragraph (b)
introductory text.
■ c. By revising paragraphs (b)(1)
through (5).
■ d. By revising paragraph (b)(6)
introductory text.
■ e. By revising paragraphs (b)(7)(i)(A)
through (C).
■ f. By revising paragraph (b)(7)(ii)(B).
■ g. By adding paragraph (b)(8).
§ 60.45
Emissions and fuel monitoring.
(a) Each owner or operator of an
affected facility subject to the applicable
emissions standard shall install,
calibrate, maintain, and operate
continuous opacity monitoring system
(COMS) for measuring opacity and a
continuous emissions monitoring
system (CEMS) for measuring SO2
emissions, NOX emissions, and either
oxygen (O2) or carbon dioxide (CO2)
except as provided in paragraph (b) of
this section.
(b) Certain of the CEMS and COMS
requirements under paragraph (a) of this
section do not apply to owners or
operators under the following
conditions:
(1) For a fossil-fuel-fired steam
generator that combusts only gaseous or
liquid fossil fuel (excluding residual oil)
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with potential SO2 emissions rates of 26
ng/J (0.060 lb/MMBtu) or less and that
does not use post-combustion
technology to reduce emissions of SO2
or PM, COMS for measuring the opacity
of emissions and CEMS for measuring
SO2 emissions are not required if the
owner or operator monitors SO2
emissions by fuel sampling and analysis
or fuel receipts.
(2) For a fossil-fuel-fired steam
generator that does not use a flue gas
desulfurization device, a CEMS for
measuring SO2 emissions is not required
if the owner or operator monitors SO2
emissions by fuel sampling and
analysis.
(3) Notwithstanding § 60.13(b),
installation of a CEMS for NOX may be
delayed until after the initial
performance tests under § 60.8 have
been conducted. If the owner or
operator demonstrates during the
performance test that emissions of NOX
are less than 70 percent of the
applicable standards in § 60.44, a CEMS
for measuring NOX emissions is not
required. If the initial performance test
results show that NOX emissions are
greater than 70 percent of the applicable
standard, the owner or operator shall
install a CEMS for NOX within one year
after the date of the initial performance
tests under § 60.8 and comply with all
other applicable monitoring
requirements under this part.
(4) If an owner or operator is not
required to and elects not to install any
CEMS for either SO2 or NOX, a CEMS
for measuring either O2 or CO2 is not
required.
(5) For affected facilities using a PM
CEMS, a bag leak detection system to
monitor the performance of a fabric
filter (baghouse) according to the most
current requirements in § 60.48Da of
this part, or an ESP predictive model to
monitor the performance of the ESP
developed in accordance and operated
according to the most current
requirements in section § 60.48Da of
this part a COMS is not required.
(6) A COMS for measuring the opacity
of emissions is not required for an
affected facility that does not use postcombustion technology (except a wet
scrubber) for reducing PM, SO2, or
carbon monoxide (CO) emissions, burns
only gaseous fuels or fuel oils that
contain less than or equal to 0.30 weight
percent sulfur, and is operated such that
emissions of CO to the atmosphere from
the affected source are maintained at
levels less than or equal to 0.15 lb/
MMBtu on a boiler operating day
average basis. Owners and operators of
affected sources electing to comply with
this paragraph must demonstrate
compliance according to the procedures
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specified in paragraphs (b)(6)(i) through
(iv) of this section.
*
*
*
*
*
(7) * * *
(i) * * *
(A) If no visible emissions are
observed, a subsequent Method 9 of
appendix A–4 of this part performance
test must be completed within 12
calendar months from the date that the
most recent performance test was
conducted or within 45 days of the next
day that fuel with an opacity standard
is combusted, whichever is later;
(B) If visible emissions are observed
but the maximum 6-minute average
opacity is less than or equal to 5
percent, a subsequent Method 9 of
appendix A–4 of this part performance
test must be completed within 6
calendar months from the date that the
most recent performance test was
conducted or within 45 days of the next
day that fuel with an opacity standard
is combusted, whichever is later;
(C) If the maximum 6-minute average
opacity is greater than 5 percent but less
than or equal to 10 percent, a
subsequent Method 9 of appendix A–4
of this part performance test must be
completed within 3 calendar months
from the date that the most recent
performance test was conducted or
within 45 days of the next day that fuel
with an opacity standard is combusted,
whichever is later; or
*
*
*
*
*
(ii) * * *
(B) If no visible emissions are
observed for 10 operating days during
which an opacity standard is applicable,
observations can be reduced to once
every 7 operating days during which an
opacity standard is applicable. If any
visible emissions are observed, daily
observations shall be resumed.
*
*
*
*
*
(8) A COMS for measuring the opacity
of emissions is not required for an
affected facility at which the owner or
operator installs, calibrates, operates,
and maintains a particulate matter
continuous parametric monitoring
system (PM CPMS) according to the
requirements specified in subpart
UUUUU of part 63.
*
*
*
*
*
Subpart Da—[Amended]
10. The subpart heading for Subpart
Da is revised to read as follows:
■
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Subpart Da—Standards of
Performance for Electric Utility Steam
Generating Units
11. Section 60.40Da is amended by
revising paragraphs (b)(1) and (e) to read
as follows:
■
§ 60.40Da Applicability and designation of
affected facility.
*
*
*
*
*
(b) * * *
(1) The IGCC electric utility steam
generating unit is capable of combusting
more than 73 MW (250 MMBtu/h) heat
input of fossil fuel (either alone or in
combination with any other fuel) in the
combustion turbine engine and
associated heat recovery steam
generator; and
*
*
*
*
*
(e) Applicability of this subpart to an
electric utility combined cycle gas
turbine other than an IGCC electric
utility steam generating unit is as
specified in paragraphs (e)(1) through
(3) of this section.
(1) Affected facilities (i.e. heat
recovery steam generators used with
duct burners) associated with a
stationary combustion turbine that are
capable of combusting more than 73
MW (250 MMBtu/h) heat input of fossil
fuel are subject to this subpart except in
cases when the affected facility (i.e. heat
recovery steam generator) meets the
applicability requirements of and is
subject to subpart KKKK of this part.
(2) For heat recovery steam generators
use with duct burners subject to this
subpart, only emissions resulting from
the combustion of fuels in the steam
generating unit (i.e. duct burners) are
subject to the standards under this
subpart. (The emissions resulting from
the combustion of fuels in the stationary
combustion turbine engine are subject to
subpart GG or KKKK, as applicable, of
this part.)
(3) Any affected facility that meets the
applicability requirements and is
subject to subpart Eb or subpart CCCC
of this part is not subject to the emission
standards under subpart Da.
■ 12. Section 60.41Da is amended as
follows:
■ a. By revising the definitions of
‘‘boiler operating day’’, ‘‘gaseous fuel’’,
‘‘integrated gasification combined cycle
electric utility steam generating unit’’,
‘‘natural gas’’, ‘‘petroleum’’, ‘‘potential
combustion concentration’’, and ‘‘steam
generating unit’’.
■ b. By adding the definitions of
‘‘affirmative defense’’, ‘‘combined heat
and power’’, ‘‘gross energy output’’, ‘‘net
energy output’’, ‘‘out-of-control period’’,
and ‘‘petroleum coke’’ in alphabetical
order.
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c. By removing the definitions of
‘‘available purchase power’’,
‘‘cogeneration’’, ‘‘dry flue gas
desulfurization technology ‘‘, ‘‘electric
utility company’’, ‘‘emergency
condition’’, ‘‘emission rate period’’,
‘‘gross output’’, ‘‘interconnected’’, ‘‘net
system capacity’’, ‘‘principal company’’,
‘‘responsible official’’, ‘‘spare flue gas
desulfurization system module’’,
‘‘spinning reserve’’, ‘‘system emergency
reserves’’, and ‘‘system load’’.
■
§ 60.41Da
Definitions.
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*
Affirmative defense means, in the
context of an enforcement proceeding, a
response or defense put forward by a
defendant, regarding which the
defendant has the burden of proof, and
the merits of which are independently
and objectively evaluated in a judicial
or administrative proceeding.
*
*
*
*
*
Boiler operating day for units
constructed, reconstructed, or modified
before February 29, 2005, means a 24hour period during which fossil fuel is
combusted in a steam-generating unit
for the entire 24 hours. For units
constructed, reconstructed, or modified
after February 28, 2005, boiler operating
day means a 24-hour period between 12
midnight and the following midnight
during which any fuel is combusted at
any time in the steam-generating unit. It
is not necessary for fuel to be combusted
the entire 24-hour period.
*
*
*
*
*
Combined heat and power, also
known as ‘‘cogeneration,’’ means a
steam-generating unit that
simultaneously produces both electric
(and mechanical) and useful thermal
energy from the same primary energy
source.
*
*
*
*
*
Gaseous fuel means any fuel that is
present as a gas at standard conditions
and includes, but is not limited to,
natural gas, refinery fuel gas, process
gas, coke-oven gas, synthetic gas, and
gasified coal.
*
*
*
*
*
Gross energy output means:
(1) For facilities constructed,
reconstructed, or modified before May
4, 2011, the gross electrical or
mechanical output from the affected
facility plus 75 percent of the useful
thermal output measured relative to ISO
conditions that is not used to generate
additional electrical or mechanical
output or to enhance the performance of
the unit (i.e., steam delivered to an
industrial process);
(2) For facilities constructed,
reconstructed, or modified after May 3,
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2011, the gross electrical or mechanical
output from the affected facility minus
any electricity used to power the
feedwater pumps and any associated gas
compressors (air separation unit main
compressor, oxygen compressor, and
nitrogen compressor) plus 75 percent of
the useful thermal output measured
relative to ISO conditions that is not
used to generate additional electrical or
mechanical output or to enhance the
performance of the unit (i.e., steam
delivered to an industrial process);
(3) For combined heat and power
facilities constructed, reconstructed, or
modified after May 3, 2011, the gross
electrical or mechanical output from the
affected facility divided by 0.95 minus
any electricity used to power the
feedwater pumps and any associated gas
compressors (air separation unit main
compressor, oxygen compressor, and
nitrogen compressor) plus 75 percent of
the useful thermal output measured
relative to ISO conditions that is not
used to generate additional electrical or
mechanical output or to enhance the
performance of the unit (i.e., steam
delivered to an industrial process);
(4) For a IGCC electric utility
generating unit that coproduces
chemicals constructed, reconstructed, or
modified after May 3, 2011, the gross
useful work performed is the gross
electrical or mechanical output from the
unit minus electricity used to power the
feedwater pumps and any associated gas
compressors (air separation unit main
compressor, oxygen compressor, and
nitrogen compressor) that are associated
with power production plus 75 percent
of the useful thermal output measured
relative to ISO conditions that is not
used to generate additional electrical or
mechanical output or to enhance the
performance of the unit (i.e., steam
delivered to an industrial process).
Auxiliary loads that are associated with
power production are determined based
on the energy in the coproduced
chemicals compared to the energy of the
syngas combusted in combustion
turbine engine and associated duct
burners.
*
*
*
*
*
Integrated gasification combined
cycle electric utility steam generating
unit or IGCC electric utility steam
generating unit means an electric utility
combined cycle gas turbine that is
designed to burn fuels containing 50
percent (by heat input) or more solidderived fuel not meeting the definition
of natural gas. The Administrator may
waive the 50 percent solid-derived fuel
requirement during periods of the
gasification system construction or
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repair. No solid fuel is directly burned
in the unit during operation.
*
*
*
*
*
Natural gas means a fluid mixture of
hydrocarbons (e.g., methane, ethane, or
propane), composed of at least 70
percent methane by volume or that has
a gross calorific value between 35 and
41 megajoules (MJ) per dry standard
cubic meter (950 and 1,100 Btu per dry
standard cubic foot), that maintains a
gaseous state under ISO conditions. In
addition, natural gas contains 20.0
grains or less of total sulfur per 100
standard cubic feet. Finally, natural gas
does not include the following gaseous
fuels: landfill gas, digester gas, refinery
gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven
gas, or any gaseous fuel produced in a
process which might result in highly
variable sulfur content or heating value.
Net energy output means the gross
energy output minus the parasitic load
associated with power production.
Parasitic load includes, but is not
limited to, the power required to operate
the equipment used for fuel delivery
systems, air pollution control systems,
wastewater treatment systems, ash
handling and disposal systems, and
other controls (i.e., pumps, fans,
compressors, motors, instrumentation,
and other ancillary equipment required
to operate the affected facility).
*
*
*
*
*
Out-of-control period means any
period beginning with the quadrant
corresponding to the completion of a
daily calibration error, linearity check,
or quality assurance audit that indicates
that the instrument is not measuring
and recording within the applicable
performance specifications and ending
with the quadrant corresponding to the
completion of an additional calibration
error, linearity check, or quality
assurance audit following corrective
action that demonstrates that the
instrument is measuring and recording
within the applicable performance
specifications.
Petroleum for facilities constructed,
reconstructed, or modified before May
4, 2011, means crude oil or a fuel
derived from crude oil, including, but
not limited to, distillate oil, and residual
oil. For units constructed,
reconstructed, or modified after May 3,
2011, petroleum means crude oil or a
fuel derived from crude oil, including,
but not limited to, distillate oil, residual
oil, and petroleum coke.
Petroleum coke, also known as
‘‘petcoke,’’ means a carbonization
product of high-boiling hydrocarbon
fractions obtained in petroleum
processing (heavy residues). Petroleum
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coke is typically derived from oil
refinery coker units or other cracking
processes.
Potential combustion concentration
means the theoretical emissions
(nanograms per joule (ng/J), lb/MMBtu
heat input) that would result from
combustion of a fuel in an uncleaned
state without emission control systems.
For sulfur dioxide (SO2) the potential
combustion concentration is determined
under § 60.50Da(c).
*
*
*
*
*
Steam generating unit for facilities
constructed, reconstructed, or modified
before May 4, 2011, means any furnace,
boiler, or other device used for
combusting fuel for the purpose of
producing steam (including fossil-fuelfired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included). For
units constructed, reconstructed, or
modified after May 3, 2011, steam
generating unit means any furnace,
boiler, or other device used for
combusting fuel for the purpose of
producing steam (including fossil-fuelfired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included) plus
any integrated combustion turbines and
fuel cells.
*
*
*
*
*
■ 13. Section 60.42Da is revised to read
as follows:
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§ 60.42Da
(PM).
Standards for particulate matter
(a) Except as provided in paragraph (f)
of this section, on and after the date on
which the initial performance test is
completed or required to be completed
under § 60.8, whichever date comes
first, an owner or operator of an affected
facility shall not cause to be discharged
into the atmosphere from any affected
facility for which construction,
reconstruction, or modification
commenced before March 1, 2005, any
gases that contain PM in excess of 13
ng/J (0.030 lb/MMBtu) heat input.
(b) Except as provided in paragraphs
(b)(1) and (b)(2) of this section, on and
after the date the initial PM performance
test is completed or required to be
completed under § 60.8, whichever date
comes first, an owner or operator of an
affected facility shall not cause to be
discharged into the atmosphere any
gases which exhibit greater than 20
percent opacity (6-minute average),
except for one 6-minute period per hour
of not more than 27 percent opacity.
(1) An owner or operator of an
affected facility that elects to install,
calibrate, maintain, and operate a
continuous emissions monitoring
system (CEMS) for measuring PM
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emissions according to the requirements
of this subpart is exempt from the
opacity standard specified in this
paragraph (b) of this section.
(2) An owner or operator of an
affected facility that combusts only
natural gas is exempt from the opacity
standard specified in paragraph (b) of
this section.
(c) Except as provided in paragraphs
(d) and (f) of this section, on and after
the date on which the initial
performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
commenced construction,
reconstruction, or modification after
February 28, 2005, but before May 4,
2011, shall cause to be discharged into
the atmosphere from that affected
facility any gases that contain PM in
excess of either:
(1) 18 ng/J (0.14 lb/MWh) gross energy
output; or
(2) 6.4 ng/J (0.015 lb/MMBtu) heat
input derived from the combustion of
solid, liquid, or gaseous fuel.
(d) As an alternative to meeting the
requirements of paragraph (c) of this
section, the owner or operator of an
affected facility for which construction,
reconstruction, or modification
commenced after February 28, 2005, but
before May 4, 2011, may elect to meet
the requirements of this paragraph. On
and after the date on which the initial
performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility shall
cause to be discharged into the
atmosphere from that affected facility
any gases that contain PM in excess of:
(1) 13 ng/J (0.030 lb/MMBtu) heat
input derived from the combustion of
solid, liquid, or gaseous fuel, and
(2) For an affected facility that
commenced construction or
reconstruction, 0.1 percent of the
combustion concentration determined
according to the procedure in
§ 60.48Da(o)(5) (99.9 percent reduction)
when combusting solid, liquid, or
gaseous fuel, or
(3) For an affected facility that
commenced modification, 0.2 percent of
the combustion concentration
determined according to the procedure
in § 60.48Da(o)(5) (99.8 percent
reduction) when combusting solid,
liquid, or gaseous fuel.
(e) Except as provided in paragraph (f)
of this section, the owner or operator of
an affected facility that commenced
construction, reconstruction, or
modification commenced after May 3,
2011, shall meet the requirements
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specified in paragraphs (e)(1) and (2) of
this section.
(1) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator shall cause to be discharged
into the atmosphere from that affected
facility at all times except during
periods of startup and shutdown, any
gases that contain PM in excess of the
applicable emissions limit specified in
paragraphs (e)(1)(i) or (ii) of this section.
(i) For an affected facility which
commenced construction or
reconstruction, any gases that contain
PM in excess of either:
(A) 11 ng/J (0.090 lb/MWh) gross
energy output; or
(B) 12 ng/J (0.097 lb/MWh) net energy
output.
(ii) For an affected facility which
commenced modification, any gases that
contain PM in excess of 13 ng/J (0.015
lb/MMBtu) heat input.
(2) During periods of startup and
shutdown, the owner or operator shall
meet the work practice standards
specified in Table 3 to subpart UUUUU
of part 63.
(f) An owner or operator of an affected
facility that meets the conditions in
either paragraphs (f)(1) or (2) of this
section is exempt from the PM
emissions limits in this section.
(1) The affected facility combusts only
gaseous or liquid fuels (excluding
residual oil) with potential SO2
emissions rates of 26 ng/J (0.060 lb/
MMBtu) or less, and that does not use
a post-combustion technology to reduce
emissions of SO2 or PM.
(2) The affected facility is operated
under a PM commercial demonstration
permit issued by the Administrator
according to the provisions of § 60.47Da.
■ 14. Section 60.43Da is amended as
follows:
■ a. The section heading is revised.
■ b. By revising paragraphs (a)(1) and
(2).
■ c. By adding paragraphs (a)(3) and (4).
■ d. By removing and reserving
paragraph (c).
■ e. By revising paragraph (f).
■ f. By revising paragraph (i).
■ g. By revising paragraph (k).
■ h. By adding paragraph (l).
■ i. By adding paragraph (m).
§ 60.43Da
(SO2).
Standards for sulfur dioxide
(a) * * *
(1) 520 ng/J (1.20 lb/MMBtu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction);
(2) 30 percent of the potential
combustion concentration (70 percent
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srobinson on DSK4SPTVN1PROD with RULES2
reduction), when emissions are less
than 260 ng/J (0.60 lb/MMBtu) heat
input;
(3) 180 ng/J (1.4 lb/MWh) gross energy
output; or
(4) 65 ng/J (0.15 lb/MMBtu) heat
input.
*
*
*
*
*
(f) The SO2 standards under this
section do not apply to an owner or
operator of an affected facility that is
operated under an SO2 commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.47Da.
*
*
*
*
*
(i) Except as provided in paragraphs
(j) and (k) of this section, on and after
the date on which the initial
performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility for which
construction, reconstruction, or
modification commenced after February
28, 2005, but before May 4, 2011, shall
cause to be discharged into the
atmosphere from that affected facility,
any gases that contain SO2 in excess of
the applicable emissions limit specified
in paragraphs (i)(1) through (3) of this
section.
(1) For an affected facility which
commenced construction, any gases that
contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy
output; or
(ii) 5 percent of the potential
combustion concentration (95 percent
reduction).
(2) For an affected facility which
commenced reconstruction, any gases
that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy
output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat
input; or
(iii) 5 percent of the potential
combustion concentration (95 percent
reduction).
(3) For an affected facility which
commenced modification, any gases that
contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy
output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat
input; or
(iii) 10 percent of the potential
combustion concentration (90 percent
reduction).
*
*
*
*
*
(k) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility located in
a noncontinental area for which
construction, reconstruction, or
modification commenced after February
28, 2005, but before May 4, 2011, shall
cause to be discharged into the
atmosphere from that affected facility
any gases that contain SO2 in excess of
the applicable emissions limit specified
in paragraphs (k)(1) and (2) of this
section.
(1) For an affected facility that burns
solid or solid-derived fuel, the owner or
operator shall not cause to be
discharged into the atmosphere any
gases that contain SO2 in excess of 520
ng/J (1.2 lb/MMBtu) heat input.
(2) For an affected facility that burns
other than solid or solid-derived fuel,
the owner or operator shall not cause to
be discharged into the atmosphere any
gases that contain SO2 in excess of 230
ng/J (0.54 lb/MMBtu) heat input.
(l) Except as provided in paragraphs
(j) and (m) of this section, on and after
the date on which the initial
performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility for which
construction, reconstruction, or
modification commenced after May 3,
2011, shall cause to be discharged into
the atmosphere from that affected
facility, any gases that contain SO2 in
excess of the applicable emissions limit
specified in paragraphs (l)(1) and (2) of
this section.
(1) For an affected facility which
commenced construction or
reconstruction, any gases that contain
SO2 in excess of either:
(i) 130 ng/J (1.0 lb/MWh) gross energy
output; or
(ii) 140 ng/J (1.2 lb/MWh) net energy
output; or
(iii) 3 percent of the potential
combustion concentration (97 percent
reduction).
(2) For an affected facility which
commenced modification, any gases that
contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy
output; or
(ii) 10 percent of the potential
combustion concentration (90 percent
reduction).
(m) On and after the date on which
the initial performance test is completed
or required to be completed under
§ 60.8, whichever date comes first, no
owner or operator of an affected facility
located in a noncontinental area for
which construction, reconstruction, or
modification commenced after May 3,
2011, shall cause to be discharged into
the atmosphere from that affected
facility any gases that contain SO2 in
excess of the applicable emissions limit
specified in paragraphs (m)(1) and (2) of
this section.
(1) For an affected facility that burns
solid or solid-derived fuel, the owner or
operator shall not cause to be
discharged into the atmosphere any
gases that contain SO2 in excess of 520
ng/J (1.2 lb/MMBtu) heat input.
(2) For an affected facility that burns
other than solid or solid-derived fuel,
the owner or operator shall not cause to
be discharged into the atmosphere any
gases that contain SO2 in excess of 230
ng/J (0.54 lb/MMBtu) heat input.
■ 15. Section 60.44Da is revised to read
as follows:
§ 60.44Da
(NOX).
Standards for nitrogen oxides
(a) Except as provided in paragraph
(h) of this section, on and after the date
on which the initial performance test is
completed or required to be completed
under § 60.8, whichever date comes
first, no owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility for which
construction, reconstruction, or
modification commenced before July 10,
1997 any gases that contain NOX
(expressed as NO2) in excess of the
applicable emissions limit in paragraphs
(a)(1) and (2) of this section.
(1) The owner or operator shall not
cause to be discharged into the
atmosphere any gases that contain NOX
in excess of the emissions limit listed in
the following table as applicable to the
fuel type combusted and as determined
on a 30-boiler operating day rolling
average basis.
Emission limit for heat
input
Fuel type
ng/J
Gaseous fuels:
Coal-derived fuels .....................................................................................................................................................
All other fuels ............................................................................................................................................................
Liquid fuels:
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lb/MMBtu
210
86
0.50
0.20
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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
Emission limit for heat
input
Fuel type
ng/J
Coal-derived fuels .....................................................................................................................................................
Shale oil ....................................................................................................................................................................
All other fuels ............................................................................................................................................................
Solid fuels:
Coal-derived fuels .....................................................................................................................................................
Any fuel containing more than 25%, by weight, coal refuse ...................................................................................
Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace 2 ...........................................................................................................
Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit 2 ............
Subbituminous coal .........................................................................................................................................................
Bituminous coal ...............................................................................................................................................................
Anthracite coal .................................................................................................................................................................
All other fuels ...................................................................................................................................................................
lb/MMBtu
210
210
130
0.50
0.50
0.30
210
(1)
0.50
(1)
340
260
210
260
260
260
0.80
0.60
0.50
0.60
0.60
0.60
1 Exempt
2 Any
from NOX standards and NOX monitoring requirements.
fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel.
emissions limit (En) is determined by
proration using the following formula:
Where:
contain NOX in excess of 200 ng/J (1.6
lb/MWh) gross energy output.
(2) For an affected facility which
commenced reconstruction, any gases
that contain NOX in excess of 65 ng/J
(0.15 lb/MMBtu) heat input.
(e) Except as provided in paragraphs
(f) and (h) of this section, on and after
the date on which the initial
performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
commenced construction,
reconstruction, or modification after
February 28, 2005 but before May 4,
2011, shall cause to be discharged into
the atmosphere from that affected
facility any gases that contain NOX
(expressed as NO2) in excess of the
applicable emissions limit specified in
paragraphs (e)(1) through (3) of this
section as determined on a 30-boiler
operating day rolling average basis.
(1) For an affected facility which
commenced construction, any gases that
contain NOX in excess of 130 ng/J (1.0
lb/MWh) gross energy output.
(2) For an affected facility which
commenced reconstruction, any gases
that contain NOX in excess of either:
(i) 130 ng/J (1.0 lb/MWh) gross energy
output; or
(ii) 47 ng/J (0.11 lb/MMBtu) heat
input.
(3) For an affected facility which
commenced modification, any gases that
contain NOX in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy
output; or
srobinson on DSK4SPTVN1PROD with RULES2
En = Applicable NOX emissions limit when
multiple fuels are combusted
simultaneously (ng/J heat input);
w = Percentage of total heat input derived
from the combustion of fuels subject to
the 86 ng/J heat input standard;
x = Percentage of total heat input derived
from the combustion of fuels subject to
the 130 ng/J heat input standard;
y = Percentage of total heat input derived
from the combustion of fuels subject to
the 210 ng/J heat input standard;
z = Percentage of total heat input derived
from the combustion of fuels subject to
the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered
from the combustion of fuels subject to
the 340 ng/J heat input standard.
(b) [Reserved]
(c) [Reserved]
(d) Except as provided in paragraph
(h) of this section, on and after the date
on which the initial performance test is
completed or required to be completed
under § 60.8, whichever date comes
first, no owner or operator of an affected
facility that commenced construction,
reconstruction, or modification after
July 9, 1997, but before March 1, 2005,
shall cause to be discharged into the
atmosphere from that affected facility
any gases that contain NOX (expressed
as NO2) in excess of the applicable
emissions limit specified in paragraphs
(d)(1) and (2) of this section as
determined on a 30-boiler operating day
rolling average basis.
(1) For an affected facility which
commenced construction, any gases that
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(ii) 65 ng/J (0.15 lb/MMBtu) heat
input.
(f) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8,
whichever date comes first, the owner
or operator of an IGCC electric utility
steam generating unit subject to the
provisions of this subpart and for which
construction, reconstruction, or
modification commenced after February
28, 2005 but before May 4, 2011, shall
meet the requirements specified in
paragraphs (f)(1) through (3) of this
section.
(1) Except as provided for in
paragraphs (f)(2) and (3) of this section,
the owner or operator shall not cause to
be discharged into the atmosphere any
gases that contain NOX (expressed as
NO2) in excess of 130 ng/J (1.0 lb/MWh)
gross energy output.
(2) When burning liquid fuel
exclusively or in combination with
solid-derived fuel such that the liquid
fuel contributes 50 percent or more of
the total heat input to the combined
cycle combustion turbine, the owner or
operator shall not cause to be
discharged into the atmosphere any
gases that contain NOX (expressed as
NO2) in excess of 190 ng/J (1.5 lb/MWh)
gross energy output.
(3) In cases when during a 30-boiler
operating day rolling average
compliance period liquid fuel is burned
in such a manner to meet the conditions
in paragraph (f)(2) of this section for
only a portion of the clock hours in the
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(2) When two or more fuels are
combusted simultaneously in an
affected facility, the applicable
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
srobinson on DSK4SPTVN1PROD with RULES2
30-day compliance period, the owner or
operator shall not cause to be
discharged into the atmosphere any
gases that contain NOX (expressed as
NO2) in excess of the computed
weighted-average emissions limit based
on the proportion of gross energy output
(in MWh) generated during the
compliance period for each of emissions
limits in paragraphs (f)(1) and (2) of this
section.
(g) Except as provided in paragraphs
(h) of this section and § 60.45Da, on and
after the date on which the initial
performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
commenced construction,
reconstruction, or modification after
May 3, 2011, shall cause to be
discharged into the atmosphere from
that affected facility any gases that
contain NOX (expressed as NO2) in
excess of the applicable emissions limit
specified in paragraphs (g)(1) through
(3) of this section.
(1) For an affected facility which
commenced construction or
reconstruction, any gases that contain
NOX in excess of either:
(i) 88 ng/J (0.70 lb/MWh) gross energy
output; or
(ii) 95 ng/J (0.76 lb/MWh) net energy
output.
(2) For an affected facility which
commenced construction or
reconstruction and that burns 75
percent or more coal refuse (by heat
input) on a 12-month rolling average
basis, any gases that contain NOX in
excess of either:
(i) 110 ng/J (0.85 lb/MWh) gross
energy output; or
(ii) 120 ng/J (0.92 lb/MWh) net energy
output.
(3) For an affected facility which
commenced modification, any gases that
contain NOX in excess of 140 ng/J (1.1
lb/MWh) gross energy output.
(h) The NOX emissions limits under
this section do not apply to an owner or
operator of an affected facility which is
operating under a commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.47Da.
■ 16. Section 60.45Da is revised to read
as follows:
§ 60.45Da Alternative standards for
combined nitrogen oxides (NOX) and
carbon monoxide (CO).
(a) The owner or operator of an
affected facility that commenced
construction, reconstruction, or
modification after May 3, 2011 as
alternate to meeting the applicable NOX
emissions limits specified in § 60.44Da
may elect to meet the applicable
standards for combined NOX and CO
specified in paragraph (b) of this
section.
(b) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8
no owner or operator of an affected
facility that commenced construction,
reconstruction, or modification after
May 3, 2011, shall cause to be
discharged into the atmosphere from
that affected facility any gases that
contain NOX (expressed as NO2) plus
CO in excess of the applicable emissions
limit specified in paragraphs (b)(1)
through (3) of this section as determined
on a 30-boiler operating day rolling
average basis.
(1) For an affected facility which
commenced construction or
reconstruction, any gases that contain
NOX plus CO in excess of either:
(i) 140 ng/J (1.1 lb/MWh) gross energy
output; or
(ii) 150 ng/J (1.2 lb/MWh) net energy
output.
(2) For an affected facility which
commenced construction or
reconstruction and that burns 75
percent or more coal refuse (by heat
input) on a 12-month rolling average
basis, any gases that contain NOX plus
CO in excess of either:
(i) 160 ng/J (1.3 lb/MWh) gross energy
output; or
(ii) 170 ng/J (1.4 lb/MWh) net energy
output.
(3) For an affected facility which
commenced modification, any gases that
contain NOX plus CO in excess of 190
ng/J (1.5 lb/MWh) gross energy output.
■ 17. Section 60.47Da is amended as
follows:
■ a. By revising paragraph (c).
■ b. By adding paragraph (f).
■ c. By adding paragraph (g).
■ d. By adding paragraph (h).
■ e. By adding paragraph (i).
§ 60.47Da
permit.
Commercial demonstration
*
*
*
*
*
(c) An owner or operator of an
affected facility that uses fluidized bed
combustion (atmospheric or
pressurized) and who is issued a
commercial demonstration permit by
the Administrator is not subject to the
SO2 emission reduction requirements
under § 60.43Da(a) but must, as a
minimum, reduce SO2 emissions to 15
percent of the potential combustion
concentration (85 percent reduction) on
a 30-day rolling average basis and to less
than 520 ng/J (1.20 lb/MMBtu) heat
input on a 30-day rolling average basis.
*
*
*
*
*
(f) An owner or operator of an affected
facility that uses a pressurized fluidized
bed or a multi-pollutant emissions
controls system who is issued a
commercial demonstration permit by
the Administrator is not subject to the
total PM emission reduction
requirements under § 60.42Da but must,
as a minimum, reduce PM emissions to
less than 6.4 ng/J (0.015 lb/MMBtu) heat
input.
(g) An owner or operator of an
affected facility that uses a pressurized
fluidized bed or a multi-pollutant
emissions controls system who is issued
a commercial demonstration permit by
the Administrator is not subject to the
SO2 standards or emission reduction
requirements under § 60.43Da but must,
as a minimum, reduce SO2 emissions to
5 percent of the potential combustion
concentration (95 percent reduction) or
to less than 180 ng/J (1.4 lb/MWh) gross
energy output on a 30-boiler operating
day rolling average basis.
(h) An owner or operator of an
affected facility that uses a pressurized
fluidized bed or a multi-pollutant
emissions control system or advanced
combustion controls who is issued a
commercial demonstration permit by
the Administrator is not subject to the
NOX standards or emission reduction
requirements under § 60.44Da but must,
as a minimum, reduce NOX emissions to
less than 130 ng/J (1.0 lb/MWh) or the
combined NOX plus CO emissions to
less than 180 ng/J (1.4 lb/MWh) gross
energy output on a 30-boiler operating
day rolling average basis.
(i) Commercial demonstration permits
may not exceed the following equivalent
MW electrical generation capacity for
any one technology category listed in
the following table.
Technology
Pollutant
Multi-pollutant Emission Control ........................................................................................................................................
SO2 ..........
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9453
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Equivalent
electrical
capacity
(MW electrical output)
1,000
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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
Technology
Pollutant
Multi-pollutant Emission Control ........................................................................................................................................
Multi-pollutant Emission Control ........................................................................................................................................
Pressurized Fluidized Bed Combustion ............................................................................................................................
Pressurized Fluidized Bed Combustion ............................................................................................................................
Pressurized Fluidized Bed Combustion ............................................................................................................................
Advanced Combustion Controls ........................................................................................................................................
NOX .........
PM ...........
SO2 ..........
NOX .........
PM ...........
NOX .........
18. Section 60.48Da is amended as
follows:
■ a. By revising paragraphs (a) through
(g).
■ b. By revising paragraph (i).
■ c. By revising paragraph (k)(1)(i).
■ d. By revising paragraph (k)(2)(i).
■ e. By revising paragraph (k)(2)(iv).
■ f. By removing and reserving
paragraph (l).
■ g. By revising paragraph (m).
■ h. By revising paragraph (n).
■ i. By revising paragraphs (p)(5), (7),
and (8).
■ j. By adding paragraph (r).
■ k. By adding paragraph (s).
■
srobinson on DSK4SPTVN1PROD with RULES2
§ 60.48Da
Compliance provisions.
(a) For affected facilities for which
construction, modification, or
reconstruction commenced before May
4, 2011, the applicable PM emissions
limit and opacity standard under
§ 60.42Da, SO2 emissions limit under
§ 60.43Da, and NOX emissions limit
under § 60.44Da apply at all times
except during periods of startup,
shutdown, or malfunction. For affected
facilities for which construction,
modification, or reconstruction
commenced after May 3, 2011, the
applicable SO2 emissions limit under
§ 60.43Da, NOX emissions limit under
§ 60.44Da, and NOX plus CO emissions
limit under § 60.45Da apply at all times.
The applicable PM emissions limit and
opacity standard under § 60.42Da apply
at all times except during periods of
startup and shutdown.
(b) After the initial performance test
required under § 60.8, compliance with
the applicable SO2 emissions limit and
percentage reduction requirements
under § 60.43Da, NOX emissions limit
under § 60.44Da, and NOX plus CO
emissions limit under § 60.45Da is
based on the average emission rate for
30 successive boiler operating days. A
separate performance test is completed
at the end of each boiler operating day
after the initial performance test, and a
new 30-boiler operating day rolling
average emission rate for both SO2, NOX
or NOX plus CO as applicable, and a
new percent reduction for SO2 are
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Jkt 226001
calculated to demonstrate compliance
with the standards.
(c) For the initial performance test
required under § 60.8, compliance with
the applicable SO2 emissions limits and
percentage reduction requirements
under § 60.43Da, the NOX emissions
limits under § 60.44Da, and the NOX
plus CO emissions limits under
§ 60.45Da is based on the average
emission rates for SO2, NOX, CO, and
percent reduction for SO2 for the first 30
successive boiler operating days. The
initial performance test is the only test
in which at least 30 days prior notice is
required unless otherwise specified by
the Administrator. The initial
performance test is to be scheduled so
that the first boiler operating day of the
30 successive boiler operating days is
completed within 60 days after
achieving the maximum production rate
at which the affected facility will be
operated, but not later than 180 days
after initial startup of the facility.
(d) For affected facilities for which
construction, modification, or
reconstruction commenced before May
4, 2011, compliance with applicable 30boiler operating day rolling average SO2
and NOX emissions limits is determined
by calculating the arithmetic average of
all hourly emission rates for SO2 and
NOX for the 30 successive boiler
operating days, except for data obtained
during startup, shutdown, or
malfunction. For affected facilities for
which construction, modification, or
reconstruction commenced after May 3,
2011, compliance with applicable 30boiler operating day rolling average SO2
and NOX emissions limits is determined
by dividing the sum of the SO2 and NOX
emissions for the 30 successive boiler
operating days by the sum of the gross
energy output or net energy output, as
applicable, for the 30 successive boiler
operating days.
(e) For affected facilities for which
construction, modification, or
reconstruction commenced before May
4, 2011, compliance with applicable
SO2 percentage reduction requirements
is determined based on the average inlet
and outlet SO2 emission rates for the 30
successive boiler operating days. For
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Equivalent
electrical
capacity
(MW electrical output)
1,000
1,000
1,000
1,000
1,000
1,000
affected facilities for which
construction, modification, or
reconstruction commenced after May 3,
2011, compliance with applicable SO2
percentage reduction requirements is
determined based on the ‘‘as fired’’ total
potential emissions and the total outlet
SO2 emissions for the 30 successive
boiler operating days.
(f) For affected facilities for which
construction, modification, or
reconstruction commenced before May
4, 2011, compliance with applicable
daily average PM emissions limits is
determined by calculating the
arithmetic average of all hourly
emission rates for PM each boiler
operating day, except for data obtained
during startup, shutdown, and
malfunction. Daily averages are only
calculated for boiler operating days that
have non-out-of-control data for at least
18 hours of unit operation during which
the standard applies. Instead, all of the
non-out-of-control hourly emission rates
of the operating day(s) not meeting the
minimum 18 hours non-out-of-control
data daily average requirement are
averaged with all of the non-out-ofcontrol hourly emission rates of the next
boiler operating day with 18 hours or
more of non-out-of-control PM CEMS
data to determine compliance. For
affected facilities for which
construction, modification, or
reconstruction commenced after May 3,
2011, compliance with applicable daily
average PM emissions limits is
determined by dividing the sum of the
PM emissions for the 30 successive
boiler operating days by the sum of the
gross useful output or net energy output,
as applicable, for the 30 successive
boiler operating days.
(g) For affected facilities for which
construction, modification, or
reconstruction commenced after May 3,
2011, compliance with applicable 30boiler operating day rolling average NOX
plus CO emissions limit is determined
by dividing the sum of the NOX plus CO
emissions for the 30 successive boiler
operating days by the sum of the gross
energy output or net energy output, as
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9455
flow rate (measured in scfh, according
to the provisions of § 60.49Da(l) or
§ 60.49Da(m)), divided by the average
hourly gross energy output (measured
according to the provisions of
§ 60.49Da(k)) or the average hourly net
energy output, as applicable.
Alternatively, for oil-fired and gas-fired
units, NOX emissions may be calculated
by multiplying the hourly NOX emission
rate in lb/MMBtu (measured by the
CEMS required under § 60.49Da(c) and
(d)), by the hourly heat input rate
(measured according to the provisions
of § 60.49Da(n)), and dividing the result
by the average gross energy output
(measured according to the provisions
of § 60.49Da(k)) or the average hourly
net energy output, as applicable.
(k) * * *
(1) * * *
(i) The emission rate (E) of NOX shall
be computed using Equation 2 in this
section:
Where:
E = Emission rate of NOX from the duct
burner, ng/J (lb/MWh) gross energy
output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/
dscm (lb/dscf);
Cte = Average hourly concentration of NOX in
the turbine exhaust upstream from duct
burner, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of
exhaust gas from steam generating unit,
dscm/h (dscf/h);
Qte = Average hourly volumetric flow rate of
exhaust gas from combustion turbine,
dscm/h (dscf/h);
Osg = Average hourly gross energy output
from steam generating unit, J/h (MW);
and
h = Average hourly fraction of the total heat
input to the steam generating unit
derived from the combustion of fuel in
the affected duct burner.
Where:
E = Emission rate of NOX from the duct
burner, ng/J (lb/MWh) gross energy
output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/
dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of
exhaust gas from steam generating unit,
dscm/h (dscf/h); and
Occ = Average hourly gross energy output
from entire combined cycle unit, J/h
(MW).
*
*
*
*
(iv) The owner or operator may, in
lieu of installing, operating, and
recording data from the continuous flow
monitoring system specified in
§ 60.49Da(l), determine the mass rate
(lb/h) of NOX emissions by installing,
operating, and maintaining continuous
fuel flowmeters following the
appropriate measurements procedures
specified in appendix D of part 75 of
this chapter. If this compliance option is
selected, the emission rate (E) of NOX
shall be computed using Equation 4 in
this section:
Where:
E = Emission rate of NOX from the duct
burner, ng/J (lb/MWh) gross energy
output;
ERsg = Average hourly emission rate of NOX
exiting the steam generating unit heat
input calculated using appropriate F
factor as described in Method 19 of
appendix A of this part, ng/J (lb/
MMBtu);
Hcc = Average hourly heat input rate of entire
combined cycle unit, J/h (MMBtu/h); and
Occ = Average hourly gross energy output
from entire combined cycle unit, J/h
(MW).
(l)(1)(i), (l)(1)(ii), or (l)(2). The owner or
operator shall calculate SO2 emissions
as 1.660 × 10¥7 lb/scf-ppm times the
average hourly SO2 output
concentration in ppm (measured
according to the provisions of
§ 60.49Da(b)), times the average hourly
flow rate (measured according to the
provisions of § 60.49Da(l) or
§ 60.49Da(m)), divided by the average
hourly gross energy output (measured
according to the provisions of
§ 60.49Da(k)) or the average hourly net
energy output, as applicable.
Alternatively, for oil-fired and gas-fired
units, SO2 emissions may be calculated
by multiplying the hourly SO2 emission
rate (in lb/MMBtu), measured by the
CEMS required under § 60.49Da, by the
hourly heat input rate (measured
according to the provisions of
§ 60.49Da(n)), and dividing the result by
the average gross energy output
(measured according to the provisions
of § 60.49Da(k)) or the average hourly
net energy output, as applicable.
(n) Compliance provisions for sources
subject to § 60.42Da(c)(1) or (e)(1)(i).
The owner or operator shall calculate
PM emissions by multiplying the
average hourly PM output concentration
(measured according to the provisions
of § 60.49Da(t)), by the average hourly
flow rate (measured according to the
provisions of § 60.49Da(l) or
§ 60.49Da(m)), and dividing by the
average hourly gross energy output
(measured according to the provisions
*
*
*
*
(m) Compliance provisions for
sources subject to § 60.43Da(i)(1)(i),
(i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), (j)(3)(i),
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*
*
*
*
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ER16FE12.002</GPH>
(2) * * *
(i) The emission rate (E) of NOX shall
be computed using Equation 3 in this
section:
ER16FE12.001</GPH>
*
*
*
ER16FE12.000</GPH>
srobinson on DSK4SPTVN1PROD with RULES2
applicable, for the 30 successive boiler
operating days.
*
*
*
*
*
(i) Compliance provisions for sources
subject to § 60.44Da(d)(1), (e)(1),
(e)(2)(i), (e)(3)(i), (f), or (g). The owner or
operator shall calculate NOX emissions
as 1.194 × 10¥7 lb/scf-ppm times the
average hourly NOX output
concentration in ppm (measured
according to the provisions of
§ 60.49Da(c)), times the average hourly
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of § 60.49Da(k)) or the average hourly
net energy output, as applicable.
*
*
*
*
*
(p) * * *
(5) At a minimum, non-out-of-control
CEMS hourly averages shall be obtained
for 75 percent of all operating hours on
a 30-boiler operating day rolling average
basis. Beginning on January 1, 2012,
non-out-of-control CEMS hourly
averages shall be obtained for 90 percent
of all operating hours on a 30-boiler
operating day rolling average basis.
(i) At least two data points per hour
shall be used to calculate each 1-hour
arithmetic average.
(ii) [Reserved]
*
*
*
*
*
(7) All non-out-of-control CEMS data
shall be used in calculating average
emission concentrations even if the
minimum CEMS data requirements of
paragraph (j)(5) of this section are not
met.
(8) When PM emissions data are not
obtained because of CEMS breakdowns,
repairs, calibration checks, and zero and
span adjustments, emissions data shall
be obtained by using other monitoring
systems as approved by the
Administrator or EPA Reference Method
19 of appendix A of this part to provide,
as necessary, non-out-of-control
emissions data for a minimum of 90
percent (only 75 percent is required
prior to January 1, 2012) of all operating
hours per 30-boiler operating day rolling
average.
*
*
*
*
*
(r) Compliance provisions for sources
subject to § 60.45Da. To determine
compliance with the NOX plus CO
emissions limit, the owner or operator
shall use the procedures specified in
paragraphs (r)(1) through (3) of this
section.
(1) Calculate NOX emissions as 1.194
× 10¥7 lb/scf-ppm times the average
hourly NOX output concentration in
ppm (measured according to the
provisions of § 60.49Da(c)), times the
average hourly flow rate (measured in
scfh, according to the provisions of
§ 60.49Da(l) or § 60.49Da(m)), divided
by the average hourly gross energy
output (measured according to the
provisions of § 60.49Da(k)) or the
average hourly net energy output, as
applicable.
(2) Calculate CO emissions by
multiplying the average hourly CO
output concentration (measured
according to the provisions of
§ 60.49Da(u), by the average hourly flow
rate (measured according to the
provisions of § 60.49Da(l) or
§ 60.49Da(m)), and dividing by the
average hourly gross energy output
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(measured according to the provisions
of § 60.49Da(k)) or the average hourly
net energy output, as applicable.
(3) Calculate NOX plus CO emissions
by summing the NOX emissions results
from paragraph (r)(1) of this section plus
the CO emissions results from paragraph
(r)(2) of this section.
(s) Affirmative defense for exceedance
of emissions limit during malfunction.
In response to an action to enforce the
standards set forth in paragraph
§§ 60.42Da, 60.43Da, 60.44Da, and
60.45Da, you may assert an affirmative
defense to a claim for civil penalties for
exceedances of such standards that are
caused by malfunction, as defined at 40
CFR 60.2. Appropriate penalties may be
assessed, however, if you fail to meet
your burden of proving all of the
requirements in the affirmative defense
as specified in paragraphs (s)(1) and (2)
of this section. The affirmative defense
shall not be available for claims for
injunctive relief.
(1) To establish the affirmative
defense in any action to enforce such a
limit, you must timely meet the
notification requirements in paragraph
(s)(2) of this section, and must prove by
a preponderance of evidence that:
(i) The excess emissions:
(A) Were caused by a sudden,
infrequent, and unavoidable failure of
air pollution control and monitoring
equipment, process equipment, or a
process to operate in a normal or usual
manner; and
(B) Could not have been prevented
through careful planning, proper design,
or better operation and maintenance
practices; and
(C) Did not stem from any activity or
event that could have been foreseen and
avoided, or planned for; and
(D) Were not part of a recurring
pattern indicative of inadequate design,
operation, or maintenance; and
(ii) Repairs were made as
expeditiously as possible when the
applicable emissions limits were being
exceeded. Off-shift and overtime labor
were used, to the extent practicable to
make these repairs; and
(iii) The frequency, amount, and
duration of the excess emissions
(including any bypass) were minimized
to the maximum extent practicable
during periods of such emissions; and
(iv) If the excess emissions resulted
from a bypass of control equipment or
a process, then the bypass was
unavoidable to prevent loss of life,
personal injury, or severe property
damage; and
(v) All possible steps were taken to
minimize the impact of the excess
emissions on ambient air quality, the
environment, and human health; and
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(vi) All emissions monitoring and
control systems were kept in operation
if at all possible, consistent with safety
and good air pollution control practices;
and
(vii) All of the actions in response to
the excess emissions were documented
by properly signed, contemporaneous
operating logs; and
(viii) At all times, the facility was
operated in a manner consistent with
good practices for minimizing
emissions; and
(ix) A written root cause analysis has
been prepared, the purpose of which is
to determine, correct, and eliminate the
primary causes of the malfunction and
the excess emissions resulting from the
malfunction event at issue. The analysis
shall also specify, using best monitoring
methods and engineering judgment, the
amount of excess emissions that were
the result of the malfunction.
(2) Notification. The owner or
operator of the affected source
experiencing an exceedance of its
emission limit(s) during a malfunction
shall notify the Administrator by
telephone or facsimile (FAX)
transmission as soon as possible, but no
later than two business days after the
initial occurrence of the malfunction or,
if it is not possible to determine within
two business days whether the
malfunction caused or contributed to an
exceedance, no later than two business
days after the owner or operator knew
or should have known that the
malfunction caused or contributed to an
exceedance, but, in no event later than
two business days after the end of the
averaging period, if it wishes to avail
itself of an affirmative defense to civil
penalties for that malfunction. The
owner or operator seeking to assert an
affirmative defense shall also submit a
written report to the Administrator
within 45 days of the initial occurrence
of the exceedance of the standard in
§ 63.9991 to demonstrate, with all
necessary supporting documentation,
that it has met the requirements set forth
in paragraph (s)(1) of this section. The
owner or operator may seek an
extension of this deadline for up to 30
additional days by submitting a written
request to the Administrator before the
expiration of the 45 day period. Until a
request for an extension has been
approved by the Administrator, the
owner or operator is subject to the
requirement to submit such report
within 45 days of the initial occurrence
of the exceedance.
■ 19. Section 60.49Da is amended as
follows:
■ a. By revising paragraphs (a)(1) and
(2).
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b. By revising paragraph (a)(3)
introductory text.
■ c. By revising paragraph (a)(3)(ii).
■ d. By revising paragraph (a)(3)(iii)(B).
■ e. By adding paragraph (a)(4).
■ f. By revising paragraph (b)
introductory text.
■ g. By revising paragraph (b)(2).
■ h. By revising paragraph (e).
■ i. By revising paragraph (k)
introductory text.
■ j. By revising paragraph (k)(3).
■ k. By revising paragraph (l).
■ l. By removing and reserving
paragraph (p).
■ m. By removing and reserving
paragraph (q).
■ n. By removing and reserving
paragraph (r).
■ o. By revising paragraph (t).
■ p. By revising paragraph (u)(1)(iii).
■ q. By revising paragraph (v)(4).
■
srobinson on DSK4SPTVN1PROD with RULES2
§ 60.49Da
Emission monitoring.
(a) * * *
(1) Except as provided for in
paragraphs (a)(2) and (4) of this section,
the owner or operator of an affected
facility subject to an opacity standard,
shall install, calibrate, maintain, and
operate a COMS, and record the output
of the system, for measuring the opacity
of emissions discharged to the
atmosphere. If opacity interference due
to water droplets exists in the stack (for
example, from the use of an FGD
system), the opacity is monitored
upstream of the interference (at the inlet
to the FGD system). If opacity
interference is experienced at all
locations (both at the inlet and outlet of
the SO2 control system), alternate
parameters indicative of the PM control
system’s performance and/or good
combustion are monitored (subject to
the approval of the Administrator).
(2) As an alternative to the monitoring
requirements in paragraph (a)(1) of this
section, an owner or operator of an
affected facility that meets the
conditions in either paragraph (a)(2)(i),
(ii), (iii), or (iv) of this section may elect
to monitor opacity as specified in
paragraph (a)(3) of this section.
(i) The affected facility uses a fabric
filter (baghouse) to meet the standards
in § 60.42Da and a bag leak detection
system is installed and operated
according to the requirements in
paragraphs § 60.48Da(o)(4)(i) through
(v);
(ii) The affected facility burns only
gaseous or liquid fuels (excluding
residual oil) with potential SO2
emissions rates of 26 ng/J (0.060 lb/
MMBtu) or less, and does not use a postcombustion technology to reduce
emissions of SO2 or PM;
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(iii) The affected facility meets all of
the conditions specified in paragraphs
(a)(2)(iii)(A) through (C) of this section.
(A) No post-combustion technology
(except a wet scrubber) is used for
reducing PM, SO2, or CO emissions;
(B) Only natural gas, gaseous fuels, or
fuel oils that contain less than or equal
to 0.30 weight percent sulfur are
burned; and
(C) Emissions of CO discharged to the
atmosphere are maintained at levels less
than or equal to 1.4 lb/MWh on a boiler
operating day average basis as
demonstrated by the use of a CEMS
measuring CO emissions according to
the procedures specified in paragraph
(u) of this section; or
(iv) The affected facility uses an ESP
and uses an ESP predictive model to
monitor the performance of the ESP
developed in accordance and operated
according to the most current
requirements in section § 60.48Da of
this part.
(3) The owner or operator of an
affected facility that meets the
conditions in paragraph (a)(2) of this
section may, as an alternative to using
a COMS, elect to monitor visible
emissions using the applicable
procedures specified in paragraphs
(a)(3)(i) through (iv) of this section. The
opacity performance test requirement in
paragraph (a)(3)(i) must be conducted by
April 29, 2011, within 45 days after
stopping use of an existing COMS, or
within 180 days after initial startup of
the facility, whichever is later.
*
*
*
*
*
(ii) Except as provided in paragraph
(a)(3)(iii) or (iv) of this section, the
owner or operator shall conduct
subsequent Method 9 of appendix A–4
of this part performance tests using the
procedures in paragraph (a)(3)(i) of this
section according to the applicable
schedule in paragraphs (a)(3)(ii)(A)
through (a)(3)(ii)(C) of this section, as
determined by the most recent Method
9 of appendix A–4 of this part
performance test results.
(A) If the maximum 6-minute average
opacity is less than or equal to 5
percent, a subsequent Method 9 of
appendix A–4 of this part performance
test must be completed within 12
calendar months from the date that the
most recent performance test was
conducted or within 45 days of the next
day that fuel with an opacity standard
is combusted, whichever is later;
(B) If the maximum 6-minute average
opacity is greater than 5 percent but less
than or equal to 10 percent, a
subsequent Method 9 of appendix A–4
of this part performance test must be
completed within 3 calendar months
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9457
from the date that the most recent
performance test was conducted or
within 45 days of the next day that fuel
with an opacity standard is combusted,
whichever is later; or
(C) If the maximum 6-minute average
opacity is greater than 10 percent, a
subsequent Method 9 of appendix A–4
of this part performance test must be
completed within 45 calendar days from
the date that the most recent
performance test was conducted.
(iii) * * *
(B) If no visible emissions are
observed for 10 operating days during
which an opacity standard is applicable,
observations can be reduced to once
every 7 operating days during which an
opacity standard is applicable. If any
visible emissions are observed, daily
observations shall be resumed.
*
*
*
*
*
(4) An owner or operator of an
affected facility that is subject to an
opacity standard under § 60.42a(b) is
not required to operate a COMS
provided that affected facility meets the
conditions in either paragraph (a)(4)(i)
or (ii) of this section.
(i) The affected facility combusts only
gaseous fuels and/or liquid fuels
(excluding residue oil) with a potential
SO2 emissions rate no greater than 26
ng/J (0.060 lb/MMBtu), and the unit
operates according to a written sitespecific monitoring plan approved by
the permitting authority. This
monitoring plan must include
procedures and criteria for establishing
and monitoring specific parameters for
the affected facility indicative of
compliance with the opacity standard.
For testing performed as part of this sitespecific monitoring plan, the permitting
authority may require as an alternative
to the notification and reporting
requirements specified in §§ 60.8 and
60.11 that the owner or operator submit
any deviations with the excess
emissions report required under
§ 60.51a(d).
(ii) The owner or operator of the
affected facility installs, calibrates,
operates, and maintains a particulate
matter continuous parametric
monitoring system (PM CPMS)
according to the requirements specified
in subpart UUUUU of part 63.
(b) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a CEMS, and
record the output of the system, for
measuring SO2 emissions, except where
natural gas and/or liquid fuels
(excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/
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MMBtu) or less are the only fuels
combusted, as follows:
*
*
*
*
*
(2) For a facility that qualifies under
the numerical limit provisions of
§ 60.43Da, SO2 emissions are only
monitored as discharged to the
atmosphere.
*
*
*
*
*
(e) The CEMS under paragraphs (b),
(c), and (d) of this section are operated
and data recorded during all periods of
operation of the affected facility
including periods of startup, shutdown,
and malfunction, except for CEMS
breakdowns, repairs, calibration checks,
and zero and span adjustments.
*
*
*
*
*
(k) The procedures specified in
paragraphs (k)(1) through (3) of this
section shall be used to determine gross
energy output for sources demonstrating
compliance with an output-based
standard.
*
*
*
*
*
(3) For an affected facility generating
process steam in combination with
electrical generation, the gross energy
output is determined according to the
definition of ‘‘gross energy output’’
specified in § 60.41Da that is applicable
to the affected facility.
(l) The owner or operator of an
affected facility demonstrating
compliance with an output-based
standard shall install, certify, operate,
and maintain a continuous flow
monitoring system meeting the
requirements of Performance
Specification 6 of appendix B of this
part and the calibration drift (CD)
assessment, relative accuracy test audit
(RATA), and reporting provisions of
procedure 1 of appendix F of this part,
and record the output of the system, for
measuring the volumetric flow rate of
exhaust gases discharged to the
atmosphere; or
*
*
*
*
*
(t) The owner or operator of an
affected facility demonstrating
compliance with the output-based
emissions limitation under § 60.42Da
shall install, certify, operate, and
maintain a CEMS for measuring PM
emissions according to the requirements
of paragraph (v) of this section. An
owner or operator of an affected facility
demonstrating compliance with the
input-based emissions limit in
§ 60.42Da may install, certify, operate,
and maintain a CEMS for measuring PM
emissions according to the requirements
of paragraph (v) of this section.
(u) * * *
(1) * * *
(iii) At a minimum, non-out-of-control
1-hour CO emissions averages must be
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obtained for at least 90 percent of the
operating hours on a 30-boiler operating
day rolling average basis. The 1-hour
averages are calculated using the data
points required in § 60.13(h)(2).
*
*
*
*
*
(v) * * *
(4) As of January 1, 2012, and within
90 days after the date of completing
each performance test, as defined in
§ 60.8, conducted to demonstrate
compliance with this subpart, you must
submit relative accuracy test audit (i.e.,
reference method) data and performance
test (i.e., compliance test) data, except
opacity data, electronically to EPA’s
Central Data Exchange (CDX) by using
the Electronic Reporting Tool (ERT) (see
https://www.epa.gov/ttn/chief/ert/ert
tool.html/) or other compatible
electronic spreadsheet. Only data
collected using test methods compatible
with ERT are subject to this requirement
to be submitted electronically into
EPA’s WebFire database.
*
*
*
*
*
■ 20. Section 60.50Da is amended as
follows:
■ a. By revising paragraph (b).
■ b. By removing paragraph (g).
■ c. By removing paragraph (h).
■ d. By removing paragraph (i).
§ 60.50Da Compliance determination
procedures and methods.
*
*
*
*
*
(b) In conducting the performance
tests to determine compliance with the
PM emissions limits in § 60.42Da, the
owner or operator shall meet the
requirements specified in paragraphs
(b)(1) through (3) of this section.
(1) The owner or operator shall
measure filterable PM to determine
compliance with the applicable PM
emissions limit in § 60.42Da as specified
in paragraphs (b)(1)(i) through (ii) of this
section.
(i) The dry basis F factor (O2)
procedures in Method 19 of appendix A
of this part shall be used to compute the
emission rate of PM.
(ii) For the PM concentration, Method
5 of appendix A of this part shall be
used for an affected facility that does
not use a wet FGD. For an affected
facility that uses a wet FGD, Method 5B
of appendix A of this part shall be used
downstream of the wet FGD.
(A) The sampling time and sample
volume for each run shall be at least 120
minutes and 1.70 dscm (60 dscf). The
probe and filter holder heating system
in the sampling train may be set to
provide an average gas temperature of
no greater than 160 ± 14 °C (320 ±
25 °F).
(B) For each particulate run, the
emission rate correction factor,
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integrated or grab sampling and analysis
procedures of Method 3B of appendix A
of this part shall be used to determine
the O2 concentration. The O2 sample
shall be obtained simultaneously with,
and at the same traverse points as, the
particulate run. If the particulate run
has more than 12 traverse points, the O2
traverse points may be reduced to 12
provided that Method 1 of appendix A
of this part is used to locate the 12 O2
traverse points. If the grab sampling
procedure is used, the O2 concentration
for the run shall be the arithmetic mean
of the sample O2 concentrations at all
traverse points.
(2) In conjunction with a performance
test performed according to the
requirements in paragraph (b)(1) of this
section, the owner or operator of an
affected facility for which construction,
reconstruction, or modification
commenced after May 3, 2011, shall
measure condensable PM using Method
202 of appendix M of part 51.
(3) Method 9 of appendix A of this
part and the procedures in § 60.11 shall
be used to determine opacity.
*
*
*
*
*
■ 21. Section 60.51Da is amended as
follows:
■ a. By revising paragraph (a).
■ b. By revising paragraph (b)(5).
■ c. By revising paragraph (d).
■ d. By removing and reserving
paragraph (g).
■ e. By revising paragraph (k).
§ 60.51Da
Reporting requirements.
(a) For SO2, NOX, PM, and NOX plus
CO emissions, the performance test data
from the initial and subsequent
performance test and from the
performance evaluation of the
continuous monitors (including the
transmissometer) must be reported to
the Administrator.
(b) * * *
(5) Identification of the times when
emissions data have been excluded from
the calculation of average emission rates
because of startup, shutdown, or
malfunction.
*
*
*
*
*
(d) In addition to the applicable
requirements in § 60.7, the owner or
operator of an affected facility subject to
the opacity limits in § 60.43c(c) and
conducting performance tests using
Method 9 of appendix A–4 of this part
shall submit excess emission reports for
any excess emissions from the affected
facility that occur during the reporting
period and maintain records according
to the requirements specified in
paragraph (d)(1) of this section.
(1) For each performance test
conducted using Method 9 of appendix
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A–4 of this part, the owner or operator
shall keep the records including the
information specified in paragraphs
(d)(1)(i) through (iii) of this section.
(i) Dates and time intervals of all
opacity observation periods;
(ii) Name, affiliation, and copy of
current visible emission reading
certification for each visible emission
observer participating in the
performance test; and
(iii) Copies of all visible emission
observer opacity field data sheets.
(2) [Reserved]
*
*
*
*
*
(k) The owner or operator of an
affected facility may submit electronic
quarterly reports for SO2 and/or NOX
and/or opacity in lieu of submitting the
written reports required under
paragraphs (b) and (i) of this section.
The format of each quarterly electronic
report shall be coordinated with the
permitting authority. The electronic
report(s) shall be submitted no later
than 30 days after the end of the
calendar quarter and shall be
accompanied by a certification
statement from the owner or operator,
indicating whether compliance with the
applicable emission standards and
minimum data requirements of this
subpart was achieved during the
reporting period.
§ 60.52Da
[Amended]
22. Section 60.52Da is amended by
removing and reserving paragraph (a).
■
Subpart Db—[Amended]
23. Section 60.40b is amended as
follows:
■ a. By revising paragraph (c).
■ b. By revising paragraph (h).
■ c. By revising paragraph (i).
■ d. By adding paragraph (1).
■ e. By adding paragraph (m).
■
§ 60.40b Applicability and delegation of
authority.
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*
*
*
*
*
(c) Affected facilities that also meet
the applicability requirements under
subpart J or subpart Ja of this part are
subject to the PM and NOX standards
under this subpart and the SO2
standards under subpart J or subpart Ja
of this part, as applicable.
*
*
*
*
*
(h) Any affected facility that meets the
applicability requirements and is
subject to subpart Ea, subpart Eb,
subpart AAAA, or subpart CCCC of this
part is not subject to this subpart.
(i) Affected facilities (i.e., heat
recovery steam generators) that are
associated with stationary combustion
turbines and that meet the applicability
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requirements of subpart KKKK of this
part are not subject to this subpart. This
subpart will continue to apply to all
other affected facilities (i.e. heat
recovery steam generators with duct
burners) that are capable of combusting
more than 29 MW (100 MMBtu/h) heat
input of fossil fuel. If the affected
facility (i.e. heat recovery steam
generator) is subject to this subpart, only
emissions resulting from combustion of
fuels in the steam generating unit are
subject to this subpart. (The stationary
combustion turbine emissions are
subject to subpart GG or KKKK, as
applicable, of this part.)
*
*
*
*
*
(l) Affected facilities that also meet
the applicability requirements under
subpart BB of this part (Standards of
Performance for Kraft Pulp Mills) are
subject to the SO2 and NOX standards
under this subpart and the PM
standards under subpart BB.
(m) Temporary boilers are not subject
to this subpart.
24. Section 60.41b is amended by
revising the definition of ‘‘distillate oil’’,
and adding the definition of ‘‘temporary
boiler’’ in alphabetical order to read as
follows:
§ 60.41b
Definitions.
*
*
*
*
*
Distillate oil means fuel oils that
contain 0.05 weight percent nitrogen or
less and comply with the specifications
for fuel oil numbers 1 and 2, as defined
by the American Society of Testing and
Materials in ASTM D396 (incorporated
by reference, see § 60.17), diesel fuel oil
numbers 1 and 2, as defined by the
American Society for Testing and
Materials in ASTM D975 (incorporated
by reference, see § 60.17), kerosine, as
defined by the American Society of
Testing and Materials in ASTM D3699
(incorporated by reference, see § 60.17),
biodiesel as defined by the American
Society of Testing and Materials in
ASTM D6751 (incorporated by
reference, see § 60.17), or biodiesel
blends as defined by the American
Society of Testing and Materials in
ASTM D7467 (incorporated by
reference, see § 60.17).
*
*
*
*
*
Temporary boiler means any gaseous
or liquid fuel-fired steam generating
unit that is designed to, and is capable
of, being carried or moved from one
location to another by means of, for
example, wheels, skids, carrying
handles, dollies, trailers, or platforms. A
steam generating unit is not a temporary
boiler if any one of the following
conditions exists:
(1) The equipment is attached to a
foundation.
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(2) The steam generating unit or a
replacement remains at a location for
more than 180 consecutive days. Any
temporary boiler that replaces a
temporary boiler at a location and
performs the same or similar function
will be included in calculating the
consecutive time period.
(3) The equipment is located at a
seasonal facility and operates during the
full annual operating period of the
seasonal facility, remains at the facility
for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one
location to another in an attempt to
circumvent the residence time
requirements of this definition.
*
*
*
*
*
■ 25. Section 60.43b is amended by
revising paragraph (f) to read as follows:
§ 60.43b
(PM).
Standard for particulate matter
*
*
*
*
*
(f) On and after the date on which the
initial performance test is completed or
is required to be completed under
§ 60.8, whichever date comes first, no
owner or operator of an affected facility
that combusts coal, oil, wood, or
mixtures of these fuels with any other
fuels shall cause to be discharged into
the atmosphere any gases that exhibit
greater than 20 percent opacity (6minute average), except for one 6minute period per hour of not more than
27 percent opacity. An owner or
operator of an affected facility that
elects to install, calibrate, maintain, and
operate a continuous emissions
monitoring system (CEMS) for
measuring PM emissions according to
the requirements of this subpart and is
subject to a federally enforceable PM
limit of 0.030 lb/MMBtu or less is
exempt from the opacity standard
specified in this paragraph.
*
*
*
*
*
■ 26. Section 60.44b is amended as
follows:
■ a. The section heading is revised.
■ b. By revising paragraph (b)
introductory text.
■ c. By revising paragraph (c).
■ d. By revising paragraph (d).
■ e. By revising paragraph (e).
■ f. By revising paragraph (l)(1).
§ 60.44b
(NOX).
Standard for nitrogen oxides
*
*
*
*
*
(b) Except as provided under
paragraphs (k) and (l) of this section, on
and after the date on which the initial
performance test is completed or is
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
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simultaneously combusts mixtures of
only coal, oil, or natural gas shall cause
to be discharged into the atmosphere
from that affected facility any gases that
contain NOX in excess of a limit
determined by the use of the following
formula:
*
*
*
*
*
(c) Except as provided under
paragraph (d) and (l) of this section, on
and after the date on which the initial
performance test is completed or is
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
simultaneously combusts coal or oil,
natural gas (or any combination of the
three), and wood, or any other fuel shall
cause to be discharged into the
atmosphere any gases that contain NOX
in excess of the emission limit for the
coal, oil, natural gas (or any
combination of the three), combusted in
the affected facility, as determined
pursuant to paragraph (a) or (b) of this
section. This standard does not apply to
an affected facility that is subject to and
in compliance with a federally
enforceable requirement that limits
operation of the affected facility to an
annual capacity factor of 10 percent
(0.10) or less for coal, oil, natural gas (or
any combination of the three).
(d) On and after the date on which the
initial performance test is completed or
is required to be completed under
§ 60.8, whichever date comes first, no
owner or operator of an affected facility
that simultaneously combusts natural
gas and/or distillate oil with a potential
SO2 emissions rate of 26 ng/J (0.060 lb/
MMBtu) or less with wood, municipaltype solid waste, or other solid fuel,
except coal, shall cause to be discharged
into the atmosphere from that affected
facility any gases that contain NOX in
excess of 130 ng/J (0.30 lb/MMBtu) heat
input unless the affected facility has an
annual capacity factor for natural gas,
distillate oil, or a mixture of these fuels
of 10 percent (0.10) or less and is subject
to a federally enforceable requirement
that limits operation of the affected
facility to an annual capacity factor of
10 percent (0.10) or less for natural gas,
distillate oil, or a mixture of these fuels.
(e) Except as provided under
paragraph (l) of this section, on and after
the date on which the initial
performance test is completed or is
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
simultaneously combusts only coal, oil,
or natural gas with byproduct/waste
shall cause to be discharged into the
atmosphere any gases that contain NOX
in excess of the emission limit
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determined by the following formula
unless the affected facility has an
annual capacity factor for coal, oil, and
natural gas of 10 percent (0.10) or less
and is subject to a federally enforceable
requirement that limits operation of the
affected facility to an annual capacity
factor of 10 percent (0.10) or less:
*
*
*
*
*
(l) * * *
(1) 86 ng/J (0.20 lb/MMBtu) heat input
if the affected facility combusts coal, oil,
or natural gas (or any combination of the
three), alone or with any other fuels.
The affected facility is not subject to this
limit if it is subject to and in compliance
with a federally enforceable requirement
that limits operation of the facility to an
annual capacity factor of 10 percent
(0.10) or less for coal, oil, and natural
gas (or any combination of the three); or
*
*
*
*
*
■ 27. Section 60.46b is amended by
revising paragraph (j)(14) to read as
follows:
§ 60.46b Compliance and performance test
methods and procedures for particulate
matter and nitrogen oxides.
*
*
*
*
*
(j) * * *
(14) As of January 1, 2012, and within
90 days after the date of completing
each performance test, as defined in
§ 60.8, conducted to demonstrate
compliance with this subpart, you must
submit relative accuracy test audit (i.e.,
reference method) data and performance
test (i.e., compliance test) data, except
opacity data, electronically to EPA’s
Central Data Exchange (CDX) by using
the Electronic Reporting Tool (ERT) (see
https://www.epa.gov/ttn/chief/ert/
ert_tool.html/) or other compatible
electronic spreadsheet. Only data
collected using test methods compatible
with ERT are subject to this requirement
to be submitted electronically into
EPA’s WebFIRE database.
■ 28. Section 60.48b is amended as
follows:
■ a. By revising paragraph (a)
introductory text.
■ b. By revising paragraphs (a)(1)(i)
through (iii) .
■ c. By revising paragraph (a)(2)(ii).
■ d. By revising paragraph (j)
introductory text.
■ e. By revising paragraph (j)(5).
■ f. By revising paragraph (j)(6).
■ g. By adding paragraph (j)(7).
■ h. By adding paragraph (l).
§ 60.48b Emission monitoring for
particulate matter and nitrogen oxides.
(a) Except as provided in paragraph (j)
of this section, the owner or operator of
an affected facility subject to the opacity
standard under § 60.43b shall install,
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calibrate, maintain, and operate a
continuous opacity monitoring systems
(COMS) for measuring the opacity of
emissions discharged to the atmosphere
and record the output of the system. The
owner or operator of an affected facility
subject to an opacity standard under
§ 60.43b and meeting the conditions
under paragraphs (j)(1), (2), (3), (4), (5),
or (6) of this section who elects not to
use a COMS shall conduct a
performance test using Method 9 of
appendix A–4 of this part and the
procedures in § 60.11 to demonstrate
compliance with the applicable limit in
§ 60.43b by April 29, 2011, within 45
days of stopping use of an existing
COMS, or within 180 days after initial
startup of the facility, whichever is later,
and shall comply with either paragraphs
(a)(1), (a)(2), or (a)(3) of this section. The
observation period for Method 9 of
appendix A–4 of this part performance
tests may be reduced from 3 hours to 60
minutes if all 6-minute averages are less
than 10 percent and all individual 15second observations are less than or
equal to 20 percent during the initial 60
minutes of observation.
(1) * * *
(i) If no visible emissions are
observed, a subsequent Method 9 of
appendix A–4 of this part performance
test must be completed within 12
calendar months from the date that the
most recent performance test was
conducted or within 45 days of the next
day that fuel with an opacity standard
is combusted, whichever is later;
(ii) If visible emissions are observed
but the maximum 6-minute average
opacity is less than or equal to 5
percent, a subsequent Method 9 of
appendix A–4 of this part performance
test must be completed within 6
calendar months from the date that the
most recent performance test was
conducted or within 45 days of the next
day that fuel with an opacity standard
is combusted, whichever is later;
(iii) If the maximum 6-minute average
opacity is greater than 5 percent but less
than or equal to 10 percent, a
subsequent Method 9 of appendix A–4
of this part performance test must be
completed within 3 calendar months
from the date that the most recent
performance test was conducted or
within 45 days of the next day that fuel
with an opacity standard is combusted,
whichever is later; or
*
*
*
*
*
(2) * * *
(ii) If no visible emissions are
observed for 10 operating days during
which an opacity standard is applicable,
observations can be reduced to once
every 7 operating days during which an
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opacity standard is applicable. If any
visible emissions are observed, daily
observations shall be resumed.
*
*
*
*
*
(j) The owner or operator of an
affected facility that meets the
conditions in either paragraph (j)(1), (2),
(3), (4), (5), (6), or (7) of this section is
not required to install or operate a
COMS if:
*
*
*
*
*
(5) The affected facility uses a bag
leak detection system to monitor the
performance of a fabric filter (baghouse)
according to the most current
requirements in section § 60.48Da of
this part; or
(6) The affected facility uses an ESP
as the primary PM control device and
uses an ESP predictive model to
monitor the performance of the ESP
developed in accordance and operated
according to the most current
requirements in section § 60.48Da of
this part; or
(7) The affected facility burns only
gaseous fuels or fuel oils that contain
less than or equal to 0.30 weight percent
sulfur and operates according to a
written site-specific monitoring plan
approved by the permitting authority.
This monitoring plan must include
procedures and criteria for establishing
and monitoring specific parameters for
the affected facility indicative of
compliance with the opacity standard.
*
*
*
*
*
(l) An owner or operator of an affected
facility that is subject to an opacity
standard under § 60.43b(f) is not
required to operate a COMS provided
that the unit burns only gaseous fuels
and/or liquid fuels (excluding residue
oil) with a potential SO2 emissions rate
no greater than 26 ng/J (0.060 lb/
MMBtu), and the unit operates
according to a written site-specific
monitoring plan approved by the
permitting authority is not required to
operate a COMS. This monitoring plan
must include procedures and criteria for
establishing and monitoring specific
parameters for the affected facility
indicative of compliance with the
opacity standard. For testing performed
as part of this site-specific monitoring
plan, the permitting authority may
require as an alternative to the
notification and reporting requirements
specified in §§ 60.8 and 60.11 that the
owner or operator submit any deviations
with the excess emissions report
required under § 60.49b(h).
■ 29. Section 60.49b is amended by
revising paragraph (r)(1) to read as
follows.
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§ 60.49b Reporting and recordkeeping
requirements.
*
*
*
*
*
(r) * * *
(1) The owner or operator of an
affected facility who elects to
demonstrate that the affected facility
combusts only very low sulfur oil,
natural gas, wood, a mixture of these
fuels, or any of these fuels (or a mixture
of these fuels) in combination with
other fuels that are known to contain an
insignificant amount of sulfur in
§ 60.42b(j) or § 60.42b(k) shall obtain
and maintain at the affected facility fuel
receipts (such as a current, valid
purchase contract, tariff sheet, or
transportation contract) from the fuel
supplier that certify that the oil meets
the definition of distillate oil and
gaseous fuel meets the definition of
natural gas as defined in § 60.41b and
the applicable sulfur limit. For the
purposes of this section, the distillate
oil need not meet the fuel nitrogen
content specification in the definition of
distillate oil. Reports shall be submitted
to the Administrator certifying that only
very low sulfur oil meeting this
definition, natural gas, wood, and/or
other fuels that are known to contain
insignificant amounts of sulfur were
combusted in the affected facility during
the reporting period; or
*
*
*
*
*
Subpart Dc—[Amended]
30. Section 60.40c is amended as
follows:
■ a. By revising paragraph (a).
■ b. By revising paragraph (e).
■ c. By revising paragraph (f).
■ d. By revising paragraph (g).
■ e. By adding paragraph (h).
■ f. By adding paragraph (i).
■
§ 60.40c Applicability and delegation of
authority.
(a) Except as provided in paragraphs
(d), (e), (f), and (g) of this section, the
affected facility to which this subpart
applies is each steam generating unit for
which construction, modification, or
reconstruction is commenced after June
9, 1989 and that has a maximum design
heat input capacity of 29 megawatts
(MW) (100 million British thermal units
per hour (MMBtu/h)) or less, but greater
than or equal to 2.9 MW (10 MMBtu/h).
*
*
*
*
*
(e) Affected facilities (i.e. heat
recovery steam generators and fuel
heaters) that are associated with
stationary combustion turbines and
meet the applicability requirements of
subpart KKKK of this part are not
subject to this subpart. This subpart will
continue to apply to all other heat
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9461
recovery steam generators, fuel heaters,
and other affected facilities that are
capable of combusting more than or
equal to 2.9 MW (10 MMBtu/h) heat
input of fossil fuel but less than or equal
to 29 MW (100 MMBtu/h) heat input of
fossil fuel. If the heat recovery steam
generator, fuel heater, or other affected
facility is subject to this subpart, only
emissions resulting from combustion of
fuels in the steam generating unit are
subject to this subpart. (The stationary
combustion turbine emissions are
subject to subpart GG or KKKK, as
applicable, of this part.)
(f) Any affected facility that meets the
applicability requirements of and is
subject to subpart AAAA or subpart
CCCC of this part is not subject to this
subpart.
(g) Any facility that meets the
applicability requirements and is
subject to an EPA approved State or
Federal section 111(d)/129 plan
implementing subpart BBBB of this part
is not subject to this subpart.
(h) Affected facilities that also meet
the applicability requirements under
subpart J or subpart Ja of this part are
subject to the PM and NOX standards
under this subpart and the SO2
standards under subpart J or subpart Ja
of this part, as applicable.
(i) Temporary boilers are not subject
to this subpart.
■ 31. Section 60.41c is amended as
follows:
■ a. By removing the definition of
‘‘Cogeneration.’’
■ b. By revising the definition of
‘‘Distillate oil.’’
■ c. By adding a definition of
‘‘Temporary boiler’’ in alphabetical
order.
§ 60.41c
Definitions.
*
*
*
*
*
Distillate oil means fuel oil that
complies with the specifications for fuel
oil numbers 1 or 2, as defined by the
American Society for Testing and
Materials in ASTM D396 (incorporated
by reference, see § 60.17), diesel fuel oil
numbers 1 or 2, as defined by the
American Society for Testing and
Materials in ASTM D975 (incorporated
by reference, see § 60.17), kerosine, as
defined by the American Society of
Testing and Materials in ASTM D3699
(incorporated by reference, see § 60.17),
biodiesel as defined by the American
Society of Testing and Materials in
ASTM D6751 (incorporated by
reference, see § 60.17), or biodiesel
blends as defined by the American
Society of Testing and Materials in
ASTM D7467 (incorporated by
reference, see § 60.17).
*
*
*
*
*
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Temporary boiler means a steam
generating unit that combusts natural
gas or distillate oil with a potential SO2
emissions rate no greater than 26 ng/J
(0.060 lb/MMBtu), and the unit is
designed to, and is capable of, being
carried or moved from one location to
another by means of, for example,
wheels, skids, carrying handles, dollies,
trailers, or platforms. A steam
generating unit is not a temporary boiler
if any one of the following conditions
exists:
(1) The equipment is attached to a
foundation.
(2) The steam generating unit or a
replacement remains at a location for
more than 180 consecutive days. Any
temporary boiler that replaces a
temporary boiler at a location and
performs the same or similar function
will be included in calculating the
consecutive time period.
(3) The equipment is located at a
seasonal facility and operates during the
full annual operating period of the
seasonal facility, remains at the facility
for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one
location to another in an attempt to
circumvent the residence time
requirements of this definition.
*
*
*
*
*
■ 32. Section 60.42c is amended as
follows:
■ a. By revising paragraph (c)(1) and (3).
■ b. By revising paragraph (d).
■ c. By revising paragraph (e)(1)(ii).
■ d. By revising paragraph (h)
introductory text.
■ e. By revising paragraph (h)(3).
■ f. By adding paragraph (h)(4).
§ 60.42c
Standard for sulfur dioxide (SO2).
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*
*
*
*
*
(c) * * *
(1) Affected facilities that have a heat
input capacity of 22 MW (75 MMBtu/h)
or less;
*
*
*
*
*
(3) Affected facilities located in a
noncontinental area; or
*
*
*
*
*
(d) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
combusts oil shall cause to be
discharged into the atmosphere from
that affected facility any gases that
contain SO2 in excess of 215 ng/J (0.50
lb/MMBtu) heat input from oil; or, as an
alternative, no owner or operator of an
affected facility that combusts oil shall
combust oil in the affected facility that
contains greater than 0.5 weight percent
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sulfur. The percent reduction
requirements are not applicable to
affected facilities under this paragraph.
(e) * * *
(1) * * *
(ii) Has a heat input capacity greater
than 22 MW (75 MMBtu/h); and
*
*
*
*
*
(h) For affected facilities listed under
paragraphs (h)(1), (2), (3), or (4) of this
section, compliance with the emission
limits or fuel oil sulfur limits under this
section may be determined based on a
certification from the fuel supplier, as
described under § 60.48c(f), as
applicable.
*
*
*
*
*
(3) Coal-fired affected facilities with
heat input capacities between 2.9 and
8.7 MW (10 and 30 MMBtu/h).
(4) Other fuels-fired affected facilities
with heat input capacities between 2.9
and 8.7 MW (10 and 30 MMBtu/h).
*
*
*
*
*
■ 33. Section 60.43c is amended as
follows:
■ a. By revising paragraph (a)
introductory text.
■ b. By revising paragraph (b)
introductory text.
■ c. By revising paragraph (c).
■ d. By revising paragraphs (e)(1), (3),
and (4).
§ 60.43c
(PM).
Standard for particulate matter
(a) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
commenced construction,
reconstruction, or modification on or
before February 28, 2005, that combusts
coal or combusts mixtures of coal with
other fuels and has a heat input capacity
of 8.7 MW (30 MMBtu/h) or greater,
shall cause to be discharged into the
atmosphere from that affected facility
any gases that contain PM in excess of
the following emission limits:
*
*
*
*
*
(b) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
commenced construction,
reconstruction, or modification on or
before February 28, 2005, that combusts
wood or combusts mixtures of wood
with other fuels (except coal) and has a
heat input capacity of 8.7 MW (30
MMBtu/h) or greater, shall cause to be
discharged into the atmosphere from
that affected facility any gases that
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contain PM in excess of the following
emissions limits:
*
*
*
*
*
(c) On and after the date on which the
initial performance test is completed or
required to be completed under § 60.8,
whichever date comes first, no owner or
operator of an affected facility that
combusts coal, wood, or oil and has a
heat input capacity of 8.7 MW (30
MMBtu/h) or greater shall cause to be
discharged into the atmosphere from
that affected facility any gases that
exhibit greater than 20 percent opacity
(6-minute average), except for one 6minute period per hour of not more than
27 percent opacity. Owners and
operators of an affected facility that
elect to install, calibrate, maintain, and
operate a continuous emissions
monitoring system (CEMS) for
measuring PM emissions according to
the requirements of this subpart and are
subject to a federally enforceable PM
limit of 0.030 lb/MMBtu or less are
exempt from the opacity standard
specified in this paragraph (c).
*
*
*
*
*
(e)(1) On and after the date on which
the initial performance test is completed
or is required to be completed under
§ 60.8, whichever date comes first, no
owner or operator of an affected facility
that commences construction,
reconstruction, or modification after
February 28, 2005, and that combusts
coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any
other fuels and has a heat input capacity
of 8.7 MW (30 MMBtu/h) or greater
shall cause to be discharged into the
atmosphere from that affected facility
any gases that contain PM in excess of
13 ng/J (0.030 lb/MMBtu) heat input,
except as provided in paragraphs (e)(2),
(e)(3), and (e)(4) of this section.
*
*
*
*
*
(3) On and after the date on which the
initial performance test is completed or
is required to be completed under
§ 60.8, whichever date comes first, no
owner or operator of an affected facility
that commences modification after
February 28, 2005, and that combusts
over 30 percent wood (by heat input) on
an annual basis and has a heat input
capacity of 8.7 MW (30 MMBtu/h) or
greater shall cause to be discharged into
the atmosphere from that affected
facility any gases that contain PM in
excess of 43 ng/J (0.10 lb/MMBtu) heat
input.
(4) An owner or operator of an
affected facility that commences
construction, reconstruction, or
modification after February 28, 2005,
and that combusts only oil that contains
no more than 0.50 weight percent sulfur
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or a mixture of 0.50 weight percent
sulfur oil with other fuels not subject to
a PM standard under § 60.43c and not
using a post-combustion technology
(except a wet scrubber) to reduce PM or
SO2 emissions is not subject to the PM
limit in this section.
■ 34. Section 60.45c is amended as
follows:
■ a. By revising paragraph (c)(14).
■ b. By revising paragraph (d).
§ 60.45c Compliance and performance test
methods and procedures for particulate
matter.
*
*
*
*
*
(c) * * *
(14) As of January 1, 2012, and within
90 days after the date of completing
each performance test, as defined in
§ 60.8, conducted to demonstrate
compliance with this subpart, you must
submit relative accuracy test audit (i.e.,
reference method) data and performance
test (i.e., compliance test) data, except
opacity data, electronically to EPA’s
Central Data Exchange (CDX) by using
the Electronic Reporting Tool (ERT) (see
https://www.epa.gov/ttn/chief/ert/ert
tool.html/) or other compatible
electronic spreadsheet. Only data
collected using test methods compatible
with ERT are subject to this requirement
to be submitted electronically into
EPA’s WebFIRE database.
(d) The owner or operator of an
affected facility seeking to demonstrate
compliance under § 60.43c(e)(4) shall
follow the applicable procedures under
§ 60.48c(f). For residual oil-fired
affected facilities, fuel supplier
certifications are only allowed for
facilities with heat input capacities
between 2.9 and 8.7 MW (10 to 30
MMBtu/h).
■ 35. Section 60.47c is amended as
follows:
■ a. By revising paragraph (a)
introductory text.
■ b. By revising paragraphs (a)(1)(i)
through (iii).
■ c. By revising paragraph (a)(2)(ii).
■ d. By revising paragraph (f).
■ e. By removing paragraph (g).
srobinson on DSK4SPTVN1PROD with RULES2
§ 60.47c Emission monitoring for
particulate matter.
(a) Except as provided in paragraphs
(c), (d), (e), and (f) of this section, the
owner or operator of an affected facility
combusting coal, oil, or wood that is
subject to the opacity standards under
§ 60.43c shall install, calibrate,
maintain, and operate a continuous
opacity monitoring system (COMS) for
measuring the opacity of the emissions
discharged to the atmosphere and
record the output of the system. The
owner or operator of an affected facility
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subject to an opacity standard in
§ 60.43c(c) that is not required to use a
COMS due to paragraphs (c), (d), (e), or
(f) of this section that elects not to use
a COMS shall conduct a performance
test using Method 9 of appendix A–4 of
this part and the procedures in § 60.11
to demonstrate compliance with the
applicable limit in § 60.43c by April 29,
2011, within 45 days of stopping use of
an existing COMS, or within 180 days
after initial startup of the facility,
whichever is later, and shall comply
with either paragraphs (a)(1), (a)(2), or
(a)(3) of this section. The observation
period for Method 9 of appendix A–4 of
this part performance tests may be
reduced from 3 hours to 60 minutes if
all 6-minute averages are less than 10
percent and all individual 15-second
observations are less than or equal to 20
percent during the initial 60 minutes of
observation.
(1) * * *
(i) If no visible emissions are
observed, a subsequent Method 9 of
appendix A–4 of this part performance
test must be completed within 12
calendar months from the date that the
most recent performance test was
conducted or within 45 days of the next
day that fuel with an opacity standard
is combusted, whichever is later;
(ii) If visible emissions are observed
but the maximum 6-minute average
opacity is less than or equal to 5
percent, a subsequent Method 9 of
appendix A–4 of this part performance
test must be completed within 6
calendar months from the date that the
most recent performance test was
conducted or within 45 days of the next
day that fuel with an opacity standard
is combusted, whichever is later;
(iii) If the maximum 6-minute average
opacity is greater than 5 percent but less
than or equal to 10 percent, a
subsequent Method 9 of appendix A–4
of this part performance test must be
completed within 3 calendar months
from the date that the most recent
performance test was conducted or
within 45 days of the next day that fuel
with an opacity standard is combusted,
whichever is later; or
*
*
*
*
*
(2) * * *
(ii) If no visible emissions are
observed for 10 operating days during
which an opacity standard is applicable,
observations can be reduced to once
every 7 operating days during which an
opacity standard is applicable. If any
visible emissions are observed, daily
observations shall be resumed.
*
*
*
*
*
(f) An owner or operator of an affected
facility that is subject to an opacity
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9463
standard in § 60.43c(c) is not required to
operate a COMS provided that the
affected facility meets the conditions in
either paragraphs (f)(1), (2), or (3) of this
section.
(1) The affected facility uses a fabric
filter (baghouse) as the primary PM
control device and, the owner or
operator operates a bag leak detection
system to monitor the performance of
the fabric filter according to the
requirements in section § 60.48Da of
this part.
(2) The affected facility uses an ESP
as the primary PM control device, and
the owner or operator uses an ESP
predictive model to monitor the
performance of the ESP developed in
accordance and operated according to
the requirements in section § 60.48Da of
this part.
(3) The affected facility burns only
gaseous fuels and/or fuel oils that
contain no greater than 0.5 weight
percent sulfur, and the owner or
operator operates the unit according to
a written site-specific monitoring plan
approved by the permitting authority.
This monitoring plan must include
procedures and criteria for establishing
and monitoring specific parameters for
the affected facility indicative of
compliance with the opacity standard.
For testing performed as part of this sitespecific monitoring plan, the permitting
authority may require as an alternative
to the notification and reporting
requirements specified in §§ 60.8 and
60.11 that the owner or operator submit
any deviations with the excess
emissions report required under
§ 60.48c(c).
Subpart HHHH—[Removed and
Reserved]
36. Subpart HHHH is removed and
reserved.
■
PART 63—[AMENDED]
37. The authority citation for 40 CFR
Part 63 continues to read as follows:
■
Authority: 42 U.S.C. 7401, et seq.
Subpart A—[Amended]
38. Section 63.14 is amended as
follows:
■ a. By adding paragraphs (b)(19) and
(20).
■ b. By adding paragraphs (b)(22) and
(23).
■ c. By adding paragraphs (b)(69)
through (72).
■ d. By revising paragraph (i)(1).
■
§ 63.14
*
Incorporation by reference.
*
*
(b) * * *
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*
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(19) ASTM D95–05 (Reapproved
2010), Standard Test Method for Water
in Petroleum Products and Bituminous
Materials by Distillation, approved May
1, 2010, IBR approved for
§ 63.10005(i)(4)(i).
(20) ASTM Method D388–05,
Standard Classification of Coals by
Rank, approved September 15, 2005,
IBR approved for § 63.10042.
*
*
*
*
*
(22) ASTM Method D396–10,
Standard Specification for Fuel Oils,
including Appendix X1, approved
October 1, 2010, IBR approved for
§ 63.10042.
(23) ASTM D4006–11, Standard Test
Method for Water in Crude Oil by
Distillation, including Annex A1 and
Appendix X1, approved June 1, 2011,
IBR approved for § 63.10005(i)(4)(ii).
*
*
*
*
*
(69) ASTM D4057–06 (Reapproved
2011), Standard Practice for Manual
Sampling of Petroleum and Petroleum
Products, including Annex A1,
approved June 1, 2011, IBR approved for
§ 63.10005(i)(4)(iv).
(70) ASTM D4177–95 (Reapproved
2010), Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products, including Annexes A1
through A6 and Appendices X1 and X2,
approved May 1, 2010, IBR approved for
§ 63.10005(i)(4)(iii).
(71) ASTM D6348–03 (Reapproved
2010), Standard Test Method for
Determination of Gaseous Compounds
by Extractive Direct Interface Fourier
Transform Infrared (FTIR) Spectroscopy,
including Annexes A1 through A8,
approved October 1, 2010, IBR approved
for table 1 to subpart UUUUU of this
part, table 2 to subpart UUUUU of this
part, table 5 to subpart UUUUU of this
part, and appendix B to subpart
UUUUU of this part.
(72) ASTM D6784–02 (Reapproved
2008), Standard Test Method for
Elemental, Oxidized, Particle-Bound
and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary
Sources (Ontario Hydro Method),
approved April 1, 2008, IBR approved
for table 5 to subpart UUUUU of this
part, and appendix A to subpart
UUUUU of this part.
*
*
*
*
*
(i) * * *
(1) ANSI/ASME PTC 19.10–1981,
‘‘Flue and Exhaust Gas Analyses [part
10, Instruments and Apparatus],’’ IBR
approved for §§ 63.309(k)(1)(iii),
63.865(b), 63.3166(a)(3),
63.3360(e)(1)(iii), 63.3545(a)(3),
63.3555(a)(3), 63.4166(a)(3),
63.4362(a)(3), 63.4766(a)(3),
63.4965(a)(3), 63.5160(d)(1)(iii),
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63.9307(c)(2), 63.9323(a)(3),
63.11148(e)(3)(iii), 63.11155(e)(3),
63.11162(f)(3)(iii) and (f)(4),
63.11163(g)(1)(iii) and (g)(2),
63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C),
table 5 to subpart DDDDD of this part,
table 1 to subpart ZZZZZ of this part,
table 4 to subpart JJJJJJ of this part, and
table 5 to subpart UUUUU of this part.
*
*
*
*
*
39. Part 63 is amended by adding
subpart UUUUU to read as follows:
■
Subpart UUUUU—National Emission
Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric
Utility Steam Generating Units
Sec.
What This Subpart Covers
63.9980 What is the purpose of this
subpart?
63.9981 Am I subject to this subpart?
63.9982 What is the affected source of this
subpart?
63.9983 Are any EGUs not subject to this
subpart?
63.9984 When do I have to comply with
this subpart?
63.9985 What is a new EGU?
Emission Limitations and Work Practice
Standards
63.9990 What are the subcategories of
EGUs?
63.9991 What emission limitations, work
practice standards, and operating limits
must I meet?
General Compliance Requirements
63.10000 What are my general requirements
for complying with this subpart?
63.10001 Affirmative defense for
exceedence of emission limit during
malfunction.
Testing and Initial Compliance
Requirements
63.10005 What are my initial compliance
requirements and by what date must I
conduct them?
63.10006 When must I conduct subsequent
performance tests or tune-ups?
63.10007 What methods and other
procedures must I use for the
performance tests?
63.10008 [Reserved]
63.10009 May I use emissions averaging to
comply with this subpart?
63.10010 What are my monitoring,
installation, operation, and maintenance
requirements?
63.10011 How do I demonstrate initial
compliance with the emission
limitations and work practice standards?
Continuous Compliance Requirements
63.10020 How do I monitor and collect data
to demonstrate continuous compliance?
63.10021 How do I demonstrate continuous
compliance with the emission
limitations, operating limits, and work
practice standards?
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63.10022 How do I demonstrate continuous
compliance under the emissions
averaging provision?
63.10023 How do I establish my PM CPMS
operating limit and determine
compliance with it?
Notifications, Reports, and Records
63.10030 What notifications must I submit
and when?
63.10031 What reports must I submit and
when?
63.10032 What records must I keep?
63.10033 In what form and how long must
I keep my records?
Other Requirements and Information
63.10040 What parts of the General
Provisions apply to me?
63.10041 Who implements and enforces
this subpart?
63.10042 What definitions apply to this
subpart?
Tables to Subpart UUUUU of Part 63
Table 1 to Subpart UUUUU of Part 63—
Emission Limits for New or
Reconstructed EGUs
Table 2 to Subpart UUUUU of Part 63—
Emission Limits for Existing EGUs
Table 3 to Subpart UUUUU of Part 63—Work
Practice Standards
Table 4 to Subpart UUUUU of Part 63—
Operating Limits for EGUs
Table 5 to Subpart UUUUU of Part 63—
Performance Testing Requirements
Table 6 to Subpart UUUUU of Part 63—
Establishing PM CPMS Operating Limits
Table 7 to Subpart UUUUU of Part 63—
Demonstrating Continuous Compliance
Table 8 to Subpart UUUUU of Part 63—
Reporting Requirements
Table 9 to Subpart UUUUU of Part 63—
Applicability of General Provisions to
Subpart UUUUU
Appendix A to Subpart UUUUU—Hg
Monitoring Provisions
Appendix B to Subpart UUUUU—HCl and
HF Monitoring Provisions
Subpart UUUUU—National Emission
Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric
Utility Steam Generating Units
What This Subpart Covers
§ 63.9980
subpart?
What is the purpose of this
This subpart establishes national
emission limitations and work practice
standards for hazardous air pollutants
(HAP) emitted from coal- and oil-fired
electric utility steam generating units
(EGUs) as defined in § 63.10042 of this
subpart. This subpart also establishes
requirements to demonstrate initial and
continuous compliance with the
emission limitations.
§ 63.9981
Am I subject to this subpart?
You are subject to this subpart if you
own or operate a coal-fired EGU or an
oil-fired EGU as defined in § 63.10042 of
this subpart.
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§ 63.9982 What is the affected source of
this subpart?
(a) This subpart applies to each
individual or group of two or more new,
reconstructed, and existing affected
source(s) as described in paragraphs
(a)(1) and (2) of this section within a
contiguous area and under common
control.
(1) The affected source of this subpart
is the collection of all existing coal- or
oil-fired EGUs, as defined in 63.10042,
within a subcategory.
(2) The affected source of this subpart
is each new or reconstructed coal- or
oil-fired EGU as defined in 63.10042.
(b) An EGU is new if you commence
construction of the coal- or oil-fired
EGU after May 3, 2011, and you meet
the applicability criteria at the time you
commence construction.
(c) An EGU is reconstructed if you
meet the reconstruction criteria as
defined in § 63.2, you commence
reconstruction after May 3, 2011, and
you meet the applicability criteria at the
time you commence reconstruction.
(d) An EGU is existing if it is not new
or reconstructed. An existing electric
steam generating unit that meets the
applicability requirements after the
effective date of this final rule due to a
change process (e.g., fuel or utilization)
is considered to be an existing source
under this subpart.
srobinson on DSK4SPTVN1PROD with RULES2
§ 63.9983
subpart?
Are any EGUs not subject to this
The types of electric steam generating
units listed in paragraphs (a) through (d)
of this section are not subject to this
subpart.
(a) Any unit designated as a stationary
combustion turbine, other than an
integrated gasification combined cycle
(IGCC) unit, covered by 40 CFR part 63,
subpart YYYY.
(b) Any electric utility steam
generating unit that is not a coal- or oilfired EGU and combusts natural gas for
more than 10.0 percent of the average
annual heat input during any 3 calendar
years or for more than 15.0 percent of
the annual heat input during any
calendar year.
(c) Any electric utility steam
generating unit that has the capability of
combusting more than 25 MW of coal or
oil but did not fire coal or oil for more
than 10.0 percent of the average annual
heat input during any 3 calendar years
or for more than 15.0 percent of the
annual heat input during any calendar
year. Heat input means heat derived
from combustion of fuel in an EGU and
does not include the heat derived from
preheated combustion air, recirculated
flue gases or exhaust gases from other
sources (such as stationary gas turbines,
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internal combustion engines, and
industrial boilers).
(d) Any electric steam generating unit
combusting solid waste is a solid waste
incineration unit subject to standards
established under sections 129 and 111
of the Clean Air Act.
§ 63.9984 When do I have to comply with
this subpart?
(a) If you have a new or reconstructed
EGU, you must comply with this
subpart by April 16, 2012 or upon
startup of your EGU, whichever is later,
and as further provided for in
§ 63.10005(g).
(b) If you have an existing EGU, you
must comply with this subpart no later
than April 16, 2015.
(c) You must meet the notification
requirements in § 63.10030 according to
the schedule in § 63.10030 and in
subpart A of this part. Some of the
notifications must be submitted before
you are required to comply with the
emission limits and work practice
standards in this subpart.
(d) An electric steam generating unit
that does not meet the definition of an
EGU subject to this subpart on April 16,
2012 for new sources or April 16, 2015
for existing sources must comply with
the applicable existing source
provisions of this subpart on the date
such unit meets the definition of an
EGU subject to this subpart.
(e) If you own or operate an electric
steam generating unit that is exempted
from this subpart under § 63.9983(d), if
the manner of operating the unit
changes such that the combustion of
waste is discontinued and the unit
becomes a coal-fired or oil-fired EGU (as
defined in § 63.10042), you must be in
compliance with this subpart on April
16, 2015 or on the effective date of the
switch from waste combustion to coal or
oil combustion, whichever is later.
(f) You must demonstrate that
compliance has been achieved, by
conducting the required performance
tests and other activities, no later than
180 days after the applicable date in
paragraph (a), (b), (c), (d), or (e) of this
section.
§ 63.9985
What is a new EGU?
(a) A new EGU is an EGU that meets
any of the criteria specified in paragraph
(a)(1) through (a)(2) of this section.
(1) An EGU that commenced
construction after May 3, 2011.
(2) An EGU that commenced
reconstruction or modification after May
3, 2011.
(b) [Reserved]
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Emission Limitations and Work
Practice Standards
§ 63.9990
EGUs?
What are the subcategories of
(a) Coal-fired EGUs are subcategorized
as defined in paragraphs (a)(1) through
(a)(2) of this section and as defined in
§ 63.10042.
(1) EGUs designed for coal with a
heating value greater than or equal to
8,300 Btu/lb, and
(2) EGUs designed for low rank virgin
coal.
(b) Oil-fired EGUs are subcategorized
as noted in paragraphs (b)(1) through
(b)(4) of this section and as defined in
§ 63.10042.
(1) Continental liquid oil-fired EGUs
(2) Non-continental liquid oil-fired
EGUs,
(3) Limited-use liquid oil-fired EGUs,
and
(4) EGUs designed to burn solid oilderived fuel.
(c) IGCC units combusting either
gasified coal or gasified solid oil-derived
fuel. For purposes of compliance,
monitoring, recordkeeping, and
reporting requirements in this subpart,
IGCC units are subject in the same
manner as coal-fired units and solid oilderived fuel-fired units, unless
otherwise indicated.
§ 63.9991 What emission limitations, work
practice standards, and operating limits
must I meet?
(a) You must meet the requirements in
paragraphs (a)(1) and (2) of this section.
You must meet these requirements at all
times.
(1) You must meet each emission
limit and work practice standard in
Table 1 through 3 to this subpart that
applies to your EGU, for each EGU at
your source, except as provided under
§ 63.10009.
(2) You must meet each operating
limit in Table 4 to this subpart that
applies to your EGU.
(b) As provided in § 63.6(g), the
Administrator may approve use of an
alternative to the work practice
standards in this section.
(c) You may use the alternate SO2
limit in Tables 1 and 2 to this subpart
only if your coal-fired EGU:
(1) Has a system using wet or dry flue
gas desulfurization technology and SO2
continuous emissions monitoring
system (CEMS) installed on the unit;
and
(2) At all times, you operate the wet
or dry flue gas desulfurization
technology installed on the unit
consistent with § 63.10000(b).
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General Compliance Requirements
srobinson on DSK4SPTVN1PROD with RULES2
§ 63.10000 What are my general
requirements for complying with this
subpart?
(a) You must be in compliance with
the emission limits and operating limits
in this subpart. These limits apply to
you at all times except during periods
of startup and shutdown; however, for
coal-fired, liquid oil-fired, or solid oilderived fuel-fired EGUs, you are
required to meet the work practice
requirements in Table 3 to this subpart
during periods of startup or shutdown.
(b) At all times you must operate and
maintain any affected source, including
associated air pollution control
equipment and monitoring equipment,
in a manner consistent with safety and
good air pollution control practices for
minimizing emissions. Determination of
whether such operation and
maintenance procedures are being used
will be based on information available
to the EPA Administrator which may
include, but is not limited to,
monitoring results, review of operation
and maintenance procedures, review of
operation and maintenance records, and
inspection of the source.
(c)(1) For coal-fired units and solid
oil-derived fuel-fired units, initial
performance testing is required for all
pollutants, to demonstrate compliance
with the applicable emission limits.
(i) For a coal-fired or solid oil-derived
fuel-fired EGU or IGCC EGU, you may
conduct the initial performance testing
in accordance with § 63.10005(h), to
determine whether the unit qualifies as
a low emitting EGU (LEE) for one or
more applicable emissions limits, with
two exceptions:
(A) You may not pursue the LEE
option if your coal-fired, IGCC, or solid
oil-derived fuel-fired EGU is equipped
with an acid gas scrubber and has a
main stack and bypass stack exhaust
configuration, and
(B) You may not pursue the LEE
option for Hg if your coal-fired, solid
oil-fired fuel fired EGU or IGCC EGU is
new.
(ii) For a qualifying LEE for Hg
emissions limits, you must conduct a
30-day performance test using Method
30B at least once every 12 calendar
months to demonstrate continued LEE
status.
(iii) For a qualifying LEE of any other
applicable emissions limits, you must
conduct a performance test at least once
every 36 calendar months to
demonstrate continued LEE status.
(iv) If your coal-fired or solid oilderived fuel-fired EGU or IGCC EGU
does not qualify as a LEE for total nonmercury HAP metals, individual non-
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mercury HAP metals, or filterable
particulate matter (PM), you must
demonstrate compliance through an
initial performance test and you must
monitor continuous performance
through either use of a particulate
matter continuous parametric
monitoring system (PM CPMS), a PM
CEMS, or compliance performance
testing repeated quarterly.
(A) If you elect to use PM CPMS, you
will establish a site-specific operating
limit corresponding to the results of the
performance test demonstrating
compliance with the pollutant with
which you choose to comply: total nonmercury HAP metals, individual nonmercury HAP metals or filterable PM.
You will use the PM CPMS to
demonstrate continuous compliance
with this operating limit. If you elect to
use a PM CPMS, you must repeat the
performance test annually for the
selected pollutant limit and reassess and
adjust the site-specific operating limit in
accordance with the results of the
performance test.
(B) You may also opt to install and
operate a particulate matter CEMS
certified in accordance with
Performance Specification 11 and
Procedure 2 of 40 CFR part 60,
Appendices B and F, respectively, in
accordance with § 63.10010(i).
(v) If your coal-fired or solid oilderived fuel-fired EGU does not qualify
as a LEE for hydrogen chloride (HCl),
you may demonstrate initial and
continuous compliance through use of
an HCl CEMS, installed and operated in
accordance with Appendix B to this
subpart. As an alternative to HCl CEMS,
you may demonstrate initial and
continuous compliance by conducting
an initial and periodic quarterly
performance stack test for HCl. If your
EGU uses wet or dry flue gas
desulfurization technology (this
includes limestone injection into a
fluidized bed combustion unit), you
may apply a second alternative to HCl
CEMS by installing and operating a
sulfur dioxide (SO2) CEMS installed and
operated in accordance with part 75 of
this chapter to demonstrate compliance
with the applicable SO2 emissions limit.
(vi) If your coal-fired or solid oilderived fuel-fired EGU does not qualify
as a LEE for Hg, you must demonstrate
initial and continuous compliance
through use of a Hg CEMS or a sorbent
trap monitoring system, in accordance
with appendix A to this subpart.
(2) For liquid oil-fired EGUs, except
limited use liquid oil-fired EGUs, initial
performance testing is required for all
pollutants, to demonstrate compliance
with the applicable emission limits.
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(i) For an existing liquid oil-fired unit,
you may conduct the performance
testing in accordance with
§ 63.10005(h), to determine whether the
unit qualifies as a LEE for one or more
pollutants. For a qualifying LEE for Hg
emissions limits, you must conduct a
30-day performance test using Method
30B at least once every 12 calendar
months to demonstrate continued LEE
status. For a qualifying LEE of any other
applicable emissions limits, you must
conduct a performance test at least once
every 36 calendar months to
demonstrate continued LEE status.
(ii) If your existing liquid oil-fired
unit does not qualify as a LEE for total
HAP metals (including mercury),
individual metals (including mercury),
or filterable PM you must demonstrate
compliance through an initial
performance test and you must monitor
continuous performance through either
use of a PM CPMS, a PM CEMS, or
performance testing conducted
quarterly.
(A) If you elect to use PM CPMS, you
will establish a site-specific operating
limit corresponding to the results of the
performance test demonstrating
compliance with the pollutant with
which you choose to comply: total HAP
metals, individual HAP metals, or
filterable PM. You will use the PM
CPMS to demonstrate continuous
compliance with this operating limit. If
you elect to use a PM CPMS, you must
repeat the performance test at least
annually for the selected pollutant limit
and reassess and adjust the site-specific
operating limit in accordance with the
results of the performance test.
(B) If you elect to use a PM CEMS,
you will use the CEMS in accordance
with § 63.10010(i) to demonstrate initial
and continuous compliance with the
filterable PM emission limit.
(iii) If your existing liquid oil-fired
unit does not qualify as a LEE for
hydrogen chloride (HCl) or for hydrogen
fluoride (HF), you may demonstrate
initial and continuous compliance
through use of an HCl CEMS, an HF
CEMS, or an HCl and HF CEMS,
installed and operated in accordance
with Appendix B to this rule. As an
alternative to HCl CEMS, HF CEMS, or
HCl and HF CEMS, you may
demonstrate initial and continuous
compliance by conducting periodic
quarterly performance stack tests for
HCl and HF. If you elect to demonstrate
compliance through quarterly
performance testing, then you must also
develop a site-specific monitoring plan
to ensure that the operations of the unit
remain consistent with those during the
performance test. As another alternative,
you may measure or obtain, and keep
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records of, fuel moisture content; as
long as fuel moisture does not exceed
1.0 percent by weight, you need not
conduct other HCl or HF monitoring or
testing.
(iv) If your unit qualifies as a limiteduse liquid oil-fired as defined in
§ 63.10042, then you are not subject to
the emission limits in Tables 1 and 2,
but must comply with the performance
tune-up work practice requirements in
Table 3.
(d)(1) If you demonstrate compliance
with any applicable emissions limit
through use of a continuous monitoring
system (CMS), where a CMS includes a
continuous parameter monitoring
system (CPMS) as well as a continuous
emissions monitoring system (CEMS),
you must develop a site-specific
monitoring plan and submit this sitespecific monitoring plan, if requested, at
least 60 days before your initial
performance evaluation (where
applicable) of your CMS. This
requirement also applies to you if you
petition the Administrator for
alternative monitoring parameters under
§ 63.8(f). This requirement to develop
and submit a site-specific monitoring
plan does not apply to affected sources
with existing monitoring plans that
apply to CEMS and CPMS prepared
under Appendix B to part 60 or part 75
of this chapter, and that meet the
requirements of § 63.10010. Using the
process described in § 63.8(f)(4), you
may request approval of monitoring
system quality assurance and quality
control procedures alternative to those
specified in this paragraph of this
section and, if approved, include those
in your site-specific monitoring plan.
The monitoring plan must address the
provisions in paragraphs (d)(2) through
(5) of this section.
(2) The site-specific monitoring plan
shall include the information specified
in paragraphs (d)(5)(i) through (d)(5)(vii)
of this section. Alternatively, the
requirements of paragraphs (d)(5)(i)
through (d)(5)(vii) are considered to be
met for a particular CMS or sorbent trap
monitoring system if:
(i) The CMS or sorbent trap
monitoring system is installed, certified,
maintained, operated, and qualityassured either according to part 75 of
this chapter, or appendix A or B to this
subpart; and
(ii) The recordkeeping and reporting
requirements of part 75 of this chapter,
or appendix A or B to this subpart, that
pertain to the CMS are met.
(3) If requested by the Administrator,
you must submit the monitoring plan
(or relevant portion of the plan) at least
60 days before the initial performance
evaluation of a particular CMS, except
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where the CMS has already undergone
a performance evaluation that meets the
requirements of § 63.10010 (e.g., if the
CMS was previously certified under
another program).
(4) You must operate and maintain
the CMS according to the site-specific
monitoring plan.
(5) The provisions of the site-specific
monitoring plan must address the
following items:
(i) Installation of the CEMS or sorbent
trap monitoring system sampling probe
or other interface at a measurement
location relative to each affected process
unit such that the measurement is
representative of control of the exhaust
emissions (e.g., on or downstream of the
last control device). See § 63.10010(a)
for further details. For CPMS
installations, follow the procedures in
§ 63.10010(h).
(ii) Performance and equipment
specifications for the sample interface,
the pollutant concentration or
parametric signal analyzer, and the data
collection and reduction systems.
(iii) Schedule for conducting initial
and periodic performance evaluations.
(iv) Performance evaluation
procedures and acceptance criteria (e.g.,
calibrations), including ongoing data
quality assurance procedures in
accordance with the general
requirements of § 63.8(d).
(v) On-going operation and
maintenance procedures, in accordance
with the general requirements of
§§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii).
(vi) Conditions that define a CMS that
is out of control consistent with
§ 63.8(c)(7)(i) and for responding to out
of control periods consistent with
§§ 63.8(c)(7)(ii) and (c)(8).
(vii) On-going recordkeeping and
reporting procedures, in accordance
with the general requirements of
§§ 63.10(c), (e)(1), and (e)(2)(i), or as
specifically required under this subpart.
(e) As part of your demonstration of
continuous compliance, you must
perform periodic tune-ups of your
EGU(s), according to § 63.10021(e).
(f) You are subject to the requirements
of this subpart for at least 6 months
following the last date you met the
definition of an EGU subject to this
subpart (e.g., 6 months after a
cogeneration unit provided more than
one third of its potential electrical
output capacity and more than 25
megawatts electrical output to any
power distributions system for sale).
You may opt to remain subject to the
provisions of this subpart beyond 6
months after the last date you met the
definition of an EGU subject to this
subpart, unless you are a solid waste
incineration unit subject to standards
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9467
under CAA section 129 (e.g., 40 CFR
part 60, subpart CCCC (New Source
Performance Standards (NSPS) for
Commercial and Industrial Solid Waste
Incineration Units, or Subpart DDDD
(Emissions Guidelines (EG) for Existing
Commercial and Industrial Solid Waste
Incineration Units). Notwithstanding
the provisions of this subpart, an EGU
that starts combusting solid waste is
immediately subject to standards under
CAA section 129 and the EGU remains
subject to those standards until the EGU
no longer meets the definition of a solid
waste incineration unit consistent with
the provisions of the applicable CAA
section 129 standards.
(g) If you no longer meet the
definition of an EGU subject to this
subpart you must be in compliance with
any newly applicable standards on the
date you are no longer subject to this
subpart. The date you are no longer
subject to this subpart is a date selected
by you, that must be at least 6 months
from the date that you last met the
definition of an EGU subject to this
subpart or the date you begin
combusting solid waste, consistent with
§ 63.9983(d). Your source must remain
in compliance with this subpart until
the date you select to cease complying
with this subpart or the date you begin
combusting solid waste, whichever is
earlier.
(h)(1) If you own or operate an EGU
that does not meet the definition of an
EGU subject to this subpart on April 16,
2015, and you commence or
recommence operations that cause you
to meet the definition of an EGU subject
to this subpart, you are subject to the
provisions of this subpart, including,
but not limited to, the emission
limitations and the monitoring
requirements, as of the first day you
meet the definition of an EGU subject to
this subpart. You must complete all
initial compliance demonstrations for
this subpart applicable to your EGU
within 180 days after you commence or
recommence operations that cause you
to meet the definition of an EGU subject
to this subpart.
(2) You must provide 30 days prior
notice of the date you intend to
commence or recommence operations
that cause you to meet the definition of
an EGU subject to this subpart. The
notification must identify:
(i) The name of the owner or operator
of the EGU, the location of the facility,
the unit(s) that will commence or
recommence operations that will cause
the unit(s) to meet the definition of an
EGU subject to this subpart, and the
date of the notice;
(ii) The 40 CFR part 60, part 62, or
part 63 subpart and subcategory
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currently applicable to your unit(s), and
the subcategory of this subpart that will
be applicable after you commence or
recommence operation that will cause
the unit(s) to meet the definition of an
EGU subject to this subpart;
(iii) The date on which you became
subject to the currently applicable
emission limits;
(iv) The date upon which you will
commence or recommence operations
that will cause your unit to meet the
definition of an EGU subject to this
subpart, consistent with paragraph (f) of
this section.
(i)(1) If you own or operate an EGU
subject to this subpart, and it has been
at least 6 months since you operated in
a manner that caused you to meet the
definition of an EGU subject to this
subpart, you may, consistent with
paragraph (g) of this section, select the
date on which your EGU will no longer
be subject to this subpart. You must be
in compliance with any newly
applicable section 112 or 129 standards
on the date you selected.
(2) You must provide 30 days prior
notice of the date your EGU will cease
complying with this subpart. The
notification must identify:
(i) The name of the owner or operator
of the EGU(s), the location of the
facility, the EGU(s) that will cease
complying with this subpart, and the
date of the notice;
(ii) The currently applicable
subcategory under this subpart, and any
40 CFR part 60, part 62, or part 63
subpart and subcategory that will be
applicable after you cease complying
with this subpart;
(iii) The date on which you became
subject to this subpart;
(iv) The date upon which you will
cease complying with this subpart,
consistent with paragraph (g) of this
section.
(j) All air pollution control equipment
necessary for compliance with any
newly applicable emissions limits
which apply as a result of the cessation
or commencement or recommencement
of operations that cause your EGU to
meet the definition of an EGU subject to
this subpart must be installed and
operational as of the date your source
ceases to be or becomes subject to this
subpart.
(k) All monitoring systems necessary
for compliance with any newly
applicable monitoring requirements
which apply as a result of the cessation
or commencement or recommencement
of operations that cause your EGU to
meet the definition of an EGU subject to
this subpart must be installed and
operational as of the date your source
ceases to be or becomes subject to this
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subpart. All calibration and drift checks
must be performed as of the date your
source ceases to be or becomes subject
to this subpart. You must also comply
with provisions of §§ 63.10010,
63.10020, and 63.10021 of this subpart.
Relative accuracy tests must be
performed as of the performance test
deadline for PM CEMS, if applicable.
Relative accuracy testing for other
CEMS need not be repeated if that
testing was previously performed
consistent with CAA section 112
monitoring requirements or monitoring
requirements under this subpart.
§ 63.10001 Affirmative defense for
exceedence of emission limit during
malfunction.
In response to an action to enforce the
standards set forth in § 63.9991 you may
assert an affirmative defense to a claim
for civil penalties for exceedances of
such standards that are caused by
malfunction, as defined at 40 CFR 63.2.
Appropriate penalties may be assessed,
however, if you fail to meet your burden
of proving all of the requirements in the
affirmative defense. The affirmative
defense shall not be available for claims
for injunctive relief.
(a) To establish the affirmative
defense in any action to enforce such a
limit, you must timely meet the
notification requirements in paragraph
(b) of this section, and must prove by a
preponderance of evidence that:
(1) The excess emissions:
(i) Were caused by a sudden,
infrequent, and unavoidable failure of
air pollution control and monitoring
equipment, process equipment, or a
process to operate in a normal or usual
manner, and
(ii) Could not have been prevented
through careful planning, proper design
or better operation and maintenance
practices; and
(iii) Did not stem from any activity or
event that could have been foreseen and
avoided, or planned for; and
(iv) Were not part of a recurring
pattern indicative of inadequate design,
operation, or maintenance; and
(2) Repairs were made as
expeditiously as possible when the
applicable emission limitations were
being exceeded. Off-shift and overtime
labor were used, to the extent
practicable to make these repairs; and
(3) The frequency, amount and
duration of the excess emissions
(including any bypass) were minimized
to the maximum extent practicable
during periods of such emissions; and
(4) If the excess emissions resulted
from a bypass of control equipment or
a process, then the bypass was
unavoidable to prevent loss of life,
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personal injury, or severe property
damage; and
(5) All possible steps were taken to
minimize the impact of the excess
emissions on ambient air quality, the
environment and human health; and
(6) All emissions monitoring and
control systems were kept in operation
if at all possible, consistent with safety
and good air pollution control practices;
and
(7) All of the actions in response to
the excess emissions were documented
by properly signed, contemporaneous
operating logs; and
(8) At all times, the affected source
was operated in a manner consistent
with good practices for minimizing
emissions; and
(9) A written root cause analysis has
been prepared, the purpose of which is
to determine, correct, and eliminate the
primary causes of the malfunction and
the excess emissions resulting from the
malfunction event at issue. The analysis
shall also specify, using best monitoring
methods and engineering judgment, the
amount of excess emissions that were
the result of the malfunction.
(b) Notification. The owner or
operator of the affected source
experiencing an exceedance of its
emission limit(s) during a malfunction
shall notify the Administrator by
telephone or facsimile (FAX)
transmission as soon as possible, but no
later than two business days after the
initial occurrence of the malfunction or,
if it is not possible to determine within
two business days whether the
malfunction caused or contributed to an
exceedance, no later than two business
days after the owner or operator knew
or should have known that the
malfunction caused or contributed to an
exceedance, but, in no event later than
two business days after the end of the
averaging period, if it wishes to avail
itself of an affirmative defense to civil
penalties for that malfunction. The
owner or operator seeking to assert an
affirmative defense shall also submit a
written report to the Administrator
within 45 days of the initial occurrence
of the exceedance of the standard in
§ 63.9991 to demonstrate, with all
necessary supporting documentation,
that it has met the requirements set forth
in paragraph (a) of this section. The
owner or operator may seek an
extension of this deadline for up to 30
additional days by submitting a written
request to the Administrator before the
expiration of the 45 day period. Until a
request for an extension has been
approved by the Administrator, the
owner or operator is subject to the
requirement to submit such report
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within 45 days of the initial occurrence
of the exceedance.
Testing and Initial Compliance
Requirements
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§ 63.10005 What are my initial compliance
requirements and by what date must I
conduct them?
(a) General requirements. For each of
your affected EGUs, you must
demonstrate initial compliance with
each applicable emissions limit in Table
1 or 2 of this subpart through
performance testing. Where two
emissions limits are specified for a
particular pollutant (e.g., a heat inputbased limit in lb/MMBtu and an
electrical output-based limit in lb/
MWh), you may demonstrate
compliance with either emission limit.
For a particular compliance
demonstration, you may be required to
conduct one or more of the following
activities in conjunction with
performance testing: collection of
hourly electrical load data (megawatts);
establishment of operating limits
according to § 63.10011 and Tables 4
and 7 to this subpart; and CMS
performance evaluations. In all cases,
you must demonstrate initial
compliance no later than the applicable
date in paragraph (f) of this section for
tune-up work practices for existing
EGUs, in § 63.9984 for other
requirements for existing EGUs, and in
paragraph (g) of this section for all
requirements for new EGUs.
(1) To demonstrate initial compliance
with an applicable emissions limit in
Table 1 or 2 to this subpart using stack
testing, the initial performance test
generally consists of three runs at
specified process operating conditions
using approved methods. If you are
required to establish operating limits
(see paragraph (d) of this section and
Table 4 to this subpart), you must
collect all applicable parametric data
during the performance test period.
Also, if you choose to comply with an
electrical output-based emission limit,
you must collect hourly electrical load
data during the test period.
(2) To demonstrate initial compliance
using either a CMS that measures HAP
concentrations directly (i.e., an Hg, HCl,
or HF CEMS, or a sorbent trap
monitoring system) or an SO2 or PM
CEMS, the initial performance test
consists of 30 boiler operating days of
data collected by the initial compliance
demonstration date specified in
§ 63.10005 with the certified monitoring
system.
(i) The 30-boiler operating day CMS
performance test must demonstrate
compliance with the applicable Hg, HCl,
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HF, PM, or SO2 emissions limit in Table
1 or 2 to this subpart.
(ii) If you choose to comply with an
electrical output-based emission limit,
you must collect hourly electrical load
data during the performance test period.
(b) Performance testing requirements.
If you choose to use performance testing
to demonstrate initial compliance with
the applicable emissions limits in
Tables 1 and 2 to this subpart for your
EGUs, you must conduct the tests
according to § 63.10007 and Table 5 to
this subpart. For the purposes of the
initial compliance demonstration, you
may use test data and results from a
performance test conducted prior to the
date on which compliance is required as
specified in § 63.9984, provided that the
following conditions are fully met:
(1) For a performance test based on
stack test data, the test was conducted
no more than 12 calendar months prior
to the date on which compliance is
required as specified in § 63.9984;
(2) For a performance test based on
data from a certified CEMS or sorbent
trap monitoring system, the test consists
of all valid data CMS data recorded in
the 30 boiler operating days
immediately preceding that date;
(3) The performance test was
conducted in accordance with all
applicable requirements in § 63.10007
and Table 5 to this subpart;
(4) A record of all parameters needed
to convert pollutant concentrations to
units of the emission standard (e.g.,
stack flow rate, diluent gas
concentrations, hourly electrical loads)
is available for the entire performance
test period; and
(5) For each performance test based
on stack test data, you certify, and keep
documentation demonstrating, that the
EGU configuration, control devices, and
fuel(s) have remained consistent with
conditions since the prior performance
test was conducted.
(c) Operating limits. In accordance
with § 63.10010 and Table 4 to this
subpart, you may be required to
establish operating limits using PM
CPMS and using site-specific
monitoring for certain liquid oil-fired
units as part of your initial compliance
demonstration.
(d) CMS requirements. If, for a
particular emission or operating limit,
you are required to (or elect to)
demonstrate initial compliance using a
continuous monitoring system, the CMS
must pass a performance evaluation
prior to the initial compliance
demonstration. If a CMS has been
previously certified under another state
or federal program and is continuing to
meet the on-going quality-assurance
(QA) requirements of that program,
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9469
then, provided that the certification and
QA provisions of that program meet the
applicable requirements of
§§ 63.10010(b) through (h), an
additional performance evaluation of
the CMS is not required under this
subpart.
(1) For an affected coal-fired, solid oilderived fuel-fired, or liquid oil-fired
EGU, you may demonstrate initial
compliance with the applicable SO2,
HCl, or HF emissions limit in Table 1
or 2 of this subpart through use of an
SO2, HCl, or HF CEMS installed and
operated in accordance with part 75 of
this chapter or Appendix B to this
subpart, as applicable. You may also
demonstrate compliance with a
filterable PM emission limit in Table 1
or 2 of this subpart through use of a PM
CEMS installed, certified, and operated
in accordance with § 63.10010(i). Initial
compliance is achieved if the arithmetic
average of 30-boiler operating days of
quality-assured CEMS data, expressed
in units of the standard (see
§ 63.10007(e)), meets the applicable
SO2, PM, HCl, or HF emissions limit in
Table 1 or 2 to this subpart. Use
Equation 19–19 of Method 19 in
appendix A–7 to part 60 of this chapter
to calculate the 30-boiler operating day
average emissions rate. (Note: for this
calculation, the term Ehj in Equation 19–
19 must be in the same units of measure
as the applicable HCl or HF emission
limit in Table 1 or 2 to this subpart).
(2) For affected coal-fired or solid oilderived fuel-fired EGUs that
demonstrate compliance with the
applicable emission limits for total nonmercury HAP metals, individual nonmercury HAP metals, total HAP metals,
individual HAP metals, or filterable PM
listed in Table 1 or 2 to this subpart
using initial performance testing and
continuous monitoring with PM CPMS:
(i) You must demonstrate initial
compliance no later than the applicable
date specified in § 63.9984(f) for existing
EGUs and in paragraph (g) of this
section for new EGUs.
(ii) You must demonstrate continuous
compliance with the PM CPMS sitespecific operating limit that
corresponding to the results of the
performance test demonstrating
compliance with the pollutant with
which you choose to comply.
(iii) You must repeat the performance
test annually for the selected pollutant
emissions limit and reassess and adjust
the site-specific operating limit in
accordance with the results of the
performance test.
(3) For affected EGUs that are either
required to or elect to demonstrate
initial compliance with the applicable
Hg emission limit in Table 1 or 2 of this
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subpart using Hg CEMS or sorbent trap
monitoring systems, initial compliance
must be demonstrated no later than the
applicable date specified in § 63.9984(f)
for existing EGUs and in paragraph (g)
of this section for new EGUs. Initial
compliance is achieved if the arithmetic
average of 30-boiler operating days of
quality-assured CEMS (or sorbent trap
monitoring system) data, expressed in
units of the standard (see section 6.2 of
appendix A to this subpart), meets the
applicable Hg emission limit in Table 1
or 2 to this subpart.
(4) For affected liquid oil-fired EGUs
that demonstrate compliance with the
applicable emission limits for HCl or HF
listed in Table 1 or 2 to this subpart
using quarterly testing and continuous
monitoring with a CMS:
(i) You must demonstrate initial
compliance no later than the applicable
date specified in § 63.9984 for existing
EGUs and in paragraph (g) of this
section for new EGUs.
(ii) You must demonstrate continuous
compliance with the CMS site-specific
operating limit that corresponding to the
results of the performance test
demonstrating compliance with the HCl
or HF emissions limit.
(iii) You must repeat the performance
test annually for the HCl or HF
emissions limit and reassess and adjust
the site-specific operating limit in
accordance with the results of the
performance test.
(e) Tune-ups. All affected EGUs are
subject to the work practice standards in
Table 3 of this subpart. As part of your
initial compliance demonstration, you
must conduct a performance tune-up of
your EGU according to § 63.10021(e).
(f) For existing affected sources a
tune-up may occur prior to April 16,
2012, so that existing sources without
neural networks have up to 42 calendar
months (3 years from promulgation plus
180 days) or, in the case of units
employing neural network combustion
controls, up to 54 calendar months (48
months from promulgation plus 180
days) after the date that is specified for
your source in § 63.9984 and according
to the applicable provisions in
§ 63.7(a)(2) as cited in Table 9 to this
subpart to demonstrate compliance with
this requirement. If a tune-up occurs
prior to such date, the source must
maintain adequate records to show that
the tune-up met the requirements of this
standard.
(g) If your new or reconstructed
affected source commenced
construction or reconstruction between
May 3, 2011, and July 2, 2011, you must
demonstrate initial compliance with
either the proposed emission limits or
the promulgated emission limits no later
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than 180 days after April 16, 2012 or
within 180 days after startup of the
source, whichever is later, according to
§ 63.7(a)(2)(ix).
(1) For the new or reconstructed
affected source described in this
paragraph (g), if you choose to comply
with the proposed emission limits when
demonstrating initial compliance, you
must conduct a second compliance
demonstration for the promulgated
emission limits within 3 years after
April 16, 2012 or within 3 years after
startup of the affected source, whichever
is later.
(2) If your new or reconstructed
affected source commences construction
or reconstruction after April 16, 2012,
you must demonstrate initial
compliance with the promulgated
emission limits no later than 180 days
after startup of the source.
(h) Low emitting EGUs. The
provisions of this paragraph (h) apply to
pollutants with emissions limits from
new EGUs except Hg and to all
pollutants with emissions limits from
existing EGUs. You may not pursue this
compliance option if your existing EGU
is equipped with an acid gas scrubber
and has a main stack and bypass stack
exhaust configuration.
(1) An EGU may qualify for low
emitting EGU (LEE) status for Hg, HCl,
HF, filterable PM, total non-Hg HAP
metals, or individual non-Hg HAP
metals (or total HAP metals or
individual HAP metals, for liquid oilfired EGUs) if you collect performance
test data that meet the requirements of
this paragraph (h), and if those data
demonstrate:
(i) For all pollutants except Hg,
performance test emissions results less
than 50 percent of the applicable
emissions limits in Table 1 or 2 to this
subpart for all required testing for 3
consecutive years; or
(ii) For Hg emissions from an existing
EGU, either:
(A) Average emissions less than 10
percent of the applicable Hg emissions
limit in Table 2 to this subpart
(expressed either in units of lb/TBtu or
lb/GWh); or
(B) Potential Hg mass emissions of
29.0 or fewer pounds per year and
compliance with the applicable Hg
emission limit in Table 2 to this subpart
(expressed either in units of lb/TBtu or
lb/GWh).
(2) For all pollutants except Hg, you
must conduct all required performance
tests described in § 63.10007 to
demonstrate that a unit qualifies for LEE
status.
(i) When conducting emissions testing
to demonstrate LEE status, you must
increase the minimum sample volume
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specified in Table 1 or 2 nominally by
a factor of two.
(ii) Follow the instructions in
§ 63.10007(e) and Table 5 to this subpart
to convert the test data to the units of
the applicable standard.
(3) For Hg, you must conduct a 30boiler operating day performance test
using Method 30B in appendix A–8 to
part 60 of this chapter to determine
whether a unit qualifies for LEE status.
Locate the Method 30B sampling probe
tip at a point within the 10 percent
centroidal area of the duct at a location
that meets Method 1 in appendix A–1
to part 60 of this chapter and conduct
at least three nominally equal length test
runs over the 30-boiler operating day
test period. Collect Hg emissions data
continuously over the entire test period
(except when changing sorbent traps or
performing required reference method
QA procedures), under all process
operating conditions. You may use a
pair of sorbent traps to sample the stack
gas for no more than 10 days.
(i) Depending on whether you intend
to assess LEE status for Hg in terms of
the lb/TBtu or lb/GWh emission limit in
Table 2 to this subpart or in terms of the
annual Hg mass emissions limit of 29.0
lb/year, you will have to collect some or
all of the following data during the 30boiler operating day test period (see
paragraph (h)(3)(iii) of this section):
(A) Diluent gas (CO2 or O2) data, using
either Method 3A in appendix A–3 to
part 60 of this chapter or a diluent gas
monitor that has been certified
according to part 75 of this chapter.
(B) Stack gas flow rate data, using
either Method 2, 2F, or 2G in
appendices A–1 and A–2 to part 60 of
this chapter, or a flow rate monitor that
has been certified according to part 75
of this chapter.
(C) Stack gas moisture content data,
using either Method 4 in appendix A–
1 to part 60 of this chapter, or a
moisture monitoring system that has
been certified according to part 75 of
this chapter. Alternatively, an
appropriate fuel-specific default
moisture value from § 75.11(b) of this
chapter may be used in the calculations
or you may petition the Administrator
under § 75.66 of this chapter for use of
a default moisture value for non-coalfired units.
(D) Hourly electrical load data
(megawatts), from facility records.
(ii) If you use CEMS to measure CO2
(or O2) concentration, and/or flow rate,
and/or moisture, record hourly average
values of each parameter throughout the
30-boiler operating day test period. If
you opt to use EPA reference methods
rather than CEMS for any parameter,
you must perform at least one
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representative test run on each
operating day of the test period, using
the applicable reference method.
(iii) Calculate the average Hg
concentration, in mg/m3 (dry basis), for
the 30-boiler operating day performance
test, as the arithmetic average of all
Method 30B sorbent trap results. Also
calculate, as applicable, the average
values of CO2 or O2 concentration, stack
gas flow rate, stack gas moisture
content, and electrical load for the test
period. Then:
(A) To express the test results in units
of lb/TBtu, follow the procedures in
§ 63.10007(e). Use the average Hg
concentration and diluent gas values in
the calculations.
(B) To express the test results in units
of lb/GWh, use Equations A–3 and A–
4 in section 6.2.2 of appendix A to this
subpart, replacing the hourly values
‘‘Ch’’, ‘‘Qh’’, ‘‘Bws’’ and ‘‘(MW)h’’ with the
average values of these parameters from
the performance test.
(C) To calculate pounds of Hg per
year, use one of the following methods:
(1) Multiply the average lb/TBtu Hg
emission rate (determined according to
paragraph (h)(3)(iii)(A) of this section)
by the maximum potential annual heat
input to the unit (TBtu), which is equal
to the maximum rated unit heat input
(TBtu/hr) times 8,760 hours. If the
maximum rated heat input value is
expressed in units of MMBtu/hr,
multiply it by 106 to convert it to TBtu/
hr; or
(2) Multiply the average lb/GWh Hg
emission rate (determined according to
paragraph (h)(3)(iii)(B) of this section)
by the maximum potential annual
electricity generation (GWh), which is
equal to the maximum rated electrical
output of the unit (GW) times 8,760
hours. If the maximum rated electrical
output value is expressed in units of
MW, multiply it by 103 to convert it to
GW; or
(3) If an EGU has a federallyenforceable permit limit on either the
annual heat input or the number of
annual operating hours, you may
modify the calculations in paragraph
(h)(3)(iii)(C)(1) of this section by
replacing the maximum potential
annual heat input or 8,760 unit
operating hours with the permit limit on
annual heat input or operating hours (as
applicable).
(4) For a group of affected units that
vent to a common stack, you may either
assess LEE status for the units
individually by performing a separate
emission test of each unit in the duct
leading from the unit to the common
stack, or you may perform a single
emission test in the common stack. If
you choose the common stack testing
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option, the units in the configuration
qualify for LEE status if:
(i) The emission rate measured at the
common stack is less than 50 percent
(10 percent for Hg) of the applicable
emission limit in Table 1 or 2 to this
subpart; or
(ii) For Hg from an existing EGU, the
applicable Hg emission limit in Table 2
to this subpart is met and the potential
annual mass emissions, calculated
according to paragraph (h)(3)(iii) of this
section (with some modifications), are
less than or equal to 29.0 pounds times
the number of units sharing the
common stack. Base your calculations
on the combined heat input capacity of
all units sharing the stack (i.e., either
the combined maximum rated value or,
if applicable, a lower combined value
restricted by permit conditions or
operating hours).
(5) For an affected unit with a
multiple stack or duct configuration in
which the exhaust stacks or ducts are
downstream of all emission control
devices, you must perform a separate
emission test in each stack or duct. The
unit qualifies for LEE status if:
(i) The emission rate, based on all test
runs performed at all of the stacks or
ducts, is less than 50 percent (10
percent for Hg) of the applicable
emission limit in Table 1 or 2 to this
subpart; or
(ii) For Hg from an existing EGU, the
applicable Hg emission limit in Table 2
to this subpart is met and the potential
annual mass emissions, calculated
according to paragraph (h)(3)(iii) of this
section, are less than or equal to 29.0
pounds. Use the average Hg emission
rate from paragraph (h)(5)(i) of this
section in your calculations.
(i) Liquid-oil fuel moisture
measurement. If your EGU combusts
liquid fuels, if your fuel moisture
content is no greater than 1.0 percent by
weight, and if you would like to
demonstrate initial and ongoing
compliance with HCl and HF emissions
limits, you must meet the requirements
of paragraphs (i)(1) through (5) of this
section.
(1) Measure fuel moisture content of
each shipment of fuel if your fuel
arrives on a batch basis; or
(2) Measure fuel moisture content
daily if your fuel arrives on a
continuous basis; or
(3) Obtain and maintain a fuel
moisture certification from your fuel
supplier.
(4) Use one of the following methods
to determine fuel moisture content:
(i) ASTM D95–05 (Reapproved 2010),
‘‘Standard Test Method for Water in
Petroleum Products and Bituminous
Materials by Distillation,’’ or
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(ii) ASTM D4006–11, ‘‘Standard Test
Method for Water in Crude Oil by
Distillation,’’ including Annex A1 and
Appendix A1, or
(iii) ASTM D4177–95 (Reapproved
2010), ‘‘Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products,’’ including Annexes A1
through A6 and Appendices X1 and X2,
or
(iv) ASTM D4057–06 (Reapproved
2011), ‘‘Standard Practice for Manual
Sampling of Petroleum and Petroleum
Products,’’ including Annex A1.
(5) Should the moisture in your liquid
fuel be more than 1.0 percent by weight,
you must
(i) Conduct HCl and HF emissions
testing quarterly (and monitor sitespecific operating parameters as
provided in § 63.10000(c)(2)(iii) or
(ii) Use an HCl CEMS and/or HF
CEMS.
(j) Startup and shutdown for coalfired or solid oil derived-fired units.
You must follow the requirements given
in Table 3 to this subpart.
(k) You must submit a Notification of
Compliance Status summarizing the
results of your initial compliance
demonstration, as provided in
§ 63.10030.
§ 63.10006 When must I conduct
subsequent performance tests or tune-ups?
(a) For liquid oil-fired, solid oilderived fuel- and coal-fired EGUs and
IGCC units using PM CPMS to monitor
continuous performance with an
applicable emission limit as provided
for under § 63.10000(c), you must
conduct all applicable performance tests
according to Table 5 to this subpart and
§ 63.10007 at least every year.
(b) For affected units meeting the LEE
requirements of § 63.10005(h), you must
repeat the performance test once every
3 years (once every year for Hg)
according to Table 5 and § 63.10007.
Should subsequent emissions testing
results show the unit does not meet the
LEE eligibility requirements, LEE status
is lost. If this should occur:
(1) For all pollutant emission limits
except for Hg, you must conduct
emissions testing quarterly, except as
otherwise provided in § 63.10021(d)(1).
(2) For Hg, you must install, certify,
maintain, and operate a Hg CEMS or a
sorbent trap monitoring system in
accordance with appendix A to this
subpart, within 6 calendar months of
losing LEE eligibility. Until the Hg
CEMS or sorbent trap monitoring system
is installed, certified, and operating, you
must conduct Hg emissions testing
quarterly, except as otherwise provided
in § 63.10021(d)(1). You must have 3
calendar years of testing and CEMS or
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sorbent trap monitoring system data that
satisfy the LEE emissions criteria to
reestablish LEE status.
(c) Except where paragraphs (a) or (b)
of this section apply, or where you
install, certify, and operate a PM CEMS
to demonstrate compliance with a
filterable PM emission limit, for liquid
oil-fired EGUs, you must conduct all
applicable periodic emissions tests for
filterable PM, or individual or total HAP
metals emissions according to Table 5 to
this subpart and § 63.10007 at least
quarterly, except as otherwise provided
in § 63.10021(d)(1).
(d) Except where paragraph (b) of this
section applies, for solid oil-derived
fuel- and coal-fired EGUs that do not
use either an HCl CEMS to monitor
compliance with the HCl limit or an SO2
CEMS to monitor compliance with the
alternate equivalent SO2 emission limit,
you must conduct all applicable
periodic HCl emissions tests according
to Table 5 to this subpart and § 63.10007
at least quarterly, except as otherwise
provided in § 63.10021(d)(1).
(e) Except where paragraph (b) of this
section applies, for liquid oil-fired EGUs
without HCl CEMS, HF CEMS, or HCl
and HF CEMS, you must conduct all
applicable emissions tests for HCl, HF,
or HCl and HF emissions according to
Table 5 to this subpart and § 63.10007
at least quarterly, except as otherwise
provided in § 63.10021(d)(1), and
conduct site-specific monitoring under a
plan as provided for in
§ 63.10000(c)(2)(iii).
(f) Unless you follow the requirements
listed in paragraphs (g) and (h) of this
section, performance tests required at
least every 3 calendar years must be
completed within 35 to 37 calendar
months after the previous performance
test; performance tests required at least
every year must be completed within 11
to 13 calendar months after the previous
performance test; and performance tests
required at least quarterly must be
completed within 80 to 100 calendar
days after the previous performance test,
except as otherwise provided in
§ 63.10021(d)(1).
(g) If you elect to demonstrate
compliance using emissions averaging
under § 63.10009, you must continue to
conduct performance stack tests at the
appropriate frequency given in section
(c) through (f) of this section.
(h) If a performance test on a nonmercury LEE shows emissions in excess
of 50 percent of the emission limit and
if you choose to reapply for LEE status,
you must conduct performance tests at
the appropriate frequency given in
section (c) through (e) of this section for
that pollutant until all performance tests
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over a consecutive 3-year period show
compliance with the LEE criteria.
(i) If you are required to meet an
applicable tune-up work practice
standard, you must conduct a
performance tune-up according to
§ 63.10021(e).
(1) For EGUs not employing neural
network combustion optimization
during normal operation, each
performance tune-up specified in
§ 63.10021(e) must be no more than 36
calendar months after the previous
performance tune-up.
(2) For EGUs employing neural
network combustion optimization
systems during normal operation, each
performance tune-up specified in
§ 63.10021(e) must be no more than 48
calendar months after the previous
performance tune-up.
(j) You must report the results of
performance tests and performance
tune-ups within 60 days after the
completion of the performance tests and
performance tune-ups. The reports for
all subsequent performance tests must
include all applicable information
required in § 63.10031.
§ 63.10007 What methods and other
procedures must I use for the performance
tests?
(a) Except as otherwise provided in
this section, you must conduct all
required performance tests according to
§ 63.7(d), (e), (f), and (h). You must also
develop a site-specific test plan
according to the requirements in
§ 63.7(c).
(1) If you use CEMS (Hg, HCl, SO2, or
other) to determine compliance with a
30-boiler operating day rolling average
emission limit, you must collect data for
all nonexempt unit operating conditions
(see § 63.10011(g) and Table 3 to this
subpart).
(2) If you conduct performance testing
with test methods in lieu of continuous
monitoring, operate the unit at
maximum normal operating load
conditions during each periodic (e.g.,
quarterly) performance test. Maximum
normal operating load will be generally
between 90 and 110 percent of design
capacity but should be representative of
site specific normal operations during
each test run.
(3) For establishing operating limits
with particulate matter continuous
parametric monitoring system (PM
CPMS) to demonstrate compliance with
a PM or non Hg metals emissions limit,
operate the unit at maximum normal
operating load conditions during the
performance test period. Maximum
normal operating load will be generally
between 90 and 110 percent of design
capacity but should be representative of
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site specific normal operations during
each test run.
(b) You must conduct each
performance test (including traditional
3-run stack tests, 30-boiler operating day
tests based on CEMS data (or sorbent
trap monitoring system data), and 30boiler operating day Hg emission tests
for LEE qualification) according to the
requirements in Table 5 to this subpart.
(c) If you choose to comply with the
filterable PM emission limit and
demonstrate continuous performance
using a PM CPMS for an applicable
emission limit as provided for in
§ 63.10000(c), you must also establish
an operating limit according to
§ 63.10011(b)(5) and Tables 4 and 6 to
this subpart. Should you desire to have
operating limits that correspond to loads
other than maximum normal operating
load, you must conduct testing at those
other loads to determine the additional
operating limits.
(d) Except for a 30-boiler operating
day performance test based on CEMS (or
sorbent trap monitoring system) data,
where the concept of test runs does not
apply, you must conduct a minimum of
three separate test runs for each
performance test, as specified in
§ 63.7(e)(3). Each test run must comply
with the minimum applicable sampling
time or volume specified in Table 1 or
2 to this subpart. Sections 63.10005(d)
and (h), respectively, provide special
instructions for conducting performance
tests based on CEMS or sorbent trap
monitoring systems, and for conducting
emission tests for LEE qualification.
(e) To use the results of performance
testing to determine compliance with
the applicable emission limits in Table
1 or 2 to this subpart, proceed as
follows:
(1) Except for a 30-boiler operating
day performance test based on CEMS (or
sorbent trap monitoring system) data, if
measurement results for any pollutant
are reported as below the method
detection level (e.g., laboratory
analytical results for one or more
sample components are below the
method defined analytical detection
level), you must use the method
detection level as the measured
emissions level for that pollutant in
calculating compliance. The measured
result for a multiple component analysis
(e.g., analytical values for multiple
Method 29 fractions both for individual
HAP metals and for total HAP metals)
may include a combination of method
detection level data and analytical data
reported above the method detection
level.
(2) If the limits are expressed in lb/
MMBtu or lb/TBtu, you must use the Ffactor methodology and equations in
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appendix A to this subpart to calculate
the pollutant emission rate in lb/GWh.
In this calculation, define (M)h as the
calculated pollutant mass emission rate
for the performance test (lb/h), and
define (MW)h as the average electrical
load during the performance test
(megawatts). If the applicable emission
limit is in lb/MWh rather than lb/GWh,
omit the 103 term from Equation A–4 to
determine the pollutant emission rate in
lb/MWh.
(f) Upon request, you shall make
available to the EPA Administrator such
records as may be necessary to
determine whether the performance
tests have been done according to the
requirements of this section.
Where:
WAERm = Weighted average emissions rate
maximum in terms of lb/heat input or lb/
gross electrical output,
Hermi = Hourly emissions rate (e.g., lb/
MMBtu, lb/MWh) from CEMS or sorbent
trap monitoring for hour i,
Rmmi = Maximum rated heat input or gross
electrical output of unit i in terms of heat
input or gross electrical output,
p = number of EGUs in emissions averaging
group that rely on CEMS,
n = number of hourly rates collected over 30group boiler operating days,
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§ 63.10008
[Reserved]
§ 63.10009 May I use emissions averaging
to comply with this subpart?
(a) General eligibility. (1) You may use
emissions averaging as described in
paragraph (a)(2) of this section as an
alternative to meeting the requirements
of § 63.9991 for filterable PM, SO2, HF,
HCl, non-Hg HAP metals, or Hg on an
EGU-specific basis if:
(i) You have more than one existing
EGU in the same subcategory located at
one or more contiguous properties,
belonging to a single major industrial
grouping, which are under common
control of the same person (or persons
under common control); and
(ii) You use CEMS (or sorbent trap
monitoring systems for determining Hg
emissions) or quarterly emissions
testing for demonstrating compliance.
(2) You may demonstrate compliance
by emissions averaging among the
existing EGUs in the same subcategory,
if your averaged Hg emissions for EGUs
in the ‘‘unit designed for coal ≥ 8,300
Btu/lb’’ subcategory are equal to or less
than 1.0 lb/TBtu or 1.1E–2 lb/GWh or if
your averaged emissions of individual,
other pollutants from other
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subcategories of such EGUs are equal to
or less than the applicable emissions
limit in Table 2, according to the
procedures in this section. Note that
except for Hg emissions from EGUs in
the ‘‘unit designed for coal ≥ 8,300 Btu/
lb’’ subcategory, the averaging time for
emissions averaging for pollutants is 30
days (rolling daily) using data from
CEMS or a combination of data from
CEMS and manual performance testing.
The averaging time for emissions
averaging for Hg from EGUs in the ‘‘unit
designed for coal ≥ 8,300 Btu/lb’’
subcategory is 90 days (rolling daily)
using data from CEMS, sorbent trap
monitoring, or a combination of
monitoring data and data from manual
performance testing. For the purposes of
this paragraph, 30- (or 90-day) group
boiler operating days is defined as a
period during which at least one unit in
the emissions averaging group has
operated 30 (or 90) days. You must
calculate the weighted average
emissions rate for the group in
accordance with the procedures in this
paragraph using the data from all units
in the group including any that operate
fewer than 30 (or 90) days during the
preceding 30 (or 90) group boiler days.
(i) You may choose to have your EGU
emissions averaging group meet either
the heat input basis (MMBtu or TBtu, as
appropriate for the pollutant) or gross
electrical output basis (MWh or GWh, as
appropriate for the pollutant).
(ii) You may not mix bases within
your EGU emissions averaging group.
(iii) You may use emissions averaging
for affected units in different
subcategories if the units vent to the
atmosphere through a common stack
(see paragraph (m) of this section).
(b) Equations. Use the following
equations when performing calculations
for your EGU emissions averaging
group:
(1) Group eligibility equations.
Teri = Emissions rate from most recent test
of unit i in terms of lb/heat input or lb/
gross electrical output,
Rmti = Maximum rated heat input or gross
electrical output of unit i in terms of lb/
heat input or lb/gross electrical output,
and
m = number of EGUs in emissions averaging
group that rely on emissions testing.
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sections 12.2 and 12.3 of EPA Method
19 in appendix A–7 to part 60 of this
chapter. In cases where an appropriate
F-factor is not listed in Table 19–2 of
Method 19, you may use F-factors from
Table 1 in section 3.3.5 of appendix F
to part 75 of this chapter, or F-factors
derived using the procedures in section
3.3.6 of appendix to part 75 of this
chapter. Use the following factors to
convert the pollutant concentrations
measured during the initial performance
tests to units of lb/scf, for use in the
applicable Method 19 equations:
(i) Multiply SO2 ppm by 1.66 × 10¥7;
(ii) Multiply HCl ppm by 9.43 × 10¥8;
(iii) Multiply HF ppm by 5.18 × 10¥8;
(iv) Multiply HAP metals
concentrations (mg/dscm) by 6.24 ×
10¥8; and
(v) Multiply Hg concentrations (mg/
scm) by 6.24 × 10¥11.
(3) To determine compliance with
emission limits expressed in lb/MWh or
lb/GWh, you must first calculate the
pollutant mass emission rate during the
performance test, in units of lb/h. For
Hg, if a CEMS or sorbent trap
monitoring system is used, use Equation
A–2 or A–3 in appendix A to this
subpart (as applicable). In all other
cases, use an equation that has the
general form of Equation A–2 or A–3,
replacing the value of K with 1.66 ×
10¥7 lb/scf-ppm for SO2, 9.43 × 10¥8 lb/
scf-ppm for HCl (if an HCl CEMS is
used), 5.18 × 10¥8 lb/scf-ppm for HF (if
an HF CEMS is used), or 6.24 × 10¥8 lbscm/mg-scf for HAP metals and for HCl
and HF (when performance stack testing
is used), and defining Ch as the average
SO2, HCl, or HF concentration in ppm,
or the average HAP metals
concentration in mg/dscm. This
calculation requires stack gas
volumetric flow rate (scfh) and (in some
cases) moisture content data (see
§§ 63.10005(h)(3) and 63.10010). Then,
if the applicable emission limit is in
units of lb/GWh, use Equation A–4 in
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Where:
generated or gross electrical output per
pound of steam generated, from unit i
that uses CEMS or sorbent trap
monitoring,
Smti = maximum steam generation in units
of pounds from unit i that uses emissions
testing, and
Cfti = conversion factor, calculated from the
most recent emissions test results, in
units of heat input per pound of steam
variables with similar names share the
descriptions for Equation 1a,
Smmi = maximum steam generation in units
of pounds from unit i that uses CEMS or
sorbent trap monitoring,
Cfmi = conversion factor, calculated from the
most recent emissions test results, in
units of heat input per pound of steam
Where:
Heri = hourly emission rate (e.g., lb/MMBtu,
lb/MWh) from unit i’s CEMS for the
preceding 30-group boiler operating
days,
Rmi = hourly heat input or gross electrical
output from unit i for the preceding 30group boiler operating days,
Where:
generated or gross electrical output per
pound of steam generated, from unit i
that uses CEMS from the preceding 30group boiler operating days,
Sti = steam generation in units of pounds
from unit i that uses emissions testing,
and
Cfti = conversion factor, calculated from the
most recent compliance test results, in
units of heat input per pound of steam
generated or gross electrical output per
(2) Weighted 30-day rolling average
emissions rate equations for pollutants
other than Hg. Use equation 2a or 2b to
calculate the 30-day rolling average
emissions daily.
Rti = Maximum rated heat input or gross
electrical output of unit i in terms of lb/
heat input or lb/gross electrical output,
and
m = number of EGUs in emissions averaging
group that rely on emissions testing.
pound of steam generated, from unit i
that uses emissions testing.
(3) Weighted 90-boiler operating day
rolling average emissions rate equations
for Hg emissions from EGUs in the ‘‘unit
designed for coal ≥ 8,300 Btu/lb’’
subcategory. Use equation 3a or 3b to
calculate the 90-day rolling average
emissions daily.
Rti = Maximum rated heat input or gross
electrical output of unit i in terms of lb/
heat input or lb/gross electrical output,
and
m = number of EGUs in emissions averaging
group that rely on emissions testing.
ER16FE12.006</GPH>
p = number of EGUs in emissions averaging
group that rely on CEMS,
n = number of hourly rates collected over the
90-group boiler operating days,
Teri = Emissions rate from most recent
emissions test of unit i in terms of lb/
heat input or lb/gross electrical output,
ER16FE12.005</GPH>
Heri = hourly emission rate from unit i’s
CEMS or Hg sorbent trap monitoring for
the preceding 90-group boiler operating
days,
Rmi = hourly heat input or gross electrical
output from unit i for the preceding 90group boiler operating days,
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ER16FE12.004</GPH>
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Where:
ER16FE12.007</GPH>
ER16FE12.008</GPH>
variables with similar names share the
descriptions for Equation 2a,
Smi = steam generation in units of pounds
from unit i that uses CEMS for the
preceding 30-group boiler operating
days,
Cfmi = conversion factor, calculated from the
most recent compliance test results, in
units of heat input per pound of steam
p = number of EGUs in emissions averaging
group that rely on CEMS or sorbent trap
monitoring,
n = number of hourly rates collected over 30group boiler operating days,
Teri = Emissions rate from most recent
emissions test of unit i in terms of lb/
heat input or lb/gross electrical output,
generated or gross electrical output per
pound of steam generated, from unit i
that uses emissions testing.
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
Where:
srobinson on DSK4SPTVN1PROD with RULES2
variables with similar names share the
descriptions for Equation 2a,
Smi = steam generation in units of pounds
from unit i that uses CEMS or a Hg
sorbent trap monitoring for the preceding
90-group boiler operating days,
Cfmi = conversion factor, calculated from the
most recent compliance test results, in
units of heat input per pound of steam
generated or gross electrical output per
pound of steam generated, from unit i
that uses CEMS or sorbent trap
monitoring from the preceding 90-group
boiler operating days,
Sti = steam generation in units of pounds
from unit i that uses emissions testing,
and
Cfti = conversion factor, calculated from the
most recent emissions test results, in
units of heat input per pound of steam
generated or gross electrical output per
pound of steam generated, from unit i
that uses emissions testing.
(c) Separate stack requirements. For a
group of two or more existing EGUs in
the same subcategory that each vent to
a separate stack, you may average
filterable PM, SO2, HF, HCl, non-Hg
HAP metals, or Hg emissions to
demonstrate compliance with the limits
in Table 2 to this subpart if you satisfy
the requirements in paragraphs (d)
through (j) of this section.
(d) For each existing EGU in the
averaging group:
(1) The emissions rate achieved
during the initial performance test for
the HAP being averaged must not
exceed the emissions level that was
being achieved 180 days after April 16,
2015, or the date on which emissions
testing done to support your emissions
averaging plan is complete (if the
Administrator does not require
submission and approval of your
emissions averaging plan), or the date
that you begin emissions averaging,
whichever is earlier; or
(2) The control technology employed
during the initial performance test must
not be less than the design efficiency of
the emissions control technology
employed 180 days after April 16, 2015
or the date that you begin emissions
averaging, whichever is earlier.
(e) The weighted-average emissions
rate from the existing EGUs
participating in the emissions averaging
option must be in compliance with the
limits in Table 2 to this subpart at all
times following the compliance date
specified 180 days after April 16, 2015,
or the date on which you complete the
emissions measurements used to
support your emissions averaging plan
(if the Administrator does not require
submission and approval of your
emissions averaging plan), or the date
that you begin emissions averaging,
whichever is earlier.
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(f) Emissions averaging group
eligibility demonstration. You must
demonstrate the ability for the EGUs
included in the emissions averaging
group to demonstrate initial compliance
according to paragraph (f)(1) or (2) of
this section using the maximum normal
operating load of each EGU and the
results of the initial performance tests.
For this demonstration and prior to
submitting your emissions averaging
plan, if requested, you must conduct
required emissions monitoring for 30
days of boiler operation and any
required manual performance testing to
calculate an initial weighted average
emissions rate in accordance with this
section. Should the Administrator
require approval, you must submit your
proposed emissions averaging plan and
supporting data at least 120 days before
April 16, 2015. If the Administrator
requires approval of your plan, you may
not begin using emissions averaging
until the Administrator approves your
plan.
(1) You must use Equation 1a in
paragraph (b) of this section to
demonstrate that the maximum
weighted average emissions rates of
filterable PM, HF, SO2, HCl, non-Hg
HAP metals, or Hg emissions from the
existing units participating in the
emissions averaging option do not
exceed the emissions limits in Table 2
to this subpart.
(2) If you are not capable of
monitoring heat input or gross electrical
output, and the EGU generates steam for
purposes other than generating
electricity, you may use Equation 1b of
this section as an alternative to using
Equation 1a of this section to
demonstrate that the maximum
weighted average emissions rates of
filterable PM, HF, SO2, HCl, non-Hg
HAP metals, or Hg emissions from the
existing units participating in the
emissions averaging group do not
exceed the emission limits in Table 2 to
this subpart.
(g) You must determine the weighted
average emissions rate in units of the
applicable emissions limit on a 30 day
rolling average (90 day rolling average
for Hg) basis according to paragraphs
(f)(1) through (3) of this section. The
first averaging period begins on 30 (or
90 for Hg) days after February 16, 2015
or the date that you begin emissions
averaging, whichever is earlier.
(1) You must use Equation 2a or 3a of
paragraph (b) of this section to calculate
the weighted average emissions rate
using the actual heat input or gross
electrical output for each existing unit
participating in the emissions averaging
option.
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(2) If you are not capable of
monitoring heat input or gross electrical
output, you may use Equation 2b or 3b
of paragraph (b) of this section as an
alternative to using Equation 2a of
paragraph (b) of this section to calculate
the average weighted emission rate
using the actual steam generation from
the units participating in the emissions
averaging option.
(h) CEMS (or sorbent trap monitoring)
use. If an EGU in your emissions
averaging group uses CEMS (or a
sorbent trap monitor for Hg emissions)
to demonstrate compliance, you must
use those data to determine the 30 (or
90) group boiler operating day rolling
average emissions rate.
(i) Emissions testing. If you use
manual emissions testing to
demonstrate compliance for one or more
EGUs in your emissions averaging
group, you must use the results from the
most recent performance test to
determine the 30 (or 90) day rolling
average. You may use CEMS or sorbent
trap data in combination with data from
the most recent manual performance
test in calculating the 30 (or 90) group
boiler operating day rolling average
emissions rate.
(j) Emissions averaging plan. You
must develop an implementation plan
for emissions averaging according to the
following procedures and requirements
in paragraphs (j)(1) and (2) of this
section.
(1) You must include the information
contained in paragraphs (j)(1)(i) through
(v) of this section in your
implementation plan for all the
emissions units included in an
emissions averaging:
(i) The identification of all existing
EGUs in the emissions averaging group,
including for each either the applicable
HAP emission level or the control
technology installed as of 180 days after
February 16, 2015, or the date on which
you complete the emissions
measurements used to support your
emissions averaging plan (if the
Administrator does not require
submission and approval of your
emissions averaging plan), or the date
that you begin emissions averaging,
whichever is earlier; and the date on
which you are requesting emissions
averaging to commence;
(ii) The process weighting parameter
(heat input, gross electrical output, or
steam generated) that will be monitored
for each averaging group;
(iii) The specific control technology or
pollution prevention measure to be used
for each emission EGU in the averaging
group and the date of its installation or
application. If the pollution prevention
measure reduces or eliminates
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emissions from multiple EGUs, you
must identify each EGU;
(iv) The means of measurement (e.g.,
CEMS, sorbent trap monitoring, manual
performance test) of filterable PM, SO2,
HF, HCl, individual or total non-Hg
HAP metals, or Hg emissions in
accordance with the requirements in
§ 63.10007 and to be used in the
emissions averaging calculations; and
(v) A demonstration that emissions
averaging can produce compliance with
each of the applicable emission limit(s)
in accordance with paragraph (b)(1) of
this section.
(2) If the Administrator requests you
to submit the plan for review and
approval, you must submit a complete
implementation plan at least 120 days
before April 16, 2015. If the
Administrator requests you to submit
the plan for review and approval, you
must receive approval before initiating
emissions averaging.
(i) The Administrator shall use
following criteria in reviewing and
approving or disapproving the plan:
(A) Whether the content of the plan
includes all of the information specified
in paragraph (h)(1) of this section; and
(B) Whether the plan presents
information sufficient to determine that
compliance will be achieved and
maintained.
(ii) The Administrator shall not
approve an emissions averaging
implementation plan containing any of
the following provisions:
(A) Any averaging between emissions
of different pollutants or between units
located at different facilities; or
(B) The inclusion of any emissions
unit other than an existing unit in the
same subcategory.
(k) Common stack requirements. For a
group of two or more existing affected
units, each of which vents through a
single common stack, you may average
emissions to demonstrate compliance
with the limits in Table 2 to this subpart
if you satisfy the requirements in
paragraph (l) or (m) of this section.
(l) For a group of two or more existing
units in the same subcategory and
which vent through a common
emissions control system to a common
stack that does not receive emissions
from units in other subcategories or
categories, you may treat such averaging
group as a single existing unit for
purposes of this subpart and comply
with the requirements of this subpart as
if the group were a single unit.
(m) For all other groups of units
subject to paragraph (k) of this section,
you may elect to conduct manual
performance tests according to
procedures specified in § 63.10007 in
the common stack. If emissions from
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affected units included in the emissions
averaging and from other units not
included in the emissions averaging
(e.g., in a different subcategory) or other
nonaffected units all vent to the
common stack, you must shut down the
units not included in the emissions
averaging and the nonaffected units or
vent their emissions to a different stack
during the performance test.
Alternatively, you may conduct a
performance test of the combined
emissions in the common stack with all
units operating and show that the
combined emissions meet the most
stringent emissions limit. You may also
use a CEMS or sorbent trap monitoring
to apply this latter alternative to
demonstrate that the combined
emissions comply with the most
stringent emissions limit on a
continuous basis.
(n) Combination requirements. The
common stack of a group of two or more
existing EGUs in the same subcategory
subject to paragraph (k) of this section
may be treated as a single stack for
purposes of paragraph (c) of this section
and included in an emissions averaging
group subject to paragraph (c) of this
section.
§ 63.10010 What are my monitoring,
installation, operation, and maintenance
requirements?
(a) Flue gases from the affected units
under this subpart exhaust to the
atmosphere through a variety of
different configurations, including but
not limited to individual stacks, a
common stack configuration or a main
stack plus a bypass stack. For the CEMS,
PM CPMS, and sorbent trap monitoring
systems used to provide data under this
subpart, the continuous monitoring
system installation requirements for
these exhaust configurations are as
follows:
(1) Single unit-single stack
configurations. For an affected unit that
exhausts to the atmosphere through a
single, dedicated stack, you shall either
install the required CEMS, PM CPMS,
and sorbent trap monitoring systems in
the stack or at a location in the
ductwork downstream of all emissions
control devices, where the pollutant and
diluents concentrations are
representative of the emissions that exit
to the atmosphere.
(2) Unit utilizing common stack with
other affected unit(s). When an affected
unit utilizes a common stack with one
or more other affected units, but no nonaffected units, you shall either:
(i) Install the required CEMS, PM
CPMS, and sorbent trap monitoring
systems in the duct leading to the
common stack from each unit; or
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(ii) Install the required CEMS, PM
CPMS, and sorbent trap monitoring
systems in the common stack.
(3) Unit(s) utilizing common stack
with non-affected unit(s).
(i) When one or more affected units
shares a common stack with one or
more non-affected units, you shall
either:
(A) Install the required CEMS, PM
CPMS, and sorbent trap monitoring
systems in the ducts leading to the
common stack from each affected unit;
or
(B) Install the required CEMS, PM
CPMS, and sorbent trap monitoring
systems described in this section in the
common stack and attribute all of the
emissions measured at the common
stack to the affected unit(s).
(ii) If you choose the common stack
monitoring option:
(A) For each hour in which valid data
are obtained for all parameters, you
must calculate the pollutant emission
rate and
(B) You must assign the calculated
pollutant emission rate to each unit that
shares the common stack.
(4) Unit with a main stack and a
bypass stack. If the exhaust
configuration of an affected unit
consists of a main stack and a bypass
stack, you shall install CEMS on both
the main stack and the bypass stack, or,
if it is not feasible to certify and qualityassure the data from a monitoring
system on the bypass stack, you shall
install a CEMS only on the main stack
and count bypass hours of deviation
from the monitoring requirements.
(5) Unit with a common control
device with multiple stack or duct
configuration. If the flue gases from an
affected unit, which is configured such
that emissions are controlled with a
common control device or series of
control devices, are discharged to the
atmosphere through more than one
stack or are fed into a single stack
through two or more ducts, you may:
(i) Install required CEMS, PM CPMS,
and sorbent trap monitoring systems in
each of the multiple stacks;
(ii) Install required CEMS, PM CPMS,
and sorbent trap monitoring systems in
each of the ducts that feed into the
stack;
(iii) Install required CEMS, PM CPMS,
and sorbent trap monitoring systems in
one of the multiple stacks or ducts and
monitor the flows and dilution rates in
all multiple stacks or ducts in order to
determine total exhaust gas flow rate
and pollutant mass emissions rate in
accordance with the applicable limit; or
(iv) In the case of multiple ducts
feeding into a single stack, install
CEMS, PM CPMS, and sorbent trap
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monitoring systems in the single stack
as described in paragraph (a)(1) of this
section.
(6) Unit with multiple parallel control
devices with multiple stacks. If the flue
gases from an affected unit, which is
configured such that emissions are
controlled with multiple parallel control
devices or multiple series of control
devices are discharged to the
atmosphere through more than one
stack, you shall install the required
CEMS, PM CPMS, and sorbent trap
monitoring systems described in each of
the multiple stacks. You shall calculate
hourly flow-weighted average pollutant
emission rates for the unit as follows:
(i) Calculate the pollutant emission
rate at each stack or duct for each hour
in which valid data are obtained for all
parameters;
(ii) Multiply each calculated hourly
pollutant emission rate at each stack or
duct by the corresponding hourly stack
gas flow rate at that stack or duct;
(iii) Sum the products determined
under paragraph (a)(5)(iii)(B) of this
section; and
(iv) Divide the result obtained in
paragraph (a)(5)(iii)(C) of this section by
the total hourly stack gas flow rate for
the unit, summed across all of the stacks
or ducts.
(b) If you use an oxygen (O2) or carbon
dioxide (CO2) CEMS to convert
measured pollutant concentrations to
the units of the applicable emissions
limit, the O2 or CO2 concentrations shall
be monitored at a location that
represents emissions to the atmosphere,
i.e., at the outlet of the EGU,
downstream of all emission control
devices. You must install, certify,
maintain, and operate the CEMS
according to part 75 of this chapter. Use
only quality-assured O2 or CO2 data in
the emissions calculations; do not use
part 75 substitute data values.
(c) If you are required to use a stack
gas flow rate monitor, either for routine
operation of a sorbent trap monitoring
system or to convert pollutant
concentrations to units of an electrical
output-based emission standard in
Table 1 or 2 to this subpart, you must
install, certify, operate, and maintain
the monitoring system and conduct ongoing quality-assurance testing of the
system according to part 75 of this
chapter. Use only unadjusted, qualityassured flow rate data in the emissions
calculations. Do not apply bias
adjustment factors to the flow rate data
and do not use substitute flow rate data
in the calculations.
(d) If you are required to make
corrections for stack gas moisture
content when converting pollutant
concentrations to the units of an
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emission standard in Table 1 of 2 to this
subpart, you must install, certify,
operate, and maintain a moisture
monitoring system in accordance with
part 75 of this chapter. Alternatively, for
coal-fired units, you may use
appropriate fuel-specific default
moisture values from § 75.11(b) of this
chapter to estimate the moisture content
of the stack gas or you may petition the
Administrator under § 75.66 of this
chapter for use of a default moisture
value for non-coal-fired units. If you
install and operate a moisture
monitoring system, do not use substitute
moisture data in the emissions
calculations.
(e) If you use an HCl and/or HF
CEMS, you must install, certify, operate,
maintain, and quality-assure the data
from the monitoring system in
accordance with appendix B to this
subpart. Calculate and record a 30-boiler
operating day rolling average HCl or HF
emission rate in the units of the
standard, updated after each new boiler
operating day. Each 30-boiler operating
day rolling average emission rate is the
average of all the valid hourly HCl or HF
emission rates in the preceding 30 boiler
operating days (see section 9.4 of
appendix B to this subpart).
(f)(1) If you use an SO2 CEMS, you
must install the monitor at the outlet of
the EGU, downstream of all emission
control devices, and you must certify,
operate, and maintain the CEMS
according to part 75 of this chapter.
(2) For on-going QA, the SO2 CEMS
must meet the applicable daily,
quarterly, and semiannual or annual
requirements in sections 2.1 through 2.3
of appendix B to part 75 of this chapter,
with the following addition: You must
perform the linearity checks required in
section 2.2 of appendix B to part 75 of
this chapter if the SO2 CEMS has a span
value of 30 ppm or less.
(3) Calculate and record a 30-boiler
operating day rolling average SO2
emission rate in the units of the
standard, updated after each new boiler
operating day. Each 30-boiler operating
day rolling average emission rate is the
average of all of the valid SO2 emission
rates in the preceding 30 boiler
operating days.
(4) Use only unadjusted, qualityassured SO2 concentration values in the
emissions calculations; do not apply
bias adjustment factors to the part 75
SO2 data and do not use part 75
substitute data values.
(g) If you use a Hg CEMS or a sorbent
trap monitoring system, you must
install, certify, operate, maintain and
quality-assure the data from the
monitoring system in accordance with
appendix A to this subpart. You must
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calculate and record a 30-boiler
operating day rolling average Hg
emission rate, in units of the standard,
updated after each new boiler operating
day. Each 30-boiler operating day
rolling average emission rate, calculated
according to section 6.2 of appendix A
to the subpart, is the average of all of the
valid hourly Hg emission rates in the
preceding 30 boiler operating days.
Section 7.1.4.3 of appendix A to this
subpart explains how to reduce sorbent
trap monitoring system data to an
hourly basis.
(h) If you use a PM CPMS to
demonstrate continuous compliance
with an operating limit, you must
install, calibrate, maintain, and operate
the PM CPMS and record the output of
the system as specified in paragraphs
(h)(1) through (5) of this section.
(1) Install, calibrate, operate, and
maintain your PM CPMS according to
the procedures in your approved sitespecific monitoring plan developed in
accordance with § 63.10000(d), and
meet the requirements in paragraphs
(h)(1)(i) through (iii) of this section.
(i) The operating principle of the PM
CPMS must be based on in-stack or
extractive light scatter, light
scintillation, beta attenuation, or mass
accumulation detection of the exhaust
gas or representative sample. The
reportable measurement output from the
PM CPMS may be expressed as
milliamps, stack concentration, or other
raw data signal.
(ii) The PM CPMS must have a cycle
time (i.e., period required to complete
sampling, measurement, and reporting
for each measurement) no longer than
60 minutes.
(iii) The PM CPMS must be capable,
at a minimum, of detecting and
responding to particulate matter
concentrations of 0.5 mg/acm.
(2) For a new unit, complete the
initial PM CPMS performance
evaluation no later than October 13,
2012 or 180 days after the date of initial
startup, whichever is later. For an
existing unit, complete the initial
performance evaluation no later than
October 13, 2015.
(3) Collect PM CPMS hourly average
output data for all boiler operating
hours except as indicated in paragraph
(h)(5) of this section. Express the PM
CPMS output as milliamps, PM
concentration, or other raw data signal
value.
(4) Calculate the arithmetic 30-boiler
operating day rolling average of all of
the hourly average PM CPMS output
collected during all nonexempt boiler
operating hours data (e.g., milliamps,
PM concentration, raw data signal).
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(5) You must collect data using the
PM CPMS at all times the process unit
is operating and at the intervals
specified in paragraph (h)(1)(ii) of this
section, except for periods of monitoring
system malfunctions, repairs associated
with monitoring system malfunctions,
required monitoring system quality
assurance or quality control activities
(including, as applicable, calibration
checks and required zero and span
adjustments), and any scheduled
maintenance as defined in your sitespecific monitoring plan.
(6) You must use all the data collected
during all boiler operating hours in
assessing the compliance with your
operating limit except:
(i) Any data collected during
monitoring system malfunctions, repairs
associated with monitoring system
malfunctions, or required monitoring
system quality assurance or quality
control activities conducted during
monitoring system malfunctions are not
used in calculations (report any such
periods in your annual deviation
report);
(ii) Any data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, repairs associated with
periods when the monitoring system is
out of control, or required monitoring
system quality assurance or quality
control activities conducted during outof-control periods are not used in
calculations (report emissions or
operating levels and report any such
periods in your annual deviation
report);
(iii) Any data recorded during periods
of startup or shutdown.
(7) You must record and make
available upon request results of PM
CPMS system performance audits, as
well as the dates and duration of
periods from when the PM CPMS is out
of control until completion of the
corrective actions necessary to return
the PM CPMS to operation consistent
with your site-specific monitoring plan.
(i) If you choose to comply with the
PM filterable emissions limit in lieu of
metal HAP limits, you may choose to
install, certify, operate, and maintain a
PM CEMS and record the output of the
PM CEMS as specified in paragraphs
(i)(1) through (5) of this section. The
compliance limit will be expressed as a
30-boiler operating day rolling average
of the numerical emissions limit value
applicable for your unit in tables 1 or 2
to this subpart.
(1) Install and certify your PM CEMS
according to the procedures and
requirements in Performance
Specification 11—Specifications and
Test Procedures for Particulate Matter
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Continuous Emission Monitoring
Systems at Stationary Sources in
Appendix B to part 60 of this chapter,
using Method 5 at Appendix A–3 to part
60 of this chapter and ensuring that the
front half filter temperature shall be
160° ± 14°C (320° ± 25°F). The
reportable measurement output from the
PM CEMS must be expressed in units of
the applicable emissions limit (e.g., lb/
MMBtu, lb/MWh).
(2) Operate and maintain your PM
CEMS according to the procedures and
requirements in Procedure 2—Quality
Assurance Requirements for Particulate
Matter Continuous Emission Monitoring
Systems at Stationary Sources in
Appendix F to part 60 of this chapter.
(i) You must conduct the relative
response audit (RRA) for your PM CEMS
at least once annually.
(ii) You must conduct the relative
correlation audit (RCA) for your PM
CEMS at least once every 3 years.
(3) Collect PM CEMS hourly average
output data for all boiler operating
hours except as indicated in paragraph
(i) of this section.
(4) Calculate the arithmetic 30-boiler
operating day rolling average of all of
the hourly average PM CEMS output
data collected during all nonexempt
boiler operating hours.
(5) You must collect data using the
PM CEMS at all times the process unit
is operating and at the intervals
specified in paragraph (a) of this
section, except for periods of monitoring
system malfunctions, repairs associated
with monitoring system malfunctions,
and required monitoring system quality
assurance or quality control activities.
(i) You must use all the data collected
during all boiler operating hours in
assessing the compliance with your
operating limit except:
(A) Any data collected during
monitoring system malfunctions, repairs
associated with monitoring system
malfunctions, or required monitoring
system quality assurance or control
activities conducted during monitoring
system malfunctions in calculations and
report any such periods in your annual
deviation report;
(B) Any data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, repairs associated with
periods when the monitoring system is
out of control, or required monitoring
system quality assurance or control
activities conducted during out of
control periods in calculations used to
report emissions or operating levels and
report any such periods in your annual
deviation report;
(C) Any data recorded during periods
of startup or shutdown.
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(ii) You must record and make
available upon request results of PM
CEMS system performance audits, dates
and duration of periods when the PM
CEMS is out of control to completion of
the corrective actions necessary to
return the PM CEMS to operation
consistent with your site-specific
monitoring plan.
(j) You may choose to comply with
the metal HAP emissions limits using
CEMS approved in accordance with
§ 63.7(f) as an alternative to the
performance test method specified in
this rule. If approved to use a HAP
metals CEMS, the compliance limit will
be expressed as a 30-boiler operating
day rolling average of the numerical
emissions limit value applicable for
your unit in tables 1 or 2. If approved,
you may choose to install, certify,
operate, and maintain a HAP metals
CEMS and record the output of the HAP
metals CEMS as specified in paragraphs
(j)(1) through (5) of this section.
(1)(i) Install and certify your HAP
metals CEMS according to the
procedures and requirements in you
approved site specific test plan as
required in § 63.7(e). The reportable
measurement output from the HAP
metals CEMS must be expressed in units
of the applicable emissions limit (e.g.,
lb/MMBtu, lb/MWh) and in the form of
a 30-boiler operating day rolling
average.
(ii) Operate and maintain your HAP
metals CEMS according to the
procedures and criteria in your site
specific performance evaluation and
quality control program plan required in
§ 63.8(d).
(2) Collect HAP metals CEMS hourly
average output data for all boiler
operating hours except as indicated in
section (j)(4) of this section.
(3) Calculate the arithmetic 30-boiler
operating day rolling average of all of
the hourly average HAP metals CEMS
output data collected during all
nonexempt boiler operating hours data.
(4) You must collect data using the
HAP metals CEMS at all times the
process unit is operating and at the
intervals specified in paragraph (a) of
this section, except for periods of
monitoring system malfunctions, repairs
associated with monitoring system
malfunctions, and required monitoring
system quality assurance or quality
control activities.
(i) You must use all the data collected
during all boiler operating hours in
assessing the compliance with your
emission limit except:
(A) Any data collected during
monitoring system malfunctions, repairs
associated with monitoring system
malfunctions, or required monitoring
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system quality assurance or control
activities conducted during monitoring
system malfunctions in calculations and
report any such periods in your annual
deviation report;
(B) Any data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, repairs associated with
periods when the monitoring system is
out of control, or required monitoring
system quality assurance or control
activities conducted during out of
control periods in calculations used to
report emissions or operating levels and
report any such periods in your annual
deviation report;
(C) Any data recorded during periods
of startup or shutdown.
(ii) You must record and make
available upon request results of HAP
metals CEMS system performance
audits, dates and duration of periods
when the HAP metals CEMS is out of
control to completion of the corrective
actions necessary to return the HAP
metals CEMS to operation consistent
with your site-specific performance
evaluation and quality control program
plan.
(k) If you demonstrate compliance
with the HCl and HF emission limits for
a liquid oil-fired EGU by conducting
quarterly testing, you must also develop
a site-specific monitoring plan as
provided for in § 63.10000(c)(2)(iii) and
Table 7 to this subpart.
srobinson on DSK4SPTVN1PROD with RULES2
§ 63.10011 How do I demonstrate initial
compliance with the emissions limits and
work practice standards?
(a) You must demonstrate initial
compliance with each emissions limit
that applies to you by conducting
performance testing.
(b) If you are subject to an operating
limit in Table 4 to this subpart, you
demonstrate initial compliance with
HAP metals or filterable PM emission
limit(s) through performance stack tests
and you elect to use a PM CPMS to
demonstrate continuous performance, or
if, for a liquid oil-fired unit, and you use
quarterly stack testing for HCl and HF
plus site-specific parameter monitoring
to demonstrate continuous performance,
you must also establish a site-specific
operating limit, in accordance with
Table 4 to this subpart, § 63.10007, and
Table 6 to this subpart. You may use
only the parametric data recorded
during successful performance tests
(i.e., tests that demonstrate compliance
with the applicable emissions limits) to
establish an operating limit.
(c)(1) If you use CEMS or sorbent trap
monitoring systems to measure a HAP
(e.g., Hg or HCl) directly, the first 30boiler operating day rolling average
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emission rate obtained with certified
CEMS after the applicable date in
§ 63.9984 (or, if applicable, prior to that
date, as described in § 63.10005(b)(2)),
expressed in units of the standard, is the
initial performance test. Initial
compliance is demonstrated if the
results of the performance test meet the
applicable emission limit in Table 1 or
2 to this subpart.
(2) For a unit that uses a CEMS to
measure SO2 or PM emissions for initial
compliance, the first 30 boiler operating
day average emission rate obtained with
certified CEMS after the applicable date
in § 63.9984 (or, if applicable, prior to
that date, as described in
§ 63.10005(b)(2)), expressed in units of
the standard, is the initial performance
test. Initial compliance is demonstrated
if the results of the performance test
meet the applicable SO2 or filterable PM
emission limit in Table 1 or 2 to this
subpart.
(d) For candidate LEE units, use the
results of the performance testing
described in § 63.10005(h) to determine
initial compliance with the applicable
emission limit(s) in Table 1 or 2 to this
subpart and to determine whether the
unit qualifies for LEE status.
(e) You must submit a Notification of
Compliance Status containing the
results of the initial compliance
demonstration, according to
§ 63.10030(e).
(f)(1) You must determine the fuel
whose combustion produces the least
uncontrolled emissions, i.e., the
cleanest fuel, either natural gas or
distillate oil, that is available on site or
accessible nearby for use during periods
of startup or shutdown.
(2) Your cleanest fuel, either natural
gas or distillate oil, for use during
periods of startup or shutdown
determination may take safety
considerations into account.
(g) You must follow the startup or
shutdown requirements given in Table 3
for each coal-fired, liquid oil-fired, and
solid oil-derived fuel-fired EGU.
Continuous Compliance Requirements
§ 63.10020 How do I monitor and collect
data to demonstrate continuous
compliance?
(a) You must monitor and collect data
according to this section and the sitespecific monitoring plan required by
§ 63.10000(d).
(b) You must operate the monitoring
system and collect data at all required
intervals at all times that the affected
EGU is operating, except for periods of
monitoring system malfunctions or outof-control periods (see § 63.8(c)(7) of
this part), and required monitoring
system quality assurance or quality
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9479
control activities, including, as
applicable, calibration checks and
required zero and span adjustments.
You are required to affect monitoring
system repairs in response to
monitoring system malfunctions and to
return the monitoring system to
operation as expeditiously as
practicable.
(c) You may not use data recorded
during EGU startup or shutdown or
monitoring system malfunctions or
monitoring system out-of-control
periods, repairs associated with
monitoring system malfunctions or
monitoring system out-of-control
periods, or required monitoring system
quality assurance or control activities in
calculations used to report emissions or
operating levels. You must use all the
data collected during all other periods
in assessing the operation of the control
device and associated control system.
(d) Except for periods of monitoring
system malfunctions or monitoring
system out-of-control periods, repairs
associated with monitoring system
malfunctions or monitoring system outof-control periods, and required
monitoring system quality assurance or
quality control activities including, as
applicable, calibration checks and
required zero and span adjustments),
failure to collect required data is a
deviation of the monitoring
requirements.
§ 63.10021 How do I demonstrate
continuous compliance with the emission
limitations, operating limits, and work
practice standards?
(a) You must demonstrate continuous
compliance with each emissions limit,
operating limit, and work practice
standard in Tables 1 through 4 to this
subpart that applies to you, according to
the monitoring specified in Tables 6 and
7 to this subpart and paragraphs (b)
through (g) of this section.
(b) Except as otherwise provided in
§ 63.10020(c), if you use a CEMS to
measure SO2, PM, HCl, HF, or Hg
emissions, or using a sorbent trap
monitoring system to measure Hg
emissions, you must demonstrate
continuous compliance by using all
quality-assured hourly data recorded by
the CEMS (or sorbent trap monitoring
system) and the other required
monitoring systems (e.g., flow rate, CO2,
O2, or moisture systems) to calculate the
arithmetic average emissions rate in
units of the standard on a continuous
30-boiler operating day rolling average
basis, updated at the end of each new
boiler operating day. Use Equation 8 to
determine the 30-boiler operating day
rolling average.
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(c) If you use a PM CPMS data to
measure compliance with an operating
limit in Table 4 to this subpart, you
srobinson on DSK4SPTVN1PROD with RULES2
Where:
Hpvi is the hourly parameter value for hour
i and n is the number of valid hourly
parameter values collected over 30 boiler
operating days.
(d) If you use quarterly performance
testing to demonstrate compliance with
one or more applicable emissions limits
in Table 1 or 2 to this subpart, you
(1) May skip performance testing in
those quarters during which less than
168 boiler operating hours occur, except
that a performance test must be
conducted at least once every calendar
year.
(2) Must conduct the performance test
as defined in Table 5 to this subpart and
calculate the results of the testing in
units of the applicable emissions
standard; and
(3) Must conduct site-specific
monitoring for a liquid oil-fired unit to
ensure compliance with the HCl and HF
emission limits in Tables 1 and 2 to this
subpart, in accordance with the
requirements of § 63.10000(c)(2)(iii).
The monitoring must meet the general
operating requirements provided in
§ 63.10020(a).
(e) If you must conduct periodic
performance tune-ups of your EGU(s), as
specified in paragraphs (e)(1) through
(9) of this section, perform the first tuneup as part of your initial compliance
demonstration. Notwithstanding this
requirement, you may delay the first
burner inspection until the next
scheduled unit outage provided you
meet the requirements of § 63.10005.
Subsequently, you must perform an
inspection of the burner at least once
every 36 calendar months unless your
EGU employs neural network
combustion optimization during normal
operations in which case you must
perform an inspection of the burner and
combustion controls at least once every
48 calendar months.
(1) As applicable, inspect the burner
and combustion controls, and clean or
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must record the PM CPMS output data
for all periods when the process is
operating and the PM CPMS is not outof-control. You must demonstrate
continuous compliance by using all
quality-assured hourly average data
collected by the PM CPMS for all
operating hours to calculate the
arithmetic average operating parameter
in units of the operating limit (e.g.,
milliamps, PM concentration, raw data
signal) on a 30 operating day rolling
average basis, updated at the end of
each new boiler operating day. Use
Equation 9 to determine the 30 boiler
operating day average.
replace any components of the burner or
combustion controls as necessary upon
initiation of the work practice program
and at least once every required
inspection period. Repair of a burner or
combustion control component
requiring special order parts may be
scheduled as follows:
(i) Burner or combustion control
component parts needing replacement
that affect the ability to optimize NOX
and CO must be installed within 3
calendar months after the burner
inspection,
(ii) Burner or combustion control
component parts that do not affect the
ability to optimize NOX and CO may be
installed on a schedule determined by
the operator;
(2) As applicable, inspect the flame
pattern and make any adjustments to the
burner or combustion controls necessary
to optimize the flame pattern. The
adjustment should be consistent with
the manufacturer’s specifications, if
available, or in accordance with best
combustion engineering practice for that
burner type;
(3) As applicable, observe the damper
operations as a function of mill and/or
cyclone loadings, cyclone and
pulverizer coal feeder loadings, or other
pulverizer and coal mill performance
parameters, making adjustments and
effecting repair to dampers, controls,
mills, pulverizers, cyclones, and
sensors;
(4) As applicable, evaluate windbox
pressures and air proportions, making
adjustments and effecting repair to
dampers, actuators, controls, and
sensors;
(5) Inspect the system controlling the
air-to-fuel ratio and ensure that it is
correctly calibrated and functioning
properly. Such inspection may include
calibrating excess O2 probes and/or
sensors, adjusting overfire air systems,
changing software parameters, and
calibrating associated actuators and
dampers to ensure that the systems are
operated as designed. Any component
out of calibration, in or near failure, or
in a state that is likely to negate
combustion optimization efforts prior to
the next tune-up, should be corrected or
repaired as necessary;
(6) Optimize combustion to minimize
generation of CO and NOX. This
optimization should be consistent with
the manufacturer’s specifications, if
available, or best combustion
engineering practice for the applicable
burner type. NOX optimization includes
burners, overfire air controls, concentric
firing system improvements, neural
network or combustion efficiency
software, control systems calibrations,
adjusting combustion zone temperature
profiles, and add-on controls such as
SCR and SNCR; CO optimization
includes burners, overfire air controls,
concentric firing system improvements,
neural network or combustion efficiency
software, control systems calibrations,
and adjusting combustion zone
temperature profiles;
(7) While operating at full load or the
predominantly operated load, measure
the concentration in the effluent stream
of CO and NOX in ppm, by volume, and
oxygen in volume percent, before and
after the tune-up adjustments are made
(measurements may be either on a dry
or wet basis, as long as it is the same
basis before and after the adjustments
are made). You may use portable CO,
NOX and O2 monitors for this
measurement. EGU’s employing neural
network optimization systems need only
provide a single pre- and post-tune-up
value rather than continual values
before and after each optimization
adjustment made by the system;
(8) Maintain on-site and submit, if
requested by the Administrator, an
annual report containing the
information in paragraphs (e)(1) through
(e)(9) of this section including:
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E:\FR\FM\16FER2.SGM
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ER16FE12.010</GPH>
Where:
Heri is the hourly emissions rate for hour i
and n is the number of hourly emissions
rate values collected over 30 boiler
operating days.
ER16FE12.009</GPH>
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(i) The concentrations of CO and NOX
in the effluent stream in ppm by
volume, and oxygen in volume percent,
measured before and after an adjustment
of the EGU combustion systems;
(ii) A description of any corrective
actions taken as a part of the
combustion adjustment; and
(iii) The type(s) and amount(s) of fuel
used over the 12 calendar months prior
to an adjustment, but only if the unit
was physically and legally capable of
using more than one type of fuel during
that period; and
(9) Report the dates of the initial and
subsequent tune-ups as follows:
(i) If the first required tune-up is
performed as part of the initial
compliance demonstration, report the
date of the tune-up in hard copy (as
specified in § 63.10030) and
electronically (as specified in
§ 63.10031). Report the date of each
subsequent tune-up electronically (as
specified in § 63.10031).
(ii) If the first tune-up is not
conducted as part of the initial
compliance demonstration, but is
postponed until the next unit outage,
report the date of that tune-up and all
subsequent tune-ups electronically, in
accordance with § 63.10031.
(f) You must submit the reports
required under § 63.10031 and, if
applicable, the reports required under
appendices A and B to this subpart. The
electronic reports required by
appendices A and B to this subpart must
be sent to the Administrator
electronically in a format prescribed by
the Administrator, as provided in
§ 63.10031. CEMS data (except for PM
CEMS and any approved alternative
monitoring using a HAP metals CEMS)
shall be submitted using EPA’s
Emissions Collection and Monitoring
Plan System (ECMPS) Client Tool. Other
data, including PM CEMS data, HAP
metals CEMS data, and CEMS
performance test detail reports, shall be
submitted in the file format generated
through use of EPA’s Electronic
Reporting Tool, the Compliance and
Emissions Data Reporting Interface, or
alternate electronic file format, all as
provided for under § 63.10031.
(g) You must report each instance in
which you did not meet an applicable
emissions limit or operating limit in
Tables 1 through 4 to this subpart or
failed to conduct a required tune-up.
These instances are deviations from the
requirements of this subpart. These
deviations must be reported according
to § 63.10031.
(h) You must keep records as
specified in § 63.10032 during periods
of startup and shutdown.
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(i) You must provide reports as
specified in § 63.10031 concerning
activities and periods of startup and
shutdown.
§ 63.10022 How do I demonstrate
continuous compliance under the
emissions averaging provision?
(a) Following the compliance date, the
owner or operator must demonstrate
compliance with this subpart on a
continuous basis by meeting the
requirements of paragraphs (a)(1)
through (3) of this section.
(1) For each calendar month,
demonstrate compliance with the
average weighted emissions limit for the
existing units participating in the
emissions averaging option as
determined in § 63.10009(f) and (g);
(2) For each existing unit participating
in the emissions averaging option that is
equipped with PM CPMS, maintain the
average parameter value at or below the
operating limit established during the
most recent performance test;
(3) For each existing unit participating
in the emissions averaging option
venting to a common stack
configuration containing affected units
from other subcategories, maintain the
appropriate operating limit for each unit
as specified in Table 4 to this subpart
that applies.
(b) Any instance where the owner or
operator fails to comply with the
continuous monitoring requirements in
paragraphs (a)(1) through (3) of this
section is a deviation.
§ 63.10023 How do I establish my PM
CPMS operating limit and determine
compliance with it?
(a) During the initial performance test
or any such subsequent performance
test that demonstrates compliance with
the filterable PM, individual nonmercury HAP metals, or total nonmercury HAP metals limit (or for liquid
oil-fired units, individual HAP metals or
total HAP metals limit, including Hg) in
Table 1 or 2, record all hourly average
output values (e.g., milliamps, stack
concentration, or other raw data signal)
from the PM CPMS for the periods
corresponding to the test runs (e.g., nine
1-hour average PM CPMS output values
for three 3-hour test runs).
(b) Determine your operating limit as
the highest 1-hour average PM CPMS
output value recorded during the
performance test. You must verify an
existing or establish a new operating
limit after each repeated performance
test.
(c) You must operate and maintain
your process and control equipment
such that the 30 operating day average
PM CPMS output does not exceed the
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9481
operating limit determined in
paragraphs (a) and (b) of this section.
Notification, Reports, and Records
§ 63.10030 What notifications must I
submit and when?
(a) You must submit all of the
notifications in §§ 63.7(b) and (c), 63.8
(e), (f)(4) and (6), and 63.9 (b) through
(h) that apply to you by the dates
specified.
(b) As specified in § 63.9(b)(2), if you
startup your affected source before April
16, 2012, you must submit an Initial
Notification not later than 120 days after
April 16, 2012.
(c) As specified in § 63.9(b)(4) and
(b)(5), if you startup your new or
reconstructed affected source on or after
April 16, 2012, you must submit an
Initial Notification not later than 15
days after the actual date of startup of
the affected source.
(d) When you are required to conduct
a performance test, you must submit a
Notification of Intent to conduct a
performance test at least 30 days before
the performance test is scheduled to
begin.
(e) When you are required to conduct
an initial compliance demonstration as
specified in § 63.10011(a), you must
submit a Notification of Compliance
Status according to § 63.9(h)(2)(ii). The
Notification of Compliance Status report
must contain all the information
specified in paragraphs (e)(1) through
(7), as applicable.
(1) A description of the affected
source(s) including identification of
which subcategory the source is in, the
design capacity of the source, a
description of the add-on controls used
on the source, description of the fuel(s)
burned, including whether the fuel(s)
were determined by you or EPA through
a petition process to be a non-waste
under 40 CFR 241.3, whether the fuel(s)
were processed from discarded nonhazardous secondary materials within
the meaning of 40 CFR 241.3, and
justification for the selection of fuel(s)
burned during the performance test.
(2) Summary of the results of all
performance tests and fuel analyses and
calculations conducted to demonstrate
initial compliance including all
established operating limits.
(3) Identification of whether you plan
to demonstrate compliance with each
applicable emission limit through
performance testing; fuel moisture
analyses; performance testing with
operating limits (e.g., use of PM CPMS);
CEMS; or a sorbent trap monitoring
system.
(4) Identification of whether you plan
to demonstrate compliance by emissions
averaging.
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(5) A signed certification that you
have met all applicable emission limits
and work practice standards.
(6) If you had a deviation from any
emission limit, work practice standard,
or operating limit, you must also submit
a brief description of the deviation, the
duration of the deviation, emissions
point identification, and the cause of the
deviation in the Notification of
Compliance Status report.
(7) In addition to the information
required in § 63.9(h)(2), your
notification of compliance status must
include the following:
(i) A summary of the results of the
annual performance tests and
documentation of any operating limits
that were reestablished during this test,
if applicable. If you are conducting stack
tests once every 3 years consistent with
§ 63.10006(i), the date of the last three
stack tests, a comparison of the emission
level you achieved in the last three stack
tests to the 50 percent emission limit
threshold required in § 63.10006(i), and
a statement as to whether there have
been any operational changes since the
last stack test that could increase
emissions.
(ii) Certifications of compliance, as
applicable, and must be signed by a
responsible official stating:
(A) ‘‘This EGU complies with the
requirements in § 63.10021(a) to
demonstrate continuous compliance.’’
and
(B) ‘‘No secondary materials that are
solid waste were combusted in any
affected unit.’’
srobinson on DSK4SPTVN1PROD with RULES2
§ 63.10031
when?
What reports must I submit and
(a) You must submit each report in
Table 8 to this subpart that applies to
you. If you are required to (or elect to)
continuously monitor Hg and/or HCl
and/or HF emissions, you must also
submit the electronic reports required
under appendix A and/or appendix B to
the subpart, at the specified frequency.
(b) Unless the Administrator has
approved a different schedule for
submission of reports under § 63.10(a),
you must submit each report by the date
in Table 8 to this subpart and according
to the requirements in paragraphs (b)(1)
through (5) of this section.
(1) The first compliance report must
cover the period beginning on the
compliance date that is specified for
your affected source in § 63.9984 and
ending on June 30 or December 31,
whichever date is the first date that
occurs at least 180 days after the
compliance date that is specified for
your source in § 63.9984.
(2) The first compliance report must
be postmarked or submitted
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electronically no later than July 31 or
January 31, whichever date is the first
date following the end of the first
calendar half after the compliance date
that is specified for your source in
§ 63.9984.
(3) Each subsequent compliance
report must cover the semiannual
reporting period from January 1 through
June 30 or the semiannual reporting
period from July 1 through December
31.
(4) Each subsequent compliance
report must be postmarked or submitted
electronically no later than July 31 or
January 31, whichever date is the first
date following the end of the
semiannual reporting period.
(5) For each affected source that is
subject to permitting regulations
pursuant to part 70 or part 71 of this
chapter, and if the permitting authority
has established dates for submitting
semiannual reports pursuant to 40 CFR
70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the
first and subsequent compliance reports
according to the dates the permitting
authority has established instead of
according to the dates in paragraphs
(b)(1) through (4) of this section.
(c) The compliance report must
contain the information required in
paragraphs (c)(1) through (4) of this
section.
(1) The information required by the
summary report located in
63.10(e)(3)(vi).
(2) The total fuel use by each affected
source subject to an emission limit, for
each calendar month within the
semiannual reporting period, including,
but not limited to, a description of the
fuel, whether the fuel has received a
non-waste determination by EPA or
your basis for concluding that the fuel
is not a waste, and the total fuel usage
amount with units of measure.
(3) Indicate whether you burned new
types of fuel during the reporting
period. If you did burn new types of fuel
you must include the date of the
performance test where that fuel was in
use.
(4) Include the date of the most recent
tune-up for each unit subject to the
requirement to conduct a performance
tune-up according to § 63.10021(e).
Include the date of the most recent
burner inspection if it was not done
annually and was delayed until the next
scheduled unit shutdown.
(d) For each excess emissions
occurring at an affected source where
you are using a CMS to comply with
that emission limit or operating limit,
you must include the information
required in § 63.10(e)(3)(v) in the
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compliance report specified in section
(c).
(e) Each affected source that has
obtained a Title V operating permit
pursuant to part 70 or part 71 of this
chapter must report all deviations as
defined in this subpart in the
semiannual monitoring report required
by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A). If an affected source
submits a compliance report pursuant to
Table 8 to this subpart along with, or as
part of, the semiannual monitoring
report required by 40 CFR
70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), and the compliance
report includes all required information
concerning deviations from any
emission limit, operating limit, or work
practice requirement in this subpart,
submission of the compliance report
satisfies any obligation to report the
same deviations in the semiannual
monitoring report. Submission of a
compliance report does not otherwise
affect any obligation the affected source
may have to report deviations from
permit requirements to the permit
authority.
(f) As of January 1, 2012, and within
60 days after the date of completing
each performance test, you must submit
the results of the performance tests
required by this subpart to EPA’s
WebFIRE database by using the
Compliance and Emissions Data
Reporting Interface (CEDRI) that is
accessed through EPA’s Central Data
Exchange (CDX) (www.epa.gov/cdx).
Performance test data must be submitted
in the file format generated through use
of EPA’s Electronic Reporting Tool
(ERT) (see https://www.epa.gov/ttn/chief/
ert/). Only data collected
using those test methods on the ERT
Web site are subject to this requirement
for submitting reports electronically to
WebFIRE. Owners or operators who
claim that some of the information being
submitted for performance tests is
confidential business information (CBI)
must submit a complete ERT file
including information claimed to be CBI
on a compact disk or other commonly
used electronic storage media
(including, but not limited to, flash
drives) to EPA. The electronic media
must be clearly marked as CBI and
mailed to U.S. EPA/OAPQS/CORE CBI
Office, Attention: WebFIRE
Administrator, MD C404–02, 4930 Old
Page Rd., Durham, NC 27703. The same
ERT file with the CBI omitted must be
submitted to EPA via CDX as described
earlier in this paragraph. At the
discretion of the delegated authority,
you must also submit these reports,
including the confidential business
information, to the delegated authority
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in the format specified by the delegated
authority.
(1) Within 60 days after the date of
completing each CEMS (SO2, PM, HCl,
HF, and Hg) performance evaluation
test, as defined in § 63.2 and required by
this subpart, you must submit the
relative accuracy test audit (RATA) data
(or, for PM CEMS, RCA and RRA data)
required by this subpart to EPA’s
WebFIRE database by using the
Compliance and Emissions Data
Reporting Interface (CEDRI) that is
accessed through EPA’s Central Data
Exchange (CDX) (www.epa.gov/cdx).
The RATA data shall be submitted in
the file format generated through use of
EPA’s Electronic Reporting Tool (ERT)
(https://www.epa.gov/ttn/chief/ert/
index.html). Only RATA data
compounds listed on the ERT Web site
are subject to this requirement. Owners
or operators who claim that some of the
information being submitted for RATAs
is confidential business information
(CBI) shall submit a complete ERT file
including information claimed to be CBI
on a compact disk or other commonly
used electronic storage media
(including, but not limited to, flash
drives) by registered letter to EPA and
the same ERT file with the CBI omitted
to EPA via CDX as described earlier in
this paragraph. The compact disk or
other commonly used electronic storage
media shall be clearly marked as CBI
and mailed to U.S. EPA/OAPQS/CORE
CBI Office, Attention: WebFIRE
Administrator, MD C404–02, 4930 Old
Page Rd., Durham, NC 27703. At the
discretion of the delegated authority,
owners or operators shall also submit
these RATAs to the delegated authority
in the format specified by the delegated
authority. Owners or operators shall
submit calibration error testing, drift
checks, and other information required
in the performance evaluation as
described in § 63.2 and as required in
this chapter.
(2) For a PM CEMS, PM CPMS, or
approved alternative monitoring using a
HAP metals CEMS, within 60 days after
the reporting periods ending on March
31st, June 30th, September 30th, and
December 31st, you must submit
quarterly reports to EPA’s WebFIRE
database by using the Compliance and
Emissions Data Reporting Interface
(CEDRI) that is accessed through EPA’s
Central Data Exchange (CDX)
(www.epa.gov/cdx). You must use the
appropriate electronic reporting form in
CEDRI or provide an alternate electronic
file consistent with EPA’s reporting
form output format. For each reporting
period, the quarterly reports must
include all of the calculated 30-boiler
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operating day rolling average values
derived from the CEMS and PM CPMS.
(3) Reports for an SO2 CEMS, a Hg
CEMS or sorbent trap monitoring
system, an HCl or HF CEMS, and any
supporting monitors for such systems
(such as a diluent or moisture monitor)
shall be submitted using the ECMPS
Client Tool, as provided for in
Appendices A and B to this subpart and
§ 63.10021(f).
(4) Submit the compliance reports
required under paragraphs (c) and (d) of
this section and the notification of
compliance status required under
§ 63.10030(e) to EPA’s WebFIRE
database by using the Compliance and
Emissions Data Reporting Interface
(CEDRI) that is accessed through EPA’s
Central Data Exchange (CDX)
(www.epa.gov/cdx). You must use the
appropriate electronic reporting form in
CEDRI or provide an alternate electronic
file consistent with EPA’s reporting
form output format.
(5) All reports required by this
subpart not subject to the requirements
in paragraphs (f)(1) through (4) of this
section must be sent to the
Administrator at the appropriate
address listed in § 63.13. If acceptable to
both the Administrator and the owner or
operator of a source, these reports may
be submitted on electronic media. The
Administrator retains the right to
require submittal of reports subject to
paragraphs (f)(1), (2), and (3) of this
section in paper format.
(g) If you had a malfunction during
the reporting period, the compliance
report must include the number,
duration, and a brief description for
each type of malfunction which
occurred during the reporting period
and which caused or may have caused
any applicable emission limitation to be
exceeded.
§ 63.10032
What records must I keep?
(a) You must keep records according
to paragraphs (a)(1) and (2) of this
section. If you are required to (or elect
to) continuously monitor Hg and/or HCl
and/or HF emissions, you must also
keep the records required under
appendix A and/or appendix B to this
subpart.
(1) A copy of each notification and
report that you submitted to comply
with this subpart, including all
documentation supporting any Initial
Notification or Notification of
Compliance Status or semiannual
compliance report that you submitted,
according to the requirements in
§ 63.10(b)(2)(xiv).
(2) Records of performance stack tests,
fuel analyses, or other compliance
demonstrations and performance
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9483
evaluations, as required in
§ 63.10(b)(2)(viii).
(b) For each CEMS and CPMS, you
must keep records according to
paragraphs (b)(1) through (4) of this
section.
(1) Records described in
§ 63.10(b)(2)(vi) through (xi).
(2) Previous (i.e., superseded)
versions of the performance evaluation
plan as required in § 63.8(d)(3).
(3) Request for alternatives to relative
accuracy test for CEMS as required in
§ 63.8(f)(6)(i).
(4) Records of the date and time that
each deviation started and stopped, and
whether the deviation occurred during a
period of startup, shutdown, or
malfunction or during another period.
(c) You must keep the records
required in Table 7 to this subpart
including records of all monitoring data
and calculated averages for applicable
PM CPMS operating limits to show
continuous compliance with each
emission limit and operating limit that
applies to you.
(d) For each EGU subject to an
emission limit, you must also keep the
records in paragraphs (d)(1) through (3)
of this section.
(1) You must keep records of monthly
fuel use by each EGU, including the
type(s) of fuel and amount(s) used.
(2) If you combust non-hazardous
secondary materials that have been
determined not to be solid waste
pursuant to 40 CFR 241.3(b)(1), you
must keep a record which documents
how the secondary material meets each
of the legitimacy criteria. If you combust
a fuel that has been processed from a
discarded non-hazardous secondary
material pursuant to 40 CFR 241.3(b)(2),
you must keep records as to how the
operations that produced the fuel
satisfies the definition of processing in
40 CFR 241.2. If the fuel received a nonwaste determination pursuant to the
petition process submitted under 40
CFR 241.3(c), you must keep a record
which documents how the fuel satisfies
the requirements of the petition process.
(3) For an EGU that qualifies as an
LEE under § 63.10005(h), you must keep
annual records that document that your
emissions in the previous stack test(s)
continue to qualify the unit for LEE
status for an applicable pollutant, and
document that there was no change in
source operations including fuel
composition and operation of air
pollution control equipment that would
cause emissions of the pollutant to
increase within the past year.
(e) If you elect to average emissions
consistent with § 63.10009, you must
additionally keep a copy of the
emissions averaging implementation
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plan required in § 63.10009(g), all
calculations required under § 63.10009,
including daily records of heat input or
steam generation, as applicable, and
monitoring records consistent with
§ 63.10022.
(f) You must keep records of the
occurrence and duration of each startup
and/or shutdown.
(g) You must keep records of the
occurrence and duration of each
malfunction of an operation (i.e.,
process equipment) or the air pollution
control and monitoring equipment.
(h) You must keep records of actions
taken during periods of malfunction to
minimize emissions in accordance with
§ 63.10000(b), including corrective
actions to restore malfunctioning
process and air pollution control and
monitoring equipment to its normal or
usual manner of operation.
(i) You must keep records of the
type(s) and amount(s) of fuel used
during each startup or shutdown.
(j) If you elect to establish that an EGU
qualifies as a limited-use liquid oil-fired
EGU, you must keep records of the
type(s) and amount(s) of fuel use in each
calendar quarter to document that the
capacity factor limitation for that
subcategory is met.
§ 63.10033 In what form and how long
must I keep my records?
(a) Your records must be in a form
suitable and readily available for
expeditious review, according to
§ 63.10(b)(1).
(b) As specified in § 63.10(b)(1), you
must keep each record for 5 years
following the date of each occurrence,
measurement, maintenance, corrective
action, report, or record.
(c) You must keep each record on site
for at least 2 years after the date of each
occurrence, measurement, maintenance,
corrective action, report, or record,
according to § 63.10(b)(1). You can keep
the records off site for the remaining 3
years.
Other Requirements and Information
§ 63.10040 What parts of the General
Provisions apply to me?
Table 9 to this subpart shows which
parts of the General Provisions in
§§ 63.1 through 63.15 apply to you.
srobinson on DSK4SPTVN1PROD with RULES2
§ 63.10041 Who implements and enforces
this subpart?
(a) This subpart can be implemented
and enforced by U.S. EPA, or a
delegated authority such as your state,
local, or tribal agency. If the EPA
Administrator has delegated authority to
your state, local, or tribal agency, then
that agency (as well as the U.S. EPA) has
the authority to implement and enforce
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this subpart. You should contact your
EPA Regional Office to find out if this
subpart is delegated to your state, local,
or tribal agency.
(b) In delegating implementation and
enforcement authority of this subpart to
a state, local, or tribal agency under 40
CFR part 63, subpart E, the authorities
listed in paragraphs (b)(1) through (4) of
this section are retained by the EPA
Administrator and are not transferred to
the state, local, or tribal agency;
moreover, the U.S. EPA retains
oversight of this subpart and can take
enforcement actions, as appropriate,
with respect to any failure by any
person to comply with any provision of
this subpart.
(1) Approval of alternatives to the
non-opacity emission limits and work
practice standards in § 63.9991(a) and
(b) under § 63.6(g).
(2) Approval of major change to test
methods in Table 5 to this subpart
under § 63.7(e)(2)(ii) and (f) and as
defined in § 63.90, approval of minor
and intermediate changes to monitoring
performance specifications/procedures
in Table 5 where the monitoring serves
as the performance test method (see
definition of ‘‘test method’’ in § 63.2.
(3) Approval of major changes to
monitoring under § 63.8(f) and as
defined in § 63.90.
(4) Approval of major change to
recordkeeping and reporting under
§ 63.10(e) and as defined in § 63.90.
§ 63.10042
subpart?
What definitions apply to this
Terms used in this subpart are
defined in the Clean Air Act (CAA), in
§ 63.2 (the General Provisions), and in
this section as follows:
Affirmative defense means, in the
context of an enforcement proceeding, a
response or defense put forward by a
defendant, regarding which the
defendant has the burden of proof, and
the merits of which are independently
and objectively evaluated in a judicial
or administrative proceeding.
Anthracite coal means solid fossil fuel
classified as anthracite coal by
American Society of Testing and
Materials (ASTM) Method D388–05,
‘‘Standard Classification of Coals by
Rank’’ (incorporated by reference, see
§ 63.14).
Bituminous coal means coal that is
classified as bituminous according to
ASTM Method D388–05, ‘‘Standard
Classification of Coals by Rank’’
(incorporated by reference, see § 63.14).
Boiler operating day means a 24-hour
period between midnight and the
following midnight during which any
fuel is combusted at any time in the
steam generating unit. It is not necessary
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for the fuel to be combusted the entire
24-hour period.
Capacity factor for a liquid oil-fired
EGU means the total annual heat input
from oil divided by the product of
maximum hourly heat input for the
EGU, regardless of fuel, multiplied by
8,760 hours.
Coal means all solid fuels classifiable
as anthracite, bituminous, subbituminous, or lignite by ASTM Method
D388–05, ‘‘Standard Classification of
Coals by Rank’’ (incorporated by
reference, see § 63.14), and coal refuse.
Synthetic fuels derived from coal for the
purpose of creating useful heat
including but not limited to, coal
derived gases (not meeting the
definition of natural gas), solventrefined coal, coal-oil mixtures, and coalwater mixtures, are considered ‘‘coal’’
for the purposes of this subpart.
Coal-fired electric utility steam
generating unit means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that
burns coal for more than 10.0 percent of
the average annual heat input during
any 3 consecutive calendar years or for
more than 15.0 percent of the annual
heat input during any one calendar year.
Coal refuse means any by-product of
coal mining, physical coal cleaning, and
coal preparation operations (e.g., culm,
gob, etc.) containing coal, matrix
material, clay, and other organic and
inorganic material with an ash content
greater than 50 percent (by weight) and
a heating value less than 13,900
kilojoules per kilogram (6,000 Btu per
pound) on a dry basis.
Cogeneration means a steamgenerating unit that simultaneously
produces both electrical and useful
thermal (or mechanical) energy from the
same primary energy source.
Cogeneration unit means a stationary,
fossil fuel-fired EGU meeting the
definition of ‘‘fossil fuel-fired’’ or
stationary, integrated gasification
combined cycle:
(1) Having equipment used to produce
electricity and useful thermal energy for
industrial, commercial, heating, or
cooling purposes through the sequential
use of energy; and
(2) Producing during the 12-month
period starting on the date the unit first
produces electricity and during any
calendar year after which the unit first
produces electricity:
(i) For a topping-cycle cogeneration
unit,
(A) Useful thermal energy not less
than 5 percent of total energy output;
and
(B) Useful power that, when added to
one-half of useful thermal energy
produced, is not less than 42.5 percent
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of total energy input, if useful thermal
energy produced is 15 percent or more
of total energy output, or not less than
45 percent of total energy input, if
useful thermal energy produced is less
than 15 percent of total energy output.
(ii) For a bottoming-cycle
cogeneration unit, useful power not less
than 45 percent of total energy input.
(3) Provided that the total energy
input under paragraphs (2)(i)(B) and
(2)(ii) of this definition shall equal the
unit’s total energy input from all fuel
except biomass if the unit is a boiler.
Combined-cycle gas stationary
combustion turbine means a stationary
combustion turbine system where heat
from the turbine exhaust gases is
recovered by a waste heat boiler.
Common stack means the exhaust of
emissions from two or more affected
units through a single flue.
Continental liquid oil-fired
subcategory means any oil-fired electric
utility steam generating unit that burns
liquid oil and is located in the
continental United States.
Deviation. (1) Deviation means any
instance in which an affected source
subject to this subpart, or an owner or
operator of such a source:
(i) Fails to meet any requirement or
obligation established by this subpart
including, but not limited to, any
emission limit, operating limit, work
practice standard, or monitoring
requirement; or
(ii) Fails to meet any term or
condition that is adopted to implement
an applicable requirement in this
subpart and that is included in the
operating permit for any affected source
required to obtain such a permit.
(2) A deviation is not always a
violation. The determination of whether
a deviation constitutes a violation of the
standard is up to the discretion of the
entity responsible for enforcement of the
standards.
Distillate oil means fuel oils,
including recycled oils, that comply
with the specifications for fuel oil
numbers 1 and 2, as defined by ASTM
Method D396–10, ‘‘Standard
Specification for Fuel Oils’’
(incorporated by reference, see § 63.14).
Dry flue gas desulfurization
technology, or dry FGD, or spray dryer
absorber (SDA), or spray dryer, or dry
scrubber means an add-on air pollution
control system located downstream of
the steam generating unit that injects a
dry alkaline sorbent (dry sorbent
injection) or sprays an alkaline sorbent
slurry (spray dryer) to react with and
neutralize acid gases such as SO2 and
HCl in the exhaust stream forming a dry
powder material. Alkaline sorbent
injection systems in fluidized bed
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combustors (FBC) or circulating
fluidized bed (CFB) boilers are included
in this definition.
Dry sorbent injection (DSI) means an
add-on air pollution control system in
which sorbent (e.g., conventional
activated carbon, brominated activated
carbon, Trona, hydrated lime, sodium
carbonate, etc.) is injected into the flue
gas steam upstream of a PM control
device to react with and neutralize acid
gases (such as SO2 and HCl) or Hg in the
exhaust stream forming a dry powder
material that may be removed in a
primary or secondary PM control
device.
Electric Steam generating unit means
any furnace, boiler, or other device used
for combusting fuel for the purpose of
producing steam (including fossil-fuelfired steam generators associated with
integrated gasification combined cycle
gas turbines; nuclear steam generators
are not included) for the purpose of
powering a generator to produce
electricity or electricity and other
thermal energy.
Electric utility steam generating unit
(EGU) means a fossil fuel-fired
combustion unit of more than 25
megawatts electric (MWe) that serves a
generator that produces electricity for
sale. A fossil fuel-fired unit that
cogenerates steam and electricity and
supplies more than one-third of its
potential electric output capacity and
more than 25 MWe output to any utility
power distribution system for sale is
considered an electric utility steam
generating unit.
Emission limitation means any
emissions limit, work practice standard,
or operating limit.
Excess emissions means, with respect
to this subpart, results of any required
measurements outside the applicable
range (e.g., emissions limitations,
parametric operating limits) that is
permitted by this subpart. The values of
measurements will be in the same units
and averaging time as the values
specified in this subpart for the
limitations.
Federally enforceable means all
limitations and conditions that are
enforceable by the Administrator,
including the requirements of 40 CFR
parts 60, 61, and 63; requirements
within any applicable state
implementation plan; and any permit
requirements established under 40 CFR
52.21 or under 40 CFR 51.18 and 40
CFR 51.24.
Flue gas desulfurization system
means any add-on air pollution control
system located downstream of the steam
generating unit whose purpose or effect
is to remove at least 50 percent of the
SO2 in the exhaust gas stream.
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Fossil fuel means natural gas, oil,
coal, and any form of solid, liquid, or
gaseous fuel derived from such material.
Fossil fuel-fired means an electric
utility steam generating unit (EGU) that
is capable of combusting more than 25
MW of fossil fuels. To be ‘‘capable of
combusting’’ fossil fuels, an EGU would
need to have these fuels allowed in its
operating permit and have the
appropriate fuel handling facilities onsite or otherwise available (e.g., coal
handling equipment, including coal
storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In
addition, fossil fuel-fired means any
EGU that fired fossil fuels for more than
10.0 percent of the average annual heat
input during any 3 consecutive calendar
years or for more than 15.0 percent of
the annual heat input during any one
calendar year after the applicable
compliance date.
Fuel type means each category of fuels
that share a common name or
classification. Examples include, but are
not limited to, bituminous coal,
subbituminous coal, lignite, anthracite,
biomass, and residual oil. Individual
fuel types received from different
suppliers are not considered new fuel
types.
Fluidized bed boiler, or fluidized bed
combustor, or circulating fluidized
boiler, or CFB means a boiler utilizing
a fluidized bed combustion process.
Fluidized bed combustion means a
process where a fuel is burned in a bed
of granulated particles which are
maintained in a mobile suspension by
the upward flow of air and combustion
products.
Gaseous fuel includes, but is not
limited to, natural gas, process gas,
landfill gas, coal derived gas, solid oilderived gas, refinery gas, and biogas.
Generator means a device that
produces electricity.
Gross output means the gross useful
work performed by the steam generated
and, for an IGCC electric utility steam
generating unit, the work performed by
the stationary combustion turbines. For
a unit generating only electricity, the
gross useful work performed is the gross
electrical output from the unit’s turbine/
generator sets. For a cogeneration unit,
the gross useful work performed is the
gross electrical output, including any
such electricity used in the power
production process (which process
includes, but is not limited to, any onsite processing or treatment of fuel
combusted at the unit and any on-site
emission controls), or mechanical
output plus 75 percent of the useful
thermal output measured relative to ISO
conditions that is not used to generate
additional electrical or mechanical
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output or to enhance the performance of
the unit (i.e., steam delivered to an
industrial process).
Heat input means heat derived from
combustion of fuel in an EGU (synthetic
gas for an IGCC) and does not include
the heat input from preheated
combustion air, recirculated flue gases,
or exhaust gases from other sources
such as gas turbines, internal
combustion engines, etc.
Integrated gasification combined
cycle electric utility steam generating
unit or IGCC means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that
burns a synthetic gas derived from coal
and/or solid oil-derived fuel for more
than 10.0 percent of the average annual
heat input during any 3 consecutive
calendar years or for more than 15.0
percent of the annual heat input during
any one calendar year in a combinedcycle gas turbine. No solid coal or solid
oil-derived fuel is directly burned in the
unit during operation.
ISO conditions means a temperature
of 288 Kelvin, a relative humidity of 60
percent, and a pressure of 101.3
kilopascals.
Lignite coal means coal that is
classified as lignite A or B according to
ASTM Method D388–05, ‘‘Standard
Classification of Coals by Rank’’
(incorporated by reference, see § 63.14).
Limited-use liquid oil-fired
subcategory means an oil-fired electric
utility steam generating unit with an
annual capacity factor of less than 8
percent of its maximum or nameplate
heat input, whichever is greater,
averaged over a 24-month block
contiguous period commencing April
16, 2015.
Liquid fuel includes, but is not
limited to, distillate oil and residual oil.
Monitoring system malfunction or out
of control period means any sudden,
infrequent, not reasonably preventable
failure of the monitoring system to
provide valid data. Monitoring system
failures that are caused in part by poor
maintenance or careless operation are
not malfunctions.
Natural gas means a naturally
occurring fluid mixture of hydrocarbons
(e.g., methane, ethane, or propane)
produced in geological formations
beneath the Earth’s surface that
maintains a gaseous state at standard
atmospheric temperature and pressure
under ordinary conditions. Natural gas
contains 20.0 grains or less of total
sulfur per 100 standard cubic feet.
Additionally, natural gas must either be
composed of at least 70 percent methane
by volume or have a gross calorific
value between 950 and 1,100 Btu per
standard cubic foot. Natural gas does
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not include the following gaseous fuels:
landfill gas, digester gas, refinery gas,
sour gas, blast furnace gas, coal-derived
gas, producer gas, coke oven gas, or any
gaseous fuel produced in a process
which might result in highly variable
sulfur content or heating value.
Natural gas-fired electric utility steam
generating unit means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that is
not a coal-fired, oil-fired, or IGCC
electric utility steam generating unit and
that burns natural gas for more than 10.0
percent of the average annual heat input
during any 3 consecutive calendar years
or for more than 15.0 percent of the
annual heat input during any one
calendar year.
Net-electric output means the gross
electric sales to the utility power
distribution system minus purchased
power on a calendar year basis.
Non-continental area means the State
of Hawaii, the Virgin Islands, Guam,
American Samoa, the Commonwealth of
Puerto Rico, or the Northern Mariana
Islands.
Non-continental liquid oil-fired
subcategory means any oil-fired electric
utility steam generating unit that burns
liquid oil and is located outside the
continental United States.
Non-mercury (Hg) HAP metals means
Antimony (Sb), Arsenic (As), Beryllium
(Be), Cadmium (Cd), Chromium (Cr),
Cobalt (Co), Lead (Pb), Manganese (Mn),
Nickel (Ni), and Selenium (Se). Oil
means crude oil or petroleum or a fuel
derived from crude oil or petroleum,
including distillate and residual oil,
solid oil-derived fuel (e.g., petroleum
coke) and gases derived from solid oilderived fuels (not meeting the definition
of natural gas).
Oil-fired electric utility steam
generating unit means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that is
not a coal-fired electric utility steam
generating unit and that burns oil for
more than 10.0 percent of the average
annual heat input during any 3
consecutive calendar years or for more
than 15.0 percent of the annual heat
input during any one calendar year.
Particulate matter or PM means any
finely divided solid material as
measured by the test methods specified
under this subpart, or an alternative
method.
Pulverized coal (PC) boiler means an
EGU in which pulverized coal is
introduced into an air stream that
carries the coal to the combustion
chamber of the EGU where it is fired in
suspension.
Residual oil means crude oil, and all
fuel oil numbers 4, 5 and 6, as defined
PO 00000
Frm 00184
Fmt 4701
Sfmt 4700
by ASTM Method D396–10, ‘‘Standard
Specification for Fuel Oils’’
(incorporated by reference, see § 63.14).
Responsible official means
responsible official as defined in 40 CFR
70.2.
Shutdown means the cessation of
operation of a boiler for any purpose.
Shutdown begins either when none of
the steam from the boiler is used to
generate electricity for sale over the grid
or for any other purpose (including onsite use), or at the point of no fuel being
fired in the boiler, whichever is earlier.
Shutdown ends when there is both no
electricity being generated and no fuel
being fired in the boiler.
Startup means either the first-ever
firing of fuel in a boiler for the purpose
of producing electricity, or the firing of
fuel in a boiler after a shutdown event
for any purpose. Startup ends when any
of the steam from the boiler is used to
generate electricity for sale over the grid
or for any other purpose (including onsite use).
Stationary combustion turbine means
all equipment, including but not limited
to the turbine, the fuel, air, lubrication
and exhaust gas systems, control
systems (except emissions control
equipment), and any ancillary
components and sub-components
comprising any simple cycle stationary
combustion turbine, any regenerative/
recuperative cycle stationary
combustion turbine, the combustion
turbine portion of any stationary
cogeneration cycle combustion system,
or the combustion turbine portion of
any stationary combined cycle steam/
electric generating system. Stationary
means that the combustion turbine is
not self propelled or intended to be
propelled while performing its function.
Stationary combustion turbines do not
include turbines located at a research or
laboratory facility, if research is
conducted on the turbine itself and the
turbine is not being used to power other
applications at the research or
laboratory facility.
Steam generating unit means any
furnace, boiler, or other device used for
combusting fuel for the purpose of
producing steam (including fossil-fuelfired steam generators associated with
integrated gasification combined cycle
gas turbines; nuclear steam generators
are not included).
Stoker means a unit consisting of a
mechanically operated fuel feeding
mechanism, a stationary or moving grate
to support the burning of fuel and admit
undergrate air to the fuel, an overfire air
system to complete combustion, and an
ash discharge system. There are two
general types of stokers: underfeed and
E:\FR\FM\16FER2.SGM
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Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
overfeed. Overfeed stokers include mass
feed and spreader stokers.
Subbituminous coal means coal that
is classified as subbituminous A, B, or
C according to ASTM Method D388–05,
‘‘Standard Classification of Coals by
Rank’’ (incorporated by reference, see
§ 63.14).
Unit designed for coal > 8,300 Btu/lb
subcategory means any coal-fired EGU
that is not a coal-fired EGU in the ‘‘unit
designed for low rank virgin coal’’
subcategory.
Unit designed for low rank virgin coal
subcategory means any coal-fired EGU
that is designed to burn and that is
burning nonagglomerating virgin coal
having a calorific value (moist, mineral
matter-free basis) of less than 19,305 kJ/
kg (8,300 Btu/lb) that is constructed and
operates at or near the mine that
produces such coal.
Unit designed to burn solid oilderived fuel subcategory means any oilfired EGU that burns solid oil-derived
fuel.
Voluntary consensus standards or
VCS mean technical standards (e.g.,
materials specifications, test methods,
sampling procedures, business
practices) developed or adopted by one
or more voluntary consensus bodies.
The EPA/OAQPS has by precedent only
used VCS that are written in English.
Examples of VCS bodies are: American
Society of Testing and Materials
(ASTM), American Society of
Mechanical Engineers (ASME),
International Standards Organization
(ISO), Standards Australia (AS), British
Standards (BS), Canadian Standards
(CSA), European Standard (EN or CEN)
and German Engineering Standards
(VDI). The types of standards that are
not considered VCS are standards
developed by: the U.S. states, e.g.,
California (CARB) and Texas (TCEQ);
industry groups, such as American
Petroleum Institute (API), Gas
Processors Association (GPA), and Gas
Research Institute (GRI); and other
9487
branches of the U.S. government, e.g.,
Department of Defense (DOD) and
Department of Transportation (DOT).
This does not preclude EPA from using
standards developed by groups that are
not VCS bodies within an EPA rule.
When this occurs, EPA has done
searches and reviews for VCS equivalent
to these non-VCS methods.
Wet flue gas desulfurization
technology, or wet FGD, or wet scrubber
means any add-on air pollution control
device that is located downstream of the
steam generating unit that mixes an
aqueous stream or slurry with the
exhaust gases from an EGU to control
emissions of PM and/or to absorb and
neutralize acid gases, such as SO2 and
HCl.
Work practice standard means any
design, equipment, work practice, or
operational standard, or combination
thereof, which is promulgated pursuant
to CAA section 112(h).
Tables to Subpart UUUUU of Part 63
TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS
[As stated in § 63.9991, you must comply with the following applicable emission limits]
For the following pollutants . . .
If your EGU is in this
subcategory . . .
1. Coal-fired unit not low rank virgin coal.
You must meet the following
emission limits and work practice
standards . . .
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table . . .
a.
7.0E–3 lb/MWh1 ............................
Collect a minimum of 4 dscm per
run.
Filterable particulate
(PM).
OR
Total non-Hg HAP metals
matter
OR
6.0E–2 lb/GWh .............................
Collect a minimum of 4 dscm per
run.
8.0E–3
3.0E–3
6.0E–4
4.0E–4
7.0E–3
2.0E–3
2.0E–3
4.0E–3
4.0E–2
6.0E–3
4.0E–4
OR.
Sulfur dioxide (SO2) 3 ....................
c. Mercury (Hg) .............................
2. Coal-fired units low rank virgin
coal.
OR
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HC1) .........
srobinson on DSK4SPTVN1PROD with RULES2
OR
individual HAP metals: .................
4.0E–1 lb/MWh .............................
2.0E–4 lb/GWh .............................
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
a.
7.0E–3 lb/MWh1 ............................
Collect a minimum of 4 dscm per
run.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
Collect a minimum of 3 dscm per
run.
lb/GW.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
OR
6.0E–2 lb/GWh .............................
OR
Individual HAP metals:
VerDate Mar<15>2010
22:15 Feb 15, 2012
Collect a minimum of 4 dscm per
run.
OR
Antimony (Sb) ...............................
Arsenic (As) ..................................
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
8.0E–3 lb/GWh.
3.0E–3 lb/GWh.
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Fmt 4701
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E:\FR\FM\16FER2.SGM
Collect a minimum of 3 dscm per
run.
16FER2
9488
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits]
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table . . .
For the following pollutants . . .
7.0E–2 lb/MWh 4 ...........................
9.0E–2 lb/MWh 5
OR
4.0E–1 lb/GWh .............................
Collect a minimum of 1 dscm per
run.
OR
.......................................................
2.0E–2
2.0E–2
1.0E–3
2.0E–3
4.0E–2
4.0E–3
9.0E–3
2.0E–2
7.0E–2
3.0E–1
2.0E–3
4.0E–1 lb/MWh .............................
3.0E–3 lb/GWh .............................
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
a.
matter
7.0E–2 lb/MWh1 ............................
Collect a minimum of 1 dscm per
run.
OR
Total HAP metals .........................
OR
2.0E–4 lb/MWh .............................
OR
Individual HAP metals:
srobinson on DSK4SPTVN1PROD with RULES2
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
OR
Sulfur dioxide (SO2) 3
c. Mercury (Hg) .............................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
22:15 Feb 15, 2012
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
VerDate Mar<15>2010
4.0E–1 lb/MWh .............................
4.0E–2 lb/GWh .............................
OR
Individual HAP metals:
4. Liquid oil-fired unit—continental
(excluding limited-use liquid oilfired subcategory units).
6.0E–4
4.0E–4
7.0E–3
2.0E–3
2.0E–3
4.0E–3
4.0E–2
6.0E–3
4.0E–4
OR
Sulfur dioxide (SO2) 3 ....................
c. Mercury (Hg) .............................
3. IGCC unit ...................................
You must meet the following
emission limits and work practice
standards . . .
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
If your EGU is in this
subcategory . . .
1.0E–2
3.0E–3
5.0E–4
2.0E–4
2.0E–2
3.0E–2
8.0E–3
2.0E–2
9.0E–2
2.0E–2
a.
Filterable
(PM).
Jkt 226001
PO 00000
particulate
Frm 00186
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lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 2 dscm per
run.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 2 dscm per
run.
Collect a minimum of 2 dscm per
run.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
Sfmt 4700
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16FER2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
9489
TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits]
For the following pollutants . . .
1.0E–4 lb/GWh .............................
b. Hydrogen chloride (HCl)
4.0E–4 lb/MWh .............................
c. Hydrogen fluoride (HF)
5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units).
You must meet the following
emission limits and work practice
standards . . .
Mercury (Hg)
If your EGU is in this
subcategory . . .
4.0E–4 lb/MWh .............................
a.
Filterable
(PM).
particulate
matter
2.0E–1 lb/MWh1 ............................
OR
Total HAP metals
OR
Individual HAP metals:
8.0E–3
6.0E–2
2.0E–3
2.0E–3
2.0E–2
3.0E–1
3.0E–2
1.0E–1
4.1E–0
2.0E–2
4.0E–4
b. Hydrogen chloride (HCl)
2.0E–3 lb/MWh .............................
c. Hydrogen fluoride (HF)
srobinson on DSK4SPTVN1PROD with RULES2
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
Mercury (Hg) .................................
6. Solid oil-derived fuel-fired unit ...
OR
7.0E–3 lb/MWh .............................
5.0E–4 lb/MWh .............................
a.
Filterable particulate
(PM).
OR
Total non-Hg HAP metals
matter
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh .............................
2.0E–2 lb/MWh1 ............................
OR
6.0E–1 lb/GWh .............................
OR
Individual HAP metals:
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
VerDate Mar<15>2010
23:04 Feb 15, 2012
OR
.......................................................
8.0E–3
3.0E–3
6.0E–4
7.0E–4
6.0E–3
2.0E–3
Jkt 226001
PO 00000
Frm 00187
Fmt 4701
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table . . .
For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be <1⁄2 the
standard.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be < 1⁄2 the
standard.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–032 or Method
320, sample for a minimum of 1
hour
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
Sfmt 4700
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16FER2
9490
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits]
For the following pollutants . . .
You must meet the following
emission limits and work practice
standards . . .
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
If your EGU is in this
subcategory . . .
2.0E–2
7.0E–3
4.0E–2
6.0E–3
4.0E–4
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table . . .
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 3 ....................
c. Mercury (Hg) .............................
1 Gross electric output.
2 Incorporated by reference, see § 63.14.
3 You may not use the alternate SO limit if your EGU
2
4 Duct burners on syngas; gross electric output.
5 Duct burners on natural gas; gross electric output
4.0E–1 lb/MWh .............................
2.0E–3 lb/GWh .............................
SO2 CEMS.
Hg CEMS or Sorbent trap monitoring system only.
does not have some form of FGD system and SO2 CEMS installed.
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS
[As stated in § 63.9991, you must comply with the following applicable emission limits] 1
If your EGU is in this subcategory
For the following pollutants
1. Coal-fired unit not low rank virgin coal.
You must meet the following
emission limits and work practice
standards
a.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals .............
OR
Individual HAP metals
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ...............................
Chromium (Cr) ..............................
Cobalt (Co) ....................................
Lead (Pb) ......................................
Manganese (Mn) ...........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
OR
Sulfur dioxide (SO2) 4 ....................
srobinson on DSK4SPTVN1PROD with RULES2
c. Mercury (Hg) .............................
2. Coal-fired unit low rank virgin
coal.
a.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals .............
OR
VerDate Mar<15>2010
22:15 Feb 15, 2012
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Frm 00188
Fmt 4701
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh 2.
OR
5.0E–5 lb/MMBtu or 5.0E–1 lb/
GWh.
OR
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.1E0 lb/TBtu or 2.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
2.8E0 lb/TBtu or 3.0E–2 lb/GWh.
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.2E0 lb/TBtu or 2.0E–2 lb/GWh.
4.0E0 lb/TBtu or 5.0E–2 lb/GWh.
3.5E0 lb/TBtu or 4.0E–2 lb/GWh.
5.0E0 lb/TBtu or 6.0E–2 lb/GWh.
2.0E–3 lb/MMBtu or 2.0E–2 lb/
MWh.
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods in
Table 5
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
For Method 26A, collect a minimum of 0.75 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
2.0E–1 lb/MMBtu or 1.5E0 lb/
MWh.
1.2E0 lb/TBtu or 1.3E–2 lb/GWh ..
SO2 CEMS.
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh2.
OR
5.0E–5 lb/MMBtu or 5.0E–1 lb/
GWh.
OR
Collect a minimum of 1 dscm per
run.
Sfmt 4700
E:\FR\FM\16FER2.SGM
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or sorbent trap
monitoring system only.
Collect a minimum of 1 dscm per
run.
16FER2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
9491
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits] 1
For the following pollutants
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods in
Table 5
Individual HAP metals:
.......................................................
Collect a minimum of 3 dscm per
run.
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ...............................
Chromium (Cr) ..............................
Cobalt (Co) ....................................
Lead (Pb) ......................................
Manganese (Mn) ...........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
If your EGU is in this subcategory
You must meet the following
emission limits and work practice
standards
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.1E0 lb/TBtu or 2.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
2.8E0 lb/TBtu or 3.0E–2 lb/GWh.
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.2E0 lb/TBtu or 2.0E–2 lb/GWh.
4.0E0 lb/TBtu or 5.0E–2 lb/GWh.
3.5E0 lb/TBtu or 4.0E–2 lb/GWh.
5.0E0 lb/TBtu or 6.0E–2 lb/GWh.
2.0E–3 lb/MMBtu or 2.0E–2 lb/
MWh.
OR
Sulfur dioxide (SO2) 4 ....................
c. Mercury (Hg) .............................
3. IGCC unit ..................................
a.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals .............
OR
Individual HAP metals: ..................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ...............................
Chromium (Cr) ..............................
Cobalt (Co) ....................................
Lead (Pb) ......................................
Manganese (Mn) ...........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
For Method 26A, collect a minimum of 0.75 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
2.0E–1 lb/MMBtu or 1.5E0 lb/
MWh.
4.0E0 lb/TBtu or 4.0E–2 lb/GWh ..
SO2 CEMS.
4.0E–2 lb/MMBtu or 4.0E–1 lb/
MWh2.
OR
6.0E–5 lb/MMBtu or 5.0E–1 lb/
GWh.
OR
.......................................................
Collect a minimum of 1 dscm per
run.
1.4E0 lb/TBtu or 2.0E–2 lb/GWh.
1.5E0 lb/TBtu or 2.0E–2 lb/GWh.
1.0E–1 lb/TBtu or 1.0E–3 lb/GWh.
1.5E–1 lb/TBtu or 2.0E–3 lb/GWh.
2.9E0 lb/TBtu or 3.0E–2 lb/GWh.
1.2E0 lb/TBtu or 2.0E–2 lb/GWh.
1.9E+2 lb/MMBtu or 1.8E0 lb/
MWh.
2.5E0 lb/TBtu or 3.0E–2 lb/GWh.
6.5E0 lb/TBtu or 7.0E–2 lb/GWh.
2.2E+1 lb/TBtu or 3.0E–1 lb/GWh.
5.0E–4 lb/MMBtu or 5.0E–3 lb/
MWh.
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or sorbent trap
monitoring system only.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 2 dscm per
run.
For Method 26A, collect a minimum of 1 dscm per
run; for Method 26, collect a minimum of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or sorbent trap
monitoring system only.
srobinson on DSK4SPTVN1PROD with RULES2
c. Mercury (Hg) .............................
a.
matter
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh2.
Collect a minimum of 1 dscm per
run.
OR
Total HAP metals ..........................
4. Liquid oil-fired unit—continental
(excluding limited-use liquid oilfired subcategory units).
2.5E0 lb/TBtu or 3.0E–2 lb/GWh ..
OR
8.0E–4 lb/MMBtu or 8.0E–3 lb/
MWh.
OR
Collect a minimum of 1 dscm per
run.
Filterable
(PM).
particulate
OR
Individual HAP metals ...................
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Collect a minimum of 1 dscm per
run.
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16FER2
9492
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits] 1
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods in
Table 5
a.
matter
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh2.
Collect a minimum of 1 dscm per
run.
OR
6.0E–4 lb/MMBtu or 7.0E–3 lb/
MWh.
OR
.......................................................
Collect a minimum of 1 dscm per
run.
OR
Individual HAP metals ...................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ...............................
Chromium (Cr) ..............................
Cobalt (Co) ....................................
Lead (Pb) ......................................
Manganese (Mn) ...........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
Mercury (Hg) .................................
2.2E0 lb/TBtu or 2.0E–2 lb/GWh.
4.3E0 lb/TBtu or 8.0E–2 lb/GWh.
6.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
3.1E+1 lb/TBtu or 3.0E–1 lb/GWh.
1.1E+2 lb/TBtu or 1.4E0 lb/GWh.
4.9E0 lb/TBtu or 8.0E–2 lb/GWh.
2.0E+1 lb/TBtu or 3.0E–1 lb/GWh.
4.7E+2 lb/TBtu or 4.1E0 lb/GWh.
9.8E0 lb/TBtu or 2.0E–1 lb/GWh.
4.0E–2 lb/TBtu or 4.0E–4 lb/GWh
Hydrogen chloride (HCl) ...............
srobinson on DSK4SPTVN1PROD with RULES2
4.0E–4 lb/MMBtu or 4.0E–3 lb/
MWh.
OR
Total HAP metals ..........................
2.0E–4 lb/MMBtu or 2.0E–3 lb/
MWh.
c. Hydrogen fluoride (HF) .............
22:15 Feb 15, 2012
2.0E–3 lb/MMBtu or 1.0E–2 lb/
MWh.
c. Hydrogen fluoride (HF) .............
VerDate Mar<15>2010
1.3E+1 lb/TBtu or 2.0E–1 lb/GWh.
2.8E0 lb/TBtu or 3.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
5.5E0 lb/TBtu or 6.0E–2 lb/GWh.
2.1E+1 lb/TBtu or 3.0E–1 lb/GWh.
8.1E0 lb/TBtu or 8.0E–2 lb/GWh.
2.2E+1 lb/TBtu or 3.0E–1 lb/GWh.
1.1E+2 lb/TBtu or 1.1E0 lb/GWh.
3.3E0 lb/TBtu or 4.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh
b. Hydrogen chloride (HCl) ...........
5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units).
For the following pollutants
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ...............................
Chromium (Cr) ..............................
Cobalt (Co) ....................................
Lead (Pb) ......................................
Manganese (Mn) ...........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
Mercury (Hg) .................................
If your EGU is in this subcategory
You must meet the following
emission limits and work practice
standards
6.0E–5 lb/MMBtu or 5.0E–4 lb/
MWh.
Filterable
(PM).
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For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be < 1⁄2 the
standard.
For Method 26A, collect a minimum of 1 dscm per
Run; for Method 26, collect a minimum of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 2 dscm per
run.
For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be < 1⁄2 the
standard.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 2
hours.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 2
hours.
16FER2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
9493
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits] 1
If your EGU is in this subcategory
For the following pollutants
6. Solid oil-derived fuel-fired unit ..
You must meet the following
emission limits and work practice
standards
a.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals .............
OR
Individual HAP metals ...................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ...............................
Chromium (Cr) ..............................
Cobalt (Co) ....................................
Lead (Pb) ......................................
Manganese (Mn) ...........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
OR
Sulfur dioxide (SO2) 4 ....................
c. Mercury (Hg) .............................
8.0E–3 lb/MMBtu or 9.0E–2 lb/
MWh2.
OR
4.0E–5 lb/MMBtu or 6.0E–1 lb/
GWh.
OR
.......................................................
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 5.0E–3 lb/GWh.
6.0E–2 lb/TBtu or 6.0E–4 lb/GWh.
3.0E–1 lb/TBtu or 4.0E–3 lb/GWh.
8.0E–1 lb/TBtu or 2.0E–2 lb/GWh.
1.1E0 lb/TBtu or 2.0E–2 lb/GWh.
8.0E–1 lb/TBtu or 2.0E–2 lb/GWh.
2.3E0 lb/TBtu or 4.0E–2 lb/GWh.
9.0E0 lb/TBtu or 2.0E–1 lb/GWh.
1.2E0 lb/TBtu 2.0E–2 lb/GWh.
5.0E–3 lb/MMBtu or 8.0E–2 lb/
MWh.
3.0E–1 lb/MMBtu or 2.0E0 lb/
MWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods in
Table 5
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
For Method 26A, collect a minimum of 0.75 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
SO2 CEMS.
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or Sorbent
trap monitoring system only.
1 For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must
be increased nominally by a factor of two.
2 Gross electric output.
3 Incorporated by reference, see § 63.14.
4 You may not use the alternate SO limit if your EGU does not have some form of FGD system and SO CEMS installed.
2
2
TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS
[As stated in §§ 63.9991, you must comply with the following applicable work practice standards]
You must meet the following . . .
1. An existing EGU .............................................
Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar
months, or each 48 calendar months if neural network combustion optimization software is
employed, as specified in § 63.10021(e).
2. A new or reconstructed EGU .........................
Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar
months, or each 48 calendar months if neural network combustion optimization software is
employed, as specified in § 63.10021(e).
3. A coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGU during startup.
srobinson on DSK4SPTVN1PROD with RULES2
If your EGU is . . .
You must operate all CMS during startup. Startup means either the first-ever firing of fuel in a
boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown
event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on site use). For
startup of a unit, you must use clean fuels, either natural gas or distillate oil or a combination of clean fuels for ignition. Once you convert to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the applicable control technologies except dry scrubber
and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to
comply with relevant standards applicable during normal operation. You must comply with all
applicable emissions limits at all times except for periods that meet the definitions of startup
and shutdown in this subpart. You must keep records during periods of startup. You must
provide reports concerning activities and periods of startup, as specified in § 63.10011(g)
and § 63.10021(h) and (i).
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16FER2
9494
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS—Continued
[As stated in §§ 63.9991, you must comply with the following applicable work practice standards]
If your EGU is . . .
You must meet the following . . .
4. A coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGU during shutdown.
You must operate all CMS during shutdown. Shutdown means the cessation of operation of a
boiler for any purpose. Shutdown begins either when none of the steam from the boiler is
used to generate electricity for sale over the grid or for any other purpose (including on-site
use) or at the point of no fuel being fired in the boiler. Shutdown ends when there is both no
electricity being generated and no fuel being fired in the boiler. During shutdown, you must
operate all applicable control technologies while firing coal, residual oil, or solid oil-derived
fuel. You must comply with all applicable emissions limits at all times except for periods that
meet the definitions of startup and shutdown in this subpart. You must keep records during
periods of startup. You must provide reports concerning activities and periods of startup, as
specified in § 63.10011(g) and § 63.10021(h) and (i).
TABLE 4 TO SUBPART UUUUU OF PART 63—OPERATING LIMITS FOR EGUS
[As stated in § 63.9991, you must comply with the applicable operating limits]
If you demonstrate compliance using . . .
You must meet these operating limits . . .
1. PM CPMS .......................................................
Maintain the 30-boiler operating day rolling average PM CPMS output at or below the highest
1-hour average measured during the most recent performance test demonstrating compliance with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oilfired units), or individual non-mercury HAP metals (individual HAP metals including Hg, for
liquid oil-fired units) emissions limitation(s).
TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS
[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected
sources 1]
To conduct a performance test for the following pollutant . . .
Using . . .
You must perform the following activities, as
applicable to your input- or output-based
emission limit . . .
1. Filterable Particulate
matter (PM).
Emissions Testing ......
a. Select sampling ports location and the
number of traverse points.
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
d. Measure the moisture content of the stack
gas.
e. Measure the filterable PM concentration ....
f. Convert emissions concentration to lb/
MMBtu or lb/MWh emissions rates.
srobinson on DSK4SPTVN1PROD with RULES2
OR
PM CEMS
OR
a. Install, certify, operate, and maintain the
PM CEMS.
b. Install, certify, operate, and maintain the
diluent gas, flow rate, and/or moisture monitoring systems.
c. Convert hourly emissions concentrations to
30 boiler operating day rolling average lb/
MMBtu or lb/MWh emissions rates.
2. Total or individual
non-Hg HAP metals.
VerDate Mar<15>2010
Emissions Testing ......
22:15 Feb 15, 2012
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number of traverse points.
b. Determine velocity and volumetric flow-rate
of the stack gas.
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Using 2 . . .
Method 1 at Appendix A–1 to part 60 of this
chapter.
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix
A–1 or A–2 to part 60 of this chapter.
Method 3A or 3B at Appendix A–2 to part 60
of this chapter, or ANSI/ASME PTC 19.10–
1981.3
Method 4 at Appendix A–3 to part 60 of this
chapter.
Method 5 at Appendix A–3 to part 60 of this
chapter.
For positive pressure fabric filters, Method 5D
at Appendix A–3 to part 60 of this chapter
for filterable PM emissions.
Note that the Method 5 front half temperature
shall be 160 ° ± 14 °C (320 ° ± 25 °F).
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
Performance Specification 11 at Appendix B
to part 60 of this chapter and Procedure 2
at Appendix F to Part 60 of this chapter.
Part 75 of this chapter and §§ 63.10010(a),
(b), (c), and (d).
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
Method 1 at Appendix A–1 to part 60 of this
chapter.
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix
A–1 or A–2 to part 60 of this chapter.
E:\FR\FM\16FER2.SGM
16FER2
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
9495
TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued
[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected
sources 1]
To conduct a performance test for the following pollutant . . .
You must perform the following activities, as
applicable to your input- or output-based
emission limit . . .
Using . . .
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
Using 2 . . .
f. Convert emissions concentrations (individual HAP metals, total filterable HAP
metals, and total HAP metals) to lb/MMBtu
or lb/MWh emissions rates.
Method 3A or 3B at Appendix A–2 to part 60
of this chapter, or ANSI/ASME PTC 19.10–
1981.3
Method 4 at Appendix A–3 to part 60 of this
chapter.
Method 29 at Appendix A–8 to part 60 of this
chapter. For liquid oil-fired units, Hg is included in HAP metals and you may use
Method 29, Method 30B at Appendix A–8
to part 60 of this chapter; for Method 29,
you must report the front half and back half
results separately.
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
a. Select sampling ports location and the
number of traverse points.
Method 1 at Appendix A–1 to part 60 of this
chapter.
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix
A–1 or A–2 to part 60 of this chapter.
Method 3A or 3B at Appendix A–2 to part 60
of this chapter, or ANSI/ASME PTC 19.10–
1981.3
Method 4 at Appendix A–3 to part 60 of this
chapter.
Method 26 or Method 26A at Appendix A–8
to part 60 of this chapter or Method 320 at
Appendix A to part 63 of this chapter or
ASTM 6348–03 3 with (1) additional quality
assurance measures in footnote 4 and (2)
spiking levels nominally no greater than
two times the level corresponding to the
applicable emission limit. Method 26A must
be used if there are entrained water droplets in the exhaust stream.
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
d. Measure the moisture content of the stack
gas.
e. Measure the HAP metals emissions concentrations and determine each individual
HAP metals emissions concentration, as
well as the total filterable HAP metals
emissions concentration and total HAP
metals emissions concentration.
3. Hydrogen chloride
(HCl) and hydrogen
fluoride (HF).
Emissions Testing ......
d. Measure the moisture content of the stack
gas.
e. Measure the HCl and HF emissions concentrations.
f. Convert emissions concentration to lb/
MMBtu or lb/MWh emissions rates.
OR
HCl and/or HF CEMS
srobinson on DSK4SPTVN1PROD with RULES2
4. Mercury (Hg) ...........
Emissions Testing ......
OR
a. Install, certify, operate, and maintain the
HCl or HF CEMS.
b. Install, certify, operate, and maintain the
diluent gas, flow rate, and/or moisture monitoring systems.
c. Convert hourly emissions concentrations to
30 boiler operating day rolling average lb/
MMBtu or lb/MWh emissions rates.
a. Select sampling ports location and the
number of traverse points.
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
d. Measure the moisture content of the stack
gas.
e. Measure the Hg emission concentration ....
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Appendix B of this subpart.
Part 75 of this chapter and §§ 63.10010(a),
(b), (c), and (d).
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
Method 1 at Appendix A–1 to part 60 of this
chapter or Method 30B at Appendix A–8
for Method 30B point selection.
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix
A–1 or A–2 to part 60 of this chapter.
Method 3A or 3B at Appendix A–1 to part 60
of this chapter, or ANSI/ASME PTC 19.10–
1981.3
Method 4 at Appendix A–3 to part 60 of this
chapter.
Method 30B at Appendix A–8 to part 60 of
this chapter, ASTM D6784 3, or Method 29
at Appendix A–8 to part 60 of this chapter;
for Method 29, you must report the front
half and back half results separately.
E:\FR\FM\16FER2.SGM
16FER2
9496
Federal Register / Vol. 77, No. 32 / Thursday, February 16, 2012 / Rules and Regulations
TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued
[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected
sources 1]
To conduct a performance test for the following pollutant . . .
You must perform the following activities, as
applicable to your input- or output-based
emission limit . . .
Using . . .
f. Convert emissions concentration to lb/TBtu
or lb/GWh emission rates.
OR
OR
Sorbent trap monitoring system.
OR
LEE testing .................
OR
Hg CEMS ........................................................
a. Install, certify, operate, and maintain the
CEMS.
b. Install, certify, operate, and maintain the
diluent gas, flow rate, and/or moisture monitoring systems.
c. Convert hourly emissions concentrations to
30 boiler operating day rolling average lb/
TBtu or lb/GWh emissions rates.
OR
a. Install, certify, operate, and maintain the
sorbent trap monitoring system.
b. Install, operate, and maintain the diluent
gas, flow rate, and/or moisture monitoring
systems.
c. Convert emissions concentrations to 30
boiler operating day rolling average lb/TBtu
or lb/GWh emissions rates.
OR
a. Select sampling ports location and the
number of traverse points.
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
d. Measure the moisture content of the stack
gas.
e. Measure the Hg emission concentration ....
f. Convert emissions concentrations from the
LEE test to lb/TBtu or lb/GWh emissions
rates.
g. Convert average lb/TBtu or lb/GWh Hg
emission rate to lb/year, if you are attempting to meet the 22.0 lb/year threshold.
srobinson on DSK4SPTVN1PROD with RULES2
5. Sulfur dioxide (SO2)
1 Regarding
VerDate Mar<15>2010
SO2 CEMS .................
a. Install, certify, operate, and maintain the
CEMS.
b. Install, operate, and maintain the diluent
gas, flow rate, and/or moisture monitoring
systems.
c. Convert hourly emissions concentrations to
30 boiler operating day rolling average lb/
MMBtu or lb/MWh emissions rates.
Using 2 . . .
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
Sections 3.2.1 and 5.1 of Appendix A of this
subpart.
Part 75 of this chapter and §§ 63.10010(a),
(b), (c), and (d).
Section 6 of Appendix A to this subpart.
Sections 3.2.2 and 5.2 of Appendix A to this
subpart.
Part 75 of this chapter and §§ 63.10010(a),
(b), (c), and (d).
Section 6 of Appendix A to this subpart.
Single point located at the 10% centroidal
area of the duct at a port location per
Method 1 at Appendix A–1 to part 60 of
this chapter or Method 30B at Appendix A–
8 for Method 30B point selection.
Method 2, 2A, 2C, 2F, 2G, or 2H at Appendix
A–1 or A–2 to part 60 of this chapter or
flow monitoring system certified per Appendix A of this subpart.
Method 3A or 3B at Appendix A–1 to part 60
of this chapter, or ANSI/ASME PTC 19.10–
1981,3 or diluent gas monitoring systems
certified according to Part 75 of this chapter.
Method 4 at Appendix A–3 to part 60 of this
chapter, or moisture monitoring systems
certified according to part 75 of this chapter.
Method 30B at Appendix A–8 to part 60 of
this chapter; perform a 30 operating day
test, with a maximum of 10 operating days
per run (i.e., per pair of sorbent traps) or
sorbent trap monitoring system or Hg
CEMS certified per Appendix A of this subpart.
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
Potential maximum annual heat input in TBtu
or potential maximum electricity generated
in GWh.
Part 75 of this chapter and §§ 63.10010(a)
and (f).
Part 75 of this chapter and §§ 63.10010(a),
(b), (c), and (d).
Method 19 F-factor methodology at Appendix
A–7 to part 60 of this chapter, or calculate
using mass emissions rate and electrical
output data (see § 63.10007(e)).
emissions data collected during periods of startup or shutdown, see §§ 63.10020(b) and (c) and § 63.10021(h).
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9497
2 See
Tables 1 and 2 to this subpart for required sample volumes and/or sampling run times.
by reference, see § 63.14.
4 When using ASTM D6348–03, the following conditions must be met: (1) The test plan preparation and implementation in the Annexes to
ASTM D6348–03, Sections A1 through A8 are mandatory; (2) For ASTM D6348–03 Annex A5 (Analyte Spiking Technique), the percent (%) R
must be determined for each target analyte (see Equation A5.5); (3) For the ASTM D6348–03 test data to be acceptable for a target analyte, %R
must be 70% ≥ R ≤ 130%; and (4) The %R value for each compound must be reported in the test report and all field measurements corrected
with the calculated %R value for that compound using the following equation:
3 Incorporated
TABLE 6 TO SUBPART UUUUU OF PART 63—ESTABLISHING PM CPMS OPERATING LIMITS
[As stated in § 63.10007, you must comply with the following requirements for establishing operating limits]
If you have an applicable
emission limit for . . .
And you choose to establish
PM CPMS operating limits,
you must . . .
And . . .
Using . . .
According to the following
procedures . . .
Particulate matter (PM),
total non-mercury HAP
metals, individual nonmercury HAP metals,
total HAP metals, individual HAP metals.
Install, certify, maintain, and
operate a PM CPMS for
monitoring emissions discharged to the atmosphere
according
to
§ 63.10010(g)(1).
Establish a site-specific
operating limit in units
of PM CPMS output
signal (e.g., milliamps,
mg/acm, or other raw
signal).
Data from the PM CPMS
and the PM or HAP
metals performance
tests.
1. Collect PM CPMS output data during the entire period of the performance tests.
2. Record the average
hourly PM CPMS output for each test run in
the three run performance test.
3. Determine the highest
1-hour average PM
CPMS measured during the performance
test demonstrating
compliance with the filterable PM or HAP
metals emissions limitations.
TABLE 7 TO SUBPART UUUUU OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE
[As stated in § 63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following]
If you use one of the following to meet applicable emissions limits, operating limits, or work practice standards . . .
You demonstrate continuous compliance by . . .
1. CEMS to measure filterable PM, SO2, HCl, HF, or Hg emissions, or
using a sorbent trap monitoring system to measure Hg.
Calculating the 30-boiler operating day rolling arithmetic average emissions rate in units of the applicable emissions standard basis at the
end of each boiler operating day using all of the quality assured
hourly average CEMS or sorbent trap data for the previous 30 boiler
operating days, excluding data recorded during periods of startup or
shutdown.
Calculating the arithmetic 30-boiler operating day rolling average of all
of the quality assured hourly average PM CPMS output data (e.g.,
milliamps, PM concentration, raw data signal) collected for all operating hours for the previous 30 boiler operating days, excluding data
recorded during periods of startup or shutdown.
If applicable, by conducting the monitoring in accordance with an approved site-specific monitoring plan.
Calculating the results of the testing in units of the applicable emissions standard.
srobinson on DSK4SPTVN1PROD with RULES2
3. Site-specific monitoring for liquid oil-fired units for HCl and HF emission limit monitoring.
4. Quarterly performance testing for coal-fired, solid oil derived fired, or
liquid oil-fired units to measure compliance with one or more applicable emissions limit in Table 1 or 2.
5. Conducting periodic performance tune-ups of your EGU(s) ................
6. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during startup.
7. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during shutdown.
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Conducting periodic performance tune-ups of your EGU(s), as specified in § 63.10021(e).
Operating in accordance with Table 3.
Operating in accordance with Table 3.
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ER16FE12.011</GPH>
2. PM CPMS to measure compliance with a parametric operating limit
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TABLE 8 TO SUBPART UUUUU OF PART 63—REPORTING REQUIREMENTS
[As stated in § 63.10031, you must comply with the following requirements for reports]
You must submit a . . .
The report must contain . . .
You must submit the report . . .
1. Compliance report ..........
a. Information required in § 63.10031(c)(1) through (4); and
b. If there are no deviations from any emission limitation (emission limit and operating limit) that applies to you and there are no deviations from the requirements for work practice standards in Table 3 to this subpart that apply to you,
a statement that there were no deviations from the emission limitations and
work practice standards during the reporting period. If there were no periods
during which the CMSs, including continuous emissions monitoring system,
and operating parameter monitoring systems, were out-of-control as specified
in § 63.8(c)(7), a statement that there were no periods during which the CMSs
were out-of-control during the reporting period; and
c. If you have a deviation from any emission limitation (emission limit and operating limit) or work practice standard during the reporting period, the report
must contain the information in § 63.10031(d). If there were periods during
which the CMSs, including continuous emissions monitoring systems and
continuous parameter monitoring systems, were out-of-control, as specified in
§ 63.8(c)(7), the report must contain the information in § 63.10031(e).
Semiannually according to the
requirements in
§ 63.10031(b).
TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU
[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following]
Citation
§ 63.1
§ 63.2
§ 63.3
§ 63.4
§ 63.5
Subject
.................................................................
.................................................................
.................................................................
.................................................................
.................................................................
§ 63.6(a), (b)(1)–(b)(5), (b)(7), (c), (f)(2)–(3),
(g), (h)(2)–(h)(9), (i), (j).
§ 63.6(e)(1)(i) .....................................................
§ 63.6(e)(1)(ii) .....................................................
§ 63.6(e)(3) .........................................................
§ 63.6(f)(1) ..........................................................
§ 63.6(h)(1) .........................................................
§ 63.7(a), (b), (c), (d), (e)(2)–(e)(9), (f), (g), and
(h).
§ 63.7(e)(1) .........................................................
§ 63.8 .................................................................
63.8(c)(1)(i) ........................................................
Applies to subpart UUUUU
Applicability .......................................................
Definitions .........................................................
Units and Abbreviations ...................................
Prohibited Activities and Circumvention ...........
Preconstruction Review and Notification Requirements.
Compliance with Standards and Maintenance
Requirements.
General Duty to minimize emissions ...............
Requirement to correct malfunctions ASAP ....
SSM Plan requirements ...................................
SSM exemption ................................................
SSM exemption ................................................
Performance Testing Requirements ................
§ 63.8(c)(1)(iii) ....................................................
§ 63.8(d)(3) .........................................................
Performance testing .........................................
Monitoring Requirements .................................
General duty to minimize emissions and CMS
operation.
Requirement to develop SSM Plan for CMS ...
Written procedures for CMS ............................
§ 63.9 .................................................................
§ 63.10(a), (b)(1), (c), (d)(1)–(2), (e), and (f) .....
Notification Requirements ................................
Recordkeeping and Reporting Requirements ..
§ 63.10(b)(2)(i) ...................................................
Recordkeeping of occurrence and duration of
startups and shutdowns.
Recordkeeping of malfunctions ........................
§ 63.10(b)(2)(ii) ...................................................
§ 63.10(b)(2)(iii) ..................................................
§ 63.10(b)(2)(iv) ..................................................
srobinson on DSK4SPTVN1PROD with RULES2
§ 63.10(b)(2)(v) ..................................................
§ 63.10(b)(2)(vi) ..................................................
§ 63.10(b)(2)(vii)–(ix) ..........................................
§ 63.10(b)(3), and (d)(3)–(5) ..............................
§ 63.10(c)(7) .......................................................
§ 63.10(c)(8) .......................................................
§ 63.10(c)(10) .....................................................
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Maintenance records ........................................
Actions taken to minimize emissions during
SSM.
Actions taken to minimize emissions during
SSM.
Recordkeeping for CMS malfunctions .............
Other CMS requirements .................................
...........................................................................
Additional recordkeeping requirements for
CMS—identifying exceedances and excess
emissions.
Additional recordkeeping requirements for
CMS—identifying exceedances and excess
emissions.
Recording nature and cause of malfunctions ..
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Yes.
Yes. Additional terms defined in § 63.10042.
Yes.
Yes.
Yes.
Yes.
No. See § 63.10000(b) for general duty requirement.
No.
No.
No.
No.
Yes.
No. See § 63.10007.
Yes.
No. See § 63.10000(b) for general duty requirement.
No.
Yes, except for last sentence, which refers to
an SSM plan. SSM plans are not required.
Yes.
Yes, except for the requirements to submit
written reports under § 63.10(e)(3)(v).
No.
No. See 63.10001 for recordkeeping of (1) occurrence and duration and (2) actions taken
during malfunction.
Yes.
No.
No.
Yes.
Yes.
No.
Yes.
Yes.
No. See 63.10032(g) and (h) for malfunctions
recordkeeping requirements.
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TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU—Continued
[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following]
Citation
Subject
Applies to subpart UUUUU
§ 63.10(c)(11) .....................................................
Recording corrective actions ............................
§ 63.10(c)(15) .....................................................
§ 63.10(d)(5) .......................................................
Use of SSM Plan ..............................................
SSM reports .....................................................
§ 63.11 ...............................................................
§ 63.12 ...............................................................
§ 63.13–63.16 ....................................................
Control Device Requirements ..........................
State Authority and Delegation ........................
Addresses, Incorporation by Reference, Availability of Information, Performance Track
Provisions.
Reserved ..........................................................
No. See 63.10032(g) and (h) for malfunctions
recordkeeping requirements.
No.
No. See 63.10021(h) and (i) for malfunction
reporting requirements.
No.
Yes.
Yes.
§ 63.1(a)(5), (a)(7)–(a)(9), (b)(2), (c)(3)–(4), (d),
63.6(b)(6), (c)(3), (c)(4), (d), (e)(2), (e)(3)(ii),
(h)(3), (h)(5)(iv), 63.8(a)(3), 63.9(b)(3), (h)(4),
63.10(c)(2)–(4), (c)(9).
Appendix A to Subpart UUUUU—Hg
Monitoring Provisions
srobinson on DSK4SPTVN1PROD with RULES2
1. General Provisions
1.1 Applicability. These monitoring
provisions apply to the measurement of total
vapor phase mercury (Hg) in emissions from
electric utility steam generating units, using
either a mercury continuous emission
monitoring system (Hg CEMS) or a sorbent
trap monitoring system. The Hg CEMS or
sorbent trap monitoring system must be
capable of measuring the total vapor phase
mercury in units of the applicable emissions
standard (e.g., lb/TBtu or lb/GWh), regardless
of speciation.
1.2 Initial Certification and
Recertification Procedures. The owner or
operator of an affected unit that uses a Hg
CEMS or a sorbent trap monitoring system
together with other necessary monitoring
components to account for Hg emissions in
units of the applicable emissions standard
shall comply with the initial certification and
recertification procedures in section 4 of this
appendix.
1.3 Quality Assurance and Quality
Control Requirements. The owner or operator
of an affected unit that uses a Hg CEMS or
a sorbent trap monitoring system together
with other necessary monitoring components
to account for Hg emissions in units of the
applicable emissions standard shall meet the
applicable quality assurance requirements in
section 5 of this appendix.
1.4 Missing Data Procedures. The owner
or operator of an affected unit is not required
to substitute for missing data from Hg CEMS
or sorbent trap monitoring systems. Any
process operating hour for which qualityassured Hg concentration data are not
obtained is counted as an hour of monitoring
system downtime.
2. Monitoring of Hg Emissions
2.1 Monitoring System Installation
Requirements. Flue gases from the affected
units under this subpart vent to the
atmosphere through a variety of exhaust
configurations including single stacks,
common stack configurations, and multiple
stack configurations. For each of these
configurations, § 63.10010(a) specifies the
appropriate location(s) at which to install
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continuous monitoring systems (CMS). These
CMS installation provisions apply to the Hg
CEMS, sorbent trap monitoring systems, and
other continuous monitoring systems that
provide data for the Hg emissions
calculations in section 6.2 of this appendix.
2.2 Primary and Backup Monitoring
Systems. In the electronic monitoring plan
described in section 7.1.1.2.1 of this
appendix, you must designate a primary Hg
CEMS or sorbent trap monitoring system. The
primary system must be used to report hourly
Hg concentration values when the system is
able to provide quality-assured data, i.e.,
when the system is ‘‘in control’’. However, to
increase data availability in the event of a
primary monitoring system outage, you may
install, operate, maintain, and calibrate
backup monitoring systems, as follows:
2.2.1 Redundant Backup Systems. A
redundant backup monitoring system may be
either a separate Hg CEMS with its own
probe, sample interface, and analyzer, or a
separate sorbent trap monitoring system. A
redundant backup system is one that is
permanently installed at the unit or stack
location, and is kept on ‘‘hot standby’’ in case
the primary monitoring system is unable to
provide quality-assured data. A redundant
backup system must be represented as a
unique monitoring system in the electronic
monitoring plan. Each redundant backup
monitoring system must be certified
according to the applicable provisions in
section 4 of this appendix and must meet the
applicable on-going QA requirements in
section 5 of this appendix.
2.2.2 Non-redundant Backup Monitoring
Systems. A non-redundant backup
monitoring system is a separate Hg CEMS or
sorbent trap system that has been certified at
a particular unit or stack location, but is not
permanently installed at that location.
Rather, the system is kept on ‘‘cold standby’’
and may be reinstalled in the event of a
primary monitoring system outage. A nonredundant backup monitoring system must
be represented as a unique monitoring
system in the electronic monitoring plan.
Non-redundant backup Hg CEMS must
complete the same certification tests as the
primary monitoring system, with one
exception. The 7-day calibration error test is
not required for a non-redundant backup Hg
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No.
CEMS. Except as otherwise provided in
section 2.2.4.5 of this appendix, a nonredundant backup monitoring system may
only be used for 720 hours per year at a
particular unit or stack location.
2.2.3 Temporary Like-kind Replacement
Analyzers. When a primary Hg analyzer
needs repair or maintenance, you may
temporarily install a like-kind replacement
analyzer, to minimize data loss. Except as
otherwise provided in section 2.2.4.5 of this
appendix, a temporary like-kind replacement
analyzer may only be used for 720 hours per
year at a particular unit or stack location. The
analyzer must be represented as a component
of the primary Hg CEMS, and must be
assigned a 3-character component ID number,
beginning with the prefix ‘‘LK’’.
2.2.4 Quality Assurance Requirements for
Non-redundant Backup Monitoring Systems
and Temporary Like-kind Replacement
Analyzers. To quality-assure the data from
non-redundant backup Hg monitoring
systems and temporary like-kind replacement
Hg analyzers, the following provisions apply:
2.2.4.1 When a certified non-redundant
backup sorbent trap monitoring system is
brought into service, you must follow the
procedures for routine day-to-day operation
of the system, in accordance with
Performance Specification (PS) 12B in
appendix B to part 60 of this chapter.
2.2.4.2 When a certified non-redundant
backup Hg CEMS or a temporary like-kind
replacement Hg analyzer is brought into
service, a calibration error test and a linearity
check must be performed and passed. A
single point system integrity check is also
required, unless a NIST-traceable source of
oxidized Hg was used for the calibration
error test.
2.2.4.3 Each non-redundant backup Hg
CEMS or temporary like-kind replacement Hg
analyzer shall comply with all required daily,
weekly, and quarterly quality-assurance test
requirements in section 5 of this appendix,
for as long as the system or analyzer remains
in service.
2.2.4.4 For the routine, on-going qualityassurance of a non-redundant backup Hg
monitoring system, a relative accuracy test
audit (RATA) must be performed and passed
at least once every 8 calendar quarters at the
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unit or stack location(s) where the system
will be used.
2.2.4.5 To use a non-redundant backup
Hg monitoring system or a temporary likekind replacement analyzer for more than 720
hours per year at a particular unit or stack
location, a RATA must first be performed and
passed at that location.
srobinson on DSK4SPTVN1PROD with RULES2
3. Mercury Emissions Measurement Methods
The following definitions, equipment
specifications, procedures, and performance
criteria are applicable to the measurement of
vapor-phase Hg emissions from electric
utility steam generating units, under
relatively low-dust conditions (i.e., sampling
in the stack or duct after all pollution control
devices). The analyte measured by these
procedures and specifications is total vaporphase Hg in the flue gas, which represents
the sum of elemental Hg (Hg0, CAS Number
7439–97–6) and oxidized forms of Hg.
3.1 Definitions.
3.1.1 Mercury Continuous Emission
Monitoring System or Hg CEMS means all of
the equipment used to continuously
determine the total vapor phase Hg
concentration. The measurement system may
include the following major subsystems:
sample acquisition, Hg∂2 to Hg0 converter,
sample transport, sample conditioning, flow
control/gas manifold, gas analyzer, and data
acquisition and handling system (DAHS). Hg
CEMS may be nominally real-time or timeintegrated, batch sampling systems that
sample the gas on an intermittent basis and
concentrate on a collection medium before
intermittent analysis and reporting.
3.1.2 Sorbent Trap Monitoring System
means the equipment required to monitor Hg
emissions continuously by using paired
sorbent traps containing iodated charcoal (IC)
or other suitable sorbent medium. The
monitoring system consists of a probe, paired
sorbent traps, an umbilical line, moisture
removal components, an airtight sample
pump, a gas flow meter, and an automated
data acquisition and handling system. The
system samples the stack gas at a constant
proportional rate relative to the stack gas
volumetric flow rate. The sampling is a batch
process. The average Hg concentration in the
stack gas for the sampling period is
determined, in units of micrograms per dry
standard cubic meter (mg/dscm), based on the
sample volume measured by the gas flow
meter and the mass of Hg collected in the
sorbent traps.
3.1.3 NIST means the National Institute
of Standards and Technology, located in
Gaithersburg, Maryland.
3.1.4 NIST–Traceable Elemental Hg
Standards means either: compressed gas
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cylinders having known concentrations of
elemental Hg, which have been prepared
according to the ‘‘EPA Traceability Protocol
for Assay and Certification of Gaseous
Calibration Standards’’; or calibration gases
having known concentrations of elemental
Hg, produced by a generator that meets the
performance requirements of the ‘‘EPA
Traceability Protocol for Qualification and
Certification of Elemental Mercury Gas
Generators’’ or an interim version of that
protocol.
3.1.5 NIST–Traceable Source of Oxidized
Hg means a generator that is capable of
providing known concentrations of vapor
phase mercuric chloride (HgCl2), and that
meets the performance requirements of the
‘‘EPA Traceability Protocol for Qualification
and Certification of Mercuric Chloride Gas
Generators’’ or an interim version of that
protocol.
3.1.6 Calibration Gas means a NISTtraceable gas standard containing a known
concentration of elemental or oxidized Hg
that is produced and certified in accordance
with an EPA traceability protocol.
3.1.7 Span Value means a conservatively
high estimate of the Hg concentrations to be
measured by a CEMS. The span value of a Hg
CEMS should be set to approximately twice
the concentration corresponding to the
emission standard, rounded off as
appropriate (see section 3.2.1.4.2 of this
appendix).
3.1.8 Zero-Level Gas means calibration
gas containing a Hg concentration that is
below the level detectable by the Hg gas
analyzer in use.
3.1.9 Low-Level Gas means calibration gas
with a concentration that is 20 to 30 percent
of the span value.
3.1.10 Mid-Level Gas means calibration
gas with a concentration that is 50 to 60
percent of the span value.
3.1.11 High-Level Gas means calibration
gas with a concentration that is 80 to 100
percent of the span value.
3.1.12 Calibration Error Test means a test
designed to assess the ability of a Hg CEMS
to measure the concentrations of calibration
gases accurately. A zero-level gas and an
upscale gas are required for this test. For the
upscale gas, either a mid-level gas or a highlevel gas may be used, and the gas may either
be an elemental or oxidized Hg standard.
3.1.13 Linearity Check means a test
designed to determine whether the response
of a Hg analyzer is linear across its
measurement range. Three elemental Hg
calibration gas standards (i.e., low, mid, and
high-level gases) are required for this test.
3.1.14 System Integrity Check means a
test designed to assess the transport and
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measurement of oxidized Hg by a Hg CEMS.
Oxidized Hg standards are used for this test.
For a three-level system integrity check, low,
mid, and high-level calibration gases are
required. For a single-level check, either a
mid-level gas or a high-level gas may be used.
3.1.15 Cycle Time Test means a test
designed to measure the amount of time it
takes for a Hg CEMS, while operating
normally, to respond to a known step change
in gas concentration. For this test, a zero gas
and a high-level gas are required. The highlevel gas may be either an elemental or an
oxidized Hg standard.
3.1.16 Relative Accuracy Test Audit or
RATA means a series of nine or more test
runs, directly comparing readings from a Hg
CEMS or sorbent trap monitoring system to
measurements made with a reference stack
test method. The relative accuracy (RA) of
the monitoring system is expressed as the
absolute mean difference between the
monitoring system and reference method
measurements plus the absolute value of the
2.5 percent error confidence coefficient,
divided by the mean value of the reference
method measurements.
3.1.17 Unit Operating Hour means a
clock hour in which a unit combusts any
fuel, either for part of the hour or for the
entire hour.
3.1.18 Stack Operating Hour means a
clock hour in which gases flow through a
particular monitored stack or duct (either for
part of the hour or for the entire hour), while
the associated unit(s) are combusting fuel.
3.1.19 Operating Day means a calendar
day in which a source combusts any fuel.
3.1.20 Quality Assurance (QA) Operating
Quarter means a calendar quarter in which
there are at least 168 unit or stack operating
hours (as defined in this section).
3.1.21 Grace Period means a specified
number of unit or stack operating hours after
the deadline for a required quality-assurance
test of a continuous monitor has passed, in
which the test may be performed and passed
without loss of data.
3.2 Continuous Monitoring Methods.
3.2.1 Hg CEMS. A typical Hg CEMS is
shown in Figure A–1. The CEMS in Figure
A–1 is a dilution extractive system, which
measures Hg concentration on a wet basis,
and is the most commonly-used type of Hg
CEMS. Other system designs may be used,
provided that the CEMS meets the
performance specifications in section 4.1.1 of
this appendix.
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3.2.1.1 Equipment Specifications.
3.2.1.1.1 Materials of Construction. All
wetted sampling system components,
including probe components prior to the
point at which the calibration gas is
introduced, must be chemically inert to all
Hg species. Materials such as perfluoroalkoxy
(PFA) TeflonTM, quartz, and treated stainless
steel (SS) are examples of such materials.
3.2.1.1.2 Temperature Considerations.
All system components prior to the Hg∂2 to
Hg0 converter must be maintained at a
sample temperature above the acid gas dew
point.
3.2.1.1.3 Measurement System
Components.
3.2.1.1.3.1 Sample Probe. The probe must
be made of the appropriate materials as noted
in paragraph 3.2.1.1.1 of this section, heated
when necessary, as described in paragraph
3.2.1.1.3.4 of this section, and configured
with ports for introduction of calibration
gases.
3.2.1.1.3.2 Filter or Other Particulate
Removal Device. The filter or other
particulate removal device is part of the
measurement system, must be made of
appropriate materials, as noted in paragraph
3.2.1.1.1 of this section, and must be
included in all system tests.
3.2.1.1.3.3 Sample Line. The sample line
that connects the probe to the converter,
conditioning system, and analyzer must be
made of appropriate materials, as noted in
paragraph 3.2.1.1.1 of this section.
3.2.1.1.3.4 Conditioning Equipment. For
wet basis systems, such as the one shown in
Figure A–1, the sample must be kept above
its dew point either by: heating the sample
line and all sample transport components up
to the inlet of the analyzer (and, for hot-wet
extractive systems, also heating the analyzer);
or diluting the sample prior to analysis using
a dilution probe system. The components
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required for these operations are considered
to be conditioning equipment. For dry basis
measurements, a condenser, dryer or other
suitable device is required to remove
moisture continuously from the sample gas,
and any equipment needed to heat the probe
or sample line to avoid condensation prior to
the moisture removal component is also
required.
3.2.1.1.3.5 Sampling Pump. A pump is
needed to push or pull the sample gas
through the system at a flow rate sufficient
to minimize the response time of the
measurement system. If a mechanical sample
pump is used and its surfaces are in contact
with the sample gas prior to detection, the
pump must be leak free and must be
constructed of a material that is non-reactive
to the gas being sampled (see paragraph
3.2.1.1.1 of this section). For dilution-type
measurement systems, such as the system
shown in Figure A–1, an ejector pump
(eductor) may be used to create a sufficient
vacuum that sample gas will be drawn
through a critical orifice at a constant rate.
The ejector pump must be constructed of any
material that is non-reactive to the gas being
sampled.
3.2.1.1.3.6 Calibration Gas System(s).
Design and equip each Hg CEMS to permit
the introduction of known concentrations of
elemental Hg and HgCl2 separately, at a point
preceding the sample extraction filtration
system, such that the entire measurement
system can be checked. The calibration gas
system(s) must be designed so that the flow
rate exceeds the sampling system flow
requirements and that the gas is delivered to
the CEMS at atmospheric pressure.
3.2.1.1.3.7 Sample Gas Delivery. The
sample line may feed directly to either a
converter, a by-pass valve (for Hg speciating
systems), or a sample manifold. All valve
and/or manifold components must be made
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of material that is non-reactive to the gas
sampled and the calibration gas, and must be
configured to safely discharge any excess gas.
3.2.1.1.3.8 Hg Analyzer. An instrument is
required that continuously measures the total
vapor phase Hg concentration in the gas
stream. The analyzer may also be capable of
measuring elemental and oxidized Hg
separately.
3.2.1.1.3.9 Data Recorder. A recorder,
such as a computerized data acquisition and
handling system (DAHS), digital recorder, or
data logger, is required for recording
measurement data.
3.2.1.2 Reagents and Standards.
3.2.1.2.1 NIST Traceability. Only NISTcertified or NIST-traceable calibration gas
standards and reagents (as defined in
paragraphs 3.1.4 and 3.1.5 of this section)
shall be used for the tests and procedures
required under this subpart. Calibration gases
with known concentrations of Hg0 and HgCl2
are required. Special reagents and equipment
may be needed to prepare the Hg0 and HgCl2
gas standards (e.g., NIST-traceable solutions
of HgCl2 and gas generators equipped with
mass flow controllers).
3.2.1.2.2 Required Calibration Gas
Concentrations.
3.2.1.2.2.1 Zero-Level Gas. A zero-level
calibration gas with a Hg concentration
below the level detectable by the Hg analyzer
is required for calibration error tests and
cycle time tests of the CEMS.
3.2.1.2.2.2 Low-Level Gas. A low-level
calibration gas with a Hg concentration of 20
to 30 percent of the span value is required
for linearity checks and 3-level system
integrity checks of the CEMS. Elemental Hg
standards are required for the linearity
checks and oxidized Hg standards are
required for the system integrity checks.
3.2.1.2.2.3 Mid-Level Gas. A mid-level
calibration gas with a Hg concentration of 50
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to 60 percent of the span value is required
for linearity checks and for 3-level system
integrity checks of the CEMS, and is optional
for calibration error tests and single-level
system integrity checks. Elemental Hg
standards are required for the linearity
checks, oxidized Hg standards are required
for the system integrity checks, and either
elemental or oxidized Hg standards may be
used for the calibration error tests.
3.2.1.2.2.4 High-Level Gas. A high-level
calibration gas with a Hg concentration of 80
to 100 percent of the span value is required
for linearity checks, 3-level system integrity
checks, and cycle time tests of the CEMS, and
is optional for calibration error tests and
single-level system integrity checks.
Elemental Hg standards are required for the
linearity checks, oxidized Hg standards are
required for the system integrity checks, and
either elemental or oxidized Hg standards
may be used for the calibration error and
cycle time tests.
3.2.1.3 Installation and Measurement
Location. For the Hg CEMS and any
additional monitoring system(s) needed to
convert Hg concentrations to the desired
units of measure (i.e., a flow monitor, CO2 or
O2 monitor, and/or moisture monitor, as
applicable), install each monitoring system at
a location: that is consistent with
63.10010(a); that represents the emissions
exiting to the atmosphere; and where it is
likely that the CEMS can pass the relative
accuracy test.
3.2.1.4 Monitor Span and Range
Requirements. Determine the appropriate
span and range value(s) for the Hg CEMS as
described in paragraphs 3.2.1.4.1 through
3.2.1.4.3 of this section.
3.2.1.4.1 Maximum Potential
Concentration. There are three options for
determining the maximum potential Hg
concentration (MPC). Option 1 applies to
coal combustion. You may use a default
value of 10 mg/scm for all coal ranks
(including coal refuse) except for lignite; for
lignite, use 16 mg/scm. If different coals are
blended as part of normal operation, use the
highest MPC for any fuel in the blend. Option
2 is to base the MPC on the results of sitespecific Hg emission testing. This option may
be used only if the unit does not have addon Hg emission controls or a flue gas
desulfurization system, or if testing is
performed upstream of all emission control
devices. If Option 2 is selected, perform at
least three test runs at the normal operating
load, and the highest Hg concentration
obtained in any of the tests shall be the MPC.
Option 3 is to use fuel sampling and analysis
to estimate the MPC. To make this estimate,
use the average Hg content (i.e., the weight
percentage) from at least three representative
fuel samples, together with other available
information, including, but not limited to the
maximum fuel feed rate, the heating value of
the fuel, and an appropriate F-factor. Assume
that all of the Hg in the fuel is emitted to the
atmosphere as vapor-phase Hg.
3.2.1.4.2 Span Value. To determine the
span value of the Hg CEMS, multiply the Hg
concentration corresponding to the
applicable emissions standard by two. If the
result of this calculation is an exact multiple
of 10 mg/scm, use the result as the span value.
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Otherwise, round off the result to either: the
next highest integer; the next highest
multiple of 5 mg/scm; or the next highest
multiple of 10 mg/scm.
3.2.1.4.3 Analyzer Range. The Hg
analyzer must be capable of reading Hg
concentration as high as the MPC.
3.2.2 Sorbent Trap Monitoring System. A
sorbent trap monitoring system (as defined in
paragraph 3.1.2 of this section) may be used
as an alternative to a Hg CEMS. If this option
is selected, the monitoring system shall be
installed, maintained, and operated in
accordance with Performance Specification
(PS) 12B in Appendix B to part 60 of this
chapter. The system shall be certified in
accordance with the provisions of section
4.1.2 of this appendix.
3.2.3 Other Necessary Data Collection. To
convert measured hourly Hg concentrations
to the units of the applicable emissions
standard (i.e., lb/TBtu or lb/GWh), additional
data must be collected, as described in
paragraphs 3.2.3.1 through 3.2.3.3 of this
section. Any additional monitoring systems
needed for this purpose must be certified,
operated, maintained, and quality-assured
according to the applicable provisions of part
75 of this chapter (see §§ 63.10010(b) through
(d)). The calculation methods for the types of
emission limits described in paragraphs
3.2.3.1 and 3.2.3.2 of this section are
presented in section 6.2 of this appendix.
3.2.3.1 Heat Input-Based Emission Limits.
For a heat input-based Hg emission limit (i.e.,
in lb/TBtu), data from a certified CO2 or O2
monitor are needed, along with a fuelspecific F-factor and a conversion constant to
convert measured Hg concentration values to
the units of the standard. In some cases, the
stack gas moisture content must also be
considered in making these conversions.
3.2.3.2 Electrical Output-Based Emission
Rates. If the applicable Hg limit is electrical
output-based (i.e., lb/GWh), hourly electrical
load data and unit operating times are
required in addition to hourly data from a
certified stack gas flow rate monitor and (if
applicable) moisture data.
3.2.3.3 Sorbent Trap Monitoring System
Operation. Routine operation of a sorbent
trap monitoring system requires the use of a
certified stack gas flow rate monitor, to
maintain an established ratio of stack gas
flow rate to sample flow rate.
4. Certification and Recertification
Requirements
4.1 Certification Requirements. All Hg
CEMS and sorbent trap monitoring systems
and the additional monitoring systems used
to continuously measure Hg emissions in
units of the applicable emissions standard in
accordance with this appendix must be
certified in a timely manner, such that the
initial compliance demonstration is
completed no later than the applicable date
in § 63.10005(g).
4.1.1 Hg CEMS. Table A–1, below,
summarizes the certification test
requirements and performance specifications
for a Hg CEMS. The CEMS may not be used
to report quality-assured data until these
performance criteria are met. Paragraphs
4.1.1.1 through 4.1.1.5 of this section provide
specific instructions for the required tests.
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All tests must be performed with the affected
unit(s) operating (i.e., combusting fuel).
Except for the RATA, which must be
performed at normal load, no particular load
level is required for the certification tests.
4.1.1.1 7-Day Calibration Error Test.
Perform the 7-day calibration error test on 7
consecutive source operating days, using a
zero-level gas and either a high-level or a
mid-level calibration gas standard (as defined
in sections 3.1.8, 3.1.10, and 3.1.11 of this
appendix). Either elemental or oxidized
NIST-traceable Hg standards (as defined in
sections 3.1.4 and 3.1.5 of this appendix)
may be used for the test. If moisture and/or
chlorine is added to the calibration gas, the
dilution effect of the moisture and/or
chlorine addition on the calibration gas
concentration must be accounted for in an
appropriate manner. Operate the Hg CEMS in
its normal sampling mode during the test.
The calibrations should be approximately 24
hours apart, unless the 7-day test is
performed over nonconsecutive calendar
days. On each day of the test, inject the zerolevel and upscale gases in sequence and
record the analyzer responses. Pass the
calibration gas through all filters, scrubbers,
conditioners, and other monitor components
used during normal sampling, and through as
much of the sampling probe as is practical.
Do not make any manual adjustments to the
monitor (i.e., resetting the calibration) until
after taking measurements at both the zero
and upscale concentration levels. If
automatic adjustments are made following
both injections, conduct the calibration error
test such that the magnitude of the
adjustments can be determined, and use only
the unadjusted analyzer responses in the
calculations. Calculate the calibration error
(CE) on each day of the test, as described in
Table A–1. The CE on each day of the test
must either meet the main performance
specification or the alternative specification
in Table A–1.
4.1.1.2 Linearity Check. Perform the
linearity check using low, mid, and highlevel concentrations of NIST-traceable
elemental Hg standards. Three gas injections
at each concentration level are required, with
no two successive injections at the same
concentration level. Introduce the calibration
gas at the gas injection port, as specified in
section 3.2.1.1.3.6 of this appendix. Operate
the CEMS at its normal operating
temperature and conditions. Pass the
calibration gas through all filters, scrubbers,
conditioners, and other components used
during normal sampling, and through as
much of the sampling probe as is practical.
If moisture and/or chlorine is added to the
calibration gas, the dilution effect of the
moisture and/or chlorine addition on the
calibration gas concentration must be
accounted for in an appropriate manner.
Record the monitor response from the data
acquisition and handling system for each gas
injection. At each concentration level, use
the average analyzer response to calculate the
linearity error (LE), as described in Table A–
1. The LE must either meet the main
performance specification or the alternative
specification in Table A–1.
4.1.1.3 Three-Level System Integrity
Check. Perform the 3-level system integrity
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check using low, mid, and high-level
calibration gas concentrations generated by a
NIST-traceable source of oxidized Hg. Follow
the same basic procedure as for the linearity
check. If moisture and/or chlorine is added
to the calibration gas, the dilution effect of
the moisture and/or chlorine addition on the
calibration gas concentration must be
accounted for in an appropriate manner.
Calculate the system integrity error (SIE), as
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described in Table A–1. The SIE must either
meet the main performance specification or
the alternative specification in Table A–1.
(Note: This test is not required if the CEMS
does not have a converter).
TABLE A–1—REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR Hg CEMS
For this required certification test
. . .
The main performance specification 1 is . . .
The alternate performance specification 1 is . . .
And the conditions of the alternate specification are . . .
7-day calibration error test 2 ...........
⎢R ¥ A ⎢ ≤5.0% of span value, for
both the zero and upscale
gases, on each of the 7 days.
⎢R ¥ Aavg ⎢ ≤10.0% of the reference gas concentration at
each calibration gas level (low,
mid, or high).
⎢R ¥ Aavg ⎢ ≤10.0% of the reference gas concentration at
each calibration gas level.
20.0% RA .....................................
15 minutes.5
⎢R ¥ A ⎢ ≤1.0 μg/scm ..................
The alternate specification may
be used on any day of the test.
⎢R ¥ Aavg ⎢ ≤0.8 μg/scm ..............
The alternate specification may
be used at any gas level.
⎢R ¥ Aavg ⎢ ≤0.8 μg/scm ..............
The alternate specification may
be used at any gas level.
⎢RMavg ¥ Cavg ⎢ ≤1.0 μg/scm** ....
RMavg <5.0 μg/scm.
Linearity check 3 .............................
3-level system integrity check 4 .....
RATA .............................................
Cycle time test 2 .............................
4.1.1.4 Cycle Time Test. Perform the
cycle time test, using a zero-level gas and a
high-level calibration gas.
Either an elemental or oxidized NISTtraceable Hg standard may be used as the
high-level gas. Perform the test in two
stages—upscale and downscale. The slower
of the upscale and downscale response times
is the cycle time for the CEMS. Begin each
stage of the test by injecting calibration gas
after achieving a stable reading of the stack
emissions. The cycle time is the amount of
time it takes for the analyzer to register a
reading that is 95 percent of the way between
the stable stack emissions reading and the
final, stable reading of the calibration gas
concentration. Use the following criterion to
determine when a stable reading of stack
emissions or calibration gas has been
attained—the reading is stable if it changes
by no more than 2.0 percent of the span value
or 0.5 mg/scm (whichever is less restrictive)
for two minutes, or a reading with a change
of less than 6.0 percent from the measured
average concentration over 6 minutes.
Integrated batch sampling type Hg CEMS are
exempted from this test; however, these
systems must be capable of delivering a
measured Hg concentration reading at least
once every 15 minutes. If necessary to
increase measurement sensitivity of a batch
sampling type Hg CEMS for a specific
application, you may petition the
Administrator for approval of a time longer
than 15 minutes between readings.
4.1.1.5 Relative Accuracy Test Audit
(RATA). Perform the RATA of the Hg CEMS
at normal load. Acceptable Hg reference
methods for the RATA include ASTM
D6784–02 (Reapproved 2008), ‘‘Standard
Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue
Gas Generated from Coal-Fired Stationary
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Sources (Ontario Hydro Method)’’
(incorporated by reference, see § 63.14) and
Methods 29, 30A, and 30B in appendix A–
8 to part 60. When Method 29 or ASTM
D6784–02 is used, paired sampling trains are
required. To validate a Method 29 or ASTM
D6784–02 test run, calculate the relative
deviation (RD) using Equation A–1 of this
section, and assess the results as follows to
validate the run. The RD must not exceed 10
percent, when the average Hg concentration
is greater than 1.0 mg/dscm. If the average
concentration is ≤ 1.0 mg/dscm, the RD must
not exceed 20 percent. The RD results are
also acceptable if the absolute difference
between the two Hg concentrations does not
exceed 0.2 mg/dscm. If the RD specification
is met, the results of the two samples shall
be averaged arithmetically.
Where:
RD = Relative deviation between the Hg
concentrations of samples ‘‘a’’ and ‘‘b’’
(percent)
Ca = Hg concentration of Hg sample ‘‘a’’ (mg/
dscm)
Cb = Hg concentration of Hg sample ‘‘b’’ (mg/
dscm)
4.1.1.5.1 Special Considerations. A
minimum of nine valid test runs must be
performed, directly comparing the CEMS
measurements to the reference method. More
than nine test runs may be performed. If this
option is chosen, the results from a
maximum of three test runs may be rejected
so long as the total number of test results
used to determine the relative accuracy is
greater than or equal to nine; however, all
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data must be reported including the rejected
data. The minimum time per run is 21
minutes if Method 30A is used. If Method 29,
Method 30B, or ASTM D6784–02
(Reapproved 2008), ‘‘Standard Test Method
for Elemental, Oxidized, Particle-Bound and
Total Mercury in Flue Gas Generated from
Coal-Fired Stationary Sources (Ontario Hydro
Method)’’ (incorporated by reference, see
§ 63.14) is used, the time per run must be
long enough to collect a sufficient mass of Hg
to analyze. Complete the RATA within 168
unit operating hours, except when Method 29
or ASTM D6784–02 is used, in which case
up to 336 operating hours may be taken to
finish the test.
4.1.1.5.2 Calculation of RATA Results.
Calculate the relative accuracy (RA) of the
monitoring system, on a mg/scm basis, as
described in section 12 of Performance
Specification (PS) 2 in Appendix B to part 60
of this chapter (see Equations 2–3 through 2–
6 of PS2). For purposes of calculating the
relative accuracy, ensure that the reference
method and monitoring system data are on a
consistent moisture basis, either wet or dry.
The CEMS must either meet the main
performance specification or the alternative
specification in Table A–1.
4.1.1.5.3 Bias Adjustment. Measurement
or adjustment of Hg CEMS data for bias is not
required.
4.1.2 Sorbent Trap Monitoring Systems.
For the initial certification of a sorbent trap
monitoring system, only a RATA is required.
4.1.2.1 Reference Methods. The
acceptable reference methods for the RATA
of a sorbent trap monitoring system are the
same as those listed in paragraph 4.1.1.5 of
this section.
4.1.2.2 ‘‘The special considerations
specified in paragraph 4.1.1.5.1 of this
section apply to the RATA of a sorbent trap
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1 Note that ⎢R ¥ A ⎢ is the absolute value of the difference between the reference gas value and the analyzer reading. ⎢R ¥ A
avg, ⎢ is the absolute value of the difference between the reference gas concentration and the average of the analyzer responses, at a particular gas level.
2 Use either elemental or oxidized Hg standards; a mid-level or high-level upscale gas may be used. This test is not required for Hg CEMS that
use integrated batch sampling; however, those monitors must be capable of recording at least one Hg concentration reading every 15 minutes.
3 Use elemental Hg standards.
4 Use oxidized Hg standards. Not required if the CEMS does not have a converter.
5 Stability criteria—Readings change by <2.0% of span or by ≤0.5 μg/scm, for 2 minutes.
** Note that ⎢RMavg¥Cavg ⎢ is the absolute difference between the mean reference method value and the mean CEMS value from the RATA.
The arithmetic difference between RMavg and Cavg can be either + or ¥.
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monitoring system. During the RATA, the
monitoring system must be operated and
quality-assured in accordance with
Performance Specification (PS) 12B in
Appendix B to part 60 of this chapter with
the following exceptions for sorbent trap
section 2 breakthrough:
4.1.2.2.1 For stack Hg concentrations >1
mg/dscm, ≤10% of section 1 Hg mass;
4.1.2.2.2 For stack Hg concentrations ≤1
mg/dscm and >0.5 mg/dscm, ≤ 20% of section
1 Hg mass;
4.1.2.2.3 For stack Hg concentrations ≤0.5
mg/dscm and >0.1 mg/dscm, ≤ 50% of section
1 Hg mass; and
4.1.2.2.4 For stack Hg concentrations
≤0.1mg/dscm, no breakthrough criterion
assuming all other QA/QC specifications are
met.
4.1.2.3 The type of sorbent material used
by the traps during the RATA must be the
same as for daily operation of the monitoring
system; however, the size of the traps used
for the RATA may be smaller than the traps
used for daily operation of the system.
4.1.2.4 Calculation of RATA Results.
Calculate the relative accuracy (RA) of the
sorbent trap monitoring system, on a mg/scm
basis, as described in section 12 of
Performance Specification (PS) 2 in appendix
B to part 60 of this chapter (see Equations 2–
3 through 2–6 of PS2). For purposes of
calculating the relative accuracy, ensure that
the reference method and monitoring system
data are on a consistent moisture basis, either
wet or dry.The main and alternative RATA
performance specifications in Table A–1 for
Hg CEMS also apply to the sorbent trap
monitoring system.
4.1.2.5 Bias Adjustment. Measurement or
adjustment of sorbent trap monitoring system
data for bias is not required.
4.1.3 Diluent Gas, Flow Rate, and/or
Moisture Monitoring Systems. Monitoring
systems that are used to measure stack gas
volumetric flow rate, diluent gas
concentration, or stack gas moisture content,
either for routine operation of a sorbent trap
monitoring system or to convert Hg
concentration data to units of the applicable
emission limit, must be certified in
accordance with the applicable provisions of
part 75 of this chapter.
4.2 Recertification. Whenever the owner
or operator makes a replacement,
modification, or change to a certified CEMS
or sorbent trap monitoring system that may
significantly affect the ability of the system
to accurately measure or record pollutant or
diluent gas concentrations, stack gas flow
rates, or stack gas moisture content, the
owner or operator shall recertify the
monitoring system. Furthermore, whenever
the owner or operator makes a replacement,
modification, or change to the flue gas
handling system or the unit operation that
may significantly change the concentration or
flow profile, the owner or operator shall
recertify the monitoring system. The same
tests performed for the initial certification of
the monitoring system shall be repeated for
recertification, unless otherwise specified by
the Administrator. Examples of changes that
require recertification include: replacement
of a gas analyzer; complete monitoring
system replacement, and changing the
location or orientation of the sampling probe.
5. Ongoing Quality Assurance (QA) and Data
Validation
5.1 Hg CEMS.
5.1.1 Required QA Tests. Periodic QA
testing of each Hg CEMS is required
following initial certification. The required
QA tests, the test frequencies, and the
performance specifications that must be met
are summarized in Table A–2, below. All
tests must be performed with the affected
unit(s) operating (i.e., combusting fuel).
Except for the RATA, which must be
performed at normal load, no particular load
level is required for the tests. For each test,
follow the same basic procedures in section
4.1.1 of this appendix that were used for
initial certification.
5.1.2 Test Frequency. The frequency for
the required QA tests of the Hg CEMS shall
be as follows:
5.1.2.1 Calibration error tests of the Hg
CEMS are required daily, except during unit
outages. Use either NIST-traceable elemental
Hg standards or NIST-traceable oxidized Hg
standards for these calibrations. Both a zerolevel gas and either a mid-level or high-level
gas are required for these calibrations.
5.1.2.2 Perform a linearity check of the
Hg CEMS in each QA operating quarter,
using low-level, mid-level, and high-level
NIST-traceable elemental Hg standards. For
units that operate infrequently, limited
exemptions from this test are allowed for
‘‘non-QA operating quarters’’. A maximum of
three consecutive exemptions for this reason
are permitted, following the quarter of the
last test. After the third consecutive
exemption, a linearity check must be
performed in the next calendar quarter or
within a grace period of 168 unit or stack
operating hours after the end of that quarter.
The test frequency for 3-level system
integrity checks (if performed in lieu of
linearity checks) is the same as for the
linearity checks. Use low-level, mid-level,
and high-level NIST-traceable oxidized Hg
standards for the system integrity checks.
5.1.2.3 If required, perform a single-level
system integrity check weekly, i.e., once
every 7 operating days (see the third column
in Table A–2).
5.1.2.4 The test frequency for the RATAs
of the Hg CEMS shall be annual, i.e., once
every four QA operating quarters. For units
that operate infrequently, extensions of
RATA deadlines are allowed for non-QA
operating quarters. Following a RATA, if
there is a subsequent non-QA quarter, it
extends the deadline for the next test by one
calendar quarter. However, there is a limit to
these extensions; the deadline may not be
extended beyond the end of the eighth
calendar quarter after the quarter of the last
test. At that point, a RATA must either be
performed within the eighth calendar quarter
or in a 720 hour unit or stack operating hour
grace period following that quarter. When a
required annual RATA is done within a grace
period, the deadline for the next RATA is
three QA operating quarters after the quarter
in which the grace period test is performed.
5.1.3 Grace Periods.
5.1.3.1 A 168 unit or stack operating hour
grace period is available for quarterly
linearity checks and 3-level system integrity
checks of the Hg CEMS.
5.1.3.2 A 720 unit or stack operating hour
grace period is available for RATAs of the Hg
CEMS.
5.1.3.3 There is no grace period for
weekly system integrity checks. The test
must be completed once every 7 operating
days.
5.1.4 Data Validation. The Hg CEMS is
considered to be out-of-control, and data
from the CEMS may not be reported as
quality-assured, when any one of the
acceptance criteria for the required QA tests
in Table A–2 is not met. The CEMS is also
considered to be out-of-control when a
required QA test is not performed on
schedule or within an allotted grace period.
To end an out-of-control period, the QA test
that was either failed or not done on time
must be performed and passed. Out-ofcontrol periods are counted as hours of
monitoring system downtime.
5.1.5 Conditional Data Validation. For
certification, recertification, and diagnostic
testing of Hg monitoring systems, and for the
required QA tests when non-redundant
backup Hg monitoring systems or temporary
like-kind Hg analyzers are brought into
service, the conditional data validation
provisions in §§ 75.20(b)(3)(ii) through
(b)(3)(ix) of this chapter may be used to avoid
or minimize data loss. The allotted window
of time to complete 7-day calibration error
tests, linearity checks, cycle time tests, and
RATAs shall be as specified in
§ 75.20(b)(3)(iv) of this chapter. Required
system integrity checks must be completed
within 168 unit or stack operating hours after
the probationary calibration error test.
srobinson on DSK4SPTVN1PROD with RULES2
TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS
Perform this type of QA test . . .
At this frequency . . .
With these qualifications and exceptions . . .
Acceptance criteria . . .
Calibration error test ......................
Daily ..............................................
• Use either a mid- or high-level
gas.
⎢R¥A ⎢ ≤ 5.0% of span value.
or
⎢R¥A ⎢ ≤ 1.0 μg/scm.
• Use
either
oxidized Hg.
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TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS—Continued
Perform this type of QA test . . .
Single-level system integrity check
With these qualifications and exceptions . . .
At this frequency . . .
Weekly 1 ........................................
Quarterly 3 .....................................
Linearity check
or
3-level system integrity check
RATA .............................................
Annual 4 ........................................
• Calibrations are not required
when the unit is not in operation.
• Required only for systems with
converters.
• Use oxidized Hg—either mid- or
high-level.
• Not required if daily calibrations
are done with a NIST-traceable
source of oxidized Hg.
• Required in each ‘‘QA operating
quarter’’ 2—and no less than
once every 4 calendar quarters.
• 168 operating hour grace period available.
• Use elemental Hg for linearity
check.
• Use oxidized Hg for system integrity check.
• For system integrity check,
CEMS must have a converter.
• Test deadline may be extended
for ‘‘non-QA operating quarters’’, up to a maximum of 8
quarters from the quarter of the
previous test.
• 720 operating hour grace period available.
Acceptance criteria . . .
⎢R¥Aavg ⎢ ≤ 10.0% of the reference gas value.
or
⎢R¥Aavg ⎢ ≤ 0.8 μg/scm.
⎢R¥Aavg ⎢ ≤ 10.0% of the reference gas value, at each calibration gas level.
or
⎢R¥Aavg ⎢ ≤ 0.8 μg/scm.
20.0% RA.
or
⎢RMavg¥Cavg ⎢ ≤ 1.0 μg/scm,
if
RMavg < 5.0 μg/scm.
1 ‘‘Weekly’’
means once every 7 operating days.
‘‘QA operating quarter’’ is a calendar quarter with at least 168 unit or stack operating hours.
means once every QA operating quarter.
4 ‘‘Annual’’ means once every four QA operating quarters.
2A
srobinson on DSK4SPTVN1PROD with RULES2
3 ‘‘Quarterly’’
5.1.6 Adjustment of Span. If you discover
that a span adjustment is needed (e.g., if the
Hg concentration readings exceed the span
value for a significant percentage of the unit
operating hours in a calendar quarter), you
must implement the span adjustment within
90 days after the end of the calendar quarter
in which you identify the need for the
adjustment. A diagnostic linearity check is
required within 168 unit or stack operating
hours after changing the span value.
5.2 Sorbent Trap Monitoring Systems.
5.2.1 Each sorbent trap monitoring
system shall be continuously operated and
maintained in accordance with Performance
Specification (PS) 12B in appendix B to part
60 of this chapter. The QA/QC criteria for
routine operation of the system are
summarized in Table 12B–1 of PS 12B. Each
pair of sorbent traps may be used to sample
the stack gas for up to 14 operating days.
5.2.2 For ongoing QA, periodic RATAs of
the system are required.
5.2.2.1 The RATA frequency shall be
annual, i.e., once every four QA operating
quarters. The provisions in section 5.1.2.4 of
this appendix pertaining to RATA deadline
extensions also apply to sorbent trap
monitoring systems.
5.2.2.2 The same RATA performance
criteria specified in Table A–4 for Hg CEMS
shall apply to the annual RATAs of the
sorbent trap monitoring system.
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5.2.2.3 A 720 unit or stack operating hour
grace period is available for RATAs of the
monitoring system.
5.2.3 Data validation for sorbent trap
monitoring systems shall be done in
accordance with Table 12B–1 in Performance
Specification (PS) 12B in appendix B to part
60 of this chapter. All periods of invalid data
shall be counted as hours of monitoring
system downtime.
5.3 Flow Rate, Diluent Gas, and Moisture
Monitoring Systems. The on-going QA test
requirements for these monitoring systems
are specified in part 75 of this chapter (see
§§ 63.10010(b) through (d)).
5.4 QA/QC Program Requirements. The
owner or operator shall develop and
implement a quality assurance/quality
control (QA/QC) program for the Hg CEMS
and/or sorbent trap monitoring systems that
are used to provide data under this subpart.
At a minimum, the program shall include a
written plan that describes in detail (or that
refers to separate documents containing)
complete, step-by-step procedures and
operations for the most important QA/QC
activities. Electronic storage of the QA/QC
plan is permissible, provided that the
information can be made available in hard
copy to auditors and inspectors. The QA/QC
program requirements for the diluent gas,
flow rate, and moisture monitoring systems
described in section 3.2.1.3 of this appendix
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are specified in section 1 of appendix B to
part 75 of this chapter.
5.4.1 General Requirements.
5.4.1.1 Preventive Maintenance. Keep a
written record of procedures needed to
maintain the Hg CEMS and/or sorbent trap
monitoring system(s) in proper operating
condition and a schedule for those
procedures. Include, at a minimum, all
procedures specified by the manufacturers of
the equipment and, if applicable, additional
or alternate procedures developed for the
equipment.
5.4.1.2 Recordkeeping and Reporting.
Keep a written record describing procedures
that will be used to implement the
recordkeeping and reporting requirements of
this appendix.
5.4.1.3 Maintenance Records. Keep a
record of all testing, maintenance, or repair
activities performed on any Hg CEMS or
sorbent trap monitoring system in a location
and format suitable for inspection. A
maintenance log may be used for this
purpose. The following records should be
maintained: date, time, and description of
any testing, adjustment, repair, replacement,
or preventive maintenance action performed
on any monitoring system and records of any
corrective actions associated with a monitor
outage period. Additionally, any adjustment
that may significantly affect a system’s ability
to accurately measure emissions data must be
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K = Units conversion constant, 6.24 × 10¥11
lb-scm/mg-scf,
Ch = Hourly average Hg concentration, wet
basis (mg/scm)
Qh = Stack gas volumetric flow rate for the
hour (scfh).
(Note: Use unadjusted flow rate values;
bias adjustment is not required)
Where:
Mh = Hg mass emission rate for the hour (lb/
h)
K = Units conversion constant, 6.24 x 10¥11
lb-scm/mg-scf.
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6. Data Reduction and Calculations
6.1 Data Reduction.
6.1.1 Reduce the data from Hg CEMS to
hourly averages, in accordance with
§ 60.13(h)(2) of this chapter.
6.1.2 For sorbent trap monitoring
systems, determine the Hg concentration for
each data collection period and assign this
concentration value to each operating hour in
the data collection period.
6.1.3 For any operating hour in which
valid data are not obtained, either for Hg
concentration or for a parameter used in the
emissions calculations (i.e., flow rate, diluent
gas concentration, or moisture, as
applicable), do not calculate the Hg emission
rate for that hour. For the purposes of this
appendix, part 75 substitute data values are
not considered to be valid data.
6.1.4 Operating hours in which valid data
are not obtained for Hg concentration are
considered to be hours of monitor downtime.
The use of substitute data for Hg
concentration is not required.
6.2 Calculation of Hg Emission Rates. Use
the applicable calculation methods in
paragraphs 6.2.1 and 6.2.2 of this section to
convert Hg concentration values to the
appropriate units of the emission standard.
6.2.1 Heat Input-Based Hg Emission
Rates. Calculate hourly heat input-based Hg
emission rates, in units of lb/TBtu, according
to sections 6.2.1.1 through 6.2.1.4 of this
appendix.
6.2.1.1 Select an appropriate emission
rate equation from among Equations 19–1
through 19–9 in EPA Method 19 in appendix
A–7 to part 60 of this chapter.
6.2.1.2 Calculate the Hg emission rate in
lb/MMBtu, using the equation selected from
Method 19. Multiply the Hg concentration
value by 6.24 × 10¥11 to convert it from mg/
scm to lb/scf. In cases where an appropriate
F-factor is not listed in Table 19–2 of Method
19, you may use F-factors from Table 1 in
section 3.3.5 of appendix F to part 75 of this
chapter, or F-factors derived using the
procedures in section 3.3.6 of appendix to
part 75 of this chapter. Also, for startup and
shutdown hours, you may calculate the Hg
emission rate using the applicable diluent
cap value specified in section 3.3.4.1 of
appendix F to part 75 of this chapter,
provided that the diluent gas monitor is not
out-of-control and the hourly average O2
concentration is above 14.0% O2 (19.0% for
an IGCC) or the hourly average CO2
concentration is below 5.0% CO2 (1.0% for
an IGCC), as applicable.
6.2.1.3 Multiply the lb/MMBtu value
obtained in section 6.2.1.2 of this appendix
by 106 to convert it to lb/TBtu.
6.2.1.4 The heat input-based Hg emission
rate limit in Table 2 to this subpart must be
met on a 30 boiler operating day rolling
average basis. Use Equation 19–19 in EPA
Method 19 to calculate the Hg emission rate
for each averaging period. The term Ehj in
Equation 19–19 must be in the units of the
applicable emission limit. Do not include
non-operating hours with zero emissions in
the average.
6.2.2 Electrical Output-Based Hg
Emission Rates. Calculate electrical outputbased Hg emission limits in units of lb/GWh,
according to sections 6.2.2.1 through 6.2.2.3
of this appendix.
6.2.2.1 Calculate the Hg mass emissions
for each operating hour in which valid data
are obtained for all parameters, using
Equation A–2 of this section (for wet-basis
measurements of Hg concentration) or
Equation A–3 of this section (for dry-basis
measurements), as applicable:
ER16FE12.014</GPH>
a reference flow meter, the QA plan must
include a protocol for ongoing maintenance
and periodic recalibration to maintain the
accuracy and NIST-traceability of the
calibrator.
5.4.3.3 Hg Analysis. Explain the chain of
custody employed in packing, transporting,
and analyzing the sorbent traps. Keep records
of all Hg analyses. The analyses shall be
performed in accordance with the procedures
described in section 11.0 of Performance
Specification (PS) 12B in Appendix B to part
60 of this chapter.
5.4.3.4 Data Collection Period. State, and
provide the rationale for, the minimum
acceptable data collection period (e.g., one
day, one week, etc.) for the size of sorbent
trap selected for the monitoring. Address
such factors as the Hg concentration in the
stack gas, the capacity of the sorbent trap,
and the minimum mass of Hg required for the
analysis. Each pair of sorbent traps may be
used to sample the stack gas for up to 14
operating days.
5.4.3.5 Relative Accuracy Test Audit
Procedures. Keep records of the procedures
and details peculiar to the sorbent trap
monitoring systems that are to be followed
for relative accuracy test audits, such as
sampling and analysis methods.
Where:
Mh = Hg mass emission rate for the hour (lb/
h)
srobinson on DSK4SPTVN1PROD with RULES2
recorded (e.g., changing the dilution ratio of
a CEMS), and a written explanation of the
procedures used to make the adjustment(s)
shall be kept.
5.4.2 Specific Requirements for Hg CEMS.
5.4.2.1 Daily Calibrations, Linearity
Checks and System Integrity Checks. Keep a
written record of the procedures used for
daily calibrations of the Hg CEMS. If
moisture and/or chlorine is added to the Hg
calibration gas, document how the dilution
effect of the moisture and/or chlorine
addition on the calibration gas concentration
is accounted for in an appropriate manner.
Also keep records of the procedures used to
perform linearity checks of the Hg CEMS and
the procedures for system integrity checks of
the Hg CEMS. Document how the test results
are calculated and evaluated.
5.4.2.2 Monitoring System Adjustments.
Document how each component of the Hg
CEMS will be adjusted to provide correct
responses to calibration gases after routine
maintenance, repairs, or corrective actions.
5.4.2.3 Relative Accuracy Test Audits.
Keep a written record of procedures used for
RATAs of the Hg CEMS. Indicate the
reference methods used and document how
the test results are calculated and evaluated.
5.4.3 Specific Requirements for Sorbent
Trap Monitoring Systems.
5.4.3.1 Sorbent Trap Identification and
Tracking. Include procedures for inscribing
or otherwise permanently marking a unique
identification number on each sorbent trap,
for chain of custody purposes. Keep records
of the ID of the monitoring system in which
each sorbent trap is used, and the dates and
hours of each Hg collection period.
5.4.3.2 Monitoring System Integrity and
Data Quality. Document the procedures used
to perform the leak checks when a sorbent
trap is placed in service and removed from
service. Also Document the other QA
procedures used to ensure system integrity
and data quality, including, but not limited
to, gas flow meter calibrations, verification of
moisture removal, and ensuring air-tight
pump operation. In addition, the QA plan
must include the data acceptance and quality
control criteria in Table 12B–1 in section 9.0
of Performance Specification (PS) 12B in
Appendix B to part 60 of this chapter. All
reference meters used to calibrate the gas
flow meters (e.g., wet test meters) shall be
periodically recalibrated. Annual, or more
frequent, recalibration is recommended. If a
NIST-traceable calibration device is used as
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9507
(MW)h = Gross electrical load for the hour,
in megawatts (MW).
10 3 = Conversion factor from megawatts to
gigawatts.
6.2.2.3 The applicable electrical outputbased Hg emission rate limit in Table 1 or 2
to this subpart must be met on a 30-boiler
operating day rolling average basis. Use
Equation A–5 of this section to calculate the
Hg emission rate for each averaging period.
Where:
¯
Eo = Hg emission rate for the averaging
period (lb/GWh).
Eho = Electrical output-based hourly Hg
emission rate for unit or stack operating
hour ‘‘h’’ in the averaging period, from
Equation A–4 of this section (lb/GWh).
n = Number of unit or stack operating hours
in the averaging period in which valid
data were obtained for all parameters
(Note: Do not include non-operating
hours with zero emission rates in the
average).
handling system or the flue gas handling
system) which affects information reported in
the monitoring plan (e.g., a change to a serial
number for a component of a monitoring
system), the owner or operator shall update
the monitoring plan.
7.1.1.2 Contents of the Monitoring Plan.
For Hg CEMS and sorbent trap monitoring
systems, the monitoring plan shall contain
the information in sections 7.1.1.2.1 and
7.1.1.2.2 of this appendix, as applicable. For
stack gas flow rate, diluent gas, and moisture
monitoring systems, the monitoring plan
shall include the information required for
those systems under § 75.53 (g) of this
chapter.
7.1.1.2.1 Electronic. The electronic
monitoring plan records must include the
following: unit or stack ID number(s);
monitoring location(s); the Hg monitoring
methodologies used; Hg monitoring system
information, including, but not limited to:
Unique system and component ID numbers;
the make, model, and serial number of the
monitoring equipment; the sample
acquisition method; formulas used to
calculate Hg emissions; Hg monitor span and
range information The electronic monitoring
plan shall be evaluated and submitted using
the Emissions Collection and Monitoring
Plan System (ECMPS) Client Tool provided
by the Clean Air Markets Division in the
Office of Atmospheric Programs of the EPA.
7.1.1.2.2 Hard Copy. Keep records of the
following: schematics and/or blueprints
showing the location of the Hg monitoring
system(s) and test ports; data flow diagrams;
test protocols; monitor span and range
calculations; miscellaneous technical
justifications.
7.1.2 Operating Parameter Records. The
owner or operator shall record the following
information for each operating hour of each
affected unit and also for each group of units
utilizing a common stack, to the extent that
these data are needed to convert Hg
concentration data to the units of the
emission standard. For non-operating hours,
record only the items in paragraphs 7.1.2.1
and 7.1.2.2 of this section. If there is heat
input to the unit(s), but no electrical load,
record only the items in paragraphs 7.1.2.1,
7.1.2.2, and (if applicable) 7.1.2.4 of this
section.
7.1.2.1 The date and hour;
7.1.2.2 The unit or stack operating time
(rounded up to the nearest fraction of an hour
(in equal increments that can range from one
hundredth to one quarter of an hour, at the
option of the owner or operator);
7.1.2.3 The hourly gross unit load
(rounded to nearest MWe); and
7.1.2.4 If applicable, the F-factor used to
calculate the heat input-based Hg emission
rate.
7.1.3 Hg Emissions Records (Hg CEMS).
For each affected unit or common stack using
a Hg CEMS, the owner or operator shall
record the following information for each
unit or stack operating hour:
7.1.3.1 The date and hour;
7.1.3.2 Monitoring system and
component identification codes, as provided
in the monitoring plan, if the CEMS provides
a quality-assured value of Hg concentration
for the hour;
7.1.3.3 The hourly Hg concentration, if a
quality-assured value is obtained for the hour
(mg/scm, rounded to three significant figures);
7.1.3.4 A special code, indicating
whether or not a quality-assured Hg
concentration is obtained for the hour. This
code may be entered manually when a
temporary like-kind replacement Hg analyzer
is used for reporting; and
7.1.3.5 Monitor data availability, as a
percentage of unit or stack operating hours,
calculated according to § 75.32 of this
chapter.
7.1.4 Hg Emissions Records (Sorbent
Trap Monitoring Systems). For each affected
unit or common stack using a sorbent trap
monitoring system, each owner or operator
shall record the following information for the
unit or stack operating hour in each data
collection period:
7.1.4.1 The date and hour;
7.1.4.2 Monitoring system and
component identification codes, as provided
in the monitoring plan, if the sorbent trap
7. Recordkeeping and Reporting
7.1 Recordkeeping Provisions. For the Hg
CEMS and/or sorbent trap monitoring
systems and any other necessary monitoring
systems installed at each affected unit, the
owner or operator must maintain a file of all
measurements, data, reports, and other
information required by this appendix in a
form suitable for inspection, for 5 years from
the date of each record, in accordance with
§ 63.10033. The file shall contain the
information in paragraphs 7.1.1 through
7.1.10 of this section.
7.1.1 Monitoring Plan Records. For each
affected unit or group of units monitored at
a common stack, the owner or operator shall
prepare and maintain a monitoring plan for
the Hg CEMS and/or sorbent trap monitoring
system(s) and any other monitoring system(s)
(i.e., flow rate, diluent gas, or moisture
systems) needed for routine operation of a
sorbent trap monitoring system or to convert
Hg concentrations to units of the applicable
emission standard. The monitoring plan shall
contain essential information on the
continuous monitoring systems and shall
Document how the data derived from these
systems ensure that all Hg emissions from the
unit or stack are monitored and reported.
7.1.1.1 Updates. Whenever the owner or
operator makes a replacement, modification,
or change in a certified continuous
monitoring system that is used to provide
data under this subpart (including a change
in the automated data acquisition and
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ER16FE12.017</GPH>
6.2.2.2 Use Equation A–4 of this section
to calculate the emission rate for each unit
or stack operating hour in which valid data
are obtained for all parameters.
ER16FE12.016</GPH>
(Note: Use unadjusted flow rate values; bias
adjustment is not required).
Bws = Moisture fraction of the stack gas,
expressed as a decimal (equal to % H2O/
100)
Where:
Eho = Electrical output-based Hg emission
rate (lb/GWh).
Mh = Hg mass emission rate for the hour,
from Equation A–2 or A–3 of this
section, as applicable (lb/h).
srobinson on DSK4SPTVN1PROD with RULES2
Ch = Hourly average Hg concentration, dry
basis (mg/dscm).
Qh = Stack gas volumetric flow rate for the
hour (scfh)
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system provides a quality-assured value of
Hg concentration for the hour;
7.1.4.3 The hourly Hg concentration, if a
quality-assured value is obtained for the hour
(mg/scm, rounded to three significant figures).
Note that when a quality-assured Hg
concentration value is obtained for a
particular data collection period, that single
concentration value is applied to each
operating hour of the data collection period.
7.1.4.4 A special code, indicating
whether or not a quality-assured Hg
concentration is obtained for the hour;
7.1.4.5 The average flow rate of stack gas
through each sorbent trap (in appropriate
units, e.g., liters/min, cc/min, dscm/min);
7.1.4.6 The gas flow meter reading (in
dscm, rounded to the nearest hundredth), at
the beginning and end of the collection
period and at least once in each unit
operating hour during the collection period;
7.1.4.7 The ratio of the stack gas flow rate
to the sample flow rate, as described in
section 12.2 of Performance Specification
(PS) 12B in Appendix B to part 60 of this
chapter; and
7.1.4.8 Monitor data availability, as a
percentage of unit or stack operating hours,
calculated according to § 75.32 of this
chapter.
7.1.5 Stack Gas Volumetric Flow Rate
Records.
7.1.5.1 Hourly measurements of stack gas
volumetric flow rate during unit operation
are required for routine operation of sorbent
trap monitoring systems, to maintain the
required ratio of stack gas flow rate to sample
flow rate (see section 8.2.2 of Performance
Specification (PS) 12B in Appendix B to part
60 of this chapter). Hourly stack gas flow rate
data are also needed in order to demonstrate
compliance with electrical output-based Hg
emissions limits, as provided in section 6.2.2
of this appendix.
7.1.5.2 For each affected unit or common
stack, if hourly measurements of stack gas
flow rate are needed for sorbent trap
monitoring system operation or to convert Hg
concentrations to the units of the emission
standard, use a flow rate monitor that meets
the requirements of part 75 of this chapter to
record the required data. You must keep
hourly flow rate records, as specified in
§ 75.57(c)(2) of this chapter.
7.1.6 Records of Stack Gas Moisture
Content.
7.1.6.1 Correction of hourly Hg
concentration data for moisture is sometimes
required when converting Hg concentrations
to the units of the applicable Hg emissions
limit. In particular, these corrections are
required:
7.1.6.1.1 For sorbent trap monitoring
systems;
7.1.6.1.2 For Hg CEMS that measure Hg
concentration on a dry basis, when you must
calculate electrical output-based Hg emission
rates; and
7.1.6.1.3 When using certain equations
from EPA Method 19 in appendix A–7 to part
60 of this chapter to calculate heat inputbased Hg emission rates.
7.1.6.2 If hourly moisture corrections are
required, either use a fuel-specific default
moisture percentage from § 75.11(b)(1) of this
chapter or a certified moisture monitoring
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system that meets the requirements of part 75
of this chapter, to record the required data.
If you use a moisture monitoring system, you
must keep hourly records of the stack gas
moisture content, as specified in § 75.57(c)(3)
of this chapter.
7.1.7 Records of Diluent Gas (CO2 or O2)
Concentration.
7.1.7.1 When a heat input-based Hg mass
emissions limit must be met, in units of lb/
TBtu, hourly measurements of CO2 or O2
concentration are required to convert Hg
concentrations to units of the standard.
7.1.7.2 If hourly measurements of diluent
gas concentration are needed, use a certified
CO2 or O2 monitor that meets the
requirements of part 75 of this chapter to
record the required data. You must keep
hourly CO2 or O2 concentration records, as
specified in § 75.57(g) of this chapter.
7.1.8 Hg Emission Rate Records. For
applicable Hg emission limits in units of
lb/TBtu or lb/GWh, record the following
information for each affected unit or common
stack:
7.1.8.1 The date and hour;
7.1.8.2 The hourly Hg emissions rate
(lb/TBtu or lb/GWh, as applicable, calculated
according to section 6.2.1 or 6.2.2 of this
appendix, rounded to three significant
figures), if valid values of Hg concentration
and all other required parameters (stack gas
volumetric flow rate, diluent gas
concentration, electrical load, and moisture
data, as applicable) are obtained for the hour;
7.1.8.3 An identification code for the
formula (either the selected equation from
Method 19 in section 6.2.1 of this appendix
or Equation A–4 in section 6.2.2 of this
appendix) used to derive the hourly Hg
emission rate from Hg concentration, flow
rate, electrical load, diluent gas
concentration, and moisture data (as
applicable); and
7.1.8.4 A code indicating that the Hg
emission rate was not calculated for the hour,
if valid data for Hg concentration and/or any
of the other necessary parameters are not
obtained for the hour. For the purposes of
this appendix, the substitute data values
required under part 75 of this chapter for
diluent gas concentration, stack gas flow rate
and moisture content are not considered to
be valid data.
7.1.9 Certification and Quality Assurance
Test Records. For any Hg CEMS and sorbent
trap monitoring systems used to provide data
under this subpart, record the following
certification and quality-assurance
information:
7.1.9.1 The reference values, monitor
responses, and calculated calibration error
(CE) values, and a flag to indicate whether
the test was done using elemental or oxidized
Hg, for all required 7-day calibration error
tests and daily calibration error tests of the
Hg CEMS;
7.1.9.2 The reference values, monitor
responses, and calculated linearity error (LE)
or system integrity error (SIE) values for all
linearity checks of the Hg CEMS, and for all
single-level and 3-level system integrity
checks of the Hg CEMS;
7.1.9.3 The CEMS and reference method
readings for each test run and the calculated
relative accuracy results for all RATAs of the
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Hg CEMS and/or sorbent trap monitoring
systems;
7.1.9.4 The stable stack gas and
calibration gas readings and the calculated
results for the upscale and downscale stages
of all required cycle time tests of the Hg
CEMS or, for a batch sampling Hg CEMS, the
interval between measured Hg concentration
readings;
7.1.9.5 Supporting information for all
required RATAs of the Hg monitoring
systems, including records of the test dates,
the raw reference method and monitoring
system data, the results of sample analyses to
substantiate the reported test results, and
records of sampling equipment calibrations;
7.1.9.6 For sorbent trap monitoring
systems, also keep records of the results of
all analyses of the sorbent traps used for
routine daily operation of the system, and
information documenting the results of all
leak checks and the other applicable quality
control procedures described in Table 12B–
1 of Performance Specification (PS) 12B in
appendix B to part 60 of this chapter.
7.1.9.7 For stack gas flow rate, diluent
gas, and (if applicable) moisture monitoring
systems, you must keep records of all
certification, recertification, diagnostic, and
on-going quality-assurance tests of these
systems, as specified in § 75.59 of this
chapter.
7.2 Reporting Requirements.
7.2.1 General Reporting Provisions. The
owner or operator shall comply with the
following requirements for reporting Hg
emissions from each affected unit (or group
of units monitored at a common stack) under
this subpart:
7.2.1.1 Notifications, in accordance with
paragraph 7.2.2 of this section;
7.2.1.2 Monitoring plan reporting, in
accordance with paragraph 7.2.3 of this
section;
7.2.1.3 Certification, recertification, and
QA test submittals, in accordance with
paragraph 7.2.4 of this section; and
7.2.1.4 Electronic quarterly report
submittals, in accordance with paragraph
7.2.5 of this section.
7.2.2 Notifications. The owner or operator
shall provide notifications for each affected
unit (or group of units monitored at a
common stack) under this subpart in
accordance with § 63.10030.
7.2.3 Monitoring Plan Reporting. For each
affected unit (or group of units monitored at
a common stack) under this subpart using Hg
CEMS or sorbent trap monitoring system to
measure Hg emissions, the owner or operator
shall make electronic and hard copy
monitoring plan submittals as follows:
7.2.3.1 Submit the electronic and hard
copy information in section 7.1.1.2 of this
appendix pertaining to the Hg monitoring
systems at least 21 days prior to the
applicable date in § 63.9984. Also submit the
monitoring plan information in § 75.53.(g)
pertaining to the flow rate, diluent gas, and
moisture monitoring systems within that
same time frame, if the required records are
not already in place.
7.2.3.2 Whenever an update of the
monitoring plan is required, as provided in
paragraph 7.1.1.1 of this section. An
electronic monitoring plan information
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of each electronic quarterly emissions
monitoring report. The compliance
certification shall include a statement by a
responsible official with that official’s name,
title, and signature, certifying that, to the best
of his or her knowledge, the report is true,
accurate, and complete.
3.1.2.2 The relative accuracy (RA) of the
HCl or HF CEMS must be no greater than 20
percent of the mean value of the RM test data
in units of ppm on the same moisture basis.
Alternatively, if the mean RM value is less
than 1.0 ppm, the RA results are acceptable
if the absolute value of the difference
between the mean RM and CEMS values does
not exceed 0.20 ppm.
3.2 Any additional stack gas flow rate,
diluent gas, and moisture monitoring
system(s) needed to express pollutant
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Appendix B to Subpart UUUUU—-HCl
and HF Monitoring Provisions
1. Applicability
These monitoring provisions apply to the
measurement of HCl and/or HF emissions
from electric utility steam generating units,
using CEMS. The CEMS must be capable of
measuring HCl and/or HF in the appropriate
units of the applicable emissions standard
(e.g., lb/MMBtu, lb/MWh, or lb/GWh).
2. Monitoring of HCl and/or HF Emissions
2.1 Monitoring System Installation
Requirements. Install HCl and/or HF CEMS
and any additional monitoring systems
needed to convert pollutant concentrations to
units of the applicable emissions limit in
accordance with Performance Specification
15 for extractive Fourier Transform Infrared
Spectroscopy (FTIR) continuous emissions
monitoring systems in appendix B to part 60
of this chapter and § 63.10010(a).
2.2 Primary and Backup Monitoring
Systems. The provisions pertaining to
primary and redundant backup monitoring
systems in section 2.2 of appendix A to this
subpart apply to HCl and HF CEMS and any
additional monitoring systems needed to
convert pollutant concentrations to units of
the applicable emissions limit.
2.3 FTIR Monitoring System Equipment,
Supplies, Definitions, and General
Operation. The provisions of Performance
Specification 15 Sections 2.0, 3.0, 4.0, 5.0,
6.0, and 10.0 apply.
3. Initial Certification Procedures
The initial certification procedures for the
HCl or HF CEMS used to provide data under
this subpart are as follows:
3.1 The HCl and/or HF CEMS must be
certified according to Performance
Specification 15 using the procedures for gas
auditing and comparison to a reference
method (RM) as specified in sections 3.1.1
and 3.1.2 below. (Please Note: EPA plans to
publish a technology neutral performance
specification and appropriate on-going
quality-assurance requirements for HCl
CEMS in the near future along with
amendments to this appendix to
accommodate their use.)
3.1.1 You must conduct a gas audit of the
HCl and/or HF CEMS as described in section
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9.1 of Performance Specification 15, with the
exceptions listed in sections 3.1.2.1 and
3.1.2.2 below.
3.1.1.1 The audit sample gas does not
have to be obtained from the Administrator;
however, it must be (1) from a secondary
source of certified gases (i.e., independent of
any calibration gas used for the daily
calibration assessments) and (2) directly
traceable to National Institute of Standards
and Technology (NIST) or VSL Dutch
Metrology Institute (VSL) reference materials
through an unbroken chain of comparisons.
If audit gas traceable to NIST or VSL
reference materials is not available, you may
use a gas with a concentration certified to a
specified uncertainty by the gas
manufacturer.
3.1.1.2 Analyze the results of the gas
audit using the calculations in section 12.1
of Performance Specification 15. The
calculated correction factor (CF) from Eq. 6
of Performance Specification 15 must be
between 0.85 and 1.15. You do not have to
test the bias for statistical significance.
3.1.2 You must perform a relative
accuracy test audit or RATA according to
section 11.1.1.4 of Performance Specification
15 and the requirements below. Perform the
RATA of the HCl or HF CEMS at normal
load. Acceptable HCl/HF reference methods
(RM) are Methods 26 and 26A in appendix
A–8 to part 60 of this chapter, Method 320
in Appendix A to this part, or ASTM D6348–
03 (Reapproved 2010) ‘‘Standard Test
Method for Determination of Gaseous
Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR)
Spectroscopy’’ (incorporated by reference,
see § 63.14), each applied based on the
criteria set forth in Table 5 of this subpart.
3.1.2.1 When ASTM D6348–03 is used as
the RM, the following conditions must be
met:
3.1.2.1.1 The test plan preparation and
implementation in the Annexes to ASTM
D6348–03, Sections A1 through A8 are
mandatory;
3.1.2.1.2 In ASTM D6348–03 Annex A5
(Analyte Spiking Technique), the percent (%)
R must be determined for each target analyte
(see Equation A5.5);
3.1.2.1.3 For the ASTM D6348–03 test
data to be acceptable for a target analyte, %R
must be 70% ≥ R ≤ 130%; and
3.1.2.1.4 The %R value for each
compound must be reported in the test report
and all field measurements corrected with
the calculated %R value for that compound
using the following equation:
concentrations in units of the applicable
emissions limit must be certified according to
part 75 of this chapter.
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update must be submitted either prior to or
concurrent with the quarterly report for the
calendar quarter in which the update is
required.
7.2.3.3 All electronic monitoring plan
submittals and updates shall be made to the
Administrator using the ECMPS Client Tool.
Hard copy portions of the monitoring plan
shall be kept on record according to section
7.1 of this appendix.
7.2.4 Certification, Recertification, and
Quality-Assurance Test Reporting. Except for
daily QA tests of the required monitoring
systems (i.e., calibration error tests and flow
monitor interference checks), the results of
all required certification, recertification, and
quality-assurance tests described in
paragraphs 7.1.10.1 through 7.1.10.7 of this
section (except for test results previously
submitted, e.g., under the ARP) shall be
submitted electronically, using the ECMPS
Client Tool, either prior to or concurrent with
the relevant quarterly electronic emissions
report.
7.2.5 Quarterly Reports.
7.2.5.1 Beginning with the report for the
calendar quarter in which the initial
compliance demonstration is completed or
the calendar quarter containing the
applicable date in § 63.9984, the owner or
operator of any affected unit shall use the
ECMPS Client Tool to submit electronic
quarterly reports to the Administrator, in an
XML format specified by the Administrator,
for each affected unit (or group of units
monitored at a common stack) under this
subpart.
7.2.5.2 The electronic reports must be
submitted within 30 days following the end
of each calendar quarter, except for units that
have been placed in long-term cold storage.
7.2.5.3 Each electronic quarterly report
shall include the following information:
7.2.5.3.1 The date of report generation;
7.2.5.3.2 Facility identification
information;
7.2.5.3.3 The information in paragraphs
7.1.2 through 7.1.8 of this section, as
applicable to the Hg emission measurement
methodology (or methodologies) used and
the units of the Hg emission standard(s); and
7.2.5.3.4 The results of all daily
calibration error tests of the Hg CEMS, as
described in paragraph 7.1.90.1 of this
section and (if applicable) the results of all
daily flow monitor interference checks.
7.2.5.4 Compliance Certification. Based
on reasonable inquiry of those persons with
primary responsibility for ensuring that all
Hg emissions from the affected unit(s) under
this subpart have been correctly and fully
monitored, the owner or operator shall
submit a compliance certification in support
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4. Recertification Procedures
Whenever the owner or operator makes a
replacement, modification, or change to a
certified CEMS that may significantly affect
the ability of the system to accurately
measure or record pollutant or diluent gas
concentrations, stack gas flow rates, or stack
gas moisture content, the owner or operator
shall recertify the monitoring system.
Furthermore, whenever the owner or
operator makes a replacement, modification,
or change to the flue gas handling system or
the unit operation that may significantly
change the concentration or flow profile, the
owner or operator shall recertify the
monitoring system. The same tests performed
for the initial certification of the monitoring
system shall be repeated for recertification,
unless otherwise specified by the
Administrator. Examples of changes that
require recertification include: Replacement
of a gas analyzer; complete monitoring
system replacement, and changing the
location or orientation of the sampling probe.
5. On-Going Quality Assurance
Requirements
5.1 For on-going QA test requirements for
HCl and HF CEMS, implement the quality
assurance/quality control procedures of
Performance Specification 15 of appendix B
to part 60 of this chapter as set forth in
sections 5.1.1 through 5.1.3 and 5.3.2 of this
appendix.
5.1.1 On a daily basis, you must assess
the calibration error of the HCl or HF CEMS
using either a calibration transfer standard as
specified in Performance Specification 15
Section 10.1 which references Section 4.5 of
the FTIR Protocol or a HCl and/or HF
calibration gas at a concentration no greater
than two times the level corresponding to the
applicable emission limit. A calibration
transfer standard is a substitute calibration
compound chosen to ensure that the FTIR is
performing well at the wavelength regions
used for analysis of the target analytes. The
measured concentration of the calibration
transfer standard or HCl and/or HF
calibration gas results must agree within ± 5
percent of the reference gas value after
correction for differences in pressure.
5.1.2 On a quarterly basis, you must
conduct a gas audit of the HCl and/or HF
CEMS as described in section 3.1.1 of this
appendix. For the purposes of this appendix,
‘‘quarterly’’ means once every ‘‘QA operating
quarter’’ (as defined in section 3.1.20 of
appendix A to this subpart). You have the
option to use HCl gas in lieu of HF gas for
conducting this audit on an HF CEMS. To the
extent practicable, perform consecutive
quarterly gas audits at least 30 days apart.
The initial quarterly audit is due in the first
QA operating quarter following the calendar
quarter in which certification testing of the
CEMS is successfully completed. Up to three
consecutive exemptions from the quarterly
audit requirement are allowed for ‘‘non-QA
operating quarters’’ (i.e., calendar quarters in
which there are less than 168 unit or stack
operating hours). However, no more than
four consecutive calendar quarters may
elapse without performing a gas audit, except
as otherwise provided in section 5.3.3.2.1 of
this appendix.
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5.1.3 You must perform an annual
relative accuracy test audit or RATA of the
HCl or HF CEMS as described in section 3.1.2
of this appendix. Perform the RATA at
normal load. For the purposes of this
appendix, ‘‘annual’’ means once every four
‘‘QA operating quarters’’ (as defined in
section 3.1.20 of appendix A to this subpart).
The first annual RATA is due within four QA
operating quarters following the calendar
quarter in which the initial certification
testing of the HCl or HF CEMS is successfully
completed. The provisions in section 5.1.2.4
of appendix A to this subpart pertaining to
RATA deadline extensions also apply.
5.2 Stack gas flow rate, diluent gas, and
moisture monitoring systems must meet the
applicable on-going QA test requirements of
part 75 of this chapter.
5.3 Data Validation.
5.3.1 Out-of-Control Periods. A HCl or HF
CEMS that is used to provide data under this
appendix is considered to be out-of-control,
and data from the CEMS may not be reported
as quality-assured, when any acceptance
criteria for a required QA test is not met. The
HCl or HF CEMS is also considered to be outof-control when a required QA test is not
performed on schedule or within an allotted
grace period. To end an out-of-control period,
the QA test that was either failed or not done
on time must be performed and passed. Outof-control periods are counted as hours of
monitoring system downtime.
5.3.2 Grace Periods. For the purposes of
this appendix, a ‘‘grace period’’ is defined as
a specified number of unit or stack operating
hours after the deadline for a required
quality-assurance test of a continuous
monitor has passed, in which the test may be
performed and passed without loss of data.
5.3.2.1 For the flow rate, diluent gas, and
moisture monitoring systems described in
section 5.2 of this appendix, a 168 unit or
stack operating hour grace period is available
for quarterly linearity checks, and a 720 unit
or stack operating hour grace period is
available for RATAs, as provided,
respectively, in sections 2.2.4 and 2.3.3 of
appendix B to part 75 of this chapter.
5.3.2.2 For the purposes of this appendix,
if the deadline for a required gas audit or
RATA of a HCl or HF CEMS cannot be met
due to circumstances beyond the control of
the owner or operator:
5.3.2.2.1 A 168 unit or stack operating
hour grace period is available in which to
perform the gas audit; or
5.3.2.2.2 A 720 unit or stack operating
hour grace period is available in which to
perform the RATA.
5.3.2.3 If a required QA test is performed
during a grace period, the deadline for the
next test shall be determined as follows:
5.3.2.3.1 For a gas audit or RATA of the
monitoring systems described in section 5.1
of this appendix, determine the deadline for
the next gas audit or RATA (as applicable) in
accordance with section 2.2.4(b) or 2.3.3(d) of
appendix B to part 75 of this chapter; treat
a gas audit in the same manner as a linearity
check.
5.3.2.3.2 For the gas audit of a HCl or HF
CEMS, the grace period test only satisfies the
audit requirement for the calendar quarter in
which the test was originally due. If the
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calendar quarter in which the grace period
audit is performed is a QA operating quarter,
an additional gas audit is required for that
quarter.
5.3.2.3.3 For the RATA of a HCl or HF
CEMS, the next RATA is due within three
QA operating quarters after the calendar
quarter in which the grace period test is
performed.
5.3.4 Conditional Data Validation. For
recertification and diagnostic testing of the
monitoring systems that are used to provide
data under this appendix, and for the
required QA tests when non-redundant
backup monitoring systems or temporary
like-kind replacement analyzers are brought
into service, the conditional data validation
provisions in §§ 75.20(b)(3)(ii) through
(b)(3)(ix) of this chapter may be used to avoid
or minimize data loss. The allotted window
of time to complete calibration tests and
RATAs shall be as specified in
§ 75.20(b)(3)(iv) of this chapter; the allotted
window of time to complete a gas audit shall
be the same as for a linearity check (i.e., 168
unit or stack operating hours).
6. Missing Data Requirements
For the purposes of this appendix, the
owner or operator of an affected unit shall
not substitute for missing data from HCl or
HF CEMS. Any process operating hour for
which quality-assured HCl or HF
concentration data are not obtained is
counted as an hour of monitoring system
downtime.
7. Bias Adjustment
Bias adjustment of hourly emissions data
from a HCl or HF CEMS is not required.
8. QA/QC Program Requirements
The owner or operator shall develop and
implement a quality assurance/quality
control (QA/QC) program for the HCl and/or
HF CEMS that are used to provide data under
this subpart. At a minimum, the program
shall include a written plan that describes in
detail (or that refers to separate documents
containing) complete, step-by-step
procedures and operations for the most
important QA/QC activities. Electronic
storage of the QA/QC plan is permissible,
provided that the information can be made
available in hard copy to auditors and
inspectors. The QA/QC program
requirements for the other monitoring
systems described in section 5.2 of this
appendix are specified in section 1 of
appendix B to part 75 of this chapter.
8.1 General Requirements for HCl and HF
CEMS.
8.1.1 Preventive Maintenance. Keep a
written record of procedures needed to
maintain the HCl and/or HF CEMS in proper
operating condition and a schedule for those
procedures. This shall, at a minimum,
include procedures specified by the
manufacturers of the equipment and, if
applicable, additional or alternate procedures
developed for the equipment.
8.1.2 Recordkeeping and Reporting. Keep
a written record describing procedures that
will be used to implement the recordkeeping
and reporting requirements of this appendix.
8.1.3 Maintenance Records. Keep a
record of all testing, maintenance, or repair
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activities performed on any HCl or HF CEMS
in a location and format suitable for
inspection. A maintenance log may be used
for this purpose. The following records
should be maintained: Date, time, and
description of any testing, adjustment, repair,
replacement, or preventive maintenance
action performed on any monitoring system
and records of any corrective actions
associated with a monitor outage period.
Additionally, any adjustment that may
significantly affect a system’s ability to
accurately measure emissions data must be
recorded and a written explanation of the
procedures used to make the adjustment(s)
shall be kept.
8.2 Specific Requirements for HCl and HF
CEMS. The following requirements are
specific to HCl and HF CEMS:
8.2.1 Keep a written record of the
procedures used for each type of QA test
required for each HCl and HF CEMS. Explain
how the results of each type of QA test are
calculated and evaluated.
8.2.2 Explain how each component of the
HCl and/or HF CEMS will be adjusted to
provide correct responses to calibration gases
after routine maintenance, repairs, or
corrective actions.
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9. Data Reduction and Calculations
9.1 Design and operate the HCl and/or HF
CEMS to complete a minimum of one cycle
of operation (sampling, analyzing, and data
recording) for each successive 15-minute
period.
9.2 Reduce the HCl and/or HF
concentration data to hourly averages in
accordance with § 60.13(h)(2) of this chapter.
9.3 Convert each hourly average HCl or
HF concentration to an HCl or HF emission
rate expressed in units of the applicable
emissions limit.
9.3.1 For heat input-based emission rates,
select an appropriate emission rate equation
from among Equations 19–1 through 19–9 in
EPA Method 19 in appendix A–7 to part 60
of this chapter, to calculate the HCl or HF
emission rate in lb/MMBtu. Multiply the HCl
concentration value (ppm) by 9.43 × 10¥8 to
convert it to lb/scf, for use in the applicable
Method 19 equation. For HF, the conversion
constant from ppm to lb/scf is 5.18 × 10¥8.
9.3.2 For electrical output-based emission
rates, first calculate the HCl or HF mass
emission rate (lb/h), using an equation that
has the general form of Equation A–2 or A–
3 in appendix A to this subpart (as
applicable), replacing the value of K with
9.43 × 10¥8 lb/scf-ppm (for HCl) or 5.18 ×
10¥8 (for HF) and defining Ch as the hourly
average HCl or HF concentration in ppm.
Then, use Equation A–4 in appendix A to
this subpart to calculate the HCl or HF
emission rate in lb/GWh. If the applicable
HCl or HF limit is expressed in lb/MWh,
divide the result from Equation A–4 by 103.
9.4 Use Equation A–5 in appendix A of
this subpart to calculate the required 30
operating day rolling average HCl or HF
emission rates. Round off each 30 operating
day average to two significant figures. The
term Eho in Equation A–5 must be in the units
of the applicable emissions limit.
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10. Recordkeeping Requirements
10.1 For each HCl or HF CEMS installed
at an affected source, and for any other
monitoring system(s) needed to convert
pollutant concentrations to units of the
applicable emissions limit, the owner or
operator must maintain a file of all
measurements, data, reports, and other
information required by this appendix in a
form suitable for inspection, for 5 years from
the date of each record, in accordance with
§ 63.10033. The file shall contain the
information in paragraphs 10.1.1 through
10.1.8 of this section.
10.1.1 Monitoring Plan Records. For each
affected unit or group of units monitored at
a common stack, the owner or operator shall
prepare and maintain a monitoring plan for
the HCl and/or HF CEMS and any other
monitoring system(s) (i.e, flow rate, diluent
gas, or moisture systems) needed to convert
pollutant concentrations to units of the
applicable emission standard. The
monitoring plan shall contain essential
information on the continuous monitoring
systems and shall explain how the data
derived from these systems ensure that all
HCl or HF emissions from the unit or stack
are monitored and reported.
10.1.1.1 Updates. Whenever the owner or
operator makes a replacement, modification,
or change in a certified continuous HCl or HF
monitoring system that is used to provide
data under this subpart (including a change
in the automated data acquisition and
handling system or the flue gas handling
system) which affects information reported in
the monitoring plan (e.g., a change to a serial
number for a component of a monitoring
system), the owner or operator shall update
the monitoring plan.
10.1.1.2 Contents of the Monitoring Plan.
For HCl and/or HF CEMS, the monitoring
plan shall contain the applicable electronic
and hard copy information in sections
10.1.1.2.1 and 10.1.1.2.2 of this appendix.
For stack gas flow rate, diluent gas, and
moisture monitoring systems, the monitoring
plan shall include the electronic and hard
copy information required for those systems
under § 75.53 (g) of this chapter. The
electronic monitoring plan shall be evaluated
using the ECMPS Client Tool.
10.1.1.2.1 Electronic. Record the unit or
stack ID number(s); monitoring location(s);
the HCl or HF monitoring methodology used
(i.e., CEMS); HCl or HF monitoring system
information, including, but not limited to:
unique system and component ID numbers;
the make, model, and serial number of the
monitoring equipment; the sample
acquisition method; formulas used to
calculate emissions; monitor span and range
information (if applicable).
10.1.1.2.2 Hard Copy. Keep records of the
following: schematics and/or blueprints
showing the location of the monitoring
system(s) and test ports; data flow diagrams;
test protocols; monitor span and range
calculations (if applicable); miscellaneous
technical justifications.
10.1.2 Operating Parameter Records. For
the purposes of this appendix, the owner or
operator shall record the following
information for each operating hour of each
affected unit or group of units utilizing a
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common stack, to the extent that these data
are needed to convert pollutant concentration
data to the units of the emission standard.
For non-operating hours, record only the
items in paragraphs 10.1.2.1 and 10.1.2.2 of
this section. If there is heat input to the
unit(s), but no electrical load, record only the
items in paragraphs 10.1.2.1, 10.1.2.2, and (if
applicable) 10.1.2.4 of this section.
10.1.2.1 The date and hour;
10.1.2.2 The unit or stack operating time
(rounded up to the nearest fraction of an hour
(in equal increments that can range from one
hundredth to one quarter of an hour, at the
option of the owner or operator);
10.1.2.3 The hourly gross unit load
(rounded to nearest MWge); and
10.1.2.4 If applicable, the F-factor used to
calculate the heat input-based pollutant
emission rate.
10.1.3 HCl and/or HF Emissions Records.
For HCl and/or HF CEMS, the owner or
operator must record the following
information for each unit or stack operating
hour:
10.1.3.1 The date and hour;
10.1.3.2 Monitoring system and
component identification codes, as provided
in the electronic monitoring plan, for each
hour in which the CEMS provides a qualityassured value of HCl or HF concentration (as
applicable);
10.1.3.3 The pollutant concentration, for
each hour in which a quality-assured value
is obtained. For HCl and HF, record the data
in parts per million (ppm), rounded to three
significant figures.
10.1.3.4 A special code, indicating
whether or not a quality-assured HCl or HF
concentration value is obtained for the hour.
This code may be entered manually when a
temporary like-kind replacement HCl or HF
analyzer is used for reporting; and
10.1.3.5 Monitor data availability, as a
percentage of unit or stack operating hours,
calculated according to § 75.32 of this
chapter.
10.1.4 Stack Gas Volumetric Flow Rate
Records.
10.1.4.1 Hourly measurements of stack
gas volumetric flow rate during unit
operation are required to demonstrate
compliance with electrical output-based HCl
or HF emissions limits (i.e., lb/MWh or lb/
GWh).
10.1.4.2 Use a flow rate monitor that
meets the requirements of part 75 of this
chapter to record the required data. You must
keep hourly flow rate records, as specified in
§ 75.57(c)(2) of this chapter.
10.1.5 Records of Stack Gas Moisture
Content.
10.1.5.1 Correction of hourly pollutant
concentration data for moisture is sometimes
required when converting concentrations to
the units of the applicable Hg emissions
limit. In particular, these corrections are
required:
10.1.5.1.1 To calculate electrical outputbased pollutant emission rates, when using a
CEMS that measures pollutant concentrations
on a dry basis; and
10.1.5.1.2 To calculate heat input-based
pollutant emission rates, when using certain
equations from EPA Method 19 in appendix
A–7 to part 60 of this chapter.
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10.1.5.2 If hourly moisture corrections are
required, either use a fuel-specific default
moisture percentage for coal-fired units from
§ 75.11(b)(1) of this chapter, an Administrator
approved default moisture value for noncoal-fired units (as per paragraph 63.10010(d)
of this subpart), or a certified moisture
monitoring system that meets the
requirements of part 75 of this chapter, to
record the required data. If you elect to use
a moisture monitoring system, you must keep
hourly records of the stack gas moisture
content, as specified in § 75.57(c)(3) of this
chapter.
10.1.6 Records of Diluent Gas (CO2 or O2)
Concentration.
10.1.6.1 To assess compliance with a heat
input-based HCl or HF emission rate limit in
units of lb/MMBtu, hourly measurements of
CO2 or O2 concentration are required to
convert pollutant concentrations to units of
the standard.
10.1.6.2 If hourly measurements of
diluent gas concentration are needed, you
must use a certified CO2 or O2 monitor that
meets the requirements of part 75 of this
chapter to record the required data. For all
diluent gas monitors, you must keep hourly
CO2 or O2 concentration records, as specified
in § 75.57(g) of this chapter.
10.1.7 HCl and HF Emission Rate
Records. For applicable HCl and HF emission
limits in units of lb/MMBtu, lb/MWh, or lb/
GWh, record the following information for
each affected unit or common stack:
10.1.7.1 The date and hour;
10.1.7.2 The hourly HCl and/or HF
emissions rate (lb/MMBtu, lb/MWh, or lb/
GWh, as applicable, rounded to three
significant figures), for each hour in which
valid values of HCl or HF concentration and
all other required parameters (stack gas
volumetric flow rate, diluent gas
concentration, electrical load, and moisture
data, as applicable) are obtained for the hour;
10.1.7.3 An identification code for the
formula used to derive the hourly HCl or HF
emission rate from HCl or HF concentration,
flow rate, electrical load, diluent gas
concentration, and moisture data (as
applicable); and
10.1.7.4 A code indicating that the HCl or
HF emission rate was not calculated for the
hour, if valid data for HCl or HF
concentration and/or any of the other
necessary parameters are not obtained for the
hour. For the purposes of this appendix, the
substitute data values required under part 75
of this chapter for diluent gas concentration,
stack gas flow rate and moisture content are
not considered to be valid data.
10.1.8 Certification and Quality
Assurance Test Records. For the HCl and/or
HF CEMS used to provide data under this
subpart at each affected unit (or group of
units monitored at a common stack), record
the following information for all required
certification, recertification, diagnostic, and
quality-assurance tests:
10.1.8.1 HCl and HF CEMS.
10.1.8.1.1 For all required daily
calibrations (including calibration transfer
standard tests) of the HCl or HF CEMS,
record the test dates and times, reference
values, monitor responses, and calculated
calibration error values;
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10.1.8.1.2 For gas audits of HCl or HF
CEMS, record the date and time of each
spiked and unspiked sample, the audit gas
reference values and uncertainties. Keep
records of all calculations and data analyses
required under sections 9.1 and 12.1 of
Performance Specification 15, and the results
of those calculations and analyses.
10.1.8.1.3 For each RATA of a HCl or HF
CEMS, record the date and time of each test
run, the reference method(s) used, and the
reference method and HCl or HF CEMS
values. Keep records of the data analyses and
calculations used to determine the relative
accuracy.
10.1.8.2 Additional Monitoring Systems.
For the stack gas flow rate, diluent gas, and
moisture monitoring systems described in
section 3.2 of this appendix, you must keep
records of all certification, recertification,
diagnostic, and on-going quality-assurance
tests of these systems, as specified in
§ 75.59(a) of this chapter.
11. Reporting Requirements
11.1 General Reporting Provisions. The
owner or operator shall comply with the
following requirements for reporting HCl
and/or HF emissions from each affected unit
(or group of units monitored at a common
stack):
11.1.1 Notifications, in accordance with
paragraph 11.2 of this section;
11.1.2 Monitoring plan reporting, in
accordance with paragraph 11.3 of this
section;
11.1.3 Certification, recertification, and
QA test submittals, in accordance with
paragraph 11.4 of this section; and
11.1.4 Electronic quarterly report
submittals, in accordance with paragraph
11.5 of this section.
11.2 Notifications. The owner or operator
shall provide notifications for each affected
unit (or group of units monitored at a
common stack) in accordance with
§ 63.10030.
11.3 Monitoring Plan Reporting. For each
affected unit (or group of units monitored at
a common stack) using HCl and/or HF CEMS,
the owner or operator shall make electronic
and hard copy monitoring plan submittals as
follows:
11.3.1 Submit the electronic and hard
copy information in section 10.1.1.2 of this
appendix pertaining to the HCl and/or HF
monitoring systems at least 21 days prior to
the applicable date in § 63.9984. Also, if
applicable, submit monitoring plan
information pertaining to any required flow
rate, diluent gas, and/or moisture monitoring
systems within that same time frame, if the
required records are not already in place.
11.3.2 Update the monitoring plan when
required, as provided in paragraph 10.1.1.1 of
this appendix. An electronic monitoring plan
information update must be submitted either
prior to or concurrent with the quarterly
report for the calendar quarter in which the
update is required.
11.3.3 All electronic monitoring plan
submittals and updates shall be made to the
Administrator using the ECMPS Client Tool.
Hard copy portions of the monitoring plan
shall be kept on record according to section
10.1 of this appendix.
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11.4 Certification, Recertification, and
Quality-Assurance Test Reporting
Requirements. Except for daily QA tests (i.e.,
calibrations and flow monitor interference
checks), which are included in each
electronic quarterly emissions report, use the
ECMPS Client Tool to submit the results of
all required certification, recertification,
quality-assurance, and diagnostic tests of the
monitoring systems required under this
appendix electronically, either prior to or
concurrent with the relevant quarterly
electronic emissions report.
11.4.1 For daily calibrations (including
calibration transfer standard tests), report the
information in § 75.59(a)(1) of this chapter,
excluding paragraphs (a)(1)(ix) through
(a)(1)(xi).
11.4.2 For each quarterly gas audit of a
HCl or HF CEMS, report:
11.4.2.1 Facility ID information;
11.4.2.2 Monitoring system ID number;
11.4.2.3 Type of test (e.g., quarterly gas
audit);
11.4.2.4 Reason for test;
11.4.2.5 Certified audit (spike) gas
concentration value (ppm);
11.4.2.6 Measured value of audit (spike)
gas, including date and time of injection;
11.4.2.7 Calculated dilution ratio for
audit (spike) gas;
11.4.2.8 Date and time of each spiked flue
gas sample;
11.4.2.9 Date and time of each unspiked
flue gas sample;
11.4.2.10 The measured values for each
spiked gas and unspiked flue gas sample
(ppm);
11.4.2.11 The mean values of the spiked
and unspiked sample concentrations and the
expected value of the spiked concentration as
specified in section 12.1 of Performance
Specification 15 (ppm);
11.4.2.12 Bias at the spike level as
calculated using equation 3 in section 12.1 of
Performance Specification 15; and
11.4.2.13 The correction factor (CF),
calculated using equation 6 in section 12.1 of
Performance Specification 15.
11.4.3 For each RATA of a HCl or HF
CEMS, report:
11.4.3.1 Facility ID information;
11.4.3.2 Monitoring system ID number;
11.4.3.3 Type of test (i.e., initial or annual
RATA);
11.4.3.4 Reason for test;
11.4.3.5 The reference method used;
11.4.3.6 Starting and ending date and
time for each test run;
11.4.3.7 Units of measure;
11.4.3.8 The measured reference method
and CEMS values for each test run, on a
consistent moisture basis, in appropriate
units of measure;
11.4.3.9 Flags to indicate which test runs
were used in the calculations;
11.4.3.10 Arithmetic mean of the CEMS
values, of the reference method values, and
of their differences;
11.4.3.11 Standard deviation, as specified
in Equation 2–4 of Performance Specification
2 in appendix B to part 60 of this chapter;
11.4.3.12 Confidence coefficient, as
specified in Equation 2–5 of Performance
Specification 2 in appendix B to part 60 of
this chapter; and
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11.4.3.13 Relative accuracy calculated
using Equation 2–6 of Performance
Specification 2 in appendix B to part 60 of
this chapter or, if applicable, according to the
alternative procedure for low emitters
described in section 3.1.2.2 of this appendix.
If applicable use a flag to indicate that the
alternative RA specification for low emitters
has been applied.
11.4.4 Reporting Requirements for
Diluent Gas, Flow Rate, and Moisture
Monitoring Systems. For the certification,
recertification, diagnostic, and QA tests of
stack gas flow rate, moisture, and diluent gas
monitoring systems that are certified and
quality-assured according to part 75 of this
chapter, report the information in section
10.1.9.3 of this appendix.
11.5 Quarterly Reports.
11.5.1 Beginning with the report for the
calendar quarter in which the initial
compliance demonstration is completed or
the calendar quarter containing the
applicable date in § 63.10005(g), (h), or (j)
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(whichever is earlier), the owner or operator
of any affected unit shall use the ECMPS
Client Tool to submit electronic quarterly
reports to the Administrator, in an XML
format specified by the Administrator, for
each affected unit (or group of units
monitored at a common stack).
11.5.2 The electronic reports must be
submitted within 30 days following the end
of each calendar quarter, except for units that
have been placed in long-term cold storage.
11.5.3 Each electronic quarterly report
shall include the following information:
11.5.3.1 The date of report generation;
11.5.3.2 Facility identification
information;
11.5.3.3 The information in sections
10.1.2 through 10.1.7 of this appendix, as
applicable to the type(s) of monitoring
system(s) used to measure the pollutant
concentrations and other necessary
parameters.
11.5.3.4 The results of all daily
calibrations (including calibration transfer
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9513
standard tests) of the HCl or HF monitor as
described in section 10.1.8.1.1 of this
appendix; and
11.5.3.5 If applicable, the results of all
daily flow monitor interference checks, in
accordance with section 10.1.8.2 of this
appendix.
11.5.4 Compliance Certification. Based
on reasonable inquiry of those persons with
primary responsibility for ensuring that all
HCl and/or HF emissions from the affected
unit(s) have been correctly and fully
monitored, the owner or operator shall
submit a compliance certification in support
of each electronic quarterly emissions
monitoring report. The compliance
certification shall include a statement by a
responsible official with that official’s name,
title, and signature, certifying that, to the best
of his or her knowledge, the report is true,
accurate, and complete.
[FR Doc. 2012–806 Filed 2–15–12; 8:45 am]
BILLING CODE 6560–50–P
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]]>Agencies
[Federal Register Volume 77, Number 32 (Thursday, February 16, 2012)]
[Rules and Regulations]
[Pages 9304-9513]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-806]
[[Page 9303]]
Vol. 77
Thursday,
No. 32
February 16, 2012
Part II
Environmental Protection Agency
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40 CFR Parts 60 and 63
National Emission Standards for Hazardous Air Pollutants From Coal- and
Oil-Fired Electric Utility Steam Generating Units and Standards of
Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional, and Small Industrial-Commercial-Institutional
Steam Generating Units; Final Rule
Federal Register / Vol. 77 , No. 32 / Thursday, February 16, 2012 /
Rules and Regulations
[[Page 9304]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63
[EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044, FRL-9611-4]
RIN 2060-AP52; RIN 2060-AR31
National Emission Standards for Hazardous Air Pollutants From
Coal- and Oil-Fired Electric Utility Steam Generating Units and
Standards of Performance for Fossil-Fuel-Fired Electric Utility,
Industrial-Commercial-Institutional, and Small Industrial-Commercial-
Institutional Steam Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: On May 3, 2011, under authority of Clean Air Act (CAA)
sections 111 and 112, the EPA proposed both national emission standards
for hazardous air pollutants (NESHAP) from coal- and oil-fired electric
utility steam generating units (EGUs) and standards of performance for
fossil-fuel-fired electric utility, industrial-commercial-
institutional, and small industrial-commercial-institutional steam
generating units (76 FR 24976). After consideration of public comments,
the EPA is finalizing these rules in this action.
Pursuant to CAA section 111, the EPA is revising standards of
performance in response to a voluntary remand of a final rule.
Specifically, we are amending new source performance standards (NSPS)
after analysis of the public comments we received. We are also
finalizing several minor amendments, technical clarifications, and
corrections to existing NSPS provisions for fossil fuel-fired EGUs and
large and small industrial-commercial-institutional steam generating
units.
Pursuant to CAA section 112, the EPA is establishing NESHAP that
will require coal- and oil-fired EGUs to meet hazardous air pollutant
(HAP) standards reflecting the application of the maximum achievable
control technology. This rule protects air quality and promotes public
health by reducing emissions of the HAP listed in CAA section
112(b)(1).
DATES: This final rule is effective on April 16, 2012. The
incorporation by reference of certain publications listed in this rule
is approved by the Director of the Federal Register as of April 16,
2012.
ADDRESSES: The EPA established two dockets for this action: Docket ID.
No. EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-
2009-0234 (NESHAP action). All documents in the dockets are listed on
the https://www.regulations.gov Web site. Although listed in the index,
some information is not publicly available, e.g., confidential business
information or other information whose disclosure is restricted by
statute. Certain other material, such as copyrighted material, is not
placed on the Internet and will be publicly available only in hard copy
form. Publicly available docket materials are available either
electronically through https://www.regulations.gov or in hard copy at
EPA's Docket Center, Public Reading Room, EPA West Building, Room 3334,
1301 Constitution Avenue NW., Washington, DC 20004. This Docket
Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday,
excluding legal holidays. The telephone number for the Public Reading
Room is (202) 566-1744, and the telephone number for the Air Docket is
(202) 566-1741.
FOR FURTHER INFORMATION CONTACT: For the NESHAP action: Mr. William
Maxwell, Energy Strategies Group, Sector Policies and Programs
Division, (D243-01), Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711; Telephone number: (919) 541-5430; Fax number (919) 541-5450;
Email address: maxwell.bill@epa.gov. For the NSPS action: Mr. Christian
Fellner, Energy Strategies Group, Sector Policies and Programs
Division, (D243-01), Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711; Telephone number: (919) 541-4003; Fax number (919) 541-5450;
Email address: fellner.christian@epa.gov.
SUPPLEMENTARY INFORMATION:
The information presented in this preamble is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document?
C. Judicial Review
D. What are the costs and benefits of these final rules?
II. Background Information on the NESHAP
A. What is the statutory authority for this final NESHAP?
B. What is the litigation history of this final rule?
C. What is the relationship between this final rule and other
combustion rules?
D. What are the health effects of pollutants emitted from coal-
and oil-fired EGUs?
III. Appropriate and Necessary Finding
A. Overview
B. Peer Review of the Hg Risk TSD Supporting the Appropriate and
Necessary Finding for Coal and Oil-Fired EGUs and EPA Response
C. Summary of Results of Revised Hg Risk TSD of Risks to
Populations With High Levels of Self-Caught Fish Consumption
D. Peer Review of the Approach for Estimating Cancer Risks
Associated With Cr and Ni Emissions in the U.S. EGU Case Studies of
Cancer and Non-Cancer Inhalation Risks for Non-Mercury Hg HAP and
EPA Response
E. Summary of Results of Revised U.S. EGU Case Studies of Cancer
and Non-Cancer Inhalation Risks for Non-Mercury Hg HAP
F. Public Comments and Responses to the Appropriate and
Necessary Finding
G. EPA Affirms the Finding That It Is Appropriate and Necessary
To Regulate EGUs To Address Public Health and Environmental Hazards
Associated With Emissions of Hg and Non-Mercury Hg HAP From EGUs
IV. Denial of Delisting Petition
A. Requirements of Section 112(c)(9)
B. Rationale for Denying UARG's Delisting Petition
C. EPA's Technical Analyses for the Appropriate and Necessary
Finding Provide Further Support for the Conclusion That Coal-Fired
EGUs Should Remain a Listed Source Category
V. Summary of the Final NESHAP
A. What is the source category regulated by this final rule?
B. What is the affected source?
C. What are the pollutants regulated by this final rule?
D. What emission limits and work practice standards must I meet?
E. What are the requirements during periods of startup,
shutdown, and malfunction?
F. What are the testing and initial compliance requirements?
G. What are the continuous compliance requirements?
H. What are the notification, recordkeeping and reporting
requirements?
I. Submission of Emissions Test Results to the EPA
VI. Summary of Significant Changes Since Proposal
A. Applicability
B. Subcategories
C. Emission Limits
D. Work Practice Standards for Organic HAP Emissions
E. Requirements During Startup, Shutdown, and Malfunction
F. Testing and Initial Compliance
G. Continuous Compliance
H. Emissions Averaging
I. Notification, Recordkeeping and Reporting
J. Technical/Editorial Corrections
VII. Public Comments and Responses to the Proposed NESHAP
A. MACT Floor Analysis
B. Rationale for Subcategories
C. Surrogacy
D. Area Sources
E. Health-Based Emission Limits
F. Compliance Date and Reliability Issues
[[Page 9305]]
G. Cost and Technology Basis Issues
H. Testing and Monitoring
VIII. Background Information on the NSPS
A. What is the statutory authority for this final NSPS?
B. What is the regulatory authority for the final rule?
IX. Summary of the Final NSPS
X. Summary of Significant Changes Since Proposal
XI. Public Comments and Responses to the Proposed NSPS
XII. Impacts of the Final Rule
A. What are the air impacts?
B. What are the energy impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits of this final rule?
XIII. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review and
Executive Order 13563, Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act as Amended by the Small Business
Regulatory Enforcement Fairness Act (RFA) of 1996 SBREFA), 5 U.S.C.
601 et seq.
D. Unfunded Mandates Reform Act of 1995
E. Executive Order 13132, Federalism
F. Executive Order 13175, Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045, Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
I. General Information
A. Does this action apply to me?
The regulated categories and entities potentially affected by the
final standards are shown in Table 1 of this preamble.
Table 1--Potentially Affected Regulated Categories and Entities
------------------------------------------------------------------------
Examples of
Category NAICS code 1 potentially
regulated entities
------------------------------------------------------------------------
Industry......................... 221112 Fossil fuel-fired
electric utility
steam generating
units.
Federal government............... 2 221122 Fossil fuel-fired
electric utility
steam generating
units owned by the
federal
government.
State/local/tribal government.... 2 221122 Fossil fuel-fired
electric utility
steam generating
units owned by
states, tribes, or
municipalities.
921150 Fossil fuel-fired
electric utility
steam generating
units in Indian
country.
------------------------------------------------------------------------
1 North American Industry Classification System.
2 Federal, state, or local government-owned and operated establishments
are classified according to the activity in which they are engaged.
This table is not intended to be exhaustive, but rather is meant to
provide a guide for readers regarding entities likely to be affected by
this action. To determine whether you, as owner or operator of a
facility, company, business, organization, etc., will be regulated by
this action, you should examine the applicability criteria in 40 CFR
60.40, 60.40Da, or 60.40c or in 40 CFR 63.9981. If you have any
questions regarding the applicability of this action to a particular
entity, consult either the air permitting authority for the entity or
your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR
63.13 (General Provisions).
B. Where can I get a copy of this document?
In addition to being available in the dockets, an electronic copy
of this action will also be available on the Worldwide Web (WWW)
through the Technology Transfer Network (TTN). Following signature by
the Administrator, a copy of the action will be posted on the TTN's
policy and guidance page for newly proposed or promulgated rules at the
following address: https://www.epa.gov/ttn/oarpg/. The TTN provides
information and technology exchange in various areas of air pollution
control.
C. Judicial Review
Under CAA section 307(b)(1), judicial review of this final rule is
available only by filing a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit by April 16, 2012. Under
CAA section 307(d)(7)(B), only an objection to this final rule that was
raised with reasonable specificity during the period for public comment
(including any public hearing) can be raised during judicial review.
This section also provides a mechanism for the EPA to convene a
proceeding for reconsideration, ``[i]f the person raising an objection
can demonstrate to the Administrator that it was impracticable to raise
such objection within [the period for public comment] or if the grounds
for such objection arose after the period for public comment (but
within the time specified for judicial review) and if such objection is
of central relevance to the outcome of the rule[.]'' Any person seeking
to make such a demonstration to us should submit a Petition for
Reconsideration to the Office of the Administrator, Environmental
Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania
Ave. NW., Washington, DC 20004, with a copy to the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section, and the Associate
General Counsel for the Air and Radiation Law Office, Office of General
Counsel (Mail Code 2344A), Environmental Protection Agency, 1200
Pennsylvania Ave. NW., Washington, DC 20004. Note, under CAA section
307(b)(2), the requirements established by this final rule may not be
challenged separately in any civil or criminal proceedings brought by
EPA to enforce these requirements.
D. What are the costs and benefits of this final rule?
Consistent with Executive Order (EO) 13563, ``Improving Regulation
and Regulatory Review,'' we have estimated the costs and benefits of
the final rule. This rule will reduce emissions of HAP, including
mercury (Hg), from the electric power industry. Installing the
technology necessary to reduce emissions directly regulated by this
rule will also reduce the emissions of directly emitted
PM2.5 and sulfur dioxide (SO2), a
PM2.5 precursor. The benefits associated with these PM and
SO2 reductions are referred to as co-benefits, as these
reductions are not the primary objective of this rule.
The EPA estimates that this final rule will yield annual monetized
benefits (in 2007$) of between $37 to $90 billion using a 3 percent
discount rate and $33 to $81 billion using a 7 percent discount rate.
The great majority of the estimates are attributable to co-benefits
from reductions in PM2.5-related mortality. The annual
social costs, approximated
[[Page 9306]]
by the sum of the compliance costs and monitoring and reporting costs,
are $9.6 billion (2007$) and the annual quantified net benefits (the
difference between benefits and costs) are $27 to $80 billion using a 3
percent discount rate or $24 to $71 billion using a 7 percent discount
rate. It is important to note that the PM2.5 co-benefits
reported here contain uncertainty, due in part to the important
assumption that all fine particles are equally potent in causing
premature mortality and because many of the benefits are associated
with reducing PM2.5 levels at the low end of the
concentration distributions examined in the epidemiology studies from
which the PM2.5-mortality relationships used in this
analysis are derived.
The benefits of this rule outweigh costs by between 3 to 1 or 9 to
1 depending on the benefit estimate and discount rate used. The co-
benefits are substantially attributable to the 4,200 to 11,000 fewer
PM2.5-related premature mortalities estimated to occur as a
result of this rule. The EPA could not monetize some costs and
important benefits, such as some Hg benefits and those for the HAP
reduced by this final rule other than Hg. Upon considering these
limitations and uncertainties, it remains clear that the benefits of
this rule, referred to in short as the Mercury and Air Toxics Standards
(MATS), are substantial and far outweigh the costs.
Table 2--Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Final Rule in 2016
[Billions of 2007$] \a\
----------------------------------------------------------------------------------------------------------------
3% Discount rate 7% Discount rate
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \b\..... $37 to $90............................ $33 to $81.
Partial Hg-related Benefits \c\.. $0.004 to $0.006...................... $0.0005 to $0.001.
PM2.5-related Co-benefits \b\.... $36 to $89............................ $33 to $80.
Climate-related Co-Benefits \d\.. $0.36................................. $0.36.
Total Social Costs \e\........... $9.6.................................. $9.6.
Net Benefits..................... $27 to $80............................ $24 to $71.
Non-monetized Benefits........... Visibility in Class I areas.
Other neurological effects of Hg exposure.
Other health effects of Hg exposure.
Health effects of ozone and direct exposure to SO2 and NO2.
Ecosystem effects.
Health effects from commercial and non-freshwater fish consumption.
Health risks from exposure to non-mercury HAP.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for 2016, and are rounded to two significant figures.
\b\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5.
The reduction in premature fatalities each year accounts for over 90 percent of total monetized benefits.
Benefits in this table are nationwide and are associated with directly emitted PM2.5 and SO2 reductions. The
estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon,
discussed further in chapter 5 of the RIA. Mercury benefits were calculated using the baseline from proposal.
The difference in emissions reductions between proposal and final does not substantially affect the Hg
benefits.
\c\ Based on an analysis of health effects due to recreational freshwater fish consumption.
\d\ This table shows monetized CO2 co-benefits that were calculated using the global average social cost of
carbon estimate at a 3 percent discount rate. In section 5.6 of the Regulatory Impact Analysis (RIA) we also
report the monetized CO2 co-benefits using discount rates of 5 percent, 2.5 percent, and 3 percent (95th
percentile).
\e\ Total social costs are approximated by the compliance costs for both coal- and oil-fired units. This
includes monitoring, recordkeeping, and reporting costs.
For more information on how EPA is addressing EO 13563, see the EO
discussion in the Statutory and Executive Order Reviews section of this
preamble.
II. Background Information on the NESHAP
On May 3, 2011, the EPA proposed this rule to address emissions of
toxic air pollutants from coal and oil-fired electric generating units
as required by the CAA. The proposal explained at length the statutory
history and requirements leading to this rule, the factual and legal
basis for the rule and its specific provisions, and the costs and
benefits to the public health and environment from the proposed
requirements.
The EPA received over 900,000 comments from members of the public
on the proposed rule, substantially more than for any other prior
regulatory proposal. The comments express concerns about the presence
of Hg in the environment and the effect it has on human health,
concerns about the costs of the rule, how challenging it may be for
some sources to comply and questions about the impact it may have on
this country's electricity supply and economy. Many comments provided
additional information and data that have enriched the factual record
and enabled EPA to finalize a rule that fulfills the mandate of the CAA
while providing flexibility and compliance options to affected
sources--options that make the rule less costly and compliance more
readily manageable.
This rule establishes uniform emissions-control standards that
sources can meet with proven and available technologies and operational
processes in a timeframe that is achievable. They will put this
industry, now the single largest source of Hg emissions in the United
States (U.S.) with emissions of 29 tons per year, on a path to reducing
those emissions by approximately 90 percent. Emissions of other toxic
metals, such as arsenic (As) and nickel (Ni), dioxins and furans, acid
gases (including hydrochloric acid (HCl) and SO2) will also
decrease dramatically with the installation of pollution controls. And
the flexibilities established in this rule along with other available
tools provide a clear pathway to compliance without jeopardizing the
country's energy supply.
This preamble explains EPA's appropriate and necessary finding, the
elements of the final rule, key changes the EPA is making in response
to comments submitted on the proposed rule, and our responses to many
of the comments we received. A full response to comments is provided in
the response to comments document available in the docket for this
rulemaking.
[[Page 9307]]
A. What is the statutory authority for this final rule?
Congress established a specific structure for determining whether
to regulate EGUs under CAA section 112.\1\ Specifically, Congress
enacted CAA section 112(n)(1).
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\1\ ``Electric utility steam generating unit'' is defined, in
part, as any ``fossil fuel fired combustion unit of more than 25
megawatts that serves a generator that produces electricity for
sale.'' See CAA section 112(a)(8).
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Section 112(n)(1)(A) of the CAA requires the EPA to conduct a study
to evaluate the remaining public health hazards that are reasonably
anticipated to occur as a result of EGUs' HAP emissions after
imposition of CAA requirements. The EPA must report the results of that
study to Congress, and regulate EGUs ``if the Administrator finds such
regulation is appropriate and necessary,'' after considering the
results of that study. Thus, CAA section 112(n)(1)(A) governs how the
Administrator decides whether to list EGUs for regulation under CAA
section 112. See New Jersey v. EPA, 517 F.3d 574 at 582 (D.C. Cir.
2008) (``Section 112(n)(1) governs how the Administrator decides
whether to list EGUs; it says nothing about delisting EGUs.'').
As directed, the EPA conducted the study to evaluate the remaining
public health hazards and reported the results to Congress (Utility
Study Report to Congress (Utility Study)).\2\ We discuss this study
below in conjunction with other studies that CAA section 112(n)(1)
requires concerning EGUs. See also 76 FR 24982-24984 (summarizing
studies).
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\2\ U.S. EPA. Study of Hazardous Air Pollutant Emissions from
Electric Utility Steam Generating Units--Final Report to Congress.
EPA-453/R-98-004a. February 1998.
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Once the EPA lists a source category pursuant to CAA section
112(c), the EPA must then establish technology-based emission standards
under CAA section 112(d). For major sources, the EPA must establish
emission standards that ``require the maximum degree of reduction in
emissions of the hazardous air pollutants subject to this section''
that the EPA determines are achievable taking into account certain
statutory factors. See CAA section 112(d)(2). These standards are
referred to as ``maximum achievable control technology'' or ``MACT''
standards. The MACT standards for existing sources must be at least as
stringent as the average emission limitation achieved by the best
performing 12 percent of existing sources in the category (for which
the Administrator has emissions information) or the best performing 5
sources for source categories with less than 30 sources. See CAA
section 112(d)(3)(A) and (B), respectively. This level of minimum
stringency is referred to as the ``MACT floor,'' and the EPA cannot
consider cost in setting the floor. For new sources, MACT standards
must be at least as stringent as the control level achieved in practice
by the best controlled similar source. See CAA section 112(d)(3).
The EPA also must consider more stringent ``beyond-the-floor''
control options. When considering beyond-the-floor options, the EPA
must consider the maximum degree of reduction in HAP emissions and take
into account costs, energy, and non-air quality health and
environmental impacts when doing so. See Cement Kiln Recycling Coal. v.
EPA, 255 F.3d 855, 857-58 (D.C. Cir. 2001).
Alternatively, the EPA may set a health-based standard for HAP that
have an established health threshold, and the standard must provide
``an ample margin of safety.'' See CAA section 112(d)(4). As these
standards could be less stringent than MACT standards, the Agency must
have detailed information on HAP emissions from the subject sources and
sources located near the subject sources before exercising its
discretion to set such standards.
For area sources, the EPA may issue standards or requirements that
provide for the use of generally available control technologies or
management practices (GACT standards) in lieu of promulgating MACT or
health-based standards. See CAA section 112(d)(5).
As noted above, CAA section 112(n) requires completion of various
reports concerning EGUs. For the first report, the Utility Study,
Congress required the EPA to evaluate the hazards to public health
reasonably anticipated to occur as the result of HAP emissions from
EGUs after imposition of the requirements of the CAA. See CAA section
112(n)(1)(A). The EPA was required to report results from this study to
Congress by November 15, 1993. Id. Congress also directed the EPA to
conduct ``a study of mercury emissions from [EGUs], municipal waste
combustion units, and other sources, including area sources'' (Mercury
Study). See CAA section 112(n)(1)(B). The EPA was required to report
the results from this study to Congress by November 15, 1994. Id. In
conducting this Mercury Study, Congress directed the EPA to ``consider
the rate and mass of such emissions, the health and environmental
effects of such emissions, technologies which are available to control
such emissions, and the costs of such technologies.'' Id. Congress
directed the National Institute of Environmental Health Sciences
(NIEHS) to conduct the last required evaluation, ``a study to determine
the threshold level of mercury exposure below which adverse human
health effects are not expected to occur'' (NIEHS Study). See CAA
section 112(n)(1)(C). The NIEHS was required to submit the results to
Congress by November 15, 1993. Id. In conducting this study, NIEHS was
to determine ``a threshold for mercury concentrations in the tissue of
fish which may be consumed (including consumption by sensitive
populations) without adverse effects to public health.'' Id.
In addition, Congress, in conference report language associated
with the EPA's fiscal year 1999 appropriations, directed the EPA to
fund the National Academy of Sciences (NAS) to perform an independent
evaluation of the available data related to the health impacts of
methylmercury (MeHg) (NAS Study or MeHg Study). H.R. Conf. Rep. No 105-
769, at 281-282 (1998). Specifically, Congress required NAS to advise
the EPA as to the appropriate reference dose (RfD) for MeHg. 65 FR
79826. The RfD is the amount of a chemical which, when ingested daily
over a lifetime, is anticipated to be without adverse health effects to
humans, including sensitive subpopulations. In the same conference
report, Congress indicated that the EPA should not make the appropriate
and necessary regulatory determination for Hg emissions until the EPA
had reviewed the results of the NAS Study. See H.R. Conf. Rep. No 105-
769, at 281-282 (1998).
As directed by Congress through different vehicles, the NAS Study
and the NIEHS Study evaluated the same issues. The NIEHS completed the
NIEHS Study in 1995,\3\ and the NAS completed the NAS Study in 2000.\4\
Because NAS completed its study 5 years after the NIEHS Study, and
considered additional information not earlier available to NIEHS, for
purposes of this document we discuss the content of the NAS Study as
opposed to the NIEHS Study.
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\3\ NIEHS Study, August 1995; EPA-HQ-OAR-2009-3053.
\4\ National Research Council (NAS). 2000. Toxicological Effects
of Methylmercury. Committee on the Toxicological Effects of
Methylmercury, Board on Environmental Studies and Toxicology,
National Research Council.
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The EPA conducted the studies required by CAA section 112(n)(1)
concerning utility HAP emissions, the Utility Study and the Mercury
Study,\5\ and completed both by 1998. Prior to issuance of the Mercury
Study, the EPA
[[Page 9308]]
engaged in two extensive external peer reviews of the document.
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\5\ Mercury Study Report to Congress, December 1997; EPA-HQ-OAR-
2009-0234-3054.
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On December 20, 2000, the EPA issued a finding pursuant to CAA
section 112(n)(1)(A) that it was appropriate and necessary to regulate
coal- and oil-fired EGUs under CAA section 112 and added such units to
the list of source categories subject to regulation under CAA section
112(d). In making that finding, the EPA considered the Utility Study,
the Mercury Study, the NAS Study, and certain additional information,
including information about Hg emissions from coal-fired EGUs that the
EPA obtained pursuant to an information collection request (ICR) under
the authority of CAA section 114. 65 FR 79826-27.
B. What is the litigation history of this final rule?
Shortly after issuance of the December 2000 finding, an industry
group challenged that finding in the Court of Appeals for the D.C.
Circuit (D.C. Circuit). Utility Air Regulatory Group (UARG) v. EPA,
2001 WL 936363, No. 01-1074 (D.C. Cir. July 26, 2001). The D.C. Circuit
dismissed the lawsuit holding that it did not have jurisdiction because
CAA section 112(e)(4) provides, in pertinent part, that ``no action of
the Administrator * * * listing a source category or subcategory under
subsection (c) of this section shall be a final agency action subject
to judicial review, except that any such action may be reviewed under
section 7607 of (the CAA) when the Administrator issues emission
standards for such pollutant or category.'' Id. (emphasis added).
Pursuant to a settlement agreement, the deadline for issuing
emission standards was March 15, 2005. However, instead of issuing
emission standards pursuant to CAA section 112(d), on March 29, 2005,
the EPA issued the Section 112(n) Revision Rule (2005 Action). That
action delisted EGUs after finding that it was neither appropriate nor
necessary to regulate such units under CAA section 112. In addition, on
May 18, 2005, the EPA issued the Clean Air Mercury Rule (CAMR). 70 FR
28606. That rule established standards of performance for emissions of
Hg from new and existing coal-fired EGUs pursuant to CAA section 111.
Environmental groups, states, and tribes challenged the 2005 Action
and CAMR. Among other things, the environmental and state petitioners
argued that the EPA could not remove EGUs from the CAA section 112(c)
source category list without following the requirements of CAA section
112(c)(9).
On February 8, 2008, the D.C. Circuit vacated both the 2005 Action
and CAMR. The D.C. Circuit held that the EPA failed to comply with the
requirements of CAA section 112(c)(9) for delisting source categories.
Specifically, the D.C. Circuit held that CAA section 112(c)(9) applies
to the removal of ``any source category'' from the CAA section 112(c)
list, including EGUs. The D.C. Circuit found that, by enacting CAA
section 112(c)(9), Congress limited the EPA's discretion to reverse
itself and remove source categories from the CAA section 112(c) list.
The D.C. Circuit found that the EPA's contrary position would ``nullify
Sec. 112(c)(9) altogether.'' New Jersey v. EPA, 517 F.3d 574, 583
(D.C. Cir. 2008). The D.C. Circuit did not reach the merits of
petitioners' arguments on CAMR, but vacated CAMR for existing sources
because coal-fired EGUs were already listed sources under CAA section
112. The D.C. Circuit reasoned that even under the EPA's own
interpretation of the CAA, regulation of existing sources' Hg emissions
under CAA section 111 was prohibited if those sources were a listed
source category under CAA section 112.\6\ Id. The D.C. Circuit vacated
and remanded CAMR for new sources because it concluded that the
assumptions the EPA made when issuing CAMR for new sources were no
longer accurate (i.e., that there would be no CAA section 112
regulation of EGUs and that the CAA section 111 standards would be
accompanied by standards for existing sources). Id. at 583-84. Thus,
CAMR and the 2005 Action became null and void.
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\6\ In CAMR and the 2005 Action, EPA interpreted section 111(d)
of the Act as prohibiting the Agency from establishing an existing
source standard of performance under CAA section 111(d) for any HAP
emitted from a particular source category, if the source category is
regulated under CAA section 112.
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On December 18, 2008, several environmental and public health
organizations filed a complaint in the U.S. District Court for the
District of Columbia.\7\ They alleged that the Agency had failed to
perform a nondiscretionary duty under CAA section 304(a)(2), by failing
to promulgate final CAA section 112(d) standards for HAP from coal- and
oil-fired EGUs by the statutorily-mandated deadline, December 20, 2002,
2 years after such sources were listed under CAA section 112(c). The
EPA settled that litigation. The consent decree resolving the case
requires the EPA to sign a notice of proposed rulemaking setting forth
the EPA's proposed CAA section 112(d) emission standards for coal- and
oil-fired EGUs by March 16, 2011, and a notice of final rulemaking by
December 16, 2011.\8\
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\7\ American Nurses Association, Chesapeake Bay Foundation,
Inc., Conservation Law Foundation, Environment America,
Environmental Defense Fund, Izaak Walton League of America, Natural
Resources Council of Maine, Natural Resources Defense Council,
Physicians for Social Responsibility, Sierra Club, The Ohio
Environmental Council, and Waterkeeper Alliance, Inc. (Civ. No.
1:08-cv-02198 (RMC)).
\8\ The consent decree originally required EPA to sign a notice
of final rulemaking no later than November 16, 2011; however, on
October 21, 2011, pursuant to paragraph 6 of the consent decree, the
parties agreed to a 30-day extension of the final rule deadline. As
stated in the stipulation memorializing the extension, the parties
agreed to the extension of 30 days because EPA provided an
additional 30 days for public comment and the time was necessary to
respond to comments submitted on the proposed rule.
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C. What is the relationship between this final rule and other
combustion rules?
1. CAA Section 111
The EPA promulgated revised NSPS for SO2, nitrogen
oxides (NOX), and PM under CAA section 111 for EGUs (40 CFR
part 60, subpart Da) and industrial boilers (IB) (40 CFR part 60,
subparts Db and Dc) on February 27, 2006 (71 FR 9866). As noted
elsewhere, in this action we are finalizing certain amendments to 40
CFR part 60, subpart Da. In developing this final rule, we considered
the monitoring, testing, and recordkeeping requirements of the existing
and revised NSPS to avoid duplicating requirements to the extent
possible.
2. CAA Section 112
The EPA has previously developed other non-EGU combustion-related
NESHAP under CAA section 112(d). The EPA promulgated final NESHAP for
major source industrial, commercial and institutional boilers and
process heaters (IB) and area source industrial, commercial and
institutional boilers on March 21, 2011 (40 CFR part 63, subpart DDDDD,
76 FR 15608; and subpart JJJJJJ, 76 FR 15249, respectively), and
promulgated standards for stationary combustion turbines (CT) on March
5, 2004 (40 CFR part 63 subpart YYYY; 69 FR 10512). In addition to
these three NESHAP, on March 21, 2011, the EPA also promulgated final
CAA section 129 standards for commercial and institutional solid waste
incineration (CISWI) units, including energy recovery units (40 CFR
part 60, subparts CCCC (NSPS) and DDDD (emission guidelines); 76 FR
15704); and a definition of non-hazardous secondary materials that are
solid waste (Non-hazardous Solid Waste Definition Rule (40 CFR part
241, subpart B; 76 FR 15456)). Electric generating units and IB
[[Page 9309]]
that combust fossil fuel and solid waste, as that term is defined by
the Administrator pursuant to the Resource Conservation and Recovery
Act (RCRA), see 76 FR 15456, will be subject to standards issued
pursuant to CAA section 129 (e.g., CISWI), unless they meet one of the
exemptions in CAA section 129(g)(1). Clean Air Act section 129
standards are discussed in more detail below.
The two IB (Boiler) NESHAP, the CT NESHAP, and this final rule will
regulate HAP emissions from sources that combust fossil fuels for
electrical power, process operations, or heating. The differences among
these rules are due to the size of the units (megawatt (MW), megawatt-
electric (MWe), or British thermal unit per hour (Btu/hr)), the boiler/
furnace technology, and/or the portion of their electrical output (if
any) for sale to any utility power distribution systems.
Pursuant to the CAA, an EGU is ``any fossil fuel fired combustion
unit of more than 25 megawatts that serves a generator that produces
electricity for sale. A unit that cogenerates steam and electricity and
supplies more than one-third of its potential electric output capacity
and more than 25 megawatts electrical output to any utility power
distribution system for sale shall be considered an electric utility
steam generating unit.'' CAA section 112(a)(8). We consider all of the
MW ratings quoted in the final rule to be the original rated nameplate
capacity of the unit. We consider cogeneration to be the simultaneous
production of power (electricity) and another form of useful thermal
energy (usually steam or hot water) from a single fuel-consuming
process.
We consider any combustion unit, regardless of size, that produces
steam to serve a generator that produces electricity exclusively for
industrial, commercial, or institutional purposes (i.e., makes no sales
to the national electrical distribution grid) to be an IB unit. We do
not consider a fossil fuel-fired combustion unit that serves a
generator that produces electricity for sale to be an EGU under the
final rule if the size of the combustion unit is less than or equal to
25 MW. Units that are 25 MW or less are likely subject to one of the
two Boiler NESHAP.
Because of the combustion technology of simple-cycle and combined-
cycle stationary CTs (with the exception of integrated gasification
combined cycle (IGCC) units that burn gasified coal or petroleum coke
synthesis gas/syngas), we do not consider these CTs to be EGUs for
purposes of this final rule.\9\
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\9\ The CT NESHAP regulates HAP emissions from all simple-cycle
and combined-cycle stationary CTs producing electricity or steam for
any purpose.
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The December 2000 listing discussed above did not list natural gas-
fired EGUs. Thus, this final rule does not regulate a unit that
otherwise meets the CAA section 112(a)(8) definition of an EGU but that
combusts natural gas exclusively or natural gas in combination with
another fossil fuel where the natural gas constitutes 90.0 percent or
more of the average annual heat input during any 3 consecutive calendar
years or 85.0 percent or more of the annual heat input in one calendar
year. We consider such units to be natural gas-fired EGUs
notwithstanding the combustion of some coal or oil (or derivative
thereof) and such units are not subject to this final rule.
The CAA does not define the terms ``fossil fuel-fired'' and
``fossil fuel.'' In this rule, we are finalizing definitions for both
terms for purposes of this rule. The definition of ``fossil fuel-
fired'' will help determine the applicability of the final rule to
combustion units that sell electricity to the utility power
distribution system. The definition of ``fossil fuel-fired''
establishes the amount of fossil fuel combustion necessary to make a
unit ``fossil fuel-fired'' and hence potentially subject to this final
rule. These definitions will help determine applicability of the final
rule to units that primarily fire non-fossil fuels (e.g., biomass) but
generally start up using either natural gas or distillate oil and may
use these fuels (or coal) during normal operation for flame
stabilization.
In addition, the EPA is finalizing in the definition of ``fossil
fuel-fired'' that, among other things, an EGU must fire coal or oil for
more than 10.0 percent of the average annual heat input during any 3
consecutive calendar years or for more than 15.0 percent of the annual
heat input during any one calendar year after the applicable compliance
date in order to be considered a fossil fuel-fired EGU subject to this
final rule. The EPA has based these threshold percentage values on the
definition of ``oil-fired'' in the Acid Rain Program (ARP) found at 40
CFR 72.2. Though the EPA does not have annual heat input data for, for
example, biomass co-fired EGUs because their use is not yet
commonplace, we believe this definition accounts for the use of fossil
fuels for flame stabilization use without inappropriately subjecting
such units to this final rule.
Units that do not meet the EGU definition will in most cases be
considered IB units subject to one of the two Boiler NESHAP. Thus, for
example, a biomass-fired EGU, regardless of size, that utilizes fossil
fuels for startup and flame stabilization purposes only (i.e., less
than or equal to 10.0 percent of the average annual heat input in any 3
consecutive calendar years or less than or equal to 15.0 percent of the
annual heat input during any one calendar year) is not considered to be
a fossil fuel-fired EGU under this final rule.
A cogeneration facility that sells electricity to any utility power
distribution system equal to more than one-third of its potential
electric output capacity and more than 25 MW will be considered an EGU
if the facility is fossil fuel-fired as that term is defined in the
final rule.
We recognize that different CAA section 112 rules may impact a
particular unit at different times. For example, the Boiler NESHAP may
cover some cogeneration units. Such a unit may decide to increase or
decrease the proportion of production output it supplies to the
electric utility grid, thus causing the unit to meet the EGU
cogeneration criteria (i.e., greater than one-third of its potential
output capacity and greater than 25 MW). A unit subject to one of the
Boiler NESHAP that increases its electricity output and meets the
definition of an EGU would be subject to the final EGU NESHAP.
Another rule intersection may occur where one or more coal- or oil-
fired EGU(s) share an air pollution control device (APCD) and/or an
exhaust stack with one or more similarly-fueled IB unit(s). To
demonstrate compliance with two different rules, either the emissions
would need to be apportioned to the appropriate source or the more
stringent emission limit would need to be met. Data needed to apportion
emissions are not currently required by this final rule or the final
boiler NESHAP and are not otherwise available. Therefore, the EPA is
finalizing the requirement to comply with the more stringent emission
limit.
3. CAA Section 129
Clean Air Act section 129 regulates units that combust ``non-
hazardous secondary materials,'' as that term is defined by the
Administrator under the Resource Conservation and Recovery Act (RCRA),
that are ``solid wastes.'' On March 21, 2011, the EPA promulgated the
final Non-Hazardous Solid Waste Definition Rule (76 FR 15456). Any EGU
that combusts any solid waste as defined in that final rule is a solid
waste
[[Page 9310]]
incineration unit subject to emissions standards under CAA section 129.
In the Non-Hazardous Solid Waste Definition Rule, the EPA
determined that coal refuse from current mining operations is not
considered to be a ``solid waste'' if it is not discarded. Coal refuse
that is in legacy coal refuse piles is considered a ``solid waste''
because it has been discarded. However, if discarded coal refuse is
processed in the same manner as currently mined coal refuse, the coal
refuse would not be considered a solid waste but instead would be
considered a product fossil fuel. Therefore, the combustion of such
material by a combustion unit would not subject that unit to regulation
under CAA section 129. Instead, the unit would be subject to this final
rule if it meets the definition of EGU. In the proposed rule, we
assumed that all units that combust coal refuse and otherwise meet the
definition of a coal-fired EGU are in fact combusting newly mined coal
refuse or coal refuse from legacy piles that has been processed such
that it is not a solid waste. We did not receive any information since
proposal that would cause us to revise this determination in the final
rule.
Further, CAA section 129(g)(1)(B) exempts from regulation
``* * * qualifying small power production facilities, as defined
in section 796(17)(C) of Title 16, or qualifying cogeneration
facilities, as defined in section 796(18)(B) of Title 16, which burn
homogeneous waste * * * for the production of electric energy or in
the case of qualifying cogeneration facilities which burn
homogeneous waste for the production of electric energy and steam or
forms of useful energy (such as heat) which are used for industrial,
commercial, heating or cooling purposes * * *''
If the ``homogeneous waste'' material that such facilities combust is
also a fossil fuel, and those facilities otherwise meet the definition
of an EGU under CAA section 112(a)(8), then those facilities are exempt
from regulation under CAA section 129 but covered under this final
rule. For example, a qualifying small power production facility or
cogeneration facility combusting only coal refuse that is a solid waste
and a ``homogenous waste,'' as that term is defined in the final CAA
section 129 CISWI standards, would be subject to this final rule if the
unit also met the definition of EGU.
D. What are the health effects of pollutants emitted from coal- and
oil-fired EGUs?
This final rule protects air quality and promotes public health by
reducing emissions of some of the HAP listed in CAA section 112(b)(1).
Utilities are by far the largest anthropogenic source of Hg in the U.S.
In addition, EGUs are the largest source of HCl, hydrogen fluoride
(HF), and selenium (Se) emissions, and a major source of metallic HAP
emissions including As, chromium (Cr), Ni, and others. The discrepancy
is even greater now that almost all other major source categories have
been required to control Hg and other HAP under CAA section 112. In
2005, U.S. EGUs emitted 50 percent of total domestic anthropogenic Hg
emissions, 62 percent of total As emissions, 39 percent of total
cadmium (Cd) emissions, 22 percent of total Cr emissions, 82 percent of
total HCl emissions, 62 percent of total HF emissions, 28 percent of
total Ni emissions, and 83 percent of total Se emissions.\10\ Exposure
to these HAP, depending on exposure duration and levels of exposures,
is associated with a variety of adverse health effects. These adverse
health effects may include chronic health disorders (e.g., irritation
of the lung, skin, and mucus membranes; detrimental effects on the
central nervous system; damage to the kidneys; and alimentary effects
such as nausea and vomiting). Two of the HAP are classified as human
carcinogens (As and CrVI) and two as probable human carcinogens (Cd and
Ni). See 76 FR 25003-25005 for a fuller discussion of the health
effects associated with these pollutants.
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\10\ From 2005 National-Scale Air Toxics Assessment (NATA),
available at https://www.epa.gov/ttn/atw/nata2005/.
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III. Appropriate and Necessary Finding
A. Overview
In December 2000, the EPA issued a finding pursuant to CAA section
112(n)(1)(A) that it was appropriate and necessary to regulate coal-
and oil-fired EGUs under CAA section 112 and added such units to the
list of source categories subject to regulation under section 112(d).
The EPA found that it was appropriate to regulate HAP emissions from
coal- and oil-fired EGUs because, among other reasons, Hg is a hazard
to public health, and U.S. EGUs are the largest domestic source of Hg
emissions. The EPA also found it appropriate to regulate HAP emissions
from EGUs because it had identified certain control options that would
effectively reduce HAP emissions from U.S. EGUs. The EPA found that it
was necessary to regulate HAP emissions from U.S. EGUs under section
112 because the implementation of other requirements under the CAA will
not adequately address the serious public health and environmental
hazards arising from HAP emissions from U.S. EGUs and that CAA section
112 is intended to address HAP emissions. See 76 FR 24984-20985 (for
further discussion of 2000 finding).
Because several years had passed since the 2000 finding, the EPA
performed additional technical analyses for the proposed rule, even
though those analyses were not required. These analyses included a
national-scale Hg risk assessment focused on populations with high
levels of self-caught fish consumption, and a set of 16 case studies of
inhalation cancer risks for non-Hg HAP. The analyses confirm that it
remains appropriate and necessary to regulate U.S. EGUs under section
112.
In the preamble to the proposed rule, the EPA reported the results
of those additional technical analyses. Those analyses confirmed the
2000 finding that it is appropriate to regulate U.S. EGUs under section
112 by demonstrating that (1) Hg continues to pose a hazard to public
health because up to 28 percent of watersheds were estimated to have Hg
deposition attributable to U.S. EGUs that contributes to potential
exposures above the reference dose for methylmercury (MeHg RfD), a
level above which there is increased risk of neurological effects in
children, (2) non-Hg HAP emissions pose a hazard to public health
because case studies at 16 facilities demonstrated that lifetime cancer
risks at 4 of the facilities exceed 1 in 1 million, and (3) U.S. EGUs
remain the largest domestic source of Hg emissions and several HAP
(e.g., HF, Se, HCl), and are among the largest contributors for other
HAP (e.g., As, Cr, Ni, HCN). Thus, in the preamble to the proposed
rule, the EPA found that Hg and non-Hg HAP emissions from U.S. EGUs
pose hazards to public health, which confirmed the 2000 finding and
demonstrated that it remains appropriate to regulate U.S. EGUs under
section 112.
In the preamble to the proposed rule, the EPA also found that it is
appropriate to regulate U.S. EGUs because (1) Hg emissions pose a
hazard to the environment and wildlife, adversely impacting species of
fish-eating birds and mammals, (2) acid gas HAP pose a hazard to the
environment because they contribute to aquatic acidification, and (3)
effective controls are available to reduce Hg and non-Hg HAP emissions
from U.S. EGUs.
The additional analyses reported in the preamble to the proposed
rule also confirmed that it remains necessary to regulate U.S. EGU
under CAA section 112. These analyses demonstrated that (1) Hg
emissions from U.S. EGUs remaining in 2016 are reasonably anticipated
to pose a hazard to public health after imposition of other CAA
[[Page 9311]]
requirements, such as the Cross-State Air Pollution Rule (CSAPR); (2)
U.S. EGUs are reasonably anticipated to remain the largest source of Hg
in the U.S. and thus contribute to the risk associated with exposure to
MeHg; (3) Hg emissions from U.S. EGUs after imposition of the
requirements of the CAA were projected to be 29 tons per year in 2016,
similar to levels of Hg emitted today, indicating that further
substantial reductions in Hg emissions are not reasonably anticipated
without federal regulations on Hg from U.S. EGUs; (4) we cannot be
certain that the identified cancer risks attributable to non-Hg
emissions from U.S. EGUs will be addressed through imposition of the
requirements of the CAA because companies can use compliance strategies
for criteria pollutants that do not achieve HAP co-benefits (e.g.,
purchasing allowances in a trading program); and (5) we cannot ensure
that Hg and non-Hg HAP emissions reductions achieved since 2005 would
be permanent without federally binding regulations for Hg from U.S.
EGUs.
Since issuance of the proposed rule, the EPA has conducted peer
reviews of the national-scale Hg risk assessment (Hg Risk TSD) and the
approach for estimating chromium and nickel inhalation cancer risk in
the case studies.11 12 The peer review of the Hg Risk TSD
was conducted by EPA's independent Science Advisory Board (SAB). The
SAB stated that it ``supports the overall design of and approach to the
risk assessment and finds that it should provide an objective,
reasonable, and credible determination of the potential for a public
health hazard from mercury emitted from U.S. EGUs.'' \13\ SAB
recommended several improvements to the data, methods and documentation
of the analyses, which EPA has fully addressed in the revised Hg Risk
TSD.
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\11\ U.S. EPA. 2011a. National-Scale Assessment of Mercury Risk
to Populations with High Consumption of Self-caught Freshwater Fish
In Support of the Appropriate and Necessary Finding for Coal- and
Oil-Fired Electric Generating Units. Office of Air Quality Planning
and Standards. November. EPA-452/R-11-009.
\12\ U.S. EPA. 2011b. Supplement to Non-mercury Case Study
Chronic Inhalation Risk Assessment for the Utility MACT Appropriate
and Necessary Analysis. Office of Air Quality Planning and
Standards. November.
\13\ U.S. Environmental Protection Agency-Science Advisory Board
(U.S. EPA-SAB). 2011. Peer Review of EPA's Draft National-Scale
Mercury Risk Assessment. EPA-SAB-11-017. September. Available on the
Internet at https://yosemite.epa.gov/sab/sabproduct.nsf/
BCA23C5B7917F5BF8525791A0072CCA1/$File/EPA-SAB-11-017-unsigned.pdf.
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As described in the revised Hg Risk TSD, after addressing comments
from the peer review, the revised results show that up to 29 percent of
modeled watersheds are estimated to have Hg deposition attributable to
U.S. EGUs that contributes to potential exposures above the MeHg RfD,
an increase of one percentage point from the results reported in the
proposed rule. We conclude that Hg emissions from EGUs pose a hazard to
public health based on the total of 29 percent of modeled watersheds at
risk. Our analyses show that of the 29 percent of watersheds with
population at-risk, in 10 percent of those watersheds U.S. EGU
deposition alone without considering deposition from other sources
would lead to potential exposures that exceed the MeHg RfD, and in 24
percent of those watersheds, total potential exposures to MeHg exceed
the RfD and U.S. EGUs contribute at least 5 percent to Hg
deposition.14 15 Each of these results independently
supports our conclusion that Hg emissions from EGUs pose hazards to
public health.
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\14\ Because some watersheds with exposures sufficient to exceed
the RfD with Hg deposition from U.S. EGUs alone without considering
deposition from other sources also have U.S. EGU contributions of
more than 5 percent of total Hg deposition, there is some overlap
between the two risk metrics. This explains why the total percent of
watersheds exceeding either risk metric is less than the sum of the
individual risk metrics.
\15\ Requiring at least a 5 percent EGU contribution is a
conservative approach given the increasing risks associated with
incremental exposures above the RfD. Because we are finding 24
percent of watersheds with populations potentially at risk even
using this conservative approach, we have confidence that emissions
of Hg from U.S. EGUs are causing a hazard to public health.
---------------------------------------------------------------------------
The peer review of the approach to estimate Ni and Cr cancer risk
in the case studies also supported EPA's assessment. The EPA enhanced
this analysis in response to the peer review and public comments. The
results of those revised analyses show that 6 of 16 modeled facilities
have lifetime cancer risks greater than 1 in a million, thus confirming
that non-Hg HAP emissions from U.S. EGUs remain a hazard to public
health. Given Congress' determination that categories of sources that
emit HAP resulting in a lifetime cancer risk greater than 1 in a
million should not be removed from the CAA section 112(c) source
category list and should continue to be regulated under CAA section
112, the EPA concludes that risk above that level represents a hazard
to public health.
Based on our consideration of the peer reviews, public comments,
and our updated analyses, we confirm the findings that Hg and non-Hg
HAP emissions from U.S. EGUs pose hazards to public health and that it
remains appropriate to regulate U.S. EGUs under CAA section 112. We
also conclude that it remains appropriate to regulate U.S. EGUs under
CAA section 112 because of the magnitude of Hg and non-Hg emissions,
environmental effects of Hg and certain non-Hg emissions, and the
availability of controls to reduce HAP emissions from EGUs.
In addition, we conclude that the hazards to public health from Hg
and non-Hg emissions from U.S. EGUs are reasonably anticipated to
remain after imposition of the requirements of the CAA. The same is
true for hazards to the environment. Thus, we confirm that it is
necessary to regulate U.S. EGUs under CAA section 112.
B. Peer Review of the Hg Risk TSD Supporting the Appropriate and
Necessary Finding for Coal and Oil-Fired EGUs and EPA Response
In the preamble to the proposed rule, the EPA stated that ``in
making the finding that it remains appropriate and necessary to
regulate EGUs to address public health and environmental hazards
associated with emissions of Hg and Non-Hg HAP from EGUs, the EPA
determined that the Hg Risk TSD supporting EPA's 2011 review of U.S.
EGU health impacts should be peer-reviewed.'' \16\ We also indicated
that due to the court-ordered schedule for the final rule, we planned
to conduct the peer review as expeditiously as possible after issuance
of the proposed rule, and that the results of the peer review and any
EPA response would be published before the final rule. Due to the
extension of the public comment period and the volume of public
comments received on the analyses supporting the proposed rule, we were
unable to publish EPA's response prior to signature of the final rule.
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\16\ 76 FR 25012.
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The EPA's response to the peer review the Hg Risk TSD is fully
documented in the revised Technical Support Document (TSD): National-
Scale Assessment of Hg Risk to Populations of High Consumption of Self-
Caught Fish In Support of the Appropriate and Necessary Finding for
Coal and Oil-Fired Electric Generating Units.\17\ The following
sections describe the peer review process that we followed, provide the
peer review charge questions presented to the peer review panel,
summarize the key recommendations from the peer review, and summarize
our responses to those recommendations.
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\17\ U.S. EPA, 2011a.
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[[Page 9312]]
1. Summary of Peer Review Process
Peer review is consistent with EPA's open and transparent process
to ensure that the Agency's scientific assessments and rulemakings are
based on the best science available. This regulatory action was
supported by the Hg Risk TSD, which is a highly influential scientific
assessment. Therefore, the EPA conducted a peer review in accordance
with OMB's Final Information Quality Bulletin for Peer Review \18\ as
described below. All the materials related to the peer review,
including the SAB's final report, can be found in the docket for this
rulemaking.
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\18\ Office of Management and Budget (OMB). 2004. Final
Information Quality Bulletin for Peer Review. December. Available on
the Internet at https://www.whitehouse.gov/omb/memoranda_fy2005_m05-03.
---------------------------------------------------------------------------
The EPA commissioned the peer review through EPA's SAB, which
provides independent advice and peer review to EPA's Administrator on
the scientific and technical aspects of environmental issues. The SAB
convened a 22-member peer review committee. The SAB process for
selecting the panel began with two Federal Register Notices requesting
nominations for the Mercury Review Panel.\19\ Based on nominations
received, a list of potential panel members, along with bio-sketches,
was posted for public comment on the SAB Web site on April 15, 2011.
The members of the Mercury Review Panel were announced on May 24, 2011.
The membership of the panel included representatives of 16 academic
institutions, 4 state health or environmental agencies, 1 federal
agency, and 1 utility industry organization.\20\ The panel held a
public meeting in Research Triangle Park, NC, on June 15-17, 2011,
which included the opportunity for public comment on the Hg Risk TSD
and the peer review process.\21\ At the June 15-17 public meeting, the
panel completed a draft peer review report. The minutes of that meeting
and the draft peer review report were posted to the SAB public Web site
within the public comment period for the proposed rule. The panel
discussed the draft report at a public teleconference on July 12, 2011,
during which additional opportunities for public comment were
provided,\22\ and submitted a revised draft for quality review by the
Chartered SAB before the end of the public comment period on the rule.
The Chartered SAB held a public teleconference on September 7, 2011, to
conduct a quality review of the draft report; this teleconference also
included a final opportunity for public comment.\23\ The SAB submitted
its final report to EPA on September 29, 2011.\24\ Notice of all the
meetings was published in the Federal Register and all of the materials
discussed at the SAB meetings, including technical documents,
presentations, meeting minutes, and draft reports were posted for
public access on the SAB Web site \25\ and were added to the docket for
the final rule on October 14, 2011.
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\19\ 76 FR 10896 and 76 FR 17649. The first notice requested
nominations to a Clean Air Scientific Advisory Committee (CASAC)
panel. Upon review of the scope of the CASAC charter (resulting from
a public comment received in response to the first notice), the SAB
determined that it would be more appropriate to form a panel under
the SAB, rather than CASAC. The second notice announced this change
and requested nominations for the SAB panel.
\20\ The full list of panel members is documented at https://
yosemite.epa.gov/sab/sabproduct.nsf/0/
9F048172004D93BB8525783900503486/$File/
Determination%20memo%20with%20addendum-05.24.11.pdf.
\21\ 76 FR 29746.
\22\ 76 FR 39102.
\23\ 76 FR 50729.
\24\ U.S. EPA-SAB, 2011. Peer Review of EPA's Draft National-
Scale Mercury Risk Assessment.
\25\ See https://yosemite.epa.gov/sab/sabpeople.nsf/WebCommittees/BOARD.
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2. Peer Review Charge Questions
The EPA asked the SAB to comment on the Hg Risk TSD, including the
overall design and approach and the use of specific models and key
assumptions. The EPA also asked the SAB to comment on the extent to
which specific facets of the assessment were well characterized in the
Hg Risk TSD. The specific charge questions are listed below:
Question 1. Please comment on the scientific credibility of the
overall design of the mercury risk assessment as an approach to
characterize human health exposure and risk associated with U.S. EGU
mercury emissions (with a focus on those more highly exposed).
Question 2. Are there any additional critical health endpoint(s)
besides IQ loss, which could be quantitatively estimated with a
reasonable degree of confidence to supplement the mercury risk
assessment (see section 1.2 of the Mercury Risk TSD for an overview of
the risk metrics used in the risk assessment)?
Question 3. Please comment on the benchmark used for identifying a
potentially significant public health impact in the context of
interpreting the IQ loss risk metric (i.e., an IQ loss of 1 to 2 points
or more representing a potential public health hazard). Is there any
scientifically credible alternate decrement in IQ that should be
considered as a benchmark to guide interpretation of the IQ risk
estimates (see section 1.2 of the Mercury Risk TSD for additional
detail on the benchmark used for interpreting the IQ loss estimates)?
Question 4: Please comment on the spatial scale used in defining
watersheds that formed the basis for risk estimates generated for the
analysis (i.e., use of 12-digit hydrologic unit code classification).
To what extent do [Hydrologic Unit Code] HUC12 watersheds capture the
appropriate level of spatial resolution in the relationship between
changes in mercury deposition and changes in MeHg fish tissue levels?
(see section 1.3 and Appendix A of the Mercury Risk TSD for additional
detail on specifying the spatial scale of watersheds used in the
analysis).
Question 5: Please comment on the extent to which the fish tissue
data used as the basis for the risk assessment are appropriate and
sufficient given the goals of the analysis. Please comment on the
extent to which focusing on data from the period after 1999 increases
confidence that the fish tissue data used are more likely to reflect
more contemporaneous patterns of Hg deposition and less likely to
reflect earlier patterns of Hg deposition. Are there any additional
sources of fish tissue MeHg data that would be appropriate for
inclusion in the risk assessment?
Question 6: Given the stated goal of estimating potential risks to
highly exposed populations, please comment on the use of the 75th
percentile fish tissue MeHg value (reflecting targeting of larger but
not the largest fish for subsistence consumption) as the basis for
estimating risk at each watershed. Are there scientifically credible
alternatives to use of the 75th percentile in representing potential
population exposures at the watershed level?
Question 7: Please comment on the extent to which characterization
of consumption rates and the potential location for fishing activity
for high-end self-caught fish consuming populations modeled in the
analysis are supported by the available study data cited in the Mercury
Risk TSD. In addition, please comment on the extent to which
consumption rates documented in Section 1.3 and in Appendix C of the
Mercury Risk TSD provide appropriate representation of high-end fish
consumption by the subsistence population scenarios used in modeling
exposures and risk. Are there additional data on consumption behavior
in subsistence populations active at inland freshwater water bodies
within the continental U.S.?
Question 8: Please comment on the approach used in the risk
assessment of
[[Page 9313]]
assuming that a high-end fish consuming population could be active at a
watershed if the ``source population'' for that fishing population is
associated with that watershed (e.g., at least 25 individuals of that
population are present in a U.S. Census tract intersecting that
watershed). Please identify any additional alternative approaches for
identifying the potential for population exposures in watersheds and
the strengths and limitations associated with these alternative
approaches (additional detail on how EPA assessed where specific high-
consuming fisher populations might be active is provided in section 1.3
and Appendix C of the Mercury Risk TSD).
Question 9: Please comment on the draft risk assessment's
characterization of the limitations and uncertainty associated with
application of the Mercury Maps approach (including the assumption of
proportionality between changes in mercury deposition over watersheds
and associated changes in fish tissue MeHg levels) in the risk
assessment. Please comment on how the output of CMAQ [Community
Multiscale Air Quality] modeling has been integrated into the analysis
to estimate changes in fish tissue MeHg levels and in the exposures and
risks associated with the EGU-related fish tissue MeHg fraction (e.g.,
matching of spatial and temporal resolution between CMAQ modeling and
HUC12 watersheds). Given the national scale of the analysis, are there
recommended alternatives to the Mercury Maps approach that could have
been used to link modeled estimates of mercury deposition to monitored
MeHg fish tissue levels for all the watersheds evaluated? (additional
detail on the Mercury Maps approach and its application in the risk
assessment is presented in section 1.3 and Appendix E of the Mercury
Risk TSD).
Question 10: Please comment on the EPA's approach of excluding
watersheds with significant non-air loadings of mercury as a method to
reduce uncertainty associated with application of the Mercury Maps
approach. Are there additional criteria that should be considered in
including or excluding watersheds?
Question 11: Please comment on the specification of the
concentration-response function used in modeling IQ loss. Please
comment on whether EPA, as part of uncertainty characterization, should
consider alternative concentration-response functions in addition to
the model used in the risk assessment. Please comment on the extent to
which available data and methods support a quantitative treatment of
the potential masking effect of fish nutrients (e.g., omega-3 fatty
acids and selenium) on the adverse neurological effects associated with
mercury exposure, including IQ loss (detail on the concentration-
response function used in modeling IQ loss can be found in section 1.3
of the Mercury Risk TSD).
Question 12: Please comment on the degree to which key sources of
uncertainty and variability associated with the risk assessment have
been identified and the degree to which they are sufficiently
characterized.
Question 13: Please comment on the draft Mercury Risk TSD's
discussion of analytical results for each component of the analysis.
For each of the components below, please comment on the extent to which
EPA's observations are supported by the analytical results presented
and whether there is a sufficient characterization of uncertainty,
variability, and data limitations, taking into account the models and
data used: Mercury deposition from U.S. EGUs, fish tissue MeHg
concentrations, patterns of Hg deposition with HG fish tissue data,
percentile risk estimates, and number and frequency of watersheds with
populations potentially at risk due to U.S. EGU mercury emissions.
Question 14: Please comment on the degree to which the final
summary of key observations in Section 2.8 is supported by the
analytical results presented. In addition, please comment on the degree
to which the level of confidence and precision in the overall analysis
is sufficient to support use of the risk characterization framework
described on page 18.
3. Summary of Peer Review Findings and Recommendations
The SAB was generally supportive of EPA's approach.\26\ The SAB
concluded, ``[i]n summary, based on its review of the draft Technical
Support Document and additional information provided by EPA
representatives during the public meetings, the SAB supports the
overall design of and approach to the risk assessment and finds that it
should provide an objective, reasonable, and credible determination of
the potential for a public health hazard from mercury emitted from U.S.
EGUs.'' \27\ The SAB further concluded, ``[t]he SAB regards the design
of the risk assessment as suitable for its intended purpose, to inform
decision-making regarding an `appropriate and necessary finding' for
regulation of hazardous air pollutants from coal and oil-fired EGUs,
provided that our recommendations are fully considered in the revision
of the assessment.'' \28\
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\26\ U.S. EPA-SAB, 2011.
\27\ Id.
\28\ Id.
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The SAB report contained many recommendations for improving the Hg
Risk TSD, which the SAB organized into three general themes: (1)
Improve the clarity of the Hg Risk TSD regarding methods and
presentation of results, (2) expand the discussion of sources of
variability and uncertainty, and (3) de-emphasize IQ loss as an
endpoint. In the following subsection, we provide EPA's response to
these recommendations.
4. The EPA's Responses to Peer Review Recommendations
In response to the peer review, the EPA has substantially revised
the Hg Risk TSD. The revised Hg Risk TSD addresses all of the
recommendations from the SAB and includes a detailed list of the
specific revisions made to the Hg Risk TSD. Revisions in response to
the main recommendations are summarized below. Italicized statements
are the SAB's recommendations, which are followed by EPA's response.
The watershed-focus of the Hg Risk TSD should be clearly
stated early in the introduction to the document. We have stated
clearly in the introduction to the revised Hg Risk TSD that the focus
of the analysis is on scenarios of high fish consumption by subsistence
level fishing populations, assessed at watersheds where there is the
potential for such subsistence fishing activity. Specifically, we
modeled risk for a set of subsistence fisher scenarios at those
watersheds where (a) we have measured fish tissue Hg data and (b) it is
reasonable to assume that subsistence-level fishing activity could
occur. We emphasize the point that the analysis is not a representative
population-weighted assessment of risk. Rather, it is based on
evaluating these potential exposure scenarios.
Because IQ does not fully capture the range of
neurodevelopmental effects associated with Hg exposure, analysis of
this endpoint should be deemphasized (and moved to an appendix) and
primary focus should be placed on the MeHg RfD-based hazard quotient
metric. We modified the structure of the revised Hg Risk TSD
accordingly.
Clarify the rationale for using a Hazard Quotient (HQ) at
or above 1.5 as the basis for selecting potentially impacted
watersheds. The SAB fully supported using HQ as the risk metric, but we
revised the discussion in the Hg Risk TSD to clarify why we selected
1.5
[[Page 9314]]
as the benchmark. We clarified that exposures above the RfD (i.e., an
HQ above one) represent increasing risk of neurological health
effects.\29\ We further clarified that the HQ is calculated to only one
significant digit, based on the precision in the underlying RfD
calculations. As a result, rounding convention requires that any values
at or above 1.5 be expressed as an HQ of 2, while any values below 1.5
(e.g., 1.49) be rounded to an HQ of 1. Thus, MeHg exposures leading to
an HQ at or above 1.5 for pregnant women are considered above the RfD
and are associated with increased risk of neurological health effects
in children born to those mothers.
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\29\ As stated in the preamble to the proposal, based on the
current literature, exposures above the RfD contribute to risk of
adverse effects.
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Regarding the fish tissue dataset used in the Hg Risk TSD,
clarify which species of Hg is reflected in the underlying samples and
discuss the implications of differences across states in sampling
protocols in introducing bias into the analysis. We clarified that in
most cases, the fish tissue is measured for total Hg. Furthermore,
based on the scientific literature,\30\ it is reasonable to assume that
more than 90 percent of fish tissue Hg is MeHg. Therefore, we
incorporated an Hg conversion factor \31\ into our exposure
calculations to account for the fraction of total Hg that is MeHg in
fish. We also expanded the discussion of uncertainty to address the
potential for different sampling protocols across states to introduce
bias into the Hg Risk TSD.
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\30\ See the literature summary in Chapter 4 of U.S. EPA. 2000.
Guidance for Assessing Chemical Contaminant Data for Use in Fish
Advisories. Office of Science and Technology, Office of Water,
Washington, DC EPA 823-B-00-007.
\31\ In the Hg Risk TSD accompanying the proposed rule, we
assumed that 100 percent of Hg in fish was MeHg. We derived the 0.95
conversion factor for the revised Hg Risk TSD to reflect that most
studies show that more than 90 percent of total Hg in fish is MeHg.
See Chapter 4 of U.S. EPA, 2000.
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Additional detail should be provided on the
characteristics of the fish tissue Hg dataset, including its derivation
and the distribution of specific attributes across the dataset (e.g.,
number of fish tissue samples and number of different waterbodies in a
watershed, number of species reflected across watersheds). We included
additional figures and tables describing the derivation of the
watershed-level fish tissue Hg dataset, including the filtering steps
applied to the original water body level data and the additional steps
taken to generate the watershed-level fish tissue Hg percentile
estimates. In addition, we included tables summarizing key attributes
of the dataset (e.g., distribution of fish tissue sample size and
number of species across the watershed-level estimates).
Determine whether there is additional (more recent) fish
tissue data for key states including Pennsylvania, New Jersey, Kentucky
and Illinois where U.S. EGUs Hg deposition may be more significant. We
expanded the fish tissue dataset by incorporating additional fish
tissue data from the National Listing of Fish Advisories (NLFA), which
included additional data for four states (MI, NJ, PA, and MN). We also
obtained additional data for Wisconsin. These additional data expanded
the number of watersheds in the analysis from 2,317 to 3,141, an
increase of 36 percent. The additional watersheds improve coverage in
areas with high levels of U.S. EGU-attributable Hg deposition, and thus
increase our confidence in the overall results of the Hg Risk TSD.
Include additional discussion of the potential that the
low sampling rates reflected across many of the watersheds may low-bias
the 75th percentile fish tissue Hg estimates used in estimating
potential exposures. In addition, include a sensitivity analysis using
the 50th percentile estimates to provide a bound on the risk. The SAB
expressed support for the use of the 75th percentile fish tissue Hg
value in the Hg Risk TSD, while recommending additional discussion of
the issue. We provided additional description of the fish tissue
dataset, including distribution of sample sizes and fish species across
the watersheds, and an improved discussion of uncertainty and potential
low bias resulting from estimation of the 75th percentile fish tissue
levels. We also included a sensitivity analysis that used the 50th
percentile watershed-level fish tissue Hg level. This sensitivity
analysis showed that using the 50th percentile estimates resulted in a
decrease in the number and percentage of modeled watersheds with
populations potentially at-risk from U.S. EGU-attributable MeHg
exposures, from 29 percent of watersheds exceeding either risk metric
(i.e., MeHg exposure from U.S. EGUs alone exceeds the RfD or total MeHg
exposure exceeds the RfD and U.S. EGUs contribute at least 5 percent)
in the revised Hg Risk TSD to 26 percent in the sensitivity analysis in
the revised Hg Risk TSD.
Expand the discussion of caveats associated with the fish
consumption rates used in the analysis. The SAB was generally
supportive of the consumption rates used, while recommending additional
discussion of caveats. We expanded the discussion of uncertainty
related to the fish consumption rates to address the caveats identified
by the SAB. The uncertainty discussion now explains (1) that high-end
consumption rates for South Carolina reflect small sample sizes, and
therefore may be more uncertain, (2) that the consumption surveys
underlying the studies are older (i.e., mostly based on survey data
from the 1990s) and behavior may have changed (i.e., consumption rates
may have changed since the surveys were conducted), and (3) that
consumption rates used in the Hg Risk TSD are annualized rather than
seasonal rates and thus contribute little to overall uncertainty. None
of these sources of uncertainty is associated with a particular
directional bias (e.g., neither systematically higher nor lower risk).
Verify whether the consumption rates are daily values
expressed as annual averages and whether they are ``as caught'' or ``as
prepared.'' We carefully reviewed the studies underlying the fish
consumption rates used in the Hg Risk TSD and verified that the rates
are annual averages of the daily consumption rates and that they
represent as prepared estimates. We also expanded the explanation of
the exposure calculations to describe more completely the exposure
factors and equation used to generate the average daily MeHg intake
estimates for the subsistence scenarios.
Explain the criteria for exclusion of fish less than 7
inches in length from analysis. We provided the rationale for the 7-
inch cutoff for edible fish used in the Hg Risk TSD. Seven inches
represents a minimum size limit for a number of key edible freshwater
fish species established at the state level. For example, Pennsylvania
establishes 7 inches as the minimum size limit for both trout and
salmon (other edible fish species such as bass, walleye and northern
pike have higher minimum size limits). The impact of the 7-inch cutoff
is likely to be quite small, as only 6 percent of potential fish
samples were excluded due to this criterion.
Identify the number of watersheds excluded from the
analysis due to the criterion for excluding watersheds with less than
25 members of a source population. The SAB was generally supportive of
the approach used for identifying watersheds with the potential for
subsistence activity, while recommending additional information on the
results of applying the approach. We added a figure to illustrate the
number of watersheds with fish tissue Hg data used to model risk for
each of the subsistence fishing scenarios. For all scenarios except the
female subsistence fishing scenario, the exposure scenarios
significantly limited the number of
[[Page 9315]]
watersheds. Because the female subsistence fishing scenario does not
differentiate with regard to ethnicity or socio-economic status (SES),
we applied this scenario to all regions of the country and to all
watersheds with fish tissue Hg data. This reflects our assumption that,
given the generalized nature of the female subsistence fishing
scenario, it is reasonable to assume that it could potentially occur at
any watershed with fish tissue Hg data. The female subsistence fishing
scenario included in the revised risk assessment is similar to the
high-consuming female scenario included in the Hg Risk TSD.\32\
However, the female subsistence fishing scenario is applied to all
watersheds, while in the scenario for the high-consuming low-income
female angler, we only evaluated watersheds with a population of at
least 25 low-income females. The female subsistence fishing scenario
provides greater coverage geographically than the high-consuming low-
income female scenario. As described in the revised Hg Risk TSD, the
EPA made this change in response to SAB's concerns regarding the
potential exclusion of watersheds with fewer than 25 individuals and
regarding coverage for high-end recreational fish consumption.\33\
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\32\ In the Revised Hg Risk TSD, this population is also
referred to as the ``typical female subsistence consumer.''
\33\ This change led to a very small increase in the number of
watersheds with populations potentially at-risk. In the Hg Risk TSD
accompanying the proposed rule, approximately 4 percent of modeled
watersheds were excluded based on the SES-based filtering criteria.
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Enhance the discussion of the assumption of a linear
relationship between changes in Hg deposition and changes in fish
tissue Hg at the watershed level, including providing citations to more
recent studies supporting the proportional relationship between changes
in Hg deposition and changes in MeHg fish tissue levels. The SAB
supported the assumption of a linear relationship between changes in Hg
deposition and changes in fish tissue Hg at the watershed level, while
recommending additional supporting language. We expanded our discussion
of the scientific basis for the proportionality assumption and added
citations for the more recent studies supporting the assumption. We
also expanded the discussion of uncertainties associated with this
assumption, including uncertainties related to the potential for
sampled fish tissue Hg level to reflect previous Hg deposition, and the
potential for non-air sources of Hg to contribute to sampled fish
tissue Hg levels. Each of these sources of uncertainty may result in
potential bias in the estimate of exposure associated with current
deposition. If the fish tissue Hg levels are too high due to either
previous Hg deposition or non-air sources of Hg, then the absolute
level of exposure attributed to both total Hg deposition and U.S. EGU-
attributable Hg deposition will be biased high. However, the percent
contribution from U.S. EGUs will not be affected as it depends entirely
on deposition. The EPA took steps to minimize the potential for these
biases by (1) only using fish tissue Hg samples from after 1999, and
(2) screening out watersheds that either contained active gold mines or
had other substantial non-U.S. EGU anthropogenic emissions of Hg. The
SAB concluded that the EPA's approach to minimizing the potential for
these biases to affect the results of the Hg Risk TSD is sound. In
addition, we conducted several sensitivity analyses to gauge the impact
of excluding watersheds with the potential for non-EGU Hg loading. We
found that the estimates of the percent of modeled watersheds with
populations potentially at-risk were largely insensitive to these
exclusions, suggesting that any potential biases from including
watersheds with potential non-air Hg loadings are likely to be small.
Additional sources of variability should be discussed in
terms of the degree to which they are reflected in the design of the
risk assessment and the impact that they might have on risk estimates.
These include: (1) The geographic patterns of populations of
subsistence fishers, including how this factor interacts with the
limited coverage we have for watersheds with our fish tissue Hg data,
(2) the protocols used by states in collecting fish tissue Hg data, (3)
body weights for subsistence fishing populations and the impact that
this might have on exposure estimates, and (4) preparation and cooking
methods which affect the conversion of fish tissue Hg levels (as
measured) into ``as consumed'' values. We expanded the discussion of
sources of variability in the revised Hg Risk TSD to more fully address
these sources of variability. The Hg Risk TSD quantitatively reflected
many aspects of variability, including spatial and temporal variability
in Hg emissions, Hg deposition, fish tissue Hg levels, and subsistence
behavior. After evaluating the aspects of variability assessed
qualitatively in the Hg Risk TSD such as temporal response in fish
tissue, we do not believe that quantitatively incorporating any of
these aspects would substantially change the risk results given the
stated goal of the analysis to identify watersheds where potential
exposures to MeHg from self-caught fish consumption could exceed the
RfD.
Additional sources of uncertainty should be discussed in
terms of their potential impact on risk estimates. These include: (1)
Emissions inventory used in projecting total and U.S. EGU-attributable
Hg deposition, including the projection of reductions in U.S. EGU
emissions for the 2016 scenario, (2) air quality modeling with CMAQ
including the prediction of future air quality scenarios, (3) ability
of the Mercury Maps-based approach for relating Hg deposition to MeHg
in fish to capture Hg hotspots, (4) the limited coverage that we have
with fish tissue Hg data for watersheds in the U.S. and implications
for the Hg Risk TSD, (5) the preparation factor used to estimate ``as
consumed'' fish tissue Hg levels, (6) the proportionality assumption
used to relate changes in Hg deposition to changes in fish tissue Hg
levels at the watershed-level, (7) characterization of the spatial
location of subsistence fisher populations (including the degree to
which these provide coverage for high-consuming recreational fishers),
and (8) application of the RfD to low SES populations and concerns that
this could low-bias the risk estimates. We expanded the discussion of
sources of uncertainty presented in the revised TSD to address more
fully these sources of uncertainty and the potential impact on risk
estimates. Regarding these eight additional sources of uncertainty, we
have (1) evaluated the uncertainties in the emissions and determined
that while an important source of uncertainty, we are not able to
quantify emissions uncertainty in the risk analysis, but have
determined that the emissions inventories and emissions models
represent the best available methods for predicting Hg emissions in the
U.S., (2) evaluated the uncertainties in the Hg deposition predictions
and determined that while an important source of uncertainty, we are
not able to quantify uncertainty in Hg deposition in the Hg Risk TSD.
Moreover, the CMAQ model used to estimate deposition is based on peer
reviewed science and represents the best available method for
predicting Hg deposition in the U.S., (3) evaluated the ability of the
Mercury Maps-based approach for relating Hg deposition to MeHg in fish
to capture Hg hotspots and determined that while finer resolution
deposition modeling might reveal additional areas with elevated
deposition, the 12 kilometer
[[Page 9316]]
(km) deposition modeling matches well with the watershed size selected
for the analysis, and thus the use of 12 km deposition estimates with
the Mercury Maps based approach will not be a large source of
uncertainty, (4) evaluated the limited coverage that we have with fish
tissue Hg data for watersheds in the U.S. and implications for the Hg
Risk TSD and based on the SAB's recommendations, we supplemented the
coverage of watersheds by obtaining additional fish tissue Hg samples
for areas heavily impacted by U.S. EGU deposition, thus reducing the
uncertainty in the analysis, (5) evaluated the uncertainty in the
preparation factor and determined that the level of uncertainty is low,
and as such would have minimal impact on the risk estimates, (6)
evaluated the uncertainty resulting from the proportionality assumption
used to relate changes in Hg deposition to changes in fish tissue Hg
levels at the watershed-level, and determined, based both on
quantitative sensitivity analyses and qualitative assessments, that
this source of uncertainty is not likely to greatly influence the
results, and is not likely to have a specific directional bias, (7)
evaluated the uncertainty related to characterization of the spatial
locations of subsistence populations and determined that uncertainty
could be reduced by focusing the risk estimates on female subsistence
fishing populations, which are assumed to have the potential to fish in
all watersheds, in response to SAB's concerns regarding potential
exclusion of watersheds with fewer than 25 individuals and (8)
evaluated the potential impact of the uncertainty in application of the
RfD to low SES populations. The EPA determined that due to the method
used in calculating the RfD, we have confidence that the RfD provides
protection for low SES populations.
Expand the sensitivity analyses (over those included in
the original risk assessment) to address uncertainty related to the use
of the 75th percentile fish tissue Hg value (at each watershed) as the
core risk estimate. Based on the SAB's recommendation, we added a
sensitivity analysis using the median fish tissue Hg estimate (at the
watershed level). This sensitivity analysis showed that use of the
median fish tissue Hg concentration instead of the 75th percentile
resulted in a relatively small decrease (i.e., 10 percent) in the
estimates of watersheds with populations potentially at-risk, and did
not substantially change the conclusions of the risk assessment.
C. Summary of Results of Revised Hg Risk TSD of Risks to Populations
With High Levels of Self-Caught Fish Consumption
Based on the recommendations we received from the SAB, we revised
the quantitative analysis of risk to subsistence fishing populations
with high levels of fish consumption. Our revision to the quantitative
risk results reflects three key recommendations from the SAB, including
(1) addition of 824 watersheds based on additional fish tissue Hg
sample data we obtained from states and the National Listing of Fish
Advisories, (2) application of a 0.95 adjustment factor to the reported
fish tissue Hg concentrations to account for the fraction that is MeHg,
and (3) inclusion of all watersheds with fish samples that meet the
filtering criteria \34\ in representing potential exposures associated
with increased risk of neurologic health effects for female subsistence
fishing populations.
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\34\ The watersheds were filtered to exclude watersheds that:
(a) Were not freshwater, (b) did not have fish sampling data since
2000, (c) did not have fish larger than 7 inches in length, (d)
contained active gold mines or (e) had substantial non-air Hg
loading.
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Based on these revisions, our estimates of the number and percent
of modeled watersheds with populations potentially at-risk from
exposure to EGU-attributable MeHg changed from those presented in the
preamble to the proposed rule.\35\ For the 99th percentile consumption
scenario, the number of watersheds with fish tissue Hg samples where
subsistence fishing populations may be at-risk from exposure to EGU-
attributable MeHg increased from 672 to 917 (an increase of 36
percent). For this same scenario, the total percent of modeled
watersheds with populations potentially at-risk from either risk metric
(i.e., MeHg exposure from U.S. EGUs alone exceeds the RfD or total MeHg
exposure exceeds the RfD and U.S. EGUs contribute at least 5 percent)
increased from 28 percent estimated at proposal to 29 percent after
addressing SAB recommendations. The increase in the total percent of
modeled watersheds with populations potentially at-risk using the
expanded geographic coverage of watersheds provides additional
confidence that emissions of Hg from U.S. EGUs pose a hazard to public
health. For the 99th percentile consumption scenario, the percent of
modeled watersheds with populations potentially at-risk from total
potential exposures to MeHg that exceed the RfD and U.S. EGUs
contribute at least 5 percent increased from 22 percent to 24 percent.
For the 99th percentile consumption scenario, the percent of modeled
watersheds with populations potentially at-risk based on Hg deposition
from U.S. EGUs alone decreased from 12 percent to 10 percent.
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\35\ Since the time of the analyses conducted in support of the
proposed rule, the EPA updated IPM modeling to reflect the most
recently available information, including public comments and the
final CSAPR (see IPM Documentation for further details on these
updates, which is available in the docket). Compared to the modeling
conducted at proposal, these updates are projected to result in
greater reductions in criteria pollutants, and also to have a
slightly greater impact on U.S. EGU Hg emissions. Based on the
revised projection for 2016, the EPA estimates that U.S. EGUs would
emit 27 tons of Hg, as compared to the 29 tons we modeled for the Hg
Risk TSD. We do not expect this 2 ton difference to substantially
change the mercury risks reported in the preamble to the proposed
rule, as this represents less than a 10 percent reduction in Hg
emissions.
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The additional sensitivity analyses conducted in response to the
SAB peer review showed that the estimates of the percent of modeled
watersheds with populations potentially at-risk are robust to
alternative assumptions about both the watersheds included in the
analysis and the selection of the 50th percentile or 75th percentile
fish tissue Hg level. Sensitivity analyses excluding entire states with
the potential for historical loadings of Hg from non-air sources \36\
resulted in an increase from 29 percent to 33 percent in the total
percent of modeled watersheds with populations potentially at-risk
exceeding either risk metric (i.e., U.S. EGUs alone or total potential
exposures to MeHg exceed the RfD and U.S. EGUs contribute at least 5
percent). Including only watersheds in the top 25th percentile of U.S.
EGU deposition resulted in an increase in the total percent of modeled
watersheds with populations potentially at-risk exceeding either risk
metric, from 29 percent to 30 percent. Using the 50th percentile fish
tissue Hg level resulted in a decrease in the total percent of modeled
watersheds with populations potentially at-risk exceeding either risk
metric, from 29 percent to 26 percent. On balance, these sensitivity
analyses do not substantially reduce the percent of modeled watersheds
with populations potentially at-risk, and thus confirm the finding that
Hg emissions from U.S. EGUs pose a hazard to public health. In fact,
given the broader coverage of modeled watersheds in the revised
analysis, we have even greater confidence in our finding that Hg
[[Page 9317]]
emissions from U.S. EGUs pose a hazard to public health.
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\36\ The SAB noted that areas with substantially elevated fish
tissue Hg levels could also be characterized by lakes and rivers
with high natural methylation rates, and thus some of the states we
excluded for this sensitivity analysis might not have fish tissue Hg
levels that reflect non-U.S. EGU Hg loadings.
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D. Peer Review of the Approach for Estimating Cancer Risks Associated
With Cr and Ni Emissions in the U.S. EGU Case Studies of Cancer and
Non-Cancer Inhalation Risks for Non-Hg HAP and EPA Response
As explained in the preamble to the proposed rule, the EPA
submitted for peer review its characterization of the chemical
speciation for the emissions of Cr and Ni used in the non-Hg HAP
inhalation risk case studies. The remaining aspects of the non-Hg HAP
case study risk assessments used methods that were previously peer
reviewed. Specifically, the methodologies used to conduct the non-Hg
case studies are consistent with those used to conduct inhalation risk
assessments under EPA's Risk and Technology Review (RTR) program.
Because the RTR assessments are considered to be highly influential
science assessments, the methodologies used to conduct them were
subject to a peer review by the SAB in 2009. The SAB issued its peer
review report in May 2010.\37\ The report endorsed the risk assessment
methodologies used in the program, and made a number of technical
recommendations for EPA to consider as the RTR program evolves.
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\37\ U.S. Environmental Protection Agency--Science Advisory
Board (U.S. EPA-SAB). 2010. Review of EPA's draft entitled, ``Risk
and Technology Review (RTR) Risk Assessment Methodologies: For
Review by the EPA's Science Advisory Board with Case Studies--MACT I
Petroleum Refining Sources and Portland Cement Manufacturing''. EPA-
SAB-10-007. May. Available on-line at: https://yosemite.epa.gov/sab/
sabproduct.nsf/4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-
007-unsigned.pdf.
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The EPA's case studies identified Cr and Ni emissions as the key
drivers of the estimated inhalation cancer risks for EGUs. Because
these results hinged on specific scientific interpretations of data
used to characterize EGU emissions of Cr and Ni, the EPA conducted a
letter peer review of its analysis and interpretation of those data
relative to the quantification of inhalation risks associated with Cr
and Ni emissions from U.S. EGUs. The following sections describe the
peer review process, enumerate the peer review charge questions
presented to the peer review panel, summarize the key recommendations
from the peer review, and summarize our responses to those
recommendations.
1. Summary of Peer Review Process
The EPA asked three independent, external peer reviewers
representing government, academic and the private sector to review of
the methods for developing inhalation cancer risk estimates associated
with emissions of Cr and Ni compounds from coal- and oil-fired EGUs in
support of the appropriate and necessary finding. The approaches and
rationale for the technical and scientific considerations used to
derive inhalation cancer risks were summarized in the draft document
entitled, ``Methods to Develop Inhalation Cancer Risk Estimates for
Chromium and Nickel Compounds.'' The peer reviewers received several
charge questions (three questions on Cr and two questions on Ni, which
are provided below) on the technical and scientific relevance of the
approaches used to develop the inhalation unit risk estimates. The EPA
also provided information on Cr speciation profiles for different
industrial sources, as well as information on the Ni speciation of PM
from oil-fired EGUs.
2. Peer Review Charge Questions
Below, we present the charge questions posed to the peer reviewers
to help guide their review and development of recommendations to EPA on
key issues relevant to the characterization of risks from EGU emissions
containing either Cr or Ni compounds.
The EPA asked three questions regarding Cr and Cr compounds:
Question 1: Do EPA's judgments related to speciated Cr emissions
adequately take into account the available Cr speciation data?
Question 2: Has EPA selected the species of Cr (i.e., hexavalent
Cr, Cr(VI)) that accurately represents the toxicity of Cr and Cr
compounds?
Question 3: Are the assumptions used in past analysis
scientifically defensible, and are there alternatives that EPA should
consider for future analysis?
The EPA asked two questions regarding Ni and Ni compounds:
Question 1: Do EPA's judgments related to speciated Ni emissions
adequately take into account available speciation data, including
recent industry spectrometry studies?
Question 2: Based on the speciation information available and on
what we know about the health effects of Ni and Ni compounds, and
taking into account the existing Unit Risk Estimates (URE) values
(i.e., values derived for EPA's Integrated Risk Information System
(IRIS), California Environmental Protection Agency (Cal EPA) and Texas
Commission on Environmental Quality (TCEQ)), the EPA has provided
several approaches \38\ to derive unit risk estimates that may be more
scientifically defensible than those used in past analyses. Which of
the options presented would result in more accurate and defensible
characterization of risks from exposure to Ni and Ni compounds? Are
there alternative approaches that EPA should consider?
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\38\ See section 3.3 of U.S. Environmental Protection Agency
(U.S. EPA). 2011c. Methods to Develop Inhalation Cancer Risk
Estimates for Chromium and Nickel Compounds. Office of Air Quality
Planning and Standards. October.
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3. Summary of Peer Review Findings and Recommendations
Regarding Cr and Cr compounds, all three reviewers considered
Cr(VI) as the species likely to be driving cancer risks based on solid
evidence from the health effects database for Cr and Cr compounds. All
three authors also considered EPA's use of the average of the range of
the available speciation data (i.e., 12 percent and 18 percent Cr(VI)
contained in coal- and oil-fired EGUs, respectively) as a reasonable
approach for the derivation of default speciation profiles to be used
when there is no speciation data available. All reviewers agreed that
there is high uncertainty associated with the variability in the
speciation data available for Cr (e.g., range of approximately 4 to 23
percent Cr(VI) from coal-fired units). One of the reviewers recommended
several additional studies for EPA's consideration; the EPA considered
these in finalizing the report.
Regarding Ni and Ni compounds, the reviewers agreed with the views
of the international scientific bodies, which consider Ni compounds
carcinogenic as a group. One reviewer recommended that the EPA review
several additional Ni speciation data that suggests that sulfidic Ni
compounds (which the reviewer considered as the most potent carcinogens
within the group of all Ni compounds) are present at low levels in
emissions from EGUs. In addition, this reviewer pointed out that there
is a recently proposed model that may explain the differences in
carcinogenic potential across Ni compounds.
4. The EPA's Responses to Peer Review Recommendations
We summarize EPA's basic responses to the peer review comments
below, first for Cr-related issues, and second for Ni-related issues,
which are reflected in the revised document.\39\
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\39\ U.S. EPA, 2011c.
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[[Page 9318]]
a. Cr and Cr Compounds
In agreement with the peer reviewers and based on the health
effects information available for Cr, the EPA assigns high confidence
in the assumption that Cr(VI) is the carcinogenic species driving the
risk of Cr-emitting facilities. In agreement with the reviews, the EPA
considers derivation of default speciation profiles based on the mass
of Cr(VI) a reasonable approach. As suggested by one of the reviewers,
the EPA reviewed two potentially relevant studies, one of which showed
coal combustion emissions containing as much as 43 percent Cr(VI),\40\
which suggests that the EPA's quantitative approach could actually
underestimate Cr(VI) inhalation risks. However, the other study
reviewed by EPA on speciation of Cr in coal combustion showed Cr(VI)
percentage levels close to detection limits (i.e., 3 to 5 percent of
total Cr, which was close to the limit of detection in this study).\41\
Thus, the more recent speciation data available is unlikely to reduce
the uncertainty of the Cr speciation analyses used by EPA as the bases
for risk characterization analysis.
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\40\ Galbreath KC, Zygarlicke CJ. 2004. ``Formation and chemical
speciation of arsenic-, chromium-, and nickel-bearing coal
combustion PM2.5,'' Fuel Process Technol 85:701-726.
\41\ Huggins FE, Najih M, Huffman GP. 1999. ``Direct speciation
of chromium in coal combustion by-products by X-ray absorption fine
structure spectroscopy,'' Fuel Process Technol 78:233-242.
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In agreement with the peer reviewers, the EPA also recognizes that
the confidence in the default speciation profiles is low because the
profiles are based on a limited data set with a wide range of
percentages of Cr(VI) across the different samples.
b. Ni and Ni Compounds
Based on the views of the major scientific bodies mentioned above
and the peer reviewers that commented on EPA's approaches to risk
characterization of Ni compounds, the EPA considers all Ni compounds to
be carcinogenic as a group and the EPA does not consider Ni speciation
or Ni solubility to be strong determinants of Ni carcinogenicity. These
scientific bodies also recognize that based on the data available, the
precise Ni compound(s) responsible for the carcinogenic effects in
humans is not always clear, and that there may be differences in the
potential toxicity and carcinogenic potential across Ni compounds.
Nevertheless, studies in humans indicate that various mixtures of Ni
compounds (including Ni sulfate, sulfides and oxides, alone or in
combination) encountered in the Ni refining industries may cause cancer
in humans, and there is no reason to expect anything different from
this for mixtures of Ni compounds from other emission sources. One of
the reviewers suggested we consider views by some authors that believe
that water soluble Ni, such as Ni sulfate, should not be considered a
human carcinogen. This view is based primarily on a negative Ni sulfate
2-year rodent bioassay by the National Toxicology Program (NTP) (which
is different from the positive 2-year NTP bioassay for Ni
subsulfide).42 43 44 One review article identifies the
discrepancies between the animal and human data (i.e., from studies of
cancers in workers inhaling certain forms of Ni versus inhalation
studies suggesting different carcinogenic potential in rodents with
different Ni compounds) and states that the epidemiological data
available clearly support an association between Ni and increased
cancer risk, although the article acknowledges that the data are
weakest regarding water soluble Ni. In addition, the EPA identified a
recent review \45\ that highlights the robustness and consistency of
the epidemiological evidence across several decades showing
associations between exposure to Ni and Ni compounds (including Ni
sulfate) and cancer.
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\42\ Oller A. 2002. ``Respiratory carcinogenicity assessment of
soluble nickel compounds.'' Environ Health Perspect. 110:841-844.
\43\ Heller JG, Thornhill PG, Conard BR. 2009. ``New views on
the hypothesis of respiratory cancer risk from soluble nickel
exposure; and reconsideration of this risk's historical sources in
nickel refineries.'' J Occup Med Toxicol. 4:23.
\44\ Goodman JE, Prueitt RL, Thakali S, and Oller AR. 2011.
``The nickel iron bioavailability model of the carcinogenic
potential of nickel-containing substances in the lung.'' Crit Rev
Toxicol 41:142-174.
\45\ Grimsrud TK and Andersen A. ``Evidence of carcinogenicity
in humans of water-soluble nickel salts.'' J Occup Med Toxicol.
2010. 5:1-7. Available online at https://www.ossup-med.com/content/5/1/7.
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Regarding the second charge question on Ni compounds, two reviewers
suggested using the URE derived by the TCEQ \46\ for all Ni compounds
as a group, rather than the one derived by the Integrated Risk
Information System (IRIS, 1991) \47\ specifically for Ni subsulfide.
The third reviewer did not comment on an alternative approach.
Considering this, to develop our primary risk estimate, the EPA decided
to use a health protective approach by applying 100 percent of the
current IRIS URE for Ni subsulfide, rather than assuming that 65
percent of the total mass of emitted Ni might be Ni subsulfide, as used
in previous analyses. We used the IRIS URE value because IRIS values
are preferred given the conceptual consistency with EPA risk assessment
guidelines and the level of peer review that such values receive. We
used 100 percent of the IRIS value because of the concerns about the
potential carcinogenicity of all forms of Ni raised by the major
national and international scientific bodies, and recommendations of
the peer reviewers. Nevertheless, taking into account that there are
potential differences in toxicity and/or carcinogenic potential across
the different Ni compounds, and given that two URE values have been
derived for exposure to mixtures of Ni compounds that are two to three
fold lower than the IRIS URE for Ni subsulfide, the EPA also considers
it reasonable to use a value that is 50 percent of the IRIS URE for Ni
subsulfide for providing an estimate of the lower end of a plausible
range of cancer potency values for different mixtures of Ni compounds.
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\46\ Texas Commission on Environmental Quality (TCEQ). 2011.
Development Support Document for nickel and inorganic nickel
compounds. Available online at https://www.tceq.state.tx.us/assets/public/implementation/tox/dsd/final/june11/nickel_&_compounds.pdf.
\47\ U.S. EPA, 1991. Integrated Risk Information Service (IRIS)
assessment for nickel subsulfide. Available at: https://www.epa.gov/iris/subst/0273.htm.
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Although this report focused primarily on cancer risks associated
with emissions containing Ni compounds, it is important to note that
comparative quantitative analyses of non-cancer toxicity of Ni
compounds indicate that Ni sulfate is as toxic or more toxic than Ni
subsulfide or Ni oxide which does not support the notion that the
solubility of Ni compounds is a strong determinant of its
toxicity.48 49
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\48\ Haber LT, Allen BC, Kimmel CA. 1998. ``Non-Cancer Risk
Assessment for Nickel Compounds: Issues Associated with Dose-
Response Modeling of Inhalation and Oral Exposures.'' Toxicol Sci.
43:213-229.
\49\ National Toxicology Program (NTP). 1996. Technical Report
Series No. 454, Toxicology and carcinogenesis studies of nickel
sulfate hexahydrate. July. Available online at https://ntp.niehs.nih.gov/ntp/htdocs/LT_rpts/tr454.pdf.
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E. Summary of Results of Revised U.S. EGU Case Studies of Cancer and
Non-Cancer Inhalation Risks for Non-Hg HAP
Based on the results of the peer review and public comments on the
non-Hg case study chronic inhalation risk assessment, we made several
changes to the emissions estimates, dispersion modeling, and risk
characterization for the modeled case study facilities. Key changes
include (1) changes in emissions, (2) changes in stack parameters for
some facilities based on new data received during the
[[Page 9319]]
public comment period, (3) use of updated versions of AERMOD and its
input processors (AERMAP, AERMINUTE, and AERMET), and (4) use of 100
percent of the current IRIS URE for Ni subsulfide to calculate Ni-
associated inhalation cancer risks (rather than assuming that the Ni
might be 65 percent as potent as Ni subsulfide).
Based on estimated actual emissions, the highest estimated
individual lifetime cancer risk from any of the 16 case study
facilities was 20 in a million, driven by Ni emissions from the one
case study facility with oil-fired EGUs. Of the facilities with coal-
fired EGUs, five facilities had maximum individual cancer risks greater
than one in a million \50\ (the highest was five in a million), with
the risk from four due to emissions of Cr(VI) and the risk from one due
to emissions of Ni.\51\ There were also two facilities with coal-fired
EGUs that had maximum individual cancer risks equal to one in a
million. All of the facilities had non-cancer Target Organ Specific
Hazard Index (TOSHI) \52\ values less than one, with a maximum TOSHI
value of 0.4 (also driven by Ni emissions from the one case study
facility with oil-fired EGUs).
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\50\ A risk level of 1 in a million implies a likelihood that up
to one person, out of one million equally exposed people would
contract cancer if exposed continuously (24 hours per day) to the
specific concentration over 70 years (an assumed lifetime). This
would be in addition to those cancer cases that would normally occur
in an unexposed population of one million people.
\51\ When the lower end of the cancer potency range for Ni was
used to develop risk estimates, 5 of the 16 facilities had maximum
cancer risks exceeding 1 in a million, and the maximum individual
cancer risk for any single facility fell to 10 in a million.
\52\ The target-organ-specific hazard index (TOSHI) is a metric
used to assess whether there is an appreciable risk of deleterious
(noncancer) effects to a specific target organ due to continuous
inhalation exposures over a lifetime. If a TOSHI value is less than
or equal to one, such effects are unlikely. For TOSHI values greater
than one, there is an increased risk of such effects.
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Since these case studies do not cover all facilities in the
category, and since our assessment does not include the potential for
impacts from different EGU facilities to overlap one another (i.e.,
these case studies only look at facilities in isolation), the maximum
risk estimates from the case studies likely underestimates true maximum
risks for the source category.
Based on the fact that six U.S. EGUs were estimated to meet or
exceed the CAA section 112(c)(9) criterion of one in a million, EGUs
cannot be removed from the list of source categories to be regulated
under CAA section 112.
F. Public Comments and Responses to the Appropriate and Necessary
Finding
1. Legal Aspects of Appropriate and Necessary Finding
a. History of Section 112(n)(1)(A)
Comment: One commenter provided a detailed history of EPA's
regulatory actions concerning EGUs and implementation of CAA section
112(n)(1)(A). The same commenter implies that the EPA's 2000
appropriate and necessary finding and listing of EGUs was flawed
because the Agency did not comply with CAA section 307(d) rulemaking
process. The commenter sought review of the 2000 notice in the U.S.
Court of Appeals for the District of Columbia Circuit, which was
dismissed by the D.C. Circuit. Utility Air Regulatory Group v. EPA, No.
01-1074 (D.C. Cir. July 26, 2001). The commenter then characterizes at
length the 2005 EPA action that revised the interpretation of CAA
section 112(n)(1)(A) and, which the D.C. Circuit concluded illegally
removed EGUs from the CAA section 112(c) list of sources that must be
regulated under CAA section 112. See New Jersey v. EPA, 517 F.3d 574
(D.C. Cir. 2008). The commenter notes that the D.C. Circuit did not
rule on the legal correctness or the sufficiency of the factual record
supporting EPA's 2000 listing decision or on the factual correctness of
EPA's later decision to reverse its CAA section 112(n)(1)(A)
determination. The commenter noted further that the D.C. Circuit
indicated that the listing decision could be challenged when the Agency
issued the final CAA section 112(d) standards pursuant to CAA section
112(e)(4). The commenter concluded by asserting that the Agency could
not ignore the history associated with the regulation of EGUs under
section 112 and that two earlier dockets--Docket ID. No. A-92-55 and
Docket ID. No. EPA-HQ-OAR-2002-0056--are also part of this long
rulemaking effort and must be accounted for in conjunction with Docket
No. EPA-HQ-OAR-2009-0234 if all pertinent material and comments are to
be part of the rulemaking record.
Response: The commenter characterizes the regulatory history of the
rule EPA proposed on May 3, 2011. To the extent that characterization
is inconsistent with the lengthy regulatory history EPA provided in the
preamble to the May 3, 2011 rule, we disagree. We address several of
the statements in more detail below.
First, the commenter makes much of the fact that the EPA did not go
through CAA section 307(d) notice and comment rulemaking when making
the appropriate and necessary finding and listing decision in 2000.
However, the commenter's complaint is without foundation. The CAA does
not require CAA section 307(d) rulemaking for listing decisions. In
fact, CAA section 112(e)(4) specifically provides that listing
decisions may only be challenged ``when the Administrator issues
emission standards for such * * * [listed] category.'' Second, the
commenter challenged the listing decision in the U.S. Court of Appeals
for the District of Columbia Circuit (Court) and, on July 26, 2001, the
Court granted EPA's motion to dismiss that action based on the plain
language of CAA section 112(e)(4). Moreover, in addition to the 2000
notice, the EPA clearly articulated its basis for listing EGUs in this
proposed rule, which is consistent with CAA section 307(d), and the
commenter was provided an ample opportunity to comment. Finally, the
commenter asserts that the rulemaking docket for this action is
incomplete because the Agency did not include two earlier dockets--
Docket ID. No. A-92-55 and Docket ID. No. EPA-HQ-OAR-2002-0056--for the
Section 112(n) Revision Rule, 70 FR 15994 (March 29, 2005), and the
reconsideration of the Section 112(n) Revision Rule, 71 FR 33388 (June
9, 2006), respectively. The commenter is incorrect because EPA
incorporated by reference the two dockets at issue. See EPA-HQ-OAR-
2009-0234-3056.
Comment: One commenter stated that the EPA has assessed the public
health risks posed by HAP emissions from coal- and oil-fired EGUs for
the last 40 years. According to the commenter, throughout that time,
the EPA has come to a single repeated conclusion that HAP emissions
from EGUs pose little or no risk to public health. Based on this
conclusion, the EPA has properly chosen not to require EGUs to install
expensive, new pollution control equipment to control HAP emissions.
The commenter asserts that, in this proposed rule, the EPA shifts its
opinion on the health impacts of EGU HAP emissions 180 degrees and now
seeks to impose sweeping regulatory requirements on all power plants.
According to the commenter, the EPA's newfound concern about HAP
emissions from EGUs is not based on new and different assessments of
the public health consequences of EGU HAP emissions but instead on
health benefits from the reduction of non-hazardous air pollutants,
primarily PM, which the Agency is required to regulate under other
provisions of the CAA. One
[[Page 9320]]
commenter stated that for decades, the EPA set primary ambient air
quality standards that protect public health with an adequate margin of
safety, CAA section 109(b)(1), and set secondary standards that are
[sic] ``requisite to protect the public welfare from any known or
anticipated adverse effects associated with the presence of such air
pollutant in the ambient air,'' CAA 109(b)(2). The commenter notes that
even if EPA now views those past PM standards as inadequate, the EPA
has ongoing regulatory proceedings in which it can address any
perceived health concerns. The commenter concludes that regulation of
EGU HAP emissions under CAA section 112 is an unlawful way to address
those concerns.
Response: The commenter is incorrect in its assertion that the
Agency has consistently concluded that HAP emissions from EGUs do not
present a hazard to public health. In the 2000 finding, the Agency
concluded that HAP emissions from coal- and oil-fired EGUs do pose a
hazard to public health and determined that it was appropriate and
necessary to regulate such units under CAA section 112. As a result of
that finding, the EPA added coal- and oil-fired EGUs to the CAA section
112(c) list of source categories for which emission standards are to be
established pursuant to CAA section 112(d). Further, in support of the
proposed rule, the EPA conducted additional extensive quantitative and
qualitative analyses, which confirm that it remains appropriate and
necessary to regulate EGUs under CAA section 112. Among other things,
those analyses demonstrate that emissions from coal- and oil-fired EGUs
continue to pose a hazard to public health. The commenter also fails to
note that the EPA found that HAP emissions from EGUs pose a hazard to
the environment as well.
The commenter seems confused about the basis for the Agency's
appropriate and necessary finding because it maintains that the EPA
made the appropriate and necessary finding based on the health co-
benefits attributable to PM reductions that will be achieved as a
result of the Agency's regulation of HAP emissions from EGUs. Nowhere
in the May 2011 proposal does EPA state that it based the appropriate
and necessary finding on hazards to public health attributable to PM
emissions. The commenter's allegation lacks foundation. The appropriate
and necessary finding unmistakably focuses on the hazards to public
health and hazards to the environment associated with HAP emissions
from EGUs.
Comment: One commenter stated that CAA section 112 required EPA to
make a risk-based determination in order to regulate HAP. According to
the commenter, the EPA may regulate substances ``reasonably * * *
anticipated to result in an increase in mortality or increase in
serious illness'' to a level that protects public health with an
``ample margin of safety.'' According to the commenter, the EPA has
regulated a number of HAP emitted from industrial source categories
other than EGUs.
As for EGUs, according to the commenter, the EPA found that the
combustion of fossil fuels produces extremely small emissions of a
broad variety of substances that are present in trace amounts in fuels
and that are removed from the gas stream by control equipment installed
to satisfy other CAA requirements. The commenter stated that the EPA,
in past reviews, found that these HAP emissions did not pose hazards to
public health. See 48 FR 15076, 15085 (1983) (radionuclides). the
commenter further stated that ``[i]n the case of Hg specifically, the
EPA found that ``coal-fired power plants * * * do not emit mercury in
such quantities that they are likely to cause ambient mercury
concentration to exceed'' a level that ``will protect public health
with an ample margin of safety.'' 40 FR 48297-98 (October 19, 1975)
(Hg); 52 FR 8724, 8725 (March. 19, 1987) (reaffirming Hg conclusion).
According to the commenter, in the late 1980s, the EPA was
concerned that its prior risk assessments of individual HAP emissions
from fossil-fuel-fired power plants may not reflect the total risks
posed by all HAP emitted by those sources. The commenter states that
the EPA modeled the risks posed by all HAP emitted by power plants
(very much like the analyses the Agency would conduct for the Utility
Study ten years later). The commenter asserts that the modeling again
failed to identify threats to public health that warranted regulation
under an ``ample margin of safety'' test.
Response: The commenter's statements concerning the pre-1990 CAA
are not relevant to the current action. Congress enacted CAA section
112(n)(1) as part of the 1990 amendments to the Act. That provision
requires, among other things, that the Agency evaluate the hazards to
public health posed by HAP emissions from fossil-fuel fired EGUs. Had
Congress concluded, as commenter appears to assert, that HAP emissions
from EGUs did not pose a hazard to public health or the environment, it
defies reason that Congress would have required EPA to conduct the
three studies at issue in CAA section 112(n)(1) (titled ``Electric
utility steam generating units'') and regulate EGUs under section 112
if the Administrator determined in her discretion that it was
appropriate and necessary to do so. The Agency complied with the
statutory mandates in CAA section 112(n)(1) in conducting the studies
and reasonably exercised its discretion in making the appropriate and
necessary finding.
We acknowledge that Congress treated radionuclide emissions from
EGUs differently. For radionuclides from EGUs (and certain other
sources), Congress included CAA section 112(q)(3), which authorizes but
does not require the Agency to maintain the regulations of
radionuclides in effect prior to the 1990 amendments. The fact that
Congress made an exception for radionuclides and no other HAP from EGUs
further demonstrates that the HAP-related actions EPA took with regard
to EGUs prior to the 1990 amendments to the CAA are not germane.
As for the commenter's statements about Hg emissions from EGUs, we
find their conclusions wholly inconsistent with CAA section 112(n)(1).
That provision is titled ``Electric utility steam generating units,''
and it directs EPA to conduct two Hg-specific studies. See CAA sections
112(n)(1)(B) and 112(n)(1)(C). The commenter's suggestion that the EPA
could or should rely on assessments of Hg from EGUs conducted prior to
the 1990 amendments is not tenable.
Finally, the commenter stated that the EPA conducted a risk
assessment of all HAP from EGUs prior to the 1990 amendments and that
the Agency did not identify any HAP that failed the ``ample margin of
safety'' test. The commenter did not cite the study or provide any
information to support the statements so we are unable to respond to
the alleged study directly; however, the risk assessments conducted in
support of the appropriate and necessary finding, as well as the 2000
finding, demonstrate that HAP emissions from EGUs pose hazards to
public health and the environment.
b. Interpretation of ``Appropriate'' and ``Necessary''
Comment: One commenter stated that in the preamble to the proposed
rule, the EPA sets out its ``interpretation of the critical terms in
CAA section 112(n)(1),'' arguing that this latest interpretation is
``wholly consistent with the CAA'' and with the Agency's earlier ``2000
finding.'' See 76 FR 24976, 24986 (May 3, 2011). The commenter stated
that throughout the proposal EPA tries to suggest that it is returning
to
[[Page 9321]]
some earlier, ``correct'' interpretation of CAA section 112(n)(1) set
forth in its 2000 action. See, e.g., 76 FR 24989 (``The Agency's
interpretation of the term `appropriate' * * * is wholly consistent
with the Agency's appropriate finding in 2000''); id. at 24992 (``Our
interpretation of the necessary finding is reasonable and consistent
with the 2000 finding''). According to the commenter, the EPA did not
provide in 2000 any interpretation of what it now characterizes as the
``critical terms'' of section 112(n)(1). See, e.g., 70 FR 15999 n.13
(the ``2000 finding does not provide an interpretation of the phrase
`after imposition of the requirements of the Act' ''); id. at 16000/2
(in 2000, the EPA ``did not provide an interpretation of the term
`appropriate' ''); 76 FR 24992 (the ``Agency did not expressly
interpret the term necessary in the 2000 finding''). The commenter
believes that for that reason alone, it is impossible to credit EPA's
assertion that it ``appropriately concluded that it was appropriate and
necessary to regulate hazardous air pollutants * * * from EGUs'' in
2000, and that it is today merely ``confirm[ing] that finding and
conclud[ing] that it remains appropriate and necessary to regulate
these emissions.* * *'' \53\
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\53\ Id. at 24,977/3.
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Response: The commenter disagrees with certain statements in the
preamble to the proposed rule that provide that the Agency's
interpretation of CAA section 112(n)(1) is reasonable and consistent
with the 2000 finding. It is difficult to decipher the exact complaint
that the commenter has with EPA's proposed rule in this regard, but the
commenter does assert that ``the Agency did not provide in 2000 any
interpretation of what it now characterizes as the ``critical terms''
of CAA section 112(n)(1).'' The commenter's assertion lacks foundation.
Although the 2000 finding did not provide detailed interpretations of
the regulatory terms at issue, it discussed the types of considerations
relevant to the appropriate and necessary inquiry. For example, it is
clear that in 2000, the Agency was concerned with the then current
hazards to public health and the environment when assessing whether it
was appropriate to regulate EGUs under section 112.\54\ In addition,
when evaluating whether it was necessary to regulate utilities, the
Agency stated that it was necessary to regulate HAP emissions from U.S.
EGUs under section 112 because the implementation of the other
requirements of the Act would not adequately address the serious public
health and environmental hazards arising from HAP emissions from EGUs.
The Agency also specifically noted that ``section 112 is the authority
intended to address'' hazards to public health and the environment
posed by HAP emissions. Id.
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\54\ 65 FR 79830.
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The detailed interpretation set forth in the preamble to the
proposed rule is consistent with the 2000 finding, but EPA does not
assert that the interpretation is in any way necessary to support the
factual conclusions reached in the 2000 finding. Instead, we noted in
the preamble to the proposed rule that our interpretation is consistent
with the 2000 finding because in 2005 we interpreted the statute in a
manner that was not consistent with the 2000 finding. The commenter has
provided no legal support for its position that the Agency erred in
interpreting the statute in a manner that is consistent with a prior
factual finding.
Comment: Several commenters assert that in the 1990 amendments to
the Clean Air Act, Congress directed the EPA to base its determination
regarding regulation of fossil-fuel-fired generating units on
consideration of any adverse public health effects identified in the
study mandated by the first sentence of section 112(n)(1)(A) and that
Congress did not dictate in section 112(n)(1)(A) that the EPA must
regulate electric utility steam generating units under section 112.
According to the commenters the sponsor of the House bill that
became section 112(n)(1)(A) provides an explanation that contradicts
the EPA's approach to regulating EGUs:
Pursuant to section 112(n), the Administrator may regulate
fossil fuel fired electric utility steam generating units only if
the studies described in section 112(n) clearly establish that
emissions of any pollutant, or aggregate of pollutants, from such
units cause a significant risk of serious adverse effects on the
public health. Thus, * * * he may regulate only those units that he
determines--after taking into account compliance with all provisions
of the act and any other Federal, State, or local regulation and
voluntary emission reductions--have been demonstrated to cause a
significant threat of serious adverse effects on the public health.
136 Cong. Rec. H12,934 (daily ed. Oct. 26, 1990) (statement of Rep.
Michael Oxley).
The commenters stated that the EPA position is premised on the
assumption that ``regulation under section 112'' necessarily means
``regulation under 112(d)'' and falsely premised on the assumption that
source categories listed by operation of section 112(n)(1)(A) cannot be
regulated differently. The commenters conclude that the language of
section 112(n)(1)(a) reflects Congress' intent that ``regulation of HAP
from EGUs was not intended to operate under section 112(d) but was
instead intended to be tailored to the findings of the utility study
mandated by section 112(n)(1)(A).''
Response: The commenters maintain that the Agency's interpretation
of CAA section 112(n)(1) is flawed in many respects. The primary
support for one commenter's arguments against EPA's interpretation,
including in the comment above, is legislative history in the form of
statements from one Congressman, Representative Oxley. The Supreme
Court has repeatedly stated that the statements of one legislator alone
should not be given much weight. See Brock v. Pierce County, 476 U.S.
253, 263 (1986) (finding that ``statements by individual legislators
should not be given controlling effect, but when they are consistent
with the statutory language and other legislative history, they provide
evidence of Congress' intent.'') (emphasis added) (citation omitted);
Garcia, et al., v. U.S., 469 U.S. 70, 78 (1984), citing Zuber v. Allen,
396 U.S. 168, 187 (1969) (reiterating its prior findings, the Court
indicated that isolated statements ``are `not impressive legislative
history.' ''); Weinberger, et al., v. Rossi et al., 456 U.S. 25, 35
(declining to make a ruling based on ``one isolated remark by a single
Senator''); Consumer Product Safety Comm., et al. v. GTE Sylvania,
Inc., et al., 447 U.S. 102, 117-118 (1980) (declining to give much
weight to isolated remarks of one Representative); Chrysler Corp. v.
Brown, et al., 441 U.S. 281, 311 (1979) (finding that ``[t]he remarks
of a single legislator, even the sponsor, are not controlling in
analyzing legislative history.''); Zuber, 396 U.S. at 186 (concluding
that ``[f]loor debates reflect at best the understanding of individual
Congressmen.''); and U.S. v. O'Brien, 391 U.S. 367, 384 (1968) (in
evaluating the statements of a handful of Congressmen, the Court
concluded that ``[w]hat motivates one legislator to make a speech about
a statute is not necessarily what motivates scores of others to enact
it. * * *.''). As these cases show, the Supreme Court does not give
weight to the statements of an individual legislator, except when the
statements are supported by other legislative history and the clear
intent of the statute. The commenters cited no case law that would
support reliance on such limited legislative history.
The commenter has not cited any other legislative history to
support
[[Page 9322]]
Representative Oxley's statement, and the lack of additional support
makes the statement of little utility or import under the case law. In
fact, there does not appear to be anything in the House, Senate, or
Committee Reports that supports Oxley's statement. The lack of support
for Oxley's statement in the Committee Report is particularly telling
since, as the commenter notes, the House and Senate bills required
different approaches to regulating EGUs under section 112, with the
Senate bill requiring EGUs be regulated prior to the Utility Study. In
fact, legislative statements from Senator Durenberger, a supporter of
the Senate version, demonstrate that others would almost certainly not
have agreed with Oxley's interpretation. For example, Senator
Durenberger stated, ``It seems to me inequitable to impose a regulatory
regime on every industry in America and then exempt one category,
especially a category like power plants which are a significant part of
the air toxics problem.''
Senator Durenberger discussed the negotiations with the
Administration and the industry push to avoid regulation, including
industry arguments for not regulating Hg from U.S. EGUs:
The utility industry continued to adamantly oppose [regulation
under section 112]. First, they argued that mercury isn't much of an
environmental problem. But as the evidence mounted over the summer
and it became clear that mercury is a substantial threat to the
health of our lakes, rivers and estuaries and that power plants are
among the principal culprits, they changed their tactic. Now they
are arguing that mercury is a global problem so severe that just
cleaning up U.S. power plants won't make enough of a difference to
be worth it. They've gone from `we're not a problem' to `you can't
regulate us until you address the whole global problem.' Recasting
an issue that way is not new around here. So, it is not a surprise.
But it does suggest the direction in which this debate will be
heading in the next few years.
136 Cong. Rec. 36062 (October 27, 1990).
Senator Durenberger also explained why the House version was
adopted:
Given that a resolution of the difficult issues in the
conference were necessary to conclude work on this bill, the Senate
proposed to recede to the House provision which was taken from the
original administration bill. It provides for a 3-year study of
utility emissions followed by regulation to the extent that the
Administrator finds them necessary.
Id.
Senator Durenberger's statements indicate that it is unlikely that
he would agree with Oxley's interpretation of CAA section 112(n)(1), a
provision that provides the Agency with considerable discretion, and
nothing indicates that others in the Senate (or for that matter anyone
else in the House) would agree with that interpretation. Given the
Supreme Court's views on the use of such limited legislative history,
the EPA reasonably declined to consider (or even discuss) the
legislative history in the preamble to the proposed rule and we believe
it would be improper to ascribe Representative Oxley's statements to
the entire Congress.
Moreover, Representative Oxley's statement directly conflicts with
the statutory text. Representative Oxley stated that ``[the
Administrator may regulate only those units that he determines--after
taking into account compliance with all provisions of the act and any
other Federal, State, or local regulation and voluntary emission
reductions--have been demonstrated to cause a significant threat of
serious adverse effects on the public health.'' 136 Cong. Rec. H12934
(daily ed. Oct. 26, 1990), reprinted in 1 1990 Legis. Hist. at 1416-17
(emphasis added). However, the Utility Study required under CAA section
112(n)(1)(A) directs the Agency to consider the hazards to public
health reasonably anticipated to occur after ``imposition of the
requirements of [the Clean Air Act].'' EPA was not required to consider
state or local regulations or voluntary emission reduction programs in
the Utility Study, and that study is the only condition precedent to
making the appropriate and necessary finding.\55\
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\55\ In addition, the EPA only considered CAA requirements in
the Utility Study and this was the correct approach because Congress
knew how to require consideration of non-Federal requirements when
directing EPA to conduct a study or assessment. See CAA section
112(n)(5) (Congress required EPA to conduct an assessment of
hydrogen sulfide from oil and gas extraction activities and provided
that the assessment ``shall include review of existing State and
industry control standards, techniques and enforcement.'').
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The legislative history the commenters rely on is not controlling.
The Agency believes that it has reasonably interpreted section
112(n)(1)(A), for all the reasons described herein and in the proposal.
The commenters also cite Representative Oxley's statements as support
for alternative interpretations of CAA section 112(n)(1). We believe
that any arguments that rely on such limited legislative history are
without merit.
Comment: One commenter stated that the EPA does acknowledge that,
in many significant respects, its new interpretation of CAA section
112(n)(1) ``differs from that set forth'' in the Agency's 2005
rulemaking, but argues that its change of position is permissible. See
76 FR 24988/1 (``[T]o the extent our interpretation differs from that
set forth in the 2005 Action, we explain the basis for that difference
and why the interpretation, as set forth in this preamble, is
reasonable.''). In support, commenters note that the EPA cites National
Cable & Telecommunication Ass'n v. Brand X Internet Services, 545 U.S.
967 (2005). The commenters agree that it is true that, in Brand X
Internet Services, the Supreme Court explained that, if an agency
``adequately explains the reasons for a reversal of policy,'' such
change is ``not invalidating,'' since the ``whole point of Chevron is
to leave the discretion provided by the ambiguities of a statute with
the implementing agency.'' 545 U.S. at 981 (internal quotations
omitted). The commenters maintain that all Brand X Internet Services
was saying is that ``[a]gency inconsistency is not a basis for
declining to analyze the agency's interpretation under the Chevron
framework.'' Id.
According to the commenter, it is not enough that the EPA has
purported to ``explain'' why it has abandoned the interpretation of CAA
section 112(n)(1) adopted in 2005. The commenter states that under the
first step of Chevron, the Agency's latest interpretation must still be
consistent with congressional intent. See Chevron v. NRDC, 467 U.S. at
842-43. The commenters state that under the second step of Chevron, if
there is discretion for EPA to exercise in interpreting the ``critical
terms'' of CAA section 112(n)(1), the Agency must properly define the
range of that discretion and then act reasonably in exercising that
discretion. See Chevron, 467 U.S. at 843; see also Village of
Barrington, Ill. v. Surface Transportation Bd., No. 09-1002 (D.C. Cir.
Mar. 15, 2011).The commenters allege that the EPA failed to properly
define and exercise the scope of its discretion. In each instance, the
commenter maintains that the Agency has departed from the correct
interpretation of CAA section 112(n)(1) that it adopted in 2005,
seizing instead upon a new approach that is contrary to the plain
language of the CAA itself, as interpreted after considering the
statements of Representative Oxley.
Response: The commenter appears to argue that the EPA's
interpretation of CAA section 112(n)(1) is not consistent with the
plain language of the statute, implying that the statute is clear and
must be evaluated under step one of Chevron. See Chevron v. NRDC, 467
U.S. 837 842-42 (1984) (finding that when the legislative intent is
clear no additional analysis is required).
[[Page 9323]]
However, as noted above, much of the commenter's argument that the
plain language of the statute precludes EPA's interpretation is based
on the unpersuasive legislative history discussed above. As explained
in the preamble to the proposed rule, the statute directs the Agency to
determine whether it is appropriate and necessary to regulate EGUs
under section 112. As the D.C. Circuit has held, the terms
``appropriate'' and ``necessary'' are very broad terms. Because these
terms are broad they are susceptible to different interpretations. We
believe we have reasonably interpreted the appropriate and necessary
language in section 112(n)(1)(A). To the extent that interpretation
differs from the one set forth in 2005, we have fully explained the
basis for such changes. See 76 FR 24986-24993 (setting forth the
Agency's interpretation of section 112(n)(1)).
Furthermore, we properly considered the scope of our discretion in
interpreting the statute as explained in detail in the preamble to the
proposed rule. We believe the interpretation set forth in the preamble
to the proposed rule is consistent with the Act and, therefore, the
Agency should be afforded deference pursuant to National Cable &
Telecommunication Ass'n v. Brand X Internet Services, 545 U.S. 967
(2005).
Comment: A number of commenters agreed with the Agency's
interpretation of section 112(n)(1) and the terms appropriate and
necessary. The commenters also agreed that the EPA's interpretation of
that provision was reasonable and consistent with the statute.
Response: We agree with the commenters and appreciate their
support.
Comment: One commenter asserts that the EPA's ultimate motivation
for rejecting its prior interpretation of CAA section 112(n)(1) and
embracing this flawed new approach is made clear from the very outset
of the proposal. According to the commenter, the EPA touts the fact
that ``one consequence'' of the MACT rule would be that the ``market
for electricity in the U.S. will be more level'' and ``no longer skewed
in favor of the higher polluting units that were exempted from the CAA
at its inception on Congress' assumption that their useful life was
near an end.'' See 76 FR 24979/2. The MACT rule would ``require
companies to make a decision--control HAP emissions from virtually
uncontrolled sources'' or else ``retire these sometimes 60 year old
units and shift their emphasis to more efficient, cleaner modern
methods of generation, including modern coal-fired generation.'' Id.
The commenter stated that this remarkably forthright statement
establishes that the underlying basis for EPA's proposal to regulate
EGUs under CAA section 112 is not to address any ``hazards to public
health'' that might be attributed to the emission by EGUs of HAP listed
under CAA section 112(b). Rather, according to commenter, the EPA is
utilizing the regulation of EGUs under CAA section 112 as a means to an
entirely different end: To force the imposition of controls that will
also have the result of reducing non-HAP emissions (primarily PM) or
force the shutdown of those units for which the cost of such controls
would be prohibitive. At the same time, according to commenter, the EPA
tacitly acknowledges that it cannot hope to make out a case that the
regulation of EGU HAP emissions is ``appropriate and necessary'' within
the meaning of CAA section 112(n)(1). The commenter asserts that the
only HAP whose health-related benefits EPA quantifies is Hg. Elsewhere,
the commenter stated that the EPA contends there are ``additional
health and environmental effects'' attributable to HAP other than Hg,
but admits that it has ``not quantified'' those risks due supposedly to
``insufficient information.'' See 76 FR 24999/2. With respect to Hg the
commenter stated that the benefits are so questionable and miniscule,
some $4 million to $6 million (given a 3 percent discount rate), that
compared to the total social costs of the rule (i.e., nearly $11
billion) the rule cannot be justified were EPA properly to interpret
CAA section 112(n)(1) and undertake the sort of regulatory analysis
Congress intended. The commenter stated that the reason that the EPA
touts in this rulemaking the health benefits EPA attributes to the
reduction of non-hazardous air pollutants (again, primarily PM), the
regulation of which is authorized under provisions of the CAA apart
from CAA section 112, is to elide the inconvenient truth regarding the
truly trivial nature of the benefits attributable to HAP regulation
itself. The commenter concludes that the EPA distorts CAA section
112(n)(1)(A) ``beyond all recognition.''
One commenter stated that the EPA is directed by CAA section
112(n)(1)(A) to study the ``hazards to public health anticipated to
occur as a result of emissions'' by EGUs of ``pollutants listed under
subsection (b) of this section''--i.e., HAP and HAP alone. Thereafter,
the EPA is authorized to regulate EGU HAP emissions if, and only if,
they determine that ``such regulation'' of HAP emissions is
``appropriate and necessary'' to address the ``hazards to public
health'' that may be attributable to HAP emissions. According to the
commenter, by contrast, in this rulemaking, the EPA has seized upon the
fact that the control of EGU HAP emissions will also control non-HAP
(such as PM), and then seeks to justify the regulation of HAP emissions
based almost entirely on the health benefits of the reductions in non-
HAP emissions that would be coincidentally achieved. The commenter
believes that this ``regulatory sleight-of-hand'' runs afoul of
congressional intent and is unlawful.
Response: The commenter alleges that the health-related benefits to
regulating HAP emissions from EGUs are ``questionable and miniscule,''
and that the only real benefits stem from non-HAP emissions, such as
PM. The commenter also implies that regulation of HAP is nothing more
than a straw man and that the Agency's ultimate goal is to regulate
other pollutants, and specifically PM. These allegations are wholly
without merit. The Agency has conducted comprehensive technical
analyses that confirm that HAP emissions from EGUs pose a hazard to
public health. The analyses are discussed at length elsewhere in this
final rule, and a review of the proposed and final rules utterly
refutes commenter's assertion that PM reductions form the basis for the
appropriate and necessary finding. In addition, the commenter appears
to ignore the Agency's findings concerning the hazards to public health
and the environment posed by HAP emissions simply because the Agency is
not able to quantify many of the benefits associated with reductions of
HAP emissions from EGUs or because the estimated HAP benefits that are
quantified are small in relation to the co-benefits achieved through
reductions in non-HAP air pollutants, such as PM and SO2,
which are surrogates for certain HAP. The Agency is regulating EGUs
pursuant to section 112(d) for all of the reasons explained in the
preamble and discussed elsewhere in this response to comments. The
commenter fails to recognize that the statute neither requires a cost-
benefit analysis prior to finding it appropriate and necessary to
regulate EGUs, nor requires such analysis prior to setting emission
standards. Indeed, Congress expressly precluded consideration of costs
when setting MACT floors. As explained below, the EPA does not believe
that it is appropriate to consider costs when
[[Page 9324]]
determining whether to regulate EGUs under CAA section 112.
Comment: One commenter stated that the EPA has ignored the language
and intent of CAA section 112(n)(1)(A), as interpreted based on
Representative Oxley's statements, and that the Agency's interpretation
of this provision violates step one of Chevron. Under Chevron where the
``intent of Congress is clear,'' that is the ``end of the matter,'' for
both the implementing agency and a reviewing court ``must give effect
to the unambiguously expressed intent of Congress.'' Chevron, 467 U.S.
at 842-43. The commenter asserts that the legislative history of CAA
section 112(n)(1)(A) ``sheds considerable light on Congress' unique
approach to regulation of EGUs under CAA Sec. 112.'' According to the
commenter, on April 3, 1990, the Senate passed S. 1630. The Senate bill
would have required EPA to list EGUs under CAA section 112(c) and to
regulate them under the MACT provisions of CAA section 112(d). See S.
1630 section 301, 3 1990 Legis. Hist. at 4407. Thereafter, the House of
Representatives passed a modified version of S. 1630 on May 23, 1990.
This House version substantially changed the provisions of CAA section
112 as they applied to EGUs. See 1 1990 Legis. Hist. at 572-73. The
House version was virtually identical to the current CAA section
112(n)(1)(A), and was ultimately adopted by the conference committee,
enacted by Congress and signed into law. According to the commenter,
Congress expressly rejected the ``list-under-(c)-and-regulate-under-
(d)'' approach that S. 1630 would have applied to EGUs, and that
Congress did choose to apply to other source categories. The commenter
stated that the EPA's interpretation that the Agency is ``required to
establish emission standards for EGUs consistent with the requirements
set forth in section 112(d)'' (Id. at 24,993/3) fails to take the
legislative history into account, and in a footnote, the commenter
states that the Agency erred by not addressing the legislative history
as it did in the 2005 action.
Response: For the reasons stated above, we believe commenter's
reliance on the single statement of one legislator is flawed. In
addition, in a footnote the commenter stated that the EPA recognized
``that it had to address'' the legislative history in its 2005 action,
and that the EPA erred in this case because we did not address the
legislative history. The commenter cites no case law to support its
contention that an Agency must ``address'' unpersuasive legislative
history. Further, in the 2005 action, the EPA relegated to a footnote
the Oxley statement that commenter relies on so heavily even though the
statement supported the interpretation we provided in that rule. We
recognized then what the commenter fails to recognize now, which is
that the Agency cannot argue that the meaning of CAA section
112(n)(1)(A) is clear based on the statements of one legislator.
Furthermore, the Agency's interpretation does not violate Chevron
Step 1. The terms ``appropriate'' and ``necessary'' are ambiguous. The
statements of a lone legislator do not transform those ambiguous words
into a Chevron Step 1 situation.
Moreover, the commenter's assertion that Congress unambiguously
defined the factors to consider in making the appropriate determination
is without merit. We fully explain in the preamble to the proposed rule
the basis for the Agency's interpretation, and we are not revising that
interpretation based on the comments received.
Finally, the EPA notes that the sentence concerning regulation
under CAA section 112(d) that the commenter quotes from the preamble
states, in full: ``Congress did not exempt EGUs from the other
requirements of section 112 and, once listed, the EPA is required to
establish emission standards for EGUs consistent with the requirements
set forth in section 112(d), as described above.'' 76 FR 24993
(emphasis added). The EPA discusses requirements to regulate section
112(c) listed sources under section 112(d) in response to other
comments.
c. Consideration of Both Environmental Effects and Health Effects From
Other Sources
Comment: Several commenters stated that the EPA acts contrary to
congressional intent when the Agency considers itself ``thereby
authorized to consider `environmental effects' and the effects of HAP
emissions from non-EGU sources, in making its `appropriate and
necessary' finding under subparagraph (n)(1)(A).''
Commenters assert that the EPA misreads CAA section 112(n)(1)(B)
and (C) to inject environmental effects in the CAA section 112(n)(1)(A)
determination. According to one commenter the plain language of CAA
section 112(n)(1) establishes that regulation of EGUs is to be
predicated solely on ``hazards to public health'' attributable to HAP
emissions. The legislative history providing that the EPA ``may
regulate [EGUs] only if the studies described in section 112(n) clearly
establish that emissions of any pollutant * * * from such units cause a
significant risk of serious adverse risk to the public health''
confirms that plain language. See Oxley Statement at 1416-17. The
commenter further stated that nothing on the face of CAA section
112(n)(1)(A) indicates that Congress intended that the EPA should (or
must) take into account any additional information that might be
developed through the other studies mentioned in subparagraphs
(n)(1)(B) and (C) (i.e., the Mercury Study \56\ and the NAS Study
\57\), such as HAP emissions from non-EGU sources. The commenter also
identified other provisions of section 112 that specifically require
consideration of environmental effects and states that Congress would
have requires such consideration in CAA section 112(n)(1) if it had
wanted EPA to consider environmental effects.
---------------------------------------------------------------------------
\56\ U.S. EPA. 1997. Mercury Study Report to Congress. EPA-452/
R-97-003. December.
\57\ NAS, 2000.
---------------------------------------------------------------------------
The commenter makes a related assertion that the EPA acts contrary
to congressional intent by assuming authority to assess the ```hazard
to public health or the environment [from] HAP emissions from EGUs
alone' or the `result of HAP emissions from EGUs in conjunction with
HAP emissions from other sources''' (citing 76 FR at 24,988/1).
According to the commenter, the only evident basis for the Agency's
interpretation that, in making its ``appropriate and necessary''
finding, the EPA can (and should) take into account HAP emissions from
sources other than EGUs, is that the Mercury Study authorized by CAA
112(n)(1)(B) references ``mercury emissions from * * * municipal waste
combustion units, and other sources, including area sources,'' in
addition to EGUs. The commenter asserts, however, that subparagraph
(n)(1)(A) identifies the Utility Study as the sole study to inform
EPA's ``appropriate and necessary'' finding. The commenter states that
if Congress had intended that the EPA take into account information
developed through the Mercury Study, Congress ``would not have
specified that the EPA was to predicate its `appropriate and necessary'
finding on the `results of the study required by this subparagraph'
(n)(1)(A).''
Commenter also cites to a number of other section 112 provisions
that expressly address environmental effects and the commenter states
the only conclusion to draw from the inclusion in those provisions and
the absence of such language in section 112(n)(1)(A) is that Congress
intended public health to be the only basis for the appropriate and
necessary finding.
[[Page 9325]]
Response: The commenter again relies in part on the statements of
one legislator to attack EPA's reasoned interpretation of an ambiguous
statute. To the extent the commenter's arguments rely on this limited
evidence, we refer to the response above. As we stated above, CAA
section 112(n)(1) is an ambiguous statutory provision; thus, the EPA's
interpretation, not commenter's, is entitled to considerable deference
if it is a reasonable reading of the statute. Chevron, 467 U.S. at 843-
44. For the reasons described herein and in the proposal, we believe
that we have reasonably interpreted the statutory terms at issue here.
The Agency directs attention to section III.A. of the proposed rule,
which includes a thorough discussion of the Agency's interpretation of
the relevant statutory terms. To the extent the commenters disagree
with EPA's interpretations, the EPA refers back to its discussion in
the proposal and responds to the comments as follows.
The commenter appears to maintain that the EPA must interpret the
scope of the appropriate and necessary finding solely in the context of
the CAA section 112(n)(1)(A) Utility Study, such that only hazards to
public health and only EGU HAP emissions may be considered. The
commenter incorrectly conflates the requirements for the Utility Study
with the requirement to regulate EGUs under CAA section 112 if EPA
determines it is appropriate and necessary to do so. The commenter
concedes that the Agency may consider information other than that
contained in the Utility Study, but only to the extent it relates
specifically to hazards to public health directly attributable to HAP
emissions from EGUs. We agree that we may consider additional
information other than that contained in the Utility Study, as we
stated in the preamble to the proposed rule, because courts do not
interpret phrases like ``after considering the results of'' in a manner
that precludes the consideration of other information. See United
States v. United Technologies Corp., 985 F.2d 1148, 1158 (2nd Cir.
1993) (``based upon'' does not mean ``solely); \58\ see also 76 FR
24988. We further explained in the preamble to the proposed rule that
it was reasonable to interpret the scope of the appropriate and
necessary finding in the context of all three studies required under
CAA section 112(n)(1) because the provision is title ``Electric utility
steam generating units.'' \59\ The commenter has provided little more
than unpersuasive legislative history to support its restrictive
interpretation of our authority. Id.
---------------------------------------------------------------------------
\58\ Several commenters have taken issue with our citation to
United States v. United Technologies Corp. because the language at
issue in that case was ``based upon'' and the language of section
112(n)(1)(A) is ``after considering the results of.'' We believe
that, if anything, ``based upon'' is more prescriptive than ``after
considering the results of'' such that the case supports the
Agency's interpretation that additional information other than the
Utility Study may be considered in making the appropriate and
necessary finding.
\59\ 76 FR 24986-87.
---------------------------------------------------------------------------
The commenter also argues that the statute clearly prohibits the
Agency from considering adverse environmental effects or the cumulative
effects of HAP emissions from EGUs and other sources based on its claim
that the statute is clear when one properly considers the legislative
history. Again, the commenter has provided no support for its
contention other than the statements of one Representative and the
improper conflation of the CAA section 112(n)(1)(A) direction on the
conduct of the Utility Study and the appropriate and necessary finding.
Congress left it to the Agency to determine whether it is appropriate
and necessary to regulate EGUs under CAA section 112 and the statute
does not limit the Agency to considering only hazards to public health
and only harms directly and solely attributable to EGUs.
The commenter stated that Congress specifically told EPA when it
wanted EPA to consider adverse environmental effects in CAA section 112
and cites to several provisions of the Act that require consideration
of adverse environmental effects. The commenter ignores CAA section
112(n)(1)(B), which directs the Agency to consider adverse
environmental effect. In any event, even were we to view section
112(n)(1)(A) in isolation, as the commenter suggests, we still maintain
that we can consider adverse environmental effects under 112(n)(1)(A).
Nothing in section 112(n)(1)(A) precludes consideration of
environmental effects. Congress required the Agency to assess whether
it is appropriate and necessary to regulate EGUs under section 112. We
believe that adverse environmental effects can be considered in the
appropriate analysis. Congress specifically directed the Agency to
consider adverse environmental effects when delisting source categories
pursuant to section 112(c)(9), and thus we believe it is reasonable to
consider such effects when determining whether it is appropriate to
regulate such units under section 112, especially given that Congress
did not limit our appropriate and necessary inquiry to the Utility
Study. See CAA section 112(c)(9)(B)(ii).
Moreover, the other provisions of CAA section 112 that specifically
discuss environmental effects have purposes that are distinguishable
from CAA section 112(n)(1), and we do not believe one can reasonably
draw the conclusion that the commenter does when comparing those
provisions to CAA section 112(n)(1)(A). The lack of a requirement to
consider environmental effects in CAA section 112(n)(1)(A) does not
equate to a prohibition on the consideration of environmental effects
as the commenter concludes. The EPA maintains that it reasonably
concluded that we should protect against identified or potential
adverse environmental effects absent clear direction to the contrary.
Concerning the consideration of the cumulative effect of HAP
emissions from EGUs and other sources, we provided a reasonable
interpretation of the statute and noted that our interpretation, unlike
commenters, does not ``ignore the manner in which public health and the
environment are affected by air pollution. An individual that suffers
adverse health effects as the result of the combined HAP emissions from
EGUs and other sources is harmed, irrespective of whether HAP emissions
from EGUs alone would cause the harm.'' \60\
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\60\ 76 FR 24988.
---------------------------------------------------------------------------
d. Finding for All HAP To Be Regulated
Comment: Several commenters stated that for those EGU HAP for which
the Agency makes no CAA section 112(n)(1)(A) determination, their
regulation under CAA section 112 is not authorized. For example, one
commenter maintains that the Agency could regulate HAP emissions from
EGUs under CAA section 112(n). Accordingly, to the extent that the EPA
reads CAA section 112, as construed by National Lime Ass'n, as
compelling it to regulate all HAP emitted by EGUs, should the Agency
make an ``appropriate and necessary'' determination under CAA section
112(n)(1)(A) with respect to a single HAP (e.g., Hg), the EPA stands
poised to commit a fundamental legal error that will condemn the final
rule on review. Cf., e.g., PDK Laboratories, Inc., 362 F.3d at 797-98;
Holland v. Nat'l Mining Ass'n, 309 F.3d at 817 (where an agency applies
a Court of Appeals ``interpretation * * * because it believed that it
had no choice'' and that it ``was effectively `coerced' to do so,''
then the agency ``cannot be deemed to have exercised its reasoned
judgment'').
Response: We do not agree with the commenter's assertion that
Congress intended EPA to regulate only those EGU HAP emissions for
which an appropriate and necessary finding is
[[Page 9326]]
made, and the commenter has cited no provision of the statute that
states a contrary position. The EPA reasonably concluded that we must
find it ``appropriate'' to regulate EGUs under CAA section 112 if we
determine that a single HAP emitted from EGUs poses a hazard to public
health or the environment. If we also find that regulation is
necessary, the Agency is authorized to list EGUs pursuant to CAA
section 112(c) because listing is the logical first step in regulating
source categories that satisfy the statutory criteria for listing under
the statutory framework of CAA section 112. See New Jersey, 517 F.3d at
582 (stating that ``[s]ection 112(n)(1) governs how the Administrator
decides whether to list EGUs. * * *''). As we noted in the preamble to
the proposed rule, D.C. Circuit precedent requires the Agency to
regulate all HAP from major sources of HAP emissions once a source
category is added to the list of categories under CAA section 112(c).
National Lime Ass'n v. EPA, 233 F.3d 625, 633 (D.C. Cir. 2000). 76 FR
24989.
The commenter does not explain its issues with our interpretation
of how regulation under section 112 works--i.e. making a determination
that a source category should be listed under CAA section 112(c),
listing the source category under CAA section 112(c), regulating the
source category under CAA section 112(d), and conducting the residual
risk review for sources subject to MACT standards pursuant to CAA
section 112(f). Instead, it asserts that our decision is flawed because
the interpretation we provided does not account for all the
alternatives for regulating EGUs under section 112, and that we have
not properly exercised our discretion leading to a fatal flaw in our
rulemaking.
The commenter also ignores the language of section 112(n)(1)(A). As
explained in the proposed rule, the use of the terms section,
subsection, and subparagraph in section 112(n)(1)(A) demonstrates that
Congress was consciously distinguishing the various provisions of
section 112 in directing EPA's action under section 112(n)(1)(A).
Congress directed the Agency to regulate utilities ``under this
section,'' not ``under this subparagraph,'' and accordingly EGUs should
be regulated under section 112 in the same manner as other categories
for which the statute requires regulation. Furthermore, the D.C.
Circuit Court found that section 112(n)(1) ``governs how the
Administrator decides whether to list EGUs'' and that once listed, EGUs
are subject to the requirements of section 112. New Jersey, 517 F.3d at
583. Indeed, the D.C. Circuit Court expressly noted that ``where
Congress wished to exempt EGUs from specific requirements of section
112, it said so explicitly,'' noting that ``section 112(c)(6) expressly
exempts EGUs from the strict deadlines imposed on other sources of
certain pollutants.'' Id. Congress did not exempt EGUs from the other
requirements of section 112, and once listed, the EPA is reasonably
regulating EGUs pursuant to the standard-setting provisions in section
112(d), as it does for all other listed source categories.
The commenter provided no alternative theory for regulating EGUs
under CAA section 112, other than to state that the EPA could regulate
under CAA section 112(n)(1). However, even assuming for the sake of
argument, that we could issue standards pursuant to CAA section
112(n)(1), we would decline to do because there is nothing in section
112(n)(1)(A) that provides any guidance as to how such standards should
be developed. Any mechanism we devised, absent explicit statutory
support, would likely receive less deference than a CAA section 112(d)
standard issued in the same manner in which the Agency issues standards
for other listed source categories. We would also decline to establish
standards under section 112(n)(1) because Congress did provide a
mechanism under CAA sections 112(d) and (f) for establishing emission
standards for HAP emissions from stationary sources and it is
reasonable to use that mechanism to regulate HAP emissions from EGUs.
e. Considering Costs in Finding
Comment: Several commenters assert that the EPA must consider costs
in assessing whether regulation of EGUs is appropriate under CAA
section 112(n)(1)(A). Commenters posit that the EPA's position that
``the term `appropriate' * * * does not allow for the consideration of
costs in assessing whether hazards * * * are reasonably anticipated to
occur based on EGU emissions,'' 76 FR at 24,989/1, does not withstand
scrutiny. According to the commenters, the treatment of ``costs'' under
section 112(c) does not support the Agency's position, and the process
by which sources may be ``delisted'' under section 112(c)(9), including
no consideration of costs, sheds no light on the circumstances under
which it may be ``appropriate'' to regulate EGUs under section
112(n)(1)(A).
Commenters characterize as ``unintelligible'' the EPA's position
that it is ``reasonable to conclude that costs may not be considered in
determining whether to regulate EGUs'' when ``hazards to public health
and the environmental are at issue (citing 76 FR at 24989). ``Two
commenters stated that a natural reading of the term ``appropriate''
would include the consideration of costs. According to the commenters,
something may be found to be ``appropriate'' where it is ``specially
suitable,'' ``fit,'' or ``proper.'' See Webster's Third New
International Dictionary at 106 (1993). The term ``appropriate''
carries with it the connotation of something that is ``suitable or
proper in the circumstances.'' See New Oxford American Dictionary (2d
Ed. 2005). Considering the costs associated with undertaking a
particular action is inextricably linked with any determination as to
whether that action is ``specially suitable'' or ``proper in the
circumstances.'' One commenter notes that in 2005 (70 FR 15994, 16000;
March 29, 2005) the EPA used the dictionary definition of
``appropriate,'' as being ``especially suitable or compatible'' and
that it would be difficult to fathom how a regulatory program could be
either ``suitable'' or ``compatible'' for a given public health
objective without consideration of cost.
One commenter asserts that on the face of CAA section 112(n)(1)(A),
it is clear that the EPA is expected to consider costs. According to
the commenter, that Congress intended that the EPA investigate and
consider ``alternative control strategies'' for emissions as part of
the section 112 (n)(1) Utility Study when making the ``appropriate and
necessary'' determination refutes the notion that the Agency can, and
indeed must, disregard the cost of regulation in making that
determination, because the cost of a given emission ``control
strategy'' is a central factor in any evaluation of ``alternative''
controls.
Further, according to commenters, it is well-settled that CAA
regulatory provisions should be read with a presumption in favor of
considering costs (citing Michigan v. EPA, 213 F.3d 663, 678 (D.C. Cir.
2000)), and the legislative history of section 112(n)(1)(A) confirms
that Congress intended EPA to consider costs (citing Oxley Statement at
1417).
Commenters also assert that the EPA falsely represents that it
``did not consider costs when making the ``appropriate'' determination
in the EPA's December 2000 notice (76 FR at 24,989/2).
Response: The commenters first take issue with EPA's explanation of
why the Agency determined that costs should not be considered in making
the appropriate determination. What
[[Page 9327]]
commenters do not identify is an express statutory requirement that the
Agency consider costs in making the appropriate determination. Congress
treated the regulation of HAP emissions differently in the 1990 CAA
amendments because the Agency was not acting quickly enough to address
these air pollutants with the potential to adversely affect human
health and the environment. See New Jersey, 517 F.3d at 578.
Specifically, following the 1990 CAA amendments, the CAA required the
Agency to list source categories and nothing in the statute required us
to consider costs in those listing decision, and we have not done so
when listing other source categories. Thus, it is reasonable to make
the listing decision, including the appropriate determination, without
considering costs.
The commenters next argue that the Agency is compelled by the
statute to consider costs based on a dictionary definition of
``appropriate'' and the CAA section 112(n)(1)(A) direction to consider
alternative control strategies for regulating HAP emissions in the
Utility Study.
Concerning the definition of ``appropriate'', commenters stated:
Not only is it ``reasonable'' for EPA to consider costs in
determining whether it is ``appropriate'' to regulate EGU HAP
emissions, a natural reading of the term indicates that excluding
the consideration of costs would be entirely unreasonable. Something
may be found to be ``appropriate'' where it is ``specially
suitable,'' ``fit,'' or ``proper.'' See Webster's Third New
International Dictionary at 106 (1993). The term ``appropriate''
carries with it the connotation of something that is ``suitable or
proper in the circumstances.'' See New Oxford American Dictionary
(2d Ed. 2005) at 76. Considering the costs associated with
undertaking a particular action is inextricably linked with any
determination as to whether that action is ``specially suitable'' or
``proper in the circumstances.''
The EPA believes the definition of ``appropriate'' that the
commenters provide wholly support its interpretation and nothing about
the definition compels a consideration of costs. It is appropriate to
regulate EGUs under CAA section 112 because EPA has determined that HAP
emissions from EGUs pose hazards to public health and the environment,
and section 112 is ``specially suitable'' for regulating HAP emissions,
and Congress specifically designated CAA section 112 as the ``proper''
authority for regulating HAP emissions from stationary sources,
including EGUs. Section 112 of the CAA is ``suitable [and] proper in
the circumstances'' because EPA has identified a hazard to public
health and the environment from HAP emissions from EGUs and Congress
directed the Agency to regulate HAP emissions from EGUs under that
provision if we make such a finding. Cost does not have to be read into
the definition of ``appropriate'' as commenter suggests. In addition,
as stated elsewhere in response to comments, the Agency does not
consider costs in any listing or delisting determinations, and the EPA
maintains that it is reasonable to assess whether to list EGUs (i.e.
the appropriate and necessary finding) without considering costs.
The commenters' argument that costs must be considered based on the
CAA section 112(n)(1)(A) requirement to ``develop and describe
alternative control strategies'' in the Utility Study is equally
flawed. The argument is flawed because Congress did not direct the
Agency to consider in the Utility Study the costs of the controls when
evaluating the alternative control strategies. In addition, the EPA did
not consider the costs of the alternative controls in the Utility
Study, as implied by the commenter. Thus, even viewing section
112(n)(1)(A) in isolation, there is nothing in that section that
compels EPA to consider costs. For the reasons described herein, we do
not believe that it is appropriate to consider costs in determining
whether to regulate EGUs under section 112.
Additionally, one commenter attempts to refute EPA's statement in
the preamble to the proposed rule that the EPA did not consider costs
in the 2000 finding by pointing to the only two mentions of cost in
that notice. However, the EPA did not say that costs were not mentioned
in the 2000 finding and a review of the regulatory finding will show
that costs were not considered in the regulatory finding. 65 FR 79830
(December 20, 2000) (``Section III. What is EPA's Regulatory
Finding?'').
f. Considering Requirements of the CAA in ``Necessary''
Comment: Several commenters disagree with EPA's position that it
need consider ``only those requirements that Congress directly imposed
on EGUs through the CAA as amended in 1990,'' for which ``EPA could
reasonably predict HAP emission reductions at the time of the Utility
Study.'' According to the commenters, the statutory language of CAA
section 112(n)(1) requires that the EPA consider the scope and effect
of EGU HAP emissions after the imposition of all of the
``requirements'' of the CAA, not just the Acid Rain program. The
commenter maintains that it would have been easy enough for Congress in
subparagraph 112(n)(1)(A) to specify ``after imposition of the
requirements of Title IV of this chapter,'' but Congress did not. The
commenters further add that the legislative history confirms that
Congress meant something much broader than that, providing that the EPA
is authorized to regulate EGUs under CAA section 112 only after
``taking into account compliance with all provisions of the act and any
other Federal, State, or local regulation and voluntary emission
reductions.'' The commenters stated that the CAA's ``requirements''
include the submission by states of ozone and fine PM attainment
demonstrations, as well as SIP provisions needed to reach attainment of
the NAAQS because such provisions could include controls on EGUs to
reduce SO2 and NOX, which controls could also
result in a reduction in Hg emissions.
Response: The commenter's characterization of the facts is flawed
and its reliance on legislative history that is in direct conflict with
the express terms of the statute is unpersuasive.
On the facts, the EPA explained in the preamble to the proposed
rule its interpretation of the phrase ``after imposition of the
requirements of [the Act]'' as it related to the conduct of the Utility
Study.\61\ We reasonably concluded that, since Congress only provided 3
years after enactment to conduct the study, the phrase referred to
requirements that were directly imposed on EGUs through the CAA
amendments and for which the Agency could reasonably predict co-benefit
HAP emission reductions. Id. The EPA did not state that the phrase only
applied to the Acid Rain program, as commenter asserts, and the Utility
Study in fact discussed other regulations, including the NSPS for EGUs
and revised NAAQS. With regard to the latter, the EPA ultimately
determined that it could not sufficiently quantify the reductions that
might be attributable to the NAAQS because states are tasked with
implementing those standards. See Utility Study, pages ES-25, 1-3, 2-
32. Conversely, commenter's position is that the EPA must consider
implementation of all the requirements of the CAA, but it does not
indicate how in conducting the Utility Study the Agency could have
possibly considered co-benefit HAP reductions attributable to all
future CAA requirements. The Agency appropriately considered the other
requirements of the Act in the Utility Study and considered those
requirements in determining that it was
[[Page 9328]]
necessary to regulate coal- and oil-fired EGUs in December 2000.
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\61\ 76 FR 24990.
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Although not required, the Agency in the preamble to the proposed
rule conducted further analyses in support of the 2000 finding. In
doing so, we considered a number of requirements that far exceed what
Congress contemplated when enacting CAA section 112(n)(1)(A)), and our
analyses still show that it remains necessary to regulate coal- and
oil-fired EGUs under section 112. 76 FR 24991.
We maintain that we have reasonably interpreted the requirement to
consider the hazards to public health and the environment reasonably
anticipated to occur after imposition of the requirements of the Act as
explained in the preamble to the proposed rule.\62\ In addition, as
stated above, we also believe it would be reasonable to find it
necessary to regulate HAP emissions from EGUs based on our finding that
such emissions pose a hazard to public health and the environment today
without considering future reductions that we currently project to
occur as the result of imposition of CAA requirements that are not yet
effective (e.g., CSAPR).
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\62\ 76 FR 24990.
---------------------------------------------------------------------------
Moreover, Representative Oxley's statement cited by the commenter
is not consistent with the express terms of CAA section 112(n)(1)(A) on
this issue. Representative Oxley stated that the EPA was to take ``into
account compliance with all the provisions of the act and any other
Federal, State, or local regulation and voluntary emission
reductions,'' but CAA section 112(n)(1)(A) directs the Agency to
consider ``imposition of the requirements of this chapter,'' which
means the CAA. The Agency reasonably focused on the requirements of the
Clean Air Act, which are federally enforceable, and declined to include
potential future reductions that may be attributable to voluntary
emission reduction programs or state and local regulations that have no
basis in the Clean Air Act and are not federally enforceable. In
addition to the statutory direction not to consider such requirements,
the EPA believes it is reasonable not to include potential reductions
attributable to such requirements because the Agency cannot assure that
such requirements and the attendant HAP reductions will remain absent
regulation under section 112. Finally, the commenter implies that EPA's
position is that the Agency will only consider requirements of the Act
that directly regulate HAP emissions. The EPA never stated or suggested
that interpretation and a fair reading of the proposed rule will
demonstrate that EPA considered requirements that achieve co-benefit
HAP emission reductions, for example the Transport Rule (known as
CSAPR).
Comment: One commenter stated that, under CAA section 112,
regulating EGUs is permissible only insofar as it is focused, targeted,
and predicated on concrete findings by the Agency that such regulation
is indeed ``necessary.'' According to the commenter, the EPA construes
CAA section 112(n)(1)(A) as permitting it to find that it is
``necessary'' to regulate EGUs even where the Agency does not actually
know whether it is ``necessary'' to regulate EGUs. Citing the D.C.
Circuit, the EPA suggests that ```there are many situations in which
the use of the word `necessary,' in context, means something that is
done, regardless of whether it is indispensible,''' in order to
```achieve a particular end.''' 76 FR 24990, quoting Cellular
Telecommunications v. FCC, 330 F.3d 502, 510 (D.C. Cir. 2003). The
commenter stated that in the ``context'' of CAA section 112(n)(1)(A),
as informed by the relevant legislative history from Representative
Oxley, it is clear that regulation of EGU HAP emissions can be
considered ``necessary'' only if EPA were to ``clearly establish'' that
such regulation was effectively ``indispensible'' to address the
identified harm. As EPA concedes that it has made no such determination
here, its proposal is fatally flawed for that reason alone.
The commenter further asserts that the EPA erred when it concluded
that it may `` `determine it is necessary to regulate under section
112' when the Agency is `uncertain whether imposition of the
requirements of the CAA will address the identified hazards''' (citing
76 FR at 24,991/3). According to the commenter, the EPA ``cannot take
refuge in its own `uncertainty' to support a finding that it is
`necessary' to regulate EGUs under section 112, and the Act precludes
the EPA from ```err[ing] on the side of regulation''' in face of
uncertainty (id.). The commenter also implies that the finding was
based on non-HAP emissions.
Response: The commenter again relies on the legislative statements
of one Representative and asserts that the statements are controlling.
The EPA disagrees with commenter and maintains that its interpretation
of the term ``necessary'' is reasonable. 76 FR 24990-92 (Section
III.A.2.b of the preamble to the proposed rule contains the EPA's
interpretation of the term ``necessary''.) 76 FR 24990-92 (Section
III.A.2.b of the proposed rule contains EPA's interpretation of the
term ``necessary''.) The commenter also, in a footnote, implies that
EPA based the appropriate and necessary finding on non-HAP air
pollution. The commenter is wrong as explained in more detail above.
As an initial matter, this comment is only addressing one aspect of
the Agency's interpretation of the term necessary. As EPA stated at
proposal:
If we determine that the imposition of the requirements of the
CAA will not address the identified hazards, EPA must find it
necessary to regulate EGUs under section 112. Section 112 is the
authority Congress provided to address hazards to public health and
the environment posed by HAP emissions and section 112(n)(1)(A)
requires the Agency to regulate under section 112 if we find
regulation is ``appropriate and necessary.'' If we conclude that HAP
emissions from EGUs pose a hazard today, such that it is
appropriate, and we further conclude based on our scientific and
technical expertise that the identified hazards will not be resolved
through imposition of the requirements of the CAA, we believe there
is no justification in the statute to conclude that it is not
necessary to regulate EGUs under section 112.
76 FR 24991.
The EPA has determined that the imposition of the requirements of
the CAA will not address the hazards to public health or hazards to the
environment that EPA has identified; therefore, it is necessary to
regulate EGUs under CAA section 112.
The EPA further interpreted the statute to allow the Agency to find
that it is necessary to regulate EGUs under other circumstances, and it
is with one of our additional interpretations that commenter takes
issue. Specifically, the commenter argues that EPA's interpretation
authorizes the Agency to find it necessary to regulate EGUs when we are
uncertain it is necessary, but that misconstrues our interpretation and
the record. At proposal, the EPA stated:
In addition, we may determine it is necessary to regulate under
section 112 even if we are uncertain whether the imposition of the
requirements of the CAA will address the identified hazards.
Congress left it to EPA to determine whether regulation of EGUs
under section 112 is necessary. We believe it is reasonable to err
on the side of regulation of such highly toxic pollutants in the
face of uncertainty. Further, if we are unsure whether the other
requirements of the CAA will address an identified hazard, it is
reasonable to exercise our discretion in a manner that assures
adequate protection of public health and the environment. Moreover,
we must be particularly mindful of CAA regulations we include in our
modeled estimates of future emissions if they are not
[[Page 9329]]
final or are still subject to judicial review ([e.g.], the Transport
Rule). If such rules are either not finalized or upheld by the
Courts, the level of risk would potentially increase.
Id.
The CAA requires EPA to exercise its discretion in determining
whether regulation under section 112 is necessary, and the D.C. Circuit
has stated that ``there are many situations in which the use of the
word `necessary,' in context, means something that is done, regardless
of whether it is indispensible, to achieve a particular end.'' See
Cellular Telecommunications & Internet Association, et al. v. FCC, 330
F.3d 502, 510 (D.C. Cir. 2003). The EPA's interpretation of
``necessary'' is reasonable in the context of CAA section 112(n)(1)(A).
The commenter stated that EPA concedes that the Agency has not
``clearly established'' that regulation of HAP emissions under CAA
section 112 is ``indispensible.'' The EPA has conceded nothing but,
more importantly, the supposed standard that the commenter presents for
evaluating whether it is necessary to regulate HAP emissions from EGUs
is not required by the statute. Even the limited legislative history on
which the commenter incorrectly relies does not espouse such a
standard. The commenter specifically takes issue with EPA's statement
that the Agency may find it is necessary to regulate EGUs under CAA
section 112 if we are ``uncertain whether imposition of the other
requirements of the CAA will sufficiently address the identified
hazards.'' 76 FR at 24990. The commenter has again misinterpreted the
Agency's position by stating that ``EPA construes CAA section
112(n)(1)(A) as permitting it to find that it is ``necessary'' to
regulate EGUs even where the Agency does not actually know whether it
is ``necessary'' to regulate EGUs.'' Instead, the EPA maintains that it
may be necessary to regulate EGUs under CAA section 112 if we identify
a hazard to public health or the environment that is appropriate to
regulate today and our projections into the future do not clearly
establish that the imposition of the requirements of the CAA will
address the identified hazard in the future. Making a prediction about
future emission reductions from a source category is difficult for
statutory provisions that do not mandate direct control of the given
source category or pollutants of concern. We maintain that erring on
the side of caution is appropriate when the protection of public health
and the environment from HAP emissions is not assured based on our
modeling of future emissions.
Furthermore, as we stated in the preamble to the proposed rule, we
believe it would be reasonable to find it appropriate and necessary to
regulate EGUs under section 112 today based on a determination that HAP
emissions from EGUs pose a hazard to public health and the environment
without considering future HAP emission reductions. 76 FR 24991, n.14.
We maintain this is reasonable because ``Congress could not have
contemplated in 1990 that EPA would have failed in 2011 to have
regulated HAP emissions from EGU's where hazards to public health and
the environment remain.'' Id. The phrase ``after imposition of the
requirements of [the Act]'' as contemplated CAA section 112(n)(1)(A)
could be read to apply only to those requirements clearly and directly
applicable to EGUs under the 1990 CAA amendments, all of which have
been implemented and still hazards to public health and the environment
from HAP emissions from EGUs remain.
g. Listing EGUs Under 112
Comment: One commenter stated that even if EPA were to establish
under CAA section 112(n)(1)(A) that it is ``appropriate and necessary''
to regulate HAP emissions from EGUs, regulating those emissions in the
form of a MACT standard established pursuant to CAA section 112(d) is
contrary to the plain language of the Act. According to the commenter,
if EPA proceeds to finalize the proposal and adopts such a standard,
the rule will for this reason alone be ``dead-on-arrival''. According
to the commenter, the EPA apparently believes that its only option in
regulating EGU HAP emissions is establishing a MACT standard under CAA
section 112(d). In the preamble to its proposal, the commenter states
that EPA contends that, ``once the appropriate and necessary finding is
made,'' EGUs are then ``subject to section 112 in the same manner as
other sources of HAP emissions''--i.e., by ``listing'' EGUs under CAA
section 112(c) and adopting a MACT standard under CAA section 112(d).
See 76 FR 24993/2 (emphasis added). The commenter further stated that,
given that Congress ``directed the Agency to regulate utilities `under
this section' [i.e., CAA section 112],'' EPA continues, it follows that
``EGUs should be regulated in the same manner as other categories for
which the statute requires regulation.'' Id. (emphasis added). The
commenter asserts that as EPA sees it, because ``Congress did not
exempt EGUs from the other requirements of section 112,'' once EGUs
were ``listed'' under CAA section 112(c), the Agency was ``required to
establish emission standards for EGUs consistent with the requirements
set forth in section 112(d).'' Id. at 24,993/3 (emphasis added).
The commenter stated that, in support of this reading of the CAA,
the EPA invokes the decision of the U.S. Court of Appeals for the D.C.
Circuit in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). The
commenter further alleged that, according to EPA, the D.C. Circuit has
``already held that section 112(n)(1) `governs how the Administrator
decides whether to list EGUs.' '' See 76 FR 24993/2-3, quoting 517 F.3d
at 583. The commenter stated that EPA construes that holding as
indicating that, ``once listed, EGUs are subject to the requirements of
section 112''--including, the EPA presumes, CAA section 112(d). Id. The
commenter stated that elsewhere, the EPA construes CAA section
112(n)(1) (A) as ``govern[ing] how the Administrator decides whether to
list EGUs for regulation under section 112,'' and quotes the D.C.
Circuit's observation in New Jersey that ``Section 112(n)(1) governs
how the Administrator decides whether to list EGUs; it says nothing
about delisting EGUs.'' See 76 FR 24981/2, quoting 517 F.2d at 582.
The commenter asserts that EPA misinterprets the ``under this
section'' language of CAA section 112(n)(1); overstates the
significance of the New Jersey decision; and, as a consequence,
misapprehends the scope of its own discretion to formulate regulatory
standards for EGUs under CAA section 112. In light of these errors, the
commenter maintains that EPA should withdraw the proposed MACT rule.
One commenter stated that if Congress had intended that EPA
regulate EGU HAP emissions only through a MACT standard, Congress could
have--and presumably would have--directed the Agency to regulate EGU
emissions ``under CAA section 112(d).'' Thus, the commenter maintained
that EPA's authority to regulate EGU HAP emissions is not derived from
any particular subsection of CAA section 112. Rather, the commenter
stated that EPA is authorized to regulate ``under this section''--i.e.,
CAA section 112 generally--as may be ``appropriate and necessary.'' The
commenter stated that there is nothing on the face of CAA section
112(n)(1)(A) that specifies that regulation of EGUs must occur under
CAA section 112(d). To the contrary, according to the commenter, a
plain reading of CAA section 112(n)(1)(A), as interpreted based on the
Oxley statement, indicates that establishing a
[[Page 9330]]
MACT standard for EGUs under CAA section 112(d) is not what Congress
had in mind at all.
Response: We do not agree with the commenter. The EPA interpreted
CAA section 112(n)(1)(A) in a manner that gives meaning to all the
words used in the provision. See NRDC v. EPA, 489 F.3d 1364, 1373 (D.C.
Cir. 2007) (admonishing EPA for an interpretation of CAA section
112(c)(9) that ignored certain words and the context in which they were
used. The Court stated that ``EPA's interpretation would make the words
redundant and one of them `mere surplusage,' which is inconsistent with
a court's duty to give meaning to each word used by Congress.'')
(citing TRW Inc. v. Andrews, 534 U.S. 19, 31, 122 S. Ct. 441, 151 L.
Ed. 2d 339 (2001)). Specifically, in the preamble to the proposed rule,
we stated:
The statute directs the Agency to regulate EGUs under section
112 if the Agency finds such regulation is appropriate and
necessary. Once the appropriate and necessary finding is made, EGUs
are subject to section 112 in the same manner as other sources of
HAP emissions. Section 112(n)(1)(A) provision provides, in part,
that: `[t]he Administrator shall perform a study of the hazards to
public health reasonably anticipated to occur as a result of
emissions by electric utility steam generating units of pollutants
listed under subsection (b) of this section after imposition of the
requirements of this chapter. * * * The Administrator shall regulate
electric utility steam generating units under this section, if the
Administrator finds such regulation is appropriate and necessary
after considering the results of the study required by this
subparagraph.'' Emphasis added.
In the first sentence, Congress described the study and directed
the Agency to evaluate the hazards to public health posed by HAP
emissions listed under subsection (b) (i.e., CAA section 112(b)). The
last sentence requires the Agency to regulate under this section (i.e.,
CAA section 112) if the Agency finds such regulation is appropriate and
necessary after considering the results of the study required by this
subparagraph (i.e., CAA section 112(n)(1)(A)). The use of the terms
``section'', ``subsection'', and ``subparagraph'' demonstrates that
Congress was consciously distinguishing the various provisions of CAA
section 112 in directing the conduct of the study and the manner in
which the Agency must regulate EGUs if the Agency finds it appropriate
and necessary to do so. Congress directed the Agency to regulate
utilities ``under this section,'' and accordingly EGUs should be
regulated in the same manner as other categories for which the statute
requires regulation. See 76 FR 24993.
We maintain that our interpretation of the statute gives meaning to
all the words, and the commenter's interpretation does not give any
particular meaning to the requirement to ``regulate under this section
[112]''. The commenter is correct that Congress could have in CAA
section 112(n)(1)(A) directed EPA to regulate HAP from EGUs under CAA
section 112(d) after making the appropriate and necessary finding, but
the commenter presumes too much when it stated that Congress would have
directed the Agency to regulate HAP emissions from EGUs in such a
manner if that is what Congress wanted, simply by including the phrase
``regulate under this paragraph'' or ``regulate under this
subparagraph'' instead of directing the Agency to ``regulate under this
section''. It did not do so.
As we explained in the section II.A. of the proposed rule, CAA
section 112 establishes a mechanism to list and regulate stationary
sources of HAP emissions. 76 FR 24980-81. Regulation under CAA section
112 generally requires listing under CAA section 112(c), regulation
under CAA section 112(d), and, for sources subjected to MACT standards,
residual risk regulations under CAA section 112(f) (as necessary to
protect human health and the environment with an ample margin of
safety). A determination that EGUs should be listed once the
prerequisite appropriate and necessary finding is made is wholly
consistent with the language of section 112(n)(1)(A), and listed
sources must be regulated under CAA section 112(d). See CAA section
112(c)(2); see also New Jersey, 517 F.3d at 583 (112(n)(1)(A) ``governs
how the Administrator decides whether to list EGUs'').
As noted above, Congress used the terms section, subsection, and
subparagraph in section 112(n)(1)(A). The use of these three terms
demonstrates that Congress was consciously distinguishing between the
various provisions of section 112. Congress directed the Agency to
regulate utilities ``under this section,'' and accordingly EGUs should
be regulated in the same manner as other categories for which the
statute requires regulation.
Furthermore, the flaws in the commenter's interpretation are
highlighted by other CAA section 112 provisions wherein Congress
provided specific direction as to the manner of regulation. For
example, CAA section 112(m)(6) requires the Administrator to determine
``whether the other provisions of this section [112] are adequate'' and
also indicates that ``[a]ny requirements promulgated pursuant to this
paragraph * * * shall only apply to the coastal waters of the States
which are subject to [section 328 of the CAA].'' (emphasis added).
In addition, CAA section 112(n)(3) provides that when the Agency is
``promulgating any standard under this section [112] applicable to
publicly owned treatment works, the Administrator may provide for
control measures that include pretreatment of discharges causing
emissions of hazardous air pollutants and process or product
substitutions or limitations that may be effective in reducing such
emissions.'' Finally, CAA section 112(n)(5) directs the Agency to
assess hydrogen sulfide emissions from oil and gas extraction and
``develop and implement a control strategy for emissions of hydrogen
sulfide to protect human health and the environment * * * using
authorities under [the CAA] including [section 111] of this title and
this section [112].'' (emphasis added). We believe these provisions
provide ample evidence that Congress knew how to alter or caveat
regulation under CAA section 112 when that was its intent. For these
reasons, we believe commenter's argument is without merit.
Comment: Two commenters stated that CAA section 112(n)(1)(A) does
not specify that regulation of EGUs must proceed under CAA section
112(d). According to the commenter, an argument could be made,
therefore, that the CAA accords EPA with the discretion to regulate
EGUs using strategies other than emission standards in CAA section
112(d). The commenters also state that section 112(n)(1)(A) of the CAA
requires that EPA ``develop and describe'' alternative control
strategies for emissions which may warrant regulation under CAA section
112. According to the commenters if Congress meant for EPA to have one
sole regulatory option, i.e., regulation of EGUs only under CAA section
112(d), then the development of alternative control strategies would be
rendered meaningless because under CAA section 112(d)(3), the EPA is
required to determine the level of control that is achieved by the best
performing existing units for which it has data and then to impose that
level of control on all existing units. The commenter further states
that the development of ``alternative control strategies'' has no role
to play in this process. One commenter does note that the consideration
of ``alternative'' controls becomes relevant, if at all, only in those
circumstances where EPA might seek to establish a ``Beyond-the-Floor''
MACT standard pursuant to CAA section 112(d)(2).
[[Page 9331]]
Response: The commenters are correct that CAA section 112(n)(1)(A)
directed the Agency to develop and describe in the Utility Study report
to Congress alternative control strategies for HAP emissions from EGUs
that may warrant regulation in the Utility Study, but the commenters'
interpretation of and conclusion based on that language are both
factually and legally inaccurate.
The commenters appear to interpret the word ``alternative control
strategies'' to mean something other than the traditional control
technologies and control measures that are used to control HAP
emissions from EGUs. We do not believe that is a reasonable
interpretation of the statute, and the Agency did not interpret the
statute in that manner when it conducted the Utility Study. In Chapter
13 of the Utility Study, the EPA considered a range of control measures
that would reduce the different types of HAP emitted from EGUs. https://www.epa.gov/ttn/atw/combust/utiltox/eurtc1.pdf. The EPA considered pre-
combustion controls such as coal washing, fuel switching, and
gasification; combustion controls such as boiler design; post-
combustion controls such as fabric filters, scrubbers, and carbon
absorption; and alternative controls strategies such as demand-side
management, energy conservation, and use of alternative fuels (e.g.,
biomass) or renewable energy. The options discussed in the Utility
Study for controlling HAP emissions from EGUs are almost universally
available to comply with a CAA section 112(d) standard.
Given the manner in which the Agency conducted the Utility Study,
the EPA interpreted the statutory direction as a requirement to set
forth the potential alternative control options available to EGUs to
comply with CAA section 112 standards in the event the Agency
determined regulation under section 112 was appropriate and necessary.
The EPA's development and discussion in the Utility Study of
alternative control strategies for complying with the standards would
help prepare EGUs to comply with the standards if promulgated. Thus,
the EPA interpreted the direction to address control strategies in the
Utility Study as a request to identify the controls available to EGUs
for addressing HAP emissions, and such information would, of course, be
relevant if EPA determined that such emissions warranted regulation
under section 112.
Furthermore, the EPA establishes CAA section 112(d) standards for
stationary sources and it is the responsibility of the sources to
comply with the standards using any mechanism available, including pre-
combustion and post-combustion measures. Also, the establishment of a
MACT standard under CAA section 112(d)(2) and (3) is a two-step
process. In the first step, the Agency establishes a floor based on the
performance of the best controlled unit or units. See CAA section
112(d)(3). In the second step, the Agency must consider additional
measures that may reduce HAP emissions and adopt such measures if
reasonable after considering costs and non-air quality health and
environmental effects. See CAA section 112(d)(2). Under the second
step, the Agency can consider any measure that reduces HAP emissions
even if no source in the category is employing the option under
consideration. So, even under the commenter's flawed interpretation of
``alternative control strategies'', the direction in CAA section
112(n)(1)(A) is not a ``pointless exercise'' for the development of CAA
section 112(d) standards as the Agency considers relevant technologies
and HAP emission reduction approaches in evaluating whether to set a
more stringent beyond the floor standard.
Comment: One commenter points to CAA section 307(d)(1)(C) and notes
that CAA section 112(n) is listed among the provision for which the
rulemaking requirements of CAA 307(d) apply. Commenter maintains that
this inclusion creates an expectation under the statute that EPA may
establish regulatory standards under CAA 112(n). The commenter points
to CAA sections 112 (n)(1), (n)(3), and (n)(5) and states that those
provisions specifically discuss regulation under CAA section 112 and
that EPA must explain why CAA 307(d)(1)(C) states ``any regulation
under'' CAA 112(n) to defend regulation of utilities under section
112(d). The commenter then implies that EPA erred by not even
mentioning this provision at proposal.
The commenter also takes issue with EPA's statement in the proposed
rule that ``use of the terms section, subsection, and subparagraph''
``demonstrates that Congress was consciously distinguishing the various
provisions of section 112 in directing the conduct of the study and the
manner in which the Agency must regulate EGUs,'' if EPA determines that
it is appropriate and necessary to regulate EGUs. See 76 FR at 24,993/
2.
One commenter does not agree with the EPA's finding that the word
``subsection'' in the first sentence of CAA section 112(n)(1)(A)
demonstrates that Congress was consciously distinguishing between the
various provisions of CAA section 112 in directing the conduct of the
study and the manner in which the Agency must regulate EGUs,'' were the
EPA to ``find[ ] it appropriate and necessary to do so.'' See 76 FR
24993/2. According to the commenter, the only evident reason that the
word ``subsection'' is used in the first sentence of CAA section
112(n)(1)(A) is because the reference is made to the ``pollutants''
which the Utility Study is to address--i.e., the ``pollutants'' that
are emitted by EGUs and which are ``listed under subsection (b)'' of
CAA section 112. Similarly, the word ``subparagraph'' is used in the
last sentence of CAA section 112(n)(1)(A) to identify ``the study''
which the EPA is directed to undertake by subparagraph (A) of CAA
section 112(n)(1)--i.e., the Utility Study. That the last sentence of
subparagraph (n)(1)(A) also states that EPA ``shall regulate electric
utility steam generating units under this section'' does not even
imply--much less expressly communicate--that regulation ``under this
section'' must mean ``regulation under section 112(d).'' The commenter
stated that Congress was ``consciously distinguishing'' between the
``various provisions of section 112'' for the sake of clarity in the
drafting of CAA section 112(n).
The commenter also asserts that the EPA mistakenly relies on
section 112(c)(6) when the EPA states that `` `where Congress wished to
exempt EGUs from specific requirements of section 112, it said so
explicitly. Congress did not exempt EGUs from the other requirements of
section 112,' '' and thus the Agency is `` `required to establish
emission standards for EGUs consistent with the requirements set forth
in section 112(d)' '' (citing 76 FR at 24,993 (internal quotation
omitted)).
According to the commenter, nothing in section 112(c)(6) indicates
how (or even whether) EGU HAP emissions should be regulated under
section 112; paragraph (c)(6) serves only to reiterate that the
regulation of such emissions is to occur (if at all) as is provided by
section 112(n)(1). The commenter also asserts that the EPA mistakenly
relies on New Jersey. According to the commenter, the D.C. Circuit in
that case did not indicate that the language of section 112(c)(6)
should, or could, be construed to mean that EGUs must be regulated
under a MACT standard adopted pursuant to section 112(d).
Response: The commenter makes a number of arguments that appear to
take issue with the EPA's determination that EGUs should be regulated
under CAA section 112(d) if the Agency determines that regulation of
HAP emissions from such units is appropriate and necessary.
[[Page 9332]]
The commenter implies that the EPA erred because alternative mechanisms
for regulation of EGUs under CAA section 112 might exist. We do not
agree.
The commenter's argument that the EPA erred because we did not
explain why section CAA section 307(d)(1)(C) contemplates regulations
under CAA section 112(n) is without merit. It is correct that the
Agency believes EGUs should be regulated in the same manner as other
sources if the appropriate and necessary finding is made because of the
structure of CAA section 112. Nothing in CAA section 112(n)(1) requires
or implies that the Agency should or must establish standards for EGUs
under that provision. Furthermore, unlike CAA sections 112(n)(3) and
112(n)(5) that commenter cites, CAA section 112(n)(1)(A) does not
provide any guidance concerning the manner in which EPA is authorized
or required to regulate sources under CAA section 112. See CAA section
112(n)(3) (specifically authorizing identified control measures and
other requirements for consideration in issuing standards under CAA
section 112); see also CAA section 112(n)(5) (directing the Agency to
develop and implement a control strategy for emissions of hydrogen
sulfide using any authority available under the CAA, including sections
112 and 111, if regulation is appropriate). For these reasons, we
disagree that any error occurred because we did not specifically
discuss in this proposed rule whether we could or should regulate EGUs
under CAA section 112(n)(1) instead of CAA section 112(d).\63\ The
Agency validly listed EGUs in 2000 and listed sources must be regulated
pursuant to CAA section 112(d).
---------------------------------------------------------------------------
\63\ We note that in our January 2004 proposed rule, we
solicited comment on whether section 112(n)(1)(A) provided
independent authority to regulate EGUs. We received several comments
on this issue, and we rejected the concept after reviewing the
comments and further considering the language of section
112(n)(1)(A) and the structure of section 112. As such, we proposed
and are finalizing that once the Agency determines that it is
appropriate and necessary to regulate EGUs under section 112, those
sources are listed pursuant to subsection 112(c), as we did in
December 2000, and the Agency must set standards for those sources
pursuant to section 112(d). See section 112(c) and (d)(1) (requiring
establishment of 112(d) standards for listed source categories).
---------------------------------------------------------------------------
Even if we agreed that regulation under CAA section 112(n)(1) was a
viable option for EGUs, we would still have listed and regulated EGUs
like other sources because CAA section 112(d) provides a statutory
framework for regulating HAP emissions from sources and CAA section
112(n)(1) does not. We believe that even if CAA section 112(n)(1) were
available to regulate EGUs, there would be sufficient uncertainty about
the legal vulnerability of such an approach to caution against
employing it. This legal uncertainty would be particularly troubling in
light of the fact that we have identified hazards to public health and
the environment from HAP emissions from EGUs that warrant regulation,
and these regulations are long overdue.
The commenter also takes issue with our statement in the preamble
to the proposed rule that the use of the words ``section'',
``subsection'', and ``subparagraph'' in CAA section 112(n)(1)(A)
``demonstrates that Congress was consciously distinguishing the various
provisions of section 112 in directing the conduct of the study and the
manner in which the Agency must regulate EGUs.'' See 76 FR 24993. The
commenter appears to make much of our use of the word ``must'' in that
sentence and also states that our interpretation of the significance of
the use of the three terms in CAA section 112(n)(1)(A) is flawed
because Congress only used the three terms for purposes of clarity. The
commenter is incorrect on both points. With respect to the commenter's
concern regarding the use of the word ``must'' in the sentence quoted
above, we note that in the next sentence we stated that ``Congress
directed the Agency to regulate utilities `under this section,' and
accordingly EGUs should be regulated in the same manner as other
categories for which the statute requires regulation.'' Id. (emphasis
added). We were not foreclosing the possibility of any alternative
interpretation and our use of the term ``must'' should not detract from
the point we were trying to make. Specifically, we believe that
Congress would have directed us to regulate EGUs under CAA section
112(n)(1)(A) if that was its intent and, absent that mandate, the
better reading of the statute is the one provided in the preamble to
the proposed rule, which is that EGUs should be listed pursuant to CAA
section 112(c) and subject to CAA section 112(d) emission standards.
The commenter also stated that the EPA relied on CAA section
112(c)(6) to support a conclusion that EGUs must be regulated under CAA
section 112(d). The commenter takes the EPA's statements out of
context. The statement in whole read:
Furthermore, the D.C. Circuit Court has already held that
section 112(n)(1) ``governs how the Administrator decides whether to
list EGUs'' and that once listed, EGUs are subject to the
requirements of CAA section 112. New Jersey, 517 F.3d at 583.
Indeed, the D.C. Circuit Court expressly noted that ``where Congress
wished to exempt EGUs from specific requirements of section 112, it
said so explicitly,'' noting that ``section 112(c)(6) expressly
exempts EGUs from the strict deadlines imposed on other sources of
certain pollutants.'' Id. Congress did not exempt EGUs from the
other requirements of CAA section 112, and once listed, EPA is
required to establish emission standards for EGUs consistent with
the requirements set forth in CAA section 112(d), as described
below. See 76 FR 24993.
As can be seen from this passage, the Court cited section 112(c)(6)
as an example of Congress' intent regarding regulating EGUs under CAA
section 112. The commenter cited the last clause of the last sentence
of the paragraph quoted above without including the prefatory clause
``once listed,'' and, without that clause, the statement is not fairly
characterized. The point the EPA was making in that paragraph is that
EGUs are a listed source category and listed sources must be regulated
under CAA section 112(d) unless the EPA delists the source category.
Comment: One commenter stated that EPA overstates the significance
of the D.C. Circuit's holding in New Jersey by suggesting that the
decision mandates EGU regulation under CAA section 112(d) because EGUs
``remain listed'' under CAA section 112(c), See New Jersey, 517 F.3d at
582. According to the commenter, the court declined to address the
lawfulness of EPA's having ``listed'' EGUs under CAA section 112(c),
leaving that matter to be decided if and when EPA adopted standards for
EGUs under CAA section 112. Nowhere in the decision did the D.C.
Circuit indicate that EPA must regulate EGUs under CAA section 112(d).
According to the commenter, the EPA must consider both whether the
regulation of EGUs is ``appropriate and necessary'' under section
112(n)(1) and address anew whether the Agency is authorized by section
112 to list EGUs under section 112(c) at all. The commenter asserts
that on the face of the proposal, the EPA has not revisited the
question whether the ``listing'' of EGUs under section 112(c) is
consistent with congressional intent.
Response: The commenter's arguments are circular and it is
difficult to fully determine exactly what its issue is with EPA's
listing; however, it appears that the commenter believes that EPA
incorrectly relied on the New Jersey decision to justify the listing of
EGUs. The commenter also appears to argue that the Agency has never
explained why it has the authority to list EGUs at all. We disagree.
As stated in the preamble to the proposed rule, CAA section
112(n)(1)(A)
[[Page 9333]]
requires EPA to conduct a study of HAP emissions from EGUs and regulate
EGUs under CAA section 112 if we determine that regulation is
appropriate and necessary, after considering the results of the study.
76 FR 24981, 24986, and 24998. The only condition precedent to
regulating EGUs under CAA section 112 is a finding that such regulation
is appropriate and necessary (after conducting and considering the
Utility Study), and once that finding is made the Agency has the
authority to list EGUs under CAA section 112(c) as the first step in
the process of establishing regulations under section 112. The D.C.
Circuit agrees with that interpretation of the statute as evidenced by
its statement in New Jersey that ``section 112(n)(1)(A) governs how the
Administrator decides whether to list EGUs for regulation under section
112,'' 517 F.3d at 582, and the Court's statement directly contradicts
the commenter's position.
The EPA did not rely on the New Jersey decision to justify the
appropriate and necessary finding as the commenter suggests. We based
the finding in 2000 on the extensive information available to the
Agency at the time, and we confirmed the finding in the preamble to the
proposed rule based on new information. The commenter had ample
opportunity to comment on the appropriate and necessary finding, and it
may challenge the basis of the listing (i.e. the appropriate and
necessary finding) when EPA issues the final standards.
Comment: One commenter believes that the D.C. Circuit will condemn
the final rule as a result of EPA's ``misapprehension'' that upon
making an ``appropriate and necessary'' finding, the Agency is
compelled by the CAA to adopt a regulatory standard for EGUs under CAA
section 112(d). According to the commenter, a regulation will be
invalid if the regulation `` `was not based on the [agency's] own
judgment' '' but `` `rather on the unjustified assumption that it was
Congress' judgment that such [a regulation] is desirable' or
required.'' See Transitional Hospitals Corp. v. Shalala, 222 F.3d 1019,
1029 (D.C. Cir. 2000), quoting Prill v. NLRB, 755 F.2d 941, 948 (D.C.
Cir. 1985). The commenter further notes that the D.C. Circuit has held
that, where an agency wrongly construes a judicial decision as
compelling a particular statutory interpretation, and thereby unduly
limits the scope of its own discretion, the agency's action cannot be
sustained. See, e.g., Phillips Petroleum Co. v. FERC, 792 F.2d 1165,
1171 (D.C. Cir. 1986). The commenter believes the rule is bound to be
rejected and that the EPA should ``reconsider the legal interpretations
on which it purports to base its rule.''
Response: We do not agree that we have improperly interpreted the
statute as limiting our discretion in the manner suggested by the
commenter. The commenter makes only one specific allegation in this
comment and that concerns the Agency's conclusion that it must
establish CAA section 112(d) standards for EGUs in light of the New
Jersey decision. The commenter does not explain why that conclusion is
incorrect. As we state above and in the preamble to the proposed rule,
because EGUs are a CAA section 112(c) listed source category, the
Agency must establish CAA section 112(d) standards or delist EGUs
pursuant to CAA section 112(c)(9). See New Jersey, 517 F.3d at 582-83
(holding that EGUs remain listed under section 112(c)); see also CAA
section 112(c)(2) (requiring the Agency to ``establish emission
standards under subsection [112] (d)'' for listed source categories and
subcategories); 76 FR 24998-99. We concluded in the preamble to the
proposed rule that we could not delist EGUs because our appropriate and
necessary analysis showed that EGUs did not satisfy the CAA section
112(c)(9)(B)(i) delisting criteria. Id. We did not address in the
preamble to the proposed rule whether EGUs satisfied the CAA section
112(c)(9)(B)(ii) criteria because EGUs failed the first prong of the
delisting provisions. Id. We reach the same conclusion in the final
rule and also address the delisting petition submitted by this
commenter. Because we cannot delist EGUs, we must regulate them under
CAA section 112(d). The commenter has provided no legitimate argument
to rebut this conclusion. See also previous responses regarding
regulation under section 112(n)(1)(A).
Comment: One commenter alleges that EPA impermissibly relied on CAA
section 112(c)(9) to interpret ``hazards to public health'', and argues
that the ``residual risk'' provisions in CAA section 112(f)(2) are more
appropriate for the establishment of standards for EGUs. The commenter
stated that by using CAA section 112(c)(9)(B)(i) in defining ``hazards
to public health'', the Agency has seized on the one interpretation of
the phrase that is surely contrary to congressional intent and, thus,
falls outside the permissible range of its interpretative discretion.
The commenter maintains that the ``delisting'' criteria of CAA section
112(c)(9) are simply irrelevant to the decision whether EGU HAP
emissions will present any ``hazards to public health'' sufficient to
warrant regulation of those emissions under CAA section 112.
The commenter also argues that Congress intended that EGUs be
treated differently from all other ``major sources'' to which the
``delisting'' provisions of CAA section 112(c)(9), and the standard-
setting provisions of CAA section 112(d) necessarily and automatically
apply. Therefore, according to the commenter, the EPA's proposal to
utilize the criteria of CAA section 112(c)(9) to inform its findings
under CAA section 112(n)(1)(A) treats EGUs exactly the same as all
other major source categories, is contrary to congressional intent, and
thus unlawful. The commenter goes on to state that in exercising its
discretion to define ``hazards to public health'' as the phrase is used
in CAA section 112(n)(1)(A), the EPA would be better served to consider
the ``residual health risk'' provisions of CAA section 112(f)(2). Those
provisions provide a better analogy to the establishment of standards
for EGUs under CAA section 112 than do the ``de-listing'' criteria of
CAA section 112(c)(9).
The commenter believes the category-specific criteria of paragraph
(c)(9) are a poor fit for an evaluation of ``hazards to public health''
that should reasonably include such factors as the affected population,
the characteristics of exposure, the nature of the health effects, and
the uncertainties associated with the data. The commenter states that,
while CAA section 112(n)(1)(A) does not expressly include any
requirement that EGU emissions be regulated with an ``ample margin of
safety,'' that standard is more appropriate than the ``one-in-a-
million'' cancer risk standard of CAA section 112(c)(9)(B)(i) that EPA
proposes to employ.
Response: The commenter acknowledges that EPA has broad discretion
to interpret the phrase ``hazard to public health'' but argues that the
one thing we cannot do is use the CAA section 112(c)(9)(B) delisting
provisions as a benchmark in making that interpretation. The commenter
asserts that the use of the delisting standard is clearly contrary to
Congressional intent but it does not provide any substantive rebuttal
to our conclusion that the CAA section 112(c)(9) standards reflects the
level of hazard which Congress concluded warranted continued
regulation. Instead, the commenter reverted to its argument that the
statute treated EGUs differently. The EPA views the disparate treatment
of EGUs in a different light than commenter. While it is true that
Congress established a different
[[Page 9334]]
statutory provision governing whether to add EGUs as a regulated source
category under section 112, we do not interpret CAA section
112(n)(1)(A) as providing Congressional license to ignore risks that
Congress determined warranted regulation for all other source
categories. Because CAA section 112(c)(9) defines that level of risk,
it is reasonable to consider it when evaluating whether EGU HAP
emissions pose hazards to public health.
The commenter also suggests that the ``ample margin of safety
standard'' of CAA section 112(f)(2) is a better fit than the one-in-a-
million standard set forth in CAA section 112(c)(9)(B)(1) for
evaluating hazards to public health. The commenter asserts that an
evaluation of ``hazards to public health'' should include such factors
as the affected population, the characteristics of exposure, the nature
of the health effects, and the uncertainties associated with the data.
However, the EPA did not rely solely on the delisting provisions for
evaluating hazards to public health as commenter suggests. In fact, the
EPA considered all of the factors the commenter suggests in making our
finding.\64\ Thus, we decline to adjust our approach to evaluating
hazards to public health and the environment based on the comments.
---------------------------------------------------------------------------
\64\ 76 FR 24992.
---------------------------------------------------------------------------
h. 2000 Finding (and 2005 Delisting)
Comment: Several commenters generally support EPA's 2000 finding
that regulating HAP emissions from EGUs under CAA section 112 is
``appropriate and necessary.'' According to the commenters, the 2000
finding was proper under the CAA and within EPA's discretion, well-
supported based on sound science available to the Agency at the time on
the harm from HAP emitted by EGUs, and no additional information makes
the finding invalid. Several commenters cited the conclusions of the
Utility Study \65\ and Mercury Study,\66\ which they assert supported
the finding and satisfied the only prerequisite for the finding. One
commenter specifically asserted that the 2000 finding was well-
supported by the Utility Study's conclusions that (1) there was a link
between anthropogenic Hg emissions and MeHg found in freshwater fish,
(2) Hg emissions from coal-fired utilities were expected to worsen by
2010, and (3) MeHg in fish presents a threat to public health from fish
consumption. One commenter noted that the CAA does not require a
conclusive link between HAP emissions and harm. One commenter stated
that the CAA grants the Administrator discretion in her finding, and
that discretionary decision should not be overly scrutinized, citing
court opinion.\67\ In support of the finding, one commenter stated that
it would not make sense for Congress to limit HAP emissions from small
businesses such as dry cleaners but to exempt U.S. EGUs, which are the
largest sources of many HAP emissions. One commenter agreed that
finding was further supported because numerous control options were
available to reduce HAP emissions. One commenter agreed with the 2000
finding that the Agency lacked sufficient evidence to conclude that
non-Hg HAP from EGUs posed no hazard.
---------------------------------------------------------------------------
\65\ U.S. EPA 1998. Study of Hazardous Air Pollutant Emissions
from Electric Utility Steam Generating Units--Final Report to
Congress. EPA-453/R-98-004a. February.
\66\ U.S. EPA, 1997.
\67\ ``Where a statute is precautionary in nature, the evidence
difficult to come by, uncertain, or conflicting because it is on the
frontiers of scientific knowledge, the regulations designed to
protect the public health, and the decision that of an expert
administrator, [courts] will not demand rigorous step-by-step proof
of cause and effect.'' Ethyl Corp. v. EPA, 541 F.2d 1, 28 (Ct. App.
D.C. Circ. 1978).
---------------------------------------------------------------------------
The commenters who generally supported the 2000 finding also
commented on specific aspects of the finding. Several commenters
asserted that while the evidence on Hg alone supports the finding, the
potential harm from non-Hg HAP further supported the 2000 finding.
Several commenters noted that new science continues to support the 2000
finding. Several commenters also stated that the ``appropriate''
finding was further supported because numerous control options were
available at the time of the finding that would reduce HAP emissions.
One commenter concurred with EPA that regulating natural gas-fired EGUs
was not appropriate and necessary because the impacts due to HAP
emissions from such units are negligible based on the results of the
Utility Study.
Several commenters addressed the 2005 reversal of the 2000 finding.
Several commenters specifically supported the vacatur of the 2005
action. Other commenters asserted that the 2005 action was proper, and
that EPA reverted back to the 2000 finding in the proposed rule without
adequate explanation or support. Several commenters cited the 2005
action as invalidating the 2000 finding, specifically noting that EPA
concluded that ``no hazards to public health'' remained after
accounting for emission reductions under CAIR. These commenters assert
that EPA's current position is illegal because EPA took the exact
opposite position on the interpretation of the term ``necessary'' in
its 2005 reversal, and, thus, deserves no judicial deference. One
commenter stated that in 2005 EPA recognized the potential for
excessive regulation created by CAA section 112 and determined that the
2000 finding lacked foundation.
Several commenters generally disagreed with the 2000 finding, with
two commenters stating that EPA did not have a rational justification
for it and another claiming that it was fraught with misinformation and
overestimating assumptions. One commenter claimed that EPA did not
explain the terms ``appropriate'' and ``necessary'' in the 2000 finding
and that the emission control analysis was inadequate. Two commenters
stated that the 2000 finding was based on data that was more than 10
years old, which causes serious concern regarding the validity of the
findings because technology, the regulatory environment, and the
economic climate have evolved. Furthermore, because the Utility Report
underestimated emissions controls that EGUs would install by 2010 and
additional controls that would be later required by the CSAPR, the
basis for EPA's 2000 finding has changed. Several commenters stated
that a ``plausible link'' between anthropogenic Hg and MeHg in fish is
not an adequate reason for the 2000 finding. Several commenters claim
that EPA only identified health concerns for Hg (and potentially Ni)
but not other HAP from coal-fired EGUs in the 2000 finding, and, thus,
cannot regulate HAP other than Hg because the 2000 finding authorizes
only the regulation of Hg. One commenter questioned the Hg emissions
underlying the 2000 finding, specifically the fraction of total
deposition attributable to U.S. EGUS and the fact that EPA projected an
increase in U.S. EGU emissions from 1990 to 2010 though emissions
actually declined.
Several commenters raised procedural issues related to the 2000
finding. Several commenters stated that the 2000 finding failed to
provide public notice and comment. According to the commenters, the CAA
requires that any decision made under CAA section 112(n) must go
through public notice and comment. The commenters further stated that
the failure to provide public notice and comment means that this MACT
is outside EPA's statutory authority. One commenter stated that because
the 2000 finding was never ``fully ventilated'' in front of the D.C.
Circuit, the EPA's authority to regulate EGUs under CAA section 112(d)
is directly at issue. The commenters claim that specific issues did not
undergo
[[Page 9335]]
public notice and comment, including least-cost regulatory options, the
impact of regulation on electricity reliability, and EPA's
interpretation of the requirements under CAA section 112(n)(1)(A). One
commenter claims that EPA attempted to provide after-the-fact support
for its 2000 finding with new legal analysis and new factual
information, contrary to New Jersey v. EPA that held that EPA may not
revisit its 2000 finding except through delisting under CAA section
112(c)(9). One commenter stated that EPA's 2000 finding should be
reviewed when EPA issues the actual NESHAP.\68\ One commenter stated
that the 2000 finding ignored EO 12866.
---------------------------------------------------------------------------
\68\ See UARG v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir.
July 26, 2001).
---------------------------------------------------------------------------
Response: EPA agrees with the commenters that the 2000 finding was
reasonable and disagrees with the commenters asserting that the 2000
finding was unreasonable or failed to follow proper procedural
requirements.
The EPA agrees that reviewing courts defer to the reasoned
scientific and technical decisions of an Agency charged with
implementing complex statutory provisions such as those at issue in
this case. As EPA stated in the preamble to the proposed rule, the EPA
maintains that the 2000 finding was reasonable and based on well-
supported evidence available at the time, including the Utility Study,
the Mercury Study,\69\ and the NAS study,\70\ which all showed the
hazards to public health and the environment from HAP emitted from
EGUs. New technical analyses conducted by EPA confirm that it remains
appropriate and necessary to regulate HAP emissions from EGUs.
Furthermore, the EPA agrees with the commenters on several points
raised, specifically that EGUs were and remain the largest
anthropogenic source of several HAP in the U.S., that risk assessments
supporting the 2000 finding indicated potential concern for several
non-Hg HAP, and that several available control options would
effectively reduce HAP emissions from U.S. EGUs.
---------------------------------------------------------------------------
\69\ U.S. EPA, 1997.
\70\ NAS, 2000.
---------------------------------------------------------------------------
The EPA agrees with the commenters that Congress did not exempt
EGUs from section 112(d) HAP emission limits while simultaneously
limiting emissions at other sources with less HAP emissions. Congress
simply provided EPA with a separate path for listing EGUs by requiring
that the Agency evaluate HAP emissions from EGUs and determine whether
regulation under CAA section 112 was appropriate and necessary. Since
1990, the EPA has promulgated regulations requiring the use of
available control technology and other practices to reduce HAP
emissions for more than 170 source categories. U.S. EGUs are the most
significant source of HAP in the country that remains unaddressed by
Congress's air toxics program. The EPA listed EGUs in 2000 because the
considerable amount of available data supported the conclusion that
regulation of EGUs under CAA section 112 was appropriate and necessary.
That finding was valid at the time, and EPA reasonably added EGUs to
the CAA section 112(c) list of sources that must be regulated under CAA
section 112.
The EPA acknowledges that we did not expressly define the terms
appropriate and necessary in the 2000 finding, but the finding is
instructive in that it shows that EPA considered whether HAP emissions
from EGUs posed a hazard to public health and the environment and
whether there were control strategies available to reduce HAP emissions
from EGUs when determining whether it was appropriate to regulated
EGUs.\71\ When concluding it was necessary, the Agency stated that
imposition of the requirements of the Act would not address the
identified hazards to public health or environment from HAP emissions
and that section 112 was the proper authority to address HAP
emissions.\72\ The EPA explained in the preamble to the proposed rule
its conclusion that the 2000 finding was fully supported by the
information available at the time,\73\ and EPA stands by the
conclusions in that notice. Furthermore, the EPA provided an
interpretation of the terms appropriate and necessary that is wholly
consistent with the 2000 finding. The EPA does not agree with the
commenters that a quantification of emissions reductions or a specific
identification of the available controls was necessary to support the
2000 finding and listing. The EPA considered the Utility Study when
making the finding, and that study clearly articulated the various
alternative control strategies that EGUs could employ to control HAP
emissions.\74\ As to emission reductions, the EPA cannot estimate the
level of HAP emission reductions until the Agency proposes a CAA
section 112(d) standard after a source category is listed.
---------------------------------------------------------------------------
\71\ 65 FR 79830.
\72\ Id.
\73\ 65 FR 24994-24996.
\74\ See Chapter 13 of the Utility Study (U.S. EPA, 1998).
---------------------------------------------------------------------------
The EPA disagrees with commenters that suggest it was not
``rational'' to determine that it was appropriate to regulate HAP
emissions from EGUs due to the cancer risks identified in the Utility
Study or the potential concerns associated with other HAP emissions
from EGUs. Nothing in CAA section 112(n)(1)(A) suggests that EPA must
determine that every HAP emitted by EGUs poses a hazard to public
health or the environment before EPA can find it appropriate to
regulate EGUs under CAA section 112. In fact, the EPA maintains that it
must find it appropriate and necessary to regulate EGUs under CAA
section 112 if it determines that any one HAP emitted from EGUs poses a
hazard to public health or the environment that will not be addressed
through imposition of the requirements of the Act. The EPA disputes the
commenters' conclusion that the 2000 finding was limited to Hg and Ni
emissions, but, even if it were, the EPA reasonably concluded that EGUs
should be listed pursuant to CAA section 112(c) based on the Hg and Ni
finding. As stated in the 2000 finding, cancer risks from some non-Hg
metal HAP (including As, Cr, Ni, and Cd) were not low enough to be to
eliminate as potential concern.\75\ Source categories listed for
regulation under CAA section 112(c) must be regulated under CAA section
112(d), and the D.C. Circuit has stated that EPA has a ``clear
statutory obligation to set emission standards for each listed HAP''.
See Sierra Club v. EPA, 479 F.3d 875, 883 (D.C. Cir. 2007), quoting
National Lime Association v. EPA, 233 F.3d 625, 634 (D.C. Cir. 2000).
Therefore, even if EPA concluded that CAA section 112(n)(1) authorized
a different approach for regulating HAP emissions from EGUs, the chosen
course which is supported by the CAA (i.e., listing under CAA section
112(c)) requires the Agency to regulate under CAA section 112(d)
consistent with the statute and case law interpreting that provision.
---------------------------------------------------------------------------
\75\ 76 FR 79827.
---------------------------------------------------------------------------
The EPA disagrees that there is any concern regarding the validity
of the 2000 finding or that the emissions information provided in the
2000 finding makes the finding ``questionable'' as stated by some of
the commenters. The EPA maintains that the 2000 finding was sound and
fully supported by the record available at the time, including the
future year emissions projections. Therefore, the listing of EGUs is
valid based on that finding alone. Even though Hg emissions have
decreased since the 2000 finding instead of increasing as projected,
the new technical analyses confirm that Hg emissions from EGUs continue
to pose hazards to public
[[Page 9336]]
health and the environment. The EPA also indicated potential concern
for several non-Hg HAP in the 2000 finding. It is well established that
even small amounts of HAP can cause significant harm to human health
and the environment.
The EPA agrees with the commenters who assert that the 2005 action
was in error and disagrees with the commenters that the 2005 action
invalidated the 2000 finding. As fully described in the preamble to the
proposal, the EPA erred in the 2005 action by concluding that the 2000
finding lacked foundation. The 2005 action improperly conflated the
``appropriate'' and ``necessary'' analyses by addressing the ``after
imposition of the requirements of the Act'' in the appropriate finding
as well as the necessary finding. The EPA also indicated that it was
not reasonable to interpret the necessary prong of the finding as a
requirement to scour the CAA for alternative authorities to regulate
HAP emissions from stationary sources, including EGUs, when Congress
provided section 112 for that purpose. The EPA asserts that the 2000
finding was sound and fully supported by the record available at the
time for all the reasons stated in this final rule and the proposed
rule. The 2005 action interpreted the statute in a manner inconsistent
with the 2000 finding and attempted to delist EGUs without complying
with the mandates of CAA section 112(c)(9)(B). See New Jersey, 517 F.3d
at 583 (vacating the 2005 ``delisting'' action). In the preamble to the
proposed rule, the EPA set forth a revised interpretation of CAA
section 112(n)(1) that is consistent with the statute and the 2000
finding. The EPA also explained in the preamble to the proposed rule
why the 2005 action was not technically or scientifically sound. The
EPA specifically addressed the errors associated with the 2005 action
in the preamble to the proposed rule, and commenters' assertions do not
cause us to revisit these issues. The commenter is also incorrect in
suggesting that a change in interpretation is per se invalid and
provided no support for that position. See National Cable &
Telecommunications Ass'n, et al., v. Brand X Internet Services, et al.,
545 U.S. 967, 981 (discussing the deference provided to an Agency
changing interpretations, the Court stated ``change is not
invalidating, since the whole point of Chevron deference is to leave
the discretion provided by ambiguities of a statute with the
implementing Agency.'') (Internal citations and quotations omitted).
The EPA disagrees with the commenters who raise concerns about the
validity of the 2000 finding because the data on which that finding was
based were more than 10 years old. The EPA made the finding at that
time based on the scientific and technical information available, and
the finding is wholly supported by that information. In addition, even
though not required to do so, the EPA has since conducted new technical
analyses utilizing the best information available in 2010 as several
years have passed since the 2000 finding. These new analyses confirm
that HAP emissions from EGUs continue to pose a hazard to public health
and the environment, even after taking into account emission reductions
that have occurred since 2000 from promulgated rules, settlements, and
consent decrees. See 76 FR 24991.
Contrary to the commenter's assertion, the EPA did not violate CAA
section 307(d) by not providing a notice and comment opportunity before
making the December 2000 appropriate and necessary finding. One
commenter challenged EPA's 2000 finding and listing on the same
grounds, and the D.C. Circuit dismissed the case because CAA section
112(e)(4) clearly states that listing decisions cannot be challenged
until the Agency issues final emission standards for the listed source
category. See UARG v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir. July
26, 2001). The EPA has provided the public an opportunity to comment on
both the 2000 finding and the 2011 analyses that support the
appropriate and necessary determination as part of the proposed rule,
and anyone may challenge the listing in the D.C. Circuit in conjunction
with a challenge to this final rule. The commenters could have also
commented on the CAA section 112(n)(1) (e.g., the Utility Study and the
Mercury Study) studies in 2000 as they were included in the docket, but
EPA is not aware of any comments on those studies. In any case, these
studies were peer reviewed and considered the best information
available at that time. The EPA has fully complied with the rulemaking
requirements of CAA section 307(d).
The EPA also disagrees with the commenters' characterization of the
New Jersey case. The D.C. Circuit did not say, as one commenter
suggested, that EPA is not able to consider additional information that
is collected after the 2000 finding; instead, the Court stated that EPA
could not revise its appropriate and necessary finding and remove EGUs
from the CAA section 112(c) list without complying with the delisting
provisions of CAA section 112(c)(9). See New Jersey, 517 F.3d at 582-
83. The EPA also disagrees with the commenter's assertion that EPA
disregarded EO 12866 when making the 2000 finding. As stated in the
Federal Register notice, the 2000 finding did not impose regulatory
requirements or costs and was reviewed by the Office of Management and
Budget (OMB) in accordance with the EO.\76\
---------------------------------------------------------------------------
\76\ 65 FR 79831.
---------------------------------------------------------------------------
2. New Technical Analyses
a. General Comments on New Technical Analyses
Comment: Several commenters stated that the new analyses, including
the risk assessments and technology assessments, confirm that it
remains appropriate and necessary to regulate U.S. EGU HAP under CAA
section 112. These commenters stated that the new analyses provide even
more support than the risk and technology information available at the
time the 2000 finding was made, including information on further
developed emissions control technology, proven and cost-effective
control of acid gases using trona and dry sorbent injection, stabilized
natural gas prices that makes fuel switching and switching dispatch to
underutilized combined cycle plants more feasible, more information on
ecosystem impacts from HAP, ``hotspots'' from the deposition of Hg
around EGUs, the potential for re-emission of Hg, updated emissions
data and future projections of HAP emissions, and modern air pollution
modeling tools. One commenter states affordable control technology has
been in use in this sector for 10 to 40 years, and studies on EGU-
attributable Hg hazard has undergone two in-depth EPA reviews, as well
as a review by the NAS. Several commenters claimed that regulating U.S.
EGUs is appropriate and necessary to protect public health based on
information provided in the new technical analyses. These commenters
acknowledged the substantial reductions in HAP from recent regulations
and new studies that confirm serious health risks from HAP exposure.
One commenter stated that new studies show higher risks to fetuses than
previously estimated, increasing the potential for neurodevelopmental
effects in newborns. One commenter noted that EGUs are a major source
of HAP, including HCl, HF, As, antimony, Cr, Ni, and selenium, all of
which adversely affect human health. The commenter stated that because
of these health effects, the EPA has ample evidence to support a
determination
[[Page 9337]]
that non-Hg HAP emissions present a risk to human health.
Other commenters disagreed that the new analyses confirm that it
remains appropriate and necessary to regulate U.S. EGUs. One commenter
claims that EPA tried to use the new technical analyses to provide
retroactive justification for the 2000 finding, which only found
``plausible links'' of health effects and ``potential concerns'' of
health effects of certain metal emissions, dioxins and acid based
aerosols. The commenter also asserted that none of these new analyses
demonstrate that EGU regulation under section 112 is necessary and
appropriate.
One commenter agreed that EPA may supplement its finding with new
information, analyses and arguments to reaffirm the 2000 finding up
until EPA issues final emissions standards. The commenter noted that
the CAA does not freeze the finding. However, another commenter argued
that EPA does not have the authority to rely on new technical analyses
because the CAA requires EPA to make the finding on the basis of the
Utility Study alone. According to that commenter, the EPA unreasonably
stretched the language of CAA section 112 by considering new technical
analyses.
Citing a report from Dr. Willie Soon that was submitted to the SAB,
one commenter stated that the new technical analyses supporting the
proposed rule do not conform to the Information Quality Act, which
requires that information relied on by EPA be accurate, reliable,
unbiased, and presented in a complete and unbiased manner.
Response: The EPA agrees with the commenters that state that the
new technical analyses (e.g., the risk assessments and technology
assessment) confirm the 2000 finding and disagrees with the commenters
that state otherwise. The EPA also agrees with the commenters that the
2000 finding was valid at the time it was made based on the CAA section
112(n)(1) studies and other information available to the Agency at that
time. Furthermore, the EPA agrees with commenters that the final rule
will lead to substantial reductions in HAP emissions from EGUs, that
control of the HAP is estimated to lead to public health and
environmental benefits as discussed in the RIA, that Hg emissions from
U.S. EGUs pose a hazard to public health, and that non-Hg HAP emissions
from EGUs pose a hazard to public health.
Although these new analyses were not required, the EPA agrees with
the commenters that stated that EPA is authorized to conduct additional
analyses to confirm the 2000 finding. The EPA disagrees with the
commenter's assertion that the Agency is not authorized to consider new
information and at the same time unable to use the information
available in 2000 because, according to the commenter, that information
is ``stale.'' Under this theory, the Agency could not ever make an
appropriate and necessary finding prospectively, thereby excusing the
Agency from its obligations to protect public health and the
environment because it did not diligently act in undertaking its
statutory responsibility to establish CAA section 112(d) standards
within two years of listing EGUs. See CAA section 112(c)(5). This is an
illogical result that finds no basis in the statute. The EPA also
disagrees with the commenter's assertion that EPA may not consider new
analyses conducted after the Utility Study in determining whether it is
appropriate and necessary to regulate EGUs under section 112 for the
reasons set forth in the preamble to the proposed rule.\77\
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\77\ 76 FR 24988.
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The EPA disagrees with the commenter's implication that EPA
conducted the new analyses because of alleged flaws in the 2000
finding. As explained in detail in the preamble to the proposed rule,
the 2000 finding was wholly valid and reasonable based on the
information available to the Agency at that time, including the Utility
Study. Further, the EPA maintains that had it complied with the
statutory mandate to issue CAA section 112(d) standards within two
years of listing EGUs, the EPA would likely have declined to conduct
new analyses. The EPA conducted new analyses because over 10 years had
passed since the 2000 finding, and EPA wanted to evaluate HAP emissions
from U.S. EGUs based on the most accurate information available, though
the Agency was not required to reevaluate the 2000 finding. In
conducting the new analyses, the EPA used this updated information to
further support the finding.
The EPA strongly disagrees with the commenter that stated that EPA
failed to conform to the Information Quality Act. The EPA used peer
reviewed information and quality-assured data in all aspects of the
technical analyses used to support the appropriate and necessary
finding supporting this regulation. In addition, the EPA submitted the
Hg Risk TSD to the SAB for peer review, which ``supports the overall
design of and approach to the risk assessment and finds that it should
provide an objective, reasonable, and credible determination of the
potential for a public health hazard from mercury emitted from U.S.
EGUs.'' \78\ The SAB received the comments from Dr. Willie Soon, and
had those comments available for consideration in their deliberations
regarding the Hg risk analysis. The SAB specifically supported elements
of the analysis criticized by Dr. Willie Soon regarding the use of the
EPA RfD as a benchmark for risk and the connection between Hg emissions
from U.S. EGUs and MeHg concentrations in fish. In addition, the risk
assessment methodology for the non-Hg case studies is consistent with
the methodology that EPA uses for assessments performed for Risk and
Technology Review rulemakings, which underwent peer review by the SAB
in 2009. \79\ During the public comment period, the EPA also completed
a letter peer review of the methods used to develop inhalation cancer
risk estimates for Cr and Ni compounds, and those reviews were
generally supportive. See above description of this peer review. For
the final rulemaking, the EPA revised both risk assessments consistent
with recommendations from the peer reviewers. The EPA relies on the
SAB's review of the quality of the information supporting the
analytical results. Accordingly, contrary to the commenters'
assertions, the EPA acted consistently with the Information Quality Act
as well as EPA's and OMB's peer review requirements.
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\78\ U.S. EPA-SAB, 2011.
\79\ U.S. EPA-SAB, 2010.
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b. Hg Emissions Estimates
1. Hg Emissions From EGUs
Comment: The commenters addressed the 2005 and 2016 emissions
estimates for Hg and expressed concern that inaccuracies in these
emissions estimates result in overestimates of risks from Hg
deposition. Further, commenters compared EPA's 2010 estimate and 2016
estimate, and stated that it is not possible for 29 tons to be a
correct inventory total for Hg emissions in both years given expected
reductions from CSAPR. In addition, commenters specifically commented
on assumptions included in the Integrated Planning Modeling (IPM),
including a concern that Hg speciation factors used by IPM overestimate
emissions in 2016. Other commenters noted that EGU sources are the
predominant source of U.S. anthropogenic Hg emissions, particularly the
oxidized and particulate forms of Hg that are of primary concern for Hg
deposition.
Response: The EPA disagrees with commenters' assertions that the
EPA's
[[Page 9338]]
emissions estimates overestimate risk. While EPA agrees that the 2005
Hg emissions may be overestimated, such an overestimate in 2005 would
actually lead to an underestimate of risk in 2016 and not an
overestimate of risk, as claimed by the commenter, because the ratio
approach used by EPA to scale fish tissue data would underestimate risk
if 2005 Hg estimates were overestimated. Since the 2005 emissions are
not used as a starting point for 2016 emissions from IPM, any 2005
overestimate does not affect the 2016 emissions levels. The 2016
emissions are computed by IPM based on forecasts of demand, fuel type,
Hg content of the fuel, and the emissions reductions resulting from
each unit's configurations. See IPM Documentation for further
information, which is available in the docket. No commenter has
provided any evidence that the IPM 2016 emissions projection
methodology resulted in an overestimate.
The EPA acknowledges that the current Hg emissions estimate would
not be the same as the 2016 Hg emissions estimate given that compliance
with CSAPR is anticipated to have some Hg co-benefits. For this reason,
the EPA reflected emission reductions anticipated from CSAPR in the Hg
deposition modeling for 2016 in the Hg Risk TSD. In the final rule, the
EPA revised the estimate of Hg emissions remaining from U.S. EGUs in
2016, which includes additional emission reductions anticipated from
the final CSAPR. The revised estimate shows that U.S. EGUs would emit
27 tons of Hg in 2016. Although EPA does not use the current Hg
emissions estimates in any of the risk calculations, the EPA estimates
that current Hg emissions are 29 tons. Conclusions about the trend
between current emissions and emissions in 2016 are limited by the fact
that different methods were used to compute the two estimates, as fully
explained in the revised Emissions Overview memo in the docket.
The EPA disagrees with the commenter's assertion that incorrect Hg
emission factors result in incorrect 2016 emissions. The 2016 projected
Hg emissions are not based on emissions factors. The 2016 Hg emissions
are computed by the IPM based on forecasts of demand, fuel type, Hg
content of the fuel, and the emissions reductions resulting from each
unit's configurations. The speciation factors referenced by the
commenter provide a basis for the speciation of total projected Hg
emissions into particulate, divalent gaseous, and elemental species,
and do not impact the total amount of Hg emissions.
The EPA agrees with commenters who noted that EGU sources are the
predominant source of U.S. anthropogenic Hg emissions, and in
particular the oxidized and particulate forms of Hg that are of primary
concern for Hg deposition.
2. Global Hg Emissions
Comment: Several commenters stated that predicted Hg deposition
relies heavily on the amount of gaseous elemental Hg used to define the
boundary and initial conditions of a model, e.g., the Hg that enters
the U.S. from outside the U.S. boundaries. The commenters asserted that
this is especially important because Hg emissions from Asia--the region
immediately upwind of North America that affects U.S. Hg deposition
significantly and also affects it the most compared to other regions--
are expected to continue to increase.80 81 82 83 84 85
According to the commenter, this would affect the amount of Hg in the
boundary and initial conditions. The commenters claim that EPA's
modeling did not account for these emission changes, thus leading to an
overestimate of U.S. EGU-attributable deposition in 2016.
---------------------------------------------------------------------------
\80\ Jaffe D., Prestbo E., Swartzendruber P., Weiss-Penzias P.,
Kato S., Takami A., Hatakeyama S., Kajii Y., 2005. ``Export of
Atmospheric Mercury From Asia,'' Atmospheric Environment, 39, 3029-
3038.
\81\ Jaffe D., Strode S., 2008. ``Fate and Transport of
Atmospheric Mercury From Asia,'' Environmental Chemistry, 5, 121.
\82\ Pacyna E.G., Pacyna J.M., Sundseth K., Munthe J., Kindbom
K., Wilson S., Steenhuisen F., Maxson P., 2010. ``Global Emission of
Mercury to the Atmosphere From Anthropogenic Sources in 2005 and
Projections to 2020,'' Atmospheric Environment, 44, 2487-2499.
\83\ Pirrone N., Cinnirella S., Feng X., Finkelman R.B., Friedli
H.R., Leaner J., Mason R., Mukherjee A.B., Stracher G.B., Streets D.
G., Telmer K., 2010. ``Global Mercury Emissions to the Atmosphere
From Anthropogenic and Natural Sources,'' Atmospheric Chemistry and
Physics, 10, 5951-5964.
\84\ Streets, D.G., Zhang, Q., Wu, Y., 2009. ``Projections of
Global Mercury Emissions in 2050.'' Environmental Science &
Technology 43, 2983-2988.
\85\ Weiss-Penzias P., Jaffe D., Swartzendruber P., Dennison
J.B., Chand D., Hafner W., Prestbo E., 2006. ``Observations of Asian
Air Pollution in the Free Troposphere at Mt. Bachelor Observatory in
the Spring of 2004,'' Journal of Geophysical Research, 110, D10304.
---------------------------------------------------------------------------
Several commenters noted that Hg emissions from U.S. EGUs are small
when compared to global Hg emissions totals and natural sources within
the U.S. These commenters used a variety of information to support
alternative conclusions about the necessity to control U.S. EGU
emissions to reduce Hg risk: global Hg emissions inventories, global
and regional photochemical modeling research, and observation-based
assessments. A commenter stated that EPA has not acknowledged the
dramatic decline in Hg emissions from U.S. EGUs since the late 1990s
(approximately 50 percent) to the current level or consider the
relative magnitude of Hg emissions from U.S. EGUs compared to other
sources, natural (such as fires) and human-caused.
Response: The EPA disagrees that boundary and initial conditions
used in modeling Hg deposition need adjustment for several reasons.
First, the EPA does not use the first 10 days of the modeling
simulation in the analysis, which is more than sufficient to remove the
influence of initial conditions on Hg deposition estimates.\86\ Second,
it is difficult to accurately characterize the speciation of Hg that
flows into the U.S. from other countries due to the lack of data near
the boundaries of the modeling domain. Third, the boundary inflow for
the CMAQ Hg modeling used in the Hg deposition modeling are based on a
global model GEOS-CHEM simulation using a 2000 based global
inventory.\87\ A recently published comparison of global Hg emissions
by continent for 2000 and 2006 found that total Hg emissions from Asia
(and Oceania) total 1,306 Mg/yr in 2000 and 1,317 Mg/yr in 2006.\88\
The EPA has determined that because the Asian Hg emissions estimated in
this study are nearly constant between 2005 and 2006, any adjustments
to the boundary conditions or adjustments to modeled Hg deposition
would be invalid and inappropriate. Recent research has shown that
ambient Hg concentrations have been decreasing in the northern
hemisphere since 2000.\89\ Because emissions from Asia have not
appreciably changed between 2000 and 2006 and ambient Hg concentrations
have been decreasing, ENVIRON's analysis contains incorrect assumptions
and we need not address them further. For these reasons and the large
uncertainties surrounding projected Hg
[[Page 9339]]
global inventories, the EPA concludes that the most appropriate
technical choice is to keep the Hg boundary conditions the same between
the 2005 and 2016 simulations.
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\86\ Pongprueksa, P., Lin, C.J., Lindberg, SE., Jang, C.,
Braverman, T., Bullock, O.R., Ho, T.C., Chu, H.W., 2008.
``Scientific Uncertainties in Atmospheric Mercury Models III:
Boundary and Initial Conditions, Model Grid Resolution, and Hg (II)
Reduction Mechanism.'' Atmospheric Environment 42, 1828-1845.
\87\ Selin, NE., Jacob, D.J., Park, R.J., Yantosca, R.M.,
Strode, S., Jaegle, L., Jaffe, D. 2007. ``Chemical Cycling and
Deposition of Atmospheric Mercury: Global Constraints From
Observations.'' Journal of Geophysical Research-Atmospheres 112.
\88\ Streets et al., 2009.
\89\ Slemr, F., Brunke, E.G., Ebinghaus, R., Kuss, J., 2011.
``Worldwide Trend of Atmospheric Mercury Since 1995.'' Atmospheric
Chemistry and Physics 11, 4779-4787.
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The EPA also disagrees with the commenters' assertion that EPA has
not acknowledged the decline in Hg emissions for the U.S. EGUs since
the late 1990s. The EPA analyzed historical, current, and future
projected Hg emissions from the power generation sector, as cited in
the preamble to the proposed rule. The EPA also disagrees with the
commenters' assertions that EPA failed to consider the relative
magnitude of Hg emissions from U.S. EGUs compared to other sources. As
noted in the Hg Risk TSD, the EPA modeled Hg emissions from U.S. and
non-U.S. anthropogenic and natural sources to estimate Hg deposition
across the country. The EPA also determined the contribution of Hg
emissions from U.S. EGUs to total Hg deposition in the U.S. by running
modeling simulations for 2005 and 2016 with Hg emissions from U.S. EGUs
set to zero. Based on the Hg Risk TSD, Hg emissions from U.S. EGUs pose
a hazard to public health based on the total of 29 percent of modeled
watersheds potentially at-risk. Our analyses show that of the 29
percent of watersheds with population at-risk, in 10 percent of those
watersheds U.S. EGU deposition alone leads to potential exposures that
exceed the MeHg RfD, and in 24 percent of those watersheds, total
potential exposures to MeHg exceed the RfD and U.S. EGUs contribute at
least 5 percent to Hg deposition.
The commenters suggest that Hg emissions from U.S. EGUs represent a
limited portion of the total Hg emitted worldwide, including
anthropogenic and natural sources. While EPA acknowledges that Hg
emissions from U.S. EGUs are a small fraction of the total Hg emitted
globally, it views the environmental significance of Hg emissions from
U.S. EGUs and other domestic sources as a more germane consideration.
Mercury is emitted from EGUs in three forms. Each form of Hg has
specific physical and chemical properties that determine how far it
travels in the atmosphere before depositing to the landscape. Although
gaseous oxidized Hg and particle-bound Hg are generally local/regional
Hg deposition concerns, all forms of Hg may deposit to local or
regional watersheds. U.S. coal-fired power plants account for over half
of the U.S. controllable emissions of the quickly depositing forms of
Hg. Although emissions from international Hg sources contribute to Hg
deposition in the U.S., the peer reviewed scientific literature shows
that Hg emissions from U.S. EGUs in the U.S. significantly enhance Hg
deposition and the response of ecosystems in the U.S.
90 91 92 93
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\90\ Caffrey et al., 2010.
\91\ Driscoll, C. T., Han, Y.-J., Chen, C. Y., Evers, D. C.,
Lambert, K. F., Holsen, T. M., et al., (2007). ``Mercury
Contamination in Forest and Freshwater Ecosystems in the
Northeastern United States.'' BioScience, 57(1).
\92\ Keeler, G.J., Landis, M.S., Norris, G.A., Christianson,
E.M., Dvonch, J.T., 2006. ``Sources of Mercury Wet Deposition in
Eastern Ohio, USA.'' Environmental Science & Technology 40, 5874-
5881.
\93\ White, E.M., Keeler, G.J., Landis, M.S., 2009. ``Spatial
Variability of Mercury Wet Deposition in Eastern Ohio: Summertime
Meteorological Case Study Analysis of Local Source Influences.''
Environmental Science & Technology 43, 4946-4953.
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c. Hg Deposition Modeling
1. General Comments on Deposition Modeling
Comment: Several commenters stated that according to the ENVIRON
report, the EPA overestimated U.S. EGU-attributable Hg deposition by 10
percent on average (and up to 41 percent in some areas). The commenters
claim this overestimation is the result of boundary condition
treatment, the exclusion of U.S. fire emissions,\94\ and Hg plume
chemistry approach. In addition, one commenter referenced the same
ENVIRON report and stated that before implementation of controls
required by the proposed rule, areas with relatively high EGU-
attributable Hg deposition (one-fifth or more of total deposition) in
2016 constitute less than 0.25 percent of the continental U.S. area,
and only three grid cells have EGU contributions exceeding half of
total deposition.
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\94\ Finley, B.D., Swartzendruber, P.C., Jaffe, D.A., 2009.
``Particulate Mercury Emissions in Regional Wildfire Plumes Observed
at the Mount Bachelor Observatory.'' Atmospheric Environment 43,
6074-6083.
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Another commenter suggested that current research shows that models
of Hg atmospheric fate and transport overestimate the local and
regional impacts of some anthropogenic sources, such as U.S. EGUs.
Thus, according to the commenter, calculated contributions to Hg
deposition and fish tissue MeHg levels from these sources represent
upper bounds of actual contributions,\95\ \96\ and EPA should present
results as estimates of lower and upper bound limits.
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\95\ Seigneur, C., Lohman, K., Vijayaraghavan, K., Shia, R.L.,
2003. ``Contributions of global and regional sources to mercury
deposition in New York State.'' Environmental Pollution 123, 365-
373.
\96\ Seigneur, C., Vijayaraghavan, K., Lohman, K.,
Karamchandani, P., Scott, C., 2004. ``Modeling the atmospheric fate
and transport of mercury over North America: power plant emission
scenarios.'' Fuel Processing Technology 85, 441-450.
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Response: The EPA disagrees with the information presented by
ENVIRON. The ENVIRON report is based on the misapplication of multiple
incommensurate modeling studies and false premises which include the
incorrect notion that the boundary conditions are over-estimated and
the idea that EPA should use in-plume chemistry that has not been
explicitly characterized and peer reviewed. Reactions that may reduce
gas phase oxidized Hg in plumes have not been explicitly identified in
literature. Recent studies in central Wisconsin and central California
suggest the opposite may happen; elemental Hg may be oxidized to Hg(II)
in plumes.\97\ \98\ Better field study measurements and specific
reaction mechanisms need to be identified before making conclusions
about potential Hg in-plume chemistry or applying surrogate reactions
in regulatory modeling. The possibility that Hg(0) is oxidized to
Hg(II) in plumes suggests coal-fired power plant Hg contribution inside
the U.S. may be underestimated in EPA modeling.
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\97\ Kolker, A., Olson, M.L., Krabbenhoft, D.P., Tate, M.T.,
Engle, M.A., 2010. ``Patterns of mercury dispersion from local and
regional emission sources, rural Central Wisconsin, USA.''
Atmospheric Chemistry and Physics 10, 4467-4476.
\98\ Rothenberg, SE., McKee, L., Gilbreath, A., Yee, D., Connor,
M., Fu, X.W., 2010. ``Wet deposition of mercury within the vicinity
of a cement plant before and during cement plant maintenance.''
Atmospheric Environment 44, 1255-1262.
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The EPA asserts that the numbers suggested by the commenter are
inaccurate, as it is not appropriate to adjust EPA's deposition
estimates based on previous Hg modeling done with older Hg chemistry,
in-plume reactions that have not been explicitly identified, and
erroneous adjustments to Hg boundary inflow. Recent research has shown
that ambient Hg concentrations have been decreasing in the northern
hemisphere since 2000.\99\ The EPA declines to revise this analysis as
commenter suggests for several reasons, including available evidence
indicates that emissions from China have not appreciably changed
between 2000 and 2006 \100\ and ambient Hg concentrations have
decreased, the commenter inappropriately comingled out-of-date Hg
modeling simulations with EPA results, and ENVIRON's analysis has not
undergone any scientific peer review and presents information with
incorrect assumptions as noted in this response.
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\99\ Slemr et al., 2011.
\100\ Streets et al., 2009.
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The EPA also disagrees with the commenter's interpretation of the
applicability of wildfire Hg emissions to
[[Page 9340]]
this assessment. Finley et al., (2009) \101\ suggests caution when
using their field data to make assumptions about Hg(p) emissions from
wildfires; the estimated particulate Hg emissions from wildfires is
based on one field site with a limited sample size, and the assumptions
made (such as the observed Hg(p) to carbon monoxide ratios at this
location) may not be valid on a broader scale.\102\ Mercury emissions
from wildfires are a re-volatilization of previously deposited Hg.\103\
Given that electrical generating power plants are currently and
historically have been among the largest Hg-emitting sources, the
inclusion of wildfire emissions in a modeling assessment would
necessarily increase the contribution from this emissions sector.
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\101\ Finley et al., 2009.
\102\ Id.
\103\ Wiedinmyer, C., Friedli, H., 2007. ``Mercury emission
estimates from fires: An initial inventory for the United States.''
Environmental Science & Technology 41, 8092-8098.
\104\ Seigneur et al., 2003.
\105\ Seigneur et al., 2004.
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The EPA disagrees with the assertion that EPA failed to consider
the relative magnitude of Hg emissions from U.S. EGUs compared to other
sources and disagrees with the interpretation of EGU deposition
presented in the ENVIRON report. As noted in the Hg Risk TSD, the EPA
modeled Hg emissions from U.S. and non-U.S. anthropogenic and natural
sources to estimate Hg deposition across the country. The EPA also
determined the contribution of Hg emissions from U.S. EGUs to total Hg
deposition in the U.S. by running modeling simulations for 2005 and
2016 with Hg emissions from U.S. EGUs set to zero. Hg emissions from
U.S. EGUs pose a hazard to public health based on the total of 29
percent of modeled watersheds potentially at-risk. Our analyses show
that of the 29 percent of watersheds with population at-risk, in 10
percent of those watersheds U.S. EGU deposition alone leads to
potential exposures that exceed the MeHg RfD, and in 24 percent of
those watersheds, total potential exposures to MeHg exceed the RfD and
U.S. EGUs contribute at least 5 percent to Hg deposition. The ENVIRON
report provides no risk analysis of EGU contribution.
The EPA disagrees that research 104 105 presented by the
commenter shows that U.S. EGU impacts are over-estimated. The
commenter's references do not support this statement. The references
provided by the commenter are based on Hg modeling that uses models
that are no longer applied and that are based on out-dated Hg chemistry
and deposition assumptions. Given the advances in Hg modeling since the
early 2000s, the EPA does not believe an upper and lower bound estimate
is necessary.
2. Chemical Reactions
Comment: Several commenters stated that the CMAQ modeling fails to
account for the chemical reduction of gaseous ionic Hg to elemental Hg
that may occur in EGU plumes. The commenters noted that EPA did not use
the Electric Power Research Institute's (EPRI) Advanced Plume-in-Grid
Treatment, which includes a surrogate reaction to reduce gaseous ionic
Hg to elemental Hg inside plumes. Multiple commenters claimed that the
reduction of reactive gaseous Hg to gaseous elemental Hg has been
reported in power plant plumes and that supporting data include
atmospheric concentrations of speciated Hg measured downwind of power
plant stacks at ground-level monitor sites and dispersion model
predictions.106 107 A detailed description of various plume
measurement studies is provided in EPRI Comments, Section 3.4: Plant
Bowen, Georgia, Plant Pleasant, Wisconsin, and Plant Crist, Florida.
One commenter believed the impact of grid resolution (12 km sized grid
cells) on the CMAQ modeling was not appropriately addressed by EPA.
Their concerns due to grid resolution include the notion that a
source's emissions will be averaged over the entire grid cell.
According to the commenter, such averaging causes an artificially fast
dilution that smoothes out areas of high and low deposition, which may
limit the ability of the model to simulate smaller areas of localized
high deposition. This commenter believed that using the APT would
address these issues.
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\106\ Edgerton, E.S., Hartsell, B.E., Jansen, J.J., 2006.
``Mercury speciation in coal-fired power plant plumes observed at
three surface sites in the southeastern U.S.'' Environmental Science
& Technology 40, 4563-4570.
\107\ Lohman, K., Seigneur, C., Edgerton, E., Jansen, J., 2006.
``Modeling mercury in power plant plumes.'' Environmental Science &
Technology 40, 3848-3854.
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Response: The EPA disagrees with the commenters' claims that
oxidized Hg chemically reduces to elemental mercury within the plume.
There is no evidence of these chemical reactions in the scientific
literature. The references cited by the commenters are from non-peer
reviewed reports and conference proceedings. The EPA does not consider
information presented at conferences or industry reports to be peer
reviewed literature, and consideration of oral presentation material
would be inappropriate. Further, even these cited references do not
provide sufficient information for incorporating the supposed reactions
into the modeling (e.g., specific chemical reactions, reaction rates,
etc.); rather, the cited references only suggest that oxidized gas
phase Hg could be reduced and postulate a possible pathway.
Recent studies in central Wisconsin and central California suggest
the opposite may happen; elemental Hg may be oxidized to Hg(II) in
plumes.108 109 Better field study measurements and specific
reaction mechanisms need to be identified before making conclusions
about potential Hg in-plume chemistry or applying surrogate reactions
in regulatory modeling. Currently, models such as Advanced Plume
Treatment (APT) use a surrogate reaction for the potential reactive gas
phase Hg reduction that may or may not occur in plumes.\110\ Reactions
that may reduce gas phase oxidized Hg in plumes have not been
explicitly identified in literature. The application of potentially
erroneous in-plume chemistry that is a fundamental component of APT
would be inappropriate. In addition, the APT is not available in the
most recent version of CMAQ. It would be inappropriate for EPA to apply
an out of date photochemical model with in-plume chemistry that has not
been shown to exist.
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\108\ Kolker et al., 2010.
\109\ Rothenberg et al., 2010.
\110\ Vijayaraghavan, K., Seigneur, C., Karamchandani, P., Chen,
S.Y., 2007. ``Development and application of a multipollutant model
for atmospheric mercury deposition.'' Journal of Applied Meteorology
and Climatology 46, 1341-1353.
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The EPA agrees with the commenter that the CMAQ modeling with 12 km
grid resolution may provide a lower bound estimate on EGU contribution
as higher impacts using finer grid resolution are possible. The
commenter's assertion that EGU impacts are likely higher further
supports the final conclusions of the exposure modeling assessment. The
EPA notes that the application of a photochemical model at a 12 km grid
resolution for the entire continental U.S. is more robust in terms of
grid resolution and scale that anything published in literature and
represents the most advanced modeling platform used for a national Hg
deposition assessment.
3. Modeled Deposition Compared to Measured Deposition
Comment: Multiple commenters expressed dissatisfaction related to
EPA's model performance evaluation of CMAQ estimated Hg deposition. The
commenters stated that EPA failed to evaluate the CMAQ model against
real-world measurements and that EPA fails to provide first-hand
information on wet and dry deposition processes. The commenters also
stated that EPA needs
[[Page 9341]]
to assess how predicted values of deposition compare to Mercury
Deposition Network (MDN) data and how predicted values of ambient
speciated Hg concentrations compare to measurement networks like AMNet
and SEARCH. In addition, commenters stated that EPA used highly
aggregated performance metrics comparing model estimates to
observations that they believe result in a degraded and lenient
operational evaluation of the modeling system. A commenter suggested
that EPA's model performance provides no confidence for the intended
purpose of estimating deposition near point sources. One commenter
simply noted that EPA's model over-estimated total Hg wet deposition at
MDN monitors. Finally, several commenters noted that EPA presented a
negative modeled wet deposition total in the Air Quality Modeling TSD,
which is physically impossible.
Response: EPA agrees with the commenters that the negative estimate
for wet deposition in the Air Quality Modeling TSD was an error. This
error reflected an incorrect calculation in the post-processing of
model and observation pairs that only influenced the calculation of
model performance metrics. The error has been fixed, and the model
performance metrics in the revised Air Quality Modeling TSD have been
updated. This error did not affect Hg deposition. In response to
comments, the EPA provided additional model performance evaluation by
season to the revised Air Quality Modeling TSD. In addition, in
response to comments, the EPA also included model performance
evaluation for total Hg wet deposition for the 36 km modeling domain in
the revised Air Quality Modeling TSD.
The EPA disagrees that it did not conduct an assessment comparing
CMAQ total Hg wet deposition estimates to MDN data. The Air Quality
Modeling TSD clearly shows a comparison of CMAQ estimated total Hg wet
deposition with MDN data for the entire length of the modeling period.
The CMAQ wet deposition of Hg has been and will continue to be
extensively evaluated against MDN sites.\111\ There is no dry
deposition monitoring network, which precludes evaluating CMAQ dry
deposition processes. The EPA disagrees that an evaluation of ambient
speciated Hg against routine monitor networks such as AMNet or SEARCH
would be useful for this particular modeling application. The AMNet Hg
network did not exist in 2005, which is EPA's baseline model simulation
time period, and the SEARCH network started making preliminary
measurements of Hg at one or two sites in 2005. In addition,
measurement artifacts related to gaseous oxidized Hg are difficult to
quantify and make direct comparison to model estimates
problematic.\112\ Considering the problems associated with TEKRAN
measurements of ambient Hg and the sparse nature of routine
measurements in the U.S., the EPA did not compare ambient Hg against
model estimates.
---------------------------------------------------------------------------
\111\ Bullock, O.R., Atkinson, D., Braverman, T., Civerolo, K.,
Dastoor, A., Davignon, D., Ku, J.Y., Lohman, K., Myers, T.C., Park,
R.J., Seigneur, C., Selin, NE., Sistla, G., Vijayaraghavan, K.,
2009. ``An analysis of simulated wet deposition of mercury from the
North American Mercury Model Intercomparison Study.'' Journal of
Geophysical Research-Atmospheres 114.
\112\ Lyman, S.N., Jaffe, D.A., Gustin, M.S., 2010. ``Release of
mercury halides from KCl denuders in the presence of ozone.''
Atmospheric Chemistry and Physics 10, 8197-8204.
---------------------------------------------------------------------------
The EPA disagrees that the model performance presented in the air
quality TSD is insufficient. The EPA asserts that the model performance
evaluation is generally similar to the level of model performance
presented in literature. One commenter presented the results of several
Hg modeling studies as providing information that the commenter
believes to be relevant for this assessment in terms of model
performance metric estimation and the level of model performance
evaluation shown for assessments modeling Hg near point sources. For
example, one cited study titled ``Modeling Mercury in Power Plant
Plumes'' models near-source Hg chemistry from U.S. EGUs, but provides
absolutely no information about model performance evaluation.\113\
---------------------------------------------------------------------------
\113\ Lohman et al., 2006.
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Another commenter identified two studies as supposedly having Hg
modeling results that are applicable to EPA's
analysis.114 115 These studies present similar model
performance metrics as EPA. The EPA disagrees that the Agency used
``highly aggregated performance metrics'' that result in degraded and
lenient model evaluation. The studies presented 116 117 as
relevant for point source mercury modeling use an approach to aggregate
the operational performance metrics across many monitor locations as
did EPA; however, these articles calculate long term annual averages of
modeled and observed total Hg wet deposition before estimating
performance metrics. It is common practice to pair modeled estimates
and observations in space and time (weekly in this case) and estimate
performance metrics, then average all the metrics together. The latter
is the approach taken by the EPA and should have been taken by the
studies presented by the commenter. The EPA used a more stringent
approach to match observations and predictions and aggregation of
operational model performance. The EPA agrees that the commenter
accurately restated total wet deposition model performance information
provided by the EPA in the Air Quality Modeling TSD. To provide
context, other Hg modeling studies show a positive bias for annual
total Hg wet deposition.118 119 An annual Hg modeling
application done by ENVIRON \120\ and the Atmospheric and Environmental
Research for Lake Michigan Air Directors Consortium show seasonal
average normalized bias between 70 and 158 percent and seasonal average
normalized error between 72 and 503 percent.\121\ These results
indicate a very large over-estimation tendency. The model performance
shown by EPA is consistent with other long-term Hg modeling
applications.
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\114\ Seigneur, C., Lohman, K., Vijayaraghavan, K., Jansen, J.,
Levin, L., 2006. ``Modeling atmospheric mercury deposition in the
vicinity of power plants.'' Journal of the Air & Waste Management
Association 56, 743-751.
\115\ Vijayaraghavan, K., Karamchandani, P., Seigneur, C.,
Balmori, R., Chen, S.-Y., 2008. ``Plume-in-grid modeling of
atmospheric mercury.'' Journal of Geophysical Research-Atmospheres
113.
\116\ Seigneur, C., Lohman, K., Vijayaraghavan, K., Jansen, J.,
Levin, L., 2006. ``Modeling atmospheric mercury deposition in the
vicinity of power plants.'' Journal of the Air & Waste Management
Association 56, 743-751.
\117\ Vijayaraghavan, K., Karamchandani, P., Seigneur, C.,
Balmori, R., Chen, S.-Y., 2008. ``Plume-in-grid modeling of
atmospheric mercury.'' Journal of Geophysical Research-Atmospheres
113.
\118\ Id.
\119\ Vijayaraghavan et al., 2007.
\120\ Yarwood, G, Lau, S., Jia, Y., Karamchandani, P.,
Vijayaraghavan, K. 2003. Final Report: Modeling Atmospheric Mercury
Chemistry and Deposition with CAMx for a 2002 Annual Simulation.
Prepared for Wisconsin Department of Natural Resources. https://www.gypsymoth.wi.gov/air/toxics/mercury/hg_X97579601_appB.pdf.
\121\ Yarwood et al., 2003.
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4. Excess Local Deposition From Hg Emissions From U.S. EGUs (Deposition
Hotspots)
Comment: One commenter stated that reducing Hg will benefit local
environments. The commenter stated that a 2007 study confirmed the
presence of Hg ``hotspots'' downwind from coal-fired power plants and
confirmed that coal-fired power plants within the U.S. are the primary
source of Hg to the Great Lakes and the Chesapeake Bay.\122\ The
commenter also stated that the study is consistent with a major Hg
deposition study conducted
[[Page 9342]]
by the EPA and the University of Michigan that concluded that
approximately 70 percent of Hg wet deposition resulted from local
fossil fuel emissions in the region.\123\
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\122\ Evers, David C. et al., 2007. ``Biological Mercury
Hotspots in the Northeastern United States and Southeastern
Canada,'' Bioscience. Vol. 57 No. 1. p. 29.
\123\ Cohen, et al., 2004. ``Modeling the Atmospheric Transport
and Deposition of Mercury to the Great Lakes,'' Environmental
Research 95, (247-265).
---------------------------------------------------------------------------
One commenter agreed with the Agency's assessment of the potential
for deposition ``hotspots'' that shows that Hg deposition near EGUs can
be three times as large as the regional average. The commenter stated
that this excess Hg deposition would substantially increase the health
and environmental risks associated with emissions at these sites. The
same commenter also stated that EPA applied a conservative methodology
to quantify near-source Hg deposition. The commenter stated that
maximum excess local Hg deposition may be significantly underestimated
by averaging high deposition sites downwind of an EGU in the direction
of prevailing winds with lower excess deposition at locations close to
but frequently upwind of the facility. The same commenter suggests that
had EPA used CMAQ and individual 12x12 km\2\ grid cells to quantify
local deposition, the model could increase the excess Hg deposition at
these locations significantly and place them at even greater risk of
adverse health and environmental effects of HAP from U.S. EGUs.
One commenter stated that the Hubbard Brook Research Foundation
issued a report in 2007 that identified five Hg hotspots, one of which
was in the Adirondack Park, along with four suspected hotspots.\124\
The commenter stated that this study also provides a good description
of the impacts of Hg on the Common Loon, which is a symbol of a healthy
Adirondack environment.
---------------------------------------------------------------------------
\124\ Driscoll, C.T., D. Evers, K.F. Lambert, N. Kamman, T.
Holsen, Y-J. Han, C. Chen, W. Goodale, T. Butler, T. Clair, and R.
Munson. Mercury Matters: Linking Mercury Science with Public Policy
inthe Northeastern United States. 2007. Hubbard Brook Research
Foundation. Science Links Publication. Vol. 1, no. 3.
---------------------------------------------------------------------------
One commenter stated that there is there is no evidence of Hg
hotspots due to local deposition associated with coal-fired power
plants. According to the commenter, the EPA's use of a 50 km radius to
calculate hotspots is flawed. The commenter stated that modeling
studies show that deposition of Hg emitted from power plants is not
confined to a 50-km radius around the plants and that most emissions
from power plants travel beyond 50 km.\125\
---------------------------------------------------------------------------
\125\ Seigneur et al., 2006.
---------------------------------------------------------------------------
Several commenters stated that the EPA does not adequately define
hotspots in this proposed rule. Those same commenters cited a previous
EPA definition of hotspots as ``a waterbody that is a source of
consumable fish with MeHg tissue concentrations, attributable solely to
utilities, greater than EPA's MeHg water quality criterion of 0.3 mg/
kg'' (milligrams per kilogram).\126\ The same commenters stated that it
is unclear why EPA changed from defining a hotspot by fish tissue MeHg
concentration to defining a hotspot by depositional excess. Two
commenters suggested that a Hg hotspot is a specific location that is
characterized by elevated concentrations of Hg exceeding a well-
established criterion, such as a reference concentration (RfC) when
compared to its surroundings. Those same commenters stated that
identifying Hg hotspots should not be constrained to locations where
concentrations can be attributed to a single source or sector.\127\ One
of those two commenters noted that others have defined ``hotspots as a
spatially large region in which environmental concentrations far exceed
expected values, with such values (i.e. concentrations) being 2 to
three standard deviations above the relevant mean.'' \128\
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\126\ U.S. EPA, 2005. 40 CFR Part 63 [OAR-2002-0056; FRL-7887-7]
RIN 2060-AM96. Revision of December 2000 Regulatory Finding on the
Emissions of Hazardous Air Pollutants From Electric Utility Steam
Generating Units and the Removal of Coal- and Oil-Fired Electric
Utility Steam Generating Units From the Section 112(c). Final rule,
March 29.
\127\ Evers et al., 2007.
\128\ Sullivan T., 2005. ``The Impacts of Mercury Emissions from
coal-fired Power Plants on Local Deposition and Human Health Risk.''
Presented at the Pennsylvania Mercury Rule Workgroup Meeting,
October 28.
---------------------------------------------------------------------------
One commenter stated that Hg concentrations are not always highest
at sites closest to a major source. The commenter referred to a study
\129\ that demonstrated that concentrations of atmospheric reactive
gaseous Hg, gaseous elemental Hg, and fine particulate Hg were lower
when measured 25 km from a 1,114 MW coal-fired EGU than when measured
100 km away. The commenter stated that these findings contradict the
idea, implicit in EPA's hotspot analysis, that reactive gaseous Hg
decreases with distance from a large point source.
---------------------------------------------------------------------------
\129\ Kolker, et al., 2010.
---------------------------------------------------------------------------
One commenter provided information from a non-peer reviewed report
with wet Hg deposition measurements downwind from the coal-fired power
plant Crist in Pensacola, FL. The commenter stated that using the same
data from these same wet deposition sites, one study \130\ found that
Hg wet deposition and concentrations did not differ in a statistically
significant manner among these three sites and that the concentrations
values were similar to those from Mercury Deposition Network (MDN)
sites that are more than 50 km away from Plant Crist located along the
Northern Gulf of Mexico coast.
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\130\ Caffrey, J.M., Landing, W.M., Nolek, S.D., Gosnell, K.J.,
Bagui, S.S., Bagui, S.C., 2010. ``Atmospheric deposition of mercury
and major ions to the Pensacola (Florida) watershed: spatial,
seasonal, and inter-annual variability.'' Atmospheric Chemistry and
Physics 10, 5425-5434.
---------------------------------------------------------------------------
Another commenter stated that Plant Crist installed a wet scrubber
and has operated that scrubber continuously since December 2009. The
commenter stated that the scrubber reduces total Hg emissions by about
70 percent and reduces emissions of reactive gaseous Hg by about 85
percent. The commenter cited a non-peer reviewed conference
presentation \131\ that reported changes in Hg wet deposition relative
to historic measurements. The commenter stated that, taken
collectively, these findings show that increased local total Hg
deposition, possibly due to EGUs, and deposition changes due to changes
in EGU emissions, are small.
---------------------------------------------------------------------------
\131\ Krishnamurthy N., Landing W.M, Caffrey J.M., 2011.
``Rainfall Deposition of Mercury and Other Trace Elements to the
Northern Gulf of Mexico.'' Presented at the 10th International
Conference on Mercury as a Global Pollutant, Halifax, Nova Scotia,
Canada, July 27.
---------------------------------------------------------------------------
Two commenters stated that a study by the Department of Energy
(DOE) that collected and analyzed soil and vegetation samples for Hg
near three U.S. coal-fired power plants--one in North Dakota, one in
Illinois, and one in Texas--found no strong evidence of ``hotspots''
around these three plants.
Two commenters stated that analysis of long-term trends in Hg
emissions from coal-fired EGUs and wet deposition in Florida concluded
that statistical analysis does not show evidence of a significant
relationship between temporal trends in Hg emissions from coal-fired
EGUs in Florida and Hg concentrations in precipitation during 1998 to
2010.
Two commenters stated that the Hg Risk TSD presents no information,
summary statistics, and/or actual calculations showing how excess
deposition within 50 km of an EGU source is obtained. The commenters
stated that by assessing only Hg deposition attributable to EGUs, the
EPA fails to provide a context for all other sources of Hg deposition.
The commenters stated that the Agency does not explain why deposition
from the top 10 percent of EGU Hg emitters does not decline, despite
substantial reductions in modeled Hg emissions from those sources
between 2005 and 2016.
[[Page 9343]]
According to the commenters this implies that the top 10 percent EGUs
may have approximately as much of a regional effect as a local effect.
Two commenters stated that the CMAQ model has limitations when used
to predict local deposition and tends to overestimate local deposition.
The commenters stated that modeling studies using either a plume model
or an Eulerian model predict that 91 to 96 percent of the Hg emitted by
an EGU travels beyond 50 km.\132\
---------------------------------------------------------------------------
\132\ Edgerton et al., 2006.
---------------------------------------------------------------------------
Response: The EPA agrees with the commenters that stated that Hg
emissions from EGUs deposit locally and regionally and contribute to
excess local deposition near U.S. EGUs. The EPA acknowledges additional
studies \133\ cited by those commenters that corroborate EPA's
conclusions. However, the EPA disagrees with those commenters'
characterization of the methodology used to calculate the potential for
excess local deposition. In response, the EPA has clarified the
methodology in the new TSD entitled ``Technical Support Document:
Potential for Excess Local Deposition of U.S. EGU Attributable Mercury
in Areas near U.S. EGUs,'' which is available in the docket.
---------------------------------------------------------------------------
\133\ Driscoll et al., 2007.
---------------------------------------------------------------------------
The EPA agrees that there is no generally agreed-upon definition of
``hotspot.'' As discussed in the preamble and TSD, for the purposes of
the appropriate and necessary finding, the EPA determined that
information on the potential for excess deposition of Hg in areas
surrounding power plants would be useful in informing the finding. The
EPA disagrees with some commenters who misinterpreted the intent of the
Hg deposition hotspot analysis. Specifically, the analysis is not of
``Hg hotspots'', which are often defined as high Hg concentration in
fish, but rather of Hg deposition hotspots, defined as excess local Hg
deposition around U.S. EGUs, as clarified in the new Local Deposition
TSD. Because EPA did not identify ``Hg hotspots'' of high Hg
concentrations in fish, the EPA's MeHg water quality criterion of 0.3
mg/kg is irrelevant to EPA's analysis of excess local Hg deposition for
this rule.
The EPA disagrees that the analysis assumes that deposition of Hg
is confined to a 50-km radius around power plants. The purpose of the
EPA's analysis was to evaluate whether there existed ``excess
deposition of Hg in nearby locations within 50 km of EGUs that might
result in Hg deposition `hotspots'.'' As explained further in the new
TSD, the EPA calculated the average EGU-attributable deposition (based
on CMAQ modeling of Hg deposition) in the area 500 km around each plant
and the average EGU-attributable deposition in the area 50 km around
each plant. The difference between those two values is the excess local
deposition around the plant. The EPA does not suggest Hg emissions from
power plants stop at 50 km from the source. Some portion of EGU
emissions deposit before 50 km, and some portion travels beyond 50 km.
In addition, Hg disperses as it transports, so the average EGU
contribution can be lower in areas beyond 50km relative to areas within
50km even though Hg emissions from EGUs are depositing into U.S.
watersheds.
The EPA disagrees with some commenters' interpretation of the
analysis as being focused on local deposition from all sources. In
fact, the focus was on excess local deposition, rather than all local
deposition. The EPA has clarified the purpose of the excess local
deposition analysis in the new TSD. The EPA agrees that all EGUs add to
local deposition, however, not all EGUs have local deposition that
greatly exceeds regional deposition, which is the relevant question.
The EPA disagrees that the DOE study referenced by the commenters
attempted to assess the same analytical question as EPA's analysis. The
DOE study focused on comparisons of total deposition near and far from
power plants. The EPA's analysis did not focus on total Hg deposition,
because as EPA acknowledges throughout its analysis, global sources of
Hg deposition account for a large percentage of total Hg deposition. In
addition, including global sources of Hg deposition would obscure the
comparison of local and regional U.S. EGU-attributable Hg deposition.
Because of regional deposition from both domestic and global sources of
Hg, total Hg deposition at any location is unlikely to be highly
correlated with local sources. The EPA's analysis focused on U.S. EGU-
attributable Hg deposition and demonstrates that for some plants
(especially those with high Hg emissions), there is local deposition of
Hg that exceeds the average regional deposition around the plant.
The EPA's analysis shows heterogeneity in the amount of excess
local deposition around plants. The new Local Deposition TSD shows that
some plants can have local deposition that is less than the regional
average deposition, suggesting that most of the Hg from those plants is
transported regionally or that other EGUs in the vicinity of those
plants dominate the deposition of Hg near the plants. This does not
detract from the overall finding that around some power plants with
high levels of Hg emissions excess local deposition is on average three
times the regional EGU-attributable deposition around those plants.
The EPA disagrees that the Hg Risk TSD did not provide sufficient
information regarding the excess local deposition calculation.
Nonetheless, the EPA has further clarified the methodology in the new
Local Deposition TSD, including further descriptions of the method used
to calculate the local and regional deposition around power plants
along with maps and tables of results.
The EPA disagrees with the commenters that stated that the
discussion of local deposition in the Hg Risk TSD did not demonstrate
that Hg deposition from the top 10 percent of EGU Hg emitters declines.
Table 1 of the new Local Deposition TSD clearly shows that mean local
deposition (within 50km of a plant) for the top 10 percent of emitters
declines from 4.89 micrograms per cubic meter ([micro]g/m\3\) to 1.18
[micro]g/m\3\. What does not change is the percent local excess for
EGU-attributable Hg deposition. This implies that while Hg deposition
from EGUs is declining, there is still an excess contribution to local
deposition relative to regional deposition; e.g., because of
dispersion, the contribution to average deposition outside 50 km from
the plant is lower than the contribution to average deposition within
50 km of the plant.
The EPA disagrees that the information \134\ provided by the
commenter regarding the Crist plant and other coal-fired power plants
in Florida is relevant to EPA's analysis of excess local deposition
from U.S. EGUs because it is based on measurements of wet Hg deposition
without consideration of dry Hg deposition, which can be a significant
component of Hg deposition.
---------------------------------------------------------------------------
\134\ EPRI, 2010.
---------------------------------------------------------------------------
The EPA disagrees with the commenter regarding the interpretation
of the literature related to the spatial extent of deposition of Hg
emitted by U.S. EGUs. The EPA also disagrees that the peer-reviewed
CMAQ model has limitations for this application or overestimates local
deposition. The commenter does not provide any credible support for the
assertion that grid-based models typically overestimate local
deposition surrounding EGUs. The EPA maintains that the CMAQ
photochemical model represents the best science currently available in
simulating atmospheric
[[Page 9344]]
chemistry, transport, and deposition processes.
The study \135\ cited by the commenter to support the notion that
91 to 96 percent of Hg emitted from power plants travels beyond 50 km
is based on a photochemical transport model (the TEAM model) that does
not employ current state-of-the-science and is not actively developed
or updated. Furthermore, the modeling is based on grid cells that are
20 km in size, which limits generalizability to EPA modeling performed
at 12 km grid resolution using a state of the science photochemical
grid model. The cited modeling study ignores dry deposition of
elemental Hg from all sources, an assumption that clearly limits the
regional impacts from sources.\136\ The methodology of this study cited
by the commenter is critically flawed in that it presents no results
where individual Hg emission sources are removed and the difference
between the zero out simulation (where emissions from U.S. EGUs are set
to zero) and the baseline model simulations are directly compared.
Finally, the modeling study cited by the commenter presents an
illustration of gridded total annual Hg deposition from the TEAM model
for the eastern U.S. that clearly shows elevated annual total Hg
deposition in the vicinity of coal-fired power plants in the Ohio River
Valley and northeast Texas.
---------------------------------------------------------------------------
\135\ Seigneur et al., 2006.
\136\ Id.
---------------------------------------------------------------------------
d. Hg Risk TSD
1. Assumption of Linear Proportionality in Relationship Between Changes
in Hg Deposition and Changes in Fish Tissue Hg Concentrations (Mercury
Maps)
Comment: Several commenters criticized EPA's assumption that
changes in deposition resulting from U.S. EGU emissions of Hg will
result in proportional changes in fish tissue Hg concentrations at the
watershed level, as supported by the Mercury Maps modeling exercise.
According to one commenter, the Mercury Maps model has limited
capability to adequately determine bioaccumulation in fish. The same
commenter stated that the Mercury Cycling Model (MCM) developed by EPRI
is a more rigorous model that was developed expressly to evaluate the
relationship between changes in atmospheric Hg deposition to
waterbodies and changes in fish tissue MeHg levels.
Several commenters stated that the Mercury Maps model has many
deficiencies. Those commenters stated that Mercury Maps is a static
model unable to account for the dynamics of ecosystems that affect Hg
bioaccumulation in fish, cannot consider non-air Hg inputs to
watersheds, and assumes reductions in airborne Hg lead to proportional
reductions in fish MeHg concentrations. Another commenter claimed that
data that demonstrate a steady-state linear reduction in fish tissue
MeHg in response to a reduction in atmospheric Hg deposition within
watersheds do not exist and provided several references that they
claimed show non-linear responses to changes in Hg
deposition.137 138
---------------------------------------------------------------------------
\137\ Harris., R.C., John W.M. Rudd, Marc Amyot, Christopher L.
Babiarz, Ken G. Beaty, Paul J. Blanchfield, R.A. Bodaly, Brian A.
Branfireun, Cynthia C. Gilmour, Jennifer A. Graydon, Andrew Heyes,
Holger Hintelmann, James P. Hurley, Carol A. Kelly, David P.
Krabbenhoft, Steve E. Lindberg, Robert P. Mason, Michael J.
Paterson, Cheryl L. Podemski, Art Robinson, Ken A. Sandilands,
George R. Southworth, Vincent L. St. Louis, and Michael T. TateRudd,
J. W.M., Amyot M., et al., Whole-Ecosystem study Shows Rapid Fish-
Mercury Response to Changes in Mercury Deposition. Proceedings of
the National Academy of Sciences Early Edition, PNAS 2007 104 (42)
pp. 16586-16591; (published ahead of print September 27, 2007).
\138\ Orihel D.M., Paterson M.J., Blanchfield P.J., Bodaly R.A.,
Gilmour C.C., Hintelmann H., 2007. ``Temporal Changes in the
Distribution, Methylation, and Bioaccumulation of Newly Deposited
Mercury in an Aquatic Ecosystem,'' Environmental Pollution, 154, 77-
88.
---------------------------------------------------------------------------
The same commenter disagreed with EPA's interpretation of Figure 2-
17 in the March TSD and stated that a U.S. Geological Survey national
waterway study \139\ showed that sheet flow and drainage, not
deposition, dominated input to the waterbodies it surveyed. The
commenter stated that sheet flow and drainage could contain Hg and thus
complicate the relationship that EPA asserts is linear and direct.
Another commenter cited Figure 2-17 in the Hg Risk TSD as showing that
there is no well-defined relationship between Hg deposition and MeHg
concentrations in fish tissue on a national basis.
---------------------------------------------------------------------------
\139\ Scudder B.C., Chasar L.C., Wentz D.A., Bauch N.J., Brigham
M.E., Moran P.W., Krabbenhoft D.P., 2009. Mercury in fish, bed
sediment, and water from streams across the United States, 1998-
2005: U.S. Geological Survey Scientific Investigations Report 2009-
5109, 74 p.
---------------------------------------------------------------------------
Several commenters provided comments related to the assumption that
fish tissue Hg levels used in the analysis represent a steady-state.
One commenter stated that given the demonstrated lag time in response
to deposition change, it is logical to conclude that a lag time needs
to be incorporated in Mercury Maps to adjust the estimation of how much
fish tissue MeHg levels decrease in response to decreases in Hg
deposition attributable to U.S. EGUs. According to the same commenter,
the METAALICUS study shows that there is a lag time (and a non-
proportional response) after 3-4 years. The same commenter noted that
there are numerous factors that influence lag time including (1)
watershed characteristics,\140\ (2) the fact that watersheds may act as
legacy sources releasing Hg when disturbed,\141\ (3) the magnitude of
emission reductions and subsequent changes in atmospheric deposition
need to be weighed against the amount of Hg already in an
ecosystem,\142\ (4) the distance of an ecosystem from Hg sources,\143\
and (5) the fact that Hg deposited to aquatic ecosystems becomes less
available for uptake by biota over time.\144\ Another commenter stated
that additional Mercury Maps assumptions do not allow for
considerations of lag in response to changes in: (1) Deposition, (2)
legacy sources of Hg such as mining, (3) historical Hg deposition, (4)
natural Hg levels in fish, (5) ecosystem dynamics over time, or (6) the
relative source contributions over time. Another commenter stated that
lag times need to be included in the modeling and be able to vary from
watershed to watershed and sometimes even from waterbody to waterbody
within a watershed. Several commenters stated that the emission rates
of Hg due to U.S. sources have been decreasing for more than a decade,
while emissions due to sources outside the U.S. have been increasing.
For this reason, the commenter asserted that the system is not at
steady-state, a basic premise of the model. Another commenter stated
that while the time lag for deposition to reach a waterbody is
mentioned in the Hg Risk TSD, there is no discussion of the fact that a
[[Page 9345]]
portion of the deposition is unlikely to reach the water at all.
---------------------------------------------------------------------------
\140\ Grigal D.F., 2002. ``Inputs and Outputs of Mercury from
Terrestrial Watersheds: A Review,'' Environmental Review, 10, 1-39.
\141\ Yang H., Rose N.L., Battarbee R.W., Boyle J.F., 2002.
``Mercury and Lead Budgets for Lochnagar, a Scottish Mountain Lake
and Its Catchment,'' Environmental Science & Technology, 36, 1383-
1388.
\142\ Krabbenhoft D.P., Engstrom D., Gilmour C., Harris R.,
Hurley J., Mason R., 2007. Monitoring and Evaluating Trends in
Sediment and Water Indicators. In Harris R., Krabbenhoft D., Mason
R., Murray M.W., Reash R., Saltman T. (Eds.), Ecosystem Responses to
Mercury Contamination: Indicators of Change. New York: Society of
Environmental Toxicology and Chemistry (SETAC) North America
Workshop on Mercury Monitoring and Assessment, CRC, pp. 47-87.
\143\ Lindberg S. et al. 2007. ``A synthesis of progress and
uncertainties in attributing the sources of mercury in deposition.''
Ambio 36(1): 19-32.
\144\ Orihel D.M., Paterson M.J., Blanchfield P.J., Bodaly R.A.,
Hintelmann H., 2008. ``Experimental Evidence of a Linear
Relationship between Inorganic Mercury Loading and Methylmercury
Accumulation by Aquatic Biota,'' Environmental Science & Technology,
41, 4952-4958.
---------------------------------------------------------------------------
One commenter believes EPA incorrectly implied that its EGU risk
estimates using Mercury Maps are underestimated because they do not
account for legacy EGU-attributable deposition, which EPA assumes to be
higher.
One commenter stated that while EPA properly screened out
watersheds with significant current non-air sources of Hg, the EPA did
not adequately screen out watersheds with significant Hg contributions
from non-air sources, specifically watersheds with historic Hg or gold
mining or other industrial Hg discharges. The same commenter stated
that EPA's study was not geographically balanced and was dominated by
rivers in the coastal region of the southeast that has numerous
wetlands, which are favorable locations for methylation and have
conditions that are not typical of much of the rest of the U.S.
Response: The EPA disagrees with the commenters who challenged the
assumption of a linear proportional relationship between changes in
U.S. EGU deposition and fish tissue Hg levels. The EPA specifically
asked the SAB to evaluate EPA's assumption of linear proportionality in
the relationship between Hg deposition and fish tissue MeHg
concentrations, supported by the Mercury Maps analysis. The SAB peer
review committee provided the following overall response, which
generally supports EPA's approach:
The SAB agrees with the Mercury Maps approach used in the
analysis and has cited additional work that supports a linear
relationship between mercury loading and accumulation in aquatic
biota. These studies suggest that mercury deposited directly to
aquatic ecosystems can become quickly available to biota and
accumulated in fish, and reductions in atmospheric mercury
deposition should lead to decreases in methylmercury concentrations
in biota. The SAB notes other modeling tools are available to link
deposition to fish concentrations, but does not consider them to be
superior for this analysis or recommend their use. The integration
of Community Multiscale Air Quality Modeling System (CMAQ)
deposition modeling to produce estimates of changes in fish tissue
concentrations is considered to be sound. Although the SAB is
generally satisfied with the presentation of uncertainties and
limitations associated with the application of the Mercury Maps
approach in qualitative terms, it recommends that the document
include quantitative estimates of uncertainty available in the
existing literature.\145\
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\145\ U.S. EPA-SAB, 2011.
The SAB peer review committee specifically addressed the MCM
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suggested by the commenter and had the following response:
The SAB agrees with the application of Mercury Maps in this
assessment. There are other modeling tools capable of making a
national scale assessment, such as the Regional Mercury Cycling
Model (R-MCM). However, the R-MCM is more data intensive and the
results produced by the two model approaches should be equivalent.
The R-MCM, a steady-state version of the time-dependent Dynamic
Mercury Cycling Model, has been publicly available to and used by
the EPA (Region 4, Athens, Environmental Research Laboratory) for a
number of years. R-MCM requires more detail on water chemistry,
methylation potential, etc., and yields more information as well.
Substantial data support the Mercury Maps and the R-MCM steady-state
results, so that the results of the sensitivity analysis and the
outcomes from using the alternative models would be equivalent
between the two modeling approaches. Though running an alternative
model framework may provide additional reassurance that the Mercury
Maps ``base case'' approach is a valid one, it is unlikely that
substantial additional insight would be gained with the alternative
model framework.\146\
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\146\ U.S. EPA-SAB, 2011.
In addition, the SAB stated, ``Since the Mercury Maps approach was
developed, several recent publications have supported the finding of a
linear relationship between mercury loading and accumulation in aquatic
biota.147 148 149 These studies suggested that mercury
deposited directly to aquatic ecosystems can become quickly available
to biota and accumulated in fish, and that reductions in atmospheric
mercury deposition should lead to decreases in methylmercury
concentrations in biota. These results substantiate EPA's assumption
that proportionality between air deposition changes and fish tissue
methylmercury level changes is sufficiently robust for its application
in this risk assessment.'' \150\
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\147\ Orihel et al., 2007.
\148\ Orihel et al., 2008.
\149\ Harris et al., 2007.
\150\ U.S. EPA-SAB, 2011.
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Based on the responses of the SAB peer review committee, the EPA's
use of the linear proportionality assumption, supported by the Mercury
Maps analysis, is well-supported.
The EPA also disagrees with commenters' interpretation of Figure 2-
17. As stated in the Hg Risk TSD, while this figure is useful to
demonstrate the lack of correlation across watersheds between total
deposition of Hg and MeHg concentrations in fish tissue, it is not
indicative of the likely correlation between changes in Hg deposition
at a given watershed and changes in MeHg concentrations in fish tissue
from that watershed. The SAB agreed with this interpretation, noting
the importance of Figure 2-17 demonstrating that ``spatial variability
of deposition rates is only one major driver of spatial variability of
fish methylmercury and that variability of ecosystem factors that
control methylation potential (especially wetlands, aqueous organic
carbon, pH, and sulfate) also play a key role.'' \151\
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\151\ U.S. EPA-SAB, 2011.
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In response to recommendations from the SAB, the EPA expanded the
discussion of uncertainties associated with the linearity assumption,
including uncertainties related to the potential for sampled fish
tissue Hg level to reflect previous Hg deposition and the potential for
non-air sources of Hg to contribute to sampled fish tissue Hg levels.
Each of these sources of uncertainty may result in potential bias in
the estimate of exposure associated with current deposition. The EPA
took steps to minimize the potential for these biases by (1) only using
fish tissue Hg samples from after 1999, and (2) screening out
watersheds that either contained active gold mines or had other
substantial non-U.S. EGU anthropogenic emissions of Hg. The SAB
commented that EPA's approach to minimizing the potential for these
biases to affect the results of the risk analysis appears to be sound
and that additional criteria that could be applied are unlikely to
substantially change the results. As a result, the EPA disagrees with
the commenter that EPA's screening process is inadequate. In addition,
we conducted several sensitivity analyses to gauge the impact of
excluding watersheds with the potential for non-EGU Hg emissions, and
found that the results were robust to these exclusions.
In response to specific comments regarding the use of the Mercury
Maps model, the EPA clarifies that the Hg Risk TSD did not directly use
the Mercury Maps model. Instead, the EPA applied an assumption of
linear proportionality between changes in Hg deposition and changes in
MeHg concentrations in fish that is supported by the Mercury Maps
modeling. By assuming steady-state conditions in apportioning fish
tissue Hg levels and risk, the EPA does not attempt to project lag
times. Recent research cited by the SAB 152 153 154
identifies relatively rapid response of fish tissue Hg to changes in Hg
loading, which suggests that fish tissue Hg levels could react more
[[Page 9346]]
quickly to reductions in Hg deposition than previously thought. This
finding reduces concern that fish tissue Hg levels could be linked to
older patterns of Hg deposition and strengthens the approach used in
the revised Hg Risk TSD. While fish tissue may respond rapidly to
changes in Hg loading, this does not change the fact that previously
emitted Hg from U.S. EGUs can be re-emitted and re-deposited, and thus
affect Hg concentration in fish.
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\152\ Orihel et al., 2007.
\153\ Orihel et al., 2008.
\154\ Orihel et al., 2007.
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2. Characterization of Subsistence Fishing Populations and Exposure
Scenario
Comment: Several commenters stated that EPA provides no clear
definition of subsistence, near subsistence, or high-end fish
consumption, instead assuming that poverty is a direct indication of
subsistence fishing and high-end fish consumption. One commenter stated
no documentation exists to supports these assumptions. Another
commenter stated that EPA's definitions of subsistence fishers in the
Hg Risk TSD are not consistent with earlier EPA documents and are used
inconsistently throughout the Hg Risk TSD. Several commenters stated
that while subsistence fishing can be associated with poverty, poverty
does not indicate subsistence fishing. One commenter stated that by
including watersheds with as few as 25 members of individuals living in
poverty, the EPA overstates risks.
One commenter stated that it is unclear what literature the Agency
says ``generally supports the plausibility of high-end subsistence-like
fishing * * * to some extent across the watersheds'' and stated that if
other studies exist, the EPA should provide the values for comparison.
One commenter stated that EPA combined two parameters with
differing scales to establish the geographic unit used in the Hg Risk
TSD risk assessment. The HUC watersheds are based on average about 35
square miles in size, while U.S. census tracts used to identify
watersheds relevant for subpopulations of interest--cover a few tenths
to hundreds of square miles. Several commenters stated that it is
unclear how the analysis handled differences in geographic resolution
between watersheds and census tracts were.
One commenter stated that the procedure for assigning census tracts
could bias exposure outcomes. For example, the commenter stated that a
single influential census tract in a watershed could drive risk, even
if the watershed had only a minimal number of fish samples. The
commenter stated that this possibility is a concern in urban areas,
which account for the majority of census tracts, because these census
tracts are more likely to be included in a risk analysis because they
have more than 25 people living in poverty. The commenter stated that
these census tracts may drive the extremes of the distribution without
regard to the actual number of high-level, self-caught fish consumers
within their boundaries. The commenter stated that they could not
assess the potential bias and noted that EPA did not test the bias by
sensitivity analyses.
Several commenters stated that EPA was not clear whether the
poverty criteria were applied in all scenarios or just for the high-end
female fish consumer scenario. One commenter stated that EPA should
apply the minimum 25 source population criteria only to populations of
women of childbearing age. One commenter stated that EPA's assumption
would result in any densely populated urban census tract with a single
fish tissue sample being assigned to a modeled watershed with
populations potentially at-risk, regardless of the actual degree of
recreational or subsistence fishing taking place there.
Response: The EPA agrees with the comments that subsistence fish
consumption was not clearly defined, and we have provided a clearer
definition in the revised Hg Risk TSD, however, this clarification does
not result in any changes to the quantitative analysis. In the revised
Hg Risk TSD, the EPA clarifies that ``subsistence fishers'' are defined
as individuals who rely on noncommercial fish as a major source of
protein.\155\ This definition is reflected in the range of fish
consumption rates used in estimating risk. The likely presence of this
type of subsistence fish consumer is supported by available peer
reviewed literature (see Table 1-5 of the revised Hg Risk TSD). These
studies clearly show that a subset of surveyed fishers consumes self-
caught fish at the rates cited in the Hg Risk TSD. The SAB peer review
concluded that the consumption rates and locations for fishing activity
are supported by the data presented in the Hg Risk TSD, and are
generally reasonable and appropriate given the available data.\156\
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\155\ U.S. EPA, U.S. Environmental Protection Agency. 2000.
Guidance for Assessing Chemical Contaminant Data for Use in Fish
Advisories, Volume 3: Overview of Risk Management. Office of Science
and Technology, Office of Water, U.S. Environmental Protection
Agency, Washington, DC EPA 823-B-00-007.
\156\ U.S. EPA-SAB, 2011.
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The EPA notes that there is some confusion in the comments related
to the size of the watersheds modeled. Several commenters stated that
HUC watersheds are 35 km on a side. The commenters appear to be
referring to HUC8 classifications. The HUCs are defined for varying
spatial resolutions. The geographic unit used as the basis for
generating risk estimates is HUC12, which are watersheds about 10 km on
a side, which is comparable with the size of the 12 km\2\ grid cells in
CMAQ, which are 12 km\2\. The EPA has also clarified that the specific
unit of analysis for this assessment is at the watershed, not
enumerated subpopulations.
The EPA only used the U.S. Census tracts to determine whether there
are populations in the vicinity of a given watershed, which could
increase the potential for a category of subsistence fishers to be
active at that watershed. In the revised Hg Risk TSD, the EPA modified
the female subsistence scenario to apply equally to all watersheds with
fish tissue Hg data based on the likelihood that these populations have
the potential to fish at most watersheds. As described in the revised
Hg Risk TSD, the EPA made this change in response to SAB's concerns
regarding the potential exclusion of watersheds with fewer than 25
individuals and regarding coverage for high-end recreational fish
consumption.\157\ Thus, concerns regarding the use of census data to
select watersheds with the potential for subsistence fishing no longer
apply to this scenario. However, for the remaining subsistence
scenarios, the EPA continues to use U.S. Census tract-level data to
evaluate the presence of a ``source population'' in the vicinity of the
watershed being modeled for risk. In this context, the EPA uses the
U.S. Census data to assess whether a socioeconomic status (SES)-
differentiated group similar to the particular type of subsistence
fisher being modeled (e.g., poor Hispanics) are located in the vicinity
of the watershed. If a source population is nearby, then this increases
the potential that subsistence fishing activity could occur for that
population scenario.
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\157\ This change led to a very small increase in the number of
watersheds with populations potentially at-risk. In the Hg Risk TSD
accompanying the proposed rule, approximately 4 percent of modeled
watersheds were excluded based on the SES-based filtering criteria.
---------------------------------------------------------------------------
The EPA continues to model risk for white and black subsistence
fishers active in the southeast and for Hispanics assessed nationally.
In this case, the EPA links poverty with subsistence fishing, as EPA
only modeled locations with poor source populations. However, in
modeling these three populations, the
[[Page 9347]]
EPA asserts that the presence of a poor source population indicates the
potential for subsistence fishing activity, rather the presence of such
activity. The linkage between poverty and higher rates of subsistence
fish consumption is supported by the Burger et al. study,\158\ which
identified substantially higher consumption rates for poor individuals
(see Table 5 of the study). The EPA acknowledges that subsistence
fishing activity by specific subpopulations might only be present
across a subset of the watersheds EPA modeled for risk. However, given
the stated goal of the analysis to determine the percent of watersheds
where the potential exists for exposures to U.S. EGU-attributable Hg to
represent a public health hazard, identifying a set of watersheds with
the potential for the type of high fish consumption that leads to high
Hg exposure is appropriate. The EPA notes that relatively few
watersheds (less than 4 percent) have fish tissue Hg data, and, thus,
can be included in the risk assessment. Consequently, while there is
the potential for including some watersheds in the analysis that may
not have currently active subsistence fishing activity, it is likely
that EPA excluded other watersheds from the analysis where this type of
subsistence fishing activity occurs due to a lack of fish tissue Hg
data.
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\158\ Burger, J., 2002. ``Daily Consumption of Wild Fish and
Game: Exposures of High End Recreationists,'' International Journal
of Environmental Research and Public Health, 12 (4), 343-54.
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While EPA agrees with the comment that it is likely that exposure
to total MeHg through commercial fish consumption represents a more
significant risk for the general population than consumption of
freshwater fish obtained through self-caught fishing activity, exposure
to total MeHg through self-caught fish consumption is the most
significant risk for subsistence fishing populations and high-end
recreational fishers. For the subset of these populations that focus
their fishing activity in freshwater streams and lakes, it is also the
case that they will experience a higher fraction of MeHg exposure
attributable to U.S. EGU Hg emissions. As a result, the EPA focused the
risk assessment on subsistence fishers active at inland freshwater
watersheds because they are likely to experience the highest levels of
individual risk as a result of exposure to U.S. EGU-attributable Hg.
3. Cooking Loss Adjustment Factor
Comment: Several commenters stated that EPA did not justify the
selection of a cooking loss factor of 1.5 that, according to one
commenter, increases estimated intake by 50 percent, thus increasing
the daily MeHg intake rate by a constant factor of 33 percent and also
increasing any resulting (HQ) risk estimate by a similar factor.
Several commenters stated that the source of EPA's selected loss factor
\159\ reported a range of cooking losses from 1.1 to 6. Several
commenters cite several studies that report no or highly variable
changes in MeHg levels as a result of cooking
fish.160 161 162 163 164 One commenter suggested that EPA's
cooking loss adjustment factor of 1.5 is at the high-end of the values
supported by the literature. Another commenter stated that EPA has used
other adjustment factors in previous documents, and that the adjustment
factor should not be fixed across different populations given potential
differences in cooking practices. Several commenters noted that the
cooking loss adjustment factor should only be applied to estimates of
consumption rates for prepared fish, and that some sources of
consumption rates are based on raw fish.
---------------------------------------------------------------------------
\159\ Morgan, J.N., M.R. Berry, and R.L. Graves. 1997. ``Effects
of Commonly Used Cooking Practices on Total Mercury Concentration in
Fish and Their Impact on Exposure Assessments.'' Journal of Exposure
Analysis and Environmental Epidemiology 7(1):119-133.
\160\ Armbruster G., Gerow K.G., Lisk D.J., 1988. ``The Effects
of Six Methods of Cooking on Residues of Mercury in Striped Bass,''
Nutrition Reports International, 37, 123-126.
\161\ Gutenmann, W.H. and Lisk D.J., 1991. ``Higher Average
Mercury Concentration in Fish Fillets after Skinning and Fat
Removal,'' Journal of Food Safety, 11, 99-103.
\162\ Farias L.A., Favaro, D.I., Santos J.O., Vasconcellos M.B.,
et al., 2010. ``Cooking Process Evaluation on Mercury Content in
Fish,'' Acta Amazonia, 40 (4), 741-748.
\163\ Perell[oacute] G., Mart[iacute]-Cid R., Llobet J.M.,
Domingo J.L., 2008. ``Effects of Various Cooking Processes on the
Concentrations of Arsenic, Cadmium, Mercury, and Lead in Foods,''
Journal of Agricultural and Food Chemistry, 156 (22), 11262-11269.
\164\ Torres-Escribano S., Ruiz A., Barrios L., V[eacute]lez D.,
Montoro R., 2011. ``Influence of Mercury Bioaccessibility on
Exposure Assessment Associated with Consumption of Cooked Predatory
Fish in Spain,'' Journal of the Science of Food and Agriculture, 91
(6), 981-6.
---------------------------------------------------------------------------
Response: The EPA disagrees with the commenters that the selection
of the cooking loss factor of 1.5 is not justified by the literature.
The EPA also disagrees with the comment that the cooking loss
adjustment factor of 1.5 is at the high-end of the range of values in
the literature. The EPA selected the Morgan study \165\ as the basis
for the food preparation/cooking adjustment factor because it focused
on the types of freshwater fish species representative of what might be
consumed by subsistence fishing populations (i.e., walleye and lake
trout). This study \166\ provides a range of adjustment factors for
each fish type including 1.1 to 1.5 for walleye and 1.5 to 2.0 for lake
trout. Given these two ranges, the EPA determined it to be reasonable
to take an intermediate value between the two ranges (i.e., 1.5),
rather than focus on either the highest or lowest values, which is not
the most conservative assumption that the EPA could have made. This
study \167\ also explains that preparation/cooking of fish results in
an increase in MeHg levels per unit fish because Hg concentrates in the
muscle, while preparation/cooking tends to reduce non-muscle elements
(e.g., water, bone, fat).
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\165\ Morgan et al., 1997.
\166\ Id.
\167\ Id.
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Regarding the alternative studies identified by the commenters, the
EPA disagrees that these studies considered collectively contradict the
cooking loss factor in the analysis. Specifically, the first study
\168\ may have included measurement of non-fish components added to
dishes (e.g., onions, heavy breading etc.), which could dilute the
post-cooking Hg measurements and give the appearance of a cooking loss
even as actual fish tissue Hg levels could have increased. In the
second study,\169\ the fish species are saltwater and not freshwater,
and the authors note that the reduction of water and fat could increase
in the Hg concentration without changing absolute content. The third
study focused on measurement of bioaccessible Hg in raw and cooked
fish.\170\ However, available information currently allows us to
specify the risk model in terms of total Hg intake, not bioaccessible
Hg, thus, this article is potentially informative for guiding future
research and methods development, not the current risk assessment. The
fourth study \171\ found a modest but statistically insignificant
increase in Hg levels for most of the cooking methods assessed, which
is directionally consistent with EPA's cooking loss adjustment. The
fifth study \172\ only addressed the issue qualitatively, thus cannot
be used for the cooking loss factor. When considered collectively, the
EPA disagrees that the additional studies identified by the commenter
contradict the cooking loss factor used in the risk assessment and
maintains that the Morgan study \173\ remains the most
[[Page 9348]]
applicable for characterizing cooking/preparation effects on Hg
concentrations in fish.
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\168\ Farias et al., 2002.
\169\ Perell[oacute] et al., 2008.
\170\ Torres-Escribano et al., 2011.
\171\ Armbruster et al., 1988.
\172\ Gutenmann et al., 1991.
\173\ Morgan et al., 1997.
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The EPA agrees that application of the cooking loss adjustment
factor is appropriate if the fish consumption rates are for as cooked
or as consumed and not for raw fish. Careful review of the three
studies used in the risk assessment to identify subsistence fisher
consumption rates suggests that all three represent annual-average
daily intakes (g/day) of as consumed or as cooked fish. One study
stated that they used models of portion or meal size servings (the size
of the serving the respondent regularly eats).\174\ Therefore, the EPA
interprets the fish consumption rates provided in this study \175\ as
representing as cooked/prepared and not for raw fish and for that
reason, application of a preparation/cooking adjustment factor is
required. Another study \176\ used different sized models of cooked
fish filets and therefore these consumption rates are also interpreted
as represented as cooked/prepared and not raw fish. One study
177 178 queried survey responders for meal portion or
serving size and therefore, the consumption rates do represent as
cooked/prepared. Because all three studies provide consumption rates
based on as cooked/prepared or as consumed, it is appropriate to apply
the cooking loss adjustment factor in modeling exposure.
---------------------------------------------------------------------------
\174\ Burger et al., 2002.
\175\ Id.
\176\ Shilling, Fraser, Aubrey White, Lucas Lippert, Mark Lubell
(2010). Contaminated fish consumption in California's Central Valley
Delta. Environmental Research 110, p. 334-344.
\177\ Dellinger JA. 2004. ``Exposure assessment and initial
intervention regarding fish consumption of tribal members of the
Upper Great Lakes Region in the United States.'' Environ Res 95:325-
340.
\178\ Personal communication, Dr. Dellinger, September 27, 2011.
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4. Fish Consumption Rates and Fish Tissue Hg Characterization
Comment: One commenter stated that in the past the Agency has
recommended various default consumption rates (in the general range of
130 to <150 g/day) to provide default intakes for subsistence fishers
under the Risk Assessment Guidance for Superfund (RAGS) or the Fish
Advisory Guidance.179 180 The commenter stated that these
default consumption rates are derived from various studies and
generally are based on 90th or 99th percentile distribution estimates.
Another commenter stated that EPA's use of the 99th percentile fish
consumption for its risk analysis is inconsistent with the Agency's
risk assessment guidelines, which recommend evaluating a reasonable
maximum exposure (``RME'') scenario,\181 \which equates to about a 95th
percentile fish consumption value. The same commenter stated that EPA
applied the 99th percentile to a ``small survey of 149 South Carolina
female anglers'' to calculate an ingestion rate of 373 grams per day
(g/day). The commenter stated that if the 95th percentile is used the
ingestion rate would be 173 g/day and if the default ingestion rate for
determining ambient water standards is used the ingestion rate would be
142 g/day.
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\179\ U.S. EPA. 1991. Risk Assessment Guidance for Superfund
(RAGS). Part C 1991 EPA/9285.7-01C. October.
\180\ U.S. EPA. 2000. National Guidance: Guidance for Assessing
Chemical Contaminant Data for Use in Fish Advisories, Volume 2. EPA
823-B-00-008, November.
\181\ U.S. EPA. 1989. Risk Assessment Guidance for Superfund
(RAGS). EPA/540/1-89/002. December.
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Several commenters stated that EPA based its fish consumption rates
used in the risk analysis on a limited number of studies and that those
studies are poorly documented.
Another commenter stated that EPA should summarize available
supporting studies by basic study content, characteristics, design,
size, demographics, dietary recall period, and fish intake rates by
demographic variables. According to the commenter, this summary would
support the scientific validity of the assessment and better illustrate
the potential variability and uncertainty involved in extrapolating
data from small populations to the national-scale. The commenter also
noted that the three studies actually used to provide subsistence
population estimates, which were extrapolated to the national-scale,
included a limited number of individuals living in diverse and
localized areas.
One commenter stated that the assumption with the greatest impact
on risk is the fish consumption rate. That same commenter stated that
using 99th percentile ingestion rate dramatically increases HQ and IQ
loss compared to the 50th percentile ingestion rate. The commenter
stated that when an estimate of the 95th percentile ingestion rate of
the 15 to 44 year old female population is considered, the HQ is a
tenth of the value computed with the 99th percentile high-end female
fisher.
One commenter stated that EPA provides broad summary statistics of
its fish tissue data in Table 5-2 of the Regulatory Impact Analysis
(RIA), but the summary does not allow an assessment of the
representativeness and robustness of the underlying data for the risk
assessment, especially at the tails of the distribution. The commenter
stated that the table does not include a median statistic and does not
provide any information on the number of lakes and river segments in
each watershed. According to the commenter, an analysis of EPA's
database by the SAB indicated that 60 percent of the watersheds with
fish Hg data from rivers have risks calculated based upon a sample size
of one or two fish. The commenter stated that it is not reasonable to
base a significant policy and regulation decision on watersheds where
exposure is based on a single fish sample in a single water body within
it.
Several commenters criticized EPA's use of the 75th percentile fish
tissue MeHg level in a watershed. One commenter stated that EPA
provided no rationale for its decision to choose the highest of the
75th percentile for fish Hg levels among rivers and lakes within the
HUC. Several commenters stated that subsistence fishers are less likely
to target larger fish relative to recreational fishers. Several
commenters suggested that EPA include a sensitivity analysis using the
mean or median fish MeHg level in a watershed. One commenter also
stated that EPA arbitrarily inflated the risk estimates by assuming
consumption of only fish greater than 7 inches and choosing the largest
of the 75th percentile of fish Hg levels from these larger fish (i.e.,
larger than 7 inches) for rivers and lakes. That same commenter
suggested using the median of all size fish, not just those over 7
inches.
One commenter stated that EPA should quantify adverse effects from
the ingestion of MeHg in seafood in addition to ingestion of MeHg from
self-caught freshwater fish. According to the commenter, recent studies
demonstrate that were EPA to take into account consumption of seafood,
MeHg consumption in the U.S. is of even greater concern.
Response: The EPA acknowledges that the focus of the Hg Risk TSD is
characterizing risk for the groups likely to experience the greatest
U.S. EGU-attributable Hg risk, which are subsistence fishing
populations active at inland freshwater lakes and rivers. Specifically,
within that subsistence fishing population, the EPA is interested in
those individuals who are most at-risk, which includes those who
consume the most fish. For that reason, the EPA considered a range of
high-end fish consumption rates including the 99th percentile
representing the most highly-exposed individuals. In responding to the
SAB peer review, the EPA clarified this focus in the
[[Page 9349]]
introduction to the revised Hg Risk TSD and changed the full title to
revised Technical Support Document: National-Scale Assessment of
Mercury Risk to Populations with High Consumption of Self-caught
Freshwater Fish.
The EPA agrees that the fish consumption rate is an important
factor in calculating risk from exposure to MeHg in fish. The EPA
acknowledges that the distribution of fish consumption rates is
positively skewed, which means that at higher percentiles (e.g., 90th,
95th, and 99th) there is a substantial increase in ingestion rates
relative to the mean or median. The revised Hg Risk TSD includes a
reasonableness check on the amount of fish consumed (as a daily value)
reflected in the different rates. While the 99th percentile consumption
rates for the subsistence female fisher (373 g/day) is substantially
higher than the 90th or 95th percentile values (123 and 173 g/day
respectively), the 99th percentile value translates into a 13-ounce
meal. While this represents a large serving, it is still reasonable if
representing an individual who receives all of their meat protein from
self-caught fishing, and the 13 ounces per day do not have to be eaten
all at one meal. The higher consumption rates (i.e., greater than 250
g/day) are supported by all three studies used in the risk assessment,
and therefore, there is support across studies near the upper bound of
likely consumption rates in this range. The EPA acknowledges
uncertainty associated with estimating high-end percentile values in
these studies due to relatively low sample sizes for some population
groups. However, even if a few individuals reported these high self-
caught fish consumption rates, making it difficult to characterize the
population percentiles they represent, the values still suggest that
these levels of high fish consumption exist among surveyed individuals.
To determine whether a public health hazard could exist, the EPA
asserts that it is reasonable to include these consumption rates as
representative of the most at-risk populations. In these cases,
however, the EPA acknowledges that it is important to highlight
uncertainty associated with characterizing the specific population
percentile that these ingestion rates represent, and EPA has done so in
the revised Hg Risk TSD.
The EPA disagrees with the comment that high consumption rates are
poorly documented. Evidence of these high fish consuming populations
can be found in surveys \182\ and specialized
studies.183 184 185 186 187 Several studies identified
additional fishing populations with subsistence or near subsistence
consumption rates, including urban fishing populations (including low-
income populations),188 189 190 Laotian communities,\191\
and Hispanics. The EPA participated in 1999 in a project investigating
exposures of poor, minority communities in New York City to a number of
contaminants including Hg, which found these populations can have very
high fish consumption rates.\192\ The SAB concluded that the
consumption rates and locations for fishing activity are supported by
the data presented in the Hg Risk TSD, and are generally reasonable and
appropriate given the available data.\193\
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\182\ Burger et al., 2002.
\183\ Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, and S. Von
Hagen. 1999a. ``Fishing in Urban New Jersey: Ethnicity Affects
Information Sources, Perception, and Compliance.'' Risk Analysis
19(2): 217-229.
\184\ Burger, J., Stephens, W. L., Boring, C. S., Kuklinski, M.,
Gibbons, J. W., Gochfeld M. 1999b. ``Factors in Exposure Assessment:
Ethnic and Socioeconomic Differences in Fishing and Soncumption of
Fish Caught along the Savannah River.'' Risk Analysis, Vol. 19, No.
3, p. 427.
\185\ California Environmental Protection Agency (CalEPA). 1997.
Chemicals in Fish Report No. 1: Consumption of Fish and Shellfish in
California and the United States Final Draft Report. Pesticide and
Environmental Toxicology Section, Office of Environmental Health
Hazard Assessment, July.
\186\ Tai, S. 1999. ``Environmental Hazards and the Richmond
Laotian American Community: A Case Study in Environmental Justice.''
Asian Law Journal 6: 189.
\187\ Corburn, J. 2002. ``Combining community-based research and
local knowledge to confront asthma and subsistence-fishing hazards
in Greenpoint/Williamsburg, Brooklyn, New York.'' Environmental
Health Perspectives 110(2).
\188\ Burger et al., 1999a.
\189\ Burger et al., 1999b.
\190\ CalEPA, 1997.
\191\ Tai, 1999.
\192\ Corburn, 2002.
\193\ U.S. EPA-SAB, 2011.
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The EPA agrees that the Hg Risk TSD would be improved by clarifying
that the literature review focused on identifying studies that
characterize subsistence fish consumption for groups active at
freshwater locations within the U.S., and EPA has revised the Hg Risk
TSD accordingly. In the Hg Risk TSD, the EPA summarized important study
attributes for the source studies used to obtain fish consumption
rates. This information was provided in Table C-1 in an appendix. To
improve clarity, the EPA moved the summary table to the main body in
the revised Hg Risk TSD. In identifying these studies, the EPA focused
on surveys for subsistence fishers that were applicable at the broader
regional or national level. In the Hg Risk TSD, the EPA acknowledged
the smaller sample sizes for some of the subsistence fisher groups, and
in several cases the EPA did not use the 99th percentile consumption
rates because the sample sizes were too low to support this level of
resolution. This decision did not affect EPA's finding of a hazard to
public health, which is based on the results for the female subsistence
fishing population, which has an estimate of the 99th percentile
consumption rate that is supported by an adequate sample size.
The EPA disagrees with the comment that it did not provide a
rationale for choosing the 75th percentile fish tissue concentration
across lakes and rivers in a watershed. However, the EPA modified the
methodology based on evaluation of the number of samples within each
watershed (responding to a recommendation from the SAB). In the revised
methodology, the EPA computes the 75th percentile value at each
sampling site within a watershed. The EPA then computed the average of
the site-specific 75th percentile fish tissue Hg values within a given
watershed. This approach does not differentiate between rivers and
lakes and reflects an improved treatment of behavior, allowing for
fishers to choose among multiple fishing sites within a watershed.
The EPA generally agrees with the comment that some fraction of
subsistence fishers likely consume fish without consideration for size
(given dietary necessity), however, the EPA considers it reasonable to
assume that a subset of subsistence fishers could target larger fish in
order to maximize the potential consumption per unit of fishing effort.
The EPA uses this subset of subsistence fishers targeting larger fish,
which is represented by the 75th percentile fish tissue value, in the
risk assessment. In addition, including the female subsistence fishing
population in the analysis also provides coverage for high-end
recreational anglers who target larger freshwater fish. The SAB
commented that: ``Using the 75th percentile of fish tissue values as a
reflection of consumption of larger, but not the largest, fish among
sport and subsistence fishers is a reasonable approach and is
consistent with published and unpublished data on predominant types of
fish consumed.'' \194\ The SAB suggested that EPA include a sensitivity
analysis based on use of the median value, and EPA has done so in the
revised Hg Risk TSD. This sensitivity analysis showed that using the
median estimates had only a small impact on the number and percent of
modeled watersheds with
[[Page 9350]]
populations potentially at-risk from U.S. EGU-attributable MeHg
exposures. In the revised Hg Risk TSD, the EPA clarified that the 7-
inch cutoff represents a minimum size limit for a number of key edible
freshwater fish species established at the State-level. For example,
Pennsylvania establishes 7 inches as the minimum size limit for both
trout and salmon (other edible fish species such as bass, walleye and
northern pike have higher minimum size limits).\195\
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\194\ U.S. EPA-SAB, 2011.
\195\ Pennsylvania Fish and Boat Commission. 2011. Summary Book:
2011 Pennsylvania Fishing Laws & Regulations available at: https://fishandboat.com/fishpub/summary/inland.html.
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The EPA disagrees with the comment that it is not reasonable to use
watersheds where only a single fish sample is available. Although it is
generally preferred to have multiple samples, the SAB noted that using
a single sample is likely to underestimate the 75th percentile fish
MeHg concentration and is, therefore, likely to underestimate the risk
estimates for those watersheds. The SAB suggested that EPA conduct
additional analyses of the fish tissue MeHg data, which EPA has done
and included in the revised Hg Risk TSD. The revised Hg Risk TSD
includes information on the number of watersheds modeled in the risk
assessment with various fish tissue Hg samples sizes (e.g., 1, 2, 3-5,
6-10 and >10 measurements).
5. Reference Dose (RfD) for MeHg and Hg Health Effects Studies
Comment: Several commenters stated that EPA's RfD \196\ is based on
sound science, which was supported by the findings of the NAS
Study,\197\ and that EPA appropriately applied the RfD in the Hg risk
assessment. The commenters also stated that recent studies find clear
associations between maternal blood Hg levels and delayed child
development and cardiovascular effects, as well as potential for
effects due to exposure to pollutant mixtures including lead.
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\196\ U.S. Environmental Protection Agency--Integrated Risk
Information System (U.S. EPA-IRIS). 2001. Methylmercury (MeHg)
(CASRN 22967-92-6). Available at https://www.epa.gov/iris/subst/0073.htm.
\197\ NAS, 2000.
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However, many commenters expressed concerns regarding EPA's use of
the MeHg RfD as a benchmark for health risk. Several commenters raised
concerns claiming that EPA has not incorporated the best available Hg
toxicological data into the RfD, which results in a flawed analysis and
an overestimate of the impact of Hg emissions on human health.
Several commenters stated that, when deriving the RfD, the EPA
relied on the flawed Faroe Islands' children study and ignored the
Seychelles Islands study,\198\ which did not confirm any harm on
children due to MeHg exposure. According to the commenters, application
of the Faroe Island study is suspect because (1) the raw data from the
study have never been made available for independent analysis and
scrutiny, (2) there is potential for confounding by polychlorinated
biphenyls (PCBs) and lead, (3) population exposure to MeHg was through
consumption of highly contaminated pilot whale meats and blubbers, and
(4) exposure levels in the U.S. remain lower than those observed in the
primary study. One commenter also notes that (1) Seychelles Islanders
consume far more fish than Americans do; (2) the amount of MeHg in the
U.S. population is much lower than the Seychelles Islanders; and (3)
all ocean fish contain about the same amount of MeHg, so MeHg intake
per fish meal is similar between Americans and Seychelles Islanders.
However, another commenter stated that industry arguments against using
the Faroe Islands study fail to acknowledge that the study results were
consistent with studies in the Seychelles Islands, New Zealand,\199\
and Poland.\200\
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\198\ Budtz-Jorgensen E, Debes F, Weihe P, Grandjean P. 2005.
``Adverse Mercury Effects in 7-Year-Old Children Expressed as Loss
in ``IQ''.'' EPA-HQ-OAR-2002-0056-6046.
\199\ Kjellstrom, T; Kennedy, P; Wallis, S; et al. 1986.
Physical and mental development of children with prenatal exposure
to mercury from fish. Stage 1: Preliminary test at age 4. Natl Swed
Environ Protec Bd, Rpt 3080 (Solna, Sweden).
\200\ Wieslaw Jedrychowski et al. 2006. ``Effects of Prenatal
Exposure to Mercury on Cognitive and Psychomotor Function in One-
Year-Old Infants: Epidemiologic Cohort Study in Poland,'' 16 Annals
of Epidemiology 439.
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One commenter criticized EPA for using a linear dose-response model
for the RfD-based HQ metric and the IQ metric. Another commenter stated
that the RfD assumes a threshold dose below which an appreciable risk
of adverse effects is unlikely, and NAS did not evaluate whether MeHg
exposure data were better fit by a linear or non-linear model or by a
threshold or non-threshold model.
Several commenters stated that EPA's MeHg RfD is more conservative
than ``safe'' levels determined by other federal agencies and claim
that EPA assigned unusually high uncertainty factors. Several
commenters stated that EPA's use of the 1999 National Health and
Nutrition Examination Survey (NHANES) blood Hg levels show a downward
trend since 1999, and the levels have been below the RfD since 2001.
One commenter stated that a study by Texas Department of State
Health Services (DSHS, 2004) \201\ determined that among subsistence
fishers who eat fish from Caddo Lake with elevated MeHg, women of
child-bearing years did not have blood Hg levels greater than the RfD.
Thus, according to the commenter, the connection between MeHg in fish
and adverse health effects in the U.S. is not fully understood and
could involve other factors, including the protective effects of fatty
acids and selenium in fish, which EPA did not taken into account.
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\201\ DSHS. 2005. Health Consultation: Mercury Exposure
Investigation Caddo Lake Area-Harrison County Texas. Agency for
Toxic Substances and Disease Registry. https://www.tceq.state.tx.us/assets/public/comm_exec/pubs/sfr/085.pdf.
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Two commenters claim that EPA uses the RfD as if it were an
absolute threshold for health risk in the risk assessment even though
the RfD methodology is a screening tool for deciding when risks clearly
do not exist.
Several commenters recommended adding qualitative discussions to
the Hg Risk TSD regarding several aspects of uncertainty, including
uncertainty in the RfD, uncertainty in extrapolating a dose-response
relationship between MeHg exposure and change in IQ, uncertainty in
extrapolating the dose-response relationship from marine fish and
marine mammals to freshwater fish, and uncertainty due to potential
confounding by PCBs in marine species.
Several commenters raised concerns regarding the relationship
between MeHg exposure and IQ loss. Two commenters stated that changes
in IQ are not a well-defined health consequence of MeHg exposure. One
commenter stated that the SAB had reservations about EPA's use of IQ
loss. Two commenters questioned whether IQ impacts would even occur
because in Japan and Korea, where the maternal blood Hg levels are
higher than in the U.S., there is no evidence of adverse effects.
Another commenter cited a study\202\ that found verbal IQ scores for
children from mothers with no seafood intake were 50 percent more
likely to be in the lowest quartile. One commenter questions using an
IQ risk metric threshold of >1 or >2 points because variation in IQ
measures and the intra-individual variation in IQ are higher than the
threshold.
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\202\ Hibbeln JR, Davis JM, Steer C, Emmett P, Rogers I,
Williams C, et al., 2007. ``Maternal seafood consumption in
pregnancy and neurodevelopmental outcomes in childhood (ALSPAC
study): an observational cohort study. '' Lancet 369:
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Several commenters question the relationship between cardiovascular
effects and MeHg exposure. Two
[[Page 9351]]
commenters cited studies examining the relationship between MeHg
exposure and cardiovascular effects,203 204 205 206 207 208
but concluded that it seems premature to use these studies to establish
a dose-response relationship.
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\203\ Roman HA, Walsh TL, Coull BA, Dewailly [Eacute], Guallar
E, Hattis D, et al., 2011. Evaluation of the Cardiovascular Effects
of Methylmercury Exposures: Current Evidence Supports Development of
a Dose-Response Function for Regulatory Benefits Analysis. Environ
Health Perspect 119:607-614.
\204\ Guallar E, Sanz-Gallardo MI, van't Veer P, et al., 2002.
``Mercury, fish oils, and the risk of myocardial infarction.'' N
Engl J Med.;347:1747.
\205\ Virtanen JK, Voutilainen S, Rissanen TH, et al., 2005.
``Mercury, fish oils, and risk of acute coronary events and
cardiovascular disease, coronary heart disease, and all-cause
mortality in men in eastern Finland.'' Arterioscler Thromb Vasc
Biol. 2005;25:228.
\206\ Yoshizawa, Rimm, Morris, Spate, Hsieh, Spiegelman,
Stampfer, Willett. ``Mercury and the Risk of Coronary Heart Disease
in Men,'' N Engl J Med 2002; 347:1755-1760.
\207\ Hallgren CG, Hallmans G, Jansson JH, et al., 2001. Markers
of high fish intake are associated with decreased risk of a first
myocardial infarction. Br J Nutr: 86:397.
\208\ Mozaffarian, Dariush. 2011. ``Mercury Exposure and Risk of
Cardiovascular Disease in Two U.S. Cohorts,'' N Engl J Med 364:
1116-1125.
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Several commenters assert that the risks from eating seafood are
low relative to the benefits, that fish advisories can limit the
beneficial aspects of fish consumption, and that fish advisories are
often unsuccessful in changing behavior.209 210 One
commenter noted the important protective role of dietary selenium
against MeHg toxicity because the binding affinity of Hg to Se is much
higher than binding to sulfur.
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\209\ Hibbeln et al., 2007.
\210\ Mozaffarian, et al., 2011.
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Response: The EPA agrees with commenters that state the MeHg RfD is
the appropriate health value for determining elevated risks from MeHg
exposure and disagrees with commenters that state otherwise. At this
time, the EPA is neither reviewing nor revising its 2001 RfD for MeHg.
The 2001 RfD for MeHg is EPA's current peer-reviewed RfD, which is the
value EPA uses in all its risk assessments. The EPA's RfD is based on
multiple benchmark doses, and RfDs were calculated on various endpoints
using the three extant large studies of childhood effects of in utero
exposure: Faroe Islands, New Zealand, and an integrative measure
including data from Seychelles. The EPA did not choose to base the MeHg
RfD solely on results from the Seychelles Islands, as both the NAS
\211\ and an independent scientific review panel convened as part of
the IRIS process \212\ advised strongly against using results from a
study that at the time had not shown an association between MeHg
exposure and adverse effects. Further, the EPA disagrees with comments
stating that EPA based the MeHg RfD solely on results from the Faroe
Islands population and disagrees that the information underlying the
RfD is ``poorly explained''. The EPA has provided detailed
documentation for the choices underlying calculation of the
RfD.213 214 215 To correct a misunderstanding by the
commenter, the data underlying the Faroe Islands study have been
previously published in the peer reviewed literature.
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\211\ NAS, 2000.
\212\ U.S. EPA. 2001b. Responses to Comments of the Peer Review
Panel and Public Comments on Methylmercury. Available on the
Internet at https://www.epa.gov/iris/supdocs/methpr.pdf.
\213\ U.S. EPA, 2001a. Water Quality Criterion for the
Protection of the Human Health: MethylmercuryEPA-823-T-01-001,
available at https://water.epa.gov/scitech/swguidance/standards/criteria/aqlife/pollutants/methylmercury/index.cfm.
\214\ U.S. EPA-IRIS, 2001.
\215\ Rice D, Schoeny R, Mahaffey K. 2003. ``Methods and
Rationale for Derivation of a Reference Dose for Methylmercury by
the U.S. EPA.'' Risk Analysis 23(1)107-115.
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The EPA disagrees that it did not incorporate the latest Hg data to
support the appropriate and necessary finding. It is the policy of EPA
to use the most current peer reviewed, publicly available data and
methodologies in its risk assessments. However, the EPA noted in the
preamble to the proposed rule that ``data published since 2001 are
generally consistent with those of the earlier studies that were the
basis of the RfD, demonstrating persistent effects in the Faroe Island
cohort, and in some cases associations of effects with lower MeHg
exposure concentrations than in the Faroe Islands. These new studies
provide additional confidence that exposures above the RfD are
contributing to risk of adverse effects, and that reductions in
exposures above the RfD can lead to incremental reductions in risk.''
However, the EPA has not completed a comprehensive review of the new
literature, and as such, it would be premature to draw conclusions
about the overall implications for the RfD.
The EPA agrees that EPA's RfD is not the same as the levels used by
other federal agencies. In their advice to the EPA on the appropriate
bases for a MeHg RfD, NAS specifically recommended that EPA use neither
the study nor the uncertainty factor employed by the Agency for Toxic
Substances Disease Registry (ATSDR) in the calculation of the minimal
risk level.\216\
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\216\ NAS, 2000.
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The EPA disagrees that the uncertainty factor is ``unusually
high''. The uncertainty factor used in calculation of EPA's peer-
reviewed RfD is small (10 fold); half of this factor is to account for
measured variability in human pharmacokinetics, which is based on
advice of the NAS \217\ and an independent panel of scientific peer
reviewers convened as part of the IRIS process.\218\
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\217\ Id.
\218\ U.S. EPA, 2001b.
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The IRIS makes this statement regarding a threshold for MeHg, ``It
is also important to note that no evidence of a threshold arose for
methylmercury-related neurotoxicity within the range of exposures in
the Faroe Islands study. This lack [of a threshold] is indicated by the
fact that, of the K power models, K = 1 provided a better fit for the
endpoint models than did higher values of K.'' \219\
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\219\ U.S. EPA-IRIS, 2001.
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The EPA disagrees that it is using the MeHg RfD as an absolute
bright line for health effects in the risk assessment. As stated in the
preamble to this proposed rule, the RfD is an estimate of a daily
exposure to the human population that is likely to be without an
appreciable risk of deleterious effects during a lifetime. The EPA also
stated that no RfD defines an exposure level corresponding to zero
risk. Because mercury is a cumulative neurotoxin, it is important to
distinguish health effects from public health hazard. Within the
context of the appropriate and necessary finding, we interpret a public
health hazard as risk, rather than certain occurrence of health
effects.
The EPA disagrees that exposure levels in the U.S. are lower than
those in the Faroe Islands study. Exposure to MeHg in the U.S. has been
reported at the same levels as those published in the Faroe
Islands.\220\ One study notes that in the NHANES data (1999 to 2004),
the highest five percent of women's blood Hg exceeded 8.2 microgram per
liter ([micro]g/L) in the Northeast U.S. and 7.2 [micro]g/L in coastal
areas.\221\ Higher levels have been reported among subjects known to
consume fish. For example, one study reported mean blood Hg for adult
women to be 15 [micro]g/L; range for
[[Page 9352]]
men and women was 2 to 89.5 [micro]g/L.\222\ Note that some
publications have reported Hg effects in U.S. populations at or below
the current U.S. RfD.223 224 Also, the EPA disagrees with
the commenter stating all ocean fish throughout the world contain about
the same amount of MeHg. Marine fish in commerce differ widely in Hg
concentration by species, and fish within the same species but caught
at different locations have variable amounts of Hg in their
tissues.225 226
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\220\ Schober Susan E, Sinks Thomas H, Jones Robert L, Bolger P
Michael, McDowell Margaret, Osterloh John, Garrett E Spencer, Canady
Richard A, Dillon Charles F, Sun Yu, Joseph Catherine B, Mahaffey
Kathryn R. Blood mercury levels in U.S. children and women of
childbearing age, 1999-2000. JAMA. 2003 Apr 2; 289(13): 1667-1674.
\221\ Mahaffey, K.R., R.P. Clickner and R.A. Jeffries. 2009.
Adult Women's Blood Mercury Concentrations Vary Regionally in the
U.S.: Association with Patterns of Fish Consumption (NHANES 1999-
2004). Environ. Health Perspect., 117: 47-53.
\222\ Hightower Jane M, Moore Dan. Mercury levels in high-end
consumers of fish. Environ Health Perspect. 2003 Apr; 111(4): 604-
608.
\223\ Oken, E., Radesky, J.S., Wright, R.O., Bellinger, D.C.,
Amarasiriwardena, C.J., Kleinman, K.P., Hu, H., Gillman, M.W. 2008.
Maternal fish Intake during Pregnancy, Blood Mercury Levels, and
Child Cognition at Age 3 Years in a U.S. Cohort. American Journal of
Epidemiology, 167(10), 1,171-1,181.
\224\ Lederman, Sally Ann Robert L. Jones, Kathleen L. Caldwell,
Virginia Rauh, Stephen E. Sheets, Deliang Tang, Sheila Viswanathan,
Mark Becker, Janet L. Stein, Richard Y. Wang, and Frederica P.
Perera. 2008. Relation between Cord Blood Mercury Levels and Early
Child Development in a World Trade Center Cohort. Environmental
Health Perspectives 118(8) 1085-1091.
\225\ Hisamichi Y, Haraguchi K, Endo T. 2010. ``Levels of
mercury and organochlorine compounds and stable isotope ratios in
three tuna species taken from different regions of Japan.'' Environ
Sci Technol 44(15): 5971-8.
\226\ Sunderland EM. 2007. ``Mercury exposure from domestic and
imported estuarine and marine fish in the U.S. seafood market.''
Environ Health Perspect. 115(2): 235-42. Epub 2006 Nov 20.
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The EPA disagrees that there is a statistically discernible
downward trend in the NHANES data on blood Hg. The EPA is unaware that
a formal statistical analysis for temporal trends has been completed
for NHANES data on blood Hg levels for the period 1999 to 2008.
Mahaffeyet al., evaluating NHANES data collected 1999 to 2004 for women
at child-bearing age, could ``not support the conclusion that there was
a general downward trend in blood Hg concentrations over the 6-year
study period.'' \227\ However, the same publication noted that ``there
was a decline in the upper percentiles reflecting the most highly
exposed women'' having blood Hg concentration greater than established
levels of concern. Visual observations of the data show a slight
decrease in Hg blood level concentrations from 1999-2008 at the
geometric mean, but this decrease may not be statistically significant.
The EPA remains concerned that substantial numbers of women of
childbearing age in the U.S. may have blood Hg levels that are
equivalent to exposures at or above the RfD. While mean and 95th
percentiles from recent NHANES data are below the blood Hg
concentration equivalent to the RfD, blood levels for some portions of
the population (high consumers of fish, for example) show exposures
above this level. One study estimated very high blood Hg levels at the
99th percentile for females of child-bearing age.\228\ Other published
studies have shown that various population groups can have high blood
Hg levels.229 230 231 232 233 For example, one study found
that 83 percent of the NHANES Asian population exceeded the RfD-
equivalent blood mercury level.\234\
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\227\ Mahaffey, K.R., R.P. Clickner and R.A. Jeffries. 2009.
Adult Women's Blood Mercury Concentrations Vary Regionally in the
U.S.: Association with Patterns of Fish Consumption (NHANES 1999-
2004). Environ. Health Perspect., 117: 47-53.
\228\ Tran, N.L., L. Barraj, et al., 2004. ``Combining food
frequency and survey data to quantify long-term dietary exposure: a
methyl mercury case study.'' Risk Anal 24(1): 19-30.
\229\ Id.
\230\ Miranda, M.L., S. Edwards, et al., 2011. ``Mercury levels
in an urban pregnant population in Durham County, North Carolina.''
Int J Environ Res Public Health 8(3): 698-712.
\231\ Hightower and Moore, 2003.
\232\ Hightower, J.M., A. O'Hare, et al., (2006). ``Blood
mercury reporting in NHANES: identifying Asian, Pacific Islander,
Native American, and multiracial groups.'' Environ Health Perspect
114(2): 173-175.
\233\ McKelvey, W., R.C. Gwynn, et al., 2007. ``A biomonitoring
study of lead, cadmium, and mercury in the blood of New York city
adults.'' Environ Health Perspect 115(10): 1435-1441.
\234\ Hightoweret al., 2006.
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The EPA disagrees with the commenter regarding confounding by PCBs
and lead. Exposure to MeHg in the Faroe Islands was largely from
consumption of pilot whale meat; exposure to PCBs was found in the
portion of the population who also consume whale blubber. Numerous
analyses have shown neurobehavioral effects of PCBs; however, the
effects of MeHg and PCB in the Faroe Islands study are separable.\235\
The EPA also documented the independence of PCB and MeHg effects in the
Faroe Islands population.\236\ The National Institute of Environmental
Health Sciences (NIEHS) concluded that both PCB and Hg had adverse
effects.\237\ The NAS concluded that there was no empirical evidence or
theoretical mechanism to support the opinion that in utero Faroese
exposure to PCBs exacerbated the reported MeHg effect.\238\ A second
set of analyses found that the effect of prenatal PCB exposure was
reduced when the data were sorted into tertiles by cord PCB
concentrations.\239\ These analyses support a conclusion that there are
measurable effects of MeHg exposure in the Faroese children that are
not attributable to PCB toxicity. We also note that there was no report
of lead exposure in the Faroe Islands population.
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\235\ NAS, 2000.
\236\ U.S. EPA, 2001a.
\237\ National Institute of Environmental Health Sciences
(NIEHS). 1998. Scientific issues relevant to assessment of health
effects from exposure to methylmercury. Workshop organized by
Committee on Environmental and Natural Resources (CENR) Office of
Science and Technology Policy (OSTP), The White House, November 18-
20, 1998, Raleigh, NC.
\238\ NAS, 2000.
\239\ Budtz-J[oslash]rgensen, E., N. Keiding, and P. Grandjean.
1999. Benchmark modeling of the Faroese methylmercury data. Final
Report to U.S. EPA.
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The EPA disagrees with the commenter's assertion that the
connection between MeHg in fish and observed health effects is not
understood due to evidence from the cited Texas study.\240\ This is an
exposure study rather than a study on measures of neurobehavioral or
any other health endpoint. TCEQ noted that none of the Caddo Lake study
participants had blood Hg levels above the benchmark dose level (BMDL)
of 5.8 [mu]g/L (one of the several used by EPA in the calculation of
the MeHg RfD). The BMDL is not a ``no effect'' level. Rather it is an
effect level for a percentage of the population. The EPA has noted in
correspondence with TCEQ that, as an exposure study, the Caddo Lake
study may be representative of the surrounding population; however, the
sample size is very small. It is not appropriate to extrapolate from
Caddo Lake to larger regional or national populations.
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\240\ DSHA, 2005.
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The EPA is aware of the possibility of both interactions among
environmental contaminants and cumulative effects of pollutants that
produce the same adverse endpoint. The EPA guidance exists for dealing
with such scenarios.241 242 243 244 The Agency's concern
with the likelihood of human exposure to multiple contaminants is
[[Page 9353]]
reflected in the multi-chemical scope of the rulemaking. However, the
EPA focused the technical analyses supporting the proposed regulation
on effects of individual pollutants rather than cumulative effects.
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\241\ U.S. EPA. 1986. Guidelines for the Health Risk Assessment
of Chemical Mixtures. U.S. Environmental Protection Agency, Office
of Research and Development, Washington, DC September. EPA/630/R-98/
002. Available at https://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=2256.
\242\ U.S. EPA. 1999. Guidance for Performing Aggregate Exposure
and Risk Assessments. U.S. Environmental Protection Agency, Office
of Pesticide Programs, Washington, DC October. Available at https://www.pestlaw.com/x/guide/1999/EPA-19991029A.html.
\243\ U.S. EPA. 2000a. Supplementary Guidance for Conducting
Health Risk Assessment of Chemical Mixtures. U.S. Environmental
Protection Agency, Risk Assessment Forum, Washington, DC EPA/630/R-
00/002. Available at https://www.epa.gov/ncea/raf/pdfs/chem_mix/chem_mix_08_2001.pdf.
\244\ U.S. EPA. 2003a. Framework for Cumulative Risk Assessment.
Risk Assessment Forum, U.S. Environmental Protection Agency.
Washington, DC EPA/630/P-02/001F. EPA/600/P-02/001F. Available at
https://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=54944.
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The EPA disagrees with commenters suggesting that the RfD-based HQ
is inappropriate. The SAB ``agreed that EPA's calculation of a hazard
quotient for each watershed included in the assessment is appropriate
as the primary means of expressing risk,'' and that ``because the RfD
from which the HQ is calculated is an integrative metric of
neurodevelopmental effects of methylmercury, it constitutes a
reasonable basis for assessing risk.'' \245\
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\245\ U.S. EPA-SAB, 2011.
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The SAB also recommended that EPA revise the Hg Risk TSD to include
additional qualitative discussion about uncertainty in the revised Hg
Risk TSD. Specifically, the SAB recommended that EPA revise the Hg Risk
TSD ``to better explain the methods and choices made in the analysis,
and analytical results, and where the uncertainties lie.'' The SAB
noted several uncertainties related to the RfD. The EPA agrees with
this recommendation and included a more complete discussion of these
uncertainties in the revised Hg Risk TSD.
The EPA disagrees that the IQ metric threshold is questionable. The
SAB concluded that it was reasonable to consider a loss of >1 or >2 IQ
points a public health concern. The SAB stated, ``The Panel agreed that
if IQ loss is retained in the risk assessment despite these
reservations, a loss of one or two points would be an appropriate
benchmark.'' \246\ The SAB further comments in their report: ``The
consensus is that if IQ were to be used, then a loss of 1 or 2 points
as a population average is a credible decrement to use for this risk
assessment. This metric seems to be derived from the lead literature
and was peer reviewed by the Clean Air Scientific Advisory Committee
(U.S. EPA CASAC 2007).\247\ Although its applicability to methylmercury
is questionable, the size of the decrement is justified based on the
extensive analyses available from the literature reviewed by CASAC.''
\248\ As noted in other studies,\249\ \250\ a decrease of 1-2 points
at the mean results in a much larger decrease in those with IQs that
are much lower or higher than the mean.
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\246\ U.S. EPA-SAB, 2011.
\247\ U.S. Environmental Protection Agency--Science Advisory
Board (U.S. EPA-SAB). 2007. Clean Air Scientific Advisory
Committee's (CASAC) Review of the 1st Draft Lead Staff Paper and
Draft Lead Exposure and Risk Assessments. EPA-CASAC-07-003. March.
Available on the internet at https://yosemite.epa.gov/sab/
sabproduct.nsf/989B57DCD436111B852572AC0079DA8A/$File/casac-07-
003.pdf.
\248\ U.S. EPA-SAB, 2011.
\249\ Axelrad, D. A.; Bellinger, D. C.; Ryan, L. M.; Woodruff,
T. J. 2007. ``Dose-response relationship of prenatal mercury
exposure and IQ: An integrative analysis of epidemiologic data.''
Environmental Health Perspectives, 115, 609-615.
\250\ Bellinger DC. 2005. Neurobehavioral Assessments Conducted
in the New Zealand, Faroe Islands, and Seychelles Islands Studies of
Methylmercury Neurotoxicity in Children. Report to the U.S.
Environmental Protection Agency. EPA-HQ-OAR-2002-0056-6045.
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Although EPA disagrees that the IQ results are too uncertain to
rely upon, the EPA acknowledges that IQ is not the most sensitive
neurodevelopmental endpoint affected by MeHg exposure, as also noted by
the SAB. The SAB recommended that the IQ analyses be retained but be
de-emphasized in the documentation underlying the final regulation. The
SAB concluded, ``The Panel does not consider it appropriate to use IQ
loss in the risk assessment and recommended that this aspect of the
analysis be de-emphasized, moving it to an appendix where IQ loss is
discussed along with other possible endpoints not included in the
primary assessment. While the Panel agreed that the concentration-
response function for IQ loss used in the risk assessment is
appropriate, and no better alternatives are available, IQ loss is not a
sensitive response to methylmercury and its use likely underestimates
the impact of reducing methylmercury in water bodies.'' \251\ The EPA
is following the SAB's recommendation by deemphasizing the IQ analysis
and placing that analysis in an appendix to the revised Hg Risk TSD.
---------------------------------------------------------------------------
\251\ U.S. EPA-SAB, 2011.
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The SAB, however, supported the use of the IQ dose-response
function calculated by EPA in the Hg Risk TSD. The SAB noted, ``The
function used came from a paper by Axelrad and Bellinger (2007) that
seeks to define a relationship between methylmercury exposure and IQ. A
whitepaper by Bellinger (Bellinger, 2005) \252\ describes the sequence
of steps in relating methylmercury exposure to maternal hair mercury
and then that to IQ. The Mercury Risk TSD furthers notes that IQ has
shown utility in describing the health effects of other neurotoxicants.
These are appropriate bases for examining a potential impact of
reducing methylmercury on IQ, but the SAB does not consider these
compelling reasons for using IQ as a primary driver of the risk
assessment.'' \253\
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\252\ Bellinger, 2005.
\253\ U.S. EPA-SAB, 2011.
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The EPA disagrees that the Agency has overstated or failed to
review the scientific literature on cardiovascular effects from MeHg
exposure. As summarized in the preamble to the proposal, the EPA stated
that the NAS study concluded that ``Although the data base is not as
extensive for cardiovascular effects as it is for other end points
(i.e., neurologic effects) the cardiovascular system appears to be a
target for MeHg toxicity in humans and animals.'' \254\ The EPA also
stated that additional cardiovascular studies have been published since
2000. The EPA did not develop a quantitative dose response assessment
for cardiovascular effects associated with MeHg exposures, as there is
no consensus among scientists on the dose-response functions for these
effects, and there is inconsistency among available studies as to the
association between MeHg exposure and various cardiovascular system
effects. In the future, the EPA may update the MeHg RfD and will review
all of the relevant scientific literature available at that time,
including data on all relevant endpoints, and weight of evidence for
likelihood that MeHg produces specific effects in humans.
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\254\ 76 FR 25001.
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The EPA acknowledges the research regarding the effectiveness of
fish advisories. However, the proposed regulation does not address the
subject of fish advisories, consumer advice on fish or efficacy of such
advice. The EPA rejects the commenter's speculation regarding whether
the estimated IQ impacts for the regulation are real. Adverse effects
of in utero Hg exposure have been reported in populations in the
U.S.255 256 In another study on neurobehavioral effects of
prenatal exposure to MeHg through maternal consumption of seafood,
adverse effects are observed for MeHg even without controlling for fish
consumption.\257\ That study suggests that at normal Japanese dietary
intake of MeHg and fish nutrients, the overall effect is adverse. While
Japanese fish consumption and Hg exposure are both somewhat higher than
the mean U.S. exposure, these levels are still within the distribution
of U.S. consumers.
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\255\ Oken et al., 2008.
\256\ Lederman et al., 2008.
\257\ Suzuki, K., Nakai, K., Sugawara, T., Nakamura, T., Ohba,
T., Shimada, M., Hosokawa, T., Okamura, K., Sakai, T., Kurokawa, N.,
Murata, K., Satoh, C., and Satoh, H. 2007. ``Neurobehavioral effects
of prenatal exposure to methylmercury and PCBs, and seafood intake:
neonatal behavioral assessment scale results of Tohoku study of
child development.'' Environ Res 110, 699-704.
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[[Page 9354]]
Moreover, many studies show that beneficial effects of fish on both
cardiovascular and neurodevelopmental health are decreased by
concomitant exposure to MeHg. Several studies describe one or more
aspects of exposure to fish nutrients and
MeHg.258 259 260 261 262 263 264 Recent studies
265 266 267 and analyses indicate the potential for
nutrients in fish (particularly marine fish) to mask some of the
observed adverse effects of MeHg. Because EPA did not adjust for
potential confounding by nutrients in marine fish and mammals, the
benchmark doses used in the RfD derivation may be underestimated.
---------------------------------------------------------------------------
\258\ Grandjean P, Bjereve K, Wihe P, and Sterewald u. 2001a.
``UBirthweight in a fishing community: significance of essential
fatty acids and marine food contaminants.'' In. J. Epidemiol.
30:1272-1278.
\259\ Budtz-Jorgensen, E.; Grandjean, P.; Weihe, P. 2007.
``Separation of risks and benefits of 16 seafood intake.''
Environmental Health Perspectives. Vol. 115, 323-327.
\260\ Choi et al., 2008a.
\261\ Choi et al., 2008b.
\262\ Oken et al., 2008.
\263\ Strain, J.J. et al., 2008. Associations of maternal long
chain polyunsaturated fatty acids, methyl mercury, and infant
development in the Seychelles Child Development Nutrition Study.''
Neurotoxicology. 29(5): 776-782.
\264\ Suzuki, et al., 2007.
\265\ Oken et al., 2008.
\266\ Choi AL, Cordier S, Weihe P, Grandjean P. 2008a.
``Negative confounding in the evaluation of toxicity: the case of
methylmercury in fish and seafood.'' Crit Rev Toxicol.
2008;38(10):877-93.
\267\ Choi AL, Budtz-J[oslash]rgensen E, J[oslash]rgensen PJ,
Steuerwald U, Debes F, Weihe P, Grandjean P. 2008b. ``Selenium as a
potential protective factor against mercury developmental
neurotoxicity.'' Environ Res. May;107(1):45-52. Epub 2007 Sep 12.
---------------------------------------------------------------------------
The EPA recognizes the potential for confounding of the effects of
Hg on the developing nervous system by a range of nutrients and
discusses this uncertainty in the revised Hg Risk TSD. Regarding
selenium, the SAB commented that ``one SAB member suggests the use of
blood markers of selenium-dependent enzyme function, noting that
methylmercury irreversibly inhibits selenium-dependent enzymes that are
required to support vital-but-vulnerable metabolic pathways in the
brain and endocrine system. Impaired selenoenzyme activities would be
observed in the blood before they would be observed in brain, but the
effect is also expected to be transitory. The use of these measures is
a minority view among the SAB members.'' \268\ The SAB did not express
a consensus recommendation on adjustments to the risk estimates for
exposure to selenium or other nutrients, noting that ``there is not
enough known about their quantitative impact to support a
recommendation of a re-analysis.'' \269\
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\268\ U.S. EPA-SAB, 2011.
\269\ Id.
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6. General Comments on Hg Risk Assessment
Comment: Several commenters generally supported the Hg risk
assessment, but several other commenters generally disagreed with the
Hg risk assessment. One supporter stated that EPA reasonably determined
that Hg emissions pose a public health hazard, correctly requested peer
review of Hg risk analysis and correctly concluded EGU-attributable
MeHg poses a hazard to public health at watersheds when considering all
sources of Hg deposition and U.S. EGUs alone. Two commenters noted that
the contribution of U.S. EGUs to total Hg deposition can significantly
contribute to hundreds of watersheds, and U.S. EGU deposition alone may
endanger sensitive populations near many of these watersheds.
Several commenters claimed that overly conservative assumptions in
the risk analysis render the results flawed and unreliable, including
using CMAQ to model deposition, Mercury Maps, fish consumption rate and
fish MeHg concentrations, overly stringent RFD, national-scale model,
using poverty as a surrogate for subsistence fishing, assuming a
subsistence fisher resides in most watersheds with fish tissue data,
fishers only eat larger fish with high Hg concentrations, cooking loss
adjustment, unrealistically high fish ingestion rates (a large fish
meal every day), focused on the extremes of the distributions, cast
many assumptions as an underestimate of the effect despite evidence to
the contrary, and created inappropriate metrics for risk that show no
improvement despite significant Hg emissions reductions in the U.S.
Several commenters cite Tetra Tech's analysis that assessed Hg risk
using different consumption rates, cooking factor, mean fish tissue
concentrations, and EGU-attributable Hg deposition only, which showed
considerably fewer watersheds that exceed an HQ of 1 at 2016 deposition
levels.
Several commenters claim that this regulation would not
significantly reduce Hg exposure via fish consumption because EGU-
attributable deposition is a small fraction of total deposition. One
commenter stated that EPA's data shows Hg emissions from U.S. EGUs have
little influence on fish Hg concentrations despite a reduction of 41
tons of Hg in the U.S. between 2005 and 2016. One commenter requested
that EPA accurately describe the low health risks posed by utility
hazardous air pollutant emissions. One commenter stated that EPA did
not consider scientific information showing that there is no
straightforward connection between Hg emissions from U.S. EGUs to the
Hg level in fish, which is dependent upon many environmental factors,
such as sunlight and organic matter, pH, water temperature, sulfate,
bacteria, and zooplankton present in the ecosystem. One commenter
stated that there is not any demonstrable evidence that anyone in the
U.S. has suffered adverse health problems as a result of Hg emissions
from coal-fired EGUs. One commenter stated that EPA's findings are
similar to the 2000 findings where EPA found a plausible link between
anthropogenic emissions of Hg from sources in the U.S. and MeHg in
fish, and ``plausible'' is a euphemism for unproven.
Several commenters had recommendations for the Hg risk analysis.
One commenter stated that more data from Florida should have been
included because Florida is known to have a rich data set on fish Hg
concentrations. One commenter stated that EPA should characterize
general recreational angler fishers instead of subsistence fishers. One
commenter claims that EPA made math errors in the Hg Risk TSD regarding
the deposition in watersheds at specific percentiles. One commenter
questioned EPA's policy metrics used to characterize Hg risk.
Several commenters stated that the Hg TSD is unclear and lacks
detail, as noted by the SAB. One commenter stated that the SAB is
critical of EPA's efforts, stating that the SAB found it difficult to
evaluate the risk assessment based solely upon Hg Risk TSD and
recommended that EPA transparently explain the methods and
uncertainties. One commenter stated that because of insufficient review
time and the lack of detail in the Hg Risk TSD, they could not assess
key questions, such as the nation-wide representativeness of the fish
tissue data.
One commenter stated the subset of watersheds considered in the
analysis (i.e., with fish tissue data) have clearly higher U.S. EGU-
attributable deposition than the distribution of all watersheds.
One commenter stated EPA's reporting of IQ point loss is erroneous
and not relevant to informing policy, and the U.S. EGU contribution to
risk is marginal as evidenced by the null values for the 50th
percentile watershed.
One commenter notes that U.S. EGU-attributable emissions of Hg have
decreased significantly between 2005
[[Page 9355]]
and 2016, but claims that this decrease does not appear to affect the
risk results.
Response: The purpose of the Hg risk assessment is not to assess
the magnitude of risk reduction under the proposed rule, but rather to
estimate the magnitude of absolute risk attributable to U.S. EGUs
currently and following implementation of other applicable CAA
requirements. That said, any potential risk reductions following
implementation of the MACT rule itself would likely reflect a number of
factors besides the national average U.S. EGU deposition value cited by
the commenter. These additional factors include: (a) Spatial gradients
in the magnitude of absolute U.S. EGU-attributable Hg deposition, (b)
spatial gradients in the magnitude of reductions in Hg deposition
linked to the rule, (c) availability of measured fish tissue Hg levels
in the vicinity of U.S. EGUs experiencing larger Hg emission reductions
to support risk modeling, and (d) the potential for subsistence fishing
activity at watersheds in the vicinity of U.S. EGUs experiencing larger
reductions in Hg emissions (also required to support risk modeling). It
is also important to point out that while the national average U.S.
EGU-attributable Hg deposition (for the 2016 scenario--see revised Hg
Risk TSD) is two percent, values range up to 11 percent for the 99th
percentile watershed. This illustrates the substantial spatial
variation in U.S. EGU-attributable Hg deposition, which translates into
spatial variation in the magnitude of U.S. EGU-attributable subsistence
fisher risk.
The SAB conducted a comprehensive peer review of all of EPA's
assumptions in the Hg Risk TSD, and concluded that ``the SAB supports
the overall design of and approach to the risk assessment and finds
that it should provide an objective, reasonable, and credible
determination of the potential for a public health hazard from Hg
emitted from U.S. EGUs.'' \270\ Furthermore, the SAB concluded, ``The
SAB regards the design of the risk assessment as suitable for its
intended purpose, to inform decision-making regarding an ``appropriate
and necessary finding'' for regulation of hazardous air pollutants from
coal and oil-fired EGUs, provided that our recommendations are fully
considered in the revision of the assessment.'' \271\ Although the SAB
did indicate difficulty in evaluating the risk assessment based solely
on the Hg Risk TSD, the panel obtained additional information from EPA
through the peer review process and determined that ``the SAB supports
the overall design of and approach to the risk assessment and finds
that it should provide an objective, reasonable, and credible
determination of the potential for a public health hazard from mercury
emitted from U.S. EGUs.'' \272\ The primary advice of the SAB panel was
that EPA should ``revise the Technical Support Document to better
explain the methods and choices made in the analysis, and analytical
results, and where the uncertainties lie.'' \273\ The EPA has revised
the Hg Risk TSD as part of the final rulemaking to address the SAB's
recommendations and has made that revised Hg Risk TSD available in the
rule docket.
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\270\ U.S. EPA-SAB, 2011.
\271\ Id.
\272\ Id.
\273\ Id.
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The SAB concurred with EPA's analytical assumptions and overall
study design for the Hg Risk TSD, including the RfD-based HQ approach,
fish tissue data, 75th percentile size fish, Mercury Maps assumption,
and consumption rates. Based on the SAB peer review, the EPA strongly
disagrees with commenter statements that the results reported in the Hg
Risk TSD are unreliable, overly conservative, extreme, inconsistent
with EPA risk guidelines, or severely overstate risk based on the
stated objectives of the analysis. The EPA has specifically addressed
each of these assumptions in the previous sections of the preamble, and
thus, does not repeat those responses here. Based on the review by the
SAB, the EPA has accurately described the health risks posed by utility
hazardous air pollutant emissions and disagrees with the commenter's
statement that EPA has not provided any demonstrable evidence to show
that adverse health risks exist. The EPA has applied peer reviewed
modeling to estimate the deposition of Hg attributable to U.S. EGUs.
The EPA asserts that these metrics demonstrate a clear hazard to public
health from Hg emissions from U.S. EGUs.
The EPA thoroughly evaluated the Tetra Tech analysis. The EPA does
not agree that the analysis by Tetra Tech uses assumptions that are
``more reasonable'', and the SAB agreed that all of EPA's assumptions
in the Hg Risk TSD are reasonable and appropriate. The EPA asserts that
Tetra Tech's analysis does not fully cover subsistence fishers likely
to experience elevated U.S. EGU-related Hg exposure. Specifically, the
risk estimate cited in the comment reflects application of a number of
behavioral assumptions that provide significantly less coverage for
higher risk subsistence fishers. Fish consumption surveys cited in the
revised Hg Risk TSD suggest that higher percentile subsistence fishers
eat more than twice the level of fish assumed by Tetra Tech. Tetra
Tech's analysis also used the median fish tissue levels, but it is
reasonable to assume that subsistence fishers would target somewhat
larger fish to maximize the volume of edible meat per unit time spent
fishing. Tetra Tech's analysis also assumed that cooking fish did not
concentrate Hg, but a number of studies discussed in the revised Hg
Risk TSD explicitly provide adjustment factors involving a higher unit
concentration following preparation. Taken together, Tetra Tech's
analysis does not address the stated goal of the risk assessment to
assess the nature and magnitude of risk for those individuals likely to
experience the greatest risk associated with exposure to U.S. EGU-
attributable Hg.
The EPA disagrees with the commenter's assertion that this rule
will not affect risks associated with Hg exposure. Hg from U.S. EGUs
contributes to the levels of MeHg in fish across the country and
consumption of contaminated fish can lead to increased risk of adverse
health effects. The EPA has shown in the RIA (Chapter 5) that this rule
will reduce Hg levels in fish.
The EPA acknowledges that U.S. EGUs contribute only a small
fraction of total Hg deposition in the U.S. However, U.S. EGUs remain
the largest emitter of Hg in the U.S., and the revised Hg Risk TSD
shows that U.S. EGU-attributable Hg deposition results in up to 29
percent of modeled watersheds with populations potentially at-risk. Our
analyses show that of the 29 percent of watersheds with population at-
risk, in 10 percent of those watersheds U.S. EGU deposition alone leads
to potential exposures that exceed the MeHg RfD, and in 24 percent of
those watersheds, total potential exposures to MeHg exceed the RfD and
U.S. EGUs contribute at least 5 percent to Hg deposition. Mercury risk
is increasing for exposures above the RfD, and as a result, any
reductions in Hg exposures in locations where total exposures exceed
the RfD can result in reduced risks. While these reductions in risk may
be small for most populations and locations, in some watersheds and for
some populations, reductions in risk may be greater.
The SAB also directly addressed the question of the nation-wide
representativeness of the fish tissue MeHg data in the national Hg risk
assessment. The SAB concluded, ``Although the SAB considers the number
of watersheds included in the assessment adequate, some watersheds
[[Page 9356]]
in areas with relatively high mercury deposition from U.S. EGUs were
under-sampled due to lack of fish tissue methy[l]mercury data. The SAB
encourages the Agency to contact states with these watersheds to
determine if additional fish tissue methylmercury data are available to
improve coverage of the assessment.'' \274\ In response to the SAB's
recommendations, the EPA obtained additional fish tissue sample data
from several states, particularly Pennsylvania, Wisconsin, Minnesota,
New Jersey, and Michigan. This additional data increased the total
number of watersheds assessed in the analysis by 33 percent nationally.
In Florida, the EPA assessed the Hg-related health risk for 40
watersheds. Because EPA did not find any additional fish tissue data
for watersheds in Florida that could be incorporated into the analysis,
the total number of watersheds in Florida assessed in the revised Hg
Risk TSD remains the same as the Hg Risk TSD at proposal.
---------------------------------------------------------------------------
\274\ U.S. EPA-SAB, 2011.
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The EPA disagrees with the commenter that there were errors in the
Hg Risk TSD. Instead, the commenter has misinterpreted how EPA
calculated the percentiles. The percentile (and mean) values presented
in Table ES-1 for total and U.S. EGU-attributable Hg deposition are not
matched by watershed. In other words, the EPA queried for the
percentiles (and mean) provided for total Hg deposition and presented
those percentiles and then separately estimated the percentiles for
U.S. EGU-attributable Hg. Therefore, the total and U.S. EGU-
attributable values for the 99th percentile do not necessarily occur at
the same watershed. The EPA has provided additional clarification in
the revised Hg Risk TSD.
The EPA agrees with the commenter that MeHg levels in fish depend
on a complicated set of environmental factors, and EPA acknowledged
this in the revised Hg Risk TSD. Furthermore, the EPA acknowledges that
total Hg fish tissue levels are not correlated with levels of total Hg
deposition when looking across watersheds because this relationship is
highly dependent on the methylation potential at the specific
waterbody, which is affected by pH, sulfate deposition, turbidity, etc.
However, several recent studies 275 276 277 show, and the
SAB agrees, that it is appropriate for EPA to assume that changes in Hg
deposition are linearly associated with changes in fish tissue
concentration. In addition, the EPA agrees that the subset of
watersheds in the risk analysis have somewhat higher U.S. EGU
deposition than the distribution of all watersheds, but EPA disagrees
that oversampling of high deposition watersheds is inappropriate.
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\275\ Orihel et al., 2007.
\276\ Orihel et al., 2008.
\277\ Harris et al., 2007.
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The EPA does not agree that there is no improvement in fish Hg
concentrations between 2005 and 2016, or that there will be no further
improvement from decreasing Hg emissions from U.S. EGUs from the
baseline in 2016. Although total risk from all Hg exposures will remain
elevated in much of the U.S., much of that risk is associated with
global, non-U.S. Hg emissions. U.S. EGUs remain the largest source of
Hg emissions in the U.S., and reductions in those emissions will result
in reduced Hg deposition in many highly impacted watersheds. As shown
in the revised Hg Risk TSD, average U.S. EGU-attributable fish tissue
Hg concentrations is estimated to decrease by 44 percent between 2005
and 2016. Although we did not remodel risk for the 2005 scenario in the
revised Hg Risk TSD, we estimated at proposal that the total percent of
modeled watersheds with populations potentially at-risk from Hg
emissions from U.S. EGUs exceeding either risk metric (i.e., U.S. EGUs
alone or total potential exposures to MeHg exceed the RfD and U.S. EGUs
contribute at least 5 percent) would decline from 62 percent in 2005 to
28 percent in 2016. This projected decline is primarily due to a
combination of additional pollution control technologies installed to
comply with federal regulations, such as CSAPR, and changing fuels,
such as the shift to natural gas.
The EPA disagrees that IQ loss is erroneous or irrelevant to
informing policy, but EPA has moved that analysis to an appendix in the
revised Hg Risk TSD, per the SAB's recommendation. The EPA disagrees
that the IQ effects at the 50th percentile watershed are useful in
determining that there is not a hazard to public health because EPA's
stated goal of the risk assessment was to focus on populations likely
to experience relatively higher exposures to U.S. EGU-attributable Hg.
We also disagree with those commenters that point to the SAB's
statements concerning the clarity of the Hg Risk TSD to suggest that
the public did not have an ample opportunity to comment on the Hg risk
assessment. Although it is correct that the SAB said the Hg Risk TSD
was difficult to evaluate until EPA staff explained it at the public
meeting in June 2011, we note that the commenters that assert that this
issue amounts to a violation of CAA section 307(d) notice requirements
made detailed technical comments, including many of the same comments
as the SAB. Furthermore, the EPA provided notice of the peer review in
the preamble to the proposed rule and a number of Federal Register
notices advised the public of the peer review process and all the
meetings were open to the public for comment and participation and the
minutes of those meetings were posted on the SAB Web site. The minutes
for the June 2011 meeting, during which EPA provided clarifying
information, were available well within the public comment period for
the proposed rule. For these reasons, we maintain that the public was
provided an adequate opportunity to comment on the Hg risk assessment.
e. Non-Hg HAP Case Studies
1. Emissions for Non-Hg Case Studies
Comment: The commenters raised concerns about a wide variety of
aspects of EPA's approach for emissions used for the non-Hg case
studies, including the use of an arithmetic mean for computing emission
factors for representing emissions of untested units, the suggestion of
statistical outliers in the Cr test data, the claim that metals content
of the fuel is an indicator of flawed test data, the statistical
approaches used by EPA to create emission factors, the absence in EPA's
approach of an equation that commenters claim better represents
emissions values, that EPA's approach to estimate Cr(VI) is flawed, and
the lack of coal rank as a delineating factor for emission factor
calculation. The commenters also suggested that EPA should revise stack
parameters used for the case studies based on better available data.
Response: In response to the comments on the emission factors, the
EPA has undertaken additional analysis to address all commenter
concerns. The EPA disagrees with commenter's criticisms of emission
factors based on arithmetic means, and EPA demonstrates that the use of
an arithmetic mean provides the most representative result. The EPA
analysis has found that the geometric mean approach recommended by the
commenter always under predicts actual emissions by an average of more
than seventy percent. The EPA agrees with commenters' recommendations
to use statistical outlier tests, but has applied tests different from
those suggested by the commenters. As further explained in the response
to comments document in the docket, this approach did not eliminate the
Cr test data from the Cr
[[Page 9357]]
emission factors used for some of the case study emissions.
The EPA disagrees with commenters' assertions that the metal
content of the coal is a basis for invalidating the test results of
high Cr emissions. The identification of sources whose measured
emissions do not match the commenters' preconceived idea of emissions
behavior is not surprising. There are many possible explanations for
these differences. For example, the inconsistency between the test data
and the coal analysis could be due to any number of reasons including
unrepresentative coal sampling, control device problems, degradation of
the refractory, or sampling contamination. The idea that test data
should be discarded because it does not match initial expectations is
unfounded.
The EPA disagrees with the commenter recommendations for using an
equation from AP-42, developed in part by the commenters. Based on
analyses of metal emissions measured at the site compared to
statistically predicted estimates, the EPA concluded that measured
emissions test data better predict actual emissions, and emission
factors based on the arithmetic mean are a reasonable method to
estimate emissions when test data are not available. The EPA analysis
of the ICR data has found that the emissions equation recommended by
the commenter is not a good predictor of actual EGU emissions. The EPA
also disagrees with commenters' concerns about the assumption that 12
percent of the Cr will be Cr(VI) for every coal-fired unit, which was
specifically supported by the peer review on the approach for
estimating cancer risks associated with Cr and Ni emissions. The EPA
disagrees with the commenter's assertion that any impact of scrubbers
will impact the case study analyses. In EPA's revised case study
analysis, 6 facilities have risk greater than 1 in a million, and of
these, four facilities have Cr as the risk driver (James River,
Conesville, TVA Gallatin, and Dominion--Chesapeake Bay). For these
facilities, none of the units contributing the bulk of the Cr emissions
have scrubbers according to the data provided to EPA by those
facilities, so scrubber impacts on Cr speciation is not relevant to
EPA's conclusions based on the non-Hg case studies. In any case, the
EPA disagrees with the commenter's conclusions about the impacts of
scrubbers on Cr speciation and provides evidence that impacts of
scrubbers on Cr speciation can have the opposite effect on Cr(VI)
fractions, concluding that EPA's 12 percent assumption is somewhat
conservative.
The EPA also disagrees that coal rank must be a factor in computing
Cr emission factors for use in the case studies. The EPA's analysis has
demonstrated that coal rank appears to play no role in non-Hg metals
emissions. The EPA's newly revised emissions factor development
procedures can isolate and compare subgroups based on control device
type or coal rank; the ICR data were subjected to these tests and no
statistical significance was found between coal rank groups.
Finally, the EPA agrees with one commenter's recommendations on
revised stack parameters for the case studies and has included these
revisions in the case study modeling for the final rule.
2. General Comments on Non-Hg Risk Case Study
Comment: One commenter stated that EPA's case study assessment
reaffirms the need to regulate HAP emitted by both coal and oil-fired
EGUs. The commenter noted that over 40 percent of the case studies
conducted by EPA to quantify health hazards associated with the
inhalation of non-Hg HAP indicated a cancer risk greater than or equal
to the one in a million threshold level required to delist a source
category under CAA section 112.
One commenter stated that EPA's case study assessment might be
flawed by the use of ``beta'' tests versions of the AERMOD
meteorological preprocessors (AERMINUTE and AERMET). The commenter
obtained from EPA the meteorological data used for EPA's assessment of
the Conesville facility and processed these data with EPA's current
regulatory versions of these preprocessors, which differ from the beta
version. According to the commenter, a comparison of the hourly wind
speed and hourly wind direction data produced by the beta preprocessor
and by current EPA preprocessors revealed numerous and often
substantial disparities.
One commenter stated that EPA's finding that only three coal-fired
facilities and one oil-fired facility out of roughly 440 coal-fired
facilities and 97 oil-fired facilities in the U.S. indicated risk
greater than one-in-a-million supports a finding that it is
``appropriate'' to regulate those four and not the other 537. Another
commenter stated that EPA found only a ``few'' facilities that have
estimated maximum cancer risks in excess of one in a million, and that
this does not justify regulating all non-Hg HAP for all sources in this
category.
One commenter stated that EPA's discussion in the preamble to the
proposed rule misleads the reader into believing that non-Hg HAP
emissions from EGUs are associated with serious human health effects.
According to the commenter, the EPA's discussion of the effects
associated with excessive exposure to an individual HAP would lead the
reader to believe that those effects inevitably occur from EGU
emissions because EGU emissions have trace amounts of non-Hg HAP.
One commenter stated that with the assumptions in the Utility
Study, both in terms of conservative scientific estimates and
overestimated amounts of oil burned by these units, the EPA concluded
that the risks from oil-fired units would result in only one new cancer
case every 5 years. The commenter does not believe that this level of
risk warrants regulation under CAA section 112(n)(1)(A).
Several commenters stated that even if the additional studies EPA
performed were accurate, they hardly demonstrate that it is necessary
and appropriate to regulate coal-fired EGU HAP under CAA section 112
because three sites nationwide show risks greater than one in a
million, with the highest at eight in a million.
One commenter stated that the highest cancer risk estimated for
coal-fired EGUs is still within the acceptable range used by EPA in
other programs and is also far less than the background exposure risks
the average person experiences. The background risk of developing
cancer in a lifetime is approximately one in three (0.33). According to
EPA's own data, the predicted added cancer risk of exposure to HAP from
U.S. EGUs would change the background risk from 0.33 to 0.330001. This
level of change is so minimal that it could not be observed in any
health effects study that might be conducted.
One commenter stated that EPA conducted a health risk assessment on
a limited number of facilities and found a ``few'' facilities that have
estimated maximum cancer risks in excess of one in a million. The
commenter stated that, based on this limited health risk assessment,
the EPA apparently decided that they were justified to regulate all
non-Hg HAP for all sources in this category.
Several commenters stated that EPA's assumption implies that a
person stays exactly at the center of a census tract for 70 years and
that a unit will operate in exactly the same manner for 70 years is
unrealistic. The commenters suggest that Tier 3 risk assessment is
warranted
[[Page 9358]]
or a lifetime exposure adjustment is needed.
One commenter asserts that because the alleged health benefits are
derived from total exposure, the EPA should explain how its numerical
emission limit units, which would not directly restrict total exposure
if heat inputs increase, redress this health concern. In its preamble,
the EPA simply notes that its emission limit units are consistent with,
and allow for simple comparison to, other regulations.
One commenter questioned whether acid gas emissions limits for oil-
fired units are ``appropriate'' or ``necessary'' because EPA's new
technical analyses do not indicate a health concern from acid gas
emissions from oil-fired units. According to the commenter, the EPA
identifies Ni as the main HAP of concern from oil-fired units, even
though cancer-related inhalation risks were well below the RfCs and EPA
states that significant uncertainty remains as to whether those
emissions present a health concern.
Response: The EPA agrees with the commenter that the non-Hg HAP
risk assessment confirms the appropriate and necessary finding.
The EPA disagrees that EPA's case study assessment is flawed by the
use of beta versions of AERMINUTE and AERMET. The EPA remodeled the
case study facilities using the current versions of AERMINUTE (version
11059), AERMET (version 11059), and AERMOD (version 11103). Although
there were differences in the number of calm and missing winds in the
current AERMINUTE/AERMET output compared to the beta version, the
resulting risks differed by less than two percent, on average. For
Conesville, which had the largest difference in calms between the beta
and current versions of AERMINUTE/AERMET, the risks differed by three
percent. For the final rule, the case study facilities have been
modeled with the current available versions of AERMINUTE, AERMET, and
AERMOD.
The EPA disagrees with the commenter that having only a few case
study facilities exceeding one in a million risk invalidates the
``appropriate finding''. The 16 facilities EPA selected as case studies
for assessment may not represent the highest-emitting or highest-risk
sources. Although case study facility selection criteria included high
estimated cancer and non-cancer risks using the 2005 NEI data, high
throughput, and minimal emission control, another necessary criterion
was the availability of Information Collection Request (ICR) data for
the EGUs at those facilities (or for similar EGUs at other facilities).
Because the ICR data were collected for the purpose of developing the
MACT standards, the ICR was targeted towards better performing sources
for non-Hg metal HAP, acid gas HAP, and organic HAP, with a smaller set
of random recipients. Therefore, facilities for which ICR data were
available may not represent the highest-emitting sources. The EPA's
assessment of the case study facilities for the proposed rule concluded
that three coal-fired facilities and one oil-fired facility had
estimated lifetime cancer risks greater than one in a million. For the
final rule, revisions were made to the 16 case studies based on
comments received, and the results indicate that 5 coal-fired
facilities and 1 oil-fired facility had estimated lifetime cancer risks
greater than 1 in a million. The EPA maintains that its finding that
more than 30 percent of the case study facilities had a cancer risk
greater than one in a million is sufficient to support the appropriate
finding.
The EPA disagrees with the commenter's assertion that the health
effects associated with exposures to non-Hg HAP from U.S. EGUs are
mischaracterized in the preamble to the proposed rule. The discussion
of the health effects of non-Hg HAP provided in the preamble includes
general information on the potential health effects associated with a
broad range of exposure concentrations (from low to high levels) of the
various non-Hg HAP (some of which have been determined to be
carcinogenic to humans) based on peer reviewed scientific information
extracted from priority sources such as IRIS, Cal EPA and ATSDR health
effects assessments.
The EPA disagrees with the commenter's characterization of the
Utility Study. The Utility Study represented the highest-quality
factual record of information available at the time regarding EGU
emissions and risks. Further, the EPA's revised risk assessments of 16
case studies, performed with more recent data and refined scientific
methods, indicate that there are six U.S. EGU facilities that pose
estimated inhalation cancer risks greater than 1 in a million. The EPA
maintains that the findings of the case studies are one element that
independently supports our determination that it remains appropriate
and necessary to regulate EGUs under CAA section 112.
The EPA does not agree with the commenter who suggested that EPA
should interpret the results of the non-Hg HAP risk analysis in the
context of background cancer risk. As explained in the preamble to the
proposed rule, the EPA reasonably looked to the cancer risk threshold
established under CAA section 112(c)(9)(B)(1) for delisting a source
category as an indicator of the level of cancer risk that was
appropriate to regulate under CAA section 112. The commenters
comparison of the cancer risk from EGUs as compared with the risk of
contracting cancer from unknown sources is not the standard Congress
established for evaluating HAP emission risk and the commenter has
provided no support for its contention that the Agency should evaluate
risk in that manner. The EPA maintains that the analysis was
reasonable.
The EPA does not agree with the commenter's implication that EPA
must make a facility-specific finding for each HAP for each source and
then only regulate individual EGU facilities for the individual HAP
that identified as causing an identified hazard to public health or the
environment. That approach is not required under CAA section 112(n)(1)
or anywhere under CAA section 112, and it would be virtually impossible
to undertake such an effort. For these reasons, the EPA does not agree
with the commenter and maintains that the appropriate and necessary
finding is reasonably supported by the record and consistent with the
statute for all the reasons set forth in the preamble to the proposed
rule and this final action.
The EPA disagrees that an exposure adjustment is needed to account
for conditions changing over 70 years because it runs counter to the
long-standing approach that EPA has taken to estimate the maximum
individual risk, or MIR. The MIR is defined by EPA's Benzene NESHAP
regulation of 1989 \278\ and codified by CAA section 112(f) as the
lifetime risk for a person located at the site of maximum exposure 24
hours a day, 365 days a year for 70 years (e.g., census block
centroids). The MIR is the metric associated with the determination of
whether or not a source category may be delisted from regulatory
consideration under CAA section 112(c)(9). The MIR is the risk metric
used to characterize the inhalation cancer risks associated with the
case study facilities. The EPA used the annual average ambient air
concentration of each HAP at each census block centroid as a surrogate
for the lifetime inhalation exposure concentration of all the people
who reside in the census block. The EPA has used this approach to
estimate MIR values in all of its risk assessments to
[[Page 9359]]
support risk-based rulemakings under CAA section 112 to date.
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\278\ 54 FR 38044.
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The EPA disagrees with the commenter's assertion that the numerical
emission limits being promulgated in today's final rule must be
justified on their ability to redress the health concerns that were
identified as the basis for regulating EGUs. The emission limits in
today's rule are technology-based, as prescribed under CAA section 112,
and do not need to be justified based on their ability to protect
public health. Regarding potential health concerns, the EPA has up to 8
years after the promulgation of the technology-based emission limits
for EGUs to determine whether the regulations protect public health
with an ample margin of safety. If the regulations do not, the CAA
directs EPA to promulgate additional more stringent standards (within
the prescribed 8 years) to achieve the appropriate level of public
health protection.
Furthermore, the EPA reasonably concluded that it was appropriate
and necessary to regulate oil-fired EGUs in 2000, and EPA confirmed
that conclusion was proper with the analysis set forth in the preamble
to the proposed rule. Certain commenters question the determination
based on their views of how the Agency can and should exercise its
discretion. The EPA disagrees with these commenters and stands by the
determination for the reasons set forth in the preamble to the proposed
rule. The EPA also stands by the determination that the maximum cancer
risks posed by emissions of oil-fired EGUs are greater than one in a
million, due primarily to emissions of Ni compounds. Based on our
analysis, we are unable to delist oil-fired EGUs.
3. Ni Risk
Comment: Several commenters stated that the assumptions regarding
the speciation and carcinogenic potential of Ni compounds used in EPA's
inhalation risk assessment of the case study facilities are overly
conservative and likely to overstate the risks. With respect to Ni
speciation, the commenters stated that there are substantial
uncertainties regarding the species of Ni being emitted and the risk of
such emissions, and that EPA has made ultraconservative assumptions
aimed at overestimating the risk. The commenters stated that assigning
the same carcinogenic potency of Ni subsulfide to other forms of Ni is
overly conservative and inconsistent with the best available evidence.
Response: The EPA disagrees with the commenters' assertion that it
is impossible to give an accurate assessment of the risks to human
health from Ni emissions from EGUs, and maintains that its assessment
of the potential inhalation risks from EGU emissions of Ni compounds is
scientifically valid, reasonable, and based on the best-available
current scientific understanding. To that end, in July 2011, the EPA
completed an external peer review (using three independent expert
reviewers) of the methods used to evaluate the risks from Ni and Cr
compounds emitted by EGUs.\279\ There were two charge questions
relating to Ni in that review. First, do EPA's judgments related to
speciated Ni emissions adequately take into account available
speciation data, including recent industry spectrometry studies?
Second, based on the speciation information available and what is known
about the health effects of Ni compounds, and taking into account the
existing URE values (i.e., values derived by the Integrated Risk
Information System,\280\ California Department of Health Services,\281\
and the Texas Commission on Environmental Quality \282\), which of the
following approaches to derive unit risk estimates would result in a
more accurate and defensible characterization of risks from exposure to
Ni compounds?
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\279\ U.S. EPA, 2011c.
\280\ U.S. EPA, 1991.
\281\ California Department of Health Services (CDHS) 1991.
Health Risk Assessment for Nickel. Air Toxicology and Epidemiology
Section, Berkeley, CA. Available online at https://oehha.ca.gov/air/toxic_contaminants/html/Nickel.htm.
\282\ Texas Commission on Environmental Quality (TCEQ), 2011.
Development Support Document for nickel and inorganic nickel
compounds. Available online at https://www.tceq.state.tx.us/assets/public/implementation/tox/dsd/final/june11/nickel_&_compounds.pdf.
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1. To continue using the same approach as that developed for use in
the 2000 NATA, which consists of using the IRIS URE for nickel
subsulfide and assuming that nickel subsulfide constitutes 65 percent
of the mass emissions of all Ni compounds.
2. To consider a more health-protective approach, based on the
consistent views of the most authoritative scientific bodies (i.e., NTP
in their 12th ROC, IARC, and other international agencies) that
consider Ni compounds to be carcinogenic as a group.
3. To make the same assumptions as in option 2, but considering
alternative UREs derived by the CDHS or TCEQ.
In responding to these peer review questions, two of the reviewers
agreed with the views of the most authoritative scientific bodies,
which consider Ni compounds carcinogenic as a group. These reviewers,
therefore, did not focus on the availability of Ni speciation profile
data. The third reviewer recommended that EPA review several
manuscripts on Ni speciation profiles showing that sulfidic Ni
compounds (which the reviewer considered as the most potent
carcinogens) are present at low levels in emissions from EGUs.
Nickel and Ni compounds have been classified as human carcinogens
by national and international scientific bodies including the
IARC,\283\ the World Health Organization,\284\ and the European Union's
Scientific Committee on Health and Environmental Risks.\285\ In their
12th Report of the Carcinogens, the NTP has classified Ni compounds as
known to be human carcinogens based on sufficient evidence of
carcinogenicity from studies in humans showing associations between
exposure to Ni compounds and cancer, and supporting animal and
mechanistic data. More specifically, this classification is based on
consistent findings of increased risk of cancer in exposed workers, and
supporting evidence from experimental animals that shows that exposure
to an assortment of Ni compounds by multiple routes causes malignant
tumors at various organ sites and in multiple species. The 12th Report
of the Carcinogens states that the ``combined results of
epidemiological studies, mechanistic studies, and carcinogenesis
studies in rodents support the concept that Ni compounds generate Ni
ions in target cells at sites critical for carcinogenesis, thus
allowing consideration and evaluation of these compounds as a single
group''.\286\ Although the precise Ni compound (or compounds)
responsible for the carcinogenic effects in humans is not always clear,
studies indicate that Ni sulfate and the combinations of Ni sulfides
and oxides encountered in the Ni refining industries cause cancer in
humans. There have been different views on whether or not Ni compounds,
as a group, should be considered as carcinogenic to humans. Some
authors
[[Page 9360]]
believe that water soluble Ni, such as Ni sulfate, should not be
considered a human carcinogen, based primarily on a negative Ni sulfate
2-year NTP rodent bioassay (which is different than the positive 2-year
NTP bioassay for Ni subsulfide).287 288 289 Although these
authors agree that the epidemiological data clearly supports an
association between Ni and increased cancer risk, they sustain that the
data are weakest regarding water soluble Ni. A recent review \290\
highlights the robustness and consistency of the epidemiological
evidence across several decades showing associations between exposure
to Ni and Ni compounds (including Ni sulfate) and cancer.
---------------------------------------------------------------------------
\283\ International Agency for Research on Cancer (IARC), 1990.
IARC monographs on the evaluation of carcinogenic risks to humans.
Chromium, nickel and welding. Vol. 49. Lyons, France: International
Agency for Research on Cancer, World Health Organization Vol.
49:256.
\284\ International Labour Organization/United Nations
Environment Programme, World Health Organization (WHO), 1991.
Nickel. In Environmental Health Criteria No 108 Geneva.
\285\ European Commission, Scientific Committee on Health and
Environmental Risks (SCHER), 2006. Opinion on: Reports on Nickel,
Human Health part. SCHER, 11th plenary meeting of 04 May 2006 https://ec.europa.eu/health/ph_risk/committees/04_scher/docs/scher_o_034.pdf.
\286\ NTP, 2011.
\287\ Oller A. Respiratory carcinogenicity assessment of soluble
nickel compounds. Environ Health Perspect. 2002, 110:841-844.
\288\ Heller JG, Thornhill PG, Conard BR. New views on the
hypothesis of respiratory cancer risk from soluble nickel exposure;
and reconsideration of this risk's historical sources in nickel
refineries. J Occup Med Toxicol. 2009, 4:23.
\289\ Goodman JE, Prueitt RL, Thakali S, and Oller AR. The
nickel iron bioavailability model of the carcinogenic potential of
nickel-containing substances in the lung. Crit Rev Toxicol. 2011,
41:142-174.
\290\ Grimsrud TK and Andersen A. Evidence of carcinogenicity in
humans of water-soluble nickel salts. J Occup Med Toxicol. 2010.
5:1-7. Available online at https://www.ossup-med.com/content/5/1/7.
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Based on the views of the major scientific bodies mentioned above,
and those of expert peer reviewers that commented on EPA's approaches
to risk characterization of Ni compounds, the EPA considers all Ni
compounds to be carcinogenic as a group and does not consider Ni
speciation or Ni solubility to be strong determinants of Ni
carcinogenicity. With regards to non-cancer effects, comparative
quantitative analysis across Ni compounds indicates that Ni sulfate is
as toxic or more toxic than Ni subsulfide or Ni
oxide.291 292
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\291\ Haber LT, Allen BC, Kimmel CA. Non-Cancer Risk Assessment
for Nickel Compounds: Issues Associated with Dose-Response Modeling
of Inhalation and Oral Exposures. Toxicol Sci. 1998. 43:213-229.
\292\ NTP, 1996.
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Regarding the second charge question, two of the reviewers
suggested using the URE derived by TCEQ for all Ni compounds as a
group, rather than the one derived by IRIS specifically for Ni
subsulfide. The third reviewer did not comment on alternative
approaches. The EPA decided to continue using 100 percent of the
current IRIS URE for Ni subsulfide because IRIS values are at the top
of the hierarchy with respect to the dose response information used in
EPA's risk characterizations, and because of the concerns about the
potential carcinogenicity of all forms of Ni raised by the major
national and international scientific bodies. Nevertheless, taking into
account that there are potential differences in toxicity and/or
carcinogenic potential across the different Ni compounds, and given
that there have been two URE values derived for exposure to mixtures of
Ni compounds that are 2-3 fold lower than the IRIS URE for Ni
subsulfide, the EPA also considers it reasonable to use a value that is
50 percent of the IRIS URE for Ni subsulfide for providing an estimate
of the lower end of a plausible range of cancer potency values for
different mixtures of Ni compounds.
4. Cr Risk
Comment: One commenter stated there are several problems with EPA's
analysis related to the fact that Cr emissions were evaluated as being
entirely Cr(VI). The commenter stated that not all of the emitted Cr
will remain in the hexavalent form by the time it reaches the target
population, and that some may be converted to the much less toxic (and
noncarcinogenic) trivalent species. The commenter also stated that the
concentration levels considered in the case study assessment are far
below occupational levels. The commenter concluded that EPA's cancer
estimates should, therefore, be looked on with some skepticism. Another
commenter stated that EPA's estimate of 12 percent Cr(VI) from coal-
fired EGUs is unsupported, and that EPA failed to recognize that Cr(VI)
is highly water-soluble and is easily reduced to Cr(III) in the
presence of SO2 in a low pH environment. The resulting
Cr(III) would be expected to precipitate out in a FGD. The commenter
stated that the actual amount of Cr(VI) that would be present in the
emissions from an EGU with a wet scrubber is likely to be far lower
than the 12 percent estimate made by EPA.
Several commenters questioned the validity of the chronic
inhalation study by EPA because of (1) the use of surrogate speciated
Cr emissions data instead of actual emissions data, (2) the assumption
that units were run 100 percent of the time which is impossible, (3)
dispersion modeling was used that is biased towards over predicting
downwind impacts, and (4) estimated ambient concentrations were
utilized as substitutes for real exposure concentrations for all people
within a census block.
Response: The EPA disagrees with the commenters' assertion that all
Cr was considered to be hexavalent. As discussed in ``Methods to
Develop Inhalation Cancer Risk Estimates for Chromium and Nickel
Compounds,'' \293\ existing test data for utility and industrial
boilers indicate that Cr(VI) is, on average, 12 percent of total Cr
from coal-fired boilers. This document underwent peer review by three
external reviewers, and all three reviewers considered EPA's use of the
values to be reasonable given the limited data available for Cr
speciation profiling. The EPRI inhalation study for coal-fired boilers
also used the 12 percent value.
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\293\ U.S. EPA, 2011c.
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The EPA also disagrees that units were assumed to operate 100
percent of the time. The dispersion modeling performed for the case
study facilities used hourly heat input as a temporalization factor for
estimating hourly emissions, and in some cases hourly heat inputs (and
emissions) were zero or very low. The commenter provided no data or
information to support their claim that the dispersion modeling EPA
used is biased towards overestimating downwind impacts.
The EPA disagrees with the commenters' assertion that ``real
exposure concentrations for all people within a census block'' must be
considered because it runs counter to the long-standing approach that
EPA has taken to estimate the maximum individual risk, or MIR. The MIR
is defined by EPA's Benzene NESHAP regulation of 1989 \294\ and
codified by CAA section 112(f) as the lifetime risk for a person
located at the site of maximum exposure 24 hours a day, 365 days a year
for 70 years (e.g., census block centroids). The MIR is the metric
associated with the determination of whether or not a source category
may be delisted from regulatory consideration under CAA section
112(c)(9). The MIR is the risk metric used to characterize the
inhalation cancer risks associated with the case study facilities. The
EPA used the annual average ambient air concentration of each HAP at
each census block centroid as a surrogate for the lifetime inhalation
exposure concentration of all the people who reside in the census
block. The EPA has used this approach to estimate MIR values in all of
its risk assessments to support risk-based rulemakings under CAA
section 112 to date.
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\294\ 54 FR 3804.
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5. Acid Gas Risk
Comment: One commenter stated that acid gas emissions from oil-
fired EGUs are not of the magnitude that triggered EPA's decision to
regulate EGUs in general, raising the question of whether reduction (or
even total elimination) of acid gas emissions from oil-fired EGUs could
have any significant effect on EPA's goals of reducing non-cancer
[[Page 9361]]
health risk or acidification of sensitive ecosystems in the U.S.
Several commenters stated that acid gas concentrations estimated in
the case study facility assessment and the Utility Study do not exceed
human health thresholds of concern. Two commenters stated that HCl
emissions are negligible compared to other primary emissions (such as
SO2) that can lead to potential acidification of ecosystems.
Response: We do not agree with commenter's implication that
Congress intended EPA to regulate only those HAP emissions from U.S.
EGUs for which an appropriate and necessary finding is made, and
commenter has cited no provision of the statute that states a contrary
position. The EPA concluded that we must find it ``appropriate'' to
regulate EGUs under CAA section 112 if we determine that a single HAP
emitted from EGUs poses a hazard to public health or the environment.
If we also find that regulation is necessary, the Agency is authorized
to list EGUs pursuant to CAA section 112(c) because listing is the
logical first step in regulating source categories that satisfy the
statutory criteria for listing under the statutory framework of CAA
section 112. See New Jersey, 517 F.3d at 582 (stating that ``[s]ection
112(n)(1) governs how the Administrator decides whether to list EGUs *
* *''). As we noted in the preamble to the proposed rule, D.C. Circuit
precedent requires the Agency to regulate all HAP from major sources of
HAP emissions once a source category is added to the list of categories
under CAA section 112(c). National Lime Ass'n v. EPA, 233 F.3d 625, 633
(D.C. Cir. 2000). 76 FR 24989. The EPA discusses in the preamble to the
proposed rule and this final action its concerns with HCl and other
acid gas HAP emissions from EGUs and the Agency's approach for
establishing section 112(d) standards for acid gas HAP.
6. EPRI Risk Analysis
Comment: Two commenters stated that a comprehensive tiered
inhalation risk assessment (the EPRI study) using EPA-prescribed
methods with improved emission factors, fuel data, and confirmed stack
parameters did not identify significant health risks (cancer or non-
cancer) among U.S. coal-fired power plants (as they existed in 2007).
The commenters noted that these results contrast with those presented
by EPA for its non-Hg case studies on 16 (15 coal-fired) power plants.
The commenters stated that several issues appear to underlie these
differences, indicating the need for EPA to reevaluate its assessment
and to undertake more refined (Tier 3) risk assessment for any facility
of concern. Several commenters stated that for non-Hg HAP EPA produced
one study on chronic inhalation risk assessment that identified three
sites with cancer risks greater that one in a million for Cr(VI), which
was authored by EPA staff and not peer reviewed. One commenter stated
that EPA study is based on misinformation and overestimates
assumptions, and that EPA has no data demonstrating health impacts from
EGU emissions of non-Hg HAP, or the benefit from reducing such
emissions. Two commenters stated that no benefits will be derived from
the non-Hg HAP emission reductions associated with the proposed rule
because no non-Hg HAP health risks were proven, and that no showing was
made that EGU non-Hg HAP emission levels reach levels associated with
adverse health effects. Another commenter stated that EPA must complete
a comparable and separate national-scale risk assessment for non-Hg
metals in order to determine appropriateness of proposing emissions
standards for non-Hg metals.
Response: The commenters are incorrect in the assertion that EPA's
case studies were performed with less rigor than the EPRI analysis. The
EPRI analysis used a tiered approach to risk assessment, beginning with
Tier 1 using EPA's SCREEN3 dispersion model on all 470 coal-fired power
plants in the U.S., and following with Tier 2 with EPA's Human Exposure
Model (which uses the AERMOD dispersion model) for plants with higher
risks from the Tier 1 modeling. Although tiered risk assessment is an
appropriate approach, the Tier 2 modeling could have been more refined.
For example, more meteorological data could have been used and building
downwash could have been considered. The EPRI analysis ostensibly
concluded that the Tier 2 modeling with HEM was conservative, and that
because the modeled risks did not exceed certain thresholds, no further
refinement was necessary. However, such refinements could result in
higher modeled risks than those from the commenter's Tier 2 modeling.
The EPA's dispersion modeling of the case study facilities was
actually performed with a greater degree of refinement than the EPRI
analysis, and was consistent with EPA's Guideline on Air Quality
Models.\295\
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\295\ Appendix W to 40 CFR Part 51.
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In contrast to the approach used in the EPRI analysis, the EPA
used:
(1) 5 years of recent meteorological data from the weather
station nearest to each facility, rather than one year of
meteorological data. This is more representative of long-term (i.e.,
lifetime) exposures and risks.
(2) Temporally-varying emissions based on continuous emissions
monitoring data, rather than assuming a constant emission rate for
each facility throughout the entire simulation.
(3) Building downwash, where appropriate.
(4) The latest version of AERMOD [version 11103].
The EPA's assessment of the case study facilities for the proposed
rule concluded that three coal-fired facilities and one oil-fired
facility had estimated lifetime cancer risks greater than one in a
million. For the final rule, revisions were made to the case studies
based on comments received, and the results indicate that five coal-
fired facilities and one oil-fired facility had estimated lifetime
cancer risks greater than one in a million.
Regarding peer review, the risk assessment methodology used by EPA
for the case studies was consistent with the method that EPA uses for
assessments performed for Risk and Technology Review rulemakings, which
underwent peer review by the Science Advisory Board in 2009.\296\ The
SAB issued its peer review report in May 2010. The report generally
endorsed the risk assessment methodologies used in the program. In
addition, in July 2011, the EPA completed a letter peer review of the
methods used to develop inhalation cancer risk estimates for Cr and Ni
compounds.
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\296\ U.S. EPA-SAB, 2010.
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f. Ecosystem Impacts From HAP
Comment: Two commenters assert that EPA is not justified in
regulating acid gases based on concern about the potential that acid
gases contribute to ecosystem acidification rather than concerns about
hazards to public health. The commenters further claim that HCl's
contribution to ecosystem acidification is de minimis. The commenters
point out that EPA acknowledges uncertainty in quantification of
acidification and EPA relies on recently published research \297\ that
is irrelevant to the question since it is based on research conducted
in the peat bog ecosystem in the United Kingdom. Another commenter
calls attention to several new studies published in a special issue of
the
[[Page 9362]]
journal Ecotoxicology devoted to the effects of MeHg on wildlife.
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\297\ Evans, Chris D., Don T. Monteith, David Fowler, J. Neil
Cape, and Susan Brayshaw. 2011. ``Hydrochloric Acid: An Overlooked
Driver of Environmental Change.'' Environmental Science & Technology
45 (5), 1887-1894.
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Response: Although EPA agrees that quantification of acidification
effects has remaining uncertainty, the science and methodology has
progressed in recent years. Based on recent peer reviewed research
including Evans et al.,\298\ acid gases can significantly contribute to
acidification. The EPA published a comprehensive risk assessment of
acidification effects of nitrogen and sulfur deposition \299\ and a
policy assessment.\300\ Given the extent and importance of the
sensitive ecosystems evaluated in the review of nitrogen and sulfur
deposition any substance that contributes to further acidification must
be considered to be affecting the public welfare. The EPA disagrees
that the peer reviewed study mentioned by commenter by Evans et al.,
(2011) is not relevant to U.S. ecosystems. The paper presents evidence
that show (1) that HCl is highly mobile in the environment,
transferring acidity easily through soils and water, (2) that HCl can
transport longer distances than previously thought (given its presence
in remote ecosystems, and (3) that it can be a larger driver of
acidification than previously thought. The fact that this study took
place in the U.K. is itself irrelevant. The chemical interactions of
HCl in water are the same the world over and sensitive ecosystems exist
in the U.S. as well as in Europe as illustrated in the ecological risk
assessment \301\ for NOX and SOX. Furthermore,
the commenter is factually incorrect that EPA is justifying that it is
appropriate and necessary to regulate HAP emissions from EGUs based on
this one study. The EPA agrees with the commenter that Hg exposure in
wildlife is responsible for various adverse health effects in many
species across the U.S. and recognizes that research is ongoing in this
area. As discussed in the preamble to the proposed rule, the EPA agrees
that there are potential environmental risks from exposures of
ecosystems through Hg and non-Hg HAP deposition. The EPA cited relevant
articles from the special edition of Ecotoxicology \302\ mentioned by
the commenter in the ecosystem effects section on Chapter 5 of the RIA
for this rule, which is available in the docket.
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\298\ Id.
\299\ U.S. Environmental Protection Agency (U.S. EPA). 2009.
Risk and Exposure Assessment for Review of the Secondary National
Ambient Air Quality Standards for Oxides of Nitrogen and Oxides of
Sulfur (Final). EPA-452/R-09-008a. Office of Air Quality Planning
and Standards, Research Triangle Park, NC. September. Available on
the Internet at https://www.epa.gov/ttn/naaqs/standards/no2so2sec/data/NOxSOxREASep2009MainContent.pdf.
\300\ U.S. Environmental Protection Agency (U.S. EPA). 2011d.
Policy Assessment for the Review of the Secondary National Ambient
Air Quality Standards for Oxides of Nitrogen and Oxides of Sulfur.
EPA-452/R-11-005a. Office of Air Quality Planning and Standards,
Research Triangle Park, NC. February. Available on the Internet at
https://www.epa.gov/ttnnaaqs/standards/no2so2sec/data/20110204pamain.pdf.
\301\ U.S. EPA, 2009.
\302\ Ecotoxicology 17:83-91, 2008.
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G. EPA Affirms the Finding That It Is Appropriate and Necessary to
Regulate EGUs To Address Public Health and Environmental Hazards
Associated With Emissions of Hg and Non-Hg HAP From EGUs
In response to peer reviews of both the Hg and non-Hg HAP risk
analyses, and taking into account public comments, the EPA conducted
revised analyses of the risks associated with emissions of Hg and non-
Hg HAP from U.S. EGUs. These revised analyses demonstrated that the
risk results reported in the preamble to the proposed rule are robust
to revisions in response to the peer reviews and public comments.
Specifically, the revised Hg Risk TSD shows that up to 29 percent
of modeled watersheds have populations potentially at-risk from
exposure to Hg from U.S. EGUs.\303\ This 29 percent of watersheds with
populations potentially at-risk includes up to 10 percent of modeled
watersheds where deposition from U.S. EGUs alone leads to potential
exposures that exceed the MeHg RfD, and up to 24 percent of modeled
watersheds where total potential exposures to MeHg exceed the RfD and
U.S. EGUs contribute at least 5 percent to Hg deposition. Each of these
results independently supports our conclusion that U.S. EGUs pose
hazards to public health.
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\303\ This corresponds to 28 percent of modeled watersheds with
populations potentially at-risk in the analysis reported in the
preamble to the proposed rule.
---------------------------------------------------------------------------
In the preamble to the proposed rule and in the 2000 finding, the
EPA explained at length the serious nature of the health effects
associated with Hg exposures, and the persistent nature of Hg in the
environment. Congress specifically recognized the significant impacts
of persistent bioaccumulative pollutants, like Hg, when it enacted
section 112(c)(6), which requires the EPA to subject source categories
listed pursuant to that section to MACT standards. Congress also
required certain studies be conducted under CAA section 112(n)
regarding the health effects of Hg. The EPA interprets CAA section
112(n)(1), with regard to Hg, as intended to protect the public,
including sensitive populations, against exposures to Hg from EGUs that
would exceed the level determined by the EPA to be without appreciable
risk, e.g., exposures that are above the RfD for methylmercury (MeHg),
or would contribute additional risk in areas where Hg exposures exceed
the RfD due to contributions from all sources of Hg. Our recent
technical analyses show that 98 percent of the watersheds for which we
had fish tissue data have total Hg deposition such that potential
exposures exceed the MeHg RfD, above which there is an increased risk
of adverse effects on human health. In these watersheds, any reductions
in exposures to Hg will reduce risk, and thus the incremental
contribution to Hg exposure from any individual source or group of
sources, such as EGUs, may reasonably be anticipated to cause
additional risk.
As we have explained, in calculating the estimates described above,
the EPA has used peer-reviewed methods, and focused on populations
likely to be at higher risk of exposure to Hg from U.S. EGUs, e.g.,
female subsistence fishing populations consuming at the 99th percentile
fish consumption rate. The EPA did not, however, use the most
conservative assumptions that would lead to upper bound risk estimates.
As discussed above and in the revised Hg Risk TSD, we did not use the
highest fish tissue cooking loss adjustment factor that was reported in
the literature, which, had we done so, would have increased the
estimates of Hg exposure substantially. Thus, we believe our analysis
could understate risk to the most exposed individual, noting that we
have focused on the 99th percentile consumption rate in our estimates.
Further, we were able to assess potential Hg exposures in only a
small subset of generally representative watersheds in the U.S. because
our analysis was necessarily premised on those water bodies for which
we had fish tissue Hg samples. Specifically, we analyzed 3,141 of the
approximately 88,000 watersheds in the United States. This limited set
of watersheds excludes several of the watersheds with the highest U.S.
EGU attributable deposition, and may also not have included watersheds
with the highest sensitivity to Hg deposition, e.g., the highest
methylation rates (see above). Nevertheless, our analysis of the subset
of watersheds we examined demonstrates that almost one third of the
watersheds are estimated to have Hg deposition attributable to U.S.
EGUs that contributes to potential exposures above the MeHg RfD. The
SAB
[[Page 9363]]
confirmed that the subset of watersheds we examined is sufficient.
Considering these points and the information on Hg in the record,
the EPA believes that 10 percent of watersheds with populations at risk
due to U.S. EGU emissions alone is unacceptable, as is 24 percent of
watersheds with populations at risk due to U.S. EGU contributions in
conjunction with total deposition from other sources. Taking into
account the percentage of watersheds at risk, and the potential for
even higher percentages to be at risk using more conservative risk
assumptions and a more complete coverage of high U.S. EGU Hg deposition
watersheds, the EPA concludes that Hg emissions from U.S. EGUs pose a
hazard to public health.
Given these findings, and considering that (1) the revised risk
analysis showed the percent of modeled watersheds with populations
potentially at-risk increased from 28 to 29 percent, and (2) the
revised analysis includes 36 percent more watersheds, which
significantly expands the coverage in several states, we conclude that
the finding that emissions of Hg from U.S. EGUs pose a hazard to public
health is confirmed by the national-scale revised Hg Risk TSD. As a
result, we conclude that it remains appropriate to regulate Hg
emissions from U.S. EGUs because those Hg emissions pose a hazard to
public health.
With regards to the revised non-Hg inhalation case studies, the
highest estimated individual lifetime cancer risk for the one case
study facility (out of 16) with oil-fired EGUs is estimated to be 20 in
a million, driven by Ni emissions. For the facilities with coal-fired
EGUs, there were five (out of 16) with maximum individual cancer risks
greater than one in a million (the highest was five in a million), four
of which were driven by emissions of Cr(VI), and one of which was
driven by emissions of Ni. Therefore, a total of six facilities exceed
the criterion for EGUs to be regulated under CAA section 112. There
were also two facilities with coal-fired EGUs with maximum individual
cancer risks at one in a million. In the preamble to the proposed rule,
we reported that the maximum individual lifetime cancer risk for the
one facility with oil-fired EGUs was estimated to be 10 in a million,
and that there were 3 coal-fired EGU facilities with maximum individual
cancer risks greater than 1 in a million (the highest was 8 in a
million), and 1 coal-fired EGU facility with maximum individual cancer
risks equal to 1 in a million. Given that (1) the lifetime cancer risk
for the oil-fired EGU facility has increased from 10 to 20 in a
million, (2) the number of coal-fired EGU facilities with cancer risks
greater than 1 in a million has increased from 3 to 5, and (3) the
highest risk coal-fired facility still has cancer risks of 5 in a
million, which is above the 1 in a million benchmark, we conclude that
the finding that emissions of non-Hg HAP from U.S. EGUs pose a hazard
to public health is confirmed by the revised non-Hg risk inhalation
case studies.
Moreover, some HAP emissions from U.S. EGUs contribute to adverse
ecosystem effects. While we did not do new analyses on these topics, we
reiterate that (1) Hg emissions from U.S. EGUs pose a hazard to the
environment, contributing to adverse impacts on fish-eating birds and
mammals, (2) Hg is a persistent bioaccumulative environmental
contaminant, and as a result, failing to control Hg emissions from U.S.
EGU sources will result in long-term environmental loadings of Hg,
above and beyond those loadings caused by immediate deposition of Hg
within the U.S.; controlling Hg emissions from U.S. EGUs helps to
reduce the potential for environmental hazard from Hg now and in the
future, and (4) it is appropriate to regulate those HAP which are not
known to cause cancer but are known to contribute to chronic non-cancer
toxicity and environmental degradation, such as the acid gases. In
addition, we have identified effective controls available to reduce Hg
and non-Hg HAP emissions.
In summary, we confirm the findings that Hg and non-Hg HAP
emissions from U.S. EGUs each pose hazards to public health and that it
remains appropriate to regulate U.S. EGUs under CAA section 112 for
those reasons. We also conclude that it remains appropriate to regulate
EGUs under CAA section 112 because of the magnitude of Hg and non-Hg
emissions and the environmental effects of Hg and some non-Hg
emissions, each of which standing alone, supports the appropriate
finding. The availability of controls to reduce HAP emissions from EGUs
only further supports the appropriate finding.
Our revised analyses still show that in 2016 after implementation
of other provisions of the CAA, HAP emissions from U.S. EGUs are
reasonably anticipated to pose hazards to public health; therefore, it
is necessary to regulate EGUs under CAA section 112. Moreover, HAP
emissions from U.S. EGUs are expected to continue to contribute to
adverse ecosystem effects. In addition, based on evaluation of the
regulations required by the CAA, including the recent CSAPR, it is
necessary to regulate U.S. EGUs under CAA section 112 because the only
way to ensure permanent reductions in HAP emissions from U.S. EGUs and
the associated risks to public health and the environment is through
standards set under CAA section 112. While CSAPR is projected to
achieve some Hg reductions due to co-control of Hg provided by controls
put in place to achieve required reductions in SO2
emissions, the results of the revised Hg Risk TSD indicate that an
unacceptable percentage of modeled watersheds have populations
potentially at-risk from U.S. EGU-attributable Hg deposition would
remain after implementation of CSAPR. While we modeled slightly higher
Hg emissions from U.S. EGUs (i.e., 29 tons of Hg) in our risk analysis
compared to the most recent estimate of 27 tons, we do not believe this
2 ton difference would substantially change our finding that Hg
emissions from U.S. EGUs pose a hazard to public health or the Hg risks
reported in the preamble to the proposed rule, as this represents less
than a 10 percent reduction in Hg emissions. In addition, the actual
reductions in Hg that will occur due to application of controls to meet
the SO2 emissions requirements of CSAPR may differ from
those projected to occur, due to differences in the technologies that
individual EGU sources choose to install. The only way to ensure
reductions in Hg, including those modeled as resulting from the CSAPR,
is to directly regulate Hg emissions under CAA section 112.
In summary, we confirm the findings that it is necessary to
regulate HAP emissions from U.S. EGUs because (1) the national-scale Hg
Risk TSD shows that the hazards to public health posed by Hg emissions
from U.S. EGUs will not be addressed through imposition of the CAA, (2)
we cannot be certain that the identified cancer risks attributable to
U.S. EGUs will be addressed through imposition of the requirements of
the CAA, (3) the environmental hazards posed by acidification will not
be fully addressed through imposition of the CAA, (4) regulation under
CAA section 112 is the only way to ensure that all HAP emissions
reductions that have been achieved since 2005 remain permanent, and (5)
direct control of Hg emissions affecting U.S. deposition is only
possible through regulation of U.S. emissions as we are unable to
control global emissions directly. All of these findings independently
support a finding that it is necessary to regulate U.S. EGUs under CAA
section 112.
Based on these findings, the Agency affirms its finding that it
remains appropriate and necessary to regulate
[[Page 9364]]
coal- and oil-fired EGUs under CAA section 112, and maintains that the
inclusion of coal- and oil-fired EGUs on the CAA section 112(c) list of
source categories regulated under CAA section 112 remains valid.
IV. Denial of Delisting Petition
During the comment period on the proposed rule, UARG submitted a
petition pursuant to CAA section 112(c)(9), asking the Agency to delete
a portion of the EGU source category from the list of source categories
to be regulated under CAA section 112. Specifically, UARG asks that EPA
delist coal-fired EGUs from the CAA section 112(c) source category
list. A copy of UARG's petition has been placed in the docket for
today's rulemaking, along with the analysis conducted by EPRI that UARG
uses to support its petition (hereinafter referred to as UARG's
analysis). In support of its petition, UARG asserts that: (1) No coal-
fired EGU or group of coal-fired EGUs will emit HAP in amounts that
will cause a lifetime cancer risk greater than one in one million; and
(2) no coal-fired EGU or group of coal-fired EGUs will emit non-
carcinogenic HAP in amounts that will exceed a level which is adequate
to protect public health with an ample margin of safety or cause
adverse environmental effects. We disagree with UARG's assertions and
for the reasons set forth below are denying UARG's petition to delist
coal-fired EGUs from the section 112(c) source category list.
A. Requirements of CAA Section 112(c)(9)
CAA section 112(c)(9)(B) provides that ``[t]he Administrator may
delete any source category'' from the section 112(c) source category
list if the Agency determines that: (i) For HAP that may cause cancer
in humans, ``no source in the category (or group of sources in the case
of area sources) emits such hazardous air pollutants in quantities
which may cause a lifetime risk of cancer greater than one in one
million to the individual in the population who is most exposed to
emissions of such pollutants from the source (or group of sources in
the case of area sources)''; and (ii) for HAP that may result in human
health effects other than cancer or adverse environmental effects, ``a
determination that emissions from no source in the category or
subcategory concerned (or group of sources in the case of area sources)
exceed a level which is adequate to protect public health with an ample
margin of safety and no adverse environmental effect will result from
emissions from any source.''
The EPA has the discretion to delete a source category under CAA
section 112(c)(9)(B), but only if EPA concludes that the relevant
requirements of CAA section 112(c)(9)(B) have been met. HAP emissions
from EGUs present both cancer risks, which implicate the requirements
of CAA section 112(c)(9)(B)(i), and non-cancer human health effects or
adverse environmental effects, which implicate the requirements of CAA
section 112(c)(9)(B)(ii). As such, UARG bears the burden of
demonstrating that the requirements of both clauses are met.
B. Rationale for Denying UARG's Delisting Petition
The EPA is denying UARG's petition to delist EGUs from the CAA
section 112(c) source category list. UARG improperly seeks to delist a
portion of a CAA section 112(c) listed source category that emits
carcinogens, which is contrary to the plain language of CAA section
112(c)(9). Even setting aside this fundamental defect, UARG has failed
to meet the requirements of CAA section 112(c)(9)(B).
1. UARG's Attempt to Delist a Portion of a Listed Source Category
Conflicts With D.C. Circuit Precedent
In December 2000, the EPA listed coal- and oil-fired EGUs as a
single source category. UARG asks the Agency to delist a portion of
that listed source category: Coal-fired EGUs. UARG's request conflicts,
however, with D.C. Circuit precedent, which provides that for
categories, like EGUs, that pose cancer risks, the EPA may not delist a
portion of a source category. NRDC v. U.S. EPA, 489 F.3d 1364 (D.C.
Cir. 2007). Specifically, in NRDC, the D.C. Circuit held that the
Agency's attempt to delist a ``low-risk'' subcategory was ``contrary to
the plain language of the statute,'' and that the statute only
authorized the agency to remove source categories pursuant to section
112(c)(9). Id. at 1373 (``Because EPA's interpretation of Section
112(c)(9) as allowing it to exempt the risk-based subcategory is
contrary to the plain language of the statute, the EPA's interpretation
fails at Chevron step one.'').
UARG's request is indistinguishable from the situation before the
court in NRDC. UARG does not seek to delist coal- and oil-fired EGUs,
which is the source category that EPA listed, but rather a portion of
that category. UARG also does not dispute that coal-fired EGUs emit
carcinogenic HAP. Because UARG's request to delist is contrary to the
plain language of CAA section 112(c)(9)(B) and NRDC, we are denying the
delisting petition.
2. Even Assuming, for the Sake of Argument, That EPA Could Delist a
Portion of a Source Category, UARG has Failed to Meet the Requirements
of CAA Section 112(c)(9)
Even assuming, for the sake of argument, that EPA could delist a
portion of a source category that emits carcinogens, which it cannot,
UARG has failed to demonstrate that the requirements for delisting in
CAA section 112(c)(9)(i) and (ii) have been met. UARG contends that it
used EPA's models and approaches, as well as the most recent data. We
have carefully reviewed UARG's analyses, however, and found certain
flaws that we believe bias their risk results low. Specifically, we
identified flaws in emissions estimation. UARG developed estimates for
all EGU facilities using data which pre-date the 2010 ICR emissions
measurement data that EPA obtained to support this rule. UARG also
relied upon an emissions equation developed by EPRI and DOE to develop
its metal emissions estimates. With regard to that approach, the EPA
analysis of the ICR data has found that the regression approach is not
a good predictor of actual EGU emissions. Furthermore, we found fault
with their use of the geometric mean and their outlier analysis for
computing emission factors. The EPA analysis has found that the
geometric mean approach underpredicts actual emissions by an average of
more than seventy percent. This had an especially large impact on the
arsenic, chromium, and nickel emissions estimates. These and other
issues are explained in further detail in the response to comments
document. As a result, we believe the resulting risk estimates in
UARG's analysis are biased low. In addition, we note that there are
dispersion model refinements that are not included in the UARG
analyses, but were included in EPA's analysis. For example, for the
dispersion modeling of the 16 non-Hg case studies, the EPA considered
building downwash and used time-varying emissions, neither of which
were used in UARG's analysis. These factors could also bias the UARG
risk estimates low.
However, even taking UARG's analysis at face value and accepting,
for arguments' sake, their assumptions and emissions estimates, UARG's
own data supports denial of the petition because UARG itself identifies
a maximum individual cancer risk exceeding 1 in a million, which is the
statutory threshold in CAA section 112(c)(9)(B)(i). Specifically,
UARG's multi-pathway
[[Page 9365]]
model plant ingestion risk analysis concluded that adult anglers would
face cancer risks of 4 in a million. For this reason alone, the
petition should be denied.
UARG dismisses the 4 in a million cancer result, arguing that the
refined model plant multipathway risk assessment that it conducted is
``overly conservative.'' UARG conducted its multi-pathway risk analysis
to evaluate the risks associated with ingesting persistent and
bioaccumulative HAP which are emitted into the atmosphere and
subsequently deposit into the environment and bioaccumulate in animals
which are eventually consumed as food. Instead of conducting this
multipathway analysis for each EGU facility, UARG instead analyzed
multi-pathway risks by evaluating a single model plant. Nothing in the
record indicates, however, that UARG's model plant represents the
worst-case scenario for cancer human health risks from any EGU. Indeed,
although UARG claims in its petition that the site selected for its
case study is ``likely as close to a worst-case scenario as is possible
given the numerous variables associated with ingestion pathway risks''
(UARG petition at 12), the supporting documentation for that case study
specifically acknowledges that its fictional model plant scenario ``is
not intended to represent the risk due to emissions from an actual
plant or the highest level of risk that could be associated with a
coal-fired power plant at any location'' (EPRI at 1). The statute
requires that no source in the category may cause a lifetime cancer
risk greater than one in one million to the most exposed individual,
and UARG has failed to make this showing. UARG has neither modeled
multi-pathway risks for a worst-case model facility, nor evaluated the
multipathway risks associated with each individual EGU facility.
Accordingly, UARG has not made the demonstration required by CAA
section 112(c)(9)(B)(i). But, even focusing on the multi-pathway risk
analysis that UARG did conduct, which admittedly does not represent a
worst-case facility, UARG's analysis still shows cancer risks greater
than one in a million. Accordingly, UARG's petition must be denied.
Although it is not necessary to reach the requirements of CAA
section 112(c)(9)(B)(ii) that address non-cancer human health risks, we
note that UARG has also failed to show that ``emissions from no source
in the category * * * exceed a level which is adequate to protect
public health with an ample margin of safety.'' Again, even accepting,
for argument's sake, the conclusions in UARG's analysis, UARG only
evaluated the non-cancer inhalation risks associated with each EGU
facility. It did not conduct a similar analysis to assess multipathway
risks for each EGU facility. Instead, it conducted a model plant
analysis and admits that such model plant does not represent the worst-
case scenario for noncancer human health risks from any EGU. Thus, the
analysis fails to fully characterize noncancer multipathway risks for
the source category, and UARG's petition must be denied on this basis
as well.
Finally, UARG failed to meet its burden of showing that ``no
adverse environmental effect will result from emissions from any
source'' pursuant to CAA section 112(c)(9)(B)(ii). UARG analyzed
environmental effects only in conjunction with its model plant. Because
UARG's model plant does not represent the worst-case scenario for
environmental effects, UARG's analysis falls short and fails to
characterize fully the potential environmental impacts, and UARG's
petition must be denied.
For all of these reasons, the EPA denies UARG's petition to delist
coal-fired EGUs from the CAA section 112(c) source category list.
C. EPA's Technical Analyses for the Appropriate and Necessary Finding
Provide Further Support for the Conclusion That Coal-Fired EGUs Should
Remain a Listed Source Category
The EPA reasonably concluded in December 2000, based on the
information available to the Agency at that time, that it was
appropriate and necessary to regulate coal- and oil-fired EGUs under
CAA section 112 and added such units to the list of source categories
subject to regulation under CAA section 112(d). As discussed in section
III above, the EPA conducted additional, extensive technical analyses
based on recent data that confirm it remains appropriate and necessary
to regulate HAP from coal- and oil-fired EGUs, because such EGUs
continue to pose hazards to public health. HAP emissions from coal- and
oil-fired EGUs also continue to cause adverse environmental effects.
UARG advances several arguments, challenging the analyses the Agency
completed in support of the proposed rule. We address those arguments
in section III above. The Agency's analyses supporting the appropriate
and necessary finding confirm that EGUs cannot be delisted pursuant to
CAA section 112(c)(9).
Specifically, as explained further in section III above, the EPA
analyzed non-Hg inhalation risks from 16 EGU facility case studies,
including both coal- and oil-fired EGUs, as part of its technical
analyses supporting the appropriate and necessary finding. That
analysis demonstrates that there are 6 EGU facilities (of the 16 that
we analyzed) with cancer risks exceeding one in one million. These
cancer risk levels exceed the delisting criteria set forth in CAA
section 112(c)(9)(B)(i), and confirm that EGUs must remain a listed
source category. As explained above, some commenters assert that EPA's
analysis of non-Hg inhalation risks from EGUs conducted in support of
the proposal for this rulemaking overstated emissions from, and risks
associated with, EGUs. These commenters argue that the analysis
supporting UARG's petition more appropriately assesses EGU risk. The
EPA disagrees with these comments and addresses these comments in
section III above.
Significantly, the EPA based its analysis of 16 case study EGUs
directly on the 2010 emissions test data from EGUs obtained through the
ICR. The EPA's 16 case study analysis used emissions data either taken
directly from the 2010 emissions test data, or derived using emissions
factors based on the 2010 data for similar EGU units. The EPA also
included dispersion model refinements in its final case studies, as
noted above. Further, the EPA re-analyzed the 16 case studies that we
conducted for the proposal and revised those analyses consistent with
new non-Hg HAP emissions data and corrected stack parameters provided
by commenters (including UARG) during the comment period on the
proposed rule. The EPA received revised information concerning
emissions tests, stack heights and stack diameters for some of the case
study EGU facilities. The EPA incorporated all of these corrections
into our analysis and then re-analyzed the risks for the 16 case study
facilities. When completed, the EPA determined that the corrections
incorporated into the reanalysis had little effect on the overall
results. In the final rule, the EPA concludes that the maximum
individual inhalation cancer risks for 6 out of the 16 case study EGU
facilities are greater than 1 in a million. These cancer risk levels
confirm that EGUs do not satisfy the delisting criterion of CAA section
112(c)(9)(B)(i) and thus should remain a listed source category.
The EPA's national-scale Hg Risk TSD supporting the appropriate and
necessary finding also confirm that Hg emissions from coal- and oil-
fired US EGUs are reasonably anticipated to pose a hazard to public
health. As discussed
[[Page 9366]]
in section III above, the EPA interprets CAA section 112(n)(1), with
regard to mercury, as intended to protect the public, including
sensitive populations, against exposures to Hg from EGUs that would
exceed the level determined by EPA to be without appreciable risk,
e.g., exposures that are above the RfD for methylmercury (MeHg), or
would contribute additional risk in areas where Hg exposures exceed the
RfD due to contributions from all sources of Hg.
In order to determine whether EGU Hg emissions pose a hazard to
public health, the EPA conducted a national-scale Hg Risk TSD focused
on populations with high levels of self-caught freshwater fish
consumption. The results of the Hg Risk TSD show that 98 percent of
modeled watersheds have total exposures to MeHg that exceed the MeHg
RfD, above which there is an increased risk of adverse effects on human
health. In these watersheds, any reductions in exposures to Hg will
reduce risk, and thus the incremental contribution to Hg exposure from
any individual source or group of sources, such as EGUs, may reasonably
be anticipated to cause additional risk. The Hg Risk TSD focused on
those watersheds that either exceeded the RfD based on U.S. EGU
attributable deposition alone, without considering other sources of
deposition, or watersheds that exceed the RfD due to total Hg
deposition and to which U.S. EGUs contributed at least 5 percent of the
Hg deposition. The results of that analysis show that up to 29 percent
of the modeled watersheds have populations that are potentially at-risk
from exposure to Hg from U.S. EGUs, including up to 10 percent of
modeled watersheds where deposition from U.S. EGUs alone leads to
potential exposures that exceed the MeHg RfD, and up to 24 percent of
modeled watersheds where total potential exposures to MeHg exceed the
RfD and U.S. EGUs contribute at least 5 percent to Hg deposition. This
approach to assessing national risks from Hg deposition from EGUs was
supported by the independent peer review conducted by the Science
Advisory Board, as discussed fully in section III.
Finally, as discussed in section III, based on this assessment, the
EPA has confirmed that Hg emitted from U.S. EGUs pose a hazard to
public health and it is appropriate to regulate U.S. EGUs under CAA
section 112. This determination and the confirmatory assessments
support our conclusion that UARG's delisting petition must be denied.
UARG attempts to dismiss the results of EPA's national-scale Hg
Risk TSD, arguing that EPA cannot consider the risks posed by EGUs in
conjunction with any other risks, including those from other source
categories. Nothing in CAA section 112(c)(9), however, provides that
the Agency cannot consider background or emissions due to other
sources. CAA section 112(c)(9)(B)(ii) provides that ``no source in the
category or subcategory concerned (or group of sources in the case of
area sources) exceed a level which is adequate to protect public health
with an ample margin of safety and no adverse environmental effect will
result from emissions from any source.'' This language could be read to
provide that the Agency consider only the risks associated with the
source category at issue, and ignore how those risks fit with real-
world exposures.\304\ However, the language could also be read to
provide that the Agency consider the cumulative effect of HAP emissions
from the individual sources in the category in conjunction with the HAP
emissions from other sources. The latter is a reasonable
interpretation, especially when considering how the public is exposed
to HAP emissions. Considering the individual sources in a source
category in isolation treats the sources as if they exist in a vacuum,
which does not mirror reality. Such an approach is particularly
problematic for environmentally persistent HAP that bio-accumulate in
the food chain, such as mercury.\305\
---------------------------------------------------------------------------
\304\ The same is true with respect to section 112(c)(9)(B)(i).
\305\ In a prior rulemaking, EPA stated that the language in
section 112(c)(9)(B)(ii) ``does not direct EPA to extend its
analysis to either emissions from other sources in other categories
or subcategories or to non-attributable background concentrations.''
71 FR 8347 (Feb. 16, 2006). The preamble to that rule repeatedly
states that the ``focus'' of the delisting determination in that
rule was on emissions from sources in the category under review. See
71 FR 8346-47. The preamble went on to compare section 112(c)(9)(B)
to section 112(f)(2)(A) in a way that suggested that EPA can
consider risks presented by sources other than the subject source
category under section 112(f)(2), but not under section 112(c)(9).
We do not believe the language of section 112(c)(9) compels any
different treatment. The section 112(f) analysis occurs after a
source category has already complied with section 112(d) standards,
whereas, potential delistings under section 112(c)(9) may involve
source categories unregulated by section 112. A delisting decision
is significant in that the category that is delisted will no longer
be subject to HAP regulation under the Act. It is difficult to
justify why we would examine risks from other sources under section
112(f), but not under section 112(c)(9), where Congress established
such a specific test for delisting.
---------------------------------------------------------------------------
Here, the record demonstrates that 98 percent of the watersheds EPA
modeled have total exposures to MeHg that exceed the MeHg RfD, above
which there is increased risk of adverse effects on human health,
especially on the developing nervous systems of children during
gestation. EGUs remain one of the largest unregulated sources of Hg
emissions, and those emissions continue to contribute to Hg exposures
and risk. UARG seeks to ignore the fact that exposures above the RfD
exist in almost every watershed we modeled, and instead focuses on the
contribution provided solely by EGUs. The EPA did as UARG asked and
found that up to 10 percent of modeled watersheds where deposition from
U.S. EGUs alone leads to potential exposures that exceed the MeHg RfD.
Thus, even focusing on EGU emissions in a vacuum, which we do not
believe is appropriate or required under CAA section 112(c)(9), we
still found that up to 10 percent of the watersheds exceed the RfD due
to EGU emissions even before taking into account the numerous other
sources of Hg deposition, and we believe this to be an unacceptable
percentage of watersheds above the RfD. Due to the persistent,
bioacccumulative nature of Hg, among other factors, we believe it is
appropriate to consider the combined impact of Hg emissions from EGUs
and other sources of Hg. Thus, we also considered the 24 percent of
modeled watersheds where, even though U.S. EGU emissions alone are not
enough to cause exposures that exceed the RfD, those emissions
contribute at least 5 percent of total exposures to MeHg that exceed
the RfD. The combined total of 29 percent of modeled watersheds where
U.S. EGUs cause or contribute to MeHg exposures above the RfD is
clearly unacceptable and thus the UARG petition to delist must be
denied.
Thus, the technical analyses the Agency conducted in support of the
appropriate and necessary finding confirm that EGUs should remain a
listed source category.
V. Summary of This Final NESHAP
This section summarizes the requirements of the final EGU NESHAP.
Section VI below summarizes the significant changes to this final rule
following proposal.
A. What is the source category regulated by this final rule?
This final rule affects coal- and oil-fired EGUs.
B. What is the affected source?
An existing affected source under this final rule is the collection
of coal- or oil-fired EGUs in a subcategory within a single contiguous
area and under common control. A new affected source is each coal- or
oil-fired EGU for which construction or reconstruction began after May
3, 2011.
[[Page 9367]]
CAA section 112(a)(8) defines an EGU as: a fossil fuel-fired
combustion unit of more than 25 megawatts that serves a generator
that produces electricity for sale. A unit that cogenerates steam
and electricity and supplies more than one-third of its potential
electric output capacity and more than 25 megawatts electrical
output to any utility power distribution system for sale shall be
considered an electric utility steam generating unit.
If an EGU burns coal (either as a primary fuel or as a
supplementary fuel) or any combination of coal with another fuel
(except for solid waste as noted below) where the coal accounts for
more than 10.0 percent of the average annual heat input during any 3
consecutive calendar years or for more than 15.0 percent of the annual
heat input during any one calendar year after the applicable compliance
date, the unit is considered to be coal-fired under this final rule.
If a unit is not a coal-fired unit and burns only oil or burns oil
in combination with a fuel other than coal (except solid waste as noted
below) where the oil accounts for more than 10.0 percent of the average
annual heat input during any 3 consecutive calendar years or for more
than 15.0 percent of the annual heat input during any one calendar year
after the applicable compliance date, the unit is considered to be oil-
fired under this final rule.
As noted below, the EPA is finalizing in this rule a definition to
determine whether the combustion unit is ``fossil fuel fired'' such
that it is considered an EGU as defined in CAA section 112(a)(8) and,
thus, potentially subject to this final rule. In addition, using the
construct of the definition of ``oil-fired'' from the ARP, we are
finalizing in this rule a requirement that the unit fire coal or oil
(or natural gas), or any combination thereof, for more than 10.0
percent of the average annual heat input during any 3 consecutive
calendar years or for more than 15.0 percent of the annual heat input
during any one calendar year to be considered a ``fossil fuel-fired''
EGU as defined in CAA section 112(a)(8). However, if a new or existing
EGU is not coal- or oil-fired, and the unit burns natural gas
exclusively or burns natural gas in combination with another fuel where
the natural gas constitutes 10 percent or more of the average annual
heat input during any 3 calendar years or 15 percent or more of the
annual heat input during any 1 calendar year, the unit is considered to
be natural gas-fired EGU and not subject to this final rule. As
discussed later, we believe that this definition will address those
situations where an EGU co-fires limited amounts of either coal or oil
with natural gas or other non-fossil fuels (e.g., biomass).
If an EGU combusts solid waste, standards issued pursuant to CAA
section 129 apply to that EGU, rather than this final rule.
C. What are the pollutants regulated by this final rule?
For coal-fired EGUs, this final rule regulates HCl as a surrogate
for acid gas HAP, with an alternate of SO2 as a surrogate
for acid gas HAP for coal-fired EGUs with FGD systems installed and
operational; filterable PM as a surrogate for non-mercury HAP metals,
with total non-mercury HAP metals and individual non-mercury HAP metals
as alternative equivalent standards; Hg; and organic HAP. For oil-fired
EGUs, this final rule regulates HCl and HF; filterable PM as a
surrogate for total HAP metals, with individual HAP metals as
alternative equivalent standards; and organic HAP.
D. What emission limits and work practice standards must I meet and
what are the subcategories in the final rule?
We are finalizing the emission limitations presented in Tables 3
and 4 of this preamble. Within the two major subcategories of ``coal''
and ``oil,'' emission limitations were developed for new and existing
sources for seven subcategories, two for coal-fired EGUs, one for IGCC
EGUs burning synthetic gas derived from coal- and/or solid oil-derived
fuel, one for solid oil-derived fuel-fired EGUs, and four for liquid
oil-fired EGUs, as described in more detail below. The limited-use
liquid oil-fired subcategory, discussed elsewhere in this preamble, is
not presented in Table 3 because only work practice standards apply to
this subcategory.
Table 3--Emission Limitations for Coal-Fired and Solid Oil-Derived Fuel-Fired EGUs
----------------------------------------------------------------------------------------------------------------
Filterable particulate
Subcategory matter Hydrogen chloride Mercury
----------------------------------------------------------------------------------------------------------------
Existing--Unit not low rank 3.0E-2 lb/MMBtu.......... 2.0E-3 lb/MMBtu......... 1.2E0 lb/TBtu.
virgin coal. (3.0E-1 lb/MWh).......... (2.0E-2 lb/MWh)......... (1.3E-2 lb/GWh).
Existing--Unit designed low rank 3.0E-2 lb/MMBtu.......... 2.0E-3 lb/MMBtu......... 1.1E+1 lb/TBtu.
virgin coal. (3.0E-1 lb/MWh).......... (2.0E-2 lb/MWh)......... (1.2E-1 lb/GWh).
4.0E0 lb/TBtu \a\.
(4.0E-2 lb/GWh \a\).
Existing--IGCC................... 4.0E-2 lb/MMBtu.......... 5.0E-4 lb/MMBtu......... 2.5E0 lb/TBtu.
(4.0E-1 lb/MWh).......... (5.0E-3 lb/MWh)......... (3.0E-2 lb/GWh).
Existing--Solid oil-derived...... 8.0E-3 lb/MMBtu.......... 5.0E-3 lb/MMBtu......... 2.0E-1 lb/TBtu.
(9.0E-2 lb/MWh).......... (8.0E-2 lb/MWh)......... (2.0E-3 lb/GWh).
New--Unit not low rank virgin 7.0E-3 lb/MWh............ 4.0E-4 lb/MWh........... 2.0E-4 lb/GWh.
coal.
New--Unit designed for low rank 7.0E-3 lb/MWh............ 4.0E-4 lb/MWh........... 4.0E-2 lb/GWh.
virgin coal.
New--IGCC........................ 7.0E-2 lb/MWh \b\........ 2.0E-3 lb/MWh \d\....... 3.0E-3 lb/GWh \e\.
9.0E-2 lb/MWh \c\........
New--Solid oil-derived........... 2.0E-2 lb/MWh............ 4.0E-4 lb/MWh........... 2.0E-3 lb/GWh.
----------------------------------------------------------------------------------------------------------------
Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input.
lb/TBtu = pounds pollutant per trillion British thermal units fuel input.
lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
\a\ Beyond-the-floor limit as discussed elsewhere.
\b\ Duct burners on syngas; based on permit levels in comments received.
[[Page 9368]]
\c\ Duct burners on natural gas; based on permit levels in comments received.
\d\ Based on best-performing similar source.
\e\ Based on permit levels in comments received.
Table 4--Emission Limitations for Liquid Oil-Fired EGUs
----------------------------------------------------------------------------------------------------------------
Filterable particulate
Subcategory matter Hydrogen chloride Hydrogen fluoride
----------------------------------------------------------------------------------------------------------------
Existing--Liquid oil-- 3.0E-2 lb/MMBtu........... 2.0E-3 lb/MMBtu.......... 4.0E-4 lb/MMBtu.
continental. (3.0E-1 lb/MWh)........... (1.0E-2 lb/MWh).......... (4.0E-3 lb/MWh).
Existing--Liquid oil--non- 3.0E-2 lb/MMBtu........... 2.0E-4 lb/MMBtu.......... 6.0E-5 lb/MMBtu.
continental. (3.0E-1 lb/MWh)........... (2.0E-3 lb/MWh).......... (5.0E-4 lb/MWh).
New--Liquid oil--continental.. 7.0E-2 lb/MWh............. 4.0E-4 lb/MWh............ 4.0E-4 lb/MWh.
New--Liquid oil--non- 2.0E-1 lb/MWh............. 2.0E-3 lb/MWh............ 5.0E-4 lb/MWh.
continental.
----------------------------------------------------------------------------------------------------------------
We are also finalizing alternate equivalent emission standards (for
certain subcategories) to the final surrogate standards in three areas:
SO2 (for HCl), individual non-mercury metals and total non-
mercury metals (for filterable PM) from coal- and solid oil-derived
fuel-fired EGUs, and individual and total metals (for filterable PM)
from oil-fired EGUs. The final alternate emission limitations are
provided in Tables 5 and 6 of this preamble.
Table 5--Alternate Emission Limitations for Existing Coal- and Oil-Fired EGUs
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Subcategory/Pollutant Coal-fired EGUs IGCC Liquid oil, continental Liquid oil, non-continental Solid oil- derived
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
SO2............................... 2.0E-1 lb/MMBtu............... NA............................ NA............................ NA........................... 3.0E-1 lb/MMBtu.
(1.5E0 lb/MWh)................ (2.0E0 lb/MWh).
Total non-mercury metals.......... 5.0E-5 lb/MMBtu............... 6.0E-5 lb/MMBtu............... 8.0E-4 lb/MMBtu............... 6.0E-4 lb/MMBtu.............. 4.0E-5 lb/MMBtu.
(5.0E-1 lb/GWh)............... (5.0E-1 lb/GWh)............... (8.0E-3 lb/MWh) \a\........... (7.0E-3 lb.MWh) \a\.......... (6.0E-1 lb/GWh).
Antimony, Sb...................... 8.0E-1 lb/TBtu................ 1.4E0 lb/TBtu................. 1.3E+1 lb/TBtu................ 2.2E0 lb/TBtu................ 8.0E-1 lb/TBtu.
(8.0E-3 lb/GWh)............... (2.0E-2 lb/GWh)............... (2.0E-1 lb/GWh)............... (2.0E-2 lb/GWh).............. (8.0E-3 lb/GWh).
Arsenic, As....................... 1.1E0 lb/TBtu................. 1.5E0 lb/TBtu................. 2.8E0 lb/TBtu................. 4.3E0 lb/TBtu................ 3.0E-1 lb/TBtu.
(2.0E-2 lb/GWh)............... (2.0E-2 lb/GWh)............... (3.0E-2 lb/GWh)............... (8.0E-2 lb/GWh).............. (5.0E-3 lb/GWh).
Beryllium, Be..................... 2.0E-1 lb/TBtu................ 1.0E-1 lb/TBtu................ 2.0E-1 lb/TBtu................ 6.0E-1 lb/TBtu............... 6.0E-2 lb/TBtu.
(2.0E-3 lb/GWh)............... (1.0E-3 lb/GWh)............... (2.0E-3 lb/GWh)............... (3.0E-3 lb/GWh).............. (6.0E-4 lb/GWh).
Cadmium, Cd....................... 3.0E-1 lb/TBtu................ 1.5E-1 lb/TBtu................ 3.0E-1 lb/TBtu................ 3.0E-1 lb/TBtu............... 3.0E-1 lb/TBtu.
(3.0E-3 lb/GWh)............... (2.0E-3 lb/GWh)............... 2.0E-3 lb/GWh)................ (3.0E-3 lb/GWh).............. (4.0E-3 lb/GWh).
Chromium, Cr...................... 2.8E0 lb/TBtu................. 2.9E0 lb/TBtu................. 5.5E0 lb/TBtu................. 3.1E+1 lb/TBtu............... 8.0E-1 lb/TBtu.
(3.0E-2 lb/GWh)............... (3.0E-2 lb/GWh)............... (6.0E-2 lb/GWh)............... (3.0E-1 lb/GWh).............. (2.0E-2 lb/GWh).
Cobalt, Co........................ 8.0E-1 lb/TBtu................ 1.2E0 lb/TBtu................. 2.1E+1 lb/TBtu................ 1.1E+2 lb/TBtu............... 1.1E0 lb/TBtu.
(8.0E-3 lb/GWh)............... (2.0E-2 lb/GWh)............... (3.0E-1 lb/GWh)............... (1.4E0 lb/GWh)............... (2.0E-2 lb/GWh).
Lead, Pb.......................... 1.2E0 lb/TBtu................. 1.9E+2 lb/MMBtu............... 8.1E0 lb/TBtu................. 4.9E0 lb/TBtu................ 8.0E-1 lb/TBtu.
(2.0E-2 lb/GWh)............... (1.8E0 lb/MWh)................ (8.0E-2 lb/GWh)............... (8.0E-2 lb/GWh).............. (2.0E-2 lb/GWh).
Manganese, Mn..................... 4.0E0 lb/TBtu................. 2.5E0 lb/TBtu................. 2.2E+1 lb/TBtu................ 2.0E+1 lb/TBtu............... 2.3E0 lb/TBtu.
(5.0E-2 lb/GWh................ (3.0E-2 lb/GWh)............... (3.0E-1 lb/GWh)............... (3.0E-1 lb/GWh).............. (4.0E-2 lb/GWh).
Mercury, Hg....................... NA............................ NA............................ 2.0E-1 lb/TBtu................ 4.0E-2 lb/TBtu (4.0E-4 lb/ NA.
(2.0E-3 lb/GWh)............... GWh).
Nickel, Ni........................ 3.5E0 lb/TBtu................. 6.5E0 lb/TBtu................. 1.1E+2 lb/TBtu................ 4.7E+2 lb/TBtu............... 9.0E0 lb/TBtu.
(4.0E-2 lb/GWh)............... (7.0E-2 lb/GWh)............... (1.1E0 lb/GWh)................ (4.1E0 lb/GWh)............... (2.0E-1 lb/GWh).
Selenium, Se...................... 5.0E0 lb/TBtu................. 2.2E+1 lb/TBtu................ 3.3E0 lb/TBtu................. 9.8E0 lb/TBtu................ 1.2E0 lb/TBtu.
(6.0E-2 lb/GWh)............... (3.0E-1 lb/GWh)............... (4.0E-2 lb/GWh)............... (2.0E-1 lb/GWh).............. (2.0E-2 lb/GWh).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NA = Not applicable.
\a\ Includes Hg.
Table 6--Alternate Emission Limitations for New Coal- and Oil-Fired EGUs
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Liquid oil, continental, lb/ Liquid oil, non-continental,
Subcategory/Pollutant Coal-fired EGUs IGCC \a\ GWh lb/GWh Solid oil- derived
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
SO2............................... 4.0E-1 lb/MWh................. 4.0E-1 lb/MWh................. NA............................ NA........................... 4.0E-1 lb/MWh
Total non-mercury metals.......... 6.0E-2 lb/GWh................. 4.0E-1 lb/GWh................. 2.0E-4 lb/MWh \b\............. 7.0E-3 lb/MWh \b\............ 6.0E-1 lb/GWh
Antimony, Sb...................... 8.0E-3 lb/GWh................. 2.0E-2 lb/GWh................. 1.0E-2........................ 8.0E-3....................... 8.0E-3 lb/GWh
Arsenic, As....................... 3.0E-3 lb/GWh................. 2.0E-2 lb/GWh................. 3.0E-3........................ 6.0E-2....................... 3.0E-3 lb/GWh
Beryllium, Be..................... 6.0E-4 lb/GWh................. 1.0E-3 lb/GWh................. 5.0E-4........................ 2.0E-3....................... 6.0E-4 lb/GWh
Cadmium, Cd....................... 4.0E-4 lb/GWh................. 2.0E-3 lb/GWh................. 2.0E-4........................ 2.0E-3....................... 7.0E-4 lb/GWh
Chromium, Cr...................... 7.0E-3 lb/GWh................. 4.0E-2 lb/GWh................. 2.0E-2........................ 2.0E-2....................... 6.0E-3 lb/GWh
Cobalt, Co........................ 2.0E-3 lb/GWh................. 4.0E-3 lb/GWh................. 3.0E-2........................ 3.0E-1....................... 2.0E-3 lb/GWh
Lead, Pb.......................... 2.0E-3 lb/GWh................. 9.0E-3 lb/GWh................. 8.0E-3........................ 3.0E-2....................... 2.0E-2 lb/GWh
Mercury, Hg....................... NA............................ NA............................ 1.0E-4........................ 4.0E-4....................... 2.0E-3 lb/GWh
Manganese, Mn..................... 4.0E-3 lb/GWh................. 2.0E-2 lb/GWh................. 2.0E-2........................ 1.0E-1....................... 7.0E-3 lb/GWh
[[Page 9369]]
Nickel, Ni........................ 4.0E-2 lb/GWh................. 7.0E-2 lb/GWh................. 9.0E-2........................ 4.1E0........................ 4.0E-2 lb/GWh
Selenium, Se...................... 6.0E-3 lb/GWh................. 3.0E-1 lb/GWh................. 2.0E-2........................ 2.0E-2....................... 6.0E-3 lb/GWh
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NA = Not applicable.
\a\ Based on best-performing similar source.
\b\ Includes Hg.
As noted elsewhere in this preamble, we are finalizing a
requirement to use filterable PM as a surrogate for the non-mercury
metallic HAP and HCl as a surrogate for the acid gas HAP for all
subcategories of coal-fired EGUs and for the solid oil derived fuel-
fired EGUs. For all liquid oil-fired EGUs, we are finalizing a
requirement to use filterable PM as a surrogate for the total metallic
HAP, and we are finalizing HCl and HF limits.
In addition, we are finalizing alternative standards for certain
HAP for some subcategories. The alternative pollutants and
subcategories are as follows: (1) SO2 as a surrogate to HCl
for all subcategories with add-on FGD systems (except liquid oil-fired
subcategories as there were no existing units from which to base an
alternate SO2 limit); (2) individual non-mercury metallic
HAP as an alternate to filterable PM for all subcategories (except that
it includes Hg for liquid oil-fired subcategories); and (3) total non-
mercury metallic HAP as an alternate to filterable PM for all
subcategories (except that it includes Hg for liquid oil-fired
subcategories). These alternative standards are discussed elsewhere in
this preamble.
We are finalizing a beyond-the-floor standard for Hg only for all
existing coal-fired units designed for low rank virgin coal based on
the use of activated carbon injection (ACI) for Hg control, as
described elsewhere in this preamble. The EPA has determined that this
beyond-the-floor level is achievable after considering the relevant CAA
section 112(d)(2) provisions.
As noted elsewhere in this preamble, we are also finalizing a
compliance assurance option that would allow you to monitor liquid oil
fuel moisture to demonstrate that fuel moisture content is no greater
than 1.0 percent. Provided that demonstration is made, you will not
have to conduct additional testing and monitoring to demonstrate
compliance with the HCl and HF emission limits for units in both liquid
oil subcategories (i.e., continental and non-continental).
Pursuant to CAA section 112(h), we are finalizing a work practice
standard for organic HAP, including emissions of dioxins and furans,
for all subcategories of EGUs. The work practice standard being
finalized requires the implementation of periodic burner tune-up
procedures described elsewhere in this preamble. We are finalizing work
practice standards because the significant majority of data for
measured organic HAP emissions from EGUs are below the detection levels
of the EPA test methods, even when long duration (around 8 hour) test
runs are considered. As such, we consider it impracticable to measure
emissions from these units. As discussed at proposal, we believe the
inaccuracy of a majority of measurements, coupled with the extended
sampling times used, allow a work practice standard under CAA section
112(h) to apply to these HAP.\306\ We believe that a work practice
standard will lead to a better environmental outcome than would be
obtained through a requirement to measure a pollutant for which results
may or may not be obtained. We believe that the work practice standard
will result in actions being taken that will reduce emissions of these
HAP.
---------------------------------------------------------------------------
\306\ We would also note that the EPA, as a part of the
Industrial Boiler MACT reconsideration proposal that was signed on
December 2, 2011, is proposing to establish work practice standards
for control of dioxins and furans from industrial boilers.
---------------------------------------------------------------------------
In addition, as discussed below, we are creating a subcategory for
limited use liquid oil-fired electric utility steam generating unit
with an annual capacity factor of less than 8 percent of its maximum or
nameplate heat input and we are establishing work practice standards
applicable to such units pursuant to CAA section 112(h).
We are finalizing that new or existing EGUs are ``coal-fired'' if
they combust coal more than 10 percent of the average annual heat input
during any 3 consecutive calendar years or for more than 15 percent of
the annual heat input during any one calendar year and meet the final
definition of ``fossil fuel-fired.'' We are finalizing that an EGU is
considered to be in the coal-fired ``unit designed for coal greater
than or equal to 8,300 Btu/lb'' subcategory if the EGU: (1) meets the
final definitions of ``fossil fuel-fired'' and ``coal-fired electric
utility steam generating unit;'' and (2) is not a coal-fired EGU in the
``unit designed for low rank virgin coal'' subcategory.
We are finalizing that the EGU is considered to be in the ``unit
designed for low rank virgin coal'' subcategory if the EGU: (1) meets
the final definitions of ``fossil fuel-fired'' and ``coal-fired
electric utility steam generating unit;'' and (2) is designed to burn
and is burning nonagglomerating virgin coal having a calorific value
(moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300
Btu/lb) and that is constructed and operates at or near the mine that
produces such coal.\307\
---------------------------------------------------------------------------
\307\ ASTM Method D388-05, ``Standard Classification of Coals by
Rank'' (incorporated by reference, see Sec. 63.14).
---------------------------------------------------------------------------
We are finalizing that the EGU is considered to be an IGCC unit if
the EGU: (1) Combusts a synthetic gas derived from gasified coal or
solid oil-derived fuel (e.g., petroleum coke, pet coke), (2) meets the
final definition of ``fossil fuel-fired,'' and (3) is classified as an
IGCC unit. We are not subcategorizing IGCC EGUs based on the source of
the syngas used (e.g., coal, petroleum coke). Based on information
available to the Agency, although the fuel characteristics of coal and
petcoke are quite different, the syngas products from both feedstocks
have similar HAP content and similar HAP emissions characteristics that
can be controlled in a similar manner.\308\
---------------------------------------------------------------------------
\308\ U.S. Department of Energy, Wabash River Coal Gaification
Repowering Project. Project Performance Summary; Clean Coal
Technology Demonstration Program. DOE/FE-0448. July 2002. EPA-HQ-
OAR-2009-0234-2933.
---------------------------------------------------------------------------
We are finalizing that the EGU is considered to be in the
``Continental liquid oil-fired'' subcategory if (1) meets the final
definitions of ``oil-fired electric utility steam generating unit'' and
``fossil fuel-fired;'' and (2) is located in the continental United
States (U.S.).
We are finalizing that the EGU is considered to be ``Non-
continental liquid oil-fired'' subcategory if (1) meets the final
definitions of ``oil-fired electric utility steam generating unit'' and
[[Page 9370]]
``fossil fuel-fired;'' and (2) is located outside continental U.S.
We are finalizing that the EGU is considered to be ``solid oil-
derived fuel-fired'' if (1) the EGU is not a coal-fired EGU and burns
solid oil-derived fuel (e.g., petroleum coke, pet coke); and (2) meets
the final definitions of ``oil-fired electric utility steam generating
unit'' and ``fossil fuel-fired.''
We are finalizing that the EGU is considered to be a ``limited-use
liquid oil-fired'' if (1) the EGU meets the final definitions of ``oil-
fired electric utility steam generating unit'' and ``fossil fuel-
fired;'' and (2) has an annual capacity factor of less than 8 percent
of its maximum or nameplate heat input, whichever is greater, averaged
over a 24-month block contiguous period commencing.
E. What are the requirements during periods of startup, shutdown, and
malfunction?
As discussed below in section VI.E., for startup and shutdown, the
requirements have changed since proposal. For periods of startup and
shutdown, the EPA is finalizing work practice standards in lieu of
numeric emission limits. Numeric emission limits apply for all other
periods for all pollutants, except organic HAP. For malfunctions, the
EPA is finalizing an affirmative defense for exceedances of the
numerical emission limits that are caused by malfunctions.
F. What are the testing and initial compliance requirements?
We are requiring that you, as an owner or operator of a new or
existing coal- or oil-fired EGU, must conduct performance tests to
demonstrate compliance with all applicable emission limits. For units
using certified continuous emissions monitoring systems (CEMS) that
directly measure the regulated pollutant under final 40 CFR part 63,
subpart UUUUU (e.g., Hg CEMS, HCl CEMS, HF CEMS, SO2 CEMS
(where an SO2 limit applies as the alternative equivalent
standard)), or sorbent trap monitoring systems, the initial performance
test consists of all valid data recorded with the certified monitoring
system in the first 30 boiler operating days of data collected with the
certified monitoring system prior to the initial compliance
demonstration date specified in Sec. 63.10005. A source may also elect
to use a PM CEMS to demonstrate compliance with the filterable PM
emission limit. If this option is selected, then the same provisions as
noted above for other CEMS will apply. (Note that EPA anticipates that
the PM monitoring device that may most often will be used is a PM
continuous parameter monitoring system (CPMS) in conjunction with an
operating limit, as more fully described below.) For units and
pollutants not being monitored via CEMS, the owner or operator of an
affected unit must perform the initial performance testing in
accordance with established EPA reference test methods or the voluntary
consensus standard methods incorporated by reference. You, as the owner
or operator of an affected unit, must conduct the following compliance
tests where applicable:
(1) For coal-fired units, IGCC units, and solid oil-derived fuel-
fired units, if you elect to comply with the filterable PM emission
limit, you must conduct filterable PM emissions testing using EPA
Method 5 from Appendix A to part 60 of chapter 40 to determine initial
compliance. Alternatively, if you elect to comply with the total non-
mercury HAP metals emission limit or the individual non-mercury HAP
metals emissions limits, you must conduct HAP metals testing using EPA
Method 29 from Appendix A to part 60 of chapter 40. Note for this rule
that the filter temperature for each Method 5 or 29 emissions test must
be maintained at 160[deg] 14 [deg]C (320 [deg] 25 [deg]F), and the material in Method 29 impingers must be
analyzed for metals content. Whenever metals testing is performed with
Method 29, you must report the front half and back half analytical
fractions separately.
(2) For coal-fired, IGCC, and solid oil-derived fuel-fired units,
you must use a Hg CEMS or a sorbent trap monitoring system for both
initial compliance and continuous compliance using the continuous Hg
monitoring provisions of Appendix A to 40 CFR part 63, subpart UUUUU,
except where the low emitting EGU (LEE) requirements apply (see below).
The initial performance test consists of all valid data recorded with
the certified Hg monitoring system in the 30 boiler operating days of
data collected with the certified monitoring system by the initial
compliance demonstration date specified in Sec. 63.10005.
(3) For coal-fired and solid oil-derived fuel-fired units and new
or reconstructed IGCC units that employ FGD technology and elect to
meet the alternative SO2 limit in place of the HCl limit,
you need not conduct an initial stack test for HCl or SO2.
Instead, the 30 boiler operating days of data collected with the
certified SO2 CEMS by the initial compliance demonstration
date specified in Sec. 63.10005 are used to determine initial
compliance, and the SO2 CEMS is used thereafter to
demonstrate continuous compliance. If you instead opt to meet the HCl
limit and use an HCl CEMS for compliance, you need not conduct an
initial stack test for HCl. Instead, the 30 boiler operating days of
data collected with the certified HCl CEMS by the initial compliance
demonstration date specified in Sec. 63.10005 are used to determine
initial compliance. For units not using the SO2 or HCl CEMS
options, you must conduct an initial stack test for HCl using EPA
Method 26, 26A, or 320 from Appendix A to part 60 of chapter 40. You
may use EPA Method 26 or 320 or ASTM Method D6348-03 (Reapproved 2010)
with additional quality assurance if no entrained water droplets exist
in the exhaust gas, but you must use Method 26A if entrained water
droplets exist in the exhaust gas.
(4) For liquid oil-fired units, you must conduct initial
performance testing as follows. If you elect to meet the filterable PM
limit instead of the non-mercury metals limit (total or individual),
then use Method 5 with the filter material maintained at 160[deg]
14[deg]C (320[deg] 25[deg]F). Alternatively,
you may use a PM CEMS as discussed elsewhere in this preamble. If you
elect to meet either the total or individual HAP metals limit, you will
use Method 29 for all non-mercury HAP metals. For Hg, conduct emissions
testing using EPA Method 29 or 30B from Appendix A to part 60 of
chapter 40, or ASTM Method D6784-02 (Reapproved 2008). For acid gases,
conduct HCl and HF testing using EPA Method 26A, 320, or 26; or you may
elect to comply by using an HCl CEMS and/or an HF CEMS; or under
certain conditions you may choose to demonstrate compliance by
measuring fuel moisture to demonstrate that moisture content is no
greater than 1.0 percent. You must measure daily if fuel is delivered
continuously or per shipment if fuel is delivered on a batch basis, or
you may use a fuel moisture content certification provided by your fuel
supplier. If you use a CEMS, then use the 30 boiler operating days of
data collected with the certified monitoring system by the initial
compliance demonstration date specified in Sec. 63.10005 to determine
initial compliance.
(5) For the required performance stack tests, if you are
demonstrating compliance with a heat-input based standard, you must
conduct concurrent O2 or carbon dioxide (CO2)
emission testing using EPA Method 3A or 3B from appendix A to part 60
of chapter 40 or ANSI/ASME PTC 19.10-1981 and then use an appropriate
equation, selected from among Equations 19-1
[[Page 9371]]
through 19-9 in EPA Method 19 from appendix A to part 60 of chapter 40,
to convert measured pollutant concentrations to lb/MMBtu values.
Multiply the lb/MMBtu value by one million to get the lb/TBtu value
(where applicable). If you choose to meet an electrical output-based
emissions limit, you must also collect concurrent stack gas flow rate
and electrical production data.
(6) For an existing unit that you believe will qualify as LEE for
Hg, you must conduct an initial Method 30B test over 30 days and follow
the calculation procedures in the final rule to document a potential to
emit less than 10 percent of the applicable Hg emissions limit or less
than 29 pounds of Hg per year. If your unit qualifies as a LEE for Hg,
you must conduct subsequent performance tests on an annual basis to
demonstrate that the unit continues to qualify. For all other
pollutants, you must conduct the initial compliance test, and then all
other required tests over a 3-year period, and in all such tests, your
emission results must be less than 50 percent of the applicable
emission limit. If you qualify as a LEE on that basis, you must conduct
subsequent performance tests every 3 years to demonstrate that the unit
continues to qualify.
(7) You may use results from tests conducted no earlier than 12
months before the compliance date of this rule as the initial
performance test for an applicable pollutant, provided that:
a. You certify and keep records demonstrating that no significant
changes have occurred,
b. Tests were conducted using methods allowed in this rule in
accordance with Sec. 63.10007 and Table 5,
c. You have records of all parameters needed to convert results to
units of the standard for the entire period, and
d. For a CEMS-based performance test, you have all the required
data for the entire 30-boiler operating day rolling average period.
Operating Limit for PM CEMS
Under the final rule, you may elect to comply continuously with an
operating limit, established during the initial performance test, to
demonstrate continuous compliance with the filterable PM, total non-
mercury HAP metals, or individual non-mercury HAP metals limit. You
will use a PM CPMS to monitor compliance with the operating limit. The
PM CPMS operating principle must be based on in-stack or extractive
light scatter, light scintillation, beta attenuation, or mass
accumulation detection of the exhaust gas or representative exhaust gas
sample. The reportable measurement output from the PM CPMS may be
expressed as milliamps, stack concentration, or other raw data signal.
Meeting the operating limit serves as your demonstration of continuous
compliance with the filterable PM, total non-mercury HAP metals, or
individual non-mercury HAP metals limit. As mentioned earlier, if you
use this method to demonstrate continuous compliance, you must install
a PM CPMS and establish the operating limit during the initial
compliance test for filterable PM, total non-mercury HAP metals, or
individual non-mercury HAP metals. As noted below, when you use this
operating limit, you can reduce stack testing frequency to demonstrate
ongoing compliance. You may also opt to install and operate a PM CEMS
certified in accordance with Performance Specification 11 and Procedure
2 of 40 CFR part 60, Appendices B and F, respectively. If you elect to
use this option, then the requirements for quarterly testing with
Method 5, or annual testing and use of a PM CPMS, are no longer
applicable.
Dioxins/Furans and Non-Dioxin/Furan Organic HAP
For dioxins and furans and non-dioxin/furan organic HAP, you must
submit documentation that you have conducted a combustion process tune-
up, a thorough equipment inspection, and an optimization to minimize
generation of CO and NOX, all meeting the requirements of
this final rule. The work practice standard involves maintaining and
inspecting the burners and associated combustion controls, tuning the
specific burner type to optimize combustion, obtaining and recording CO
and NOX values before and after burner adjustments, keeping
records of activity and measurements, and submitting a report for each
tune-up conducted. You must collect CO and NOX data and may
use portable analyzers (which include handheld or similar devices) to
monitor and verify the results. The specific details are addressed in
40 CFR 63.10021 of the final rule.
This same work practice standard also applies in place of any
emission limits for Hg, non-mercury metals HAP, acid gas HAP, dioxins
and furans, and non-dioxin/furan organic HAP from a limited-use, liquid
oil-fired EGU (i.e., a unit that has an annual capacity factor on oil
of less than 8 percent of its maximum or nameplate heat input,
whichever is greater). The EPA established this subcategory in response
to comments and a further analysis of the units within this subcategory
in the ICR database. For these units, EPA believes that the required
work practice standards are appropriate and consistent with the
requirement of CAA section 112(h).
G. What are the continuous compliance requirements?
To demonstrate continuous compliance with the emission limitations,
the final rule includes the following requirements:
(1) Use of CEMS. Where a CEMS or a sorbent trap monitoring system
is used for demonstrating initial compliance, you also must use the
CEMS or sorbent trap monitoring system on a continuous basis to
demonstrate ongoing compliance with the numerical emission limits. CEMS
or sorbent trap monitoring system data are not used to determine
compliance with the work practice standards applicable during periods
of startup and shutdown, but sources that install a CEMS or a sorbent
trap monitoring system to demonstrate compliance with the numerical
emission limits must operate the system at all times, as EPA intends to
evaluate the continuous monitoring data from start-up and shutdown
periods as discussed below. You must calculate a rolling average for
each successive 30-boiler operating day rolling average period. All
valid data collected during each successive period will be used to
demonstrate compliance, except for data collected during periods of
startup and shutdown; during those periods, the owner or operator must
meet work practice requirements instead of the numerical emission
limits. There is no numerical minimum data availability required to
constitute a valid 30-boiler operating day rolling average; however,
you must monitor at all times that the process is in operation
(including during startups and shutdowns, although emissions during
these periods are not included in the 30-boiler operating day average).
You must operate, maintain, and quality-assure the CEMS or sorbent trap
monitoring systems in accordance with the provisions in 40 CFR 63.10010
and Appendix A and B of the final rule (for Hg, HCl, and HF CEMS), in
accordance with Performance Specification 11 in Appendix B to 40 CFR
part 60 and Procedure 2 in Appendix F to part 60 (for PM CEMS used for
direct compliance), or in accordance with 40 CFR part 75 (for
SO2 CEMS, and certain ancillary monitors such as a diluent
or moisture monitor).
For each unit using HCl, HF, SO2, PM, or Hg CEMS or a
sorbent trap monitoring system for continuous compliance, you must
install, certify, maintain, operate and quality-assure the
[[Page 9372]]
additional CEMS (e.g., CEMS that measure O2 or
CO2 concentration, stack gas flow rate, and, if default
moisture values are not used, moisture content) needed to convert
pollutant concentrations to units of the emission standards or
operating limits. Where appropriate, you must certify and quality-
assure these additional CEMS according to 40 CFR part 75.
For HCl and HF CEMS, the EPA is adding monitoring provisions as
Appendix B to 40 CFR part 63, subpart UUUUU. Appendix A references
performance specification (PS) 15 of Appendix B to 40 CFR part 60 for
Fourier Transform Infrared (FTIR) CEMS for procedures to certify and
conduct ongoing quality assurance on these FTIR CEMS. In addition, we
expect to publish a PS specific to HCl CEMS in the near future (prior
to the compliance date of this rule). In the meantime, you may petition
the Administrator under the procedure given in 40 CFR 63.7(f) for an
alternative approach to compliance monitoring or testing for HCl or any
other regulated pollutant.
When using a sorbent trap monitoring system, you may use each pair
of sorbent traps to collect Hg samples for no more than 15 boiler
operating days. Under the general duty to monitor at all times, you
must replace traps in a timely manner to ensure that Hg emissions are
sampled continuously.
For Hg monitoring, the EPA is adding Hg monitoring provisions as
Appendix A to 40 CFR part 63, subpart UUUUU, and requiring use of these
provisions to document continuous compliance with the rule for coal-
fired, IGCC, and solid oil derived-fired units that cannot qualify as
LEEs. Appendix A consolidates all Hg monitoring provisions.
Today's rule provides two basic Hg continuous monitoring options:
Hg CEMS and sorbent trap monitoring systems. Appendix A requires
initial certification and periodic quality assurance (QA) testing of
the Hg CEMS and sorbent trap monitoring systems. The certification
tests required for the Hg CEMS are a 7-day calibration error test; a
linearity check, using NIST-traceable elemental Hg standards; a 3-level
system integrity check (similar to a linearity check), using NIST-
traceable oxidized Hg standards; a cycle time test; and a relative
accuracy test audit (RATA). Table A-1 of Appendix A summarizes the
performance specifications for the required certification tests. For
ongoing QA of the Hg CEMS, Appendix A requires daily calibrations,
weekly single-point system integrity checks, quarterly linearity checks
(or 3-level system integrity checks), and annual RATAs. Table A-2 in
Appendix A summarizes these ongoing QA test requirements and the
applicable performance criteria for Hg CEMS, which are consistent with
those published in support of CAMR and are, thus, familiar to the
industry.
For sorbent trap monitoring systems, a RATA is required for initial
certification, and annual RATAs are required for ongoing QA. The
performance specification for these RATAs is the same as for the RATAs
of the Hg CEMS. Bias adjustment of the measured Hg concentration data
is not required. For day-to-day operation of the sorbent trap system,
Appendix A requires you to follow the procedures and QA/QC criteria in
PS 12B in Appendix B to 40 CFR part 60. PS 12B is nearly identical to
the Appendix K to 40 CFR part 75, published in support of CAMR and with
which the industry is familiar. The 40 CFR part 75 concepts of:
a. Determining the due dates for certain QA tests on the basis of
``QA operating quarters'' and
b. Grace periods for certain QA tests apply to both Hg CEMS and
sorbent trap monitoring systems. Mercury concentrations measured by Hg
CEMS or sorbent trap systems are used together with hourly flow rate,
diluent gas, moisture, and electrical load data, to express the Hg
emissions in units of the rule, on an hourly basis (i.e., lb/TBtu or
lb/GWh). Section 6 of Appendix A provides the necessary equations for
these unit conversions.
For HCl and HF CEMS, the EPA is adding monitoring provisions as
Appendix B to 40 CFR part 63, Subpart UUUUU. Appendix A references
performance specification (PS) 15 of Appendix B to 40 CFR part 60 for
Fourier Transform Infrared (FTIR) CEMS for procedures to certify and
conduct ongoing quality assurance on these FTIR CEMS. In addition, we
expect to promulgate a generic PS specific to HCl CEMS prior to the
compliance date of this rule. In the meantime, you may petition the
Administrator under the procedure given in 40 CFR 63.7(f) for an
alternative approach to compliance monitoring or testing for HCl or any
other regulated pollutant.
(2) Use of stack tests. If you demonstrate initial compliance on
the basis of a stack test, you must demonstrate continuous compliance
by conducting periodic stack tests on a quarterly basis. This includes
filterable PM (or non-mercury HAP metals) and HCl from coal-fired and
solid oil-derived fuel-fired EGUs, and filterable PM (or HAP metals)
and HCl and HF from liquid oil-fired EGUs with the following
exceptions:
a. If you use a PM CPMS and associated operating limit, you may
conduct the applicable Method 5 or Method 29 test once annually rather
than quarterly, in which case you must re-establish the operating limit
during each performance test. A PM CPMS does not need to meet the
requirements for a PM CEMS under PS 11. The final rule includes basic
quality checks that the PM CPMS must meet and a requirement for you to
develop and follow a site-specific monitoring plan to be approved by
the delegated authority. You must demonstrate compliance with the
operating limit by using all valid hourly data collected during each
successive 30-boiler operating day period rolled daily. The 30-boiler
operating day rolling average is calculated by all of the valid hourly
average PM CPMS output values collected for the 30 boiler operating
days (excluding hours of startup and shutdown; see section V.E. of this
preamble).
b. If you combust liquid fuels and if your fuel moisture content is
no greater than 1.0 percent, you may demonstrate ongoing compliance
with HCl and HF emissions limits by:
i. Measuring fuel moisture content of each shipment of fuel if your
fuel arrives on a batch basis;
ii. Measuring fuel moisture content daily if your fuel arrives on a
continuous basis; or
iii. Obtaining and maintaining a fuel moisture certification from
your fuel supplier.
Should the moisture in your liquid fuel be more than 1.0 percent,
you must
i. Conduct HCl and HF emissions testing quarterly and establish
site-specific monitoring to demonstrate continued acid gas control
performance between periodic tests, or
ii. Use an HCl CEMS and/or HF CEMS.
c. If your existing unit qualifies as an LEE for Hg, you must
conduct another 30-day Method 30B performance test on your unit once
per year to reestablish that the unit continues to qualify as a LEE for
Hg. If the results of the LEE test show that the unit exceeds 10
percent of the emissions limit or exceeds the potential to emit 29
pounds of Hg per year, you will lose LEE status for the unit. You can
regain LEE status for that unit if every required performance test for
a 3-year period shows that emissions from the unit did not exceed the
LEE limit. If LEE status is lost for a solid fuel unit, you must
commence quarterly performance testing until you install,
[[Page 9373]]
certify, and operate a Hg CEMS or a sorbent trap monitoring system, and
you must complete the installation and certification within 6 months of
losing LEE status; for a liquid fuel unit, you must commence quarterly
performance testing.
d. If a liquid oil-fired EGU has an annual capacity factor on oil
of less than 8 percent of its maximum or nameplate heat input,
whichever is greater, you must demonstrate continuous compliance with
the applicable work practice standard by conducting at least once every
36 calendar months (48 calendar months if a neural network is employed)
a combustion process tune-up, a thorough equipment inspection, and an
optimization to minimize generation of CO and NOX, all
meeting the requirements of this final rule. You must maintain and
inspect the burners and associated combustion controls, tuning the
specific burner type to optimize combustion, obtaining and recording CO
and NOX values before and after burner adjustments, keeping
records of activity and measurements, and submitting a report for each
tune-up conducted. You must collect CO and NOX data using
portable analyzers (which typically include handheld or similar
devices). Specific details are addressed in 40 CFR 63.10021 of the
final rule. In addition, you must record boiler operating hours, by
fuel type, in each calendar quarter.
e. The rule allows a grant of LEE status to existing units with
test results that show a history of low, non-mercury emissions. As
mentioned earlier, LEE status reduces testing frequency for units.
After a 3-year period during which every emissions test for a specific
pollutant shows emissions no greater than 50 percent of the emissions
limit, you may reduce the emissions testing frequency for that specific
non-mercury pollutant to once every 36 months. If any subsequent
emissions test for that pollutant exhibits emissions greater than 50
percent of the emissions limit, you must revert to the original
emissions testing frequency until you re-establish a 3-year period of
very low emissions no greater than 50 percent of the standard.
f. For liquid oil-fired units that demonstrate continuous
compliance with quarterly performance tests for HCl and HF emission
limits rather than through use of HCl and HF CEMS, the final rule
requires a site-specific monitoring plan in addition to the quarterly
tests. For these pollutants, there is unlikely to be any existing
underlying monitoring (such as compliance assurance monitoring) that
serves as an additional tool to ensure the source's operations remain
consistent with operating conditions during a recent successful
performance test. The requirement for a site-specific monitoring plan
fills this gap and ensures that in between tests, the source continues
to operate in a manner designed to maintain HCl and HF emissions in
compliance with the emission limits under this rule. The appropriate
parameters to monitor will depend on the compliance strategy employed
by a specific source, and thus EPA is enabling the monitoring approach
to be established on a case-by-case basis. Given the relatively small
number of these units and the other compliance options available, we
anticipate that this approach will apply to a small set of units. The
monitoring plan will identify the parameters monitored, the monitoring
methods, the QA/QC elements that apply, and the data reduction elements
(including appropriate averaging periods, as applicable). See 40 CFR
63.10000(c)(2)(ii).
(3) Work practice standard. For the performance tune-up work
practice requirements, you must demonstrate continuous compliance by
conducting the work practice at least once every 36 calendar months (48
calendar months if a neural network is employed). The work practice
involves maintaining and inspecting the burners and associated
combustion controls, tuning the specific burner type, as applicable, to
optimize combustion, obtaining and recording CO and NOX
values before and after burner adjustments, keeping records of activity
and measurements, and submitting a report for each tune-up conducted. A
combustion tune-up will involve optimizing combustion of the unit
consistent with manufacturer's instruction as applicable, or in
accordance with best combustion engineering practice for that burner
type.
H. What are the notification, recordkeeping and reporting requirements?
All new and existing sources in all subcategories must comply with
certain requirements of the General Provisions (40 CFR part 63, subpart
A), which are identified in Table 9 of this final rule. The General
Provisions include specific requirements for notifications,
recordkeeping, and reporting. You must submit a notification of
compliance status report for each unit, according to the schedule
required by 40 CFR 63.9(h) of the General Provisions, including a
certification of compliance.
Except for units that use CEMS for continuous compliance, under
this rule you must provide semiannual compliance reports, as required
by 40 CFR 63.10(e)(3) of subpart A, that indicate whether a deviation
from any of the requirements in the rule occurred and whether or not
any process changes occurred and compliance certifications were
reevaluated. As discussed below, we are finalizing a requirement to use
the 40 CFR part 75-based Emissions Collection and Monitoring Plan
System (ECMPS) for reporting emissions and related data for units using
CEMS for most pollutants. Also, as discussed below, for the PM CPMS, PM
CEMS, and performance test results, we require you to use EPA's WebFIRE
\309\ database for reporting.
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\309\ WebFIRE is the Internet version of FIRE. The Factor
Information Retrieval (FIRE) Data System is a database management
system containing EPA's recommended emission estimation factors for
criteria and HAP. It includes information about industries and their
emitting processes, the chemicals emitted, and the emission factors
themselves.
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This rule requires you to keep certain records to demonstrate
compliance with each emission limit and work practice standard. The
General Provisions to 40 CFR part 63 specify these recordkeeping
requirements (see Table 9 to this subpart). Among other specific
records, you must keep the following:
(1) All reports and notifications submitted to comply with this
rule.
(2) Continuous monitoring data as required in this rule.
(3) Each instance in which you did not meet an emission limit, work
practice requirement, operating limit, or other compliance obligation
(i.e., deviations from this rule).
(4) Daily hours of operation by each unit.
(5) As part of the general duty to keep all monitoring data, fuel
moisture content of liquid fuel, if you elect to demonstrate compliance
using that information.
(6) A copy of the results of all performance tests, monitor
certifications, performance evaluations, or other compliance
demonstrations conducted to demonstrate initial or continuous
compliance with this rule.
(7) A copy of your site-specific performance evaluation test plans
developed for this rule as specified in 40 CFR 63.8(e), if applicable.
(8) A copy of your acid gas control system parameter monitoring
plan under 40 CFR 63.10000(c)(2)(ii).
You also must submit the following additional notifications:
(1) Notifications required by the General Provisions.
(2) Initial Notification no later than 120 calendar days after you
become subject to this subpart.
[[Page 9374]]
(3) Notification of Intent to conduct performance tests and/or
compliance demonstration at least 60 calendar days before the
performance test and/or compliance demonstration is scheduled.
(4) Notification of Compliance Status 60 calendar days following
completion of the performance test and/or compliance demonstration.
Electronic reporting is becoming a common element of modern life
(as evidenced by electronic banking and income tax filing), and the EPA
is beginning to require electronic submittal of environmental data.
Electronic reporting is already common in environmental data collection
and many media offices at EPA are reducing reporting burden for the
regulated community by embracing electronic reporting systems as an
alternative to paper-based reporting.
One of the major benefits of reporting electronically is
standardization, to the extent possible, of the data reporting formats
that provides more certainty to users of what data are required in
specific reports. For example, electronic reporting software allows for
more efficient data submittal and the software's validation mechanism
helps industry users submit fewer incomplete reports. This alone saves
industry report processing resources and reduces transaction times.
Standardization also allows for development of efficient methods to
compile and store much of the documentation required to be reported by
this rule.
Use of Electronic Reporting System
We are requiring that you submit certain reports electronically. In
addition to supporting regulation development, control strategy
development, and other air pollution control activities, having an
electronic database populated with these reports will save industry,
state, local, tribal agencies, the public, and the EPA significant
time, money, and effort while also improving the transparency and
quality of emission inventories and, as a result, air quality
regulations.
The reports to be submitted electronically include all performance
test reports, notification of compliance status reports, compliance,
and continuous monitoring data summaries specified in 40 CFR 63.10031
of this rule. Performance tests are required to be conducted as
described in 40 CFR 63.7 of the General Provisions. The data that must
be submitted as the performance test report are also described in 40
CFR 63.7. These data must be submitted (except in limited cases) to
EPA's WebFIRE database by using the electronic reporting tool (ERT) and
the Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through EPA's Central Data Exchange (CDX), as described below.
The data requirements for the notification of compliance status and
compliance reports are described in detail in the regulatory text (40
CFR 63.10031) of this rule, but they essentially mirror the
requirements in 40 CFR 63.6 of the General Provisions. These reports
will also be submitted to WebFIRE using an electronic form found in
CEDRI and through the CDX as described below. As required in 40 CFR
63.10031(f)(2) of the final rule, the continuous monitoring summaries
are required to be submitted quarterly. The quarterly reports must
include all of the calculated 30-boiler operating day rolling average
values derived from the PM CPMS. These reports will also be submitted
to WebFIRE using an electronic form found in CEDRI and through the CDX,
as described below. This same approach will apply if a source elects to
use a PM CEMS or receives approval to use a HAP metals CEMS as an
alternative monitoring method.
The availability of electronic reporting for sources subject to the
Subpart UUUUU will provide efficiency, improved services, better
accessibility of information, and more transparency and accountability.
Additionally, submittal of these required reports electronically
provides significant benefits for regulatory agencies, industry, and
the public. The compliance data electronic reporting system (CEDRI and
CDX) is being developed such that once a facility's initial data entry
into the system is established and a report is generated, subsequent
data submittal will only consist of electronic updates to existing
information in the system. Such a system will effectively reduce the
burden associated with submittal of data and reports by reducing the
time, costs, and effort required to submit and update hard copies of
documentation. State, local, and tribal air pollution control agencies
will also benefit from having access to the more streamlined and
accurate electronic data submitted to the EPA. Electronic reporting
will allow for an electronic review process rather than a manual data
assessment, making review and evaluation of the source-provided data
and calculations easier and more efficient. Electronic reporting will
also benefit the public by generating a more transparent review process
and increasing the ease and efficiency of data accessibility.
Furthermore, electronic reporting will reduce the burden on the
regulated community by reducing the effort involved in data collection
and reporting activities. In the future, we anticipate there will be
fewer and less substantial data collection requests in conjunction with
prospective required residual risk assessments or technology reviews.
Electronic reporting will substantially reduce this burden, because the
EPA will already have these data available and consolidated in an
electronic database named WebFIRE. We anticipate that using electronic
reporting for the required reports will result in an overall reduction
in reporting costs; for a discussion of the economic and cost impacts
of electronic reporting, see section XII.D. of this preamble.
Another benefit of electronic data submittal is that these data
will greatly improve the overall quality of existing and new emissions
factors by supplementing the pool of emissions test data for
establishing emissions factors and by ensuring that the factors are
more representative of current industry operational procedures. A
common complaint heard from industry and regulators is that emission
factors are outdated or not representative of a particular source
category. With timely receipt and incorporation of data from most
performance tests, the EPA will be able to ensure that emission
factors, when updated, represent the most current range of operational
practices.
Data entry of these electronic reports will be through the CEDRI
that is accessed through EPA's CDX (www.epa.gov/cdx). Data submitted
electronically through CEDRI will be stored in CDX as an official copy
of record.
Once you have accessed CEDRI, you will select the applicable
subpart for the report that you are submitting. You will then select
the report being submitted, enter the data into the form, and click on
the submit button. In some cases, such as with submittal of a
notification of compliance status report, you will select the report
icon, enter basic facility information, and then upload the report in a
specified file format.
In addition, we believe that there will be value in allowing other
reporting forms to be developed and used in cases where the other
reporting forms can provide an alternate electronic file consistent
with EPA's form output format. This approach has been used successfully
to provide alternatives for other electronic forms (e.g., income tax
submittal).
In cases where performance test data are to be submitted to the
EPA, you must enter the performance test data
[[Page 9375]]
and information into the electronic reporting tool (ERT) which can be
accessed at https://www.epa.gov/ttn/chief/ert/. In CEDRI, the
user must then upload the ERT file. CEDRI submits a copy of the ERT
project data file directly to WebFIRE where the data are made
available. Where performance test reports are submitted, WebFIRE
notifies the appropriate state, local, or tribal agency contact that an
ERT project data file was received from the source.
Submitting performance test data electronically to the EPA will
apply only to those performance tests conducted using test methods that
will be supported by the ERT. The ERT contains a specific electronic
data entry form for most of the commonly used EPA reference methods. A
listing of the pollutants and test methods supported by the ERT is
available at the ERT Web site listed above.
I. Submission of Emissions Test Results to the EPA
The EPA has determined that harmonization of the monitoring and
reporting requirements of this final rule with 40 CFR part 75 is
appropriate, where the affected industry already has a well-defined
system for continuous monitoring and reporting of emissions under that
part. Therefore, the Agency is finalizing monitoring and reporting
requirements for most CEMS that are consistent with 40 CFR part 75. You
must report CEMS data (other than PM CEMS data or data from alternative
monitoring subject to site-specific approval such as a HAP metals CEMS)
to the EPA electronically, on a quarterly basis, using the ECMPS.
The ECMPS process divides electronic data into three categories,
the first of which is monitoring plan data. You must maintain the
electronic monitoring plan separately and can update it at any time if
necessary. The monitoring plan documents the characteristics of the
affected units (e.g., unit type, rated heat input capacity, etc.) and
the monitoring methodology used for each parameter (e.g., CEMS). The
monitoring plan also describes the type of monitoring equipment used
(hardware and software components), includes analyzer span and range
settings, and provides other useful information. Nearly all coal-fired
EGUs are subject to the ARP and thus have established electronic
monitoring plans that describe their required SO2, flow
rate, CO2 or O2, and, in some cases, moisture
monitoring systems. The EPA will adjust the ECMPS monitoring plan
format to accommodate this same type of information for Hg, HCl, and HF
CEMS, with the addition of a few codes for the new parameters.
The second type of data collected through ECMPS is certification
and QA test data. These data include data from linearity checks, RATAs,
cycle time tests, 7-day calibration error tests, and a number of other
QA tests that are required to validate the emissions data. You may
submit the results of these tests to the EPA as soon as you obtain the
results, with one notable exception. Daily calibration error tests are
not treated as individual QA tests, due to the large number of records
generated each quarter. Rather, these tests must be included in the
quarterly electronic reports, along with the hourly emissions data. The
ECMPS system is set up to receive and process certification and QA data
from SO2, CO2, O2, flow rate, and
moisture monitoring systems that are installed, certified, maintained,
operated, and quality-assured according to 40 CFR part 75. EGUs
routinely submit these data to the EPA under the ARP and other
emissions trading programs.
To accommodate the certification and QA tests for Hg CEMS, other
CEMS, and sorbent trap monitoring systems, the structure and
functionality of ECMPS needs relatively few changes, because most of
the tests are the same as those required for other gas monitors. For
reporting Hg, HCl, SO2, and HF CEMS data under this rule, we
are disabling ECMPS' 40 CFR part 75 bias test (which is required for
certain types of monitors under the EPA's SO2 and
NOX emissions trading programs). The bias adjustment of the
data from these monitors is unnecessary for compliance with the rule.
The third type of data collected through ECMPS is the hourly
emissions data, which, as previously noted, is reported on a quarterly
schedule. You must submit reports within 30 days after the end of each
calendar quarter. The emissions data format requires hourly reporting
of all measured and calculated emissions values, in a standardized
electronic format. You must report direct measurements made with CEMS,
such as gas concentrations, in a Monitor Hourly Value (MHV) record. A
typical MHV record for gas concentration includes data fields for:
(1) The parameter monitored (e.g., SO2);
(2) The unadjusted and bias-adjusted hourly concentration values
(note that if bias adjustment is not required, only the unadjusted
hourly value is reported);
(3) The source of the data, i.e., a code indicating either that
each reported hourly concentration is a quality assured value from a
primary or backup monitor, or that quality-assured data were not
obtained for the hour; and
(4) The percent monitor availability (PMA), which is updated hour-
by-hour. This generic record structure could easily accommodate hourly
average measurements from CEMS used under this rule.
The ECMPS reporting structure is quite flexible, which makes it
useful for assessing compliance with various emission limits. The
Derived Hourly Value (DHV) record allows calculations of a wide variety
of quantities from the reported hourly emissions data. For instance, if
an emission limit is expressed in units of lb/MMBtu, the DHV record can
be used to report hourly pollutant concentration values in these units
of measure, since the lb/MMBtu values can be derived from the hourly
pollutant and diluent gas (CO2 or O2)
concentrations reported in the MHV records. The ECMPS can also
accommodate multiple DHV records for a given hour in which more than
one derived value is required to be reported. The system will support
reporting hourly data in the units of the emission standards (e.g., lb/
MMBtu, lb/TBtu, lb/GWh, etc.) when hourly Hg concentration data are
reported through ECMPS using the DHV record, in conjunction with the
appropriate equations and auxiliary information such as heat input and
electrical load (all of which are reported hourly in the emissions
reports).
One change in this rule from standard 40 CFR part 75 emissions data
reporting is elimination of the requirement to provide substitute data
calculations within ECMPS. The ARP and other emissions trading programs
that report emissions data to the EPA using 40 CFR part 75 require
provision of a complete data record. Emissions data are required to be
reported for every unit operating hour. When CEMS are out of service,
substitute data must be reported to fill in the gaps. However, for the
purposes of compliance with a NESHAP, reporting substitute data during
monitor outages is not necessary, as quantification of total mass
emissions is not the focus of the rule. Hours when a monitoring system
is out of service would be counted as hours of monitor down-time and
may be a deviation from the monitoring requirements of this rule unless
the rule provides an exception, as it does for routine quality control
and maintenance activities.
In contrast to the CEMS-related data that would be submitted
through ECMPS, you must submit reports of performance tests and PM CPMS
data to EPA's WebFIRE database by using CEDRI that is accessed through
EPA's
[[Page 9376]]
CDX (www.epa.gov/cdx). You must submit performance test data in the
file format generated through use of EPA's ERT (see https://www.epa.gov/ttn/chief/ert/) within 60 days of performance test
completion. Electronic data submittal requirements are described in
section V.H. of this preamble.
Other notifications and reports not currently accepted by the
electronic reporting system will be submitted in hardcopy form at this
time.
VI. Summary of Significant Changes Since Proposal
The previous section described the requirements that EPA is
finalizing in this rule. This section will discuss in greater detail
the key changes EPA is making from the proposed. These changes result
from EPA's review of the additional data and information provided to us
and our consideration of the many substantive and thoughtful comments
submitted on the proposal. While our approach and methodology to
establishing the standards remain the same, the changes make the final
rule more flexible and cost-effective, reduce reliability concerns and
improve clarity, while fully preserving, or improving, the public
health and environmental protection required by the CAA.
A. Applicability
Since proposal, the EPA has made certain changes to the
applicability provisions of the final rule to provide clarity. These
changes do not change the universe of sources subject to the rule.
The EPA is revising a number of the proposed definitions and adding
a definition for ``natural gas-fired electric utility steam generating
unit'' in the final rule to provide clarity to the regulated community
concerning the standards applicable to coal- and oil-fired EGUs.
In the proposed rule, the EPA defined ``[e]lectric utility steam
generating unit'' consistent with the CAA section 112(a)(8) definition:
A fossil fuel-fired combustion unit of more than 25 megawatts
electric (MWe) that serves a generator that produces electricity for
sale. A fossil fuel-fired unit that cogenerates steam and
electricity and supplies more than one-third of its potential
electric output capacity and more than 25 MWe output to any utility
power distribution system for sale is considered an electric utility
steam generating unit.
40 CFR 63.10042.
We also indicated how we would determine whether units were coal-
fired or oil-fired fired EGUs: ``If an EGU burns coal (either as a
primary fuel or as a supplementary fuel), or any combination of coal
with another fuel (except solid waste as noted below), the unit is
considered to be coal fired under this proposed rule. If a unit is not
a coal-fired unit and burns only oil, or oil in combination with
another fuel other than coal (except as noted below), the unit is
considered to be oil fired under this proposed rule.'' 76 FR 25020.
We proposed a definition for the term ``fossil fuel-fired'' because
that term was not defined in the statute and we wanted to clarify the
level of fossil fuel combustion necessary to satisfy the CAA section
112(a)(8) definition of EGU. The definition focused on coal and oil
combustion because the EPA was only regulating coal- and oil-fired EGUs
in this final rule. The proposed definition contained two primary
elements: (1) the unit must be capable of combusting sufficient amounts
of coal or oil to generate the equivalent of 25 megawatts electrical
output; and (2) the unit must have fired coal or oil for more than 10.0
percent of the average annual heat input during the previous 3 calendar
years or for more than 15.0 percent of the annual heat input during any
one of those calendar years. 76 FR 25025. We further stated that for a
unit to be ``capable of combusting'' coal or oil the unit must have a
permit that authorized the combustion of coal or oil and also have the
appropriate fuel handling facilities on-site. Id.
As explained in the proposed rule, natural gas-fired EGUs were not
included in the December 2000 listing so such units that otherwise met
the CAA section 112(a)(8) definition of EGU because of natural gas
combustion are not subject to the final rule. In the proposed rule, we
stated that an EGU that ``combusts natural gas exclusively or natural
gas in combination with another fuel where the natural gas constitutes
90 percent or more of the average annual heat input during the previous
3 calendar years or 85.0 percent or more of the annual heat input
during any one of those calendar years'' was not subject to the rule.
Id. The references to 90 percent natural gas combustion over 3 years
and 85 percent natural gas combustion in any one year were included to
align with the definitions of ``fossil fuel-fired'' so that it would be
clear that units combusting primarily natural gas would not be
considered coal-fired, oil-fired, or IGCC EGUs if they burned 10
percent or less of coal, oil, or synthetic gas derived from coal or
solid oil over 3 years or 15 percent or less of such fuels in any one
year. We did not intend to suggest that to be considered a fossil fuel-
fired EGU a natural gas-fired unit that is not a coal-fired or oil-
fired EGU would have to combust natural gas that exceeded the 10
percent/15 percent thresholds set forth in the proposed rule. In fact,
in 40 CFR 63.9983 of the proposed rule, we stated that ``[a]ny EGU that
is not a coal- or oil-fired EGU and combusts natural gas more than 10.0
percent of the average annual heat input during the previous 3 calendar
years or for more than 15.0 percent of the annual heat input during any
one of those calendar years'' is not subject to this subpart.
We further explained that the percentages included in the
definition of ``fossil fuel-fired'' would prevent units that primarily
combusted fuels other than fossil fuels from being subjected to the
final rule:
Units that do not meet the definition of fossil-fuel fired
would, in most cases, be considered IB units subject to one of the
Boiler NESHAP. Thus, for example, a biomass-fired EGU, regardless of
size, that utilizes fossil fuels for startup and flame stabilization
purposes only (i.e., less than or equal to 250 MMBtu/hr and used
less than 10.0 percent of the average annual heat input during the
previous 3 calendar years or less than 15.0 percent of the annual
heat input during any one of those calendar years) is not considered
to be a fossil fuel-fired EGU under this proposed rule. The EPA has
based its threshold value on the definition of ``oil-fired'' in the
ARP found at 40 CFR 72.2. As EPA has no data on such use for (e.g.)
biomass co-fired EGUs because their use has not yet become
commonplace, we believe this definition also accounts for the use of
fossil fuels for flame stabilization use without inappropriately
subjecting such units to this proposed rule. Id.
Thus, in the proposed rule, we intended to create thresholds to
determine when a unit is fossil fuel-fired and for which fossil fuel
the unit is fossil fuel-fired. We intended to include a unit combusting
more than the defined amount of coal in one of the coal-fired EGU
subcategories. If a unit is not coal-fired and it is combusting more
than the defined amount of oil, we intended to include the unit in one
of the oil-fired EGU subcategories. We also intended to make clear that
EGUs that are neither coal-fired nor oil-fired but combust more than
the defined amount of natural gas are natural gas-fired EGUs not
subject to the final standards. However, the definitions, as proposed,
were not sufficiently descriptive.
For example, we included a definition for ``coal-fired electric
utility steam generating unit'' that did not include the requirement
that the unit must combust coal for at least 10 percent of the heat
input over 3 years or 15 percent of the heat input in any one year.
Instead, in the proposed rule we indicated that a unit was coal-fired
if it burned coal in any amount. We did not intend to
[[Page 9377]]
define a unit as coal-fired if it burned coal that accounted for 10
percent or less over 3 years or 15 percent of less in any one year, as
that would be inconsistent with the definition of fossil fuel-fired and
the definitions for the oil-fired EGU subcategories. Under the proposed
rule construct, a unit that combusts mostly biomass and less than 10
percent coal over 3 years would not be a coal-fired EGU because it
would not meet the ``fossil fuel-fired'' definition. But a unit burning
mostly petroleum coke and less than 10 percent coal over 3 years might
be considered a coal-fired EGU because it would meet the definition of
``fossil fuel-fired'' and be burning some coal, even though that level
of coal combustion alone would not be sufficient to make the unit
``fossil fuel-fired'' for coal. That result is at odds with our intent.
The same would hold true for an EGU that combusts mostly natural gas
and less than 10 percent synthetic gas derived from coal over a 3-year
period. Our proposal preamble makes clear that we did not intend this
result because we specifically stated that units burning 90 percent or
more natural gas over a 3-year period would be considered natural-gas
fired EGUs. 76 FR 25025.
In addition, we proposed to define ``[u]nit designed to burn solid
oil fuel subcategory'' to include any EGU that burned a solid fuel
derived from oil for more than 10.0 percent of the average annual heat
input during the previous 3 calendar years or for more than 15.0
percent of the annual heat input during any one of those calendar
years, either alone or in combination with other fuels. We also
included the 10 percent/15 percent thresholds in the definition for the
liquid oil subcategory, but, as stated above, we did not include the
thresholds in the definition of ``coal-fired'' EGU. Therefore, there
would be some confusion for a source that blended coal with solid oil
derived fuel (e.g., petroleum coke). For example, the owner or operator
of an EGU that burned sufficient solid oil-derived fuel that accounted
for 80 percent of the heat input in a given year and the remainder of
the fuel was coal would not be sure which standard applied because the
definitions in the proposed rule were internally inconsistent.
For these reasons, we are revising the definitions for ``coal-fired
electric utility steam generating unit,'' ``integrated gasification
combined cycle electric utility steam generating unit,'' and ``oil-
fired electric utility steam generating unit,'' and we are adding a
definition of ``natural-gas fired electric utility steam generating
unit'' as set out in 40 CFR 63.10042.
In addition to these changes, we are revising the definition of
``fossil fuel-fired'' based on comments. We are revising the definition
to remove the heat input equivalent of 25 MW because commenters noted
that the equivalency used (taken from 40 CFR part 60, subpart Da) could
not be applied consistently because of differing boiler efficiencies.
Commenters noted that owners/operators were familiar with the use of
the ``MW'' term for the boilers and boilers include nameplate
capacities that are readily identifiable.
We are also including a revision to the definition so that the
fossil fuel combustion thresholds of 10 percent over 3 consecutive
years and 15 percent in one year are evaluated after the applicable
compliance date of the final rule on a rolling basis. Commenters
correctly noted that some existing coal- and oil-fired EGUs will
convert their units to alternative fuels (e.g., natural gas or biomass)
and if the definition were finalized as proposed such units could be
improperly subjected to the final standards.
The new definition is set out in 40 CFR 63.10042.
For clarity, we are also removing the definition of ``[u]nit
designed to burn liquid oil fuel subcategory,'' revising the definition
of ``[u]nit designed to burn solid oil fuel subcategory,'' adding
definitions for the continental and non-continental liquid oil-fired
EGU subcategories, and adding a definition of a limited-use liquid oil-
fired EGU as set out in 40 CFR 63.10042.
In the proposed rule, we stated that we believed EGUs may at times
not meet the definition of an EGU subject to this subpart. For example,
we explained that there may be some cogeneration units that are
determined to be covered under the Boiler NESHAP. Such unit(s) may make
a decision to increase the proportion of production output being
supplied to the electric utility grid, thus causing the unit(s) to meet
the EGU cogeneration criteria (i.e., greater than one-third of its
potential output capacity and greater than 25 MW). In the preamble to
the proposed rule, we indicated that a unit subject to one of the
Boiler NESHAP that increases its electricity output and meets the
definition of an EGU would be subject to the EGU NESHAP for the 6-month
period after the unit meets the EGU definition.\310\ 76 FR 25026.
Assuming the EGU did not meet the definition of an EGU following that
initial occurrence, at the end of the 6-month period it would revert
back to being subject to the Boiler NESHAP, or other applicable
standard. We solicited comment on the extent to which situations like
this might occur, how the EPA should address situations where units
change applicability, and whether we should include provisions similar
to those included in the final CISWI (40 CFR 60.2145) to address such
situations. Id.
---------------------------------------------------------------------------
\310\ Although we clearly stated the intent to require sources
to comply for 6 months after meeting the definition of an EGU, we
inadvertently failed to include the provision in the proposed rule.
---------------------------------------------------------------------------
Several commenters asked the Agency to include provisions in the
final rule that would address situations like the ones described in the
preamble to the proposed rule. Because applicability to the final rule
is based in part on the statutory definition of an EGU is CAA section
112(a)(8), similar to the situation with units combusting solid waste
under CAA section 129(g)(1) (e.g., CISWI Rule), we are adopting
provisions in the final rule that are based on the fuel switching
provisions of the final CISWI Rule (See Final CISWI Rule, 40 CFR
60.2145). For example, a cogeneration unit that did not historically
provide more than one third of its potential electrical output capacity
to a power distribution system could change its output and provide more
than 25 megawatts electrical output to any power distribution system
for sale. Such units would be subject to MATS. If the cogeneration unit
later reduced its output such that it no longer met the definition of
an EGU, that source would nevertheless remain subject to MATS for at
least 6 months from the date that the unit first qualified as an EGU.
In addition, we are finalizing a provision whereby you may opt to
remain subject to the provisions of this final rule, unless you combust
solid waste, in which case you are a solid waste incineration unit
subject to standards under CAA section 129 (e.g., 40 CFR part 60,
subpart CCCC (New Source Performance Standards (NSPS) for Commercial
and Industrial Solid Waste Incineration Units), or subpart DDDD
(Emissions Guidelines (EG) for Existing Commercial and Industrial Solid
Waste Incineration Units)). We believe the provision to opt to remain
subject to this final rule will ameliorate conditions where EGUs may
potentially move between NESHAP on a relatively frequent basis.
Notwithstanding the provisions of this final rule, an EGU that starts
combusting solid waste is subject to standards under CAA section 129,
and the unit remains subject to those standards until the unit no
longer meets the definition of a solid waste incineration unit
consistent with the provisions of the applicable CAA section 129
standards.
[[Page 9378]]
The changes to the definitions described above provide clarity to
sources, permitting agencies, and the public about the applicability of
the rule and help ensure that sources are appropriately covered by the
regulation.
B. Subcategories
In this final rule, the EPA is adding subcategories for limited-use
oil-fired units and non-continental oil-fired units and revising the
definitions for the coal-fired EGU subcategories.
The proposed rule subcategorized EGUs burning coal into two
subcategories: EGUs designed for coal >=8,300 Btu/lb and EGUs designed
for virgin coal <8,300 Btu/lb (low rank virgin coal). We received a
number of comments indicating that the definition of the low rank
virgin coal subcategory was technically deficient.
Under CAA section 112(d)(1), the Administrator has the discretion
to ``* * * distinguish among classes, types, and sizes of sources
within a category or subcategory in establishing * * *'' standards. The
EPA maintains that, normally, any basis for subcategorization (i.e.,
class, type, or size) must be related to an effect on HAP emissions
that is due to the difference in class, type, or size of the units. See
76 FR 25036-25037. The EPA believes it is not reasonable to exercise
our discretion without such a difference because if sources can achieve
the same level of emissions reductions notwithstanding a difference in
class, type, or size, the purposes of CAA section 112 are better served
by requiring a similar level of control for all such units in the
category or subcategory. See Lignite Energy Council v. EPA, 198 F. 3d
930, 933 (D.C. Cir. 1999) (``EPA is not required by law to
subcategorize--section 111[b][2] merely states that `the Administrator
may distinguish among classes, types, and sizes within categories of
new sources''' (emphasis original)); see also CAA section 112(d)(1)
(containing almost identical language to CAA section 111, CAA section
112(d)(1) provides that ``the Administrator may distinguish among
classes, types, and sizes of sources within a category or subcategory
in establishing [ ] standards * * *''). Even if we determine that
emissions characteristics are different for units that differ in class,
type, or size, the Agency may still decline to subcategorize if there
are compelling policy justifications that suggest subcategorization is
not appropriate. Id.
When developing the proposed rule, we examined the EGUs in the top
performing 12 percent of sources for Hg emissions. We determined that:
There were no EGUs designed to burn a nonagglomerating virgin
coal having a calorific value (moist, mineral matter-free basis) of
19,305 kJ/kg (8,300 Btu/lb) or less in an EGU with a height-to-depth
ratio of 3.82 or greater among the top performing 12 percent of
sources for Hg emissions, indicating a difference in the emissions
for this HAP from these types of units. The boiler of a coal-fired
EGU designed to burn coal with that heat value is bigger than a
boiler designed to burn coals with higher heat values to account for
the larger volume of coal that must be combusted to generate the
desired level of electricity. Because the emissions of Hg are
different between these two subcategories, we are proposing to
establish different Hg emission limits for the two coal-fired
subcategories. For all other HAP from these two subcategories of
coal-fired units, the data did not show any difference in the level
of the HAP emissions and, therefore, we have determined that it is
not reasonable to establish separate emissions limits for the other
HAP. 76 FR 25036-67.
Based on this determination, we proposed to establish two
subcategories with separate Hg limits. Comments on the proposed rule
indicate that we correctly identified the EGUs that should be included
in each subcategory, but the comments also demonstrated that we made
certain incorrect conclusions that require us to revise the definitions
of our coal-fired EGU subcategories. The revised definitions ensure
that the EGUs we identified at proposal as having different Hg
emissions remain in one subcategory.
As stated above, we believed at proposal that the boiler size was
the cause of the different Hg emissions characteristics that led us to
propose subcategorization, but many commenters indicated that it was
not the boiler size but the fact that the EGUs burned a
nonagglomerating virgin coal having a calorific value (moist, mineral
matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) (low rank
virgin coal) that causes the disparity in Hg emissions. Several
commenters indicated that their EGUs were designed to burn and burned
low rank virgin coal but the units did not meet the height-to-depth
ratio that EPA proposed. For example, the height-to-depth ratio of
certain EGUs in this subcategory is in fact 3.5, not 3.82. Further,
there are other EGUs in this subcategory that are circulating fluidized
bed (CFB) combustion units which do not meet the height-to-depth ratio
parameters in the proposed rule, nor are they anything like the
pulverized coal (PC) EGUs we initially identified as having the 3.82
height-to-depth ratio.
In addition to the comments concerning EGUs firing this coal, we
received comments from at least two commenters indicating that the EPA
should clarify in which subcategory a unit belongs when it does not
burn low rank virgin coal but is designed to combust low rank virgin
coal and has a height-to-depth ratio of greater than 3.82. Commenters
also indicated that CFB units that are burning coal-refuse \311\ or
other nonagglomerating virgin coal having a calorific value (moist,
mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or greater
are ``designed to burn'' any type of coal. Owners of CFB units that are
not firing low rank virgin coal asked which subcategory they belong to
based on their ability to burn any type of coal (including low rank
virgin coal) without modification. These commenters also indicated that
some coal refuse that is combusted has a heating value less than 8,300
Btu/lb but is not ``virgin coal.'' It was unclear to which subcategory
they belonged since the proposed rule did not in fact require the unit
to burn any specific coal, instead only requiring the unit be
``designed'' to burn lower Btu coal.
---------------------------------------------------------------------------
\311\ It is our understanding that no unit combusts coal-refuse
from nonagglomerating virgin coal having a calorific value (moist,
mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb).
---------------------------------------------------------------------------
Based on the comments received, we reevaluated the subcategory
definitions because we were concerned that the definitions we proposed
would improperly categorize a number of the EGUs in both subcategories.
We concluded that we should not maintain the proposed definition for
``[u]nits designed for coal <8,300 Btu/lb'' and exclude the CFB units
and PC EGUs with a height-to-depth ratio less than 3.82 that combusted
low rank virgin coal.
We were equally concerned that the subcategory definitions not be
revised in a manner that would move EGUs that we believed the data show
could comply with a more stringent standard into a subcategory with a
less stringent standard because, aside from the type of EGUs we
identified, all other classes, types, and sizes of EGUs were
represented among the top performing 12 percent for Hg in the >=8,300
Btu/lb subcategory. We were particularly concerned about the CFB units
because other CFB units are well represented among the best performing
EGUs for Hg in the >=8,300 Btu/lb subcategory, but the CFB units
burning low rank virgin coal are not achieving the same levels of Hg
emissions control. Including the best performing CFB units from the
other subcategory in the low rank virgin coal subcategory would likely
lead to a Hg standard as stringent as the standard for
[[Page 9379]]
EGUs in the >=8,300 Btu/lb subcategory because the CFB units from the
other subcategory would be used to establish the floor. We believe that
result would be inconsistent with the intent of the proposed rule. We
were also concerned about the information that some EGUs that fired low
rank virgin coal had a height-to-depth ratio of 3.5, not 3.82, and that
some EGUs that fired other ranks of coal had a height-to-depth ratio
greater than 3.82. For these reasons, we did not revise the definition
to include CFB units and PC EGUs with a height-to-depth ratio greater
than 3.5.
After fully considering the available information, including the
comments received, we have concluded that it is appropriate to continue
to base the subcategory definitions, at least in part, on whether the
EGUs were designed to burn and, in fact, did burn low rank-virgin coal,
but that it is not appropriate to continue to use the height-to-depth
ratio criteria because that approach would potentially exclude EGUs we
identified as having different Hg emission characteristics and include
EGUs that did not have different emissions characteristics. We
recognize that some commenters have taken the position that it is
unlawful to subcategorize based on factors such as fuel type but
nothing in the statute prohibits such an approach and the case law
supports this approach to the extent courts have considered
subcategorization based on such factors. See Sierra Club v. Costle, 657
F. 2d 298, 318-19 (D.C. Cir. 1981) (differing pollutant content of
input material can justify a different standard based on
subcategorization authority to ``distinguish among classes, types and
sizes within categories of new sources''). Furthermore, we believe had
Congress intended to prohibit the EPA from subcategorizing based on an
EGU being designed to use and using a certain material input (e.g.,
fuel) it would have clearly stated such intent in the CAA. However, we
believe the Agency could decline to exercise its discretion to
subcategorize even if the potential result would be the prohibition of
the use of some materials if the circumstances warranted. We note that
even if we did not subcategorize on the final basis selected, the Hg
emissions standard of 1.2E0 lb/Tbtu for the ``unit designed for coal
>=8,300 Btu/lb'' would remain the same.
We considered basing the subcategory solely on an EGU being
designed to burn and burning low rank virgin coal. We decided not to do
so because we were concerned that such a definition would allow sources
to potentially meet the definition by combusting very small amounts of
low rank virgin coal. For example, an EGU on the east coast (or any
other region) that was not designed to burn and did not routinely burn
low rank virgin coal could import one truck full of low rank virgin
coal and burn a very small quantity of it periodically to meet the
subcategory definition. To avoid creating this potential loophole, we
considered other characteristics that would distinguish EGUs combusting
low rank virgin coal.
We determined that these EGUs are universally constructed ``at or
near'' a mine containing low rank virgin coal because it is not cost-
effective to transport large quantities of such fuel long distances.
Furthermore, we believe that this subcategory of EGUs are almost always
built at a mine and limited transportation of the coal is only required
as the mine face moves over the course of time. Many such EGUs
construct dedicated rail lines, private roads, or conveyor systems to
transport the coal to the EGU as the mine face moves. We obtained
information from data acquired to develop the CSAPR indicating that the
longest distance any EGU firing low rank virgin coal transports that
coal is 40 miles. We believe that this distance is near the outer
limits for the transport of such coal, but, even for those EGUs, the
EGUs were constructed closer to a now idle mine or closer to the
working face of a mine that has now expanded away from the EGU site.
For these reasons, we are including a requirement that the unit be
constructed and operated at or near a mine containing the low rank
virgin coal it burns.
We are revising the coal-fired EGU subcategory definitions as set
out in 40 CFR 63.10042.
We believe the revised subcategory definitions are reasonable for
all the reasons set forth above. The revised definitions maintain the
EGUs we identified as having different Hg emissions characteristics in
one subcategory and the definitions prevent other EGUs that are not
firing low rank virgin coal from being required to comply only with the
less stringent Hg emission standard.
As discussed in response to comments, we do not believe that
additional subcategorization of other coal-fired EGUs is reasonable or
appropriate. All other coal-fired EGUs that are not designed to burn
and are burning low rank virgin coal are represented among the best
performing sources for Hg, such that no argument exists to support that
the Hg emissions from those EGUs are different. In any case, even if
emissions are somewhat different as some commenters suggest, we would
decline to exercise our discretion because the data demonstrate that
the best performing EGUs designed to burn and burning all other ranks
of coal are able to achieve the MACT level of control using currently
available controls and other HAP emission reduction mechanisms (e.g.,
coal washing) for the >=8,300 Btu/lb subcategory.
A second issue related to subcategorization concerns non-
continental liquid oil-fired EGUs. At proposal, the EPA did not have
sufficient emissions data from non-continental liquid oil-fired EGUs
upon which to base a subcategory and took comment on the issue. The
data have since been provided in response to the ICR and we received
comments suggesting that a non-continental subcategory is appropriate
based on the location of such units, the limited availability of
alternative fuel sources, and the fact that the emissions
characteristics of such units are distinct from continental liquid oil-
fired EGUs. The EPA has evaluated the data and comments and we agree
that a subcategory is warranted based for the reasons suggested by the
commenters. Therefore, the Agency is finalizing the liquid oil-fired
EGU subcategories of ``continental'' and ``non-continental.''
Lastly, the EPA did not have sufficient information on limited-use
liquid oil-fired EGUs upon which to base a subcategory at proposal
because some sources required to test under the ICR did not submit the
data until after proposal. We took comment on whether a limited-use
subcategory was warranted. Commenters indicated that their units were a
different class and type of units because many of them were only called
to service to address reliability issues associated with, for example,
natural gas curtailments. The commenters further indicated that their
units are different because of the generally infrequent use and the
sporadic, and at times frequent, start-up and shutdown periods (e.g.,
they are often only required to run for a couple of hours). These
factors would lead to differences in the emissions characteristics for
these units such that a numeric standard based on base load units would
not likely be achievable during the very limited times that these
limited use oil-fired units operate. Based on comments received and our
own analysis, we are finalizing a subcategory for limited-use liquid
oil-fired EGUs as discussed further elsewhere in this preamble.
[[Page 9380]]
C. Emission Limits
The proposed rule included numerical emission limits for PM, Hg,
HCl, HF, SO2, total HAP metals, and individual HAP metals,
depending on the subcategory and specific situation. These proposed
limits resulted from calculations of MACT floors using information and
data available to the Agency prior to proposal, as required by CAA
section 112. Based on information and data received during the comment
period, we have made data and calculation corrections where necessary
and then re-ranked the best performing units in the MACT floor pools.
Based on the new ranking, a limited number of the emission limits in
the final rule have changed from those proposed.
In addition to adjustments to the emission limits themselves, we
are finalizing several other changes to the emission standards that
will simplify and improve compliance for sources without compromising
the toxics reductions achieved. One key change, as discussed elsewhere
in this notice, is that we have changed the surrogate for non-mercury
metallic HAP from total particulate matter (PM) to filterable PM for
coal-fired and solid oil-derived EGUs. This change is based on
information provided in comments and our own conclusion that
measurement of filterable PM provided assurance of equivalent HAP
emissions control. Most of the non-mercury metal HAP, for which PM is a
surrogate, are filterable PM and the one that is not (Se) is well
controlled by the limit on acid gases. Using filterable PM as the
surrogate will allow us to use continuous PM monitoring systems, which
measure filterable (but not total) PM, thereby providing a more
continuous measure of compliance.
For liquid oil-fired EGUs, based on comments received and
corrections made to the data submitted, we have added a filterable PM
limit in the final rule as an alternative equivalent standard for the
total metal-HAP limit in the proposed rule. In addition, as discussed
elsewhere in this notice, we have added measurement of the moisture
content of the oil (with a 1 percent limit) as an alternate compliance
assurance measure for liquid oil-fired EGUs for determining compliance
with the HCl and HF limits. Direct measurement of HCl and HF remains a
compliance demonstration method in the final rule. Finally, as
discussed in section VI.D of this notice, the final work practice
standard consisting of burner tune-ups, much like those required for
organic HAP control, for those limited-use liquid oil-fired EGUs whose
annual capacity factor is less than 8 percent.
D. Work Practice Standards for Organic HAP Emissions
As noted earlier in section V.D., the final rule includes a work
practice standard for organic HAP, including dioxins and furans,
applicable to all EGUs. As noted in section V.D. above, the majority of
emissions of these pollutants are below the detection levels of EPA
test methods and, therefore, are impractical to measure. The work
practice standard, described below, is a practical approach to ensuring
that equipment is maintained and run so as to minimize emissions of
dioxins and furans, and we expect it to be more effective than
establishing a numeric standard that cannot reliably be measured or
monitored. The work practice also applies to the limited-use liquid
oil-fired subcategory included in the final rule.
The work practice involves maintaining and inspecting the burners
and associated combustion controls (as applicable), tuning the specific
burner type to optimize combustion, obtaining and recording CO and
NOX values before and after the burner adjustments, keeping
records of activity and measurements, and submitting a report for each
tune-up conducted. In Table 3 of the final regulation, we have
clarified that this refers to performance tune-ups, not tests, and have
addressed the frequency requirement as discussed in response to
comments about the appropriateness of the 18-month frequency. The
provisions of 40 CFR 63.10006(h)(i) refer to 40 CFR 63.10021(e) for the
specific steps required to be part of the periodic tune-up. We have
also adjusted the language in the final rule to recognize the value of
automated boiler optimization tools such as neural network systems.
Under the final rule, the tune-up must be conducted at each planned
major outage and in no event less frequently than every 36 calendar
months, with an exception that if the unit employs a neural-network
system for combustion optimization during hours of normal unit
operation, the required frequency is a minimum of once every 4 years
(48 calendar months). Initial compliance with the work practice
standard of maintaining burners must occur within 180 days of the
compliance date of the rule. The initial compliance demonstration for
the work practice standard of conducting a tune-up may occur prior to
the compliance date of the rule, but must occur no later than 42 months
(36 months plus 180 days) from the compliance date of the rule or, in
the case of units employing neural network combustion controls, 54
months (48 months plus 180 days). If the tune-up occurs prior to the
compliance date of the rule, you must maintain adequate records to show
that the tune-up met the requirements of this standard.
We have made a number of specific changes to address what to do for
repairs that may require longer term corrective actions, additional
methods for evaluating combustion effectiveness, and clarification on
procedures for recording CO and NOX information. There were
specific comments that opposed the reference to manufacturer
specifications, if available. We retained this language in the final
rule, but note that these specifications apply only to the extent
applicable. Specifically, if manufacturer specifications only address
equipment or conditions that are no longer present given current boiler
operations, then those specifications are not applicable and other
combustion engineering best practice procedures for that burner type
would apply. We have also clarified that portable emission monitoring
equipment may be used to collect the required emissions optimization
data regarding pre- and post-tune-up CO and NOX emission
levels.
E. Requirements During Startup, Shutdown, and Malfunction
We proposed numerical emission standards that would apply at all
times, including during periods of startup, shutdown, and malfunction.
Although at proposal we stated that we were not setting a different
standard for startup and shutdown, we did propose different standards
for startup and shutdown by our inclusion of the default values
described below, which applied only during startup and shutdown.
Specifically, we stated:
To appropriately determine emissions during startup and shutdown
and account for those emissions in assessing compliance with the
proposed emission standards, we propose use of a default diluent
value of 10.0 percent O2 or the corresponding fuel
specific CO2 concentration for calculating emissions in
units of lb/MMBtu or lb/TBtu during startup or shutdown periods. For
calculating emissions in units of lb/MWh or lb/GWh, we propose
source owners use an electrical production rate of 5 percent of
rated capacity during periods of startup or shutdown. We recognize
that there are other approaches for determining emissions during
periods of startup and shutdown, and we request comment on those
approaches. We further solicit comment on the proposed approach
described above and whether the values we are proposing are
appropriate.
[[Page 9381]]
We proposed application of the respective emission limits during
periods of startup and shutdown and use of default values to calculate
the emission limits. The standards that apply at all times other than
startup and shutdown are production-based limits, which is why we
proposed the default values. The default values were meant to account
for the fact that during startup and shutdown events, production (in
this case the generation of electricity) is by definition nonexistent.
Thus, in effect, we proposed a separate standard to apply during
startup and shutdown.
We received a variety of comments on the proposed standards that
would apply during startup and shutdown. Many commenters pointed to the
lack of data in the record concerning emissions that occur during
periods of startup and shutdown. They further asserted that emissions
during these periods can be highly variable in light of the sequence of
events that occurs during the startup and shutdown of an EGU. Although
a number of commenters supported the use of the diluent factor
approach, including the default 5 percent of rated capacity, during
startup/shutdown periods, other commenters questioned the feasibility
of collecting additional data during such periods and had concerns
regarding the reliability of measurements obtained from EGUs during
such periods.
In response to the Agency's ICR to the utility industry, seven
owners or operators indicated that they provided startup and shutdown
data for their EGUs. These data were submitted in response to the
requirement in the ICR to provide all available data from the 5 years
prior to the date the ICR was issued. Of these data, there were almost
no HAP data for startup and shutdown periods and almost all of the data
failed to meet our data quality requirements.\312\ Thus, we do not have
sufficient data on emissions that occur during startup and shutdown on
which to set emission standards. We are therefore establishing work
practice standards rather than numeric emissions standards for periods
of startup and shutdown in the final rule. Before we describe those
work practices, we first address what constitutes startup and shutdown.
---------------------------------------------------------------------------
\312\ In response to the ICR, we also received SO2
CEMS data and the Agency had additional SO2 CEMS data
available through the CAMD ARP database. We are not able to identify
specific periods of start-up and shutdown in either the ICR CEMS
data or the CAMD ARP data, and the ICR respondents do not indicate
that the ICR data includes periods of startup and shutdown. We set
the emission limits for SO2 and HCl using the data
provided to the EPA from the 2010 ICR, not the CAMD data, since
those data were taken concurrently under the same specified
operating conditions using the same fuel. We used the SO2
CEMS data that was submitted in response to the ICR by converting it
to single point data to correlate to the data from units that did
not provide CEMS data from the relevant testing period. The
emissions limits for the NESHAP incorporated variability by applying
the 99 percent UPL to the average emissions developed from the stack
test data and SO2 CEMS data that was converted to stack
test data. Thus, we did not have data on which to establish an
SO2 standard during periods of startup and shutdown and
the numeric standards do not apply to those periods in the final
rule. In contrast, the NSPS for SO2 is applicable during
periods of startup and shutdown since the long term CAMD ARP CEMS
data were used to determine the average performance of the best
demonstrated technology. Those long term data were assumed to
incorporate process variability including that associated with fuel
and process/operational changes and periods of startup and shutdown.
---------------------------------------------------------------------------
Several commenters had an expansive view of what constitutes
startup and shutdown. We disagree with these commenters that asserted
that periods of ``load swings'' should be considered ``startup'' or
``shutdown,'' as they are generally routine, normal operations with
production (i.e., generation of electricity) taking place. We maintain
that the standards as promulgated account for any variability in
emissions that may occur during these periods over a 30-day averaging
period, and commenters have provided no data that cause us to doubt
that determination. We have included definitions of startup and
shutdown in the final rule that are consistent with the definitions in
the proposed rule. At proposal, we defined startup as the setting in
operation of an affected source or portion of an affected source for
any purpose, and shutdown as the cessation of operation of an affected
source or portion of an affected source for any purpose.
Commenters sought more clarity regarding the meaning of these terms
as applied to EGUs, so we are revising the definitions in the final
rule as set out in 40 CFR 63.10042.
These interpretations are tailored for EGUs and are consistent with
the definitions of ``startup'' and ``shutdown'' contained in the 40 CFR
part 63, subpart A General Provisions. We believe these revised
definitions address the comments and are rational based on the fact
that EGUs function to provide electricity primarily for sale to the
grid but also at times for use on-site; therefore, EGUs should be
considered to be operating normally at all times electricity is
generated. We further believe these revised definitions address what
some commenters describe as ``warm'' and ``hot'' startups as long as
the EGU is shutdown (i.e., no fuel fired and no electricity generation)
prior to the ``warm'' or ``hot'' startup period.
As for the work practices, in this final rule, the EPA is requiring
sources to operate using either natural gas or distillate oil for
ignition during startup. The EPA also is requiring sources to vent
emissions to the main stack(s) and operate all control devices
necessary to meet the normal operating standards under this final rule
(with the exception of dry scrubbers and SCRs) when coal, solid oil-
derived fuel, or residual oil is fired in the boiler during startup or
shutdown. It is the responsibility of the operators of EGUs to start
their dry scrubber and SCR systems appropriately to comply with
relevant standards applicable during normal operation.
The EPA carefully considered fuels and potential operational
constraints of air pollution control devices (APCDs) when designing its
work practices for periods of startup and shutdown. The EPA notes that
there is no technical barrier to burning natural gas or distillate oil
for longer portions of startup or shutdown periods, if needed, at a
boiler, and the HAP emission reduction benefits warrant additional
utilization of such fuels until the temperature and stack emissions
pressure is sufficient to engage the APCDs. The EPA is aware that SCR
systems with ammonia injection need to be operated within a prescribed
and relatively narrow temperature window to provide NOX
reductions. Further, the EPA is aware that dry scrubbers also need to
be operated close to flue gas saturation temperature. Because these
devices have specific temperature requirements for proper operation,
the EPA notes in its work practices that it is the responsibility of
the operators of EGUs to start their SCR and dry scrubber systems
appropriately to comply with relevant standards applicable during
normal operation.
Some commenters have asserted that firing of fuel oil during
periods of startup and shutdown constrains operation of PM controls
(ESPs and baghouses) because under cooler conditions, acids and tars
can condense on surfaces in these controls. The commenters assert that
such condensation can cause detrimental impacts on hardware and
operation of these controls, and could cause safety concerns. The EPA
understands that concerns with acidic and tarry deposits are related to
firing of heavy (residual) oil and not distillate oil. Accordingly,
with residual fuel oil firing, site-specific flue gas temperature and
oxygen (O2) concentration thresholds may be applicable to
minimize condensation of acids and tars and thereby minimize any
potential for detrimental impacts on hardware and any safety concerns.
[[Page 9382]]
However, the EPA notes that its work practice requirements provide
flexibility to the operator to take appropriate site-specific remedial
measures, if needed. The EPA further notes that boilers have several
options to prevent detrimental impacts by: (1) Using startup fuels,
natural gas or distillate oil, until appropriate flue gas conditions
have been reached and then fire residual oil; (2) pre-coating the PM
control surfaces \313\ with an alkaline powder (e.g., limestone); (3)
installing chemically resistant bags \314\ in baghouses if applicable;
and (4) using low-sulfur oils. The EPA also notes that currently the
industry has many operational residual oil-fired boilers that are
started up with either natural gas or distillate fuel oil. At these
boilers, the transition from the startup fuel, distillate oil or
natural gas, to residual oil is already being practiced without
unacceptable impacts on APCDs including PM controls, which are operated
to meet applicable opacity limits. Based on this experience and the
options described above, those boilers where residual oil is used for
either a part of the startup period, or as the main fuel, will also be
able to operate their PM controls to meet the work practice
requirements of the rule. Note that coal firing is done at high enough
temperatures that concerns with condensation are not relevant. None of
the commenters have specifically commented on this aspect of coal
firing.
---------------------------------------------------------------------------
\313\ Coal Power, May 1, 2007: https://www.coalpowermag.com/plant_design/Coal-Plant-O-and-M-River-Locks-and-Barges-Are-an-Aging-Workforce-Too 36.html.
\314\ Neundorfer: Lesson r, p.4-7, Table 4-1: https://www.neundorfer.com/FileUploads/CMSFiles/Fabric%20Filter%2OMaterial
[0].pdf.
---------------------------------------------------------------------------
The EPA is not aware of any operational constraints applicable to
operation of wet scrubbers during startup that could cause detrimental
impacts on wet scrubber hardware and safety concerns and none of the
commenters have commented on this aspect of wet scrubber operation.
Finally, the EPA notes that dry sorbent injection (DSI) can be
applied across a very broad temperature range and will be engaged when
residual oil or coal is fired in a boiler to comply with HCl
requirements. Again, no comments have been received on this aspect of
DSI operation.
This final rule requires work practice standards for emissions
during startup and shutdown, and the rule requires sources to measure
and report their emissions at all times, including periods of startup
and shutdown, when continuous monitoring is used to demonstrate
compliance. Data collected under this final rule will provide the EPA
with information to more fully analyze this issue and address it during
the 8-year review established under CAA section 112.
We now address malfunctions. In contrast to the exclusion of
startup and shutdown period emissions from 30-boiler operating day
rolling average emissions, the final rule requires inclusion of
emissions during periods of source or APCD malfunction. We have
concluded that when combined with the availability of an affirmative
defense as described below, this is an appropriate and practical
approach.
As mentioned earlier, periods of startup, normal operations, and
shutdown are all predictable and routine aspects of a source's
operations. However, by contrast, malfunction is defined as a ``sudden,
infrequent, and not reasonably preventable failure of air pollution
control and monitoring equipment, process equipment or a process to
operate in a normal or usual manner * * *'' (40 CFR 63.2). The EPA has
determined that CAA section 112 does not require that emissions that
occur during periods of malfunction be factored into development of CAA
section 112 standards. Under CAA section 112, emissions standards for
new sources must be no less stringent than the level ``achieved'' by
the best controlled similar source and for existing sources generally
must be no less stringent than the average emission limitation
``achieved'' by the best performing 12 percent of sources in the
category. There is nothing in CAA section 112 that directs the Agency
to consider malfunctions in determining the level ``achieved'' by the
best performing or best controlled sources when setting emission
standards. Moreover, while the EPA accounts for variability in setting
emissions standards consistent with the CAA section 112 case law,
nothing in that case law requires the Agency to consider malfunctions
as part of that analysis. Clean Air Act section 112 uses the concept of
``best controlled'' and ``best performing'' unit in defining the level
of stringency that CAA section 112 performance standards must meet.
Applying the concept of ``best controlled'' or ``best performing'' to a
unit that is malfunctioning presents significant difficulties, as
malfunctions are sudden and unexpected events.
Further, accounting for malfunctions would be difficult, if not
impossible, given the myriad different types of malfunctions that can
occur across all sources in the category and given the difficulties
associated with predicting or accounting for the frequency, degree, and
duration of various malfunctions that might occur. As such, the
performance of units that are malfunctioning is not ``reasonably''
foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d 658, 662 (D.C.
Cir. 1999) (The EPA typically has wide latitude in determining the
extent of data-gathering necessary to solve a problem. We generally
defer to an agency's decision to proceed on the basis of imperfect
scientific information, rather than to ``invest the resources to
conduct the perfect study.''). See also, Weyerhaeuser v. Costle, 590
F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of things, no general
limit, individual permit, or even any upset provision can anticipate
all upset situations. After a certain point, the transgression of
regulatory limits caused by `uncontrollable acts of third parties,'
such as strikes, sabotage, operator intoxication or insanity, and a
variety of other eventualities, must be a matter for the administrative
exercise of case-by-case enforcement discretion, not for specification
in advance by regulation.''). In addition, the goal of a best
controlled or best performing source is to operate in such a way as to
avoid malfunctions of the source and accounting for malfunctions could
lead to standards that are significantly less stringent than levels
that are achieved by a well-performing non-malfunctioning source. The
EPA's approach to malfunctions is consistent with CAA section 112, and
we believe it is a reasonable interpretation of the statute. This
approach to malfunctions has been used consistently in CAA section 112
and CAA section 129 rulemaking actions since the D.C. Circuit's
decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008) vacated
the SSM exemption contained in CFR 63.6(f)(1) and 40 CFR 63.6(h)(1).
(See, e.g., National Emission Standards for Hazardous Air Pollutants
From the Portland Cement Manufacturing Industry and Standards of
Performance for Portland Cement Plants, 75 FR 54970 (September 9,
2010); Standards of Performance for New Stationary Sources and Emission
Guidelines for Existing Sources: Sewage Sludge Incineration Units;
Final Rule, 76 FR 15372 (March 21, 2011).
In the event that a source fails to comply with the applicable CAA
section 112(d) standards as a result of a malfunction event, the EPA
would determine an appropriate response based on, among other things,
the good faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses
[[Page 9383]]
to ascertain and rectify excess emissions. The EPA would also consider
whether the source's failure to comply with the CAA section 112(d)
standard was, in fact, ``sudden, infrequent, not reasonably
preventable'' and was not instead ``caused in part by poor maintenance
or careless operation.'' 40 CFR 63.2 (definition of malfunction).
Finally, the EPA recognizes that even equipment that is properly
designed and maintained can sometimes fail and that such failure can
sometimes cause an exceedance of the relevant emission standard. (See,
e.g., State Implementation Plans: Policy Regarding Excessive Emissions
During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on
Excess Emissions During Startup, Shutdown, Maintenance, and
Malfunctions (Feb. 15, 1983)). The EPA is therefore adding to the final
rule an affirmative defense to civil penalties for exceedances of
emission limits that are caused by malfunctions. See 40 CFR 63.10042
(defining ``affirmative defense'' to mean, in the context of an
enforcement proceeding, a response or defense put forward by a
defendant, regarding which the defendant has the burden of proof, and
the merits of which are independently and objectively evaluated in a
judicial or administrative proceeding). We also have added other
regulatory provisions to specify the elements that are necessary to
establish this affirmative defense; the source must prove by a
preponderance of the evidence that it has met all of the elements set
forth in 63.10001. (See 40 CFR 22.24). The criteria ensure that the
affirmative defense is available only where the event that causes an
exceedance of the emission limit meets the narrow definition of
malfunction in 40 CFR 63.2 (i.e., sudden, infrequent, not reasonable
preventable and not caused by poor maintenance and or careless
operation). For example, to assert the affirmative defense
successfully, the source must prove by a preponderance of the evidence
that excess emissions ``[w]ere caused by a sudden, infrequent, and
unavoidable failure of air pollution control and monitoring equipment,
process equipment, or a process to operate in a normal or usual manner
* * *'' The criteria also are designed to ensure that steps are taken
to correct the malfunction, to minimize emissions in accordance with
section 63.10001 and to prevent future malfunctions. For example, the
source must prove by a preponderance of the evidence that ``[r]epairs
were made as expeditiously as possible when the applicable emission
limitations were being exceeded * * *'' and that ``[a]ll possible steps
were taken to minimize the impact of the excess emissions on ambient
air quality, the environment and human health * * *'' In any judicial
or administrative proceeding, the Administrator may challenge the
assertion of the affirmative defense and, if the respondent has not met
its burden of proving all of the requirements in the affirmative
defense, appropriate penalties may be assessed in accordance with CAA
section 113 (see also 40 CFR 22.27).
The EPA is including an affirmative defense in the final rule as we
have in other recent MACT rules so as to balance the tension, inherent
in many types of air regulation, to ensure adequate compliance while
simultaneously recognizing that despite the most diligent of efforts,
emission limits may be exceeded under circumstances beyond the control
of the source. The EPA must establish emission standards that ``limit
the quantity, rate, or concentration of emissions of air pollutants on
a continuous basis.'' 42 U.S.C. 7602(k) (defining ``emission limitation
and emission standard''). See generally Sierra Club v. EPA, 551 F.3d
1019, 1021 (D.C. Cir. 2008). Thus, the EPA is required to ensure that
section 112 emissions limitations are continuous. The affirmative
defense for malfunction events meets this requirement by ensuring that
even where there is a malfunction, the emission limitation is still
enforceable through injunctive relief. While ``continuous''
limitations, on the one hand, are required, there is also case law
indicating that in some situations it is appropriate for the EPA to
account for the practical realities of technology. For example, in
Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the
D.C. Circuit acknowledged that in setting standards under CAA section
111 ``variant provisions'' such as provisions allowing for upsets
during startup, shutdown and equipment malfunction ``appear necessary
to preserve the reasonableness of the standards as a whole and that the
record does not support the `never to be exceeded' standard currently
in force.'' See also, Portland Cement Association v. Ruckelshaus, 486
F.2d 375 (D.C. Cir. 1973). Though intervening case law such as Sierra
Club v. EPA and the CAA 1977 amendments calls into question the
relevance of these cases today, they support the EPA's view that a
system that incorporates some level of flexibility is reasonable. The
affirmative defense simply provides for a defense to civil penalties
for excess emissions that are proven to be beyond the control of the
source. By incorporating an affirmative defense, the EPA has formalized
its approach to upset events. In a Clean Water Act setting, the Ninth
Circuit required this type of formalized approach when regulating
``upsets beyond the control of the permit holder.'' Marathon Oil Co. v.
EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977). But see, Weyerhaeuser Co.
v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an
informal approach is adequate). The affirmative defense provisions give
the EPA the flexibility to ensure both that its emission limitations
are ``continuous'' as required by 42 U.S.C. 7602(k), and account for
unplanned upsets and thus support the reasonableness of the standard as
a whole.
F. Testing and Initial Compliance
We have carefully evaluated the wide-ranging comments on testing,
continuous monitoring, and other provisions regarding initial
compliance demonstrations, and we have made adjustments intended to
help streamline implementation while still ensuring adequate
demonstration of compliance with the emission limits and other
standards established under this final rule. The significant changes
include:
1. No Fuel Analysis Requirements
Apart from an alternative that allows you to analyze fuel moisture
for liquid oil-fired EGUs rather than measuring HCl and HF, the final
rule does not include any of the fuel analysis requirements that were
in the proposed rule, either as part of initial compliance
demonstrations or ongoing compliance demonstrations. In reviewing the
results of the fuel analyses and the expected range of results that
would be received from laboratories conducting the proposed analyses,
we determined that too many results would be returned as ``below
detection level'' and, thus, provide little information to assist with
rule implementation and compliance oversight. Given the costs and
efforts involved, we determined that the proposed fuel analysis
requirements would not be an effective compliance monitoring tool for
this final rule.
2. Clarification of Testing
We have clarified that where options for emission limits apply
(such as filterable PM versus non-mercury HAP metals, or SO2
versus HCl), you need only perform stack testing to demonstrate
compliance with the selected emission limit. For example, if you elect
to meet the individual non-
[[Page 9384]]
mercury HAP metals standards, you must conduct the Method 29 test for
the metals, and you do not have to conduct a Method 5 test for PM.
3. Low Emitting EGU Qualification
We have significantly modified the proposed requirements to qualify
as a LEE unit for a pollutant other than Hg based on an initial
performance test. Under the proposed rule, the operating limit
monitoring provided additional assurance of compliance for a source
qualified for non-mercury LEE status based on an initial compliance
demonstration. Under the final rule, to qualify for LEE status for
pollutants other than Hg, a unit must meet the LEE criteria for a
series of performance tests over a 3-year period to demonstrate that
the unit continues to perform well below the standard for which the
source has obtained LEE status.
G. Continuous Compliance
The most significant changes to the testing and monitoring
requirements involve the procedures for demonstrating continuous
compliance. The proposed rule contained different options involving
CEMS, periodic stack tests, fuel analysis, and various PM and control
device operating limits. The final rule greatly simplifies the
requirements and provides two basic approaches for most situations: use
of continuous monitoring (either CEMS or PM continuous parametric
monitoring system, CPMS) or periodic quarterly testing. The final rule
does not contain the proposed fuel analysis requirements. For periodic
testing, the proposed rule required testing every month or every 2
months. For those EGU owners or operators who choose to use emissions
testing to demonstrate compliance, the final rule requires quarterly
filterable PM or non-mercury metals HAP, whether individual or total
metals, testing for coal- and liquid oil-fired units. The rule requires
quarterly HCl testing for coal-fired units and quarterly HCl and HF
testing, along with site-specific monitoring for liquid oil-fired units
to ensure compliance with the HCl and HF standards. The final rule also
has a separate compliance demonstration for those liquid oil-fired EGUs
that have an annual capacity factor of less than 8 percent (emission
limits do not apply, just the tune-up work practice standard). For
those EGU owners or operators who choose to use emissions testing to
demonstrate compliance, the final rule requires quarterly filterable PM
or non-mercury metals HAP, whether individual or total metals, testing
for coal- and liquid oil- fired units; quarterly HCl testing for coal-
fired units and quarterly HCl and HF testing, along with site-specific
parameter monitoring for liquid oil-fired units to ensure compliance
with the HCl and HF standards.
The continuous monitoring options remain generally intact from the
proposed rule, with relatively minor clarifications concerning
calculation of 30-boiler operating day averages and QA requirements.
The final rule eliminates all operating limits for PM except for
the use of a PM CPMS. For the PM CPMS, the final rule clarifies
procedures for setting this operating limit and how it is distinct from
the PM emission limit. The PM CPMS will not be correlated as a PM CEMS
under PS 11 and will produce data in terms of a signal you define. That
signal could be milliamps, stack concentration, or other output signal
instead of PM emissions in units of the standard. The operating limit
will be set using the highest hourly average obtained from the PM CPMS
during the performance test. Compliance with the limit is based on a
30-boiler operating day rolling average basis. However, the final rule
also does provide for the use of a PM CEMS to determine compliance with
the filterable PM emission limit if the source elects to use this
approach. The EPA believes that some sources may be interested in
adopting this direct approach, and so has included that option in the
final rule. If this approach is selected, the PM CEMS is used as the
direct method of compliance and no additional testing is required other
than tests that are required as part of the QA requirements in PS 11
and Procedure 2. To use this option, the source must elect to meet the
filterable PM standard, and not one of the HAP metals standards.
Apart from the operating limit for site-specific monitoring
associated with liquid oil-fired EGUs, we removed the other operating
limits for control devices based on a review of the comments, after
considering other programs in place to ensure proper operations of
controls at EGUs. Those other programs include compliance assurance
monitoring under part 64, part 70, and New Source Review permit
conditions, and other SIP and NSPS requirements for operating and
maintaining equipment in accordance with good air pollution control
practices. Those requirements, in combination with the CEMS, PM CPMS,
and frequent periodic testing provisions under the final rule, will
enhance the monitoring of continuous compliance with the requirements
of this rule.
Because the EPA is concerned that there will be little or no
monitoring in these underlying applicable requirements for acid gases
at liquid oil-fired EGUs, the final rule requires a site-specific
monitoring plan for those units in this subcategory that demonstrate
compliance with the HCl and HF standards through quarterly performance
tests. With the exception for limited-use liquid oil-fired EGUs and
other monitoring options available (such as fuel moisture monitoring or
HCl/HF CEMS), the EPA believes this provision will apply to few units.
The owner or operator will submit the site-specific plan to identify
appropriate parameters that ensure that the operations of the unit
critical to meeting the HCl/HF emission limits remain consistent with
conditions during performance testing. This will be approved similarly
to an alternative monitoring request. The plan should include the
parameters, monitoring approach, QA/QC elements, and data reduction
(including averaging period) elements. Like the PM CPMS operating
limit, the operating limit for acid gas control devices on liquid oil-
fired EGUs will be set using the highest hourly average obtained during
the HCl and HF performance tests. Compliance with the limit is based on
a 30-boiler operating day rolling average basis.
Finally, we have changed the continuous compliance requirements for
the performance tune-up work practice standard since the proposal. Our
intent was that this work practice standard could be performed in
conjunction with routine maintenance operations at a facility and be a
logical extension of routine best practices for boiler inspection and
optimization. Based on the comments received, we have reduced the
required frequency for this inspection to every 3 years and provided
incentives for neural network combustion management and optimization
practices by providing a longer interval of 4 years between inspections
when such systems are in use at a given EGU.
H. Emissions Averaging
We are finalizing that owners and operators of existing affected
sources may demonstrate compliance by emissions averaging for existing
EGUs that are located at the same facility that are within a single
subcategory and that rely on emissions testing as the compliance
demonstration method. In response to our request for comments on the
suitability of emissions averaging and need for a discount factor, we
received a range of suggestions, including requests for clarification
regarding eligibility, points for and against the need for a discount
factor, and suggestions to ease implementation.
[[Page 9385]]
As we noted at proposal, part of the EPA's general policy of
encouraging the use of flexible compliance approaches where they can be
properly monitored and enforced is to include emissions averaging.
Emissions averaging can provide sources the flexibility to comply in
the least costly manner while still maintaining a regulation that is
workable and enforceable. Emissions averaging would not be applicable
to new affected sources and could only be used between EGUs in the same
subcategory at a particular facility. Also, owners or operators of
existing sources subject to the EGU NSPS (40 CFR part 60, subparts D
and Da) would be required to continue to meet the PM emission standard
of that NSPS regardless of whether or not they are using emissions
averaging (i.e., an EGU subject to 40 CFR part 60, subpart D or Da must
meet its applicable NSPS filterable PM emission limit even if it is
included in a 40 CFR part 63, subpart UUUUU, emissions averaging group
for filterable PM).
Emissions averaging allows owners and operators of a facility that
includes existing EGUs within a subcategory to demonstrate that the
source complies with the proposed emission limits by averaging the
emissions from an individual affected EGU that is emitting above the
proposed emission limits with other affected EGUs at the same facility
that are emitting below the proposed emission limits and that are
within the same subcategory. Although some commenters note that the
MACT limits are low, based on the data available to the Agency, we
believe that dozens of existing EGUs are achieving all of the limits
and, thus, emissions averaging is a possible approach.
The final rule includes an emissions averaging compliance
alternative because emissions averaging \315\ represents an equivalent,
more flexible, and less costly alternative to controlling certain
emission points to MACT levels. We have concluded that averaging in the
proposed rule could be implemented and that it would not lessen the
stringency of the MACT floor limits and would provide flexibility in
compliance, cost and energy savings to owners and operators. We also
recognize that we must ensure that any emissions averaging option can
be implemented and enforced, will be clear to sources, and most
importantly, will be no less stringent than unit-by-unit implementation
of the MACT floor limits.
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\315\ As long as required emission rates are designed to account
for factors such as changes in averaging times.
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In the final rule, the EPA is providing that sources may average
emissions from existing EGUs at the same facility and within the same
subcategory. Further, for Hg emissions only from existing EGUs within
the same subcategory, such EGUs in an emissions averaging plan may use
an alternate compliance approach consisting of a 90-boiler operating
day rolling average emission limit of 1.0 lb/TBtu or 1.1E-2 lb/GWh.
In the memo entitled ``The Impact of Emission Averaging Time on the
Stringency of an Emission Standard'' in the docket, we have illustrated
why a longer-term average results in a lower limit. In essence, longer-
term averages allow particularly high (or low) measurements to be
averaged with many more measurements closer to the mean. This results
in the highest averages from a longer-term averaging period (e.g., 90
days) being lower than the highest averages in a shorter term averaging
period (e.g., 30 days).
We have illustrated this concept by taking Hg CEMS data and
calculating rolling 30-day averages and rolling 90-day averages. The
30-day averages have greater variability and, thus, higher peaks and
valleys. The 90-day average has less variability; therefore, the same
unit is able to meet a tighter 90-day limit.
The EPA is providing this alternate 90-day rolling average
compliance approach for Hg only. A 90-day rolling average is
appropriate for Hg, and only for Hg, because the health and
environmental impacts associated with Hg are related to environmental
loading rather than shorter term inhalation or other acute exposure, as
is the case with HCl and PM. We believe that this alternative
compliance approach will provide at least the same level of
environmental protection while allowing companies greater flexibility
to use emissions averaging. For example, such an approach would allow
for the averaging of an infrequently operated unit that is operating
slightly above the standard with a more frequently operated unit that
is operating below the standard in the instances when the more
frequently operated unit is in a multi-day or multi-week maintenance
outage.
The EPA has concluded that it is permissible to establish within a
NESHAP a unified compliance regimen that permits averaging within the
same facility across individual existing EGUs subject to the same
standards under certain conditions. As mentioned earlier, individual
EGUs within an emissions averaging group would be allowed to have
emissions greater than, less than, or equivalent with the emissions
limit for their subcategory, provided that the average emissions
comprised from individual EGU emissions do not exceed the emissions
limit for their subcategory. Averaging across affected units is
permitted only if it can be demonstrated that the total quantity of any
particular HAP that may be emitted by that portion of a contiguous
major source that is subject to the same standards in the NESHAP will
not be greater under the averaging mechanism than it could be if each
individual affected EGU in the subcategory complied separately with the
applicable standard. Under this test, the practical outcome of
averaging is equivalent to compliance with the MACT floor limits by
each discrete EGU, and the statutory requirement that the MACT standard
reflect the maximum achievable emissions reductions is, therefore,
fully effectuated.
As noted in the proposal preamble, in past rulemakings, the EPA has
generally imposed certain limits on the scope and nature of emissions
averaging programs. These limits include: (1) No averaging between
different types of pollutants; (2) No averaging between sources that
are not part of the same affected source; (3) No averaging between
individual sources within a single major source if the individual
sources are not subject to the same NESHAP; and (4) No averaging
between existing sources and new sources.
The final rule fully satisfies each of these criteria. First,
emissions averaging would only be permitted between individual existing
sources at a single stationary source (i.e., the facility), and would
only be permitted between individual sources in the same subcategory in
the final EGU NESHAP. Further, emissions averaging would not be
permitted between two or more different affected sources. Finally, new
affected sources could not use emissions averaging. Accordingly, we
have concluded that the averaging of emissions across affected units in
the same existing source subcategory is consistent with the CAA. In
addition, the final rule requires each facility that intends to utilize
emissions averaging to develop an emissions averaging plan, which
provides additional assurance that the necessary criteria will be
followed. In this emissions averaging plan, the facility must include
the identification of: (1) All units in the averaging group; (2) the
control technology installed; (3) the process parameter that will be
monitored; (4) the specific control technology or pollution
[[Page 9386]]
prevention measure to be used; (5) the test plan for the measurement of
the HAP being averaged; and (6) the operating parameters to be
monitored for each control device. A state, local, or tribal regulatory
agency that is delegated authority for this rule could require the
emissions averaging plan to be submitted or even approved before
emissions averaging could be used. Upon receipt, the regulatory
authority would not be able to approve an emissions averaging plan
differing from the eligibility criteria contained in the rule.
The final rule excludes new affected sources from the emissions
averaging provision. The EPA does not believe the statute authorizes
emissions averaging for new affected sources. One reason we allow
emissions averaging is to give existing sources flexibility to achieve
compliance at diverse points with varying degrees of add-on control
already in place in the most cost-effective and technically reasonable
fashion.
With the monitoring and compliance provisions that are being
finalized, there is additional assurance that the environmental benefit
will be realized. Further, the emissions averaging provision would not
apply to individual EGUs if the EGU shares a common stack with units in
other subcategories, because in that circumstance it is not possible to
distinguish the emissions from each individual unit.\316\
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\316\ The EPA has reviewed monitoring data submitted to the
Agency under the Title IV Acid Rain Program. Based on that review,
the EPA is unaware of any coal- and oil-fired units that share a
common stack.
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The rule allows EGUs that rely on CEMS for compliance
demonstrations to be able to participate in emissions averaging and the
emissions limits are not subject to a discount. The EPA believes that
the data certainty provided by units that use CEMS would be ideal for
emissions averaging and the flexibility and cost-effectiveness it
offers. Given the homogeneity of fuels within the rules subcategories,
along with other emissions averaging criteria, the Agency believes use
of a discount factor to be unwarranted for this rule.
The emissions averaging provisions in this final rule are based in
part on the emissions averaging provisions in the Hazardous Organic
NESHAP (HON). The legal basis and rationale for the HON emissions
averaging provisions were provided in the preamble to the final
HON.\317\ We do not believe that we have the authority to provide for
emissions averaging among EGUs in different subcategories or among EGUs
not physically located at the same affected facility.
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\317\ Hazardous Organic NESHAP (59 FR 19,425; April 22, 1994).
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I. Notification, Recordkeeping, and Reporting
Compared to the proposed rule, the reduced continuous compliance
requirements in the final rule--primarily reduced testing frequencies
and removal of fuel analyses and control device or fuel operating
parameter monitoring--considerably reduces the overall burden
associated with recordkeeping and reporting. Based on evaluation of the
comments received, we have established a provision in the final rule
for submission of most CEMS data (including monitoring plan, emissions
data, and QA data) through ECMPS, so that the affected industry uses a
common reporting tool for submitting CEMS data.
For data other than most CEMS data, the final rule requires
electronic reporting of certain data, including performance test
reports, PM CPMS data, PM CEMS data, and, if approved as part of an
alternative monitoring request, HAP metals CEMS data. Other reports,
such as notifications, must be submitted in hard copy format or in
accordance with the procedures established by state and local agencies
that receive delegation for implementing this rule. In the proposed
rule, we took comment on these approaches and stated our anticipation
of adopting these approaches. In the final rule, we have extended the
ECMPS reporting to most CEMS data to promote harmonization for CEMS
data from the industry, while leaving reporting of non-CEMS data in a
separate reporting system.
J. Technical/Editorial Corrections
In this final action, we are making a number of technical
corrections and clarifications to 40 CFR part 63, subpart UUUUU. These
changes clarify procedures for implementing the emission limitations
for affected sources. We are also clarifying several definitions to
help affected sources determine applicability of this rule. We have
modified some proposed regulatory language based on public comments. In
addition, in response to comments received (including the May 2010
notice from the Utility Air Regulatory Group (UARG) of calculation
errors in the proposed Hg MACT floor limits), we have checked all
calculations and made corrections where necessary.
In several places throughout the subpart, including the associated
tables, we have corrected the cross-references to other sections and
paragraphs of the subpart.
VII. Public Comments and Responses to the Proposed NESHAP
A. MACT Floor Analysis
1. New Data/Technical Corrections to Old Data
Comment: Many commenters identified errors in the emissions
database compiled through information provided by industry in response
to the 2010 information collection request (ICR) that supported
development of this rule. Commenters submitted corrections to the EPA
during the public comment period.
Response: The EPA has incorporated technical corrections and new
data submitted prior to the end of the comment period. The corrections
and new data are described in detail in a memorandum in the docket. The
EPA re-ranked the sources in the MACT floor pools to the extent
necessary based on the new or corrected data, and we recalculated the
MACT floors as necessary based on the re-ranking of sources. The
revised MACT floors were established using the same methodology set
forth in the proposed rule.
2. Pollutant-by-Pollutant Approach
Comment: Many commenters raised concerns about the way the EPA
determined the MACT floors using a pollutant-by-pollutant approach.
Commenters contended that such a methodology produced limits that are
not achievable in combination, and as such, the limits do not comport
with the intent of the statute or the recent court decision (NRDC v.
EPA, 2007). Commenters further added that the CAA directs the EPA to
set standards based on the overall performance of ``sources'' and CAA
sections 112(d)(1), (2), and (3) specify that emissions standards be
established on the ``in practice'' performance of a ``source'' in the
category or subcategory. Commenters stated that if Congress had
intended for the EPA to establish MACT floor levels considering the
achievable emission limits of individual HAP, it could have worded CAA
section 112(d)(3) to refer to the best-performing sources ``for each
pollutant.'' Many commenters added that the EPA's discretion in setting
standards is limited to distinguishing among classes, types, and sizes
of sources. Commenters contend that although Congress limited the EPA's
authority to parse units and sources with similar design and types, it
does not allow the EPA to ``distinguish'' units and sources by
individual pollutant as proposed in this rule (Sierra Club v. EPA, 551
F.3d 1019, 1028 (D.C. Cir. 2008)). By calculating each MACT floor
[[Page 9387]]
independently of the other pollutants, commenters contend that the
combination of HAP limits results in a set of standards that only a
hypothetical ``best performing'' unit could achieve.
Response: We disagree with the commenters who believe MACT floors
cannot be set on a pollutant-by pollutant basis. Contrary to the
commenters' suggestion, CAA section 112(d)(3) does not mandate a total
facility approach. A reasonable interpretation of CAA section 112(d)(3)
is that MACT floors may be established on a HAP-by-HAP basis, so that
there can be different pools of best performers for each HAP. Indeed,
as illustrated below, the total facility approach not only is not
compelled by the statutory language but can lead to results so
arbitrary that the approach may simply not be legally permissible.
Clean Air Act section 112(d)(3) is not explicit as to whether the
MACT floor is to be based on the performance of an entire source or on
the performance achieved in controlling particular HAP. Congress
specified in CAA section 112(d)(3) the minimum level of emission
reduction that could satisfy the requirement to adopt MACT. For new
sources, this floor level is to be ``the emission control that is
achieved in practice by the best controlled similar source.'' For
existing sources, the floor level is to be ``the average emission
limitation achieved by the best performing 12 percent of the existing
sources'' for categories and subcategories with 30 or more sources, or
``the average emission limitation achieved by the best performing 5
sources'' for categories and subcategories with fewer than 30 sources.
Commenters point to the statute's reference to the best performing
``sources,'' and claim that Congress would have specifically referred
to the best performing sources ``for each pollutant'' if it intended
for the EPA to establish MACT floors separately for each HAP.
The EPA disagrees. The language of the Act does not address whether
floor levels can be established HAP-by-HAP or by any other means. The
reference to ``sources'' does not lead to the assumption the commenters
make that the best performing sources can only be the best-performing
sources for the entire suite of regulated HAP. Instead, the language
can be reasonably interpreted as referring to the source as a whole or
to performance as to a particular HAP. Similarly, the reference in the
new source MACT floor provision to ``emission control achieved by the
best controlled similar source'' can mean emission control as to a
particular HAP or emission control achieved by a source as a whole.
Commenters also stressed that CAA section 112(d) requires that
floors be based on actual performance from real facilities. The EPA
agrees that this language refers to sources' actual operation, but
again the language says nothing about whether it is referring to
performance as to individual HAP or to single facility's performance
for all HAP. Industry commenters also said that Congress could have
mandated a HAP-by-HAP result by using the phrase ``for each HAP'' at
appropriate points in CAA section 112(d). The fact that Congress did
not do so does not compel any inference that Congress was sub-silentio
mandating a different result when it left the provision ambiguous on
this issue. The argument that MACT floors set HAP-by-HAP are based on
the performance of a hypothetical facility, so that the limitations are
not based on those achieved in practice, just reiterates the question
of whether CAA section 112(d)(3) refers to whole facilities or
individual HAP. All of the limitations in the floors in this rule
reflect sources' actual performance and were achieved in practice. As
to commenters' claims that standards set in this manner cannot be met
by any actual sources, we have determined that there are approximately
69 existing coal-fired EGUs that meet all of the final existing source
MACT emission limits (out of 252 EGUs that reported data for Hg, PM,
and HCl in the 2010 ICR) and at least one EGU that meets all of the
final new source MACT emission limits.
Commenters also point to the EPA's subcategorization authority, and
claim that because Congress authorized the EPA to distinguish among
classes, types, and sizes of units, the EPA cannot distinguish units by
individual pollutant, as they allege the EPA did in the proposed rule.
However, that statutory language addresses the EPA's authority to
subcategorize sources within a source category prior to setting
standards, which the EPA has done for certain EGUs. The EPA is not
distinguishing within each subcategory based on HAP emitted. Rather, it
is establishing emissions standards based on the emissions limits
achieved by units in each subcategory. Therefore, the EPA's
subcategorization authority is irrelevant to the question of how the
EPA establishes MACT floor standards once it has made the decision to
distinguish among sources and create subcategories.
The EPA's long-standing interpretation of the Act is that the
existing and new source MACT floors are to be established on a HAP-by-
HAP basis. One reason for this interpretation is that a whole plant
approach could yield least common denominator floors--that is, floors
reflecting limited or no control, rather than performance which is the
average of what best performers have achieved. See 61 FR 173687 (April
19, 1996); 62 FR 48363-64 (September 15, 1997) (same approach adopted
under the very similar language of CAA section 129(a)(2)). Such an
approach would allow the performance of sources that are outside of the
best-performing 12 percent for certain pollutants to be included in the
floor calculations for those same pollutants, and it is even
conceivable that the worst performing source for a pollutant could be
considered a best performer overall, a result Congress could not have
intended. Inclusion of units that are outside of the best performing 12
percent for particular pollutants would lead to emission limits that do
not meet the requirements of the statute.
For example, if the best performing 12 percent of facilities for
HAP metals were also the worst performing units for acid gas HAP and
the best performers for acid gas HAP were the worst performers for HAP
metals, the floor for acid gases or metals would end up not reflecting
best performance. In such a situation, the EPA would have to make a
value judgment as to which pollutant reductions were most critical to
decide which sources are best controlled.\318\ Such value judgments are
antithetical to the direction of the statute at the MACT floor-setting
stage.
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\318\ See Petitioners Brief in Medical Waste Institute et al. v.
EPA, No. 09-1297 (D.C. Cir.) pointing out, in this context, that
``the best performers for some pollutants are the worst performers
for others'' (p. 34) and ``[s]ome of the best performers for certain
pollutants are among the worst performers for others.''
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Commenters suggested that a multi-pollutant approach could be
implemented by weighting pollutants according to relative toxicity and
calculating weighted emissions totals to use as a basis for identifying
and ranking best performers. This suggested approach would require the
EPA to essentially prioritize the regulated HAP based on relative risk
to human health of each pollutant, where risk is a criterion that has
no place in the establishment of MACT floors, which are required by
statute to be based on technology.
The central purpose of the amended air toxics provisions was to
apply strict technology-based emission controls on HAP. See, e.g., H.
Rep. No. 952, 101st Cong. 2d sess. 338. An interpretation that the
floor level of control must be limited by the performance of devices
[[Page 9388]]
that only control some of these pollutants effectively guts the
standards by including worse performers in the averaging process,
whereas the EPA's interpretation promotes the evident Congressional
objective of having the floor reflect the average performance of best
performing sources. Because Congress has not spoken to the precise
question at issue, and the Agency's interpretation effectuates
statutory goals and policies in a reasonable manner, its interpretation
must be upheld. See Chevron v. NRDC, 467 U.S. 837 (1984).\319\
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\319\ Because industry commenters argued that the statute can
only be read to allow floors to be determined on a single source
basis, commenters offered no view of why their reading could be
viewed as reasonable in light of the statute's goals and objectives.
It is not evident how any statutory goal is promoted by an
interpretation that allows floors to be determined in a manner
likely to result in floors reflecting emissions from worst or
mediocre performers.
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The EPA notes, however, that if optimized performance for different
HAP is not technologically possible due to mutually inconsistent
control technologies (for example, if metals performance decreased as
organics reduction is optimized), then this would have to be taken into
account by the EPA in establishing a floor (or floors). The Senate
Report indicates that if certain types of otherwise needed controls are
mutually exclusive, the EPA is to optimize the part of the standard
providing the most environmental protection. S. Rep. No. 228, 101st
Cong. 1st sess. 168 (although, as noted, the bill accompanying this
Report contained no floor provisions). It should be emphasized,
however, that the D.C. Circuit has stated that ``the fact that no plant
has been shown to be able to meet all of the limitations does not
demonstrate that all the limitations are not achievable.'' Chemical
Manufacturers Association v. EPA, 885 F. 2d at 264 (upholding
technology-based standards based on best performance for each pollutant
by different plants, where at least one plant met each of the
limitations but no single plant met all of them).
All available data for EGUs indicate that there is no technical
problem achieving the floor levels contained in this final rule for
each HAP simultaneously, using the MACT floor technology. Data
demonstrating a technical conflict in meeting all of the limits have
not been provided, and, as stated above, based on the available data,
there are approximately 64 EGUs that meet all of the final existing
source emission limits and at least one EGU that meets all of the final
new source emission limits.
3. Minimum Number of EGUs To Set Floors
Comment: Many commenters indicated that CAA section 112 requires
that data from a minimum of 5 units are required to set MACT floors for
existing sources. Commenters noted that the EPA's use of less than 5
units for subcategories with greater than 30 units is a legalistic
reading of CAA section 112 that could result in such absurd results as
using 5 units to set MACT floors for a subcategory with 29 units and
data for only 10 units, but using a single unit to set MACT floors for
a subcategory with 31 units and data for only 10 units.
Response: The EPA does not agree that CAA section 112(d)(3)
mandates a minimum of 5 sources in all instances, notwithstanding the
incongruity of having less data to establish floors for larger source
categories than is mandated for smaller ones. The literal language of
the provision appears to compel this result. CAA section 112(d)(3)
states that for categories and subcategories with at least 30 sources,
the MACT floor for existing sources shall be no less stringent than the
average emission limitation achieved by the best-performing 12 percent
of the sources for which the Administrator has emissions information.
The plain language of this provision requires the use of fewer data
points for large source categories than for small source categories
where the Administrator only has emissions information on a small
number of units for categories and subcategories with 30 or more
sources. Furthermore, commenters contend that Congress could not have
intended the floors for a subcategory with 29 sources to be based on 5
sources and a subcategory with 31 sources to be based on less than that
number; but we maintain this contention is without merit because 12
percent of 31 is 3.72 (rounded to 4) so the EPA would not base
standards for a subcategory with 31 sources on 5 sources even if we had
data on all 31 sources in the subcategory. For these reasons, we
decline to adopt commenters' position and continue to adhere to the
clear statutory directive.
4. Treatment of Detection Levels
Comment: Commenters stated that when setting the MACT floors, non-
detect values are present in many of the datasets from best performing
units. Commenters provided input on how these non-detect values should
be treated in the MACT floor analysis. Some commenters agreed that it
is appropriate to keep the detection levels as reported, while certain
commenters suggested that the detection levels should be replaced using
a value of half the method detection limit (MDL). Many other commenters
stated that data that are below the detection limit should not be used
in setting the floors, and these data should be replaced with a higher
value including either the MDL, limit of quantitation (LOQ), practical
quantitation limit (PQL), or reporting limit (RL) for the purposes of
the MACT floor calculations. Other commenters stated all non-detect
values should be excluded from the floor analysis, or all values should
be treated as zero.
Some commenters stated it is necessary to keep the data as reported
because changing values would lead to an upward bias. Additional
commenters agreed with this basic premise, but suggested that replacing
non-detect data with a value of half the MDL is appropriate while still
minimizing the bias. They noted that treating measurements below the
MDL as occurring at the MDL is statistically incorrect and violates the
statute's ``shall not be less stringent than'' requirement for MACT
floors. One commenter also provided a reference for a statistical
method based on a log-normal distribution of the data which estimated
the ``maximum likelihood'' of data values; this result is slightly
higher than half the MDL.
Some commenters stated that it is necessary to substitute the MDL
value when performing the MACT floor calculations. With MDL defined as
the lowest concentration that can be distinguished from the blank at a
defined level of statistical significance, this is an appropriate
value. If MDL values are not reported, one commenter suggested an
approach for estimating an MDL equivalent value, but recognized that
the background laboratory and test report files may not be available to
the EPA in order to derive these estimates.
Most commenters representing industry and industry trade groups
argued that either LOQ or PQL values should replace non-detects. The
LOQ is defined as the smallest concentration of the analyte which can
be measured. These commenters contended that the LOQ leads to a
quantifiable amount of the substance with an acceptable level of
uncertainty. A few commenters provided calculations showing some of the
proposed MACT floors were below the LOQ. Additionally, some of these
commenters stated that using LOQ or PQL values also incorporates
additional sources of random and inherent sampling error throughout the
testing process, which is necessary. These errors occur during sample
collection, sample recovery, and sample analysis;
[[Page 9389]]
MDL values only account for method specific (e.g., instrument) errors.
These commenters contended that the three times the MDL approach
discussed in the proposal accounts for some measurement errors but does
not account for these unavoidable sampling errors. The commenters also
noted that an LOQ is calculated as 3.18 times the MDL, and PQL is
calculated as 5 to 10 times the MDL. Many of the commenters in support
of using either an LOQ or PQL value ultimately believed a work practice
is more appropriate where a MACT floor limit is below either of these
two values. They cited CAA section 112(h)(1) which allows work
practices under CAA section 112(h)(2) if ``the application of
measurement methodology to a particular class of sources is not
practicable due to technological and economic limitations''. These
commenters stated that the inability of sources to accurately measure a
pollutant at the level of the MACT floor qualifies as such a
technological limitation that warrants a work practice standard.
Commenters stated that where the proposed MACT floor is below the
LOQ or PQL then that source category has a technological measurement
limitation. A few commenters suggested RL values should be used when
developing the floor limits. They stated that the RL is the lowest
level at which the entire analytical system gives reliable signals and
includes an acceptable calibration point. They added that use of an
acceptable calibration point is critical in showing that numbers are
real versus multiplying the MDL by various factors.
Several commenters stated that all non-detect values should be
excluded from MACT floor calculations. They believed that excluding all
non-detect values would eliminate any potential errors or accuracy
issues related to testing for compliance. Due to inconsistencies of the
MDL value reported for non-detect data, one commenter suggested
treating all such values as zero. This would provide a consistent
approach for setting the floor as well as determining compliance.
Several commenters provided input on the EPA's proposed method of
three times the MDL as an option for setting limits. A few commenters
in support noted that this approach provided a reasonable method to
account for data variability as it took into account more than just
analytical instrument precision. Many other commenters argued that this
method results in limits which are too low, namely that it is still
lower than the LOQ value which they are in favor of as a substitute for
any reported non-detect data. Other commenters disagreed with this
method and claimed that it would lead to results which introduce a high
bias in the floor setting process. A few contended that multiplying by
3 would introduce a 300 percent error into the floor, resulting in a
floor that is less stringent than required by the Act. Others suggested
that the MDL values are antiquated and already too high and thus it is
not appropriate to multiply them by three. Also, a few commenters
suggested multiplying the MDL by three would not reflect the actual
lower emissions achieved by any source and as such is unlawful under
CAA section 112(d).
Response: We agree with many of the comments related to treatment
of data reported as detection limit values in the development of MACT
floors and emissions limits. As we noted at proposal, the statistical
probability procedures applied in calculating the floor or an emissions
limit inherently and reasonably account for emissions data variability
including measurement imprecision when the database represents multiple
tests from multiple emissions units for which all of the data are
measured significantly above the method detection level. That is less
true when the database includes emissions occurring below method
detection capabilities regardless of how those data are reported.
The EPA's guidance to respondents for reporting pollutant emissions
used to support the data collection specified the criteria for
determining test-specific method detection levels. Those criteria
ensure that there is only about a 1 percent probability of an error in
deciding that the pollutant measured at the method detection level is
present when in fact it was absent. (Reference: ReMAP: PHASE 1,
Precision of Manual Stack Emission Measurements; American Society of
Mechanical Engineers, Research Committee on Industrial and Municipal
Waste, February 2001.) Such a probability is also called a false
positive or the alpha, Type I, error. This means specifically that for
a normally distributed set of measurement data, 99 out of 100 single
measurements will fall within 2.54 x standard deviation of
the true concentration. The anticipated range for the average of
repeated measurements comes progressively closer to the true
concentration. More precisely, the anticipated range varies inversely
with the square root of the number of measurements. Thus, for a known
standard deviation (SD) of anticipated single measurements, the
anticipated range for 99 out of 100 future triplicate measurements will
fall within 2.54 SD/[radic]3 of the true concentration.
This relationship translates to an expected measurement imprecision for
an emissions value occurring at or near the method detection level of
about 40 to 50 percent.
By assuming a similar distribution of measurements across a range
of values and increasing the mean value to a representative higher
value (e.g., 3 times minimum detection level or 3xMDL), we can estimate
measurement imprecision at other levels. For an assumed 3xMDL, the
estimated measurement imprecision for a three test run average value
would be on the order 10 to 20 percent. This is about the same
measurement imprecision as found for Methods 23 and 29 indicated in the
ASME ReMAP study for the sample volumes prescribed in the final rule
(e.g., 4 to 6 dscm) for multiple tests.
Analytical laboratories often report a value above the method
detection limit that represents the laboratory's perceived confidence
in the quality of the value. This independently adjusted value is
expressed differently by various laboratories and is called LOQ, PQL,
or RL. In many cases, the LOQ, PQL, or RL is simply a multiplication of
the method detection limit. Commonly used multipliers range from 3 to
10. Because these values reflect individual laboratories' perceived
confidence, and, therefore, could be viewed as arbitrary, we decline to
adopt the LOQ, PQL, or RL because such approaches in our view would
inappropriately inflate the MACT floor standards. Our alternative to
those inconsistent approaches is discussed below.
Consistent with findings expressed in reports of emissions
measurement imprecision and the practices of analytical laboratories,
we believe that using a measurement value of 3 times a representative
method detection limit established in a manner that assures 99 percent
confidence of a measurement above zero will produce a representative
method reporting limit suitable for establishing regulatory floor
values.
On the other hand, we also agree with commenters that an emissions
limit set from a small subset of data or data from a single source may
be significantly different than the actual method detection levels
achieved by the best performing units in practice. This fact, combined
with the low levels of emissions measured from many of the best
performing units, led the EPA since proposal to review and revise the
procedure intended to account for the contribution of measurement
imprecision to data variability in establishing effective emissions
limits. In response to the comments about the
[[Page 9390]]
quality of measurements at very low emissions limits especially for new
sources, we revised the procedure for identifying a representative
method detection level (RDL).
The revised procedure for determining an RDL starts with
identifying all of the available reported pollutant-specific method
detection levels for the best performing units regardless of any
subcategory (e.g., existing or new, fuel type, etc.). From that
combined pool of data, we calculate the arithmetic mean value. By
limiting the data set to those tests used to establish the floor or
emissions limit (i.e., best performers), which in this case is a larger
data set than normally available for establishing NESHAP, we believe
that the result is representative of the best performing testing
companies and laboratories using the most sensitive analytical
procedures. We believe that the outcome should minimize the effect of a
test(s) with an inordinately high method detection level (e.g., the
sample volume was too small, the laboratory technique was
insufficiently sensitive, or the procedure for determining the minimum
value for reporting was other than the detection level). We then call
the resulting mean of the method detection levels the representative
detection level (RDL) because it is characteristic of accepted source
emissions measurement performance.
The second step in the process is to calculate 3xRDL to compare
with the calculated floor or emissions limit. This step is similar to
what we have used for other NESHAP including the Portland Cement rule.
As outlined above, we use the multiplication factor of 3 to reduce the
imprecision of the analytical method until the imprecision in the field
sampling reflects the relative method precision as estimated by the
ASME ReMAP study. That study indicates that such relative imprecision
remains a constant 10 to 20 percent over the range of the method. For
assessing the calculated floor results relative to measurement method
capabilities, if 3xRDL were less than the calculated floor or emissions
limit (e.g., calculated from the upper predictive limit, UPL), we would
conclude that measurement variability was adequately addressed with the
initial floor calculation. The calculated floor or emissions limit
would need no adjustment. If, on the other hand, the value equal to
3xRDL were greater than the UPL, we would conclude that the calculated
floor or emissions limit did not account entirely for measurement
variability. Where such was the case, we substituted the value equal to
3xRDL for the calculated floor or emissions limit (UPL) which results
in a concentration where the method would produce measurement accuracy
on the order of 10 to 20 percent similar to other EPA test methods and
the results found in the ASME ReMAP study.
We determined the RDL for each pollutant using data from tests of
all the best performers for all of the final regulatory subcategories
(i.e., pooled test data). We applied the same pollutant-specific RDL
and emissions limit assessment and adjustment procedures to all
subcategories for which we established emissions limits. We believe
that adjusting emissions limits in this manner, which ensures that
measurement variability is adequately addressed relative to compliance
determinations, is a better procedure than the one applied at proposal,
which was based on more limited data. We also believe that currently
available emissions testing procedures and technologies provide the
measurement certainty sufficient for sources to demonstrate compliance
at the levels of the revised emissions limits.
5. Basis for New Source MACT
Comment: Several commenters stated that the proposed limits set for
new EGUs do not represent the best performing EGU. The commenters state
that the EPA has chosen the strictest limit irrespective of the EGU and
that limits for new EGUs should be achievable. According to the
commenters, no existing EGU is currently meeting the proposed limits,
which will result in a moratorium on the construction of new coal-fired
EGUs. Further, commenters state that another result of the EPA's flawed
approach is that the proposed standards for new EGUs are so low that
adequate test methodologies to demonstrate compliance do not exist.
Without accurate testing methodologies, commenters assert that
contractors will not guarantee that potential emission control
technologies will meet the proposed standards. Without accurate test
methodologies and vendor guarantees, commenters believe that financing
of new facilities will be virtually impossible to secure which will, in
turn, effectively preclude the construction of any new coal-based EGUs.
Commenters also stated that the EPA failed to address cumulative
effects of using multiple pollution control devices in determining MACT
levels applicable to PM levels. In proposing total PM as a surrogate,
commenters believe that the EPA failed to consider or address the
antagonistic effects that adding multiple pollution control devices can
have on an EGU's HAP emissions. Commenters indicated that EGUs would
not be able to comply with the proposed new source HCl limit without
adding a scrubber or some type of sorbent injection to control HCl
emissions. Adding these HCl control technologies will increase the
total PM emissions of these units. According to commenters, because a
fabric filter-alone configuration (the basis for the new source PM
limit) would not meet all MACT limits, these units may not be the best-
performing units.
Response: The EPA disagrees with the commenters' statements that no
existing unit is currently meeting the new source limits. The EPA
established the new source limits based on data from existing EGUs and
there is at least one EGU, based on the data available, that is meeting
all three final HAP limits and at least eight EGUs that are meeting one
or more of the new source limits. As a result of comments received on
the full body of data, the EPA has re-ranked the best performing EGUs
and reviewed the new source limits based on the re-ranking where
appropriate. Based on the revised ranking, the best performing source
for PM has changed and that source now forms the basis for the new
source filterable PM limit in the final rule. The source is a coal-
fired EGU that includes the entire suite of controls that would likely
be required on a new coal-fired source constructed prospectively (i.e.,
it is a unit with SCR, dry FGD, and FF). Thus, the commenters' concerns
are no longer relevant as they relate to PM emissions from coal-fired
EGUs.
The EPA also believes that the EGUs serving as the basis for the
new source Hg and HCl limits in the final rule are representative of
what a new coal-fired EGU would look like to meet all of the requisite
regulations applicable to EGUs (e.g., NSPS and the CSAPR) as they also
include the entire suite of controls that would likely be required on a
new coal-fired source constructed prospectively. The EPA has also taken
into account the ability of the various test methods to accurately
measure emissions at the levels being demonstrated by the EGUs in the
top performing 12 percent in establishing the final limits, and we have
determined that there are adequate test methods to measure the
regulated HAP at the new source levels.
6. Achievability of Limits
Comment: A number of commenters state that the EPA has chosen the
strictest limit irrespective of the unit and that limits for new EGUs
should be achievable. According to the
[[Page 9391]]
commenters, no existing unit is currently meeting the proposed new
source limits, which will result in a moratorium on the construction of
new coal-fired units. The commenters state that this regulation goes
beyond protecting public health and will impact the country's choice of
fuel for energy production. Other commenters state that another result
of the EPA's flawed approach is that the proposed standards for new
units are so low that adequate test methodologies to demonstrate
compliance do not exist. Without accurate testing methodologies,
commenters allege that contractors will not guarantee that potential
emission control technologies will meet the proposed standards. Without
accurate test methodologies and vendor guarantees, commenters believe
that financing of new facilities will be virtually impossible to
secure, and that this in turn will effectively preclude the
construction of any new coal-based units. Commenters maintain that
adopting standards effectively banning new coal units amounts to a
momentous change in national energy policy without discussion or
analysis and far exceeds the EPA's authority.
Some commenters add that the proposed new source MACT standards do
not represent rates that have been achieved in practice and are orders
of magnitude lower than any of the CAA section 112(g) case-by-case MACT
limits established for the most advanced units in the U.S. coal fleet
by multiple state agencies.
Other commenters stated that the synergistic impact of multiple
controls has not been taken into account in the proposed rules.
Commenters argue that circumstances exist with respect to the control
of acid gases, which will require scrubbers or other SO2
controls that add particulate to the flue gas stream, and that added
particulate must be removed by PM control devices along with the
particulate added to the flue gas for EGUs that need to install ACI for
Hg control. Because particulate devices provide a fixed percent
reduction of particulate, commenters assert that it is mathematically
certain that PM performance will decrease because control of both acid
gases and Hg would add PM to the flue gas stream which would in turn
decrease performance of the PM control on the relevant mass metric. As
a consequence, commenters allege that there is no assurance that
sources can meet the EPA's ``cherry-picked'' floors for acid gases and
for Hg by ``optimizing'' these systems to meet the performance of the
floor units because to do so would impact their ability to meet the
EPA's similarly ``cherry-picked'' total PM floor standard.
The commenters state that, for existing sources as with the new
source standard-setting approach, a pollutant-by-pollutant approach
does not consider what the top performing 12 percent achieve in
practice for all pollutants and does not consider the antagonistic
effects of the concurrent use of various control technologies. For
example, one commenter states that 47 of the 131 sources used to
calculate the existing source total PM limit only had PM control but no
acid gas or Hg controls that could emit additional PM. According to the
commenter, the CAA is clear that standards must be based on actual
sources and not the product of a pollutant-by-pollutant determination
resulting in a set of composite standards that do not necessarily
reflect the overall performance of any actual source. To address these
issues, the commenter recommends that the EPA use an approach that more
accurately reflects what actual best performing sources achieve.
Response: The EPA disagrees with the commenters' contention that
the pollutant-by-pollutant approach to establishing MACT floors is
inconsistent with the CAA for the reasons set forth in the response to
comments on the EPA's MACT floor setting process. In addition, the EPA
established the proposed new source limits based on data from existing
EGUs, and there are EGUs that are able to meet the new source limits.
To the extent the commenters are concerned that no existing source is
simultaneously meeting all of the new sources limits, we note that the
EPA has revised the new source standards based on comments and data
corrections that industry made to data it incorrectly provided in
response to the utility ICR. We have identified at least one source
that is meeting all of the new source MACT limits in the final rule.
We disagree with commenters that suggest the proposed new source
standards are invalid because they are more stringent than CAA section
112(g) case-by-case MACT limits established by state agencies. As
commenters note, states, not the EPA, established the CAA section
112(g) standards, and they did so based on the information available to
them. The EPA likewise must establish CAA section 112(d) standards
based on the available data. We have considered the available data and
information, including the 2010 ICR data, and complied with the
requirements of CAA section 112(d) in establishing the standards in
this final rule. That the final standards are more stringent than CAA
section 112(g) standards issued by certain state agencies has no
bearing on the legitimacy of the standards at issue here.
The EPA agrees with commenters that the SO2 and some Hg
controls may add to the PM loading and that it is reasonable to
establish the new source standard based on an EGU that has a suite of
controls that will be required of any new source. For example, new
coal-fired EGUs will be required to comply with the utility NSPS and
may have to comply with the CSAPR and other requirements (e.g., SIP or
state-only requirements). Commenters are also correct that the proposed
new source PM surrogate standard was based on a source that is not like
a coal-fired EGU that would be constructed today (i.e., an EGU with
only PM control and no SO2 controls).
The final standard is not based on the source used to establish the
proposed limit. As stated above, industry commenters provided data
corrections and new data and the EPA considered that new and revised
data in establishing the final standards. We re-ranked all the coal-
fired EGUs based on the new data. The new ranking of coal-fired EGUs
resulted in a change of the source we used to establish the new source
PM surrogate standard for non-mercury metal HAP. The basis for the new
source limit in the final rule is a unit that has a full suite of
controls similar to what would be required for any new coal-fired EGUs
(i.e., it is a unit with SCR, dry FGD, and FF). The EPA has identified
at least one EGU meeting all of the final new source limits; thus, the
EPA does not believe that it is finalizing standards that ``ban'' new
coal-fired generation as indicated by the commenter.
The EPA also disagrees that the final new source standards are so
stringent that there are not adequate test methods available to
determine compliance with the standards. The EPA has taken into account
the ability of the various test methods to accurately measure emissions
at the levels being demonstrated by the best performing EGUs in
establishing the final limits. This has been done through use of the
3XRDL (discussed elsewhere in this preamble and the Response to
Comments document) and through adjustments to the sampling time
requirements for certain of the HAP.
7. Comments on Technical Approaches
Comment: Commenters disagreed with the EPA's use of data from
multiple units exhausting through a common stack and argued that the
EPA unreasonably treated data from multiple
[[Page 9392]]
units exhausting through a single stack as multiple data points in
establishing the MACT floors. The commenters believe it is improper to
count a single data point from a multiple-unit common stack as multiple
data points. The commenters state that where two units exhaust through
a common stack, the performance is not that of two sources, but only
one. The commenters indicate that emissions performance that is
actually achieved reflects combined operation, which cannot rationally
be split into two parts (data points) because this emissions
performance was not achieved by two separate sources. Commenters assert
that although it may be acceptable for the EPA to surmise that the
combined performance of multiple EGUs and pollution control devices
represents an emissions control strategy that could be a best
performer, thereby entitling the Agency to use the data at all, the
fact is there is only one performer not two. Commenters contend that
apart from being inconsistent with applicable MACT case law, counting
combined stack emissions as two or more data points is unreasonable
because it dampens variability and over-represents the emissions data
by creating multiple ``performers'' or sources when there is in fact
only one. Commenters note that in the major-source Industrial Boiler
NESHAP, the EPA argued its approach of creating two data points from a
single combined stack data point is reasonable because it cannot
separate the comingled fraction of the emissions from the different
emission points. Commenters state that this is irrelevant, believing
that there is no basis to separate these emissions because the MACT
floor is based on best performing sources and there is only a single
source.
According to commenters, the EPA cannot determine what amount of
the overall performance of a combined stack data point is the specific
result of the combination. Commenters assert that the EPA also argues
that applying the emissions equally to multiple units exhausting
through a single stack ``accurately represents the emissions of those
units on average.'' Commenters believe that is simply not correct and
there is no plausible factual basis for that statement, believing that
there is no unit that ``achieved'' those emissions. Rather, the data
represent the combined weighted average of two units, without knowing
how either unit actually performed. One commenter also stated that in
several instances when a facility operated tandem or multiple EGUs but
only submitted a single stack measurement, the EPA used the single
stack measurement to represent Hg emissions from the facility's other
stacks.
Response: The EPA disagrees with commenters. As in the major-source
Industrial Boiler NESHAP, the EPA continues to believe that the
emissions from the common stack represent the average emissions of the
EGUs exhausting to the common stack and are representative of both
EGUs. Commenters have provided no data to support the contention that
this assumption is false. In addition, commenters' contention that
distinct EGUs (i.e., boilers) are one source if they emit out of a
common stack is not consistent with the CAA section 112(a)(8)
definition, which clearly applies to the individual boiler units with a
capacity of more than 25 MW. It would not be reasonable in light of
that definition to consider the emissions from two boilers to a common
stack as the emissions of one EGU. The EPA only used data from combined
stacks where both EGUs were operating or where the owner/operator
certified that no air leakage could occur. The EPA expects that
companies will comply with the final rule by conducting testing at the
common stack as that is usually where the sampling locations are
(rather than in the intermediate ductwork) and will report the results
as being for each EGU.
The EPA has reviewed the data based on comments received and does
not believe that there are any inconsistencies in the data set used for
the final rule. In the MACT floor analysis, the EPA only used data from
stacks that were tested or for which test data were provided. These
stack measurements were not used to represent emissions from other,
non-tested, stacks in the MACT analysis.
8. Alternative Units for Emission Limits
Comment: Several commenters submitted a variety of alternatives to
the input- or output-based MACT floor limits as means of establishing
the MACT floors. Some commenters suggested emission reductions or
removal efficiencies. These commenters suggest that a percent reduction
MACT metric be considered as an alternative, and not a substitute, to
some of the proposed MACT numerical limits, particularly those that
appear too problematic to meet in reality. A necessary data format and
protocol could be developed for some HAP, such as Hg, that would allow
an appropriate percent reduction alternative to be developed.
Commenters believe that the Brick MACT decision stands for the
proposition that a MACT level cannot be based on a specific technology;
commenters are advocating that a percent reduction format would specify
the level or reduction but would not dictate any specific control or
methodology.
Comments were also received that some state programs contain Hg
emission limits that are more stringent than the EPA's proposed
emission limits. The programs of Connecticut, Massachusetts, New
Hampshire, New Jersey, and New York were noted. Commenters provided
information on these states' Hg emission limits, which often are in the
form of either a lb/TBtu format or a percent reduction. Commenters
noted that EGUs in these states were in compliance with the state
regulations and, therefore, the EPA's emission limits should be more
stringent.
Response: The EPA disagrees with the commenters' suggestion that a
percent reduction standard should be included in the final rule. The
EPA notes that the inability to account for Hg removed from the coal
prior to combustion was not the only reason provided for not using a
percent reduction format. As noted in the proposal preamble (76 FR
25040), we did consider using a percent reduction format for Hg. We
determined not to propose a percent reduction standard for several
reasons. The percent reduction format for Hg and other HAP emissions
would not have addressed the EPA's desire to promote, and give credit
for, coal preparation practices that remove Hg and other HAP before
firing because we did not have the data to account for those practices.
Specifically, to account for the coal preparation practices, sources
would be required to track the HAP concentrations in coal from the mine
to the stack, and not just before and after the control device(s). Such
an approach would be difficult to implement and enforce. Moreover, we
do not have the data necessary to establish percent reduction standards
for HAP at this time. Depending on what was considered to be the
``inlet'' and the degree to which precombustion removal of HAP was
desired to be included in the calculation, the EPA would need (e.g.)
the HAP content of the coal as it left the mine face, as it entered the
coal preparation facility, as it left the coal preparation facility, as
it entered the EGU, as it entered the control devices, and as it left
the stack to be able to establish percent reduction standards. We do
not have this type of information.
The EPA believes that an emission rate format allows for, and
promotes, the use of pre-combustion HAP removal processes because such
practices will
[[Page 9393]]
help sources assure they will comply with the proposed standard. A
percent reduction requirement would likely limit the flexibility of the
regulated community by requiring the use of a control device. In
addition, as discussed in the Portland Cement NESHAP (75 FR 55002;
September 9, 2010), the EPA believes that a percent reduction format
negates the contribution of HAP inputs to EGU performance and, thus,
may be inconsistent with the D.C. Circuit's rulings as restated in the
Brick case (479 F.3d at 880) which say, in effect, that it is the
emissions achieved in practice (i.e., emissions to the atmosphere) that
matter, not how one achieves those emissions.
The 2010 ICR data confirm that plant inputs likely play a role in
emissions to the atmosphere. These data indicate that some EGUs are
achieving lower Hg emissions to the atmosphere at a lower Hg percent
reduction (e.g., 75 to 85 percent) than are other EGUs with higher
percent reductions (e.g., 90 percent or greater). However, we are not
sure whether these data accurately reflect the total percent reduction
mine-to-stack because we do not have all the data necessary to make
that determination. Thus, we proposed to establish numerical emission
standards for Hg HAP emissions from EGUs and we are finalizing
numerical emission standards. The same issues prevent us from
considering percent reduction standards for the other HAP emitted from
EGUs.
With regard to the comments relating to some state programs being
more stringent than the EPA's proposed limits, the EPA would note that
many of the programs identified by one commenter have an ``either/or''
format for their Hg standards. That is, an EGU can either meet an
emission limit (e.g., lb/TBtu) or achieve a percent reduction. The
commenter did not note which form of the standard the EGUs were meeting
so it is unclear whether the standards are in fact more stringent. In
any case, CAA section 112(d) does not mandate that federal standards be
more stringent than state requirements for HAP emissions. Furthermore,
states are authorized to establish standards more stringent than this
final NESHAP so promulgation of this rule will in no way affect a
source's responsibility to comply with an otherwise applicable state Hg
or other HAP standard.
9. Beyond-the-Floor
Comment: Several commenters stated that the proposed beyond-the-
floor Hg limit for low rank coal EGUs is based on too little data and
is technically and economically unattainable, noting that the EPA's
proposed beyond-the-floor limit is based on only three samples from a
single test held at only one EGU, which is not enough data to develop
such a limit, especially as more data were available for this EGU in
the database. Commenters noted that although this one EGU may have been
able to achieve the proposed limit during this one test, the three
samples are not adequate to demonstrate the long-term ability of this
EGU to meet that limit consistently, let alone the long-term abilities
of the top 12 percent of all low rank coal EGUs to meet that limit
consistently. Given Texas lignite's particularly high rates of
variability of Hg concentration, and the inability to minimize this
variability, the commenters believe that the EPA is obliged to have
more, not less, data to support the proposed beyond-the-floor Hg limit
for low rank coal EGUs. One commenter added that the EPA's decision to
require a beyond-the-floor limit for the low rank virgin coal
subcategory does not comply with CAA section 112(d)(2). Some commenters
also contended that the EPA failed to include the cost of a baghouse in
its beyond-the-floor analysis. They note that, according to the EPA, in
order to comply with the proposed EGU MACT rule, units will either fuel
switch to a lower Hg fuel or retrofit air pollution controls.
Response: The EPA notes that all of the low rank virgin coal-fired
EGUs for which data were submitted in response to the 2010 ICR were
meeting the Hg floor limit (11 lb/TBtu). Four of the EGUs have ACI
systems installed and three of the four EGUs tested were also meeting
the beyond-the-floor Hg emission limit of 4.0 lb/TBtu. Those three
units were achieving control levels of greater than 95 percent (fuel to
stack). The other low rank virgin coal-fired EGUs that are not
currently meeting the beyond-the-floor emission limit do not have
installed Hg-specific controls. An analysis of the Hg content of the
fuel used during the 2010 ICR testing suggests that control in the
range of 80 to 90 percent (fuel to stack) would be needed to meet the
beyond-the-floor limit of 4.0 lb/TBtu. One low rank virgin coal-fired
EGU achieved 75 percent control with no Hg-specific control technology
(e.g., ACI).
The EPA believes that its beyond-the-floor analysis is appropriate,
including the costs analyzed. The EPA's cost analysis is meant to serve
as an average for all sources in the subcategory recognizing that some
EGU's costs will be more and some less; EGUs whose costs are higher are
not exempted from the regulation. Further, five EGUs in the subcategory
are meeting the final beyond-the-floor limit based on available data
(see the MACT Floor analyses in the docket), and, in any case, CAA
section 112(d) does not require that a specified percentage of sources
in a category or subcategory be able to meet the MACT standard that is
established. This is even truer for beyond-the-floor standards which
are set at levels beyond what the average of the best performing
sources are achieving in practice and instead based on what is
achievable. Commenters have failed to provide any data that supports
the contention that some EGUs in the subcategory will not be able to
achieve the standards with additional controls.
Comment: Commenters indicated that the EPA has not justified a
beyond-the-floor limit for Hg for new IGCC units. The EPA's choice of
the beyond-the-floor Hg limit for new IGCCs is not derived from IGCC
test data from the 2010 ICR and commenters allege that the EPA has not
provided adequate justification for its decision from a technology
capability assessment. Commenters note that ACI for Hg treatment of
coal-derived syngas is not in use in any operating IGCC plant today,
nor can it be used in the same fashion as it is used at conventional
coal-fired EGUs. Commenters assert that the EPA also lacks data with
respect to new IGCC units, yet the EPA proposed beyond-the-floor MACT
limits for new IGCC sources. The commenters assert that the EPA's
limits for new IGCC sources are based on beliefs, predictions,
projections and design target assumptions. The limits from the 2007 DOE
Report referenced in the preamble are based on environmental target
assumptions. These IGCC environmental targets were chosen to match
Electric Power Research Institute (EPRI) design basis from their Coal
Fleet for Tomorrow Initiative. Commenter states that EPRI notes that
these were design targets and were not to be used for permitting
values. Commenters assert that the EPA has simply not justified its
process for going beyond-the-floor for new IGCC units and that, without
sufficient justification, the EPA actions are unsupported.
Two commenters provided permit information, based on IGCC units
currently under construction, for PM and Hg emissions. One commenter
requested that the proposed new MACT floor limit for PM be modified to
address the two scenarios for duct burners at IGCC plants, syngas-fired
and natural-gas-fired. The commenter requested the 0.050 lb/MWh limit
be increased to at least 0.068 lb/MWh
[[Page 9394]]
based on gross energy output from the combined cycle generating unit
when operated with duct burners fired with syngas. The 0.068 lb/MWh
value is consistent with the calculated emission ceiling for its permit
to construct for this operating scenario. According to the commenter,
there is not sufficient experience with syngas turbines for
manufacturers to guarantee performance in the 0.050 lb/MWh range. The
0.0681b/MWh performance basis proposed by the commenter was calculated
based on the emission guarantees that the commenter was able to obtain
for a turbine fired on the syngas. The commenter also requested that
the 0.050 lb/MWh limit be increased to 0.083 lb/MWh based on gross
energy output from the combined cycle unit when operated with duct
burners fired by natural gas. The commenter indicated that, depending
on market conditions, the syngas produced at an IGCC may have more
value as a raw material for producing co-products than it would have as
duct burner fuel. Where that is the case, the economic viability of an
IGCC would be enhanced by firing the duct burners on natural gas and
diverting that syngas to manufacture of a co-product. The commenter's
air permits are currently based on the use of syngas as duct burner
fuel; however, the commenter is currently examining an alternative
operating scenario that may result in amendments to the air permits to
authorize firing natural gas in the duct burners. Commenter states that
preliminary calculations indicate that the PM limit would need to be
set at 0.083 lb/MWh gross energy output when operated with duct burners
fired with natural gas.
The commenter also noted that there is not sufficient test data to
precisely predict the Hg emissions performance of even the best-
controlled IGCC units, other than that IGCC Hg emissions are expected
to be much less than those for EGUs that directly burn coal. In its
permit application, the commenter proposed to establish a new standard
for Hg removal in IGCC units by treating the syngas in catalytic
reactors. The catalytic reactor system is expected to achieve greater
than 95 percent Hg removal using either sulfur-impregnated activated
carbon or alumina catalyst. In the absence of actual stack test data,
the commenter has had to estimate expected emissions based on
engineering estimates of how much Hg may arrive in the syngas routed to
the catalytic reactors. Based on these engineering estimates and 95
percent Hg removal in the catalytic reactors, the commenter believes
that the resulting Hg emission limit for a state-or-the-art IGCC unit
would be 0.003 lb/GWh, which is much less than the Hg emissions for
EGUs that directly burn coal.
The commenter notes that IGCC units are still in their infancy.
Funding for them will be very difficult or unavailable if there is a
regulatory limit below the level that can be supported by vendor
guarantees. Given the important role that IGCC units may have in
meeting global energy and climate stability goals, the commenter
believes it would be a mistake to erect barriers to the implementation
of this technology. The commenter stated that the EPA can reevaluate
the appropriate levels for future IGCC units after demonstration units
which incorporate effective controls have been built and tested.
Response: The EPA is not finalizing the proposed new source
standards for IGCC units. As commenters noted, EPA proposed beyond-the-
floor limits for IGCC units based on the performance of PC-fired EGUs
and solicited data from IGCC units that would represent what a new IGCC
could achieve. We received information that there are new IGCC units
permitted and under construction. The EPA believes one IGCC unit under
construction for which permit data were provided is representative of
both current technologies and of IGCC units that will be built in the
near-term future. Therefore, the EPA believes these permit levels
should be the basis of the new source IGCC emission limits and the
Agency is finalizing the PM and Hg limits on that basis, as that source
will be required to comply with its permitted limits once constructed
and it is a similar source. However, permit limits were only provided
for PM and Hg; therefore, the EPA is finalizing the new source limits
for acid gas HAP based on data from the best-performing of the existing
IGCC units for the respective HAP.
B. Rationale for Subcategories
Many commenters stated that the EPA should have proposed more
subcategories, while others believed that too many subcategories were
proposed. Many different issues were raised by commenters, and some of
the key issues that were considered in the final rule (some of which
led to changes in the final rule) include: the technical deficiencies
in the definition for the low-Btu coal subcategory; additional
subcategorization of the coal-fired EGU population; the need for
subcategorization of distillate vs. residual oil-fired EGUS; the need
for a limited-use subcategory for EGUs that operate for only a small
percentage of hours during a year; and the need for a non-continental
liquid oil subcategory for island units that have limited fuel options
and other unique circumstances. The comments and the EPA responses are
provided below.
In general, the EPA has reviewed the data provided and continues to
believe that the coal-fired EGU subcategories proposed are the only
ones supported by the data, though we have revised the basis for EGUs
designed to burn low rank virgin coal as discussed above. The EPA may
not subcategorize by air pollution control technology type as requested
by a few commenters. Further, the EPA has reviewed the other suggested
coal-fired subcategories and finds no basis for further
subcategorization (e.g., based on boiler design, boiler size, or duty
cycle).
1. Coal Subcategories
Comment: Commenters noted that although other subcategories had
been evaluated, including subcategorization of other coal ranks, no
other coal rank subcategorization was proposed. Commenters submit there
should be subcategories for the coal ranks of bituminous,
subbituminous, and lignite. The commenters noted that such treatment
would be consistent with past practice (e.g., CAMR where the
differences in the type of emissions of Hg due to the different
chemical properties of coal within differing fuel ranks was discussed).
Commenters note that activated carbon has been shown to be very
effective when used in combination with low chlorine coals (such as
western subbituminous coals); however, activated carbons can suffer
from poor performance when used with high sulfur coals. Commenters
indicate that firing high sulfur coals (especially when an SCR is also
used) can result in sulfur trioxide (SO3) vapor in the flue
gas stream. The SO3 competes with Hg for binding sites on
the surface of the activated carbon (or unburned carbon) and limits the
effectiveness of the injected activated carbon. But another commenter
noted that an SO3 mitigation technology, such as dry sorbent
injection (DSI, e.g., trona or hydrated lime), applied upstream of the
ACI can minimize this effect.
Commenters also stated that without further subcategorization the
economic impacts on individual Midwestern states will be particularly
acute as huge segments of the U.S. coal reserve will be disenfranchised
by this rule. According to the commenters, the EPA did not even attempt
to legitimately analyze this issue and, thus, in their opinion the
Agency's proffered rationale for
[[Page 9395]]
declining to further subcategorize based on the acid gas standard is
belied by the record. The commenters believe that the EPA needs to
better align this rule with its previous position in CAMR and further
subcategorize based on coal type.
Other commenters are opposed to any further subcategorization based
on coal rank. Because many sources blend several ranks of coal on a
regular basis, commenters believe that establishing coal rank
subcategories would create numerous opportunities for sources to game
the regulations and substantially increase emissions. Commenters stated
that there is no need for such an approach since modern pollution
controls can accommodate a wide range of coals. These commenters
believe that EGUs firing different ranks of coal are not fundamentally
different in size, class, or type in a way that impacts emissions or
that limits the availability of controls. The commenters believe that
emissions of fuel-dependent HAP can be controlled by either changing
the fuel prior to combustion or by removing the HAP from the flue gas
after combustion. Commenters state that ACI systems, DSI controls, and
PM controls are available for installation at units firing sub-
bituminous coal and are equally available for units firing bituminous,
anthracite, or lignite coal. These commenters also believe that as long
as a control option is commercially available, the cost for a
particular EGU is irrelevant to the EPA's development of emission
standards based on MACT. Commenters stated that subcategories based on
coal rank would make a meaningful consideration of fuel switching
impossible, contrary to the judicial mandate to consider substitution
of materials in setting the floor and the statutory mandate to consider
substitution of materials in the beyond-the-floor analysis.
One commenter stated that although they previously supported the
subcategorization of coal-fired units on the basis of coal rank, they
no longer object to grouping units that burn bituminous and
subbituminous coals in a single category because the prior basis for
subcategorization no longer exists. The commenter indicated that at the
time of CAMR, it was widely recognized that although coal-fired units
combusting bituminous coal, with its higher concentration of chlorine
and, therefore, ionic Hg, could effectively limit Hg emissions by
utilizing existing control technologies such as scrubbers, units
burning subbituminous coal could not do so with the same controls
because of the coal's higher levels of elemental Hg. The commenter
stated that activated carbon was only a fledgling and unproven
technology at the time; today, however, activated carbon has been
proven, and units burning bituminous and subbituminous coal can achieve
the same levels of emissions for Hg and other HAP. Consequently, the
commenter believes the prior basis for subcategorization no longer
exists and the commenter, therefore, agrees that coal-fired EGUs
burning bituminous and subbituminous coals ought to be grouped in a
single category.
Response: The EPA disagrees with commenters that additional coal-
fired subcategories are warranted and has not provided any in the final
rule. Commenters are correct that additional subcategorization was
proposed in January 2004. Whether or not such subcategorization was
warranted at that time, the EPA believes that the current conditions
are such that, even if appropriate at that time, such further
subcategorization is not appropriate at this time.
When all of the factors noted by commenters have been reviewed,
with the exception of Hg for certain units, as discussed above, the EPA
does not believe that the HAP emissions to the atmosphere are
sufficiently different from coal-fired EGUs to warrant further
subcategorization. There are EGUs firing bituminous, subbituminous, and
coal refuse among the top performing units for Hg and EGUs firing
bituminous, subbituminous, lignite, and coal refuse are all among the
top performers for the acid gas HAP and non-mercury metallic HAP
indicating that the MACT floor limits established based on these units
are achievable by units burning all ranks of coal.
As noted by commenters, ACI, not fully developed in 2004, is now
able to effect Hg control levels on subbituminous coals such that
similar emissions to the atmosphere may be achieved as those achieved
by higher-chlorine bituminous coals when FGD systems are used or by
coal refuse EGU with less controls. Thus, in looking at the total
system, similar emissions to the atmosphere are achieved by all of
these coal ranks. The EPA has addressed elsewhere in this document its
rationale for not subcategorizing by coal chlorine content. The EPA
does not believe that any fundamental discrimination between coal ranks
will occur as a result of the final rule, though clearly some sources
will be required to install greater controls to comply with the final
standard. We maintain that such result is consistent with the intent of
CAA section 112 standards, which are not intended to have an outcome
whereby all sources can comply with final standards without any action.
The EPA agrees, in theory, that EGUs are designed around a basic
set of coal characteristics. However, the 1999 ICR demonstrated that
numerous EGUs have conducted trial burns and gained sufficient
experience such that co-firing blends of various coal ranks is now
common practice. In fact, the EPA believes that such blends may be
modified daily, depending on the characteristics of the coal being
burned and on the level of generation needed. The extent of blending,
and the ability to switch the blends on short notice, does not lend
itself (or, in fact, argue for) additional subcategorization.
The EPA disagrees with any assertion that the EPA ignored possible
subcategorization approaches or that it has insufficient data upon
which to base or evaluate various subcategories. The EPA fully examined
the record, which demonstrates that coal-fired EGUs, with the exception
of certain units for Hg, have similar HAP emissions profiles and that
similar control approaches are available to such EGUs. Although
commenters suggested additional subcategories were warranted, they
failed to provide sufficient data to support their proposed alternative
subcategories. As noted elsewhere, the EPA does not disagree with
commenters that there are some differences in EGUs. However, the EPA
does disagree with commenters that those differences result in
differences in emissions to the atmosphere such that additional
subcategorization is justified.
Failing to demonstrate that coal-fired EGUs are different based on
emissions, the commenters turn to economic arguments, asserting that
failing to subcategorize will impose an economic hardship on certain
sources. Congress precluded consideration of costs in setting MACT
floors, and it is not appropriate to premise subcategorization on costs
either. See S. Rep No. 101-228 at 166-67 (5 Legislative History at
8506-07) (rejecting the implication that separate categories could be
based on ``assertions of extraordinary economic effects''); see also
NRDC v. EPA 489 F.3d 1364 (D.C. Cir. 2007) (holding that EPA properly
declined to create a subcategory for a particular source and rejecting
the argument that the source may have to incur more costs to comply
with the rule without such subcategory).
The final limits are based on EGUs currently operating with
available controls. As noted above, the record shows that the various
types of EGUs are represented in the floors, with the exception of
certain units for Hg, which
[[Page 9396]]
indicates that the levels are achievable by such units. Thus, the data
actually show that the MACT standards are achievable for a wide variety
of EGUs.
In addition, the EPA believes it has fulfilled the CAA section
112(c)(l) directive that ``[t]o the extent practicable, the categories
and subcategories listed under this subsection shall be consistent * *
*'' with those of CAA section 111, notwithstanding commenters assertion
to the contrary. The decision on whether to directly align CAA sections
112 and 111 subcategories is discretionary and EPA has reasonably
exercised its discretion in declining to create additional
subcategories for coal-fired EGUs based on the record, with the
exception of certain sources for Hg.
Finally, the EPA disagrees with the commenters that suggest that
EPA lacks the legal authority to consider material inputs when
considering subcategories. We agree, however, that material inputs must
be considered when establishing MACT standards for the subcategories
that are established. We also believe a meaningful consideration of
fuel switching can occur even if sources are subcategorized based on
fuel inputs because EPA considers fuels switching in evaluating
potential beyond-the-floor alternatives.
Comment: One commenter stated that the EPA should establish an
existing source acid-gas subcategory for high sulfur or high chlorine
coals because the same factors that the EPA relied on to support a low
rank virgin coal subcategory for Hg are also present in the high sulfur
or high chlorine coal context. The commenter stated that the data
indicate that even well-controlled units burning high sulfur coals
would not be in the top performers for acid gases even at removal rates
of 95 or 96 percent. The commenter added that absent such a
subcategory, about 12 percent of coal deliveries (2005 data), and the
vast majority of coal shipped from the states of Indiana, Ohio, and
Illinois (2008 data), would become unusable. The commenter expressed
support for the alternative SO2 standard for units unable to
meet the HCl standard; however, the commenter also believed that it is
appropriate to establish a coal chlorine or sulfur content-based
subcategory for the alternative SO2 standard. The commenter
stated that coal testing data indicate a clear break in chlorine
concentrations in the coals burned by EGUs, as well as in sulfur
content. The commenter indicated that there are factors supporting a
high sulfur or high chlorine coal subcategory that are similar to those
that the EPA relied upon to support a Hg subcategory for low rank
virgin coal. According to the commenter, the EPA's key rationale for a
Hg subcategory for low rank virgin coal was that no low rank virgin
coal-fired unit appeared in the ``top performing 12 percent of sources,
indicating a difference in the emissions for this HAP from these types
of units.'' The EPA did not establish other subcategories because ``the
data did not show any difference in the level of HAP emissions and,
therefore, we have determined that it is not reasonable to establish
separate emissions limits for other HAP.'' The commenter indicated that
the EPA does not need emissions data to know that even well-controlled
units burning higher sulfur coals would be unable to meet the
alternative SO2 emissions rate, and would therefore also not
appear in the top 12 percent of performing units.
Response: The EPA disagrees with commenters that subcategories
should be established for high sulfur and high chlorine coals. It
appears from the comments that it is not in fact the chlorine content
that is at issue but the sulfur content of the coal. Commenters state
that they are unable to meet the HCl limit, but they only provide
information indicating it would be difficult to meet the alternative
equivalent SO2 limit. In fact, our data show that coals with
chloride contents as high as 2,100 ppm (0.16 lb/MMBtu) were burned by
EGUs making up the MACT floor pool of sources for the final HCl
emission limit and that the best-performing unit was burning coal with
a maximum chloride content of 1,200 ppm. The median chloride level for
bituminous coals identified from data submitted through the 1999 ICR
was 1,030 ppm so we believe that the coals represented in the MACT
floor pool indicate that the final limits are achievable with high-
chlorine coals. We have determined that HCl removal is very effective
using a number of different types of FGD systems. Absent information
demonstrating that sources are unable to meet the proposed HCl limit
due to the chlorine content of the coal, we believe it is unnecessary
and inappropriate to consider subcategorizing based on chlorine content
in the coal.
In addition, as noted above, the SO2 limit is an
alternative equivalent standard that is available to sources that have
an SO2 control and CEMS and operate the controls at all
times. The EPA did not provide the alternative equivalent standard for
sources that could not meet the HCl limit as one commenter suggests;
instead, we provided the standard as a convenience and cost saving
measure to EGUs with installed FGD systems because we recognize that
many EGUs have SO2 CEMS. Sources are required to comply with
the HCl limit as a surrogate for all the acid gas HAP or the
SO2 limit as an alternate equivalent standard. Commenters
have not demonstrated that they are unable to meet the HCl standard and
our data show that the standard is achievable even for high chlorine
coals.
Comment: Several commenters supported the development of a separate
subcategory for fluidized bed combustors (FBC) or circulating fluidized
bed (CFB) EGUs. The commenters encouraged the Agency to consider
subcategorization of FBC EGUs for Hg emissions noting that the industry
has long contended that the design, construction, and operation of FBCs
are different than conventional boilers and that FBCs employ
fundamentally different processes than conventional PC-fired EGUs. The
selection of an FBC unit over a conventional PC boiler is driven in
large part by fuel characteristics. The commenters assert that, as a
result, the emissions profile of FBC units generally differ from
conventional PC boilers because FBC units more advantageously combust
waste coals, as well as coal blends with other carbonaceous material.
The commenters stated that the EPA did not discuss the design
differences between FBC units and PC units in the preamble to this
proposed rule unlike what the Agency did when it previously proposed Hg
MACT limits in January 2004. Commenters state that, for these reasons,
FBC units can be considered a distinct type of boiler.
The commenters noted that an examination of the 40 ``best
performing'' units for Hg emissions in the proposed MACT floor
spreadsheet showed that 14 of those units are FBC units. The commenters
maintained that had FBC units performed as well as conventional PC
boilers, 2 units would have been expected to be in the top 40. The
commenters allege that the far higher percentage of FBCs in the top 40
leads to the conclusion that these units are different from
conventional PCs with regard to Hg emissions and, as a result, should
have been placed in their own subcategory. Further, commenters noted
that the largest FBC has a nameplate capacity of about 300 MW while the
largest conventional boilers have nameplate capacities of around 1,300
MW.
The commenters stated that FBCs combust relatively large coal
particles in a bed of sorbent or inert material at a lower degree of
combustion efficiency.
[[Page 9397]]
Fluidized bed units operate at less than half of the temperature of a
conventional boiler and have much longer fuel residence times.
Conventional boilers pulverize coal to a very fine particle size to
maximize combustion efficiency and minimize unburned carbon. As a
result, the commenters noted that FBCs typically have higher levels of
unburned carbon present in the ash, which behaves much like activated
carbon and helps promote more efficient Hg removal. Accordingly,
commenters maintain that Hg emissions of FBC boilers and PC boilers are
statistically different, with emissions from FBCs significantly lower
than those from PC boilers. According to commenters, this statistically
significant difference in the Hg emissions profiles for these two
distinct boiler technologies argues in favor of the creation of a
separate subcategory for FBCs, as there is no control technology that
PCs could install that would result in emissions reductions similar to
those achieved by FBCs. The active quantity of calcium oxide (lime-CaO)
available in a FBC boiler is also orders-of-magnitude greater than
compared to a PC boiler, whose alkalinity is derived solely from the
coal's mineral content. Significantly higher CaO can alter the process
chemistry in the boiler, including the oxidation levels of Hg.
One commenter stated that the EPA properly declined to
subcategorize units based on design type where there is no indication
that any physical distinctions among unit designs have a meaningful and
substantial impact on HAP emissions. The commenter indicated that it
would be inappropriate to subcategorize FBCs because there is no
evidence to support a determination that FBC design is responsible for
a unit falling in or out of the top 12 percent for a particular HAP.
Response: The EPA acknowledges that there are design and operation
differences between conventional PC-fired EGUs and FBC/CFB EGUS;
however, the commenters are incorrect in asserting that the HAP
emissions levels and characteristics are sufficiently distinct from
other coal-fired EGUs to support subcategorization. Further, commenters
fail to note that FBC EGUs were not subcategorized in CAMR even though,
as commenters note, such design and operation differences were cited
there. The fact that FBC units operate at lower temperatures is of no
consequence as they still operate at temperatures high enough to
vaporize Hg.
Commenters assert that FBC units are disproportionately represented
among the best performers, with the inference being that they were
selected to test in the 2010 ICR because of their boiler design.
However, FBC EGUs were not specifically selected as best performers for
Hg, as EPA did not select any EGUs based on a determination that they
were best performers for Hg (as noted elsewhere, we had no basis for
selecting EGUs as being best performers for Hg), and to the extent CFB
units were selected in the 2010 ICR, they were selected because we
determined they were best performers for non-mercury metallic HAP, acid
gas HAP, or organic HAP or because they were randomly selected among
the non-best performers for those three HAP groupings. Thus, the CFBs
were selected for testing under the 2010 ICR based not on their boiler
design but, rather, based on the age and on their PM and FGD control
systems (as noted in the Supporting Statement for the 2010 ICR). As
many FBC EGUs, including CFB EGUs, are relatively new, they were
included in the non-mercury metallic HAP group selected for testing
(because their PM controls were among the 175 newest), the acid gas HAP
group selected for testing (because FBC was considered to be an FGD
system and the units were among the 175 newest), and organic HAP
testing (because they were among the newest and, thus, determined to be
among the most efficient).
The effect on Hg emissions is not what commenters suggest because,
although, as noted by commenters, FBC units may be found among the
better performers (among the top 10 EGUs) on the Hg MACT floor
spreadsheet, they are also found in the range of 221 to 226 EGUs (of
393 data points). The fact that FBC units have ``vastly dissimilar ash
properties'' that may contain higher levels of lime or unburned carbon
in the fly ash than conventional PC EGUs does not indicate that the
overall system behaves any differently with regard to emissions to the
atmosphere (the key metric) than a conventional PC EGU with add-on
controls. The asserted higher levels of unburned carbon result in a
range of effectiveness of Hg control that is similar to that of ACI
found on PC EGUs; such ACI control may be found on EGUs that are among
the better performers as well as on EGUs as low as 369 on the list of
data points. Thus, the EPA disagrees that FBC units are
disproportionately represented in the Hg floor and that their inclusion
is somehow inappropriate or leads to skewing of the analysis.
All types of coal-fired EGUs other than those we subcategorized are
represented in the MACT floors for Hg and all types of EGUs are
represented in the floors for the non-mercury HAP. Fluidized bed
combustion EGUs are not an exception and such EGUs are found across the
range of top performing EGUs for all of the HAP categories: Acid gas,
non-mercury metallic, and Hg. In addition, any assertion that non-FBC
EGUs are unable to meet the final standards because FBC EGUs are
included in the same subcategory (or vice versa) is plainly refuted by
the fact that EGUs of all types are currently meeting one or more of
the final standards. Thus, the EPA finds no basis for subcategorizing
FBC EGUs.
Further, as noted below, the EPA does not believe there is a basis
for subcategorizing small EGUs, either FBC or PC. In addition, the data
have been re-evaluated based on comments received and an FBC unit is
not the basis for the new source Hg MACT floor.
Comment: Many commenters stated that the EPA should have considered
additional subcategorization schemes, including one based on EGU size.
Commenters noted that one of the factors that the Administrator can
consider under CAA section 112(d)(1) in making subcategorization
decisions is unit size. Commenters stated that an analysis of the 2010
ICR data showed a statistical difference between EGUs with a capacity
of 100 MW or less and EGUs above 100 MW; other commenters suggested
that the cut-off range should be 125 MW. Although large in number
(about 27 percent) of all EGUs, these small EGUs only comprise about 5
percent of the coal-fired capacity in the U.S. Thus, commenters assert
that if different MACT limits are set for this subcategory of EGUs, it
will not have a significant impact on the health effects of HAP
emissions. Commenters noted that although emission rates from such
small EGUs are greater than those found in the large unit fleet, their
contribution to the total EGU emissions is not significant. The costs
associated with coming into compliance with the proposed rule by
installing new controls would be proportionally much higher for these
small EGUs than larger EGUs according to the commenters. The commenters
allege that this would force the retirement of generation capacity and
threaten electrical reliability without appreciable benefit to the
environment.
One commenter stated that in general, the nature of many public
power facilities differs from the general population of coal-fired
power plants. Public power units tend to be smaller in size, and are
often space-constrained by growth in the community surrounding the
generating unit since its initial construction. These limitations
restrict the ability of these EGUs to achieve the same performance
levels of larger,
[[Page 9398]]
unconstrained EGUs; and, for those EGUs that can comply with the
proposed standards, the installation of controls sharply increases the
cost of compliance. The commenter stated that the EPA did not
adequately subcategorize to accommodate many small- and medium-sized
public power utilities. In particular, the EPA did not avail itself of
the opportunity to use a public power electric utility subcategory,
rural subcategory, or fuel type subcategories. Other commenters
endorsed the establishment of a less than 100 MW subcategory that would
reduce the costs of the proposed rule significantly, but only affect 5
percent of the total electric utility sector, and help minimize
retirement of uneconomical plants.
One commenter stated that the EPA properly recognized that
subcategories based on unit size would be inappropriate because the
proposed emission limits are in terms of lb/MMBtu or lb/TBtu and noting
that an EGU's total nameplate capacity is wholly unrelated to its
ability to achieve the proposed limits. Another commenter opposed any
proposal to subcategorize units below 100 MW. The proposed rule does
not apply to units less than or equal to 25 MW, and this commenter
believed that this is a sufficient threshold for applicability.
One commenter stated that the EPA could establish subcategories for
the purpose of temporarily exempting, for example, a subcategory of
utilities that meet the definition of small entity for purposes of the
proposed rule. The temporary exemption would sunset on a date certain
(e.g., 3 years from the effective date of the rule) at which point the
sources in the subcategory would become subject to the rule, and a
compliance timetable would start to run. The commenter believed that
this time-staged promulgation and compliance proposal would greatly
increase the chance that the control measures could be added in an
orderly and efficient manner with minimal disruption to power markets
and grid reliability.
Response: The EPA agrees with commenters who stated that an EGU's
size is totally unrelated to its ability to comply with the final
concentration-based limits. The EPA examined the size of units within
the respective MACT floor pools of sources and found units ranging in
size from 25 to 1,320 MW in the HCl floor pool, from 25 to 869 MW in
the non-mercury metallic floor pool, and from 47 to 544 MW in the Hg
floor pool. Thus, we find no more difference between a 25 MW EGU and
(e.g.) a 500 MW EGU than we do between a 500 MW EGU and a 1,300 MW EGU
and reaffirm our position that the MW capacity of the EGU is not a
determining factor in its emissions. Further, the EPA believes that
units of all sizes are owned by both large and small entities.
The EPA examined the effect if EGUs less than 125 MW were
subcategorized for Hg. The resultant MACT floor for these EGUs would be
1.0 lb/TBtu on a 30-boiler operating day rolling average, a level more
stringent than that developed for the >8,300 Btu subcategory as a
whole. We do not believe that this is what commenters envisioned when
suggesting such a subcategory but we believe it confirms our analysis
of the data that indicates, as noted, these units are controlled in the
same manner as other, larger EGUs, such that additional
subcategorization is not necessary or reasonable. Further, based on the
number of EGUs less than 125 MW in the HCl and PM MACT floor pools, we
believe that a similar analysis for HCl and PM would lead to similar or
more stringent standards than without the additional subcategory. Thus,
units of all sizes are capable of achieving the proposed limits and the
EPA is not finalizing a subcategory based on unit size in the final
rule.
The CAA authorizes EPA to subcategorize based on ``classes, types,
and sizes of sources.'' The EPA does not believe that this provision
permits subcategorizing sources based solely on their status as small
entities for several reasons. As a threshold matter, commenters
provided no information to suggest that EGUs at small entities are
different from EGUs owned by other entities. Instead, the commenters'
justification for such a subcategory was that the costs to comply with
the standards make it more difficult for small entities; thus, the
basis is essentially a cost basis and we do not think that is
consistent with the statute. Moreover, the legislative history of CAA
section 112(d) supports EPA's interpretation that subcategories cannot
be based on the cost of compliance. See S. Rep No. 101-228 at 166-67 (5
Legislative History at 8506-07) (rejecting the implication that
separate categories could be based on ``assertions of extraordinary
economic effects'').
In addition, the EGUs owned by small entities use the same type of
fuel as other units, have the same type of combustor designs, and can
use the same types of controls, and so there is no difference in the
HAP emissions from such units. So, even if we believed a subcategory
based on small entities was consistent with the statute, we would
decline to include such a subcategory.
Therefore, given the language of CAA section 112(d), the
legislative history, and the available information, EPA is not creating
a separate subcategory for EGUs owned by small entities.
In addition, the D.C. Circuit has clearly stated that the EPA does
not have the statutory authority under CAA section 112 to extend
compliance dates past the 3-year maximum compliance time authorized in
CAA section 112(i)(3)(A) except consistent with CAA sections
112(i)(3)(B) and 112(i)(4). See NRDC v. EPA, 489 F.3d 1364, 1374 (D.C.
Cir. 2007) (finding that ``Congress enumerated specific exceptions to
the 3-year maximum, which indicates that Congress has spoken on the
question and has not provided the EPA with authority under subsection
112(i)(3)(B) to extend the compliance date * * *'') (citing also CAA
section 112(i)(4)). The EPA may not alter the compliance date based on
size or ownership considerations and, thus, we are not providing a
separate compliance date for different groups of EGUs in the final
rule.
Comment: One commenter stated that the EPA should establish a
subcategory consisting of EGUs that had received air construction
permits but had not yet commenced construction as of the date of the
EPA's proposed rule. The commenter believed that such a category would
be justified because a substantial amount of time, money, and effort
has been invested in these units. The commenter asserted that imposing
new source standards on these EGUs for which the EPA's proposed rule
had not been anticipated during their permit consideration would
unreasonably and arbitrarily impose additional costs and burdens on
these projects and would likely threaten the viability of many of them.
The standards for this subcategory would be based on the anticipated
performance of these units (as reflected by the permitted case-by-case
emission levels), ensuring a reasonable and appropriate level of HAP
control without unreasonably and arbitrarily interfering with the
development of these units.
Response: Clean Air Act section 112(a)(4) defines a new source as
``a stationary source the construction or reconstruction of which is
commenced after the Administrator first proposes regulations under this
section establishing an emission standard applicable to such source.''
The EPA's regulations implementing the CAA section 112 General
Provisions define ``commenced'' to mean ``with respect to construction
or reconstruction of an
[[Page 9399]]
affected source, that an owner or operator has undertaken a continuous
program of construction or reconstruction or that an owner or operator
has entered into a contractual obligation to undertake and complete,
within a reasonable time, a continuous program of construction or
reconstruction.'' See 40 CFR 63.2.
The EPA is constrained by the definition of ``new source'' such
that any source that ``commenced'' construction after the May 3, 2011,
proposal date is considered a new source under the statute and the
source must comply with the new source standards even if the source
received a final and legally effective CAA section 112(g) permit before
proposal. It is unclear from the comments whether the sources
identified in the comments have commenced construction as defined in
the regulations; however, the identified sources are existing sources,
not new sources, under the final rule if construction was commenced
prior to the proposal date.
Under the final rule, new sources must comply with the standards on
the date of promulgation or at startup, whichever is earlier, and
existing sources have 3 years to come into compliance with the final
standards. Pursuant to the EPA's regulations at 40 CFR 63.44(b)(1),
however, we may provide in a final CAA section 112(d) standard a
specific compliance date for those sources that obtained a final and
legally effective CAA section 112(g) case-by-case MACT standard and
submitted the information required by 40 CFR 63.43 to the Agency before
the close of the comment period. The EPA does not believe it has
received such information during the comment period and we are not
establishing a separate specific compliance period for sources that
obtained final and legally effective CAA section 112(g) standards prior
to promulgation of the final rule. In the absence of EPA action on this
issue, state Title V permitting authorities are required to ``establish
a compliance date in the [title V] permit that assures that the owner
or operator shall comply with the promulgated standard [ ] as
expeditiously as practicable, but not longer than 8 years after such
standard is promulgated * * *'' 40 CFR 63.44(b)(2). Sources with final
and legally effective section 112(g) standards should work with their
permitting authorities to determine the appropriate compliance date
consistent with the EPA regulations.
Comment: One commenter stated that in accordance with CAA section
112(d)(l), based on the government-to-government relationship of the
Navajo Nation and the U.S. government, and consistent with the right of
sovereignty and self-determination of the Navajo Nation, it may be
appropriate to classify EGUs on tribal lands in a different subcategory
from those on non-Indian lands. The commenter stated that in accordance
with the distinctive status of Indian lands, based on principles of
tribal sovereignty and self-determination, the government-to-government
relationship, and the flexibility of federal agencies mandated under
E.O. 13175, the EPA should classify sources on tribal lands as a unique
subcategory of EGUs for which emission standards for NESHAP should be
set pursuant to CAA section 112(d)(3).
Response: Pursuant to CAA section 112(d)(1), the EPA may
subcategorize sources based on differences in class, type, or size. In
the preamble to the proposed rule, the EPA further explains that any
basis for subcategorizing (e.g., class) must be related to an effect on
emissions, rather than some difference which does not affect emissions
performance. The EPA does not agree that a subcategory based on
location on Tribal lands is consistent with the statutory authority to
subcategorize, and commenters do not explain why emissions would be
different for EGUs located on Tribal lands. Absent that showing, EPA
believes it would not be appropriate to subcategorize units even if we
believed such a subcategory is consistent with the statute. CAA section
112 imposes specific requirements with respect to the methodology that
the EPA must use in establishing emission standards for HAP, including
Hg emissions from EGUs. Pursuant to CAA section 112(d)(1), the EPA may
subcategorize sources based on differences in class, type, or size. The
EPA believes, that any basis for subcategorizing (e.g., class) must be
related to an effect on emissions, rather than some difference which
does not affect emissions performance.
However, the EPA is sensitive to the commenters' concerns and
particularly recognizes the significance of Navajo Generating Station
to the Central Arizona Project and the water delivery to tribes. As a
result, EPA has been consulting with affected Indian tribes and working
closely with other federal agencies, including the Department of the
Interior, on these issues and intends to work with tribal and other
authorities to ensure a smooth transition and address specific issues
as they arise.
2. Oil Subcategories
Comment: Several commenters stated that distillate oil, and in
particular ultra-low sulfur diesel (ULSD) oil, has fuel characteristics
closer to that of pipeline gas than to residual oils. The metals, as
well as the ash and nitrogen content, of distillate oils are very low,
and the sulfur content of ULSD is approximately the same as that of
pipeline natural gas. The commenters state that distillate oil is a
more refined product than residual oil and, thus, burns cleaner.
According to commenters, separating liquid oil-fired EGUs into two
subcategories (distillate and residual oil) would be consistent with
the discussion of subcategory differentiation in the rule's preamble
which indicates that the division of a category into subcategories is
justified if the two subcategories have very different emissions, which
is true for distillate vs. residual oils. Distillate and residual oils
are also differentiated by their operating requirements. Some
commenters stated that as a consequence of the mechanical differences
between boilers designed for residual oil vs. distillate oils, and
between the fuel-handling requirements for the different fuels, it is
not possible to interchange oil types without significant modifications
to the oil storage tanks, transfer pumps, piping and valves, flow
control systems, burners, and burner control systems. Commenters also
noted that some of the EGUs in the EPA's liquid oil-fired database were
mischaracterized with regard to the type of oil burned during the 2010
ICR testing.
Some commenters alleged that by combining distillate and residual
oil into a single MACT category, the resultant MACT standards cannot be
satisfied by a boiler firing residual oil without substantial add-on
controls. The commenters asserted that creation of separate
subcategories for liquid oil-fired units that distinguish between
residual and distilled oil would render the standards more achievable
for distinct subcategories of EGUs and reduce the number of potential
plant closures while still advancing the goal of reducing overall
emissions. These commenters contend that MACT floors should not be used
to eliminate whole classes of existing EGUs through mathematical floor
calculations based on data from uncontrolled units and combining boiler
subcategories that are not capable of accommodating a different fuel.
One commenter stated that the EPA should not subcategorize liquid
oil-fired EGUs based upon different grades of liquid oil. Although
different grades of liquid oil may vary in their heat contents or
viscosities, the commenter maintained that there is no indication in
the rulemaking record that any physical
[[Page 9400]]
distinction among units burning different grades of liquid oil affects
the nature or characteristics of emissions in a way that impacts the
availability of controls. According to the commenter, both distillate
and residual oil-fired units can apply similar control technologies to
reduce HAP emissions, and EGUs firing these fuels do not have physical
distinctions that prevent controls from operating effectively. The
commenter believes that fuel switching is an appropriate control
technology and is available for liquid oil-fired sources. Residual fuel
oil contains higher levels of contaminants, including HAP, than
distillate oil, and because a regulated entity can readily burn cleaner
distillate oil in lieu of residual oil, it is inappropriate to
subcategorize based on the distillation fraction of the liquid oil.
Thus, according to the commenter, the grade of liquid-oil fuel does not
provide a reasonable basis for subcategorizing various groups of liquid
oil-fired EGUs. Another commenter alleges that the EPA did not list
distillate oil-fired EGUs in the 2000 Finding.
Response: The EPA has reviewed the data and determined that it is
not necessary to subcategorize distillate vs. residual oil. Commenters
had noted that the EPA's MACT Floor Analysis spreadsheet at proposal
had erroneously assigned the oil type used during testing for some
boilers. The EPA reviewed the data and determined that the submitting
companies had entered the data incorrectly, or had indicated that two
types of oil were fired in different parts of the 2010 ICR responses.
The EPA contacted all of the companies with oil-fired EGUs in the 2010
ICR to confirm the oil used during testing. Upon review of these data,
it became apparent that units using residual oil with ESPs or
distillate oil without control were the best-performing oil-fired EGUs
for PM and the HAP metals. Further, although emissions of HAP from
distillate oil-fired EGUs are generally lower than those from residual
oil-fired EGUs, EGUs burning distillate oil appeared to have higher
emissions of some HAP but lower emissions of others.
In addition, the EPA does not agree that distillate oil-fired EGUs
were not listed in the 2000 Finding. We believe it is inappropriate to
exclude distillate oil-fired EGUs from regulation under the final rule
because the Agency did not make a distinction when listing the oil-
fired units.
The EPA also disagrees with commenters that by providing the
distillate vs. residual oil subcategories as requested, the resultant
standards would be more achievable. Were the EPA to subcategorize
distillate oil from residual oil, the users of distillate oil would
have no means of compliance other than obtaining ``compliance'' oil
from their distributor (which was not indicated as an option by any
commenter) or converting to natural gas and being removed from the
subcategory. With no further subcategorization, oil-fired EGUs have the
option of installing an ESP or converting to distillate oil for
compliance. Commenters did not contend that it was impossible to
convert to distillate oil, only that it would require plant
modifications. Installing controls would also require plant
modifications so sources will be able to evaluate the options and
determine the most cost-effective option to comply with the final rule.
CAA section 112 is intended to be a technology-forcing statute, and,
because both distillate oil- and residual oil-fired EGUs were among the
best performing sources in the floor and both types are meeting the
final standards, we cannot reasonably conclude that the HAP emissions
characteristics of these similar types of units are distinct.
Therefore, the EPA is not establishing separate subcategories for
distillate and residual oil-fired units in the final rule.
3. Limited-Use Subcategory
Comment: Several commenters stated that EPA should establish a
limited-use subcategory for liquid oil-fired EGUs that are required to
burn oil during periods of natural gas curtailment. One commenter
stated that under New York State Reliability Council Rules, their
facility is required by the New York Independent System Operator
(NYISO), for reliability purposes, to maintain the capability to burn
oil and actually burn oil, from time to time, at varying load levels to
help avoid or avert potential natural gas shortages in New York City.
The requirements to burn oil under this program are mandatory and are
not within the commenter's discretion. The reliability rules require
that the commenter's EGUs maintain their co-firing capability to
respond to unplanned, emergency scenarios by operating on oil during
required minimum oil burn periods, typically 25 percent oil/75 percent
natural gas. The commenter noted that operation using oil at other
times or on 100 percent oil during reliability operation periods occurs
very infrequently; with natural gas expected to become more available
in future years, such an operating scenario will become less likely.
However, while the reliability rules remain in place and commenter's
boilers are required to operate under his regimen, the commenter
believed that it is essential that it be able to do so.
Other commenters noted that requiring installation of emission
controls on oil-fired units that operate at a 10 percent oil-fired
capacity factor or less is nonsensical and will result in little
environmental benefit. Commenters contend that low-capacity factor
units emit significantly less HAP than even well-controlled oil-fired
units with much higher capacity factors. In addition, commenters allege
that stack-testing at such units would be equally impractical and, in
addition, would likely require the unit to operate on oil (and emit HAP
just for the test) when it would otherwise be off-line or operating on
natural gas.
Response: As stated above, after considering comments received, we
are establishing a limited-use subcategory for liquid oil-fired EGUs
with an annual fired capacity factor of less than 8 percent averaged
over each 24-month block period after the compliance date.
At proposal, we solicited comment on establishing a limited-use
subcategory for liquid oil-fired EGUs:
EPA is also considering a limited-use subcategory to account for
liquid oil-fired units that only operate a limited amount of time
per year on oil and are inoperative the remainder of the year. Such
units could have specific emission limitations, reduced monitoring
requirements (limited operation may preclude the ability to conduct
stack testing), or be held to the same emission limitations (which
could be met through fuel sampling) as other liquid oil-fired units.
EPA solicits comment on all of these proposed subcategorization
approaches.
As stated above, the EPA did not have sufficient information on
limited-use liquid oil-fired EGUs upon which to base a subcategory at
proposal. Some sources required to test under the ICR did not submit
the data until after proposal. Commenters indicated that their units
are different because many of them are only called to service to
address reliability issues associated with, for example, natural gas
curtailments. The commenters further indicated that their units are
different because of the generally infrequent use and the sporadic, and
at times frequent, start-up and shutdown periods (e.g., they are often
only required to run for a couple of hours). These factors would lead
to differences in the emissions characteristics for these units such
that a numeric standard based on base load units would not likely be
achievable during the very limited times that these limited use oil-
fired units operate.
Based on comments received and our own analysis, we are finalizing
a subcategory for limited-use liquid oil-
[[Page 9401]]
fired EGUs as indicated elsewhere in this preamble. We find that these
units constitute a different class and type of units because they are
generally only used to address reliability issues associated with, for
example, natural gas curtailments, and because they in fact only run
for very limited periods in a year on a seasonal basis.
Although some commenters indicated a prevalence of natural gas/oil
co-fired EGUs, the EPA also understands that there are other liquid
oil-fired EGUs that do not co-fire natural gas but that could be
subject to mandatory operation during periods of natural gas
curtailment in their operating area if sufficient non-natural gas
capacity is not available. Based on a review of units that report oil
use to EPA, in 2010 there were 228 liquid oil-fired EGUs with a
capacity factor of less than 5 percent and an additional 10 units with
a capacity factor of between 5 percent and 10 percent. Only 2 of these
units have capacity factors between 5 percent and 8 percent. This
subcategory applies only to oil-fired EGUs that operate on oil alone
and act as peaking units, as they generally address reliability issues.
We are establishing the capacity factor threshold of 8 percent averaged
over each 24-month block period after the compliance date.\320\ In
addition, as discussed below, we are establishing work practice
standard for this subcategory in lieu of numeric emission standards.
---------------------------------------------------------------------------
\320\ Units that co-fire oil and natural gas where the oil
combustion comprises 10 percent or less of the capacity factor are
natural gas-fired EGUs that are not subject to this final rule.
---------------------------------------------------------------------------
Commenters that requested a subcategory for these units noted the
dichotomy of establishing a NESHAP to reduce emissions of HAP to the
environment while at the same time requiring an EGU to run for the sole
purpose of conducting emissions testing and thereby emitting those same
HAP. Because the operation of these units is infrequent and
unpredictable, performing testing to demonstrate that emission limits
are being met requires the sources to be scheduled to be operated
merely for the purpose of performing testing. We realize that similar
situations occurred in the gathering of emissions data through the 2010
ICR. However, unlike the case of one-time testing on a limited number
of these units, such testing would be mandatory on a yearly basis for
all of the EGUs upon the effective date of the final rule. Because
requiring testing under this rule would in many cases require operators
of these EGUs to schedule operation of these EGUs at times they would
not otherwise run, it would result in both extra cost related to the
testing as well as extra emissions; therefore, the Agency believes that
it is technically and economically impracticable to monitor emissions
for these EGUs, and that they should be subject to work practice
standards that would not require emissions monitoring.
The annual average capacity factor would be calculated on a 24-
month block period, commencing with the compliance date of the final
rule. For example, assuming a March 1, 2015, compliance date, the first
24-month block would commence on March 1, 2015, and end on February 28,
2017, with the next 24-month block averaging period commencing on March
1, 2017. We believe the 24-month averaging period is reasonable to
account for the fact that units needed to address reliability issues
(e.g., natural gas curtailment periods) will be called to service
sporadically. A 24-month averaging period provides flexibility to
ensure that these units can run if there are large periods when natural
gas is unavailable. As explained above, the data shows that most of
these units operate for less than 8 percent of the time, and in fact it
is usually less than 5 percent. Therefore, when considering whether
these units would be able to perform stack testing, in many cases this
will be for units that in fact operate significantly less than 8
percent of the time. In these cases, the EPA does not want to require
the units to operate more just for the purpose of running a stack test
resulting in additional pollution and cost. With projections for rising
oil prices relative to natural gas prices, we expect this trend to
continue. Liquid oil-fired EGUs subject to this subcategory would be
required to conduct the same initial and periodic tune-up as all other
affected units, but would have no other emission limit or work practice
requirements.
Although the EPA believes that the ability to burn oil up to 8
percent of the time should address concerns about units that may need
to operate using oil during gas curtailments. The EPA recognizes that
if there were a period where gas use was more severely limited, such
units might need the flexibility to operate for more than 8 percent in
one year and less in the next, which is why we are providing the 2-year
period; however based on the data we do not think EGUs in this
subcategory will exceed even the 5 percent capacity factor that the
data indicate is the average level for these sources.
4. Non-Continental Units
Comment: Commenters from affected island EGUs requested that non-
continental EGUs be subcategorized from continental EGUs based on their
lack of access to natural gas. The commenters urged the EPA to include
a ``non-continental liquid oil'' subcategory in the final rule.
According to the commenters, establishing a subcategory for non-
continental units is consistent with the approach the EPA has taken in
past rulemakings, including the final Industrial Boiler NESHAP. Non-
continental EGUs have little or no access to natural gas, minimal
control over the quality of available fuel, and disproportionately high
operational and maintenance costs. All oil-fired EGUs operating in
Hawaii, Guam, and Puerto Rico combust residual fuel oil exclusively and
all are limited by the crude slates of their fuel suppliers. Island
utilities can contract with suppliers for certain fuel specifications,
such as sulfur content, pour point, flash point, API gravity and
viscosity, which the refiners are able to meet primarily by blending
and some sulfur removal during the refining process. However, the
commenters state that the suppliers do not and cannot economically
control for metal content. The crude slate feeding the refinery
determines the HAP metal content of the residual oil produced according
to the commenters. Because island utilities are dependent on local
sources of fuel, they are equally limited by these factors.
Two commenters believe that the separate non-continental
subcategory should be expanded to include continental areas that are
not interconnected with other utilities and have limited compliance
options due to remote locations (e.g., Alaska).
Response: The EPA agrees that the unique considerations faced by
non-continental EGUs warrant a separate subcategory for these units and
the data show that the difference in location causes a difference in
emissions apparently due to the fuel that is available for such units;
thus, the Agency has included such a subcategory in the final rule. At
proposal, the EPA did not have all of the data from liquid oil-fired
units in non-continental areas (e.g., Guam, Puerto Rico) and solicited
comment on whether a subcategory should be established, based on the
data to be received, for non-continental oil-fired EGUs. The EPA has
now received these late data and, based on those data, is finalizing a
non-continental subcategory for liquid oil-fired EGUs in Guam, Hawaii,
Puerto Rico, and the U.S. Virgin Islands. The EPA is not aware of
[[Page 9402]]
any liquid oil-fired EGUs in any of the other U.S. territories that
meet the CAA section 112(a)(8) definition but, if there are such units,
they would also be part of the non-continental subcategory.
The EPA agrees that the unique considerations faced by non-
continental refineries, including a limited ability to obtain
alternative fuels that lead to different emissions characteristics,
warrant a separate subcategory for these EGUs. The EPA believes that
units in this subcategory will comply through the use of cleaner oils
or, for PM, through the installation of an ESP. The EPA finds no merit
in the comment that Alaska should be included in this non-continental
subcategory because utilities in Alaska are not faced with the same
access issues affecting island-based facilities.
C. Surrogacy
1. Filterable PM vs. Total PM
Comment: Numerous commenters strongly objected to the use of total
PM as the surrogate standard for non-mercury HAP metals. They argued
that filterable PM is a better surrogate, especially given EPA's intent
to use a PM CEMS for continuous compliance demonstration. Other
commenters argued that we should not use a surrogate and instead should
require direct compliance with a non-mercury HAP metals standard.
Response: We have decided to use a filterable PM limit for the PM
surrogate emission limit in the final rule.
Although the objective of the emission limits we are establishing
is to reduce the risks associated with HAP emissions, the limits are
based in part upon the demonstrated capabilities of control
technologies which are installed on existing sources. Except for Hg,
the best PM controls provide the best controls of metal emissions.
Emissions measurements of either filterable particulate, total
particulate, individual metals, or total metals provide comparable
indications that the best level of control is achieved. We can find no
significant difference in the emissions that would be achieved by using
any one of these emissions measurements.
We re-assessed the relationships between individual metal
emissions, filterable PM emissions, total PM emissions, and total
PM2.5 emissions based on the test results provided through
part III of the 2010 ICR. We compared the measured emissions of metals
and PM with the uncontrolled emissions estimates and found that control
of PM was indicative of the control of metals emissions. In addition,
we compared the correlations associated with non-mercury HAP metal
emissions and the three forms of PM and found that no specific
particulate form provided a consistently superior indicator of better
metals control. Although control of filterable PM provided the best
indicator of performance for control of some HAP metals, control of
total particulate or total PM2.5 was nearly as good as an
indicator. For control of other HAP metals, total PM measurement
provided the best indicator of control performance because it included
the vapor-phase metal HAP, although, measurement of the control of
filterable particulate was nearly as good an indicator. In addition,
certain data analyzed by our Office of Research and Development
indicate that a vapor-phase metal, such as Se, can be present as an
acid gas and reduced significantly using acid gas technologies (wet and
dry scrubbing). Given that the rule also provides for acid gas control
monitoring, and the general equivalency of the different indicators, we
have concluded that use of a filterable PM limit as the PM surrogate
emission limit is appropriate.
2. Moisture Content of Oil
Comment: A number of commenters stated that studies suggest that
chloride in fuel oil can result from contamination during
transportation and processing of crude oils and then be emitted as HCl
during combustion. For example, the commenters asserted that the
chloride contamination of crude oils can occur as a result of the
ballasting of tanker ships with seawater. However, the Oil Pollution
Act of 1990 requires all new oil tankers to be double hulled and
establishes a phase out schedule (by the middle of the decade) for
existing single hulled tankers with un-segregated ballasts. Because of
the role of seawater contamination in introducing contaminants into the
oil, the commenters suggest that the EPA set a percent water content
limit for fuel oil at a level of 1.0 percent, rather than setting HCl
and HF emissions limits. This would encourage handling and transport
practices to limit salt water contamination. One commenter recommended
a standard of 1.0 percent water because several of the lowest HCl and
HF emitting units currently require percent water (or water and
sediment) specifications between 0.5 percent and 1.0 percent.
Response: The EPA is providing the alternative compliance assurance
approaches in the final rule for liquid oil-fired EGUs of demonstrating
compliance through either specific HCl or HF measurements or by
demonstrating that the moisture content in the fuel oil remains at a
level no more than 1.0 percent.
The EPA is not aware of any FGD systems installed on oil-fired
EGUs. Thus, it is only the quality of the oil, and the level of HAP
constituents contained therein, that can be relied upon for ensuring
compliance.
In the proposal preamble, we stated:
We believe that chlorine may not be a compound generally
expected to be present in oil. The ICR data that we have received
suggests that in at least some oil, it is in fact present. EPA
requests comment on whether chlorine would be expected to be a
contaminant in oil and if not, why it is appearing in the ICR data.
To the extent it would not be expected, we are taking comment on the
appropriateness of an HCl limit. See 76 FR 25045.
Commenters refer to certain studies that provide a plausible reason
for the chloride/fluoride contamination of fuel oils. We found this
reason persuasive and accordingly are providing alternative compliance
approaches in the final rule to demonstrate compliance with the acid
gas HAP standards. Specifically, sources can demonstrate compliance
through either specific HCl or HF measurements or by demonstrating that
the moisture content in the fuel oil remains at a level no more than
1.0 percent.
D. Area Sources
Comment: Numerous comments were received both in support of and in
opposition to the establishment of generally available control
technology (GACT) standards for area source EGUs.
Several commenters in opposition to area source standards stated
that the EPA properly established emissions limitations based upon the
performance of all EGUs, rather than distinguishing between major
sources and area sources. The commenters believe that Congress did not
intend the EPA to distinguish between ``major source'' EGUs and ``area
source'' EGUs in determining whether and how to regulate EGUs under CAA
section 112. These commenters indicated that differentiating major
source and area source EGUs for purposes of setting emissions standards
is inappropriate in light of the 2000 Finding regarding the threat
posed by the absence of regulation of HAP emissions from EGUs. The 2000
Finding was based upon studies whose conclusions regarding the impacts
from EGU emissions did not depend upon any relevant distinction between
major source and area source EGUs. The commenters note that segregating
``major source'' and ``area source'' EGUs
[[Page 9403]]
would have the perverse effect of eliminating some of the best
performing sources from the MACT pool of sources that constitute the
``best performing'' 12 percent. Many of the best performing sources
have employed control technology that brings their emissions below the
major source threshold, despite the fact that they are larger units. As
a result, the commenters believe that if the EPA created standards for
``major source'' EGUs based only upon those units, the MACT standards
for ``major source'' EGUs would be less stringent for each of the
pollutants than proposed in this Rule. At the same time, the less
polluting sources, the ``area source'' EGUs, could face limits more
stringent than those proposed in the Rule. Commenters also note that
after reviewing the substantial record in this rulemaking, they believe
that the EPA has correctly determined that major and area source EGUs
greater than 25 MW have similar HAP emissions and use the same control
technologies and techniques to reduce HAP emissions. Thus, the
commenters asserted that the record demonstrates that there is no
technical basis for distinguishing between major and area source EGUs
for purposes of establishing HAP emission control standards under CAA
section 112(d).
Many commenters in support of an area source designation for EGUs
stated that the EPA has promulgated area source limits for many source
categories of HAP emissions, including most recently industrial boilers
and note that GACT controls have been used successfully in many other
EPA MACT rules, including rules for iron & steel foundries, electric
arc steelmaking, coatings operations, clay ceramics manufacturing,
glass manufacturing, and secondary nonferrous metals manufacturing, in
order to reduce costs and regulatory burdens. The commenters state that
Congress has given the EPA the ability to subcategorize area sources
because of their low HAP emissions and low potential impact on human
health and that, contrary to the plain language of CAA section 112 and
its legislative history, the EPA made no attempt in the proposed rule
to distinguish between major sources and area sources for purposes of
listing or setting standards. The commenters indicated that where
Congress was concerned about the health impacts of specific pollutants
from specific sources, it knew how to specify that MACT limits be
promulgated (e.g., CAA section 112(c)(6)). The commenters state that
area source rules would lessen the regulatory burden of a CAA section
112 EGU rule on many small entities (arguing that many EGUs owned by
small public power entities are area sources) and that as many as 12
percent of the EGU population could qualify as area sources. A number
of commenters pointed out that the small entity representatives (SER)
on the SBREFA panel suggested that the EPA establish separate emission
standards for EGUs located at area sources of HAP and that the
standards be based on GACT as allowed under CAA section 112(d)(5).
Specifically, the SERs recommended that the EPA establish management
practice standards for area source EGUs.
Response: The EPA is not establishing an area vs. major source
distinction in the final rule.
The CAA section 112(a)(8) definition of EGU does not distinguish
between major and area sources, and we maintain that EGUs are a single
source category that contains both major and area sources. The EPA
proposed to regulate five subcategories of EGUs without distinguishing
between major and area sources for purposes of establishing the
standards for the different subcategories. Our approach is wholly
consistent with the statutory definition of EGU and reasonable.
Nevertheless, the Agency did examine whether to set separate
standards for area source EGUs, because we do not believe that the
statute prohibits the Agency from exercising its discretion to
establish GACT standards for area sources pursuant to CAA section
112(d)(5) if we determine such standards are appropriate. The EPA is
not required, however, to establish GACT standards for area sources,
and we believe it may even be unreasonable to do so under the
circumstances we identified in the proposed rule as supported by the
record of this final rule.
At proposal, we determined that it was not appropriate to establish
separate standards for major and area source EGUs, and even if we had
exercised our discretion to set separate standards, we would have
likely declined to exercise our discretion to set GACT standards for
area source EGUs given our appropriate and necessary finding and the
fact that a potentially large number of area source EGUs are in fact
large well controlled units.
Some commenters note that there could be as many as 12 percent of
the total population that could be classified as area sources. We are
not sure of the commenters' point in regard to this statement. As to
commenters' statements that many of the area sources are municipal
utilities, our information shows that many rather large EGUs (e.g.,
hundreds of MW) are also area sources, and the commenters have not
provided any justification for establishing GACT standards for large
synthetic area sources.
Commenters did not provide an evaluation of the health and
environmental impacts of the area sources and simply presume that the
risks from such sources are lower, even though many of the same
commenters noted that these smaller EGUs are often located in densely
populated areas where populations are more likely to have adverse
health effects from the HAP emissions. Furthermore, other commenters,
including some industry commenters, noted that the vast majority of
these potential area sources meet the criteria due to the installation
of emission controls installed to meet other requirements. According to
these commenters, these synthetic area sources would likely be able to
meet the limits of this rulemaking and imposition of this rule would
not appear to result in the installation of additional controls in a
number of cases. We do not know if this assertion is correct but we
determined approximately 69 coal-fired EGUs will be able to meet the
existing source MACT standards with their current control configuration
(out of 252 EGUs that reported data for Hg, PM, and HCl in the 2010
ICR).
Commenters also note that the Agency has exercised its discretion
in other NESHAP rulemakings to establish area source limits. Although
true, the fact that the EPA has established area source limits in some
source categories is irrelevant to similar decisions for different
source categories. Commenters have not shown that the circumstances
applicable to those other source categories are similar to the
circumstances identified for major and area source EGUs (e.g., similar
controls, similar emission characteristics, large number of synthetic
minor area sources). Further, those other source categories are not
statutorily defined in a manner that includes both area and major
sources. EGUs are the only source category defined in CAA section 112
and, in establishing the definition of an ``electric utility steam
generating unit'' under CAA section 112(a)(8), Congress included in the
EGU source category both area and major sources. Thus, it is reasonable
to regulate the EGU category in the manner Congress defined the
category. Commenters have provided no legal support for the contention
that the EPA must regulate area and major sources in the same category
in separate rulemakings, and the EPA has in fact regulated both major
and area sources in
[[Page 9404]]
the same rulemaking even absent a statutory definition that includes
both major and area sources. (See National Emission Standards for
Hazardous Air Pollutants From the Portland Cement Manufacturing
Industry and Standards of Performance for Portland Cement Plants; 75 FR
54970; September 9, 2010.)
The EPA considered the totality of the circumstances when
determining whether to set separate area and major source standards for
EGUs and also considered whether it would be reasonable to establish
GACT standards for areas sources. We reasonably considered whether
emissions characteristics of major and area sources are different when
determining whether to establish GACT standards, notwithstanding
commenters' assertion that such consideration is not correct. That we
also consider emission characteristics in subcategorization decisions
is of no consequence for area source decisions. Given that the
statutory definition of EGUs contains both major and area sources, it
was reasonable to evaluate whether there were sufficient differences
between area and major sources when deciding whether to exercise our
discretion to set separate area and major source standards.
In addition, we find commenter's point concerning CAA section
112(c)(6) odd because EGUs emit several of the CAA section 112(c)(6)
HAP (e.g., lead, Hg). Although EGUs were exempted from that provision,
the fact that they emit some of the HAP called out for MACT control
supports our decision to not establish GACT standards for any EGUs. CAA
section 112(d)(5) leaves it to the Agency's discretion to determine
whether GACT standards should be established for area sources, and the
statute does not require GACT standards or even indicate that such
standards are to be the default regulatory approach for area sources.
See 76 FR 25021. Instead, the statute provides the Agency with
discretion and we have exercised it reasonably in this case.
Commenters indicate that many EGUs owned by small entities are
potential area sources. However, commenters fail to note that there are
also EGUs owned by small entities that are not potential area sources,
and, thus, would not accrue any ``lessened regulatory burden'' benefit
from a decision by the EPA to establish area source standards.
Some commenters state that the EPA's mere assertion that there
would be no difference between GACT and MACT to justify an area source
finding does not provide sufficient documentation for the decision. But
EPA did not say there would be no difference between MACT and GACT.
Instead, it stated that it would be difficult to make a distinction
given the similarities between the EGUs and major and area source
facilities. Specifically, as noted by other commenters, and observable
by a review of the MACT Floor Analysis spreadsheets, potential area
sources range in size from units near the CAA section 112(a)(8) defined
lower size limit to units of hundreds of megawatts. Further, these
larger area source units are, for the most part, controlled with the
full suite of emission control technologies available (e.g., fabric
filters, scrubbers).
In addition, the data that were available in the docket for the
proposed rule show that there is little difference between major and
area source EGUs individually, and that generally the driver for
whether a utility facility is a major or area source depends on the
number of EGUs located at a facility (almost exclusively one or two
EGUs located at area sources), not on any inherent difference between
the EGUs themselves. See ``Evaluation of Area Source EGUs'' TSD, Docket
EPA-HQ-OAR-2009-0234. In fact there are a number of EGUs that are quite
large that are area sources and others that are small that are major
sources. Id. This is the case because the acid gas HAP emissions are
what drive EGUs to have HAP emissions exceeding the major source
threshold. With a few exceptions, the EGUs located at area sources have
FGD or other acid gas controls that reduce the acid gas HAP to area
source levels. Id. Thus, the majority of sources that currently qualify
as area sources were, in fact, major sources prior to installing
controls. The exceptions are those units that would likely be able to
achieve the MACT level of control for acid gas with minimal use of DSI
at a reasonable cost. Id.
In addition, the data show that a number of area sources for which
we have data are high emitters of Hg and non-Hg metal HAP. Id. Pursuant
to our appropriate and necessary finding, these HAP pose a significant
threat to human health. Thus, even were we to distinguish between major
and area sources, which we do not believe is appropriate given the
similarities between such sources, we would still decline to set GACT
standards, and as such we maintain that MACT standards are appropriate.
Moreover, for acid gas HAP, as discussed above, the data indicate that
the level of control would likely be the same even if we did establish
GACT standards under CAA section 112(d)(5).
We fully evaluated the nature of EGUs, and we do not see a basis on
which to distinguish these sources for purposes of setting standards.
Thus, we maintain that we reasonably exercised the discretion afforded
the Agency under the statute and declined to set separate standards for
area source EGUs.
E. Health-Based Emission Limits
Comment: Many commenters noted that in the proposed rule the EPA
considered whether it was appropriate to exercise its discretionary
authority to establish health-based emission limits (HBEL) under CAA
section 112(d)(4) for HCl and other acid gases and proposed not to
adopt such limits, citing, among other things, information gaps
regarding facility-specific emissions of acid gases, co-located sources
of acid gases and their cumulative impacts, potential environmental
impacts of acid gases, and the significant co-benefits estimated from
the adoption of the conventional MACT standard. Comments were received
both supporting this position and refuting it. Several commenters
suggested legal, regulatory and scientific reasons for why HBEL for HCl
might be appropriate for this MACT standard. With respect to legal
concerns, some commenters indicated that CAA section 112(d)(4)
establishes a mechanism for the EPA to exclude facilities from certain
pollution control regulations and circumstances when these facilities
can demonstrate that emissions do not pose a health risk. Commenters
cited a Senate Report that influenced development of CAA section
112(d)(4), where Congress recognized that, ``For some pollutants a MACT
emissions limitation may be far more stringent than is necessary to
protect public health and the environment.'' (Footnote: S. Rep. No.
101-128 (1990) at 171.) Commenters also cited regulatory precedent for
addressing HCl as a threshold pollutant, including the Hazardous Waste
Combustors and the Chemical Recovery Combustion Sources at Kraft, Soda,
Sulfite, and Stand-Alone Semichemical Pulp Mills NESHAP. Commenters
requested that the EPA incorporate the flexibility afforded by CAA
section 112(d)(4) and allow sources reasonable means for demonstrating
that their respective emissions do not warrant further control. The
commenters also cited the 2004 vacated Boiler MACT as precedent for
HBEL for HCl. The commenters contended that the EPA failed to explain
why the health-based emissions limitations it established in the 2004
Boiler MACT and the justification provided for those limitations could
not be used in this case. The commenters also cited a 2006
[[Page 9405]]
court briefing where the EPA vigorously defended the HBEL included in
the 2004 Boiler rule when it was challenged in the D.C. Circuit (Final
Brief For Respondent U.S. Environmental Protection Agency, D.C. Cir.
Case No. 04-1385 (Dec. 4, 2006) at 59-65, 69).
Other commenters stated that on August 6, 2010, the EPA adopted a
NESHAP for Portland Cement plants that specifically rejected adoption
of risk-based exemptions or HBEL for HCl and manganese (Mn). These
commenters argue there are no differences sufficient to warrant a
reversal of that decision in the EGU MACT standard. The commenters
raised concerns that health risk information cited by the EPA for HCl,
HF, and hydrogen cyanide (HCN) does not establish ``an ample margin of
safety'' and, therefore, no health threshold should be established. The
commenters believe risk-based exemptions at levels less stringent than
the MACT floor are prone to lawsuits that could potentially further
delay implementation of the EGU MACT.
Some commenters disagreed with using a hazard quotient (HQ)
approach to establish a risk-based standard because the HQ would not
account for potential toxicological interactions. The commenter noted
that an HQ approach incorrectly assumes the different acid gases affect
health through the same health endpoint, rather than assuming that the
gases interact in an additive fashion. This commenter suggested that a
hazard index approach, as described in the EPA's ``Guideline for the
Health Risk Assessment of Chemical Mixtures,'' would be more
appropriate.
Some commenters dispute that emissions from other EGUs or source
categories should be considered when developing an HBEL and they argued
that Congress expected the EPA to consider the effect of co-located
facilities during the CAA section 112(f) residual risk program instead
of under CAA section 112(d). Commenters added that there is no prior
EPA precedent for considering co-located facilities from a different
source category during the same CAA section 112 rulemaking.
Several commenters disputed the EPA's consideration of non-HAP
collateral emissions reductions in setting MACT standards. They
contended that the EPA's sole support for its ``collateral benefits''
theory is legislative history--the Senate Report that accompanied
Senate Bill 1630 in 1989 and noted that the D.C. Circuit rejected this
use of this theory since the Senate Report referred to an earlier
version of the statute that was ultimately not enacted. Instead
commenters suggested that other components of the CAA, such as the
National Ambient Air Quality Standards (NAAQS), are more appropriate
avenues for mitigating emissions of criteria pollutants.
Several other commenters suggested it is impossible to assess an
established health threshold for HCl such that a CAA section 112(d)(4)
standard could be set without evaluating the collateral benefits of a
MACT standard. And, as described in the recently finalized cement kiln
MACT rule, setting technology-based standards for HCl will result in
significant reductions in the emissions of other pollutants, including
SO2, Hg, and PM. The commenter added that these reductions
will provide enormous health and environmental benefits, which would
not be experienced if CAA section 112(d)(4) standards had been
finalized. These commenters contended that HCl and other dangerous acid
gases produced by EGUs pose substantial risks to industrial workers, as
well as surrounding communities, and must be limited by the strict
conventional MACT standards.
Several commenters indicated that the current economic climate
requires the EPA to balance economic and environmental interests and
indicated that HBEL would help target investments into solving true
health threats where limits are no more or less stringent than needed
to protect public health. Many commenters provided estimates of
compliance cost savings if an HBEL is included in this final rule. Some
commenters stressed the importance of an HBEL for small entities
affected by the regulations. Several other commenters suggested that
the EPA should estimate the costs and environmental effects of the HBEL
option compared to a conventional MACT standard in order to make an
informed decision on the adoption of HBEL.
Response: After considering the comments received, the EPA has
decided not to adopt an emissions standard based on its authority under
CAA section 112(d)(4) for all the reasons set forth in the proposed
rule.
The EPA notes that the Agency's authority under CAA section
112(d)(4) is discretionary. That provision states that the EPA ``may''
consider establishing health thresholds when setting emissions
standards under CAA section 112(d). By the use of the term ``may,''
Congress clearly intended to allow the EPA to decide not to consider a
health threshold even for pollutants which have an established
threshold. As explained in the preamble to the proposed rule, it is
appropriate for the EPA to consider relevant factors when deciding
whether to exercise its discretion under CAA section 112(d)(4), and,
notwithstanding commenters' assertions to the contrary, the
considerations we include in our analysis are reasonable. The EPA has
considered the public comments received and is not adopting an
emissions standard under CAA section 112(d)(4) for the reasons set
forth in the proposed rule and explained below. We note that this
action is consistent with EPA's recent decisions not to develop
standards under CAA section 112(d)(4) for the Industrial, Commercial
and Institutional Boilers and Process Heaters and the Portland Cement
source categories.
As explained in the preamble to the proposed rule, the EPA
continues to believe that the potential cumulative public health and
environmental effects of all acid gas HAP emissions, not just HCl
emissions, from EGUs and other acid gas sources located near EGUs
supports the Agency's decision not to exercise its discretion under CAA
section 112(d)(4). Additional data for all acid gas emissions were not
provided during the comment period, and the data already in hand
regarding these emissions are not sufficient to support the development
of emissions standards for EGUs under CAA section 112(d) that take into
account the health threshold for acid gas HAP, particularly given that
the Act requires the EPA's consideration of health thresholds under CAA
section 112(d)(4) to protect public health with an ample margin of
safety. We note here that EPA agrees with the commenter who pointed out
that a better way to evaluate the potential health impact interactions
of all acid gases would be to use the approach in EPA's ``Guideline for
the Health Risk Assessment of Chemical Mixtures'' rather than a simple
evaluation of individual HQ values for each acid gas, but we further
note that use of such an approach requires a substantially greater
knowledge of acid gas emissions than is currently available. We further
note that, even if cost were a relevant factor in setting standards
under CAA section 112(d)(4), since the data are not available that
would allow us to develop an acid gas HBEL appropriate to protect
public health with an ample margin of safety, we cannot determine
whether such standards would have any cost savings associated with them
or not. In addition, the concerns expressed by the EPA in the proposal
regarding the potential environmental impacts and the cumulative
impacts of acid gases on public health were not assuaged by the
[[Page 9406]]
comments received because no significant data regarding these impacts
were received.
The EPA also received comments recommending not only that the EPA
establish emissions standards for acid gases pursuant to CAA section
112(d)(4), but that it do so by excluding specific facilities from
complying with emissions limits if the facility demonstrates that its
emissions do not pose a health risk. The EPA does not believe that a
plain reading of the statute supports the establishment of such an
approach. Although CAA section 112(d)(4) authorizes the EPA to consider
the level of the health threshold for pollutants which have an
established threshold, that threshold may be considered ``when
establishing emissions standards under [CAA section 112(d)].''
Therefore, the EPA must still establish emissions standards under CAA
section 112(d) even if it chooses to exercise its discretion to
consider an established health threshold. A source-by-source standard
is not mandated as some commenters seem to imply, and we are unsure how
we could reasonably implement such an approach even if we determined
such an approach was legally available. For these reasons alone, we
concluded it was not appropriate to exercise our discretion to
establish section 112(d)(4) standards for acid gas HAP emissions.
In addition, as explained in the preamble to the proposed rule, the
EPA also considered the co-benefits of setting a conventional MACT
standard for HCl. The EPA considered the comments received on this
issue and continues to believe that the estimated co-benefits are
significant and provide an additional basis for the Administrator to
conclude that it is not appropriate to exercise her discretion under
CAA section 112(d)(4). The EPA disagrees with the commenters who stated
that it is not appropriate to consider non-HAP benefits in deciding
whether to invoke CAA section 112(d)(4). Although MACT standards may
directly regulate only HAP and not criteria pollutants, Congress did
recognize, in the legislative history to CAA section 112(d)(4), that
MACT standards would have the collateral benefit of controlling
criteria pollutants as well and viewed this as an important benefit of
the air toxics program. See S. Rep. No. 101-228, 101st Cong. 1st sess.
at 172. The EPA consequently does not accept the argument that it
cannot consider reductions of criteria pollutants in determining
whether to take or not take certain discretionary actions, such as
whether to adopt an HBEL under CAA section 112(d)(4). There appears to
be no valid reason that, in situations where the EPA has discretion in
what type of standard to adopt, the EPA must ignore controls which
further the health and environmental outcomes at which CAA section
112(d) is fundamentally aimed because such controls not only reduce HAP
emissions but emissions of other air pollutants as well. Thus, the
issue being addressed is not whether to regulate non-HAP under CAA
section 112(d) or whether to consider other air quality benefits in
setting CAA section 112(d)(2) standards--neither of which the EPA is
doing--but rather whether EPA may exercise its discretion to regulate
certain HAP based on the MACT approach and consider collateral health
and environmental benefits when choosing whether to exercise that
discretion. The EPA believes there is no legal principle that precludes
it from doing so and commenters have not provided one.
F. Compliance Date and Reliability Issues
Comment: Multiple commenters asked that the compliance date be
clearly stated as soon as possible, as well as that guidance be
provided for utilities unable to comply with the stated timelines, to
allow time for utilities to prepare for compliance. Commenters also
asked that any decisions or policies on extensions be published in a
rulemaking. In addition, commenters requested that the EPA establish,
streamline, and simplify the process of applying for the 1-year
extension under CAA section 112(i)(3).
Multiple commenters offered suggestions on methods for allowing
more time for compliance, including EPA's authority under CAA section
112(n)(1)(A); state authority under CAA section 112(i)(3); Presidential
authority under CAA section 112(i)(4); categorical extensions for
publicly-owned or governmental facilities according to EO 13132, 13563,
and UMRA of 1995; state-designed programs under the delegation
provisions of CAA section 112; various Consent Decrees; Administrative
Orders of Consent (AOCs); temporary waiver mechanisms; and adoption of
MACT compliance schedules through minor permit modifications of a
source's Title V federal operating permits. Absent such considerations
for additional compliance time, many commenters suggested that the
reliability of the nation's electric grid would be jeopardized as
utility companies were forced to retire EGUs because they could not
install the needed controls in the requisite time.
Compliance times requested by commenters ranged from 1 additional
year (4 years total) to 6 additional years (9 years total). Multiple
commenters requested that a utility be required to demonstrate good
faith progress toward compliance to get any extension. Some commenters
suggested that the EPA require utilities to submit a notice concerning
which EGUs will be retrofitted or retired within 1 year of the
effective date; that the compliance date align with the Power Year used
by RTOs; and that the EPA clarify that retirement and any clean
replacement power that complies with the NESHAP rule, including off-
site combined heat and power and waste heat recovery, can be deemed
``controls'' under the CAA.
Commenters noted the specific situations related to small entities
and their inability to compete with the larger, investor-owned
utilities for financing and engineering and technical labor as well as
the different process they need to follow for capital improvements.
Multiple commenters asked that the EPA consider other simultaneous
rulemakings (e.g., Cooling Water Intake Structures; Coal Combustion
Residuals; CSAPR, etc.) and extend the compliance period. Many
commenters noted these other requirements and suggested that
installation of the necessary controls could not be completed within
the compliance period allowed under CAA section 112, even if a fourth
year were to be granted by the permitting authority, citing examples of
the times necessary for installation of various pieces of control
equipment or replacement power.
Some commenters pointed to existing state programs (e.g., Colorado,
Oregon, Washington) and indicated that if states can demonstrate that
overall emissions reductions would be equivalent or greater than those
that would be achieved by the proposed rule, the EPA should delegate
the CAA section 112 program to these states, even if the state
emissions reductions would not necessarily occur on the same schedule
(many state programs call for retirement of EGUs in years beyond the
CAA section 112 compliance date). The commenters did not want the
promulgation of the final rule to undermine the significant amount of
work that may have been invested in creating state-specific programs to
curb emissions within a reasonable timeframe. The commenters seek to
make use of temporal flexibility, authorized under CAA section
112(i)(3), in obtaining delegation of the final rule to preserve the
hard-negotiated comprehensive state-specific programs designed to yield
greater emission reductions than the MATS alone.
[[Page 9407]]
Other commenters requested that no additional time be granted for
compliance. These commenters reference a number of reports (e.g., by
the URS Corporation, by M.J. Bradley & Associates and the Analysis
Group, and by the Bipartisan Policy Center) to indicate that not only
is technology readily available, but that the technology can typically
be installed in less than 2 years and that the electric industry is
well-positioned to comply with the EPA's proposed air regulations
without threatening electric system reliability. Commenters assert
that, if electric system reliability were to be threatened in local
areas as a result of the rule, the EPA has the statutory authority to
grant, on a case-by-case basis, extensions of time to complete the
installation of pollution control systems. One commenter stated that no
additional controls would need to be installed in many cases and any
coal unit should be able to comply with all of the standards. Another
commenter noted that utilities that failed to plan ahead ``should not
be permitted to use their own inaction to justify more time.''
Commenters noted that several major utility companies have anticipated
the EPA's rules and are already taking action to ensure a reliable
supply of electricity in their service territory and beyond. Other
commenters agree that there is significant excess generation capacity
in the country and reliability will not be threatened by the rule.
According to one commenter, companies are already preparing for a 2015
compliance date, factoring in the capital expenditures required to
comply and delays would undermine decisions that have already been
made. Commenters cite, for example, recent electricity forward capacity
market auctions in the PJM market for the period of 2014 and 2015 that
indicate that the capacity markets cleared with electricity reserve
margins of 20 percent; this is in excess of the default reliability
targets used by the North American Electric Reliability Corporation
(NERC) for the year 2015. One commenter quoted NERC, stating that NERC
does not see impacts from proposed climate legislation or anticipated
EPA regulation as a reliability concern. Another commenter noted that
the Building and Construction Division of the AFL-CIO has stated that
there is no evidence to suggest that the availability of skilled
manpower will constrain pollution control technology installation. In
fact, according to the commenter, given the high levels of unemployment
in the construction sector, these jobs are much needed.
A number of commenters expressed concern that the time frame for
compliance with a regulation under CAA section 112(d) was too short for
this industry and would result in compromising the reliability of
electricity supply. Commenters asserted that reliability would be
compromised in several ways: (1) EGUs might have to temporarily close
if the owner or operator is unable to install controls on the unit
within the 3-year time frame or 3 years plus one; (2) the timing of
outages to install controls will cause short term closures that could
threaten grid stability; (3) owner/operators may shut down EGUs rather
than invest in retrofits to keep them running and that these closures
may cause a loss of critical generation; and (4) the construction of
replacement generation or implementation of other measures to address
reliability concerns due to plant retirements could take longer than 3
years, and that units slated for closure may be necessary beyond the 3-
year compliance period but will be unable to run because they have not
installed the necessary controls.
Response: Clean Air Act section 112 specifies the dates by which
affected sources must comply with this rule. New or reconstructed units
must be in compliance immediately upon startup or the effective date of
this rule, whichever is later. Existing sources may be provided up to 3
years after the effective date to comply with the final rule; if an
existing source is unable to comply within 3 years, a permitting
authority has the ability to grant such a source up to a 1-year
extension, on a case-by-case basis, if such additional time is
necessary for the installation of controls.
As is explained earlier in this preamble, the 3-year compliance
window is based on the date that is 60 days after publication of this
rule in the Federal Register. Because publication doesn't occur until
several weeks after the rule is signed by the Administrator, the
earliest required date for compliance would be sometime in March 2015.
Because the last stage of control installations usually needs to occur
when the unit is off-line and because scheduled outages are usually
scheduled for the spring or fall months when peak electric demand is
lower, this additional time is significant as it provides companies an
additional outage period, the spring of 2015, to install controls.
The EPA has considered the concerns raised by commenters and has
concluded that given the flexibilities further detailed in this
section, the requirements of the final rule for existing sources can be
met by most sources without adversely impacting electric reliability.
In particular, EPA believes that the flexibility of permitting
authorities to allow a fourth year for compliance should be available
in a broad range of situations (as discussed below), and that this
flexibility addresses many of the concerns that have been raised.
Furthermore as indicated below, in the event that an isolated,
localized concern were to emerge that could not be addressed solely
through the 1-year extension under CAA section 112(i)(3), the CAA
provides flexibilities to bring sources into compliance while
maintaining reliability.
The EPA considered the impact that potential retirements in
response to this rule will have on resource adequacy in order to gauge
the rule's impact on reliability. In considering these impacts, the EPA
considered both the analysis it has conducted as well as analyses
conducted by a number of other groups. The EPA's analysis shows that
the expected retirements of coal-fueled units as a result of this final
rule (4.7 GW) are fewer than was estimated at proposal and much fewer
than some have predicted.\321\ The net capacity reductions projected by
the EPA make up less than one-half of one percent of the total
generating capacity in the U.S. and about one and one-half percent of
U.S. coal capacity. Because concerns have been raised that the use of
DSI may not be as prevalent as the Agency has predicted and because
this could lead to more coal retirements, the Agency also performed a
sensitivity analysis in which fewer DSI systems and more scrubber
systems were installed. In that sensitivity, we see approximately 1
more GW of retirements. This small change would have only a very small
potential impact on resource adequacy. When considering the impact that
one specific action has on power plant retirements, it is important to
understand that the economics that drive retirements are based on
multiple factors including: expected demand for electricity, the cost
of alternative generation, and the cost of continuing to generate using
an existing unit. The EPA's analysis shows that the lower cost of
alternative fuels, particularly natural gas, as well as reductions in
demand, will have a greater impact on the
[[Page 9408]]
number of projected retirements than will the impact of this final
rule.
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\321\ The EPA's analysis also identifies a small amount of
capacity loss (less than 0.7 GW) due to derating of certain units,
as well as partially offsetting reductions in non-coal retirements
in comparison with the base case. The net estimated reduction in
capacity, in comparison with the base case, is estimated at less
than 5 GW.
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The EPA's assessment looked at the capacity reserve margins in each
of 32 subregions in the continental U.S. Demand forecasts used were
based on EIA projected demand growth. The analysis shows that with the
addition of very little new capacity, average reserve margins are
significantly higher than required. The NERC assumes a default reserve
margin of 15 percent while the average capacity margin seen after
implementation of the policy is nearly 25 percent. Although such an
analysis does not address the potential for more localized reliability
concerns associated with transmission constraints or the provision of
location-specific ancillary services (such as voltage support and black
start service), the number of retirements projected suggests that the
magnitude of any local reliability concerns should be manageable with
existing tools and processes.
Several outside analyses have reached conclusions consistent with
EPA's analysis. The DOE, in December 2011, published a report that
looked at resource adequacy in the bulk power system when faced with a
stress test which was a regulatory scenario far more stringent than
EPA's regulations.\322\ For this stress test, in addition to CSAPR and
MATS requirements, each uncontrolled electric generator is required to
install both a wet FGD system and a fabric filter to reduce air toxics
emissions. If such installations are not economically justified, this
scenario assumes that the plant must retire by 2015. In reality, as
discussed previously, power plant owners will have multiple other
technology options to comply with the regulations--options that
typically cost less than installations of FGDs and fabric filters. The
analysis finds that target reserve margins can be met in all regions,
even under these stringent assumptions. Moreover, in every region but
one (TRE), no additional new capacity is needed. In TRE, the analysis
finds that less than 1 GW of new natural gas capacity would be needed
by 2015 beyond the additions already projected to occur in the
Reference Case. This analysis also finds that the total amount of new
capacity that would be added by 2015 is less than the amount that is
already under development.
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\322\ U.S. Department of Energy, December 2011, ``Resource
Adequacy Implications of Forthcoming EPA Air Quality Regulations.''
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In June 2011, the Bipartisan Policy Center issued a report
analyzing potential collective impacts of EPA's pending power sector
rules and concluding that ``scenarios in which electric system
reliability is broadly affected are unlikely to occur.'' \323\
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\323\ Bipartisan Policy Center, June 2011, ``Environmental
Regulation and Electric System Reliability.''
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In August 2011, PJM Interconnection--the Regional Transmission
Operator (RTO) responsible for planning and reliable operation of the
bulk power system serving all or portions of 13 states in the Mid-
Atlantic and Midwestern regions--issued a report analyzing the impacts
of the CSAPR and the proposed MATS rule.\324\ Although PJM's analysis
assumes substantially more retirements than EPA projects, it
nevertheless concludes that resource adequacy is not threatened in the
PJM region. This is particularly significant, given that the PJM region
is one of the largest and most heavily dependent on coal-fueled
generation in the country. The PJM analysis notes, as EPA has
acknowledged, that even where there is adequate generation capacity on
a regional basis, localized reliability issues may emerge in connection
with retirements that may need to be addressed.
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\324\ PJM Interconnection, August 26, 2011, `` Coal Capacity at
Risk for Retirement in PJM: Potential Impacts of the Finalized EPA
Cross State Air Pollution Rule and Proposed National Emissions
Standards for Hazardous Air Pollutants.''
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The EPA has reviewed industry and NERC studies suggesting, contrary
to the EPA's and these other groups' analyses, that EPA rules affecting
the power sector (including this final rule, the CSAPR, EPA's proposed
rule addressing power plant cooling water intake systems under section
316(b) of the Clean Water Act (CWA), and EPA's proposed rule addressing
coal combustion residuals under the Resource Conservation and Recovery
Act) will result in substantial power plant retirements. Some of these
studies predict that such levels of retirements will have adverse
effects on electric reliability in some regions of the country.
Although the specifics of these analyses differ, in general they share
a number of serious flaws in common that call their conclusions into
question.
First, most of these studies make assumptions about the
requirements of the EPA rules that are inconsistent with, and
dramatically more expensive than, the EPA's actual proposals or final
rules. For example, a large proportion of the retirements projected by
several of these studies is attributable to their inaccurate assumption
that EPA's cooling water intake rule under CWA section 316(b) would
require all or virtually all existing power plants to install cooling
towers. In one study, the reliability effects reported are based on
inaccurate assumptions that all existing EGUs with a capacity
utilization factor of less than 35 percent would close, and that all
in-scope electric generators would be required to install cooling
towers within 5 years, whereas the not-selected options with closed
cycle cooling in EPA's proposal envisioned that permit authorities
could exercise discretion to allow facilities 10 to 15 years' time to
comply. In most cases, these analyses were performed before the CWA
section 316(b) rule or the MATS rule were even proposed; even analyses
subsequent to the CWA section 316(b) proposal continue to inaccurately
portray EPA's proposed approach.
Second, in reporting the number of retirements, many analyses fail
to differentiate between plant retirements attributable to the EPA
rules and retirements of older, smaller, and less efficient plants that
are already scheduled for retirement because owners have made business
decisions, based in significant part on market conditions, not to
continue operating them.
Third, most of these analyses fail to account for the broad range
of responses available to address electric reliability concerns
associated with power plant retirements, including upgrades to the
transmission system, construction of new generation, and implementation
of demand-side measures. These measures are discussed at greater length
below.
As a preliminary matter, none of these situations, either alone or
in combination, will necessarily lead to an electric reliability
problem. There is excess generating capacity in the U.S. today and in
most cases an EGU that closes, either temporarily until it comes into
compliance or permanently, will not cause a reliability problem. As
explained above, our modeling of the impact of this final rule at the
regional level projects retirements of less than one percent of
nationwide generating capacity and confirms that there will continue to
be adequate capacity in all 32 subregions of the country as sources
comply with the rule.\325\ This analysis shows that significantly less
capacity will close in response to the final rule than might have under
the proposal. Moreover, the regional modeling of retirements
demonstrates that plants that close in response to this rule are spread
out across the country rather than clustered in one area.
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\325\ See Technical Support Document on Resource Adequacy in
this Docket.
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Outside analyses have identified many of the same flaws in studies
[[Page 9409]]
projecting large-scale retirements as a result of EPA's power sector
rules. For example, on August 8, 2011, the Congressional Research
Service (CRS) \326\ issued a report concluded that studies that assert
that EPA rules will cause reliability problems, often make assumptions
about the requirements of the rules that are inconsistent with, and
dramatically more expensive than, the EPA's actual proposals. The CRS
further noted that EPA's rules will primarily affect units that are
more than 40-years old, that have not yet installed state-of-the-art
pollution controls, and that are inefficient. Many of these plants are
being replaced by combined cycle natural gas plants, driven more my
lower gas prices than by EPA's regulations. The June 2011 Bipartisan
Policy Center report referenced above likewise highlighted many of
these same shortcomings in the studies in question.\327\
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\326\ James E. McCarthy and Claudia Copeland, Congressional
Research Service, August 8, 2011, ``EPA's Regulation of Coal-Fired
Power: Is a `Train Wreck' Coming?''.
\327\ Bipartisan Policy Center, June 2011, ``Environmental
Regulation and Electric System Reliability.''
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Although we do not expect to see any regional reliability problems,
we acknowledge that there could be localized reliability issues in some
areas--due to transmission constraints or location-specific ancillary
services provided by retiring generation--if utilities and other
entities with responsibility for maintaining electric reliability do
not take actions to mitigate such issues in a timely fashion. There are
many potential actions that could be taken to address this problem and
multiple safeguards to assure a reliable electricity supply.
First, utilities can help to assure reliability through proactive
steps in coordination with relevant planning and regulatory
authorities. As we said in the proposal, early planning is key. The
industry has adequate resources to install the necessary controls and
develop the new capacity that may be required within the compliance
time provided for in the final rule.\328\ Although there are a
significant number of controls that need to be installed across the
industry, with proper planning, we believe that the compliance schedule
established by the CAA can be met. Many companies have begun to do the
detailed analysis and engineering and are ahead of others in their
compliance strategy. There are already tools in place (such as
integrated resource planning, and in some cases, forward auctions for
future generating capacity) that ensure that companies adequately plan
for, and markets are responsive to, future requirements such as this
final rule.
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\328\ As stated above, EPA has provided the maximum compliance
time authorized under CAA section 112(i)(3)(A).
---------------------------------------------------------------------------
Second, companies that intend to retire EGUs should formally notify
their RTO (or comparable planning authority in the case of non-RTO
regions), state regulatory agencies, and regional reliability entities
as soon as possible of their compliance plans, particularly with regard
to any planned unit retirements. As we said before, in most places a
closing plant will not be a cause for concern for reliability. The same
is true of any outages required for retrofitting of units with
controls. To the extent there is concern, however, early notification
will provide an opportunity for transmission planners, market
participants, and state authorities to develop solutions to avoid a
reliability problem. In RTOs with forward capacity markets, owner/
operators that do not bid generating capacity that they plan to shut
down will provide an advance signal to market participants to take
action to assure adequate future capacity. In all regions, early and
public notification will allow market participants, planning
coordinators and state authorities, as appropriate and in a timely
fashion, to bring new generation on line, put demand side resources in
place, and/or complete any transmission upgrades needed to circumvent a
potential issue. Most RTOs only require 45 to 120 days notification of
closure. In combined comments to EPA, 5 RTOs suggested that such
notification should be made no later than 12 months after this
regulation is final in order to allow a smooth transitioning to action
to avoid a reliability problem. The EPA strongly encourages sources to
provide notice to the RTOs as early as possible and believes that
responsible owner/operators should and will do the early planning for
compliance and provide early notification of their compliance plans,
especially where such plans include retiring one or more units.
On the supply side, there are a range of options including the
development of more centralized power resources (either base-load or
peaking) and/or the development of cogeneration or distributed
generation. Even with the current large reserve margins, there are
companies ready to implement supply-side projects quickly. For
instance, in the PJM region, there are over 11,600 MW of capacity that
have completed feasibility and impact studies; the units representing
this capacity could be on-line by the third quarter of 2014.\329\ The
EPA notes, as well, that in the 3 years from 2001 to 2003, industry
brought over 160 GW of generation on line.\330\
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\329\ Paul M Sotkiewicz, PJM Interconnection, Presentation at
the Bipartisan Policy Commission Workshop Series on Environmental
Regulation and Electric System Reliability, Workshop 3: Local,
State, Regional and Federal Solutions, January 19, 2011, Washington,
DC, https://www.bipartisanpolicy.org/sites/default/files/Paul%20Sotkiewicz-%20Panel%202_0.pdf, slide 6.
\330\ Form EIA-860 Annual Electric Generator Report, https://www.eia.gov/cneaf/electricity/page/eia860.html.
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Demand side options include energy efficiency as well as demand
response programs. These types of resources can also be developed very
quickly. In 2006, PJM had less than 2,000 MWs of capacity in demand
side resources. Within 4 years this capacity nearly quadrupled to
almost 8,000 MW of capacity.\331\ In addition to helping address
reliability concerns, reducing demand through mechanisms such as energy
efficiency and demand side management practices has many other
benefits. It can reduce the cost of compliance and has collateral air
quality benefits by reducing emissions in periods where there are peak
air quality concerns.
---------------------------------------------------------------------------
\331\ BPC slides cited above--slide 5.
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With regard to transmission, recent experience also shows that, in
many cases, transmission upgrades to address reliability issues from
plant closures can be implemented in less than 3 years. For instance,
when Exelon notified PJM of its intention to retire four units,\332\ it
was determined that transmission upgrades necessary to allow retirement
of two units could be made within 6 months of notification,
transmission upgrades for the third unit would require slightly over 1
year and transmission upgrades to allow the fourth unit to retire could
be made in approximately 18 months.\333\
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\332\ https://www.exeloncorp.com/Newsroom/pages/pr_20091202_Generation.aspx?k=eddystone.
\333\ Cromby Units 1 and 2 and Eddystone Units 1 and 2--
Deactivation Study, Updated September 7, 2010--https://policyintegrity.org/documents/20100907-cromby-and-eddystone-retirement-study-posting-update.pdf.
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The CAA allows CAA Title V permitting authorities the discretion to
grant extensions to the compliance time of up to one year if needed for
installation of controls. See CAA section 112(i)(3)(B)). If an existing
source is unable, despite best efforts, to comply within 3 years, a
permitting authority has the discretion to grant such a source up to a
1-year extension, on a case-by-case basis, if such additional time is
necessary for the installation of controls. Id. Permitting authorities
should be familiar with the operation of the 1-year
[[Page 9410]]
extension provision because EPA has established regulations to
implement the provision and the provision applies to all NESHAP. See 40
CFR 63.6(i)(4)(A).
We believe that the permitting authorities have the discretion to
use this extension authority to address a range of situations in which
installation schedules may take more than 3 years including: staggering
installations for reliability reasons or other site-specific challenges
that may arise related to source-specific construction, permitting, or
labor, procurement or resource challenges. Staggered installation
allows companies to schedule outages at multiple units so that reliable
power can be provided during these outage periods. It can also be
helpful for particularly complex retrofits (e.g., when controls for one
unit need to be located in an open area needed to construct controls on
another unit). The additional 1-year extension would provide an
additional two shoulder periods (i.e., seasons flanking annual high-
demand periods) to schedule outages, thus enabling owners/operators to
gain the full benefit of staggering outages in support of complex
installations. The EPA believes that although most units will be able
to fully comply within 3 years, the fourth year that permitting
authorities are allowed to grant for installation of controls is an
important flexibility that will address situations where an extra year
is necessary. That fourth year should be broadly available to enable a
facility owner to install controls within 4 years if the 3-year time
frame is inadequate for completing the installation.
As we indicated at proposal, this source category is unique due to
the large, complex and interconnected nature of electrical generation,
transmission and distribution, and the critical role of the electric
grid in the functioning of all aspects of the economy. The grid
functions as an interconnected system that supplies electricity to end
users on a continuous basis. Safe, reliable operation of the grid
requires coordination among actions taken at individual units,
including timing of outages for the installation of controls, derating,
or deactivation. It was for this reason that we specifically addressed
in the proposed rule reasonable interpretations of the phrase
``installation of controls'' in CAA section 112(i)(3)(B). We determined
that it was important to provide Title V permit authorities with
information that might be useful if they were asked to authorize a
fourth year for specific EGUs.
The EPA took comment on whether the construction of on-site
replacement power could be considered the ``installation of controls''
such that a fourth year would be available while the replacement unit
is being completed for a unit that is retiring (e.g., a case when a
coal-fueled unit is being shut down and the capacity is being replaced
on-site by another cleaner unit such as a combined cycle or simple
cycle gas turbine). After reviewing the comments, EPA believes that it
is reasonable for permit authorities to allow the fourth year extension
to apply to the installation of replacement power at the site of the
facility. The EPA believes that building replacement power constitutes
the ``installation of controls'' at a facility to meet the regulatory
requirements.
Commenters were generally supportive of the proposed approach
described above, but a number of commenters suggested several
additional situations that should be considered as the ``installation
of controls'' such that it would be appropriate for permitting
authorities to grant a 1-year extension beyond the 3-year compliance
time-frame. In particular, commenters suggested that the 1-year
extension should be available for a unit if a company's compliance
choice was to retire that unit but doing so within the 3-year time-
frame caused reliability problems for any of the following reasons: (1)
Generation from the retiring unit is needed to maintain reliability
while other units install emission controls; (2) new off-site
generation was being built to replace the retiring unit, but the new
generation was not scheduled to be operational within the 3-year time-
frame and any gap between the time the existing unit retires and the
new unit comes on line would cause reliability problems; and (3)
transmission upgrades were needed in order to maintain electric
reliability after the unit retired but could not be completed within 3
years.
While the ultimate discretion to provide a 1-year extension lies
with the permitting authority, EPA believes that all three of these
cases may provide reasonable justification for granting the 1-year
extension if the permitting authority determines, for example, based on
information from the RTO or other planning authority or other entities
with relevant expertise, that continued operation of a particular unit
slated for retirement for some or all of the additional year is
necessary to avoid a serious risk to electric reliability.
In a case where pollution controls are being installed, or onsite
replacement power is being constructed to allow for retirement of
older, under-controlled generation, a determination that an extra year
is necessary for compliance should be relatively straightforward. In
order to install controls, companies will have to go through a number
of steps fairly early in the process including obtaining necessary
building and environmental permits and hiring contractors to perform
the construction of the emission controls or replacement power. This
should provide sufficient information for a permitting authority to
determine that emission controls are being installed or that
replacement power is being constructed. Because companies will need to
develop this information early in the process and because a
determination can easily be made as to whether the schedule will exceed
3 years, the EPA believes that Title V permitting authorities should be
able to quickly make determinations as to when extensions are
appropriate.
In the three cases related to retirement of a unit without
construction of onsite replacement power, additional information is
needed. The Title V permitting authority should request that the
affected company or companies provide information, including, for
example, from the RTO or other planning authority for the relevant
region, the state electric regulatory agency, NERC or its regional
entities, and/or FERC or the DOE, demonstrating that retirement of a
particular unit within the 3-year compliance period would result in a
serious risk to electric reliability.
The first two situations involving a retiring unit--where one or
more related existing units are upgrading pollution controls or a new
unit is being constructed off-site--are similar to the situation we
discussed in the proposed rule wherein a retiring unit at a facility
runs an additional year while a replacement unit on the same site is
constructed. In each of these situations, the retiring unit would be
allowed to run so a unit compliant with the rule (either a retrofitted
existing unit or a new unit) can come on line. We believe that these
situations may, in the appropriate circumstances, constitute ones in
which a 1-year extension for the retiring unit is ``necessary for the
installation of controls.'' In these two situations, however, we
believe that it would be appropriate for the Title V permitting
authority to consider reliability concerns as a necessary factor before
granting the additional year because continuing operation of the
retiring unit is only ``necessary'' to the extent it is required for
reliability. In each of these situations, the permitting authority
should determine that the retiring unit is necessary to maintain
[[Page 9411]]
reliability until the new unit comes on line or the other existing unit
is retrofitted. Title V permitting authorities may determine that
multiple retiring units are available to maintain reliability, but
unless all the units are necessary to address the issue, it would
likely be unreasonable to provide the additional year for all the
identified units.
The third hypothetical situation identified above is one in which
transmission upgrades are necessary to address a reliability issue
resulting from the retirement of a unit in order to comply with this
rule, where the upgrade cannot be completed by the 3-year compliance
date. In terms of the functionality of the electric grid, this
situation has some similarity to those discussed above. Here, it is the
completion of the transmission upgrades, rather than bringing another
compliant (retrofitted or new) unit on line, that would allow the
retiring unit to come into compliance (by retiring) without threatening
reliability. The general objective and result is similar: Reductions of
the existing unit's HAP emissions (through retirement) while
maintaining electric reliability. If such situations develop and the
reliability problem has been properly demonstrated, permitting
authorities should consider whether an extension under CAA section
112(i)(3)(B) may be provided.
The EPA continues to believe, based on the analysis discussed at
the beginning of this section, that most, if not all, units will be
able to comply with the requirements of this rule within 3 years. The
EPA also believes that making it clear that permitting authorities have
the authority to grant a 1-year compliance extension where necessary,
in the range of situations described above, addresses many of the other
concerns that commenters have raised. The EPA believes that the number
of cases in which a unit is reliability critical and in which it is not
possible to either install controls on the unit or mitigate the
reliability issue through construction of new generation, transmission
upgrades, or demand-side measures, within 4 years, is likely to be very
small or nonexistent. This view is consistent with statements from
commenters explicitly mandated with ensuring grid reliability.
The EPA's authority to provide relief from the requirements of this
final rule beyond the fourth year is limited by the statute. If
reliability issues do develop, however, the CAA provides mechanisms for
sources to come into compliance while maintaining electric reliability.
One area where the EPA has some measure of flexibility is with respect
to the exercise of its enforcement authorities. The Agency has used
such authority in the past to bring sources into compliance with the
requirements of the CAA while maintaining electric reliability,
although these authorities are not as flexible as suggested by some
commenters.
The EPA generally does not speak publicly to the intended scope of
its enforcement efforts, particularly well in advance of the date when
a violation may occur. In light of the importance of ensuring electric
reliability, however, the Office of Enforcement and Compliance
Assurance will separately publish a document that articulates our
intended approach with respect to sources that operate in noncompliance
with this final rule to address a specific and documented reliability
concerns.
That document provides a pathway for reliability critical units (as
such units are described in the document) to achieve compliance within
an additional year. The result is that qualifying reliability critical
units may come into compliance within up to 5 years. This pathway is
structured to maintain reliability, to ensure CAA compliance and to
increase certainty for sources in planning by allowing a unit owner/
operator to determine whether it qualifies for a compliance schedule
well in advance of the MATS compliance deadline.
The EPA believes that there will be few, if any, situations in
which it will be necessary to have recourse to the processes discussed
in the document just described, and that there are likely to be fewer,
if any, cases in which it is not possible to mitigate a reliability
issue within the further year contemplated under that document.
However, there is always the possibility that some unit owner/operator
will be unable to address its reliability issues within 5 years and
there is always the possibility that a unit owner/operator will be
unable to timely comply with the MATS for some other reason. Consistent
with its longstanding historical practice under the CAA, the EPA will
address individual non-compliance circumstances on a case-by-case
basis, at the appropriate time, to determine the appropriate response
and resolution.
A number of commenters also raised concerns about inconsistencies
between the compliance timelines under this final rule and existing
state agreements with specific owners/operators to install pollution
control equipment and/or retire EGUs. The EPA believes the
flexibilities provided in this discussion allow for some discretion to
address those cases, but that they may not be fully addressed. The EPA
is supportive of such efforts and believes they can have important
multi-pollutant health and environmental benefits. To the extent that
the flexibilities discussed here do not fully address a particular
situation, we encourage states and sources to contact the EPA as early
as possible to discuss their individual circumstances.
G. Cost and Technology Basis Issues
1. Dry Sorbent Injection
Comment: Several commenters stated that there is limited commercial
operating experience in using DSI to control acid gas emissions from
coal-fired boilers. They suggest that the technology is not adequately
proven for use in this application.
Other commenters disagree with statements made that DSI is not
proven. One commenter stated that DSI is a mature technology. The
commenter indicated that DSI is well suited for units that burn fuels
with lower or mid-level sulfur contents, and is among the viable
options available for a number of sources to achieve the proposed HCl
limits. Thus, the commenter believes that DSI represents a real
technology control option for many units, and is among the suite of
technology options that certain units will be able to employ to meet
the proposed HCl limit.
Response: As explained in this response and elsewhere in this
preamble, the EPA agrees that DSI technology is proven and ready for
commercial use in controlling acid gases from coal combustion. One of
the largest coal-burning electric utilities in the U.S, American
Electric Power (AEP), pioneered the practical use of DSI with trona, a
sodium-based sorbent, for SO3 mitigation. American Electric
Power has implemented trona injection for that purpose across its
entire bituminous coal-fired fleet where both SCR and wet FGD systems
are in place.\334\ Examples of coal-fired EGUs already using trona DSI
to control SO2 emissions include NRG Energy's Dunkirk
Generating Station Units 1-4 and CR Huntley Units 67 and 68 in New
York.\335\ The Dunkirk units range in size from 75 MW to 190 MW. Much
larger units may also be economic when using DSI for SO2
control, as suggested by Dominion Energy's studies of adding DSI on two
[[Page 9412]]
625 MW units at the Kincaid plant in Illinois.\336\ One of the largest
suppliers of air emission control systems in the world, vouches that
DSI is commercially proven for acid gas control:337 338
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\334\ SO3 Control: AEP Pioneers and Refines Trona Injection
Process for SO3 Mitigation, Coal Power, March 2007, https://www.coalpowermag.com/plant_design/SO3-Control-AEP-Pioneers-and-Refines-Trona-Injection-Process-for-SO3-Mitigation_29.html.
\335\ NRG Energy letter to RGGI, Inc, November 22, 2010, https://www.rggi.org/docs/NRG_Nov_2010.pdf.
\336\ Dominion Energy, BART Analysis for the Kincaid Power
Plant, January 2009, https://www.epa.state.il.us/air/drafts/regional-haze/bart-kincaid.pdf.
\337\ Dry Sorbent Injection Systems for Acid Gas Control,
Babcock & Wilcox, 2010, https://www.babcock.com/library/pdf/ps-451.pdf.
\338\ Technologies for Acid Gas Control, Babcck & Wilcox, 2011,
https://www.babcock.com/library/pdf/ps-457.pdf.
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Comment: Numerous comments were received on EPA's IPM modeling of
DSI in the MATS analysis. A few commenters stated that DSI will not
work on bituminous coals. Some commenters stated that DSI is only
suitable for use on low sulfur, low chlorine western coals. Others
stated that DSI is only likely to be used on relatively small units,
and that larger units would use scrubbers for acid gas control. Several
commenters expressed the opinion that because there is little
commercial operating experience in using DSI to control SO2
emissions from coal-fired boilers, EPA's IPM modeling assumptions on
the efficacy and cost of the DSI control option are unjustifiably
optimistic. Some commenters believe that DSI will not be as economic or
as widely applicable for either SO2 or HCl control as
projected by EPA's IPM modeling. Commenters observe that wet or dry
scrubbers for FGD, longer-standing control technologies for
SO2 and HCl, are more complex systems with a much higher
capital cost than DSI. These commenters argue that the sector will need
to retrofit many more FGD scrubbers than projected by IPM for MATS
compliance and will therefore experience a much higher overall cost of
compliance than projected by IPM, as well as needing more time and
resources for retrofit construction. A few commenters suggested that
EPA should base its MATS modeling on this more conservative outlook. A
few commenters were concerned that EPA's DSI modeling assumptions
relied on performance data from only one DSI vendor.
Some commenters were concerned that fly ash currently sold for
beneficial uses will become unsalable because it will be contaminated
by injected sodium-based DSI sorbents. Two commenters argued that EPA's
IPM analysis understates DSI cost by not including the costs of
foregone fly ash sales revenue and contaminated fly ash disposal. A few
commenters observed that landfilling of sodium-based DSI solid wastes
will produce leachate containing sodium and other compounds that are
challenging to handle, thus requiring special landfill designs and a
high cost for landfill disposal of DSI waste.
Response: The EPA believes that its representation of DSI in MATS
compliance modeling is reasonable, is properly limited to applications
that are technically feasible, and reflects a conservative approach to
modeling future use of this technology.
The EPA disagrees that its IPM modeling of DSI is overly optimistic
and therefore underestimates the costs of MATS compliance. In its IPM
modeling, EPA restricts the availability of the DSI option to only
those units that use or switch to relatively low sulfur coal: Less than
2 lb SO2/MMBtu (see IPM documentation in the docket). The
EPA's IPM projections for MATS compliance, therefore, already include
the costs of any additional FGD scrubbers that are economically
justified and projected for use on units using higher sulfur coals. The
EPA models DSI assuming fine-milled trona as the injected sorbent. As
mentioned by several commenters, sodium bicarbonate (SBC), which is
processed from trona, is also suitable for use with DSI. Sodium
bicarbonate is more reactive with acid gases than trona. It would
require less tonnage of sorbent and less tonnage of waste disposal than
trona for the same SO2 removal effect, albeit at somewhat
higher sorbent cost. Non-sodium based sorbents such as hydrated lime
(calcium based) could also be used. Therefore, EPA's modeling of DSI
technology does not include the full spectrum of sorbent choices that
real-world applications enjoy, meaning that there may be opportunities
for lower-cost applications of DSI that are not captured in EPA's
projections for MATS. The EPA models DSI with trona injection rates
corresponding to 70 percent SO2 removal for all coals,
assuming that an equivalent amount of sorbent is needed to provide 90
percent HCl removal, regardless of the low sulfur and chlorine content
of western coals.
Senior technical staff from the EPA have carefully evaluated the
key assumptions regarding the cost and operation of emission control
technologies. In general, these staff believe that trona should have
strong HCl reaction selectivity and, consequently, EPA's assumed trona
injection rates may be overstated. The extent to which this assumption
may actually overstate DSI control costs can be observed through DSI
pilot testing for Solvay Chemicals by the Energy & Environmental
Research Center (EERC) at the University of North Dakota.\339\ The
EERC's testing of trona DSI on a central Appalachian bituminous coal
(1.3 lb SO2/MMBtu) substantiates the strong HCl reaction
selectivity of sodium-based sorbents, including trona, and calcium-
based hydrated lime. The EERC's pilot testing shows that fine-milled
trona, when well mixed into 325 [deg]F flue gas upstream of a FF,
provides 90 percent HCl removal at a SO2 removal rate of
less than 20 percent (as compared to EPA's modeling assumption of
aligning 90 percent HCl removal with sorbent injection designed to
achieve 70 percent SO2 removal). The data show that 95
percent or higher HCl removal is readily obtained at somewhat higher
SO2 removal rates. Similarly strong HCl selectivity results
were obtained using trona and an ESP at 650 [deg]F. Test data from
United Conveyor \340\ on full-scale units also show these high HCl
selectivity trends. Overall, these test data from multiple major
vendors suggest that even if a SO2 removal rate of 30
percent were required in order to obtain 90 percent HCl removal in the
imperfectly mixed flow of a full-scale unit, it still appears that
EPA's assumed trona injection rates may be as much as twice as high as
would actually be needed in practice for certain applications. It is
apparent that if EPA were to re-analyze MATS compliance with DSI
injection rates reduced by 50 percent, there would be a corresponding
reduction in the sorbent and related waste disposal costs that
constitute most of the cost of using DSI.
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\339\ Solvay Chemicals, Inc., HCl Removal in the Presence of
SO2 Using Dry Sodium Sorbent Injection, https://www.solvair.us/SiteCollectionDocuments/presentations/20111214_hcl_presentation.pdf.
\340\ United Conveyor Corporation, Dry Sorbent Injection for
Simultaneous SO2, HCl, and Hg Removal, October 2011, https://unitedconveyor.com/uploadedFiles/Systems/Systems_Sub/McIlvaine%20Multipollutant%20Removal%20Oct%202011.pdf.
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Given the EERC test data, it is also apparent that most units that
have ESPs and are burning low sulfur western coal could meet the HCl
limit using DSI without the addition of a FF. If EPA were to re-analyze
MATS compliance while allowing DSI use without the need for a
downstream FF, it is apparent that there would be a very significant
reduction in the overall number of FF retrofits projected, and a
corresponding reduction in annualized capital costs. For the MATS
proposal, the EPA modeled DSI on the assumption that all chlorine in
coal converts to HCl, and that DSI would be the only mechanism by which
the unit could prevent HCl from being emitted. Based on public
[[Page 9413]]
comments and a more thorough review of the ICR data, the EPA has
introduced in final MATS modeling a recognition that the relatively
high alkalinity of ash from subbituminous and lignite coals ``removes''
much of the HCl that would otherwise be emitted from combustion of
these particular coals. The 2010 ICR data indicate that in some cases
the ash itself removes sufficient HCl from these coals for MATS
compliance; in effect, these acid-gas emissions are absorbed by coal
ash and are captured by particulate control devices instead of being
emitted in gaseous form. As a conservative measure, EPA's revised final
MATS modeling assumes that 75 percent of HCl is removed by the ash for
these coals. In the event that ash capture in practice is more
effective than this 75 percent assumption, then EPA's analysis projects
a conservatively higher level of DSI installations (and, thus,
compliance cost) than would actually occur in practice. In any case, it
appears that significantly less sorbent injection would actually be
required in practice than assumed by EPA for these low sulfur, low
chlorine coals, and that the IPM projected DSI operating costs are
likewise higher for these coals than would be experienced in practice.
The EPA models DSI with sorbent injection occurring downstream of
an existing electrostatic precipitator (ESP). The existing ESP is
assumed to remain in service. The model adds a fabric filter downstream
of the DSI injection point to capture the small amount of PM passing
through the ESP plus the reacted and unreacted DSI sorbent. Most of the
DSI projected by IPM, therefore, includes the costs of a retrofitted
FF. This modeled configuration allows fly ash currently captured in
ESPs to remain uncontaminated by DSI sorbent and, therefore, remain
available for sale and beneficial use. The EPA conservatively models FF
costs based on an assumed full-size system with an air-to-cloth ratio
of 4.0. The FF costs could be somewhat less in practice if a smaller
system (with an air-to-cloth ratio of 6.0) were used for the reduced
DSI dust loading. The EPA observes that some of the owners of units
with ESPs may chose to convert existing ESPs into FFs,\341\ an option
not modeled in IPM, but that would likely have a lower capital cost
than a retrofitted FF. In the MATS proposal EPA modeled DSI with a
waste disposal cost of $50/ton, based on a Sargent & Lundy DSI cost
model prepared for EPA (see proposal IPM documentation in the docket).
The EPA has continued to model DSI at this waste disposal cost for
analysis of the final rule. However, recent discussions between senior
technical staff from the DOE and the EPA have suggested that in some
situations sodium sulfates, that would be formed by the injection of
trona, could potentially leach out of the fly ash/sorbent mixture on
contact with water. Although the technical staff recognized that these
concerns are more relevant to bituminous coal-fired units where ashes
are not cementitious, unless mixed with limestone or lime, they
suggested that the impacts of potentially higher disposal costs be
evaluated. Based on public comments, further investigations by Sargent
& Lundy, and suggestions from the EPA and DOE technical staff, EPA's
analysis of the final rule has included an IPM sensitivity case using a
DSI waste disposal cost of $100/ton. The sensitivity case indicates
that a 100 percent increase in assumed DSI waste disposal cost produces
slightly less than a 1 percent increase in the projected cost of the
rule.
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\341\ TW Lugar, et al., The Ultimate ESP Rebuild: Casing
Conversion To a Pulse Jet Fabric Filter, a Case Study, Electric
Power Conference, May 2009, https://www.cecoenviro.com/uploads/ESP%20to%20Fabric%20Filter%20Baghouse%20Conversion%20-%20Buell%20Case%20History.pdf.
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Comment: A few commenters expressed the concern that there is an
inadequate supply of trona to support DSI operations at the levels
projected by the EPA for MATS compliance.
Response: The EPA projects that just over 50 GW of coal-fired
capacity might retrofit with DSI for MATS compliance, thus reducing
SO2 emissions by about 1 million tons per year. Based on
conservatively high trona injection rates, as discussed above, the EPA
estimates that the amount of trona required to support DSI operations
at this level is about 4 million tons per year. By comparison, the
trona mining industry in the U.S. has a demonstrated production
capacity of at least 18 million tons annually, and was running well
below that capacity (16.5 million tons) in 2010.342 343 If
the EPA's assumed trona injection rates are as much as 50 percent
greater than actually needed for at least 90 percent HCl control, as
discussed above, and given that some subbituminous coals will
apparently need little or no sorbent injection for HCl control, there
may already be an adequate surplus of trona production capacity to
support DSI for MATS compliance. The EPA, therefore, concludes that
trona supply for DSI is either already adequate, or will require at
most a small increase in production capacity.
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\342\ https://www.wma-minelife.com/trona/tronmine/tronmine.htm.
\343\ https://www.wma-minelife.com/trona/TronaPage2/trona_production.htm.
---------------------------------------------------------------------------
For all of these reasons, the EPA believes that its representation
of DSI in MATS compliance modeling is reasonable, is properly limited
to applications that are technically feasible, and reflects a
conservative approach to modeling future use of this technology.
2. Economic Hardship
a. Job Losses and Economic Impacts
Comment: Several commenters indicated that they believe the
proposed rule will weaken industry, cause job losses and hurt power
consumers. One commenter reported that the proposed rule will affect
1,350 coal and oil-fired units at 525 power plants and that NERC
reports that by 2018 nearly 50,000 MW of capacity will be retired by
the proposed rule. Many of these commenters compared the cost estimated
by EPA to a variety of other sources that estimate substantially higher
costs of the rule. The commenters expressed concern that electricity
price increases are likely to be up to 24 percent in some regions as a
result of the proposed rule. In addition to the economic difficulty the
proposed rule could place on consumers, the commenter believes that
many in the energy sector will lose their jobs due to coal-fired
capacity losses. The commenters believe the effects on coal-fired
plants in the Southeast especially will mean the loss of high-paying,
high-skilled jobs and drastic price increases in energy costs.
Additionally, commenters expressed concern that increased electricity
and natural gas prices would impact businesses in multiple sectors
across the country.
Response: The EPA disagrees with the estimates presented by the
commenters. The EPA has updated its analysis to reflect the final MATS.
The Agency estimates the annual costs of the final rule in 2015 to be
$9.6 billion in 2007 dollars. The estimate of early retirements of
coal-fired units due to this rule is 4.7 GW, lower than the level
estimated at proposal. Both of these estimates were prepared using the
IPM, a model that has been extensively reviewed and has been utilized
in several rulemakings affecting the power generation sector over the
last 15 years. The Agency's analyses are credible and accurate to the
extent possible, and all assumptions and data are made public.
Limitations and caveats to these analyses can be found in the RIA for
this rule.
The EPA estimates that there will be an increase of 3.1 percent in
retail
[[Page 9414]]
electricity price on average in the contiguous U.S. in 2015 as an
outcome of this rule, with the range of increases from 1.3 percent to
6.3 percent in regions throughout the U.S. No region of the U.S. is
expected to experience a double-digit increase in retail electricity
prices in 2015 or in any year later than that, according to the
Agency's analysis, as a result of this rule. To put this in context,
the roughly 3 percent incremental increase in aggregate end-user
electricity prices projected to occur over the next 4 years is about
the same as the 3 percent absolute average change in total end-user
electricity prices observed on an annual basis.\344\ Furthermore, the
roughly 3 percent incremental price effect of this rule is small
relative to the changes observed in the absolute levels of electricity
prices over the last 50 years, which have ranged from as much as 23
percent lower (in 1969) to as much as 23 percent higher (in 1982) than
prices observed in 2010.\345\ Even with this rule in effect,
electricity prices are projected to be lower in 2015 and 2020 than they
were in 2010.\346\
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\344\ EIA Annual Energy Outlook 2010 annual total electricity
prices from 1960 to 2010, Table 8-10.
\345\ Ibid, EIA AEO 2010, Table 8-10.
\346\ Ibid, EIA AEO 2010, Table 8-10 for price levels; and
Chapter 3 of the RIA for electricity price differential.
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The Agency found that the readily discernible impact on long-term
employment nationally within the most directly affected sectors should
be small and the EPA also estimated that about 46,000 job-years \347\
of one-time construction labor could be supported or created by this
rule. This includes jobs manufacturing steel, cement and other
materials needed to build pollution control equipment, jobs creating
and assembling pollution control equipment, and jobs installing the
equipment at power plants. Potential job increases from increased
output by lower-emitting facilities (such as increased generation from
well-controlled coal-fired plants that replace generation from older
coal-fired plants) are expected to partially or fully offset potential
job losses resulting from reduced output from higher-emitting
facilities. The EPA analysis projects a net change in the directly
affected EGU sector of between 15,000 net jobs lost to 30,000 net jobs
gained on an annual basis.\348\ See Chapter 6 of the RIA for further
details.
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\347\ A ``job-year'' is a combined measure of jobs and job
duration which is equivalent to one person being employed for one
year. For example, 2 job-years could represent two years of
employment for one worker, one year of employment for two workers,
or 6 months of employment for four workers. Estimates of employment
changes that involve non-permanent workers are usually reported in
job years to give a sense of the total employment effects.
\348\ It should be noted that if more labor must be used to
produce a given amount of output, then this implies a decrease in
labor productivity. A decrease in labor productivity will cause a
short-run aggregate supply curve to shift to the left, and
businesses will produce less, all other things being equal.
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The EPA has also looked at the possibility that changes in the
price of electricity may influence the levels and geographic
distribution of downstream economic activities, and associated
employment. Projecting how potentially higher electricity prices may
affect various downstream economic activities in particular regions as
a result of this rule is challenging for several reasons: (1) There are
significant uncertainties regarding projections of consumer- and
location-specific electricity price changes in response to future firm-
specific compliance strategies; (2) the availability of competitively-
priced alternative energy sources (including energy conservation) and
less electricity-intensive substitute goods and services may
significantly mitigate potentially adverse economic consequences
resulting from projected increases in electricity prices in ways which
are not captured effectively in currently available models; and (3)
available modeling tools are not configured to capture the effects over
time of economically significant effects of cleaner air (e.g.,
reductions in medical expenditures and improvements in labor
productivity resulting from fewer lost work days) achieved by rules
evaluated using single target year criteria pollutant and/or HAP
benefits projections. After considering these methodological
limitations, the Agency concludes that there is not a satisfactory
methodology for projecting the downstream economic (including
employment) effects of any changes in electricity prices due to this
rule.
We expect the downstream economic effects of this rule to be small
because electricity is only a small factor in the production of most
goods and services.\349\ A 3 percent increase in end-user electricity
prices translates to a much smaller effect on prices and potential
output of goods and services from end-users of electricity. Over time,
the incremental effect of this rule on electricity prices is projected
to diminish significantly; for example the difference in expected
prices is projected to narrow from 3.1 percent in 2015 to 2.0 percent
in 2020 as shown in Chapter 3 of the RIA.
---------------------------------------------------------------------------
\349\ BEA. (2007b). Commodity-by-Industry Direct Requirements
after Redefinitions, 2002. Available in: 2002 Summary Tables, 2002
Benchmark Input-Output Data. Retrieved from https://www.bea.gov/industry/io_benchmark.htm#2002data.
---------------------------------------------------------------------------
Despite the absence of a satisfactory methodology for quantifying
the potential economy-wide effects (including employment) of any
potential increases in electricity prices resulting from this rule, the
EPA expects the incremental effects of this rule on electricity prices
to be small given the projected electricity price increases relative to
historical levels and volatility in end-user electricity prices. Based
on these projections and contextual information, the Agency believes
that the incremental effects on electricity prices and economic
activity of this rule are likely to be small relative to other factors
influencing electricity prices, overall employment, and other aspects
of economic activity.
Comment: Several commenters considered the proposed rule to be a
tax on the American public, since utilities implementing upgrades will
pass the costs on to the consumer. Commenters questioned the preference
of Americans to subsidize renewable energy sources and put money into
the proposed rule instead of other environmental programs with greater
benefits. Commenters explained that the tax-like price increase reduces
income of energy consumers and depresses business development. The
commenters used California as an example of a state that uses low rates
of coal-based electricity and cites companies that have left the state
as a result of substituting higher cost forms of electricity for coal.
A commenter stated that coal-derived energy will rapidly become more
expensive, especially in the ``rust belt'' and Southeast region, as can
be seen by the rate increase already requested in Louisville. A
commenter believes the ``indirect taxation'' limits the ability of the
economy to absorb the cost of retrofitting and new capacity projects,
lowers discretionary spending and leads to job losses and lost tax
revenues, given the restrictive timeframe for compliance.
Response: The Agency does not agree that this rule creates or
alters any taxes on affected sources required under this rule to reduce
their emissions of toxic air pollutants, nor are taxes created or
altered or imposed on consumers of electricity which is provided to the
market by affected sources. Moreover, unlike a tax, this rule does not
generate government revenue. The rule does, however, indirectly address
the problem of the ``externality cost'' of higher health risks and
other adverse effects on the populations exposed to toxic air pollution
emissions from affected sources. This rule may have the effect of
[[Page 9415]]
reducing or eliminating a market distortion that provides an implicit
subsidy to affected facilities. This implicit subsidy results from the
fact that some facilities currently can avoid the costs of toxic air
pollution controls by imposing higher health and other costs on those
who are exposed to higher levels of toxic air pollution. The Agency
also disagrees with the implication that the costs incurred by less-
controlled sources to bring their toxic air emissions in line with
their better-controlled competitors will lead to significant or
debilitating changes in market and economic conditions. The Agency's
estimate of the potential increase in retail electricity price is an
average of 3.1 percent in 2015, with a range of increases by region
from 1.3 percent to 6.3 percent. As shown in Chapter 3 of the RIA, the
higher rates of potential electricity price increase tend to occur in
those regions where electricity prices have been relatively low, due to
some extent to reliance on coal-fired units which have been cheaper to
operate due to underinvestment in toxic air pollution controls.\350\ As
shown in Chapter 3 of the RIA, all regions with year 2015 projected
percentage increases in retail electricity prices above the contiguous
U.S. average are also projected to have baseline retail electricity
prices which are below the contiguous U.S. average price level in that
year. In addition, natural gas prices will only increase by 0.3 to 0.6
percent on average over the time horizon of 2015 to 2030. As discussed
above, for consumers of electricity in the commercial and industrial
sectors, electricity tends to be a fairly small fraction of total costs
of production, implying that the average projected electricity price
increase of 3 percent will lead to only a small fractional change in
the costs of providing goods and services to the economy. While some
residential electricity consumers may similarly see a small price
increase in retail electricity prices, it should be noted that these
consumers tend to reside in the same area or region as the affected
facility and so will also experience the improvement in air quality
from the reductions due to the rule. The reduction in health risk and
other improvements to quality of life associated with lower exposure to
toxic and other air pollutants achieved by this rule will confer
benefits on these consumers which include lower risks of premature
mortality, lower morbidity, and improved productivity and
competitiveness of U.S. workers due to reduction in work days lost to
air pollution-related illness. The benefits of these improvements are
projected to exceed costs of compliance by affected sources by at least
six-fold. The potential price increases in electricity and natural gas
should be considered in light of the substantial health, welfare, and
economic benefits achieved by this rule.
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\350\ https://www.epa.gov/airmarkets/images/CoalControls.pdf.
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Comment: Many commenters expressed support for the EPA's impact
analysis and disputed claims by other commenters that the projected
rule will harm economic growth. A number of commenters mentioned
testimonials by power company CEOs stating that the proposed rule will
not affect the economic health of the industry and a survey showing
nearly 60 percent of the coal-fired units already comply with the EPA's
proposed Hg standard, and several other meaningful quotes from utility
executives. The commenters also pointed out that 17 states already
require plants to address Hg pollution, with some imposing more
stringent emission limits than the EPA proposes. The commenters believe
that utilities use the threat of power plant closures and lost jobs to
delay Hg reductions from coal-fired plants. Commenters also believe
that the rules will drive innovation and job creation as new
technologies to reduce pollution are created. Several commenters quoted
the Economic Policy Institute finding that the proposed rule will
increase job growth by 28,000 to 158,000 jobs by 2015 (including
approximately 56,000 direct jobs and 35,000 indirect jobs), the
University of Massachusetts study that showed an increase 1.4 million
jobs in 5 years, and the Constellation Energy Group installation
project that employed nearly 1,400 skilled workers. Commenters also
cited the University of Massachusetts study statement that a net gain
of over 4,200 long-term operation and maintenance jobs will result.
Several commenters observed that the positive impacts of the rule
strongly favor its adoption. These commenters stated that, contrary to
the unfounded assertions by critics of EPA and the rule, EPA has
conducted a technically sound and conservative benefit-cost analysis
showing that the proposed rule's estimated benefits are at least five
times as high as its costs. One commenter stated, ``With sound, albeit
unduly conservative, econometric modeling, EPA has also determined that
the Toxics Rule will promote economic growth and create jobs in both
the long and short term.'' Two commenters cited the EPA impact analyses
by Dr. Charles Cicchetti which confirm this finding and state that the
analysis underestimates the rule's net benefits and positive impacts on
the nation's economy. By considering some benefits not monetized in the
EPA analysis, Dr. Cicchetti concludes that the proposed rule will
create $52.5 to $139.5 billion in net benefits annually, create 115,200
jobs, generate annual health savings of $4.513 billion, annual
increases in GDP of $7.17 billion and $2.689 billion in additional
annual tax revenues, and spur innovation and modernization of EGUs. The
commenters state that the study findings show no need to delay
implementation of the rule or needlessly duplicate economic analyses
already completed.
Commenters reported that multiple researchers confirmed that the
EPA's estimates of economic stimulus are conservative and that the
proposed rule will stimulate job growth. A commenter quotes Dr. Josh
Bivens of the Economic Policy Institute, who also found that EPA's
conclusions were conservative. Dr. Bivens concluded, ``The EPA RIA on
the proposed toxics rule makes a compelling case that the rule passes
any reasonable cost-benefit analysis with flying colors--the monetized
benefits of longer lives, better health, and greater productivity dwarf
the projected costs of compliance * * * Whether regulation in general
and the toxics rule in particular costs jobs is an empirical question
this paper attempts to answer. In particular, this paper examines the
possible channels through which the proposed toxics rule could affect
employment in the United States and finds that claims that this
regulation destroys jobs are flat wrong: ``The jobs-impact of the rule
will be modest, but it will be positive.'' His report details the
following major findings:
1. The proposed rule would have a modest positive net impact on
overall employment, likely leading to the creation of 28,000 to 158,000
jobs between now and 2015.
2. The employment effect of the [MATS] on the utility industry
itself could range from 17,000 jobs lost to 35,000 jobs gained.
3. The proposed rule would create between 81,000 and 101,000 jobs
in the pollution abatement and control industry (which includes
suppliers such as steelmakers).
4. Between 31,000 and 46,000 jobs would be lost due to higher
energy prices leading to reductions in output.
5. Assuming a re-spending multiplier of 0.5, and since the net
impact of the above impacts is positive, another 9,000 to 53,000 jobs
would be created through re-spending.
[[Page 9416]]
Response: The EPA thanks the commenters for these observations. The
Agency's estimates of employment impacts, found in the RIA for the
rule, are smaller than those identified by the some commenters, though
the EPA uses a different methodology that focuses on impacts specific
to the electric power sector.
b. Impacts on Low-Income Consumers
Comment: Commenters expressed concern that the EPA's overview of
the price increases does not consider the hardships that will be the
reality of increased prices on low-income or fixed-income households or
small businesses. The commenter reports increases of $90 million in
capital costs, $11.4 million in annual operating costs and $6.4 million
in annual debt service costs to achieve compliance, which will lead to
a 13 percent increase in rates for the proposed rule, and a 41 percent
increase for all proposed and new regulation compliance costs. The
commenter argues against the EPA's view that energy efficiencies will
offset rate increases, because low income customers will need to use
less electricity due to economic necessity. The commenter also sees
large price increases for customers if units are converted to natural
gas, which is approximately 2.5 times more expensive than the coal that
the commenter currently uses to generate electricity.
Response: The EPA's estimates of increase, relative to the
baseline, in the retail electricity price range from 1.3 percent to 6.3
percent regionally in 2015, with an average increase nationwide of 3.1
percent in 2015. Low-income households will thus see some increase in
electricity price, but this increase should be modest. In addition, the
increase in the price of natural gas as a result of this rule is
expected to be 0.3 to 0.6 percent over a time horizon of 2015 to 2030.
This increase in price is low enough that electricity customers should
not experience a major increase in price resulting from any modest
changes to electricity generated by natural gas. The roughly 3 percent
incremental price effect of this rule is small relative to the changes
observed in the absolute levels of electricity prices over the last 50
years, which have ranged from as much as 23 percent lower (in 1969) to
as much as 23 percent higher (in 1982) than prices observed in
2010.\351\
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\351\ EIA Annual Energy Outlook 2010 annual total electricity
prices from 1960 to 2010, Table 8-10.
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c. State or Regional Impacts
Comment: Multiple commenters expressed concern over the impact of
the rule on electricity prices and reliability in specific states or
regions. These commenters were concerned that these impacts would
adversely affect specific industries such as construction and
manufacturing. One commenter suggested the EPA consider regional
differences that will impact system reliability and costs, such as the
increased impacts on regions relying heavily on coal and oil and
encourages cooperation between the EPA and state and federal energy and
environmental regulators.
Response: The Agency has studied possible impacts on resource
adequacy as a result of this rule, and has determined that these
impacts should not be significant. Furthermore, industry, along with
relevant federal agencies, has the tools needed to address any
reliability concerns. The Agency has prepared an updated feasibility
TSD in support of the final rule, which is in the docket for this
rulemaking.\352\ The Agency has considered impacts on a regional basis
as part of its overall analyses done using the IPM; these results are
documented in the RIA for the rule and in the feasibility TSD.
---------------------------------------------------------------------------
\352\ See ``An Assessment of the Feasibility of Retrofits for
the Mercury and Air Toxics Standards Rule'' in the docket.
---------------------------------------------------------------------------
The EPA's analysis shows that retail electricity price increases
will not fall disproportionately on a specific region. In fact, those
regions experiencing the largest change in prices are projected to have
retail electricity prices below the national average both in the
absence of MATS and after the implementation of MATS. In Chapter 3 of
the RIA, the EPA presents retail electricity prices by region in 2015,
for both the base case and MATS policy case. The six regions that are
projected to have retail electricity prices above the national average
price in 2015 in the absence of MATS are projected to have increases
that are below the national average increase following the
implementation of MATS. Those regions that have projected retail
electricity price increases that are above the national average are all
projected to have retail electricity prices below the national average
in the absence of MATS.
Comment: A commenter quoted National Mining Association statistics
showing coal is responsible for $65.738 billion in annual economic
activity, produces 1,798,800 jobs and $36.345 billion in annual labor
income. The commenter reports that regions such as Appalachia, the
Midwest and Rocky Mountain West will be significantly affected by the
proposed rule, including increased unemployment. Other commenters
stated that communities near existing coal-fired generation units will
be especially hard-hit if the plants are permanently retired. The
communities will suffer from job loss and diminished tax revenue.
Response: The Agency's analysis, as found in the RIA, shows that
impacts to these regions are mixed. For Appalachia, coal production is
projected to fall by 6 percent in 2015, while the Western coal
producing region will experience a decrease of 3 percent in production
in 2015. The Interior region is projected to see a 9 percent increase
in production. Retail electricity prices are expected to increase by
1.3 percent to 6.3 percent in various parts of the country in 2015.
Also, the estimated number of early retirements according to the Agency
that may result from this rule is 4.7 GW in 2015, or less than 2
percent of all U.S. coal-fired capacity in that year. Thus, there may
be some negative impacts from this rule in some regions, but these same
regions will also experience some of the benefits, such as reduced
premature mortality from less exposure to PM2.5 emissions as
shown in Chapter 5 of the RIA. As discussed previously, the EPA's
analysis shows that retail electricity price increases will not fall
disproportionately on a specific region. In fact, those regions
experiencing the largest change in prices are projected to have retail
electricity prices below the national average both in the absence of
MATS and after the implementation of MATS.
The results of the EPA's employment analysis, found in Chapter 6 of
the RIA, indicate that the final MATS has the potential to provide
significant short-term employment opportunities, primarily driven by
the high demand for new pollution control equipment. While the
employment gains related to the new pollution controls are likely to be
tempered by some losses due to certain coal retirements, some of these
workers who lose their jobs due to plant retirements could find
replacement employment operating the new pollution controls at nearby
units. Finally, job losses due to reduced coal demand are expected to
be offset by job gains due to increased natural gas demand, resulting
in a small positive net change in employment due to fuel demand
changes.
While shifts in employment are difficult for those directly
affected, and the Agency remains concerned about the challenges job
shifts can bring to the
[[Page 9417]]
individuals affected, Bureau of Labor Statistics data indicate that
compliance with pollution control requirements is a relatively very
small contributor to overall employment shifts in the U.S. economy.
Specifically, the main cause of mass layoffs over the last four years
according to 2007 to 2011 Bureau of Labor Statistics data is ``lack of
business demand,'' accounting for over 40 percent of the layoffs
reported by industry. In contrast, all types of regulatory actions
(including health, safety, and environmental) by all levels of
government (Federal, State, local) combined were cited as the primary
factor in only 0.2 percent of mass layoffs over the same period.\353\
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\353\ U.S. Bureau of Labor Statistics, 2011. Extended Mass
Layoffs in 2010. https://www.bls.gov/mls/mlsreport1038.pdf.
---------------------------------------------------------------------------
d. Retirements of Coal-Fired EGUs and Shutdowns
Comment: A commenter discussed the economic factors behind EGU
retirements. These factors include the cost of alternative generation
using natural gas, the cost of implementing demand response measures
that can be bid into capacity markets, and the cost of continuing to
generate power from an existing unit. The commenter states that
regardless of the costs associated with the Toxics Rule and other EPA
electric power industry regulations, some power plants were already
economically unsustainable. The commenter quotes M.J. Bradley, who
points out, ``[o]f the 122 coal units in PJM with capacity less than or
equal to 200 MW, 35 failed to recover their avoidable costs and another
52 were close to not recovering those costs. Therefore, in PJM * * * in
addition to approximately 10 GW of coal generation that has or will be
retired during the 7 years from 2004 to 2011, another 11 GW faces a
troubling economic outlook.'' The commenter provides confirmation of
this by the most recent PJM capacity auction, where approximately 6.9
fewer GW of coal-fired capacity cleared the auction (1.85 fewer GW were
offered) as compared with the prior year's auction, and an additional
4.836 GW of new demand response (energy efficiency) resources cleared
the auction. Thus, the commenter states, some claims linking
retirements to the MATS are overstated and misleading. The commenter
gives the example of the American Electric Power attempt to link its
planned plant closures to the MATS, but those plants already are slated
to either close or to upgrade controls to comply with existing laws.
The commenter goes on to quote three independent studies that support
the finding that over 50 percent of the fleet is equipped with
scrubbers and the number will increase to nearly \2/3\ by 2015.
Response: The EPA agrees with the findings of the independent
studies mentioned by the commenter.
e. Impacts on Mining
Comment: Multiple commenters mention the proposed rule's impact on
mining. One commenter mentioned increasing energy costs for the U.S.
mining industry, resulting in fewer projects and associated jobs, as
well as increasing dependence on foreign mineral resources. Commenters
see mining impacts being disproportionally large for lignite mines,
which are dependent on their co-located lignite-fired power plants. The
commenters state that if the plant closes, there is no market for the
lignite and the mine will also close, displacing plant workers. These
impacts are largest in Texas, the largest coal consuming state and
fifth largest coal producing state, as well as a deregulated
electricity market. One commenter pointed out that the Texas coal
market provided a buffer against natural gas price volatility and in
particular believes the proposed rule does not take into account the
emission reductions already achieved by industry in general and their
company in particular. A commenter stated that impacts will be
magnified in Texas, since it is the largest coal consuming state and
mines lignite. A commenter indicated they believe it is unclear the
extent to which EPA includes the impacts on the mining industry that
will result from this rule.
Response: The Agency presents impacts on the coal mining sector
from this rule in the RIA. Given the modest increase in coal and other
energy costs associated with the rule, the Agency does not expect
widespread impacts on coal mining. The Agency's modeling accounts for
all emission controls and programs installed and/or implemented up
through December 2010, including those in Texas.
f. Flexible Regulations
Comment: Several commenters expressed concern over the potential
impacts of the regulation and believe that the requirements should be
more flexible in order to mitigate these impacts.
Response: The EPA believes the requirements of the final rule have
been made as flexible as possible consistent with the CAA. The final
rule allows some flexibility, including allowing averaging across units
in the same subcategory at a facility, allowing for an option of an
input or output standard for existing units, and allowing for
alternative compliance options (e.g., for coal, filterable PM or total
non-mercury metallic HAP or individual HAP metals). In addition, the
Agency is not prescribing specific technologies as part of this final
rule, but instead requiring emissions limitations be met. This approach
allows the industry to find the most cost-effective approach to meeting
the requirements while ensuring considerable public health benefits.
g. Temporary vs. Permanent Jobs
Comment: A commenter expressed disagreement with the EPA prediction
of new jobs created, because the commenter believes far more plants
will shut down than the EPA predicts, resulting in higher job losses.
The commenter also pointed out that while jobs running power plants are
permanent, the jobs predicted to be created by the proposed rule are
short term construction jobs, and will all occur in the same short
timeframe for compliance. The commenter also stated that the EPA
estimate does not include the opportunity cost of lost construction
jobs due to new power plants that will not be constructed due to the
proposed rules.
Response: The Agency believes that the employment impacts of the
final rule will be small, as has been the case historically with
regards to environmental regulation. The Agency does provide an
estimate of the long-term employment impacts to the electric power
sector in the RIA for the rule, and that estimate shows a range of
impacts from 15,000 net jobs lost to 30,000 net jobs gained (all
annual), but also recognizes important limitations to these estimates.
The Agency's estimate of impacts to short-term jobs, including those in
construction, accounts for both losses and gains that result from the
rule. This is shown in Chapter 6 of the RIA.
Comment: Commenters believe that installation of new pollution
controls would be a job-growth opportunity in their states because
money spent on controls for power plants creates high-quality jobs in
steel, cement and other materials, as well as in the assembling of the
equipment as well as installing and operating it. A commenter shares
the Alabama Fisheries Association estimate that the water-based
recreation industry brings in over $1 billion per year to the state's
economy though the state ranks third for imperiled fish with 61 bodies
of water cited for Hg contamination. The commenter believes the HAP
accumulating in the waterways
[[Page 9418]]
threatens the industry with permanent job-losses and lost revenue.
Response: The Agency agrees with the commenter that the reduction
in HAP that will take place as a result of the rule over time will help
to improve waterways in Alabama and thus help the water-based
recreation in that state. More information on the benefits of Hg and
other HAP reductions can be found in Chapter 4 of the RIA for the rule.
The Agency also agrees with the commenter that the addition of control
equipment for EGUs may stimulate employment in a variety of industries.
h. Natural Gas
Comment: A commenter states that natural gas use is only an option
in places where infrastructure exists to supply sufficient natural gas
to the EGU and other local needs and reports that year-round reliable
gas delivery is rare due to requirements to meet the other needs. The
commenter says that gas interruptions are prevalent in the winter, but
can happen year-round, and the costs of establishing a natural gas line
to a power plant can be tens of millions of dollars or more, and moving
a plant to a gas source can take many years. The commenter describes
the options for a Norwalk Harbor plant, and explains that the
modifications are costly and difficult even before considering the
modifications needed to alter the boiler and fuel supply system to
allow natural gas combustion.
Response: The final rule does not prescribe either pollution
control technologies to be used, nor does it dictate the types of fuels
that should be burned. The requirements of the final rule are designed
to allow industry to find the most cost-effective approach to
addressing harmful emissions that are covered by this action. The
Agency believes that cost-effective technologies exist today and have
been deployed on many power plants, and utilities will be able to find
intelligent solutions to address harmful emissions. The EPA has
provided supporting information as part of the preamble and RIA for
this rule, along with the feasibility TSD, which demonstrate the
availability and performance of technologies to meet the requirements
of the final rule.
Comment: A commenter discusses the factors that could lead to
higher natural gas prices not currently reflected in the EPA impact
projections, including industrial load and demand not rebounding to
2008 levels and the influence of liquefied natural gas exports. The
commenter asks that the EPA address a variety of factors related to its
natural gas assumptions.
Response: The Agency has fully documented its assumptions and
framework for modeling natural gas in IPM for both the proposed and
final MATS. This information can be found in Chapter 10 of the IPM
documentation (https://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Chapter10.pdf). The documentation provides a thorough overview of
the natural gas module, describes the very detailed process-engineering
model and data sources used to characterize North American
conventional, unconventional, and frontier natural gas resources and
reserves and to derive all the cost components incurred in bringing
natural gas from the ground to the pipeline. Also documented are the
resource constraints, liquefied natural gas (LNG), demand side issues,
the natural gas pipeline network and capacity, procedures used to
capture pipeline transportation costs, natural gas storage, oil and
natural gas liquids (NGL) assumptions, and key gas market parameters.
i. Compliance Timeline and General Timeline
Comment: A commenter states that the proposed rule will require
costs be passed on to consumers, meaning state public utility
commissions will be flooded with requests for rate increases from
utilities trying to recover expenditures. The short deadline will also
result in a large number of extension requests made to state permitting
authorities, further burdening them.
Response: The compliance date for this rule for existing sources
will be 3 years and 60 days after publication of the final rule in the
Federal Register, or approximately March 2015. Thus, there will be some
time before the impacts of this rule such as any increase in retail
electricity prices become a concern. It also should be noted that
increases in retail electricity prices will be 3.1 percent on average
in 2015, with a range regionally from 1.3 percent to 6.3 percent.
Comment: A commenter reports that they will need to install add-on
pollution controls to meet the proposed emission standards as well as
implement other physical or operational changes. The commenter
expresses concern about the number of pre-construction steps that would
be required, as well as the new construction activities and the
challenges of scheduling sequence relative to interconnections and
other tie-in considerations involved in compliance.
Response: The Agency has addressed concerns with the feasibility
and timing of control installations in its report on the subject (see
feasibility TSD contained in the docket for this rule).
Comment: Multiple commenters do not believe that labor availability
will constrain control installation in the required timeframe and cites
an Institute of Clean Air Companies (ICAC) response that it will not
for these reasons:
1. The power sector has demonstrated ability to install large
number of systems in short time period;
2. The majority of coal plans have installed control systems
already;
3. Fewer resource and labor-intensive control options being used
for compliance; and
4. End users have utilized cost reducing and implementation
efficiency strategies for efficient deployment of technologies.
Another commenter states that a wide range of technical and
economically feasible practices and technologies are available
currently to meet the emission limits and are in use around the
country.
Response: These comments are generally consistent with the
conclusions of the Agency's analyses on feasibility of control
installations for this rule as found in the feasibility TSD in the
docket for this rulemaking.
j. Burden Outweighs Environmental Gain
Comment: Several commenters state that the EPA has no data relating
to benefits from reducing non-mercury HAP, so the costs of the proposed
rule exceed the HAP benefits by 29,000 times. One commenter states that
the impact analysis was largely focused on Hg with little support for
other HAP reductions and failed to provide account of true costs and
benefits.
Response: While we are not able to monetize the benefits from
reductions of non-mercury HAP that will take place, these important
effects are discussed qualitatively in Chapter 4 of the RIA. The
quantified benefits of this rule include the reductions in non-HAP
emissions such as SO2 and PM2.5 that will occur
as a co-benefit of this rule as modeled by EPA. The total benefits are
estimated to outweigh the total annual costs of the rule by a margin of
either 3 to 1 or 9 to 1, depending on the benefits estimate and
discount rate used. These reductions are credible and are considerable
in size. The estimates of these benefits reflect the latest scientific
understanding on the subject. More information on the estimates and
[[Page 9419]]
the methodology for their preparation can be found in the RIA for the
rule.
Comment: Several commenters consider the proposed rule to be the
most expensive clean air rule ever. They point out the estimated $10.9
billion annual cost in 2015 and approximate 1,200 existing coal-fired
EGUs affected, both of which were estimated by the EPA. Commenters
believe the EPA's estimates are incorrect and the true cost will be far
more, due to cumulative effects of all proposed power sector rules, and
indirect costs from job losses, reduced productivity and
competitiveness resulting from electricity costs. They ask the EPA to
keep these high costs in mind when evaluating impacts of the proposed
rule and consider the costs with respect to the benefits. One commenter
requests that the EPA explain how its approach utilized ``the best
available techniques to quantify anticipated present and future
benefits and costs as accurately as possible'' and includes analyses by
EIA, EEI, NERC, NERA, Credit Suisse, ICF, and Burns & McDonnell.
Response: As noted earlier, the Agency did not prepare a cumulative
impact analysis to accompany the rule for the following reasons: (1)
The various EO requirements that the Agency must comply with require us
to estimate impacts specific to this rule; (2) decisionmakers and the
public need to know the impacts specific to a particular rule in order
to judge the merits of the regulation; and (3) estimates specific to a
particular rule are more transparent than those from a cumulative
impact analysis. A cumulative impact analysis lumps several regulations
together and can potentially mask a high-cost/low benefit regulation
among other rules that may have large net benefits. By analyzing each
regulation separately, EPA makes clear statements about the impacts,
costs, and benefits that are estimated as a result of this particular
regulation.
This does not, however, mean EPA has failed to incorporate these
regulations into this analysis. The inclusion of CSAPR and other
regulatory actions (including federal, state, and local actions) in the
IPM base case reflects the level of controls that are likely to be in
place in response to other requirements apart from MATS. This base case
provides meaningful projections of how the power sector will respond to
the cumulative regulatory requirements for air emissions, while
isolating the incremental impacts of MATS. These results are presented
in Chapter 3 of the RIA.
Additionally, the Agency does reflect on the cumulative impacts of
our regulations. In March 2011, EPA issued the Second Clean Air Act
Prospective Report which assessed the benefits and costs of regulations
pursuant to the 1990 Clean Air Act Amendments. The study examines the
cumulative impact of these regulations (found at https://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As shown in the report, the
direct benefits from the 1990 Clean Air Act Amendments are estimated to
reach almost $2 trillion for the year 2020, a figure that dwarfs the
direct costs of implementation ($65 billion). The full report is at
https://www.epa.gov/air/sect812/prospective2.html.
The direct benefits of the 1990 Clean Air Act Amendments and
associated programs are estimated to significantly exceed their direct
costs, which means economic welfare and quality of life for Americans
were improved by passage of the 1990 Amendments. The wide margin by
which benefits are estimated to exceed costs, combined with extensive
uncertainty analysis, suggest it is very unlikely this result would be
reversed using any reasonable alternative assumptions or methods. The
analysis presented in the RIA for the current regulation uses a similar
methodology.
The techniques employed by the Agency for generating benefits and
costs, and consider the most recent and complete data available to the
Agency. The EPA recognizes that the analyses have caveats and
limitations, and we discuss our analyses and their caveats and
limitations in the RIA for the rule, as well as in the benefits section
of the preamble. The Agency has also revised the cost analyses for the
final rule to reflect data received in public comments on the proposed
rule, and costs are lower than when the rule was proposed.
k. Impact on State Regulators
Comment: Several commenters expressed concern over the burden
imposed on state regulatory agencies by the rule.
Response: The Agency has estimated the costs of implementation of
the rule to states that own EGUs affected by the rule, and has included
this analysis in the RIA. The Agency has updated this analysis for the
final rule and it is included in the RIA. While the EPA has not
prepared an analysis of the impacts of the rule on state programs, the
Agency does not believe the rule will be unduly burdensome to the state
regulatory agencies. The EPA works closely with state regulatory
authorities to ensure that the rules are implemented properly, and the
Agency will continue to do so in support of this final rule.
Comment: A commenter states that the reductions in SO2
and PM2.5 required by the proposed rule will assist state
and local air pollution control agencies to meet health-based air
quality standards, reduce haze and improve visibility. The commenter
points out that substantial reduction in emissions made by the very
large sources under the proposed rule will lead to fewer pollution
controls needed at smaller sources to meet health-based ambient air
requirements. This is a far more cost-effective approach than controls
at smaller facilities and is the lowest cost path to improved public
health and a cleaner environment.
Response: The EPA acknowledges that the HAP standards in this final
rule will lead to considerable co-benefit reductions in PM and
SO2.
l. Miscellaneous
Comment: A few commenters discussed the impact of the rule on the
federal budget deficit. One commenter points out that the proposed rule
will affect the federal budget in two ways:
1. Direct compliance costs to electric generating units (EGUs)
owned by federal agencies; and
2. Pass-through compliance costs paid in the form of higher prices
for electricity purchased by federal agencies.
Response: The Agency estimates the direct compliance costs to EGUs
that are federally owned as part of the overall cost analysis completed
for the proposal and disclosed in the RIA for the rule. The Agency does
not provide an estimate of the impact on federal agencies from higher
electricity prices associated with the rule, however. This type of
analysis is not required under EO 12866 and statutory requirements.
H. Testing and Monitoring
Comment: Commenters raised numerous issues with the testing and
monitoring requirements for initial and continuous compliance. The
following discussion highlights the comments and responses to a number
of the critical issues and describe where the comments have resulted in
a significant rule change or where we disagreed with commenters'
suggestions of issues or need for changes in the rule. Additional
comments and responses are addressed in the Response to Comments
document included in the docket for the final rule.
Test Methods. A number of commenters suggested that we should allow
for the use of Method 5B to determine compliance with the PM emission
limit. In addition, a number of
[[Page 9420]]
commenters objected to the frequency of stack testing when used as the
method for demonstrating continuous compliance. Commenters also
objected to the requirement for testing one pollutant when the source
was complying with an optional surrogate (or vice versa); for example,
commenters objected to testing for HCl if a unit was complying with the
optional SO2 limit, or testing for metals if the unit was
complying with the optional PM limit.
Response: Although Method 5B is specified for wet scrubber-
controlled utility boilers under 40 CFR part 60, subparts D, Da and Db,
we are excluding Method 5B for demonstrating compliance with the
filterable PM emissions standard in this final rule. The extended high
temperature heating of the filters prior to weighing as specified in
Method 5B would introduce differences between the compliance test data
and the data that underlie the filterable particulate standard. Because
the test data that underlie and filterable particulate standard are
based primarily on Method 29 and Method 5 data collected at
320[emsp14][deg]F or comparable filterable particulate methods, we are
specifying those same methods for determining compliance with the
standard.
For stack test frequency, we modified the final rule to require
quarterly testing to demonstrate continuous compliance. In addition, we
agree that testing should be required only for the emission limits that
your source is complying with, and, thus, the final rule does not
require testing of both the pollutant and the surrogate.
Comment: Fuel Analysis Methods. A number of commenters raised
various concerns with the fuel analysis methods specified in the
proposed rule.
Response: Based on the comments received and a further review of
the technical challenges associated with the proposed fuel analysis
requirements, we have not finalized the proposed fuel analysis
requirements. As the rule no longer requires operating limits based on
fuel content or fuel analysis, the comments on this issue are largely
moot. For LEEs, we agree that the proposed LEE ongoing eligibility
requirements were overly burdensome and restrictive. As a result,
existing solid or liquid fired units that qualify for Hg LEE status
will be required to conduct a 30-day test for Hg using Method 30B each
year. Neither fuel analysis nor adherence to an operating limit will be
required. Should an annual test show ineligibility for LEE status, the
source will revert to the requirements for Hg monitoring using CEMS or
sorbent traps or, for oil-fired units, quarterly emissions testing.
Existing solid or liquid fired units that qualify for non-mercury LEE
status will be required to conduct a stack test every 3 years, and
neither fuel analysis nor adherence to an operating limit will be
required. Should the stack test show ineligibility for LEE status, the
source will revert to using CEMS or PM CPMS or conducting quarterly
emissions testing.
Comment: Operating Parameter Limits: Some commenters objected to
the use of enforceable operating parameter limits, requested that the
rule be more consistent with the compliance assurance monitoring
program, and raised specific objections to certain parameters required
for certain control devices. Commenters also raised concerns about a PM
CEMS operating limit establishing a de facto more stringent PM emission
limit than the one being tested for under the total PM standard in the
proposal.
Response: We believe that continuous monitoring in the form of
CEMS, sorbent trap monitoring systems, and PM CPMS, or frequent stack
emissions testing are appropriate to ensure ongoing compliance with
this final rule. We also agree with commenters that some of the
monitoring provisions in the proposal may have been duplicative and
unnecessary. In order to provide flexibility in the final rule, we have
retained a source's ability to define an operating limit and to monitor
using a PM CPMS as an option to periodic filterable PM emissions
testing.
The final rule establishes the PM CPMS as an operating limit
monitor and not a direct filterable PM emission monitoring requirement
that meets PS 11 requirements. Although we recognize the importance of
continued control device performance to ensure emissions minimization,
we also are aware that other rules that apply to these units including,
but not limited to, the Operating Permits rule, the Compliance
Assurance Monitoring rule, the ARP rules, and the NSPS already require
continuous monitoring in most cases. Those rules will remain in effect
so the need to impose additional operating limits monitoring or CEMS on
those units is much reduced.
The final rule also provides for the use of a PM CEMS to determine
compliance with the filterable PM emission limit if the source elects
to use this approach. In that case, the PM CEMS is used as the direct
method of compliance and no additional testing is required other than
tests that are required as part of satisfying the requirements in
Performance Specification 11 in Appendix B to 40 CFR part 60 and
Procedure 2 in Appendix F to part 60. The EPA provided this option in
response to the comments in order to provide a straightforward direct
measure of compliance that some sources may want to implement.
Comment: Hg CEMS. Commenters raised a number of technical concerns
about Hg CEMS. Many commenters requested modifications so that the
requirements would be more consistent with 40 CFR part 75 monitoring
requirements. Some commenters questioned the ability of the technology
to demonstrate compliance with emission limits at very low levels
especially for new sources. Commenters also opposed high data
availability requirements given that the technology is new and
difficult to operate and maintain.
Response: We indicated in the proposed rule the intent to adopt
CAMR-based requirements for Hg monitoring in place of the general 40
CFR part 63 performance specifications and QA requirements. With CAMR,
these operating and reporting requirements for Hg CEMS went through
notice and comment rulemaking for the same sources as covered by this
final rule. Although CAMR was set aside on other grounds, these
technical specifications and QA requirements reflect significant input
from stakeholders and analysis by the EPA to establish an appropriate
foundation for Hg monitoring at electric utilities under the CAA. For
the final rule, we have made conforming changes to ensure that this
intent is carried out effectively throughout the rule text and Appendix
A, as well as including certain additional clarifications based on the
input received in response to the proposed rule. We have also removed a
cycle time test as unworkable for certain types of Hg CEMS.
The final rule provides the option for use of either Hg CEMS or
sorbent trap monitoring systems. We believe the record clearly shows
these to be proven technologies each providing certain advantages. For
existing and some of the new unit standards, the level of the NIST-
traceable Hg gas standards will be adequate and consistent with
existing applications of Hg CEMS. For the lowest limits and other
applications where an integrated sampling system offers advantages,
affected facilities may opt to use sorbent trap monitoring systems to
comply. There are data in the recent draft report entitled
``Determining the Variability Of CMMS At Low Hg Levels,''\354\ that
demonstrate reasonable
[[Page 9421]]
performance of at least one Hg CEMS at Hg levels below 1.0 microgram
per cubic meter ([mu]g/m3) down to approximately 0.1 [mu]g/
m3. Finally, there is no specific minimum data availability
requirement for Hg CEMS (or any other CMS required under this final
rule). This issue is discussed further below.
---------------------------------------------------------------------------
\354\ https://www.icci.org/reports/10Laudal6A-1.pdf.
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Comment: SO2 CEMS: Although commenters were generally
supportive of the ability to use SO2 CEMS for units with FGD
installed to demonstrate compliance with an alternate SO2
emission limit instead of the HCl emission limit, there were some
concerns with aspects of the proposal. Commenters requested that the
SO2 monitoring requirements rely on 40 CFR part 75 given
that their sources were already meeting those requirements and that
this rule not establish any new requirements, especially a fourth
linearity level and the application of 7-day calibration error tests
for units with low concentrations (where 40 CFR part 75 provides an
exemption). Commenters were also concerned that the rule language only
allows the option where the FGD is operated ``at all times'' which
seems to imply that the option is not allowed if the source ever
bypasses the FGD for start-up, shutdown, or malfunction reasons.
Response: After reviewing the comments and assessing the need for
an additional calibration gas at the emissions limit, we have removed
this requirement from the final rule while retaining the requirement
for a linearity check even for SO2 monitors with low span
values (<= 30 ppm). A source can already report linearity tests for
these units within the context of the existing ECMPS reporting without
triggering any critical errors. This test can be accommodated within
the current framework without causing issues for 40 CFR part 75
reporting. The requirement for a 7-day calibration error test is
removed. For the ``at all times'' language, we have clarified this in
the final rule. The intent is that the FGD be operated during all
routine boiler operations, and not operated intermittently, seasonally,
or on some other non-fulltime basis.
Comment: HCl CEMS. In general, commenters argued that HCl CEMS do
not have an approved performance specification and are not widely
demonstrated as a proven technology. Those concerns were also mentioned
for HF CEMS.
Response: We disagree with commenters' contention that continuous
HCl monitoring is premature or not available for the measurement at the
emission limits set in the final rule. HCl CEMS are being used on
source categories such as municipal waste combustors and EGUs. We have
reviewed HCl CEMS vendor technology claims and found sufficient
capability to support this rule requirement. We are engaged with
representative stakeholders to develop a generic performance
specification for HCl CEMS scheduled for completion in time to be
responsive to compliance with this rule.
The final rule provides several options for HCl and/or HF
monitoring including:
(1) Using Fourier Transform Infrared (FTIR)-based HCl CEMS and/or
HF CEMS complying with Appendix B to the rule which relies on PS 15,
(2) Seeking approval for an alternative HCl monitoring procedure
through 40 CFR 63.7(f),
(3) Monitoring compliance continuously with the alternate
SO2 emission limit at coal-fired or other solid fuel
affected facilities equipped with FGD technology for SO2,
and
(4) Quarterly reference method testing.
Including these options in the final rule provides flexibility to
adopt CEMS monitoring options as the technology continues to mature and
the new, non-technology-specific EPA performance specifications becomes
available.
Comment: Bypass Stacks. Several commenters raised concerns about
the technical feasibility of monitoring bypass stacks with a CEMS.
Response: We have modified the bypass stack monitoring
requirements. Under 40 CFR part 75, we allow the use of a maximum
potential concentration value for reporting when emissions are vented
to a bypass stack. That approach works within the context of an
emissions trading program, but is not appropriate when evaluating
compliance with a specific emission limit. Thus, we have provided two
other options. One is to monitor the bypass stack, consistent with the
final rule. The other is to treat any hours of bypass stack emissions
as periods of monitor downtime and hours of deviation from the
monitoring requirements. Note that a source's units must continue to
meet their 30-boiler operating day emissions limits during malfunction
periods.
Comment: 40 CFR part 75 Issues. There were a number of general
comments about the value of relying on 40 CFR part 75 requirements,
including elements such as conditional data validation. The commenters
generally agreed that the 40 CFR part 75 bias test and bias adjustment
factor, and the 40 CFR part 75 substitute data provisions should not
apply. Instead of substitute data, many commenters suggested that we
needed to clarify the valid reasons for monitor downtime and establish
an appropriate minimum data availability requirement.
Response: We have attempted to harmonize the CEMS requirements in
this final rule with those under 40 CFR part 75 wherever appropriate.
One of those examples is the inclusion of conditional data validation
for Hg CEMS. We disagree that this final rule needs a minimum data
availability requirement. We have not included any specific minimum
data availability requirement for CEMS or other monitoring in this
final rule nor do we provide a specific tool for data substitution. We
believe that there are other provisions in the final rule to provide
incentives to conduct monitoring in a manner consistent with good air
pollution control practices and to provide data sufficient to
demonstrate compliance with a relatively long-term (30-boiler operating
day) emissions rate limit. We agree that data quality certainty
associated with any calculated value decreases with the collection of
less data such as would occur with extended periods of monitoring
system downtime. Even so, we believe also that it is necessary and
critical for compliance with the regulation that a source use all
measured data collected during an averaging period to assess compliance
regardless of any periods of missing data. Sources should not
disqualify any data otherwise meeting required data quality
requirements simply because there were data missing for other hours or
days of the averaging period.
Instead of a minimum data availability threshold that would
invalidate data collected for some averaging periods because one did
not collect data for at least a specified percent of an averaging time,
the final rule requires that a source report as deviations to the rule
failure to collect data during required periods if these deviations are
not covered by exceptions allowed in the final rule.
On the issue of applying a data substitution procedure to represent
actual emissions or pollution control performance, we are not requiring
data substitutions under this rule. We believe, however, that
defensibility concerns make it incumbent on the source to collect and
evaluate other information in accordance with 40 CFR section 63.6(f)(3)
during periods of monitoring downtime to assure compliance with the
applicable emissions limitations and standards.
We believe that enforcement authorities also can and should
determine whether a source is meeting any monitoring system operating
[[Page 9422]]
requirements. Should the source or the enforcement authority be
concerned about the representativeness of data such as during periods
of missing data, either one may consider collecting information through
other means (e.g., supplemental emissions testing) to fill data gaps
not only because such gaps are deviations from the rule but such gaps
can lead to uncertainty about compliance status.
We further believe that the final rule provides sufficient means to
ensure CMS performance and ongoing compliance without specifying an
arbitrary numerical minimum data availability or data substitution
requirement. We believe that specifying failure to collect required or
otherwise excepted data as a deviation from the rule will provide the
necessary incentive to collect data sufficient to demonstrate
compliance with the limits in the final rule.
Comment: Recordkeeping. Several commenters opposed the requirements
related to maintaining records on site and for 5 years.
Response: We believe the recordkeeping and retention requirements
are consistent with other requirements already in place, specifically
40 CFR 63.10 (b).
In addition, the 5-year retention period is the general rule for
all recordkeeping for all sources under the part 70 operating permits
program. Given that the General Provisions for 40 CFR part 63 and part
70 already establish a 5-year retention period, we believe it is
justified in using those precedents for the retention periods under
this subpart. If we stayed silent on retention period in this subpart,
the General Provisions would provide for the 5-year retention as would
the part 70 requirements. Thus, this action does not establish any new
retention requirements, but merely confirms that the existing retention
requirements apply.
Comment: Electronic Reporting. In the proposed rule, we requested
comment on using ECMPS for reporting under this rule, as well as other
options including the ERT. Commenters generally supported the use of
ECMPS, especially for CEMS data. Some commenters requested an
additional rulemaking on the specific data elements to be collected.
There were some concerns raised about the ERT given experience during
the 2010 ICR process during the development of this rule.
Response: We recognize that emissions reporting for continuously
measured pollutants (SO2, NOX, etc.) and for
periodically measured pollutants (PM, HAP metals, etc.) have different
data demands. We recognize that minor revisions of the ECMPS will
fulfill our data needs for most continuously measured pollutants and we
will make these modifications for receipt of the additional CEMS data.
We also recognize the need for substantial modifications to the ECMPS
to accommodate the data needs for periodically measured pollutants and
certain CEMS data such as PM CEMS data and possibly HAP metals CEMS
data. Although major modifications of the ECMPS would be required for
periodic compliance tests by isokinetic and instrumental test methods
(as well as certain types of CEMS), only minor revisions are required
of the ERT to receive these tests. We are implementing the changes in
the ERT that are required to provide the software tools to implement
the delivery of these performance test data to us.
The electronic submission of compliance test reports to us through
the Central Data Exchange (CDX) is not solely for the purpose of
developing improved emissions factors as some commenters assert.
Although populating WebFIRE will allow us to improve emissions factors,
we intend to use data stored in WebFIRE as the primary location for
compliance test reports for use by regulatory authorities. The
electronic submission of compliance test reports is a continuation of
our efforts to bring the submission and sharing of environmental data
into the modern age. The storage of this compliance data in our WebFIRE
provides a convenient location which is already used to store source
test data.
As federal and state and local agencies' data systems mature,
information provided through the ERT will be used to populate these
data systems. We are currently upgrading the AIRS Facility System and
expect to replace manually entered information with electronic
population from the ERT. We are also working with several state and
local agencies to adopt the use of the ERT for delivery of compliance
test reports. The ERT is also much improved since the version used
during the 2010 ICR process, and there is no expectation that the
information to be reported under this final rule will be as extensive
as some of the data reported for the 2010 ICR purposes.
We disagree that a separate and independent regulatory action is
required to implement electronic reporting for selected regulated
sources. Each of these regulatory actions for selected source
categories provides ample notice and the opportunity for individuals to
provide comment. We also disagree that the system to receive the
compliance data must be operational prior to establishing the
requirement for regulated sources to submit compliance data
electronically. We are on track to have the capability to receive
electronic compliance tests through our CDX in sufficient time to
receive all utility source test reports required by this final rule.
We do plan a separate and independent regulatory action to
implement electronic reporting for regulated entities which are covered
by past and future rules. Although we have provided draft procedures
for the development of emissions factors, that effort is an ancillary
effort to the electronic delivery of compliance test reports. It is our
intention to convert to the electronic delivery and storage of all air
emissions compliance source test data. With this transition, we believe
this valuable information will be more readily available not only for
compliance purposes but also for a variety of other uses.
I. Emissions Averaging
Comment: In response to our request for comments on the suitability
of emissions averaging and need for a discount factor, we received a
range of suggestions, including requests for clarification regarding
eligibility, points for and against the need for a discount factor, and
suggestions to ease implementation.
Response: We are finalizing that owners and operators of existing
affected sources may demonstrate compliance by emissions averaging for
EGUs at the affected source that are within a single subcategory and
that rely on emissions testing as the compliance demonstration method.
See section VI of thie preamble for a fuller discussion.
J. LEE Criteria
Comment: A commenter supported the LEE provisions but believed one
of the LEE eligibility criteria should set at 29.0 lb/year, rather than
22.0 lb/year. The commenter suggested 29.0 lb/year to be an equally
reasonable cut point, especially since that value matches the low mass
emitter Hg monitoring cutoff in CAMR and the low mass emitter Hg
monitoring cutoff that several states have adopted, including Illinois,
35 Ill. Admin. Code section 225.240(a)(4). (See, e.g., Colorado (5
Colo. Code Regs. section 1 00 1-8, Reg. No.6, part B, Section
VIII.B.l0); Michigan (Mich. Admin. Code R. 336.2160); Montana (Mont.
Admin. R. 17.8771(12))). Further, a LEE cutoff of 29.0 lb would
eliminate conflicts and confusion with low mass emitter provisions in
existing state Hg
[[Page 9423]]
programs and significantly reduce compliance costs and burdens for the
additional qualifying units without adversely affecting compliance
assurance with the EGU NESHAP Hg emission limits or materially
increasing the number of potential qualifying LEEs. Given the many
other costly burdens that the rule would impose, the benefit of LEE to
a qualifying unit is not insignificant.
Response: The Agency reviewed the commenter's suggestions, and one
of the LEE eligibility criteria in the rule has been revised from 22.0
to 29.0 lb of Hg per year. The Agency finds the result of consistency
with existing state regulations outweighs the two percent difference in
nationwide Hg mass emissions, from 5 percent to 7 percent, for LEE
eligibility.
VIII. Background Information on the NSPS
A. What is the statutory authority for this final NSPS?
New source performance standards implement CAA section 111(b), and
are issued for categories of sources which cause, or contribute
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare. Section 111 of the CAA requires that
NSPS reflect the application of the best system of emissions reductions
which (taking into consideration the cost of achieving such emissions
reductions, any non-air quality health and environmental impact and
energy requirements) the Administrator determines has been adequately
demonstrated. The level of control prescribed by CAA section 111
historically has been referred to as ``Best Demonstrated Technology''
or BDT. In order to better reflect that CAA section 111 was amended in
1990 to clarify that ``best systems'' may or may not be ``technology,''
the EPA is now using the term ``best system of emission reduction'' or
BSER. As was done previously in analyzing BDT, the EPA uses available
information and considers the emission reductions and incremental costs
for different systems available at reasonable cost. Then, the EPA
determines the appropriate emission limits representative of BSER.
Section 111(b)(1)(B) of the CAA requires EPA to periodically review and
revise the standards of performance, as necessary, to reflect
improvements in methods for reducing emissions.
B. What is the regulatory authority for the final rule?
The current standards for steam generating units are contained in
the NSPS for EGUs (40 CFR part 60, subpart Da), industrial-commercial-
institutional steam generating units (40 CFR part 60, subpart Db), and
small industrial-commercial-institutional steam generating units (40
CFR part 60, subpart Dc).
The NSPS for EGUs (40 CFR part 60, subpart Da) were originally
promulgated on June 11, 1979 (44 FR 33580) and apply to units capable
of firing more than 73 megawatts (MW) (250 MMBtu/h) heat input of
fossil fuel that commenced construction, reconstruction, or
modification after September 18, 1978. The NSPS for EGUs also apply to
industrial-commercial-institutional cogeneration units that sell more
than 25 MW and more than one-third of their potential output capacity
to any utility power distribution system. The most recent significant
amendments to emission standards under 40 CFR part 60, subpart Da, were
promulgated in 2006 (71 FR 9866) resulting in new PM, SO2,
and NOP2 limitations for 40 CFR part 60, subpart Da units.
The NSPS for industrial-commercial-institutional steam generating
units (40 CFR part 60, subpart Db) apply to units for which
construction, modification, or reconstruction commenced after June 19,
1984, that have a heat input capacity greater than 29 MW (100 MMBtu/h).
Those standards were originally promulgated on November 25, 1986 (51 FR
42768) and also have been amended since the original promulgation to
reflect changes in BSER for these sources.
The NSPS for small industrial-commercial-institutional steam
generating units (40 CFR part 60, subpart Dc) were originally
promulgated on September 12, 1990 (55 FR 37674) and apply to units with
a maximum heat input capacity greater than or equal to 2.9 MW (10
MMBtu/h) but less than 29 MW (100 MMBtu/h). Those standards apply to
units that commenced construction, reconstruction, or modification
after June 9, 1989.
IX. Summary of the Final NSPS
The final rule amends the emission standards for SO2,
NOP2, and PM in 40 CFR part 60, subpart Da. Only those units
that begin construction, modification, or reconstruction after May 3,
2011, will be affected by the final rule. Compliance with the emission
limits of the final rule will be determined using testing, monitoring,
and other compliance provisions similar to those set forth in the
existing standards. In addition to the emissions limits contained in
the final rule, we also are including several technical clarifications
and corrections to existing provisions of the subparts.
A. What are the requirements for new EGUs (40 CFR part 60, subpart Da)?
The filterable PM emissions standard for new and reconstructed EGUs
is 11 nanograms per joule (ng/J) (0.090 pound per megawatt hour (lb/
MWh)) gross energy output regardless of the type of fuel burned. The PM
emissions standard for modified EGUs is essentially equivalent to the
existing requirements of 13 ng/J (0.015 lb/MWh) heat input regardless
of the type of fuel burned. Compliance with this emission limit can be
determined using testing, monitoring, and other compliance provisions
similar to those for PM standards set forth in the existing rule. While
not required, PM CEMS may be used as an alternative method to
demonstrate continuous compliance and as an alternative to opacity and
parameter monitoring requirements.
The SO2 emission limit for new and reconstructed EGUs is
130 ng/J (1.0 lb/MWh) gross energy output or 97 percent reduction
regardless of the type of fuel burned with one exception. The EPA
neither proposed to amended the SO2 standard for coal
refuse-fired EGUs, not reopened the issue of whether coal refuse-fired
EGUs is an appropriate subcategory, and, therefore, that emissions
standard is unchanged. The SO2 emission limit for modified
EGUs burning any fuel is 180 ng/J (1.4 lb/MWh) gross energy output or
90 percent reduction. Compliance with the SO2 emission limit
is determined on a 30-boiler operating day rolling average basis using
a CEMS to measure SO2 emissions and following the compliance
provisions in the proposed rule.
The NOX emission limit for new and reconstructed EGUs is
88 ng/J (0.70 lb/MWh) gross energy output regardless of the type of
fuel burned with one exception. The exception is that for new and
reconstructed EGUs that burn over 75 percent coal refuse (by heat
input), the NOX emission limit is 110 ng/J (0.85 lb/MWh)
gross energy output. The NOX limit for modified EGUs is 140
ng/J (1.1 lb/MWh) gross energy output regardless of the type of fuel
burned in the unit. Compliance with this emission limit is determined
on a 30-boiler operating day rolling average basis using testing,
monitoring, and other compliance provisions similar to those in the
proposed rule.
As an alternative to the NOX standard, owners/operators
of new and reconstructed EGUs may elect to comply with a combined
NOX/CO standard of 140 ng/J (1.1 lb/MWh) with one exception.
The exception is that for new
[[Page 9424]]
and reconstructed EGUs that burn over 75 percent coal refuse (by heat
input) on an annual basis, the NOX/CO emission limit is 160
ng/J (1.3 lb/MWh) gross energy output. Finally, owners/operators of
modified EGUs may elect to comply with a combined NOX/CO
standard of 190 ng/J (1.5 lb/MWh).
B. Additional Amendments
See the Response to Comments document.
X. Summary of Significant Changes Since Proposal
A. Emission Limits
The proposal included a combined (filterable plus condensable) PM
standard. The final standard is based only on filterable PM. No
standard is being established for condensable PM. The rationale for
this is set forth in the Response to Comments (RTC) document for this
final rule (the NSPS Final Rule RTC).
The proposal requested comment on whether the final standard should
include a stand-alone NOX standard or a combined
NOX/CO standard. In response to comments we received and our
own further evaluation of the situation, the final standard includes a
stand-alone NOX standard and an optional, but not required,
combined NOX/CO standard as an alternative to the amended
NOX standard. Again, our full rationale for this is set
forth in the NSPS Final Rule RTC. The proposal also included a request
for comment on whether the standard should be based on gross or net
output. In response to comments we received and our own further
evaluation of the situation, the final standards are based on an
amended definition of gross output with an optional net output-based
standard. This too is addressed more fully in the NSPS Final Rule RTC.
The proposal included alternate emission standards for commercial
demonstration projects. Proposed commercial demonstrations included
pressurized fluidized beds, multi-pollutant control technologies, and
advanced combustion controls. The final rule includes the commercial
demonstration permit exemption for pressurized fluidized beds and
multi-pollutant control technologies, but not advanced combustion
controls. Advanced combustion controls are applicable to existing
facilities and the exemption is not necessary to further the
development of the technology.
B. Requirements During Startup, Shutdown, and Malfunction
For startup and shutdown, the requirements for PM have changed
since proposal. For periods of startup and shutdown, the EPA is
finalizing work practice standards for PM in lieu of numeric emission
limits. Emissions incurred during periods of startup and shutdown for
PM are not used in demonstrations of compliance with the 30-boiler
operating day rolling average period applicable for numeric emission
standards.
XI. Public Comments and Responses to the Proposed NSPS
See the Response to Comments document.
XII. Impacts of the Final Rule
The EPA anticipates significant public health and environmental
benefits from the rule as a direct result of the substantial reduction
in the emissions of several pollutants, including SO2, Hg,
acid gases and fine particles and metals. For example, exposure to Hg
can damage the developing nervous system, which can impair children's
ability to think and learn, and fine particles can cause adverse
cardiovascular effects. Further, reducing Hg deposition to ecosystems
will benefit wildlife including fish, birds, and mammals. Fish and
fish-eating birds, such as the common loon, and mammals suffer
reproductive, survival, and behavioral impairments due to mercury
exposure. These effects have also been observed in insect-eating and
wading birds, including egrets and white ibis. Reductions of emissions
targeted by this rule also will slow acidification and eutrophication
of water bodies.
Additionally, the EPA anticipates significant non-health, non-
ecological benefits from this rule. The fine particle and
SO2 emission reductions achieved by this rule will improve
visibility, which is especially important for our national parks.
Emissions reductions from this rule will also avoid an estimated $360
million (in $2007) of climate-related costs, such as agricultural
productivity and property damage from increased flood risks.
A. What are the air impacts?
The EPA anticipates significant emission reductions under the final
rule from coal-fired EGUs, which are of particular interest due to
their share of total power sector emissions. In 2015, annual HCl
emissions are projected to be reduced by 88 percent, Hg emissions
reduced by 75 percent, and PM2.5 emissions reduced by 19
percent from coal-fired EGUs greater than 25 MW. In addition, the EPA
projects SO2 emission reductions of 41 percent, and annual
CO2 reductions of 1 percent from coal-fired EGUs greater
than 25 MW by 2015, relative to the base case. See Table 7.
Table 7--Summary of Emission Reductions From Coal-Fired EGUS Greater Than 25 MW (TPY)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2 (million NOX (million HCl (thousand PM2.5 (thousand CO2 (million
tons) tons) Mercury (tons) tons) tons) metric tonnes)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Base Case............................. 3.3 1.7 27 45 270 1,906
MATS.................................. 1.9 1.7 7 6 218 1,882
Change................................ -1.4 0.0 -20 -40 -52 -23
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Numbers may not add due to rounding.
The reductions in this table do not account for reductions in other
HAP which will occur as a result of this rule. For instance, the fine
particulate reductions presented above only partly reflect reductions
in many heavy metal particulates, and the HCl reductions above only
partly reflect reductions of all acid gases. This rule will also result
in additional HAP reductions from oil-fired EGUs, which are covered by
the rule but are not included in the EPA's analysis of emission
reductions.
B. What are the energy impacts?
The EPA projects that approximately 4.7 GW of coal-fired generation
(less than 2 percent of all coal-fired capacity and 0.5 percent of
total generation capacity in 2015) may be uneconomic to maintain and
may be removed from operation by 2015. These units are predominantly
smaller, less frequently used, and are dispersed throughout the
country. If current forecasts of either natural gas prices or
electricity demand were revised in the future to be higher, that would
create a greater incentive to
[[Page 9425]]
make further investments in these facilities and keep these units
operational.
The final rule has other important energy market implications.
Average nationwide retail electricity prices are projected to increase
in the contiguous U.S. by 3.1 percent in 2015. The average delivered
coal price is projected to increase by less than 2 percent in 2015 as a
result of shifts within and across coal types. The EPA also projects
that electric power sector-delivered natural gas prices will increase
by between 0.3 and 0.6 percent over the 2015 to 2030 timeframe, on
average, and that natural gas use for electricity generation will
increase by less than 200 billion cubic feet (BCF) in 2015. These
impacts are well within the range of price variability that is
regularly experienced in natural gas markets. Finally, the EPA projects
coal production for use by the power sector, a large component of total
coal production, will decrease by 10 million tons in 2015 from base
case levels, which is about 1 percent of total coal produced for the
electric power sector in that year.
C. What are the cost impacts?
The power industry's ``compliance costs'' are represented in this
analysis as the change in electric power generation costs between the
base case and policy case in which the sector pursues pollution control
approaches to meet the MATS emission standards. In simple terms, these
costs are the resource costs of direct power industry expenditures to
comply with the EPA's requirements.
The EPA projects that the annual incremental compliance cost of
MATS is $9.6 billion in 2015 ($2007). The annualized incremental cost
is the projected additional cost of complying with the rule in the year
analyzed, and includes the amortized cost of capital investment and the
ongoing costs of operating additional pollution controls, needed new
capacity, shifts between or amongst various fuels, and other actions
associated with compliance.
The total incremental compliance cost includes compliance costs
modeled in IPM of $9.4 billion, costs modeled outside of IPM for oil-
fired EGUs of $56 million, and monitoring, reporting, and recordkeeping
costs of $158 million.
D. What are the economic impacts?
For this final rule, EPA analyzed the costs using the IPM. The IPM
is a dynamic linear programming model that can be used to examine the
economic impacts of air pollution control policies for a variety of HAP
and other pollutants throughout the contiguous U.S. for the entire
power system.
Documentation for IPM can be found in the docket for this
rulemaking or at https://www.epa.gov/airmarkets/progsregs/epa-ipm/.
The EPA performed a screening analysis for impacts on small
entities by comparing compliance costs to sales/revenues (e.g., sales
and revenue tests). The EPA's analysis can be found in Chapter 7 of the
RIA for this rule. The EPA has also prepared a Final Regulatory
Flexibility Analysis (FRFA) that discusses alternative regulatory or
policy options that minimize the rule's small entity impacts.
Although a stand-alone analysis of employment impacts is not
included in a standard cost-benefit analysis, the current economic
climate has led to heightened concerns about potential job impacts.
Executive Order 13563 specifically states that our ``regulatory system
must protect public health, welfare, safety, and our environment while
promoting economic growth, innovation, competitiveness, and job
creation'' (emphasis added).
Under conditions of full employment, it is conventional to assume
that regulations will merely shift jobs from one sector to another,
without having a material effect on employment levels. Potential
employment effects are of greater concern in the current economic
climate, with high levels of employment, because of the risk that
displaced workers may not find alternative jobs. In addition,
regulations that result in firms hiring workers, in order to ensure
compliance, may have a positive effect on employment.
During sustained periods of excess unemployment, the opportunity
cost of labor required by regulated sectors to bring their facilities
into compliance with an environmental regulation may be lower than it
would be during a period of full employment (particularly if regulated
industries employ otherwise idled labor to design, fabricate, or
install the pollution control equipment required under this final
rule). Consistent with EO 13563, the EPA includes estimates of job
impacts associated with the final rule. In the electricity sector, the
EPA estimates that the net employment effect will range from -15,000 to
+30,000 jobs, with a central estimate of +8,000. The EPA also presents
an estimate of short-term employment effects as a result of increased
demand for pollution control equipment.
The results of this analysis, found in Chapter 6 of the RIA,
indicate that the final rule has the potential to provide increases in
short-term employment in the environmental industry, primarily driven
by the high demand for new pollution control equipment. Overall, the
results suggest that the final rule could support a net of roughly
46,000 job years \355\ in direct employment impacts in 2015.
---------------------------------------------------------------------------
\355\ Numbers of job years are not the same as numbers of
individual jobs, but represents the amount of work that can be
performed by the equivalent of one full-time individual for a year
(or FTE). For example, 25 job years may be equivalent to five full-
time workers for five years, 25 full-time workers for one year, or
one full-time worker for 25 years.
---------------------------------------------------------------------------
There are other employment effects that cannot be estimated
quantitatively at this time. The employment gains related to the new
pollution controls are likely to be tempered by some losses due to
certain coal retirements. On the other hand, some of those workers who
lose their jobs due to plant retirements could find alternative
employment operating the replacement electricity generating equipment
or new pollution controls at nearby units. Finally, job losses due to
reduced coal demand may be offset by job gains due to increased natural
gas demand, potentially resulting in a positive net change in
employment due to fuel demand changes.
The basic approach to estimate these employment impacts involved
using IPM projections from the final rule analysis, in particular the
amount of existing coal-fired capacity that is projected to be retrofit
with pollution control technologies. These data, along with data on
labor and resource needs of new pollution controls and labor
productivity from engineering studies and secondary sources, are used
to estimate employment impacts for the pollution control industry in
2015. For more information, please refer to Chapter 6 and appendix 6B
in the RIA.
The EPA relied on Morgenstern, et al., (2002), to identify three
economic mechanisms by which pollution abatement activities can
influence jobs in the regulated sector separately from the short-term
employment effects:
[ssquf] Higher production costs raise market prices, higher prices
reduce consumption, and employment within an industry falls (``demand
effect'');
[ssquf] Pollution abatement activities require additional labor
services to produce the same level of output (``cost effect''); and
[ssquf] Post-regulation production technologies may be more or less
labor intensive (i.e., more/less labor is required per dollar of
output) (``factor-shift effect'').
Using plant-level Census information between the years 1979 and
1991,
[[Page 9426]]
Morgenstern,et al., estimate the size of each effect for four polluting
and regulated industries (petroleum, plastic material, pulp and paper,
and steel). On average across the four industries, each additional $1
million spent on pollution abatement results in a small net increase of
1.55 jobs; the estimated effect is not a statistically different from
zero. As a result, the authors conclude that increases in pollution
abatement expenditures may increase employment in the relevant sectors
and do not necessarily cause economically significant employment
changes. The conclusion is similar to that of Berman and Bui (2001) who
found that increased air quality regulation in Los Angeles did not
cause large employment changes.\356\ For more information, please refer
to Chapter 6 of the RIA for this final rule.\357\
---------------------------------------------------------------------------
\356\ For alternative views in economic journals, see Henderson
(1996) and Greenstone (2002).
\357\ It should be noted that if more labor must be used to
produce a given amount of output, then this implies a decrease in
labor productivity. A decrease in labor productivity will cause a
short-run aggregate supply curve to shift to the left, and
businesses will produce less, all other things being equal.
---------------------------------------------------------------------------
In the directly affected sector, the EPA estimates that the net
employment effect will range from -15,000 to +30,000 jobs, with a
central estimate of +8,000. The ranges of job effects for the
electricity sector, as calculated using the Morgenstern,et al.,
approach are listed in Table 8.
Table 8--Range of Job Effects for the Electricity Sector
--------------------------------------------------------------------------------------------------------------------------------------------------------
Estimates using Morgenstern, et al., (2001)
--------------------------------------------------------------------------------------------------------------------------
Demand effect Cost effect Factor shift effect Net effect
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Full-Time Jobs per -3.56........................ 2.42......................... 2.68......................... 1.55.
Million Dollars of
Environmental Expenditure a.
Standard Error............... 2.03......................... 0.83......................... 1.35......................... 2.24.
EPA estimate for Final Rule b -39,000 to................... +4,000 to.................... +200 to...................... -15,000 to
+2,000....................... +21,000...................... +27,000...................... +30,000.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Expressed in 1987 dollars. See footnote a from Table 6-2 of the RIA for inflation adjustment factor used in the analysis.
\b\ According to the 2007 Economic Census, the electric power generation, transmission and distribution sector (NAICS 2211) had approximately 510,000
paid employees.
The EPA recognizes there may be other job effects that are not
considered in the Morgenstern,et al., study. Although EPA has
considered some economy-wide changes, we do not have sufficient
information to quantify other job effects associated with this rule.
E. What are the benefits of this final rule?
1. Benefits of Reducing HAP Emissions
a. Human Health and Environmental Effects Due to Exposure to MeHg.
In this section, we provide a qualitative description of human health
and environmental effects due to exposure to MeHg. The NAS Study (NRC,
2000) provides a thorough review of the effects of MeHg on human
health. Many of the peer-reviewed articles cited in this section are
publications originally cited in the NAS Study. In addition, the EPA
has conducted literature searches to obtain other related and more
recent publications to complement the material summarized by the NAS in
2000.
b. Neurologic Effects of Exposure to MeHg. In its review of the
literature, the NAS found neurodevelopmental effects to be the most
sensitive and best documented endpoints and concluded that they are
appropriate for establishing an RfD (NRC, 2000); in particular NAS
supported the use of results from neurobehavioral or neuropsychological
tests. The NAS Study (NRC, 2000) noted that studies in animals reported
sensory effects as well as effects on brain development and memory
functions and support the conclusions based on epidemiology studies.
The NAS noted that their recommended neurodevelopmental endpoints for
an RfD are associated with the ability of children to learn and to
succeed in school. They concluded the following: ``The population at
highest risk is the children of women who consumed large amounts of
fish and seafood during pregnancy. The committee concludes that the
risk to that population is likely to be sufficient to result in an
increase in the number of children who have to struggle to keep up in
school.''
c. Cardiovascular Impacts of Exposure to MeHg. The NAS summarized
data on cardiovascular effects available up to 2000. Based on these and
other studies, the NAS Study concluded that ``Although the data base is
not as extensive for cardiovascular effects as it is for other end
points (i.e., neurologic effects) the cardiovascular system appears to
be a target for MeHg toxicity in humans and animals.'' The report also
stated that ``additional studies are needed to better characterize the
effect of MeHg exposure on blood pressure and cardiovascular function
at various stages of life.''
Additional cardiovascular studies have been published since 2000.
The EPA did not develop a quantitative dose-response assessment for
cardiovascular effects associated with MeHg exposures, as there is no
consensus among scientists on the dose-response functions for these
effects. In addition, there is inconsistency among available studies as
to the association between MeHg exposure and various cardiovascular
system effects. The pharmacokinetics of some of the exposure measures
(such as toenail Hg levels) are not well understood. The studies have
not yet received the review and scrutiny of the more well-established
neurotoxicity data base.
d. Genotoxic Effects of Exposure to MeHg. The Mercury Study noted
that MeHg is not a potent mutagen but is capable of causing chromosomal
damage in a number of experimental systems. The NAS Study indicated
that evidence that human exposure to MeHg causes genetic damage is
inconclusive; they note that some earlier studies showing chromosomal
damage in lymphocytes may not have controlled sufficiently for
potential confounders. One study of adults living in the Tapaj[oacute]s
River region in Brazil (Amorimet al., 2000) reported a direct
relationship between MeHg concentration in hair and DNA damage in
lymphocytes, as well as effects on chromosomes. Long-term MeHg
exposures in this population were believed to occur through consumption
of fish, suggesting that genotoxic effects (largely chromosomal
aberrations) may result from dietary, chronic MeHg exposures similar to
and above those
[[Page 9427]]
seen in the populations studied in the Faroe Islands and Republic of
Seychelles.
e. Immunotoxic Effects to Exposure to MeHg. Although exposure to
some forms of Hg can result in a decrease in immune activity or an
autoimmune response (ATSDR, 1999), evidence for immunotoxic effects of
MeHg is limited (NRC, 2000).
f. Other Hg-Related Human Toxicity Data. Based on limited human and
animal data, MeHg is classified as a ``possible'' human carcinogen by
the International Agency for Research on Cancer (IARC, 1994) and in
IRIS (USEPA, 2002). The existing evidence supporting the possibility of
carcinogenic effects in humans from low-dose chronic exposures is
tenuous. Multiple human epidemiological studies have found no
significant association between Hg exposure and overall cancer
incidence, although a few studies have shown an association between Hg
exposure and specific types of cancer incidence (e.g., acute leukemia
and liver cancer) (NAS, 2000).
Some evidence of reproductive and renal toxicity in humans from
MeHg exposure exists. However, overall, human data regarding
reproductive, renal, and hematological toxicity from MeHg are very
limited and are based on studies of the two high-dose poisoning
episodes in Iraq and Japan or animal data, rather than epidemiological
studies of chronic exposures at the levels of interest in this
analysis.
g. Ecological Effects of Hg. Deposition of Hg to watersheds can
also have an impact on ecosystems and wildlife. Mercury contamination
is present in all environmental media, with aquatic systems
experiencing the greatest exposures due to bioaccumulation.
Bioaccumulation refers to the net uptake of a contaminant from all
possible pathways and includes the accumulation that may occur by
direct exposure to contaminated media as well as uptake from food.
A review of the literature on effects of Hg on fish \358\ reports
results for numerous species including trout, bass (large and
smallmouth), northern pike, carp, walleye, salmon, and others from
laboratory and field studies. The effects of MeHg in fish are
reproductive in nature. Although we cannot determine at this time
whether these reproductive deficits are affecting fish populations
across the U.S. it should be noted that it would seem reasonable that
over time reproductive deficits would have an effect on populations.
Mercury also affects avian species. In previous reports \359\ much
of the focus has been on large piscivorous species, in particular the
common loon. According to Evers,et al., significant adverse effects
from Hg on breeding loons have been found to occur, including
behavioral (reduced nest-sitting), physiological (flight feather
asymmetry) and reproductive (chicks fledged/territorial pair) effects
and reduced survival.\360\ Additionally, Evers, et al., (see footnote
5), believe that the weight of evidence indicates that population-level
effects occur in parts of Maine and New Hampshire, and potentially in
broad areas of the loon's range.
---------------------------------------------------------------------------
\358\ Crump, KL, and Trudeau, VL. Mercury-induced reproductive
impairment in fish. Environmental Toxicology and Chemistry. Vol. 28,
No. 5, 2009.
\359\ U.S. Environmental Protection Agency (EPA). 1997. Mercury
Study Report to Congress. Volume V: Health Effects of Mercury and
Mercury Compounds. EPA-452/R-97-007. U.S. EPA Office of Air Quality
Planning and Standards, and Office of Research and Development; U.S.
Environmental Protection Agency (U.S. EPA). 2005. Regulatory Impact
Analysis of the Final Clean Air Mercury Rule. Research Triangle
Park, NC., March; EPA report no. EPA-452/R-05-003. Available on the
Internet at https://www.epa.gov/ttn/ecas/regdata/RIAs/mercury_ria_final.pdf.
\360\ Evers, DC, Savoy, LJ, DeSorbo, CR, Yates, DE, Hanson, W,
Taylor, KM, Siegel, LS, Cooley, JH, Jr., Bank, MS, Major, A, Munney,
K, Mower, BF, Vogel, HS, Schoch, N, Pokras, M, Goodale, MW, Fair, J.
Adverse effects from environmental mercury loads on breeding common
loons. Ecotoxicology. 17:69-81, 2008; Mitro, MG, Evers, DC, Meyer,
MW, and Piper, WH. Common loon survival rates and mercury in New
England and Wisconsin. Journal of Wildlife Management. 72(3): 665-
673, 2008.
---------------------------------------------------------------------------
Recently, attention has turned to other piscivorous species such as
the white ibis and great snowy egret. These wading birds have a very
wide diet including crayfish, crabs, snails, insects and frogs. White
ibis have been observed to have decreased foraging efficiency\361\ and
have been shown to exhibit decreased reproductive success and altered
pair behavior.\362\ In egrets, Hg has been implicated in the decline of
the species in south Florida,\363\ and Hoffman\364\ has shown that
egrets exhibit liver and possibly kidney effects. Although ibises and
egrets are most abundant in coastal areas and these studies were
conducted in south Florida and Nevada, the ranges of ibises and egrets
extend to a large portion of the U.S.
---------------------------------------------------------------------------
\361\ Adams, EM, and Frederick, PC. Effects of methylmercury and
spatial complexity on foraging behavior and foraging efficiency in
juvenile white ibises (Eudocimus albus). Environmental Toxicology
and Chemistry. Vol 27, No. 8, 2008.
\362\ Frederick, P, and Jayasena, N. Altered pairing behavior
and reproductive success in white ibises exposed to environmentally
relevant concentrations of methylmercury. Proceedings of The Royal
Society B. doi: 10-1098, 2010.
\363\ Sepulveda, MS, Frederick, PC, Spalding, MG, and Williams,
GE, Jr. Mercury contamination in free-ranging great egret nestlings
(Ardea albus) from southern Florida, USA. Environmental Toxicology
and Chemistry. Vol. 18, No. 5, 1999.
\364\ Hoffman, DJ, Henny, CJ, Hill, EF, Grover, RA, Kaiser, JL,
Stebbins, KR. Mercury and drought along the lower Carson River,
Nevada: III. Effects on blood and organ biochemistry and
histopathology of snowy egrets and black-crowned night-herons on
Lahontan Reservoir, 2002-2006. Journal of Toxicology and
Environmental Health, Part A. 72: 20, 1223-1241, 2009.
---------------------------------------------------------------------------
Insectivorous birds have also been shown to suffer adverse effects
due to Hg exposure. Songbirds such as Bicknell's thrush, tree swallows,
and the great tit have shown reduced reproduction, survival, and
changes in singing behavior. Exposed tree swallows produced fewer
fledglings,\365\ had lower survival rates,\366\ and had compromised
immune competence.\367\ The great tit has exhibited reduced singing
behavior and smaller song repertoire in areas of high
contamination.\368\
---------------------------------------------------------------------------
\365\ Brasso, RL, and Cristol, DA. Effects of mercury exposure
in the reproductive success of tree swallows (Tachycineta bicolor).
Ecotoxicology. 17:133-141, 2008.
\366\ Hallinger, KK, Cornell, KL, Brasso, RL, and Cristol, DA.
Mercury exposure and survival in free-living tree swallows
(Tachycineta bicolor). Ecotoxicology. Doi: 10.1007/s10646-010-0554-
4, 2010.
\367\ Hawley, DM, Hallinger, KK, Cristol, DA. Compromised immune
competence in free-living tree swallows exposed to mercury.
Ecotoxicology. 18:499-503, 2009.
\368\ Gorissen, L, Snoeijs, T, Van Duyse, E, and Eens, M. Heavy
metal pollution affects dawn singing behavior in a small passerine
bird. Oecologia. 145: 540-509, 2005.
---------------------------------------------------------------------------
In mammals, adverse effects have been observed in mink and river
otter, both fish eating species. For otter from Maine and Vermont,
maximum concentrations of Hg in fur nearly equal or exceed a level
associated with mortality and concentration in liver for mink in
Massachusetts/Connecticut and the levels in fur from mink in Maine
exceed concentrations associated with acute mortality.\369\ Adverse
sublethal effects may be associated with lower Hg concentrations and
consequently may be more widespread than potential acute effects. These
effects may include increased activity, poorer maze performance,
abnormal startle reflex, and impaired escape and avoidance
behavior.\370\
---------------------------------------------------------------------------
\369\ Yates, DE, Mayack, DT, Munney, K, Evers DC, Major, A,
Kaur, T, and Taylor, RJ. Mercury levels in mink (Mustela vison) and
river otter (Lonra canadensis) from northeastern North America.
Ecotoxicology. 14, 263-274, 2005.
\370\ Scheuhammer, AM, Meyer MW, Sandheinrich, MB, and Murray,
MW. Effects of environmental methylmercury on the health of wild
birds, mammals, and fish. Ambio. Vol.36, No.1, 2007.
---------------------------------------------------------------------------
h. Methodology for Partial Hg Benefits Estimation. The EPA has
conducted a national-scale analysis of the benefits to recreational
anglers of avoided IQ loss related to reductions of Hg emissions
[[Page 9428]]
and subsequent deposition that will be achieved by this rule. Because
the primary measurable health effect of concern--developmental
neurological abnormalities in children--occurs as a result of in-utero
exposures to Hg, the specific population of interest in this case is
prenatally exposed children. To identify and estimate the size of this
exposed population, the benefits analysis focused on pregnant women in
freshwater recreational angler households. Estimating Hg exposures for
this exposure pathway and population of interest requires three main
components: (1) The size of the exposed population of interest (annual
number of pregnant women in freshwater angler households during the
year), (2) the average concentration of MeHg in noncommercial
freshwater fish filets consumed, and (3) the average daily consumption
rate of noncommercial freshwater fish. The Hg concentrations of fish in
the waterbodies where the fish are caught are modeled using Mercury
Maps to project the decline in concentrations due to the rule. To
approximate the percentage of freshwater fishing trips (and exposed
individuals) from each Census tract matched to each waterbody type, the
EPA used state-level averages. These averages were calculated for each
state, based on the portion of residents' freshwater fishing trips that
are to each waterbody type, based on 2001 National Survey of Fishing,
Hunting, and Wildlife-Associated Recreation (FHWAR) data.
Data from the 1994 National Survey on Recreation and the
Environment (NSRE) were used to approximate the percentage of
freshwater fishing trips (and exposed individuals) matched to different
distances from anglers' residential location.
To determine an appropriate daily fish consumption rate for the
analysis, the EPA conducted an extensive review of existing literature
characterizing self-caught freshwater fish consumption. Based on this
review, it was decided that the ingestion rates for recreational
freshwater fishers, specified as ``recommended'' in the EPA's
``Environmental Exposure Factors Handbook'' (EPA, 1997), represented
the most appropriate values to use in this analysis.
Estimating the IQ decrements in children that result from mothers'
prenatal ingestion of Hg from fish required two steps. First, based on
the estimated average daily maternal ingestion rate, the expected Hg
concentration in the hair of exposed pregnant women was estimated.
Second, to estimate the expected IQ decrement in offspring, the
following dose-response relationship was developed based on the summary
findings reported in Axelrad et al., (2007).
The valuation approach used to assess monetary losses due to IQ
decrements is based on an approach applied in previous EPA analyses
(EPA, 2008). The approach expresses the potential loss to an affected
individual resulting from IQ decrements in terms of foregone future
earnings (net of changes in education costs) for that individual.
The estimate for ``Present Value of Lifetime Earnings'' is derived
using earnings and labor force participation rate data from the Bureau
of Labor Statistics 2006 Current Population Survey. Estimates of the
average effect of a 1-point increase in IQ on lifetime earnings range
from a 1.76 percent increase (Schwartz, 1994) to a 2.379 percent
increase (Salkever, 1995). The percentage increases in the two studies
reflect both the direct impact of IQ on hourly wages and indirect
effects on annual earnings as the result of additional schooling and
increased labor force participation. The estimate for years of
additional schooling is based on Schwartz (1994), who reports an
increase of 0.131 years of schooling per IQ point.
In addition to this positive net effect on earnings, an increase in
IQ is also assumed to have a positive effect on the amount of time
spent in school and on associated costs. To incorporate (1) uncertainty
regarding the size of the percentage change in future earnings and (2)
different assumptions regarding the discount rate, the resulting value
estimates for the average net loss per IQ point decrement are expressed
as a range. Assuming a 3 percent discount rate, value IQ ranges from
$8,013 (using the Schwartz estimates) to $11,859 (using the Salkever
estimates) in increased earnings per year per 1-point IQ increase. With
a 7 percent discount rate assumption, the value IQ estimates range from
$893 to $1,958 in increased earnings per year per 1-point IQ increase.
The EPA analyzed the aggregate national IQ and present-value loss
estimates for two base case and three emission control scenarios. The
highest losses are estimated for the 2005 base case. For the population
of prenatally exposed children included in the analysis (almost
240,000), Hg exposures under baseline conditions during the year 2005
are estimated to have resulted in more than 25,500 IQ points lost.
Assuming a 3 percent discount rate, the present-year value of these
losses ranges from $204.8 million to $292.5 million nationally.\371\
These losses represent expected present value of declines in future net
earnings over the entire lifetimes of the children who are prenatally
exposed during the year 2005. With a 7 percent discount rate, the
present-year value range is considerably lower: $22.8 million to $50.0
million.
---------------------------------------------------------------------------
\371\ Monetized benefits estimates are for an immediate change
in MeHg levels in fish. If a lag in the response of MeHg levels in
fish were assumed, the monetized benefits could be significantly
lower, depending on the length of the lag and the discount rate
used. As noted in the discussion of the Mercury Maps modeling, the
relationship between deposition and fish tissue MeHg is proportional
in equilibrium, but the Mercury Maps approach does not provide any
information on the time lag of response.
---------------------------------------------------------------------------
For this rule, the EPA generated estimates of aggregate nationwide
benefits associated with reductions in Hg exposures and resulting
reductions in IQ losses. Most importantly, the benefits of the 2016
MATS scenario (relative to the 2016 base case) are estimated to range
between $4 million and $6 million (assuming a 3 percent discount rate),
because of an estimated 511 point reduction in IQ losses. The EPA
recognizes that these calculated benefits are a small subset of the
benefits of reducing Hg emissions.
2. Health and Welfare Co-Benefits
Emission controls installed to meet the requirements of this rule
will generate co-benefits by reducing criteria pollutants including
PM2.5 and SO2, as well as CO2. For
this rule, we were only able to estimate the mortality benefits of
PM2.5 reductions due to changes in emissions of
SO2 and direct PM2.5 and climate benefits
resulting from CO2 reductions. Additional co-benefits may
result from decreases in PM2.5 morbidity impacts, decreases
in sulfur deposition and direct health effects of SO2, and
improvements in visibility in national parks and wilderness areas.
Total co-benefits may be higher than the partial estimates of co-
benefits provided here. Our best estimate of the monetized health and
climate co-benefits of this rule in 2016 at a 3 percent discount rate
are $37 billion to $90 billion or $33 billion to $81 billion at a 7
percent discount rate (2007$). Using alternate relationships between
PM2.5 and premature mortality supplied by experts, higher
and lower health co-benefits estimates are plausible, but most of the
expert-based estimates fall between these two estimates.\372\
---------------------------------------------------------------------------
\372\ Roman, et al., 2008. Expert Judgment Assessment of the
Mortality Impact of Changes in Ambient Fine Particulate Matter in
the U.S. Environ. Sci. Technol., 42, 7, 2268-2274.
---------------------------------------------------------------------------
a. Human Health Co-Benefits. To estimate the human health co-
benefits of this rule, the EPA used benefit-per-ton
[[Page 9429]]
factors to quantify the changes in PM2.5-related health
impacts and monetized benefits based on changes in SO2 and
direct PM2.5 emissions. These benefit-per-ton factors were
based on an interim baseline and policy scenario for which full-scale
ambient air quality modeling and air quality-based human health
benefits assessments were performed. This general approach and
methodology is laid out in Fann, et al., (2009),\373\ but for this rule
the air quality modeling used a better spatial representation of the
emission changes from EGUs. Using a benefit-per-ton approach adds
another important source of uncertainty to the benefits estimates. For
more details on the creation of the benefit-per-ton factors and their
application to emission reductions under this rule, please refer to the
RIA for this rule in the docket.
---------------------------------------------------------------------------
\373\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. ``The
influence of location, source, and emission type in estimates of the
human health benefits of reducing a ton of air pollution.'' Air Qual
Atmos Health (2009) 2:169-176.
---------------------------------------------------------------------------
Table 9 presents the estimates of reduced annual incidence of
PM2.5-related health effects in 2016 resulting from this
rule. Table 10 presents the estimated annual monetary value of the
reduced incidence of quantified health endpoints in 2016 resulting from
this rule.
The reduction in premature fatalities each year accounts for
between 93 and 97 percent of the estimated health co-benefits that were
monetized.
Table 9--Estimated Reductions in Incidence of PM2.5-Related Health
Effects in 2016 a
------------------------------------------------------------------------
Health effect Number of reduced cases
------------------------------------------------------------------------
Adult Premature Mortality
------------------------------------------------------------------------
Pope et al., (2002) (age 4,200.
>30). (1,200 to 7,200).
Laden et al., (2006) (age 11,000.
>25). (5,000 to 17,000).
Infant Premature Mortality 20.
(<1 year). (-22 to 61).
Chronic Bronchitis........... 2,800.
(88 to 5,600).
Non-fatal heart attacks (age 4,700.
>18). (1,200 to 8,300).
Hospital admissions-- 830.
respiratory (all ages). (330 to 1,300).
Hospital admissions-- 1,800.
cardiovascular (age >18). (1,200 to 2,200).
Emergency room visits for 3,100.
asthma (age <18). (1,600 to 4,700).
Acute bronchitis (age 8-12).. 6,300.
(-1,400 to 14,000).
Lower respiratory symptoms 80,000.
(age 7-14). (31,000 to 130,000).
Upper respiratory symptoms 60,000.
(asthmatics age 9-11). (11,000 to 110,000).
Asthma exacerbation 130,000.
(asthmatics 6-18). (4,500 to 450,000).
Lost work days (ages 18-65).. 540,000.
(460,000 to 620,000).
Minor restricted-activity 3,200,000.
days (ages 18-65). (2,600,000 to 3,800,000).
------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Co-benefits from reducing
exposure to ozone, other criteria pollutants, and HAP, as well as
reducing visibility impairment and ecosystem effects are not included
here.
Table 10--Estimated Monetary Value (Billions 2007$) of PM2.5-Related
Health Benefits in 2016 a
------------------------------------------------------------------------
Health effect Monetized benefits
------------------------------------------------------------------------
Adult Premature Mortality
------------------------------------------------------------------------
Pope, et al., (2002) (age
>30):
3% discount rate......... $34.
($2.6 to $100).
7% discount rate......... $30.
($2.4 to $92).
Laden, et al., (2006) (age
>25):
3% discount rate......... $87.
($7.5 to $250).
7% discount rate......... $78.
($6.8 to $230).
Infant Premature Mortality $0.2.
(<1 year). ($-0.2 to $0.8).
Chronic Bronchitis........... $1.4.
($0.1 to $6.4).
Non-fatal heart attacks (age
>18):
[[Page 9430]]
3% discount rate......... $0.5.
($0.1 to $1.3).
7% discount rate......... $0.4.
($0.1 to $1.0).
Hospital admissions-- $0.01.
respiratory (all ages). ($0.01 to $0.02).
Hospital admissions-- $0.03.
cardiovascular (age >18). (<$0.01 to $0.05).
Emergency room visits for <$0.01.
asthma (age <18).
Acute bronchitis (age 8-12).. <$0.01.
Lower respiratory symptoms <$0.01.
(age 7-14).
Upper respiratory symptoms <$0.01.
(asthmatics age 9-11).
Asthma exacerbation <$0.01.
(asthmatics 6-18).
Lost work days (ages 18-65).. $0.1.
($0.1 to $0.1).
Minor restricted-activity $0.2.
days (ages 18-65). ($0.1 to $0.3).
------------------------------------------------------------------------
Monetized Health Co-Benefits
------------------------------------------------------------------------
Pope, et al., (2002):
3% discount rate......... $36.
($2.8-$110).
7% discount rate......... $33.
($2.5-$100).
Laden, et al., (2006):
3% discount rate......... $89.
($7.7-$260).
7% discount rate......... $80.
($6.9-$240).
------------------------------------------------------------------------
a Values rounded to two significant figures. Co-benefits from reducing
exposure to ozone, other criteria pollutants, and HAP, as well as
reducing visibility impairment and ecosystem effects are not included
here.
It is important to note that the magnitude of the PM2.5
co-benefits is largely driven by the concentration response function
for premature mortality. Experts have advised the EPA to consider a
variety of assumptions, including estimates based both on empirical
(epidemiological) studies and judgments elicited from scientific
experts, to characterize the uncertainty in the relationship between
PM2.5 concentrations and premature mortality. We cite two
key empirical studies, one based on the American Cancer Society cohort
study \374\ and the other based on the extended Six Cities cohort
study.\375\ The analyses upon which this rule is based were selected
from the peer-reviewed scientific literature. We used up-to-date
assessment tools, and we believe the results are highly useful in
assessing this rule.
---------------------------------------------------------------------------
\374\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary
Mortality, and Long-term Exposure to Fine Particulate Air
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
\375\ Ladenet al., 2006. ``Reduction in Fine Particulate Air
Pollution and Mortality.'' American Journal of Respiratory and
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------
Every benefit analysis examining the potential effects of a change
in environmental protection requirements is limited to some extent by
data gaps, model capabilities (such as geographic coverage), and
uncertainties in the underlying scientific and economic studies used to
configure the benefit and cost models. Gaps in the scientific
literature often result in the inability to estimate quantitative
changes in health and environmental effects, or to assign economic
values even to those health and environmental outcomes that can be
quantified. The uncertainties in the underlying scientific and
economics literature (that may result in overestimation or
underestimation of the co-benefits) are discussed in detail in the RIA.
Despite these uncertainties, we believe the benefit analysis for this
rule provides a reasonable indication of the expected health co-
benefits of the rulemaking in future years under a set of reasonable
assumptions.
When characterizing uncertainty in the PM-mortality relationship,
the EPA has historically presented a sensitivity analysis applying
alternate assumed thresholds in the PM concentration-response
relationship. In its synthesis of the current state of the PM science,
the EPA's 2009 Integrated Science Assessment for Particulate Matter
concluded that a no-threshold log-linear model most adequately portrays
the PM-mortality concentration-response relationship.
In the RIA accompanying this rulemaking, rather than segmenting out
impacts predicted to be associated with levels above and below a
``bright line'' threshold, the EPA includes a ``lowest measured level''
(LML) analysis that illustrates the increasing uncertainty that
characterizes exposure attributed to levels of PM2.5 below
the LML of each epidemiological study used to estimate
PM2.5-related premature death. Figures provided in the RIA
show the distribution of baseline exposure to PM2.5, as well
as the lowest air quality levels measured in each of the epidemiology
cohort studies. This information provides a context for considering the
likely portion of PM-related mortality benefits occurring above or
below the LML of each study; in general, our confidence in the size of
the estimated reduction in PM2.5-related premature mortality
diminishes as baseline concentrations of PM2.5 are lowered.
Based on the modeled interim baseline which is approximately
equivalent to the final baseline (see Appendix A of the RIA), 11
percent and 73 percent of the estimated avoided mortality impacts occur
at or above an
[[Page 9431]]
annual mean PM2.5 level of 10 [micro]g/m3 (the LML of the
Ladenet al., 2006 study)or 7.5 [micro]g/m3 (the LML of the Pope,et al.,
2002 study), respectively. Although the LML analysis provides some
insight into the level of uncertainty in the estimated PM mortality
benefits, the EPA does not view the LML as a threshold and continues to
quantify PM-related mortality impacts using a full range of modeled air
quality concentrations. A large fraction of the PM2.5-
related benefits occur below the level of the National Ambient Air
Quality Standard (NAAQS) for PM2.5 at 15 [micro]g/m3, which
was set in 2006. It is important to emphasize that NAAQS are not set at
a level of zero risk. Instead, the NAAQS reflect the level determined
by the Administrator to be protective of public health within an
adequate margin of safety, taking into consideration effects on
susceptible populations. While benefits occurring below the standard
may be less certain than those occurring above the standard, EPA
considers them to be legitimate components of the total benefits
estimate.
It is important to note that the monetized benefits include many
but not all health effects associated with PM2.5 exposure.
Benefits are shown as a range from Pope, et al., (2002), to Laden, et
al., (2006). These studies assume that all fine particles, regardless
of their chemical composition, are equally potent in causing premature
mortality because there is no clear scientific evidence that would
support the development of differential effects estimates by particle
type. Even though we assume that all fine particles have equivalent
health effects, the benefit-per-ton estimates vary between directly-
emitted particles (carbonaceous and crustal particles) and
SO2 emissions that form sulfate particles, based on the
location of emission changes and magnitude of population exposure
changes. Regardless, however, the assumption that all fine particles
are equally potent in causing premature mortality adds uncertainty to
the benefits estimate.
b. Non-Climate Welfare Co-Benefits. Emission controls installed to
comply with the requirements specified in this rule will also generate
co-benefits by improving visibility. We anticipate that improvements in
visibility in Class I areas as well as residential areas where people
live, work, and recreate could be substantial. Because full-scale air
quality modeling was not performed for this rule, we are unable to
quantify these visibility co-benefits for this rule. However, the
estimated value of visibility benefits calculated from the modeled
interim baseline and policy scenario was $1.1 billion (in 2007$). These
visibility benefits are not included in the total co-benefits estimate
of the final policy scenario used as a basis for this final rule. The
distribution of emission reductions did not change substantially in the
visibility regions studied, therefore visibility benefits of the final
policy scenario are likely to be of a similar magnitude.
Ecosystem and other welfare effects include reduced acidification
and, in the case of NOX, eutrophication of water bodies;
possible reduced nitrate contamination of drinking water; ozone
vegetation damage; a reduction in the role of sulfate in Hg
methylation; and reduced acid and particulate deposition that causes
damages to cultural monuments, as well as soiling and other materials
damage. To illustrate the important nature of benefit categories the
EPA is currently unable to monetize, we discuss the potential public
welfare and environmental impacts related to reductions in emissions
required by this rule in the RIA, including reduced visibility
impairment, reduced effects from acid deposition, reduced effects from
nutrient enrichment, and reduced vegetation effects from ambient
exposure to SO2 and NO2.
c. Climate co-benefits. This rule is expected to reduce
CO2 emissions from the electricity sector. The EPA has
assigned a dollar value to reductions in CO2 emissions using
recent estimates of the ``social cost of carbon'' (SCC). The SCC is an
estimate of the monetized damages associated with an incremental
increase in carbon emissions in a given year or the per metric ton
benefit estimate relating to decreases in CO2 emissions. It
is intended to include (but is not limited to) changes in net
agricultural productivity, human health, property damage from increased
flood risk, and the value of ecosystem services due to climate change.
The SCC estimates used in this analysis were developed through an
interagency process that included the EPA and other executive branch
entities, and that concluded in February 2010. We first used these SCC
estimates in the benefits analysis for the final joint EPA/DOT
Rulemaking to establish Light-Duty Vehicle Greenhouse Gas Emission
Standards and Corporate Average Fuel Economy Standards; see the rule's
preamble for discussion about application of the SCC (75 FR 25324; May
7, 2010). The SCC Technical Support Document (SCC TSD) provides a
complete discussion of the methods used to develop these SCC
estimates.\376\
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\376\ Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support
Document: Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866, Interagency Working Group on Social Cost of
Carbon, with participation by Council of Economic Advisers, Council
on Environmental Quality, Department of Agriculture, Department of
Commerce, Department of Energy, Department of Transportation,
Environmental Protection Agency, National Economic Council, Office
of Energy and Climate Change, Office of Management and Budget,
Office of Science and Technology Policy, and Department of Treasury
(February 2010). Also available at https://epa.gov/otaq/climate/regulations.htm.
---------------------------------------------------------------------------
The interagency group selected four SCC values for use in
regulatory analyses, which we have applied in this analysis: $5.9,
$24.3, $39, and $74.4 per metric ton of CO2 emissions in
2016, in 2007 dollars. The first three values are based on the average
SCC from three integrated assessment models, at discount rates of 5, 3,
and 2.5 percent, respectively. Social cost of carbon values at several
discount rates are included because the literature shows that the SCC
is quite sensitive to assumptions about the discount rate, and because
no consensus exists on the appropriate rate to use in an
intergenerational context. The fourth value is the 95th percentile of
the SCC from all three values at a 3 percent discount rate. It is
included to represent higher-than-expected impacts from temperature
change further out in the extremes of the SCC distribution. Low
probability, high impact events are incorporated into all of the SCC
values through explicit consideration of their effects in two of the
three values as well as the use of a probability density function for
equilibrium climate sensitivity. Treating climate sensitivity
probabilistically results in more high temperature outcomes, which in
turn leads to higher projections of damages.
Applying the global SCC estimates using a 3 percent discount rate,
we estimate the value of the climate related benefits of this rule in
2016 is $360 million (2007$), as shown in Table 11. See the RIA for
more detail on the methodology used to calculate these benefits and
additional estimates of climate benefits using different discount rates
and the 95th percentile of the 3 percent discount rate SCC. Important
limitations and uncertainties of the SCC approach are also described in
the RIA.
[[Page 9432]]
Table 11--Estimated Monetary Value (Billions 2007$) of PM2.5-Related
Health Benefits and Climate Benefits in 2016a
------------------------------------------------------------------------
Effect Monetized benefits
------------------------------------------------------------------------
Monetized Health Co-Benefits
------------------------------------------------------------------------
Pope, et al., (2002):
3% discount rate........................... $36
($2.8-$110)
7% discount rate........................... $33
($2.5-$100)
Laden, et al., (2006): .......................
3% discount rate........................... $89
($7.7-$260)
7% discount rate........................... $80
($6.9-$240)
Climate-related Co-Benefits (3% discount rate). $0.36
------------------------------------------------------------------------
Monetized Total Co-Benefits
------------------------------------------------------------------------
Pope, et al., (2002): .......................
3% discount rate........................... $37
($3.2-$110)
7% discount rate........................... $33
($2.9-$100)
Laden, et al., (2006): .......................
3% discount rate........................... $90
($8.0-$260)
7% discount rate........................... $81
($7.3-$240)
------------------------------------------------------------------------
a Values rounded to two significant figures. Co-benefits from reducing
exposure to ozone, other criteria pollutants, and HAP, as well as
reducing visibility impairment and ecosystem effects are not included
here.
Our best estimate for the monetized total health and climate co-
benefits of this rule in 2016 at a 3 percent discount rate is between
$37 billion and $90 billion or between $33 billion and $81 billion
(2007$) at a 7 percent discount rate. These estimates account for the
quantified health and climate benefits described in Table 11.
XIII. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review and Executive
Order 13563, Improving Regulation and Regulatory Review
Under EO 12866 (58 FR 51735; October 4, 1993), this action is an
``economically significant regulatory action'' because it is likely to
have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or state, local, or tribal governments or
communities. Accordingly, the EPA submitted this action to the OMB for
review under Executive Orders 12866 and 13563 and any changes in
response to OMB recommendations have been documented in the docket for
this action. For more information on the costs and benefits for this
rule, please refer to Table 2 of this preamble.
When estimating the human health benefits and compliance costs in
Table 2 of this preamble, the EPA applied methods and assumptions
consistent with the state-of-the-science for human health impact
assessment, economics and air quality analysis. The EPA applied its
best professional judgment in performing this analysis and believes
that these estimates provide a reasonable indication of the expected
benefits and costs to the nation of this rulemaking. The RIA available
in the docket describes in detail the empirical basis for the EPA's
assumptions and characterizes the various sources of uncertainties
affecting the estimates below. In doing what is laid out above in this
paragraph, the EPA adheres to EO 13563, ``Improving Regulation and
Regulatory Review,'' (76 FR 3821; January 18, 2011), which is a
supplement to EO 12866.
In addition to estimating costs and benefits, EO 13563 focuses on
the importance of a ``regulatory system [that] * * * promote[s]
predictability and reduce[s] uncertainty'' and that ``identify[ies] and
use[s] the best, most innovative, and least burdensome tools for
achieving regulatory ends.'' In addition, EO 13563 states that ``[i]n
developing regulatory actions and identifying appropriate approaches,
each agency shall attempt to promote such coordination, simplification,
and harmonization. Each agency shall also seek to identify, as
appropriate, means to achieve regulatory goals that are designed to
promote innovation.'' We recognize that the utility sector faces a
variety of requirements, including ones under CAA section 110(a)(2)(D)
dealing with the interstate transport of emissions contributing to
ozone and PM air quality problems, with coal combustion wastes, and
with the implementation of CWA section 316(b). In developing today's
final rule, the EPA recognizes that it needs to approach these
rulemakings in ways that allow the industry to make practical
investment decisions that minimize costs in complying with all of the
final rules, while still achieving the fundamentally important
environmental and public health benefits that underlie the rulemakings.
A summary of the monetized costs, benefits, and net benefits for
the final rule at discount rates of 3 percent and 7 percent is in Table
2 of this preamble. For more information on the analysis, please refer
to the RIA for this rulemaking, which is available in the docket.
B. Paperwork Reduction Act
The information collection requirements in this rule have been
submitted for approval to the OMB under the Paperwork Reduction Act, 44
[[Page 9433]]
U.S.C. 3501 et seq. The Information Collection Request (ICR) document
prepared by the EPA has been assigned EPA ICR number 2137.06.
The information collection requirements are not enforceable until
OMB approves them. The information requirements are based on
notification, recordkeeping, and reporting requirements in the NESHAP
General Provisions (40 CFR part 63, subpart A), which are mandatory for
all operators subject to national emission standards. These
recordkeeping and reporting requirements are specifically authorized by
CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency
policies set forth in 40 CFR part 2, subpart B. This final rule
requires maintenance inspections of the control devices but would not
require any notifications or reports beyond those required by the
General Provisions. The recordkeeping requirements require only the
specific information needed to determine compliance.
When a malfunction occurs, sources must report them according to
the applicable reporting requirements of 40 CFR part 63, subpart UUUUU.
An affirmative defense to civil penalties for exceedances of emission
limits that are caused by malfunctions is available to a source if it
can demonstrate that certain criteria and requirements are satisfied.
The criteria ensure that the affirmative defense is available only
where the event that causes an exceedance of the emission limit meets
the narrow definition of malfunction in 40 CFR 63.2 (sudden,
infrequent, not reasonable preventable, and not caused by poor
maintenance and or careless operation) and where the source took
necessary actions to minimize emissions. In addition, the source must
meet certain notification and reporting requirements. For example, the
source must prepare a written root cause analysis and submit a written
report to the Administrator documenting that it has met the conditions
and requirements for assertion of the affirmative defense.
For this rule, EPA is adding affirmative defense to the estimate of
burden in the ICR. To provide the public with an estimate of the
relative magnitude of the burden associated with an assertion of the
affirmative defense position adopted by a source, the EPA has provided
administrative adjustments to this ICR that shows what the
notification, recordkeeping, and reporting requirements associated with
the assertion of the affirmative defense might entail. The EPA's
estimate for the required notification, reports, and records, including
the root cause analysis, associated with a single incident totals
approximately totals $3,141, and is based on the time and effort
required of a source to review relevant data, interview plant
employees, and document the events surrounding a malfunction that has
caused an exceedance of an emission limit. The estimate also includes
time to produce and retain the record and reports for submission to
EPA. The EPA provides this illustrative estimate of this burden,
because these costs are only incurred if there has been a violation,
and a source chooses to take advantage of the affirmative defense.
The EPA provides this illustrative estimate of this burden because
these costs are only incurred if there has been a violation and a
source chooses to take advantage of the affirmative defense. Given the
variety of circumstances under which malfunctions could occur, as well
as differences among sources' operation and maintenance practices, we
cannot reliably predict the severity and frequency of malfunction-
related excess emissions events for a particular source. It is
important to note that the EPA has no basis currently for estimating
the number of malfunctions that would qualify for an affirmative
defense. Current historical records would be an inappropriate basis, as
source owners or operators previously operated their facilities in
recognition that they were exempt from the requirement to comply with
emissions standards during malfunctions. Of the number of excess
emissions events reported by source operators, only a small number
would be expected to result from a malfunction (based on the definition
above), and only a subset of excess emissions caused by malfunctions
would result in the source choosing to assert the affirmative defense.
Thus, we believe the number of instances in which source operators
might be expected to avail themselves of the affirmative defense will
be extremely small.
For this reason, we estimate no more than two such occurrences for
all sources subject to 40 CFR part 63, subpart UUUUU over the 3-year
period covered by this ICR. We expect to gather information on such
events in the future, and will revise this estimate as better
information becomes available.
The annual monitoring, reporting, and record-keeping burden for
this collection (averaged over the first 3 years after the effective
date of the standards) is estimated to be $207.6 million. This includes
700,296 labor hours per year at a total labor cost of $49.1 million per
year, annualized capital costs of $81.9 million, and annual operating
and maintenance costs of $76.5 million. This estimate includes initial
and annual performance tests, semiannual excess emission reports,
developing a monitoring plan, notifications, and recordkeeping. All
burden estimates are in 2007 dollars and represent the most cost
effective monitoring approach for affected facilities. Burden is
defined at 5 CFR 1320.3(b).
An Agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for our
regulations are listed in 40 CFR part 9. When this ICR is approved by
OMB, the Agency will publish a technical amendment to 40 CFR part 9 in
the Federal Register to display the OMB control number for the approved
information collection requirements contained in this final rule.
C. Regulatory Flexibility Act, as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et
seq.
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business that is an
electric utility producing 4 billion kilowatt-hours or less as defined
by NAICS codes 221122 (fossil fuel-fired electric utility steam
generating units) and 921150 (fossil fuel-fired electric utility steam
generating units in Indian country); (2) a small governmental
jurisdiction that is a government of a city, county, town, school
district or special district with a population of less than 50,000; and
(3) a small organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
Pursuant to RFA section 603, the EPA prepared an initial regulatory
flexibility analysis (IRFA) for the proposed rule and convened a Small
Business Advocacy Review Panel to obtain advice
[[Page 9434]]
and recommendations of representatives of the regulated small entities.
A detailed discussion of the Panel's advice and recommendations is
found in the Panel Report (EPA-HQ-OAR-2009-0234-2921). A summary of the
Panel's recommendations is presented at 76 FR 24975.
As required by RFA section 604, we also prepared a final regulatory
flexibility analysis (FRFA) for the final rule. The FRFA addresses the
issues raised by public comments on the IRFA, which was part of the
proposal of this rule. The FRFA is summarized below and in the RIA.
1. Reasons Why Action Is Being Taken
In 2000, the EPA made a finding that it was appropriate and
necessary to regulate coal- and oil-fired EGUs under CAA section 112
and listed EGUs pursuant to CAA section 112(c). On March 29, 2005 (70
FR 15994), the EPA published a final rule (2005 Action) that removed
EGUs from the list of sources for which regulation under CAA section
112 was required. That rule was published in conjunction with a rule
requiring reductions in emissions of Hg from EGUs pursuant to CAA
section 111, i.e., CAMR, May 18, 2005, 70 FR 28606). The 2005 Action
was vacated on February 8, 2008, by the U.S. Court of Appeals for the
District of Columbia Circuit. As a result of that vacatur, CAMR was
also vacated and EGUs remain on the list of sources that must be
regulated under CAA section 112. This action provides the EPA's final
NESHAP and NSPS for EGUs.
2. Statement of Objectives and Legal Basis for Final Rules
The MATS will protect air quality and promote public health by
reducing emissions of HAP. In the December 2000 regulatory
determination, the EPA made a finding that it was appropriate and
necessary to regulate EGUs under CAA section 112. The February 2008
vacatur of the 2005 Action reverted the status of the rule to the
December 2000 regulatory determination. Section 112(n)(1)(A) of the CAA
and the 2000 determination do not differentiate between EGUs located at
major versus area sources of HAP. Thus, the NESHAP for EGUs will
regulate units at both major and area sources. Major sources of HAP are
those that have the potential to emit at least 10 tons per year (tpy)
of any one HAP or at least 25 tpy of any combination of HAP. Area
sources are any stationary sources of HAP that are not major sources.
3. Summary of Issues Raised During the Public Comment Process on the
IRFA
The EPA received a number of comments related to the Regulatory
Flexibility Act during the public comment process. A consolidated
version of the comments received is reproduced below. These comments
can also be found in their entirety in the response to comment document
in the docket.
Comment: Several commenters expressed concern with the SBAR panel.
Some believe Small Entity Representatives (SERs) were not provided with
regulatory alternatives including descriptions of significant
regulatory options, differing timetables, or simplifications of
compliance and reporting requirements, and subsequently were not
presented with an opportunity to respond. One commenter believes the
EPA's formal SBAR Panel notification and subsequent information
provided by the EPA to the Panel did not include information on the
potential impacts of the rule as required by CAA section 609(b)(1).
Additional commenters suggested that the EPA's rulemaking schedule put
pressure on the SBAR Panel through the abbreviated preparation for the
Panel. Commenters also expressed concerns that the EPA did not provide
participants more than cursory background information on which to base
their comments. One commenter stated that the EPA did not provide
deliberative materials, including draft proposed rules or discussions
of regulatory alternatives, to the SBAR Panel members. One commenter
stated the SBAR Panel Report does not meet the statutory obligation to
recommend less burdensome alternatives. The commenter suggested the EPA
panel members declined to make recommendations that went further than
consideration or investigation of broad regulatory alternatives, with
the exception of those recommendations in which the EPA rejected
alternative interpretations of the CAA section 112 and relevant court
cases. Two stated that the EPA did not respond to the concerns of the
small business community, the SBA, or OMB, ignoring concerns expressed
by the SER panelists. One commenter believes the EPA failed to convene
required meetings and hearings with affected parties as required by law
for small business entities. One commenter stated that the SERs' input
is very important because more than 90 percent of public power utility
systems meet the definition and qualify as small businesses under the
SBREFA.
Response: The RFA requires that SBAR Panels collect advice and
recommendations from SERs on the issues related to:
--The number and description of the small entities to which the
proposed rule will apply;
--The projected reporting, recordkeeping and other compliance
requirements of the proposed rule;
--Duplication, overlap or conflict between the proposed rule and other
federal rules; and
--Alternatives to the proposed rule that accomplish the stated
statutory objectives and minimize any significant economic impact on
small entities.
The RFA does not require a covered agency to create or assemble
information for SERs or for the government panel members. Although CAA
section 609(b)(4) requires that the government Panel members review any
material the covered agency has prepared in connection with the RFA,
the law does not prescribe the materials to be reviewed. The EPA's
policy, as reflected in its RFA guidance, is to provide as much
information as possible, given time and resource constraints, to enable
an informed Panel discussion. In this rulemaking, because of a court-
ordered deadline, the EPA was unable to hold a pre-panel meeting but
still provided SERs with the information available at the time, held a
standard Panel Outreach meeting to collect verbal advice and
recommendations from SERs, and provided the standard 14-day written
comment period to SERs. The EPA received substantial input from the
SERs, and the Panel report describes recommendations made by the Panel
on measures the Administrator should consider that would minimize the
economic impact of the proposed rule on small entities. The EPA
complied with the RFA. In addition, we met with representatives of
small businesses, small rural cooperatives, and small governments a
number of times during the regulatory development process to discuss
their issues and concerns regarding the proposed MATS rule for EGUs.
Comment: One commenter requested that the EPA work with utilities
such that new regulations are as flexible and cost efficient as
possible.
Response: In developing the final rule, the EPA has considered all
information provided prior to, as well as in response to, the proposed
rule. The EPA has endeavored to make the final regulations flexible and
cost-efficient while adhering to the requirements of
[[Page 9435]]
the CAA. The final rule includes a number of flexibilities, such as
those related to monitoring requirements, that will lower costs and
simplify compliance for small businesses and local governments.
Comment: One commenter was concerned about the ability of small
entities or nonprofit utilities such as those owned and/or operated by
rural electric co-op utilities, and municipal utilities to comply with
the proposed standards within 3 years. The commenter believes that the
EPA disregarded the SER panelists who explained that under these
current economic conditions they have constraints on their ability to
raise capital for the construction of control projects and to acquire
the necessary resources in order to meet a 3-year compliance deadline.
Two commenters expressed concern that smaller utilities and those in
rural areas will be unable to get vendors to respond to their requests
for proposals, because they will be able to make more money serving
larger utilities.
Response: The preamble to the proposed rule (76 FR 25054; May 3,
2011) provides a detailed discussion of how the EPA determined
compliance times for the proposed (and final) rule. The EPA has
provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period
for sources to come into compliance. Sources may also seek a 1-year
extension of the compliance period from their Title V permitting
authority if the source needs that time to install controls. See CAA
section 112(i)(3)(B). If the situation described by commenters (i.e.,
where small entities or nonprofit utilities constraints on ability to
raise capital for construction of control projects and to acquire
necessary resources) results in the source needing additional time to
install controls, they would be in a position to request the 1-year
extension.
Comment: Several commenters believe the EPA did not adequately
consider the disproportionately large impact on smaller generating
units. The commenters note the diseconomies in scale for pollution
controls for such units. One commenter noted the rule will create a
more serious compliance hurdle for small communities that depend on
coal-fired generation to meet their base load demand. The commenter
notes that by not subcategorizing units, the EPA is dictating a fuel
switch due to the disproportionately high cost on small communities.
The other commenter believes the MACT and NSPS standards are
unachievable by going too far without really considering the impacts on
small municipal units, as public power is critical to communities,
jobs, economic viability and electric reliability. A generating and
transmissions electric cooperative which qualifies as a small entity
believes the rule will ultimately result in increased electricity costs
to its members and will negatively impact the economies of the
primarily rural areas that they serve. Another commenter believes there
is no legal or factual basis for creating subcategories or weaker
standards for state, tribal, or municipal governments or small entities
that are operating obsolete units, particularly given the current
market situation and applicable equitable factors. The commenter
suggests both the EPA's and SBA's analyses focus exclusively on the
effects on entities causing HAP emissions and primarily on those
operating obsolete EGUs, and fail to consider either impacts on
downwind businesses and governments or the positive impacts on small
entities and governments owning and operating competing, clean and
modern EGUs.
Response: The EPA disagrees with the commenters' belief that the
impacts on smaller generating units were not adequately considered when
developing the rule. The EPA determined the number of potentially
impacted small entities and assessed the potential impact of the
proposed action on small entities, including municipal units. A similar
assessment was conducted in support of the final action. Specifically,
the EPA estimated the incremental net annualized compliance cost, which
is a function of the change in capital and operating costs, fuel costs,
and change in revenue. The projected compliance cost was considered
relative to the projected revenue from generation. Thus, the EPA's
analysis accounts not only for the additional costs these entities face
resulting from compliance, but also the impact of higher electricity
prices. The EPA evaluated suggestions from SERs, including
subcategorization recommendations. In the preamble to the proposed
rule, the EPA explains that, normally, any basis for subcategorizing
must be related to an effect on emissions, rather than some difference
which does not affect emissions performance. The EPA does not see a
distinction between emissions from smaller generating units versus
larger units. The EPA acknowledges the comment that there is no legal
or factual basis for creating subcategories or weaker standards for
state, tribal, or municipal governments or small entities that are
operating obsolete units.
Comment: One commenter notes that the EPA recognizes LEEs in the
rule such that they should receive less onerous monitoring
requirements; however, the EPA does not recognize that small and LEEs
also need and merit more flexible and achievable pollution control
requirements. The commenter notes that the capital costs for emissions
control at small utility units is disproportionately high due to
inefficiencies in Hg removal, space constraints for control technology
retrofits, and the fact that small units have fewer rate base customers
across which to spread these costs. The commenter cites the Michigan
Department of Environmental Quality report titled ``Michigan's Mercury
Electric Utility Workgroup, Final Report on Mercury Emissions from
Coal-Fired Power Plants,'' (June 2005). The commenter notes that the
EPA has addressed such concerns previously, citing the RIA for the 1997
8-hour ozone standard. The commenter also suggests smaller utility
systems generally have less capital to invest in pollution control than
larger, investor-owned systems, due to statutory inability to borrow
from the private capital markets, statutory debt ceilings, limited
bonding capacity, borrowing limitations related to fiscal strain posed
by other, non-environmental factors, and other limitations.
Response: The EPA acknowledges that the rule contains reduced
monitoring requirements for existing units that qualify as LEEs.
Although the EPA does not believe that reduced pollution control
requirements are warranted for LEEs, including small entity LEEs, we
believe that flexible and achievable pollution control requirements are
promoted through alternative standards, alternative compliance options,
and emissions averaging as a means of demonstrating compliance with the
standards for existing EGUs.
Comment: One commenter believes that the EPA should develop more
limited monitoring requirements for small EGUs. The commenter notes
small entities do not possess the monetary resources, manpower, or
technical expertise needed to operate cutting-edge monitoring
techniques such as Hg CEMS and PM CEMS. The commenter notes the EPA
could have identified monitoring alternatives to the SER panel for
consideration.
Response: The EPA provided monitoring alternatives to using PM
CEMS, HCl CEMS, and Hg CEMS in its proposed standards and in this final
rule. The continuous compliance alternatives are available to all
affected sources, including small entities. As alternatives to the use
of PM CEMS and HCl CEMS, sources are allowed to
[[Page 9436]]
conduct additional performance testing. Sorbent trap monitoring is
allowed in lieu of Hg CEMS.
Comment: Several commenters believe the EPA has not sufficiently
complied with the requirements of the RFA or adequately considered the
impact this rulemaking would have on small entities. One commenter
believes the EPA has not engaged in meaningful outreach and
consultation with small entities and therefore recommends that the EPA
seek to revise the court-ordered deadlines to which this rulemaking is
subject, re-convene the SBAR panel, prepare a new initial regulatory
flexibility analysis (IRFA), and issue it for additional public comment
prior to final rulemaking. The commenter believes the IRFA does not
sufficiently consider impacts on small entities as identified in the
SBAR Panel Report. The commenter believes it is not apparent that the
EPA considered the recommendations of the Panel. The commenter believes
the description of significant alternatives in the IRFA is almost
entirely quoted from the SBAR Panel Report, which the commenter does
not believe is an adequate substitute for the EPA's own analysis of
alternatives. The commenter also notes the EPA does not discuss the
potential impacts of its decisions on small entities or the impacts of
possible flexibilities. Where the EPA does consider regulatory
alternatives in principle, the commenter believes it does not provide
sufficient support for its decisions to understand on what basis the
EPA rejected alternatives that may or may not have reduced burden on
small entities while meeting the stated objectives of the rule.
Additionally, the commenter notes that the EPA did not evaluate the
economic or environmental impacts of significant alternatives to the
proposed rule. One commenter believes that the EPA's stated reasons for
declining to specify or analyze an area source standard are inadequate
under the RFA. The commenter believes the EPA must give serious
consideration to regulatory alternatives that accomplish the stated
objectives of the CAA while minimizing any significant economic impacts
on small entities and that the EPA has a duty to specify and analyze
this option or to more clearly state its policy reasons for excluding
serious consideration of a separate standard for area sources. A
commenter believes the EPA did not fully consider the subcategorization
of sources such as boilers designed to burn lignite coals versus other
fossil fuels, especially in regard to non-mercury metal and acid gas
emissions. The commenter references the SBAR Panel Report suggestion
provided in the preamble of the proposed rule that the EPA consider
developing an area source vs. major source distinction for the source
category and the EPA's response. Another commenter is concerned that
the recommendations made by the SER participants were ignored and not
discussed in the rulemaking. Specifically, the commenter notes the EPA
did not discuss subcategorizing by age, type of plant, fuel, physical
space constraints or useful anticipated life of the plant. Nor did the
EPA establish GACT for smaller emitters to alleviate regulatory costs
and operational difficulties. A commenter believes it is likely that
different numerical or work practice standards are appropriate for area
sources of HAP.
Response: The EPA disagrees with one commenter's assertion that the
agency has not complied with the requirements of the RFA. The EPA
complied with both the letter and spirit of the RFA, notwithstanding
the constraints of the court-ordered deadline. For example, the EPA
notified the Chief Counsel for Advocacy of the SBA of its intent to
convene a Panel; compiled a list of SERs for the Panel to consult with;
and convened the Panel. The Panel met with SERs to collect their advice
and recommendations; reviewed the EPA materials; and drafted a report
of Panel findings. The EPA further disagrees with the commenter's
assertion that the EPA's IRFA does not sufficiently consider impacts on
small entities. The EPA's IRFA, which is included in chapter 10 of the
RIA for the proposed rule, addresses the statutorily required elements
of an IRFA, such as the economic impact of the proposed rule on small
entities and the Panel's findings.
The EPA disagrees with the comment that recommendations made by the
SERs were not considered or discussed in the proposed rulemaking such
as recommendations regarding subcategorization and separate GACT
standards for area sources. The preamble to the proposed standards
includes a detailed discussion of how the EPA determined which
subcategories and sources would be regulated (76 FR 25036-25037; May 3,
2011). In that discussion, the EPA explains the rationale for its
proposed subcategories based on five unit design types. In addition,
the EPA acknowledges the subcategorization suggestions from the SERs
and explains its reasons for not subcategorizing on those bases. The
preamble to the proposed standards also includes a discussion of the
SERs' suggestion that area source EGUs be distinguished from major-
source EGUs and the EPA's reasons for not making that distinction (76
FR 25020-25021; May 3, 2011).
The EPA also disagrees with the suggestion that the Agency pursue
an extension of the timeline for final rulemaking such that the SBAR
Panel can be reconvened and a new IRFA can be prepared and released for
public comment prior to the final rulemaking. The EPA entered into a
Consent Decree to resolve litigation alleging that the EPA failed to
perform a non-discretionary duty to promulgate CAA section 112(d)
standards for EGUs. See American Nurses Ass'n v. EPA, 08-2198 (D.D.C.).
That Decree required the EPA to sign the final MATS rule by November
16, 2011, unless the agency sought to extend the deadline consistent
with the requirements of the modification provision of the Consent
Decree. The EPA and Plaintiffs stipulated to a 30-day extension
consistent with the modification provisions of the Consent Decree and
the rule must be signed no later than December 16, 2011. If plaintiffs
in the American Nurses litigation objected to an additional extension
request, which we believe would have been likely, the Agency would have
had to file a motion with the Court seeking an extension of the
deadline. Consistent with governing case law, the Agency would have
been required to demonstrate in its motion for extension that it was
impossible to finalize the rule by the deadline provided in the Consent
Decree. See Sierra Club v. Jackson, Civil Action No. 01-1537 (D.D.C.)
(Opinion of the Court denying EPA's motion to extend a consent decree
deadline). The EPA negotiated a 30-day extension and was able to
complete the rule by December 16, 2011; accordingly, the Agency had no
basis for seeking a further extension of time.
A detailed description of the changes made to the rule since
proposal, including those made as a result of feedback received during
the public comment process can be found in sections VI (NESHAP) and X
(NSPS) of this preamble. Changes explained in the identified sections
include those related to applicability; subcategorization; work
practices; periods of startup, shutdown, and malfunction; initial
testing and compliance; continuous compliance; and notification,
recordkeeping, and reporting.
4. Description and Estimate of the Affected Small Entities
For the purposes of assessing the impacts of MATS on small
entities, a small entity is defined as:
[[Page 9437]]
(1) A small business according to the Small Business Administration
size standards by the North American Industry Classification System
(NAICS) category of the owning entity. The range of small business size
standards for electric utilities is 4 billion kilowatt hours (kWh) of
production or less;
(2) A small government jurisdiction that is a government of a city,
county, town, district, or special district with a population of less
than 50,000; and
(3) A small organization that is any not for profit enterprise that
is independently owned and operated and is not dominant in its field.
The EPA examined the potential economic impacts to small entities
associated with this rulemaking based on assumptions of how the
affected entities will install control technologies in compliance with
MATS. This analysis does not examine potential indirect economic
impacts associated with this rule, such as employment effects in
industries providing fuel and pollution control equipment, or the
potential effects of electricity price increases on industries and
households.
The EPA used Velocity Suite's Ventyx data as a basis for
identifying plant ownership and compiling the list of potentially
affected small entities. The Ventyx dataset contains detailed ownership
and corporate affiliation information. The analysis focused only on
those EGUs affected by the rule, which includes units burning coal,
oil, petroleum coke, or coal refuse as the primary fuel, and excludes
any combustion turbine units or EGUs burning natural gas. Also, because
the rule does not affect combustion units with an equivalent
electricity generating capacity up to 25 MW, small entities that do not
own at least one combustion unit with a capacity greater than 25 MW
were removed from the dataset. For the affected units remaining, boiler
and generator capacity, heat input, generation, and emissions data were
aggregated by owner and then by parent company. Entities with more than
4 billion kWh of annual electricity generation were removed from the
list, as were municipal owned entities with a population greater than
50,000. For cooperatives, investor owned utilities, and subdivisions
that generate less than 4 billion kWh of electricity annually but which
may be part of a large entity, additional research on power sales,
operating revenues, and other business activities was performed to make
a final determination regarding size. Finally, small entities for which
the IPM does not project generation in 2015 in the base case were
omitted from the analysis because they are not projected to be
operating and, thus, are not projected to face the costs of compliance
with the rule. After omitting entities for the reasons above, the EPA
identified a total of 82 potentially affected small entities that are
affiliated with 102 EGUs.
5. Compliance Cost Impacts
The number of potentially affected small entities by ownership type
and potential impacts of MATS are presented in Chapter 7 of the RIA and
summarized here. The EPA estimated the annualized net compliance cost
to small entities to be approximately $106 million in 2015 (2007$).
The EPA assessed the economic and financial impacts of the final
rule using the ratio of compliance costs to the value of revenues from
electricity generation, and our results focus on those entities for
which this measure could be greater than 1 percent or 3 percent. Of the
82 small entities identified, The EPA's analysis shows 40 entities may
experience compliance costs greater than 1 percent of base generation
revenues in 2015, and 35 may experience compliance costs greater than 3
percent of base revenues. Also, all generating capacity at 3 small
entities is projected to be uneconomic to maintain. In this analysis,
the cost of withdrawing a unit as uneconomic is estimated as the base
case profit that is forgone by not operating under the policy case.
Because 35 of the 82 total units, or more than 40 percent, are
estimated to incur compliance cost greater than 3 percent of base
revenues, the EPA has concluded that it cannot certify that there will
be no significant economic impact on a substantial number of small
entities (SISNOSE) for this rule. Results for small entities discussed
here do not account for the reality that electricity markets are
regulated in parts of the country. Entities operating in regulated or
cost-of-service markets should be able to recover all of their costs of
compliance through rate adjustments.
Note that the estimated costs for small entities are significantly
lower than those estimated by the EPA for the MATS proposal (which were
$379 million). This is driven by a small group of units (less than 6
percent) which were projected to be uneconomic to operate under the
proposal (and hence incurred lost profits due to lost electricity
revenues), but are now projected to continue their operations under
MATS. In addition, the EPA's modeling indicates one unit that would
have operated at a low capacity factor under the base case would find
it economical to increase its generation significantly under MATS to
meet electricity demand in its region. Excluding this unit, the total
cost impacts across all entities would be roughly $175 million. Changes
in compliance behavior for this small group of units, in particular the
one unit which operates at a higher capacity factor, has a substantial
impact on total costs as their increased generation revenues offsets a
large portion of the compliance costs.
The most significant components of incremental costs to these
entities are changes in electricity revenues, followed by the increased
capital and operating costs for retrofits. Capital and operating costs
increase across all ownership types, but the direction of changes in
electricity revenues varies among ownership types. All ownership types,
with the exception of private entities, experience a net gain in
electricity revenues under the MATS, unlike projections from the EPA's
modeling during the proposal, where only municipals benefitted from
higher electricity revenues. The change in electricity revenue takes
into account both the profit lost from units that do not operate under
the policy case and the difference in revenue for operating units under
the policy case. According to the EPA's modeling, an estimated 274 MW
of capacity owned by small entities are considered uneconomic to
operate under the policy case, resulting in a net loss of $13 million
(in 2007$) in profits. On the other hand, many operating units actually
increase their electricity revenue due to higher electricity prices
under MATS. In addition, as mentioned above, the EPA's modeling
indicates one unit finds it economical to increase its capacity factor
significantly under the policy case which results in significantly
higher revenues offsetting the costs.
6. Description of Steps To Minimize Impacts on Small Entities
Consistent with the requirements of the RFA and SBREFA, the EPA has
taken steps to minimize the significant economic impact on small
entities. Because this rule does not affect units with a generating
capacity of less than 25 MW, small entities that do not own at least
one generating unit with a capacity greater than 25 MW are not subject
to the rule. According to the EPA's analysis, among the coal- and oil-
fired EGUs (i.e., excluding combined cycle gas turbines and gas
combustion turbines) about 26 potentially small entities only own EGUs
with a capacity less than or equal to 25 MW, and none of those entities
are subject to the final
[[Page 9438]]
rule based on the statutory definition of potentially regulated units.
For units affected by the proposed rule, the EPA considered a
number of comments received, both during the Small Business Advocacy
Review (SBAR) Panel and the public comment period. While none of the
alternatives adopted is specifically applied to small entities, the EPA
believes these modifications will make compliance less onerous for all
regulated units, including those owned by small entities.
a. Work practice standards. The EPA proposed numerical emission
standards that would apply at all times, including during periods of
startup and shutdown. After reviewing comments and other data regarding
the nature of these periods of operation, the EPA is finalizing a work
practice standard for periods of startup and shutdown. The EPA is also
finalizing work practice standards for organic HAP from all
subcategories of EGUs. Descriptions of the work practice requirements
for startup and shutdown, as well as organic HAP and limited-use liquid
oil-fired EGUs, can be found in section VI.D-E. of the preamble.
b. Continuous compliance and notification, record-keeping, and
reporting. The final rule greatly simplifies the continuous compliance
requirements and provides two basic approaches for most situations: use
of continuous monitoring and periodic testing. The frequency of
periodic testing has been decreased from monthly in the proposal to
quarterly in the final rule. In addition to simplifying compliance, the
EPA believes these changes considerably reduce the overall burden
associated with recordkeeping and reporting. These changes to the final
rule are described in more detail in Section VI.G-H of this preamble.
c. Subcategorization. The Small Entity Representatives on the SBAR
Panel were generally supportive of subcategorization and suggested a
number of additional subcategories the EPA should consider when
developing the final rule. Although it was not consistent with the
statute to adopt the proposed subcategories, the EPA maintained the
existing subcategories and split the ``liquid oil-fired units''
subcategory into three subcategories--continental, non-continental
units, and limited-use units.
d. MACT floor calculations. As recommended by the EPA SBAR Panel
representative, the EPA established the MACT floors using all the
available ICR data that was received to the maximum extent possible
consistent with the CAA requirements. The Agency believes this approach
reasonably ensures that the emission limits selected as the MACT floors
adequately represent the level of emissions actually achieved by the
average of the units in the top 12 percent, considering operational
variability of those units.
e. Alternatives not adopted. The EPA did not adopt several of the
suggestions posed either during the SBAR Panel or public comment
period. The EPA did not propose a percent reduction standard as an
alternative to the concentration-based MACT floor. The percent
reduction format for Hg and other HAP emissions would not have
addressed the EPA's consideration of coal preparation practices that
remove Hg and other HAP before firing. Also, to account for the coal
preparation practices, sources would be required to track the HAP
concentrations in coal from the mine to the stack, and not just before
and after the control device(s), and such an approach would be
difficult to implement and enforce. Furthermore, the EPA does not
believe the percent reduction standard is in line with the Court's
interpretation of the CAA section 112 requirements. Even if we believed
it was appropriate to establish a percent reduction standard, we do not
have the data necessary to establish percent reduction standards for
HAP, as explained further in the response to comments document.
The EPA determined not to establish GACT standards for area sources
for a number of reasons. The data show that similar HAP emissions and
control technologies are found on both major and area sources greater
than 25 MW, and some large units are synthetic area sources. In fact,
because of the significant number of well-controlled EGUs of all sizes,
we believe it would be difficult to make a distinction between MACT and
GACT. Moreover, the EPA believes the standards for area source EGUs
should reflect MACT, rather than GACT, because there is no essential
difference between area source and major source EGUs with respect to
emissions of HAP.
The EPA determined not to exercise its discretionary authority to
establish health-based emission standards for HCl and other HAP acid
gases. Given the limitations of the currently available information
(e.g., the HAP mix where EGUs are located, and the cumulative impacts
of respiratory irritants from nearby sources), the environmental
effects of HCl and the other acid gas HAP, and the significant co-
benefits from reductions in criteria pollutants the EPA determined that
setting a conventional MACT standard for HCl and the other acid gas HAP
was the appropriate course of action.
As required by SBREFA section 212, the EPA also is preparing a
Small Entity Compliance Guide to help small entities comply with this
rule. Small entities will be able to obtain a copy of the Small Entity
Compliance guide at the following Web site: https://www.epa.gov/airquality/powerplanttoxics/actions.html.
D. Unfunded Mandates Reform Act of 1995
Title II of the UMRA of 1995, Public Law 104-4, establishes
requirements for federal agencies to assess the effects of their
regulatory actions on state, local, and tribal governments and the
private sector. Under UMRA section 202, we generally must prepare a
written statement, including a cost-benefit analysis, for proposed and
final rules with ``Federal mandates'' that may result in expenditures
to state, local, and tribal governments, in the aggregate, or to the
private sector, of $100 million or more in any 1 year. Before
promulgating a rule for which a written statement is needed, UMRA
section 205 generally requires us to identify and consider a reasonable
number of regulatory alternatives and adopt the least costly, most
cost-effective or least burdensome alternative that achieves the
objectives of the rule. The provisions of UMRA section 205 do not apply
when they are inconsistent with applicable law. Moreover, UMRA section
205 allows us to adopt an alternative other than the least costly, most
cost-effective or least burdensome alternative if the Administrator
publishes with the final rule an explanation why that alternative was
not adopted. Before we establish any regulatory requirements that may
significantly or uniquely affect small governments, including tribal
governments, we must develop a small government agency plan under UMRA
section 203. The plan must provide for notifying potentially affected
small governments, enabling officials of affected small governments to
have meaningful and timely input in the development of regulatory
proposals with significant federal intergovernmental mandates, and
informing, educating, and advising small governments on compliance with
the regulatory requirements.
We have determined that this rule contains a federal mandate that
may result in expenditures of $100 million or more for state, local,
and tribal governments, in the aggregate, or the private sector in any
1 year. Accordingly, we have prepared a written statement entitled
``Unfunded Mandates Reform Act Analysis'' under
[[Page 9439]]
UMRA section 202 that is within the RIA and which is summarized below.
1. Statutory Authority
As discussed elsewhere in this preamble, the statutory authority
for this rulemaking is CAA section 112. Title III of the CAA Amendments
was enacted to reduce nationwide air toxic emissions. CAA section
112(b) lists the 188 chemicals, compounds, or groups of chemicals
deemed by Congress to be HAP. These toxic air pollutants are to be
regulated by NESHAP.
CAA section 112(d) directs us to develop NESHAP which require
existing and new major sources to control emissions of HAP using MACT-
based standards. This NESHAP applies to all coal- and oil-fired EGUs.
In compliance with UMRA section 205(a), we identified and
considered a reasonable number of regulatory alternatives. Additional
information on the costs and environmental impacts of these regulatory
alternatives were presented in the RIA for the rulemaking.
The regulatory alternative upon which this rule is based represents
the MACT floor for all regulated pollutants for all but one EGU
subcategory for all but one regulated pollutant for that subcategory.
These MACT floor-based standards represent the least costly and least
burdensome alternative. Beyond-the-floor emission limits for Hg are for
existing coal-fired EGUs in the subcategory for low rank virgin coal
EGUs.
2. Social Costs and Benefits
The RIA prepared for this rule including the Agency's assessment of
costs and benefits is in the docket.
It is estimated that HAP would be reduced by thousands of tons in
2015, relative to the base case, including reductions in HCl, HF,
metallic HAP (including Hg), and several other organic HAP from EGUs.
Studies have determined a relationship between exposure to certain of
these HAP and the onset of cancer; however, the Agency is unable to
provide a monetized estimate of the HAP benefits at this time. In
addition, significant reductions in PM2.5 and SO2
will occur, including approximately 53 thousand tons of
PM2.5 and over 1 million tons of SO2. These
reductions will occur by 2016 and are expected to continue throughout
the life of the affected sources. The major health effect associated
with reducing PM2.5 and PM2.5 precursors (such as
SO2) is a reduction in premature mortality. Other health
effects associated with PM2.5 emission reductions include
avoiding cases of chronic bronchitis, heart attacks, asthma attacks,
and work-lost days (i.e., days when employees are unable to work).
Although we are unable to monetize the benefits associated with the HAP
emissions reductions other than for Hg or all benefits associated with
Hg reductions, we are able to monetize the benefits associated with the
PM2.5 and SO2 emissions reductions. For
SO2 and PM2.5, we estimated the benefits
associated with health effects of PM but were unable to quantify all
categories of benefits (particularly those associated with ecosystem
and visibility effects). Our estimates of the monetized benefits in
2016 associated with the implementation of the final rule range from
$37 billion to $90 billion (2007 dollars) when using a 3 percent
discount rate or from $33 billion to $81 billion (2007 dollars) when
using a 7 percent discount rate). Our estimate of costs is $9.6 billion
(2007 dollars). For more detailed information on the benefits and costs
estimated for this rulemaking, refer to the RIA in the docket.
3. Future and Disproportionate Costs
The UMRA requires that we estimate, where accurate estimation is
reasonably feasible, future compliance costs imposed by this rule and
any disproportionate budgetary effects. Our estimates of the future
compliance costs of this rule are discussed previously in this
preamble.
The EPA assessed the economic and financial impacts of the rule on
government-owned entities using the ratio of compliance costs to the
value of revenues from electricity generation, and our results focus on
those entities for which this measure could be greater than 1 percent
or 3 percent of base revenues. The EPA projects that 42 government
entities will have compliance costs greater than 1 percent of base
generation revenue in 2016, and 32 may experience compliance costs
greater than 3 percent of base revenues. Overall, 6 units owned by
government entities are expected to retire. The most significant
components of incremental costs to these entities are the increased
capital and operating costs, followed by changes in electricity
revenues. For more details on these results and the methodology behind
their estimation, see the results included in chapter 7 of the RIA.
4. Effects on the National Economy
The UMRA requires that we estimate the effect of this rule on the
national economy. To the extent feasible, we must estimate the effect
on productivity, economic growth, full employment, creation of
productive jobs, and international competitiveness of the U.S. goods
and services, if we determine that accurate estimates are reasonably
feasible and that such effect is relevant and material.
The nationwide economic impact of this rule is presented in the RIA
in the docket. This analysis provides estimates of the effect of this
rule on some of the categories mentioned above.
The results of the economic impact analysis are summarized
previously in this preamble. The results show that, relative to
baseline, there will be an average 3.1 percent increase in electricity
price on average nationwide in 2016, with the range of increases from
1.3 percent to 6.3 percent in regions throughout the U.S., and a less
than 1 percent increase in natural gas price nationwide in 2016. The
roughly 3 percent incremental price effect of this rule is small
relative to the changes observed in the absolute levels of electricity
prices over the last 50 years, which have ranged from as much as 23
percent lower (in 1969) to as much as 23 percent higher (in 1982) than
prices observed in 2010.\377\ Power generation from coal-fired plants
will fall by about 2 percent nationwide in 2016. No region of the U.S.
is expected to experience a double-digit increase in retail electricity
prices in 2015 or in any year later than that, according to the
Agency's analysis, as a result of this rule. To put the electricity
price effects in context, the roughly 3 percent incremental increase in
aggregate end-user electricity prices projected to occur over the next
4 years is about the same as the 3 percent absolute average change in
total end-user electricity prices observed on an annual basis.\378\
Furthermore, the roughly 3 percent incremental price effect of this
rule is small relative to the changes observed in the absolute levels
of electricity prices over the last 50 years, which have ranged from as
much as 23 percent lower (in 1969) to as much as 23 percent higher (in
1982) than prices observed in 2010.\379\ Even with this rule in effect,
electricity prices are projected to be lower in 2015 and 2020 than they
were in 2010.\380\
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\377\ EIA Annual Energy Outlook 2010 annual total electricity
prices from 1960 to 2010, Table 8-10.
\378\ EIA Annual Energy Outlook 2010 annual total electricity
prices from 1960 t0 2010, Table 8-10.
\379\ Ibid.
\380\ Ibid., EIA AEO 2010, Table-10 for price levels; and
Chapterr 3 of the RIA for electricity price differential.
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5. Consultation With Government
The UMRA requires that we describe the extent of the Agency's prior
consultation with affected state, local,
[[Page 9440]]
and tribal officials, summarize the officials' comments or concerns,
and summarize our response to those comments or concerns. In addition,
UMRA section 203 requires that we develop a plan for informing and
advising small governments that may be significantly or uniquely
impacted by a regulatory action. Consistent with the intergovernmental
consultation provisions of UMRA section 204, the EPA initiated
consultations with governmental entities affected by this rule. The EPA
invited the following 10 national organizations representing state and
local elected officials to a meeting held on October 27, 2010, in
Washington, DC: (1) National Governors Association; (2) National
Conference of State Legislatures, (3) Council of State Governments, (4)
National League of Cities, (5) U.S. Conference of Mayors, (6) National
Association of Counties, (7) International City/County Management
Association, (8) National Association of Towns and Townships, (9)
County Executives of America, and (10) Environmental Council of States.
These 10 organizations of elected state and local officials have been
identified by the EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. The
purposes of the consultation were to provide general background on the
rule, answer questions, and solicit input from state/local governments.
During the meeting, officials asked clarifying questions regarding CAA
section 112 requirements and central decision points presented by the
EPA (e.g., use of surrogate pollutants to address HAP,
subcategorization of source category, assessment of emissions
variability). They also expressed uncertainty with regard to how
utility boilers owned/operated by state and local entities would be
impacted, as well as with regard to the potential burden associated
with implementing the rule on state and local entities (i.e., burden to
re-permit affected EGUs or update existing permits). Officials
requested, and the EPA provided, addresses associated with the 112
state and local governments estimated to be potentially impacted by the
rule. The EPA has not received additional questions or requests from
state or local officials.
Consistent with UMRA section 205, the EPA has identified and
considered a reasonable number of regulatory alternatives. Because the
potential existed for a significant impact for substantial number of
small entities, the EPA convened a SBAR Panel to obtain advice and
recommendation of representatives of the small entities that
potentially would be subject to the requirements of the rule. As part
of that process, the EPA considered several options, which are
discussed previously in this preamble. Those options included
establishing emission limits, establishing work practice standards,
establishing subcategories, and consideration of monitoring options.
The regulatory alternative selected is a combination of the options
considered and includes provisions regarding a number of the
recommendations resulting from the SBAR Panel process as described
below (see the Regulatory Flexibility Act discussion in this section of
the preamble for more detail).
E. Executive Order 13132, Federalism
Under EO 13132, the EPA may not issue an action that has federalism
implications, that imposes substantial direct compliance costs, and
that is not required by statute, unless the federal government provides
the funds necessary to pay the direct compliance costs incurred by
state and local governments, or the EPA consults with state and local
officials early in the process of developing the final action.
The EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on state or local governments, and the federal government will not
provide the funds necessary to pay those costs. Accordingly, the EPA
provides the following federalism summary impact statement as required
by section 6(b) of EO 13132.
Based on estimates in the RIA, provided in the docket, the final
rule may have federalism implications because the rule may impose
approximately $294 million in annual direct compliance costs on an
estimated 96 state or local governments. Specifically, we estimate that
there are 80 municipalities, 5 states, and 11 political subdivisions
(i.e., a public district with territorial boundaries embracing an area
wider than a single municipality and frequently covering more than one
county for the purpose of generating, transmitting and distributing
electric energy) that may be directly impacted by this final rule.
Responses to the EPA's 2010 ICR were used to estimate the nationwide
number of potentially impacted state or local governments. As
previously explained, this 2010 survey was submitted to all coal- and
oil-fired EGUs listed in the 2007 version of DOE/EIA's ``Annual
Electric Generator Report,'' and ``Power Plant Operations Report.''
The EPA consulted with state and local officials in the process of
developing the rule to permit them to have meaningful and timely input
into its development. The EPA met with 10 national organizations
representing state and local elected officials to provide general
background on the rule, answer questions, and solicit input. In the
final rule, EPA has provided flexibilities that will lower compliance
costs for these entities. The EPA also recognizes that municipalities
may need a longer compliance timeframe because of required approval
processes.
F. Executive Order 13175, Consultation and Coordination With Indian
Tribal Governments
Subject to EO 13175 (65 FR 67249; November 9, 2000) the EPA may not
issue a regulation that has tribal implications, that imposes
substantial direct compliance costs, and that is not required by
statute, unless the federal government provides the funds necessary to
pay the direct compliance costs incurred by tribal governments, or the
EPA consults with tribal officials early in the process of developing
the proposed regulation and develops a tribal summary impact statement.
Executive Order 13175 requires the EPA to develop an accountable
process to ensure ``meaningful and timely input by Tribal officials in
the development of regulatory policies that have Tribal implications.''
The EPA has concluded that this action may have tribal
implications. The EPA offered consultation with tribal officials early
in the regulation development process to permit them an opportunity to
have meaningful and timely input. Consultation letters were sent to 584
tribal leaders and provided information regarding the EPA's development
of this rule and offered consultation. At the request of the tribes,
three consultation meetings were held: December 7, 2010, with the Upper
Sioux Community of Minnesota; December 13, 2010, with Moapa Band of
Paiutes, Forest County Potawatomi, Standing Rock Sioux Tribal Council,
and Fond du Lac Band of Chippewa; January 5, 2011, with the Forest
County Potawatomi, and a representative from the National Tribal Air
Association (NTAA). In these meetings, the EPA presented the authority
under the CAA used to develop these rules and an overview of the
industry and the industrial processes that have the potential for
regulation. Tribes expressed concerns about the impact of EGUs in
Indian country. Specifically, they were concerned about potential Hg
deposition and the impact on the water resources of the tribes, with
particular concern about the impact on subsistence
[[Page 9441]]
lifestyles for fishing communities, the cultural impact of impaired
water quality for ceremonial purposes, and the economic impact on
tourism. In light of these concerns, the tribes expressed interest in
an expedited implementation of the rule. Other concerns expressed by
tribes related to how the Agency would consider variability in setting
the standards, and the use of tribal-specific fish consumption data
from the tribes in our assessments. They were not supportive of using
work practice standards as part of the rule, and asked the Agency to
consider going beyond the MACT floor to offer more protection for the
tribal communities.
In addition to these consultations, the EPA also conducted outreach
on this rule through presentations at the National Tribal Forum in
Milwaukee, WI; phone calls with the NTAA; and a webinar for tribes on
the proposed rule. The EPA specifically requested tribal data that
could support the appropriate and necessary analyses and the RIA for
this rule. In addition, the EPA held individual consultations with the
Navajo Nation on October 12, 2011; as well as the Gila River Indian
Community, Ak-Chin Indian Community, and the Hopi Nation on October 14,
2011. These tribes expressed concerns about the impact of the rule on
the Navajo Generating Station (NGS), the impact on the cost of the
water allotted to the tribes from the Central Arizona Project (CAP),
the impact on tribal revenues from the coal mining operations (i.e.,
assumptions about reduced mining if NGS were to retire one or more
units), and the impacts on employment of tribal members at both the NGS
and the mine. More specific comments can be found in the docket.
The EPA will continue to work with these and other potentially
affected tribes as this final rule is implemented.
G. Executive Order 13045, Protection of Children From Environmental
Health Risks and Safety Risks
This final rule is subject to EO 13045 (62 FR 19885; April 23,
1997) because it is an economically significant regulatory action as
defined by EO 12866, and EPA believes that the environmental health or
safety risk addressed by this action may have a disproportionate effect
on children. Accordingly, we have evaluated the environmental health or
safety effects of the standards on children.
Although this final rule is based on technology performance, the
standards are designed to protect against hazards to public health with
an adequate margin of safety as described in Section III of this
preamble. The protection offered by this rule is particularly important
for children, especially the developing fetus. As referenced in Chapter
4 of the RIA, ``Mercury and Other HAP Benefits Analysis,'' children are
more vulnerable than adults to many HAP emitted by EGUs due to
differential behavior patterns and physiology. These unique
susceptibilities were carefully considered in a number of different
ways in the analyses associated with this rulemaking, and are
summarized in the RIA. We also estimate substantial health improvements
for children in the form of 130,000 fewer asthma attacks, 3,100 fewer
emergency room visits due to asthma, 6,300 fewer cases of acute
bronchitis, and approximately 140,000 fewer cases of upper and lower
respiratory illness.
H. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
Executive Order 13211 (66 FR 28355; May 22, 2001) requires EPA to
prepare and submit a Statement of Energy Effects to the Administrator
of the Office of Information and Regulatory Affairs, OMB, for actions
identified as ``significant energy actions.'' This action, which is a
significant regulatory action under EO 12866, is likely to have a
significant adverse effect on the supply, distribution, or use of
energy. We have prepared a Statement of Energy Effects for this action
as follows.
We estimate a 3.1 percent price increase for electricity nationwide
in 2016 and a less than 2 percent percentage fall in coal-fired power
production as a result of this rule. The EPA projects that electric
power sector-delivered natural gas prices will increase by about 0.6
percent over the 2015 to 2030 timeframe. For more information on the
estimated energy effects, please refer to the economic impact analysis
for this final rule. The analysis is available in the RIA, which is in
the public docket.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the
EPA to use voluntary consensus standards in its regulatory activities
unless to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures,
business practices) that are developed or adopted by voluntary
consensus standards bodies. The NTTAA directs the EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This rulemaking involves technical standards. The EPA cites the
following standards in the final rule: EPA Methods 1, 2, 2A, 2C, 2F,
2G, 3A, 3B, 4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of 40 CFR part 60
and Method 320 of 40 CFR part 63. Consistent with the NTTAA, the EPA
conducted searches to identify voluntary consensus standards in
addition to these EPA methods. No applicable voluntary consensus
standards were identified for EPA Methods 2F, 2G, 5D, and 19. The
search and review results have been documented and are placed in the
docket for the proposed rule.
The three voluntary consensus standards described below were
identified as acceptable alternatives to EPA test methods for the
purposes of the final rule.
The voluntary consensus standard American National Standards
Institute (ANSI)/American Society of Mechanical Engineers (ASME) PTC
19-10-1981, ``Flue and Exhaust Gas Analyses [part 10, Instruments and
Apparatus]'' is cited in the final rule for its manual method for
measuring the O2, CO2, and CO content of exhaust
gas. This part of ANSI/ASME PTC 19-10-1981 is an acceptable alternative
to Method 3B.
The voluntary consensus standard ASTM D6348-03 (Reapproved 2010),
``Standard Test Method for Determination of Gaseous Compounds by
Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy'' is
acceptable as an alternative to Method 320 and is cited in the final
rule, but with several conditions: (1) The test plan preparation and
implementation in the Annexes to ASTM D6348-03, Sections A1 through A8
are mandatory; and (2) In ASTM D6348-03 Annex A5 (Analyte Spiking
Technique), the percent (%) R must be determined for each target
analyte (Equation A5.5). In order for the test data to be acceptable
for a compound, %R must be 70% >= R <= 130%. If the %R value does not
meet this criterion for a target compound, the test data are not
acceptable for that compound and the test must be repeated for that
analyte (i.e., the sampling and/or analytical procedure should be
adjusted before a retest). The %R value for each compound must be
reported in the test report, and all field measurements must be
corrected with the calculated %R value for that compound by using the
following
[[Page 9442]]
equation: Reported Result = (Measured Concentration in the Stack x
100)/% R.
The voluntary consensus standard ASTM D6784-02, ``Standard Test
Method for Elemental, Oxidized, Particle-Bound and Total Mercury in
Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro
Method),'' is an acceptable alternative to use of EPA Method 29 for Hg
only or Method 30B for the purpose of conducting relative accuracy
tests of Hg continuous monitoring systems under this final rule.
Because of the limitations of this method in terms of total sampling
volume, it is not appropriate for use in performance testing under this
rule. In addition to the voluntary consensus standards the EPA used in
the final rule, the search for emissions measurement procedures
identified 16 other voluntary consensus standards. The EPA determined
that 14 of these 16 standards identified for measuring emissions of the
HAP or other pollutants subject to emission standards in the final rule
were impractical alternatives to EPA test methods for the purposes of
this final rule. Therefore, the EPA did not adopt these standards for
this purpose. The reasons for this determination for the 14 methods are
discussed below, and the remaining 2 methods are discussed later in
this section.
The voluntary consensus standard ASTM D3154-00, ``Standard Method
for Average Velocity in a Duct (Pitot Tube Method),'' is impractical as
an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of this
rulemaking because the standard appears to lack in quality control and
quality assurance requirements. Specifically, ASTM D3154-00 does not
include the following: (1) proof that openings of standard pitot tube
have not plugged during the test; (2) if differential pressure gauges
other than inclined manometers (e.g., magnehelic gauges) are used,
their calibration must be checked after each test series; and (3) the
frequency and validity range for calibration of the temperature
sensors.
The voluntary consensus standard ASTM D3464-96 (Reapproved 2001),
``Standard Test Method Average Velocity in a Duct Using a Thermal
Anemometer,'' is impractical as an alternative to EPA Method 2 for the
purposes of this rule primarily because applicability specifications
are not clearly defined, e.g., range of gas composition, temperature
limits. Also, the lack of supporting quality assurance data for the
calibration procedures and specifications, and certain variability
issues that are not adequately addressed by the standard limit the
EPA's ability to make a definitive comparison of the method in these
areas.
The voluntary consensus standard ISO 10780:1994, ``Stationary
Source Emissions--Measurement of Velocity and Volume Flowrate of Gas
Streams in Ducts,'' is impractical as an alternative to EPA Method 2 in
this rule. The standard recommends the use of an L-shaped pitot, which
historically has not been recommended by the EPA. The EPA specifies the
S-type design which has large openings that are less likely to plug up
with dust.
The voluntary consensus standard, CAN/CSA Z223.2-M86 (1999),
``Method for the Continuous Measurement of Oxygen, Carbon Dioxide,
Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed
Combustion Flue Gas Streams,'' is unacceptable as a substitute for EPA
Method 3A because it does not include quantitative specifications for
measurement system performance, most notably the calibration procedures
and instrument performance characteristics. The instrument performance
characteristics that are provided are non-mandatory and also do not
provide the same level of quality assurance as the EPA methods. For
example, the zero and span/calibration drift is only checked weekly,
whereas the EPA methods require drift checks after each run.
Two very similar voluntary consensus standards, ASTM D5835-95
(Reapproved 2001), ``Standard Practice for Sampling Stationary Source
Emissions for Automated Determination of Gas Concentration,'' and ISO
10396:1993, ``Stationary Source Emissions: Sampling for the Automated
Determination of Gas Concentrations,'' are impractical alternatives to
EPA Method 3A for the purposes of this final rule because they lack in
detail and quality assurance/quality control requirements.
Specifically, these two standards do not include the following: (1)
Sensitivity of the method; (2) acceptable levels of analyzer
calibration error; (3) acceptable levels of sampling system bias; (4)
zero drift and calibration drift limits, time span, and required
testing frequency; (5) a method to test the interference response of
the analyzer; (6) procedures to determine the minimum sampling time per
run and minimum measurement time; and (7) specifications for data
recorders, in terms of resolution (all types) and recording intervals
(digital and analog recorders, only).
The voluntary consensus standard ISO 12039:2001, ``Stationary
Source Emissions--Determination of Carbon Monoxide, Carbon Dioxide, and
Oxygen--Automated Methods,'' is not acceptable as an alternative to EPA
Method 3A. This ISO standard is similar to EPA Method 3A, but is
missing some key features. In terms of sampling, the hardware required
by ISO 12039:2001 does not include a 3-way calibration valve assembly
or equivalent to block the sample gas flow while calibration gases are
introduced. In its calibration procedures, ISO 12039:2001 only
specifies a two-point calibration while EPA Method 3A specifies a
three-point calibration. Also, ISO 12039:2001 does not specify
performance criteria for calibration error, calibration drift, or
sampling system bias tests as in the EPA method, although checks of
these quality control features are required by the ISO standard.
The voluntary consensus standard ASTM D6522-00, ``Standard Test
Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers and Process Heaters Using
Portable Analyzers'' is not an acceptable alternative to EPA Method 3A
for measuring CO and O2 concentrations for this final rule
as the method is designed for application to sources firing natural
gas.
The voluntary consensus standard ASME PTC-38-80 R85 (1985),
``Determination of the Concentration of Particulate Matter in Gas
Streams,'' is not acceptable as an alternative for EPA Method 5 because
ASTM PTC-38-80 is not specific about equipment requirements, and
instead presents the options available and the pros and cons of each
option. The key specific differences between ASME PTC-38-80 and the EPA
methods are that the ASME standard: (1) Allows in-stack filter
placement as compared to the out-of-stack filter placement in EPA
Methods 5 and 17; (2) allows many different types of nozzles, pitots,
and filtering equipment; (3) does not specify a filter weighing
protocol or a minimum allowable filter weight fluctuation as in the EPA
methods; and (4) allows filter paper to be only 99 percent efficient,
as compared to the 99.95 percent efficiency required by the EPA
methods.
The voluntary consensus standard ASTM D3685/D3685M-98, ``Test
Methods for Sampling and Determination of Particulate Matter in Stack
Gases,'' is similar to EPA Methods 5 and 17, but is lacking in the
following areas that are needed to produce quality, representative
particulate data: (1) Requirement that the filter holder temperature
should be between 120[deg]C and 134[deg]C, and not just ``above the
acid dew-point''; (2) detailed specifications
[[Page 9443]]
for measuring and monitoring the filter holder temperature during
sampling; (3) procedures similar to EPA Methods 1, 2, 3, and 4, that
are required by EPA Method 5; (4) technical guidance for performing the
Method 5 sampling procedures, e.g., maintaining and monitoring sampling
train operating temperatures, specific leak check guidelines and
procedures, and use of reagent blanks for determining and subtracting
background contamination; and (5) detailed equipment and/or operational
requirements, e.g., component exchange leak checks, use of glass
cyclones for heavy particulate loading and/or water droplets, operating
under a negative stack pressure, exchanging particulate loaded filters,
sampling preparation and implementation guidance, sample recovery
guidance, data reduction guidance, and particulate sample calculations
input.
The voluntary consensus standard ISO 9096:1992, ``Determination of
Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying
Ducts--Manual Gravimetric Method,'' is not acceptable as an alternative
for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods
1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA
Method 5 for collection of PM. The standard ISO 9096 does not provide
applicable technical guidance for performing many of the integral
procedures specified in Methods 1, 2, and 5. Major performance and
operational details are lacking or nonexistent, and detailed quality
assurance/quality control guidance for the sampling operations required
to produce quality, representative particulate data (e.g., guidance for
maintaining and monitoring train operating temperatures, specific leak
check guidelines and procedures, and sample preparation and recovery
procedures) are not provided by the standard, as in EPA Method 5. Also,
details of equipment and/or operational requirements, such as those
specified in EPA Method 5, are not included in the ISO standard, e.g.,
stack gas moisture measurements, data reduction guidance, and
particulate sample calculations.
The voluntary consensus standard CAN/CSA Z223.1-M1977, ``Method for
the Determination of Particulate Mass Flows in Enclosed Gas Streams,''
is not acceptable as an alternative for EPA Method 5. Detailed
technical procedures and quality control measures that are required in
EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second,
CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing
requirement to repeat weighing every 6 hours until a constant weight is
achieved. Third, EPA Method 5 requires the filter weight to be reported
to the nearest 0.1 milligram (mg), while CAN/CSA Z223.1 requires
reporting only to the nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the
use of a standard pitot for velocity measurement when plugging of the
tube opening is not expected to be a problem. The EPA Method 5 requires
an S-shaped pitot.
The voluntary consensus standard EN 1911-1,2,3 (1998), ``Stationary
Source Emissions-Manual Method of Determination of HCl-Part 1: Sampling
of Gases Ratified European Text-Part 2: Gaseous Compounds Absorption
Ratified European Text-Part 3: Adsorption Solutions Analysis and
Calculation Ratified European Text,'' is impractical as an alternative
to EPA Methods 26 and 26A. Part 3 of this standard cannot be considered
equivalent to EPA Method 26 or 26A because the sample absorbing
solution (water) would be expected to capture both HCl and chlorine
gas, if present, without the ability to distinguish between the two.
The EPA Methods 26 and 26A use an acidified absorbing solution to first
separate HCl and chlorine gas so that they can be selectively absorbed,
analyzed, and reported separately. In addition, in EN 1911 the
absorption efficiency for chlorine gas would be expected to vary as the
pH of the water changed during sampling.
The voluntary consensus standard EN 13211 (1998), is not acceptable
as an alternative to the Hg portion of EPA Method 29 primarily because
it is not validated for use with impingers, as in the EPA method,
although the method describes procedures for the use of impingers. This
European standard is validated for the use of fritted bubblers only and
requires the use of a side (split) stream arrangement for isokinetic
sampling because of the low sampling rate of the bubblers (up to 3
liters per minute, maximum). Also, only two bubblers (or impingers) are
required by EN 13211, whereas EPA Method 29 require the use of six
impingers. In addition, EN 13211 does not include many of the quality
control procedures of EPA Method 29, especially for the use and
calibration of temperature sensors and controllers, sampling train
assembly and disassembly, and filter weighing.
Two of the 16 voluntary consensus standards identified in this
search were not available at the time the review was conducted for the
purposes of the final rule because they are under development by a
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot
Primary Flowmeters,'' for EPA Method 2.
Finally, in addition to the three voluntary consensus standards
identified as acceptable alternatives to EPA methods required in the
final rule, the EPA is also specifying four voluntary consensus
standards in the rule for use in sampling and analysis of liquid oil
samples for moisture content. These standards are: ASTM D95-05
(Reapproved 2010), ``Standard Test Method for Water in Petroleum
Products and Bituminous Materials by Distillation,'' ASTM D4006-11,
``Standard Test Method for Water in Crude Oil by Distillation,'' ASTM
D4177-95 (Reapproved 2010), ``Standard Practice for Automatic Sampling
of Petroleum and Petroleum Products,'' and ASTM D4057-06 (Reapproved
2011), ``Standard Practice for Manual Sampling of Petroleum and
Petroleum Products.''
Table 5, section 4.1.1.5 of appendix A, and section 3.1.2 of
appendix B to subpart UUUUU, 40 CFR part 63, list the EPA testing
methods included in the final rule. Under section 63.7(f) and section
63.8(f) of subpart A of the General Provisions, a source may apply to
the EPA for permission to use alternative test methods or alternative
monitoring requirements in place of any of the EPA testing methods,
performance specifications, or procedures specified.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
federal executive policy on environmental justice (EJ). Its main
provision directs federal agencies, to the greatest extent practicable
and permitted by law, to make EJ part of their mission by identifying
and addressing, as appropriate, disproportionately high and adverse
human health or environmental effects of their programs, policies, and
activities on minority populations and low-income populations in the
U.S.
The EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority, low income, and indigenous populations because it
increases the level of environmental protection for all affected
populations without having any disproportionately
[[Page 9444]]
high and adverse human health or environmental effects on any
population, including any minority, low income, and indigenous
populations.
This final rule establishes national emission standards for new and
existing EGUs that combust coal and oil. The EPA estimates that there
are approximately 1,400 units located at 600 facilities covered by this
final rule.
This final rule will reduce emissions of all the listed HAP that
come from EGUs. This includes metals (Hg, As, Be, Cd, Cr, Pb, Mn, Ni,
and Se), organics (POM, acetaldehyde, acrolein, benzene, dioxins,
ethylene dichloride, formaldehyde, and PCB), and acid gases (HCl and
HF). At sufficient levels of exposure, these pollutants can cause a
range of health effects including cancer; irritation of the lungs,
skin, and mucous membranes; effects on the central nervous system such
as memory and IQ loss and learning disabilities; damage to the kidneys;
and other acute health disorders.
The final rule will also result in substantial reductions of
criteria pollutants such as CO, PM, and SO2. Sulfur dioxide
is a precursor pollutant that is often transformed into fine PM
(PM2.5) in the atmosphere. Reducing direct emissions of
PM2.5 and SO2 will, as a result, reduce
concentrations of PM2.5 in the atmosphere. These reductions
in PM2.5 will provide large health benefits, such as
reducing the risk of premature mortality for adults, chronic and acute
bronchitis, childhood asthma attacks, and hospitalizations for other
respiratory and cardiovascular diseases. (For more details on the
health effects of metals, organics, and PM2.5, please refer
to the RIA contained in the docket for this rulemaking.) This final
rule will also have a small effect on electricity and natural gas
prices but has the potential to affect the cost structure of the
utility industry and could lead to shifts in how and where electricity
is generated.
This final rule is one of a group of regulatory actions that the
EPA has taken and will take over the next several years to respond to
statutory and judicial mandates that will reduce exposure to HAP and
PM2.5, as well as to other pollutants, from EGUs and other
sources. In addition, the EPA will pursue energy efficiency
improvements throughout the economy, along with other federal agencies,
states and other groups. This will contribute to additional
environmental and public health improvements while lowering the costs
of realizing those improvements. Together, these rules and actions will
have substantial and long-term effects on both the U.S. power industry
and on communities currently breathing dirty air. Therefore, we
anticipate significant interest in many, if not most, of these actions
from EJ communities, among many others.
1. Key EJ Aspects of the Rule
This is an air toxics rule; therefore, it does not permit emissions
trading among sources. Instead, this final rule will place a limit on
the rates of Hg and other HAP emitted from each affected EGU. As a
result, emissions of Hg and other HAP such as HCl will be substantially
reduced in the vast majority of states. In some states, however, there
may be small increases in Hg and other HAP emissions due to shifts in
electricity generation from EGUs with higher emission rates to EGUs
with already low emission rates. Hydrogen chloride emissions are
projected to increase at a small number of sources but that does not
lead to any increased emissions at the state level.
The primary risk analysis to support the finding that this final
rule is both appropriate and necessary includes an analysis of the
effects of Hg from EGUs on people who rely on freshwater fish they
catch as a regular and frequent part of their diet. These groups are
characterized as subsistence level fishing populations or fishers. A
significant portion of the data in this analysis came from published
studies of EJ communities where people frequently consume locally-
caught freshwater fish. These communities included: (1) White and black
populations (including female and poor strata) surveyed in South
Carolina; (2) Hispanic, Vietnamese and Laotian populations surveyed in
California; and (3) Great Lakes tribal populations (Chippewa and
Ojibwe) active on ceded territories around the Great Lakes. These data
were used to help estimate risks to similar populations beyond the
areas where the study data were collected. For example, while the
Vietnamese and Laotian survey data were collected in California, given
the ethnic (heritage) nature of these high fish consumption rates, we
assumed that they could also be associated with members of these ethnic
groups living elsewhere in the U.S. Therefore, the high-end consumption
rates referenced in the California study for these ethnic groups were
used to model risk at watersheds elsewhere in the U.S. As a result of
this approach, the specific fish consumption patterns of several
different EJ groups are fundamental to the EPA's assessment of both the
underlying risks that make this final rule appropriate and necessary,
and of the analysis of the benefits of reducing exposure to Hg and the
other HAP.
The EPA's full analysis of risks from consumption of Hg-
contaminated fish is contained in the RIA for this rule. The effects of
this final rule on the health risks from Hg and other HAP are presented
in the preamble and in the RIA for this rule.
2. Potential Environmental and Public Health Impacts to Minority, Low
Income, or Tribal Populations
The EPA has conducted several analyses that provide additional
insight on the potential effects of this rule on EJ communities. These
include: (1) The socio-economic distribution of people living close to
affected EGUs who may be exposed to pollution from these sources; and
(2) an analysis of the distribution of health effects expected from the
reductions in PM2.5 that will result from implementation of
this final rule (co-benefits).
a. Socio-Economic Distribution. As part of the analysis for this
final rule, the EPA reviewed the aggregate demographic makeup of the
communities near EGUs covered by this final rule. Although this
analysis gives some indication of populations that may be exposed to
levels of pollution that cause concern, it does not identify the
demographic characteristics of the most highly affected individuals or
communities. Electric generating units usually have very tall emission
stacks; this tends to disperse the pollutants emitted from these stacks
fairly far from the source. In addition, several of the pollutants
emitted by these sources, such as a common form of Hg and
SO2, are known to travel long distances and contribute to
adverse impacts on both the environment and human health hundreds or
even thousands of miles from where they were emitted (in the case of
elemental Hg, globally).
The proximity-to-the-source review is included in the analysis for
this final rule because some EGUs emit enough HAP such as Ni or Cr(VI)
to cause elevated lifetime cancer risks greater than 1 in a million in
nearby communities. In addition, the EPA's analysis indicates that
there are localized areas with potential for elevated levels of Hg
deposition around most U.S. EGUs.\381\
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\381\ See Excess Local Deposition TSD for more detail.
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The analysis of demographic data used proximity-to-the-source as a
surrogate for exposure to identify those populations considered to be
living near affected sources, such that they have notable exposures to
current HAP
[[Page 9445]]
emissions from these sources. The demographic data for this analysis
were extracted from the 2000 census data which were provided to the EPA
by the U.S. Census Bureau. Distributions by race are based on
demographic information at the census block level, and all other
demographic groups are based on the extrapolation of census block group
level data to the census block level. The socio-demographic parameters
used in the analysis included the following categories: Racial (White,
African American, Native American, Other or Multiracial, and All Other
Races); Ethnicity (Hispanic); and Other (Number of people below the
poverty line, Number of people with ages between 0 and 18, Number of
people greater than or equal to 65, Number of people with no high
school diploma).
In determining the aggregate demographic makeup of the communities
near affected sources, the EPA focused on those census blocks within
three miles of affected sources and determined the demographic
composition (e.g., race, income, etc.) of these census blocks and
compared them to the corresponding compositions nationally. The radius
of 3 miles (or approximately 5 kilometers) is consistent with other
demographic analyses focused on areas around potential sources. In
addition, air quality modeling experience has shown that the area
within three miles of an individual source of emissions can generally
be considered the area with the highest ambient air levels of the
primary pollutants being emitted for most sources, both in absolute
terms and relative to the contribution of other sources (assuming there
are other sources in the area, as is typical in urban areas). Although
facility processes and fugitive emissions may have more localized
impacts, the EPA acknowledges that because of various stack heights
there is the potential for dispersion beyond 3 miles. To the extent
that any minority, low income, and indigenous subpopulation is
disproportionately impacted by the current emissions as a result of the
proximity of their homes to these sources, that subpopulation also
stands to see increased environmental and health benefit from the
emissions reductions called for by this rule. The results of the EPA's
demographic analysis for affected sources are shown in the following
table: 382 383
Table 12--Comparative Summary of the Demographics Within 5 KM (3 Miles) of the Affected Sources
[Population in millions] 382
--------------------------------------------------------------------------------------------------------------------------------------------------------
African Native Other and Below poverty
White American American multiracial Hispanic Minority 383 line
--------------------------------------------------------------------------------------------------------------------------------------------------------
Near Source Total (3 mi)................ 8.78 2.51 0.10 2.52 2.86 5.13 2.43
% of Near Source Total.................. 63 18 1 18 21 37 17
National Total.......................... 215 35 2.49 33.3 39.1 70.8 37.1
% of National Total..................... 75 12 1 12 14 25 13
--------------------------------------------------------------------------------------------------------------------------------------------------------
\382\ Racial and ethnic categories overlap and cannot be summed.
\383\ The ``Minority'' population is the overall population (in the first row) minus white population (in the second row).
The data indicate that coal-fired EGUs are located in areas where
the minority share of the population living within a three mile buffer
is higher than the national average by 12 percentage points or 48
percent. For these same areas, the percent of the population below the
poverty line is also higher than the national average by 4 percentage
points or 31 percent. These results are presented in more detail in the
``Review of Proximity Analysis,'' February 2011, a copy of which is
available in the docket.
b. PM2.5 (Co-Benefits) Analysis. As mentioned above,
many of the steps EGUs will take to reduce their emissions of air
toxics as required by this final rule will also reduce emissions of PM
and SO2. As a result, this final rule will reduce
concentrations of PM2.5 in the atmosphere. Exposure to
PM2.5 can cause or contribute to adverse health effects,
such as asthma and heart disease, that significantly affect many
minority, low-income, and tribal individuals and their communities.
Fine PM (PM2.5) is particularly (but not exclusively)
harmful to children, the elderly, and people with existing heart and
lung diseases, including asthma. Exposure can cause premature death and
trigger heart attacks, asthma attacks in children and adults with
asthma, chronic and acute bronchitis, and emergency room visits and
hospitalizations, as well as milder illnesses that keep children home
from school and adults home from work. Missing work due to illness or
the illness of a child is a particular problem for people who have jobs
that do not provide paid sick days. Low-wage employees also risk losing
their jobs if they are absent too often, even if it is due to their own
illness or the illness of a child or other relative. Finally, many
individuals in these communities lack access to high quality health
care to treat these types of illnesses. Due to all these factors, many
minority and low-income communities are particularly susceptible to the
health effects of PM2.5 and receive a variety of benefits
from reducing it.
We estimate that in 2016 the annual PM-related benefits of the
final rule for adults include approximately 4,200 to 11,000 fewer
premature mortalities, 2,900 fewer cases of chronic bronchitis, 4,800
fewer non-fatal heart attacks, 2,600 fewer hospitalizations (for
respiratory and cardiovascular disease combined), 3.2 million fewer
days of restricted activity due to respiratory illness and
approximately 540,000 fewer lost work days. As described in EO 13045,
Protection of Children from Environmental Health Risks and Safety
Risks, we also estimate substantial health improvements for children.
We also examined the PM2.5 mortality risks according to
race, income, and educational attainment. We then estimated the change
in PM2.5 mortality risk as a result of this final rule among
people living in the counties with the highest (top 5 percent)
PM2.5 mortality risk in 2005. We then compared the change in
risk among the people living in these ``high-risk'' counties with
people living in all other counties.
In 2005, people living in the highest risk counties and in the
poorest counties had a substantially higher risk of PM2.5-
related death than people living in the other 95 percent of counties.
This was
[[Page 9446]]
true regardless of race; the difference between the groups of counties
for each race was large while the differences among races in both
groups of counties was very small. In contrast, the analysis found that
people with less than high school education had a significantly greater
risk from PM2.5 mortality than people with a greater than
high school education. This was true both for the highest-risk counties
and for the other counties. In summary, the analysis indicates that in
2005, educational status, living in one of the poorest counties, and
living in a high-risk county are associated with higher
PM2.5 mortality risk while race is not.
Our analysis demonstrates that this final rule will significantly
reduce the PM2.5 mortality among all populations of
different races living throughout the U.S. compared to both 2005 and
2016 pre-rule (i.e., base case) levels. The analysis indicates that
people living in counties with the highest rates (top 5 percent) of
PM2.5 mortality risk in 2005 receive the largest reduction
in mortality risk after this rule takes effect. We also find that
people living in the poorest 5 percent of the counties receive a larger
reduction in PM2.5 mortality risk than all other counties.
More information can be found in Section 7.11 of the RIA.
The EPA estimates that the benefits of the final rule are
distributed among races, income levels, and levels of education fairly
evenly. However, the analysis does indicate that this final rule in
conjunction with the implementation of existing or final rules (e.g.,
the CSAPR) will reduce the disparity in risk between those in the
highest-risk counties and the other 95 percent of counties for all
races and educational levels. In addition, in many cases implementation
of this final rule and other rules will, together, reduce risks in the
highest-risk counties to the approximate level of risk for the rest of
the counties as it existed before implementation of the rule.
These results are presented in more detail in Section 7.11 of the
RIA.
3. Meaningful Public Participation
The EPA defines ``environmental justice'' to include meaningful
involvement of all people regardless of race, color, national origin,
or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and policies. To
promote meaningful involvement, the EPA publicized the rulemaking via
newsletters, EJ listserves, and the internet, including the Office of
Policy's (OP) Rulemaking Gateway Web site (https://yosemite.epa.gov/opei/RuleGate.nsf/). During the comment period, the EPA discussed the
proposed rule via a conference call with communities, conducted a
community-oriented webinar on the proposed rule, and posted the webinar
presentation on- line. The EPA also held three public hearings to
receive additional input on the proposal.
There will continue to be opportunities for public notice and
comment as the utilities move forward with implementation of this rule.
Once the rule is finalized, affected EGUs will need to update their
Title V operating permits to reflect their new emission limits, any
other new applicable requirements, and the associated monitoring and
recordkeeping from this rule. The Title V permitting process provides
that when most permits are reopened (for example, to incorporate new
applicable requirements) or renewed, there must be opportunity for
public review and comments. In addition, after the public review
process, the EPA has an opportunity to review the proposed permit and
object to its issuance if it does not meet CAA requirements.
4. Additional Analysis
In addition to the previously described assessment of EJ impacts,
the EPA conducted an analysis of sub-populations with particularly high
potential risks of Hg exposure due to high rates of fish consumption.
These populations overlap in many cases with traditional EJ populations
and would benefit from Hg reductions resulting from this rule. The EPA
also conducted an analysis of the distribution of PM2.5-
related mortality risk according to the race, income and education of
the population and how MATS changes this distribution. These analyses
can be found in Section 7.12 of the RIA.
5. Summary
This final rule strictly limits the emissions rate of Hg and other
HAP from every affected EGU. The EPA's analysis indicates substantial
health benefits, including for minority, low income, and indigenous
populations, from reductions in PM2.5.
The EPA's analysis also indicates reductions in risks for
individuals, including for members of minority populations, who eat
fish frequently from U.S. lakes and rivers and who live near affected
sources. Based on all the available information, the EPA has determined
that this final rule will not have disproportionately high and adverse
human health or environmental effects on minority, low income, and
indigenous populations. The EPA is providing multiple opportunities for
EJ communities to both learn about and comment on this rule and
welcomes their participation as implementation of the rule proceeds.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
U.S. The EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the U.S. prior to
publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective April 16, 2012.
List of Subjects
40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.
40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.
Dated: December 16, 2011.
Lisa P. Jackson,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of the Federal Regulations is amended as follows:
PART 60--[AMENDED]
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart A--[Amended]
0
2. Section 60.17 is amended:
0
a. By redesignating paragraph (a)(93), added March 21, 2011, at 76 FR
15750, and delayed indefinitely at 76 FR 28664, May 18, 2011, as
paragraph (a)(96);
[[Page 9447]]
0
b. By redesignating paragraphs (a)(91) and (a)(92) as paragraphs
(a)(94) and (a)(95);
0
c. By redesignating paragraphs (a)(89) and (a)(90) as paragraphs
(a)(91) and (a)(92);
0
d. By redesignating paragraphs (a)(54) through (a)(88) as paragraphs
(a)(55) through (a)(89);
0
e. By adding paragraph (a)(54);
0
f. By adding paragraph (a)(90); and
0
g. By adding paragraph (a)(93) to read as follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(a) * * *
(54) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, approved September 1, 2008, IBR approved for Sec. Sec.
60.41b of subpart Db of this part and 60.41c of subpart Dc of this
part.
* * * * *
(90) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, approved July 15, 2011, IBR approved for Sec. Sec. 60.41b
of subpart Db of this part and 60.41c of subpart Dc of this part.
* * * * *
(93) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
approved August 1, 2010, IBR approved for Sec. Sec. 60.41b of subpart
Db of this part and 60.41c of subpart Dc of this part.
* * * * *
Subpart B--[Amended]
0
3. Section 60.21 is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (f).
0
c. By removing paragraph (k).
Sec. 60.21 Definitions.
* * * * *
(a) Designated pollutant means any air pollutant, the emissions of
which are subject to a standard of performance for new stationary
sources, but for which air quality criteria have not been issued and
that is not included on a list published under section 108(a) or
section 112(b)(1)(A) of the Act.
* * * * *
(f) Emission standard means a legally enforceable regulation
setting forth an allowable rate of emissions into the atmosphere,
establishing an allowance system, or prescribing equipment
specifications for control of air pollution emissions.
* * * * *
0
4. Section 60.24 is amended as follows:
0
a. By revising paragraph (b)(1).
0
b. By removing paragraph (h).
Sec. 60.24 Emission standards and compliance schedules.
* * * * *
(b) * * *
(1) Emission standards shall either be based on an allowance system
or prescribe allowable rates of emissions except when it is clearly
impracticable. Such cases will be identified in the guideline documents
issued under Sec. 60.22. Where emission standards prescribing
equipment specifications are established, the plan shall, to the degree
possible, set forth the emission reductions achievable by
implementation of such specifications, and may permit compliance by the
use of equipment determined by the State to be equivalent to that
prescribed.
* * * * *
Subpart D--[Amended]
0
5. The subpart heading for Subpart D is revised to read as follows:
Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators
0
6. Section 60.40 is amended by revising paragraph (e) to read as
follows:
Sec. 60.40 Applicability and designation of affected facility.
* * * * *
(e) Any facility subject to either subpart Da or KKKK of this part
is not subject to this subpart.
0
7. Section 60.41 is amended by adding the definition of ``natural gas''
in alphabetical order to read as follows:
Sec. 60.41 Definitions.
* * * * *
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
* * * * *
0
8. Section 60.42 is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By adding paragraph (d).
0
c. By adding paragraph (e).
Sec. 60.42 Standard for particulate matter (PM).
(a) Except as provided under paragraphs (b), (c), (d), and (e) of
this section, on and after the date on which the performance test
required to be conducted by Sec. 60.8 is completed, no owner or
operator subject to the provisions of this subpart shall cause to be
discharged into the atmosphere from any affected facility any gases
that:
* * * * *
(d) An owner or operator of an affected facility that combusts only
natural gas is exempt from the PM and opacity standards specified in
paragraph (a) of this section.
(e) An owner or operator of an affected facility that combusts only
gaseous or liquid fossil fuel (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and
that does not use post-combustion technology to reduce emissions of
SO2 or PM is exempt from the PM standards specified in
paragraph (a) of this section.
0
9. Section 60.45 is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraphs (b)(1) through (5).
0
d. By revising paragraph (b)(6) introductory text.
0
e. By revising paragraphs (b)(7)(i)(A) through (C).
0
f. By revising paragraph (b)(7)(ii)(B).
0
g. By adding paragraph (b)(8).
Sec. 60.45 Emissions and fuel monitoring.
(a) Each owner or operator of an affected facility subject to the
applicable emissions standard shall install, calibrate, maintain, and
operate continuous opacity monitoring system (COMS) for measuring
opacity and a continuous emissions monitoring system (CEMS) for
measuring SO2 emissions, NOX emissions, and
either oxygen (O2) or carbon dioxide (CO2) except
as provided in paragraph (b) of this section.
(b) Certain of the CEMS and COMS requirements under paragraph (a)
of this section do not apply to owners or operators under the following
conditions:
(1) For a fossil-fuel-fired steam generator that combusts only
gaseous or liquid fossil fuel (excluding residual oil)
[[Page 9448]]
with potential SO2 emissions rates of 26 ng/J (0.060 lb/
MMBtu) or less and that does not use post-combustion technology to
reduce emissions of SO2 or PM, COMS for measuring the
opacity of emissions and CEMS for measuring SO2 emissions
are not required if the owner or operator monitors SO2
emissions by fuel sampling and analysis or fuel receipts.
(2) For a fossil-fuel-fired steam generator that does not use a
flue gas desulfurization device, a CEMS for measuring SO2
emissions is not required if the owner or operator monitors
SO2 emissions by fuel sampling and analysis.
(3) Notwithstanding Sec. 60.13(b), installation of a CEMS for
NOX may be delayed until after the initial performance tests
under Sec. 60.8 have been conducted. If the owner or operator
demonstrates during the performance test that emissions of
NOX are less than 70 percent of the applicable standards in
Sec. 60.44, a CEMS for measuring NOX emissions is not
required. If the initial performance test results show that
NOX emissions are greater than 70 percent of the applicable
standard, the owner or operator shall install a CEMS for NOX
within one year after the date of the initial performance tests under
Sec. 60.8 and comply with all other applicable monitoring requirements
under this part.
(4) If an owner or operator is not required to and elects not to
install any CEMS for either SO2 or NOX, a CEMS
for measuring either O2 or CO2 is not required.
(5) For affected facilities using a PM CEMS, a bag leak detection
system to monitor the performance of a fabric filter (baghouse)
according to the most current requirements in Sec. 60.48Da of this
part, or an ESP predictive model to monitor the performance of the ESP
developed in accordance and operated according to the most current
requirements in section Sec. 60.48Da of this part a COMS is not
required.
(6) A COMS for measuring the opacity of emissions is not required
for an affected facility that does not use post-combustion technology
(except a wet scrubber) for reducing PM, SO2, or carbon
monoxide (CO) emissions, burns only gaseous fuels or fuel oils that
contain less than or equal to 0.30 weight percent sulfur, and is
operated such that emissions of CO to the atmosphere from the affected
source are maintained at levels less than or equal to 0.15 lb/MMBtu on
a boiler operating day average basis. Owners and operators of affected
sources electing to comply with this paragraph must demonstrate
compliance according to the procedures specified in paragraphs
(b)(6)(i) through (iv) of this section.
* * * * *
(7) * * *
(i) * * *
(A) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
(B) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted or within 45 days of the next day that fuel with an
opacity standard is combusted, whichever is later;
(C) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
* * * * *
(ii) * * *
(B) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
* * * * *
(8) A COMS for measuring the opacity of emissions is not required
for an affected facility at which the owner or operator installs,
calibrates, operates, and maintains a particulate matter continuous
parametric monitoring system (PM CPMS) according to the requirements
specified in subpart UUUUU of part 63.
* * * * *
Subpart Da--[Amended]
0
10. The subpart heading for Subpart Da is revised to read as follows:
Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units
0
11. Section 60.40Da is amended by revising paragraphs (b)(1) and (e) to
read as follows:
Sec. 60.40Da Applicability and designation of affected facility.
* * * * *
(b) * * *
(1) The IGCC electric utility steam generating unit is capable of
combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel
(either alone or in combination with any other fuel) in the combustion
turbine engine and associated heat recovery steam generator; and
* * * * *
(e) Applicability of this subpart to an electric utility combined
cycle gas turbine other than an IGCC electric utility steam generating
unit is as specified in paragraphs (e)(1) through (3) of this section.
(1) Affected facilities (i.e. heat recovery steam generators used
with duct burners) associated with a stationary combustion turbine that
are capable of combusting more than 73 MW (250 MMBtu/h) heat input of
fossil fuel are subject to this subpart except in cases when the
affected facility (i.e. heat recovery steam generator) meets the
applicability requirements of and is subject to subpart KKKK of this
part.
(2) For heat recovery steam generators use with duct burners
subject to this subpart, only emissions resulting from the combustion
of fuels in the steam generating unit (i.e. duct burners) are subject
to the standards under this subpart. (The emissions resulting from the
combustion of fuels in the stationary combustion turbine engine are
subject to subpart GG or KKKK, as applicable, of this part.)
(3) Any affected facility that meets the applicability requirements
and is subject to subpart Eb or subpart CCCC of this part is not
subject to the emission standards under subpart Da.
0
12. Section 60.41Da is amended as follows:
0
a. By revising the definitions of ``boiler operating day'', ``gaseous
fuel'', ``integrated gasification combined cycle electric utility steam
generating unit'', ``natural gas'', ``petroleum'', ``potential
combustion concentration'', and ``steam generating unit''.
0
b. By adding the definitions of ``affirmative defense'', ``combined
heat and power'', ``gross energy output'', ``net energy output'',
``out-of-control period'', and ``petroleum coke'' in alphabetical
order.
[[Page 9449]]
0
c. By removing the definitions of ``available purchase power'',
``cogeneration'', ``dry flue gas desulfurization technology ``,
``electric utility company'', ``emergency condition'', ``emission rate
period'', ``gross output'', ``interconnected'', ``net system
capacity'', ``principal company'', ``responsible official'', ``spare
flue gas desulfurization system module'', ``spinning reserve'',
``system emergency reserves'', and ``system load''.
Sec. 60.41Da Definitions.
* * * * *
Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
* * * * *
Boiler operating day for units constructed, reconstructed, or
modified before February 29, 2005, means a 24-hour period during which
fossil fuel is combusted in a steam-generating unit for the entire 24
hours. For units constructed, reconstructed, or modified after February
28, 2005, boiler operating day means a 24-hour period between 12
midnight and the following midnight during which any fuel is combusted
at any time in the steam-generating unit. It is not necessary for fuel
to be combusted the entire 24-hour period.
* * * * *
Combined heat and power, also known as ``cogeneration,'' means a
steam-generating unit that simultaneously produces both electric (and
mechanical) and useful thermal energy from the same primary energy
source.
* * * * *
Gaseous fuel means any fuel that is present as a gas at standard
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
* * * * *
Gross energy output means:
(1) For facilities constructed, reconstructed, or modified before
May 4, 2011, the gross electrical or mechanical output from the
affected facility plus 75 percent of the useful thermal output measured
relative to ISO conditions that is not used to generate additional
electrical or mechanical output or to enhance the performance of the
unit (i.e., steam delivered to an industrial process);
(2) For facilities constructed, reconstructed, or modified after
May 3, 2011, the gross electrical or mechanical output from the
affected facility minus any electricity used to power the feedwater
pumps and any associated gas compressors (air separation unit main
compressor, oxygen compressor, and nitrogen compressor) plus 75 percent
of the useful thermal output measured relative to ISO conditions that
is not used to generate additional electrical or mechanical output or
to enhance the performance of the unit (i.e., steam delivered to an
industrial process);
(3) For combined heat and power facilities constructed,
reconstructed, or modified after May 3, 2011, the gross electrical or
mechanical output from the affected facility divided by 0.95 minus any
electricity used to power the feedwater pumps and any associated gas
compressors (air separation unit main compressor, oxygen compressor,
and nitrogen compressor) plus 75 percent of the useful thermal output
measured relative to ISO conditions that is not used to generate
additional electrical or mechanical output or to enhance the
performance of the unit (i.e., steam delivered to an industrial
process);
(4) For a IGCC electric utility generating unit that coproduces
chemicals constructed, reconstructed, or modified after May 3, 2011,
the gross useful work performed is the gross electrical or mechanical
output from the unit minus electricity used to power the feedwater
pumps and any associated gas compressors (air separation unit main
compressor, oxygen compressor, and nitrogen compressor) that are
associated with power production plus 75 percent of the useful thermal
output measured relative to ISO conditions that is not used to generate
additional electrical or mechanical output or to enhance the
performance of the unit (i.e., steam delivered to an industrial
process). Auxiliary loads that are associated with power production are
determined based on the energy in the coproduced chemicals compared to
the energy of the syngas combusted in combustion turbine engine and
associated duct burners.
* * * * *
Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means an
electric utility combined cycle gas turbine that is designed to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction or repair. No solid fuel is directly
burned in the unit during operation.
* * * * *
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
Net energy output means the gross energy output minus the parasitic
load associated with power production. Parasitic load includes, but is
not limited to, the power required to operate the equipment used for
fuel delivery systems, air pollution control systems, wastewater
treatment systems, ash handling and disposal systems, and other
controls (i.e., pumps, fans, compressors, motors, instrumentation, and
other ancillary equipment required to operate the affected facility).
* * * * *
Out-of-control period means any period beginning with the quadrant
corresponding to the completion of a daily calibration error, linearity
check, or quality assurance audit that indicates that the instrument is
not measuring and recording within the applicable performance
specifications and ending with the quadrant corresponding to the
completion of an additional calibration error, linearity check, or
quality assurance audit following corrective action that demonstrates
that the instrument is measuring and recording within the applicable
performance specifications.
Petroleum for facilities constructed, reconstructed, or modified
before May 4, 2011, means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate oil, and residual oil. For
units constructed, reconstructed, or modified after May 3, 2011,
petroleum means crude oil or a fuel derived from crude oil, including,
but not limited to, distillate oil, residual oil, and petroleum coke.
Petroleum coke, also known as ``petcoke,'' means a carbonization
product of high-boiling hydrocarbon fractions obtained in petroleum
processing (heavy residues). Petroleum
[[Page 9450]]
coke is typically derived from oil refinery coker units or other
cracking processes.
Potential combustion concentration means the theoretical emissions
(nanograms per joule (ng/J), lb/MMBtu heat input) that would result
from combustion of a fuel in an uncleaned state without emission
control systems. For sulfur dioxide (SO2) the potential
combustion concentration is determined under Sec. 60.50Da(c).
* * * * *
Steam generating unit for facilities constructed, reconstructed, or
modified before May 4, 2011, means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included). For units
constructed, reconstructed, or modified after May 3, 2011, steam
generating unit means any furnace, boiler, or other device used for
combusting fuel for the purpose of producing steam (including fossil-
fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included) plus any
integrated combustion turbines and fuel cells.
* * * * *
0
13. Section 60.42Da is revised to read as follows:
Sec. 60.42Da Standards for particulate matter (PM).
(a) Except as provided in paragraph (f) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
an owner or operator of an affected facility shall not cause to be
discharged into the atmosphere from any affected facility for which
construction, reconstruction, or modification commenced before March 1,
2005, any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu)
heat input.
(b) Except as provided in paragraphs (b)(1) and (b)(2) of this
section, on and after the date the initial PM performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, an owner or operator of an affected facility shall not
cause to be discharged into the atmosphere any gases which exhibit
greater than 20 percent opacity (6-minute average), except for one 6-
minute period per hour of not more than 27 percent opacity.
(1) An owner or operator of an affected facility that elects to
install, calibrate, maintain, and operate a continuous emissions
monitoring system (CEMS) for measuring PM emissions according to the
requirements of this subpart is exempt from the opacity standard
specified in this paragraph (b) of this section.
(2) An owner or operator of an affected facility that combusts only
natural gas is exempt from the opacity standard specified in paragraph
(b) of this section.
(c) Except as provided in paragraphs (d) and (f) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after February
28, 2005, but before May 4, 2011, shall cause to be discharged into the
atmosphere from that affected facility any gases that contain PM in
excess of either:
(1) 18 ng/J (0.14 lb/MWh) gross energy output; or
(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the
combustion of solid, liquid, or gaseous fuel.
(d) As an alternative to meeting the requirements of paragraph (c)
of this section, the owner or operator of an affected facility for
which construction, reconstruction, or modification commenced after
February 28, 2005, but before May 4, 2011, may elect to meet the
requirements of this paragraph. On and after the date on which the
initial performance test is completed or required to be completed under
Sec. 60.8, whichever date comes first, no owner or operator of an
affected facility shall cause to be discharged into the atmosphere from
that affected facility any gases that contain PM in excess of:
(1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel, and
(2) For an affected facility that commenced construction or
reconstruction, 0.1 percent of the combustion concentration determined
according to the procedure in Sec. 60.48Da(o)(5) (99.9 percent
reduction) when combusting solid, liquid, or gaseous fuel, or
(3) For an affected facility that commenced modification, 0.2
percent of the combustion concentration determined according to the
procedure in Sec. 60.48Da(o)(5) (99.8 percent reduction) when
combusting solid, liquid, or gaseous fuel.
(e) Except as provided in paragraph (f) of this section, the owner
or operator of an affected facility that commenced construction,
reconstruction, or modification commenced after May 3, 2011, shall meet
the requirements specified in paragraphs (e)(1) and (2) of this
section.
(1) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator shall cause to be discharged into the
atmosphere from that affected facility at all times except during
periods of startup and shutdown, any gases that contain PM in excess of
the applicable emissions limit specified in paragraphs (e)(1)(i) or
(ii) of this section.
(i) For an affected facility which commenced construction or
reconstruction, any gases that contain PM in excess of either:
(A) 11 ng/J (0.090 lb/MWh) gross energy output; or
(B) 12 ng/J (0.097 lb/MWh) net energy output.
(ii) For an affected facility which commenced modification, any
gases that contain PM in excess of 13 ng/J (0.015 lb/MMBtu) heat input.
(2) During periods of startup and shutdown, the owner or operator
shall meet the work practice standards specified in Table 3 to subpart
UUUUU of part 63.
(f) An owner or operator of an affected facility that meets the
conditions in either paragraphs (f)(1) or (2) of this section is exempt
from the PM emissions limits in this section.
(1) The affected facility combusts only gaseous or liquid fuels
(excluding residual oil) with potential SO2 emissions rates
of 26 ng/J (0.060 lb/MMBtu) or less, and that does not use a post-
combustion technology to reduce emissions of SO2 or PM.
(2) The affected facility is operated under a PM commercial
demonstration permit issued by the Administrator according to the
provisions of Sec. 60.47Da.
0
14. Section 60.43Da is amended as follows:
0
a. The section heading is revised.
0
b. By revising paragraphs (a)(1) and (2).
0
c. By adding paragraphs (a)(3) and (4).
0
d. By removing and reserving paragraph (c).
0
e. By revising paragraph (f).
0
f. By revising paragraph (i).
0
g. By revising paragraph (k).
0
h. By adding paragraph (l).
0
i. By adding paragraph (m).
Sec. 60.43Da Standards for sulfur dioxide (SO2).
(a) * * *
(1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction);
(2) 30 percent of the potential combustion concentration (70
percent
[[Page 9451]]
reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat
input;
(3) 180 ng/J (1.4 lb/MWh) gross energy output; or
(4) 65 ng/J (0.15 lb/MMBtu) heat input.
* * * * *
(f) The SO2 standards under this section do not apply to
an owner or operator of an affected facility that is operated under an
SO2 commercial demonstration permit issued by the
Administrator in accordance with the provisions of Sec. 60.47Da.
* * * * *
(i) Except as provided in paragraphs (j) and (k) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility for which
construction, reconstruction, or modification commenced after February
28, 2005, but before May 4, 2011, shall cause to be discharged into the
atmosphere from that affected facility, any gases that contain
SO2 in excess of the applicable emissions limit specified in
paragraphs (i)(1) through (3) of this section.
(1) For an affected facility which commenced construction, any
gases that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 5 percent of the potential combustion concentration (95
percent reduction).
(2) For an affected facility which commenced reconstruction, any
gases that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
(iii) 5 percent of the potential combustion concentration (95
percent reduction).
(3) For an affected facility which commenced modification, any
gases that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
(iii) 10 percent of the potential combustion concentration (90
percent reduction).
* * * * *
(k) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area for which construction, reconstruction, or
modification commenced after February 28, 2005, but before May 4, 2011,
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of the
applicable emissions limit specified in paragraphs (k)(1) and (2) of
this section.
(1) For an affected facility that burns solid or solid-derived
fuel, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input.
(2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
230 ng/J (0.54 lb/MMBtu) heat input.
(l) Except as provided in paragraphs (j) and (m) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility for which
construction, reconstruction, or modification commenced after May 3,
2011, shall cause to be discharged into the atmosphere from that
affected facility, any gases that contain SO2 in excess of
the applicable emissions limit specified in paragraphs (l)(1) and (2)
of this section.
(1) For an affected facility which commenced construction or
reconstruction, any gases that contain SO2 in excess of
either:
(i) 130 ng/J (1.0 lb/MWh) gross energy output; or
(ii) 140 ng/J (1.2 lb/MWh) net energy output; or
(iii) 3 percent of the potential combustion concentration (97
percent reduction).
(2) For an affected facility which commenced modification, any
gases that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 10 percent of the potential combustion concentration (90
percent reduction).
(m) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area for which construction, reconstruction, or
modification commenced after May 3, 2011, shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
SO2 in excess of the applicable emissions limit specified in
paragraphs (m)(1) and (2) of this section.
(1) For an affected facility that burns solid or solid-derived
fuel, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input.
(2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
230 ng/J (0.54 lb/MMBtu) heat input.
0
15. Section 60.44Da is revised to read as follows:
Sec. 60.44Da Standards for nitrogen oxides (NOX).
(a) Except as provided in paragraph (h) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator subject to the provisions of this subpart shall
cause to be discharged into the atmosphere from any affected facility
for which construction, reconstruction, or modification commenced
before July 10, 1997 any gases that contain NOX (expressed
as NO2) in excess of the applicable emissions limit in
paragraphs (a)(1) and (2) of this section.
(1) The owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX in excess of the
emissions limit listed in the following table as applicable to the fuel
type combusted and as determined on a 30-boiler operating day rolling
average basis.
------------------------------------------------------------------------
Emission limit for heat
input
Fuel type -------------------------
ng/J lb/MMBtu
------------------------------------------------------------------------
Gaseous fuels:
Coal-derived fuels........................ 210 0.50
All other fuels........................... 86 0.20
Liquid fuels:
[[Page 9452]]
Coal-derived fuels........................ 210 0.50
Shale oil................................. 210 0.50
All other fuels........................... 130 0.30
Solid fuels:
Coal-derived fuels........................ 210 0.50
Any fuel containing more than 25%, by (1) (1)
weight, coal refuse......................
Any fuel containing more than 25%, by weight, 340 0.80
lignite if the lignite is mined in North
Dakota, South Dakota, or Montana, and is
combusted in a slag tap furnace \2\..........
Any fuel containing more than 25%, by weight, 260 0.60
lignite not subject to the 340 ng/J heat
input emission limit \2\.....................
Subbituminous coal............................ 210 0.50
Bituminous coal............................... 260 0.60
Anthracite coal............................... 260 0.60
All other fuels............................... 260 0.60
------------------------------------------------------------------------
\1\ Exempt from NOX standards and NOX monitoring requirements.
\2\ Any fuel containing less than 25%, by weight, lignite is not
prorated but its percentage is added to the percentage of the
predominant fuel.
(2) When two or more fuels are combusted simultaneously in an
affected facility, the applicable emissions limit (En) is
determined by proration using the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE12.019
Where:
En = Applicable NOX emissions limit when multiple fuels
are combusted simultaneously (ng/J heat input);
w = Percentage of total heat input derived from the combustion of
fuels subject to the 86 ng/J heat input standard;
x = Percentage of total heat input derived from the combustion of
fuels subject to the 130 ng/J heat input standard;
y = Percentage of total heat input derived from the combustion of
fuels subject to the 210 ng/J heat input standard;
z = Percentage of total heat input derived from the combustion of
fuels subject to the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered from the combustion of
fuels subject to the 340 ng/J heat input standard.
(b) [Reserved]
(c) [Reserved]
(d) Except as provided in paragraph (h) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after July 9, 1997, but
before March 1, 2005, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain NOX
(expressed as NO2) in excess of the applicable emissions
limit specified in paragraphs (d)(1) and (2) of this section as
determined on a 30-boiler operating day rolling average basis.
(1) For an affected facility which commenced construction, any
gases that contain NOX in excess of 200 ng/J (1.6 lb/MWh)
gross energy output.
(2) For an affected facility which commenced reconstruction, any
gases that contain NOX in excess of 65 ng/J (0.15 lb/MMBtu)
heat input.
(e) Except as provided in paragraphs (f) and (h) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after February
28, 2005 but before May 4, 2011, shall cause to be discharged into the
atmosphere from that affected facility any gases that contain
NOX (expressed as NO2) in excess of the
applicable emissions limit specified in paragraphs (e)(1) through (3)
of this section as determined on a 30-boiler operating day rolling
average basis.
(1) For an affected facility which commenced construction, any
gases that contain NOX in excess of 130 ng/J (1.0 lb/MWh)
gross energy output.
(2) For an affected facility which commenced reconstruction, any
gases that contain NOX in excess of either:
(i) 130 ng/J (1.0 lb/MWh) gross energy output; or
(ii) 47 ng/J (0.11 lb/MMBtu) heat input.
(3) For an affected facility which commenced modification, any
gases that contain NOX in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 65 ng/J (0.15 lb/MMBtu) heat input.
(f) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator of an IGCC electric utility steam
generating unit subject to the provisions of this subpart and for which
construction, reconstruction, or modification commenced after February
28, 2005 but before May 4, 2011, shall meet the requirements specified
in paragraphs (f)(1) through (3) of this section.
(1) Except as provided for in paragraphs (f)(2) and (3) of this
section, the owner or operator shall not cause to be discharged into
the atmosphere any gases that contain NOX (expressed as
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output.
(2) When burning liquid fuel exclusively or in combination with
solid-derived fuel such that the liquid fuel contributes 50 percent or
more of the total heat input to the combined cycle combustion turbine,
the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX (expressed as
NO2) in excess of 190 ng/J (1.5 lb/MWh) gross energy output.
(3) In cases when during a 30-boiler operating day rolling average
compliance period liquid fuel is burned in such a manner to meet the
conditions in paragraph (f)(2) of this section for only a portion of
the clock hours in the
[[Page 9453]]
30-day compliance period, the owner or operator shall not cause to be
discharged into the atmosphere any gases that contain NOX
(expressed as NO2) in excess of the computed weighted-
average emissions limit based on the proportion of gross energy output
(in MWh) generated during the compliance period for each of emissions
limits in paragraphs (f)(1) and (2) of this section.
(g) Except as provided in paragraphs (h) of this section and Sec.
60.45Da, on and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after May 3,
2011, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain NOX (expressed as
NO2) in excess of the applicable emissions limit specified
in paragraphs (g)(1) through (3) of this section.
(1) For an affected facility which commenced construction or
reconstruction, any gases that contain NOX in excess of
either:
(i) 88 ng/J (0.70 lb/MWh) gross energy output; or
(ii) 95 ng/J (0.76 lb/MWh) net energy output.
(2) For an affected facility which commenced construction or
reconstruction and that burns 75 percent or more coal refuse (by heat
input) on a 12-month rolling average basis, any gases that contain
NOX in excess of either:
(i) 110 ng/J (0.85 lb/MWh) gross energy output; or
(ii) 120 ng/J (0.92 lb/MWh) net energy output.
(3) For an affected facility which commenced modification, any
gases that contain NOX in excess of 140 ng/J (1.1 lb/MWh)
gross energy output.
(h) The NOX emissions limits under this section do not
apply to an owner or operator of an affected facility which is
operating under a commercial demonstration permit issued by the
Administrator in accordance with the provisions of Sec. 60.47Da.
0
16. Section 60.45Da is revised to read as follows:
Sec. 60.45Da Alternative standards for combined nitrogen oxides (NOX)
and carbon monoxide (CO).
(a) The owner or operator of an affected facility that commenced
construction, reconstruction, or modification after May 3, 2011 as
alternate to meeting the applicable NOX emissions limits
specified in Sec. 60.44Da may elect to meet the applicable standards
for combined NOX and CO specified in paragraph (b) of this
section.
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8 no owner or
operator of an affected facility that commenced construction,
reconstruction, or modification after May 3, 2011, shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain NOX (expressed as NO2) plus CO in
excess of the applicable emissions limit specified in paragraphs (b)(1)
through (3) of this section as determined on a 30-boiler operating day
rolling average basis.
(1) For an affected facility which commenced construction or
reconstruction, any gases that contain NOX plus CO in excess
of either:
(i) 140 ng/J (1.1 lb/MWh) gross energy output; or
(ii) 150 ng/J (1.2 lb/MWh) net energy output.
(2) For an affected facility which commenced construction or
reconstruction and that burns 75 percent or more coal refuse (by heat
input) on a 12-month rolling average basis, any gases that contain
NOX plus CO in excess of either:
(i) 160 ng/J (1.3 lb/MWh) gross energy output; or
(ii) 170 ng/J (1.4 lb/MWh) net energy output.
(3) For an affected facility which commenced modification, any
gases that contain NOX plus CO in excess of 190 ng/J (1.5
lb/MWh) gross energy output.
0
17. Section 60.47Da is amended as follows:
0
a. By revising paragraph (c).
0
b. By adding paragraph (f).
0
c. By adding paragraph (g).
0
d. By adding paragraph (h).
0
e. By adding paragraph (i).
Sec. 60.47Da Commercial demonstration permit.
* * * * *
(c) An owner or operator of an affected facility that uses
fluidized bed combustion (atmospheric or pressurized) and who is issued
a commercial demonstration permit by the Administrator is not subject
to the SO2 emission reduction requirements under Sec.
60.43Da(a) but must, as a minimum, reduce SO2 emissions to
15 percent of the potential combustion concentration (85 percent
reduction) on a 30-day rolling average basis and to less than 520 ng/J
(1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
* * * * *
(f) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions controls
system who is issued a commercial demonstration permit by the
Administrator is not subject to the total PM emission reduction
requirements under Sec. 60.42Da but must, as a minimum, reduce PM
emissions to less than 6.4 ng/J (0.015 lb/MMBtu) heat input.
(g) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions controls
system who is issued a commercial demonstration permit by the
Administrator is not subject to the SO2 standards or
emission reduction requirements under Sec. 60.43Da but must, as a
minimum, reduce SO2 emissions to 5 percent of the potential
combustion concentration (95 percent reduction) or to less than 180 ng/
J (1.4 lb/MWh) gross energy output on a 30-boiler operating day rolling
average basis.
(h) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions control system
or advanced combustion controls who is issued a commercial
demonstration permit by the Administrator is not subject to the
NOX standards or emission reduction requirements under Sec.
60.44Da but must, as a minimum, reduce NOX emissions to less
than 130 ng/J (1.0 lb/MWh) or the combined NOX plus CO
emissions to less than 180 ng/J (1.4 lb/MWh) gross energy output on a
30-boiler operating day rolling average basis.
(i) Commercial demonstration permits may not exceed the following
equivalent MW electrical generation capacity for any one technology
category listed in the following table.
------------------------------------------------------------------------
Equivalent
electrical
capacity
Technology Pollutant (MW
electrical
output)
------------------------------------------------------------------------
Multi-pollutant Emission Control.... SO2.................. 1,000
[[Page 9454]]
Multi-pollutant Emission Control.... NOX.................. 1,000
Multi-pollutant Emission Control.... PM................... 1,000
Pressurized Fluidized Bed Combustion SO2.................. 1,000
Pressurized Fluidized Bed Combustion NOX.................. 1,000
Pressurized Fluidized Bed Combustion PM................... 1,000
Advanced Combustion Controls........ NOX.................. 1,000
------------------------------------------------------------------------
0
18. Section 60.48Da is amended as follows:
0
a. By revising paragraphs (a) through (g).
0
b. By revising paragraph (i).
0
c. By revising paragraph (k)(1)(i).
0
d. By revising paragraph (k)(2)(i).
0
e. By revising paragraph (k)(2)(iv).
0
f. By removing and reserving paragraph (l).
0
g. By revising paragraph (m).
0
h. By revising paragraph (n).
0
i. By revising paragraphs (p)(5), (7), and (8).
0
j. By adding paragraph (r).
0
k. By adding paragraph (s).
Sec. 60.48Da Compliance provisions.
(a) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, the applicable PM
emissions limit and opacity standard under Sec. 60.42Da,
SO2 emissions limit under Sec. 60.43Da, and NOX
emissions limit under Sec. 60.44Da apply at all times except during
periods of startup, shutdown, or malfunction. For affected facilities
for which construction, modification, or reconstruction commenced after
May 3, 2011, the applicable SO2 emissions limit under Sec.
60.43Da, NOX emissions limit under Sec. 60.44Da, and
NOX plus CO emissions limit under Sec. 60.45Da apply at all
times. The applicable PM emissions limit and opacity standard under
Sec. 60.42Da apply at all times except during periods of startup and
shutdown.
(b) After the initial performance test required under Sec. 60.8,
compliance with the applicable SO2 emissions limit and
percentage reduction requirements under Sec. 60.43Da, NOX
emissions limit under Sec. 60.44Da, and NOX plus CO
emissions limit under Sec. 60.45Da is based on the average emission
rate for 30 successive boiler operating days. A separate performance
test is completed at the end of each boiler operating day after the
initial performance test, and a new 30-boiler operating day rolling
average emission rate for both SO2, NOX or
NOX plus CO as applicable, and a new percent reduction for
SO2 are calculated to demonstrate compliance with the
standards.
(c) For the initial performance test required under Sec. 60.8,
compliance with the applicable SO2 emissions limits and
percentage reduction requirements under Sec. 60.43Da, the
NOX emissions limits under Sec. 60.44Da, and the
NOX plus CO emissions limits under Sec. 60.45Da is based on
the average emission rates for SO2, NOX, CO, and
percent reduction for SO2 for the first 30 successive boiler
operating days. The initial performance test is the only test in which
at least 30 days prior notice is required unless otherwise specified by
the Administrator. The initial performance test is to be scheduled so
that the first boiler operating day of the 30 successive boiler
operating days is completed within 60 days after achieving the maximum
production rate at which the affected facility will be operated, but
not later than 180 days after initial startup of the facility.
(d) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, compliance with
applicable 30-boiler operating day rolling average SO2 and
NOX emissions limits is determined by calculating the
arithmetic average of all hourly emission rates for SO2 and
NOX for the 30 successive boiler operating days, except for
data obtained during startup, shutdown, or malfunction. For affected
facilities for which construction, modification, or reconstruction
commenced after May 3, 2011, compliance with applicable 30-boiler
operating day rolling average SO2 and NOX
emissions limits is determined by dividing the sum of the
SO2 and NOX emissions for the 30 successive
boiler operating days by the sum of the gross energy output or net
energy output, as applicable, for the 30 successive boiler operating
days.
(e) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, compliance with
applicable SO2 percentage reduction requirements is
determined based on the average inlet and outlet SO2
emission rates for the 30 successive boiler operating days. For
affected facilities for which construction, modification, or
reconstruction commenced after May 3, 2011, compliance with applicable
SO2 percentage reduction requirements is determined based on
the ``as fired'' total potential emissions and the total outlet
SO2 emissions for the 30 successive boiler operating days.
(f) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, compliance with
applicable daily average PM emissions limits is determined by
calculating the arithmetic average of all hourly emission rates for PM
each boiler operating day, except for data obtained during startup,
shutdown, and malfunction. Daily averages are only calculated for
boiler operating days that have non-out-of-control data for at least 18
hours of unit operation during which the standard applies. Instead, all
of the non-out-of-control hourly emission rates of the operating day(s)
not meeting the minimum 18 hours non-out-of-control data daily average
requirement are averaged with all of the non-out-of-control hourly
emission rates of the next boiler operating day with 18 hours or more
of non-out-of-control PM CEMS data to determine compliance. For
affected facilities for which construction, modification, or
reconstruction commenced after May 3, 2011, compliance with applicable
daily average PM emissions limits is determined by dividing the sum of
the PM emissions for the 30 successive boiler operating days by the sum
of the gross useful output or net energy output, as applicable, for the
30 successive boiler operating days.
(g) For affected facilities for which construction, modification,
or reconstruction commenced after May 3, 2011, compliance with
applicable 30-boiler operating day rolling average NOX plus
CO emissions limit is determined by dividing the sum of the
NOX plus CO emissions for the 30 successive boiler operating
days by the sum of the gross energy output or net energy output, as
[[Page 9455]]
applicable, for the 30 successive boiler operating days.
* * * * *
(i) Compliance provisions for sources subject to Sec.
60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or (g). The owner or
operator shall calculate NOX emissions as 1.194 x
10-7 lb/scf-ppm times the average hourly NOX
output concentration in ppm (measured according to the provisions of
Sec. 60.49Da(c)), times the average hourly flow rate (measured in
scfh, according to the provisions of Sec. 60.49Da(l) or Sec.
60.49Da(m)), divided by the average hourly gross energy output
(measured according to the provisions of Sec. 60.49Da(k)) or the
average hourly net energy output, as applicable. Alternatively, for
oil-fired and gas-fired units, NOX emissions may be
calculated by multiplying the hourly NOX emission rate in
lb/MMBtu (measured by the CEMS required under Sec. 60.49Da(c) and
(d)), by the hourly heat input rate (measured according to the
provisions of Sec. 60.49Da(n)), and dividing the result by the average
gross energy output (measured according to the provisions of Sec.
60.49Da(k)) or the average hourly net energy output, as applicable.
(k) * * *
(1) * * *
(i) The emission rate (E) of NOX shall be computed using
Equation 2 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.000
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/dscm (lb/dscf);
Cte = Average hourly concentration of NOX in
the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas
from steam generating unit, dscm/h (dscf/h);
Qte = Average hourly volumetric flow rate of exhaust gas
from combustion turbine, dscm/h (dscf/h);
Osg = Average hourly gross energy output from steam
generating unit, J/h (MW); and
h = Average hourly fraction of the total heat input to the steam
generating unit derived from the combustion of fuel in the affected
duct burner.
* * * * *
(2) * * *
(i) The emission rate (E) of NOX shall be computed using
Equation 3 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.001
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas
from steam generating unit, dscm/h (dscf/h); and
Occ = Average hourly gross energy output from entire
combined cycle unit, J/h (MW).
* * * * *
(iv) The owner or operator may, in lieu of installing, operating,
and recording data from the continuous flow monitoring system specified
in Sec. 60.49Da(l), determine the mass rate (lb/h) of NOX
emissions by installing, operating, and maintaining continuous fuel
flowmeters following the appropriate measurements procedures specified
in appendix D of part 75 of this chapter. If this compliance option is
selected, the emission rate (E) of NOX shall be computed
using Equation 4 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.002
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy output;
ERsg = Average hourly emission rate of NOX
exiting the steam generating unit heat input calculated using
appropriate F factor as described in Method 19 of appendix A of this
part, ng/J (lb/MMBtu);
Hcc = Average hourly heat input rate of entire combined
cycle unit, J/h (MMBtu/h); and
Occ = Average hourly gross energy output from entire
combined cycle unit, J/h (MW).
* * * * *
(m) Compliance provisions for sources subject to Sec.
60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i),
(j)(3)(i), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator
shall calculate SO2 emissions as 1.660 x 10-7 lb/
scf-ppm times the average hourly SO2 output concentration in
ppm (measured according to the provisions of Sec. 60.49Da(b)), times
the average hourly flow rate (measured according to the provisions of
Sec. 60.49Da(l) or Sec. 60.49Da(m)), divided by the average hourly
gross energy output (measured according to the provisions of Sec.
60.49Da(k)) or the average hourly net energy output, as applicable.
Alternatively, for oil-fired and gas-fired units, SO2
emissions may be calculated by multiplying the hourly SO2
emission rate (in lb/MMBtu), measured by the CEMS required under Sec.
60.49Da, by the hourly heat input rate (measured according to the
provisions of Sec. 60.49Da(n)), and dividing the result by the average
gross energy output (measured according to the provisions of Sec.
60.49Da(k)) or the average hourly net energy output, as applicable.
(n) Compliance provisions for sources subject to Sec.
60.42Da(c)(1) or (e)(1)(i). The owner or operator shall calculate PM
emissions by multiplying the average hourly PM output concentration
(measured according to the provisions of Sec. 60.49Da(t)), by the
average hourly flow rate (measured according to the provisions of Sec.
60.49Da(l) or Sec. 60.49Da(m)), and dividing by the average hourly
gross energy output (measured according to the provisions
[[Page 9456]]
of Sec. 60.49Da(k)) or the average hourly net energy output, as
applicable.
* * * * *
(p) * * *
(5) At a minimum, non-out-of-control CEMS hourly averages shall be
obtained for 75 percent of all operating hours on a 30-boiler operating
day rolling average basis. Beginning on January 1, 2012, non-out-of-
control CEMS hourly averages shall be obtained for 90 percent of all
operating hours on a 30-boiler operating day rolling average basis.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) [Reserved]
* * * * *
(7) All non-out-of-control CEMS data shall be used in calculating
average emission concentrations even if the minimum CEMS data
requirements of paragraph (j)(5) of this section are not met.
(8) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of this part to provide, as necessary, non-out-of-control emissions
data for a minimum of 90 percent (only 75 percent is required prior to
January 1, 2012) of all operating hours per 30-boiler operating day
rolling average.
* * * * *
(r) Compliance provisions for sources subject to Sec. 60.45Da. To
determine compliance with the NOX plus CO emissions limit,
the owner or operator shall use the procedures specified in paragraphs
(r)(1) through (3) of this section.
(1) Calculate NOX emissions as 1.194 x 10-7
lb/scf-ppm times the average hourly NOX output concentration
in ppm (measured according to the provisions of Sec. 60.49Da(c)),
times the average hourly flow rate (measured in scfh, according to the
provisions of Sec. 60.49Da(l) or Sec. 60.49Da(m)), divided by the
average hourly gross energy output (measured according to the
provisions of Sec. 60.49Da(k)) or the average hourly net energy
output, as applicable.
(2) Calculate CO emissions by multiplying the average hourly CO
output concentration (measured according to the provisions of Sec.
60.49Da(u), by the average hourly flow rate (measured according to the
provisions of Sec. 60.49Da(l) or Sec. 60.49Da(m)), and dividing by
the average hourly gross energy output (measured according to the
provisions of Sec. 60.49Da(k)) or the average hourly net energy
output, as applicable.
(3) Calculate NOX plus CO emissions by summing the
NOX emissions results from paragraph (r)(1) of this section
plus the CO emissions results from paragraph (r)(2) of this section.
(s) Affirmative defense for exceedance of emissions limit during
malfunction. In response to an action to enforce the standards set
forth in paragraph Sec. Sec. 60.42Da, 60.43Da, 60.44Da, and 60.45Da,
you may assert an affirmative defense to a claim for civil penalties
for exceedances of such standards that are caused by malfunction, as
defined at 40 CFR 60.2. Appropriate penalties may be assessed, however,
if you fail to meet your burden of proving all of the requirements in
the affirmative defense as specified in paragraphs (s)(1) and (2) of
this section. The affirmative defense shall not be available for claims
for injunctive relief.
(1) To establish the affirmative defense in any action to enforce
such a limit, you must timely meet the notification requirements in
paragraph (s)(2) of this section, and must prove by a preponderance of
evidence that:
(i) The excess emissions:
(A) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring equipment, process equipment, or a
process to operate in a normal or usual manner; and
(B) Could not have been prevented through careful planning, proper
design, or better operation and maintenance practices; and
(C) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(D) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when the
applicable emissions limits were being exceeded. Off-shift and overtime
labor were used, to the extent practicable to make these repairs; and
(iii) The frequency, amount, and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
(iv) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
(v) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment, and human
health; and
(vi) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(vii) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
(viii) At all times, the facility was operated in a manner
consistent with good practices for minimizing emissions; and
(ix) A written root cause analysis has been prepared, the purpose
of which is to determine, correct, and eliminate the primary causes of
the malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
(2) Notification. The owner or operator of the affected source
experiencing an exceedance of its emission limit(s) during a
malfunction shall notify the Administrator by telephone or facsimile
(FAX) transmission as soon as possible, but no later than two business
days after the initial occurrence of the malfunction or, if it is not
possible to determine within two business days whether the malfunction
caused or contributed to an exceedance, no later than two business days
after the owner or operator knew or should have known that the
malfunction caused or contributed to an exceedance, but, in no event
later than two business days after the end of the averaging period, if
it wishes to avail itself of an affirmative defense to civil penalties
for that malfunction. The owner or operator seeking to assert an
affirmative defense shall also submit a written report to the
Administrator within 45 days of the initial occurrence of the
exceedance of the standard in Sec. 63.9991 to demonstrate, with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (s)(1) of this section. The owner or operator
may seek an extension of this deadline for up to 30 additional days by
submitting a written request to the Administrator before the expiration
of the 45 day period. Until a request for an extension has been
approved by the Administrator, the owner or operator is subject to the
requirement to submit such report within 45 days of the initial
occurrence of the exceedance.
0
19. Section 60.49Da is amended as follows:
0
a. By revising paragraphs (a)(1) and (2).
[[Page 9457]]
0
b. By revising paragraph (a)(3) introductory text.
0
c. By revising paragraph (a)(3)(ii).
0
d. By revising paragraph (a)(3)(iii)(B).
0
e. By adding paragraph (a)(4).
0
f. By revising paragraph (b) introductory text.
0
g. By revising paragraph (b)(2).
0
h. By revising paragraph (e).
0
i. By revising paragraph (k) introductory text.
0
j. By revising paragraph (k)(3).
0
k. By revising paragraph (l).
0
l. By removing and reserving paragraph (p).
0
m. By removing and reserving paragraph (q).
0
n. By removing and reserving paragraph (r).
0
o. By revising paragraph (t).
0
p. By revising paragraph (u)(1)(iii).
0
q. By revising paragraph (v)(4).
Sec. 60.49Da Emission monitoring.
(a) * * *
(1) Except as provided for in paragraphs (a)(2) and (4) of this
section, the owner or operator of an affected facility subject to an
opacity standard, shall install, calibrate, maintain, and operate a
COMS, and record the output of the system, for measuring the opacity of
emissions discharged to the atmosphere. If opacity interference due to
water droplets exists in the stack (for example, from the use of an FGD
system), the opacity is monitored upstream of the interference (at the
inlet to the FGD system). If opacity interference is experienced at all
locations (both at the inlet and outlet of the SO2 control
system), alternate parameters indicative of the PM control system's
performance and/or good combustion are monitored (subject to the
approval of the Administrator).
(2) As an alternative to the monitoring requirements in paragraph
(a)(1) of this section, an owner or operator of an affected facility
that meets the conditions in either paragraph (a)(2)(i), (ii), (iii),
or (iv) of this section may elect to monitor opacity as specified in
paragraph (a)(3) of this section.
(i) The affected facility uses a fabric filter (baghouse) to meet
the standards in Sec. 60.42Da and a bag leak detection system is
installed and operated according to the requirements in paragraphs
Sec. 60.48Da(o)(4)(i) through (v);
(ii) The affected facility burns only gaseous or liquid fuels
(excluding residual oil) with potential SO2 emissions rates
of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion
technology to reduce emissions of SO2 or PM;
(iii) The affected facility meets all of the conditions specified
in paragraphs (a)(2)(iii)(A) through (C) of this section.
(A) No post-combustion technology (except a wet scrubber) is used
for reducing PM, SO2, or CO emissions;
(B) Only natural gas, gaseous fuels, or fuel oils that contain less
than or equal to 0.30 weight percent sulfur are burned; and
(C) Emissions of CO discharged to the atmosphere are maintained at
levels less than or equal to 1.4 lb/MWh on a boiler operating day
average basis as demonstrated by the use of a CEMS measuring CO
emissions according to the procedures specified in paragraph (u) of
this section; or
(iv) The affected facility uses an ESP and uses an ESP predictive
model to monitor the performance of the ESP developed in accordance and
operated according to the most current requirements in section Sec.
60.48Da of this part.
(3) The owner or operator of an affected facility that meets the
conditions in paragraph (a)(2) of this section may, as an alternative
to using a COMS, elect to monitor visible emissions using the
applicable procedures specified in paragraphs (a)(3)(i) through (iv) of
this section. The opacity performance test requirement in paragraph
(a)(3)(i) must be conducted by April 29, 2011, within 45 days after
stopping use of an existing COMS, or within 180 days after initial
startup of the facility, whichever is later.
* * * * *
(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a)(3)(i) of this section according to the applicable
schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(C) of this
section, as determined by the most recent Method 9 of appendix A-4 of
this part performance test results.
(A) If the maximum 6-minute average opacity is less than or equal
to 5 percent, a subsequent Method 9 of appendix A-4 of this part
performance test must be completed within 12 calendar months from the
date that the most recent performance test was conducted or within 45
days of the next day that fuel with an opacity standard is combusted,
whichever is later;
(B) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
(C) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 45 calendar days from the date that the
most recent performance test was conducted.
(iii) * * *
(B) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
* * * * *
(4) An owner or operator of an affected facility that is subject to
an opacity standard under Sec. 60.42a(b) is not required to operate a
COMS provided that affected facility meets the conditions in either
paragraph (a)(4)(i) or (ii) of this section.
(i) The affected facility combusts only gaseous fuels and/or liquid
fuels (excluding residue oil) with a potential SO2 emissions
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates
according to a written site-specific monitoring plan approved by the
permitting authority. This monitoring plan must include procedures and
criteria for establishing and monitoring specific parameters for the
affected facility indicative of compliance with the opacity standard.
For testing performed as part of this site-specific monitoring plan,
the permitting authority may require as an alternative to the
notification and reporting requirements specified in Sec. Sec. 60.8
and 60.11 that the owner or operator submit any deviations with the
excess emissions report required under Sec. 60.51a(d).
(ii) The owner or operator of the affected facility installs,
calibrates, operates, and maintains a particulate matter continuous
parametric monitoring system (PM CPMS) according to the requirements
specified in subpart UUUUU of part 63.
(b) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring SO2 emissions, except where natural
gas and/or liquid fuels (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/
[[Page 9458]]
MMBtu) or less are the only fuels combusted, as follows:
* * * * *
(2) For a facility that qualifies under the numerical limit
provisions of Sec. 60.43Da, SO2 emissions are only
monitored as discharged to the atmosphere.
* * * * *
(e) The CEMS under paragraphs (b), (c), and (d) of this section are
operated and data recorded during all periods of operation of the
affected facility including periods of startup, shutdown, and
malfunction, except for CEMS breakdowns, repairs, calibration checks,
and zero and span adjustments.
* * * * *
(k) The procedures specified in paragraphs (k)(1) through (3) of
this section shall be used to determine gross energy output for sources
demonstrating compliance with an output-based standard.
* * * * *
(3) For an affected facility generating process steam in
combination with electrical generation, the gross energy output is
determined according to the definition of ``gross energy output''
specified in Sec. 60.41Da that is applicable to the affected facility.
(l) The owner or operator of an affected facility demonstrating
compliance with an output-based standard shall install, certify,
operate, and maintain a continuous flow monitoring system meeting the
requirements of Performance Specification 6 of appendix B of this part
and the calibration drift (CD) assessment, relative accuracy test audit
(RATA), and reporting provisions of procedure 1 of appendix F of this
part, and record the output of the system, for measuring the volumetric
flow rate of exhaust gases discharged to the atmosphere; or
* * * * *
(t) The owner or operator of an affected facility demonstrating
compliance with the output-based emissions limitation under Sec.
60.42Da shall install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section. An owner or operator of an affected facility
demonstrating compliance with the input-based emissions limit in Sec.
60.42Da may install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section.
(u) * * *
(1) * * *
(iii) At a minimum, non-out-of-control 1-hour CO emissions averages
must be obtained for at least 90 percent of the operating hours on a
30-boiler operating day rolling average basis. The 1-hour averages are
calculated using the data points required in Sec. 60.13(h)(2).
* * * * *
(v) * * *
(4) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec. 60.8, conducted
to demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting
Tool (ERT) (see https://www.epa.gov/ttn/chief/ert/ert tool.html/) or
other compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFire database.
* * * * *
0
20. Section 60.50Da is amended as follows:
0
a. By revising paragraph (b).
0
b. By removing paragraph (g).
0
c. By removing paragraph (h).
0
d. By removing paragraph (i).
Sec. 60.50Da Compliance determination procedures and methods.
* * * * *
(b) In conducting the performance tests to determine compliance
with the PM emissions limits in Sec. 60.42Da, the owner or operator
shall meet the requirements specified in paragraphs (b)(1) through (3)
of this section.
(1) The owner or operator shall measure filterable PM to determine
compliance with the applicable PM emissions limit in Sec. 60.42Da as
specified in paragraphs (b)(1)(i) through (ii) of this section.
(i) The dry basis F factor (O2) procedures in Method 19
of appendix A of this part shall be used to compute the emission rate
of PM.
(ii) For the PM concentration, Method 5 of appendix A of this part
shall be used for an affected facility that does not use a wet FGD. For
an affected facility that uses a wet FGD, Method 5B of appendix A of
this part shall be used downstream of the wet FGD.
(A) The sampling time and sample volume for each run shall be at
least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder
heating system in the sampling train may be set to provide an average
gas temperature of no greater than 160 14 [deg]C (320
25[emsp14][deg]F).
(B) For each particulate run, the emission rate correction factor,
integrated or grab sampling and analysis procedures of Method 3B of
appendix A of this part shall be used to determine the O2
concentration. The O2 sample shall be obtained
simultaneously with, and at the same traverse points as, the
particulate run. If the particulate run has more than 12 traverse
points, the O2 traverse points may be reduced to 12 provided
that Method 1 of appendix A of this part is used to locate the 12
O2 traverse points. If the grab sampling procedure is used,
the O2 concentration for the run shall be the arithmetic
mean of the sample O2 concentrations at all traverse points.
(2) In conjunction with a performance test performed according to
the requirements in paragraph (b)(1) of this section, the owner or
operator of an affected facility for which construction,
reconstruction, or modification commenced after May 3, 2011, shall
measure condensable PM using Method 202 of appendix M of part 51.
(3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
* * * * *
0
21. Section 60.51Da is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (b)(5).
0
c. By revising paragraph (d).
0
d. By removing and reserving paragraph (g).
0
e. By revising paragraph (k).
Sec. 60.51Da Reporting requirements.
(a) For SO2, NOX, PM, and NOX plus
CO emissions, the performance test data from the initial and subsequent
performance test and from the performance evaluation of the continuous
monitors (including the transmissometer) must be reported to the
Administrator.
(b) * * *
(5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates because of
startup, shutdown, or malfunction.
* * * * *
(d) In addition to the applicable requirements in Sec. 60.7, the
owner or operator of an affected facility subject to the opacity limits
in Sec. 60.43c(c) and conducting performance tests using Method 9 of
appendix A-4 of this part shall submit excess emission reports for any
excess emissions from the affected facility that occur during the
reporting period and maintain records according to the requirements
specified in paragraph (d)(1) of this section.
(1) For each performance test conducted using Method 9 of appendix
[[Page 9459]]
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (d)(1)(i) through
(iii) of this section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission
reading certification for each visible emission observer participating
in the performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets.
(2) [Reserved]
* * * * *
(k) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity in lieu of submitting the written reports required under
paragraphs (b) and (i) of this section. The format of each quarterly
electronic report shall be coordinated with the permitting authority.
The electronic report(s) shall be submitted no later than 30 days after
the end of the calendar quarter and shall be accompanied by a
certification statement from the owner or operator, indicating whether
compliance with the applicable emission standards and minimum data
requirements of this subpart was achieved during the reporting period.
Sec. 60.52Da [Amended]
0
22. Section 60.52Da is amended by removing and reserving paragraph (a).
Subpart Db--[Amended]
0
23. Section 60.40b is amended as follows:
0
a. By revising paragraph (c).
0
b. By revising paragraph (h).
0
c. By revising paragraph (i).
0
d. By adding paragraph (1).
0
e. By adding paragraph (m).
Sec. 60.40b Applicability and delegation of authority.
* * * * *
(c) Affected facilities that also meet the applicability
requirements under subpart J or subpart Ja of this part are subject to
the PM and NOX standards under this subpart and the
SO2 standards under subpart J or subpart Ja of this part, as
applicable.
* * * * *
(h) Any affected facility that meets the applicability requirements
and is subject to subpart Ea, subpart Eb, subpart AAAA, or subpart CCCC
of this part is not subject to this subpart.
(i) Affected facilities (i.e., heat recovery steam generators) that
are associated with stationary combustion turbines and that meet the
applicability requirements of subpart KKKK of this part are not subject
to this subpart. This subpart will continue to apply to all other
affected facilities (i.e. heat recovery steam generators with duct
burners) that are capable of combusting more than 29 MW (100 MMBtu/h)
heat input of fossil fuel. If the affected facility (i.e. heat recovery
steam generator) is subject to this subpart, only emissions resulting
from combustion of fuels in the steam generating unit are subject to
this subpart. (The stationary combustion turbine emissions are subject
to subpart GG or KKKK, as applicable, of this part.)
* * * * *
(l) Affected facilities that also meet the applicability
requirements under subpart BB of this part (Standards of Performance
for Kraft Pulp Mills) are subject to the SO2 and
NOX standards under this subpart and the PM standards under
subpart BB.
(m) Temporary boilers are not subject to this subpart.
24. Section 60.41b is amended by revising the definition of
``distillate oil'', and adding the definition of ``temporary boiler''
in alphabetical order to read as follows:
Sec. 60.41b Definitions.
* * * * *
Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec. 60.17),
diesel fuel oil numbers 1 and 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec. 60.17), kerosine, as defined by the American Society of Testing
and Materials in ASTM D3699 (incorporated by reference, see Sec.
60.17), biodiesel as defined by the American Society of Testing and
Materials in ASTM D6751 (incorporated by reference, see Sec. 60.17),
or biodiesel blends as defined by the American Society of Testing and
Materials in ASTM D7467 (incorporated by reference, see Sec. 60.17).
* * * * *
Temporary boiler means any gaseous or liquid fuel-fired steam
generating unit that is designed to, and is capable of, being carried
or moved from one location to another by means of, for example, wheels,
skids, carrying handles, dollies, trailers, or platforms. A steam
generating unit is not a temporary boiler if any one of the following
conditions exists:
(1) The equipment is attached to a foundation.
(2) The steam generating unit or a replacement remains at a
location for more than 180 consecutive days. Any temporary boiler that
replaces a temporary boiler at a location and performs the same or
similar function will be included in calculating the consecutive time
period.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another in an
attempt to circumvent the residence time requirements of this
definition.
* * * * *
0
25. Section 60.43b is amended by revising paragraph (f) to read as
follows:
Sec. 60.43b Standard for particulate matter (PM).
* * * * *
(f) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
combusts coal, oil, wood, or mixtures of these fuels with any other
fuels shall cause to be discharged into the atmosphere any gases that
exhibit greater than 20 percent opacity (6-minute average), except for
one 6-minute period per hour of not more than 27 percent opacity. An
owner or operator of an affected facility that elects to install,
calibrate, maintain, and operate a continuous emissions monitoring
system (CEMS) for measuring PM emissions according to the requirements
of this subpart and is subject to a federally enforceable PM limit of
0.030 lb/MMBtu or less is exempt from the opacity standard specified in
this paragraph.
* * * * *
0
26. Section 60.44b is amended as follows:
0
a. The section heading is revised.
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraph (c).
0
d. By revising paragraph (d).
0
e. By revising paragraph (e).
0
f. By revising paragraph (l)(1).
Sec. 60.44b Standard for nitrogen oxides (NOX).
* * * * *
(b) Except as provided under paragraphs (k) and (l) of this
section, on and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
[[Page 9460]]
simultaneously combusts mixtures of only coal, oil, or natural gas
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain NOX in excess of a limit
determined by the use of the following formula:
* * * * *
(c) Except as provided under paragraph (d) and (l) of this section,
on and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts coal or oil, natural gas (or any combination of
the three), and wood, or any other fuel shall cause to be discharged
into the atmosphere any gases that contain NOX in excess of
the emission limit for the coal, oil, natural gas (or any combination
of the three), combusted in the affected facility, as determined
pursuant to paragraph (a) or (b) of this section. This standard does
not apply to an affected facility that is subject to and in compliance
with a federally enforceable requirement that limits operation of the
affected facility to an annual capacity factor of 10 percent (0.10) or
less for coal, oil, natural gas (or any combination of the three).
(d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts natural gas and/or distillate oil with a
potential SO2 emissions rate of 26 ng/J (0.060 lb/MMBtu) or
less with wood, municipal-type solid waste, or other solid fuel, except
coal, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain NOX in excess of
130 ng/J (0.30 lb/MMBtu) heat input unless the affected facility has an
annual capacity factor for natural gas, distillate oil, or a mixture of
these fuels of 10 percent (0.10) or less and is subject to a federally
enforceable requirement that limits operation of the affected facility
to an annual capacity factor of 10 percent (0.10) or less for natural
gas, distillate oil, or a mixture of these fuels.
(e) Except as provided under paragraph (l) of this section, on and
after the date on which the initial performance test is completed or is
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that simultaneously
combusts only coal, oil, or natural gas with byproduct/waste shall
cause to be discharged into the atmosphere any gases that contain
NOX in excess of the emission limit determined by the
following formula unless the affected facility has an annual capacity
factor for coal, oil, and natural gas of 10 percent (0.10) or less and
is subject to a federally enforceable requirement that limits operation
of the affected facility to an annual capacity factor of 10 percent
(0.10) or less:
* * * * *
(l) * * *
(1) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts coal, oil, or natural gas (or any combination of the three),
alone or with any other fuels. The affected facility is not subject to
this limit if it is subject to and in compliance with a federally
enforceable requirement that limits operation of the facility to an
annual capacity factor of 10 percent (0.10) or less for coal, oil, and
natural gas (or any combination of the three); or
* * * * *
0
27. Section 60.46b is amended by revising paragraph (j)(14) to read as
follows:
Sec. 60.46b Compliance and performance test methods and procedures
for particulate matter and nitrogen oxides.
* * * * *
(j) * * *
(14) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec. 60.8, conducted
to demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting
Tool (ERT) (see https://www.epa.gov/ttn/chief/ert/ert_tool.html/) or
other compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFIRE database.
0
28. Section 60.48b is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraphs (a)(1)(i) through (iii) .
0
c. By revising paragraph (a)(2)(ii).
0
d. By revising paragraph (j) introductory text.
0
e. By revising paragraph (j)(5).
0
f. By revising paragraph (j)(6).
0
g. By adding paragraph (j)(7).
0
h. By adding paragraph (l).
Sec. 60.48b Emission monitoring for particulate matter and nitrogen
oxides.
(a) Except as provided in paragraph (j) of this section, the owner
or operator of an affected facility subject to the opacity standard
under Sec. 60.43b shall install, calibrate, maintain, and operate a
continuous opacity monitoring systems (COMS) for measuring the opacity
of emissions discharged to the atmosphere and record the output of the
system. The owner or operator of an affected facility subject to an
opacity standard under Sec. 60.43b and meeting the conditions under
paragraphs (j)(1), (2), (3), (4), (5), or (6) of this section who
elects not to use a COMS shall conduct a performance test using Method
9 of appendix A-4 of this part and the procedures in Sec. 60.11 to
demonstrate compliance with the applicable limit in Sec. 60.43b by
April 29, 2011, within 45 days of stopping use of an existing COMS, or
within 180 days after initial startup of the facility, whichever is
later, and shall comply with either paragraphs (a)(1), (a)(2), or
(a)(3) of this section. The observation period for Method 9 of appendix
A-4 of this part performance tests may be reduced from 3 hours to 60
minutes if all 6-minute averages are less than 10 percent and all
individual 15-second observations are less than or equal to 20 percent
during the initial 60 minutes of observation.
(1) * * *
(i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
(ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted or within 45 days of the next day that fuel with an
opacity standard is combusted, whichever is later;
(iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
* * * * *
(2) * * *
(ii) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an
[[Page 9461]]
opacity standard is applicable. If any visible emissions are observed,
daily observations shall be resumed.
* * * * *
(j) The owner or operator of an affected facility that meets the
conditions in either paragraph (j)(1), (2), (3), (4), (5), (6), or (7)
of this section is not required to install or operate a COMS if:
* * * * *
(5) The affected facility uses a bag leak detection system to
monitor the performance of a fabric filter (baghouse) according to the
most current requirements in section Sec. 60.48Da of this part; or
(6) The affected facility uses an ESP as the primary PM control
device and uses an ESP predictive model to monitor the performance of
the ESP developed in accordance and operated according to the most
current requirements in section Sec. 60.48Da of this part; or
(7) The affected facility burns only gaseous fuels or fuel oils
that contain less than or equal to 0.30 weight percent sulfur and
operates according to a written site-specific monitoring plan approved
by the permitting authority. This monitoring plan must include
procedures and criteria for establishing and monitoring specific
parameters for the affected facility indicative of compliance with the
opacity standard.
* * * * *
(l) An owner or operator of an affected facility that is subject to
an opacity standard under Sec. 60.43b(f) is not required to operate a
COMS provided that the unit burns only gaseous fuels and/or liquid
fuels (excluding residue oil) with a potential SO2 emissions
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates
according to a written site-specific monitoring plan approved by the
permitting authority is not required to operate a COMS. This monitoring
plan must include procedures and criteria for establishing and
monitoring specific parameters for the affected facility indicative of
compliance with the opacity standard. For testing performed as part of
this site-specific monitoring plan, the permitting authority may
require as an alternative to the notification and reporting
requirements specified in Sec. Sec. 60.8 and 60.11 that the owner or
operator submit any deviations with the excess emissions report
required under Sec. 60.49b(h).
0
29. Section 60.49b is amended by revising paragraph (r)(1) to read as
follows.
Sec. 60.49b Reporting and recordkeeping requirements.
* * * * *
(r) * * *
(1) The owner or operator of an affected facility who elects to
demonstrate that the affected facility combusts only very low sulfur
oil, natural gas, wood, a mixture of these fuels, or any of these fuels
(or a mixture of these fuels) in combination with other fuels that are
known to contain an insignificant amount of sulfur in Sec. 60.42b(j)
or Sec. 60.42b(k) shall obtain and maintain at the affected facility
fuel receipts (such as a current, valid purchase contract, tariff
sheet, or transportation contract) from the fuel supplier that certify
that the oil meets the definition of distillate oil and gaseous fuel
meets the definition of natural gas as defined in Sec. 60.41b and the
applicable sulfur limit. For the purposes of this section, the
distillate oil need not meet the fuel nitrogen content specification in
the definition of distillate oil. Reports shall be submitted to the
Administrator certifying that only very low sulfur oil meeting this
definition, natural gas, wood, and/or other fuels that are known to
contain insignificant amounts of sulfur were combusted in the affected
facility during the reporting period; or
* * * * *
Subpart Dc--[Amended]
0
30. Section 60.40c is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (e).
0
c. By revising paragraph (f).
0
d. By revising paragraph (g).
0
e. By adding paragraph (h).
0
f. By adding paragraph (i).
Sec. 60.40c Applicability and delegation of authority.
(a) Except as provided in paragraphs (d), (e), (f), and (g) of this
section, the affected facility to which this subpart applies is each
steam generating unit for which construction, modification, or
reconstruction is commenced after June 9, 1989 and that has a maximum
design heat input capacity of 29 megawatts (MW) (100 million British
thermal units per hour (MMBtu/h)) or less, but greater than or equal to
2.9 MW (10 MMBtu/h).
* * * * *
(e) Affected facilities (i.e. heat recovery steam generators and
fuel heaters) that are associated with stationary combustion turbines
and meet the applicability requirements of subpart KKKK of this part
are not subject to this subpart. This subpart will continue to apply to
all other heat recovery steam generators, fuel heaters, and other
affected facilities that are capable of combusting more than or equal
to 2.9 MW (10 MMBtu/h) heat input of fossil fuel but less than or equal
to 29 MW (100 MMBtu/h) heat input of fossil fuel. If the heat recovery
steam generator, fuel heater, or other affected facility is subject to
this subpart, only emissions resulting from combustion of fuels in the
steam generating unit are subject to this subpart. (The stationary
combustion turbine emissions are subject to subpart GG or KKKK, as
applicable, of this part.)
(f) Any affected facility that meets the applicability requirements
of and is subject to subpart AAAA or subpart CCCC of this part is not
subject to this subpart.
(g) Any facility that meets the applicability requirements and is
subject to an EPA approved State or Federal section 111(d)/129 plan
implementing subpart BBBB of this part is not subject to this subpart.
(h) Affected facilities that also meet the applicability
requirements under subpart J or subpart Ja of this part are subject to
the PM and NOX standards under this subpart and the
SO2 standards under subpart J or subpart Ja of this part, as
applicable.
(i) Temporary boilers are not subject to this subpart.
0
31. Section 60.41c is amended as follows:
0
a. By removing the definition of ``Cogeneration.''
0
b. By revising the definition of ``Distillate oil.''
0
c. By adding a definition of ``Temporary boiler'' in alphabetical
order.
Sec. 60.41c Definitions.
* * * * *
Distillate oil means fuel oil that complies with the specifications
for fuel oil numbers 1 or 2, as defined by the American Society for
Testing and Materials in ASTM D396 (incorporated by reference, see
Sec. 60.17), diesel fuel oil numbers 1 or 2, as defined by the
American Society for Testing and Materials in ASTM D975 (incorporated
by reference, see Sec. 60.17), kerosine, as defined by the American
Society of Testing and Materials in ASTM D3699 (incorporated by
reference, see Sec. 60.17), biodiesel as defined by the American
Society of Testing and Materials in ASTM D6751 (incorporated by
reference, see Sec. 60.17), or biodiesel blends as defined by the
American Society of Testing and Materials in ASTM D7467 (incorporated
by reference, see Sec. 60.17).
* * * * *
[[Page 9462]]
Temporary boiler means a steam generating unit that combusts
natural gas or distillate oil with a potential SO2 emissions
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed
to, and is capable of, being carried or moved from one location to
another by means of, for example, wheels, skids, carrying handles,
dollies, trailers, or platforms. A steam generating unit is not a
temporary boiler if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The steam generating unit or a replacement remains at a
location for more than 180 consecutive days. Any temporary boiler that
replaces a temporary boiler at a location and performs the same or
similar function will be included in calculating the consecutive time
period.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another in an
attempt to circumvent the residence time requirements of this
definition.
* * * * *
0
32. Section 60.42c is amended as follows:
0
a. By revising paragraph (c)(1) and (3).
0
b. By revising paragraph (d).
0
c. By revising paragraph (e)(1)(ii).
0
d. By revising paragraph (h) introductory text.
0
e. By revising paragraph (h)(3).
0
f. By adding paragraph (h)(4).
Sec. 60.42c Standard for sulfur dioxide (SO2).
* * * * *
(c) * * *
(1) Affected facilities that have a heat input capacity of 22 MW
(75 MMBtu/h) or less;
* * * * *
(3) Affected facilities located in a noncontinental area; or
* * * * *
(d) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
oil shall cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 215 ng/J
(0.50 lb/MMBtu) heat input from oil; or, as an alternative, no owner or
operator of an affected facility that combusts oil shall combust oil in
the affected facility that contains greater than 0.5 weight percent
sulfur. The percent reduction requirements are not applicable to
affected facilities under this paragraph.
(e) * * *
(1) * * *
(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/h); and
* * * * *
(h) For affected facilities listed under paragraphs (h)(1), (2),
(3), or (4) of this section, compliance with the emission limits or
fuel oil sulfur limits under this section may be determined based on a
certification from the fuel supplier, as described under Sec.
60.48c(f), as applicable.
* * * * *
(3) Coal-fired affected facilities with heat input capacities
between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
(4) Other fuels-fired affected facilities with heat input
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
* * * * *
0
33. Section 60.43c is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraph (c).
0
d. By revising paragraphs (e)(1), (3), and (4).
Sec. 60.43c Standard for particulate matter (PM).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, that combusts coal or combusts mixtures of coal with
other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/h) or
greater, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of the following
emission limits:
* * * * *
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, that combusts wood or combusts mixtures of wood with
other fuels (except coal) and has a heat input capacity of 8.7 MW (30
MMBtu/h) or greater, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain PM in excess of the
following emissions limits:
* * * * *
(c) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/h)
or greater shall cause to be discharged into the atmosphere from that
affected facility any gases that exhibit greater than 20 percent
opacity (6-minute average), except for one 6-minute period per hour of
not more than 27 percent opacity. Owners and operators of an affected
facility that elect to install, calibrate, maintain, and operate a
continuous emissions monitoring system (CEMS) for measuring PM
emissions according to the requirements of this subpart and are subject
to a federally enforceable PM limit of 0.030 lb/MMBtu or less are
exempt from the opacity standard specified in this paragraph (c).
* * * * *
(e)(1) On and after the date on which the initial performance test
is completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences construction, reconstruction, or modification after February
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels and has a heat input
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided
in paragraphs (e)(2), (e)(3), and (e)(4) of this section.
* * * * *
(3) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on an annual basis and has a heat input
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(4) An owner or operator of an affected facility that commences
construction, reconstruction, or modification after February 28, 2005,
and that combusts only oil that contains no more than 0.50 weight
percent sulfur
[[Page 9463]]
or a mixture of 0.50 weight percent sulfur oil with other fuels not
subject to a PM standard under Sec. 60.43c and not using a post-
combustion technology (except a wet scrubber) to reduce PM or
SO2 emissions is not subject to the PM limit in this
section.
0
34. Section 60.45c is amended as follows:
0
a. By revising paragraph (c)(14).
0
b. By revising paragraph (d).
Sec. 60.45c Compliance and performance test methods and procedures
for particulate matter.
* * * * *
(c) * * *
(14) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec. 60.8, conducted
to demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting
Tool (ERT) (see https://www.epa.gov/ttn/chief/ert/ert tool.html/) or
other compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFIRE database.
(d) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec. 60.43c(e)(4) shall follow the
applicable procedures under Sec. 60.48c(f). For residual oil-fired
affected facilities, fuel supplier certifications are only allowed for
facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30
MMBtu/h).
0
35. Section 60.47c is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraphs (a)(1)(i) through (iii).
0
c. By revising paragraph (a)(2)(ii).
0
d. By revising paragraph (f).
0
e. By removing paragraph (g).
Sec. 60.47c Emission monitoring for particulate matter.
(a) Except as provided in paragraphs (c), (d), (e), and (f) of this
section, the owner or operator of an affected facility combusting coal,
oil, or wood that is subject to the opacity standards under Sec.
60.43c shall install, calibrate, maintain, and operate a continuous
opacity monitoring system (COMS) for measuring the opacity of the
emissions discharged to the atmosphere and record the output of the
system. The owner or operator of an affected facility subject to an
opacity standard in Sec. 60.43c(c) that is not required to use a COMS
due to paragraphs (c), (d), (e), or (f) of this section that elects not
to use a COMS shall conduct a performance test using Method 9 of
appendix A-4 of this part and the procedures in Sec. 60.11 to
demonstrate compliance with the applicable limit in Sec. 60.43c by
April 29, 2011, within 45 days of stopping use of an existing COMS, or
within 180 days after initial startup of the facility, whichever is
later, and shall comply with either paragraphs (a)(1), (a)(2), or
(a)(3) of this section. The observation period for Method 9 of appendix
A-4 of this part performance tests may be reduced from 3 hours to 60
minutes if all 6-minute averages are less than 10 percent and all
individual 15-second observations are less than or equal to 20 percent
during the initial 60 minutes of observation.
(1) * * *
(i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
(ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted or within 45 days of the next day that fuel with an
opacity standard is combusted, whichever is later;
(iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
* * * * *
(2) * * *
(ii) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
* * * * *
(f) An owner or operator of an affected facility that is subject to
an opacity standard in Sec. 60.43c(c) is not required to operate a
COMS provided that the affected facility meets the conditions in either
paragraphs (f)(1), (2), or (3) of this section.
(1) The affected facility uses a fabric filter (baghouse) as the
primary PM control device and, the owner or operator operates a bag
leak detection system to monitor the performance of the fabric filter
according to the requirements in section Sec. 60.48Da of this part.
(2) The affected facility uses an ESP as the primary PM control
device, and the owner or operator uses an ESP predictive model to
monitor the performance of the ESP developed in accordance and operated
according to the requirements in section Sec. 60.48Da of this part.
(3) The affected facility burns only gaseous fuels and/or fuel oils
that contain no greater than 0.5 weight percent sulfur, and the owner
or operator operates the unit according to a written site-specific
monitoring plan approved by the permitting authority. This monitoring
plan must include procedures and criteria for establishing and
monitoring specific parameters for the affected facility indicative of
compliance with the opacity standard. For testing performed as part of
this site-specific monitoring plan, the permitting authority may
require as an alternative to the notification and reporting
requirements specified in Sec. Sec. 60.8 and 60.11 that the owner or
operator submit any deviations with the excess emissions report
required under Sec. 60.48c(c).
Subpart HHHH--[Removed and Reserved]
0
36. Subpart HHHH is removed and reserved.
PART 63--[AMENDED]
0
37. The authority citation for 40 CFR Part 63 continues to read as
follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
0
38. Section 63.14 is amended as follows:
0
a. By adding paragraphs (b)(19) and (20).
0
b. By adding paragraphs (b)(22) and (23).
0
c. By adding paragraphs (b)(69) through (72).
0
d. By revising paragraph (i)(1).
Sec. 63.14 Incorporation by reference.
* * * * *
(b) * * *
[[Page 9464]]
(19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water
in Petroleum Products and Bituminous Materials by Distillation,
approved May 1, 2010, IBR approved for Sec. 63.10005(i)(4)(i).
(20) ASTM Method D388-05, Standard Classification of Coals by Rank,
approved September 15, 2005, IBR approved for Sec. 63.10042.
* * * * *
(22) ASTM Method D396-10, Standard Specification for Fuel Oils,
including Appendix X1, approved October 1, 2010, IBR approved for Sec.
63.10042.
(23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by
Distillation, including Annex A1 and Appendix X1, approved June 1,
2011, IBR approved for Sec. 63.10005(i)(4)(ii).
* * * * *
(69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, including Annex A1,
approved June 1, 2011, IBR approved for Sec. 63.10005(i)(4)(iv).
(70) ASTM D4177-95 (Reapproved 2010), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, including
Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010,
IBR approved for Sec. 63.10005(i)(4)(iii).
(71) ASTM D6348-03 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1
through A8, approved October 1, 2010, IBR approved for table 1 to
subpart UUUUU of this part, table 2 to subpart UUUUU of this part,
table 5 to subpart UUUUU of this part, and appendix B to subpart UUUUU
of this part.
(72) ASTM D6784-02 (Reapproved 2008), Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),
approved April 1, 2008, IBR approved for table 5 to subpart UUUUU of
this part, and appendix A to subpart UUUUU of this part.
* * * * *
(i) * * *
(1) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [part
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.
63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 63.3360(e)(1)(iii),
63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3),
63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2),
63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii)
and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii),
63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, table 1 to
subpart ZZZZZ of this part, table 4 to subpart JJJJJJ of this part, and
table 5 to subpart UUUUU of this part.
* * * * *
0
39. Part 63 is amended by adding subpart UUUUU to read as follows:
Subpart UUUUU--National Emission Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating
Units
Sec.
What This Subpart Covers
63.9980 What is the purpose of this subpart?
63.9981 Am I subject to this subpart?
63.9982 What is the affected source of this subpart?
63.9983 Are any EGUs not subject to this subpart?
63.9984 When do I have to comply with this subpart?
63.9985 What is a new EGU?
Emission Limitations and Work Practice Standards
63.9990 What are the subcategories of EGUs?
63.9991 What emission limitations, work practice standards, and
operating limits must I meet?
General Compliance Requirements
63.10000 What are my general requirements for complying with this
subpart?
63.10001 Affirmative defense for exceedence of emission limit during
malfunction.
Testing and Initial Compliance Requirements
63.10005 What are my initial compliance requirements and by what
date must I conduct them?
63.10006 When must I conduct subsequent performance tests or tune-
ups?
63.10007 What methods and other procedures must I use for the
performance tests?
63.10008 [Reserved]
63.10009 May I use emissions averaging to comply with this subpart?
63.10010 What are my monitoring, installation, operation, and
maintenance requirements?
63.10011 How do I demonstrate initial compliance with the emission
limitations and work practice standards?
Continuous Compliance Requirements
63.10020 How do I monitor and collect data to demonstrate continuous
compliance?
63.10021 How do I demonstrate continuous compliance with the
emission limitations, operating limits, and work practice standards?
63.10022 How do I demonstrate continuous compliance under the
emissions averaging provision?
63.10023 How do I establish my PM CPMS operating limit and determine
compliance with it?
Notifications, Reports, and Records
63.10030 What notifications must I submit and when?
63.10031 What reports must I submit and when?
63.10032 What records must I keep?
63.10033 In what form and how long must I keep my records?
Other Requirements and Information
63.10040 What parts of the General Provisions apply to me?
63.10041 Who implements and enforces this subpart?
63.10042 What definitions apply to this subpart?
Tables to Subpart UUUUU of Part 63
Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or
Reconstructed EGUs
Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing
EGUs
Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
Table 5 to Subpart UUUUU of Part 63--Performance Testing
Requirements
Table 6 to Subpart UUUUU of Part 63--Establishing PM CPMS Operating
Limits
Table 7 to Subpart UUUUU of Part 63--Demonstrating Continuous
Compliance
Table 8 to Subpart UUUUU of Part 63--Reporting Requirements
Table 9 to Subpart UUUUU of Part 63--Applicability of General
Provisions to Subpart UUUUU
Appendix A to Subpart UUUUU--Hg Monitoring Provisions
Appendix B to Subpart UUUUU--HCl and HF Monitoring Provisions
Subpart UUUUU--National Emission Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating
Units
What This Subpart Covers
Sec. 63.9980 What is the purpose of this subpart?
This subpart establishes national emission limitations and work
practice standards for hazardous air pollutants (HAP) emitted from
coal- and oil-fired electric utility steam generating units (EGUs) as
defined in Sec. 63.10042 of this subpart. This subpart also
establishes requirements to demonstrate initial and continuous
compliance with the emission limitations.
Sec. 63.9981 Am I subject to this subpart?
You are subject to this subpart if you own or operate a coal-fired
EGU or an oil-fired EGU as defined in Sec. 63.10042 of this subpart.
[[Page 9465]]
Sec. 63.9982 What is the affected source of this subpart?
(a) This subpart applies to each individual or group of two or more
new, reconstructed, and existing affected source(s) as described in
paragraphs (a)(1) and (2) of this section within a contiguous area and
under common control.
(1) The affected source of this subpart is the collection of all
existing coal- or oil-fired EGUs, as defined in 63.10042, within a
subcategory.
(2) The affected source of this subpart is each new or
reconstructed coal- or oil-fired EGU as defined in 63.10042.
(b) An EGU is new if you commence construction of the coal- or oil-
fired EGU after May 3, 2011, and you meet the applicability criteria at
the time you commence construction.
(c) An EGU is reconstructed if you meet the reconstruction criteria
as defined in Sec. 63.2, you commence reconstruction after May 3,
2011, and you meet the applicability criteria at the time you commence
reconstruction.
(d) An EGU is existing if it is not new or reconstructed. An
existing electric steam generating unit that meets the applicability
requirements after the effective date of this final rule due to a
change process (e.g., fuel or utilization) is considered to be an
existing source under this subpart.
Sec. 63.9983 Are any EGUs not subject to this subpart?
The types of electric steam generating units listed in paragraphs
(a) through (d) of this section are not subject to this subpart.
(a) Any unit designated as a stationary combustion turbine, other
than an integrated gasification combined cycle (IGCC) unit, covered by
40 CFR part 63, subpart YYYY.
(b) Any electric utility steam generating unit that is not a coal-
or oil-fired EGU and combusts natural gas for more than 10.0 percent of
the average annual heat input during any 3 calendar years or for more
than 15.0 percent of the annual heat input during any calendar year.
(c) Any electric utility steam generating unit that has the
capability of combusting more than 25 MW of coal or oil but did not
fire coal or oil for more than 10.0 percent of the average annual heat
input during any 3 calendar years or for more than 15.0 percent of the
annual heat input during any calendar year. Heat input means heat
derived from combustion of fuel in an EGU and does not include the heat
derived from preheated combustion air, recirculated flue gases or
exhaust gases from other sources (such as stationary gas turbines,
internal combustion engines, and industrial boilers).
(d) Any electric steam generating unit combusting solid waste is a
solid waste incineration unit subject to standards established under
sections 129 and 111 of the Clean Air Act.
Sec. 63.9984 When do I have to comply with this subpart?
(a) If you have a new or reconstructed EGU, you must comply with
this subpart by April 16, 2012 or upon startup of your EGU, whichever
is later, and as further provided for in Sec. 63.10005(g).
(b) If you have an existing EGU, you must comply with this subpart
no later than April 16, 2015.
(c) You must meet the notification requirements in Sec. 63.10030
according to the schedule in Sec. 63.10030 and in subpart A of this
part. Some of the notifications must be submitted before you are
required to comply with the emission limits and work practice standards
in this subpart.
(d) An electric steam generating unit that does not meet the
definition of an EGU subject to this subpart on April 16, 2012 for new
sources or April 16, 2015 for existing sources must comply with the
applicable existing source provisions of this subpart on the date such
unit meets the definition of an EGU subject to this subpart.
(e) If you own or operate an electric steam generating unit that is
exempted from this subpart under Sec. 63.9983(d), if the manner of
operating the unit changes such that the combustion of waste is
discontinued and the unit becomes a coal-fired or oil-fired EGU (as
defined in Sec. 63.10042), you must be in compliance with this subpart
on April 16, 2015 or on the effective date of the switch from waste
combustion to coal or oil combustion, whichever is later.
(f) You must demonstrate that compliance has been achieved, by
conducting the required performance tests and other activities, no
later than 180 days after the applicable date in paragraph (a), (b),
(c), (d), or (e) of this section.
Sec. 63.9985 What is a new EGU?
(a) A new EGU is an EGU that meets any of the criteria specified in
paragraph (a)(1) through (a)(2) of this section.
(1) An EGU that commenced construction after May 3, 2011.
(2) An EGU that commenced reconstruction or modification after May
3, 2011.
(b) [Reserved]
Emission Limitations and Work Practice Standards
Sec. 63.9990 What are the subcategories of EGUs?
(a) Coal-fired EGUs are subcategorized as defined in paragraphs
(a)(1) through (a)(2) of this section and as defined in Sec. 63.10042.
(1) EGUs designed for coal with a heating value greater than or
equal to 8,300 Btu/lb, and
(2) EGUs designed for low rank virgin coal.
(b) Oil-fired EGUs are subcategorized as noted in paragraphs (b)(1)
through (b)(4) of this section and as defined in Sec. 63.10042.
(1) Continental liquid oil-fired EGUs
(2) Non-continental liquid oil-fired EGUs,
(3) Limited-use liquid oil-fired EGUs, and
(4) EGUs designed to burn solid oil-derived fuel.
(c) IGCC units combusting either gasified coal or gasified solid
oil-derived fuel. For purposes of compliance, monitoring,
recordkeeping, and reporting requirements in this subpart, IGCC units
are subject in the same manner as coal-fired units and solid oil-
derived fuel-fired units, unless otherwise indicated.
Sec. 63.9991 What emission limitations, work practice standards, and
operating limits must I meet?
(a) You must meet the requirements in paragraphs (a)(1) and (2) of
this section. You must meet these requirements at all times.
(1) You must meet each emission limit and work practice standard in
Table 1 through 3 to this subpart that applies to your EGU, for each
EGU at your source, except as provided under Sec. 63.10009.
(2) You must meet each operating limit in Table 4 to this subpart
that applies to your EGU.
(b) As provided in Sec. 63.6(g), the Administrator may approve use
of an alternative to the work practice standards in this section.
(c) You may use the alternate SO2 limit in Tables 1 and
2 to this subpart only if your coal-fired EGU:
(1) Has a system using wet or dry flue gas desulfurization
technology and SO2 continuous emissions monitoring system
(CEMS) installed on the unit; and
(2) At all times, you operate the wet or dry flue gas
desulfurization technology installed on the unit consistent with Sec.
63.10000(b).
[[Page 9466]]
General Compliance Requirements
Sec. 63.10000 What are my general requirements for complying with
this subpart?
(a) You must be in compliance with the emission limits and
operating limits in this subpart. These limits apply to you at all
times except during periods of startup and shutdown; however, for coal-
fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs, you are
required to meet the work practice requirements in Table 3 to this
subpart during periods of startup or shutdown.
(b) At all times you must operate and maintain any affected source,
including associated air pollution control equipment and monitoring
equipment, in a manner consistent with safety and good air pollution
control practices for minimizing emissions. Determination of whether
such operation and maintenance procedures are being used will be based
on information available to the EPA Administrator which may include,
but is not limited to, monitoring results, review of operation and
maintenance procedures, review of operation and maintenance records,
and inspection of the source.
(c)(1) For coal-fired units and solid oil-derived fuel-fired units,
initial performance testing is required for all pollutants, to
demonstrate compliance with the applicable emission limits.
(i) For a coal-fired or solid oil-derived fuel-fired EGU or IGCC
EGU, you may conduct the initial performance testing in accordance with
Sec. 63.10005(h), to determine whether the unit qualifies as a low
emitting EGU (LEE) for one or more applicable emissions limits, with
two exceptions:
(A) You may not pursue the LEE option if your coal-fired, IGCC, or
solid oil-derived fuel-fired EGU is equipped with an acid gas scrubber
and has a main stack and bypass stack exhaust configuration, and
(B) You may not pursue the LEE option for Hg if your coal-fired,
solid oil-fired fuel fired EGU or IGCC EGU is new.
(ii) For a qualifying LEE for Hg emissions limits, you must conduct
a 30-day performance test using Method 30B at least once every 12
calendar months to demonstrate continued LEE status.
(iii) For a qualifying LEE of any other applicable emissions
limits, you must conduct a performance test at least once every 36
calendar months to demonstrate continued LEE status.
(iv) If your coal-fired or solid oil-derived fuel-fired EGU or IGCC
EGU does not qualify as a LEE for total non-mercury HAP metals,
individual non-mercury HAP metals, or filterable particulate matter
(PM), you must demonstrate compliance through an initial performance
test and you must monitor continuous performance through either use of
a particulate matter continuous parametric monitoring system (PM CPMS),
a PM CEMS, or compliance performance testing repeated quarterly.
(A) If you elect to use PM CPMS, you will establish a site-specific
operating limit corresponding to the results of the performance test
demonstrating compliance with the pollutant with which you choose to
comply: total non-mercury HAP metals, individual non-mercury HAP metals
or filterable PM. You will use the PM CPMS to demonstrate continuous
compliance with this operating limit. If you elect to use a PM CPMS,
you must repeat the performance test annually for the selected
pollutant limit and reassess and adjust the site-specific operating
limit in accordance with the results of the performance test.
(B) You may also opt to install and operate a particulate matter
CEMS certified in accordance with Performance Specification 11 and
Procedure 2 of 40 CFR part 60, Appendices B and F, respectively, in
accordance with Sec. 63.10010(i).
(v) If your coal-fired or solid oil-derived fuel-fired EGU does not
qualify as a LEE for hydrogen chloride (HCl), you may demonstrate
initial and continuous compliance through use of an HCl CEMS, installed
and operated in accordance with Appendix B to this subpart. As an
alternative to HCl CEMS, you may demonstrate initial and continuous
compliance by conducting an initial and periodic quarterly performance
stack test for HCl. If your EGU uses wet or dry flue gas
desulfurization technology (this includes limestone injection into a
fluidized bed combustion unit), you may apply a second alternative to
HCl CEMS by installing and operating a sulfur dioxide (SO2)
CEMS installed and operated in accordance with part 75 of this chapter
to demonstrate compliance with the applicable SO2 emissions
limit.
(vi) If your coal-fired or solid oil-derived fuel-fired EGU does
not qualify as a LEE for Hg, you must demonstrate initial and
continuous compliance through use of a Hg CEMS or a sorbent trap
monitoring system, in accordance with appendix A to this subpart.
(2) For liquid oil-fired EGUs, except limited use liquid oil-fired
EGUs, initial performance testing is required for all pollutants, to
demonstrate compliance with the applicable emission limits.
(i) For an existing liquid oil-fired unit, you may conduct the
performance testing in accordance with Sec. 63.10005(h), to determine
whether the unit qualifies as a LEE for one or more pollutants. For a
qualifying LEE for Hg emissions limits, you must conduct a 30-day
performance test using Method 30B at least once every 12 calendar
months to demonstrate continued LEE status. For a qualifying LEE of any
other applicable emissions limits, you must conduct a performance test
at least once every 36 calendar months to demonstrate continued LEE
status.
(ii) If your existing liquid oil-fired unit does not qualify as a
LEE for total HAP metals (including mercury), individual metals
(including mercury), or filterable PM you must demonstrate compliance
through an initial performance test and you must monitor continuous
performance through either use of a PM CPMS, a PM CEMS, or performance
testing conducted quarterly.
(A) If you elect to use PM CPMS, you will establish a site-specific
operating limit corresponding to the results of the performance test
demonstrating compliance with the pollutant with which you choose to
comply: total HAP metals, individual HAP metals, or filterable PM. You
will use the PM CPMS to demonstrate continuous compliance with this
operating limit. If you elect to use a PM CPMS, you must repeat the
performance test at least annually for the selected pollutant limit and
reassess and adjust the site-specific operating limit in accordance
with the results of the performance test.
(B) If you elect to use a PM CEMS, you will use the CEMS in
accordance with Sec. 63.10010(i) to demonstrate initial and continuous
compliance with the filterable PM emission limit.
(iii) If your existing liquid oil-fired unit does not qualify as a
LEE for hydrogen chloride (HCl) or for hydrogen fluoride (HF), you may
demonstrate initial and continuous compliance through use of an HCl
CEMS, an HF CEMS, or an HCl and HF CEMS, installed and operated in
accordance with Appendix B to this rule. As an alternative to HCl CEMS,
HF CEMS, or HCl and HF CEMS, you may demonstrate initial and continuous
compliance by conducting periodic quarterly performance stack tests for
HCl and HF. If you elect to demonstrate compliance through quarterly
performance testing, then you must also develop a site-specific
monitoring plan to ensure that the operations of the unit remain
consistent with those during the performance test. As another
alternative, you may measure or obtain, and keep
[[Page 9467]]
records of, fuel moisture content; as long as fuel moisture does not
exceed 1.0 percent by weight, you need not conduct other HCl or HF
monitoring or testing.
(iv) If your unit qualifies as a limited-use liquid oil-fired as
defined in Sec. 63.10042, then you are not subject to the emission
limits in Tables 1 and 2, but must comply with the performance tune-up
work practice requirements in Table 3.
(d)(1) If you demonstrate compliance with any applicable emissions
limit through use of a continuous monitoring system (CMS), where a CMS
includes a continuous parameter monitoring system (CPMS) as well as a
continuous emissions monitoring system (CEMS), you must develop a site-
specific monitoring plan and submit this site-specific monitoring plan,
if requested, at least 60 days before your initial performance
evaluation (where applicable) of your CMS. This requirement also
applies to you if you petition the Administrator for alternative
monitoring parameters under Sec. 63.8(f). This requirement to develop
and submit a site-specific monitoring plan does not apply to affected
sources with existing monitoring plans that apply to CEMS and CPMS
prepared under Appendix B to part 60 or part 75 of this chapter, and
that meet the requirements of Sec. 63.10010. Using the process
described in Sec. 63.8(f)(4), you may request approval of monitoring
system quality assurance and quality control procedures alternative to
those specified in this paragraph of this section and, if approved,
include those in your site-specific monitoring plan. The monitoring
plan must address the provisions in paragraphs (d)(2) through (5) of
this section.
(2) The site-specific monitoring plan shall include the information
specified in paragraphs (d)(5)(i) through (d)(5)(vii) of this section.
Alternatively, the requirements of paragraphs (d)(5)(i) through
(d)(5)(vii) are considered to be met for a particular CMS or sorbent
trap monitoring system if:
(i) The CMS or sorbent trap monitoring system is installed,
certified, maintained, operated, and quality-assured either according
to part 75 of this chapter, or appendix A or B to this subpart; and
(ii) The recordkeeping and reporting requirements of part 75 of
this chapter, or appendix A or B to this subpart, that pertain to the
CMS are met.
(3) If requested by the Administrator, you must submit the
monitoring plan (or relevant portion of the plan) at least 60 days
before the initial performance evaluation of a particular CMS, except
where the CMS has already undergone a performance evaluation that meets
the requirements of Sec. 63.10010 (e.g., if the CMS was previously
certified under another program).
(4) You must operate and maintain the CMS according to the site-
specific monitoring plan.
(5) The provisions of the site-specific monitoring plan must
address the following items:
(i) Installation of the CEMS or sorbent trap monitoring system
sampling probe or other interface at a measurement location relative to
each affected process unit such that the measurement is representative
of control of the exhaust emissions (e.g., on or downstream of the last
control device). See Sec. 63.10010(a) for further details. For CPMS
installations, follow the procedures in Sec. 63.10010(h).
(ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems.
(iii) Schedule for conducting initial and periodic performance
evaluations.
(iv) Performance evaluation procedures and acceptance criteria
(e.g., calibrations), including ongoing data quality assurance
procedures in accordance with the general requirements of Sec.
63.8(d).
(v) On-going operation and maintenance procedures, in accordance
with the general requirements of Sec. Sec. 63.8(c)(1)(ii), (c)(3), and
(c)(4)(ii).
(vi) Conditions that define a CMS that is out of control consistent
with Sec. 63.8(c)(7)(i) and for responding to out of control periods
consistent with Sec. Sec. 63.8(c)(7)(ii) and (c)(8).
(vii) On-going recordkeeping and reporting procedures, in
accordance with the general requirements of Sec. Sec. 63.10(c),
(e)(1), and (e)(2)(i), or as specifically required under this subpart.
(e) As part of your demonstration of continuous compliance, you
must perform periodic tune-ups of your EGU(s), according to Sec.
63.10021(e).
(f) You are subject to the requirements of this subpart for at
least 6 months following the last date you met the definition of an EGU
subject to this subpart (e.g., 6 months after a cogeneration unit
provided more than one third of its potential electrical output
capacity and more than 25 megawatts electrical output to any power
distributions system for sale). You may opt to remain subject to the
provisions of this subpart beyond 6 months after the last date you met
the definition of an EGU subject to this subpart, unless you are a
solid waste incineration unit subject to standards under CAA section
129 (e.g., 40 CFR part 60, subpart CCCC (New Source Performance
Standards (NSPS) for Commercial and Industrial Solid Waste Incineration
Units, or Subpart DDDD (Emissions Guidelines (EG) for Existing
Commercial and Industrial Solid Waste Incineration Units).
Notwithstanding the provisions of this subpart, an EGU that starts
combusting solid waste is immediately subject to standards under CAA
section 129 and the EGU remains subject to those standards until the
EGU no longer meets the definition of a solid waste incineration unit
consistent with the provisions of the applicable CAA section 129
standards.
(g) If you no longer meet the definition of an EGU subject to this
subpart you must be in compliance with any newly applicable standards
on the date you are no longer subject to this subpart. The date you are
no longer subject to this subpart is a date selected by you, that must
be at least 6 months from the date that you last met the definition of
an EGU subject to this subpart or the date you begin combusting solid
waste, consistent with Sec. 63.9983(d). Your source must remain in
compliance with this subpart until the date you select to cease
complying with this subpart or the date you begin combusting solid
waste, whichever is earlier.
(h)(1) If you own or operate an EGU that does not meet the
definition of an EGU subject to this subpart on April 16, 2015, and you
commence or recommence operations that cause you to meet the definition
of an EGU subject to this subpart, you are subject to the provisions of
this subpart, including, but not limited to, the emission limitations
and the monitoring requirements, as of the first day you meet the
definition of an EGU subject to this subpart. You must complete all
initial compliance demonstrations for this subpart applicable to your
EGU within 180 days after you commence or recommence operations that
cause you to meet the definition of an EGU subject to this subpart.
(2) You must provide 30 days prior notice of the date you intend to
commence or recommence operations that cause you to meet the definition
of an EGU subject to this subpart. The notification must identify:
(i) The name of the owner or operator of the EGU, the location of
the facility, the unit(s) that will commence or recommence operations
that will cause the unit(s) to meet the definition of an EGU subject to
this subpart, and the date of the notice;
(ii) The 40 CFR part 60, part 62, or part 63 subpart and
subcategory
[[Page 9468]]
currently applicable to your unit(s), and the subcategory of this
subpart that will be applicable after you commence or recommence
operation that will cause the unit(s) to meet the definition of an EGU
subject to this subpart;
(iii) The date on which you became subject to the currently
applicable emission limits;
(iv) The date upon which you will commence or recommence operations
that will cause your unit to meet the definition of an EGU subject to
this subpart, consistent with paragraph (f) of this section.
(i)(1) If you own or operate an EGU subject to this subpart, and it
has been at least 6 months since you operated in a manner that caused
you to meet the definition of an EGU subject to this subpart, you may,
consistent with paragraph (g) of this section, select the date on which
your EGU will no longer be subject to this subpart. You must be in
compliance with any newly applicable section 112 or 129 standards on
the date you selected.
(2) You must provide 30 days prior notice of the date your EGU will
cease complying with this subpart. The notification must identify:
(i) The name of the owner or operator of the EGU(s), the location
of the facility, the EGU(s) that will cease complying with this
subpart, and the date of the notice;
(ii) The currently applicable subcategory under this subpart, and
any 40 CFR part 60, part 62, or part 63 subpart and subcategory that
will be applicable after you cease complying with this subpart;
(iii) The date on which you became subject to this subpart;
(iv) The date upon which you will cease complying with this
subpart, consistent with paragraph (g) of this section.
(j) All air pollution control equipment necessary for compliance
with any newly applicable emissions limits which apply as a result of
the cessation or commencement or recommencement of operations that
cause your EGU to meet the definition of an EGU subject to this subpart
must be installed and operational as of the date your source ceases to
be or becomes subject to this subpart.
(k) All monitoring systems necessary for compliance with any newly
applicable monitoring requirements which apply as a result of the
cessation or commencement or recommencement of operations that cause
your EGU to meet the definition of an EGU subject to this subpart must
be installed and operational as of the date your source ceases to be or
becomes subject to this subpart. All calibration and drift checks must
be performed as of the date your source ceases to be or becomes subject
to this subpart. You must also comply with provisions of Sec. Sec.
63.10010, 63.10020, and 63.10021 of this subpart. Relative accuracy
tests must be performed as of the performance test deadline for PM
CEMS, if applicable. Relative accuracy testing for other CEMS need not
be repeated if that testing was previously performed consistent with
CAA section 112 monitoring requirements or monitoring requirements
under this subpart.
Sec. 63.10001 Affirmative defense for exceedence of emission limit
during malfunction.
In response to an action to enforce the standards set forth in
Sec. 63.9991 you may assert an affirmative defense to a claim for
civil penalties for exceedances of such standards that are caused by
malfunction, as defined at 40 CFR 63.2. Appropriate penalties may be
assessed, however, if you fail to meet your burden of proving all of
the requirements in the affirmative defense. The affirmative defense
shall not be available for claims for injunctive relief.
(a) To establish the affirmative defense in any action to enforce
such a limit, you must timely meet the notification requirements in
paragraph (b) of this section, and must prove by a preponderance of
evidence that:
(1) The excess emissions:
(i) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring equipment, process equipment, or a
process to operate in a normal or usual manner, and
(ii) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(iv) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
(3) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
(4) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment and human
health; and
(6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(7) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
(8) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
(b) Notification. The owner or operator of the affected source
experiencing an exceedance of its emission limit(s) during a
malfunction shall notify the Administrator by telephone or facsimile
(FAX) transmission as soon as possible, but no later than two business
days after the initial occurrence of the malfunction or, if it is not
possible to determine within two business days whether the malfunction
caused or contributed to an exceedance, no later than two business days
after the owner or operator knew or should have known that the
malfunction caused or contributed to an exceedance, but, in no event
later than two business days after the end of the averaging period, if
it wishes to avail itself of an affirmative defense to civil penalties
for that malfunction. The owner or operator seeking to assert an
affirmative defense shall also submit a written report to the
Administrator within 45 days of the initial occurrence of the
exceedance of the standard in Sec. 63.9991 to demonstrate, with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (a) of this section. The owner or operator may
seek an extension of this deadline for up to 30 additional days by
submitting a written request to the Administrator before the expiration
of the 45 day period. Until a request for an extension has been
approved by the Administrator, the owner or operator is subject to the
requirement to submit such report
[[Page 9469]]
within 45 days of the initial occurrence of the exceedance.
Testing and Initial Compliance Requirements
Sec. 63.10005 What are my initial compliance requirements and by what
date must I conduct them?
(a) General requirements. For each of your affected EGUs, you must
demonstrate initial compliance with each applicable emissions limit in
Table 1 or 2 of this subpart through performance testing. Where two
emissions limits are specified for a particular pollutant (e.g., a heat
input-based limit in lb/MMBtu and an electrical output-based limit in
lb/MWh), you may demonstrate compliance with either emission limit. For
a particular compliance demonstration, you may be required to conduct
one or more of the following activities in conjunction with performance
testing: collection of hourly electrical load data (megawatts);
establishment of operating limits according to Sec. 63.10011 and
Tables 4 and 7 to this subpart; and CMS performance evaluations. In all
cases, you must demonstrate initial compliance no later than the
applicable date in paragraph (f) of this section for tune-up work
practices for existing EGUs, in Sec. 63.9984 for other requirements
for existing EGUs, and in paragraph (g) of this section for all
requirements for new EGUs.
(1) To demonstrate initial compliance with an applicable emissions
limit in Table 1 or 2 to this subpart using stack testing, the initial
performance test generally consists of three runs at specified process
operating conditions using approved methods. If you are required to
establish operating limits (see paragraph (d) of this section and Table
4 to this subpart), you must collect all applicable parametric data
during the performance test period. Also, if you choose to comply with
an electrical output-based emission limit, you must collect hourly
electrical load data during the test period.
(2) To demonstrate initial compliance using either a CMS that
measures HAP concentrations directly (i.e., an Hg, HCl, or HF CEMS, or
a sorbent trap monitoring system) or an SO2 or PM CEMS, the
initial performance test consists of 30 boiler operating days of data
collected by the initial compliance demonstration date specified in
Sec. 63.10005 with the certified monitoring system.
(i) The 30-boiler operating day CMS performance test must
demonstrate compliance with the applicable Hg, HCl, HF, PM, or
SO2 emissions limit in Table 1 or 2 to this subpart.
(ii) If you choose to comply with an electrical output-based
emission limit, you must collect hourly electrical load data during the
performance test period.
(b) Performance testing requirements. If you choose to use
performance testing to demonstrate initial compliance with the
applicable emissions limits in Tables 1 and 2 to this subpart for your
EGUs, you must conduct the tests according to Sec. 63.10007 and Table
5 to this subpart. For the purposes of the initial compliance
demonstration, you may use test data and results from a performance
test conducted prior to the date on which compliance is required as
specified in Sec. 63.9984, provided that the following conditions are
fully met:
(1) For a performance test based on stack test data, the test was
conducted no more than 12 calendar months prior to the date on which
compliance is required as specified in Sec. 63.9984;
(2) For a performance test based on data from a certified CEMS or
sorbent trap monitoring system, the test consists of all valid data CMS
data recorded in the 30 boiler operating days immediately preceding
that date;
(3) The performance test was conducted in accordance with all
applicable requirements in Sec. 63.10007 and Table 5 to this subpart;
(4) A record of all parameters needed to convert pollutant
concentrations to units of the emission standard (e.g., stack flow
rate, diluent gas concentrations, hourly electrical loads) is available
for the entire performance test period; and
(5) For each performance test based on stack test data, you
certify, and keep documentation demonstrating, that the EGU
configuration, control devices, and fuel(s) have remained consistent
with conditions since the prior performance test was conducted.
(c) Operating limits. In accordance with Sec. 63.10010 and Table 4
to this subpart, you may be required to establish operating limits
using PM CPMS and using site-specific monitoring for certain liquid
oil-fired units as part of your initial compliance demonstration.
(d) CMS requirements. If, for a particular emission or operating
limit, you are required to (or elect to) demonstrate initial compliance
using a continuous monitoring system, the CMS must pass a performance
evaluation prior to the initial compliance demonstration. If a CMS has
been previously certified under another state or federal program and is
continuing to meet the on-going quality-assurance (QA) requirements of
that program, then, provided that the certification and QA provisions
of that program meet the applicable requirements of Sec. Sec.
63.10010(b) through (h), an additional performance evaluation of the
CMS is not required under this subpart.
(1) For an affected coal-fired, solid oil-derived fuel-fired, or
liquid oil-fired EGU, you may demonstrate initial compliance with the
applicable SO2, HCl, or HF emissions limit in Table 1 or 2
of this subpart through use of an SO2, HCl, or HF CEMS
installed and operated in accordance with part 75 of this chapter or
Appendix B to this subpart, as applicable. You may also demonstrate
compliance with a filterable PM emission limit in Table 1 or 2 of this
subpart through use of a PM CEMS installed, certified, and operated in
accordance with Sec. 63.10010(i). Initial compliance is achieved if
the arithmetic average of 30-boiler operating days of quality-assured
CEMS data, expressed in units of the standard (see Sec. 63.10007(e)),
meets the applicable SO2, PM, HCl, or HF emissions limit in
Table 1 or 2 to this subpart. Use Equation 19-19 of Method 19 in
appendix A-7 to part 60 of this chapter to calculate the 30-boiler
operating day average emissions rate. (Note: for this calculation, the
term Ehj in Equation 19-19 must be in the same units of
measure as the applicable HCl or HF emission limit in Table 1 or 2 to
this subpart).
(2) For affected coal-fired or solid oil-derived fuel-fired EGUs
that demonstrate compliance with the applicable emission limits for
total non-mercury HAP metals, individual non-mercury HAP metals, total
HAP metals, individual HAP metals, or filterable PM listed in Table 1
or 2 to this subpart using initial performance testing and continuous
monitoring with PM CPMS:
(i) You must demonstrate initial compliance no later than the
applicable date specified in Sec. 63.9984(f) for existing EGUs and in
paragraph (g) of this section for new EGUs.
(ii) You must demonstrate continuous compliance with the PM CPMS
site-specific operating limit that corresponding to the results of the
performance test demonstrating compliance with the pollutant with which
you choose to comply.
(iii) You must repeat the performance test annually for the
selected pollutant emissions limit and reassess and adjust the site-
specific operating limit in accordance with the results of the
performance test.
(3) For affected EGUs that are either required to or elect to
demonstrate initial compliance with the applicable Hg emission limit in
Table 1 or 2 of this
[[Page 9470]]
subpart using Hg CEMS or sorbent trap monitoring systems, initial
compliance must be demonstrated no later than the applicable date
specified in Sec. 63.9984(f) for existing EGUs and in paragraph (g) of
this section for new EGUs. Initial compliance is achieved if the
arithmetic average of 30-boiler operating days of quality-assured CEMS
(or sorbent trap monitoring system) data, expressed in units of the
standard (see section 6.2 of appendix A to this subpart), meets the
applicable Hg emission limit in Table 1 or 2 to this subpart.
(4) For affected liquid oil-fired EGUs that demonstrate compliance
with the applicable emission limits for HCl or HF listed in Table 1 or
2 to this subpart using quarterly testing and continuous monitoring
with a CMS:
(i) You must demonstrate initial compliance no later than the
applicable date specified in Sec. 63.9984 for existing EGUs and in
paragraph (g) of this section for new EGUs.
(ii) You must demonstrate continuous compliance with the CMS site-
specific operating limit that corresponding to the results of the
performance test demonstrating compliance with the HCl or HF emissions
limit.
(iii) You must repeat the performance test annually for the HCl or
HF emissions limit and reassess and adjust the site-specific operating
limit in accordance with the results of the performance test.
(e) Tune-ups. All affected EGUs are subject to the work practice
standards in Table 3 of this subpart. As part of your initial
compliance demonstration, you must conduct a performance tune-up of
your EGU according to Sec. 63.10021(e).
(f) For existing affected sources a tune-up may occur prior to
April 16, 2012, so that existing sources without neural networks have
up to 42 calendar months (3 years from promulgation plus 180 days) or,
in the case of units employing neural network combustion controls, up
to 54 calendar months (48 months from promulgation plus 180 days) after
the date that is specified for your source in Sec. 63.9984 and
according to the applicable provisions in Sec. 63.7(a)(2) as cited in
Table 9 to this subpart to demonstrate compliance with this
requirement. If a tune-up occurs prior to such date, the source must
maintain adequate records to show that the tune-up met the requirements
of this standard.
(g) If your new or reconstructed affected source commenced
construction or reconstruction between May 3, 2011, and July 2, 2011,
you must demonstrate initial compliance with either the proposed
emission limits or the promulgated emission limits no later than 180
days after April 16, 2012 or within 180 days after startup of the
source, whichever is later, according to Sec. 63.7(a)(2)(ix).
(1) For the new or reconstructed affected source described in this
paragraph (g), if you choose to comply with the proposed emission
limits when demonstrating initial compliance, you must conduct a second
compliance demonstration for the promulgated emission limits within 3
years after April 16, 2012 or within 3 years after startup of the
affected source, whichever is later.
(2) If your new or reconstructed affected source commences
construction or reconstruction after April 16, 2012, you must
demonstrate initial compliance with the promulgated emission limits no
later than 180 days after startup of the source.
(h) Low emitting EGUs. The provisions of this paragraph (h) apply
to pollutants with emissions limits from new EGUs except Hg and to all
pollutants with emissions limits from existing EGUs. You may not pursue
this compliance option if your existing EGU is equipped with an acid
gas scrubber and has a main stack and bypass stack exhaust
configuration.
(1) An EGU may qualify for low emitting EGU (LEE) status for Hg,
HCl, HF, filterable PM, total non-Hg HAP metals, or individual non-Hg
HAP metals (or total HAP metals or individual HAP metals, for liquid
oil-fired EGUs) if you collect performance test data that meet the
requirements of this paragraph (h), and if those data demonstrate:
(i) For all pollutants except Hg, performance test emissions
results less than 50 percent of the applicable emissions limits in
Table 1 or 2 to this subpart for all required testing for 3 consecutive
years; or
(ii) For Hg emissions from an existing EGU, either:
(A) Average emissions less than 10 percent of the applicable Hg
emissions limit in Table 2 to this subpart (expressed either in units
of lb/TBtu or lb/GWh); or
(B) Potential Hg mass emissions of 29.0 or fewer pounds per year
and compliance with the applicable Hg emission limit in Table 2 to this
subpart (expressed either in units of lb/TBtu or lb/GWh).
(2) For all pollutants except Hg, you must conduct all required
performance tests described in Sec. 63.10007 to demonstrate that a
unit qualifies for LEE status.
(i) When conducting emissions testing to demonstrate LEE status,
you must increase the minimum sample volume specified in Table 1 or 2
nominally by a factor of two.
(ii) Follow the instructions in Sec. 63.10007(e) and Table 5 to
this subpart to convert the test data to the units of the applicable
standard.
(3) For Hg, you must conduct a 30-boiler operating day performance
test using Method 30B in appendix A-8 to part 60 of this chapter to
determine whether a unit qualifies for LEE status. Locate the Method
30B sampling probe tip at a point within the 10 percent centroidal area
of the duct at a location that meets Method 1 in appendix A-1 to part
60 of this chapter and conduct at least three nominally equal length
test runs over the 30-boiler operating day test period. Collect Hg
emissions data continuously over the entire test period (except when
changing sorbent traps or performing required reference method QA
procedures), under all process operating conditions. You may use a pair
of sorbent traps to sample the stack gas for no more than 10 days.
(i) Depending on whether you intend to assess LEE status for Hg in
terms of the lb/TBtu or lb/GWh emission limit in Table 2 to this
subpart or in terms of the annual Hg mass emissions limit of 29.0 lb/
year, you will have to collect some or all of the following data during
the 30-boiler operating day test period (see paragraph (h)(3)(iii) of
this section):
(A) Diluent gas (CO2 or O2) data, using
either Method 3A in appendix A-3 to part 60 of this chapter or a
diluent gas monitor that has been certified according to part 75 of
this chapter.
(B) Stack gas flow rate data, using either Method 2, 2F, or 2G in
appendices A-1 and A-2 to part 60 of this chapter, or a flow rate
monitor that has been certified according to part 75 of this chapter.
(C) Stack gas moisture content data, using either Method 4 in
appendix A-1 to part 60 of this chapter, or a moisture monitoring
system that has been certified according to part 75 of this chapter.
Alternatively, an appropriate fuel-specific default moisture value from
Sec. 75.11(b) of this chapter may be used in the calculations or you
may petition the Administrator under Sec. 75.66 of this chapter for
use of a default moisture value for non-coal-fired units.
(D) Hourly electrical load data (megawatts), from facility records.
(ii) If you use CEMS to measure CO2 (or O2)
concentration, and/or flow rate, and/or moisture, record hourly average
values of each parameter throughout the 30-boiler operating day test
period. If you opt to use EPA reference methods rather than CEMS for
any parameter, you must perform at least one
[[Page 9471]]
representative test run on each operating day of the test period, using
the applicable reference method.
(iii) Calculate the average Hg concentration, in [micro]g/
m3 (dry basis), for the 30-boiler operating day performance
test, as the arithmetic average of all Method 30B sorbent trap results.
Also calculate, as applicable, the average values of CO2 or
O2 concentration, stack gas flow rate, stack gas moisture
content, and electrical load for the test period. Then:
(A) To express the test results in units of lb/TBtu, follow the
procedures in Sec. 63.10007(e). Use the average Hg concentration and
diluent gas values in the calculations.
(B) To express the test results in units of lb/GWh, use Equations
A-3 and A-4 in section 6.2.2 of appendix A to this subpart, replacing
the hourly values ``Ch'', ``Qh'',
``Bws'' and ``(MW)h'' with the average values of
these parameters from the performance test.
(C) To calculate pounds of Hg per year, use one of the following
methods:
(1) Multiply the average lb/TBtu Hg emission rate (determined
according to paragraph (h)(3)(iii)(A) of this section) by the maximum
potential annual heat input to the unit (TBtu), which is equal to the
maximum rated unit heat input (TBtu/hr) times 8,760 hours. If the
maximum rated heat input value is expressed in units of MMBtu/hr,
multiply it by 106 to convert it to TBtu/hr; or
(2) Multiply the average lb/GWh Hg emission rate (determined
according to paragraph (h)(3)(iii)(B) of this section) by the maximum
potential annual electricity generation (GWh), which is equal to the
maximum rated electrical output of the unit (GW) times 8,760 hours. If
the maximum rated electrical output value is expressed in units of MW,
multiply it by 103 to convert it to GW; or
(3) If an EGU has a federally-enforceable permit limit on either
the annual heat input or the number of annual operating hours, you may
modify the calculations in paragraph (h)(3)(iii)(C)(1) of this section
by replacing the maximum potential annual heat input or 8,760 unit
operating hours with the permit limit on annual heat input or operating
hours (as applicable).
(4) For a group of affected units that vent to a common stack, you
may either assess LEE status for the units individually by performing a
separate emission test of each unit in the duct leading from the unit
to the common stack, or you may perform a single emission test in the
common stack. If you choose the common stack testing option, the units
in the configuration qualify for LEE status if:
(i) The emission rate measured at the common stack is less than 50
percent (10 percent for Hg) of the applicable emission limit in Table 1
or 2 to this subpart; or
(ii) For Hg from an existing EGU, the applicable Hg emission limit
in Table 2 to this subpart is met and the potential annual mass
emissions, calculated according to paragraph (h)(3)(iii) of this
section (with some modifications), are less than or equal to 29.0
pounds times the number of units sharing the common stack. Base your
calculations on the combined heat input capacity of all units sharing
the stack (i.e., either the combined maximum rated value or, if
applicable, a lower combined value restricted by permit conditions or
operating hours).
(5) For an affected unit with a multiple stack or duct
configuration in which the exhaust stacks or ducts are downstream of
all emission control devices, you must perform a separate emission test
in each stack or duct. The unit qualifies for LEE status if:
(i) The emission rate, based on all test runs performed at all of
the stacks or ducts, is less than 50 percent (10 percent for Hg) of the
applicable emission limit in Table 1 or 2 to this subpart; or
(ii) For Hg from an existing EGU, the applicable Hg emission limit
in Table 2 to this subpart is met and the potential annual mass
emissions, calculated according to paragraph (h)(3)(iii) of this
section, are less than or equal to 29.0 pounds. Use the average Hg
emission rate from paragraph (h)(5)(i) of this section in your
calculations.
(i) Liquid-oil fuel moisture measurement. If your EGU combusts
liquid fuels, if your fuel moisture content is no greater than 1.0
percent by weight, and if you would like to demonstrate initial and
ongoing compliance with HCl and HF emissions limits, you must meet the
requirements of paragraphs (i)(1) through (5) of this section.
(1) Measure fuel moisture content of each shipment of fuel if your
fuel arrives on a batch basis; or
(2) Measure fuel moisture content daily if your fuel arrives on a
continuous basis; or
(3) Obtain and maintain a fuel moisture certification from your
fuel supplier.
(4) Use one of the following methods to determine fuel moisture
content:
(i) ASTM D95-05 (Reapproved 2010), ``Standard Test Method for Water
in Petroleum Products and Bituminous Materials by Distillation,'' or
(ii) ASTM D4006-11, ``Standard Test Method for Water in Crude Oil
by Distillation,'' including Annex A1 and Appendix A1, or
(iii) ASTM D4177-95 (Reapproved 2010), ``Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products,'' including
Annexes A1 through A6 and Appendices X1 and X2, or
(iv) ASTM D4057-06 (Reapproved 2011), ``Standard Practice for
Manual Sampling of Petroleum and Petroleum Products,'' including Annex
A1.
(5) Should the moisture in your liquid fuel be more than 1.0
percent by weight, you must
(i) Conduct HCl and HF emissions testing quarterly (and monitor
site-specific operating parameters as provided in Sec.
63.10000(c)(2)(iii) or
(ii) Use an HCl CEMS and/or HF CEMS.
(j) Startup and shutdown for coal-fired or solid oil derived-fired
units. You must follow the requirements given in Table 3 to this
subpart.
(k) You must submit a Notification of Compliance Status summarizing
the results of your initial compliance demonstration, as provided in
Sec. 63.10030.
Sec. 63.10006 When must I conduct subsequent performance tests or
tune-ups?
(a) For liquid oil-fired, solid oil-derived fuel- and coal-fired
EGUs and IGCC units using PM CPMS to monitor continuous performance
with an applicable emission limit as provided for under Sec.
63.10000(c), you must conduct all applicable performance tests
according to Table 5 to this subpart and Sec. 63.10007 at least every
year.
(b) For affected units meeting the LEE requirements of Sec.
63.10005(h), you must repeat the performance test once every 3 years
(once every year for Hg) according to Table 5 and Sec. 63.10007.
Should subsequent emissions testing results show the unit does not meet
the LEE eligibility requirements, LEE status is lost. If this should
occur:
(1) For all pollutant emission limits except for Hg, you must
conduct emissions testing quarterly, except as otherwise provided in
Sec. 63.10021(d)(1).
(2) For Hg, you must install, certify, maintain, and operate a Hg
CEMS or a sorbent trap monitoring system in accordance with appendix A
to this subpart, within 6 calendar months of losing LEE eligibility.
Until the Hg CEMS or sorbent trap monitoring system is installed,
certified, and operating, you must conduct Hg emissions testing
quarterly, except as otherwise provided in Sec. 63.10021(d)(1). You
must have 3 calendar years of testing and CEMS or
[[Page 9472]]
sorbent trap monitoring system data that satisfy the LEE emissions
criteria to reestablish LEE status.
(c) Except where paragraphs (a) or (b) of this section apply, or
where you install, certify, and operate a PM CEMS to demonstrate
compliance with a filterable PM emission limit, for liquid oil-fired
EGUs, you must conduct all applicable periodic emissions tests for
filterable PM, or individual or total HAP metals emissions according to
Table 5 to this subpart and Sec. 63.10007 at least quarterly, except
as otherwise provided in Sec. 63.10021(d)(1).
(d) Except where paragraph (b) of this section applies, for solid
oil-derived fuel- and coal-fired EGUs that do not use either an HCl
CEMS to monitor compliance with the HCl limit or an SO2 CEMS
to monitor compliance with the alternate equivalent SO2
emission limit, you must conduct all applicable periodic HCl emissions
tests according to Table 5 to this subpart and Sec. 63.10007 at least
quarterly, except as otherwise provided in Sec. 63.10021(d)(1).
(e) Except where paragraph (b) of this section applies, for liquid
oil-fired EGUs without HCl CEMS, HF CEMS, or HCl and HF CEMS, you must
conduct all applicable emissions tests for HCl, HF, or HCl and HF
emissions according to Table 5 to this subpart and Sec. 63.10007 at
least quarterly, except as otherwise provided in Sec. 63.10021(d)(1),
and conduct site-specific monitoring under a plan as provided for in
Sec. 63.10000(c)(2)(iii).
(f) Unless you follow the requirements listed in paragraphs (g) and
(h) of this section, performance tests required at least every 3
calendar years must be completed within 35 to 37 calendar months after
the previous performance test; performance tests required at least
every year must be completed within 11 to 13 calendar months after the
previous performance test; and performance tests required at least
quarterly must be completed within 80 to 100 calendar days after the
previous performance test, except as otherwise provided in Sec.
63.10021(d)(1).
(g) If you elect to demonstrate compliance using emissions
averaging under Sec. 63.10009, you must continue to conduct
performance stack tests at the appropriate frequency given in section
(c) through (f) of this section.
(h) If a performance test on a non-mercury LEE shows emissions in
excess of 50 percent of the emission limit and if you choose to reapply
for LEE status, you must conduct performance tests at the appropriate
frequency given in section (c) through (e) of this section for that
pollutant until all performance tests over a consecutive 3-year period
show compliance with the LEE criteria.
(i) If you are required to meet an applicable tune-up work practice
standard, you must conduct a performance tune-up according to Sec.
63.10021(e).
(1) For EGUs not employing neural network combustion optimization
during normal operation, each performance tune-up specified in Sec.
63.10021(e) must be no more than 36 calendar months after the previous
performance tune-up.
(2) For EGUs employing neural network combustion optimization
systems during normal operation, each performance tune-up specified in
Sec. 63.10021(e) must be no more than 48 calendar months after the
previous performance tune-up.
(j) You must report the results of performance tests and
performance tune-ups within 60 days after the completion of the
performance tests and performance tune-ups. The reports for all
subsequent performance tests must include all applicable information
required in Sec. 63.10031.
Sec. 63.10007 What methods and other procedures must I use for the
performance tests?
(a) Except as otherwise provided in this section, you must conduct
all required performance tests according to Sec. 63.7(d), (e), (f),
and (h). You must also develop a site-specific test plan according to
the requirements in Sec. 63.7(c).
(1) If you use CEMS (Hg, HCl, SO2, or other) to
determine compliance with a 30-boiler operating day rolling average
emission limit, you must collect data for all nonexempt unit operating
conditions (see Sec. 63.10011(g) and Table 3 to this subpart).
(2) If you conduct performance testing with test methods in lieu of
continuous monitoring, operate the unit at maximum normal operating
load conditions during each periodic (e.g., quarterly) performance
test. Maximum normal operating load will be generally between 90 and
110 percent of design capacity but should be representative of site
specific normal operations during each test run.
(3) For establishing operating limits with particulate matter
continuous parametric monitoring system (PM CPMS) to demonstrate
compliance with a PM or non Hg metals emissions limit, operate the unit
at maximum normal operating load conditions during the performance test
period. Maximum normal operating load will be generally between 90 and
110 percent of design capacity but should be representative of site
specific normal operations during each test run.
(b) You must conduct each performance test (including traditional
3-run stack tests, 30-boiler operating day tests based on CEMS data (or
sorbent trap monitoring system data), and 30-boiler operating day Hg
emission tests for LEE qualification) according to the requirements in
Table 5 to this subpart.
(c) If you choose to comply with the filterable PM emission limit
and demonstrate continuous performance using a PM CPMS for an
applicable emission limit as provided for in Sec. 63.10000(c), you
must also establish an operating limit according to Sec.
63.10011(b)(5) and Tables 4 and 6 to this subpart. Should you desire to
have operating limits that correspond to loads other than maximum
normal operating load, you must conduct testing at those other loads to
determine the additional operating limits.
(d) Except for a 30-boiler operating day performance test based on
CEMS (or sorbent trap monitoring system) data, where the concept of
test runs does not apply, you must conduct a minimum of three separate
test runs for each performance test, as specified in Sec. 63.7(e)(3).
Each test run must comply with the minimum applicable sampling time or
volume specified in Table 1 or 2 to this subpart. Sections 63.10005(d)
and (h), respectively, provide special instructions for conducting
performance tests based on CEMS or sorbent trap monitoring systems, and
for conducting emission tests for LEE qualification.
(e) To use the results of performance testing to determine
compliance with the applicable emission limits in Table 1 or 2 to this
subpart, proceed as follows:
(1) Except for a 30-boiler operating day performance test based on
CEMS (or sorbent trap monitoring system) data, if measurement results
for any pollutant are reported as below the method detection level
(e.g., laboratory analytical results for one or more sample components
are below the method defined analytical detection level), you must use
the method detection level as the measured emissions level for that
pollutant in calculating compliance. The measured result for a multiple
component analysis (e.g., analytical values for multiple Method 29
fractions both for individual HAP metals and for total HAP metals) may
include a combination of method detection level data and analytical
data reported above the method detection level.
(2) If the limits are expressed in lb/MMBtu or lb/TBtu, you must
use the F-factor methodology and equations in
[[Page 9473]]
sections 12.2 and 12.3 of EPA Method 19 in appendix A-7 to part 60 of
this chapter. In cases where an appropriate F-factor is not listed in
Table 19-2 of Method 19, you may use F-factors from Table 1 in section
3.3.5 of appendix F to part 75 of this chapter, or F-factors derived
using the procedures in section 3.3.6 of appendix to part 75 of this
chapter. Use the following factors to convert the pollutant
concentrations measured during the initial performance tests to units
of lb/scf, for use in the applicable Method 19 equations:
(i) Multiply SO2 ppm by 1.66 x 10-7;
(ii) Multiply HCl ppm by 9.43 x 10-8;
(iii) Multiply HF ppm by 5.18 x 10-8;
(iv) Multiply HAP metals concentrations (mg/dscm) by 6.24 x
10-8; and
(v) Multiply Hg concentrations ([micro]g/scm) by 6.24 x
10-11.
(3) To determine compliance with emission limits expressed in lb/
MWh or lb/GWh, you must first calculate the pollutant mass emission
rate during the performance test, in units of lb/h. For Hg, if a CEMS
or sorbent trap monitoring system is used, use Equation A-2 or A-3 in
appendix A to this subpart (as applicable). In all other cases, use an
equation that has the general form of Equation A-2 or A-3, replacing
the value of K with 1.66 x 10-7 lb/scf-ppm for
SO2, 9.43 x 10-8 lb/scf-ppm for HCl (if an HCl
CEMS is used), 5.18 x 10-8 lb/scf-ppm for HF (if an HF CEMS
is used), or 6.24 x 10-8 lb-scm/mg-scf for HAP metals and
for HCl and HF (when performance stack testing is used), and defining
Ch as the average SO2, HCl, or HF concentration
in ppm, or the average HAP metals concentration in mg/dscm. This
calculation requires stack gas volumetric flow rate (scfh) and (in some
cases) moisture content data (see Sec. Sec. 63.10005(h)(3) and
63.10010). Then, if the applicable emission limit is in units of lb/
GWh, use Equation A-4 in appendix A to this subpart to calculate the
pollutant emission rate in lb/GWh. In this calculation, define
(M)h as the calculated pollutant mass emission rate for the
performance test (lb/h), and define (MW)h as the average
electrical load during the performance test (megawatts). If the
applicable emission limit is in lb/MWh rather than lb/GWh, omit the
103 term from Equation A-4 to determine the pollutant
emission rate in lb/MWh.
(f) Upon request, you shall make available to the EPA Administrator
such records as may be necessary to determine whether the performance
tests have been done according to the requirements of this section.
Sec. 63.10008 [Reserved]
Sec. 63.10009 May I use emissions averaging to comply with this
subpart?
(a) General eligibility. (1) You may use emissions averaging as
described in paragraph (a)(2) of this section as an alternative to
meeting the requirements of Sec. 63.9991 for filterable PM,
SO2, HF, HCl, non-Hg HAP metals, or Hg on an EGU-specific
basis if:
(i) You have more than one existing EGU in the same subcategory
located at one or more contiguous properties, belonging to a single
major industrial grouping, which are under common control of the same
person (or persons under common control); and
(ii) You use CEMS (or sorbent trap monitoring systems for
determining Hg emissions) or quarterly emissions testing for
demonstrating compliance.
(2) You may demonstrate compliance by emissions averaging among the
existing EGUs in the same subcategory, if your averaged Hg emissions
for EGUs in the ``unit designed for coal >= 8,300 Btu/lb'' subcategory
are equal to or less than 1.0 lb/TBtu or 1.1E-2 lb/GWh or if your
averaged emissions of individual, other pollutants from other
subcategories of such EGUs are equal to or less than the applicable
emissions limit in Table 2, according to the procedures in this
section. Note that except for Hg emissions from EGUs in the ``unit
designed for coal >= 8,300 Btu/lb'' subcategory, the averaging time for
emissions averaging for pollutants is 30 days (rolling daily) using
data from CEMS or a combination of data from CEMS and manual
performance testing. The averaging time for emissions averaging for Hg
from EGUs in the ``unit designed for coal >= 8,300 Btu/lb'' subcategory
is 90 days (rolling daily) using data from CEMS, sorbent trap
monitoring, or a combination of monitoring data and data from manual
performance testing. For the purposes of this paragraph, 30- (or 90-
day) group boiler operating days is defined as a period during which at
least one unit in the emissions averaging group has operated 30 (or 90)
days. You must calculate the weighted average emissions rate for the
group in accordance with the procedures in this paragraph using the
data from all units in the group including any that operate fewer than
30 (or 90) days during the preceding 30 (or 90) group boiler days.
(i) You may choose to have your EGU emissions averaging group meet
either the heat input basis (MMBtu or TBtu, as appropriate for the
pollutant) or gross electrical output basis (MWh or GWh, as appropriate
for the pollutant).
(ii) You may not mix bases within your EGU emissions averaging
group.
(iii) You may use emissions averaging for affected units in
different subcategories if the units vent to the atmosphere through a
common stack (see paragraph (m) of this section).
(b) Equations. Use the following equations when performing
calculations for your EGU emissions averaging group:
(1) Group eligibility equations.
[GRAPHIC] [TIFF OMITTED] TR16FE12.003
Where:
WAERm = Weighted average emissions rate maximum in terms of lb/heat
input or lb/gross electrical output,
Hermi = Hourly emissions rate (e.g., lb/MMBtu, lb/MWh)
from CEMS or sorbent trap monitoring for hour i,
Rmmi = Maximum rated heat input or gross electrical
output of unit i in terms of heat input or gross electrical output,
p = number of EGUs in emissions averaging group that rely on CEMS,
n = number of hourly rates collected over 30-group boiler operating
days,
Teri = Emissions rate from most recent test of unit i in
terms of lb/heat input or lb/gross electrical output,
Rmti = Maximum rated heat input or gross electrical
output of unit i in terms of lb/heat input or lb/gross electrical
output, and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[[Page 9474]]
[GRAPHIC] [TIFF OMITTED] TR16FE12.004
Where:
variables with similar names share the descriptions for Equation 1a,
Smmi = maximum steam generation in units of pounds from
unit i that uses CEMS or sorbent trap monitoring,
Cfmi = conversion factor, calculated from the most recent
emissions test results, in units of heat input per pound of steam
generated or gross electrical output per pound of steam generated,
from unit i that uses CEMS or sorbent trap monitoring,
Smti = maximum steam generation in units of pounds from
unit i that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent
emissions test results, in units of heat input per pound of steam
generated or gross electrical output per pound of steam generated,
from unit i that uses emissions testing.
(2) Weighted 30-day rolling average emissions rate equations for
pollutants other than Hg. Use equation 2a or 2b to calculate the 30-day
rolling average emissions daily.
[GRAPHIC] [TIFF OMITTED] TR16FE12.005
Where:
Heri = hourly emission rate (e.g., lb/MMBtu, lb/MWh) from
unit i's CEMS for the preceding 30-group boiler operating days,
Rmi = hourly heat input or gross electrical output from
unit i for the preceding 30-group boiler operating days,
p = number of EGUs in emissions averaging group that rely on CEMS or
sorbent trap monitoring,
n = number of hourly rates collected over 30-group boiler operating
days,
Teri = Emissions rate from most recent emissions test of
unit i in terms of lb/heat input or lb/gross electrical output,
Rti = Maximum rated heat input or gross electrical output
of unit i in terms of lb/heat input or lb/gross electrical output,
and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[GRAPHIC] [TIFF OMITTED] TR16FE12.006
Where:
variables with similar names share the descriptions for Equation 2a,
Smi = steam generation in units of pounds from unit i
that uses CEMS for the preceding 30-group boiler operating days,
Cfmi = conversion factor, calculated from the most recent
compliance test results, in units of heat input per pound of steam
generated or gross electrical output per pound of steam generated,
from unit i that uses CEMS from the preceding 30-group boiler
operating days,
Sti = steam generation in units of pounds from unit i
that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent
compliance test results, in units of heat input per pound of steam
generated or gross electrical output per pound of steam generated,
from unit i that uses emissions testing.
(3) Weighted 90-boiler operating day rolling average emissions rate
equations for Hg emissions from EGUs in the ``unit designed for coal >=
8,300 Btu/lb'' subcategory. Use equation 3a or 3b to calculate the 90-
day rolling average emissions daily.
[GRAPHIC] [TIFF OMITTED] TR16FE12.007
Where:
Heri = hourly emission rate from unit i's CEMS or Hg
sorbent trap monitoring for the preceding 90-group boiler operating
days,
Rmi = hourly heat input or gross electrical output from
unit i for the preceding 90-group boiler operating days,
p = number of EGUs in emissions averaging group that rely on CEMS,
n = number of hourly rates collected over the 90-group boiler
operating days,
Teri = Emissions rate from most recent emissions test of
unit i in terms of lb/heat input or lb/gross electrical output,
Rti = Maximum rated heat input or gross electrical output
of unit i in terms of lb/heat input or lb/gross electrical output,
and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[GRAPHIC] [TIFF OMITTED] TR16FE12.008
[[Page 9475]]
Where:
variables with similar names share the descriptions for Equation 2a,
Smi = steam generation in units of pounds from unit i
that uses CEMS or a Hg sorbent trap monitoring for the preceding 90-
group boiler operating days,
Cfmi = conversion factor, calculated from the most recent
compliance test results, in units of heat input per pound of steam
generated or gross electrical output per pound of steam generated,
from unit i that uses CEMS or sorbent trap monitoring from the
preceding 90-group boiler operating days,
Sti = steam generation in units of pounds from unit i
that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent
emissions test results, in units of heat input per pound of steam
generated or gross electrical output per pound of steam generated,
from unit i that uses emissions testing.
(c) Separate stack requirements. For a group of two or more
existing EGUs in the same subcategory that each vent to a separate
stack, you may average filterable PM, SO2, HF, HCl, non-Hg
HAP metals, or Hg emissions to demonstrate compliance with the limits
in Table 2 to this subpart if you satisfy the requirements in
paragraphs (d) through (j) of this section.
(d) For each existing EGU in the averaging group:
(1) The emissions rate achieved during the initial performance test
for the HAP being averaged must not exceed the emissions level that was
being achieved 180 days after April 16, 2015, or the date on which
emissions testing done to support your emissions averaging plan is
complete (if the Administrator does not require submission and approval
of your emissions averaging plan), or the date that you begin emissions
averaging, whichever is earlier; or
(2) The control technology employed during the initial performance
test must not be less than the design efficiency of the emissions
control technology employed 180 days after April 16, 2015 or the date
that you begin emissions averaging, whichever is earlier.
(e) The weighted-average emissions rate from the existing EGUs
participating in the emissions averaging option must be in compliance
with the limits in Table 2 to this subpart at all times following the
compliance date specified 180 days after April 16, 2015, or the date on
which you complete the emissions measurements used to support your
emissions averaging plan (if the Administrator does not require
submission and approval of your emissions averaging plan), or the date
that you begin emissions averaging, whichever is earlier.
(f) Emissions averaging group eligibility demonstration. You must
demonstrate the ability for the EGUs included in the emissions
averaging group to demonstrate initial compliance according to
paragraph (f)(1) or (2) of this section using the maximum normal
operating load of each EGU and the results of the initial performance
tests. For this demonstration and prior to submitting your emissions
averaging plan, if requested, you must conduct required emissions
monitoring for 30 days of boiler operation and any required manual
performance testing to calculate an initial weighted average emissions
rate in accordance with this section. Should the Administrator require
approval, you must submit your proposed emissions averaging plan and
supporting data at least 120 days before April 16, 2015. If the
Administrator requires approval of your plan, you may not begin using
emissions averaging until the Administrator approves your plan.
(1) You must use Equation 1a in paragraph (b) of this section to
demonstrate that the maximum weighted average emissions rates of
filterable PM, HF, SO2, HCl, non-Hg HAP metals, or Hg
emissions from the existing units participating in the emissions
averaging option do not exceed the emissions limits in Table 2 to this
subpart.
(2) If you are not capable of monitoring heat input or gross
electrical output, and the EGU generates steam for purposes other than
generating electricity, you may use Equation 1b of this section as an
alternative to using Equation 1a of this section to demonstrate that
the maximum weighted average emissions rates of filterable PM, HF,
SO2, HCl, non-Hg HAP metals, or Hg emissions from the
existing units participating in the emissions averaging group do not
exceed the emission limits in Table 2 to this subpart.
(g) You must determine the weighted average emissions rate in units
of the applicable emissions limit on a 30 day rolling average (90 day
rolling average for Hg) basis according to paragraphs (f)(1) through
(3) of this section. The first averaging period begins on 30 (or 90 for
Hg) days after February 16, 2015 or the date that you begin emissions
averaging, whichever is earlier.
(1) You must use Equation 2a or 3a of paragraph (b) of this section
to calculate the weighted average emissions rate using the actual heat
input or gross electrical output for each existing unit participating
in the emissions averaging option.
(2) If you are not capable of monitoring heat input or gross
electrical output, you may use Equation 2b or 3b of paragraph (b) of
this section as an alternative to using Equation 2a of paragraph (b) of
this section to calculate the average weighted emission rate using the
actual steam generation from the units participating in the emissions
averaging option.
(h) CEMS (or sorbent trap monitoring) use. If an EGU in your
emissions averaging group uses CEMS (or a sorbent trap monitor for Hg
emissions) to demonstrate compliance, you must use those data to
determine the 30 (or 90) group boiler operating day rolling average
emissions rate.
(i) Emissions testing. If you use manual emissions testing to
demonstrate compliance for one or more EGUs in your emissions averaging
group, you must use the results from the most recent performance test
to determine the 30 (or 90) day rolling average. You may use CEMS or
sorbent trap data in combination with data from the most recent manual
performance test in calculating the 30 (or 90) group boiler operating
day rolling average emissions rate.
(j) Emissions averaging plan. You must develop an implementation
plan for emissions averaging according to the following procedures and
requirements in paragraphs (j)(1) and (2) of this section.
(1) You must include the information contained in paragraphs
(j)(1)(i) through (v) of this section in your implementation plan for
all the emissions units included in an emissions averaging:
(i) The identification of all existing EGUs in the emissions
averaging group, including for each either the applicable HAP emission
level or the control technology installed as of 180 days after February
16, 2015, or the date on which you complete the emissions measurements
used to support your emissions averaging plan (if the Administrator
does not require submission and approval of your emissions averaging
plan), or the date that you begin emissions averaging, whichever is
earlier; and the date on which you are requesting emissions averaging
to commence;
(ii) The process weighting parameter (heat input, gross electrical
output, or steam generated) that will be monitored for each averaging
group;
(iii) The specific control technology or pollution prevention
measure to be used for each emission EGU in the averaging group and the
date of its installation or application. If the pollution prevention
measure reduces or eliminates
[[Page 9476]]
emissions from multiple EGUs, you must identify each EGU;
(iv) The means of measurement (e.g., CEMS, sorbent trap monitoring,
manual performance test) of filterable PM, SO2, HF, HCl,
individual or total non-Hg HAP metals, or Hg emissions in accordance
with the requirements in Sec. 63.10007 and to be used in the emissions
averaging calculations; and
(v) A demonstration that emissions averaging can produce compliance
with each of the applicable emission limit(s) in accordance with
paragraph (b)(1) of this section.
(2) If the Administrator requests you to submit the plan for review
and approval, you must submit a complete implementation plan at least
120 days before April 16, 2015. If the Administrator requests you to
submit the plan for review and approval, you must receive approval
before initiating emissions averaging.
(i) The Administrator shall use following criteria in reviewing and
approving or disapproving the plan:
(A) Whether the content of the plan includes all of the information
specified in paragraph (h)(1) of this section; and
(B) Whether the plan presents information sufficient to determine
that compliance will be achieved and maintained.
(ii) The Administrator shall not approve an emissions averaging
implementation plan containing any of the following provisions:
(A) Any averaging between emissions of different pollutants or
between units located at different facilities; or
(B) The inclusion of any emissions unit other than an existing unit
in the same subcategory.
(k) Common stack requirements. For a group of two or more existing
affected units, each of which vents through a single common stack, you
may average emissions to demonstrate compliance with the limits in
Table 2 to this subpart if you satisfy the requirements in paragraph
(l) or (m) of this section.
(l) For a group of two or more existing units in the same
subcategory and which vent through a common emissions control system to
a common stack that does not receive emissions from units in other
subcategories or categories, you may treat such averaging group as a
single existing unit for purposes of this subpart and comply with the
requirements of this subpart as if the group were a single unit.
(m) For all other groups of units subject to paragraph (k) of this
section, you may elect to conduct manual performance tests according to
procedures specified in Sec. 63.10007 in the common stack. If
emissions from affected units included in the emissions averaging and
from other units not included in the emissions averaging (e.g., in a
different subcategory) or other nonaffected units all vent to the
common stack, you must shut down the units not included in the
emissions averaging and the nonaffected units or vent their emissions
to a different stack during the performance test. Alternatively, you
may conduct a performance test of the combined emissions in the common
stack with all units operating and show that the combined emissions
meet the most stringent emissions limit. You may also use a CEMS or
sorbent trap monitoring to apply this latter alternative to demonstrate
that the combined emissions comply with the most stringent emissions
limit on a continuous basis.
(n) Combination requirements. The common stack of a group of two or
more existing EGUs in the same subcategory subject to paragraph (k) of
this section may be treated as a single stack for purposes of paragraph
(c) of this section and included in an emissions averaging group
subject to paragraph (c) of this section.
Sec. 63.10010 What are my monitoring, installation, operation, and
maintenance requirements?
(a) Flue gases from the affected units under this subpart exhaust
to the atmosphere through a variety of different configurations,
including but not limited to individual stacks, a common stack
configuration or a main stack plus a bypass stack. For the CEMS, PM
CPMS, and sorbent trap monitoring systems used to provide data under
this subpart, the continuous monitoring system installation
requirements for these exhaust configurations are as follows:
(1) Single unit-single stack configurations. For an affected unit
that exhausts to the atmosphere through a single, dedicated stack, you
shall either install the required CEMS, PM CPMS, and sorbent trap
monitoring systems in the stack or at a location in the ductwork
downstream of all emissions control devices, where the pollutant and
diluents concentrations are representative of the emissions that exit
to the atmosphere.
(2) Unit utilizing common stack with other affected unit(s). When
an affected unit utilizes a common stack with one or more other
affected units, but no non-affected units, you shall either:
(i) Install the required CEMS, PM CPMS, and sorbent trap monitoring
systems in the duct leading to the common stack from each unit; or
(ii) Install the required CEMS, PM CPMS, and sorbent trap
monitoring systems in the common stack.
(3) Unit(s) utilizing common stack with non-affected unit(s).
(i) When one or more affected units shares a common stack with one
or more non-affected units, you shall either:
(A) Install the required CEMS, PM CPMS, and sorbent trap monitoring
systems in the ducts leading to the common stack from each affected
unit; or
(B) Install the required CEMS, PM CPMS, and sorbent trap monitoring
systems described in this section in the common stack and attribute all
of the emissions measured at the common stack to the affected unit(s).
(ii) If you choose the common stack monitoring option:
(A) For each hour in which valid data are obtained for all
parameters, you must calculate the pollutant emission rate and
(B) You must assign the calculated pollutant emission rate to each
unit that shares the common stack.
(4) Unit with a main stack and a bypass stack. If the exhaust
configuration of an affected unit consists of a main stack and a bypass
stack, you shall install CEMS on both the main stack and the bypass
stack, or, if it is not feasible to certify and quality-assure the data
from a monitoring system on the bypass stack, you shall install a CEMS
only on the main stack and count bypass hours of deviation from the
monitoring requirements.
(5) Unit with a common control device with multiple stack or duct
configuration. If the flue gases from an affected unit, which is
configured such that emissions are controlled with a common control
device or series of control devices, are discharged to the atmosphere
through more than one stack or are fed into a single stack through two
or more ducts, you may:
(i) Install required CEMS, PM CPMS, and sorbent trap monitoring
systems in each of the multiple stacks;
(ii) Install required CEMS, PM CPMS, and sorbent trap monitoring
systems in each of the ducts that feed into the stack;
(iii) Install required CEMS, PM CPMS, and sorbent trap monitoring
systems in one of the multiple stacks or ducts and monitor the flows
and dilution rates in all multiple stacks or ducts in order to
determine total exhaust gas flow rate and pollutant mass emissions rate
in accordance with the applicable limit; or
(iv) In the case of multiple ducts feeding into a single stack,
install CEMS, PM CPMS, and sorbent trap
[[Page 9477]]
monitoring systems in the single stack as described in paragraph (a)(1)
of this section.
(6) Unit with multiple parallel control devices with multiple
stacks. If the flue gases from an affected unit, which is configured
such that emissions are controlled with multiple parallel control
devices or multiple series of control devices are discharged to the
atmosphere through more than one stack, you shall install the required
CEMS, PM CPMS, and sorbent trap monitoring systems described in each of
the multiple stacks. You shall calculate hourly flow-weighted average
pollutant emission rates for the unit as follows:
(i) Calculate the pollutant emission rate at each stack or duct for
each hour in which valid data are obtained for all parameters;
(ii) Multiply each calculated hourly pollutant emission rate at
each stack or duct by the corresponding hourly stack gas flow rate at
that stack or duct;
(iii) Sum the products determined under paragraph (a)(5)(iii)(B) of
this section; and
(iv) Divide the result obtained in paragraph (a)(5)(iii)(C) of this
section by the total hourly stack gas flow rate for the unit, summed
across all of the stacks or ducts.
(b) If you use an oxygen (O2) or carbon dioxide
(CO2) CEMS to convert measured pollutant concentrations to
the units of the applicable emissions limit, the O2 or
CO2 concentrations shall be monitored at a location that
represents emissions to the atmosphere, i.e., at the outlet of the EGU,
downstream of all emission control devices. You must install, certify,
maintain, and operate the CEMS according to part 75 of this chapter.
Use only quality-assured O2 or CO2 data in the
emissions calculations; do not use part 75 substitute data values.
(c) If you are required to use a stack gas flow rate monitor,
either for routine operation of a sorbent trap monitoring system or to
convert pollutant concentrations to units of an electrical output-based
emission standard in Table 1 or 2 to this subpart, you must install,
certify, operate, and maintain the monitoring system and conduct on-
going quality-assurance testing of the system according to part 75 of
this chapter. Use only unadjusted, quality-assured flow rate data in
the emissions calculations. Do not apply bias adjustment factors to the
flow rate data and do not use substitute flow rate data in the
calculations.
(d) If you are required to make corrections for stack gas moisture
content when converting pollutant concentrations to the units of an
emission standard in Table 1 of 2 to this subpart, you must install,
certify, operate, and maintain a moisture monitoring system in
accordance with part 75 of this chapter. Alternatively, for coal-fired
units, you may use appropriate fuel-specific default moisture values
from Sec. 75.11(b) of this chapter to estimate the moisture content of
the stack gas or you may petition the Administrator under Sec. 75.66
of this chapter for use of a default moisture value for non-coal-fired
units. If you install and operate a moisture monitoring system, do not
use substitute moisture data in the emissions calculations.
(e) If you use an HCl and/or HF CEMS, you must install, certify,
operate, maintain, and quality-assure the data from the monitoring
system in accordance with appendix B to this subpart. Calculate and
record a 30-boiler operating day rolling average HCl or HF emission
rate in the units of the standard, updated after each new boiler
operating day. Each 30-boiler operating day rolling average emission
rate is the average of all the valid hourly HCl or HF emission rates in
the preceding 30 boiler operating days (see section 9.4 of appendix B
to this subpart).
(f)(1) If you use an SO2 CEMS, you must install the
monitor at the outlet of the EGU, downstream of all emission control
devices, and you must certify, operate, and maintain the CEMS according
to part 75 of this chapter.
(2) For on-going QA, the SO2 CEMS must meet the
applicable daily, quarterly, and semiannual or annual requirements in
sections 2.1 through 2.3 of appendix B to part 75 of this chapter, with
the following addition: You must perform the linearity checks required
in section 2.2 of appendix B to part 75 of this chapter if the
SO2 CEMS has a span value of 30 ppm or less.
(3) Calculate and record a 30-boiler operating day rolling average
SO2 emission rate in the units of the standard, updated
after each new boiler operating day. Each 30-boiler operating day
rolling average emission rate is the average of all of the valid
SO2 emission rates in the preceding 30 boiler operating
days.
(4) Use only unadjusted, quality-assured SO2
concentration values in the emissions calculations; do not apply bias
adjustment factors to the part 75 SO2 data and do not use
part 75 substitute data values.
(g) If you use a Hg CEMS or a sorbent trap monitoring system, you
must install, certify, operate, maintain and quality-assure the data
from the monitoring system in accordance with appendix A to this
subpart. You must calculate and record a 30-boiler operating day
rolling average Hg emission rate, in units of the standard, updated
after each new boiler operating day. Each 30-boiler operating day
rolling average emission rate, calculated according to section 6.2 of
appendix A to the subpart, is the average of all of the valid hourly Hg
emission rates in the preceding 30 boiler operating days. Section
7.1.4.3 of appendix A to this subpart explains how to reduce sorbent
trap monitoring system data to an hourly basis.
(h) If you use a PM CPMS to demonstrate continuous compliance with
an operating limit, you must install, calibrate, maintain, and operate
the PM CPMS and record the output of the system as specified in
paragraphs (h)(1) through (5) of this section.
(1) Install, calibrate, operate, and maintain your PM CPMS
according to the procedures in your approved site-specific monitoring
plan developed in accordance with Sec. 63.10000(d), and meet the
requirements in paragraphs (h)(1)(i) through (iii) of this section.
(i) The operating principle of the PM CPMS must be based on in-
stack or extractive light scatter, light scintillation, beta
attenuation, or mass accumulation detection of the exhaust gas or
representative sample. The reportable measurement output from the PM
CPMS may be expressed as milliamps, stack concentration, or other raw
data signal.
(ii) The PM CPMS must have a cycle time (i.e., period required to
complete sampling, measurement, and reporting for each measurement) no
longer than 60 minutes.
(iii) The PM CPMS must be capable, at a minimum, of detecting and
responding to particulate matter concentrations of 0.5 mg/acm.
(2) For a new unit, complete the initial PM CPMS performance
evaluation no later than October 13, 2012 or 180 days after the date of
initial startup, whichever is later. For an existing unit, complete the
initial performance evaluation no later than October 13, 2015.
(3) Collect PM CPMS hourly average output data for all boiler
operating hours except as indicated in paragraph (h)(5) of this
section. Express the PM CPMS output as milliamps, PM concentration, or
other raw data signal value.
(4) Calculate the arithmetic 30-boiler operating day rolling
average of all of the hourly average PM CPMS output collected during
all nonexempt boiler operating hours data (e.g., milliamps, PM
concentration, raw data signal).
[[Page 9478]]
(5) You must collect data using the PM CPMS at all times the
process unit is operating and at the intervals specified in paragraph
(h)(1)(ii) of this section, except for periods of monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
required monitoring system quality assurance or quality control
activities (including, as applicable, calibration checks and required
zero and span adjustments), and any scheduled maintenance as defined in
your site-specific monitoring plan.
(6) You must use all the data collected during all boiler operating
hours in assessing the compliance with your operating limit except:
(i) Any data collected during monitoring system malfunctions,
repairs associated with monitoring system malfunctions, or required
monitoring system quality assurance or quality control activities
conducted during monitoring system malfunctions are not used in
calculations (report any such periods in your annual deviation report);
(ii) Any data collected during periods when the monitoring system
is out of control as specified in your site-specific monitoring plan,
repairs associated with periods when the monitoring system is out of
control, or required monitoring system quality assurance or quality
control activities conducted during out-of-control periods are not used
in calculations (report emissions or operating levels and report any
such periods in your annual deviation report);
(iii) Any data recorded during periods of startup or shutdown.
(7) You must record and make available upon request results of PM
CPMS system performance audits, as well as the dates and duration of
periods from when the PM CPMS is out of control until completion of the
corrective actions necessary to return the PM CPMS to operation
consistent with your site-specific monitoring plan.
(i) If you choose to comply with the PM filterable emissions limit
in lieu of metal HAP limits, you may choose to install, certify,
operate, and maintain a PM CEMS and record the output of the PM CEMS as
specified in paragraphs (i)(1) through (5) of this section. The
compliance limit will be expressed as a 30-boiler operating day rolling
average of the numerical emissions limit value applicable for your unit
in tables 1 or 2 to this subpart.
(1) Install and certify your PM CEMS according to the procedures
and requirements in Performance Specification 11--Specifications and
Test Procedures for Particulate Matter Continuous Emission Monitoring
Systems at Stationary Sources in Appendix B to part 60 of this chapter,
using Method 5 at Appendix A-3 to part 60 of this chapter and ensuring
that the front half filter temperature shall be 160[deg]
14[deg]C (320[deg] 25[deg]F). The reportable measurement
output from the PM CEMS must be expressed in units of the applicable
emissions limit (e.g., lb/MMBtu, lb/MWh).
(2) Operate and maintain your PM CEMS according to the procedures
and requirements in Procedure 2--Quality Assurance Requirements for
Particulate Matter Continuous Emission Monitoring Systems at Stationary
Sources in Appendix F to part 60 of this chapter.
(i) You must conduct the relative response audit (RRA) for your PM
CEMS at least once annually.
(ii) You must conduct the relative correlation audit (RCA) for your
PM CEMS at least once every 3 years.
(3) Collect PM CEMS hourly average output data for all boiler
operating hours except as indicated in paragraph (i) of this section.
(4) Calculate the arithmetic 30-boiler operating day rolling
average of all of the hourly average PM CEMS output data collected
during all nonexempt boiler operating hours.
(5) You must collect data using the PM CEMS at all times the
process unit is operating and at the intervals specified in paragraph
(a) of this section, except for periods of monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
and required monitoring system quality assurance or quality control
activities.
(i) You must use all the data collected during all boiler operating
hours in assessing the compliance with your operating limit except:
(A) Any data collected during monitoring system malfunctions,
repairs associated with monitoring system malfunctions, or required
monitoring system quality assurance or control activities conducted
during monitoring system malfunctions in calculations and report any
such periods in your annual deviation report;
(B) Any data collected during periods when the monitoring system is
out of control as specified in your site-specific monitoring plan,
repairs associated with periods when the monitoring system is out of
control, or required monitoring system quality assurance or control
activities conducted during out of control periods in calculations used
to report emissions or operating levels and report any such periods in
your annual deviation report;
(C) Any data recorded during periods of startup or shutdown.
(ii) You must record and make available upon request results of PM
CEMS system performance audits, dates and duration of periods when the
PM CEMS is out of control to completion of the corrective actions
necessary to return the PM CEMS to operation consistent with your site-
specific monitoring plan.
(j) You may choose to comply with the metal HAP emissions limits
using CEMS approved in accordance with Sec. 63.7(f) as an alternative
to the performance test method specified in this rule. If approved to
use a HAP metals CEMS, the compliance limit will be expressed as a 30-
boiler operating day rolling average of the numerical emissions limit
value applicable for your unit in tables 1 or 2. If approved, you may
choose to install, certify, operate, and maintain a HAP metals CEMS and
record the output of the HAP metals CEMS as specified in paragraphs
(j)(1) through (5) of this section.
(1)(i) Install and certify your HAP metals CEMS according to the
procedures and requirements in you approved site specific test plan as
required in Sec. 63.7(e). The reportable measurement output from the
HAP metals CEMS must be expressed in units of the applicable emissions
limit (e.g., lb/MMBtu, lb/MWh) and in the form of a 30-boiler operating
day rolling average.
(ii) Operate and maintain your HAP metals CEMS according to the
procedures and criteria in your site specific performance evaluation
and quality control program plan required in Sec. 63.8(d).
(2) Collect HAP metals CEMS hourly average output data for all
boiler operating hours except as indicated in section (j)(4) of this
section.
(3) Calculate the arithmetic 30-boiler operating day rolling
average of all of the hourly average HAP metals CEMS output data
collected during all nonexempt boiler operating hours data.
(4) You must collect data using the HAP metals CEMS at all times
the process unit is operating and at the intervals specified in
paragraph (a) of this section, except for periods of monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
and required monitoring system quality assurance or quality control
activities.
(i) You must use all the data collected during all boiler operating
hours in assessing the compliance with your emission limit except:
(A) Any data collected during monitoring system malfunctions,
repairs associated with monitoring system malfunctions, or required
monitoring
[[Page 9479]]
system quality assurance or control activities conducted during
monitoring system malfunctions in calculations and report any such
periods in your annual deviation report;
(B) Any data collected during periods when the monitoring system is
out of control as specified in your site-specific monitoring plan,
repairs associated with periods when the monitoring system is out of
control, or required monitoring system quality assurance or control
activities conducted during out of control periods in calculations used
to report emissions or operating levels and report any such periods in
your annual deviation report;
(C) Any data recorded during periods of startup or shutdown.
(ii) You must record and make available upon request results of HAP
metals CEMS system performance audits, dates and duration of periods
when the HAP metals CEMS is out of control to completion of the
corrective actions necessary to return the HAP metals CEMS to operation
consistent with your site-specific performance evaluation and quality
control program plan.
(k) If you demonstrate compliance with the HCl and HF emission
limits for a liquid oil-fired EGU by conducting quarterly testing, you
must also develop a site-specific monitoring plan as provided for in
Sec. 63.10000(c)(2)(iii) and Table 7 to this subpart.
Sec. 63.10011 How do I demonstrate initial compliance with the
emissions limits and work practice standards?
(a) You must demonstrate initial compliance with each emissions
limit that applies to you by conducting performance testing.
(b) If you are subject to an operating limit in Table 4 to this
subpart, you demonstrate initial compliance with HAP metals or
filterable PM emission limit(s) through performance stack tests and you
elect to use a PM CPMS to demonstrate continuous performance, or if,
for a liquid oil-fired unit, and you use quarterly stack testing for
HCl and HF plus site-specific parameter monitoring to demonstrate
continuous performance, you must also establish a site-specific
operating limit, in accordance with Table 4 to this subpart, Sec.
63.10007, and Table 6 to this subpart. You may use only the parametric
data recorded during successful performance tests (i.e., tests that
demonstrate compliance with the applicable emissions limits) to
establish an operating limit.
(c)(1) If you use CEMS or sorbent trap monitoring systems to
measure a HAP (e.g., Hg or HCl) directly, the first 30-boiler operating
day rolling average emission rate obtained with certified CEMS after
the applicable date in Sec. 63.9984 (or, if applicable, prior to that
date, as described in Sec. 63.10005(b)(2)), expressed in units of the
standard, is the initial performance test. Initial compliance is
demonstrated if the results of the performance test meet the applicable
emission limit in Table 1 or 2 to this subpart.
(2) For a unit that uses a CEMS to measure SO2 or PM
emissions for initial compliance, the first 30 boiler operating day
average emission rate obtained with certified CEMS after the applicable
date in Sec. 63.9984 (or, if applicable, prior to that date, as
described in Sec. 63.10005(b)(2)), expressed in units of the standard,
is the initial performance test. Initial compliance is demonstrated if
the results of the performance test meet the applicable SO2
or filterable PM emission limit in Table 1 or 2 to this subpart.
(d) For candidate LEE units, use the results of the performance
testing described in Sec. 63.10005(h) to determine initial compliance
with the applicable emission limit(s) in Table 1 or 2 to this subpart
and to determine whether the unit qualifies for LEE status.
(e) You must submit a Notification of Compliance Status containing
the results of the initial compliance demonstration, according to Sec.
63.10030(e).
(f)(1) You must determine the fuel whose combustion produces the
least uncontrolled emissions, i.e., the cleanest fuel, either natural
gas or distillate oil, that is available on site or accessible nearby
for use during periods of startup or shutdown.
(2) Your cleanest fuel, either natural gas or distillate oil, for
use during periods of startup or shutdown determination may take safety
considerations into account.
(g) You must follow the startup or shutdown requirements given in
Table 3 for each coal-fired, liquid oil-fired, and solid oil-derived
fuel-fired EGU.
Continuous Compliance Requirements
Sec. 63.10020 How do I monitor and collect data to demonstrate
continuous compliance?
(a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by Sec. 63.10000(d).
(b) You must operate the monitoring system and collect data at all
required intervals at all times that the affected EGU is operating,
except for periods of monitoring system malfunctions or out-of-control
periods (see Sec. 63.8(c)(7) of this part), and required monitoring
system quality assurance or quality control activities, including, as
applicable, calibration checks and required zero and span adjustments.
You are required to affect monitoring system repairs in response to
monitoring system malfunctions and to return the monitoring system to
operation as expeditiously as practicable.
(c) You may not use data recorded during EGU startup or shutdown or
monitoring system malfunctions or monitoring system out-of-control
periods, repairs associated with monitoring system malfunctions or
monitoring system out-of-control periods, or required monitoring system
quality assurance or control activities in calculations used to report
emissions or operating levels. You must use all the data collected
during all other periods in assessing the operation of the control
device and associated control system.
(d) Except for periods of monitoring system malfunctions or
monitoring system out-of-control periods, repairs associated with
monitoring system malfunctions or monitoring system out-of-control
periods, and required monitoring system quality assurance or quality
control activities including, as applicable, calibration checks and
required zero and span adjustments), failure to collect required data
is a deviation of the monitoring requirements.
Sec. 63.10021 How do I demonstrate continuous compliance with the
emission limitations, operating limits, and work practice standards?
(a) You must demonstrate continuous compliance with each emissions
limit, operating limit, and work practice standard in Tables 1 through
4 to this subpart that applies to you, according to the monitoring
specified in Tables 6 and 7 to this subpart and paragraphs (b) through
(g) of this section.
(b) Except as otherwise provided in Sec. 63.10020(c), if you use a
CEMS to measure SO2, PM, HCl, HF, or Hg emissions, or using
a sorbent trap monitoring system to measure Hg emissions, you must
demonstrate continuous compliance by using all quality-assured hourly
data recorded by the CEMS (or sorbent trap monitoring system) and the
other required monitoring systems (e.g., flow rate, CO2,
O2, or moisture systems) to calculate the arithmetic average
emissions rate in units of the standard on a continuous 30-boiler
operating day rolling average basis, updated at the end of each new
boiler operating day. Use Equation 8 to determine the 30-boiler
operating day rolling average.
[[Page 9480]]
[GRAPHIC] [TIFF OMITTED] TR16FE12.009
Where:
Heri is the hourly emissions rate for hour i and n is the
number of hourly emissions rate values collected over 30 boiler
operating days.
(c) If you use a PM CPMS data to measure compliance with an
operating limit in Table 4 to this subpart, you must record the PM CPMS
output data for all periods when the process is operating and the PM
CPMS is not out-of-control. You must demonstrate continuous compliance
by using all quality-assured hourly average data collected by the PM
CPMS for all operating hours to calculate the arithmetic average
operating parameter in units of the operating limit (e.g., milliamps,
PM concentration, raw data signal) on a 30 operating day rolling
average basis, updated at the end of each new boiler operating day. Use
Equation 9 to determine the 30 boiler operating day average.
[GRAPHIC] [TIFF OMITTED] TR16FE12.010
Where:
Hpvi is the hourly parameter value for hour i and n is
the number of valid hourly parameter values collected over 30 boiler
operating days.
(d) If you use quarterly performance testing to demonstrate
compliance with one or more applicable emissions limits in Table 1 or 2
to this subpart, you
(1) May skip performance testing in those quarters during which
less than 168 boiler operating hours occur, except that a performance
test must be conducted at least once every calendar year.
(2) Must conduct the performance test as defined in Table 5 to this
subpart and calculate the results of the testing in units of the
applicable emissions standard; and
(3) Must conduct site-specific monitoring for a liquid oil-fired
unit to ensure compliance with the HCl and HF emission limits in Tables
1 and 2 to this subpart, in accordance with the requirements of Sec.
63.10000(c)(2)(iii). The monitoring must meet the general operating
requirements provided in Sec. 63.10020(a).
(e) If you must conduct periodic performance tune-ups of your
EGU(s), as specified in paragraphs (e)(1) through (9) of this section,
perform the first tune-up as part of your initial compliance
demonstration. Notwithstanding this requirement, you may delay the
first burner inspection until the next scheduled unit outage provided
you meet the requirements of Sec. 63.10005. Subsequently, you must
perform an inspection of the burner at least once every 36 calendar
months unless your EGU employs neural network combustion optimization
during normal operations in which case you must perform an inspection
of the burner and combustion controls at least once every 48 calendar
months.
(1) As applicable, inspect the burner and combustion controls, and
clean or replace any components of the burner or combustion controls as
necessary upon initiation of the work practice program and at least
once every required inspection period. Repair of a burner or combustion
control component requiring special order parts may be scheduled as
follows:
(i) Burner or combustion control component parts needing
replacement that affect the ability to optimize NOX and CO
must be installed within 3 calendar months after the burner inspection,
(ii) Burner or combustion control component parts that do not
affect the ability to optimize NOX and CO may be installed
on a schedule determined by the operator;
(2) As applicable, inspect the flame pattern and make any
adjustments to the burner or combustion controls necessary to optimize
the flame pattern. The adjustment should be consistent with the
manufacturer's specifications, if available, or in accordance with best
combustion engineering practice for that burner type;
(3) As applicable, observe the damper operations as a function of
mill and/or cyclone loadings, cyclone and pulverizer coal feeder
loadings, or other pulverizer and coal mill performance parameters,
making adjustments and effecting repair to dampers, controls, mills,
pulverizers, cyclones, and sensors;
(4) As applicable, evaluate windbox pressures and air proportions,
making adjustments and effecting repair to dampers, actuators,
controls, and sensors;
(5) Inspect the system controlling the air-to-fuel ratio and ensure
that it is correctly calibrated and functioning properly. Such
inspection may include calibrating excess O2 probes and/or
sensors, adjusting overfire air systems, changing software parameters,
and calibrating associated actuators and dampers to ensure that the
systems are operated as designed. Any component out of calibration, in
or near failure, or in a state that is likely to negate combustion
optimization efforts prior to the next tune-up, should be corrected or
repaired as necessary;
(6) Optimize combustion to minimize generation of CO and
NOX. This optimization should be consistent with the
manufacturer's specifications, if available, or best combustion
engineering practice for the applicable burner type. NOX
optimization includes burners, overfire air controls, concentric firing
system improvements, neural network or combustion efficiency software,
control systems calibrations, adjusting combustion zone temperature
profiles, and add-on controls such as SCR and SNCR; CO optimization
includes burners, overfire air controls, concentric firing system
improvements, neural network or combustion efficiency software, control
systems calibrations, and adjusting combustion zone temperature
profiles;
(7) While operating at full load or the predominantly operated
load, measure the concentration in the effluent stream of CO and
NOX in ppm, by volume, and oxygen in volume percent, before
and after the tune-up adjustments are made (measurements may be either
on a dry or wet basis, as long as it is the same basis before and after
the adjustments are made). You may use portable CO, NOX and
O2 monitors for this measurement. EGU's employing neural
network optimization systems need only provide a single pre- and post-
tune-up value rather than continual values before and after each
optimization adjustment made by the system;
(8) Maintain on-site and submit, if requested by the Administrator,
an annual report containing the information in paragraphs (e)(1)
through (e)(9) of this section including:
[[Page 9481]]
(i) The concentrations of CO and NOX in the effluent
stream in ppm by volume, and oxygen in volume percent, measured before
and after an adjustment of the EGU combustion systems;
(ii) A description of any corrective actions taken as a part of the
combustion adjustment; and
(iii) The type(s) and amount(s) of fuel used over the 12 calendar
months prior to an adjustment, but only if the unit was physically and
legally capable of using more than one type of fuel during that period;
and
(9) Report the dates of the initial and subsequent tune-ups as
follows:
(i) If the first required tune-up is performed as part of the
initial compliance demonstration, report the date of the tune-up in
hard copy (as specified in Sec. 63.10030) and electronically (as
specified in Sec. 63.10031). Report the date of each subsequent tune-
up electronically (as specified in Sec. 63.10031).
(ii) If the first tune-up is not conducted as part of the initial
compliance demonstration, but is postponed until the next unit outage,
report the date of that tune-up and all subsequent tune-ups
electronically, in accordance with Sec. 63.10031.
(f) You must submit the reports required under Sec. 63.10031 and,
if applicable, the reports required under appendices A and B to this
subpart. The electronic reports required by appendices A and B to this
subpart must be sent to the Administrator electronically in a format
prescribed by the Administrator, as provided in Sec. 63.10031. CEMS
data (except for PM CEMS and any approved alternative monitoring using
a HAP metals CEMS) shall be submitted using EPA's Emissions Collection
and Monitoring Plan System (ECMPS) Client Tool. Other data, including
PM CEMS data, HAP metals CEMS data, and CEMS performance test detail
reports, shall be submitted in the file format generated through use of
EPA's Electronic Reporting Tool, the Compliance and Emissions Data
Reporting Interface, or alternate electronic file format, all as
provided for under Sec. 63.10031.
(g) You must report each instance in which you did not meet an
applicable emissions limit or operating limit in Tables 1 through 4 to
this subpart or failed to conduct a required tune-up. These instances
are deviations from the requirements of this subpart. These deviations
must be reported according to Sec. 63.10031.
(h) You must keep records as specified in Sec. 63.10032 during
periods of startup and shutdown.
(i) You must provide reports as specified in Sec. 63.10031
concerning activities and periods of startup and shutdown.
Sec. 63.10022 How do I demonstrate continuous compliance under the
emissions averaging provision?
(a) Following the compliance date, the owner or operator must
demonstrate compliance with this subpart on a continuous basis by
meeting the requirements of paragraphs (a)(1) through (3) of this
section.
(1) For each calendar month, demonstrate compliance with the
average weighted emissions limit for the existing units participating
in the emissions averaging option as determined in Sec. 63.10009(f)
and (g);
(2) For each existing unit participating in the emissions averaging
option that is equipped with PM CPMS, maintain the average parameter
value at or below the operating limit established during the most
recent performance test;
(3) For each existing unit participating in the emissions averaging
option venting to a common stack configuration containing affected
units from other subcategories, maintain the appropriate operating
limit for each unit as specified in Table 4 to this subpart that
applies.
(b) Any instance where the owner or operator fails to comply with
the continuous monitoring requirements in paragraphs (a)(1) through (3)
of this section is a deviation.
Sec. 63.10023 How do I establish my PM CPMS operating limit and
determine compliance with it?
(a) During the initial performance test or any such subsequent
performance test that demonstrates compliance with the filterable PM,
individual non-mercury HAP metals, or total non-mercury HAP metals
limit (or for liquid oil-fired units, individual HAP metals or total
HAP metals limit, including Hg) in Table 1 or 2, record all hourly
average output values (e.g., milliamps, stack concentration, or other
raw data signal) from the PM CPMS for the periods corresponding to the
test runs (e.g., nine 1-hour average PM CPMS output values for three 3-
hour test runs).
(b) Determine your operating limit as the highest 1-hour average PM
CPMS output value recorded during the performance test. You must verify
an existing or establish a new operating limit after each repeated
performance test.
(c) You must operate and maintain your process and control
equipment such that the 30 operating day average PM CPMS output does
not exceed the operating limit determined in paragraphs (a) and (b) of
this section.
Notification, Reports, and Records
Sec. 63.10030 What notifications must I submit and when?
(a) You must submit all of the notifications in Sec. Sec. 63.7(b)
and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply
to you by the dates specified.
(b) As specified in Sec. 63.9(b)(2), if you startup your affected
source before April 16, 2012, you must submit an Initial Notification
not later than 120 days after April 16, 2012.
(c) As specified in Sec. 63.9(b)(4) and (b)(5), if you startup
your new or reconstructed affected source on or after April 16, 2012,
you must submit an Initial Notification not later than 15 days after
the actual date of startup of the affected source.
(d) When you are required to conduct a performance test, you must
submit a Notification of Intent to conduct a performance test at least
30 days before the performance test is scheduled to begin.
(e) When you are required to conduct an initial compliance
demonstration as specified in Sec. 63.10011(a), you must submit a
Notification of Compliance Status according to Sec. 63.9(h)(2)(ii).
The Notification of Compliance Status report must contain all the
information specified in paragraphs (e)(1) through (7), as applicable.
(1) A description of the affected source(s) including
identification of which subcategory the source is in, the design
capacity of the source, a description of the add-on controls used on
the source, description of the fuel(s) burned, including whether the
fuel(s) were determined by you or EPA through a petition process to be
a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from
discarded non-hazardous secondary materials within the meaning of 40
CFR 241.3, and justification for the selection of fuel(s) burned during
the performance test.
(2) Summary of the results of all performance tests and fuel
analyses and calculations conducted to demonstrate initial compliance
including all established operating limits.
(3) Identification of whether you plan to demonstrate compliance
with each applicable emission limit through performance testing; fuel
moisture analyses; performance testing with operating limits (e.g., use
of PM CPMS); CEMS; or a sorbent trap monitoring system.
(4) Identification of whether you plan to demonstrate compliance by
emissions averaging.
[[Page 9482]]
(5) A signed certification that you have met all applicable
emission limits and work practice standards.
(6) If you had a deviation from any emission limit, work practice
standard, or operating limit, you must also submit a brief description
of the deviation, the duration of the deviation, emissions point
identification, and the cause of the deviation in the Notification of
Compliance Status report.
(7) In addition to the information required in Sec. 63.9(h)(2),
your notification of compliance status must include the following:
(i) A summary of the results of the annual performance tests and
documentation of any operating limits that were reestablished during
this test, if applicable. If you are conducting stack tests once every
3 years consistent with Sec. 63.10006(i), the date of the last three
stack tests, a comparison of the emission level you achieved in the
last three stack tests to the 50 percent emission limit threshold
required in Sec. 63.10006(i), and a statement as to whether there have
been any operational changes since the last stack test that could
increase emissions.
(ii) Certifications of compliance, as applicable, and must be
signed by a responsible official stating:
(A) ``This EGU complies with the requirements in Sec. 63.10021(a)
to demonstrate continuous compliance.'' and
(B) ``No secondary materials that are solid waste were combusted in
any affected unit.''
Sec. 63.10031 What reports must I submit and when?
(a) You must submit each report in Table 8 to this subpart that
applies to you. If you are required to (or elect to) continuously
monitor Hg and/or HCl and/or HF emissions, you must also submit the
electronic reports required under appendix A and/or appendix B to the
subpart, at the specified frequency.
(b) Unless the Administrator has approved a different schedule for
submission of reports under Sec. 63.10(a), you must submit each report
by the date in Table 8 to this subpart and according to the
requirements in paragraphs (b)(1) through (5) of this section.
(1) The first compliance report must cover the period beginning on
the compliance date that is specified for your affected source in Sec.
63.9984 and ending on June 30 or December 31, whichever date is the
first date that occurs at least 180 days after the compliance date that
is specified for your source in Sec. 63.9984.
(2) The first compliance report must be postmarked or submitted
electronically no later than July 31 or January 31, whichever date is
the first date following the end of the first calendar half after the
compliance date that is specified for your source in Sec. 63.9984.
(3) Each subsequent compliance report must cover the semiannual
reporting period from January 1 through June 30 or the semiannual
reporting period from July 1 through December 31.
(4) Each subsequent compliance report must be postmarked or
submitted electronically no later than July 31 or January 31, whichever
date is the first date following the end of the semiannual reporting
period.
(5) For each affected source that is subject to permitting
regulations pursuant to part 70 or part 71 of this chapter, and if the
permitting authority has established dates for submitting semiannual
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance
reports according to the dates the permitting authority has established
instead of according to the dates in paragraphs (b)(1) through (4) of
this section.
(c) The compliance report must contain the information required in
paragraphs (c)(1) through (4) of this section.
(1) The information required by the summary report located in
63.10(e)(3)(vi).
(2) The total fuel use by each affected source subject to an
emission limit, for each calendar month within the semiannual reporting
period, including, but not limited to, a description of the fuel,
whether the fuel has received a non-waste determination by EPA or your
basis for concluding that the fuel is not a waste, and the total fuel
usage amount with units of measure.
(3) Indicate whether you burned new types of fuel during the
reporting period. If you did burn new types of fuel you must include
the date of the performance test where that fuel was in use.
(4) Include the date of the most recent tune-up for each unit
subject to the requirement to conduct a performance tune-up according
to Sec. 63.10021(e). Include the date of the most recent burner
inspection if it was not done annually and was delayed until the next
scheduled unit shutdown.
(d) For each excess emissions occurring at an affected source where
you are using a CMS to comply with that emission limit or operating
limit, you must include the information required in Sec.
63.10(e)(3)(v) in the compliance report specified in section (c).
(e) Each affected source that has obtained a Title V operating
permit pursuant to part 70 or part 71 of this chapter must report all
deviations as defined in this subpart in the semiannual monitoring
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A). If an affected source submits a compliance report
pursuant to Table 8 to this subpart along with, or as part of, the
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or
40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all
required information concerning deviations from any emission limit,
operating limit, or work practice requirement in this subpart,
submission of the compliance report satisfies any obligation to report
the same deviations in the semiannual monitoring report. Submission of
a compliance report does not otherwise affect any obligation the
affected source may have to report deviations from permit requirements
to the permit authority.
(f) As of January 1, 2012, and within 60 days after the date of
completing each performance test, you must submit the results of the
performance tests required by this subpart to EPA's WebFIRE database by
using the Compliance and Emissions Data Reporting Interface (CEDRI)
that is accessed through EPA's Central Data Exchange (CDX)
(www.epa.gov/cdx). Performance test data must be submitted in the file
format generated through use of EPA's Electronic Reporting Tool (ERT)
(see https://www.epa.gov/ttn/chief/ert/). Only data collected
using those test methods on the ERT Web site are subject to this
requirement for submitting reports electronically to WebFIRE. Owners or
operators who claim that some of the information being submitted for
performance tests is confidential business information (CBI) must
submit a complete ERT file including information claimed to be CBI on a
compact disk or other commonly used electronic storage media
(including, but not limited to, flash drives) to EPA. The electronic
media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE
CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page
Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be
submitted to EPA via CDX as described earlier in this paragraph. At the
discretion of the delegated authority, you must also submit these
reports, including the confidential business information, to the
delegated authority
[[Page 9483]]
in the format specified by the delegated authority.
(1) Within 60 days after the date of completing each CEMS
(SO2, PM, HCl, HF, and Hg) performance evaluation test, as
defined in Sec. 63.2 and required by this subpart, you must submit the
relative accuracy test audit (RATA) data (or, for PM CEMS, RCA and RRA
data) required by this subpart to EPA's WebFIRE database by using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx).
The RATA data shall be submitted in the file format generated through
use of EPA's Electronic Reporting Tool (ERT) (https://www.epa.gov/ttn/chief/ert/). Only RATA data compounds listed on the ERT Web
site are subject to this requirement. Owners or operators who claim
that some of the information being submitted for RATAs is confidential
business information (CBI) shall submit a complete ERT file including
information claimed to be CBI on a compact disk or other commonly used
electronic storage media (including, but not limited to, flash drives)
by registered letter to EPA and the same ERT file with the CBI omitted
to EPA via CDX as described earlier in this paragraph. The compact disk
or other commonly used electronic storage media shall be clearly marked
as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE
Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. At the
discretion of the delegated authority, owners or operators shall also
submit these RATAs to the delegated authority in the format specified
by the delegated authority. Owners or operators shall submit
calibration error testing, drift checks, and other information required
in the performance evaluation as described in Sec. 63.2 and as
required in this chapter.
(2) For a PM CEMS, PM CPMS, or approved alternative monitoring
using a HAP metals CEMS, within 60 days after the reporting periods
ending on March 31st, June 30th, September 30th, and December 31st, you
must submit quarterly reports to EPA's WebFIRE database by using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx).
You must use the appropriate electronic reporting form in CEDRI or
provide an alternate electronic file consistent with EPA's reporting
form output format. For each reporting period, the quarterly reports
must include all of the calculated 30-boiler operating day rolling
average values derived from the CEMS and PM CPMS.
(3) Reports for an SO2 CEMS, a Hg CEMS or sorbent trap
monitoring system, an HCl or HF CEMS, and any supporting monitors for
such systems (such as a diluent or moisture monitor) shall be submitted
using the ECMPS Client Tool, as provided for in Appendices A and B to
this subpart and Sec. 63.10021(f).
(4) Submit the compliance reports required under paragraphs (c) and
(d) of this section and the notification of compliance status required
under Sec. 63.10030(e) to EPA's WebFIRE database by using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx).
You must use the appropriate electronic reporting form in CEDRI or
provide an alternate electronic file consistent with EPA's reporting
form output format.
(5) All reports required by this subpart not subject to the
requirements in paragraphs (f)(1) through (4) of this section must be
sent to the Administrator at the appropriate address listed in Sec.
63.13. If acceptable to both the Administrator and the owner or
operator of a source, these reports may be submitted on electronic
media. The Administrator retains the right to require submittal of
reports subject to paragraphs (f)(1), (2), and (3) of this section in
paper format.
(g) If you had a malfunction during the reporting period, the
compliance report must include the number, duration, and a brief
description for each type of malfunction which occurred during the
reporting period and which caused or may have caused any applicable
emission limitation to be exceeded.
Sec. 63.10032 What records must I keep?
(a) You must keep records according to paragraphs (a)(1) and (2) of
this section. If you are required to (or elect to) continuously monitor
Hg and/or HCl and/or HF emissions, you must also keep the records
required under appendix A and/or appendix B to this subpart.
(1) A copy of each notification and report that you submitted to
comply with this subpart, including all documentation supporting any
Initial Notification or Notification of Compliance Status or semiannual
compliance report that you submitted, according to the requirements in
Sec. 63.10(b)(2)(xiv).
(2) Records of performance stack tests, fuel analyses, or other
compliance demonstrations and performance evaluations, as required in
Sec. 63.10(b)(2)(viii).
(b) For each CEMS and CPMS, you must keep records according to
paragraphs (b)(1) through (4) of this section.
(1) Records described in Sec. 63.10(b)(2)(vi) through (xi).
(2) Previous (i.e., superseded) versions of the performance
evaluation plan as required in Sec. 63.8(d)(3).
(3) Request for alternatives to relative accuracy test for CEMS as
required in Sec. 63.8(f)(6)(i).
(4) Records of the date and time that each deviation started and
stopped, and whether the deviation occurred during a period of startup,
shutdown, or malfunction or during another period.
(c) You must keep the records required in Table 7 to this subpart
including records of all monitoring data and calculated averages for
applicable PM CPMS operating limits to show continuous compliance with
each emission limit and operating limit that applies to you.
(d) For each EGU subject to an emission limit, you must also keep
the records in paragraphs (d)(1) through (3) of this section.
(1) You must keep records of monthly fuel use by each EGU,
including the type(s) of fuel and amount(s) used.
(2) If you combust non-hazardous secondary materials that have been
determined not to be solid waste pursuant to 40 CFR 241.3(b)(1), you
must keep a record which documents how the secondary material meets
each of the legitimacy criteria. If you combust a fuel that has been
processed from a discarded non-hazardous secondary material pursuant to
40 CFR 241.3(b)(2), you must keep records as to how the operations that
produced the fuel satisfies the definition of processing in 40 CFR
241.2. If the fuel received a non-waste determination pursuant to the
petition process submitted under 40 CFR 241.3(c), you must keep a
record which documents how the fuel satisfies the requirements of the
petition process.
(3) For an EGU that qualifies as an LEE under Sec. 63.10005(h),
you must keep annual records that document that your emissions in the
previous stack test(s) continue to qualify the unit for LEE status for
an applicable pollutant, and document that there was no change in
source operations including fuel composition and operation of air
pollution control equipment that would cause emissions of the pollutant
to increase within the past year.
(e) If you elect to average emissions consistent with Sec.
63.10009, you must additionally keep a copy of the emissions averaging
implementation
[[Page 9484]]
plan required in Sec. 63.10009(g), all calculations required under
Sec. 63.10009, including daily records of heat input or steam
generation, as applicable, and monitoring records consistent with Sec.
63.10022.
(f) You must keep records of the occurrence and duration of each
startup and/or shutdown.
(g) You must keep records of the occurrence and duration of each
malfunction of an operation (i.e., process equipment) or the air
pollution control and monitoring equipment.
(h) You must keep records of actions taken during periods of
malfunction to minimize emissions in accordance with Sec. 63.10000(b),
including corrective actions to restore malfunctioning process and air
pollution control and monitoring equipment to its normal or usual
manner of operation.
(i) You must keep records of the type(s) and amount(s) of fuel used
during each startup or shutdown.
(j) If you elect to establish that an EGU qualifies as a limited-
use liquid oil-fired EGU, you must keep records of the type(s) and
amount(s) of fuel use in each calendar quarter to document that the
capacity factor limitation for that subcategory is met.
Sec. 63.10033 In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available
for expeditious review, according to Sec. 63.10(b)(1).
(b) As specified in Sec. 63.10(b)(1), you must keep each record
for 5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
(c) You must keep each record on site for at least 2 years after
the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec. 63.10(b)(1). You can keep
the records off site for the remaining 3 years.
Other Requirements and Information
Sec. 63.10040 What parts of the General Provisions apply to me?
Table 9 to this subpart shows which parts of the General Provisions
in Sec. Sec. 63.1 through 63.15 apply to you.
Sec. 63.10041 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by U.S. EPA, or a
delegated authority such as your state, local, or tribal agency. If the
EPA Administrator has delegated authority to your state, local, or
tribal agency, then that agency (as well as the U.S. EPA) has the
authority to implement and enforce this subpart. You should contact
your EPA Regional Office to find out if this subpart is delegated to
your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this
subpart to a state, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities listed in paragraphs (b)(1) through (4) of
this section are retained by the EPA Administrator and are not
transferred to the state, local, or tribal agency; moreover, the U.S.
EPA retains oversight of this subpart and can take enforcement actions,
as appropriate, with respect to any failure by any person to comply
with any provision of this subpart.
(1) Approval of alternatives to the non-opacity emission limits and
work practice standards in Sec. 63.9991(a) and (b) under Sec.
63.6(g).
(2) Approval of major change to test methods in Table 5 to this
subpart under Sec. 63.7(e)(2)(ii) and (f) and as defined in Sec.
63.90, approval of minor and intermediate changes to monitoring
performance specifications/procedures in Table 5 where the monitoring
serves as the performance test method (see definition of ``test
method'' in Sec. 63.2.
(3) Approval of major changes to monitoring under Sec. 63.8(f) and
as defined in Sec. 63.90.
(4) Approval of major change to recordkeeping and reporting under
Sec. 63.10(e) and as defined in Sec. 63.90.
Sec. 63.10042 What definitions apply to this subpart?
Terms used in this subpart are defined in the Clean Air Act (CAA),
in Sec. 63.2 (the General Provisions), and in this section as follows:
Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
Anthracite coal means solid fossil fuel classified as anthracite
coal by American Society of Testing and Materials (ASTM) Method D388-
05, ``Standard Classification of Coals by Rank'' (incorporated by
reference, see Sec. 63.14).
Bituminous coal means coal that is classified as bituminous
according to ASTM Method D388-05, ``Standard Classification of Coals by
Rank'' (incorporated by reference, see Sec. 63.14).
Boiler operating day means a 24-hour period between midnight and
the following midnight during which any fuel is combusted at any time
in the steam generating unit. It is not necessary for the fuel to be
combusted the entire 24-hour period.
Capacity factor for a liquid oil-fired EGU means the total annual
heat input from oil divided by the product of maximum hourly heat input
for the EGU, regardless of fuel, multiplied by 8,760 hours.
Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by ASTM Method D388-05, ``Standard
Classification of Coals by Rank'' (incorporated by reference, see Sec.
63.14), and coal refuse. Synthetic fuels derived from coal for the
purpose of creating useful heat including but not limited to, coal
derived gases (not meeting the definition of natural gas), solvent-
refined coal, coal-oil mixtures, and coal-water mixtures, are
considered ``coal'' for the purposes of this subpart.
Coal-fired electric utility steam generating unit means an electric
utility steam generating unit meeting the definition of ``fossil fuel-
fired'' that burns coal for more than 10.0 percent of the average
annual heat input during any 3 consecutive calendar years or for more
than 15.0 percent of the annual heat input during any one calendar
year.
Coal refuse means any by-product of coal mining, physical coal
cleaning, and coal preparation operations (e.g., culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material with an ash content greater than 50 percent (by weight) and a
heating value less than 13,900 kilojoules per kilogram (6,000 Btu per
pound) on a dry basis.
Cogeneration means a steam-generating unit that simultaneously
produces both electrical and useful thermal (or mechanical) energy from
the same primary energy source.
Cogeneration unit means a stationary, fossil fuel-fired EGU meeting
the definition of ``fossil fuel-fired'' or stationary, integrated
gasification combined cycle:
(1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after
which the unit first produces electricity:
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent
[[Page 9485]]
of total energy input, if useful thermal energy produced is 15 percent
or more of total energy output, or not less than 45 percent of total
energy input, if useful thermal energy produced is less than 15 percent
of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input.
(3) Provided that the total energy input under paragraphs (2)(i)(B)
and (2)(ii) of this definition shall equal the unit's total energy
input from all fuel except biomass if the unit is a boiler.
Combined-cycle gas stationary combustion turbine means a stationary
combustion turbine system where heat from the turbine exhaust gases is
recovered by a waste heat boiler.
Common stack means the exhaust of emissions from two or more
affected units through a single flue.
Continental liquid oil-fired subcategory means any oil-fired
electric utility steam generating unit that burns liquid oil and is
located in the continental United States.
Deviation. (1) Deviation means any instance in which an affected
source subject to this subpart, or an owner or operator of such a
source:
(i) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, work practice standard, or monitoring requirement; or
(ii) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit.
(2) A deviation is not always a violation. The determination of
whether a deviation constitutes a violation of the standard is up to
the discretion of the entity responsible for enforcement of the
standards.
Distillate oil means fuel oils, including recycled oils, that
comply with the specifications for fuel oil numbers 1 and 2, as defined
by ASTM Method D396-10, ``Standard Specification for Fuel Oils''
(incorporated by reference, see Sec. 63.14).
Dry flue gas desulfurization technology, or dry FGD, or spray dryer
absorber (SDA), or spray dryer, or dry scrubber means an add-on air
pollution control system located downstream of the steam generating
unit that injects a dry alkaline sorbent (dry sorbent injection) or
sprays an alkaline sorbent slurry (spray dryer) to react with and
neutralize acid gases such as SO2 and HCl in the exhaust
stream forming a dry powder material. Alkaline sorbent injection
systems in fluidized bed combustors (FBC) or circulating fluidized bed
(CFB) boilers are included in this definition.
Dry sorbent injection (DSI) means an add-on air pollution control
system in which sorbent (e.g., conventional activated carbon,
brominated activated carbon, Trona, hydrated lime, sodium carbonate,
etc.) is injected into the flue gas steam upstream of a PM control
device to react with and neutralize acid gases (such as SO2
and HCl) or Hg in the exhaust stream forming a dry powder material that
may be removed in a primary or secondary PM control device.
Electric Steam generating unit means any furnace, boiler, or other
device used for combusting fuel for the purpose of producing steam
(including fossil-fuel-fired steam generators associated with
integrated gasification combined cycle gas turbines; nuclear steam
generators are not included) for the purpose of powering a generator to
produce electricity or electricity and other thermal energy.
Electric utility steam generating unit (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts electric (MWe) that
serves a generator that produces electricity for sale. A fossil fuel-
fired unit that cogenerates steam and electricity and supplies more
than one-third of its potential electric output capacity and more than
25 MWe output to any utility power distribution system for sale is
considered an electric utility steam generating unit.
Emission limitation means any emissions limit, work practice
standard, or operating limit.
Excess emissions means, with respect to this subpart, results of
any required measurements outside the applicable range (e.g., emissions
limitations, parametric operating limits) that is permitted by this
subpart. The values of measurements will be in the same units and
averaging time as the values specified in this subpart for the
limitations.
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60, 61, and 63; requirements within any applicable state
implementation plan; and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
Flue gas desulfurization system means any add-on air pollution
control system located downstream of the steam generating unit whose
purpose or effect is to remove at least 50 percent of the
SO2 in the exhaust gas stream.
Fossil fuel means natural gas, oil, coal, and any form of solid,
liquid, or gaseous fuel derived from such material.
Fossil fuel-fired means an electric utility steam generating unit
(EGU) that is capable of combusting more than 25 MW of fossil fuels. To
be ``capable of combusting'' fossil fuels, an EGU would need to have
these fuels allowed in its operating permit and have the appropriate
fuel handling facilities on-site or otherwise available (e.g., coal
handling equipment, including coal storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired means any EGU that fired fossil fuels for more than 10.0 percent
of the average annual heat input during any 3 consecutive calendar
years or for more than 15.0 percent of the annual heat input during any
one calendar year after the applicable compliance date.
Fuel type means each category of fuels that share a common name or
classification. Examples include, but are not limited to, bituminous
coal, subbituminous coal, lignite, anthracite, biomass, and residual
oil. Individual fuel types received from different suppliers are not
considered new fuel types.
Fluidized bed boiler, or fluidized bed combustor, or circulating
fluidized boiler, or CFB means a boiler utilizing a fluidized bed
combustion process.
Fluidized bed combustion means a process where a fuel is burned in
a bed of granulated particles which are maintained in a mobile
suspension by the upward flow of air and combustion products.
Gaseous fuel includes, but is not limited to, natural gas, process
gas, landfill gas, coal derived gas, solid oil-derived gas, refinery
gas, and biogas.
Generator means a device that produces electricity.
Gross output means the gross useful work performed by the steam
generated and, for an IGCC electric utility steam generating unit, the
work performed by the stationary combustion turbines. For a unit
generating only electricity, the gross useful work performed is the
gross electrical output from the unit's turbine/generator sets. For a
cogeneration unit, the gross useful work performed is the gross
electrical output, including any such electricity used in the power
production process (which process includes, but is not limited to, any
on-site processing or treatment of fuel combusted at the unit and any
on-site emission controls), or mechanical output plus 75 percent of the
useful thermal output measured relative to ISO conditions that is not
used to generate additional electrical or mechanical
[[Page 9486]]
output or to enhance the performance of the unit (i.e., steam delivered
to an industrial process).
Heat input means heat derived from combustion of fuel in an EGU
(synthetic gas for an IGCC) and does not include the heat input from
preheated combustion air, recirculated flue gases, or exhaust gases
from other sources such as gas turbines, internal combustion engines,
etc.
Integrated gasification combined cycle electric utility steam
generating unit or IGCC means an electric utility steam generating unit
meeting the definition of ``fossil fuel-fired'' that burns a synthetic
gas derived from coal and/or solid oil-derived fuel for more than 10.0
percent of the average annual heat input during any 3 consecutive
calendar years or for more than 15.0 percent of the annual heat input
during any one calendar year in a combined-cycle gas turbine. No solid
coal or solid oil-derived fuel is directly burned in the unit during
operation.
ISO conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
Lignite coal means coal that is classified as lignite A or B
according to ASTM Method D388-05, ``Standard Classification of Coals by
Rank'' (incorporated by reference, see Sec. 63.14).
Limited-use liquid oil-fired subcategory means an oil-fired
electric utility steam generating unit with an annual capacity factor
of less than 8 percent of its maximum or nameplate heat input,
whichever is greater, averaged over a 24-month block contiguous period
commencing April 16, 2015.
Liquid fuel includes, but is not limited to, distillate oil and
residual oil.
Monitoring system malfunction or out of control period means any
sudden, infrequent, not reasonably preventable failure of the
monitoring system to provide valid data. Monitoring system failures
that are caused in part by poor maintenance or careless operation are
not malfunctions.
Natural gas means a naturally occurring fluid mixture of
hydrocarbons (e.g., methane, ethane, or propane) produced in geological
formations beneath the Earth's surface that maintains a gaseous state
at standard atmospheric temperature and pressure under ordinary
conditions. Natural gas contains 20.0 grains or less of total sulfur
per 100 standard cubic feet. Additionally, natural gas must either be
composed of at least 70 percent methane by volume or have a gross
calorific value between 950 and 1,100 Btu per standard cubic foot.
Natural gas does not include the following gaseous fuels: landfill gas,
digester gas, refinery gas, sour gas, blast furnace gas, coal-derived
gas, producer gas, coke oven gas, or any gaseous fuel produced in a
process which might result in highly variable sulfur content or heating
value.
Natural gas-fired electric utility steam generating unit means an
electric utility steam generating unit meeting the definition of
``fossil fuel-fired'' that is not a coal-fired, oil-fired, or IGCC
electric utility steam generating unit and that burns natural gas for
more than 10.0 percent of the average annual heat input during any 3
consecutive calendar years or for more than 15.0 percent of the annual
heat input during any one calendar year.
Net-electric output means the gross electric sales to the utility
power distribution system minus purchased power on a calendar year
basis.
Non-continental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Non-continental liquid oil-fired subcategory means any oil-fired
electric utility steam generating unit that burns liquid oil and is
located outside the continental United States.
Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As),
Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead (Pb),
Manganese (Mn), Nickel (Ni), and Selenium (Se). Oil means crude oil or
petroleum or a fuel derived from crude oil or petroleum, including
distillate and residual oil, solid oil-derived fuel (e.g., petroleum
coke) and gases derived from solid oil-derived fuels (not meeting the
definition of natural gas).
Oil-fired electric utility steam generating unit means an electric
utility steam generating unit meeting the definition of ``fossil fuel-
fired'' that is not a coal-fired electric utility steam generating unit
and that burns oil for more than 10.0 percent of the average annual
heat input during any 3 consecutive calendar years or for more than
15.0 percent of the annual heat input during any one calendar year.
Particulate matter or PM means any finely divided solid material as
measured by the test methods specified under this subpart, or an
alternative method.
Pulverized coal (PC) boiler means an EGU in which pulverized coal
is introduced into an air stream that carries the coal to the
combustion chamber of the EGU where it is fired in suspension.
Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6,
as defined by ASTM Method D396-10, ``Standard Specification for Fuel
Oils'' (incorporated by reference, see Sec. 63.14).
Responsible official means responsible official as defined in 40
CFR 70.2.
Shutdown means the cessation of operation of a boiler for any
purpose. Shutdown begins either when none of the steam from the boiler
is used to generate electricity for sale over the grid or for any other
purpose (including on-site use), or at the point of no fuel being fired
in the boiler, whichever is earlier. Shutdown ends when there is both
no electricity being generated and no fuel being fired in the boiler.
Startup means either the first-ever firing of fuel in a boiler for
the purpose of producing electricity, or the firing of fuel in a boiler
after a shutdown event for any purpose. Startup ends when any of the
steam from the boiler is used to generate electricity for sale over the
grid or for any other purpose (including on-site use).
Stationary combustion turbine means all equipment, including but
not limited to the turbine, the fuel, air, lubrication and exhaust gas
systems, control systems (except emissions control equipment), and any
ancillary components and sub-components comprising any simple cycle
stationary combustion turbine, any regenerative/recuperative cycle
stationary combustion turbine, the combustion turbine portion of any
stationary cogeneration cycle combustion system, or the combustion
turbine portion of any stationary combined cycle steam/electric
generating system. Stationary means that the combustion turbine is not
self propelled or intended to be propelled while performing its
function. Stationary combustion turbines do not include turbines
located at a research or laboratory facility, if research is conducted
on the turbine itself and the turbine is not being used to power other
applications at the research or laboratory facility.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with integrated
gasification combined cycle gas turbines; nuclear steam generators are
not included).
Stoker means a unit consisting of a mechanically operated fuel
feeding mechanism, a stationary or moving grate to support the burning
of fuel and admit undergrate air to the fuel, an overfire air system to
complete combustion, and an ash discharge system. There are two general
types of stokers: underfeed and
[[Page 9487]]
overfeed. Overfeed stokers include mass feed and spreader stokers.
Subbituminous coal means coal that is classified as subbituminous
A, B, or C according to ASTM Method D388-05, ``Standard Classification
of Coals by Rank'' (incorporated by reference, see Sec. 63.14).
Unit designed for coal 8,300 Btu/lb subcategory means
any coal-fired EGU that is not a coal-fired EGU in the ``unit designed
for low rank virgin coal'' subcategory.
Unit designed for low rank virgin coal subcategory means any coal-
fired EGU that is designed to burn and that is burning nonagglomerating
virgin coal having a calorific value (moist, mineral matter-free basis)
of less than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and
operates at or near the mine that produces such coal.
Unit designed to burn solid oil-derived fuel subcategory means any
oil-fired EGU that burns solid oil-derived fuel.
Voluntary consensus standards or VCS mean technical standards
(e.g., materials specifications, test methods, sampling procedures,
business practices) developed or adopted by one or more voluntary
consensus bodies. The EPA/OAQPS has by precedent only used VCS that are
written in English. Examples of VCS bodies are: American Society of
Testing and Materials (ASTM), American Society of Mechanical Engineers
(ASME), International Standards Organization (ISO), Standards Australia
(AS), British Standards (BS), Canadian Standards (CSA), European
Standard (EN or CEN) and German Engineering Standards (VDI). The types
of standards that are not considered VCS are standards developed by:
the U.S. states, e.g., California (CARB) and Texas (TCEQ); industry
groups, such as American Petroleum Institute (API), Gas Processors
Association (GPA), and Gas Research Institute (GRI); and other branches
of the U.S. government, e.g., Department of Defense (DOD) and
Department of Transportation (DOT). This does not preclude EPA from
using standards developed by groups that are not VCS bodies within an
EPA rule. When this occurs, EPA has done searches and reviews for VCS
equivalent to these non-VCS methods.
Wet flue gas desulfurization technology, or wet FGD, or wet
scrubber means any add-on air pollution control device that is located
downstream of the steam generating unit that mixes an aqueous stream or
slurry with the exhaust gases from an EGU to control emissions of PM
and/or to absorb and neutralize acid gases, such as SO2 and
HCl.
Work practice standard means any design, equipment, work practice,
or operational standard, or combination thereof, which is promulgated
pursuant to CAA section 112(h).
Tables to Subpart UUUUU of Part 63
Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or Reconstructed EGUs
[As stated in Sec. 63.9991, you must comply with the following applicable emission limits]
----------------------------------------------------------------------------------------------------------------
Using these
requirements, as
You must meet the appropriate (e.g.,
following emission specified sampling
If your EGU is in this subcategory . For the following limits and work volume or test run
. . pollutants . . . practice standards . . duration) and
. limitations with the
test methods in Table .
. .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank a. Filterable 7.0E-3 lb/MWh1......... Collect a minimum of 4
virgin coal. particulate matter dscm per run.
(PM).
OR OR .......................
Total non-Hg HAP metals 6.0E-2 lb/GWh.......... Collect a minimum of 4
dscm per run.
OR OR
individual HAP metals:. Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GW.
Arsenic (As)........... 3.0E-3 lb/GWh.
Beryllium (Be)......... 6.0E-4 lb/GWh.
Cadmium (Cd)........... 4.0E-4 lb/GWh.
Chromium (Cr).......... 7.0E-3 lb/GWh.
Cobalt (Co)............ 2.0E-3 lb/GWh.
Lead (Pb).............. 2.0E-3 lb/GWh.
Manganese (Mn)......... 4.0E-3 lb/GWh.
Nickel (Ni)............ 4.0E-2 lb/GWh.
Selenium (Se).......... 6.0E-3 lb/GWh.
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HC1). a minimum of 3 dscm
per run.
For ASTM D6348-03 2 or
Method 320, sample for
a minimum of 1 hour.
OR.
Sulfur dioxide (SO2) 3. 4.0E-1 lb/MWh.......... SO2 CEMS.
c. Mercury (Hg)........ 2.0E-4 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired units low rank virgin a. Filterable 7.0E-3 lb/MWh1......... Collect a minimum of 4
coal. particulate matter dscm per run.
(PM).
OR OR .......................
Total non-Hg HAP metals 6.0E-2 lb/GWh.......... Collect a minimum of 4
dscm per run.
OR OR .......................
Individual HAP metals: ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh.
Arsenic (As)........... 3.0E-3 lb/GWh.
[[Page 9488]]
Beryllium (Be)......... 6.0E-4 lb/GWh.
Cadmium (Cd)........... 4.0E-4 lb/GWh.
Chromium (Cr).......... 7.0E-3 lb/GWh.
Cobalt (Co)............ 2.0E-3 lb/GWh.
Lead (Pb).............. 2.0E-3 lb/GWh.
Manganese (Mn)......... 4.0E-3 lb/GWh.
Nickel (Ni)............ 4.0E-2 lb/GWh.
Selenium (Se).......... 6.0E-3 lb/GWh.
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR .......................
Sulfur dioxide (SO2) 3. 4.0E-1 lb/MWh.......... SO2 CEMS.
c. Mercury (Hg)........ 4.0E-2 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit......................... a. Filterable 7.0E-2 lb/MWh 4........ Collect a minimum of 1
particulate matter 9.0E-2 lb/MWh 5........ dscm per run.
(PM).
OR OR .......................
Total non-Hg HAP metals 4.0E-1 lb/GWh.......... Collect a minimum of 1
dscm per run.
OR OR .......................
Individual HAP metals: ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 2.0E-2 lb/GWh.
Arsenic (As)........... 2.0E-2 lb/GWh.
Beryllium (Be)......... 1.0E-3 lb/GWh.
Cadmium (Cd)........... 2.0E-3 lb/GWh.
Chromium (Cr).......... 4.0E-2 lb/GWh.
Cobalt (Co)............ 4.0E-3 lb/GWh.
Lead (Pb).............. 9.0E-3 lb/GWh.
Manganese (Mn)......... 2.0E-2 lb/GWh.
Nickel (Ni)............ 7.0E-2 lb/GWh.
Selenium (Se).......... 3.0E-1 lb/GWh.
b. Hydrogen chloride 2.0E-3 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR .......................
Sulfur dioxide (SO2) 3 4.0E-1 lb/MWh.......... SO2 CEMS.
c. Mercury (Hg)........ 3.0E-3 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit--continental a. Filterable 7.0E-2 lb/MWh1......... Collect a minimum of 1
(excluding limited-use liquid oil- particulate matter dscm per run.
fired subcategory units). (PM).
OR OR .......................
Total HAP metals....... 2.0E-4 lb/MWh.......... Collect a minimum of 2
dscm per run.
OR OR .......................
Individual HAP metals: ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 1.0E-2 lb/GWh.
Arsenic (As)........... 3.0E-3 lb/GWh.
Beryllium (Be)......... 5.0E-4 lb/GWh.
Cadmium (Cd)........... 2.0E-4 lb/GWh.
Chromium (Cr).......... 2.0E-2 lb/GWh.
Cobalt (Co)............ 3.0E-2 lb/GWh.
Lead (Pb).............. 8.0E-3 lb/GWh.
Manganese (Mn)......... 2.0E-2 lb/GWh.
Nickel (Ni)............ 9.0E-2 lb/GWh.
Selenium (Se).......... 2.0E-2 lb/GWh.
[[Page 9489]]
Mercury (Hg) 1.0E-4 lb/GWh.......... For Method 30B sample
volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\
the standard.
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HCl) a minimum of 3 dscm
per run.
For ASTM D6348-03 2 or
Method 320, sample for
a minimum of 1 hour.
c. Hydrogen fluoride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HF) a minimum of 3 dscm
per run.
For ASTM D6348-03 2 or
Method 320, sample for
a minimum of 1 hour.
----------------------------------------------------------------------------------------------------------------
5. Liquid oil-fired unit--non- a. Filterable 2.0E-1 lb/MWh1......... Collect a minimum of 1
continental (excluding limited-use particulate matter dscm per run.
liquid oil-fired subcategory units). (PM).
OR OR .......................
Total HAP metals 7.0E-3 lb/MWh.......... Collect a minimum of 1
dscm per run.
OR OR .......................
Individual HAP metals: ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh.
Arsenic (As)........... 6.0E-2 lb/GWh.
Beryllium (Be)......... 2.0E-3 lb/GWh.
Cadmium (Cd)........... 2.0E-3 lb/GWh.
Chromium (Cr).......... 2.0E-2 lb/GWh.
Cobalt (Co)............ 3.0E-1 lb/GWh.
Lead (Pb).............. 3.0E-2 lb/GWh.
Manganese (Mn)......... 1.0E-1 lb/GWh.
Nickel (Ni)............ 4.1E-0 lb/GWh.
Selenium (Se).......... 2.0E-2 lb/GWh.
Mercury (Hg)........... 4.0E-4 lb/GWh.......... For Method 30B sample
volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be < \1/2\
the standard.
b. Hydrogen chloride 2.0E-3 lb/MWh.......... For Method 26A, collect
(HCl) a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-032 or
Method 320, sample for
a minimum of 1 hour
c. Hydrogen fluoride 5.0E-4 lb/MWh.......... For Method 26A, collect
(HF) a minimum of 3 dscm
per run.
For ASTM D6348-03 2 or
Method 320, sample for
a minimum of 1 hour.
----------------------------------------------------------------------------------------------------------------
6. Solid oil-derived fuel-fired unit. a. Filterable 2.0E-2 lb/MWh1......... Collect a minimum of 1
particulate matter dscm per run.
(PM).
OR OR .......................
Total non-Hg HAP metals 6.0E-1 lb/GWh.......... Collect a minimum of 1
dscm per run.
OR OR .......................
Individual HAP metals: ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh.
Arsenic (As)........... 3.0E-3 lb/GWh.
Beryllium (Be)......... 6.0E-4 lb/GWh.
Cadmium (Cd)........... 7.0E-4 lb/GWh.
Chromium (Cr).......... 6.0E-3 lb/GWh.
Cobalt (Co)............ 2.0E-3 lb/GWh.
[[Page 9490]]
Lead (Pb).............. 2.0E-2 lb/GWh.
Manganese (Mn)......... 7.0E-3 lb/GWh.
Nickel (Ni)............ 4.0E-2 lb/GWh.
Selenium (Se).......... 6.0E-3 lb/GWh.
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 2 or
Method 320, sample for
a minimum of 1 hour.
OR .......................
Sulfur dioxide (SO2) 3. 4.0E-1 lb/MWh.......... SO2 CEMS.
c. Mercury (Hg)........ 2.0E-3 lb/GWh.......... Hg CEMS or Sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
1 Gross electric output.
2 Incorporated by reference, see Sec. 63.14.
3 You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
installed.
4 Duct burners on syngas; gross electric output.
5 Duct burners on natural gas; gross electric output
Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing EGUs
[As stated in Sec. 63.9991, you must comply with the following applicable emission limits] \1\
----------------------------------------------------------------------------------------------------------------
Using these
requirements, as
You must meet the appropriate (e.g.,
For the following following emission specified sampling
If your EGU is in this subcategory pollutants limits and work volume or test run
practice standards duration) and
limitations with the
test methods in Table 5
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
virgin coal. particulate matter 1 lb/MWh \2\. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals
Antimony (Sb).......... 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Arsenic (As)........... 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)......... 2.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Chromium (Cr).......... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)............ 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Lead (Pb).............. 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Manganese (Mn)......... 4.0E0 lb/TBtu or 5.0E-2
lb/GWh.
Nickel (Ni)............ 3.5E0 lb/TBtu or 4.0E-2
lb/GWh.
Selenium (Se).......... 5.0E0 lb/TBtu or 6.0E-2
lb/GWh.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 1.5E0 lb/MWh.
c. Mercury (Hg)........ 1.2E0 lb/TBtu or 1.3E-2 LEE Testing for 30 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired unit low rank virgin a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
coal. particulate matter 1 lb/MWh2. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
[[Page 9491]]
Individual HAP metals: ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Arsenic (As)........... 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)......... 2.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Chromium (Cr).......... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)............ 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Lead (Pb).............. 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Manganese (Mn)......... 4.0E0 lb/TBtu or 5.0E-2
lb/GWh.
Nickel (Ni)............ 3.5E0 lb/TBtu or 4.0E-2
lb/GWh.
Selenium (Se).......... 5.0E0 lb/TBtu or 6.0E-2
lb/GWh.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 1.5E0 lb/MWh.
c. Mercury (Hg)........ 4.0E0 lb/TBtu or 4.0E-2 LEE Testing for 30 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit......................... a. Filterable 4.0E-2 lb/MMBtu or 4.0E- Collect a minimum of 1
particulate matter 1 lb/MWh2. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 1.4E0 lb/TBtu or 2.0E-2
lb/GWh.
Arsenic (As)........... 1.5E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)......... 1.0E-1 lb/TBtu or 1.0E-
3 lb/GWh.
Cadmium (Cd)........... 1.5E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Chromium (Cr).......... 2.9E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)............ 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Lead (Pb).............. 1.9E+2 lb/MMBtu or
1.8E0 lb/MWh.
Manganese (Mn)......... 2.5E0 lb/TBtu or 3.0E-2
lb/GWh.
Nickel (Ni)............ 6.5E0 lb/TBtu or 7.0E-2
lb/GWh.
Selenium (Se).......... 2.2E+1 lb/TBtu or 3.0E-
1 lb/GWh.
b. Hydrogen chloride 5.0E-4 lb/MMBtu or 5.0E- For Method 26A, collect
(HCl). 3 lb/MWh. a minimum of 1 dscm
per
run; for Method 26,
collect a minimum of
120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
c. Mercury (Hg)........ 2.5E0 lb/TBtu or 3.0E-2 LEE Testing for 30 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit--continental a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
(excluding limited-use liquid oil- particulate matter 1 lb/MWh2. dscm per run.
fired subcategory units). (PM).
OR OR
Total HAP metals....... 8.0E-4 lb/MMBtu or 8.0E- Collect a minimum of 1
3 lb/MWh. dscm per run.
OR OR
Individual HAP metals.. Collect a minimum of 1
dscm per run.
[[Page 9492]]
Antimony (Sb).......... 1.3E+1 lb/TBtu or 2.0E-
1 lb/GWh.
Arsenic (As)........... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Beryllium (Be)......... 2.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Chromium (Cr).......... 5.5E0 lb/TBtu or 6.0E-2
lb/GWh.
Cobalt (Co)............ 2.1E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Lead (Pb).............. 8.1E0 lb/TBtu or 8.0E-2
lb/GWh.
Manganese (Mn)......... 2.2E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Nickel (Ni)............ 1.1E+2 lb/TBtu or 1.1E0
lb/GWh.
Selenium (Se).......... 3.3E0 lb/TBtu or 4.0E-2
lb/GWh.
Mercury (Hg)........... 2.0E-1 lb/TBtu or 2.0E- For Method 30B sample
3 lb/GWh. volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be < \1/2\
the standard.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 1.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 1 dscm
per
Run; for Method 26,
collect a minimum of
120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
c. Hydrogen fluoride 4.0E-4 lb/MMBtu or 4.0E- For Method 26A, collect
(HF). 3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
----------------------------------------------------------------------------------------------------------------
5. Liquid oil-fired unit--non- a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
continental (excluding limited-use particulate matter 1 lb/MWh2. dscm per run.
liquid oil-fired subcategory units). (PM).
OR OR
Total HAP metals....... 6.0E-4 lb/MMBtu or 7.0E- Collect a minimum of 1
3 lb/MWh. dscm per run.
OR OR
Individual HAP metals.. ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 2.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Arsenic (As)........... 4.3E0 lb/TBtu or 8.0E-2
lb/GWh.
Beryllium (Be)......... 6.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Chromium (Cr).......... 3.1E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Cobalt (Co)............ 1.1E+2 lb/TBtu or 1.4E0
lb/GWh.
Lead (Pb).............. 4.9E0 lb/TBtu or 8.0E-2
lb/GWh.
Manganese (Mn)......... 2.0E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Nickel (Ni)............ 4.7E+2 lb/TBtu or 4.1E0
lb/GWh.
Selenium (Se).......... 9.8E0 lb/TBtu or 2.0E-1
lb/GWh.
Mercury (Hg)........... 4.0E-2 lb/TBtu or 4.0E- For Method 30B sample
4 lb/GWh. volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be < \1/2\
the standard.
Hydrogen chloride (HCl) 2.0E-4 lb/MMBtu or 2.0E- For Method 26A, collect
3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 2
hours.
c. Hydrogen fluoride 6.0E-5 lb/MMBtu or 5.0E- For Method 26A, collect
(HF). 4 lb/MWh. a minimum of 3 dscm
per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 2
hours.
----------------------------------------------------------------------------------------------------------------
[[Page 9493]]
6. Solid oil-derived fuel-fired unit. a. Filterable 8.0E-3 lb/MMBtu or 9.0E- Collect a minimum of 1
particulate matter 2 lb/MWh2. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 4.0E-5 lb/MMBtu or 6.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals.. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Arsenic (As)........... 3.0E-1 lb/TBtu or 5.0E-
3 lb/GWh.
Beryllium (Be)......... 6.0E-2 lb/TBtu or 6.0E-
4 lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 4.0E-
3 lb/GWh.
Chromium (Cr).......... 8.0E-1 lb/TBtu or 2.0E-
2 lb/GWh.
Cobalt (Co)............ 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Lead (Pb).............. 8.0E-1 lb/TBtu or 2.0E-
2 lb/GWh.
Manganese (Mn)......... 2.3E0 lb/TBtu or 4.0E-2
lb/GWh.
Nickel (Ni)............ 9.0E0 lb/TBtu or 2.0E-1
lb/GWh.
Selenium (Se).......... 1.2E0 lb/TBtu 2.0E-2 lb/
GWh.
b. Hydrogen chloride 5.0E-3 lb/MMBtu or 8.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 3.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 2.0E0 lb/MWh.
c. Mercury (Hg)........ 2.0E-1 lb/TBtu or 2.0E- LEE Testing for 30 days
3 lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or Sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
\1\ For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required
minimum sampling volume must be increased nominally by a factor of two.
\2\ Gross electric output.
\3\ Incorporated by reference, see Sec. 63.14.
\4\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
installed.
Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
[As stated in Sec. Sec. 63.9991, you must comply with the following
applicable work practice standards]
------------------------------------------------------------------------
If your EGU is . . . You must meet the following . . .
------------------------------------------------------------------------
1. An existing EGU........... Conduct a tune-up of the EGU burner and
combustion controls at least each 36
calendar months, or each 48 calendar
months if neural network combustion
optimization software is employed, as
specified in Sec. 63.10021(e).
------------------------------------------------------------------------
2. A new or reconstructed EGU Conduct a tune-up of the EGU burner and
combustion controls at least each 36
calendar months, or each 48 calendar
months if neural network combustion
optimization software is employed, as
specified in Sec. 63.10021(e).
------------------------------------------------------------------------
3. A coal-fired, liquid oil- You must operate all CMS during startup.
fired, or solid oil-derived Startup means either the first-ever
fuel-fired EGU during firing of fuel in a boiler for the
startup. purpose of producing electricity, or the
firing of fuel in a boiler after a
shutdown event for any purpose. Startup
ends when any of the steam from the
boiler is used to generate electricity
for sale over the grid or for any other
purpose (including on site use). For
startup of a unit, you must use clean
fuels, either natural gas or distillate
oil or a combination of clean fuels for
ignition. Once you convert to firing
coal, residual oil, or solid oil-derived
fuel, you must engage all of the
applicable control technologies except
dry scrubber and SCR. You must start
your dry scrubber and SCR systems, if
present, appropriately to comply with
relevant standards applicable during
normal operation. You must comply with
all applicable emissions limits at all
times except for periods that meet the
definitions of startup and shutdown in
this subpart. You must keep records
during periods of startup. You must
provide reports concerning activities
and periods of startup, as specified in
Sec. 63.10011(g) and Sec.
63.10021(h) and (i).
------------------------------------------------------------------------
[[Page 9494]]
4. A coal-fired, liquid oil- You must operate all CMS during shutdown.
fired, or solid oil-derived Shutdown means the cessation of
fuel-fired EGU during operation of a boiler for any purpose.
shutdown. Shutdown begins either when none of the
steam from the boiler is used to
generate electricity for sale over the
grid or for any other purpose (including
on-site use) or at the point of no fuel
being fired in the boiler. Shutdown ends
when there is both no electricity being
generated and no fuel being fired in the
boiler. During shutdown, you must
operate all applicable control
technologies while firing coal, residual
oil, or solid oil-derived fuel. You must
comply with all applicable emissions
limits at all times except for periods
that meet the definitions of startup and
shutdown in this subpart. You must keep
records during periods of startup. You
must provide reports concerning
activities and periods of startup, as
specified in Sec. 63.10011(g) and Sec.
63.10021(h) and (i).
------------------------------------------------------------------------
Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
[As stated in Sec. 63.9991, you must comply with the applicable
operating limits]
------------------------------------------------------------------------
If you demonstrate compliance You must meet these operating limits . .
using . . . .
------------------------------------------------------------------------
1. PM CPMS................... Maintain the 30-boiler operating day
rolling average PM CPMS output at or
below the highest 1-hour average
measured during the most recent
performance test demonstrating
compliance with the filterable PM, total
non-mercury HAP metals (total HAP
metals, for liquid oil-fired units), or
individual non-mercury HAP metals
(individual HAP metals including Hg, for
liquid oil-fired units) emissions
limitation(s).
------------------------------------------------------------------------
Table 5 to Subpart UUUUU of Part 63--Performance Testing Requirements
[As stated in Sec. 63.10007, you must comply with the following requirements for performance testing for
existing, new or reconstructed affected sources \1\]
----------------------------------------------------------------------------------------------------------------
You must perform the
following activities, as
To conduct a performance test for Using . . . applicable to your input- Using \2\ . . .
the following pollutant . . . or output-based emission
limit . . .
----------------------------------------------------------------------------------------------------------------
1. Filterable Particulate matter Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
(PM). location and the number to part 60 of this
of traverse points. chapter.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-2 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the filterable Method 5 at Appendix A-3
PM concentration. to part 60 of this
chapter.
For positive pressure
fabric filters, Method
5D at Appendix A-3 to
part 60 of this chapter
for filterable PM
emissions.
Note that the Method 5
front half temperature
shall be 160 [deg] 14 [deg]C (320
[deg] 25
[deg]F).
f. Convert emissions Method 19 F-factor
concentration to lb/MMBtu methodology at Appendix
or lb/MWh emissions rates. A-7 to part 60 of this
chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
OR OR
PM CEMS a. Install, certify, Performance Specification
operate, and maintain the 11 at Appendix B to part
PM CEMS. 60 of this chapter and
Procedure 2 at Appendix
F to Part 60 of this
chapter.
b. Install, certify, Part 75 of this chapter
operate, and maintain the and Sec. Sec.
diluent gas, flow rate, 63.10010(a), (b), (c),
and/or moisture and (d).
monitoring systems.
c. Convert hourly Method 19 F-factor
emissions concentrations methodology at Appendix
to 30 boiler operating A-7 to part 60 of this
day rolling average lb/ chapter, or calculate
MMBtu or lb/MWh emissions using mass emissions
rates. rate and electrical
output data (see Sec.
63.10007(e)).
----------------------------------------------------------------------------------------------------------------
2. Total or individual non-Hg HAP Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
metals. location and the number to part 60 of this
of traverse points. chapter.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
[[Page 9495]]
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-2 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the HAP metals Method 29 at Appendix A-8
emissions concentrations to part 60 of this
and determine each chapter. For liquid oil-
individual HAP metals fired units, Hg is
emissions concentration, included in HAP metals
as well as the total and you may use Method
filterable HAP metals 29, Method 30B at
emissions concentration Appendix A-8 to part 60
and total HAP metals of this chapter; for
emissions concentration. Method 29, you must
report the front half
and back half results
separately.
f. Convert emissions Method 19 F-factor
concentrations methodology at Appendix
(individual HAP metals, A-7 to part 60 of this
total filterable HAP chapter, or calculate
metals, and total HAP using mass emissions
metals) to lb/MMBtu or lb/ rate and electrical
MWh emissions rates. output data (see Sec.
63.10007(e)).
----------------------------------------------------------------------------------------------------------------
3. Hydrogen chloride (HCl) and Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
hydrogen fluoride (HF). location and the number to part 60 of this
of traverse points. chapter.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-2 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the HCl and HF Method 26 or Method 26A
emissions concentrations. at Appendix A-8 to part
60 of this chapter or
Method 320 at Appendix A
to part 63 of this
chapter or ASTM 6348-03
\3\ with (1) additional
quality assurance
measures in footnote \4\
and (2) spiking levels
nominally no greater
than two times the level
corresponding to the
applicable emission
limit. Method 26A must
be used if there are
entrained water droplets
in the exhaust stream.
f. Convert emissions Method 19 F-factor
concentration to lb/MMBtu methodology at Appendix
or lb/MWh emissions rates. A-7 to part 60 of this
chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
OR OR
HCl and/or HF CEMS... a. Install, certify, Appendix B of this
operate, and maintain the subpart.
HCl or HF CEMS.
b. Install, certify, Part 75 of this chapter
operate, and maintain the and Sec. Sec.
diluent gas, flow rate, 63.10010(a), (b), (c),
and/or moisture and (d).
monitoring systems.
c. Convert hourly Method 19 F-factor
emissions concentrations methodology at Appendix
to 30 boiler operating A-7 to part 60 of this
day rolling average lb/ chapter, or calculate
MMBtu or lb/MWh emissions using mass emissions
rates. rate and electrical
output data (see Sec.
63.10007(e)).
----------------------------------------------------------------------------------------------------------------
4. Mercury (Hg)................... Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
location and the number to part 60 of this
of traverse points. chapter or Method 30B at
Appendix A-8 for Method
30B point selection.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-1 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the Hg emission Method 30B at Appendix A-
concentration. 8 to part 60 of this
chapter, ASTM D6784 \3\,
or Method 29 at Appendix
A-8 to part 60 of this
chapter; for Method 29,
you must report the
front half and back half
results separately.
[[Page 9496]]
f. Convert emissions Method 19 F-factor
concentration to lb/TBtu methodology at Appendix
or lb/GWh emission rates. A-7 to part 60 of this
chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
OR OR
Hg CEMS................... Sections 3.2.1 and 5.1 of
a. Install, certify, Appendix A of this
operate, and maintain the subpart.
CEMS.
b. Install, certify, Part 75 of this chapter
operate, and maintain the and Sec. Sec.
diluent gas, flow rate, 63.10010(a), (b), (c),
and/or moisture and (d).
monitoring systems.
c. Convert hourly Section 6 of Appendix A
emissions concentrations to this subpart.
to 30 boiler operating
day rolling average lb/
TBtu or lb/GWh emissions
rates.
OR OR
Sorbent trap a. Install, certify, Sections 3.2.2 and 5.2 of
monitoring system. operate, and maintain the Appendix A to this
sorbent trap monitoring subpart.
system.
b. Install, operate, and Part 75 of this chapter
maintain the diluent gas, and Sec. Sec.
flow rate, and/or 63.10010(a), (b), (c),
moisture monitoring and (d).
systems.
c. Convert emissions Section 6 of Appendix A
concentrations to 30 to this subpart.
boiler operating day
rolling average lb/TBtu
or lb/GWh emissions rates.
OR OR
LEE testing.......... a. Select sampling ports Single point located at
location and the number the 10% centroidal area
of traverse points. of the duct at a port
location per Method 1 at
Appendix A-1 to part 60
of this chapter or
Method 30B at Appendix A-
8 for Method 30B point
selection.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G,
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter or flow
monitoring system
certified per Appendix A
of this subpart.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-1 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981,\3\
or diluent gas
monitoring systems
certified according to
Part 75 of this chapter.
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter, or moisture
monitoring systems
certified according to
part 75 of this chapter.
e. Measure the Hg emission Method 30B at Appendix A-
concentration. 8 to part 60 of this
chapter; perform a 30
operating day test, with
a maximum of 10
operating days per run
(i.e., per pair of
sorbent traps) or
sorbent trap monitoring
system or Hg CEMS
certified per Appendix A
of this subpart.
f. Convert emissions Method 19 F-factor
concentrations from the methodology at Appendix
LEE test to lb/TBtu or lb/ A-7 to part 60 of this
GWh emissions rates. chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
g. Convert average lb/TBtu Potential maximum annual
or lb/GWh Hg emission heat input in TBtu or
rate to lb/year, if you potential maximum
are attempting to meet electricity generated in
the 22.0 lb/year GWh.
threshold.
----------------------------------------------------------------------------------------------------------------
5. Sulfur dioxide (SO2)........... SO2 CEMS............. a. Install, certify, Part 75 of this chapter
operate, and maintain the and Sec. Sec.
CEMS. 63.10010(a) and (f).
b. Install, operate, and Part 75 of this chapter
maintain the diluent gas, and Sec. Sec.
flow rate, and/or 63.10010(a), (b), (c),
moisture monitoring and (d).
systems.
c. Convert hourly Method 19 F-factor
emissions concentrations methodology at Appendix
to 30 boiler operating A-7 to part 60 of this
day rolling average lb/ chapter, or calculate
MMBtu or lb/MWh emissions using mass emissions
rates. rate and electrical
output data (see Sec.
63.10007(e)).
----------------------------------------------------------------------------------------------------------------
\1\ Regarding emissions data collected during periods of startup or shutdown, see Sec. Sec. 63.10020(b) and
(c) and Sec. 63.10021(h).
[[Page 9497]]
\2\ See Tables 1 and 2 to this subpart for required sample volumes and/or sampling run times.
\3\ Incorporated by reference, see Sec. 63.14.
\4\ When using ASTM D6348-03, the following conditions must be met: (1) The test plan preparation and
implementation in the Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory; (2) For ASTM D6348-03
Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (see
Equation A5.5); (3) For the ASTM D6348-03 test data to be acceptable for a target analyte, %R must be 70% >= R
<= 130%; and (4) The %R value for each compound must be reported in the test report and all field measurements
corrected with the calculated %R value for that compound using the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE12.011
Table 6 to Subpart UUUUU of Part 63--Establishing PM CPMS Operating Limits
[As stated in Sec. 63.10007, you must comply with the following requirements for establishing operating
limits]
----------------------------------------------------------------------------------------------------------------
And you choose to
If you have an applicable establish PM CPMS According to the
emission limit for . . . operating limits, And . . . Using . . . following
you must . . . procedures . . .
----------------------------------------------------------------------------------------------------------------
Particulate matter (PM), total Install, certify, Establish a site- Data from the PM 1. Collect PM CPMS
non-mercury HAP metals, maintain, and specific CPMS and the PM output data
individual non-mercury HAP operate a PM CPMS operating limit or HAP metals during the entire
metals, total HAP metals, for monitoring in units of PM performance tests. period of the
individual HAP metals. emissions CPMS output performance
discharged to the signal (e.g., tests.
atmosphere milliamps, mg/ 2. Record the
according to Sec. acm, or other raw average hourly PM
63.10010(g)(1). signal). CPMS output for
each test run in
the three run
performance test.
3. Determine the
highest 1-hour
average PM CPMS
measured during
the performance
test
demonstrating
compliance with
the filterable PM
or HAP metals
emissions
limitations.
----------------------------------------------------------------------------------------------------------------
Table 7 to Subpart UUUUU of Part 63--Demonstrating Continuous Compliance
[As stated in Sec. 63.10021, you must show continuous compliance with
the emission limitations for affected sources according to the
following]
------------------------------------------------------------------------
If you use one of the following to meet
applicable emissions limits, operating You demonstrate continuous
limits, or work practice standards . . compliance by . . .
.
------------------------------------------------------------------------
1. CEMS to measure filterable PM, SO2, Calculating the 30-boiler
HCl, HF, or Hg emissions, or using a operating day rolling
sorbent trap monitoring system to arithmetic average emissions
measure Hg. rate in units of the
applicable emissions standard
basis at the end of each
boiler operating day using all
of the quality assured hourly
average CEMS or sorbent trap
data for the previous 30
boiler operating days,
excluding data recorded during
periods of startup or
shutdown.
2. PM CPMS to measure compliance with a Calculating the arithmetic 30-
parametric operating limit. boiler operating day rolling
average of all of the quality
assured hourly average PM CPMS
output data (e.g., milliamps,
PM concentration, raw data
signal) collected for all
operating hours for the
previous 30 boiler operating
days, excluding data recorded
during periods of startup or
shutdown.
3. Site-specific monitoring for liquid If applicable, by conducting
oil-fired units for HCl and HF the monitoring in accordance
emission limit monitoring. with an approved site-specific
monitoring plan.
4. Quarterly performance testing for Calculating the results of the
coal-fired, solid oil derived fired, testing in units of the
or liquid oil-fired units to measure applicable emissions standard.
compliance with one or more applicable
emissions limit in Table 1 or 2.
5. Conducting periodic performance tune- Conducting periodic performance
ups of your EGU(s). tune-ups of your EGU(s), as
specified in Sec.
63.10021(e).
6. Work practice standards for coal- Operating in accordance with
fired, liquid oil-fired, or solid oil- Table 3.
derived fuel-fired EGUs during startup.
7. Work practice standards for coal- Operating in accordance with
fired, liquid oil-fired, or solid oil- Table 3.
derived fuel-fired EGUs during
shutdown.
------------------------------------------------------------------------
[[Page 9498]]
Table 8 to Subpart UUUUU of Part 63--Reporting Requirements
[As stated in Sec. 63.10031, you must comply with the following requirements for reports]
----------------------------------------------------------------------------------------------------------------
You must submit the report
You must submit a . . . The report must contain . . . . . .
----------------------------------------------------------------------------------------------------------------
1. Compliance report.................... a. Information required in Sec. Semiannually according to
63.10031(c)(1) through (4); and the requirements in Sec.
b. If there are no deviations from any 63.10031(b).
emission limitation (emission limit and
operating limit) that applies to you and
there are no deviations from the
requirements for work practice standards
in Table 3 to this subpart that apply to
you, a statement that there were no
deviations from the emission limitations
and work practice standards during the
reporting period. If there were no
periods during which the CMSs, including
continuous emissions monitoring system,
and operating parameter monitoring
systems, were out-of-control as specified
in Sec. 63.8(c)(7), a statement that
there were no periods during which the
CMSs were out-of-control during the
reporting period; and.
c. If you have a deviation from any ..........................
emission limitation (emission limit and
operating limit) or work practice
standard during the reporting period, the
report must contain the information in
Sec. 63.10031(d). If there were periods
during which the CMSs, including
continuous emissions monitoring systems
and continuous parameter monitoring
systems, were out-of-control, as
specified in Sec. 63.8(c)(7), the
report must contain the information in
Sec. 63.10031(e).
----------------------------------------------------------------------------------------------------------------
Table 9 to Subpart UUUUU of Part 63--Applicability of General Provisions
to Subpart UUUUU
[As stated in Sec. 63.10040, you must comply with the applicable
General Provisions according to the following]
------------------------------------------------------------------------
Applies to subpart
Citation Subject UUUUU
------------------------------------------------------------------------
Sec. 63.1..................... Applicability..... Yes.
Sec. 63.2..................... Definitions....... Yes. Additional
terms defined in
Sec. 63.10042.
Sec. 63.3..................... Units and Yes.
Abbreviations.
Sec. 63.4..................... Prohibited Yes.
Activities and
Circumvention.
Sec. 63.5..................... Preconstruction Yes.
Review and
Notification
Requirements.
Sec. 63.6(a), (b)(1)-(b)(5), Compliance with Yes.
(b)(7), (c), (f)(2)-(3), (g), Standards and
(h)(2)-(h)(9), (i), (j). Maintenance
Requirements.
Sec. 63.6(e)(1)(i)............ General Duty to No. See Sec.
minimize 63.10000(b) for
emissions. general duty
requirement.
Sec. 63.6(e)(1)(ii)........... Requirement to No.
correct
malfunctions ASAP.
Sec. 63.6(e)(3)............... SSM Plan No.
requirements.
Sec. 63.6(f)(1)............... SSM exemption..... No.
Sec. 63.6(h)(1)............... SSM exemption..... No.
Sec. 63.7(a), (b), (c), (d), Performance Yes.
(e)(2)-(e)(9), (f), (g), and Testing
(h). Requirements.
Sec. 63.7(e)(1)............... Performance No. See Sec.
testing. 63.10007.
Sec. 63.8..................... Monitoring Yes.
Requirements.
63.8(c)(1)(i)................... General duty to No. See Sec.
minimize 63.10000(b) for
emissions and CMS general duty
operation. requirement.
Sec. 63.8(c)(1)(iii).......... Requirement to No.
develop SSM Plan
for CMS.
Sec. 63.8(d)(3)............... Written procedures Yes, except for
for CMS. last sentence,
which refers to
an SSM plan. SSM
plans are not
required.
Sec. 63.9..................... Notification Yes.
Requirements.
Sec. 63.10(a), (b)(1), (c), Recordkeeping and Yes, except for
(d)(1)-(2), (e), and (f). Reporting the requirements
Requirements. to submit written
reports under
Sec.
63.10(e)(3)(v).
Sec. 63.10(b)(2)(i)........... Recordkeeping of No.
occurrence and
duration of
startups and
shutdowns.
Sec. 63.10(b)(2)(ii).......... Recordkeeping of No. See 63.10001
malfunctions. for recordkeeping
of (1) occurrence
and duration and
(2) actions taken
during
malfunction.
Sec. 63.10(b)(2)(iii)......... Maintenance Yes.
records.
Sec. 63.10(b)(2)(iv).......... Actions taken to No.
minimize
emissions during
SSM.
Sec. 63.10(b)(2)(v)........... Actions taken to No.
minimize
emissions during
SSM.
Sec. 63.10(b)(2)(vi).......... Recordkeeping for Yes.
CMS malfunctions.
Sec. 63.10(b)(2)(vii)-(ix).... Other CMS Yes.
requirements.
Sec. 63.10(b)(3), and (d)(3)- .................. No.
(5).
Sec. 63.10(c)(7).............. Additional Yes.
recordkeeping
requirements for
CMS--identifying
exceedances and
excess emissions.
Sec. 63.10(c)(8).............. Additional Yes.
recordkeeping
requirements for
CMS--identifying
exceedances and
excess emissions.
Sec. 63.10(c)(10)............. Recording nature No. See
and cause of 63.10032(g) and
malfunctions. (h) for
malfunctions
recordkeeping
requirements.
[[Page 9499]]
Sec. 63.10(c)(11)............. Recording No. See
corrective 63.10032(g) and
actions. (h) for
malfunctions
recordkeeping
requirements.
Sec. 63.10(c)(15)............. Use of SSM Plan... No.
Sec. 63.10(d)(5).............. SSM reports....... No. See
63.10021(h) and
(i) for
malfunction
reporting
requirements.
Sec. 63.11.................... Control Device No.
Requirements.
Sec. 63.12.................... State Authority Yes.
and Delegation.
Sec. 63.13-63.16.............. Addresses, Yes.
Incorporation by
Reference,
Availability of
Information,
Performance Track
Provisions.
Sec. 63.1(a)(5), (a)(7)- Reserved.......... No.
(a)(9), (b)(2), (c)(3)-(4),
(d), 63.6(b)(6), (c)(3),
(c)(4), (d), (e)(2),
(e)(3)(ii), (h)(3), (h)(5)(iv),
63.8(a)(3), 63.9(b)(3), (h)(4),
63.10(c)(2)-(4), (c)(9).
------------------------------------------------------------------------
Appendix A to Subpart UUUUU--Hg Monitoring Provisions
1. General Provisions
1.1 Applicability. These monitoring provisions apply to the
measurement of total vapor phase mercury (Hg) in emissions from
electric utility steam generating units, using either a mercury
continuous emission monitoring system (Hg CEMS) or a sorbent trap
monitoring system. The Hg CEMS or sorbent trap monitoring system
must be capable of measuring the total vapor phase mercury in units
of the applicable emissions standard (e.g., lb/TBtu or lb/GWh),
regardless of speciation.
1.2 Initial Certification and Recertification Procedures. The
owner or operator of an affected unit that uses a Hg CEMS or a
sorbent trap monitoring system together with other necessary
monitoring components to account for Hg emissions in units of the
applicable emissions standard shall comply with the initial
certification and recertification procedures in section 4 of this
appendix.
1.3 Quality Assurance and Quality Control Requirements. The
owner or operator of an affected unit that uses a Hg CEMS or a
sorbent trap monitoring system together with other necessary
monitoring components to account for Hg emissions in units of the
applicable emissions standard shall meet the applicable quality
assurance requirements in section 5 of this appendix.
1.4 Missing Data Procedures. The owner or operator of an
affected unit is not required to substitute for missing data from Hg
CEMS or sorbent trap monitoring systems. Any process operating hour
for which quality-assured Hg concentration data are not obtained is
counted as an hour of monitoring system downtime.
2. Monitoring of Hg Emissions
2.1 Monitoring System Installation Requirements. Flue gases from
the affected units under this subpart vent to the atmosphere through
a variety of exhaust configurations including single stacks, common
stack configurations, and multiple stack configurations. For each of
these configurations, Sec. 63.10010(a) specifies the appropriate
location(s) at which to install continuous monitoring systems (CMS).
These CMS installation provisions apply to the Hg CEMS, sorbent trap
monitoring systems, and other continuous monitoring systems that
provide data for the Hg emissions calculations in section 6.2 of
this appendix.
2.2 Primary and Backup Monitoring Systems. In the electronic
monitoring plan described in section 7.1.1.2.1 of this appendix, you
must designate a primary Hg CEMS or sorbent trap monitoring system.
The primary system must be used to report hourly Hg concentration
values when the system is able to provide quality-assured data,
i.e., when the system is ``in control''. However, to increase data
availability in the event of a primary monitoring system outage, you
may install, operate, maintain, and calibrate backup monitoring
systems, as follows:
2.2.1 Redundant Backup Systems. A redundant backup monitoring
system may be either a separate Hg CEMS with its own probe, sample
interface, and analyzer, or a separate sorbent trap monitoring
system. A redundant backup system is one that is permanently
installed at the unit or stack location, and is kept on ``hot
standby'' in case the primary monitoring system is unable to provide
quality-assured data. A redundant backup system must be represented
as a unique monitoring system in the electronic monitoring plan.
Each redundant backup monitoring system must be certified according
to the applicable provisions in section 4 of this appendix and must
meet the applicable on-going QA requirements in section 5 of this
appendix.
2.2.2 Non-redundant Backup Monitoring Systems. A non-redundant
backup monitoring system is a separate Hg CEMS or sorbent trap
system that has been certified at a particular unit or stack
location, but is not permanently installed at that location. Rather,
the system is kept on ``cold standby'' and may be reinstalled in the
event of a primary monitoring system outage. A non-redundant backup
monitoring system must be represented as a unique monitoring system
in the electronic monitoring plan. Non-redundant backup Hg CEMS must
complete the same certification tests as the primary monitoring
system, with one exception. The 7-day calibration error test is not
required for a non-redundant backup Hg CEMS. Except as otherwise
provided in section 2.2.4.5 of this appendix, a non-redundant backup
monitoring system may only be used for 720 hours per year at a
particular unit or stack location.
2.2.3 Temporary Like-kind Replacement Analyzers. When a primary
Hg analyzer needs repair or maintenance, you may temporarily install
a like-kind replacement analyzer, to minimize data loss. Except as
otherwise provided in section 2.2.4.5 of this appendix, a temporary
like-kind replacement analyzer may only be used for 720 hours per
year at a particular unit or stack location. The analyzer must be
represented as a component of the primary Hg CEMS, and must be
assigned a 3-character component ID number, beginning with the
prefix ``LK''.
2.2.4 Quality Assurance Requirements for Non-redundant Backup
Monitoring Systems and Temporary Like-kind Replacement Analyzers. To
quality-assure the data from non-redundant backup Hg monitoring
systems and temporary like-kind replacement Hg analyzers, the
following provisions apply:
2.2.4.1 When a certified non-redundant backup sorbent trap
monitoring system is brought into service, you must follow the
procedures for routine day-to-day operation of the system, in
accordance with Performance Specification (PS) 12B in appendix B to
part 60 of this chapter.
2.2.4.2 When a certified non-redundant backup Hg CEMS or a
temporary like-kind replacement Hg analyzer is brought into service,
a calibration error test and a linearity check must be performed and
passed. A single point system integrity check is also required,
unless a NIST-traceable source of oxidized Hg was used for the
calibration error test.
2.2.4.3 Each non-redundant backup Hg CEMS or temporary like-kind
replacement Hg analyzer shall comply with all required daily,
weekly, and quarterly quality-assurance test requirements in section
5 of this appendix, for as long as the system or analyzer remains in
service.
2.2.4.4 For the routine, on-going quality-assurance of a non-
redundant backup Hg monitoring system, a relative accuracy test
audit (RATA) must be performed and passed at least once every 8
calendar quarters at the
[[Page 9500]]
unit or stack location(s) where the system will be used.
2.2.4.5 To use a non-redundant backup Hg monitoring system or a
temporary like-kind replacement analyzer for more than 720 hours per
year at a particular unit or stack location, a RATA must first be
performed and passed at that location.
3. Mercury Emissions Measurement Methods
The following definitions, equipment specifications, procedures,
and performance criteria are applicable to the measurement of vapor-
phase Hg emissions from electric utility steam generating units,
under relatively low-dust conditions (i.e., sampling in the stack or
duct after all pollution control devices). The analyte measured by
these procedures and specifications is total vapor-phase Hg in the
flue gas, which represents the sum of elemental Hg (Hg0,
CAS Number 7439-97-6) and oxidized forms of Hg.
3.1 Definitions.
3.1.1 Mercury Continuous Emission Monitoring System or Hg CEMS
means all of the equipment used to continuously determine the total
vapor phase Hg concentration. The measurement system may include the
following major subsystems: sample acquisition, Hg+2 to
Hg0 converter, sample transport, sample conditioning,
flow control/gas manifold, gas analyzer, and data acquisition and
handling system (DAHS). Hg CEMS may be nominally real-time or time-
integrated, batch sampling systems that sample the gas on an
intermittent basis and concentrate on a collection medium before
intermittent analysis and reporting.
3.1.2 Sorbent Trap Monitoring System means the equipment
required to monitor Hg emissions continuously by using paired
sorbent traps containing iodated charcoal (IC) or other suitable
sorbent medium. The monitoring system consists of a probe, paired
sorbent traps, an umbilical line, moisture removal components, an
airtight sample pump, a gas flow meter, and an automated data
acquisition and handling system. The system samples the stack gas at
a constant proportional rate relative to the stack gas volumetric
flow rate. The sampling is a batch process. The average Hg
concentration in the stack gas for the sampling period is
determined, in units of micrograms per dry standard cubic meter
([mu]g/dscm), based on the sample volume measured by the gas flow
meter and the mass of Hg collected in the sorbent traps.
3.1.3 NIST means the National Institute of Standards and
Technology, located in Gaithersburg, Maryland.
3.1.4 NIST-Traceable Elemental Hg Standards means either:
compressed gas cylinders having known concentrations of elemental
Hg, which have been prepared according to the ``EPA Traceability
Protocol for Assay and Certification of Gaseous Calibration
Standards''; or calibration gases having known concentrations of
elemental Hg, produced by a generator that meets the performance
requirements of the ``EPA Traceability Protocol for Qualification
and Certification of Elemental Mercury Gas Generators'' or an
interim version of that protocol.
3.1.5 NIST-Traceable Source of Oxidized Hg means a generator
that is capable of providing known concentrations of vapor phase
mercuric chloride (HgCl2), and that meets the performance
requirements of the ``EPA Traceability Protocol for Qualification
and Certification of Mercuric Chloride Gas Generators'' or an
interim version of that protocol.
3.1.6 Calibration Gas means a NIST-traceable gas standard
containing a known concentration of elemental or oxidized Hg that is
produced and certified in accordance with an EPA traceability
protocol.
3.1.7 Span Value means a conservatively high estimate of the Hg
concentrations to be measured by a CEMS. The span value of a Hg CEMS
should be set to approximately twice the concentration corresponding
to the emission standard, rounded off as appropriate (see section
3.2.1.4.2 of this appendix).
3.1.8 Zero-Level Gas means calibration gas containing a Hg
concentration that is below the level detectable by the Hg gas
analyzer in use.
3.1.9 Low-Level Gas means calibration gas with a concentration
that is 20 to 30 percent of the span value.
3.1.10 Mid-Level Gas means calibration gas with a concentration
that is 50 to 60 percent of the span value.
3.1.11 High-Level Gas means calibration gas with a concentration
that is 80 to 100 percent of the span value.
3.1.12 Calibration Error Test means a test designed to assess
the ability of a Hg CEMS to measure the concentrations of
calibration gases accurately. A zero-level gas and an upscale gas
are required for this test. For the upscale gas, either a mid-level
gas or a high-level gas may be used, and the gas may either be an
elemental or oxidized Hg standard.
3.1.13 Linearity Check means a test designed to determine
whether the response of a Hg analyzer is linear across its
measurement range. Three elemental Hg calibration gas standards
(i.e., low, mid, and high-level gases) are required for this test.
3.1.14 System Integrity Check means a test designed to assess
the transport and measurement of oxidized Hg by a Hg CEMS. Oxidized
Hg standards are used for this test. For a three-level system
integrity check, low, mid, and high-level calibration gases are
required. For a single-level check, either a mid-level gas or a
high-level gas may be used.
3.1.15 Cycle Time Test means a test designed to measure the
amount of time it takes for a Hg CEMS, while operating normally, to
respond to a known step change in gas concentration. For this test,
a zero gas and a high-level gas are required. The high-level gas may
be either an elemental or an oxidized Hg standard.
3.1.16 Relative Accuracy Test Audit or RATA means a series of
nine or more test runs, directly comparing readings from a Hg CEMS
or sorbent trap monitoring system to measurements made with a
reference stack test method. The relative accuracy (RA) of the
monitoring system is expressed as the absolute mean difference
between the monitoring system and reference method measurements plus
the absolute value of the 2.5 percent error confidence coefficient,
divided by the mean value of the reference method measurements.
3.1.17 Unit Operating Hour means a clock hour in which a unit
combusts any fuel, either for part of the hour or for the entire
hour.
3.1.18 Stack Operating Hour means a clock hour in which gases
flow through a particular monitored stack or duct (either for part
of the hour or for the entire hour), while the associated unit(s)
are combusting fuel.
3.1.19 Operating Day means a calendar day in which a source
combusts any fuel.
3.1.20 Quality Assurance (QA) Operating Quarter means a calendar
quarter in which there are at least 168 unit or stack operating
hours (as defined in this section).
3.1.21 Grace Period means a specified number of unit or stack
operating hours after the deadline for a required quality-assurance
test of a continuous monitor has passed, in which the test may be
performed and passed without loss of data.
3.2 Continuous Monitoring Methods.
3.2.1 Hg CEMS. A typical Hg CEMS is shown in Figure A-1. The
CEMS in Figure A-1 is a dilution extractive system, which measures
Hg concentration on a wet basis, and is the most commonly-used type
of Hg CEMS. Other system designs may be used, provided that the CEMS
meets the performance specifications in section 4.1.1 of this
appendix.
[[Page 9501]]
[GRAPHIC] [TIFF OMITTED] TR16FE12.012
3.2.1.1 Equipment Specifications.
3.2.1.1.1 Materials of Construction. All wetted sampling system
components, including probe components prior to the point at which
the calibration gas is introduced, must be chemically inert to all
Hg species. Materials such as perfluoroalkoxy (PFA) Teflon\TM\,
quartz, and treated stainless steel (SS) are examples of such
materials.
3.2.1.1.2 Temperature Considerations. All system components
prior to the Hg+2 to Hg\0\ converter must be maintained
at a sample temperature above the acid gas dew point.
3.2.1.1.3 Measurement System Components.
3.2.1.1.3.1 Sample Probe. The probe must be made of the
appropriate materials as noted in paragraph 3.2.1.1.1 of this
section, heated when necessary, as described in paragraph
3.2.1.1.3.4 of this section, and configured with ports for
introduction of calibration gases.
3.2.1.1.3.2 Filter or Other Particulate Removal Device. The
filter or other particulate removal device is part of the
measurement system, must be made of appropriate materials, as noted
in paragraph 3.2.1.1.1 of this section, and must be included in all
system tests.
3.2.1.1.3.3 Sample Line. The sample line that connects the probe
to the converter, conditioning system, and analyzer must be made of
appropriate materials, as noted in paragraph 3.2.1.1.1 of this
section.
3.2.1.1.3.4 Conditioning Equipment. For wet basis systems, such
as the one shown in Figure A-1, the sample must be kept above its
dew point either by: heating the sample line and all sample
transport components up to the inlet of the analyzer (and, for hot-
wet extractive systems, also heating the analyzer); or diluting the
sample prior to analysis using a dilution probe system. The
components required for these operations are considered to be
conditioning equipment. For dry basis measurements, a condenser,
dryer or other suitable device is required to remove moisture
continuously from the sample gas, and any equipment needed to heat
the probe or sample line to avoid condensation prior to the moisture
removal component is also required.
3.2.1.1.3.5 Sampling Pump. A pump is needed to push or pull the
sample gas through the system at a flow rate sufficient to minimize
the response time of the measurement system. If a mechanical sample
pump is used and its surfaces are in contact with the sample gas
prior to detection, the pump must be leak free and must be
constructed of a material that is non-reactive to the gas being
sampled (see paragraph 3.2.1.1.1 of this section). For dilution-type
measurement systems, such as the system shown in Figure A-1, an
ejector pump (eductor) may be used to create a sufficient vacuum
that sample gas will be drawn through a critical orifice at a
constant rate. The ejector pump must be constructed of any material
that is non-reactive to the gas being sampled.
3.2.1.1.3.6 Calibration Gas System(s). Design and equip each Hg
CEMS to permit the introduction of known concentrations of elemental
Hg and HgCl2 separately, at a point preceding the sample
extraction filtration system, such that the entire measurement
system can be checked. The calibration gas system(s) must be
designed so that the flow rate exceeds the sampling system flow
requirements and that the gas is delivered to the CEMS at
atmospheric pressure.
3.2.1.1.3.7 Sample Gas Delivery. The sample line may feed
directly to either a converter, a by-pass valve (for Hg speciating
systems), or a sample manifold. All valve and/or manifold components
must be made of material that is non-reactive to the gas sampled and
the calibration gas, and must be configured to safely discharge any
excess gas.
3.2.1.1.3.8 Hg Analyzer. An instrument is required that
continuously measures the total vapor phase Hg concentration in the
gas stream. The analyzer may also be capable of measuring elemental
and oxidized Hg separately.
3.2.1.1.3.9 Data Recorder. A recorder, such as a computerized
data acquisition and handling system (DAHS), digital recorder, or
data logger, is required for recording measurement data.
3.2.1.2 Reagents and Standards.
3.2.1.2.1 NIST Traceability. Only NIST-certified or NIST-
traceable calibration gas standards and reagents (as defined in
paragraphs 3.1.4 and 3.1.5 of this section) shall be used for the
tests and procedures required under this subpart. Calibration gases
with known concentrations of Hg0 and HgCl2 are
required. Special reagents and equipment may be needed to prepare
the Hg0 and HgCl2 gas standards (e.g., NIST-
traceable solutions of HgCl2 and gas generators equipped
with mass flow controllers).
3.2.1.2.2 Required Calibration Gas Concentrations.
3.2.1.2.2.1 Zero-Level Gas. A zero-level calibration gas with a
Hg concentration below the level detectable by the Hg analyzer is
required for calibration error tests and cycle time tests of the
CEMS.
3.2.1.2.2.2 Low-Level Gas. A low-level calibration gas with a Hg
concentration of 20 to 30 percent of the span value is required for
linearity checks and 3-level system integrity checks of the CEMS.
Elemental Hg standards are required for the linearity checks and
oxidized Hg standards are required for the system integrity checks.
3.2.1.2.2.3 Mid-Level Gas. A mid-level calibration gas with a Hg
concentration of 50
[[Page 9502]]
to 60 percent of the span value is required for linearity checks and
for 3-level system integrity checks of the CEMS, and is optional for
calibration error tests and single-level system integrity checks.
Elemental Hg standards are required for the linearity checks,
oxidized Hg standards are required for the system integrity checks,
and either elemental or oxidized Hg standards may be used for the
calibration error tests.
3.2.1.2.2.4 High-Level Gas. A high-level calibration gas with a
Hg concentration of 80 to 100 percent of the span value is required
for linearity checks, 3-level system integrity checks, and cycle
time tests of the CEMS, and is optional for calibration error tests
and single-level system integrity checks. Elemental Hg standards are
required for the linearity checks, oxidized Hg standards are
required for the system integrity checks, and either elemental or
oxidized Hg standards may be used for the calibration error and
cycle time tests.
3.2.1.3 Installation and Measurement Location. For the Hg CEMS
and any additional monitoring system(s) needed to convert Hg
concentrations to the desired units of measure (i.e., a flow
monitor, CO2 or O2 monitor, and/or moisture
monitor, as applicable), install each monitoring system at a
location: that is consistent with 63.10010(a); that represents the
emissions exiting to the atmosphere; and where it is likely that the
CEMS can pass the relative accuracy test.
3.2.1.4 Monitor Span and Range Requirements. Determine the
appropriate span and range value(s) for the Hg CEMS as described in
paragraphs 3.2.1.4.1 through 3.2.1.4.3 of this section.
3.2.1.4.1 Maximum Potential Concentration. There are three
options for determining the maximum potential Hg concentration
(MPC). Option 1 applies to coal combustion. You may use a default
value of 10 [mu]g/scm for all coal ranks (including coal refuse)
except for lignite; for lignite, use 16 [mu]g/scm. If different
coals are blended as part of normal operation, use the highest MPC
for any fuel in the blend. Option 2 is to base the MPC on the
results of site-specific Hg emission testing. This option may be
used only if the unit does not have add-on Hg emission controls or a
flue gas desulfurization system, or if testing is performed upstream
of all emission control devices. If Option 2 is selected, perform at
least three test runs at the normal operating load, and the highest
Hg concentration obtained in any of the tests shall be the MPC.
Option 3 is to use fuel sampling and analysis to estimate the MPC.
To make this estimate, use the average Hg content (i.e., the weight
percentage) from at least three representative fuel samples,
together with other available information, including, but not
limited to the maximum fuel feed rate, the heating value of the
fuel, and an appropriate F-factor. Assume that all of the Hg in the
fuel is emitted to the atmosphere as vapor-phase Hg.
3.2.1.4.2 Span Value. To determine the span value of the Hg
CEMS, multiply the Hg concentration corresponding to the applicable
emissions standard by two. If the result of this calculation is an
exact multiple of 10 [mu]g/scm, use the result as the span value.
Otherwise, round off the result to either: the next highest integer;
the next highest multiple of 5 [mu]g/scm; or the next highest
multiple of 10 [mu]g/scm.
3.2.1.4.3 Analyzer Range. The Hg analyzer must be capable of
reading Hg concentration as high as the MPC.
3.2.2 Sorbent Trap Monitoring System. A sorbent trap monitoring
system (as defined in paragraph 3.1.2 of this section) may be used
as an alternative to a Hg CEMS. If this option is selected, the
monitoring system shall be installed, maintained, and operated in
accordance with Performance Specification (PS) 12B in Appendix B to
part 60 of this chapter. The system shall be certified in accordance
with the provisions of section 4.1.2 of this appendix.
3.2.3 Other Necessary Data Collection. To convert measured
hourly Hg concentrations to the units of the applicable emissions
standard (i.e., lb/TBtu or lb/GWh), additional data must be
collected, as described in paragraphs 3.2.3.1 through 3.2.3.3 of
this section. Any additional monitoring systems needed for this
purpose must be certified, operated, maintained, and quality-assured
according to the applicable provisions of part 75 of this chapter
(see Sec. Sec. 63.10010(b) through (d)). The calculation methods
for the types of emission limits described in paragraphs 3.2.3.1 and
3.2.3.2 of this section are presented in section 6.2 of this
appendix.
3.2.3.1 Heat Input-Based Emission Limits. For a heat input-based
Hg emission limit (i.e., in lb/TBtu), data from a certified
CO2 or O2 monitor are needed, along with a
fuel-specific F-factor and a conversion constant to convert measured
Hg concentration values to the units of the standard. In some cases,
the stack gas moisture content must also be considered in making
these conversions.
3.2.3.2 Electrical Output-Based Emission Rates. If the
applicable Hg limit is electrical output-based (i.e., lb/GWh),
hourly electrical load data and unit operating times are required in
addition to hourly data from a certified stack gas flow rate monitor
and (if applicable) moisture data.
3.2.3.3 Sorbent Trap Monitoring System Operation. Routine
operation of a sorbent trap monitoring system requires the use of a
certified stack gas flow rate monitor, to maintain an established
ratio of stack gas flow rate to sample flow rate.
4. Certification and Recertification Requirements
4.1 Certification Requirements. All Hg CEMS and sorbent trap
monitoring systems and the additional monitoring systems used to
continuously measure Hg emissions in units of the applicable
emissions standard in accordance with this appendix must be
certified in a timely manner, such that the initial compliance
demonstration is completed no later than the applicable date in
Sec. 63.10005(g).
4.1.1 Hg CEMS. Table A-1, below, summarizes the certification
test requirements and performance specifications for a Hg CEMS. The
CEMS may not be used to report quality-assured data until these
performance criteria are met. Paragraphs 4.1.1.1 through 4.1.1.5 of
this section provide specific instructions for the required tests.
All tests must be performed with the affected unit(s) operating
(i.e., combusting fuel). Except for the RATA, which must be
performed at normal load, no particular load level is required for
the certification tests.
4.1.1.1 7-Day Calibration Error Test. Perform the 7-day
calibration error test on 7 consecutive source operating days, using
a zero-level gas and either a high-level or a mid-level calibration
gas standard (as defined in sections 3.1.8, 3.1.10, and 3.1.11 of
this appendix). Either elemental or oxidized NIST-traceable Hg
standards (as defined in sections 3.1.4 and 3.1.5 of this appendix)
may be used for the test. If moisture and/or chlorine is added to
the calibration gas, the dilution effect of the moisture and/or
chlorine addition on the calibration gas concentration must be
accounted for in an appropriate manner. Operate the Hg CEMS in its
normal sampling mode during the test. The calibrations should be
approximately 24 hours apart, unless the 7-day test is performed
over nonconsecutive calendar days. On each day of the test, inject
the zero-level and upscale gases in sequence and record the analyzer
responses. Pass the calibration gas through all filters, scrubbers,
conditioners, and other monitor components used during normal
sampling, and through as much of the sampling probe as is practical.
Do not make any manual adjustments to the monitor (i.e., resetting
the calibration) until after taking measurements at both the zero
and upscale concentration levels. If automatic adjustments are made
following both injections, conduct the calibration error test such
that the magnitude of the adjustments can be determined, and use
only the unadjusted analyzer responses in the calculations.
Calculate the calibration error (CE) on each day of the test, as
described in Table A-1. The CE on each day of the test must either
meet the main performance specification or the alternative
specification in Table A-1.
4.1.1.2 Linearity Check. Perform the linearity check using low,
mid, and high-level concentrations of NIST-traceable elemental Hg
standards. Three gas injections at each concentration level are
required, with no two successive injections at the same
concentration level. Introduce the calibration gas at the gas
injection port, as specified in section 3.2.1.1.3.6 of this
appendix. Operate the CEMS at its normal operating temperature and
conditions. Pass the calibration gas through all filters, scrubbers,
conditioners, and other components used during normal sampling, and
through as much of the sampling probe as is practical. If moisture
and/or chlorine is added to the calibration gas, the dilution effect
of the moisture and/or chlorine addition on the calibration gas
concentration must be accounted for in an appropriate manner. Record
the monitor response from the data acquisition and handling system
for each gas injection. At each concentration level, use the average
analyzer response to calculate the linearity error (LE), as
described in Table A-1. The LE must either meet the main performance
specification or the alternative specification in Table A-1.
4.1.1.3 Three-Level System Integrity Check. Perform the 3-level
system integrity
[[Page 9503]]
check using low, mid, and high-level calibration gas concentrations
generated by a NIST-traceable source of oxidized Hg. Follow the same
basic procedure as for the linearity check. If moisture and/or
chlorine is added to the calibration gas, the dilution effect of the
moisture and/or chlorine addition on the calibration gas
concentration must be accounted for in an appropriate manner.
Calculate the system integrity error (SIE), as described in Table A-
1. The SIE must either meet the main performance specification or
the alternative specification in Table A-1. (Note: This test is not
required if the CEMS does not have a converter).
Table A-1--Required Certification Tests and Performance Specifications for Hg CEMS
----------------------------------------------------------------------------------------------------------------
The alternate
For this required certification test The main performance performance And the conditions of
. . . specification \1\ is . specification \1\ is . the alternate
. . . . specification are . . .
----------------------------------------------------------------------------------------------------------------
7-day calibration error test \2\..... [verbarlm]R - A [verbarlm]R - A The alternate
[verbarlm] <=5.0% of [verbarlm] <=1.0 specification may be
span value, for both [micro]g/scm. used on any day of the
the zero and upscale test.
gases, on each of the
7 days.
Linearity check \3\.................. [verbarlm]R - Aavg [verbarlm]R - Aavg The alternate
[verbarlm] <=10.0% of [verbarlm] <=0.8 specification may be
the reference gas [micro]g/scm. used at any gas level.
concentration at each
calibration gas level
(low, mid, or high).
3-level system integrity check \4\... [verbarlm]R - Aavg [verbarlm]R - Aavg The alternate
[verbarlm] <=10.0% of [verbarlm] <=0.8 specification may be
the reference gas [micro]g/scm. used at any gas level.
concentration at each
calibration gas level.
RATA................................. 20.0% RA............... [verbarlm]RMavg - Cavg RMavg <5.0 [micro]g/
[verbarlm] <=1.0 scm.
[micro]g/scm**.
Cycle time test \2\.................. 15 minutes.\5\
----------------------------------------------------------------------------------------------------------------
\1\ Note that [verbarlm]R - A [verbarlm] is the absolute value of the difference between the reference gas value
and the analyzer reading. [verbarlm]R - Aavg, [verbarlm] is the absolute value of the difference between the
reference gas concentration and the average of the analyzer responses, at a particular gas level.
\2\ Use either elemental or oxidized Hg standards; a mid-level or high-level upscale gas may be used. This test
is not required for Hg CEMS that use integrated batch sampling; however, those monitors must be capable of
recording at least one Hg concentration reading every 15 minutes.
\3\ Use elemental Hg standards.
\4\ Use oxidized Hg standards. Not required if the CEMS does not have a converter.
\5\ Stability criteria--Readings change by <2.0% of span or by <=0.5 [micro]g/scm, for 2 minutes.
** Note that [verbarlm]RMavg-Cavg [verbarlm] is the absolute difference between the mean reference method value
and the mean CEMS value from the RATA. The arithmetic difference between RMavg and Cavg can be either + or -.
4.1.1.4 Cycle Time Test. Perform the cycle time test, using a
zero-level gas and a high-level calibration gas.
Either an elemental or oxidized NIST-traceable Hg standard may
be used as the high-level gas. Perform the test in two stages--
upscale and downscale. The slower of the upscale and downscale
response times is the cycle time for the CEMS. Begin each stage of
the test by injecting calibration gas after achieving a stable
reading of the stack emissions. The cycle time is the amount of time
it takes for the analyzer to register a reading that is 95 percent
of the way between the stable stack emissions reading and the final,
stable reading of the calibration gas concentration. Use the
following criterion to determine when a stable reading of stack
emissions or calibration gas has been attained--the reading is
stable if it changes by no more than 2.0 percent of the span value
or 0.5 [micro]g/scm (whichever is less restrictive) for two minutes,
or a reading with a change of less than 6.0 percent from the
measured average concentration over 6 minutes. Integrated batch
sampling type Hg CEMS are exempted from this test; however, these
systems must be capable of delivering a measured Hg concentration
reading at least once every 15 minutes. If necessary to increase
measurement sensitivity of a batch sampling type Hg CEMS for a
specific application, you may petition the Administrator for
approval of a time longer than 15 minutes between readings.
4.1.1.5 Relative Accuracy Test Audit (RATA). Perform the RATA of
the Hg CEMS at normal load. Acceptable Hg reference methods for the
RATA include ASTM D6784-02 (Reapproved 2008), ``Standard Test Method
for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue
Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro
Method)'' (incorporated by reference, see Sec. 63.14) and Methods
29, 30A, and 30B in appendix A-8 to part 60. When Method 29 or ASTM
D6784-02 is used, paired sampling trains are required. To validate a
Method 29 or ASTM D6784-02 test run, calculate the relative
deviation (RD) using Equation A-1 of this section, and assess the
results as follows to validate the run. The RD must not exceed 10
percent, when the average Hg concentration is greater than 1.0
[micro]g/dscm. If the average concentration is <= 1.0 [micro]g/dscm,
the RD must not exceed 20 percent. The RD results are also
acceptable if the absolute difference between the two Hg
concentrations does not exceed 0.2 [micro]g/dscm. If the RD
specification is met, the results of the two samples shall be
averaged arithmetically.
[GRAPHIC] [TIFF OMITTED] TR16FE12.013
Where:
RD = Relative deviation between the Hg concentrations of samples
``a'' and ``b'' (percent)
Ca = Hg concentration of Hg sample ``a'' ([mu]g/dscm)
Cb = Hg concentration of Hg sample ``b'' ([mu]g/dscm)
4.1.1.5.1 Special Considerations. A minimum of nine valid test
runs must be performed, directly comparing the CEMS measurements to
the reference method. More than nine test runs may be performed. If
this option is chosen, the results from a maximum of three test runs
may be rejected so long as the total number of test results used to
determine the relative accuracy is greater than or equal to nine;
however, all data must be reported including the rejected data. The
minimum time per run is 21 minutes if Method 30A is used. If Method
29, Method 30B, or ASTM D6784-02 (Reapproved 2008), ``Standard Test
Method for Elemental, Oxidized, Particle-Bound and Total Mercury in
Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro
Method)'' (incorporated by reference, see Sec. 63.14) is used, the
time per run must be long enough to collect a sufficient mass of Hg
to analyze. Complete the RATA within 168 unit operating hours,
except when Method 29 or ASTM D6784-02 is used, in which case up to
336 operating hours may be taken to finish the test.
4.1.1.5.2 Calculation of RATA Results. Calculate the relative
accuracy (RA) of the monitoring system, on a [micro]g/scm basis, as
described in section 12 of Performance Specification (PS) 2 in
Appendix B to part 60 of this chapter (see Equations 2-3 through 2-6
of PS2). For purposes of calculating the relative accuracy, ensure
that the reference method and monitoring system data are on a
consistent moisture basis, either wet or dry. The CEMS must either
meet the main performance specification or the alternative
specification in Table A-1.
4.1.1.5.3 Bias Adjustment. Measurement or adjustment of Hg CEMS
data for bias is not required.
4.1.2 Sorbent Trap Monitoring Systems. For the initial
certification of a sorbent trap monitoring system, only a RATA is
required.
4.1.2.1 Reference Methods. The acceptable reference methods for
the RATA of a sorbent trap monitoring system are the same as those
listed in paragraph 4.1.1.5 of this section.
4.1.2.2 ``The special considerations specified in paragraph
4.1.1.5.1 of this section apply to the RATA of a sorbent trap
[[Page 9504]]
monitoring system. During the RATA, the monitoring system must be
operated and quality-assured in accordance with Performance
Specification (PS) 12B in Appendix B to part 60 of this chapter with
the following exceptions for sorbent trap section 2 breakthrough:
4.1.2.2.1 For stack Hg concentrations >1 [micro]g/dscm, <=10% of
section 1 Hg mass;
4.1.2.2.2 For stack Hg concentrations <=1 [micro]g/dscm and >0.5
[micro]g/dscm, <= 20% of section 1 Hg mass;
4.1.2.2.3 For stack Hg concentrations <=0.5 [micro]g/dscm and
>0.1 [micro]g/dscm, <= 50% of section 1 Hg mass; and
4.1.2.2.4 For stack Hg concentrations <=0.1[micro]g/dscm, no
breakthrough criterion assuming all other QA/QC specifications are
met.
4.1.2.3 The type of sorbent material used by the traps during
the RATA must be the same as for daily operation of the monitoring
system; however, the size of the traps used for the RATA may be
smaller than the traps used for daily operation of the system.
4.1.2.4 Calculation of RATA Results. Calculate the relative
accuracy (RA) of the sorbent trap monitoring system, on a [micro]g/
scm basis, as described in section 12 of Performance Specification
(PS) 2 in appendix B to part 60 of this chapter (see Equations 2-3
through 2-6 of PS2). For purposes of calculating the relative
accuracy, ensure that the reference method and monitoring system
data are on a consistent moisture basis, either wet or dry.The main
and alternative RATA performance specifications in Table A-1 for Hg
CEMS also apply to the sorbent trap monitoring system.
4.1.2.5 Bias Adjustment. Measurement or adjustment of sorbent
trap monitoring system data for bias is not required.
4.1.3 Diluent Gas, Flow Rate, and/or Moisture Monitoring
Systems. Monitoring systems that are used to measure stack gas
volumetric flow rate, diluent gas concentration, or stack gas
moisture content, either for routine operation of a sorbent trap
monitoring system or to convert Hg concentration data to units of
the applicable emission limit, must be certified in accordance with
the applicable provisions of part 75 of this chapter.
4.2 Recertification. Whenever the owner or operator makes a
replacement, modification, or change to a certified CEMS or sorbent
trap monitoring system that may significantly affect the ability of
the system to accurately measure or record pollutant or diluent gas
concentrations, stack gas flow rates, or stack gas moisture content,
the owner or operator shall recertify the monitoring system.
Furthermore, whenever the owner or operator makes a replacement,
modification, or change to the flue gas handling system or the unit
operation that may significantly change the concentration or flow
profile, the owner or operator shall recertify the monitoring
system. The same tests performed for the initial certification of
the monitoring system shall be repeated for recertification, unless
otherwise specified by the Administrator. Examples of changes that
require recertification include: replacement of a gas analyzer;
complete monitoring system replacement, and changing the location or
orientation of the sampling probe.
5. Ongoing Quality Assurance (QA) and Data Validation
5.1 Hg CEMS.
5.1.1 Required QA Tests. Periodic QA testing of each Hg CEMS is
required following initial certification. The required QA tests, the
test frequencies, and the performance specifications that must be
met are summarized in Table A-2, below. All tests must be performed
with the affected unit(s) operating (i.e., combusting fuel). Except
for the RATA, which must be performed at normal load, no particular
load level is required for the tests. For each test, follow the same
basic procedures in section 4.1.1 of this appendix that were used
for initial certification.
5.1.2 Test Frequency. The frequency for the required QA tests of
the Hg CEMS shall be as follows:
5.1.2.1 Calibration error tests of the Hg CEMS are required
daily, except during unit outages. Use either NIST-traceable
elemental Hg standards or NIST-traceable oxidized Hg standards for
these calibrations. Both a zero-level gas and either a mid-level or
high-level gas are required for these calibrations.
5.1.2.2 Perform a linearity check of the Hg CEMS in each QA
operating quarter, using low-level, mid-level, and high-level NIST-
traceable elemental Hg standards. For units that operate
infrequently, limited exemptions from this test are allowed for
``non-QA operating quarters''. A maximum of three consecutive
exemptions for this reason are permitted, following the quarter of
the last test. After the third consecutive exemption, a linearity
check must be performed in the next calendar quarter or within a
grace period of 168 unit or stack operating hours after the end of
that quarter. The test frequency for 3-level system integrity checks
(if performed in lieu of linearity checks) is the same as for the
linearity checks. Use low-level, mid-level, and high-level NIST-
traceable oxidized Hg standards for the system integrity checks.
5.1.2.3 If required, perform a single-level system integrity
check weekly, i.e., once every 7 operating days (see the third
column in Table A-2).
5.1.2.4 The test frequency for the RATAs of the Hg CEMS shall be
annual, i.e., once every four QA operating quarters. For units that
operate infrequently, extensions of RATA deadlines are allowed for
non-QA operating quarters. Following a RATA, if there is a
subsequent non-QA quarter, it extends the deadline for the next test
by one calendar quarter. However, there is a limit to these
extensions; the deadline may not be extended beyond the end of the
eighth calendar quarter after the quarter of the last test. At that
point, a RATA must either be performed within the eighth calendar
quarter or in a 720 hour unit or stack operating hour grace period
following that quarter. When a required annual RATA is done within a
grace period, the deadline for the next RATA is three QA operating
quarters after the quarter in which the grace period test is
performed.
5.1.3 Grace Periods.
5.1.3.1 A 168 unit or stack operating hour grace period is
available for quarterly linearity checks and 3-level system
integrity checks of the Hg CEMS.
5.1.3.2 A 720 unit or stack operating hour grace period is
available for RATAs of the Hg CEMS.
5.1.3.3 There is no grace period for weekly system integrity
checks. The test must be completed once every 7 operating days.
5.1.4 Data Validation. The Hg CEMS is considered to be out-of-
control, and data from the CEMS may not be reported as quality-
assured, when any one of the acceptance criteria for the required QA
tests in Table A-2 is not met. The CEMS is also considered to be
out-of-control when a required QA test is not performed on schedule
or within an allotted grace period. To end an out-of-control period,
the QA test that was either failed or not done on time must be
performed and passed. Out-of-control periods are counted as hours of
monitoring system downtime.
5.1.5 Conditional Data Validation. For certification,
recertification, and diagnostic testing of Hg monitoring systems,
and for the required QA tests when non-redundant backup Hg
monitoring systems or temporary like-kind Hg analyzers are brought
into service, the conditional data validation provisions in
Sec. Sec. 75.20(b)(3)(ii) through (b)(3)(ix) of this chapter may be
used to avoid or minimize data loss. The allotted window of time to
complete 7-day calibration error tests, linearity checks, cycle time
tests, and RATAs shall be as specified in Sec. 75.20(b)(3)(iv) of
this chapter. Required system integrity checks must be completed
within 168 unit or stack operating hours after the probationary
calibration error test.
Table A-2--On-Going QA Test Requirements for Hg CEMS
----------------------------------------------------------------------------------------------------------------
With these
Perform this type of QA test . . . At this frequency . . . qualifications and Acceptance criteria . .
exceptions . . . .
----------------------------------------------------------------------------------------------------------------
Calibration error test............... Daily.................. Use either a [verbarlm]R-A
mid- or high-level gas. [verbarlm] <= 5.0% of
span value.
or
[verbarlm]R-A
[verbarlm] <= 1.0
[mu]g/scm.
Use either
elemental or oxidized
Hg.
[[Page 9505]]
Calibrations
are not required when
the unit is not in
operation.
Single-level system integrity check.. Weekly \1\............. Required only [verbarlm]R-Aavg
for systems with [verbarlm] <= 10.0% of
converters. the reference gas
value.
or
[verbarlm]R-Aavg
[verbarlm] <= 0.8
[micro]g/scm.
Use oxidized
Hg--either mid- or
high-level.
Not required
if daily calibrations
are done with a NIST-
traceable source of
oxidized Hg.
Linearity check Quarterly \3\.......... Required in [verbarlm]R-Aavg
or................................... each ``QA operating [verbarlm] <= 10.0% of
3-level system integrity check....... quarter'' 2--and no the reference gas
less than once every 4 value, at each
calendar quarters. calibration gas level.
or
[verbarlm]R-Aavg
[verbarlm] <= 0.8
[mu]g/scm.
168 operating
hour grace period
available.
Use elemental
Hg for linearity check.
Use oxidized
Hg for system
integrity check.
For system
integrity check, CEMS
must have a converter.
RATA................................. Annual \4\............. Test deadline 20.0% RA.
may be extended for or
``non-QA operating [verbarlm]RMavg-Cavg
quarters'', up to a [verbarlm] <= 1.0
maximum of 8 quarters [mu]g/scm,
from the quarter of if
the previous test. RMavg < 5.0 [mu]g/scm.
720 operating
hour grace period
available.
----------------------------------------------------------------------------------------------------------------
\1\ ``Weekly'' means once every 7 operating days.
\2\ A ``QA operating quarter'' is a calendar quarter with at least 168 unit or stack operating hours.
\3\ ``Quarterly'' means once every QA operating quarter.
\4\ ``Annual'' means once every four QA operating quarters.
5.1.6 Adjustment of Span. If you discover that a span adjustment
is needed (e.g., if the Hg concentration readings exceed the span
value for a significant percentage of the unit operating hours in a
calendar quarter), you must implement the span adjustment within 90
days after the end of the calendar quarter in which you identify the
need for the adjustment. A diagnostic linearity check is required
within 168 unit or stack operating hours after changing the span
value.
5.2 Sorbent Trap Monitoring Systems.
5.2.1 Each sorbent trap monitoring system shall be continuously
operated and maintained in accordance with Performance Specification
(PS) 12B in appendix B to part 60 of this chapter. The QA/QC
criteria for routine operation of the system are summarized in Table
12B-1 of PS 12B. Each pair of sorbent traps may be used to sample
the stack gas for up to 14 operating days.
5.2.2 For ongoing QA, periodic RATAs of the system are required.
5.2.2.1 The RATA frequency shall be annual, i.e., once every
four QA operating quarters. The provisions in section 5.1.2.4 of
this appendix pertaining to RATA deadline extensions also apply to
sorbent trap monitoring systems.
5.2.2.2 The same RATA performance criteria specified in Table A-
4 for Hg CEMS shall apply to the annual RATAs of the sorbent trap
monitoring system.
5.2.2.3 A 720 unit or stack operating hour grace period is
available for RATAs of the monitoring system.
5.2.3 Data validation for sorbent trap monitoring systems shall
be done in accordance with Table 12B-1 in Performance Specification
(PS) 12B in appendix B to part 60 of this chapter. All periods of
invalid data shall be counted as hours of monitoring system
downtime.
5.3 Flow Rate, Diluent Gas, and Moisture Monitoring Systems. The
on-going QA test requirements for these monitoring systems are
specified in part 75 of this chapter (see Sec. Sec. 63.10010(b)
through (d)).
5.4 QA/QC Program Requirements. The owner or operator shall
develop and implement a quality assurance/quality control (QA/QC)
program for the Hg CEMS and/or sorbent trap monitoring systems that
are used to provide data under this subpart. At a minimum, the
program shall include a written plan that describes in detail (or
that refers to separate documents containing) complete, step-by-step
procedures and operations for the most important QA/QC activities.
Electronic storage of the QA/QC plan is permissible, provided that
the information can be made available in hard copy to auditors and
inspectors. The QA/QC program requirements for the diluent gas, flow
rate, and moisture monitoring systems described in section 3.2.1.3
of this appendix are specified in section 1 of appendix B to part 75
of this chapter.
5.4.1 General Requirements.
5.4.1.1 Preventive Maintenance. Keep a written record of
procedures needed to maintain the Hg CEMS and/or sorbent trap
monitoring system(s) in proper operating condition and a schedule
for those procedures. Include, at a minimum, all procedures
specified by the manufacturers of the equipment and, if applicable,
additional or alternate procedures developed for the equipment.
5.4.1.2 Recordkeeping and Reporting. Keep a written record
describing procedures that will be used to implement the
recordkeeping and reporting requirements of this appendix.
5.4.1.3 Maintenance Records. Keep a record of all testing,
maintenance, or repair activities performed on any Hg CEMS or
sorbent trap monitoring system in a location and format suitable for
inspection. A maintenance log may be used for this purpose. The
following records should be maintained: date, time, and description
of any testing, adjustment, repair, replacement, or preventive
maintenance action performed on any monitoring system and records of
any corrective actions associated with a monitor outage period.
Additionally, any adjustment that may significantly affect a
system's ability to accurately measure emissions data must be
[[Page 9506]]
recorded (e.g., changing the dilution ratio of a CEMS), and a
written explanation of the procedures used to make the adjustment(s)
shall be kept.
5.4.2 Specific Requirements for Hg CEMS.
5.4.2.1 Daily Calibrations, Linearity Checks and System
Integrity Checks. Keep a written record of the procedures used for
daily calibrations of the Hg CEMS. If moisture and/or chlorine is
added to the Hg calibration gas, document how the dilution effect of
the moisture and/or chlorine addition on the calibration gas
concentration is accounted for in an appropriate manner. Also keep
records of the procedures used to perform linearity checks of the Hg
CEMS and the procedures for system integrity checks of the Hg CEMS.
Document how the test results are calculated and evaluated.
5.4.2.2 Monitoring System Adjustments. Document how each
component of the Hg CEMS will be adjusted to provide correct
responses to calibration gases after routine maintenance, repairs,
or corrective actions.
5.4.2.3 Relative Accuracy Test Audits. Keep a written record of
procedures used for RATAs of the Hg CEMS. Indicate the reference
methods used and document how the test results are calculated and
evaluated.
5.4.3 Specific Requirements for Sorbent Trap Monitoring Systems.
5.4.3.1 Sorbent Trap Identification and Tracking. Include
procedures for inscribing or otherwise permanently marking a unique
identification number on each sorbent trap, for chain of custody
purposes. Keep records of the ID of the monitoring system in which
each sorbent trap is used, and the dates and hours of each Hg
collection period.
5.4.3.2 Monitoring System Integrity and Data Quality. Document
the procedures used to perform the leak checks when a sorbent trap
is placed in service and removed from service. Also Document the
other QA procedures used to ensure system integrity and data
quality, including, but not limited to, gas flow meter calibrations,
verification of moisture removal, and ensuring air-tight pump
operation. In addition, the QA plan must include the data acceptance
and quality control criteria in Table 12B-1 in section 9.0 of
Performance Specification (PS) 12B in Appendix B to part 60 of this
chapter. All reference meters used to calibrate the gas flow meters
(e.g., wet test meters) shall be periodically recalibrated. Annual,
or more frequent, recalibration is recommended. If a NIST-traceable
calibration device is used as a reference flow meter, the QA plan
must include a protocol for ongoing maintenance and periodic
recalibration to maintain the accuracy and NIST-traceability of the
calibrator.
5.4.3.3 Hg Analysis. Explain the chain of custody employed in
packing, transporting, and analyzing the sorbent traps. Keep records
of all Hg analyses. The analyses shall be performed in accordance
with the procedures described in section 11.0 of Performance
Specification (PS) 12B in Appendix B to part 60 of this chapter.
5.4.3.4 Data Collection Period. State, and provide the rationale
for, the minimum acceptable data collection period (e.g., one day,
one week, etc.) for the size of sorbent trap selected for the
monitoring. Address such factors as the Hg concentration in the
stack gas, the capacity of the sorbent trap, and the minimum mass of
Hg required for the analysis. Each pair of sorbent traps may be used
to sample the stack gas for up to 14 operating days.
5.4.3.5 Relative Accuracy Test Audit Procedures. Keep records of
the procedures and details peculiar to the sorbent trap monitoring
systems that are to be followed for relative accuracy test audits,
such as sampling and analysis methods.
6. Data Reduction and Calculations
6.1 Data Reduction.
6.1.1 Reduce the data from Hg CEMS to hourly averages, in
accordance with Sec. 60.13(h)(2) of this chapter.
6.1.2 For sorbent trap monitoring systems, determine the Hg
concentration for each data collection period and assign this
concentration value to each operating hour in the data collection
period.
6.1.3 For any operating hour in which valid data are not
obtained, either for Hg concentration or for a parameter used in the
emissions calculations (i.e., flow rate, diluent gas concentration,
or moisture, as applicable), do not calculate the Hg emission rate
for that hour. For the purposes of this appendix, part 75 substitute
data values are not considered to be valid data.
6.1.4 Operating hours in which valid data are not obtained for
Hg concentration are considered to be hours of monitor downtime. The
use of substitute data for Hg concentration is not required.
6.2 Calculation of Hg Emission Rates. Use the applicable
calculation methods in paragraphs 6.2.1 and 6.2.2 of this section to
convert Hg concentration values to the appropriate units of the
emission standard.
6.2.1 Heat Input-Based Hg Emission Rates. Calculate hourly heat
input-based Hg emission rates, in units of lb/TBtu, according to
sections 6.2.1.1 through 6.2.1.4 of this appendix.
6.2.1.1 Select an appropriate emission rate equation from among
Equations 19-1 through 19-9 in EPA Method 19 in appendix A-7 to part
60 of this chapter.
6.2.1.2 Calculate the Hg emission rate in lb/MMBtu, using the
equation selected from Method 19. Multiply the Hg concentration
value by 6.24 x 10-11 to convert it from [mu]g/scm to lb/
scf. In cases where an appropriate F-factor is not listed in Table
19-2 of Method 19, you may use F-factors from Table 1 in section
3.3.5 of appendix F to part 75 of this chapter, or F-factors derived
using the procedures in section 3.3.6 of appendix to part 75 of this
chapter. Also, for startup and shutdown hours, you may calculate the
Hg emission rate using the applicable diluent cap value specified in
section 3.3.4.1 of appendix F to part 75 of this chapter, provided
that the diluent gas monitor is not out-of-control and the hourly
average O2 concentration is above 14.0% O2
(19.0% for an IGCC) or the hourly average CO2
concentration is below 5.0% CO2 (1.0% for an IGCC), as
applicable.
6.2.1.3 Multiply the lb/MMBtu value obtained in section 6.2.1.2
of this appendix by 106 to convert it to lb/TBtu.
6.2.1.4 The heat input-based Hg emission rate limit in Table 2
to this subpart must be met on a 30 boiler operating day rolling
average basis. Use Equation 19-19 in EPA Method 19 to calculate the
Hg emission rate for each averaging period. The term Ehj
in Equation 19-19 must be in the units of the applicable emission
limit. Do not include non-operating hours with zero emissions in the
average.
6.2.2 Electrical Output-Based Hg Emission Rates. Calculate
electrical output-based Hg emission limits in units of lb/GWh,
according to sections 6.2.2.1 through 6.2.2.3 of this appendix.
6.2.2.1 Calculate the Hg mass emissions for each operating hour
in which valid data are obtained for all parameters, using Equation
A-2 of this section (for wet-basis measurements of Hg concentration)
or Equation A-3 of this section (for dry-basis measurements), as
applicable:
[GRAPHIC] [TIFF OMITTED] TR16FE12.014
Where:
Mh = Hg mass emission rate for the hour (lb/h)
K = Units conversion constant, 6.24 x 10-11 lb-scm/[mu]g-
scf,
Ch = Hourly average Hg concentration, wet basis ([mu]g/
scm)
Qh = Stack gas volumetric flow rate for the hour (scfh).
(Note: Use unadjusted flow rate values; bias adjustment is not
required)
[GRAPHIC] [TIFF OMITTED] TR16FE12.015
Where:
Mh = Hg mass emission rate for the hour (lb/h)
K = Units conversion constant, 6.24 x 10-11 lb-scm/[mu]g-
scf.
[[Page 9507]]
Ch = Hourly average Hg concentration, dry basis ([mu]g/
dscm).
Qh = Stack gas volumetric flow rate for the hour (scfh)
(Note: Use unadjusted flow rate values; bias adjustment is not
required).
Bws = Moisture fraction of the stack gas, expressed as a
decimal (equal to % H2O/100)
6.2.2.2 Use Equation A-4 of this section to calculate the
emission rate for each unit or stack operating hour in which valid
data are obtained for all parameters.
[GRAPHIC] [TIFF OMITTED] TR16FE12.016
Where:
Eho = Electrical output-based Hg emission rate (lb/GWh).
Mh = Hg mass emission rate for the hour, from Equation A-
2 or A-3 of this section, as applicable (lb/h).
(MW)h = Gross electrical load for the hour, in megawatts
(MW).
10 3 = Conversion factor from megawatts to gigawatts.
6.2.2.3 The applicable electrical output-based Hg emission rate
limit in Table 1 or 2 to this subpart must be met on a 30-boiler
operating day rolling average basis. Use Equation A-5 of this
section to calculate the Hg emission rate for each averaging period.
[GRAPHIC] [TIFF OMITTED] TR16FE12.017
Where:
Eo = Hg emission rate for the averaging period (lb/GWh).
Eho = Electrical output-based hourly Hg emission rate for
unit or stack operating hour ``h'' in the averaging period, from
Equation A-4 of this section (lb/GWh).
n = Number of unit or stack operating hours in the averaging period
in which valid data were obtained for all parameters (Note: Do not
include non-operating hours with zero emission rates in the
average).
7. Recordkeeping and Reporting
7.1 Recordkeeping Provisions. For the Hg CEMS and/or sorbent
trap monitoring systems and any other necessary monitoring systems
installed at each affected unit, the owner or operator must maintain
a file of all measurements, data, reports, and other information
required by this appendix in a form suitable for inspection, for 5
years from the date of each record, in accordance with Sec.
63.10033. The file shall contain the information in paragraphs 7.1.1
through 7.1.10 of this section.
7.1.1 Monitoring Plan Records. For each affected unit or group
of units monitored at a common stack, the owner or operator shall
prepare and maintain a monitoring plan for the Hg CEMS and/or
sorbent trap monitoring system(s) and any other monitoring system(s)
(i.e., flow rate, diluent gas, or moisture systems) needed for
routine operation of a sorbent trap monitoring system or to convert
Hg concentrations to units of the applicable emission standard. The
monitoring plan shall contain essential information on the
continuous monitoring systems and shall Document how the data
derived from these systems ensure that all Hg emissions from the
unit or stack are monitored and reported.
7.1.1.1 Updates. Whenever the owner or operator makes a
replacement, modification, or change in a certified continuous
monitoring system that is used to provide data under this subpart
(including a change in the automated data acquisition and handling
system or the flue gas handling system) which affects information
reported in the monitoring plan (e.g., a change to a serial number
for a component of a monitoring system), the owner or operator shall
update the monitoring plan.
7.1.1.2 Contents of the Monitoring Plan. For Hg CEMS and sorbent
trap monitoring systems, the monitoring plan shall contain the
information in sections 7.1.1.2.1 and 7.1.1.2.2 of this appendix, as
applicable. For stack gas flow rate, diluent gas, and moisture
monitoring systems, the monitoring plan shall include the
information required for those systems under Sec. 75.53 (g) of this
chapter.
7.1.1.2.1 Electronic. The electronic monitoring plan records
must include the following: unit or stack ID number(s); monitoring
location(s); the Hg monitoring methodologies used; Hg monitoring
system information, including, but not limited to: Unique system and
component ID numbers; the make, model, and serial number of the
monitoring equipment; the sample acquisition method; formulas used
to calculate Hg emissions; Hg monitor span and range information The
electronic monitoring plan shall be evaluated and submitted using
the Emissions Collection and Monitoring Plan System (ECMPS) Client
Tool provided by the Clean Air Markets Division in the Office of
Atmospheric Programs of the EPA.
7.1.1.2.2 Hard Copy. Keep records of the following: schematics
and/or blueprints showing the location of the Hg monitoring
system(s) and test ports; data flow diagrams; test protocols;
monitor span and range calculations; miscellaneous technical
justifications.
7.1.2 Operating Parameter Records. The owner or operator shall
record the following information for each operating hour of each
affected unit and also for each group of units utilizing a common
stack, to the extent that these data are needed to convert Hg
concentration data to the units of the emission standard. For non-
operating hours, record only the items in paragraphs 7.1.2.1 and
7.1.2.2 of this section. If there is heat input to the unit(s), but
no electrical load, record only the items in paragraphs 7.1.2.1,
7.1.2.2, and (if applicable) 7.1.2.4 of this section.
7.1.2.1 The date and hour;
7.1.2.2 The unit or stack operating time (rounded up to the
nearest fraction of an hour (in equal increments that can range from
one hundredth to one quarter of an hour, at the option of the owner
or operator);
7.1.2.3 The hourly gross unit load (rounded to nearest MWe); and
7.1.2.4 If applicable, the F-factor used to calculate the heat
input-based Hg emission rate.
7.1.3 Hg Emissions Records (Hg CEMS). For each affected unit or
common stack using a Hg CEMS, the owner or operator shall record the
following information for each unit or stack operating hour:
7.1.3.1 The date and hour;
7.1.3.2 Monitoring system and component identification codes, as
provided in the monitoring plan, if the CEMS provides a quality-
assured value of Hg concentration for the hour;
7.1.3.3 The hourly Hg concentration, if a quality-assured value
is obtained for the hour ([micro]g/scm, rounded to three significant
figures);
7.1.3.4 A special code, indicating whether or not a quality-
assured Hg concentration is obtained for the hour. This code may be
entered manually when a temporary like-kind replacement Hg analyzer
is used for reporting; and
7.1.3.5 Monitor data availability, as a percentage of unit or
stack operating hours, calculated according to Sec. 75.32 of this
chapter.
7.1.4 Hg Emissions Records (Sorbent Trap Monitoring Systems).
For each affected unit or common stack using a sorbent trap
monitoring system, each owner or operator shall record the following
information for the unit or stack operating hour in each data
collection period:
7.1.4.1 The date and hour;
7.1.4.2 Monitoring system and component identification codes, as
provided in the monitoring plan, if the sorbent trap
[[Page 9508]]
system provides a quality-assured value of Hg concentration for the
hour;
7.1.4.3 The hourly Hg concentration, if a quality-assured value
is obtained for the hour ([micro]g/scm, rounded to three significant
figures). Note that when a quality-assured Hg concentration value is
obtained for a particular data collection period, that single
concentration value is applied to each operating hour of the data
collection period.
7.1.4.4 A special code, indicating whether or not a quality-
assured Hg concentration is obtained for the hour;
7.1.4.5 The average flow rate of stack gas through each sorbent
trap (in appropriate units, e.g., liters/min, cc/min, dscm/min);
7.1.4.6 The gas flow meter reading (in dscm, rounded to the
nearest hundredth), at the beginning and end of the collection
period and at least once in each unit operating hour during the
collection period;
7.1.4.7 The ratio of the stack gas flow rate to the sample flow
rate, as described in section 12.2 of Performance Specification (PS)
12B in Appendix B to part 60 of this chapter; and
7.1.4.8 Monitor data availability, as a percentage of unit or
stack operating hours, calculated according to Sec. 75.32 of this
chapter.
7.1.5 Stack Gas Volumetric Flow Rate Records.
7.1.5.1 Hourly measurements of stack gas volumetric flow rate
during unit operation are required for routine operation of sorbent
trap monitoring systems, to maintain the required ratio of stack gas
flow rate to sample flow rate (see section 8.2.2 of Performance
Specification (PS) 12B in Appendix B to part 60 of this chapter).
Hourly stack gas flow rate data are also needed in order to
demonstrate compliance with electrical output-based Hg emissions
limits, as provided in section 6.2.2 of this appendix.
7.1.5.2 For each affected unit or common stack, if hourly
measurements of stack gas flow rate are needed for sorbent trap
monitoring system operation or to convert Hg concentrations to the
units of the emission standard, use a flow rate monitor that meets
the requirements of part 75 of this chapter to record the required
data. You must keep hourly flow rate records, as specified in Sec.
75.57(c)(2) of this chapter.
7.1.6 Records of Stack Gas Moisture Content.
7.1.6.1 Correction of hourly Hg concentration data for moisture
is sometimes required when converting Hg concentrations to the units
of the applicable Hg emissions limit. In particular, these
corrections are required:
7.1.6.1.1 For sorbent trap monitoring systems;
7.1.6.1.2 For Hg CEMS that measure Hg concentration on a dry
basis, when you must calculate electrical output-based Hg emission
rates; and
7.1.6.1.3 When using certain equations from EPA Method 19 in
appendix A-7 to part 60 of this chapter to calculate heat input-
based Hg emission rates.
7.1.6.2 If hourly moisture corrections are required, either use
a fuel-specific default moisture percentage from Sec. 75.11(b)(1)
of this chapter or a certified moisture monitoring system that meets
the requirements of part 75 of this chapter, to record the required
data. If you use a moisture monitoring system, you must keep hourly
records of the stack gas moisture content, as specified in Sec.
75.57(c)(3) of this chapter.
7.1.7 Records of Diluent Gas (CO2 or O2) Concentration.
7.1.7.1 When a heat input-based Hg mass emissions limit must be
met, in units of lb/TBtu, hourly measurements of CO2 or
O2 concentration are required to convert Hg
concentrations to units of the standard.
7.1.7.2 If hourly measurements of diluent gas concentration are
needed, use a certified CO2 or O2 monitor that
meets the requirements of part 75 of this chapter to record the
required data. You must keep hourly CO2 or O2
concentration records, as specified in Sec. 75.57(g) of this
chapter.
7.1.8 Hg Emission Rate Records. For applicable Hg emission
limits in units of lb/TBtu or lb/GWh, record the following
information for each affected unit or common stack:
7.1.8.1 The date and hour;
7.1.8.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as
applicable, calculated according to section 6.2.1 or 6.2.2 of this
appendix, rounded to three significant figures), if valid values of
Hg concentration and all other required parameters (stack gas
volumetric flow rate, diluent gas concentration, electrical load,
and moisture data, as applicable) are obtained for the hour;
7.1.8.3 An identification code for the formula (either the
selected equation from Method 19 in section 6.2.1 of this appendix
or Equation A-4 in section 6.2.2 of this appendix) used to derive
the hourly Hg emission rate from Hg concentration, flow rate,
electrical load, diluent gas concentration, and moisture data (as
applicable); and
7.1.8.4 A code indicating that the Hg emission rate was not
calculated for the hour, if valid data for Hg concentration and/or
any of the other necessary parameters are not obtained for the hour.
For the purposes of this appendix, the substitute data values
required under part 75 of this chapter for diluent gas
concentration, stack gas flow rate and moisture content are not
considered to be valid data.
7.1.9 Certification and Quality Assurance Test Records. For any
Hg CEMS and sorbent trap monitoring systems used to provide data
under this subpart, record the following certification and quality-
assurance information:
7.1.9.1 The reference values, monitor responses, and calculated
calibration error (CE) values, and a flag to indicate whether the
test was done using elemental or oxidized Hg, for all required 7-day
calibration error tests and daily calibration error tests of the Hg
CEMS;
7.1.9.2 The reference values, monitor responses, and calculated
linearity error (LE) or system integrity error (SIE) values for all
linearity checks of the Hg CEMS, and for all single-level and 3-
level system integrity checks of the Hg CEMS;
7.1.9.3 The CEMS and reference method readings for each test run
and the calculated relative accuracy results for all RATAs of the Hg
CEMS and/or sorbent trap monitoring systems;
7.1.9.4 The stable stack gas and calibration gas readings and
the calculated results for the upscale and downscale stages of all
required cycle time tests of the Hg CEMS or, for a batch sampling Hg
CEMS, the interval between measured Hg concentration readings;
7.1.9.5 Supporting information for all required RATAs of the Hg
monitoring systems, including records of the test dates, the raw
reference method and monitoring system data, the results of sample
analyses to substantiate the reported test results, and records of
sampling equipment calibrations;
7.1.9.6 For sorbent trap monitoring systems, also keep records
of the results of all analyses of the sorbent traps used for routine
daily operation of the system, and information documenting the
results of all leak checks and the other applicable quality control
procedures described in Table 12B-1 of Performance Specification
(PS) 12B in appendix B to part 60 of this chapter.
7.1.9.7 For stack gas flow rate, diluent gas, and (if
applicable) moisture monitoring systems, you must keep records of
all certification, recertification, diagnostic, and on-going
quality-assurance tests of these systems, as specified in Sec.
75.59 of this chapter.
7.2 Reporting Requirements.
7.2.1 General Reporting Provisions. The owner or operator shall
comply with the following requirements for reporting Hg emissions
from each affected unit (or group of units monitored at a common
stack) under this subpart:
7.2.1.1 Notifications, in accordance with paragraph 7.2.2 of
this section;
7.2.1.2 Monitoring plan reporting, in accordance with paragraph
7.2.3 of this section;
7.2.1.3 Certification, recertification, and QA test submittals,
in accordance with paragraph 7.2.4 of this section; and
7.2.1.4 Electronic quarterly report submittals, in accordance
with paragraph 7.2.5 of this section.
7.2.2 Notifications. The owner or operator shall provide
notifications for each affected unit (or group of units monitored at
a common stack) under this subpart in accordance with Sec.
63.10030.
7.2.3 Monitoring Plan Reporting. For each affected unit (or
group of units monitored at a common stack) under this subpart using
Hg CEMS or sorbent trap monitoring system to measure Hg emissions,
the owner or operator shall make electronic and hard copy monitoring
plan submittals as follows:
7.2.3.1 Submit the electronic and hard copy information in
section 7.1.1.2 of this appendix pertaining to the Hg monitoring
systems at least 21 days prior to the applicable date in Sec.
63.9984. Also submit the monitoring plan information in Sec.
75.53.(g) pertaining to the flow rate, diluent gas, and moisture
monitoring systems within that same time frame, if the required
records are not already in place.
7.2.3.2 Whenever an update of the monitoring plan is required,
as provided in paragraph 7.1.1.1 of this section. An electronic
monitoring plan information
[[Page 9509]]
update must be submitted either prior to or concurrent with the
quarterly report for the calendar quarter in which the update is
required.
7.2.3.3 All electronic monitoring plan submittals and updates
shall be made to the Administrator using the ECMPS Client Tool. Hard
copy portions of the monitoring plan shall be kept on record
according to section 7.1 of this appendix.
7.2.4 Certification, Recertification, and Quality-Assurance Test
Reporting. Except for daily QA tests of the required monitoring
systems (i.e., calibration error tests and flow monitor interference
checks), the results of all required certification, recertification,
and quality-assurance tests described in paragraphs 7.1.10.1 through
7.1.10.7 of this section (except for test results previously
submitted, e.g., under the ARP) shall be submitted electronically,
using the ECMPS Client Tool, either prior to or concurrent with the
relevant quarterly electronic emissions report.
7.2.5 Quarterly Reports.
7.2.5.1 Beginning with the report for the calendar quarter in
which the initial compliance demonstration is completed or the
calendar quarter containing the applicable date in Sec. 63.9984,
the owner or operator of any affected unit shall use the ECMPS
Client Tool to submit electronic quarterly reports to the
Administrator, in an XML format specified by the Administrator, for
each affected unit (or group of units monitored at a common stack)
under this subpart.
7.2.5.2 The electronic reports must be submitted within 30 days
following the end of each calendar quarter, except for units that
have been placed in long-term cold storage.
7.2.5.3 Each electronic quarterly report shall include the
following information:
7.2.5.3.1 The date of report generation;
7.2.5.3.2 Facility identification information;
7.2.5.3.3 The information in paragraphs 7.1.2 through 7.1.8 of
this section, as applicable to the Hg emission measurement
methodology (or methodologies) used and the units of the Hg emission
standard(s); and
7.2.5.3.4 The results of all daily calibration error tests of
the Hg CEMS, as described in paragraph 7.1.90.1 of this section and
(if applicable) the results of all daily flow monitor interference
checks.
7.2.5.4 Compliance Certification. Based on reasonable inquiry of
those persons with primary responsibility for ensuring that all Hg
emissions from the affected unit(s) under this subpart have been
correctly and fully monitored, the owner or operator shall submit a
compliance certification in support of each electronic quarterly
emissions monitoring report. The compliance certification shall
include a statement by a responsible official with that official's
name, title, and signature, certifying that, to the best of his or
her knowledge, the report is true, accurate, and complete.
Appendix B to Subpart UUUUU---HCl and HF Monitoring Provisions
1. Applicability
These monitoring provisions apply to the measurement of HCl and/
or HF emissions from electric utility steam generating units, using
CEMS. The CEMS must be capable of measuring HCl and/or HF in the
appropriate units of the applicable emissions standard (e.g., lb/
MMBtu, lb/MWh, or lb/GWh).
2. Monitoring of HCl and/or HF Emissions
2.1 Monitoring System Installation Requirements. Install HCl
and/or HF CEMS and any additional monitoring systems needed to
convert pollutant concentrations to units of the applicable
emissions limit in accordance with Performance Specification 15 for
extractive Fourier Transform Infrared Spectroscopy (FTIR) continuous
emissions monitoring systems in appendix B to part 60 of this
chapter and Sec. 63.10010(a).
2.2 Primary and Backup Monitoring Systems. The provisions
pertaining to primary and redundant backup monitoring systems in
section 2.2 of appendix A to this subpart apply to HCl and HF CEMS
and any additional monitoring systems needed to convert pollutant
concentrations to units of the applicable emissions limit.
2.3 FTIR Monitoring System Equipment, Supplies, Definitions, and
General Operation. The provisions of Performance Specification 15
Sections 2.0, 3.0, 4.0, 5.0, 6.0, and 10.0 apply.
3. Initial Certification Procedures
The initial certification procedures for the HCl or HF CEMS used
to provide data under this subpart are as follows:
3.1 The HCl and/or HF CEMS must be certified according to
Performance Specification 15 using the procedures for gas auditing
and comparison to a reference method (RM) as specified in sections
3.1.1 and 3.1.2 below. (Please Note: EPA plans to publish a
technology neutral performance specification and appropriate on-
going quality-assurance requirements for HCl CEMS in the near future
along with amendments to this appendix to accommodate their use.)
3.1.1 You must conduct a gas audit of the HCl and/or HF CEMS as
described in section 9.1 of Performance Specification 15, with the
exceptions listed in sections 3.1.2.1 and 3.1.2.2 below.
3.1.1.1 The audit sample gas does not have to be obtained from
the Administrator; however, it must be (1) from a secondary source
of certified gases (i.e., independent of any calibration gas used
for the daily calibration assessments) and (2) directly traceable to
National Institute of Standards and Technology (NIST) or VSL Dutch
Metrology Institute (VSL) reference materials through an unbroken
chain of comparisons. If audit gas traceable to NIST or VSL
reference materials is not available, you may use a gas with a
concentration certified to a specified uncertainty by the gas
manufacturer.
3.1.1.2 Analyze the results of the gas audit using the
calculations in section 12.1 of Performance Specification 15. The
calculated correction factor (CF) from Eq. 6 of Performance
Specification 15 must be between 0.85 and 1.15. You do not have to
test the bias for statistical significance.
3.1.2 You must perform a relative accuracy test audit or RATA
according to section 11.1.1.4 of Performance Specification 15 and
the requirements below. Perform the RATA of the HCl or HF CEMS at
normal load. Acceptable HCl/HF reference methods (RM) are Methods 26
and 26A in appendix A-8 to part 60 of this chapter, Method 320 in
Appendix A to this part, or ASTM D6348-03 (Reapproved 2010)
``Standard Test Method for Determination of Gaseous Compounds by
Extractive Direct Interface Fourier Transform Infrared (FTIR)
Spectroscopy'' (incorporated by reference, see Sec. 63.14), each
applied based on the criteria set forth in Table 5 of this subpart.
3.1.2.1 When ASTM D6348-03 is used as the RM, the following
conditions must be met:
3.1.2.1.1 The test plan preparation and implementation in the
Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory;
3.1.2.1.2 In ASTM D6348-03 Annex A5 (Analyte Spiking Technique),
the percent (%) R must be determined for each target analyte (see
Equation A5.5);
3.1.2.1.3 For the ASTM D6348-03 test data to be acceptable for a
target analyte, %R must be 70% >= R <= 130%; and
3.1.2.1.4 The %R value for each compound must be reported in the
test report and all field measurements corrected with the calculated
%R value for that compound using the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE12.018
3.1.2.2 The relative accuracy (RA) of the HCl or HF CEMS must be
no greater than 20 percent of the mean value of the RM test data in
units of ppm on the same moisture basis. Alternatively, if the mean
RM value is less than 1.0 ppm, the RA results are acceptable if the
absolute value of the difference between the mean RM and CEMS values
does not exceed 0.20 ppm.
3.2 Any additional stack gas flow rate, diluent gas, and
moisture monitoring system(s) needed to express pollutant
concentrations in units of the applicable emissions limit must be
certified according to part 75 of this chapter.
[[Page 9510]]
4. Recertification Procedures
Whenever the owner or operator makes a replacement,
modification, or change to a certified CEMS that may significantly
affect the ability of the system to accurately measure or record
pollutant or diluent gas concentrations, stack gas flow rates, or
stack gas moisture content, the owner or operator shall recertify
the monitoring system. Furthermore, whenever the owner or operator
makes a replacement, modification, or change to the flue gas
handling system or the unit operation that may significantly change
the concentration or flow profile, the owner or operator shall
recertify the monitoring system. The same tests performed for the
initial certification of the monitoring system shall be repeated for
recertification, unless otherwise specified by the Administrator.
Examples of changes that require recertification include:
Replacement of a gas analyzer; complete monitoring system
replacement, and changing the location or orientation of the
sampling probe.
5. On-Going Quality Assurance Requirements
5.1 For on-going QA test requirements for HCl and HF CEMS,
implement the quality assurance/quality control procedures of
Performance Specification 15 of appendix B to part 60 of this
chapter as set forth in sections 5.1.1 through 5.1.3 and 5.3.2 of
this appendix.
5.1.1 On a daily basis, you must assess the calibration error of
the HCl or HF CEMS using either a calibration transfer standard as
specified in Performance Specification 15 Section 10.1 which
references Section 4.5 of the FTIR Protocol or a HCl and/or HF
calibration gas at a concentration no greater than two times the
level corresponding to the applicable emission limit. A calibration
transfer standard is a substitute calibration compound chosen to
ensure that the FTIR is performing well at the wavelength regions
used for analysis of the target analytes. The measured concentration
of the calibration transfer standard or HCl and/or HF calibration
gas results must agree within 5 percent of the
reference gas value after correction for differences in pressure.
5.1.2 On a quarterly basis, you must conduct a gas audit of the
HCl and/or HF CEMS as described in section 3.1.1 of this appendix.
For the purposes of this appendix, ``quarterly'' means once every
``QA operating quarter'' (as defined in section 3.1.20 of appendix A
to this subpart). You have the option to use HCl gas in lieu of HF
gas for conducting this audit on an HF CEMS. To the extent
practicable, perform consecutive quarterly gas audits at least 30
days apart. The initial quarterly audit is due in the first QA
operating quarter following the calendar quarter in which
certification testing of the CEMS is successfully completed. Up to
three consecutive exemptions from the quarterly audit requirement
are allowed for ``non-QA operating quarters'' (i.e., calendar
quarters in which there are less than 168 unit or stack operating
hours). However, no more than four consecutive calendar quarters may
elapse without performing a gas audit, except as otherwise provided
in section 5.3.3.2.1 of this appendix.
5.1.3 You must perform an annual relative accuracy test audit or
RATA of the HCl or HF CEMS as described in section 3.1.2 of this
appendix. Perform the RATA at normal load. For the purposes of this
appendix, ``annual'' means once every four ``QA operating quarters''
(as defined in section 3.1.20 of appendix A to this subpart). The
first annual RATA is due within four QA operating quarters following
the calendar quarter in which the initial certification testing of
the HCl or HF CEMS is successfully completed. The provisions in
section 5.1.2.4 of appendix A to this subpart pertaining to RATA
deadline extensions also apply.
5.2 Stack gas flow rate, diluent gas, and moisture monitoring
systems must meet the applicable on-going QA test requirements of
part 75 of this chapter.
5.3 Data Validation.
5.3.1 Out-of-Control Periods. A HCl or HF CEMS that is used to
provide data under this appendix is considered to be out-of-control,
and data from the CEMS may not be reported as quality-assured, when
any acceptance criteria for a required QA test is not met. The HCl
or HF CEMS is also considered to be out-of-control when a required
QA test is not performed on schedule or within an allotted grace
period. To end an out-of-control period, the QA test that was either
failed or not done on time must be performed and passed. Out-of-
control periods are counted as hours of monitoring system downtime.
5.3.2 Grace Periods. For the purposes of this appendix, a
``grace period'' is defined as a specified number of unit or stack
operating hours after the deadline for a required quality-assurance
test of a continuous monitor has passed, in which the test may be
performed and passed without loss of data.
5.3.2.1 For the flow rate, diluent gas, and moisture monitoring
systems described in section 5.2 of this appendix, a 168 unit or
stack operating hour grace period is available for quarterly
linearity checks, and a 720 unit or stack operating hour grace
period is available for RATAs, as provided, respectively, in
sections 2.2.4 and 2.3.3 of appendix B to part 75 of this chapter.
5.3.2.2 For the purposes of this appendix, if the deadline for a
required gas audit or RATA of a HCl or HF CEMS cannot be met due to
circumstances beyond the control of the owner or operator:
5.3.2.2.1 A 168 unit or stack operating hour grace period is
available in which to perform the gas audit; or
5.3.2.2.2 A 720 unit or stack operating hour grace period is
available in which to perform the RATA.
5.3.2.3 If a required QA test is performed during a grace
period, the deadline for the next test shall be determined as
follows:
5.3.2.3.1 For a gas audit or RATA of the monitoring systems
described in section 5.1 of this appendix, determine the deadline
for the next gas audit or RATA (as applicable) in accordance with
section 2.2.4(b) or 2.3.3(d) of appendix B to part 75 of this
chapter; treat a gas audit in the same manner as a linearity check.
5.3.2.3.2 For the gas audit of a HCl or HF CEMS, the grace
period test only satisfies the audit requirement for the calendar
quarter in which the test was originally due. If the calendar
quarter in which the grace period audit is performed is a QA
operating quarter, an additional gas audit is required for that
quarter.
5.3.2.3.3 For the RATA of a HCl or HF CEMS, the next RATA is due
within three QA operating quarters after the calendar quarter in
which the grace period test is performed.
5.3.4 Conditional Data Validation. For recertification and
diagnostic testing of the monitoring systems that are used to
provide data under this appendix, and for the required QA tests when
non-redundant backup monitoring systems or temporary like-kind
replacement analyzers are brought into service, the conditional data
validation provisions in Sec. Sec. 75.20(b)(3)(ii) through
(b)(3)(ix) of this chapter may be used to avoid or minimize data
loss. The allotted window of time to complete calibration tests and
RATAs shall be as specified in Sec. 75.20(b)(3)(iv) of this
chapter; the allotted window of time to complete a gas audit shall
be the same as for a linearity check (i.e., 168 unit or stack
operating hours).
6. Missing Data Requirements
For the purposes of this appendix, the owner or operator of an
affected unit shall not substitute for missing data from HCl or HF
CEMS. Any process operating hour for which quality-assured HCl or HF
concentration data are not obtained is counted as an hour of
monitoring system downtime.
7. Bias Adjustment
Bias adjustment of hourly emissions data from a HCl or HF CEMS
is not required.
8. QA/QC Program Requirements
The owner or operator shall develop and implement a quality
assurance/quality control (QA/QC) program for the HCl and/or HF CEMS
that are used to provide data under this subpart. At a minimum, the
program shall include a written plan that describes in detail (or
that refers to separate documents containing) complete, step-by-step
procedures and operations for the most important QA/QC activities.
Electronic storage of the QA/QC plan is permissible, provided that
the information can be made available in hard copy to auditors and
inspectors. The QA/QC program requirements for the other monitoring
systems described in section 5.2 of this appendix are specified in
section 1 of appendix B to part 75 of this chapter.
8.1 General Requirements for HCl and HF CEMS.
8.1.1 Preventive Maintenance. Keep a written record of
procedures needed to maintain the HCl and/or HF CEMS in proper
operating condition and a schedule for those procedures. This shall,
at a minimum, include procedures specified by the manufacturers of
the equipment and, if applicable, additional or alternate procedures
developed for the equipment.
8.1.2 Recordkeeping and Reporting. Keep a written record
describing procedures that will be used to implement the
recordkeeping and reporting requirements of this appendix.
8.1.3 Maintenance Records. Keep a record of all testing,
maintenance, or repair
[[Page 9511]]
activities performed on any HCl or HF CEMS in a location and format
suitable for inspection. A maintenance log may be used for this
purpose. The following records should be maintained: Date, time, and
description of any testing, adjustment, repair, replacement, or
preventive maintenance action performed on any monitoring system and
records of any corrective actions associated with a monitor outage
period. Additionally, any adjustment that may significantly affect a
system's ability to accurately measure emissions data must be
recorded and a written explanation of the procedures used to make
the adjustment(s) shall be kept.
8.2 Specific Requirements for HCl and HF CEMS. The following
requirements are specific to HCl and HF CEMS:
8.2.1 Keep a written record of the procedures used for each type
of QA test required for each HCl and HF CEMS. Explain how the
results of each type of QA test are calculated and evaluated.
8.2.2 Explain how each component of the HCl and/or HF CEMS will
be adjusted to provide correct responses to calibration gases after
routine maintenance, repairs, or corrective actions.
9. Data Reduction and Calculations
9.1 Design and operate the HCl and/or HF CEMS to complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
9.2 Reduce the HCl and/or HF concentration data to hourly
averages in accordance with Sec. 60.13(h)(2) of this chapter.
9.3 Convert each hourly average HCl or HF concentration to an
HCl or HF emission rate expressed in units of the applicable
emissions limit.
9.3.1 For heat input-based emission rates, select an appropriate
emission rate equation from among Equations 19-1 through 19-9 in EPA
Method 19 in appendix A-7 to part 60 of this chapter, to calculate
the HCl or HF emission rate in lb/MMBtu. Multiply the HCl
concentration value (ppm) by 9.43 x 10-8 to convert it to
lb/scf, for use in the applicable Method 19 equation. For HF, the
conversion constant from ppm to lb/scf is 5.18 x 10-8.
9.3.2 For electrical output-based emission rates, first
calculate the HCl or HF mass emission rate (lb/h), using an equation
that has the general form of Equation A-2 or A-3 in appendix A to
this subpart (as applicable), replacing the value of K with 9.43 x
10-8 lb/scf-ppm (for HCl) or 5.18 x 10-8 (for
HF) and defining Ch as the hourly average HCl or HF
concentration in ppm. Then, use Equation A-4 in appendix A to this
subpart to calculate the HCl or HF emission rate in lb/GWh. If the
applicable HCl or HF limit is expressed in lb/MWh, divide the result
from Equation A-4 by 103.
9.4 Use Equation A-5 in appendix A of this subpart to calculate
the required 30 operating day rolling average HCl or HF emission
rates. Round off each 30 operating day average to two significant
figures. The term Eho in Equation A-5 must be in the
units of the applicable emissions limit.
10. Recordkeeping Requirements
10.1 For each HCl or HF CEMS installed at an affected source,
and for any other monitoring system(s) needed to convert pollutant
concentrations to units of the applicable emissions limit, the owner
or operator must maintain a file of all measurements, data, reports,
and other information required by this appendix in a form suitable
for inspection, for 5 years from the date of each record, in
accordance with Sec. 63.10033. The file shall contain the
information in paragraphs 10.1.1 through 10.1.8 of this section.
10.1.1 Monitoring Plan Records. For each affected unit or group
of units monitored at a common stack, the owner or operator shall
prepare and maintain a monitoring plan for the HCl and/or HF CEMS
and any other monitoring system(s) (i.e, flow rate, diluent gas, or
moisture systems) needed to convert pollutant concentrations to
units of the applicable emission standard. The monitoring plan shall
contain essential information on the continuous monitoring systems
and shall explain how the data derived from these systems ensure
that all HCl or HF emissions from the unit or stack are monitored
and reported.
10.1.1.1 Updates. Whenever the owner or operator makes a
replacement, modification, or change in a certified continuous HCl
or HF monitoring system that is used to provide data under this
subpart (including a change in the automated data acquisition and
handling system or the flue gas handling system) which affects
information reported in the monitoring plan (e.g., a change to a
serial number for a component of a monitoring system), the owner or
operator shall update the monitoring plan.
10.1.1.2 Contents of the Monitoring Plan. For HCl and/or HF
CEMS, the monitoring plan shall contain the applicable electronic
and hard copy information in sections 10.1.1.2.1 and 10.1.1.2.2 of
this appendix. For stack gas flow rate, diluent gas, and moisture
monitoring systems, the monitoring plan shall include the electronic
and hard copy information required for those systems under Sec.
75.53 (g) of this chapter. The electronic monitoring plan shall be
evaluated using the ECMPS Client Tool.
10.1.1.2.1 Electronic. Record the unit or stack ID number(s);
monitoring location(s); the HCl or HF monitoring methodology used
(i.e., CEMS); HCl or HF monitoring system information, including,
but not limited to: unique system and component ID numbers; the
make, model, and serial number of the monitoring equipment; the
sample acquisition method; formulas used to calculate emissions;
monitor span and range information (if applicable).
10.1.1.2.2 Hard Copy. Keep records of the following: schematics
and/or blueprints showing the location of the monitoring system(s)
and test ports; data flow diagrams; test protocols; monitor span and
range calculations (if applicable); miscellaneous technical
justifications.
10.1.2 Operating Parameter Records. For the purposes of this
appendix, the owner or operator shall record the following
information for each operating hour of each affected unit or group
of units utilizing a common stack, to the extent that these data are
needed to convert pollutant concentration data to the units of the
emission standard. For non-operating hours, record only the items in
paragraphs 10.1.2.1 and 10.1.2.2 of this section. If there is heat
input to the unit(s), but no electrical load, record only the items
in paragraphs 10.1.2.1, 10.1.2.2, and (if applicable) 10.1.2.4 of
this section.
10.1.2.1 The date and hour;
10.1.2.2 The unit or stack operating time (rounded up to the
nearest fraction of an hour (in equal increments that can range from
one hundredth to one quarter of an hour, at the option of the owner
or operator);
10.1.2.3 The hourly gross unit load (rounded to nearest MWge);
and
10.1.2.4 If applicable, the F-factor used to calculate the heat
input-based pollutant emission rate.
10.1.3 HCl and/or HF Emissions Records. For HCl and/or HF CEMS,
the owner or operator must record the following information for each
unit or stack operating hour:
10.1.3.1 The date and hour;
10.1.3.2 Monitoring system and component identification codes,
as provided in the electronic monitoring plan, for each hour in
which the CEMS provides a quality-assured value of HCl or HF
concentration (as applicable);
10.1.3.3 The pollutant concentration, for each hour in which a
quality-assured value is obtained. For HCl and HF, record the data
in parts per million (ppm), rounded to three significant figures.
10.1.3.4 A special code, indicating whether or not a quality-
assured HCl or HF concentration value is obtained for the hour. This
code may be entered manually when a temporary like-kind replacement
HCl or HF analyzer is used for reporting; and
10.1.3.5 Monitor data availability, as a percentage of unit or
stack operating hours, calculated according to Sec. 75.32 of this
chapter.
10.1.4 Stack Gas Volumetric Flow Rate Records.
10.1.4.1 Hourly measurements of stack gas volumetric flow rate
during unit operation are required to demonstrate compliance with
electrical output-based HCl or HF emissions limits (i.e., lb/MWh or
lb/GWh).
10.1.4.2 Use a flow rate monitor that meets the requirements of
part 75 of this chapter to record the required data. You must keep
hourly flow rate records, as specified in Sec. 75.57(c)(2) of this
chapter.
10.1.5 Records of Stack Gas Moisture Content.
10.1.5.1 Correction of hourly pollutant concentration data for
moisture is sometimes required when converting concentrations to the
units of the applicable Hg emissions limit. In particular, these
corrections are required:
10.1.5.1.1 To calculate electrical output-based pollutant
emission rates, when using a CEMS that measures pollutant
concentrations on a dry basis; and
10.1.5.1.2 To calculate heat input-based pollutant emission
rates, when using certain equations from EPA Method 19 in appendix
A-7 to part 60 of this chapter.
[[Page 9512]]
10.1.5.2 If hourly moisture corrections are required, either use
a fuel-specific default moisture percentage for coal-fired units
from Sec. 75.11(b)(1) of this chapter, an Administrator approved
default moisture value for non-coal-fired units (as per paragraph
63.10010(d) of this subpart), or a certified moisture monitoring
system that meets the requirements of part 75 of this chapter, to
record the required data. If you elect to use a moisture monitoring
system, you must keep hourly records of the stack gas moisture
content, as specified in Sec. 75.57(c)(3) of this chapter.
10.1.6 Records of Diluent Gas (CO2 or O2)
Concentration.
10.1.6.1 To assess compliance with a heat input-based HCl or HF
emission rate limit in units of lb/MMBtu, hourly measurements of
CO2 or O2 concentration are required to
convert pollutant concentrations to units of the standard.
10.1.6.2 If hourly measurements of diluent gas concentration are
needed, you must use a certified CO2 or O2
monitor that meets the requirements of part 75 of this chapter to
record the required data. For all diluent gas monitors, you must
keep hourly CO2 or O2 concentration records,
as specified in Sec. 75.57(g) of this chapter.
10.1.7 HCl and HF Emission Rate Records. For applicable HCl and
HF emission limits in units of lb/MMBtu, lb/MWh, or lb/GWh, record
the following information for each affected unit or common stack:
10.1.7.1 The date and hour;
10.1.7.2 The hourly HCl and/or HF emissions rate (lb/MMBtu, lb/
MWh, or lb/GWh, as applicable, rounded to three significant
figures), for each hour in which valid values of HCl or HF
concentration and all other required parameters (stack gas
volumetric flow rate, diluent gas concentration, electrical load,
and moisture data, as applicable) are obtained for the hour;
10.1.7.3 An identification code for the formula used to derive
the hourly HCl or HF emission rate from HCl or HF concentration,
flow rate, electrical load, diluent gas concentration, and moisture
data (as applicable); and
10.1.7.4 A code indicating that the HCl or HF emission rate was
not calculated for the hour, if valid data for HCl or HF
concentration and/or any of the other necessary parameters are not
obtained for the hour. For the purposes of this appendix, the
substitute data values required under part 75 of this chapter for
diluent gas concentration, stack gas flow rate and moisture content
are not considered to be valid data.
10.1.8 Certification and Quality Assurance Test Records. For the
HCl and/or HF CEMS used to provide data under this subpart at each
affected unit (or group of units monitored at a common stack),
record the following information for all required certification,
recertification, diagnostic, and quality-assurance tests:
10.1.8.1 HCl and HF CEMS.
10.1.8.1.1 For all required daily calibrations (including
calibration transfer standard tests) of the HCl or HF CEMS, record
the test dates and times, reference values, monitor responses, and
calculated calibration error values;
10.1.8.1.2 For gas audits of HCl or HF CEMS, record the date and
time of each spiked and unspiked sample, the audit gas reference
values and uncertainties. Keep records of all calculations and data
analyses required under sections 9.1 and 12.1 of Performance
Specification 15, and the results of those calculations and
analyses.
10.1.8.1.3 For each RATA of a HCl or HF CEMS, record the date
and time of each test run, the reference method(s) used, and the
reference method and HCl or HF CEMS values. Keep records of the data
analyses and calculations used to determine the relative accuracy.
10.1.8.2 Additional Monitoring Systems. For the stack gas flow
rate, diluent gas, and moisture monitoring systems described in
section 3.2 of this appendix, you must keep records of all
certification, recertification, diagnostic, and on-going quality-
assurance tests of these systems, as specified in Sec. 75.59(a) of
this chapter.
11. Reporting Requirements
11.1 General Reporting Provisions. The owner or operator shall
comply with the following requirements for reporting HCl and/or HF
emissions from each affected unit (or group of units monitored at a
common stack):
11.1.1 Notifications, in accordance with paragraph 11.2 of this
section;
11.1.2 Monitoring plan reporting, in accordance with paragraph
11.3 of this section;
11.1.3 Certification, recertification, and QA test submittals,
in accordance with paragraph 11.4 of this section; and
11.1.4 Electronic quarterly report submittals, in accordance
with paragraph 11.5 of this section.
11.2 Notifications. The owner or operator shall provide
notifications for each affected unit (or group of units monitored at
a common stack) in accordance with Sec. 63.10030.
11.3 Monitoring Plan Reporting. For each affected unit (or group
of units monitored at a common stack) using HCl and/or HF CEMS, the
owner or operator shall make electronic and hard copy monitoring
plan submittals as follows:
11.3.1 Submit the electronic and hard copy information in
section 10.1.1.2 of this appendix pertaining to the HCl and/or HF
monitoring systems at least 21 days prior to the applicable date in
Sec. 63.9984. Also, if applicable, submit monitoring plan
information pertaining to any required flow rate, diluent gas, and/
or moisture monitoring systems within that same time frame, if the
required records are not already in place.
11.3.2 Update the monitoring plan when required, as provided in
paragraph 10.1.1.1 of this appendix. An electronic monitoring plan
information update must be submitted either prior to or concurrent
with the quarterly report for the calendar quarter in which the
update is required.
11.3.3 All electronic monitoring plan submittals and updates
shall be made to the Administrator using the ECMPS Client Tool. Hard
copy portions of the monitoring plan shall be kept on record
according to section 10.1 of this appendix.
11.4 Certification, Recertification, and Quality-Assurance Test
Reporting Requirements. Except for daily QA tests (i.e.,
calibrations and flow monitor interference checks), which are
included in each electronic quarterly emissions report, use the
ECMPS Client Tool to submit the results of all required
certification, recertification, quality-assurance, and diagnostic
tests of the monitoring systems required under this appendix
electronically, either prior to or concurrent with the relevant
quarterly electronic emissions report.
11.4.1 For daily calibrations (including calibration transfer
standard tests), report the information in Sec. 75.59(a)(1) of this
chapter, excluding paragraphs (a)(1)(ix) through (a)(1)(xi).
11.4.2 For each quarterly gas audit of a HCl or HF CEMS, report:
11.4.2.1 Facility ID information;
11.4.2.2 Monitoring system ID number;
11.4.2.3 Type of test (e.g., quarterly gas audit);
11.4.2.4 Reason for test;
11.4.2.5 Certified audit (spike) gas concentration value (ppm);
11.4.2.6 Measured value of audit (spike) gas, including date and
time of injection;
11.4.2.7 Calculated dilution ratio for audit (spike) gas;
11.4.2.8 Date and time of each spiked flue gas sample;
11.4.2.9 Date and time of each unspiked flue gas sample;
11.4.2.10 The measured values for each spiked gas and unspiked
flue gas sample (ppm);
11.4.2.11 The mean values of the spiked and unspiked sample
concentrations and the expected value of the spiked concentration as
specified in section 12.1 of Performance Specification 15 (ppm);
11.4.2.12 Bias at the spike level as calculated using equation 3
in section 12.1 of Performance Specification 15; and
11.4.2.13 The correction factor (CF), calculated using equation
6 in section 12.1 of Performance Specification 15.
11.4.3 For each RATA of a HCl or HF CEMS, report:
11.4.3.1 Facility ID information;
11.4.3.2 Monitoring system ID number;
11.4.3.3 Type of test (i.e., initial or annual RATA);
11.4.3.4 Reason for test;
11.4.3.5 The reference method used;
11.4.3.6 Starting and ending date and time for each test run;
11.4.3.7 Units of measure;
11.4.3.8 The measured reference method and CEMS values for each
test run, on a consistent moisture basis, in appropriate units of
measure;
11.4.3.9 Flags to indicate which test runs were used in the
calculations;
11.4.3.10 Arithmetic mean of the CEMS values, of the reference
method values, and of their differences;
11.4.3.11 Standard deviation, as specified in Equation 2-4 of
Performance Specification 2 in appendix B to part 60 of this
chapter;
11.4.3.12 Confidence coefficient, as specified in Equation 2-5
of Performance Specification 2 in appendix B to part 60 of this
chapter; and
[[Page 9513]]
11.4.3.13 Relative accuracy calculated using Equation 2-6 of
Performance Specification 2 in appendix B to part 60 of this chapter
or, if applicable, according to the alternative procedure for low
emitters described in section 3.1.2.2 of this appendix. If
applicable use a flag to indicate that the alternative RA
specification for low emitters has been applied.
11.4.4 Reporting Requirements for Diluent Gas, Flow Rate, and
Moisture Monitoring Systems. For the certification, recertification,
diagnostic, and QA tests of stack gas flow rate, moisture, and
diluent gas monitoring systems that are certified and quality-
assured according to part 75 of this chapter, report the information
in section 10.1.9.3 of this appendix.
11.5 Quarterly Reports.
11.5.1 Beginning with the report for the calendar quarter in
which the initial compliance demonstration is completed or the
calendar quarter containing the applicable date in Sec.
63.10005(g), (h), or (j) (whichever is earlier), the owner or
operator of any affected unit shall use the ECMPS Client Tool to
submit electronic quarterly reports to the Administrator, in an XML
format specified by the Administrator, for each affected unit (or
group of units monitored at a common stack).
11.5.2 The electronic reports must be submitted within 30 days
following the end of each calendar quarter, except for units that
have been placed in long-term cold storage.
11.5.3 Each electronic quarterly report shall include the
following information:
11.5.3.1 The date of report generation;
11.5.3.2 Facility identification information;
11.5.3.3 The information in sections 10.1.2 through 10.1.7 of
this appendix, as applicable to the type(s) of monitoring system(s)
used to measure the pollutant concentrations and other necessary
parameters.
11.5.3.4 The results of all daily calibrations (including
calibration transfer standard tests) of the HCl or HF monitor as
described in section 10.1.8.1.1 of this appendix; and
11.5.3.5 If applicable, the results of all daily flow monitor
interference checks, in accordance with section 10.1.8.2 of this
appendix.
11.5.4 Compliance Certification. Based on reasonable inquiry of
those persons with primary responsibility for ensuring that all HCl
and/or HF emissions from the affected unit(s) have been correctly
and fully monitored, the owner or operator shall submit a compliance
certification in support of each electronic quarterly emissions
monitoring report. The compliance certification shall include a
statement by a responsible official with that official's name,
title, and signature, certifying that, to the best of his or her
knowledge, the report is true, accurate, and complete.
[FR Doc. 2012-806 Filed 2-15-12; 8:45 am]
BILLING CODE 6560-50-P
