Reconsideration of Certain New Source Issues: 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, 24073-24094 [2013-07859]
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Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations
24073
minimize litigation, eliminate
ambiguity, and reduce burden.
to the discovery of a significant
environmental impact from this rule.
8 p.m. to 11 p.m. unless cancelled
earlier by the Captain of the Port.
10. Protection of Children
We have analyzed this rule under
Executive Order 13045, Protection of
Children from Environmental Health
Risks and Safety Risks. This rule is not
an economically significant rule and
does not create an environmental risk to
health or risk to safety that may
disproportionately affect children.
List of Subjects in 33 CFR Part 165
Harbors, Marine safety, Navigation
(water), Reporting and recordkeeping
requirements, Security measures, and
Waterways.
For the reasons discussed in the
preamble, the Coast Guard amends 33
CFR part 165 as follows:
Dated: April 12, 2013.
A. Popiel,
Captain, U.S. Coast Guard, Captain of the
Sector North Carolina.
11. Indian Tribal Governments
This rule does not have tribal
implications under Executive Order
13175, Consultation and Coordination
with Indian Tribal Governments,
because it does not have a substantial
direct effect on one or more Indian
tribes, on the relationship between the
Federal Government and Indian tribes,
or on the distribution of power and
responsibilities between the Federal
Government and Indian tribes.
12. Energy Effects
This action is not a ‘‘significant
energy action’’ under Executive Order
13211, Actions Concerning Regulations
That Significantly Affect Energy Supply,
Distribution, or Use.
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13. Technical Standards
This rule does not use technical
standards. Therefore, we did not
consider the use of voluntary consensus
standards.
14. Environment
We have analyzed this rule under
Department of Homeland Security
Management Directive 023–01 and
Commandant Instruction M16475.lD,
which guide the Coast Guard in
complying with the National
Environmental Policy Act of 1969
(NEPA)(42 U.S.C. 4321–4370f), and
have determined that this action is one
of a category of actions that do not
individually or cumulatively have a
significant effect on the human
environment. This rule involves
establishing a safety zone for a fireworks
display launch site and fallout area and
is expected to have no impact on the
water or environment. This zone is
designed to protect mariners and
spectators from the hazards associated
with aerial fireworks displays. This rule
is categorically excluded from further
review under paragraph 34 (g) of Figure
2–1 of the Commandant Instruction. An
environmental analysis checklist
supporting this determination and a
Categorical Exclusion Determination are
available in the docket where indicated
under ADDRESSES. We seek any
comments or information that may lead
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PART 165—REGULATED NAVIGATION
AREAS AND LIMITED ACCESS AREAS
[FR Doc. 2013–09609 Filed 4–23–13; 8:45 am]
BILLING CODE 9110–04–P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 60 and 63
■
1. The authority citation for part 165
continues to read as follows:
[EPA–HQ–OAR–2009–0234; EPA–HQ–OAR–
2011–0044; FRL–9789–5]
Authority: 33 U.S.C. 1231; 46 U.S.C.
Chapter 701, 3306, 3703; 50 U.S.C. 191, 195;
33 CFR 1.05–1, 6.04–1, 6.04–6, 160.5; Pub. L.
107–295, 116 Stat. 2064; Department of
Homeland Security Delegation No. 0170.1.
RIN 2060–AR62
2. Add temporary § 165.T05–0259 to
read as follows:
■
§ 165.T05–0259 Safety Zone; Pasquotank
River; Elizabeth City, NC.
(a) Definitions. For the purposes of
this section, Captain of the Port means
the Commander, Sector North Carolina.
Representative means any Coast
Guard commissioned, warrant, or petty
officer who has been authorized to act
on the behalf of the Captain of the Port.
(b) Location. The following area is a
safety zone: Specified waters of the
Captain of the Port, Sector North
Carolina, as defined in 33 CFR 3.25–20,
all waters of the Pasquotank River
within a 300 yard radius of the
fireworks launch barge in approximate
position latitude 36°17′47″ N longitude
076°12′17″, located near Machelhe
Island.
(c) Regulations. (1) The general
regulations contained in § 165.23 of this
part apply to the area described in
paragraph (b) of this section.
(2) Persons or vessels requiring entry
into or passage through any portion of
the safety zone must first request
authorization from the Captain of the
Port, or a designated representative,
unless the Captain of the Port
previously announced via Marine Safety
Radio Broadcast on VHF Marine Band
Radio channel 22 (157.1 MHz) that this
regulation will not be enforced in that
portion of the safety zone. The Captain
of the Port can be contacted at telephone
number (910) 343–3882 or by radio on
VHF Marine Band Radio, channels 13
and 16.
(d) Enforcement. The U.S. Coast
Guard may be assisted in the patrol and
enforcement of the zone by Federal,
State, and local agencies.
(e) Enforcement period. This section
will be enforced on May 18, 2013 from
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Reconsideration of Certain New
Source Issues: 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-CommercialInstitutional, and Small IndustrialCommercial-Institutional Steam
Generating Units
Environmental Protection
Agency (EPA).
ACTION: Final rule; notice of final action
on reconsideration.
AGENCY:
The EPA is taking final action
on its reconsideration of certain issues
in the final rules titled, ‘‘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-CommercialInstitutional Steam Generating Units.’’
The National Emission Standards for
Hazardous Air Pollutants (NESHAP)
rule issued pursuant to Clean Air Act
(CAA) section 112 is referred to as the
Mercury and Air Toxics Standards
(MATS) NESHAP, and the New Source
Performance Standards rule issued
pursuant to CAA section 111 is referred
to as the Utility NSPS. The
Administrator received petitions for
reconsideration of certain aspects of the
MATS NESHAP and the Utility NSPS.
On November 30, 2012, the EPA
granted reconsideration of, proposed,
and requested comment on a limited set
of issues. We also proposed certain
technical corrections to both the MATS
NESHAP and the Utility NSPS. The EPA
is now taking final action on the revised
new source numerical standards in the
MATS NESHAP and the definitional
and monitoring provisions in the Utility
NSPS that were addressed in the
SUMMARY:
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Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations
proposed reconsideration rule. As part
of this action, the EPA is also making
certain technical corrections to both the
MATS NESHAP and the Utility NSPS.
The EPA is not taking final action on
requirements applicable during periods
of startup and shutdown in the MATS
NESHAP or on startup and shutdown
provisions related to the PM standard in
the Utility NSPS.
The effective date of the rule is
April 24, 2013.
Docket. The EPA established two
dockets for this action: Docket ID EPA–
HQ–OAR–2011–0044 (NSPS action) and
Docket ID EPA–HQ–OAR–2009–0234
(MATS NESHAP action). All documents
in the dockets are listed in the https://
www.regulations.gov index. Although
listed in the index, some information is
not publicly available (e.g., confidential
business information (CBI) or other
information whose disclosure is
restricted by statute). Certain other
material, such as copyrighted material,
will be publicly available only in hard
copy form. Publicly available docket
materials are available either
electronically in https://
www.regulations.gov or in hard copy at
the EPA Docket Center, Room 3334,
1301 Constitution Avenue NW.,
Washington, DC. The Public Reading
Room 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)
DATES:
566–1744, and the telephone number for
the Air Docket is (202) 566–1742.
FOR FURTHER INFORMATION CONTACT: For
the MATS 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:
Outline. The information presented in
this preamble is organized as follows:
I. General Information
A. Does this action apply to me?
B. How do I obtain a copy of this
document?
C. Judicial Review
II. Background
III. Summary of Today’s Action
IV. Summary of Final Action and Changes
Since Proposal—MATS NESHAP New
Source Issues
V. Summary of Final Action and Changes
Since Proposal—Utility NSPS
NAICS code1
Category
Industry .....................................................
Federal government ..................................
2 221122
221112
State/local/Tribal government ...................
2 221122
921150
1 North
VI. Technical Corrections and Clarifications
VII. Impacts of This Final Rule
A. Summary of Emissions Impacts, Costs
and Benefits
B. What are the air impacts?
C. What are the energy impacts?
D. What are the compliance costs?
E. What are the economic and employment
impacts?
F. What are the benefits of the final
standards?
VIII. 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
D. Unfunded Mandates Reform Act
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 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?
Categories and entities potentially
affected by today’s action include:
Examples of potentially regulated entities
Fossil fuel-fired
Fossil fuel-fired
ment.
Fossil fuel-fired
Fossil fuel-fired
electric utility steam generating units.
electric utility steam generating units owned by the Federal governelectric utility steam generating units owned by municipalities.
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.
tkelley on DSK3SPTVN1PROD with RULES
2 Federal,
This table is not intended to be
exhaustive but rather to provide a guide
for readers regarding entities likely to be
affected by this action. To determine
whether your facility, company,
business, organization, etc. would 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 63.9982. 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. How do I obtain a copy of this
document?
In addition to being available in the
docket, electronic copies of these final
rules will be available on the
Worldwide Web (WWW) through the
Technology Transfer Network (TTN).
Following signature, 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.
available only by filing a petition for
review in the U.S. Court of Appeals for
the District of Columbia Circuit by June
24, 2013. 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 can be raised during
judicial review. 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 the
EPA to enforce these requirements.
C. Judicial Review
Under the CAA section 307(b)(1),
judicial review of this final rule is
The final MATS NESHAP and the
Utility NSPS rules were published in
the Federal Register at 77 FR 9304 on
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II. Background
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February 16, 2012. Following
promulgation of the final rules, the
Administrator received petitions for
reconsideration of numerous provisions
of both the MATS NESHAP and the
Utility NSPS pursuant to CAA section
307(d)(7)(B). Copies of the MATS
NESHAP petitions are provided in
rulemaking docket EPA–HQ–OAR–
2009–0234. Copies of the Utility NSPS
petitions are provided in rulemaking
docket EPA–HQ–OAR–2011–0044. On
November 30, 2012, the proposal
granting reconsideration of certain
issues in the MATS NESHAP and
Utility NSPS was published in the
Federal Register at 77 FR 71323.
III. Summary of Today’s Action
This final action amends certain
provisions of the final rule issued by the
EPA on February 16, 2012. Through an
August 2, 2012, notice (77 FR 45967),
the EPA delayed the effective date of the
February 2012 MATS rule for new
sources only. That stay was limited to
90 days and has since expired. The
February 2012 final rule is and remains
in effect for all sources.
The November 30, 2012, proposed
reconsideration rule proposed: (1)
Certain revised new source numerical
standards in the MATS NESHAP, (2)
requirements applicable during periods
of startup and shutdown in the MATS
NESHAP, (3) startup and shutdown
provisions related to the particulate
matter (PM) standard in the Utility
NSPS, and (4) definitional and
monitoring provisions in the Utility
NSPS. We also proposed certain
technical corrections to both the MATS
NESHAP and the Utility NSPS. We are
taking final action today on the revised
numerical new source MATS NESHAP
limits, the definitional and monitoring
issues in the Utility NSPS, and all of the
technical corrections not related to
startup/shutdown issues.
This summary of the final rule reflects
the changes to 40 CFR Part 63, subpart
UUUUU, and 40 CFR Part 60, subpart
Da (77 FR 9304; February 16, 2012)
made in this regard.
As noted above, in the proposed
reconsideration rule, the EPA took
comment on the requirements in the
MATS NESHAP applicable during
startup and shutdown, including the
definitions of startup and shutdown.
The EPA also took comment on the
startup and shutdown provisions
relating to the PM standard in the
Utility NSPS. The EPA received
considerable comments regarding these
startup and shutdown provisions,
including data and information relevant
to the proposed work practice standard
that applies in such periods. The EPA
is not taking final action on the startup
and shutdown provisions at this time as
it needs additional time to consider and
evaluate the comments and data
provided.1 The Agency is currently
reviewing all of the comments received
on the startup and shutdown issues and
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intends to act promptly to address these
issues. We note that no existing sources
will have to comply with the existing
source MATS standards before April 16,
2015. Further, no new sources are
currently under construction and it
takes years to complete construction. 77
FR 71330, fn. 7. As such, there will be
sufficient time for the Agency to review
the comments submitted concerning the
proposed startup and shutdown
provisions and take appropriate action
well in advance of any new source being
subject to those provisions.
As described below, on the basis of
information provided since the
reconsideration proposal, today’s action
revises certain new source numerical
limits in the MATS NESHAP.
Specifically, the EPA is finalizing
revised hydrogen chloride (HCl),
filterable PM (fPM),2 sulfur dioxide
(SO2), lead (Pb), and selenium emission
limits for all new coal-fired EGUs; the
mercury (Hg) emission limit for the
‘‘unit designed for coal ≥ 8,300 Btu/lb
subcategory;’’ fPM and SO2 emission
limits for new solid oil-derived fuelfired EGUs; fPM emission limits for new
continental liquid oil-fired EGUs; and
most of the emission limits for new
integrated gasification combined cycle
(IGCC) units.
The fPM, HCl, and Hg limits that we
are finalizing in this action are provided
in table 1; the alternate limits that we
are finalizing are provided in table 2.3
TABLE 1—REVISED EMISSION LIMITATIONS FOR NEW EGUS
Filterable
particulate
matter,
lb/MWh
Subcategory
New—Unit not designed for low rank virgin coal ...............................................................
New—Unit designed for low rank virgin coal .....................................................................
New—IGCC ........................................................................................................................
New—Solid oil-derived .......................................................................................................
New—Liquid oil—continental ..............................................................................................
Hydrogen
chloride,
lb/MWh
9.0E–2 ..............
9.0E–2 ..............
7.0E–2 b ............
9.0E–2 c ............
3.0E–2 ..............
3.0E–1 ..............
1.0E–2 a ............
1.0E–2 a ............
2.0E–3 ..............
3.0E–3.
NR.
3.0E–3.
NR ....................
NR ....................
NR.
NR.
Mercury, lb/GWh
Note: lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012).
a Beyond-the-floor value.
b Duct burners on syngas; based on permit levels in comments received.
c Duct burners on natural gas; based on permit levels in comments received.
TABLE 2—REVISED ALTERNATE EMISSION LIMITATIONS FOR NEW EGUS
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Subcategory/pollutant
SO2 .....................................................................................................................................
Total non-mercury metals ...................................................................................................
Antimony, Sb ......................................................................................................................
Arsenic, As ..........................................................................................................................
1.0 lb/MWh .......
NR ....................
NR ....................
NR ....................
IGCC a
Coal-fired EGUs
1 The EPA is also still reviewing the other issues
raised in the petitions for reconsideration and is not
taking any action at this time with respect to those
issues.
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2 As the final MATS rule established a filterable
PM (fPM) limit, every reference in this preamble to
a PM limit means filterable PM.
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4.0E–1
4.0E–1
2.0E–2
2.0E–2
lb/MWh b
lb/GWh
lb/GWh
lb/GWh
Solid oil-derived
1.0 lb/MWh
NR
NR
NR
3 The final rule included certain alternative limits
(see 77 FR 9367–9369).
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TABLE 2—REVISED ALTERNATE EMISSION LIMITATIONS FOR NEW EGUS—Continued
Subcategory/pollutant
Coal-fired EGUs
IGCC a
Beryllium, Be .......................................................................................................................
Cadmium, Cd ......................................................................................................................
Chromium, Cr .....................................................................................................................
Cobalt, Co ...........................................................................................................................
Lead, Pb .............................................................................................................................
Mercury, Hg ........................................................................................................................
Manganese, Mn ..................................................................................................................
Nickel, Ni .............................................................................................................................
Selenium, Se ......................................................................................................................
NR ....................
NR ....................
NR ....................
NR ....................
2.0E–2 lb/GWh
NA .....................
NR ....................
NR ....................
5.0E–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
7.0E–2 lb/GWh
3.0E–1 lb/GWh
Solid oil-derived
NR
NR
NR
NR
NR
NR
NR
NR
NR
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NA = not applicable.
NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012).
a Based on best-performing similar source.
b Based on DOE information.
In addition, in the MATS NESHAP
the EPA is removing quarterly stack
testing as an option to demonstrate
compliance with the new source fPM
emission limits; revising the way in
which an owner or operator of a new
EGU who chooses to use PM continuous
parameter monitoring systems (CPMS)
establishes an operating limit; requiring
inspections and retesting within 45 days
of an exceedance of the operating limit
for those new EGU owners or operators
who choose to use PM CPMS as a
compliance option; and finalizing the
presumption of violation of the
emissions limit if more than 4 emissions
tests are required in a 12-month period.
The final changes to the numerical
emissions limits noted above
incorporate information about the
variability of the best performing EGUs
and more accurately reflect the
capabilities of emission control
equipment for new EGUs. The final
changes should also address
commenters’ concerns that vendors of
EGU emission controls had been
unwilling to provide guarantees
regarding the ability to meet all of the
standards for new EGUs as originally
finalized in February 2012.
We expect that source owners and
operators will install and operate the
same or similar control technologies to
meet the revised standards in this
reconsideration action as they would
have chosen to comply with the
standards in the February 2012 final
rule. Consistent with CAA section
112(a)(4), we are maintaining the new
source trigger date for the MATS
NESHAP rule as May 3, 2011. See 77 FR
71330, fn. 7. New sources must comply
with the revised MATS emission
standards described in section IV below
by April 24, 2013, or startup, whichever
is later.
In the February 2012 final Utility
NSPS rule, the EPA adopted a definition
of natural gas that excludes coal-derived
synthetic natural gas consistent with the
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definition in MATS. In the Utility NSPS
reconsideration proposal, we reproposed and requested comment on
that definition. Based on review of the
comments received in response to the
reconsideration proposal, the EPA has
concluded that the definition of natural
gas in the final Utility NSPS is
appropriate and, therefore, is not
making any changes to that definition.
We are also finalizing as proposed one
conforming amendment and two
amendments related to EGUs burning
desulfurized coal-derived synthetic
natural gas. First, we amended the
definition of coal to make it clear that
coal-derived synthetic natural gas is
considered to be coal. In addition, in
recognition of the fact that emissions
from the burning of desulfurized coalderived synthetic natural gas are very
similar to those from the burning of
natural gas, we amended the opacity
and SO2 monitoring provisions so that
facilities burning desulfurized coalderived synthetic natural gas will have
opacity and SO2 monitoring
requirements similar to those of
facilities burning natural gas. Further,
we are finalizing certain revisions to the
definition of IGCC in the Utility NSPS.
We are also finalizing as proposed the
revised procedures for calculating PM
emission rates intended to make the
Utility NSPS procedures consistent with
those in the MATS NESHAP. We did
not receive any adverse comments
regarding this proposed change. Finally,
we are finalizing as proposed the
technical corrections to the PM
standards for facilities that commenced
construction before March 1, 2005, and
for facilities that commence
modification after May 3, 2011.
The impacts of today’s revisions on
the costs and the benefits of the final
rule are minor. As noted above, we
expect that source owners and operators
will install and operate the same or
similar control technologies to meet the
revised standards in this action as they
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would have chosen to comply with the
standards in the February 2012 final
rule.
IV. Summary of Final Action and
Changes Since Proposal—MATS
NESHAP New Source Issues
After consideration of the public
comments received, the EPA has made
certain changes in this final action from
the reconsideration proposal. We
address the most significant comments
in this preamble. However for a
complete summary of the comments
received on the issues we are finalizing
today and our responses thereto, please
refer to the memorandum ‘‘National
Emission Standards For Hazardous Air
Pollutants From Coal- And Oil-Fired
Electric Utility Steam Generating
Units—Reconsideration; Summary Of
Public Comments And Responses’’
(March 2013) in rulemaking docket
EPA–HQ–OAR–2009–0234.
In this action, we are finalizing
certain new source emission limits for
the MATS NESHAP, as discussed
below.
1. Changes to Certain New Source
MATS NESHAP Limits
Commenters noted that in two
instances, Pb emissions from coal-fired
EGUs and the fPM emissions from
continental liquid oil-fired EGUs, the
EPA had proposed new source emission
limits that were less stringent than those
in the final MATS NESHAP for the
respective existing sources. This
approach was inconsistent with that
taken in the final MATS NESHAP.4
Although CAA section 112(d)(3) allows
existing source MACT floor limits to be
less stringent than new source limits,
the EPA interprets this provision as
4 See ‘‘National Emission Standards for
Hazardous Air Pollutants (NESHAP) Maximum
Achievable Control Technology (MACT) Floor
Analysis for Coal- and Oil-fired Electric Utility
Steam Generating Units for Final Rule,’’ Docket ID
EPA–HQ–OAR–2009–0234–20132, p. 13.
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precluding new source limits from being
less stringent than existing source
limits. See CAA section 112(d)(3). Thus,
for Pb emissions from coal-fired EGUs
and fPM emissions from continental
liquid oil-fired EGUs, the EPA is
finalizing new source limits that are
equivalent to the final existing-source
limits.
Next, commenters noted that when
evaluating SO2 emissions data from
coal-fired EGUs, the EPA had not
selected the lowest emitting source
upon which to base the emission limit
and that its rationale for excluding
certain data was unlawful and arbitrary.
Although the EPA disagrees with
commenters on several of the excluded
data sets (i.e., some of the data sets
suggested by commenters comprised
only a single 3-run average for each EGU
with no individual run data, making
assessment of variability impossible), it
agrees that it inadvertently omitted the
data from Stanton Unit 10 in the
proposal analyses. Stanton Unit 10 does
have a lower ‘‘lowest’’ 3-run data
average than does the EGU selected for
the new source floor analysis (Sandow
Unit 5A) in the proposed
reconsideration rule.
In this final action, the EPA used the
Stanton data to calculate the MACT
floor using the same statistical analyses
used in the proposed rule (i.e., 99
percent upper predictive limit (UPL)),
and the resulting MACT floor emission
limit is 1.3 pounds per megawatt-hour
(lb/MWh). Because this limit is less
stringent than the new source
performance standard (NSPS) finalized
in the Utility NSPS (77 FR 9451;
February 16, 2012), the EPA is finalizing
a beyond-the-floor (BTF) MACT
standard of 1.0 lb/MWh, which is the
same level required by the CAA section
111 NSPS for these same sources.5 See
40 CFR 60.43Da(l)(1)(i). Cost is a
required consideration in establishing
CAA section 111 rules and in going BTF
in establishing CAA section 112 rules.
We evaluated cost in assessing whether
to go BTF for this standard and
concluded that it was appropriate to go
BTF to a level of 1.0 lb/MWh. Moreover,
the NSPS limit (also 1.0 lb/MWh) is in
place and coal-fired EGUs are required
to comply with that limit. As such, there
is no additional cost to these sources.6
Furthermore, we have not identified any
5 The CAA section 111 standard is based on the
performance of EGUs with the best performing SO2
controls, a reasonable incremental cost effectiveness
of less than $1,000 per ton of SO2 controlled, and
controls that result in minimal secondary
environmental and energy impacts.
6 The final Utility NSPS limit was not challenged
and coal-fired EGUs constructed after May 3, 2011,
must meet that limit.
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non-air quality health or environmental
impacts or energy requirements
associated with the final standard set at
this level. In addition, in support of the
proposed reconsideration rule, we
evaluated an emissions level more
stringent than 1.0 lb/MWh and found
that level to not be cost effective.7 For
these reasons, we are finalizing 1.0 lb/
MWh as the new source MATS
NESHAP limit.
In the proposed reconsideration rule,
we indicated that detection level issues
may arise from using a sorbent trap
when short sampling periods (e.g., 30
minutes) are used. As such, the EPA
solicited comment on its establishment
of a Representative Detection Level
(RDL) associated with Hg sorbent traps.
The EPA also solicited comment on
whether the UPL calculated floor should
be compared against the 3XRDL value
for Hg to account for the shorter
sampling periods (the 3XRDL
approach). The EPA received several
comments, ranging from strong support
for the Hg RDL and the proposed
emission limit because, at that level, the
commenters asserted that vendors
would be able to provide commercial
guarantees, to concerns about the
specific inputs to the 3XRDL calculation
and the application of the 3xRDL
approach. See section 2.2.1 of the
response to comments document (RTC)
for a more complete discussion and
response to these comments.
In the proposed reconsideration rule,
the EPA recognized that 30 minutes of
sample collection is the shortest
reasonable amount of time available for
collecting and changing sorbent tubes to
provide the quick, reliable feedback that
will allow sources to react to changing
Hg emissions levels and assure
compliance with the final Hg limit.
Some commenters pointed out that the
EPA’s memorandum entitled
‘‘Determination of Representative
Detection Level (RDL) and 3 X RDL
Values for Mercury Measured Using
Sorbent Trap Technologies,’’ 8 contains
a 30-minute sample collection time in
the 3XRDL calculation, but the text of
the memorandum references a 207 See Docket ID EPA–HQ–OAR–2009–0234–
20221 and National Emission Standards for
Hazardous Air Pollutants (NESHAP) Beyond the
Maximum Achievable Control Technology (MACT)
Floor (‘Beyond-the-Floor’) Analysis for Revised
Emission Standards for New Source Coal-and Oilfired Electric Utility Steam Generating Units also in
the rulemaking docket.
8 The EPA developed the memorandum to
determine appropriate RDL and 3XRDL values for
sorbent trap monitoring systems, as well as
calculate an emissions limit, in order to determine
the shortest, reasonable sample collection period for
those systems. See EPA Docket ID EPA–HQ–OAR–
2009–0234–20222.
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24077
minute sample collection time. The EPA
has revised the text of the memorandum
to reflect its original intent, which was
to focus on a sample collection period
of 30 minutes (not 20 minutes). The
revised memorandum focuses on the 30minute sample collection period. Given
that it takes 5 minutes for sorbent trap
insertion and removal, it would take a
total of 40 minutes to secure the
requisite sample collection (30 minutes
for sample collection, 5 minutes to
remove the sorbent trap, and 5 minutes
to re-insert the trap). We are finalizing
the Hg limit using the 3XRDL approach
assuming a 30-minute sampling time.
2. Filterable PM Testing, Monitoring,
and Compliance
Certification for New EGUs in the
MATS NESHAP Rule
Several monitoring options for the
fPM standard for new sources were
provided in the MATS NESHAP final
rule, including quarterly stack testing,
PM CEMS, and PM CPMS with annual
testing.
The EPA sought comment on whether
to retain the quarterly stack testing
compliance option for new EGUs, given
that continuous, direct measurement of
fPM or a correlated parameter is
available, is preferable for determining
compliance on a continuous basis, and
is likely to be used by most new EGUs
to monitor compliance with the
proposed new source standards. As
mentioned above, this final action does
not retain the quarterly fPM
performance testing option for new
EGUs. New EGUs can be designed to
incorporate PM CEMS or PM CPMS
from the outset, without being impeded
by retrofit location installation
constraints that could impact existing
EGUs. This final action now requires
new sources to use either PM CEMS or
PM CPMS as options for determining
compliance with the new source fPM
limits.
The EPA requested comment on a
number of issues associated with PM
CPMS. The EPA first solicited comment
on three approaches to establish an
operating limit based on emissions
testing for those EGU owners or
operators who choose to use PM CPMS
as the means of demonstrating
compliance with the fPM emission
limit. The first approach would require
an EGU owner or operator to use the
highest parameter value obtained during
any run of an individual emissions test
as the operating limit when the result of
that individual test was below the limit.
The second approach would require an
EGU owner or operator to use the
average parameter value obtained from
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all runs of an individual emissions test
as the operating limit, provided that the
result of the individual emissions test
met the emissions limit. The third
approach, which the EPA is finalizing in
this final action, would require an EGU
owner or operator to use the higher of
the following: (1) A parameter scaled
from all values obtained during an
individual emissions test to 75 percent
of the emissions limit or (2) the average
parameter value obtained from all runs
of an individual emissions test as the
operating limit provided that the result
of the individual emissions test met the
emissions limit. As established and
reaffirmed in the recent Sewage Sludge
Incineration, Major Source Industrial
Boiler, and Portland Cement rules,9 it is
appropriate to provide increased
operational flexibility and reduced
emissions testing for sources that emit at
or below 75 percent of a standard—
whether an emissions or operating
limit—as these are the lowest emitting
sources. Reduced emissions testing is
available in this final rule for those
owners or operators whose EGU
emissions do not exceed this 75 percent
threshold. This 75 percent threshold
allows for compliance flexibility and is
simultaneously protective of the
emission standards. The EPA believes
well performing EGUs, i.e., those whose
emissions do not exceed 75 percent of
the emissions limit, should not face
additional scrutiny or testing
consequences provided their emissions
remain equivalent to or below the 75
percent threshold. In this final action,
the EPA uses the 75 percent threshold
so as not to impose unintended and
costly retest requirements for the lowest
emitting sources and to provide for
more cost effective, continuous, PM
parametric monitoring across the EGU
sector. This approach was selected from
the options considered as it provides the
greatest amount of EGU owner or
operator flexibility while demonstrating
continuous compliance for EGUs. With
this parametric monitoring approach in
place, the EPA expects EGUs to evaluate
control options that provide excellent
fPM emissions control and provide
them greater operational flexibility.
Moreover, after each exceedance of
the operating limit, the EPA proposed to
9 See Standards of Performance for New
Stationary Sources and Emission Guidelines for
Existing Sources: Commercial and Industrial Solid
Waste Incineration Units, 76 FR 15736 (March 21,
2011); Subpart DDDDD—National Emission
Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional
Boilers and Process Heaters, 40 CFR 63.7515(b); and
National Emission Standards for Hazardous Air
Pollutants for the Portland Cement Manufacturing
Industry and Standards of Performance for Portland
Cement Plants, 78 FR 10014 (February 12, 2013).
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require emissions testing to verify or readjust the operating limit, consistent
with the approach contained in the
recently-promulgated Portland cement
MACT standard (see 78 FR 10014). One
commenter objected to potential
frequent emissions testing to reassess
the operating limit and then being
subject to a violation of the emissions
limit. The EPA does not believe that toofrequent testing will be required. As
discussed in section 4.3.5 of the RTC,
the EPA believes well-designed
emissions testing will provide an
operating limit corresponding with EGU
operation, and such testing should yield
an operating limit that would not be
expected to be exceeded during the
course of EGU operation. Therefore, an
operating limit developed from welldesigned emissions testing should have
little, if any, need for frequent
reassessment via emissions testing more
frequently than the mandated annual
reassessment because the source will be
able to meet the limit on an ongoing
basis.
Finally, the EPA proposed that PM
CPMS exceedances leading to more than
4 required emissions tests in a 12-month
period (rolling monthly) would be
presumed (subject to the possibility of
rebuttal by the EGU owner or operator)
to be a violation of the emissions limit,
consistent with the approach contained
in the newly-promulgated Portland
cement MACT standard (see 78 FR
10014). The EPA received a number of
comments on this proposed provision,
including comments supporting and
opposing the establishment of such a
presumption.
The EPA disagrees with those
comments opposing the presumptive
violation, and believes the presumptive
violation provision in the final rule is a
reasonable and appropriate approach to
ensure compliance with the standard.
First, the EPA may permissibly establish
such an approach by rule, assuming
there is a reasonable factual basis to do
so. See Hazardous Waste Treatment
Council v. EPA, 886 F. 2d 355, 367–68
(DC Cir. 1989) (explaining that such
presumptions can legitimately establish
the elements of the EPA’s prima facie
case in an enforcement action). Second,
there is a reasonable basis here for the
presumption that four exceedances (i.e.,
increases over the parametric operating
limit) in a calendar year are a violation
of the emission standard. The
parametric monitoring limit is
established as a 30-day average of the
averaged test value in the performance
test, or the 75th percentile value if that
is higher. In either instance, the 30-day
averaging feature provides significant
leeway to the EGU owner or operator
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not to deviate from the parametric
operating level because the impact of
transient peaks or valleys is limited due
to the length of the rule’s averaging
period—30 boiler operating days, rolled
daily. See 77 FR 42377/2 and sources
there cited. See also 78 FR 10015,
10019; February, 12, 2013 (Portland
Cement MACT) and the RTC for today’s
action.
The EPA also received comments
addressing the re-testing requirements
following an exceedance. Some
commenters expressed concern about
the burden of requiring sources to
conduct performance tests in order to
demonstrate compliance and to reassess
the parameter level. In contrast, other
commenters supported a requirement to
require re-testing but claimed that the
time period between observing a
parameter exceedance and retesting is
too long. The EPA believes that the retesting requirements are reasonable and
appropriate to identify non-compliance
without imposing undue burden. For
even a single exceedance to occur, the
30-day average would have to be higher
than the operating limit established for
the PM CPMS during normal EGU
operation. If that occurs, then the EGU
owner or operator is required to conduct
an inspection to determine any
abnormalities and an emissions test to
re-establish or generate a new operating
limit. Given that EGUs and their
emissions control devices are designed
to operate at known, specific conditions,
deviations from these conditions are not
expected and are indicative of problems
with load, controls, or some
combination of both. Where these sorts
of problems result in an exceedance of
the source’s operating limit, it is
reasonable to require re-testing in order
to identify and then correct problems.
More than four such exceedances of the
30-day average would mean that the
EGU owner or operator was unable to
determine or correct the problem, since
inspection and re-calculation of the
operating limit is required after each
exceedance. This indicates an ongoing
problem with maintaining process
control and/or control device operation,
which would be the basis for a
presumptive violation of the emissions
standard. Moreover, the EPA disagrees
that the period between exceedance of
the operating limit and retesting is too
long and could result in possible
excessive emissions. Specifically, some
commenters claimed that the final rule
should not limit the number of
exceedances of the PM CPMS limit that
require follow-up performance tests in
any 12-month period. These
commenters alleged that to do so does
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not ensure continuous compliance
because the time period between an
exceedance and testing could be too
long, and a source could be exceeding
the emission limit during that time
period. The EPA believes that the retesting requirements reflect a reasonable
balance between ensuring compliance
and limiting unnecessary testing burden
on regulated sources. An EGU owner or
operator is required to visually inspect
the air pollution control device within
48 hours of the exceedance, and
corrective action must be taken as soon
as possible to return the PM CPMS
measurement to within the established
value. A performance test is also
required within 45 days of the
exceedance to determine compliance
and verify or re-establish the PM CPMS
limit. Thus, the EPA finds it unlikely
that there will be long periods of
noncompliance with the underlying
fPM standard given the inspection and
performance testing requirements.
The EPA also received comments
stating that an EGU owner or operator
should not be labeled a ‘‘violator’’ of the
fPM standard as a result of a fourth
compliance test in a 12-month period.
First, the EPA notes that the rule
identifies more than 4 compliance tests
over a 12-month period as only a
presumptive violation of the emissions
limit. A presumption of a violation is
just that—a presumption—and can be
rebutted in any particular case.
Moreover, in determining whether the
presumption has been successfully
rebutted, a Court may consider relevant
information such as data or other
information showing that the EGU’s
operating process remained in control
during the period of operating
parameter exceedance, that the ongoing
operation and maintenance conducted
on the EGU ensured its emissions
control devices remained in proper
operating condition during the period of
operating parameter exceedance, and
that results of emissions tests conducted
while replicating the conditions
observed during the period of operating
parameter exceedance remained below
the emission limit.
For the reasons explained above, this
final action includes the presumption of
violation of the emissions limit if more
than 4 emissions tests are required in a
12-month period.
V. Summary of Final Action and
Changes Since Proposal—Utility NSPS
The EPA has made a number of
changes from the reconsideration
proposal in this final action after
consideration of the public comments
received. Most of the changes to the
Utility NSPS clarify applicability and
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implementation issues raised by the
commenters. The public comments
received on the matters proposed for
reconsideration and the responses to
them can be viewed in the
memorandum ‘‘Summary of EGU NSPS
Public Comments and Responses on
Amendments Proposed November 30,
2012 (77 FR 71323)’’ in rulemaking
docket EPA–HQ–OAR–2011–0044.
In the proposed reconsideration rule,
the EPA proposed a new definition for
IGCC which would be consistent with
the MATS NESHAP definition.
However, as an alternative we requested
comment on whether to retain a
definition similar, but not identical, to
the IGCC definition in the February
2012 final Utility NSPS. We have
concluded that the alternative approach
is most appropriate and are adopting a
slightly revised definition that is
consistent with the Agency’s statements
on IGCC contained in the RTC in
support of the final Utility NSPS rule
published on February 16, 2012 (77 FR
9304). Commenters generally supported
amending the final Utility NSPS
definition of IGCC, and this final action
amends that definition consistent with
the statements made in the RTC for the
Utility NSPS. The Utility NSPS IGCC
definition deals with the intent of an
IGCC facility and is, thus, broader than
the definition in the MATS NESHAP.
The facility would still be subject to the
same criteria pollutant emission
standards even when burning natural
gas for extended periods of time. The
MATS NESHAP applicability is
determined based on the EGU’s
utilization of coal and oil and the rule
may not apply depending on the extent
of natural gas usage.
The EPA proposed that the NSPS PM
monitoring procedures be consistent
with the MATS NESHAP requirements
and included the use of quarterly stack
testing, PM CPMS, or PM CEMS. In
addition, the EPA sought comment on
whether to include the quarterly stack
testing compliance option for new
EGUs, given that continuous, direct
measurement of PM or a correlated
parameter is available. EGUs complying
with an output-based emissions
standard can be designed to incorporate
PM CEMS or PM CPMS from the outset,
without being impeded by retrofit
location installation constraints that
would impact existing EGUs. This final
action requires EGUs complying with an
output-based standard to use either PM
CEMS or PM CPMS as options for
determining compliance with the PM
limits. Therefore, the EPA is finalizing
the same monitoring procedures for PM
for the Utility NSPS as for new sources
subject to the MATS NESHAP, and is
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24079
not finalizing the quarterly stack testing
option.
The EPA proposed that facilities using
PM CPMS would be able to use either
a continuous opacity monitoring system
or a periodic alternate monitoring
approach to monitor opacity. This final
action does not require facilities using a
PM CPMS to conduct opacity
monitoring. The EPA has concluded
that the use of a PM CPMS at the level
of the emissions standard required in
subpart Da is sufficient to demonstrate
compliance with the opacity standard
and that additional monitoring is an
unnecessary burden.
VI. Technical Corrections and
Clarifications
On April 19, 2012 (77 FR 23399), the
EPA issued a technical corrections
notice addressing certain corrections to
the February 16, 2012 (77 FR 9304),
MATS NESHAP and Utility NSPS. In
the November 30, 2012, reconsideration
proposal, we proposed several
additional technical corrections.
Specific to the NSPS, we proposed
correcting the PM standard for facilities
that commenced construction before
March 1, 2005, to remove the extra
significant digit that was inadvertently
added and to correct the PM standard
for facilities that commence
modification after May 3, 2011, to be
consistent with the original intent as
expressed in the RTC of the final rule
published on February 16, 2012 (77 FR
9304). We did not receive any negative
comments on these issues and are
finalizing them as proposed. Specific
details are included in Table 3.
Specific to the MATS NESHAP, the
EPA requested comment on whether the
proposed technical corrections in Table
4 of the preamble provide the intended
accuracy, clarity, and consistency. As
mentioned in section 6.3 of the RTC,
commenters supported the proposed
changes on equations 2a and 3a and this
final action contains those changes. As
mentioned in section 6.3 of the RTC,
commenters did not support the change
from a 30 to 60-day notification period
for performance testing, and that change
was not made to the rule; however, a
change to the General Provisions
applicability table was made to provide
a consistent 30-day notification period.
Commenters suggested changes to
certain definitions to make them more
consistent with the Acid Rain rule
provisions, but, as described in section
6.4 of the RTC, these rule changes were
not made. These amendments are now
being finalized to correct inaccuracies
and other inadvertent errors in the final
rule and to make the rule language
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consistent with provisions addressed
through this reconsideration.
The final technical changes are
described in tables 3 and 4 of this
preamble.
TABLE 3—MISCELLANEOUS TECHNICAL CORRECTIONS TO 40 CFR PART 60, SUBPART DA
Section of subpart Da
Description of correction
40 CFR 60.42Da(a) ........................
40 CFR 60.42Da(e)(1)(ii) ................
Correct the erroneous ‘‘0.030’’ to the correct ‘‘0.03’’.
Correct the erroneous conversion ‘‘13 ng/J (0.015 lb/MMBtu)’’ to the correct ‘‘6.4 ng/J (0.015 lb/MMBtu)’’
by amending the regulatory text to specify that the requirements in 40 CFR 60.42Da(c) or (d), which includes two additional alternative limits, are available compliance alternatives for modified facilities.
TABLE 4—MISCELLANEOUS TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART UUUUU
Section of subpart UUUUU
Description of correction
40 CFR 63.9982(a) .........................
40 CFR 63.9982(b) and (c) ............
40 CFR 63.10005(d)(2)(ii) ...............
40 CFR 63.10005(i)(4)(ii) and (i)(5)
and add 63.10005(i)(6).
40 CFR 63.10006(c) .......................
40 CFR 63.10007(c) .......................
40
40
40
40
CFR
CFR
CFR
CFR
63.10009(b)(2) ...................
63.10009(b)(3) ...................
63.10010(j)(1)(i) .................
63.10030(b), (c), and (d) ...
40 CFR Section 63.10042 ..............
Table 5 to Subpart UUUUU of Part
63.
Table 7 to Subpart UUUUU of Part
63.
Table 9 to Subpart UUUUU of Part
63.
Section 4.1 to Appendix A to Subpart UUUUU of Part 63.
Section 5.2.2.2 to Appendix A to
Subpart UUUUU of Part 63.
Section 3.1.2.1.3 to Appendix B to
Subpart UUUUU of Part 63.
Section 5.3.4 to Appendix B to
Subpart UUUUU of Part 63.
Clarify the language to use the word ‘‘or’’ instead of ‘‘and.’’
Correct the discrepancy between 63.9982(b) and (c) and 63.9985(a).
Correct the typographical error by replacing the incorrect ‘‘corresponding’’ with the correct ‘‘corresponds.’’
Revise to clarify the determination and measurement of fuel moisture content.
Correct the omission of solid oil-derived fuel- and coal-fired EGUs and IGCC EGUs and the omission of
section 10000(c).
Correct the omission of section 63.10023 from the list of sections to be followed in establishing an operating limit.
Correct omission of the term ‘‘boiler operating’’ and clarify the term ‘‘Rti’’ in Equation 2a.
Correct omission of the term ‘‘system’’ and clarify the term ‘‘Rti’’ in Equation 3a.
Correct the typographical error to use the correct word ‘‘your’’ instead of ‘‘you.’’
Clarify the affected-source language.
Change the period by which a Notification of Intent to conduct a performance test must be submitted to
conform to the General Provisions.
Correct the typographical error in the intended definition of ‘‘unit designed for coal ≥ 8,300 Btu/lb subcategory’’ by replacing the erroneous ‘‘>’’ with the correct ‘‘≥.’’
Correct the typographical error in footnote 4 by replacing the erroneous ‘‘≥’’ with the correct ‘‘≤.’’
Clarify the applicability of the alternate 90-day average for Hg in item 1.
Revise item 3 in the table to clarify use of CMS for liquid oil-fired EGUs.
Revise to clarify the period for notification of conducting a performance test from 60 to 30 days.
Correct the typographical error by replacing the incorrect citation to ‘‘§ 63.10005(g)’’ with the correct
‘‘§ 63.9984(f).’’
Correct the typographical error by replacing the incorrect citation to ‘‘Table A–4’’ with the correct ‘‘Table A–
2’’
Correct the typographical error by replacing the erroneous ‘‘≥’’ with the correct ‘‘≤.’’
Correct the section number from the incorrect ‘‘5.3.4’’ to the correct ‘‘5.3.3.’’
VII. Impacts of This Final Rule
A. Summary of Emissions Impacts,
Costs and Benefits
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Our analysis shows that new EGUs
would choose to install and operate the
same or similar air pollution control
technologies in order to meet the
revised emission limits as would have
been necessary to meet the previously
finalized standards. We project that this
final action will result in no significant
change in costs, emission reductions, or
benefits.10 Even if there were changes in
10 See Regulatory Impact Analysis for the Final
Mercury and Air Toxics Standards [EPA–452/R–11–
011] (docket entry EPA–HQ–OAR–2009–0234–
20131) and Economic Impact Analysis for the Final
Reconsideration of the Mercury and Air Toxics
Standards in rulemaking docket EPA–HQ–OAR–
2009–0234. As noted earlier, because on an
individual EGU-by-EGU basis we anticipate very
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costs for these EGUs, such changes
would likely be small relative to both
the overall costs of the individual
projects and the overall costs and
benefits of the final rule. Further, we
believe that EGUs would put on the
same controls for this final action that
they would have for the original final
MATS rule, so there should not be any
incremental costs related to this
revision.
they would have installed to comply
with the previously finalized MATS
standards. Accordingly, we believe that
this final action will not result in
significant changes in emissions of any
of the regulated pollutants.
We believe that electric power
companies will install the same or
similar control technologies to comply
with the final standards in this action as
C. What are the energy impacts?
This final action is not anticipated to
have an effect on the supply,
distribution, or use of energy. As
previously stated, we believe that
electric power companies would install
the same or similar control technologies
as they would have installed to comply
with the previously finalized MATS
standards.
similar costs, any changes to the baseline since we
finalized MATS (e.g., potential impacts of the
CSAPR decision) would not impact this
determination.
D. What are the compliance costs?
We believe there will be no significant
change in compliance costs as a result
of this final action because electric
B. What are the air impacts?
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power companies would install the
same or similar control technologies as
they would have installed to comply
with the previously finalized MATS
standards. Moreover, we find no
additional monitoring costs are
necessary to comply with this final
action; however, as in any other rule,
EGU owners or operators may choose to
conduct additional monitoring (and
incur its expense) for their own
purposes.
E. What are the economic and
employment impacts?
Because we expect that electric power
companies would install the same or
similar control technologies to meet the
standards finalized in this action as they
would have chosen to comply with the
previously finalized MATS standards,
we do not anticipate that this final
action will result in significant changes
in emissions, energy impacts, costs,
benefits, or economic impacts. Likewise,
we believe this action will not have any
impacts on the price of electricity,
employment or labor markets, or the
U.S. economy.
F. What are the benefits of the final
standards?
As previously stated, the EPA
anticipates the power sector will not
incur significant compliance costs or
savings as a result of this action and we
do not anticipate any significant
emission changes resulting from this
action. Therefore, there are no direct
monetized benefits or disbenefits
associated with this action.
VIII. Statutory and Executive Order
Reviews
tkelley on DSK3SPTVN1PROD with RULES
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
Under Executive Order (EO) 12866
(58 FR 51735; October 4, 1993), this
action is a ‘‘significant regulatory
action’’ because it ‘‘raises novel legal or
policy issues.’’ Accordingly, the EPA
submitted this action to the Office of
Management and Budget (OMB) for
review under Executive Orders 12866
and 13563 (76 FR 3821; January 21,
2011) and any changes made in
response to OMB recommendations
have been documented in the docket for
this action.
In addition, the EPA prepared an
analysis of the potential costs and
benefits associated with this action.
This analysis is contained in the
‘‘Economic Impact Analysis for the
Final Reconsideration of the Mercury
and Air Toxics Standards’’ found in
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rulemaking docket EPA–HQ–OAR–
2009–0234. Because our analysis shows
that new electricity generating units
would choose to install the same control
technology in order to meet the revised
emission limits as would have been
necessary to meet the previously
finalized MATS standards, we project
that this action will result in no
significant change in costs, emission
reductions, or benefits.
B. Paperwork Reduction Act
This action does not impose any new
information collection burden. Today’s
action does not change the information
collection requirements previously
finalized and, as a result, does not
impose any additional burden on
industry. However, OMB has previously
approved the information collection
requirements contained in the existing
regulations (see 77 FR 9304) under the
provisions of the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. and has
assigned OMB control number 2060–
0567. The OMB control numbers for
EPA’s regulations are listed in 40 CFR
part 9 and 48 CFR chapter 15.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act
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 not-forprofit enterprises, and small
governmental jurisdictions.
For purposes of assessing the impacts
of today’s action on small entities, a
small entity is defined as: (1) A small
business as defined by the Small
Business Administration’s (SBA)
regulations at 13 CFR 121.201; (2) a
small governmental jurisdiction that is a
government of a city, county, town,
school district, or special district with a
population of less that 50,000; and (3)
a small organization that is any not-forprofit enterprise which is independently
owned and operated and is not
dominant in its field. Categories and
entities potentially regulated by the
final rule with applicable NAICS codes
are provided in the Supplementary
Information section of this action.
According to the SBA size standards
for NAICS code 221122 Utilities-Fossil
Fuel Electric Power Generation, a firm
is small if, including its affiliates, it is
primarily engaged in the generation,
transmission, and or distribution of
electric energy for sale and its total
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24081
electric output for the preceding fiscal
year did not exceed 4 million MWh.
After considering the economic
impacts of today’s action on small
entities, I certify that the notice will not
have a significant economic impact on
a substantial number of small entities.
The EPA has determined that none of
the small entities will experience a
significant impact because the action
imposes no additional regulatory
requirements on owners or operators of
affected sources. We have therefore
concluded that today’s action will not
result in a significant economic impact
on a substantial number of small
entities.
D. Unfunded Mandates Reform Act
This action contains no Federal
mandates under the provisions of Title
II of the Unfunded Mandates Reform
Act of 1995 (UMRA), 2 U.S.C. 1531–
1538 for State, local, or tribal
governments or the private sector. The
action imposes no enforceable duty on
any State, local, or tribal governments or
the private sector. Therefore, this action
is not subject to the requirements of
UMRA sections 202 or 205.
This action is also not subject to the
requirements of UMRA section 203
because it contains no regulatory
requirements that might significantly or
uniquely affect small governments
because it contains no requirements that
apply to such governments or impose
obligations upon them.
E. Executive Order 13132: Federalism
This action does not have federalism
implications. It will not have substantial
direct effects on the states, on the
relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in EO
13132. None of the affected facilities are
owned or operated by state
governments, and the requirements
discussed in today’s notice will not
supersede state regulations that are
more stringent. Thus, EO 13132 does
not apply to today’s notice of
reconsideration.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications. It will not have substantial
direct effects on tribal governments, on
the relationship between the Federal
government and Indian tribes, or on the
distribution of power and
responsibilities between the Federal
government and Indian tribes, as
specified in EO 13175. No affected
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facilities are owned or operated by
Indian tribal governments. Thus, EO
13175 does not apply to today’s action.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
This action is not subject to EO 13045
(62 FR 19885; April 23, 1997) because
it is not economically significant as
defined in EO 12866. The EPA has
evaluated the environmental health or
safety effects of the final MATS on
children. The results of the evaluation
are discussed in that final rule (77 FR
9304; February 16, 2012) and are
contained in rulemaking docket EPA–
HQ–OAR–2009–0234.
tkelley on DSK3SPTVN1PROD with RULES
H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
This action is not a ‘‘significant
energy action’’ as defined in EO 13211
(66 FR 28355; May 22, 2001) because it
is not likely to have a significant
adverse effect on the supply,
distribution, or use of energy. Further,
we conclude that today’s action is not
likely to have any adverse energy effects
because it is not expected to impose any
additional regulatory requirements on
the owners of affected facilities.
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 EPA to use
voluntary consensus standards in their
regulatory and procurement activities
unless to do so would be inconsistent
with applicable law or otherwise
impracticable. Voluntary consensus
standards are technical standards (e.g.,
material specifications, test methods,
sampling procedures, business
practices) developed or adopted by one
or more voluntary consensus bodies.
The NTTAA requires EPA to provide
Congress, through the OMB, with
explanations when EPA decides not to
use available and applicable voluntary
consensus standards.
During the development of the final
MATS rule, the EPA searched for
voluntary consensus standards that
might be applicable. The search
identified three voluntary consensus
standards that were considered practical
alternatives to the specified EPA test
methods. An assessment of these and
other voluntary consensus standards is
presented in the preamble to the final
MATS rule (77 FR 9441; February 16,
2012). Today’s action does not make use
of any additional technical standards
beyond those cited in the final MATS
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rule. Therefore, the EPA is not
considering the use of any additional
voluntary consensus standards for this
action.
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. Its main provision directs
federal agencies, to the greatest extent
practicable and permitted by law, to
make environmental justice 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 United States.
The EPA has determined that this
action will not have disproportionately
high and adverse human health or
environmental effects on minority or
low-income populations because it does
not affect the level of protection
provided to human health or the
environment. Our analysis shows that
new EGUs would choose to install the
same control technology in order to
meet the revised emission limits as
would have been necessary to meet the
previously finalized standard. Under the
relevant assumptions, we project that
this action will result in no significant
change in emission reductions.
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 United States. The EPA will
submit a report containing this final
action and other required information to
the U.S. Senate, the U.S. House of
Representatives, and the Comptroller
General of the United States 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 not a
‘‘major rule’’ as defined by 5 U.S.C.
804(2). This rule will be effective April
24, 2013.
List of Subjects in 40 CFR Parts 60 and
63
Environmental protection,
Administrative practice and procedure,
Air pollution control, Hazardous
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substances, Intergovernmental relations,
Reporting and recordkeeping
requirements.
Dated: March 28, 2013.
Bob Perciasepe,
Acting Administrator.
For the reasons discussed in the
preamble, 40 CFR parts 60 and 63 are
amended to read as follows:
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
1. The authority citation for part 60
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
2. Amend § 60.41Da by revising the
definitions of ‘‘Coal’’ and ‘‘Integrated
gasification combined cycle electric
utility steam generating unit,’’ and by
adding the definition of ‘‘Natural gas’’ in
alphabetical order to read as follows:
■
§ 60.41Da
Definitions.
*
*
*
*
*
Coal means all solid fuels classified as
anthracite, bituminous, subbituminous,
or lignite by the American Society of
Testing and Materials in ASTM D388
(incorporated by reference, see § 60.17)
and coal refuse. Synthetic fuels derived
from coal for the purpose of creating
useful heat, including but not limited to
solvent-refined coal, gasified coal, coaloil mixtures, and coal-water mixtures
are included in this definition for the
purposes of this subpart.
*
*
*
*
*
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, startup
and commissioning, shutdown, 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
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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.
*
*
*
*
*
■ 3. Amend § 60.42Da by revising
paragraphs (a), (b)(2), and (e)(1) 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 (0.03 lb/MMBtu) heat input.
(b) * * *
(2) An owner or operator of an
affected facility that combusts only
natural gas and/or synthetic natural gas
that chemically meets the definition of
natural gas is exempt from the opacity
standard specified in paragraph (b) of
this section.
*
*
*
*
*
(e) * * *
(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, the owner
or operator shall not cause to be
discharged into the atmosphere from
that affected facility 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:
(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, the emission
limits specified in paragraphs (c) or (d)
of this section.
*
*
*
*
*
■ 4. Amend § 60.48Da by revising
paragraphs (f), (o) introductory text,
(o)(1), (o)(2) introductory text, (o)(3)
introductory text, (o)(3)(i), and (o)(4)
introductory text to read as follows:
§ 60.48Da
Compliance provisions.
*
*
*
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*
*
17:22 Apr 23, 2013
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(f) For affected facilities for which
construction, modification, or
reconstruction commenced before May
4, 2011, compliance with the applicable
daily average PM emissions limit is
determined by calculating the
arithmetic average of all hourly
emission rates each boiler operating
day, except for data obtained during
startup, shutdown, or malfunction
periods. Daily averages must be
calculated for boiler operating days that
have out-of-control periods totaling no
more than 6 hours of unit operation
during which the standard applies. For
affected facilities for which construction
or reconstruction commenced after May
3, 2011, that elect to demonstrate
compliance using PM CEMS,
compliance with the applicable PM
emissions limit in § 60.42Da is
determined on a 30-boiler operating day
rolling average basis by calculating the
arithmetic average of all hourly PM
emission rates for the 30 successive
boiler operating days, except for data
obtained during periods of startup or
shutdown.
*
*
*
*
*
(o) Compliance provisions for sources
subject to § 60.42Da(c)(2), (d), or
(e)(1)(ii). Except as provided for in
paragraph (p) of this section, the owner
or operator must demonstrate
compliance with each applicable
emissions limit according to the
requirements in paragraphs (o)(1)
through (o)(5) of this section.
(1) You must conduct a performance
test to demonstrate initial compliance
with the applicable PM emissions limit
in § 60.42Da by the applicable date
specified in § 60.8(a). Thereafter, you
must conduct each subsequent
performance test within 12 calendar
months following the date the previous
performance test was required to be
conducted. You must conduct each
performance test according to the
requirements in § 60.8 using the test
methods and procedures in § 60.50Da.
The owner or operator of an affected
facility that has not operated for 60
consecutive calendar days prior to the
date that the subsequent performance
test would have been required had the
unit been operating is not required to
perform the subsequent performance
test until 30 calendar days after the next
boiler operating day. Requests for
additional 30 day extensions shall be
granted by the relevant air division or
office director of the appropriate
Regional Office of the U.S. EPA.
(2) You must monitor the performance
of each electrostatic precipitator or
fabric filter (baghouse) operated to
comply with the applicable PM
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24083
emissions limit in § 60.42Da using a
continuous opacity monitoring system
(COMS) according to the requirements
in paragraphs (o)(2)(i) through (vi)
unless you elect to comply with one of
the alternatives provided in paragraphs
(o)(3) and (o)(4) of this section, as
applicable to your control device.
*
*
*
*
*
(3) As an alternative to complying
with the requirements of paragraph
(o)(2) of this section, an owner or
operator may elect to monitor the
performance of an electrostatic
precipitator (ESP) operated to comply
with the applicable PM emissions limit
in § 60.42Da using an ESP predictive
model developed in accordance with
the requirements in paragraphs (o)(3)(i)
through (v) of this section.
(i) You must calibrate the ESP
predictive model with each PM control
device used to comply with the
applicable PM emissions limit in
§ 60.42Da operating under normal
conditions. In cases when a wet
scrubber is used in combination with an
ESP to comply with the PM emissions
limit, the wet scrubber must be
maintained and operated.
*
*
*
*
*
(4) As an alternative to complying
with the requirements of paragraph
(o)(2) of this section, an owner or
operator may elect to monitor the
performance of a fabric filter (baghouse)
operated to comply with the applicable
PM emissions limit in § 60.42Da by
using a bag leak detection system
according to the requirements in
paragraphs (o)(4)(i) through (v) of this
section.
*
*
*
*
*
■ 5. Amend § 60.49Da by:
■ a. Revising paragraphs (a)
introductory text;
■ b. Adding paragraph (a)(3)(iv); and
■ c. Revising paragraphs (a)(4), (b)
introductory text, and (t).
The revised and added text reads as
follows:
§ 60.49Da
Emission monitoring.
(a) An owner or operator of an
affected facility subject to the opacity
standard in § 60.42Da must monitor the
opacity of emissions discharged from
the affected facility to the atmosphere
according to the applicable
requirements in paragraphs (a)(1)
through (4) of this section.
*
*
*
*
*
(3) * * *
(iv) If the maximum 6-minute opacity
is less than 10 percent during the most
recent Method 9 of appendix A–4 of this
part performance test, the owner or
operator may, as an alternative to
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performing subsequent Method 9 of
appendix A–4 performance tests, elect
to perform subsequent monitoring using
a digital opacity compliance system
according to a site-specific monitoring
plan approved by the Administrator.
The observations must be similar, but
not necessarily identical, to the
requirements in paragraph (a)(3)(iii) of
this section. For reference purposes in
preparing the monitoring plan, see
OAQPS ‘‘Determination of Visible
Emission Opacity from Stationary
Sources Using Computer-Based
Photographic Analysis Systems.’’ This
document is available from the U.S.
Environmental Protection Agency (U.S.
EPA); Office of Air Quality and
Planning Standards; Sector Policies and
Programs Division; Measurement Policy
Group (D243–02), Research Triangle
Park, NC 27711. This document is also
available on the Technology Transfer
Network (TTN) under Emission
Measurement Center Preliminary
Methods.
*
*
*
*
*
(4) An owner or operator of an
affected facility that is subject to an
opacity standard under § 60.42Da 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 and/or liquid fuels (excluding
residue oil) where the potential SO2
emissions rate of each fuel is 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
§ 60.51Da(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 must install, calibrate,
maintain, and operate a CEMS, and
record the output of the system, for
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measuring SO2 emissions, except where
only gaseous and/or liquid fuels
(excluding residual oil) where the
potential SO2 emissions rate of each fuel
is 26 ng/J (0.060 lb/MMBtu) or less are
combusted, as follows:
*
*
*
*
*
(t) The owner or operator of an
affected facility demonstrating
compliance with the output-based
emissions limit under § 60.42Da must
either install, certify, operate, and
maintain a CEMS for measuring PM
emissions according to the requirements
of paragraph (v) of this section or install,
calibrate, operate, and maintain a PM
CPMS according to the requirements for
new facilities specified in subpart
UUUUU of part 63 of this chapter. 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.
*
*
*
*
*
■ 6. Revise § 60.50Da(f) to read as
follows:
§ 60.50Da Compliance determination
procedures and methods.
*
*
*
*
*
(f) The owner or operator of an
electric utility combined cycle gas
turbine that does not meet the definition
of an IGCC must conduct performance
tests for PM, SO2, and NOX using the
procedures of Method 19 of appendix
A–7 of this part. The SO2 and NOX
emission rates calculations from the gas
turbine used in Method 19 of appendix
A–7 of this part are determined when
the gas turbine is performance tested
under subpart GG of this part. The
potential uncontrolled PM emission rate
from a gas turbine is defined as 17 ng/
J (0.04 lb/MMBtu) heat input.
*
*
*
*
*
PART 63—NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS FOR SOURCE
CATEGORIES
7. The authority citation for 40 CFR
Part 63 continues to read as follows:
■
Authority: 42 U.S.C. 7401, et seq.
8. In § 63.9982, revise paragraphs (a)
introductory text, (b), and (c) to read as
follows:
■
§ 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, or existing affected
source(s) as described in paragraphs
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(a)(1) and (2) of this section within a
contiguous area and under common
control.
*
*
*
*
*
(b) An EGU is new if you commence
construction of the coal- or oil-fired
EGU after May 3, 2011.
(c) An EGU is reconstructed if you
meet the reconstruction criteria as
defined in § 63.2, and if you commence
reconstruction after May 3, 2011.
*
*
*
*
*
■ 9. In § 63.10000, revise paragraphs
(c)(1)(iv) and (c)(2)(ii) to read as follows:
§ 63.10000 What are my general
requirements for complying with this
subpart?
*
*
*
*
*
(c) * * *
(1) * * *
(iv) If your coal-fired or solid oil
derived fuel-fired EGU or IGCC EGU
does not qualify as a LEE for total nonmercury HAP metals, individual nonmercury 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, for an existing EGU,
compliance performance testing
repeated quarterly.
*
*
*
*
*
(c) * * *
(2) * * *
(ii) If your 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, for an existing
EGU, performance testing conducted
quarterly.
*
*
*
*
*
■ 10. Amend § 63.10005 by:
■ a. Revising paragraphs (d)(2)(ii),
(i)(4)(ii) and (i)(5);
■ b. Adding paragraph (i)(6).
The revised and added text read as
follows:
§ 63.10005 What are my initial compliance
requirements and by what date must I
conduct them?
*
*
*
*
*
(d) * * *
(2) * * *
(ii) You must demonstrate continuous
compliance with the PM CPMS sitespecific operating limit that corresponds
to the results of the performance test
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Rmi = hourly heat input or gross electrical
output from unit i for the preceding 30group 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 30group boiler operating days,
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
§ 63.10006 When must I conduct
subsequent performance tests or tune-ups?
*
*
*
*
*
(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 emissions limit, for liquid
oil-, solid oil-derived fuel-, coal-fired
and IGCC EGUs, you must conduct all
applicable periodic emissions tests for
filterable PM, individual, or total HAP
metals emissions according to Table 5 to
this subpart, § 63.10007, and
§ 63.10000(c), except as otherwise
provided in § 63.10021(d)(1).
*
*
*
*
*
■ 12. In § 63.10007, revise paragraph (c)
to read as follows:
§ 63.10007 What methods and other
procedures must I use for the performance
tests?
*
*
*
*
13. In § 63.10009, revise paragraphs
(b)(2) and (b)(3) to read as follows:
■
§ 63.10009 May I use emissions averaging
to comply with this subpart?
*
*
*
*
*
(b) * * *
(2) Weighted 30-boiler operating 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.
Teri = Emissions rate from most recent
emissions test of unit i in terms of lb/
heat input or lb/gross electrical output,
Rti = Total heat input or gross electrical
output of unit i for the preceding 30boiler operating days, 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
‘‘coal-fired unit not low rank virgin
coal’’ subcategory. Use equation 3a or 3b
to calculate the 90-day rolling average
emissions daily.
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ER24AP13.006</GPH>
ER24AP13.007</GPH>
*
(c) If you choose the filterable PM
method to comply with the PM
emission limit and demonstrate
continuous performance using a PM
CPMS as provided for in § 63.10000(c),
you must also establish an operating
limit according to § 63.10011(b),
§ 63.10023, 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.
*
*
*
*
*
ER24AP13.008</GPH>
(ii) Use an HCl CEMS and/or HF
CEMS.
*
*
*
*
*
■ 11. In § 63.10006, revise paragraph (c)
to read as follows:
Where:
Heri = hourly emission rate (e.g., lb/MMBtu,
lb/MWh) from unit i’s CEMS for the
preceding 30-group boiler operating
days,
tkelley on DSK3SPTVN1PROD with RULES
demonstrating compliance with the
emission limit with which you choose
to comply.
*
*
*
*
*
(i) * * *
(4) * * *
(ii) ASTM D4006–11, ‘‘Standard Test
Method for Water in Crude Oil by
Distillation,’’ including Annex A1 and
Appendix A1.
*
*
*
*
*
(5) Use one of the following methods
to obtain fuel moisture samples:
(i) 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
(ii) ASTM D4057–06 (Reapproved
2011), ‘‘Standard Practice for Manual
Sampling of Petroleum and Petroleum
Products,’’ including Annex A1.
(6) 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
24085
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Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations
Rmi = hourly heat input or gross electrical
output from unit i for the preceding 90group 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 = Total heat input or gross electrical
output of unit i for the preceding 90boiler operating days, and
m = number of EGUs in emissions averaging
group that rely on emissions testing.
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.
(1) For any exceedance of the 30boiler operating day PM CPMS average
value from the established operating
parameter limit for an EGU subject to
the emissions limits in Table 1 to this
subpart, you must:
(i) Within 48 hours of the exceedance,
visually inspect the air pollution control
device (APCD);
(ii) If the inspection of the APCD
identifies the cause of the exceedance,
take corrective action as soon as
possible, and return the PM CPMS
measurement to within the established
value; and
(iii) Within 45 days of the exceedance
or at the time of the annual compliance
test, whichever comes first, conduct a
PM emissions compliance test to
determine compliance with the PM
emissions limit and to verify or reestablish the CPMS operating limit. You
are not required to conduct any
additional testing for any exceedances
that occur between the time of the
original exceedance and the PM
emissions compliance test required
under this paragraph.
(2) PM CPMS exceedances of the
operating limit for an EGU subject to the
emissions limits in Table 1 of this
subpart leading to more than four
required performance tests in a 12month period (rolling monthly)
constitute a separate violation of this
subpart.
*
*
*
*
*
■ 16. In § 63.10023, revise paragraph (b)
to read as follows:
(2) For a new EGU, determine your
operating limit as follows.
(i) If your PM performance test
demonstrates your PM emissions do not
exceed 75 percent of your emissions
limit, you will use the average PM
CPMS value recorded during the PM
compliance test, the milliamp
equivalent of zero output from your PM
CPMS, and the average PM result of
your compliance test to establish your
operating limit. Calculate the operating
limit by establishing a relationship of
PM CPMS signal to PM concentration
using the PM CPMS instrument zero,
the average PM CPMS values
corresponding to the three compliance
test runs, and the average PM
concentration from the Method 5
compliance test with the procedures in
(b)(2)(i)(A) through (D) of this section.
(A) Determine your PM CPMS
instrument zero output with one of the
following procedures.
(1) Zero point data for in-situ
instruments should be obtained by
removing the instrument from the stack
and monitoring ambient air on a test
bench.
(2) Zero point data for extractive
instruments should be obtained by
removing the extractive probe from the
stack and drawing in clean ambient air.
(3) The zero point can also can be
obtained by performing manual
reference method measurements when
the flue gas is free of PM emissions or
contains very low PM concentrations
(e.g., when your process is not
operating, but the fans are operating or
your source is combusting only natural
gas) and plotting these with the
compliance data to find the zero
intercept.
(4) If none of the steps in paragraphs
(A)(1) through (3) of this section are
possible, you must use a zero output
value provided by the manufacturer.
(B) Determine your PM CPMS
instrument average (x) in milliamps,
and the average of your corresponding
three PM compliance test runs (y), using
equation 10.
*
*
*
*
*
14. In § 63.10010, revise paragraph
(j)(1)(i) to read as follows:
■
§ 63.10010 What are my monitoring,
installation, operation, and maintenance
requirements?
*
*
*
*
(j) * * *
(1) * * *
(i) Install and certify your HAP metals
CEMS according to the procedures and
requirements in your approved sitespecific 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.
*
*
*
*
*
■ 15. Amend § 63.10021 by adding
paragraphs (c)(1) and (2) to read as
follows:
tkelley on DSK3SPTVN1PROD with RULES
*
§ 63.10021 How do I demonstrate
continuous compliance with the emission
limitations, operating limits, and work
practice standards?
*
*
*
(c) * * *
VerDate Mar<15>2010
*
*
17:22 Apr 23, 2013
Jkt 229001
§ 63.10023 How do I establish my PM
CPMS operating limit and determine
compliance with it?
*
*
*
*
*
(b) Determine your operating limit as
provided in paragraph (b)(1) or (b)(2) of
this section. You must verify an existing
or establish a new operating limit after
each repeated performance test.
(1) For an existing EGU, determine
your operating limit based on the
highest 1-hour average PM CPMS output
value recorded during the performance
test.
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ER24AP13.009</GPH>
Where:
Heri = hourly emission rate from unit i’s
CEMS or Hg sorbent trap monitoring
system for the preceding 90-group boiler
operating days,
Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES
Where:
Xi = the PM CPMS data points for all runs
i,
n = the number of data points, and
Oh = your site specific operating limit, in
milliamps.
(iii) Your PM CPMS must provide a
4–20 milliamp output and the
establishment of its relationship to
manual reference method measurements
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17:22 Apr 23, 2013
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17. In § 63.10030, revise paragraphs
(b), (c), and (d) to read as follows:
■
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§ 63.10030 What notifications must I
submit and when?
*
*
*
*
*
(b) As specified in § 63.9(b)(2), if you
startup your EGU that is an 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 EGU that is an 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 EGU that is an 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.
*
*
*
*
*
■ 18. Amend § 63.10042 by revising the
definition of ‘‘Unit designed for coal >
8,300 Btu/lb subcategory’’ to read as
follows:
§ 63.10042
subpart?
What definitions apply to this
*
*
*
*
*
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.
*
*
*
*
*
■ 19. Revise Table 1 to Subpart UUUUU
of Part 63 to read as follows:
E:\FR\FM\24APR1.SGM
24APR1
ER24AP13.013</GPH>
(ii) If your PM compliance test
demonstrates your PM emissions exceed
75 percent of your emissions limit, you
will use the average PM CPMS value
recorded during the PM compliance test
demonstrating compliance with the PM
limit to establish your operating limit.
(A) Determine your operating limit by
averaging the PM CPMS milliamp
output corresponding to your three PM
performance test runs that demonstrate
compliance with the emission limit
using equation 13.
must be determined in units of
milliamps.
(iv) Your PM CPMS operating range
must be capable of reading PM
concentrations from zero to a level
equivalent to two times your allowable
emission limit. If your PM CPMS is an
auto-ranging instrument capable of
multiple scales, the primary range of the
instrument must be capable of reading
PM concentration from zero to a level
equivalent to two times your allowable
emission limit.
(v) During the initial performance test
or any such subsequent performance
test that demonstrates compliance with
the PM limit, record and average all
milliamp output values from the PM
CPMS for the periods corresponding to
the compliance test runs.
(vi) For PM performance test reports
used to set a PM CPMS operating limit,
the electronic submission of the test
report must also include the make and
model of the PM CPMS instrument,
serial number of the instrument,
analytical principle of the instrument
(e.g. beta attenuation), span of the
instruments primary analytical range,
milliamp value equivalent to the
instrument zero output, technique by
which this zero value was determined,
and the average milliamp signal
corresponding to each PM compliance
test run.
*
*
*
*
*
(D) Determine your source specific 30day rolling average operating limit using
the PM lb/MWh per milliamp value
from equation 11 in equation 12, below.
This sets your operating limit at the PM
CPMS output value corresponding to 75
percent of your emission limit.
ER24AP13.012</GPH>
Where:
OL = the operating limit for your PM CPMS
on a 30-day rolling average, in
milliamps,
L = your source PM emissions limit in lb/
MWh,
z = your instrument zero in milliamps,
determined from (b)(2)(i)(A) of this
section, and
R = the relative PM lb/MWh per milliamp for
your PM CPMS, from equation 11.
Where:
R = the relative PM lb/MWh per milliamp for
your PM CPMS,
y = the three run average PM lb/MWh,
x = the three run average milliamp output
from your PM CPMS, and
z = the milliamp equivalent of your
instrument zero determined from
(b)(2)(i)(A) of this section.
ER24AP13.011</GPH>
(C) With your PM CPMS instrument
zero expressed in milliamps, your three
run average PM CPMS milliamp value,
and your three run average PM
emissions value (in lb/MWh) from your
compliance runs, determine a
relationship of PM lb/MWh per
milliamp with equation 11.
ER24AP13.010</GPH>
Where:
Xi = the PM CPMS data points for run i of
the performance test,
Yi = the PM emissions value (in lb/MWh) for
run i of the performance test, and
n = the number of data points.
24087
24088
Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations
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 limit]
If your EGU is in this subcategory
For the following pollutants
You must meet the following
emission limits and work practice
standards
1. Coal-fired unit not low rank virgin coal.
a.
9.0E–2 lb/MWh 1 ...........................
OR
6.0E–2 lb/GWh .............................
OR
Individual HAP metals: .................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
8.0E–3
3.0E–3
6.0E–4
4.0E–4
7.0E–3
2.0E–3
2.0E–2
4.0E–3
4.0E–2
5.0E–2
1.0E–2
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
2. Coal-fired units low rank virgin
coal.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
.......................................................
1.0 lb/MWh ...................................
3.0E–3 lb/GWh .............................
a.
9.0E–2 lb/MWh 1 ...........................
lb/GWh.
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: .................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
8.0E–3
3.0E–3
6.0E–4
4.0E–4
7.0E–3
2.0E–3
2.0E–2
4.0E–3
4.0E–2
5.0E–2
1.0E–2
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
1.0 lb/MWh ...................................
4.0E–2 lb/GWh .............................
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
17:22 Apr 23, 2013
7.0E–2 lb/MWh 4 ...........................
9.0E–2 lb/MWh 5 ...........................
OR
4.0E–1 lb/GWh .............................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
VerDate Mar<15>2010
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
OR
Individual HAP metals: .................
3. IGCC unit ...................................
tkelley on DSK3SPTVN1PROD with RULES
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
2.0E–2
2.0E–2
1.0E–3
2.0E–3
4.0E–2
a.
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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 4 dscm per
run.
Collect a minimum of 4 dscm per
run.
Collect a minimum of 3 dscm per
run.
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.
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
Collect a minimum of 4 dscm per
run.
Collect a minimum of 4 dscm per
run.
Collect a minimum of 3 dscm per
run.
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.
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 2 dscm per
run.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
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Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations
24089
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 limit]
3.0E–1 lb/MWh 1 ...........................
OR
2.0E–4 lb/MWh .............................
OR
.......................................................
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
1.0E–4
b. Hydrogen chloride (HCl) ...........
4.0E–4 lb/MWh .............................
c. Hydrogen fluoride (HF) .............
4.0E–4 lb/MWh .............................
a.
matter
2.0E–1 lb/MWh 1 ...........................
OR
Total HAP metals .........................
OR
7.0E–3 lb/MWh .............................
OR
Individual HAP metals: .................
tkelley on DSK3SPTVN1PROD with RULES
matter
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
Mercury (Hg) .................................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
17:22 Apr 23, 2013
a.
OR
Individual HAP metals: .................
VerDate Mar<15>2010
.......................................................
4.0E–1 lb/MWh .............................
3.0E–3 lb/GWh .............................
OR
Total HAP metals .........................
5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units).
4.0E–3
9.0E–3
2.0E–2
7.0E–2
3.0E–1
2.0E–3
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
4. Liquid oil-fired unit—continental
(excluding limited-use liquid oilfired subcategory units).
For the following pollutants
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–3
6.0E–2
2.0E–3
2.0E–3
2.0E–2
3.0E–1
3.0E–2
1.0E–1
Filterable
(PM).
Filterable
(PM).
Jkt 229001
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particulate
Frm 00057
Fmt 4700
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/GWh .............................
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5
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.
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 2 dscm per
run.
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 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.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
Sfmt 4700
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24APR1
24090
Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / 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 limit]
4.1E0 lb/GWh.
2.0E–2 lb/GWh.
4.0E–4 lb/GWh .............................
b. Hydrogen chloride (HCl) ...........
2.0E–3 lb/MWh .............................
c. Hydrogen fluoride (HF) .............
6. Solid oil-derived fuel-fired unit ...
For the following pollutants
Nickel (Ni) .....................................
Selenium (Se) ...............................
Mercury (Hg) .................................
If your EGU is in this subcategory
You must meet the following
emission limits and work practice
standards
5.0E–4 lb/MWh .............................
a.
3.0E–2 lb/MWh 1 ...........................
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
OR
6.0E–1 lb/GWh .............................
OR
Individual HAP metals: .................
8.0E–3
3.0E–3
6.0E–4
7.0E–4
6.0E–3
2.0E–3
2.0E–2
7.0E–3
4.0E–2
6.0E–3
4.0E–4
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
..................................................
1.0 lb/MWh ...................................
2.0E–3 lb/GWh .............................
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 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.
OR
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5
..................................................
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
Collect a minimum of 3 dscm per
run.
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.
SO2 CEMS.
Hg CEMS or Sorbent trap monitoring system only.
1 Gross
electric output.
by reference, see § 63.14.
3 You may not use the alternate SO limit if your EGU does not have some form of FGD system (or, in the case of IGCC EGUs, some other
2
acid gas removal system either upstream or downstream of the combined cycle block) and SO2 CEMS installed.
4 Duct burners on syngas; gross electric output.
5 Duct burners on natural gas; gross electric output.
2 Incorporated
20. Revise Table 4 to Subpart UUUUU
of Part 63 to read as follows:
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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 for an existing EGU ..
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).
Maintain the 30-boiler operating day rolling average PM CPMS output determined in accordance with the
requirements of § 63.10023(b)(2) and obtained during the most recent performance test run 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 oilfired units) emissions limitation(s).
2. PM CPMS for a new EGU ..........
21. Revise footnote 4 of Table 5 to
Subpart UUUUU of Part 63 to read as
follows:
■
TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS
*
*
*
*
*
*
*
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:
22. Revise Table 6 to Subpart UUUUU
of Part 63 to read as follows:
■
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]
And you choose to establish
PM CPMS operating limits, you
must . . .
And . . .
Using . . .
According to the following
procedures . . .
1. Filterable Particulate
matter (PM), total nonmercury HAP metals,
individual non-mercury
HAP metals, total HAP
metals, or individual
HAP metals for an existing EGU.
tkelley on DSK3SPTVN1PROD with RULES
If you have an applicable
emission limit for . . .
Install, certify, maintain, and operate a PM CPMS for monitoring emissions discharged
to the atmosphere according
to § 63.10010(h)(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 1hour average PM CPMS
measured during the performance test demonstrating compliance with
the filterable PM or HAP
metals emissions limitations.
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TABLE 6 TO SUBPART UUUUU OF PART 63—ESTABLISHING PM CPMS OPERATING LIMITS—Continued
[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 . . .
2. Filterable Particulate
matter (PM), total nonmercury HAP metals,
individual non-mercury
HAP metals, total HAP
metals, or individual
HAP metals for a new
EGU.
Install, certify, maintain, and operate a PM CPMS for monitoring emissions discharged
to the atmosphere according
to § 63.10010(h)(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 performance
test.
3. Determine the PM CPMS
operating limit in accordance with the requirements
of § 63.10023(b)(2) from
data obtained during the
performance test demonstrating compliance with
the filterable PM or HAP
metals emissions limitations.
23. Revise Table 7 to Subpart UUUUU
of Part 63 to read as follows:
■
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 . . .
tkelley on DSK3SPTVN1PROD with RULES
1. CEMS to measure filterable PM,
SO2, HCl, HF, or Hg emissions,
or using a sorbent trap monitoring system to measure Hg.
2. PM CPMS to measure compliance with a parametric operating
limit.
3. Site-specific monitoring using
CMS for liquid oil-fired EGUs for
HCl and HF emission limit monitoring.
4. Quarterly performance testing for
coal-fired, solid oil derived fired,
or liquid oil-fired EGUs to measure compliance with one or more
non-PM (or its alternative emission limits) applicable emissions
limit in Table 1 or 2, or PM (or its
alternative emission limits) applicable emissions limit in Table 2.
5. Conducting periodic performance
tune-ups of your EGU(s).
6. Work practice standards for coalfired, liquid oil-fired, or solid oilderived fuel-fired EGUs during
startup.
7. Work practice standards for coalfired, liquid oil-fired, or solid oilderived fuel-fired EGUs during
shutdown.
You demonstrate continuous compliance by . . .
Calculating the 30- (or 90-) 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- (or 90-) boiler operating days, excluding
data recorded during periods of startup or shutdown.
Calculating the 30- (or 90-) boiler operating day rolling arithmetic 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- (or 90-) 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.
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.
24. Revise Table 9 to Subpart UUUUU
of Part 63 to read as follows:
■
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24093
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
Subject
...............................................
...............................................
...............................................
...............................................
Applies to subpart UUUUU
§ 63.8(d)(3) ......................................
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.
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 ...............................................
Notification requirements ...............
§ 63.10(a), (b)(1), (c), (d)(1)–(2),
(e), and (f).
§ 63.10(b)(2)(i) .................................
Recordkeeping and Reporting Requirements.
Recordkeeping of occurrence and
duration of startups and shutdowns.
Recordkeeping of malfunctions .....
§ 63.5 ...............................................
§ 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) ......................................
§ 63.8(c)(1)(iii) .................................
§ 63.10(b)(2)(ii) ................................
§ 63.10(b)(2)(iii) ...............................
§ 63.10(b)(2)(iv) ...............................
§ 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) ..................................
§ 63.10(c)(11) ..................................
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§ 63.10(c)(15) ..................................
§ 63.10(d)(5) ....................................
§ 63.11 .............................................
§ 63.12 .............................................
§ 63.13–63.16 ..................................
§ 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).
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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.
Recording corrective actions .........
Use of SSM Plan ...........................
SSM reports ...................................
Control Device Requirements .......
State Authority and Delegation .....
Addresses, Incorporation by Reference, Availability of Information, Performance Track Provisions.
Reserved .......................................
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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, except for the 60-day notification prior to conducting a performance test in § 63.9(d); instead use a 30-day notification period per
§ 63.10030(d).
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.
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.
No.
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25. Revise sections 4.1 and 5.2.2.2 to
Appendix A to Subpart UUUUU of Part
63 to read as follows:
■
Appendix A to Subpart UUUUU—Hg
Monitoring Provisions
*
*
*
*
*
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 § 63.9984(f).
*
*
*
*
*
5.2.2.2 The same RATA performance
criteria specified in Table A–2 for Hg CEMS
also apply to the annual RATAs of the
sorbent trap monitoring system.
*
*
*
*
*
26. Revise section 3.1.2.1.3 and the
heading to section 5.3.4 to Appendix B
to Subpart UUUUU of Part 63 to read as
follows:
■
Appendix B to Subpart UUUUU—HCl
and HF Monitoring Provisions
*
*
*
*
*
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
*
*
*
*
*
5.3.3 Conditional Data Validation
* * *
*
*
*
*
*
[FR Doc. 2013–07859 Filed 4–23–13; 8:45 am]
BILLING CODE 6560–50–P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 180
[EPA–HQ–OPP–2012–0282; FRL–9384–2]
Azoxystrobin; Pesticide Tolerances
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
This regulation establishes
tolerances for residues of azoxystrobin
in or on multiple commodities
discussed later in this document.
Syngenta Crop Protection, LLC
requested these tolerances under the
Federal Food, Drug, and Cosmetic Act
(FFDCA).
DATES: This regulation is effective April
24, 2013. Objections and requests for
hearings must be received on or before
June 24, 2013, and must be filed in
accordance with the instructions
provided in 40 CFR part 178 (see also
Unit I.C. of the SUPPLEMENTARY
INFORMATION).
tkelley on DSK3SPTVN1PROD with RULES
SUMMARY:
VerDate Mar<15>2010
17:22 Apr 23, 2013
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The docket for these
actions, identified by docket
identification (ID) number EPA–HQ–
OPP–2012–0282, is available at https://
www.regulations.gov or at the Office of
Pesticide Programs Regulatory Public
Docket (OPP Docket) in the
Environmental Protection Agency
Docket Center (EPA/DC), EPA West
Bldg., Rm. 3334, 1301 Constitution Ave.
NW., Washington, DC 20460–0001. The
Public Reading Room 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 OPP
Docket is (703) 305–5805. Please review
the visitor instructions and additional
information about the docket available
at https://www.epa.gov/dockets.
FOR FURTHER INFORMATION CONTACT: Erin
Malone, Registration Division (7505P),
Office of Pesticide Programs,
Environmental Protection Agency, 1200
Pennsylvania Ave. NW., Washington,
DC 20460–0001; telephone number:
(703) 347–0253; email address:
Malone.Erin@epa.gov.
SUPPLEMENTARY INFORMATION:
ADDRESSES:
I. General Information
A. Does this action apply to me?
You may be potentially affected by
this action if you are an agricultural
producer, food manufacturer, or
pesticide manufacturer. The following
list of North American Industrial
Classification System (NAICS) codes is
not intended to be exhaustive, but rather
provides a guide to help readers
determine whether this document
applies to them. Potentially affected
entities may include:
• Crop production (NAICS code 111).
• Animal production (NAICS code
112).
• Food manufacturing (NAICS code
311).
• Pesticide manufacturing (NAICS
code 32532).
B. How can I get electronic access to
other related information?
You may access a frequently updated
electronic version of EPA’s tolerance
regulations at 40 CFR part 180 through
the Government Printing Office’s eCFR
site at https://www.ecfr.gov/cgi-bin/textidx?&c=ecfr&tpl=/ecfrbrowse/Title40/
40tab_02.tpl.
C. How can I file an objection or hearing
request?
Under FFDCA section 408(g), 21
U.S.C. 346a, any person may file an
objection to any aspect of this regulation
and may also request a hearing on those
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objections. You must file your objection
or request a hearing on this regulation
in accordance with the instructions
provided in 40 CFR part 178. To ensure
proper receipt by EPA, you must
identify docket ID number EPA–HQ–
OPP–2012–0282 in the subject line on
the first page of your submission. All
objections and requests for a hearing
must be in writing, and must be
received by the Hearing Clerk on or
before June 24, 2013. Addresses for mail
and hand delivery of objections and
hearing requests are provided in 40 CFR
178.25(b).
In addition to filing an objection or
hearing request with the Hearing Clerk
as described in 40 CFR part 178, please
submit a copy of the filing (excluding
any Confidential Business Information
(CBI)) for inclusion in the public docket.
Information not marked confidential
pursuant to 40 CFR part 2 may be
disclosed publicly by EPA without prior
notice. Submit the non-CBI copy of your
objection or hearing request, identified
by docket ID number EPA–HQ–OPP–
2012–0282, by one of the following
methods:
• Federal eRulemaking Portal: https://
www.regulations.gov. Follow the online
instructions for submitting comments.
Do not submit electronically any
information you consider to be CBI or
other information whose disclosure is
restricted by statute.
• Mail: OPP Docket, Environmental
Protection Agency Docket Center (EPA/
DC), (28221T), 1200 Pennsylvania Ave.
NW., Washington, DC 20460–0001.
• Hand Delivery: To make special
arrangements for hand delivery or
delivery of boxed information, please
follow the instructions at https://
www.epa.gov/dockets/contacts.htm.
Additional instructions on
commenting or visiting the docket,
along with more information about
dockets generally, is available at
https://www.epa.gov/dockets.
II. Summary of Petitioned-For
Tolerance
In the Federal Register of April 4,
2012 (77 FR 20336) (FRL–9340–4), EPA
issued a document pursuant to FFDCA
section 408(d)(3), 21 U.S.C. 346a(d)(3),
announcing the filing of a pesticide
petition (PP 1E7945) by Syngenta Crop
Protection, LLC, P.O. Box 18300,
Greensboro, NC 27419–8300. The
petition requested that 40 CFR 180.507
be amended by establishing an import
tolerance for residues of the fungicide
azoxystrobin, [methyl(E)-2-(2-(6-(2cyanophenoxy) pyrimidin-4yloxy)phenyl)-3-methoxyacrylate], and
the Z-isomer of azoxystrobin,
[methyl(Z)-2-(2-(6-(2-
E:\FR\FM\24APR1.SGM
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]]>Agencies
[Federal Register Volume 78, Number 79 (Wednesday, April 24, 2013)]
[Rules and Regulations]
[Pages 24073-24094]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-07859]
=======================================================================
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63
[EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044; FRL-9789-5]
RIN 2060-AR62
Reconsideration of Certain New Source Issues: 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; notice of final action on reconsideration.
-----------------------------------------------------------------------
SUMMARY: The EPA is taking final action on its reconsideration of
certain issues in the final rules titled, ``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.'' The
National Emission Standards for Hazardous Air Pollutants (NESHAP) rule
issued pursuant to Clean Air Act (CAA) section 112 is referred to as
the Mercury and Air Toxics Standards (MATS) NESHAP, and the New Source
Performance Standards rule issued pursuant to CAA section 111 is
referred to as the Utility NSPS. The Administrator received petitions
for reconsideration of certain aspects of the MATS NESHAP and the
Utility NSPS.
On November 30, 2012, the EPA granted reconsideration of, proposed,
and requested comment on a limited set of issues. We also proposed
certain technical corrections to both the MATS NESHAP and the Utility
NSPS. The EPA is now taking final action on the revised new source
numerical standards in the MATS NESHAP and the definitional and
monitoring provisions in the Utility NSPS that were addressed in the
[[Page 24074]]
proposed reconsideration rule. As part of this action, the EPA is also
making certain technical corrections to both the MATS NESHAP and the
Utility NSPS. The EPA is not taking final action on requirements
applicable during periods of startup and shutdown in the MATS NESHAP or
on startup and shutdown provisions related to the PM standard in the
Utility NSPS.
DATES: The effective date of the rule is April 24, 2013.
Docket. The EPA established two dockets for this action: Docket ID
EPA-HQ-OAR-2011-0044 (NSPS action) and Docket ID EPA-HQ-OAR-2009-0234
(MATS NESHAP action). All documents in the dockets are listed in the
https://www.regulations.gov index. Although listed in the index, some
information is not publicly available (e.g., confidential business
information (CBI) or other information whose disclosure is restricted
by statute). Certain other material, such as copyrighted material, will
be publicly available only in hard copy form. Publicly available docket
materials are available either electronically in https://www.regulations.gov or in hard copy at the EPA Docket Center, Room
3334, 1301 Constitution Avenue NW., Washington, DC. The Public Reading
Room 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) 566-1742.
FOR FURTHER INFORMATION CONTACT: For the MATS 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:
Outline. The information presented in this preamble is organized as
follows:
I. General Information
A. Does this action apply to me?
B. How do I obtain a copy of this document?
C. Judicial Review
II. Background
III. Summary of Today's Action
IV. Summary of Final Action and Changes Since Proposal--MATS NESHAP
New Source Issues
V. Summary of Final Action and Changes Since Proposal--Utility NSPS
VI. Technical Corrections and Clarifications
VII. Impacts of This Final Rule
A. Summary of Emissions Impacts, Costs and Benefits
B. What are the air impacts?
C. What are the energy impacts?
D. What are the compliance costs?
E. What are the economic and employment impacts?
F. What are the benefits of the final standards?
VIII. 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
D. Unfunded Mandates Reform Act
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 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?
Categories and entities potentially affected by today's action
include:
------------------------------------------------------------------------
Examples of potentially
Category NAICS code\1\ 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 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 to provide a
guide for readers regarding entities likely to be affected by this
action. To determine whether your facility, company, business,
organization, etc. would 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 63.9982. 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. How do I obtain a copy of this document?
In addition to being available in the docket, electronic copies of
these final rules will be available on the Worldwide Web (WWW) through
the Technology Transfer Network (TTN). Following signature, 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 the 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 June 24, 2013. 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
can be raised during judicial review. 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
the EPA to enforce these requirements.
II. Background
The final MATS NESHAP and the Utility NSPS rules were published in
the Federal Register at 77 FR 9304 on
[[Page 24075]]
February 16, 2012. Following promulgation of the final rules, the
Administrator received petitions for reconsideration of numerous
provisions of both the MATS NESHAP and the Utility NSPS pursuant to CAA
section 307(d)(7)(B). Copies of the MATS NESHAP petitions are provided
in rulemaking docket EPA-HQ-OAR-2009-0234. Copies of the Utility NSPS
petitions are provided in rulemaking docket EPA-HQ-OAR-2011-0044. On
November 30, 2012, the proposal granting reconsideration of certain
issues in the MATS NESHAP and Utility NSPS was published in the Federal
Register at 77 FR 71323.
III. Summary of Today's Action
This final action amends certain provisions of the final rule
issued by the EPA on February 16, 2012. Through an August 2, 2012,
notice (77 FR 45967), the EPA delayed the effective date of the
February 2012 MATS rule for new sources only. That stay was limited to
90 days and has since expired. The February 2012 final rule is and
remains in effect for all sources.
The November 30, 2012, proposed reconsideration rule proposed: (1)
Certain revised new source numerical standards in the MATS NESHAP, (2)
requirements applicable during periods of startup and shutdown in the
MATS NESHAP, (3) startup and shutdown provisions related to the
particulate matter (PM) standard in the Utility NSPS, and (4)
definitional and monitoring provisions in the Utility NSPS. We also
proposed certain technical corrections to both the MATS NESHAP and the
Utility NSPS. We are taking final action today on the revised numerical
new source MATS NESHAP limits, the definitional and monitoring issues
in the Utility NSPS, and all of the technical corrections not related
to startup/shutdown issues.
This summary of the final rule reflects the changes to 40 CFR Part
63, subpart UUUUU, and 40 CFR Part 60, subpart Da (77 FR 9304; February
16, 2012) made in this regard.
As noted above, in the proposed reconsideration rule, the EPA took
comment on the requirements in the MATS NESHAP applicable during
startup and shutdown, including the definitions of startup and
shutdown. The EPA also took comment on the startup and shutdown
provisions relating to the PM standard in the Utility NSPS. The EPA
received considerable comments regarding these startup and shutdown
provisions, including data and information relevant to the proposed
work practice standard that applies in such periods. The EPA is not
taking final action on the startup and shutdown provisions at this time
as it needs additional time to consider and evaluate the comments and
data provided.\1\ The Agency is currently reviewing all of the comments
received on the startup and shutdown issues and intends to act promptly
to address these issues. We note that no existing sources will have to
comply with the existing source MATS standards before April 16, 2015.
Further, no new sources are currently under construction and it takes
years to complete construction. 77 FR 71330, fn. 7. As such, there will
be sufficient time for the Agency to review the comments submitted
concerning the proposed startup and shutdown provisions and take
appropriate action well in advance of any new source being subject to
those provisions.
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\1\ The EPA is also still reviewing the other issues raised in
the petitions for reconsideration and is not taking any action at
this time with respect to those issues.
---------------------------------------------------------------------------
As described below, on the basis of information provided since the
reconsideration proposal, today's action revises certain new source
numerical limits in the MATS NESHAP. Specifically, the EPA is
finalizing revised hydrogen chloride (HCl), filterable PM (fPM),\2\
sulfur dioxide (SO2), lead (Pb), and selenium emission
limits for all new coal-fired EGUs; the mercury (Hg) emission limit for
the ``unit designed for coal >= 8,300 Btu/lb subcategory;'' fPM and
SO2 emission limits for new solid oil-derived fuel-fired
EGUs; fPM emission limits for new continental liquid oil-fired EGUs;
and most of the emission limits for new integrated gasification
combined cycle (IGCC) units.
---------------------------------------------------------------------------
\2\ As the final MATS rule established a filterable PM (fPM)
limit, every reference in this preamble to a PM limit means
filterable PM.
---------------------------------------------------------------------------
The fPM, HCl, and Hg limits that we are finalizing in this action
are provided in table 1; the alternate limits that we are finalizing
are provided in table 2.\3\
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\3\ The final rule included certain alternative limits (see 77
FR 9367-9369).
Table 1--Revised Emission Limitations for New EGUs
----------------------------------------------------------------------------------------------------------------
Filterable particulate Hydrogen chloride, lb/
Subcategory matter, lb/MWh MWh Mercury, lb/GWh
----------------------------------------------------------------------------------------------------------------
New--Unit not designed for low 9.0E-2................... 1.0E-2 \a\.............. 3.0E-3.
rank virgin coal.
New--Unit designed for low rank 9.0E-2................... 1.0E-2 \a\.............. NR.
virgin coal.
New--IGCC........................ 7.0E-2 \b\............... 2.0E-3.................. 3.0E-3.
9.0E-2 \c\...............
New--Solid oil-derived........... 3.0E-2................... NR...................... NR.
New--Liquid oil--continental..... 3.0E-1................... NR...................... NR.
----------------------------------------------------------------------------------------------------------------
Note: lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012).
\a\ Beyond-the-floor value.
\b\ Duct burners on syngas; based on permit levels in comments received.
\c\ Duct burners on natural gas; based on permit levels in comments received.
Table 2--Revised Alternate Emission Limitations for New EGUs
----------------------------------------------------------------------------------------------------------------
Subcategory/pollutant Coal-fired EGUs IGCC \a\ Solid oil-derived
----------------------------------------------------------------------------------------------------------------
SO2.............................. 1.0 lb/MWh............... 4.0E-1 lb/MWh \b\....... 1.0 lb/MWh
Total non-mercury metals......... NR....................... 4.0E-1 lb/GWh........... NR
Antimony, Sb..................... NR....................... 2.0E-2 lb/GWh........... NR
Arsenic, As...................... NR....................... 2.0E-2 lb/GWh........... NR
[[Page 24076]]
Beryllium, Be.................... NR....................... 1.0E-3 lb/GWh........... NR
Cadmium, Cd...................... NR....................... 2.0E-3 lb/GWh........... NR
Chromium, Cr..................... NR....................... 4.0E-2 lb/GWh........... NR
Cobalt, Co....................... NR....................... 4.0E-3 lb/GWh........... NR
Lead, Pb......................... 2.0E-2 lb/GWh............ 9.0E-3 lb/GWh........... NR
Mercury, Hg...................... NA....................... NA...................... NR
Manganese, Mn.................... NR....................... 2.0E-2 lb/GWh........... NR
Nickel, Ni....................... NR....................... 7.0E-2 lb/GWh........... NR
Selenium, Se..................... 5.0E-2 lb/GWh............ 3.0E-1 lb/GWh........... NR
----------------------------------------------------------------------------------------------------------------
NA = not applicable.
NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012).
\a\ Based on best-performing similar source.
\b\ Based on DOE information.
In addition, in the MATS NESHAP the EPA is removing quarterly stack
testing as an option to demonstrate compliance with the new source fPM
emission limits; revising the way in which an owner or operator of a
new EGU who chooses to use PM continuous parameter monitoring systems
(CPMS) establishes an operating limit; requiring inspections and
retesting within 45 days of an exceedance of the operating limit for
those new EGU owners or operators who choose to use PM CPMS as a
compliance option; and finalizing the presumption of violation of the
emissions limit if more than 4 emissions tests are required in a 12-
month period.
The final changes to the numerical emissions limits noted above
incorporate information about the variability of the best performing
EGUs and more accurately reflect the capabilities of emission control
equipment for new EGUs. The final changes should also address
commenters' concerns that vendors of EGU emission controls had been
unwilling to provide guarantees regarding the ability to meet all of
the standards for new EGUs as originally finalized in February 2012.
We expect that source owners and operators will install and operate
the same or similar control technologies to meet the revised standards
in this reconsideration action as they would have chosen to comply with
the standards in the February 2012 final rule. Consistent with CAA
section 112(a)(4), we are maintaining the new source trigger date for
the MATS NESHAP rule as May 3, 2011. See 77 FR 71330, fn. 7. New
sources must comply with the revised MATS emission standards described
in section IV below by April 24, 2013, or startup, whichever is later.
In the February 2012 final Utility NSPS rule, the EPA adopted a
definition of natural gas that excludes coal-derived synthetic natural
gas consistent with the definition in MATS. In the Utility NSPS
reconsideration proposal, we re-proposed and requested comment on that
definition. Based on review of the comments received in response to the
reconsideration proposal, the EPA has concluded that the definition of
natural gas in the final Utility NSPS is appropriate and, therefore, is
not making any changes to that definition. We are also finalizing as
proposed one conforming amendment and two amendments related to EGUs
burning desulfurized coal-derived synthetic natural gas. First, we
amended the definition of coal to make it clear that coal-derived
synthetic natural gas is considered to be coal. In addition, in
recognition of the fact that emissions from the burning of desulfurized
coal-derived synthetic natural gas are very similar to those from the
burning of natural gas, we amended the opacity and SO2
monitoring provisions so that facilities burning desulfurized coal-
derived synthetic natural gas will have opacity and SO2
monitoring requirements similar to those of facilities burning natural
gas. Further, we are finalizing certain revisions to the definition of
IGCC in the Utility NSPS. We are also finalizing as proposed the
revised procedures for calculating PM emission rates intended to make
the Utility NSPS procedures consistent with those in the MATS NESHAP.
We did not receive any adverse comments regarding this proposed change.
Finally, we are finalizing as proposed the technical corrections to the
PM standards for facilities that commenced construction before March 1,
2005, and for facilities that commence modification after May 3, 2011.
The impacts of today's revisions on the costs and the benefits of
the final rule are minor. As noted above, we expect that source owners
and operators will install and operate the same or similar control
technologies to meet the revised standards in this action as they would
have chosen to comply with the standards in the February 2012 final
rule.
IV. Summary of Final Action and Changes Since Proposal--MATS NESHAP New
Source Issues
After consideration of the public comments received, the EPA has
made certain changes in this final action from the reconsideration
proposal. We address the most significant comments in this preamble.
However for a complete summary of the comments received on the issues
we are finalizing today and our responses thereto, please refer to the
memorandum ``National Emission Standards For Hazardous Air Pollutants
From Coal- And Oil-Fired Electric Utility Steam Generating Units--
Reconsideration; Summary Of Public Comments And Responses'' (March
2013) in rulemaking docket EPA-HQ-OAR-2009-0234.
In this action, we are finalizing certain new source emission
limits for the MATS NESHAP, as discussed below.
1. Changes to Certain New Source MATS NESHAP Limits
Commenters noted that in two instances, Pb emissions from coal-
fired EGUs and the fPM emissions from continental liquid oil-fired
EGUs, the EPA had proposed new source emission limits that were less
stringent than those in the final MATS NESHAP for the respective
existing sources. This approach was inconsistent with that taken in the
final MATS NESHAP.\4\ Although CAA section 112(d)(3) allows existing
source MACT floor limits to be less stringent than new source limits,
the EPA interprets this provision as
[[Page 24077]]
precluding new source limits from being less stringent than existing
source limits. See CAA section 112(d)(3). Thus, for Pb emissions from
coal-fired EGUs and fPM emissions from continental liquid oil-fired
EGUs, the EPA is finalizing new source limits that are equivalent to
the final existing-source limits.
---------------------------------------------------------------------------
\4\ See ``National Emission Standards for Hazardous Air
Pollutants (NESHAP) Maximum Achievable Control Technology (MACT)
Floor Analysis for Coal- and Oil-fired Electric Utility Steam
Generating Units for Final Rule,'' Docket ID EPA-HQ-OAR-2009-0234-
20132, p. 13.
---------------------------------------------------------------------------
Next, commenters noted that when evaluating SO2
emissions data from coal-fired EGUs, the EPA had not selected the
lowest emitting source upon which to base the emission limit and that
its rationale for excluding certain data was unlawful and arbitrary.
Although the EPA disagrees with commenters on several of the excluded
data sets (i.e., some of the data sets suggested by commenters
comprised only a single 3-run average for each EGU with no individual
run data, making assessment of variability impossible), it agrees that
it inadvertently omitted the data from Stanton Unit 10 in the proposal
analyses. Stanton Unit 10 does have a lower ``lowest'' 3-run data
average than does the EGU selected for the new source floor analysis
(Sandow Unit 5A) in the proposed reconsideration rule.
In this final action, the EPA used the Stanton data to calculate
the MACT floor using the same statistical analyses used in the proposed
rule (i.e., 99 percent upper predictive limit (UPL)), and the resulting
MACT floor emission limit is 1.3 pounds per megawatt-hour (lb/MWh).
Because this limit is less stringent than the new source performance
standard (NSPS) finalized in the Utility NSPS (77 FR 9451; February 16,
2012), the EPA is finalizing a beyond-the-floor (BTF) MACT standard of
1.0 lb/MWh, which is the same level required by the CAA section 111
NSPS for these same sources.\5\ See 40 CFR 60.43Da(l)(1)(i). Cost is a
required consideration in establishing CAA section 111 rules and in
going BTF in establishing CAA section 112 rules. We evaluated cost in
assessing whether to go BTF for this standard and concluded that it was
appropriate to go BTF to a level of 1.0 lb/MWh. Moreover, the NSPS
limit (also 1.0 lb/MWh) is in place and coal-fired EGUs are required to
comply with that limit. As such, there is no additional cost to these
sources.\6\ Furthermore, we have not identified any non-air quality
health or environmental impacts or energy requirements associated with
the final standard set at this level. In addition, in support of the
proposed reconsideration rule, we evaluated an emissions level more
stringent than 1.0 lb/MWh and found that level to not be cost
effective.\7\ For these reasons, we are finalizing 1.0 lb/MWh as the
new source MATS NESHAP limit.
---------------------------------------------------------------------------
\5\ The CAA section 111 standard is based on the performance of
EGUs with the best performing SO2 controls, a reasonable
incremental cost effectiveness of less than $1,000 per ton of
SO2 controlled, and controls that result in minimal
secondary environmental and energy impacts.
\6\ The final Utility NSPS limit was not challenged and coal-
fired EGUs constructed after May 3, 2011, must meet that limit.
\7\ See Docket ID EPA-HQ-OAR-2009-0234-20221 and National
Emission Standards for Hazardous Air Pollutants (NESHAP) Beyond the
Maximum Achievable Control Technology (MACT) Floor (`Beyond-the-
Floor') Analysis for Revised Emission Standards for New Source Coal-
and Oil-fired Electric Utility Steam Generating Units also in the
rulemaking docket.
---------------------------------------------------------------------------
In the proposed reconsideration rule, we indicated that detection
level issues may arise from using a sorbent trap when short sampling
periods (e.g., 30 minutes) are used. As such, the EPA solicited comment
on its establishment of a Representative Detection Level (RDL)
associated with Hg sorbent traps. The EPA also solicited comment on
whether the UPL calculated floor should be compared against the 3XRDL
value for Hg to account for the shorter sampling periods (the 3XRDL
approach). The EPA received several comments, ranging from strong
support for the Hg RDL and the proposed emission limit because, at that
level, the commenters asserted that vendors would be able to provide
commercial guarantees, to concerns about the specific inputs to the
3XRDL calculation and the application of the 3xRDL approach. See
section 2.2.1 of the response to comments document (RTC) for a more
complete discussion and response to these comments.
In the proposed reconsideration rule, the EPA recognized that 30
minutes of sample collection is the shortest reasonable amount of time
available for collecting and changing sorbent tubes to provide the
quick, reliable feedback that will allow sources to react to changing
Hg emissions levels and assure compliance with the final Hg limit. Some
commenters pointed out that the EPA's memorandum entitled
``Determination of Representative Detection Level (RDL) and 3 X RDL
Values for Mercury Measured Using Sorbent Trap Technologies,'' \8\
contains a 30-minute sample collection time in the 3XRDL calculation,
but the text of the memorandum references a 20-minute sample collection
time. The EPA has revised the text of the memorandum to reflect its
original intent, which was to focus on a sample collection period of 30
minutes (not 20 minutes). The revised memorandum focuses on the 30-
minute sample collection period. Given that it takes 5 minutes for
sorbent trap insertion and removal, it would take a total of 40 minutes
to secure the requisite sample collection (30 minutes for sample
collection, 5 minutes to remove the sorbent trap, and 5 minutes to re-
insert the trap). We are finalizing the Hg limit using the 3XRDL
approach assuming a 30-minute sampling time.
---------------------------------------------------------------------------
\8\ The EPA developed the memorandum to determine appropriate
RDL and 3XRDL values for sorbent trap monitoring systems, as well as
calculate an emissions limit, in order to determine the shortest,
reasonable sample collection period for those systems. See EPA
Docket ID EPA-HQ-OAR-2009-0234-20222.
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2. Filterable PM Testing, Monitoring, and Compliance
Certification for New EGUs in the MATS NESHAP Rule
Several monitoring options for the fPM standard for new sources
were provided in the MATS NESHAP final rule, including quarterly stack
testing, PM CEMS, and PM CPMS with annual testing.
The EPA sought comment on whether to retain the quarterly stack
testing compliance option for new EGUs, given that continuous, direct
measurement of fPM or a correlated parameter is available, is
preferable for determining compliance on a continuous basis, and is
likely to be used by most new EGUs to monitor compliance with the
proposed new source standards. As mentioned above, this final action
does not retain the quarterly fPM performance testing option for new
EGUs. New EGUs can be designed to incorporate PM CEMS or PM CPMS from
the outset, without being impeded by retrofit location installation
constraints that could impact existing EGUs. This final action now
requires new sources to use either PM CEMS or PM CPMS as options for
determining compliance with the new source fPM limits.
The EPA requested comment on a number of issues associated with PM
CPMS. The EPA first solicited comment on three approaches to establish
an operating limit based on emissions testing for those EGU owners or
operators who choose to use PM CPMS as the means of demonstrating
compliance with the fPM emission limit. The first approach would
require an EGU owner or operator to use the highest parameter value
obtained during any run of an individual emissions test as the
operating limit when the result of that individual test was below the
limit. The second approach would require an EGU owner or operator to
use the average parameter value obtained from
[[Page 24078]]
all runs of an individual emissions test as the operating limit,
provided that the result of the individual emissions test met the
emissions limit. The third approach, which the EPA is finalizing in
this final action, would require an EGU owner or operator to use the
higher of the following: (1) A parameter scaled from all values
obtained during an individual emissions test to 75 percent of the
emissions limit or (2) the average parameter value obtained from all
runs of an individual emissions test as the operating limit provided
that the result of the individual emissions test met the emissions
limit. As established and reaffirmed in the recent Sewage Sludge
Incineration, Major Source Industrial Boiler, and Portland Cement
rules,\9\ it is appropriate to provide increased operational
flexibility and reduced emissions testing for sources that emit at or
below 75 percent of a standard--whether an emissions or operating
limit--as these are the lowest emitting sources. Reduced emissions
testing is available in this final rule for those owners or operators
whose EGU emissions do not exceed this 75 percent threshold. This 75
percent threshold allows for compliance flexibility and is
simultaneously protective of the emission standards. The EPA believes
well performing EGUs, i.e., those whose emissions do not exceed 75
percent of the emissions limit, should not face additional scrutiny or
testing consequences provided their emissions remain equivalent to or
below the 75 percent threshold. In this final action, the EPA uses the
75 percent threshold so as not to impose unintended and costly retest
requirements for the lowest emitting sources and to provide for more
cost effective, continuous, PM parametric monitoring across the EGU
sector. This approach was selected from the options considered as it
provides the greatest amount of EGU owner or operator flexibility while
demonstrating continuous compliance for EGUs. With this parametric
monitoring approach in place, the EPA expects EGUs to evaluate control
options that provide excellent fPM emissions control and provide them
greater operational flexibility.
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\9\ See Standards of Performance for New Stationary Sources and
Emission Guidelines for Existing Sources: Commercial and Industrial
Solid Waste Incineration Units, 76 FR 15736 (March 21, 2011);
Subpart DDDDD--National Emission Standards for Hazardous Air
Pollutants for Major Sources: Industrial, Commercial, and
Institutional Boilers and Process Heaters, 40 CFR 63.7515(b); and
National Emission Standards for Hazardous Air Pollutants for the
Portland Cement Manufacturing Industry and Standards of Performance
for Portland Cement Plants, 78 FR 10014 (February 12, 2013).
---------------------------------------------------------------------------
Moreover, after each exceedance of the operating limit, the EPA
proposed to require emissions testing to verify or re-adjust the
operating limit, consistent with the approach contained in the
recently-promulgated Portland cement MACT standard (see 78 FR 10014).
One commenter objected to potential frequent emissions testing to
reassess the operating limit and then being subject to a violation of
the emissions limit. The EPA does not believe that too-frequent testing
will be required. As discussed in section 4.3.5 of the RTC, the EPA
believes well-designed emissions testing will provide an operating
limit corresponding with EGU operation, and such testing should yield
an operating limit that would not be expected to be exceeded during the
course of EGU operation. Therefore, an operating limit developed from
well-designed emissions testing should have little, if any, need for
frequent reassessment via emissions testing more frequently than the
mandated annual reassessment because the source will be able to meet
the limit on an ongoing basis.
Finally, the EPA proposed that PM CPMS exceedances leading to more
than 4 required emissions tests in a 12-month period (rolling monthly)
would be presumed (subject to the possibility of rebuttal by the EGU
owner or operator) to be a violation of the emissions limit, consistent
with the approach contained in the newly-promulgated Portland cement
MACT standard (see 78 FR 10014). The EPA received a number of comments
on this proposed provision, including comments supporting and opposing
the establishment of such a presumption.
The EPA disagrees with those comments opposing the presumptive
violation, and believes the presumptive violation provision in the
final rule is a reasonable and appropriate approach to ensure
compliance with the standard. First, the EPA may permissibly establish
such an approach by rule, assuming there is a reasonable factual basis
to do so. See Hazardous Waste Treatment Council v. EPA, 886 F. 2d 355,
367-68 (DC Cir. 1989) (explaining that such presumptions can
legitimately establish the elements of the EPA's prima facie case in an
enforcement action). Second, there is a reasonable basis here for the
presumption that four exceedances (i.e., increases over the parametric
operating limit) in a calendar year are a violation of the emission
standard. The parametric monitoring limit is established as a 30-day
average of the averaged test value in the performance test, or the 75th
percentile value if that is higher. In either instance, the 30-day
averaging feature provides significant leeway to the EGU owner or
operator not to deviate from the parametric operating level because the
impact of transient peaks or valleys is limited due to the length of
the rule's averaging period--30 boiler operating days, rolled daily.
See 77 FR 42377/2 and sources there cited. See also 78 FR 10015, 10019;
February, 12, 2013 (Portland Cement MACT) and the RTC for today's
action.
The EPA also received comments addressing the re-testing
requirements following an exceedance. Some commenters expressed concern
about the burden of requiring sources to conduct performance tests in
order to demonstrate compliance and to reassess the parameter level. In
contrast, other commenters supported a requirement to require re-
testing but claimed that the time period between observing a parameter
exceedance and retesting is too long. The EPA believes that the re-
testing requirements are reasonable and appropriate to identify non-
compliance without imposing undue burden. For even a single exceedance
to occur, the 30-day average would have to be higher than the operating
limit established for the PM CPMS during normal EGU operation. If that
occurs, then the EGU owner or operator is required to conduct an
inspection to determine any abnormalities and an emissions test to re-
establish or generate a new operating limit. Given that EGUs and their
emissions control devices are designed to operate at known, specific
conditions, deviations from these conditions are not expected and are
indicative of problems with load, controls, or some combination of
both. Where these sorts of problems result in an exceedance of the
source's operating limit, it is reasonable to require re-testing in
order to identify and then correct problems. More than four such
exceedances of the 30-day average would mean that the EGU owner or
operator was unable to determine or correct the problem, since
inspection and re-calculation of the operating limit is required after
each exceedance. This indicates an ongoing problem with maintaining
process control and/or control device operation, which would be the
basis for a presumptive violation of the emissions standard. Moreover,
the EPA disagrees that the period between exceedance of the operating
limit and retesting is too long and could result in possible excessive
emissions. Specifically, some commenters claimed that the final rule
should not limit the number of exceedances of the PM CPMS limit that
require follow-up performance tests in any 12-month period. These
commenters alleged that to do so does
[[Page 24079]]
not ensure continuous compliance because the time period between an
exceedance and testing could be too long, and a source could be
exceeding the emission limit during that time period. The EPA believes
that the re-testing requirements reflect a reasonable balance between
ensuring compliance and limiting unnecessary testing burden on
regulated sources. An EGU owner or operator is required to visually
inspect the air pollution control device within 48 hours of the
exceedance, and corrective action must be taken as soon as possible to
return the PM CPMS measurement to within the established value. A
performance test is also required within 45 days of the exceedance to
determine compliance and verify or re-establish the PM CPMS limit.
Thus, the EPA finds it unlikely that there will be long periods of
noncompliance with the underlying fPM standard given the inspection and
performance testing requirements.
The EPA also received comments stating that an EGU owner or
operator should not be labeled a ``violator'' of the fPM standard as a
result of a fourth compliance test in a 12-month period. First, the EPA
notes that the rule identifies more than 4 compliance tests over a 12-
month period as only a presumptive violation of the emissions limit. A
presumption of a violation is just that--a presumption--and can be
rebutted in any particular case.
Moreover, in determining whether the presumption has been
successfully rebutted, a Court may consider relevant information such
as data or other information showing that the EGU's operating process
remained in control during the period of operating parameter
exceedance, that the ongoing operation and maintenance conducted on the
EGU ensured its emissions control devices remained in proper operating
condition during the period of operating parameter exceedance, and that
results of emissions tests conducted while replicating the conditions
observed during the period of operating parameter exceedance remained
below the emission limit.
For the reasons explained above, this final action includes the
presumption of violation of the emissions limit if more than 4
emissions tests are required in a 12-month period.
V. Summary of Final Action and Changes Since Proposal--Utility NSPS
The EPA has made a number of changes from the reconsideration
proposal in this final action after consideration of the public
comments received. Most of the changes to the Utility NSPS clarify
applicability and implementation issues raised by the commenters. The
public comments received on the matters proposed for reconsideration
and the responses to them can be viewed in the memorandum ``Summary of
EGU NSPS Public Comments and Responses on Amendments Proposed November
30, 2012 (77 FR 71323)'' in rulemaking docket EPA-HQ-OAR-2011-0044.
In the proposed reconsideration rule, the EPA proposed a new
definition for IGCC which would be consistent with the MATS NESHAP
definition. However, as an alternative we requested comment on whether
to retain a definition similar, but not identical, to the IGCC
definition in the February 2012 final Utility NSPS. We have concluded
that the alternative approach is most appropriate and are adopting a
slightly revised definition that is consistent with the Agency's
statements on IGCC contained in the RTC in support of the final Utility
NSPS rule published on February 16, 2012 (77 FR 9304). Commenters
generally supported amending the final Utility NSPS definition of IGCC,
and this final action amends that definition consistent with the
statements made in the RTC for the Utility NSPS. The Utility NSPS IGCC
definition deals with the intent of an IGCC facility and is, thus,
broader than the definition in the MATS NESHAP. The facility would
still be subject to the same criteria pollutant emission standards even
when burning natural gas for extended periods of time. The MATS NESHAP
applicability is determined based on the EGU's utilization of coal and
oil and the rule may not apply depending on the extent of natural gas
usage.
The EPA proposed that the NSPS PM monitoring procedures be
consistent with the MATS NESHAP requirements and included the use of
quarterly stack testing, PM CPMS, or PM CEMS. In addition, the EPA
sought comment on whether to include the quarterly stack testing
compliance option for new EGUs, given that continuous, direct
measurement of PM or a correlated parameter is available. EGUs
complying with an output-based emissions standard can be designed to
incorporate PM CEMS or PM CPMS from the outset, without being impeded
by retrofit location installation constraints that would impact
existing EGUs. This final action requires EGUs complying with an
output-based standard to use either PM CEMS or PM CPMS as options for
determining compliance with the PM limits. Therefore, the EPA is
finalizing the same monitoring procedures for PM for the Utility NSPS
as for new sources subject to the MATS NESHAP, and is not finalizing
the quarterly stack testing option.
The EPA proposed that facilities using PM CPMS would be able to use
either a continuous opacity monitoring system or a periodic alternate
monitoring approach to monitor opacity. This final action does not
require facilities using a PM CPMS to conduct opacity monitoring. The
EPA has concluded that the use of a PM CPMS at the level of the
emissions standard required in subpart Da is sufficient to demonstrate
compliance with the opacity standard and that additional monitoring is
an unnecessary burden.
VI. Technical Corrections and Clarifications
On April 19, 2012 (77 FR 23399), the EPA issued a technical
corrections notice addressing certain corrections to the February 16,
2012 (77 FR 9304), MATS NESHAP and Utility NSPS. In the November 30,
2012, reconsideration proposal, we proposed several additional
technical corrections. Specific to the NSPS, we proposed correcting the
PM standard for facilities that commenced construction before March 1,
2005, to remove the extra significant digit that was inadvertently
added and to correct the PM standard for facilities that commence
modification after May 3, 2011, to be consistent with the original
intent as expressed in the RTC of the final rule published on February
16, 2012 (77 FR 9304). We did not receive any negative comments on
these issues and are finalizing them as proposed. Specific details are
included in Table 3.
Specific to the MATS NESHAP, the EPA requested comment on whether
the proposed technical corrections in Table 4 of the preamble provide
the intended accuracy, clarity, and consistency. As mentioned in
section 6.3 of the RTC, commenters supported the proposed changes on
equations 2a and 3a and this final action contains those changes. As
mentioned in section 6.3 of the RTC, commenters did not support the
change from a 30 to 60-day notification period for performance testing,
and that change was not made to the rule; however, a change to the
General Provisions applicability table was made to provide a consistent
30-day notification period. Commenters suggested changes to certain
definitions to make them more consistent with the Acid Rain rule
provisions, but, as described in section 6.4 of the RTC, these rule
changes were not made. These amendments are now being finalized to
correct inaccuracies and other inadvertent errors in the final rule and
to make the rule language
[[Page 24080]]
consistent with provisions addressed through this reconsideration.
The final technical changes are described in tables 3 and 4 of this
preamble.
Table 3--Miscellaneous Technical Corrections to 40 CFR Part 60, Subpart
Da
------------------------------------------------------------------------
Section of subpart Da Description of correction
------------------------------------------------------------------------
40 CFR 60.42Da(a)................. Correct the erroneous ``0.030'' to
the correct ``0.03''.
40 CFR 60.42Da(e)(1)(ii).......... Correct the erroneous conversion
``13 ng/J (0.015 lb/MMBtu)'' to the
correct ``6.4 ng/J (0.015 lb/
MMBtu)'' by amending the regulatory
text to specify that the
requirements in 40 CFR 60.42Da(c)
or (d), which includes two
additional alternative limits, are
available compliance alternatives
for modified facilities.
------------------------------------------------------------------------
Table 4--Miscellaneous Technical Corrections to 40 CFR Part 63, Subpart
UUUUU
------------------------------------------------------------------------
Section of subpart UUUUU Description of correction
------------------------------------------------------------------------
40 CFR 63.9982(a)................. Clarify the language to use the word
``or'' instead of ``and.''
40 CFR 63.9982(b) and (c)......... Correct the discrepancy between
63.9982(b) and (c) and 63.9985(a).
40 CFR 63.10005(d)(2)(ii)......... Correct the typographical error by
replacing the incorrect
``corresponding'' with the correct
``corresponds.''
40 CFR 63.10005(i)(4)(ii) and Revise to clarify the determination
(i)(5) and add 63.10005(i)(6). and measurement of fuel moisture
content.
40 CFR 63.10006(c)................ Correct the omission of solid oil-
derived fuel- and coal-fired EGUs
and IGCC EGUs and the omission of
section 10000(c).
40 CFR 63.10007(c)................ Correct the omission of section
63.10023 from the list of sections
to be followed in establishing an
operating limit.
40 CFR 63.10009(b)(2)............. Correct omission of the term
``boiler operating'' and clarify
the term ``Rti'' in Equation 2a.
40 CFR 63.10009(b)(3)............. Correct omission of the term
``system'' and clarify the term
``Rti'' in Equation 3a.
40 CFR 63.10010(j)(1)(i).......... Correct the typographical error to
use the correct word ``your''
instead of ``you.''
40 CFR 63.10030(b), (c), and (d).. Clarify the affected-source
language.
Change the period by which a
Notification of Intent to conduct a
performance test must be submitted
to conform to the General
Provisions.
40 CFR Section 63.10042........... Correct the typographical error in
the intended definition of ``unit
designed for coal >= 8,300 Btu/lb
subcategory'' by replacing the
erroneous ``>'' with the correct
``>=.''
Table 5 to Subpart UUUUU of Part Correct the typographical error in
63. footnote 4 by replacing the
erroneous ``>='' with the correct
``<=.''
Table 7 to Subpart UUUUU of Part Clarify the applicability of the
63. alternate 90-day average for Hg in
item 1.
Revise item 3 in the table to
clarify use of CMS for liquid oil-
fired EGUs.
Table 9 to Subpart UUUUU of Part Revise to clarify the period for
63. notification of conducting a
performance test from 60 to 30
days.
Section 4.1 to Appendix A to Correct the typographical error by
Subpart UUUUU of Part 63. replacing the incorrect citation to
``Sec. 63.10005(g)'' with the
correct ``Sec. 63.9984(f).''
Section 5.2.2.2 to Appendix A to Correct the typographical error by
Subpart UUUUU of Part 63. replacing the incorrect citation to
``Table A-4'' with the correct
``Table A-2''
Section 3.1.2.1.3 to Appendix B to Correct the typographical error by
Subpart UUUUU of Part 63. replacing the erroneous ``>='' with
the correct ``<=.''
Section 5.3.4 to Appendix B to Correct the section number from the
Subpart UUUUU of Part 63. incorrect ``5.3.4'' to the correct
``5.3.3.''
------------------------------------------------------------------------
VII. Impacts of This Final Rule
A. Summary of Emissions Impacts, Costs and Benefits
Our analysis shows that new EGUs would choose to install and
operate the same or similar air pollution control technologies in order
to meet the revised emission limits as would have been necessary to
meet the previously finalized standards. We project that this final
action will result in no significant change in costs, emission
reductions, or benefits.\10\ Even if there were changes in costs for
these EGUs, such changes would likely be small relative to both the
overall costs of the individual projects and the overall costs and
benefits of the final rule. Further, we believe that EGUs would put on
the same controls for this final action that they would have for the
original final MATS rule, so there should not be any incremental costs
related to this revision.
---------------------------------------------------------------------------
\10\ See Regulatory Impact Analysis for the Final Mercury and
Air Toxics Standards [EPA-452/R-11-011] (docket entry EPA-HQ-OAR-
2009-0234-20131) and Economic Impact Analysis for the Final
Reconsideration of the Mercury and Air Toxics Standards in
rulemaking docket EPA-HQ-OAR-2009-0234. As noted earlier, because on
an individual EGU-by-EGU basis we anticipate very similar costs, any
changes to the baseline since we finalized MATS (e.g., potential
impacts of the CSAPR decision) would not impact this determination.
---------------------------------------------------------------------------
B. What are the air impacts?
We believe that electric power companies will install the same or
similar control technologies to comply with the final standards in this
action as they would have installed to comply with the previously
finalized MATS standards. Accordingly, we believe that this final
action will not result in significant changes in emissions of any of
the regulated pollutants.
C. What are the energy impacts?
This final action is not anticipated to have an effect on the
supply, distribution, or use of energy. As previously stated, we
believe that electric power companies would install the same or similar
control technologies as they would have installed to comply with the
previously finalized MATS standards.
D. What are the compliance costs?
We believe there will be no significant change in compliance costs
as a result of this final action because electric
[[Page 24081]]
power companies would install the same or similar control technologies
as they would have installed to comply with the previously finalized
MATS standards. Moreover, we find no additional monitoring costs are
necessary to comply with this final action; however, as in any other
rule, EGU owners or operators may choose to conduct additional
monitoring (and incur its expense) for their own purposes.
E. What are the economic and employment impacts?
Because we expect that electric power companies would install the
same or similar control technologies to meet the standards finalized in
this action as they would have chosen to comply with the previously
finalized MATS standards, we do not anticipate that this final action
will result in significant changes in emissions, energy impacts, costs,
benefits, or economic impacts. Likewise, we believe this action will
not have any impacts on the price of electricity, employment or labor
markets, or the U.S. economy.
F. What are the benefits of the final standards?
As previously stated, the EPA anticipates the power sector will not
incur significant compliance costs or savings as a result of this
action and we do not anticipate any significant emission changes
resulting from this action. Therefore, there are no direct monetized
benefits or disbenefits associated with this action.
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
Under Executive Order (EO) 12866 (58 FR 51735; October 4, 1993),
this action is a ``significant regulatory action'' because it ``raises
novel legal or policy issues.'' Accordingly, the EPA submitted this
action to the Office of Management and Budget (OMB) for review under
Executive Orders 12866 and 13563 (76 FR 3821; January 21, 2011) and any
changes made in response to OMB recommendations have been documented in
the docket for this action.
In addition, the EPA prepared an analysis of the potential costs
and benefits associated with this action. This analysis is contained in
the ``Economic Impact Analysis for the Final Reconsideration of the
Mercury and Air Toxics Standards'' found in rulemaking docket EPA-HQ-
OAR-2009-0234. Because our analysis shows that new electricity
generating units would choose to install the same control technology in
order to meet the revised emission limits as would have been necessary
to meet the previously finalized MATS standards, we project that this
action will result in no significant change in costs, emission
reductions, or benefits.
B. Paperwork Reduction Act
This action does not impose any new information collection burden.
Today's action does not change the information collection requirements
previously finalized and, as a result, does not impose any additional
burden on industry. However, OMB has previously approved the
information collection requirements contained in the existing
regulations (see 77 FR 9304) under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control
number 2060-0567. The OMB control numbers for EPA's regulations are
listed in 40 CFR part 9 and 48 CFR chapter 15.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act 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 not-for-profit
enterprises, and small governmental jurisdictions.
For purposes of assessing the impacts of today's action on small
entities, a small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district, or special district with a
population of less that 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. Categories and entities potentially
regulated by the final rule with applicable NAICS codes are provided in
the Supplementary Information section of this action.
According to the SBA size standards for NAICS code 221122
Utilities-Fossil Fuel Electric Power Generation, a firm is small if,
including its affiliates, it is primarily engaged in the generation,
transmission, and or distribution of electric energy for sale and its
total electric output for the preceding fiscal year did not exceed 4
million MWh.
After considering the economic impacts of today's action on small
entities, I certify that the notice will not have a significant
economic impact on a substantial number of small entities.
The EPA has determined that none of the small entities will
experience a significant impact because the action imposes no
additional regulatory requirements on owners or operators of affected
sources. We have therefore concluded that today's action will not
result in a significant economic impact on a substantial number of
small entities.
D. Unfunded Mandates Reform Act
This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for State, local, or tribal governments or the private
sector. The action imposes no enforceable duty on any State, local, or
tribal governments or the private sector. Therefore, this action is not
subject to the requirements of UMRA sections 202 or 205.
This action is also not subject to the requirements of UMRA section
203 because it contains no regulatory requirements that might
significantly or uniquely affect small governments because it contains
no requirements that apply to such governments or impose obligations
upon them.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in EO 13132. None of the affected facilities are owned or
operated by state governments, and the requirements discussed in
today's notice will not supersede state regulations that are more
stringent. Thus, EO 13132 does not apply to today's notice of
reconsideration.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications. It will not have
substantial direct effects on tribal governments, on the relationship
between the Federal government and Indian tribes, or on the
distribution of power and responsibilities between the Federal
government and Indian tribes, as specified in EO 13175. No affected
[[Page 24082]]
facilities are owned or operated by Indian tribal governments. Thus, EO
13175 does not apply to today's action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to EO 13045 (62 FR 19885; April 23,
1997) because it is not economically significant as defined in EO
12866. The EPA has evaluated the environmental health or safety effects
of the final MATS on children. The results of the evaluation are
discussed in that final rule (77 FR 9304; February 16, 2012) and are
contained in rulemaking docket EPA-HQ-OAR-2009-0234.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in EO
13211 (66 FR 28355; May 22, 2001) because it is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. Further, we conclude that today's action is not likely to have
any adverse energy effects because it is not expected to impose any
additional regulatory requirements on the owners of affected
facilities.
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 EPA
to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impracticable. Voluntary consensus
standards are technical standards (e.g., material specifications, test
methods, sampling procedures, business practices) developed or adopted
by one or more voluntary consensus bodies. The NTTAA requires EPA to
provide Congress, through the OMB, with explanations when EPA decides
not to use available and applicable voluntary consensus standards.
During the development of the final MATS rule, the EPA searched for
voluntary consensus standards that might be applicable. The search
identified three voluntary consensus standards that were considered
practical alternatives to the specified EPA test methods. An assessment
of these and other voluntary consensus standards is presented in the
preamble to the final MATS rule (77 FR 9441; February 16, 2012).
Today's action does not make use of any additional technical standards
beyond those cited in the final MATS rule. Therefore, the EPA is not
considering the use of any additional voluntary consensus standards for
this action.
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. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice 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 United States.
The EPA has determined that this action will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. Our analysis shows that new EGUs would choose to install
the same control technology in order to meet the revised emission
limits as would have been necessary to meet the previously finalized
standard. Under the relevant assumptions, we project that this action
will result in no significant change in emission reductions.
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
United States. The EPA will submit a report containing this final
action and other required information to the U.S. Senate, the U.S.
House of Representatives, and the Comptroller General of the United
States 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 not a ``major rule'' as defined by
5 U.S.C. 804(2). This rule will be effective April 24, 2013.
List of Subjects in 40 CFR Parts 60 and 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.
Dated: March 28, 2013.
Bob Perciasepe,
Acting Administrator.
For the reasons discussed in the preamble, 40 CFR parts 60 and 63
are amended to read as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
0
2. Amend Sec. 60.41Da by revising the definitions of ``Coal'' and
``Integrated gasification combined cycle electric utility steam
generating unit,'' and by adding the definition of ``Natural gas'' in
alphabetical order to read as follows:
Sec. 60.41Da Definitions.
* * * * *
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17) and
coal refuse. Synthetic fuels derived from coal for the purpose of
creating useful heat, including but not limited to solvent-refined
coal, gasified coal, coal-oil mixtures, and coal-water mixtures are
included in this definition for the purposes of this subpart.
* * * * *
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, startup and commissioning, shutdown,
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
[[Page 24083]]
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
3. Amend Sec. 60.42Da by revising paragraphs (a), (b)(2), and (e)(1)
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 (0.03 lb/MMBtu)
heat input.
(b) * * *
(2) An owner or operator of an affected facility that combusts only
natural gas and/or synthetic natural gas that chemically meets the
definition of natural gas is exempt from the opacity standard specified
in paragraph (b) of this section.
* * * * *
(e) * * *
(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, the owner or operator shall not cause to be discharged
into the atmosphere from that affected facility 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:
(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, the
emission limits specified in paragraphs (c) or (d) of this section.
* * * * *
0
4. Amend Sec. 60.48Da by revising paragraphs (f), (o) introductory
text, (o)(1), (o)(2) introductory text, (o)(3) introductory text,
(o)(3)(i), and (o)(4) introductory text to read as follows:
Sec. 60.48Da Compliance provisions.
* * * * *
(f) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, compliance with the
applicable daily average PM emissions limit is determined by
calculating the arithmetic average of all hourly emission rates each
boiler operating day, except for data obtained during startup,
shutdown, or malfunction periods. Daily averages must be calculated for
boiler operating days that have out-of-control periods totaling no more
than 6 hours of unit operation during which the standard applies. For
affected facilities for which construction or reconstruction commenced
after May 3, 2011, that elect to demonstrate compliance using PM CEMS,
compliance with the applicable PM emissions limit in Sec. 60.42Da is
determined on a 30-boiler operating day rolling average basis by
calculating the arithmetic average of all hourly PM emission rates for
the 30 successive boiler operating days, except for data obtained
during periods of startup or shutdown.
* * * * *
(o) Compliance provisions for sources subject to Sec.
60.42Da(c)(2), (d), or (e)(1)(ii). Except as provided for in paragraph
(p) of this section, the owner or operator must demonstrate compliance
with each applicable emissions limit according to the requirements in
paragraphs (o)(1) through (o)(5) of this section.
(1) You must conduct a performance test to demonstrate initial
compliance with the applicable PM emissions limit in Sec. 60.42Da by
the applicable date specified in Sec. 60.8(a). Thereafter, you must
conduct each subsequent performance test within 12 calendar months
following the date the previous performance test was required to be
conducted. You must conduct each performance test according to the
requirements in Sec. 60.8 using the test methods and procedures in
Sec. 60.50Da. The owner or operator of an affected facility that has
not operated for 60 consecutive calendar days prior to the date that
the subsequent performance test would have been required had the unit
been operating is not required to perform the subsequent performance
test until 30 calendar days after the next boiler operating day.
Requests for additional 30 day extensions shall be granted by the
relevant air division or office director of the appropriate Regional
Office of the U.S. EPA.
(2) You must monitor the performance of each electrostatic
precipitator or fabric filter (baghouse) operated to comply with the
applicable PM emissions limit in Sec. 60.42Da using a continuous
opacity monitoring system (COMS) according to the requirements in
paragraphs (o)(2)(i) through (vi) unless you elect to comply with one
of the alternatives provided in paragraphs (o)(3) and (o)(4) of this
section, as applicable to your control device.
* * * * *
(3) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of an electrostatic precipitator (ESP) operated
to comply with the applicable PM emissions limit in Sec. 60.42Da using
an ESP predictive model developed in accordance with the requirements
in paragraphs (o)(3)(i) through (v) of this section.
(i) You must calibrate the ESP predictive model with each PM
control device used to comply with the applicable PM emissions limit in
Sec. 60.42Da operating under normal conditions. In cases when a wet
scrubber is used in combination with an ESP to comply with the PM
emissions limit, the wet scrubber must be maintained and operated.
* * * * *
(4) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of a fabric filter (baghouse) operated to
comply with the applicable PM emissions limit in Sec. 60.42Da by using
a bag leak detection system according to the requirements in paragraphs
(o)(4)(i) through (v) of this section.
* * * * *
0
5. Amend Sec. 60.49Da by:
0
a. Revising paragraphs (a) introductory text;
0
b. Adding paragraph (a)(3)(iv); and
0
c. Revising paragraphs (a)(4), (b) introductory text, and (t).
The revised and added text reads as follows:
Sec. 60.49Da Emission monitoring.
(a) An owner or operator of an affected facility subject to the
opacity standard in Sec. 60.42Da must monitor the opacity of emissions
discharged from the affected facility to the atmosphere according to
the applicable requirements in paragraphs (a)(1) through (4) of this
section.
* * * * *
(3) * * *
(iv) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to
[[Page 24084]]
performing subsequent Method 9 of appendix A-4 performance tests, elect
to perform subsequent monitoring using a digital opacity compliance
system according to a site-specific monitoring plan approved by the
Administrator. The observations must be similar, but not necessarily
identical, to the requirements in paragraph (a)(3)(iii) of this
section. For reference purposes in preparing the monitoring plan, see
OAQPS ``Determination of Visible Emission Opacity from Stationary
Sources Using Computer-Based Photographic Analysis Systems.'' This
document is available from the U.S. Environmental Protection Agency
(U.S. EPA); Office of Air Quality and Planning Standards; Sector
Policies and Programs Division; Measurement Policy Group (D243-02),
Research Triangle Park, NC 27711. This document is also available on
the Technology Transfer Network (TTN) under Emission Measurement Center
Preliminary Methods.
* * * * *
(4) An owner or operator of an affected facility that is subject to
an opacity standard under Sec. 60.42Da 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 and/or liquid fuels
(excluding residue oil) where the potential SO2 emissions
rate of each fuel is 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. 60.51Da(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 must install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring SO2 emissions, except where only
gaseous and/or liquid fuels (excluding residual oil) where the
potential SO2 emissions rate of each fuel is 26 ng/J (0.060
lb/MMBtu) or less are combusted, as follows:
* * * * *
(t) The owner or operator of an affected facility demonstrating
compliance with the output-based emissions limit under Sec. 60.42Da
must either install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section or install, calibrate, operate, and maintain a PM CPMS
according to the requirements for new facilities specified in subpart
UUUUU of part 63 of this chapter. 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.
* * * * *
0
6. Revise Sec. 60.50Da(f) to read as follows:
Sec. 60.50Da Compliance determination procedures and methods.
* * * * *
(f) The owner or operator of an electric utility combined cycle gas
turbine that does not meet the definition of an IGCC must conduct
performance tests for PM, SO2, and NOX using the
procedures of Method 19 of appendix A-7 of this part. The
SO2 and NOX emission rates calculations from the
gas turbine used in Method 19 of appendix A-7 of this part are
determined when the gas turbine is performance tested under subpart GG
of this part. The potential uncontrolled PM emission rate from a gas
turbine is defined as 17 ng/J (0.04 lb/MMBtu) heat input.
* * * * *
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
7. The authority citation for 40 CFR Part 63 continues to read as
follows:
Authority: 42 U.S.C. 7401, et seq.
0
8. In Sec. 63.9982, revise paragraphs (a) introductory text, (b), and
(c) to read as follows:
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, or existing affected source(s) as described in
paragraphs (a)(1) and (2) of this section within a contiguous area and
under common control.
* * * * *
(b) An EGU is new if you commence construction of the coal- or oil-
fired EGU after May 3, 2011.
(c) An EGU is reconstructed if you meet the reconstruction criteria
as defined in Sec. 63.2, and if you commence reconstruction after May
3, 2011.
* * * * *
0
9. In Sec. 63.10000, revise paragraphs (c)(1)(iv) and (c)(2)(ii) to
read as follows:
Sec. 63.10000 What are my general requirements for complying with
this subpart?
* * * * *
(c) * * *
(1) * * *
(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, for an existing EGU, compliance performance testing
repeated quarterly.
* * * * *
(c) * * *
(2) * * *
(ii) If your 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, for an existing EGU,
performance testing conducted quarterly.
* * * * *
0
10. Amend Sec. 63.10005 by:
0
a. Revising paragraphs (d)(2)(ii), (i)(4)(ii) and (i)(5);
0
b. Adding paragraph (i)(6).
The revised and added text read as follows:
Sec. 63.10005 What are my initial compliance requirements and by what
date must I conduct them?
* * * * *
(d) * * *
(2) * * *
(ii) You must demonstrate continuous compliance with the PM CPMS
site-specific operating limit that corresponds to the results of the
performance test
[[Page 24085]]
demonstrating compliance with the emission limit with which you choose
to comply.
* * * * *
(i) * * *
(4) * * *
(ii) ASTM D4006-11, ``Standard Test Method for Water in Crude Oil
by Distillation,'' including Annex A1 and Appendix A1.
* * * * *
(5) Use one of the following methods to obtain fuel moisture
samples:
(i) 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
(ii) ASTM D4057-06 (Reapproved 2011), ``Standard Practice for
Manual Sampling of Petroleum and Petroleum Products,'' including Annex
A1.
(6) 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.
* * * * *
0
11. In Sec. 63.10006, revise paragraph (c) to read as follows:
Sec. 63.10006 When must I conduct subsequent performance tests or
tune-ups?
* * * * *
(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 emissions limit, for liquid oil-, solid
oil-derived fuel-, coal-fired and IGCC EGUs, you must conduct all
applicable periodic emissions tests for filterable PM, individual, or
total HAP metals emissions according to Table 5 to this subpart, Sec.
63.10007, and Sec. 63.10000(c), except as otherwise provided in Sec.
63.10021(d)(1).
* * * * *
0
12. In Sec. 63.10007, revise paragraph (c) to read as follows:
Sec. 63.10007 What methods and other procedures must I use for the
performance tests?
* * * * *
(c) If you choose the filterable PM method to comply with the PM
emission limit and demonstrate continuous performance using a PM CPMS
as provided for in Sec. 63.10000(c), you must also establish an
operating limit according to Sec. 63.10011(b), Sec. 63.10023, 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.
* * * * *
0
13. In Sec. 63.10009, revise paragraphs (b)(2) and (b)(3) to read as
follows:
Sec. 63.10009 May I use emissions averaging to comply with this
subpart?
* * * * *
(b) * * *
(2) Weighted 30-boiler operating 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] TR24AP13.006
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 = Total heat input or gross electrical output of unit
i for the preceding 30-boiler operating days, and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[GRAPHIC] [TIFF OMITTED] TR24AP13.007
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 ``coal-fired unit not low
rank virgin coal'' subcategory. Use equation 3a or 3b to calculate the
90-day rolling average emissions daily.
[GRAPHIC] [TIFF OMITTED] TR24AP13.008
[[Page 24086]]
Where:
Heri = hourly emission rate from unit i's CEMS or Hg
sorbent trap monitoring system 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 = Total heat input or gross electrical output of unit
i for the preceding 90-boiler operating days, and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[GRAPHIC] [TIFF OMITTED] TR24AP13.009
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.
* * * * *
0
14. In Sec. 63.10010, revise paragraph (j)(1)(i) to read as follows:
Sec. 63.10010 What are my monitoring, installation, operation, and
maintenance requirements?
* * * * *
(j) * * *
(1) * * *
(i) Install and certify your HAP metals CEMS according to the
procedures and requirements in your 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.
* * * * *
0
15. Amend Sec. 63.10021 by adding paragraphs (c)(1) and (2) to read as
follows:
Sec. 63.10021 How do I demonstrate continuous compliance with the
emission limitations, operating limits, and work practice standards?
* * * * *
(c) * * *
(1) For any exceedance of the 30-boiler operating day PM CPMS
average value from the established operating parameter limit for an EGU
subject to the emissions limits in Table 1 to this subpart, you must:
(i) Within 48 hours of the exceedance, visually inspect the air
pollution control device (APCD);
(ii) If the inspection of the APCD identifies the cause of the
exceedance, take corrective action as soon as possible, and return the
PM CPMS measurement to within the established value; and
(iii) Within 45 days of the exceedance or at the time of the annual
compliance test, whichever comes first, conduct a PM emissions
compliance test to determine compliance with the PM emissions limit and
to verify or re-establish the CPMS operating limit. You are not
required to conduct any additional testing for any exceedances that
occur between the time of the original exceedance and the PM emissions
compliance test required under this paragraph.
(2) PM CPMS exceedances of the operating limit for an EGU subject
to the emissions limits in Table 1 of this subpart leading to more than
four required performance tests in a 12-month period (rolling monthly)
constitute a separate violation of this subpart.
* * * * *
0
16. In Sec. 63.10023, revise paragraph (b) to read as follows:
Sec. 63.10023 How do I establish my PM CPMS operating limit and
determine compliance with it?
* * * * *
(b) Determine your operating limit as provided in paragraph (b)(1)
or (b)(2) of this section. You must verify an existing or establish a
new operating limit after each repeated performance test.
(1) For an existing EGU, determine your operating limit based on
the highest 1-hour average PM CPMS output value recorded during the
performance test.
(2) For a new EGU, determine your operating limit as follows.
(i) If your PM performance test demonstrates your PM emissions do
not exceed 75 percent of your emissions limit, you will use the average
PM CPMS value recorded during the PM compliance test, the milliamp
equivalent of zero output from your PM CPMS, and the average PM result
of your compliance test to establish your operating limit. Calculate
the operating limit by establishing a relationship of PM CPMS signal to
PM concentration using the PM CPMS instrument zero, the average PM CPMS
values corresponding to the three compliance test runs, and the average
PM concentration from the Method 5 compliance test with the procedures
in (b)(2)(i)(A) through (D) of this section.
(A) Determine your PM CPMS instrument zero output with one of the
following procedures.
(1) Zero point data for in-situ instruments should be obtained by
removing the instrument from the stack and monitoring ambient air on a
test bench.
(2) Zero point data for extractive instruments should be obtained
by removing the extractive probe from the stack and drawing in clean
ambient air.
(3) The zero point can also can be obtained by performing manual
reference method measurements when the flue gas is free of PM emissions
or contains very low PM concentrations (e.g., when your process is not
operating, but the fans are operating or your source is combusting only
natural gas) and plotting these with the compliance data to find the
zero intercept.
(4) If none of the steps in paragraphs (A)(1) through (3) of this
section are possible, you must use a zero output value provided by the
manufacturer.
(B) Determine your PM CPMS instrument average (x) in milliamps, and
the average of your corresponding three PM compliance test runs (y),
using equation 10.
[[Page 24087]]
[GRAPHIC] [TIFF OMITTED] TR24AP13.010
Where:
Xi = the PM CPMS data points for run i of the performance
test,
Yi = the PM emissions value (in lb/MWh) for run i of the
performance test, and
n = the number of data points.
(C) With your PM CPMS instrument zero expressed in milliamps, your
three run average PM CPMS milliamp value, and your three run average PM
emissions value (in lb/MWh) from your compliance runs, determine a
relationship of PM lb/MWh per milliamp with equation 11.
[GRAPHIC] [TIFF OMITTED] TR24AP13.011
Where:
R = the relative PM lb/MWh per milliamp for your PM CPMS,
y = the three run average PM lb/MWh,
x = the three run average milliamp output from your PM CPMS, and
z = the milliamp equivalent of your instrument zero determined from
(b)(2)(i)(A) of this section.
(D) Determine your source specific 30-day rolling average operating
limit using the PM lb/MWh per milliamp value from equation 11 in
equation 12, below. This sets your operating limit at the PM CPMS
output value corresponding to 75 percent of your emission limit.
[GRAPHIC] [TIFF OMITTED] TR24AP13.012
Where:
OL = the operating limit for your PM CPMS on a 30-day
rolling average, in milliamps,
L = your source PM emissions limit in lb/MWh,
z = your instrument zero in milliamps, determined from (b)(2)(i)(A)
of this section, and
R = the relative PM lb/MWh per milliamp for your PM CPMS, from
equation 11.
(ii) If your PM compliance test demonstrates your PM emissions
exceed 75 percent of your emissions limit, you will use the average PM
CPMS value recorded during the PM compliance test demonstrating
compliance with the PM limit to establish your operating limit.
(A) Determine your operating limit by averaging the PM CPMS
milliamp output corresponding to your three PM performance test runs
that demonstrate compliance with the emission limit using equation 13.
[GRAPHIC] [TIFF OMITTED] TR24AP13.013
Where:
Xi = the PM CPMS data points for all runs i,
n = the number of data points, and
Oh = your site specific operating limit, in milliamps.
(iii) Your PM CPMS must provide a 4-20 milliamp output and the
establishment of its relationship to manual reference method
measurements must be determined in units of milliamps.
(iv) Your PM CPMS operating range must be capable of reading PM
concentrations from zero to a level equivalent to two times your
allowable emission limit. If your PM CPMS is an auto-ranging instrument
capable of multiple scales, the primary range of the instrument must be
capable of reading PM concentration from zero to a level equivalent to
two times your allowable emission limit.
(v) During the initial performance test or any such subsequent
performance test that demonstrates compliance with the PM limit, record
and average all milliamp output values from the PM CPMS for the periods
corresponding to the compliance test runs.
(vi) For PM performance test reports used to set a PM CPMS
operating limit, the electronic submission of the test report must also
include the make and model of the PM CPMS instrument, serial number of
the instrument, analytical principle of the instrument (e.g. beta
attenuation), span of the instruments primary analytical range,
milliamp value equivalent to the instrument zero output, technique by
which this zero value was determined, and the average milliamp signal
corresponding to each PM compliance test run.
* * * * *
0
17. In Sec. 63.10030, revise paragraphs (b), (c), and (d) to read as
follows:
Sec. 63.10030 What notifications must I submit and when?
* * * * *
(b) As specified in Sec. 63.9(b)(2), if you startup your EGU that
is an 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 EGU that is an 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 EGU that is an 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.
* * * * *
0
18. Amend Sec. 63.10042 by revising the definition of ``Unit designed
for coal > 8,300 Btu/lb subcategory'' to read as follows:
Sec. 63.10042 What definitions apply to this subpart?
* * * * *
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.
* * * * *
0
19. Revise Table 1 to Subpart UUUUU of Part 63 to read as follows:
[[Page 24088]]
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 limit]
----------------------------------------------------------------------------------------------------------------
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 9.0E-2 lb/MWh \1\...... 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/GWh..........
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-2 lb/GWh..........
Manganese (Mn)......... 4.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 5.0E-2 lb/GWh..........
b. Hydrogen chloride 1.0E-2 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) 1.0 lb/MWh............. SO2 CEMS.
\3\.
c. Mercury (Hg)........ 3.0E-3 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
2. Coal-fired units low rank virgin a. Filterable 9.0E-2 lb/MWh \1\...... 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..........
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-2 lb/GWh..........
Manganese (Mn)......... 4.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 5.0E-2 lb/GWh..........
b. Hydrogen chloride 1.0E-2 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) 1.0 lb/MWh............. SO2 CEMS.
\3\.
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..........
[[Page 24089]]
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) 4.0E-1 lb/MWh.......... SO2 CEMS.
\3\.
c. Mercury (Hg)........ 3.0E-3 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
4. Liquid oil-fired unit--continental a. Filterable 3.0E-1 lb/MWh \1\...... 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..........
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/MWh \1\...... 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..........
[[Page 24090]]
Nickel (Ni)............ 4.1E0 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 D6348-03 \2\
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 3.0E-2 lb/MWh \1\...... 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..........
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) 1.0 lb/MWh............. SO2 CEMS.
\3\.
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 (or, in the case
of IGCC EGUs, some other acid gas removal system either upstream or downstream of the combined cycle block)
and SO2 CEMS installed.
\4\ Duct burners on syngas; gross electric output.
\5\ Duct burners on natural gas; gross electric output.
0
20. Revise Table 4 to Subpart UUUUU of Part 63 to read as follows:
[[Page 24091]]
Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
[As stated in Sec. 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 for an existing EGU.... 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).
2. PM CPMS for a new EGU.......... Maintain the 30-boiler operating day
rolling average PM CPMS output
determined in accordance with the
requirements of Sec.
63.10023(b)(2) and obtained during
the most recent performance test
run 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).
------------------------------------------------------------------------
0
21. Revise footnote 4 of Table 5 to Subpart UUUUU of Part 63 to read as
follows:
Table 5 to Subpart UUUUU of Part 63--Performance Testing Requirements
------------------------------------------------------------------------
-------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
\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:
0
22. Revise Table 6 to Subpart UUUUU of Part 63 to read as follows:
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 . . .
----------------------------------------------------------------------------------------------------------------
1. Filterable Particulate matter Install, certify, Establish a site- Data from the PM 1. Collect PM CPMS
(PM), total non-mercury HAP maintain, and specific CPMS and the PM output data
metals, individual non-mercury operate a PM CPMS operating limit or HAP metals during the entire
HAP metals, total HAP metals, for monitoring in units of PM performance tests. period of the
or individual HAP metals for an emissions CPMS output performance
existing EGU. 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(h)(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.
[[Page 24092]]
2. Filterable Particulate matter Install, certify, Establish a site- Data from the PM 1. Collect PM CPMS
(PM), total non-mercury HAP maintain, and specific CPMS and the PM output data
metals, individual non-mercury operate a PM CPMS operating limit or HAP metals during the entire
HAP metals, total HAP metals, for monitoring in units of PM performance tests. period of the
or individual HAP metals for a emissions CPMS output performance
new EGU. 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(h)(1). signal). CPMS output for
each test run in
the performance
test.
3. Determine the
PM CPMS operating
limit in
accordance with
the requirements
of Sec.
63.10023(b)(2)
from data
obtained during
the performance
test
demonstrating
compliance with
the filterable PM
or HAP metals
emissions
limitations.
----------------------------------------------------------------------------------------------------------------
0
23. Revise Table 7 to Subpart UUUUU of Part 63 to read as follows:
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, You demonstrate continuous
operating limits, or work practice compliance by . . .
standards . . .
------------------------------------------------------------------------
1. CEMS to measure filterable PM, Calculating the 30- (or 90-) boiler
SO2, HCl, HF, or Hg emissions, or operating day rolling arithmetic
using a sorbent trap monitoring average emissions rate in units of
system to measure Hg. 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- (or 90-) boiler
operating days, excluding data
recorded during periods of startup
or shutdown.
2. PM CPMS to measure compliance Calculating the 30- (or 90-) boiler
with a parametric operating limit. operating day rolling arithmetic
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- (or 90-)
boiler operating days, excluding
data recorded during periods of
startup or shutdown.
3. Site-specific monitoring using If applicable, by conducting the
CMS for liquid oil-fired EGUs for monitoring in accordance with an
HCl and HF emission limit approved site-specific monitoring
monitoring. plan.
4. Quarterly performance testing Calculating the results of the
for coal-fired, solid oil derived testing in units of the applicable
fired, or liquid oil-fired EGUs emissions standard.
to measure compliance with one or
more non-PM (or its alternative
emission limits) applicable
emissions limit in Table 1 or 2,
or PM (or its alternative
emission limits) applicable
emissions limit in Table 2.
5. Conducting periodic performance Conducting periodic performance tune-
tune-ups of your EGU(s). ups of your EGU(s), as specified in
Sec. 63.10021(e).
6. Work practice standards for Operating in accordance with Table
coal-fired, liquid oil-fired, or 3.
solid oil-derived fuel-fired EGUs
during startup.
7. Work practice standards for Operating in accordance with Table
coal-fired, liquid oil-fired, or 3.
solid oil-derived fuel-fired EGUs
during shutdown.
------------------------------------------------------------------------
0
24. Revise Table 9 to Subpart UUUUU of Part 63 to read as follows:
[[Page 24093]]
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 general duty
CMS operation. requirement.
Sec. 63.8(c)(1)(iii)........ Requirement to No.
develop SSM Plan
for CMS.
Sec. 63.8(d)(3)............. Written Yes, except for last
procedures for sentence, which
CMS. refers to an SSM
plan. SSM plans are
not required.
Sec. 63.9................... Notification Yes, except for the
requirements. 60-day notification
prior to conducting
a performance test
in Sec. 63.9(d);
instead use a 30-day
notification period
per Sec.
63.10030(d).
Sec. 63.10(a), (b)(1), (c), Recordkeeping and Yes, except for the
(d)(1)-(2), (e), and (f). Reporting requirements to
Requirements. 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 for
malfunctions. 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 63.10032(g)
and cause of and (h) for
malfunctions. malfunctions
recordkeeping
requirements.
Sec. 63.10(c)(11)........... Recording No. See 63.10032(g)
corrective and (h) for
actions. 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).
------------------------------------------------------------------------
[[Page 24094]]
0
25. Revise sections 4.1 and 5.2.2.2 to Appendix A to Subpart UUUUU of
Part 63 to read as follows:
Appendix A to Subpart UUUUU--Hg Monitoring Provisions
* * * * *
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. 63.9984(f).
* * * * *
5.2.2.2 The same RATA performance criteria specified in Table A-
2 for Hg CEMS also apply to the annual RATAs of the sorbent trap
monitoring system.
* * * * *
0
26. Revise section 3.1.2.1.3 and the heading to section 5.3.4 to
Appendix B to Subpart UUUUU of Part 63 to read as follows:
Appendix B to Subpart UUUUU--HCl and HF Monitoring Provisions
* * * * *
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
* * * * *
5.3.3 Conditional Data Validation * * *
* * * * *
[FR Doc. 2013-07859 Filed 4-23-13; 8:45 am]
BILLING CODE 6560-50-P
