National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, 32006-32073 [2010-10827]
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Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 63
[EPA–HQ–OAR–2002–0058; FRL–9148–5]
RIN 2060–AG69
National Emission Standards for
Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and
Institutional Boilers and Process
Heaters
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AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: On September 13, 2004,
under authority of section 112 of the
Clean Air Act, EPA promulgated
national emission standards for
hazardous air pollutants for new and
existing industrial/commercial/
institutional boilers and process heaters.
On June 19, 2007, the United States
Court of Appeals for the District of
Columbia Circuit vacated and remanded
the national emission standards for
hazardous air pollutants for industrial/
commercial/institutional boilers and
process heaters.
In response to the court’s vacatur and
remand, this action would require all
major sources to meet hazardous air
pollutants emissions standards
reflecting the application of the
maximum achievable control
technology. The proposed rule would
protect air quality and promote public
health by reducing emissions of the
hazardous air pollutants listed in
section 112(b)(1) of the Clean Air Act.
We are also proposing that existing
major source facilities with an affected
boiler undergo an energy assessment on
the boiler system to identify costeffective energy conservation measures.
DATES: Comments must be received on
or before July 19, 2010. Under the
Paperwork Reduction Act, comments on
the information collection provisions
are best assured of having full effect if
the Office of Management and Budget
(OMB) receives a copy of your
comments on or before July 6, 2010.
Public Hearing. We will hold a public
hearing concerning this proposed rule
and the interrelated proposed Boiler
area source, CISWI, and RCRA rules,
discussed in this proposal and
published in the proposed rules section
of today’s Federal Register, on June 21,
2010. Persons requesting to speak at a
public hearing must contact EPA by
June 14, 2010.
ADDRESSES: Submit your comments,
identified by Docket ID No. EPA–HQ–
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OAR–2002–0058, by one of the
following methods:
• https://www.regulations.gov. Follow
the instructions for submitting
comments.
• https://www.epa.gov/oar/
docket.html. Follow the instructions for
submitting comments on the EPA Air
and Radiation Docket Web site.
• E-mail: Comments may be sent by
electronic mail (e-mail) to a-and-rdocket@epa.gov, Attention Docket ID
No. EPA–HQ–OAR–2002–0058.
• Fax: Fax your comments to: (202)
566–9744, Docket ID No. EPA–HQ–
OAR–2002–0058.
• Mail: Send your comments to: EPA
Docket Center (EPA/DC), Environmental
Protection Agency, Mailcode: 2822T,
1200 Pennsylvania Ave., NW.,
Washington, DC 20460, Docket ID No.
EPA–HQ–OAR–2002–0058. Please
include a total of two copies. In
addition, please mail a copy of your
comments on the information collection
provisions to the Office of Information
and Regulatory Affairs, OMB, Attn: Desk
Officer for EPA, 725 17th St., NW.,
Washington, DC 20503.
• Hand Delivery or Courier: Deliver
your comments to: EPA Docket Center,
EPA West, Room 3334, 1301
Constitution Ave., NW., Washington,
DC 20460. Such deliveries are only
accepted during the Docket’s normal
hours of operation (8:30 a.m. to 4:30
p.m., Monday through Friday, excluding
legal holiday), and special arrangements
should be made for deliveries of boxed
information.
Instructions: All submissions must
include agency name and docket
number or Regulatory Information
Number (RIN) for this rulemaking. All
comments will be posted without
change and may be made available
online at https://www.regulations.gov,
including any personal information
provided, unless the comment includes
information claimed to be confidential
business information (CBI) or other
information whose disclosure is
restricted by statute. Do not submit
information that you consider to be CBI
or otherwise protected through https://
www.regulations.gov or e-mail. The
https://www.regulations.gov Web site is
an ‘‘anonymous access’’ system, which
means EPA will not know your identity
or contact information unless you
provide it in the body of your comment.
If you send an e-mail comment directly
to EPA without going through https://
www.regulations.gov, your e-mail
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
made available on the Internet. If you
submit an electronic comment, EPA
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recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, EPA may not be
able to consider your comment.
Electronic files should avoid the use of
special characters, any form of
encryption, and be free of any defects or
viruses.
Public Hearing: We will hold a public
hearing concerning this proposed rule
on June 21, 2010. Persons interested in
presenting oral testimony at the hearing
should contact Ms. Pamela Garrett,
Energy Strategies Group, at (919) 541–
7966 by June 14, 2010. The public
hearing will be held in the Washington
DC area at a location and time that will
be posted at the following Web site:
https://www.epa.gov/airquality/
combustion. Please refer to this Web site
to confirm the date of the public hearing
as well. If no one requests to speak at
the public hearing by June 14, 2010 then
the public hearing will be cancelled and
a notification of cancellation posted on
the following Web site: https://
www.epa.gov/airquality/combustion.
Docket: All documents in the docket
are listed in the https://
www.regulations.gov index. Although
listed in the index, some information is
not publicly available, e.g., 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 Ave., 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: Mr.
Brian Shrager, 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–
7689; Fax number (919) 541–5450;
E-mail address: shrager.brian@epa.gov.
SUPPLEMENTARY INFORMATION: The
information presented in this preamble
is organized as follows:
I. General Information
A. Does this action apply to me?
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B. What should I consider as I prepare my
comments to EPA?
C. Where can I get a copy of this
document?
D. When would a public hearing occur?
II. Background Information
A. What is the statutory authority for the
proposed rule?
B. Summary of the Natural Resources
Defense Council v. EPA Decision
C. Summary of Other Related Court
Decisions
D. EPA’s Response to the Vacatur
E. What is the relationship between the
proposed rule and other combustion
rules?
F. What are the health effects of pollutants
emitted from industrial/commercial/
institutional boilers and process heaters?
III. Summary of the Proposed Rule
A. What source categories are affected by
the proposed rule?
B. What is the affected source?
C. Does the proposed rule apply to me?
D. What emission limitations and work
practice standards must I meet?
E. What are the startup, shutdown, and
malfunction (SSM) requirements?
F. What are the testing and initial
compliance requirements?
G. What are the continuous compliance
requirements?
H. What are the notification, recordkeeping
and reporting requirements?
I. Submission of Emissions Test Results to
EPA
IV. Rationale for the Proposed Rule
A. How did EPA determine which sources
would be regulated under the proposed
rule?
B. How did EPA select the format for the
proposed rule?
C. How did EPA determine the proposed
emission limitations for existing units?
D. How did EPA determine the MACT floor
for existing units?
E. How did EPA consider beyond-the-floor
for existing units?
F. Should EPA consider different
subcategories for solid fuel boilers and
process heaters?
G. How did EPA determine the proposed
emission limitations for new units?
H. How did EPA determine the MACT
floor for new units?
I. How did EPA consider beyond-the-floor
for new units?
J. What other compliance alternatives were
considered?
K. How did we select the compliance
requirements?
L. What alternative compliance provisions
are being proposed?
M. How did EPA determine compliance
times for the proposed rule?
N. How did EPA determine the required
records and reports for this proposed
rule?
O. How does the proposed rule affect
permits?
P. Alternative Standard for Consideration
V. Impacts of the Proposed Rule
A. What are the air impacts?
B. What are the water and solid waste
impacts?
C. What are the energy impacts?
D. What are the control costs?
E. What are the economic impacts?
F. What are the social costs and benefits of
the proposed rule?
VI. Public Participation and Request for
Comment
VII. Relationship of the Proposed Action to
Section 112(c)(6) of the CAA
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory
Planning and Review
B. Executive Order 13132, Federalism
C. Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
D. Executive Order 13045, Protection of
Children From Environmental Health
Risks and Safety Risks
E. Unfunded Mandates Reform Act of 1995
F. Regulatory Flexibility Act as Amended
by the Small Business Regulatory
Enforcement Fairness Act (RFA) of 1996
SBREFA), 5 U.S.C. 601 et seq.
G. Paperwork Reduction Act
H. National Technology Transfer and
Advancement Act
I. Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
I. General Information
A. Does this action apply to me?
The regulated categories and entities
potentially affected by the proposed
standards include:
Examples of potentially
regulated entities
NAICS code 1
Category
Any industry using a boiler or process heater as defined in the proposed rule.
32007
211
Extractors of crude petroleum and natural gas.
321
322
325
324
Manufacturers of lumber and wood products.
Pulp and paper mills.
Chemical manufacturers.
Petroleum refineries, and manufacturers of coal
products.
Manufacturers of rubber and miscellaneous plastic
products.
Steel works, blast furnaces.
Electroplating, plating, polishing, anodizing, and
coloring.
Manufacturers of motor vehicle parts and accessories.
Electric, gas, and sanitary services.
Health services.
Educational services.
316, 326, 339
331
332
336
221
622
611
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1 North
American Industry Classification System.
This table is not intended to be
exhaustive, but rather provides 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 63.7485 of subpart DDDDD
(National Emission Standards for
Hazardous Air Pollutants (NESHAP) for
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Industrial, Commercial, and Institution
Boilers and Process Heaters). 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 63.13 of subpart A
(General Provisions).
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B. What should I consider as I prepare
my comments to EPA?
Do not submit information containing
CBI to EPA through https://
www.regulations.gov or e-mail. Send or
deliver information identified as CBI
only to the following address: Roberto
Morales, OAQPS Document Control
Officer (C404–02), Office of Air Quality
Planning and Standards, U.S.
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Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, Attention: Docket ID EPA–HQ–
OAR–2002–0058. Clearly mark the part
or all of the information that you claim
to be CBI. For CBI information in a disk
or CD–ROM that you mail to EPA, mark
the outside of the disk or CD–ROM as
CBI and then identify electronically
within the disk or CD–ROM the specific
information that is claimed as CBI. In
addition to one complete version of the
comment that includes information
claimed as CBI, a copy of the comment
that does not contain the information
claimed as CBI must be submitted for
inclusion in the public docket.
Information so marked will not be
disclosed except in accordance with
procedures set forth in 40 CFR part 2.
C. Where can I get a copy of this
document?
In addition to being available in the
docket, an electronic copy of this
proposed action will also be available
on the World Wide Web (WWW)
through the Technology Transfer
Network (TTN). Following signature, a
copy of the proposed 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.
D. When would a public hearing occur?
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We will hold a public hearing
concerning this proposed rule on June
21, 2010. Persons interested in
presenting oral testimony at the hearing
should contact Ms. Pamela Garrett,
Energy Strategies Group, at (919) 541–
7966 by June 14, 2010. The public
hearing will be held in the Washington,
DC area at a location and time that will
be posted at the following Web site:
https://www.epa.gov/airquality/
combustion. Please refer to this Web site
to confirm the date of the public hearing
as well. If no one requests to speak at
the public hearing by June 14, 2010,
then the public hearing will be
cancelled and a notification of
cancellation posted on the following
Web site: https://www.epa.gov/
airquality/combustion.
II. Background Information
A. What is the statutory authority for
this proposed rule?
Section 112(d) of the Clean Air Act
(CAA) requires EPA to set emissions
standards for hazardous air pollutants
(HAP) emitted by major stationary
sources based on the performance of the
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maximum achievable control
technology (MACT). The MACT
standards for existing sources must be at
least as stringent as the average
emissions limitation achieved by the
best performing 12 percent of existing
sources (for which the Administrator
has emissions information) or the best
performing 5 sources for source
categories with less than 30 sources
(CAA section 112(d)(3)(A) and (B)). This
level of minimum stringency is called
the MACT floor. For new sources,
MACT standards must be at least as
stringent as the control level achieved in
practice by the best controlled similar
source (CAA section 112(d)(3)). EPA
also must consider more stringent
‘‘beyond-the-floor’’ control options.
When considering beyond-the-floor
options, EPA must consider not only the
maximum degree of reduction in
emissions of HAP, but must take into
account costs, energy, and nonair
environmental impacts when doing so.
CAA section 112(c)(6) requires EPA to
list categories and subcategories of
sources assuring that sources accounting
for not less than 90 percent of the
aggregate emissions of each such
pollutant (alkylated lead compounds;
polycyclic organic matter;
hexachlorobenzene; mercury;
polychlorinated byphenyls; 2,3,7,8tetrachlorodibenzofurans; and 2,3,7,8tetrachloroidibenzo-p-dioxin) are
subject to standards under subsection
112(d)(2) or (d)(4). Standards
established under CAA section 112(d)(2)
must reflect the performance of MACT.
‘‘Industrial Coal Combustion,’’
‘‘Industrial Oil Combustion,’’ ‘‘Industrial
Wood/Wood Residue Combustion,’’
‘‘Commercial Coal Combustion,’’
‘‘Commercial Oil Combustion,’’ and
‘‘Commercial Wood/Wood Residue
Combustion’’ are listed as source
categories for regulation pursuant to
CAA section 112(c)(6) due to emissions
of polycyclic organic matter (POM) and
mercury (63 FR 17838, 17848, April 10,
1998). In the documentation for the
112(c)(6) listing, the commercial fuel
combustion categories included
institutional fuel combustion (‘‘1990
Emissions Inventory of Section 112(c)(6)
Pollutants, Final Report,’’ April 1998).
CAA section 129(a)(1)(A) requires
EPA to establish specific performance
standards, including emission
limitations, for ‘‘solid waste incineration
units’’ generally, and, in particular, for
‘‘solid waste incineration units
combusting commercial or industrial
waste’’ (section 129(a)(1)(D)). Section
129 defines ‘‘solid waste incineration
unit’’ as ‘‘a distinct operating unit of any
facility which combusts any solid waste
material from commercial or industrial
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establishments or the general public.’’
Section 129(g)(1). Section 129 also
provides that ‘‘solid waste’’ shall have
the meaning established by EPA
pursuant to its authority under the
Resource Conservation and Recovery
Act. Section 129(g)(6).
In Natural Resources Defense Council
v. EPA, 489 F. 3d 1250, 1257–61 (DC
Cir. 2007), the court vacated the
Commercial and Industrial Solid Waste
Incineration (CISWI) Definitions Rule,
70 FR 55568 (September 22, 2005),
which EPA issued pursuant to CAA
section 129(a)(1)(D). In that rule, EPA
defined the term ‘‘commercial or
industrial solid waste incineration unit’’
to mean a combustion unit that
combusts ‘‘commercial or industrial
waste.’’ The rule defined ‘‘commercial or
industrial waste’’ to mean waste
combusted at a unit that does not
recover thermal energy from the
combustion for a useful purpose. Under
these definitions, only those units that
combusted commercial or industrial
waste and were not designed to, or did
not operate to, recover thermal energy
from the combustion would be subject
to section 129 standards. The District of
Columbia Circuit (DC Circuit) rejected
the definitions contained in the CISWI
Definitions Rule and interpreted the
term ‘‘solid waste incineration unit’’ in
CAA section 129(g)(1) ‘‘to
unambiguously include among the
incineration units subject to its
standards any facility that combusts any
commercial or industrial solid waste
material at all—subject to the four
statutory exceptions identified in [CAA
section 129(g)(1).]’’ NRDC v. EPA, 489
F.3d 1250, 1257–58.
CAA section 129 covers any facility
that combusts any solid waste; CAA
section 112(g)(6) directs the Agency to
the Resource Conservation and
Recovery Act (RCRA) in terms of the
definition of solid waste. The Agency is
in the process of defining solid waste for
purposes of Subtitle D of RCRA. EPA
initiated a rulemaking to define which
secondary materials are ‘‘solid waste’’ for
purposes of subtitle D (nonhazardous
waste) of RCRA when burned in a
combustion unit. (See Advance Notice
of Proposed Rulemaking (74 FR 41,
January 2, 2009) soliciting comment on
whether certain secondary materials
used as alternative fuels or ingredients
are solid wastes within the meaning of
Subtitle D of RCRA.) If a unit combusts
solid waste, it is subject to CAA section
129 of the Act, unless it falls within one
of the four specified exceptions in CAA
section 129(g).
The solid waste definitional
rulemaking under RCRA is being
proposed in a parallel action and is
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relevant to this proceeding because
some industrial, commercial, or
institutional boilers and process heaters
combust secondary materials as
alternative fuels. If industrial,
commercial, or institutional boilers or
process heaters combusts secondary
materials that are solid waste under the
proposed definitional rule, those units
would be subject to section 129. The
units subject to this rule include those
industrial, commercial, or institutional
boilers and process heaters that do not
combust solid waste. EPA recognizes
that it has imperfect information on the
exact nature of the secondary materials
which boilers and process heaters
combust, including, for example, how
much processing of such materials
occurs, if any. We nevertheless used the
information currently available to the
Agency to determine which materials
are solid waste and, therefore, subject to
CAA section 129, and which are not
solid waste and, therefore, subject to
CAA section 112.
B. Summary of the Natural Resources
Defense Council v. EPA Decision
On September 13, 2004, EPA issued
the NESHAP for Industrial, Commercial,
and Institutional Boilers and Process
Heaters (40 CFR 55218) (the Boiler
MACT). We identified 18 subcategories
of boilers and process heaters emitting
four different types of HAPs. See 69 FR
55,223–24. EPA set out to establish the
MACT floor for each subcategory
emitting each HAP according to the
effectiveness of various add-on
technologies. (See 68 FR 1660, 1674,
Jan. 13, 2003 (proposed rule).) Applying
this methodology, EPA set 25 numerical
emission standards. The 2004 final rule
established emission limitations for
particulate matter (PM), as a surrogate
for non-mercury HAP metals, mercury,
and hydrogen chloride (HCl), as a
surrogate for acid gas HAP, for existing
large solid fuel-fired sources only. For
the remaining 47 boiler subcategory/
HAP emissions, EPA determined that
the appropriate MACT floor was ‘‘no
emissions reduction’’ because ‘‘the bestperforming sources were not achieving
emissions reductions through the use of
an emission control system and there
were no other appropriate methods by
which boilers and process heaters could
reduce HAP emissions.’’ (69 FR 55,233.)
Accordingly, we established no
standards. In addition, we set risk-based
standards, also known as health-based
compliance alternatives, as alternatives
to the MACT-based standards for
hydrogen chloride and manganese.
EPA issued emissions standards for
CISWI units on December 1, 2000, and
as part of that rulemaking, defined the
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term ‘‘commercial and industrial waste’’
to mean solid waste combusted in an
enclosed device using controlled flame
combustion without energy recovery
that is a distinct operating unit of any
commercial or industrial facility. In
response to a petition for
reconsideration, EPA filed a motion for
voluntary remand, which the court
granted on September 6, 2001. On
remand, EPA solicited comments on the
CISWI Rule’s definitions of ‘‘solid
waste,’’ ‘‘commercial and industrial
waste’’ and ‘‘CISWI unit.’’ On September
22, 2005, EPA issued the CISWI
Definitions Rule, which contained
definitions that were substantively the
same as those issued before
reconsideration. In particular, the 2005
CISWI Definitions Rule defined
‘‘commercial or industrial waste’’ to
include only waste that is combusted at
a facility that cannot or does not use a
process that recovers thermal energy
from the combustion for a useful
purpose.
EPA received separate petitions from
environmental groups, industry, and
municipalities seeking judicial review
of the NESHAP for Industrial,
Commercial, and Institutional Boilers
and Process Heaters (Boiler MACT) as
well as amendments to definitional
terms in the Standards of Performance
for New Stationary Sources and
Emission Guidelines for Existing
Sources: Commercial and Industrial
Solid Waste Incineration Units (CISWI
Definitions Rule), promulgated pursuant
to CAA section 129. The environmental
organizations challenged the CISWI
Definitions Rule on the ground that its
definition of ‘‘commercial or industrial
waste’’ was inconsistent with the plain
language of CAA section 129 and
therefore impermissibly constricted the
class of ‘‘solid waste incineration
unit[s]’’ that were subject to the
emission standards of the CISWI Rule.
The environmental groups also
challenged specific emission standards
that EPA promulgated in the Boiler
MACT and EPA’s methodology for
setting them. The municipalities—the
American Municipal Power-Ohio, Inc.
and six of its members, the cities of
Dover, Hamilton, Orrville, Painesville,
Shelby and St. Mary’s—challenged the
Boiler MACT on the grounds that EPA
failed to comply with the requirements
of the Regulatory Flexibility Act (RFA)
and that the standards as applied to
small municipal utilities are unlawful.
As explained further below, the Court
concluded that EPA’s definition of
‘‘commercial or industrial waste,’’ as
incorporated in the definition of
‘‘commercial and industrial solid waste
incineration unit’’ (CISWI unit), was
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inconsistent with the plain language of
CAA section 129 and that the CISWI
Definitions Rule must, therefore, be
vacated. The Court also vacated and
remanded the Boiler MACT, finding that
the Boiler MACT must be substantially
revised as a consequence of the vacatur
and remand of the CISWI Definitions
Rule.
In its decision, the Court agreed with
the environmental petitioners that
EPA’s definition of ‘‘commercial or
industrial waste,’’ as incorporated in the
definition of CISWI units, conflicted
with the plain language of CAA section
129(g)(1). That provision defines ‘‘solid
waste incineration unit’’ to mean ‘‘any
facility which combusts any solid waste
material’’ from certain types of
establishments, with four specific
exclusions. The Court stated that, based
on the use of the term ‘‘any’’ and the
specific exclusions for only certain
types of facilities from the definition of
‘‘solid waste incineration unit,’’ CAA
section 129 unambiguously includes
among the incineration units subject to
its standards any facility that combusts
any commercial or industrial solid
waste material at all—subject only to the
four statutory exclusions. The Court
held that the definitions EPA
promulgated in the CISWI Definitions
Rule constricted the plain language of
CAA section 129(g)(1), because the
CISWI Definitions Rule excluded from
its universe operating units that
combusted solid waste and were
designed for or operating with energy
recovery.
Having determined that EPA’s
definition of ‘‘commercial and industrial
solid waste incineration unit’’ conflicts
with the plain meaning of CAA section
129 and must, therefore, be vacated, the
Court also vacated the Boiler MACT
because it concluded that the Boiler
MACT would need to be revised
because the universe of boilers subject
to its standards will be different once
EPA revises the CISWI definitions rule
consistent with the Court’s opinion. The
Court did not address petitioners’
specific challenges to the Boiler MACT.
C. Summary of Other Related Court
Decisions
In March 2007, the DC Circuit Court
issued an opinion (Sierra Club v. EPA,
479 F. 3d 875 (DC Cir. 2007) (Brick
MACT)) vacating and remanding CAA
section 112(d) MACT standards for the
Brick and Structural Clay Ceramics
source categories. Some key holdings in
that case were:
• Floors for existing sources must
reflect the average emission limitation
achieved by the best-performing 12
percent of existing sources, not levels
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EPA considers to be achievable by all
sources (479 F. 3d at 880–81);
• EPA cannot set floors of ‘‘no
control.’’ The Court reiterated its prior
holdings, including National Lime
Association, confirming that EPA must
set floor standards for all HAP emitted
by the major source, including those
HAP that are not controlled by at-thestack control devices (479 F. 3d at 883);
• EPA cannot ignore non-technology
factors that reduce HAP emissions.
Specifically, the Court held that ‘‘EPA’s
decision to base floors exclusively on
technology even though non-technology
factors affect emissions violates the
Act.’’ (479 F. 3d at 883)
Based on the Brick MACT decision,
we believe a source’s performance
resulting from the presence or absence
of HAP in fuel materials must be
accounted for in establishing floors; i.e.,
a low emitter due to low HAP fuel
materials can still be a best performer.
In addition, the fact that a specific level
of performance is unintended is not a
legal basis for excluding the source’s
performance from consideration.
(National Lime Ass’n, 233 F. 3d at 640.)
The Brick MACT decision also stated
that EPA may account for variability in
setting floors. However, the court found
that EPA erred in assessing variability
because it relied on data from the worst
performers to estimate best performers’
variability, and held that ‘‘EPA may not
use emission levels of the worst
performers to estimate variability of the
best performers without a demonstrated
relationship between the two.’’ (479 F.
3d at 882.)
The majority opinion in the Brick
MACT case does not address the
possibility of subcategorization to
address differences in the HAP content
of raw materials. However, in his
concurring opinion Judge Williams
stated that EPA’s ability to create
subcategories for sources of different
classes, size, or type (CAA section
112(d)(1)) may provide a means out of
the situation where the floor standards
are achieved for some sources, but the
same floors cannot be achieved for other
sources due to differences in local raw
materials whose use is essential. (Id. At
884–85.9)
A second court opinion is also
relevant to this proposal. In Sierra Club
v. EPA, 551 F. 3d 1019 (DC Cir. 2008),
the court vacated the portion of the
regulations contained in the General
Provisions which exempt major sources
from MACT standards during periods of
startup, shutdown and malfunction
(SSM). The regulations (in 40 CFR
63.6(f)(1) and 63.6(h)(1)) provided that
sources need not comply with the
relevant CAA section 112(d) standard
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during SSM events and instead must
‘‘minimize emissions * * * to the
greatest extent which is consistent with
safety and good air pollution control
practices.’’ The vacated Boiler MACT
did not contain specific provisions
covering operation during SSM
operating modes; rather it referenced the
now-vacated exemption in the General
Provisions. As a result of the court
decision, we are addressing SSM in this
proposed rulemaking. Discussion of this
issue may be found later in this
preamble.
D. EPA’s Response to the Vacatur
In response to the NRDC v. EPA
mandate, we initiated an information
collection effort entitled ‘‘Information
Collection Effort for Facilities with
Combustion Units.’’ This information
collection was conducted by EPA’s
Office of Air and Radiation pursuant to
CAA section 114 to assist the
Administrator in developing emissions
standards for boilers/process heaters
and CISWI units (collectively,
‘‘combustion units’’) pursuant to CAA
sections 112(d) and 129. CAA section
114(a) states, in pertinent part:
For the purpose of * * * (iii) carrying out
any provision of this Chapter * * * (1) the
Administrator may require any person who
owns or operates any emission source * * *
to- * * * (D) sample such emissions (in
accordance with such procedures or
methods, at such locations, at such intervals,
during such periods and in such manner as
the Administrator shall prescribe); (E) keep
records on control equipment parameters,
production variables or other indirect data
when direct monitoring of emissions is
impractical * * * (G) provide such other
information as the Administrator may
reasonably require * * *
There were two components to the
information collection. To obtain the
information necessary to identify and
categorize all combustion units
potentially affected by the revised
standards for boilers/process heaters
and for CISWI units, the first component
of the information collection effort
solicited information from all
potentially affected combustion units in
the format of an electronic survey. The
survey was submitted to the following
facilities: (1) All facilities that submitted
an initial notification for the 2004 boiler
MACT standard, (2) all facilities
identified by States as being subject to
the 2004 boiler MACT standard, and (3)
facilities that are classified as a major
source in their Title V permit that have
a boiler or process heater listed in their
permit. The survey was also sent to
units covered by the 2000 CISWI
emissions standards (40 CFR part 60
subpart CCCC) and to facilities that have
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incineration units (e.g., energy recovery
units) that were listed as exempt under
the 2000 CISWI standard. Each facility
was required to complete the survey for
all combustion units located at the
facility. The information requested for
each combustion unit included the unit
design, operation, air pollution control
data, the fuels/materials burned, and
available emissions test data,
continuous emission monitoring (CEM)
data, fuel/material analysis data, and
permitted and regulatory emission
limits.
The second component of the
information collection request effort
consisted of requiring the owners/
operators of 169 boilers/process heaters
to conduct emission testing for HAP and
HAP surrogates. We first analyzed the
results of the survey to determine if
sufficient emissions data existed to
develop emission standards under CAA
sections 112(d) for all types of boilers/
process heaters, all types of materials
combusted, and all HAP to be regulated.
If data were not sufficient, then we
selected pools of candidates to conduct
emission testing. We submitted a list of
candidates to stakeholders, including
state, industry, and environmental
stakeholders, who had an opportunity to
comment on the technical feasibility,
the least-cost impact of the testing
program, and the appropriateness of the
testing being requested. We then made
a selection of test sites after taking into
account stakeholder comments. The
sites selected were required to conduct
an outlet stack test, consisting of three
runs, in accordance with EPA-approved
protocols, for all of the following
pollutants: PM (filterable, condensable,
and PM2.5), dioxins/furans (D/F),
hydrogen chloride/hydrogen fluoride,
mercury, metals (including antimony,
arsenic, beryllium, cadmium,
chromium, cobalt, lead, manganese,
nickel, phosphorus, and selenium),
carbon monoxide (CO), total
hydrocarbons (THC), formaldehyde,
oxides of nitrogen (NOX), and sulfur
dioxide (SO2). Six facilities (two coalfired, two biomass-fired, and two gasfired boilers) were required to collect
CEM data over 30 operating days using
mobile CEM devices for CO, THC, and
NOX. The owner/operator of each
selected combustion unit was also
required to collect and analyze, in
accordance with acceptable procedures,
the material(s) fed to the combustion
unit during each stack test. The results
of the stack tests and the analyses of
materials combusted were required to be
submitted to the Agency and are
available in the docket and can be
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downloaded at https://www.epa.gov/ttn/
atw/boiler/boilerpg.html.
When we compared information on
boilers and process heaters from
facilities submitting initial notifications
to comply with the vacated 2004 Boiler
MACT to the information gathering
effort conducted for the 2004 Boiler
MACT, a large disparity was identified
in the number of potentially affected
units at major sources of HAP. Since the
last combustion unit data gathering
effort in 1996, many sources have shut
down, others have selected to operate
with a permit limit on their HAP
emissions in order to avoid being
subject to the Boiler MACT (i.e.,
synthetic area source), and some units
have switched out older solid fuel units
for newer equipment due to increased
insurance and maintenance costs.
Based on the definition of solid waste
as set forth in a parallel proposed
action, we revised the population of
combustion units subject to CAA
section 129 (because they combust solid
waste) and the population of boilers and
process heaters subject to CAA section
112 (because they do not combust solid
waste). We then used the new data to
develop a revised NESHAP for boilers
and process heaters under CAA section
112 and revised standards for
incineration units covered by CAA
section 129. Specifically, the data
provide the Agency with updated
information on the number of
potentially affected units, available
emission test data, and fuel/material
analysis data to address variability. We
are using all of the information before
the Administrator to calculate the
MACT floors, set emission limits, and
evaluate the emission impacts of various
regulatory options for these revised
rulemakings.
E. What is the relationship between this
proposed rule and other combustion
rules?
The proposed rule regulates source
categories covering industrial boilers,
institutional boilers, commercial boilers,
and process heaters. These source
categories potentially include
combustion units that are already
regulated by other MACT standards.
Therefore, we are excluding from this
proposed rule any boiler or process
heater that is subject to regulation under
other MACT standards.
In 1986, EPA had codified new source
performance standards (NSPS) for
industrial boilers (40 CFR part 60,
subparts Db and Dc) and revised
portions of those standards in 1999 and
2006. The NSPS regulates emissions of
PM, SO2, and NOX from boilers
constructed after June 19, 1984. Sources
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subject to the NSPS will be subject to
the final CAA section 112(d) standards
for boilers and process heaters because
it regulates sources of HAP while the
NSPS do not. However, in developing
the proposed rule, we considered the
monitoring requirements, testing
requirements, and recordkeeping
requirements of the NSPS to avoid
duplicating requirements.
This proposed rule addresses the
combustion of non-solid waste materials
in boilers and process heaters. If an
owner or operator of an affected source
subject to these proposed standards
were to start combusting a solid waste
(as defined by the Administrator under
RCRA), the affected source would cease
to be subject to this action and would
instead be subject to regulation under
CAA section 129. A rulemaking under
CAA section 129 is being proposed in a
parallel action and is relevant to this
action because it would apply to boilers
and process heaters located at a major
source that combust any solid waste.
EPA is taking comment on whether a
boiler or process heater could then opt
back into regulation under this
proposed rule by taking a federally
enforceable restriction precluding the
future combustion of any solid waste
material.
F. What are the health effects of
pollutants emitted from industrial/
commercial/institutional boilers and
process heaters?
This proposed rule protects air quality
and promotes the public health by
reducing emissions of some of the HAP
listed in CAA section 112(b)(1). As
noted above, emissions data collected
during development of the proposed
rule show that hydrogen chloride
emissions represent the predominant
HAP emitted by industrial, commercial,
and institutional (ICI) boilers,
accounting for 61 percent of the total
HAP emissions.1 ICI boilers and process
heaters also emit lesser amounts of
hydrogen fluoride, accounting for about
17 percent of total HAP emissions, and
metals (arsenic, cadmium, chromium,
mercury, manganese, nickel, and lead)
accounting for about 6 percent of total
HAP emissions. Organic HAP
(formaldehyde, POM, acetaldehyde,
benzene) account for about 15 percent of
total HAP emissions. Exposure to these
HAP, depending on exposure duration
and levels of exposures, can be
associated with a variety of adverse
health effects. These adverse health
1 See Memorandum ‘‘Methodology for Estimating
Impacts from Industrial, Commercial, Institutional
Boilers and Process Heaters at Major Sources of
Hazardous Air Pollutant Emissions’’ located in the
docket.
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effects may include, for example,
irritation of the lung, skin, and mucus
membranes, effects on the central
nervous system, damage to the kidneys,
and alimentary effects such as nausea
and vomiting. We have classified two of
the HAP as human carcinogens (arsenic
and chromium VI) and four as probable
human carcinogens (cadmium, lead,
dioxins/furans, and nickel). We do not
know the extent to which the adverse
health effects described above occur in
the populations surrounding these
facilities. However, to the extent the
adverse effects do occur, this proposed
rule would reduce emissions and
subsequent exposures.
III. Summary of This Proposed Rule
This section summarizes the
requirements proposed in today’s
action. Section IV below provides our
rationale for the proposed requirements.
A. What source categories are affected
by this proposed rule?
This proposed rule affects industrial
boilers, institutional boilers, commercial
boilers, and process heaters. In this
proposed rule, process heaters are
defined as units in which the
combustion gases do not directly come
into contact with process material or
gases in the combustion chamber (e.g.,
indirect fired). Boiler means an enclosed
device using controlled flame
combustion and having the primary
purpose of recovering thermal energy in
the form of steam or hot water.
B. What is the affected source?
The affected source is: (1) The
collection of all existing industrial,
commercial, or institutional boilers or
process heaters within a subcategory
located at a major source facility that do
not combust solid waste or (2) each new
or reconstructed industrial, commercial,
or institutional boiler or process heater
located at a major source facility that do
not combust solid waste, as that term is
defined by the Administrator under
RCRA.
The affected source does not include
boilers and process heaters that are
subject to another standard under 40
CFR part 63 or a standard established
under CAA section 129.
C. Does this proposed rule apply to me?
This proposed rule applies to you if
you own or operate a boiler or process
heater at a major source meeting the
requirements discussed previously in
this preamble. A major source of HAP
emissions is any stationary source or
group of stationary sources located
within a contiguous area and under
common control that emits or has the
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potential to emit considering controls 10
tons per year or more of any HAP or 25
tons per year or more of any
combination of HAP.
D. What emission limitations and work
practice standards must I meet?
We are proposing the emission limits
presented in Table 1 of this preamble.
Emission limits were developed for new
and existing sources for eleven
subcategories, which we developed
based on unit design.
We are proposing that if your new or
existing boiler or process heater burns at
least 10 percent coal on an annual
average heat input 2 basis, the unit is in
one of the coal subcategories. If your
new or existing boiler or process heater
burns at least 10 percent biomass, on an
annual average heat input basis, and
less than 10 percent coal, on an annual
average heat input basis, we are
proposing that the unit is in one of the
biomass subcategories. If your new or
existing boiler or process heater burns at
least 10 percent liquid fuel (such as
distillate oil, residual oil), and less than
10 percent solid fuel, on an annual heat
input basis, we are proposing that the
unit is in the liquid subcategory. If your
new or existing boiler or process heater
burns gaseous fuel and less than 10
percent, on an annual average heat
input basis, of liquid or solid fuel, we
are proposing that the unit is in one of
the gas subcategories.
TABLE 1—EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS
[Pounds per million British thermal units]
Particulate
matter
(PM)
Subcategory
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Existing—Coal Stoker ................................................
Existing—Coal Fluidized Bed ....................................
Existing—Pulverized Coal ..........................................
Existing—Biomass Stoker ..........................................
Existing—Biomass Fluidized Bed ..............................
Existing—Biomass Suspension Burner/Dutch Oven
Existing—Biomass Fuel Cells ....................................
Existing—Liquid .........................................................
Existing—Gas (Other Process Gases) ......................
New—Coal Stoker .....................................................
New—Coal Fluidized Bed ..........................................
New—Pulverized Coal ...............................................
New—Biomass Stoker ...............................................
New—Biomass Fluidized Bed ...................................
New—Biomass Suspension Burner/Dutch Oven ......
New—Biomass Fuel Cells .........................................
New—Liquid ...............................................................
New—Gas (Other Process Gases) ...........................
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.004
0.05
0.001
0.001
0.001
0.008
0.008
0.008
0.008
0.002
0.003
Hydrogen
chloride
(HCl)
0.02
0.02
0.02
0.006
0.006
0.006
0.006
0.0009
0.000003
0.00006
0.00006
0.00006
0.004
0.004
0.004
0.004
0.0004
0.000003
Carbon
monoxide (CO)
(ppm @3% oxygen)
Mercury
(Hg)
0.000003
0.000003
0.000003
0.0000009
0.0000009
0.0000009
0.0000009
0.000004
0.0000002
0.000002
0.000002
0.000002
0.0000002
0.0000002
0.0000002
0.0000002
0.0000003
0.0000002
50
30
90
560
250
1010
270
1
1
7
30
90
560
40
1010
270
1
1
Dioxins/
furans
(total TEQ)
(ng/dscm)
0.003
0.002
0.004
0.004
0.02
0.03
0.02
0.002
0.009
0.003
0.00003
0.002
0.00005
0.007
0.03
0.0005
0.002
0.009
The proposed emission limits in the
above table apply only to existing
boilers and process heaters that have a
designed heat input capacity of 10
million British thermal units (Btu) per
hour or greater. Pursuant to CAA section
112(h), we are proposing a work
practice standard for three particular
classes of boilers and process heaters:
Existing units that have a designed heat
input capacity of less than 10 million
Btu per hour and new and existing units
in the Gas 1 (natural gas/refinery gas)
subcategory and in the metal process
furnaces subcategory. The work practice
standard being proposed for these
boilers and process heaters would
require the implementation of a tune-up
program as described in section III.F of
this preamble.
We are also proposing a beyond-thefloor standard for all existing major
source facilities having affected boilers
or process heaters that would require
the performance of a one-time energy
assessment, as described in section III.F
of this preamble, by qualified personnel,
on the affected boilers and facility to
identify any cost-effective energy
conservation measures.
The United States Court of Appeals
for the District of Columbia Circuit
vacated portions of two provisions in
EPA’s CAA Section 112 regulations
governing the emissions of HAP during
periods of startup, shutdown, and
malfunction (SSM). Sierra Club v. EPA,
551 F.3d 1019 (DC Cir. 2008), cert.
denied, 2010 U.S. LEXIS 2265 (2010).
Specifically, the Court vacated the SSM
exemption contained in 40 CFR
63.6(f)(1) and 40 CFR 63.6(h)(1), that are
part of a regulation, commonly referred
to as the ‘‘General Provisions Rule,’’ that
EPA promulgated under section 112 of
the CAA. When incorporated into CAA
Section 112(d) regulations for specific
source categories, these two provisions
exempt sources from the requirement to
comply with the otherwise applicable
CAA section 112(d) emission standard
during periods of SSM.
Consistent with Sierra Club v. EPA,
EPA has established standards in this
rule that apply at all times. EPA has
attempted to ensure that we have not
incorporated into proposed regulatory
language any provisions that are
inappropriate, unnecessary, or
redundant in the absence of an SSM
exemption. We are specifically seeking
comment on whether there are any such
provisions that we have inadvertently
incorporated or overlooked. We also
request comment on whether there are
additional provisions that should be
added to regulatory text in light of the
absence of an SSM exemption and
provisions related to the SSM
exemption (such as the SSM plan
requirement and SSM recordkeeping
and reporting provisions).
In establishing the standards in this
rule, EPA has taken into account startup
and shutdown periods and, for the
2 Heat input means heat derived from combustion
of fuel in a boiler or process heater and does not
include the heat derived from preheated
combustion air, recirculated flue gases or exhaust
gases from other sources (such as stationary gas
turbines, internal combustion engines, and kilns).
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E. What are the startup, shutdown, and
malfunction (SSM) requirements?
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reasons explained below, has not
established different standards for those
periods. The standards that we are
proposing are daily or monthly
averages. Continuous emission
monitoring data obtained from best
performing units, and used in
establishing the standards, include
periods of startup and shutdown.
Boilers, especially solid fuel-fired
boilers, do not normally startup and
shutdown more the once per day. Thus,
we are not establishing a separate
emission standard for these periods
because startup and shutdown are part
of their routine operations and,
therefore, are already addressed by the
standards. Periods of startup, normal
operations, and shutdown are all
predictable and routine aspects of a
source’s operation. We have evaluated
whether it is appropriate to have the
same standards apply during startup
and shutdown as applied to normal
operations.
Periods of startup, normal operations,
and shutdown are all predictable and
routine aspects of a source’s operations.
However, by contrast, malfunction is
defined as a ‘‘sudden, infrequent, and
not reasonably preventable failure of air
pollution control and monitoring
equipment, process equipment or a
process to operate in a normal or usual
manner * * *’’ (40 CFR 63.2). EPA has
determined that malfunctions should
not be viewed as a distinct operating
mode and, therefore, any emissions that
occur at such times do not need to be
factored into development of CAA
section 112(d) standards, which, once
promulgated, apply at all times. It is
reasonable to interpret section 112(d) as
not requiring EPA to account for
malfunctions in setting emissions
standards. For example, we note that
Section 112 uses the concept of ‘‘best
performing’’ sources in defining MACT,
the level of stringency that major source
standards must meet. Applying the
concept of ‘‘best performing’’ to a source
that is malfunctioning presents
significant difficulties. The goal of best
performing sources is to operate in such
a way as to avoid malfunctions of their
units.
Moreover, even if malfunctions were
considered a distinct operating mode,
we believe it would be impracticable to
take malfunctions into account in
setting CAA section 112(d) standards for
major source boilers and process
heaters. As noted above, by definition,
malfunctions are sudden and
unexpected events and it would be
difficult to set a standard that takes into
account the myriad different types of
malfunctions that can occur across all
sources in the category. Moreover,
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malfunctions can vary in frequency,
degree, and duration, further
complicating standard setting.
In the event that a source fails to
comply with the applicable CAA section
112(d) standards as a result of a
malfunction event, EPA would
determine an appropriate response
based on, among other things, the good
faith efforts of the source to minimize
emissions during malfunction periods,
including preventative and corrective
actions, as well as root cause analyses
to ascertain and rectify excess
emissions. EPA would also consider
whether the source’s failure to comply
with the CAA section 112(d) standard
was, in fact, ‘‘sudden, infrequent, not
reasonably preventable’’ and was not
instead ‘‘caused in part by poor
maintenance or careless operation.’’ 40
CFR 63.2 (definition of malfunction).
F. What are the testing and initial
compliance requirements?
We are proposing that the owner or
operator of a new or existing boiler or
process heater must conduct
performance tests to demonstrate
compliance with all applicable emission
limits. Affected units would be required
to conduct the following compliance
tests where applicable:
(1) Conduct initial and annual stack
tests to determine compliance with the
PM emission limits using EPA Method
5 or 17.
(2) Conduct initial and annual stack
tests to determine compliance with the
mercury emission limits using EPA
method 29 or ASTM–D6784–02 (Ontario
Hydro Method).
(3) Conduct initial and annual stack
tests to determine compliance with the
HCl emission limits using EPA Method
26A or EPA Method 26 (if no entrained
water droplets in the sample).
(4) Use EPA Method 19 to convert
measured concentration values to
pound per million Btu values.
(5) Conduct initial and annual test to
determine compliance with the CO
emission limits using either EPA
Method 10 or a CO CEMS.
(6) Conduct initial and annual test to
determine compliance with the D/F
emission limits using EPA Method 23.
As part of the initial compliance
demonstration, we are proposing that
you monitor specified operating
parameters during the initial
performance tests that you would
conduct to demonstrate compliance
with the PM, mercury, D/F, and HCl
emission limits. You would calculate
the average parameter values measured
during each test run over the three run
performance test. The average of the
three average values (depending on the
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parameter measured) for each applicable
parameter would establish the sitespecific operating limit. The applicable
operating parameters for which
operating limits would be required to be
established are based on the emissions
limits applicable to your unit as well as
the types of add-on controls on the unit.
The following is a summary of the
operating limits that we are proposing to
be established for the various types of
the following units:
(1) For boilers and process heaters
without wet or dry scrubbers that must
comply with an HCl emission limit, you
must measure the average chlorine
content level in the input fuel(s) during
the HCl performance test. This is your
maximum chlorine input operating
limit.
(2) For boilers and process heaters
with wet scrubbers, you must measure
pressure drop and liquid flow rate of the
scrubber during the performance test,
and calculate the average value for each
test run. The average of the three test
run averages establishes your minimum
site-specific pressure drop and liquid
flow rate operating levels. If different
average parameter levels are measured
during the mercury, PM and HCl tests,
the highest of the average values
becomes your site-specific operating
limit. If you are complying with an HCl
emission limit, you must measure pH of
the scrubber effluent during the
performance test for HCl and determine
the average for each test run and the
average value for the performance test.
This establishes your minimum pH
operating limit.
(3) For boilers and process heaters
with sorbent injection, you would be
required to measure the sorbent
injection rate for each sorbent used
during the performance tests for HCl,
mercury, and D/F and calculate the
average for each sorbent for each test
run. The average of the three test run
averages established during the
performance tests would be your sitespecific minimum sorbent injection rate
operating limit. If different sorbents
and/or injection rates are used during
the mercury, HCl, and D/F tests, the
average value for each sorbent becomes
your site-specific operating limit.
(4) For boilers and process heaters
with fabric filters in combination with
wet scrubbers, you must measure the
pH, pressure drop, and liquid flowrate
of the wet scrubber during the
performance test and calculate the
average value for each test run. The
minimum test run average establishes
your site-specific pH, pressure drop,
and liquid flowrate operating limits for
the wet scrubber. Furthermore, the
fabric filter must be operated such that
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the bag leak detection system alarm
does not sound more than 5 percent of
the operating time during any 6-month
period unless a CEMS is installed to
measure PM.
(5) For boilers and process heaters
with electrostatic precipitators (ESP) in
combination with wet scrubbers, you
must measure the pH, pressure drop,
and liquid flow rate of the wet scrubber
during the HCl performance test and
you must measure the voltage and
current of the ESP collection fields
during the mercury and PM
performance test. You would then be
required to calculate the average value
of these parameters for each test run.
The average of the three test run
averages would establish your sitespecific minimum pH, pressure drop,
and liquid flowrate operating limit for
the wet scrubber and the minimum
voltage and current operating limits for
the ESP.
(6) For boilers and process heaters
that choose to demonstrate compliance
with the mercury emission limit on the
basis of fuel analysis, you would be
required to measure the mercury
content of the inlet fuel that was burned
during the mercury performance test.
This value is your maximum fuel inlet
mercury operating limit.
(7) For boilers and process heaters
that choose to demonstrate compliance
with the HCl emission limit on the basis
of fuel analysis, you would be required
to measure the chlorine content of the
inlet fuel that was burned during the
HCl performance test. This value is your
maximum fuel inlet chlorine operating
limit.
These proposed operating limits
would not apply to owners or operators
of boilers or process heaters having a
heat input capacity of less than 10
million Btu per hour (MMBtu/h) or
boilers or process heaters of any size
which combust natural gas or refinery
gas, as discussed in section IV.D.3 of
this preamble. Instead, we are proposing
that owners or operators of such boilers
and process heaters submit to the
delegated authority or EPA, as
appropriate, if requested,
documentation that a tune-up meeting
the requirements of the proposed rule
was conducted. We are proposing that,
to comply with the work practice
standard, a tune-up procedure include
the following:
(1) Inspect the burner, and clean or
replace any components of the burner as
necessary,
(2) Inspect the flame pattern and make
any adjustments to the burner necessary
to optimize the flame pattern consistent
with the manufacturer’s specifications,
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(3) Inspect the system controlling the
air-to-fuel ratio, and ensure that it is
correctly calibrated and functioning
properly,
(4) Minimize total emissions of CO
consistent with the manufacturer’s
specifications,
(5) Measure the concentration in the
effluent stream of CO in ppmvd, before
and after the adjustments are made,
(6) Submit an annual report
containing the concentrations of CO in
the effluent stream in ppmvd, and
oxygen in percent dry basis, measured
before and after the adjustments of the
boiler, a description of any corrective
actions taken as a part of the
combustion adjustment, and the type
and amount of fuel used over the 12
months prior to the annual adjustment.
Further, all owners or operators of
major source facilities having boilers
and process heaters subject to this rule
would be required to submit to the
delegated authority or EPA, as
appropriate, documentation that an
energy assessment was performed, by
qualified personnel, and the costeffective energy conservation measures
indentified. The procedures for an
energy assessment are:
(1) Conduct a visual inspection of the
boiler system.
(2) Establish operating characteristics
of the facility, energy system
specifications, operating and
maintenance procedures, and unusual
operating constraints,
(3) Identify major energy consuming
systems,
(4) Review available architectural and
engineering plans, facility operation and
maintenance procedures and logs, and
fuel usage,
(5) Identify a list of major energy
conservation measures,
(6) Determine the energy savings
potential of the energy conservation
measures identified, and
(7) Prepare a comprehensive report
detailing the ways to improve
efficiency, the cost of specific
improvements, benefits, and the time
frame for recouping those investments.
G. What are the continuous compliance
requirements?
To demonstrate continuous
compliance with the emission
limitations, we are proposing following
requirements:
(1) For units combusting coal,
biomass, or residual fuel oil (i.e., No 4,
5 or 6 fuel oil) with heat input
capacities of less than 250 million Btu
per hour that do not use a wet scrubber,
we are proposing that opacity levels be
maintained to less than 10 percent
(daily average) for existing and new
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units with applicable emission limits.
Or, if the unit is controlled with a fabric
filter, instead of continuous monitoring
of opacity, the fabric filter must be
continuously operated such that the bag
leak detection system alarm does not
sound more than 5 percent of the
operating time during any 6-month
period (unless a PM CEMS is used).
(2) For units combusting coal,
biomass, or residual oil with heat input
capacities of 250 million Btu per hour
or greater, we are proposing that PM
CEMS be installed and operated and
that PM levels (monthly average) be
maintained below the applicable PM
limit.
(3) For boilers and process heaters
with wet scrubbers, we are proposing
that you monitor pressure drop and
liquid flow rate of the scrubber and
maintain the 12-hour block averages at
or above the operating limits established
during the performance test. You must
monitor the pH of the scrubber and
maintain the 12-hour block average at or
above the operating limit established
during the performance test to
demonstrate continuous compliance
with the HCl emission limits.
(4) For boilers and process heaters
with dry scrubbers, we are proposing
that you continuously monitor the
sorbent injection rate and maintain it at
or above the operating limits established
during the performance tests.
(5) For boilers and process heaters
having heat input capacities of less than
250 million Btu per hour with an ESP
in combination with a wet scrubber, we
are proposing that you monitor the pH,
pressure drop, and liquid flow rate of
the wet scrubber and maintain the 12hour block averages at or above the
operating limits established during the
HCl performance test and that you
monitor the voltage and current of the
ESP collection plates and maintain the
12-hour block averages at or above the
operating limits established during the
mercury or PM performance test.
(6) For units that choose to comply
with either the mercury emission limit
or the HCl emission limit based on fuel
analysis rather than on performance
stack testing, we are proposing that you
maintain daily fuel records that
demonstrate that you burned no new
fuels or fuels from a new supplier such
that the mercury content or the chlorine
content of the inlet fuel was maintained
at or below your maximum fuel mercury
content operating limit or your chlorine
content operating limit set during the
performance stack tests. If you plan to
burn a new fuel, a fuel from a new
mixture, or a new supplier’s fuel that
differs from what was burned during the
initial performance tests, then you must
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recalculate the maximum mercury input
and/or the maximum chlorine input
anticipated from the new fuels based on
supplier data or own fuel analysis, using
the methodology specified in Table 6 of
this proposed rule. If the results of
recalculating the inputs exceed the
average content levels established
during the initial test then, you must
conduct a new performance test(s) to
demonstrate continuous compliance
with the applicable emission limit.
(7) For all boilers and process heaters,
we are proposing that you maintain
daily records of fuel use that
demonstrate that you have burned no
materials that are considered solid
waste.
(8) For boilers and process heaters in
any of the subcategories with heat input
capacities greater than 100 MMBtu/h,
we are proposing that you continuously
monitor CO and maintain the average
CO emissions at or below the applicable
limit listed in Tables 1 or 2 of this
proposed rule.
If an owner or operator would like to
use a control device other than the ones
specified in this section to comply with
this proposed rule, the owner/operator
should follow the requirements in 40
CFR 63.8(f), which presents the
procedure for submitting a request to
the Administrator to use alternative
monitoring.
H. What are the notification,
recordkeeping and reporting
requirements?
All new and existing sources would
be required to comply with certain
requirements of the General Provisions
(40 CFR part 63, subpart A), which are
identified in Table 10 of this proposed
rule. The General Provisions include
specific requirements for notifications,
recordkeeping, and reporting.
Each owner or operator would be
required to submit a notification of
compliance status report, as required by
§ 63.9(h) of the General Provisions. This
proposed rule would require the owner
or operator to include in the notification
of compliance status report
certifications of compliance with rule
requirements.
Semiannual compliance reports, as
required by § 63.10(e)(3) of subpart A,
would be required only for semiannual
reporting periods when a deviation from
any of the requirements in the rule
occurred, or any process changes
occurred and compliance certifications
were reevaluated.
This proposed rule would require
records to demonstrate compliance with
each emission limit and work practice
standard. These recordkeeping
requirements are specified directly in
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the General Provisions to 40 CFR part
63, and are identified in Table 10.
Owners or operators of sources with
units with heat input capacity of less
than 10 MMBtu/h or units combusting
natural gas or refinery gas must keep
records of the dates and the results of
each required boiler tune-up.
Records of either continuously
monitored parameter data for a control
device if a device is used to control the
emissions or CEMS data would be
required.
We are proposing that you must keep
the following records:
(1) All reports and notifications
submitted to comply with this proposed
rule.
(2) Continuous monitoring data as
required in this proposed rule.
(3) Each instance in which you did
not meet each emission limit and each
operating limit (i.e., deviations from this
proposed rule).
(4) Daily hours of operation by each
source.
(5) Total fuel use by each affected
source electing to comply with an
emission limit based on fuel analysis for
each 30-day period along with a
description of the fuel, the total fuel
usage amounts and units of measure,
and information on the supplier and
original source of the fuel.
(6) Calculations and supporting
information of chlorine fuel input, as
required in this proposed rule, for each
affected source with an applicable HCl
emission limit.
(7) Calculations and supporting
information of mercury fuel input, as
required in this proposed rule, for each
affected source with an applicable
mercury emission limit.
(8) A signed statement, as required in
this proposed rule, indicating that you
burned no new fuel type and no new
fuel mixture or that the recalculation of
chlorine input demonstrated that the
new fuel or new mixture still meets
chlorine fuel input levels, for each
affected source with an applicable HCl
emission limit.
(9) A signed statement, as required in
this proposed rule, indicating that you
burned no new fuels and no new fuel
mixture or that the recalculation of
mercury fuel input demonstrated that
the new fuel or new fuel mixture still
meets the mercury fuel input levels, for
each affected source with an applicable
mercury emission limit.
(10) A copy of the results of all
performance tests, fuel analysis, opacity
observations, performance evaluations,
or other compliance demonstrations
conducted to demonstrate initial or
continuous compliance with this
proposed rule.
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(11) A copy of your site-specific
monitoring plan developed for this
proposed rule as specified in 63 CFR
63.8(e), if applicable.
We are also proposing to require that
you submit the following reports and
notifications:
(1) Notifications required by the
General Provisions.
(2) Initial Notification no later than
120 calendar days after you become
subject to this subpart.
(3) Notification of Intent to conduct
performance tests and/or compliance
demonstration at least 60 calendar days
before the performance test and/or
compliance demonstration is scheduled.
(4) Notification of Compliance Status
60 calendar days following completion
of the performance test and/or
compliance demonstration.
(5) Compliance reports semi-annually.
I. Submission of Emissions Test Results
to EPA
The EPA must have performance test
data to conduct effective reviews of
CAA Section 112 and 129 standards, as
well as for many other purposes
including compliance determinations,
emissions factor development, and
annual emissions rate determinations.
In conducting these required reviews,
we have found it ineffective and time
consuming not only for us but also for
regulatory agencies and source owners
and operators to locate, collect, and
submit emissions test data because of
varied locations for data storage and
varied data storage methods. One
improvement that has occurred in
recent years is the availability of stack
test reports in electronic format as a
replacement for cumbersome paper
copies.
In this action, we are taking a step to
improve data accessibility. Owners and
operators of boilers and process heaters
will be required to submit to an EPA
electronic database an electronic copy of
reports of certain performance tests
required under this rule. Data entry will
be through an electronic emissions test
report structure called the Electronic
Reporting Tool (ERT) that will be used
by the EPA staff as part of the emissions
testing project. The ERT was developed
with input from stack testing companies
who generally collect and compile
performance test data electronically and
offices within State and local agencies
which perform field test assessments.
The ERT is currently available, and
access to direct data submittal to EPA’s
electronic emissions database
(WebFIRE) will become available by
December 31, 2011.
The requirement to submit source test
data electronically to EPA will not
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require any additional performance
testing and will apply to those
performance tests conducted using test
methods that are supported by ERT. The
ERT contains a specific electronic data
entry form for most of the commonly
used EPA reference methods. The Web
site listed at the end of this section
contains a listing of the pollutants and
test methods supported by ERT. In
addition, when a facility submits
performance test data to WebFIRE, there
will be no additional requirements for
emissions test data compilation.
Moreover, we believe industry will
benefit from development of improved
emissions factors, fewer follow-up
information requests, and better
regulation development as discussed
below. The information to be reported is
already required for the existing test
methods and is necessary to evaluate
the conformance to the test method.
One major advantage of submitting
source test data through the ERT is that
it provides a standardized method to
compile and store much of the
documentation required to be reported
by this rule while clearly stating what
testing information we require. Another
important benefit of submitting these
data to EPA at the time the source test
is conducted is that it will substantially
reduce the effort involved in data
collection activities in the future.
Specifically, because EPA would
already have adequate source category
data to conduct residual risk
assessments or technology reviews,
there would be fewer or less substantial
data collection requests (e.g., CAA
Section 114 letters). This results in a
reduced burden on both affected
facilities (in terms of reduced manpower
to respond to data collection requests)
and EPA (in terms of preparing and
distributing data collection requests).
State/local/Tribal agencies may also
benefit in that their review may be more
streamlined and accurate as the States
will not have to re-enter the data to
assess the calculations and verify the
data entry. Finally, another benefit of
submitting these data to WebFIRE
electronically is that these data will
improve greatly the overall quality of
the existing and new emissions factors
by supplementing the pool of emissions
test data upon which the emissions
factor is based and by ensuring that data
are more representative of current
industry operational procedures. A
common complaint we hear from
industry and regulators is that emissions
factors are outdated or not
representative of a particular source
category. Receiving and incorporating
data for most performance tests will
ensure that emissions factors, when
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updated, represent accurately the most
current operational practices. In
summary, receiving test data already
collected for other purposes and using
them in the emissions factors
development program will save
industry, State/local/Tribal agencies,
and EPA time and money and work to
improve the quality of emissions
inventories and related regulatory
decisions.
As mentioned earlier, the electronic
data base that will be used is EPA’s
WebFIRE, which is a Web site accessible
through EPA’s Technology Transfer
Network (TTN). The WebFIRE Web site
was constructed to store emissions test
data for use in developing emissions
factors. A description of the WebFIRE
data base can be found at https://
cfpub.epa.gov/oarweb/
index.cfm?action=fire.main.
The ERT will be able to transmit the
electronic report through EPA’s Central
Data Exchange (CDX) network for
storage in the WebFIRE data base.
Although ERT is not the only electronic
interface that can be used to submit
source test data to the CDX for entry
into WebFIRE, it makes submittal of
data very straightforward and easy. A
description of the ERT can be found at
https://www.epa.gov/ttn/chief/ert/
ert_tool.html.
IV. Rationale for This Proposed Rule
A. How did EPA determine which
sources would be regulated under this
proposed rule?
This proposed rule regulates source
categories covering industrial boilers,
institutional and commercial boilers,
and process heaters. These source
categories potentially include
combustion units that are already
regulated by other MACT standards
under CAA sections 112 or 129.
Therefore, we are excluding from this
proposed rule any units that are subject
to regulation in another MACT standard
established under CAA section 112 or a
standard established under CAA section
129.
The CAA specifically requires that
fossil fuel-fired steam generating units
of more than 25 megawatts that produce
electricity for sale (i.e., utility boilers) be
reviewed separately by EPA.
Consequently, this proposed rule would
not regulate fossil fuel-fired utility
boilers greater than 25 megawatts, but
would regulate fossil fuel-fired units
less than 25 megawatts and all utility
boilers firing a non-fossil fuel that is not
a solid waste.
The scope of the process heater source
category is limited to only indirect-fired
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units.3 Direct-fired units are covered in
other MACT standards or rulemakings
pertaining to industrial process
operations. For example, lime kilns are
covered by the Pulp and Paper NESHAP
(40 CFR part 63, subpart S). Indirectfired process heaters are similar to
boilers in fuel use, emissions, and
applicable controls, and, therefore, it is
appropriate for EPA to combine this
listed source category of units with the
listed source categories of industrial
boilers and commercial/institutional
boilers for purposes of developing
emission standards.
The proposed rule would not regulate
hot water heaters, as defined in this
proposed rule, because such units are
not part of the listed source categories.
Many industrial facilities have office
buildings located onsite which use hot
water heaters. Such hot water heaters,
by their design and operation, could be
considered boilers since hot water
heaters meet the definition of a boiler as
specified in the proposed rule, because
they are enclosed devices that combust
fuel for the purpose of recovery energy
to heat water. However, hot water
heaters are more appropriately
described as residential-type boilers, not
industrial, commercial, or institutional
boilers because their output (i.e., hot
water) is intended for personal use
rather than for use in an industrial,
commercial, or institutional process.
Moreover, since hot water heaters
generally are small and use natural gas
as fuel, their emissions are negligible
compared to the emissions from the
industrial operations that make such
facilities major sources, and compared
to boilers that are used for industrial,
commercial, or institutional purposes.
However, the primary reason that we are
excluding hot water heaters is that hot
water heaters are not part of the listed
source category. Consequently, we are
including a definition of hot water
heaters that includes fuel, size, pressure
and temperature limitations that we
believe are appropriate to distinguish
between residential-type units and
industrial, commercial, or institutional
units.
The CAA allows EPA to divide source
categories into subcategories based on
differences in class, type, or size. For
example, differences between given
types of units can lead to corresponding
differences in the nature of emissions
and the technical feasibility of applying
emission control techniques. The
design, operating, and emissions
information that EPA has reviewed
3 Indirect-fired process heaters are combustion
devices in which the combustion gases do not
directly come into contact with process materials.
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indicates differences in unit design that
distinguish different types of boilers.
Data indicate that there are significant
design and operational differences
between units that burn coal, biomass,
liquid, and gaseous fuels.
Boiler systems are designed for
specific fuel types and will encounter
problems if a fuel with characteristics
other than those originally specified is
fired. While many boilers in the
population data base are indicated to cofire liquids or gases with solid fuels, in
actuality most of these commonly use
fuel oil or natural gas as a startup fuel
only, and operate on solid fuel during
the remainder of their operation. In
contrast, some co-fired units are
specifically designed to fire
combinations of solids, liquids, and
gases. Changes to the fuel type would
generally require extensive changes to
the fuel handling and feeding system
(e.g., a stoker using wood as fuel would
need to be redesigned to handle fuel oil
or gaseous fuel). Additionally, the
burners and combustion chamber would
need to be redesigned and modified to
handle different fuel types and account
for increases or decreases in the fuel
volume. In some cases, the changes may
reduce the capacity and efficiency of the
boiler or process heater. An additional
effect of these changes would be
extensive retrofitting needed to operate
using a different fuel.
The design of the boiler or process
heater, which is dependent in part on
the type of fuel being burned, impacts
the degree of combustion. Boilers and
process heaters emit a number of
different types of HAP emissions.
Organic HAP are formed from
incomplete combustion and are
influenced by the design and operation
of the unit. The degree of combustion
may be greatly influenced by three
general factors: Time, turbulence, and
temperature. On the other hand, the
formation of fuel-dependent HAP
(metals, mercury, and acid gases) is
dependent upon the composition of the
fuel. These fuel-dependent HAP
emissions generally can be controlled by
either changing the fuel property before
combustion or by removing the HAP
from the flue gas after combustion.
We first examined the HAP emissions
results to determine if subcategorization
by unit design type was warranted. We
concluded that the data were sufficient
for determining that a distinguishable
difference in performance exists based
on unit design type. Therefore, because
different types of units have different
emission characteristics which may
influence the feasibility of effectiveness
of emission control, they should be
regulated separately (i.e.,
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subcategorized). Accordingly, we
propose to subcategorize boilers and
process heaters based on unit design in
order to account for these differences in
emissions and applicable controls.
For the fuel-dependent HAP (metals,
mercury, acid gases), we identified five
basic unit types as subcategories. These
are the following: (1) Units designed to
burn coal, (2) units designed to burn
biomass, (3) units designed to burn
liquid fuel, (4) units designed to burn
natural gas/refinery gas, and (5) units
designed to burn other process gases.
Within the basic unit types there are
different designs and combustion
systems that, while having a minor
effect on fuel-related HAP emissions,
have a much larger effect on organic
HAP emissions. Therefore, we decided
to further subcategorize based on these
different unit designs but only in
proposing standards for organic HAP
emissions. We have identified the
following 11 subcategories for organic
HAP:
Pulverized coal units,
Stokers designed to burn coal,
Fluidized bed units designed to burn coal,
Stokers designed to burn biomass,
Fluidized bed units designed to burn
biomass,
Suspension burners/Dutch Ovens designed to
burn biomass,
Fuel Cells designed to burn biomass,
Units designed to burn liquid fuel,
Units designed to burn natural gas/refinery
gas,
Units designed to burn other gases, and
Metal process furnaces.
These subcategories are based on the
primary fuel that the boiler or process
heater is designed to burn. We are aware
that some boilers burn a combination of
fuel types or burn a different fuel type
as a backup fuel if the primary fuel
supply is curtailed. However, boilers are
designed based on the primary fuel type
(and perhaps to burn a backup fuel) and
can encounter operational problems if
another fuel type that was not
considered in its design is fired at more
than 10 percent of the heat input to the
boiler. Also, in some cases, a small
amount of coal may be added to a
biomass designed boiler to stabilize the
combustion when the biomass has a
higher moisture content than normal. In
this case, it would not be appropriate to
classify the boiler as being in one of the
‘‘coal’’ subcategories because the boiler
design is such that it is constructed and
operated to combust biomass, and could
not combust primarily coal (without
significant retrofitting or design
changes). Therefore, we are proposing to
define boilers and process heaters that
burn at least 10 percent coal (on an
annual heat input basis) as being in one
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of the coal subcategories. We are also
proposing to define boilers and process
heaters that burn at least 10 percent
biomass, and less than 10 percent coal
(on an annual heat input basis) as being
in one of the biomass subcategories. We
are proposing to define boilers and
process heaters that burn at least 10
percent liquid fuel, and less than 10
percent solid fuel (on an annual heat
input basis) as being in the liquid
subcategory. We are proposing to define
boilers and process heaters that burn at
least 90 percent natural gas and/or
refinery gas (on an annual heat input
basis) as being in the Gas 1 subcategory.
This would ensure that each boiler and
process heater is subject to emissions
standards calculated on the basis of the
best performing units with similar
design and operation. The remaining
boilers and process heaters, except for
those described below would be in the
Gas 2 subcategory.
In addition, there is a certain class of
natural gas-fired process heaters that are
designed and operated differently
compared to typical process heaters. A
review of information gathered on
process heaters used in the metal
processing industries shows that these
process heaters typically are designed
with multiple burners that fire into
individual combustion chambers. These
individual burners are operated to cycle
on and off to maintain the proper
temperatures throughout the various
zones of the process heater. Thus, due
to their design, these process heaters
rarely operate in a steady-state
condition due to burners constantly
starting up and shutting down. This
results in emissions characteristics
different from the process heaters used
in other industries. The process heaters
used in metal processing are natural gasfired and include annealing furnaces,
preheat furnaces, reheat furnaces, aging
furnaces, and heat treat furnaces.
Therefore, we propose to identify these
metal processing process heaters
(furnaces) as a separate eleventh
subcategory.
In summary, we have identified 11
subcategories of boilers and process
heaters located at major sources.4
B. How did EPA select the format for
this proposed rule?
This proposed rule includes
numerical emission limits for PM,
mercury, HCl, CO, and D/F. The
selection of numerical emission limits
as the format for this proposed rule
4 See Memorandum ‘‘Development of Baseline
Emission Factors for Boilers and Process Heaters at
Commercial, Industrial, and Institutional Facilities’’
located in the docket.
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provides flexibility for the regulated
community by allowing a regulated
source to choose any control technology
or technique to meet the emission
limits, rather than requiring each unit to
use a prescribed control method that
may not be appropriate in each case.
We are proposing numerical emission
rate limits as a mass of pollutant emitted
per heat energy input to the boiler or
process heater for the fuel-related HAP.
The most typical units for the limits are
pounds of pollutant emitted per million
Btu of heat input. The mass per heat
input units are consistent with other
Federal and many State boiler
regulations 5 and allows easy
comparison between such requirements.
Additionally, this proposed rule
contains an option to monitor inlet
chlorine and mercury content in the fuel
to meet outlet emission rate limits. This
option can only be done on a mass
basis.
We are proposing outlet concentration
as the format for the organic HAP. An
outlet concentration limit for organic
HAP would also be consistent with the
format of other regulations.
Boilers and process heaters can emit
a wide variety of compounds,
depending on the fuel burned. Because
of the large number of HAP potentially
present and the disparity in the quantity
and quality of the emissions information
available, EPA grouped the HAP into
five categories: Mercury, non-mercury
metallic HAP, inorganic HAP, nondioxin organic HAP, and D/F. The
pollutants within each group have
similar characteristics and can be
controlled with the same techniques.
For example, non-mercury metallic HAP
can be controlled with PM controls. We
chose to look at mercury separately from
other metallic HAP due to its different
chemical characteristics and its different
control technology feasibility.
Next, EPA identified compounds that
could be used as surrogates for all the
compounds in each pollutant category.
For the non-mercury metallic HAP, we
chose to use PM as a surrogate. Most, if
not all, non-mercury metallic HAP
emitted from combustion sources will
appear on the flue gas fly-ash.
Therefore, the same control techniques
that would be used to control the fly-ash
PM will control non-mercury metallic
HAP. PM was also chosen instead of
specific metallic HAP because all fuels
do not emit the same type and amount
of metallic HAP but most generally emit
5 For example, the new source performance
standards for industrial, commercial, and
institutional steam generating units (40 CFR subpart
Db) have emission limits for sulfur dioxide,
nitrogen oxide, and PM in terms of pounds per
million Btu.
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PM that includes some amount and
combination of metallic HAP. The use
of PM as a surrogate will also eliminate
the cost of performance testing to
comply with numerous standards for
individual non-mercury metals. Since
non-mercury metallic HAP tend to be on
small size particles (i.e., fine particle
enrichment), we considered using PM2.5
as the surrogate, but we determined that
PM (filterable) was the more appropriate
surrogate for two reasons. First, the test
method (OTM 27) for measuring PM2.5
is only applicable for use in exhaust
stacks without entrained water droplets.
Therefore, the test method (OTM 27) for
measuring PM2.5 is not applicable for
units equipped with wet scrubbers
which will likely be necessary to
achieve the proposed HCl emission
limits. Second, based on the emission
data obtained during EPA’s information
collection effort from units not
equipped with wet scrubbers, the
majority of the filterable PM emitted
from units that are well controlled for
PM is fine particulate (PM2.5). Thus, we
are proposing to use PM (filterable),
instead of PM2.5, as the surrogate for
non-mercury metals.
For non-metallic inorganic HAP, EPA
is proposing using HCl as a surrogate.
The emissions test information available
to EPA indicate that the primary nonmetallic inorganic HAP emitted from
boilers and process heaters are acid
gases, with HCl present in the largest
amounts. Other inorganic compounds
emitted are found in much smaller
quantities. Control technologies that
reduce HCl also control other inorganic
compounds such as chlorine and other
acid gases. Thus, the best controls for
HCl would also be the best controls for
other inorganic HAP that are acid gases.
Therefore, HCl is a good surrogate for
inorganic HAP because controlling HCl
will result in control of other inorganic
HAP emissions.
For organic HAP, we considered both
THC and CO as a surrogate for nondioxin organic HAP emitted from
boilers and process heaters. CO has
generally been used as a surrogate for
organic HAP because CO is a good
indicator of incomplete combustion and
organic HAP are products of incomplete
combustion. However, based on
concerns that CO may not be an
appropriate surrogate for D/F because,
unlike other organic HAP, D/F can be
formed outside the combustion unit, we
are proposing to use CO as a surrogate
for non-dioxin organic HAP. We are also
proposing separate emission limits for
D/F. For non-dioxin organic HAP, using
CO as a surrogate is a reasonable
approach because minimizing CO
emissions will result in minimizing
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non-dioxin organic HAP. Methods used
for the control of non-dioxin organic
HAP emissions would be the same
methods used to control CO emissions.
These emission control methods include
achieving good combustion or using an
oxidation catalyst. Standards limiting
emissions of CO will also result in
decreases in non-dioxin organic HAP
emissions (with the additional benefit of
decreasing volatile organic compounds
(VOC) emissions). Establishing emission
limits for specific organic HAP (with the
exception of D/F) would be impractical
and costly. CO, which is less expensive
to test for and monitor, is appropriate
for use as a surrogate for non-dioxin
organic HAP.
The Agency recognizes that the level
and distribution of organic HAP
associated with CO emissions will vary
from unit to unit. For example, the
principal organic HAP emitted from
coal-fired units is benzene, which
accounts for about 20 percent of the
organic HAP while the principal organic
HAP emitted from biomass-fired units is
formaldehyde, which accounts for 34
percent of the organic HAP.6 Limiting
CO as a surrogate for only non-dioxin
organic HAP will eliminate costs
associated with speciating numerous
compounds. The proposed standards
establish separate emission limits for
D/F because of the high toxicity
associated with even low masses of
these compounds.
THC could also be an appropriate
surrogate for non-dioxin organic HAP
because low THC also ensures good
combustion efficiency and, thus, low
organic HAP. However, we believe CO
is preferable because many sources
currently have CO CEMS. In addition,
there are more CO emission data
available for the various subcategories
than THC emission data.
C. How did EPA determine the proposed
emission limitations for existing units?
All standards established pursuant to
CAA section 112(d)(2) must reflect
MACT, the maximum degree of
reduction in emissions of air pollutants
that the Administrator, taking into
consideration the cost of achieving such
emissions reductions, and any nonair
quality health and environmental
impacts and energy requirements,
determined is achievable for each
category. For existing sources, MACT
cannot be less stringent than the average
emission limitation achieved by the best
performing 12 percent of existing
6 Based on emission factors reported on EPA
webpage ‘‘AP 42, Fifth Edition, Volume 1—Chapter
1: External Combustion Sources’’ located at https://
www.epa.gov/ttn/chief/ap42/ch01/.
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sources for categories and subcategories
with 30 or more sources or the best
performing 5 sources for subcategories
with less than 30 sources. This
requirement constitutes the MACT floor
for existing boilers and process heaters.
However, EPA may not consider costs or
other impacts in determining the MACT
floor. EPA must consider cost, nonair
quality health and environmental
impacts, and energy requirements in
connection with any standards that are
more stringent than the MACT floor
(beyond-the-floor controls).
D. How did EPA determine the MACT
floors for existing units?
EPA must consider available
emissions information to determine the
MACT floors. For each pollutant, we
calculated the MACT floor for a
subcategory of sources by ranking all the
available emissions data from units
within the subcategory from lowest
emissions to highest emissions, and
then taking the numerical average of the
test results from the best performing
(lowest emitting) 12 percent of sources.
We first considered whether fuel
switching would be an appropriate
control option for sources in each
subcategory. We considered the
feasibility of fuel switching to other
fuels used in the subcategory and to
fuels from other subcategories. This
consideration included determining
whether switching fuels would achieve
lower HAP emissions. A second
consideration was whether fuel
switching could be technically achieved
by boilers and process heaters in the
subcategory considering the existing
design of boilers and process heaters.
We also considered the availability of
various types of fuel.
After considering these factors, we
determined that fuel switching was not
an appropriate control technology for
purposes of determining the MACT
floor level of control for any
subcategory. This decision was based on
the overall effect of fuel switching on
HAP emissions, technical and design
considerations discussed previously in
this preamble, and concerns about fuel
availability.
Based on the emission factors
reported in EPA’s Technology Transfer
Network, we determined that while fuel
switching from solid fuels to gaseous or
liquid fuels would decrease PM and
some metals emissions, emissions of
some organic HAP (e,g., formaldehyde)
would increase.7 This determination is
discussed in the memorandum
7 See EPA webpage ‘‘AP 42, Fifth Edition, Volume
1—Chapter 1: External Combustion Sources’’
located at https://www.epa.gov/ttn/chief/ap42/ch01/
index.html.
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‘‘Development of Fuel Switching Costs
and Emission Reductions for Industrial,
Commercial, and Institutional Boilers
and Process Heaters National Emission
Standards for Hazardous Air Pollutants’’
located in the docket.
A similar determination was made
when considering fuel switching to
cleaner fuels within a subcategory. For
example, the term ‘‘clean coal’’ refers to
coal that is lower in sulfur content and
not necessarily lower in HAP content.
Data gathered by EPA also indicates that
within specific coal types HAP content
can vary significantly. Switching to a
low sulfur coal may actually increase
emissions of some HAP. Therefore, it is
not appropriate for EPA to include fuel
switching to a low sulfur coal as part of
the MACT standards for boilers and
process heaters. Fuel switching from
coal to biomass would result in similar
impacts on HAP emissions. While this
would reduce metallic HAP emissions,
it would likely increase emissions of
organics based on information in the
emissions database.
Another factor considered was the
availability of alternative fuel types.
Natural gas pipelines are not available
in all regions of the U.S., and natural gas
is simply not available as a fuel for
many industrial, commercial, and
institutional boilers and process heaters.
Moreover, even where pipelines provide
access to natural gas, supplies of natural
gas may not be adequate. For example,
it is common practice in cities during
winter months (or periods of peak
demand) to prioritize natural gas usage
for residential areas before industrial
usage. Requiring boilers and process
heaters to switch to natural gas would
place an even greater strain on natural
gas resources. Consequently, even
where pipelines exist, some units would
not be able to run at normal or full
capacity during these times if shortages
were to occur. Therefore, under any
circumstances, there would be some
units that could not comply with a
requirement to switch to natural gas.
Similar problems for fuel switching to
biomass could arise. Existing sources
burning biomass generally are
combusting a recovered material from
the manufacturing or agriculture
process. Industrial, commercial, and
institutional facilities that are not
associated with the wood products
industry or agriculture may not have
access to a sufficient supply of biomass
materials to replace their fossil fuel.
As discussed previously in this
preamble, there is a significant concern
that switching fuels would be infeasible
for sources designed and operated to
burn specific fuel types. Changes in the
type of fuel burned by a boiler or
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process heater (solid, liquid, or gas) may
require extensive changes to the fuel
handling and feeding system (e.g., a
stoker using wood as fuel would need
to be redesigned to handle fuel oil or
gaseous fuel). Additionally, burners and
combustion chamber designs are
generally not capable of handling
different fuel types, and generally
cannot accommodate increases or
decreases in the fuel volume. Design
changes to allow different fuel use, in
some cases, may reduce the capacity
and efficiency of the boiler or process
heater. Reduced efficiency may result in
less complete combustion and, thus, an
increase in organic HAP emissions. For
the reasons discussed above, we
decided that fuel switching to cleaner
solid fuels or to liquid or gaseous fuels
is not an appropriate criteria for
identifying the MACT floor emission
levels for units in the boilers and
process heaters category.
Therefore, the MACT floor limits for
each of the HAP and HAP surrogates
(PM, mercury, CO, HCl, and D/F) are
calculated based on the performance of
the lowest emitting (best performing)
sources in each of the subcategories. We
ranked all of the sources for which we
had data based on their emissions and
identified the lowest emitting 12
percent of the sources for each HAP.
We used the emissions data for those
best performing affected sources to
determine the emission limits to be
proposed, with an accounting for
variability. EPA must exercise its
judgment, based on an evaluation of the
relevant factors and available data, to
determine the level of emissions control
that has been achieved by the best
performing sources under variable
conditions. The DC Circuit Court of
Appeals has recognized that EPA may
consider variability in estimating the
degree of emission reduction achieved
by best-performing sources and in
setting MACT floors. See Mossville
Envt’l Action Now v. EPA, 370 F.3d
1232, 1241–42 (DC Cir 2004) (holding
EPA may consider emission variability
in estimating performance achieved by
best-performing sources and may set the
floor at level that best-performing source
can expect to meet ‘‘every day and under
all operating conditions’’).
In determining the MACT floor limits,
we first determine the floor, which is
the level achieved in practice by the
average of the top 12 percent. We then
assess variability of the best performers
by using a statistical formula designed
to estimate a MACT floor level that is
achievable by the average of the best
performing sources if the best
performing sources were able to
replicate the compliance tests in our
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data base. Specifically, the MACT floor
limit is an upper prediction limit (UPL)
calculated with the Student’s t-test
using the TINV function in Microsoft
Excel. The Student’s t-test has also been
used in other EPA rulemakings (e.g.,
NSPS for Hospital/Medical/Infectious
Waste Incinerators) in accounting for
variability. A prediction interval for a
future observation is an interval that
will, with a specified degree of
confidence, contain the next (or some
other pre-specified) randomly selected
observation from a population. In other
words, the prediction interval estimates
what future values will be, based upon
present or past background samples
taken. Given this definition, the UPL
represents the value which we can
expect the mean of 3 future observations
(3-run average) to fall below, based
upon the results of an independent
sample from the same population. In
other words, if we were to randomly
select a future test condition from any
of these sources (i.e., average of 3 runs),
we can be 99% confident that the
reported level will fall at or below the
UPL value. To calculate the UPL, we
used the average (or sample mean) and
sample standard deviation, which are
two statistical measures calculated from
the sample data. The average is the
central value of a data set, and the
standard deviation is the common
measure of the dispersion of the data set
around the average.
We first determined the distribution
of the emissions data for the bestperforming 12 percent of units within
each subcategory prior to calculating
UPL values. To evaluate the distribution
of the best performing dataset, we first
computed the skewness and kurtosis
statistics and then conducted the
appropriate small-sample hypothesis
tests.
The skewness statistic (S)
characterizes the degree of asymmetry of
a given data distribution. Normally
distributed data have a skewness of 0.
A skewness statistic that is greater (less)
than 0 indicates that the data are
asymmetrically distributed with a right
(left) tail extending towards positive
(negative) values. Further, the standard
error of the skewness statistic (SES) is
given by SES = SQRT(6/N) where N is
the sample size. According to the small
sample skewness hypothesis test, if the
skewness statistic (S) is greater than two
times the SES, the data distribution can
be considered non-normal.
The kurtosis statistic (K) characterizes
the degree of peakedness or flatness of
a given data distribution in comparison
to a normal distribution. Normally
distributed data have a kurtosis of 0. A
kurtosis statistic that is greater (less)
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than 0 indicates a relatively peaked
(flat) distribution. Further, the standard
error of the kurtosis statistic (SEK) is
given by SEK = SQRT(24/N) where N is
the sample size. According to the small
sample kurtosis hypothesis test, if the
kurtosis statistic (K) is greater than two
times the SEK, the data distribution is
typically considered to be non-normal.
We applied the skewness and kurtosis
hypothesis tests to both the reported test
values and the lognormal values of the
reported test values. If the skewness (S)
and kurtosis (K) statistics of the reported
data set were both less than twice the
SES and SEK, respectively, the dataset
was classified as normally distributed. If
neither of the skewness (S) and kurtosis
(K) statistics, or only one of these
statistics were less than twice the SES
or SEK, respectively, then the skewness
and kurtosis hypothesis tests were
conducted for the natural logtransformed data. Then the distribution
most similar to a normal distribution
was selected as the basis for calculating
the UPL. If both the reported values and
the natural-log transformed reported
values had skewness (S) and kurtosis
(K) statistics that were greater than
twice the SES or SEK, respectively, the
normally distributed dataset was
selected as the basis of the floor to be
conservative. If the results of the
skewness and kurtosis hypothesis tests
were mixed for the reported values and
the natural log-transformed reported
values, we also chose the normal
distribution to be conservative. We
believe this approach is more accurate
and obtained more representative
results than a more simplistic normal
distribution assumption.
Since the compliance with the MACT
floor emission limit is based on the
average of a three run test, the UPL is
calculated by:
⎛1 1 ⎞
UPL = x +t (0.99 ,n − 1) × s2 × ⎜ + ⎟
⎝n m⎠
Where:
n = the number of test runs
m = the number of test runs in the
compliance average
This calculation was performed using
the following two Excel functions:
Normal distribution: 99% UPL =
AVERAGE(Test Runs in Top 12%)
+ [STDEV(Test Runs in Top 12%) ×
TINV(2 × probability, n-1 degrees of
freedom)*SQRT((1/n)+(1⁄3))], for a
one-tailed t-value (with 2 ×
probability), probability of 0.01, and
sample size of n
Lognormal distribution: 99% UPL =
EXP{AVERAGE(Natural Log Values
of Test Runs in Top 12%) +
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[STDEV(Natural Log Values of Test
Runs in Top 12%) × TINV(2 ×
probability, n-1 degrees of
freedom)* SQRT((1/n)+(1⁄3))]}, for a
one-tailed t-value (with 2 ×
probability), probability of 0.01, and
sample size of n
Test method measurement
imprecision can also be a component of
data variability. At very low emissions
levels as encountered in the data used
to support this rule, the inherent
imprecision in the pollutant
measurement method has a large
influence on the reliability of the data
underlying the regulatory floor or
beyond-the-floor emissions limit. Of
particular concern are those data that
are reported near or below a test
method’s pollutant detection capability.
In our guidance for reporting pollutant
emissions used to support this rule, we
specified the criteria for determining
test-specific method detection levels.
Those criteria insure that there is about
a 1 percent probability of an error in
deciding that the pollutant measured at
the method detection level is present
when in fact it was absent. Such a
probability is also called a false positive
or the alpha, Type I, error. Another view
of this probability is that one is 99
percent certain of the presence of the
pollutant measured at the method
detection level. Because of matrix
effects, laboratory techniques, sample
size, and other factors, method detection
levels normally vary from test to test.
We requested sources to identify (i.e.,
flag) data which were measured below
the method detection level and to report
those values as equal to the test-specific
method detection level.
Variability of data due to
measurement imprecision is inherently
and reasonably addressed in calculating
the floor emissions limit when the data
base represents multiple tests for which
all of the data are measured significantly
above the method detection level. That
is less true when the data base includes
emissions occurring below method
detection capabilities and are reported
as the method detection level values.
The data base is then truncated at the
lower end of the measurement range
(i.e., no values reported below the
method detection level) and we believe
that a floor emissions limit based on a
truncated data base or otherwise
including values at or near the method
detection level may not adequately
account for data measurement
variability. We did not adjust the
calculated floor for the data used for this
proposal; although, we believe that
accounting for measurement
imprecision should be an important
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consideration in calculating the floor
emissions limit. We request comment
on approaches suitable to account for
measurement variability in establishing
the floor emissions limit when based on
measurements at or near the method
detection level.
As noted above, the confidence level
that a value measured at the detection
level is greater than zero is about 99
percent. The expected measurement
imprecision for an emissions value
occurring at or near the method
detection level is about 40 to 50 percent.
Pollutant measurement imprecision
decreases to a consistent relative 10 to
15 percent for values measured at a
level about three times the method
detection level.8 One approach that we
believe could be applied to account for
measurement variability would require
defining a method detection level that is
representative of the data used in
establishing the floor emissions limits
and also minimizes the influence of an
outlier test-specific method detection
level value. The first step in this
approach would be to identify the
highest test-specific method detection
level reported in a data set that is also
equal to or less than the floor emissions
limit calculated for the data set. This
approach has the advantage of relying
on the data collected to develop the
floor emissions limit while to some
degree minimizing the effect of a test(s)
with an inordinately high method
detection level (e.g., the sample volume
was too small, the laboratory technique
was insufficiently sensitive, or the
procedure for determining the detection
level was other than that specified).
The second step would be to
determine the value equal to three times
the representative method detection
level and compare it to the calculated
floor emissions limit. If three times the
representative method detection level
were less than the calculated floor
emissions limit, we would conclude
that measurement variability is
adequately addressed and we would not
adjust the calculated floor emissions
limit. If, on the other hand, the value
equal to three times the representative
method detection level were greater
than the calculated floor emissions
limit, we would conclude that the
calculated floor emissions limit does not
account entirely for measurement
variability. We then would use the value
equal to three times the method
detection level in place of the calculated
floor emissions limit to ensure that the
8 American Society of Mechanical Engineers,
Reference Method Accuracy and Precision
(ReMAP): Phase 1, Precision of Manual Stack
Emission Measurements, CRTD Vol. 60, February
2001.
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floor emissions limit accounts for
measurement variability. We request
comment on this approach.
We are requesting comment on
whether there is a more appropriate
statistical approach to account for
variability in the MACT floor analyses
when there are emission data from a
limited number of units in the
subcategory.
However, after review of the available
HAP data, including both emission test
data and fuel analyses, we determined
that it was inappropriate to use only this
MACT floor approach to determine
variability and to establish emission
limits for boilers and process heaters,
because this approach considers only
the emissions test data. The main
problem with using only the HAP
emissions test data is that the data,
which may reflect the variability of fuelrelated HAP of the best performing
units, may not reflect the variability of
fuel-related HAP from the best
performing units over the long term.
Based on fuel-related HAP
concentrations (nine individual samples
collected over a 30-day period)
obtained, pursuant to letters mandating
data gathering issued under the
authority of CAA section 114, fuelrelated HAP levels in the various fuels
can vary significantly over time.
The first step in establishing a MACT
standard is to determine the MACT
floor. A necessary step in doing so is
determining the amount of HAP
emitted. In the case of fuel-related HAP
emitted, this is not necessarily a
straightforward undertaking. Single
stack measurements represent a
snapshot in time of a source’s
emissions, always raising questions of
how representative such emissions are
of the source’s emissions over time. The
variations in fuel-related HAP inputs
directly translate to a variability of fuelrelated HAP stack emissions.
We believe that single short term
stack test data (typically a few hours)
are probably not indicative of long term
emissions performance, and so are not
the best indicators of performance over
time. With these facts in mind, we
carefully considered alternatives other
than use of only single short-term stack
test results to quantify performance for
fuel-related HAP. We decided that the
most accurate method available to us to
determine long term fuel-related HAP
emissions performance was to use data
on the fuel-related HAP inputs in the
fuels used by the best performing units,
obtained as part of our information
collection effort under the authority of
CAA section 114, on long-term fuelrelated HAP concentrations (nine
individual samples collected over a 30-
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32021
day period) in each fuel, along with the
fuel-related HAP concentrations during
the stack tests.
As previously discussed above, we
account for variability in setting floors,
not only because variability is an
element of performance, but because it
is reasonable to assess best performance
over time. Here, for example, we know
that the HAP emission data from the
best performing units are short-term
averages, and that the actual HAP
emissions from those sources will vary
over time. If we do not account for this
variability, we would expect that even
the units that perform better than the
floor on average would potentially
exceed the floor emission levels a
significant part of the time which would
mean that variability was not properly
taken into account. This variability
includes the day-to-day variability in
the total fuel-related HAP input to each
unit and variability of the sampling and
analysis methods, and it includes the
variability resulting from site-to-site
differences for the best performing
units. We calculated the MACT floor
based on the UPL (upper 99th
percentile) as described earlier from the
average performance of the best
performing units, Students t-factor, and
the variability of the best performing
units.
This approach reasonably ensures that
the emission limit selected as the MACT
floor adequately represents the level of
emissions actually achieved by the
average of the units in the top 12
percent, considering ordinary
operational variability of those units.
Both the analysis of the measured
emissions from units representative of
the top 12 percent, and the variability
analysis, are reasonably designed to
provide a meaningful estimate of the
average performance, or central
tendency, of the best controlled 12
percent of units in a given subcategory.
A detailed discussion of the MACT
floor methodology is presented in the
memorandum ‘‘MACT Floor Analysis
(2010) for the Industrial, Commercial,
and Institutional Boilers and Process
Heaters National Emission Standards for
Hazardous Air Pollutants—Major
Source’’ in the docket.
1. Determination of MACT for the FuelRelated HAP
In developing the proposed MACT
floor for the fuel-related HAP (nonmercury metals, acid gases, and
mercury), as described earlier, we are
using PM as a surrogate for non-mercury
metallic HAP and HCl as a surrogate for
the acid gases. Table 2 of this preamble
presents the number of units in each of
the five subcategories, along with the
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number of units from which we have
collected emission data. Table 2 also
presents for each subcategory and fuelrelated HAP the number of units
comprising the best performing units
(top 12 percent), the average emission
level of the top 12 percent, and the
MACT floor (99 percent UPL of top 12
percent) which includes the variability
across the best performing units and the
long term variability across those units.
TABLE 2—SUMMARY OF MACT FLOOR RESULTS FOR THE FUEL-RELATED HAP FOR EXISTING SUBCATEGORIES
Subcategory
Parameter
PM
Units designed for Coal firing ...............................
No. of sources in subcategory .............................
No. of sources with data ......................................
No. in MACT floor ................................................
Avg of top 12%, lb/MMBtu ...................................
99% UPL of top 12% (test runs), lb/MMBtu ........
99% UPL with fuel variability of top 12%, lb/
MMBtu.
No. of sources in subcategory .............................
No. of sources with data ......................................
No. in MACT floor ................................................
Avg of top 12%, lb/MMBtu ...................................
99% UPL of top 12% (test runs), lb/MMBtu ........
99% UPL with fuel variability of top 12%, lb/
MMBtu.
No. of sources in subcategory .............................
No. of sources with data ......................................
No. in MACT floor ................................................
Avg of top 12%, lb/MMBtu ...................................
99% UPL of top 12% (test runs), lb/MMBtu ........
99% UPL with fuel variability of top 12%, lb/
MMBtu.
No. of sources in subcategory .............................
No. of sources with data ......................................
No. in MACT floor ................................................
Avg of top 12%, lb/MMBtu ...................................
99% UPL of top 12% (test runs), lb/MMBtu ........
578
366
44
7.24E–03
0.0179
....................
578
285
35
5.95E–07
1.64E–06
2.88E–06
578
318
39
4.23E–03
7.38E–03
1.11E–02
420
192
24
6.06E–03
0.0162
....................
420
91
11
3.46E–07
7.52E–07
8.88E–07
420
92
12
4.34E–03
6.00E–03
....................
826
91
11
1.40E–03
0.00323
....................
826
177
22
1.91E–06
2.78E–06
3.97E–06
826
190
23
2.59E–04
3.26E–04
8.04E–04
199
13
2
0.011
0.045
199
8
1
8.25E–08
1.86E–07
199
8
1
1.70E–06
2.50E–06
Units designed for Biomass firing .........................
Units designed for Liquid Fuel firing .....................
erowe on DSK5CLS3C1PROD with PROPOSALS5
Units designed for other gas firing .......................
Mercury
HCl
For three cases, the proposed new and
existing source MACT floors are almost
identical because the best performing 12
percent of existing units (for which we
have emissions information) is only one
or two sources. The reason we look to
the best performing 12 percent of
sources, even though we have data on
fewer than 5 sources, is that these
subcategories consist of 30 or more
units. CAA section 112(d)(3)(A)
provides that standards for existing
sources shall not be less stringent than
‘‘the average emission limitation
achieved by the best performing 12
percent of the existing sources (for
which the Administrator has emissions
information), * * * in the category or
subcategory for categories and
subcategories with 30 or more sources.’’
A plain reading of the above statutory
provisions is to apply the 12 percent
rule in deriving the MACT floor for
those categories or subcategories with
30 or more sources. The parenthetical
‘‘(for which the Administrator has
emissions information)’’ in CAA section
112(d)(3)(A) modifies the best
performing 12 percent of existing
sources, which is the clause it
immediately follows.
However, in cases where there are 30
or more sources but little emission data,
this results in only a few units setting
the existing source floor with the result
that the new and existing source MACT
floors are almost identical. In contrast,
if these subcategories had less than 30
sources, we would be required to use
the top five best performing sources,
rather than the one or two that comprise
the top 12 percent. Section 112(d)(3)(B).
We are seeking comment on whether,
with the facts of this rulemaking, we
should consider reading the intent of
Congress to allow us to consider five
sources rather than just one or two.
First, it seems evident that Congress was
concerned that floor determinations
should reflect a minimum quantum of
data: At least data from 5 sources for
source categories of less than 30 sources
(assuming that data from 5 sources
exist). Second, it does not appear that
this concern would be any less for
subcategories with 30 or more sources.
We are specifically requesting comment
on this interpretation relating to the
proposed MACT floors.9
9 The impact of using a minimum of five sources
in the MACT floor analyses for these subcategories
and HAP are presented in the Memorandum
‘‘MACT Floor Analysis (2010) for the Industrial,
Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous
Air Pollutants—Major Sources’’ located in the
Docket.
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2. Determination of MACT for Organic
HAP
In developing the MACT floor for
organic HAP, as described earlier, we
are using CO as a surrogate for nondioxin organic HAP. Table 3 of this
preamble presents the number of units
in each of the 11 subcategories, along
with the number of units from which we
have collected emission data. Table 3
also presents for each subcategory (for
CO and D/F) the number of units
comprising the best performing units
(top 12 percent), the average emission
level of the top 12 percent, and the
MACT floor (99 percent UPL of top 12
percent) which includes the variability
across the best performing units and the
long term variability.
We calculated the MACT floors based
on the upper 99th percentile UPL from
the average performance of the best
performing units and their variances as
described earlier for the fuel-related
HAP.
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TABLE 3—SUMMARY OF MACT FLOOR RESULTS FOR THE ORGANIC HAP SUBCATEGORIES
Subcategory
Parameter
CO
Dioxin/Furan (TEQ)
Stoker—Coal .......................
No. of sources in subcategory ......................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
361 .....................................
61 .......................................
8 .........................................
21.4 ppm @ 3% O2 ...........
99% UPL of top % (test runs) .......................................
48.8 ppm @ 3% O2 ...........
No. of sources in subcategory ......................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
31 .......................................
17 .......................................
3 .........................................
12.5 ppm @ 3% O2 ...........
99% UPL of top % (test runs) .......................................
21.4 ppm @ 3% O2 ...........
No. of sources in subcategory ......................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
186 .....................................
41 .......................................
5 .........................................
19.2 ppm @ 3% O2 ...........
99% UPL of top % (test runs) .......................................
82.8 ppm @ 3% O2 ...........
No. of sources in subcategory ......................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
320 .....................................
119 .....................................
15 .......................................
203 ppm @ 3% O2 ............
99% UPL of top % (test runs) .......................................
551 ppm @ 3% O2 ............
No. of sources in subcategory ......................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
12 .......................................
7 .........................................
5 .........................................
97.1 ppm @ 3% O2 ...........
99% UPL of top 12% (test runs) ...................................
No. of sources in subcategory ......................................
245 ppm @ 3% O2 ............
62 .......................................
361.
14.
2.
0.00182 ng/dscm @ 7%
O2.
0.00274 ng/dscm @ 7%
O2.
31.
12.
2.
0.000471 ng/dscm @ 7%
O2.
0.00168 ng/dscm @ 7%
O2.
186.
10.
2.
0.00158 ng/dscm @ 7%
O2.
0.00307 ng/dscm @ 7%
O2.
320.
16.
2.
0.000819 ng/dscm @ 7%
O2.
0.00339 ng/dscm @ 7%
O2.
12.
6.
5.
0.00507 ng/dscm @ 7%
O2.
0.0127 ng/dscm @ 7% O2.
62.
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
17 .......................................
3 .........................................
362 ppm @ 3% O2 ............
99% UPL of top 12% (test runs) ...................................
No. of sources in subcategory ......................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
1010 ppm @ 3% O2 ..........
26 .......................................
16 .......................................
5 .........................................
130 ppm @ 3% O2 ............
99% UPL of top 12% (test runs) ...................................
No. of sources in subcategory ......................................
262 ppm @ 3% O2 ............
826 .....................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
116 .....................................
14 .......................................
0.443 ppm @ 3% O2 .........
99% UPL of top 12% (test runs) ...................................
0.911 ppm @ 3% O2 .........
No. of sources in subcategory ......................................
199 .....................................
No. of sources with data ...............................................
No. in MACT floor .........................................................
Avg of top 12% ..............................................................
75 .......................................
9 .........................................
0.0737 ppm @ 3% O2 .......
99% UPL of top 12% (test runs) ...................................
0.134 ppm @ 3% O2 .........
Fluidized Bed—Coal ............
PC—Coal .............................
Stoker—Biomass .................
Fluidized Bed—Biomass .....
Suspension Burner/Dutch
Oven.
Fuel Cell—Biomass .............
Units designed for Liquid
fuel firing.
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Units designed for other
gases firing.
For organic HAP, as previously
discussed above for fuel-related HAP,
we account for variability in setting
floors, not only because variability is an
element of performance, but because it
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is reasonable to assess best performance
over time. Here, however, we know that
the organic HAP emissions will also
vary over the operating range of the
unit, unlike fuel-related HAP emissions.
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3.
1.
0.00952 ng/dscm @ 7%
O2.
0.0279 ng/dscm @ 7% O2.
26.
7.
5.
0.00552 ng/dscm @ 7%
O2.
0.0148 ng/dscm @ 7% O2.
826.
17.
3.
0.000733 ng/dscm @ 7%
O2.
0.00182 ng/dscm @ 7%
O2.
199.
5.
1.
0.00267 ng/dscm @ 7%
O2.
0.00828 ng/dscm @ 7%
O2.
Organic HAP are combustion-related
pollutants. That is, their levels of
emissions are a function of the
combustion process. Combustion units
operate most efficiently when operated
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at or near their design capacity. The
combustion efficiency tends to decrease
as the unit’s load (steam production)
decreases. Most industrial or
commercial/institutional units do not
continuously operate at or near their
design capacity but operate according to
the facility’s demand for steam. Thus,
operation at lower capacity rates must
be accounted for in determining
operational variability.
As part of EPA’s information
collection effort, we obtained data on
organic HAP (THC and CO) from six
units (two coal-fired, two biomass-fired,
and two gas-fired) that were collected
using CEM over a 30-day period. All of
these units were selected to test using
CEM to provide variability information
because their stack test results indicated
that they were among the best
performing units.
The CEMS data shows that CO (as a
surrogate for non-dioxin organic HAP)
from best performing units did not vary
much when such unit is operated at
below design capacity. Therefore, even
though ICI units, due to steam demand,
may operate at these low load
conditions, no additional variability due
to operating load needs to be accounted
for since the average CO emission levels
that include these low load conditions
are within the variability range
determined by the statistical analyses of
CO emissions from the best performing
units. Thus, we are proposing to add no
additional variability factor to account
for load variability to the MACT floor 99
percent UPL values determined from the
stack test data for CO emissions.
This approach reasonably ensures that
the emission limit selected as the MACT
floor adequately represents the average
level of control actually achieved by
units in the top 12 percent in each
subcategory, considering ordinary
operational variability of those units.
Both the analysis of the measured
emissions from units representative of
the top 12 percent, and the variability
analysis of those units, are reasonably
designed to provide a meaningful
estimate of the average performance, or
central tendency, of the best controlled
12 percent of units in a given
subcategory.
As was the case for the three fueldependent MACT floors, the proposed
new and existing source MACT floors
for eight combustion-dependent
subcategories are almost identical
because the best performing 12 percent
of units (for which we have emissions
information) is only one or two sources.
Again, the reason we look to the best
performing 12 percent of sources is that
these subcategories consist of 30 or
more units. In contrast, if these
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subcategories had less than 30 sources,
we would be required to use the top five
best performing sources, rather than the
one or two that comprise the top 12
percent. As stated previously, we are
seeking comment on whether, with the
facts of this rulemaking, we should
consider reading the intent of Congress
to allow us to consider five sources
rather than just one, two, or three. We
are specifically requesting comment on
this interpretation relating to the
proposed MACT floors.
3. Determination of the Work Practice
Standard
CAA section 112(h)(1) states that the
Administrator may prescribe a work
practice standard or other requirements,
consistent with the provisions of CAA
sections 112(d) or (f), in those cases
where, in the judgment of the
Administrator, it is not feasible to
enforce an emission standard. CAA
section 112(h)(2)(B) further defines the
term ‘‘not feasible’’ in this context to
apply when ‘‘the application of
measurement technology to a particular
class of sources is not practicable due to
technological and economic
limitations.’’
The standard reference methods for
measuring emissions of mercury, CO (as
a surrogate for organic HAP), D/F, HCl
(as a surrogate for acid gases) and PM
(as a surrogate for non-mercury metals)
are EPA Methods 29, 10, 23, 26A and 5.
These methods are reliable but
relatively expensive as a group.
However, the methods are generally not
able to accurately sample small
diameter (less than 12 inches) stacks.
For example, in these small diameter
stacks, the conventional EPA Method 5
stack assembly blocks a significant
portion of the cross-section of the duct
and, if unaccounted for, could cause
inaccurate measurements. Many
existing small boilers and process
heaters have stacks with diameters less
than 12 inches. The stack diameter is
generally related to the size of the unit.
Units that have capacity below 10
million Btu per hour generally have
stacks with diameters less than 12
inches. Also, many existing small units
do not currently have sampling ports or
a platform for accessing the exhaust
stack which would require an expensive
modification to install sampling ports
and a platform.
We conducted a cost analysis 10 to
evaluate the economic impact of the
testing and monitoring costs that
10 Memorandum: Methodology for Estimating
Impacts from Industrial, Commercial, and
Institutional Boilers and Process Heaters at Major
Sources of Hazardous Air Pollutant Emissions,
March 23, 2010.
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facilities with small units would incur
to demonstrate compliance with the
proposed emission limits. The
compliance costs imposed on each
facility would not only include the costs
of the stack tests and monitoring
equipment but would also include the
capital costs of any installed control
equipment. We estimate that the total
capital costs of installing control
equipment on the over 7,400 small
boilers and process heaters to achieve
the proposed emission limits would be
$6.3 billion. In addition to these costs,
additional costs would be incurred
because many of these small units do
not have test ports or testing platforms
installed in order to conduct
performance testing. Prior to conducting
a stack test each unit would need to
construct or rent scaffolding and install
test ports. EPA estimates that these
small sources would incur an additional
$185 million to install test ports and
rent temporary scaffolding. Many
establishments in each industry,
commercial, or institutional sector are
associated with multiple (as many as a
700) small units.
The results of the analysis indicate
that the annual costs for testing and
monitoring costs alone would have a
significant adverse economic impact on
these facilities. The severity of the
economic impact would depend on the
size of the facility.
Based on this analysis, the
Administrator has determined under
CAA section 112(h) that it is not feasible
to enforce emission standards for a
particular class of existing boilers and
process heaters because of the
technological and economic limitations
described above. Thus, a work practice,
as discussed below, is being proposed to
limit the emission of HAP for existing
boilers and process heaters having a
heat input capacity of less than 10
million Btu per hour. We are
specifically requesting comment on
whether a threshold higher than 10
million Btu per hour meets the technical
and economic limitations as specified in
CAA section 112(h).
For existing units, the only work
practice being used that potentially
controls HAP emissions is a tune-up.
Fuel dependent HAP are typically
controlled by removing them from the
flue gas after combustion. The only
work practices expected to minimize
fuel dependent HAP emissions are
reducing the fuel usage or fuel
switching to a fuel type with a lower
HAP content. Fuel usage can be reduced
by improving the combustion efficiency
of the unit, such as, by a tune-up. As
combustion efficiency decreases, fuel
usage must increase to maintain
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constant energy output. This increased
fuel use results in increased emissions.
On the other hand, organic HAP are
formed from incomplete combustion of
the fuel. The objective of good
combustion is to release all the energy
in the fuel while minimizing losses from
combustion imperfections and excess
air. The combination of the fuel with the
oxygen requires temperature (high
enough to ignite the fuel constituents),
mixing or turbulence (to provide
intimate oxygen-fuel contact), and
sufficient time (to complete the
process), sometimes referred to the three
Ts of combustion. Good combustion
practice (GCP), in terms of combustion
units, could be defined as the system
design and work practices expected to
minimize organic HAP emissions.
We have obtained information on
units that reported using GCP, as part of
the information collection effort for the
NESHAP. The data that we have
suggests that units typically conduct
tune-ups. We also reviewed State
regulations and permits. The work
practices listed in State regulations
includes tune-ups (10 States), operator
training (1 State), periodic inspections
(2 States), and operation in accordance
with manufacturer specifications (1
State). Of the units with a capacity of
less than 10 MMBtu/h that responded to
EPA’s information collection effort for
the NESHAP, 80 percent reported
conducting a tune-up program.
Ultimately, we determine that at least 6
percent of the units in each of the
subcategories are subject to a tune-up
requirement. Therefore, the proposed
work practice of a tune-up 11 program
does establish the MACT floor for HAP
emissions from existing units with a
heat input capacity of less than 10
MMBtu/h.
We are also proposing a work practice
standard under section 112(h) that
would require an annual tune-up for
existing boilers and process heaters
combusting natural gas or refinery gas.
These boilers and process heaters are
units included in the Gas 1 and metal
processing furnace subcategories. We
are specifically seeking comment on
whether the application of measurement
methodology to sources in this
subcategory is impracticable due to
technological or economic limitations,
as specified in section 112(h)(2)(B).
This work practice standard is being
proposed for several reasons. First, the
capital costs estimated for installing
controls on these boilers and process
heaters to comply with MACT limits for
the five HAP groups is over $14 billion.
This cost includes installation of a
combination system of a fabric filter (for
PM, mercury, and D/F control) and a
wet scrubber (for HCl control). This
capital cost is higher than the estimated
combined capital cost for boilers and
process heaters in all of the other
subcategories. The projected control
system needed for boilers and process
heaters in the other subcategories is also
a combined fabric filter/wet scrubber
system.
Second, we believe that proposing
emission standards for gas-fired boilers
and process heaters that result in the
need to employ the same emission
control system as needed for the other
fuel types would have the negative
benefit of providing a disincentive for
switching to gas as a control technique
(and a pollution prevention technique)
for boilers and process heaters in the
other fuel subcategories. In addition,
emission limits on gas-fired boilers and
process heaters may have the negative
benefit of providing an incentive for a
facility to switch from gas (considered a
‘‘clean’’ fuel) to a ‘‘dirtier’’ but cheaper
fuel (i.e., coal). It would be inconsistent
with the emissions reductions goals of
the CAA, and of section 112 in
particular, to adopt requirements that
would result in an overall increase in
HAP emissions. We are soliciting
comment on the extent to which natural
gas facilities would be expected to
switch to a ‘‘dirtier’’ fuel if emissions
limits for such facilities are adopted.
Thus, a work practice, as discussed
above for small boilers and process
heaters, is being proposed to limit the
emission of HAP for existing natural
gas-fired and refinery gas-fired boilers
and process heaters.
We request comments on whether the
emission limits listed in Table 4 of this
preamble for the Gas 1 and Metal
Process Furnace subcategories should be
promulgated. Comments should include
detailed information regarding why
emission limits for these gas-fired
boilers and process heaters are
appropriate.
TABLE 4—SUMMARY OF MACT FLOOR RESULTS FOR THE GAS 1 AND METAL PROCESS FURNACE SUBCATEGORIES
Subcategory
Metal Process Furnaces.
PM
Mercury
HCl
CO
No. of sources in
subcategory.
No. of sources
with data.
No. in MACT floor
Avg of top 12% ...
10,783 .................
10,783 .................
10,783 .................
10,783 .................
10,783.
144 ......................
14 ........................
11 ........................
754 ......................
8.
18 ........................
0.00388 lb/MMBtu
2 ..........................
1.1E–07 lb/MMBtu
99% UPL of top
12% (test runs).
No. of sources in
subcategory.
No. of sources
with data.
No. in MACT floor
Avg of top 12% ...
0.03 lb/MMBtu .....
2.0E–07 lb/MMBtu
2 ..........................
1.01E–04 lb/
MMBtu.
0.0002 lb/MMBtu
749 ......................
749 ......................
749 ......................
91 ........................
1.45 ppm @ 3%
oxygen.
20 ppm @ 3% oxygen.
749 ......................
1.
0.0026 ng/dscm
@ 7% oxygen.
0.01 ng/dscm @
7% oxygen.
749.
9 ..........................
7 ..........................
9 ..........................
15 ........................
7.
2 ..........................
0.0047 lb/MMBtu
1 ..........................
3.3E–08 lb/MMBtu
99% UPL of top
12% (test runs).
Units designed for
NG/RG firing.
erowe on DSK5CLS3C1PROD with PROPOSALS5
Dioxin/furan
(total TEQ)
Parameter
0.02 lb/MMBtu .....
2.0E–07 lb/MMBtu
2 ..........................
1.92E–04 lb/
MMBtu.
0.0004 lb/MMBtu
2 ..........................
0.38 ppm @ 3%
oxygen.
2 ppm @ 3% oxygen.
1.
0.0026 ng/dscm
@ 7% oxygen.
0.004 ng/dscm @
7% oxygen.
11 Tune-up procedure is specified in section
63.7540 of this proposed rule and includes making
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adjustments to the burner to optimize the flame to
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minimize CO emissions consistent with the
manufacturer’s specifications.
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Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules
E. How did EPA consider beyond-thefloor options for existing units?
Once the MACT floor determinations
were done for each subcategory, we
considered various regulatory options
more stringent than the MACT floor
level of control (i.e., technologies or
other work practices that could result in
lower emissions) for the different
subcategories. A detailed description of
the beyond-the-floor consideration is in
the memorandum ‘‘Methodology for
Estimating Cost and Emissions Impacts
for Industrial, Commercial, Institutional
Boilers and Process Heaters National
Emission Standards for Hazardous Air
Pollutants’’ in the docket.
We could not identify better HAP
emissions reduction approaches that
could achieve greater emissions
reductions of HAP than the control
technology combination (fabric filter,
carbon injection, scrubber, and GCP)
that we expect will be used to meet the
MACT floor level of control.
For each subcategory, fuel switching
to natural gas is an option that would
reduce HAP emissions. We determined
that fuel switching was not an
appropriate beyond-the-floor option.
First, natural gas supplies are not
available in some areas, and supplies to
industrial customers can be limited
during periods when natural gas
demand exceeds supply. Additionally,
the estimated emissions reductions that
would be achieved if solid and liquid
fuel units switched to natural gas were
compared with the estimated cost of
converting existing solid fuel and liquid
fuel units to fire natural gas. The
annualized cost of fuel switching was
estimated to be $13.5 billion compared
with $3.5 billion under the floor
approach. The emission reduction
associated with fuel switching was
estimated to be 4,296 tons per year for
metallic HAP, 8 tons per year for
mercury, and 50,332 tons per year for
inorganic HAP (HCl and HF). The cost
for fuel switching is over double the
cost of the floor approach while the
emission reductions associated with
fuel switching are approximately the
same. Additional detail on the
calculation procedures is provided in
the memorandum ‘‘Development (2010)
of Fuel Switching Costs and Emissions
Reductions for Industrial, Commercial,
and Institutional Boilers and Process
Heaters National Emission Standards for
Hazardous Air Pollutants’’ in the docket.
We also considered the pollution
prevention and energy conservation
measure of an energy assessment/audit
as a beyond-the-floor option for HAP
emissions. An energy assessment
provides valuable information on
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improving energy efficiency. An energy
assessment, or audit, is an in-depth
energy study identifying all energy
conservation measures appropriate for a
facility given its operating parameters.
An energy assessment refers to a process
which involves a thorough examination
of potential savings from energy
efficiency improvements, pollution
prevention, and productivity
improvement. It leads to the reduction
of emissions of pollutants through
process changes and other efficiency
modifications. Besides reducing
operating and maintenance costs,
improving energy efficiency reduces
negative impacts on the environment
and results in reduced emissions and
improved public health. Improvement
in energy efficiency results in decreased
fuel use which results in a
corresponding decrease in emissions
(both HAP and non-HAP) from the
combustion unit, but not necessarily a
decrease in emissions of all HAP
emitted. The Department of Energy has
conducted energy assessments at
selected manufacturing facilities and
reports that facilities can reduce fuel/
energy use by 10 to 15 percent by using
best practices to increase their energy
efficiency. Many best practices are
considered pollution prevention
because they reduce the amount of fuel
combusted which results in a
corresponding reduction in emissions
from the fuel combustion. The most
common best practice is simply tuning
the boiler to the manufacturer’s
specification.
The one-time cost of an energy
assessment ranges from $2500 to
$55,000 depending on the size of the
facility. The total annualized cost if
each major source facility conducted an
energy assessment is estimated at $26
million. If a facility implemented the
cost-effective energy conservation
measures identified in the energy
assessment, it would potentially result
in greater HAP reduction than achieved
by a boiler tune-up alone and
potentially reducing HAP emissions
(HCl, mercury, non-mercury metals, and
VOC) by an additional 820 to 1,640 tons
per year. In addition, the costs of any
energy conservation improvement will
be offset by the cost savings in lower
fuel costs. Therefore, we decided to go
beyond the MACT floor for this
proposed rule for the existing units.
These proposed standards for existing
units include the requirement of a
performance of an energy assessment to
identify cost-effective energy
conservation measures. Since there was
insufficient information to determine if
requiring implementation of cost-
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effective measures were economically
feasible, we are seeking comment on
this point.
In this proposed rule, we are defining
a cost-effective energy conservation
measure to be any measure that has a
payback (return of investment) period of
2 years or less. This payback period was
selected based on section
325(o)(2)(B)(iii) of the Energy Policy and
Conservation Act which states that there
is a presumption that an energy
conservation standard is economically
justified if the increased installed cost
for a measure is less than three times the
value of the first-year energy savings
resulting from the measure.
We believe that an energy assessment
is an appropriate beyond-the-floor
control technology because it is one of
the measures identified in CAA section
112(d)(2). CAA section 112(d)(2) states
that ‘‘Emission standards promulgated
* * * and applicable to new or existing
sources * * * is achievable * * *
through application of measures,
processes, methods, systems or
techniques including, but not limited to
measures which * * * reduce the
volume of, or eliminate emissions of,
such pollutants through process
changes, substitution of materials or
other modifications * * *’’
The purpose of an energy assessment
is to identify energy conservation
measures (such as, process changes or
other modifications to the facility) that
can be implemented to reduce the
facility energy demand which would
result in reduced fuel use. Reduced fuel
use will result in a corresponding
reduction in HAP, and non-HAP,
emissions. Thus, an energy assessment,
in combination with the MACT
emission limits will result in the
maximum degree of reduction in
emissions as required by 112(d)(2).
Therefore, we are proposing to require
all existing sources to conduct a onetime energy assessment to identify costeffective energy conservation measures.
We are proposing that the energy
assessment be conducted by energy
professionals and/or engineers that have
expertise that cover all energy using
systems, processes, and equipment. We
are aware of, at least, two organizations
that provide certification of specialists
in evaluating energy systems. We are
proposing that a qualified specialized is
someone who has successfully
completed the Department of Energy’s
Qualified Specialist Program for all
systems or a professional engineer
certified as a Certified Energy Manager
by the Association of Energy Engineers.
As part of the energy assessment, we
are proposing that the facility assess its
energy management program and
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practices using EPA’s ENERGY STAR
Facility Energy Management
Assessment Matrix. ENERGY STAR has
a simple facility energy management
assessment tool that can be used as part
of the assessment process. This tool
identifies gaps in current practices.
Facilities, as part of the requirement,
would identify steps to close the
management gaps. We are also
proposing that the facility develop an
energy management program according
to the ENERGY STAR Guidelines for
Energy Management (see
www.energystar.gov/guidelines).12
We are specifically requesting
comment on: (1) Whether our estimates
of the assessment costs are correct; (2)
is there adequate access to certified
assessors; (3) are there other
organizations for certifying energy
engineers; (4) are online tools adequate
to inform the facility’s decision to make
efficiency upgrades; (5) is the definition
of ‘‘cost-effective’’ appropriate in this
context since it refers to payback of
energy saving investments without
regard to the impact on HAP reduction;
(6) what rate of return should be used;
and (7) are there other guidelines for
energy management beside ENERGY
STAR’s that would be appropriate.
We considered proposing a beyondthe-floor requirement for certain sources
in the natural gas and refinery gas
subcategory (i.e., the Gas 1 subcategory).
Specifically, we considered proposing
that facilities with boilers or process
heaters combusting refinery gas install
and maintain a carbon adsorber bed
system 13 to remove mercury from the
refinery gas before combustion in a
boiler or process heater. Based on data
from the information collection effort,
refinery gas contains mercury and
additional mercury reductions can be
achieved from units combusting refinery
gas. Consequently, we analyzed the
mercury emissions reductions and
12 The location of the guidance is: https://
www.energystar.gov/
index.cfm?c=guidelines.assess_facility_energy.
13 Carbon adsorption of mercury can be
accomplished by (a) injecting dry carbon with or
without other dry sorbents into the offgas upstream
of a PM control device (typically a baghouse), or (b)
using a fixed or moving bed of granular carbon
through which the offgas flows. In a typical fixed
bed carbon adsorption system, the flue gas flows
through a vessel packed with a specified depth of
the carbon granules. The bed and packing are
designed to limit the linear velocity of the offgas in
the bed to increase the contact time with the
carbon. Due to the increased contact times and
typically lower operating temperatures, better
removal efficiencies can be achieved than for
carbon injection. At a residence time of 10 seconds
in the carbon bed, virtually all of the mercury can
be removed. (Ref. NUCON INTERNATIONAL, Inc.,
‘‘Design & Performance Characteristics of
MERSORBB Mercury Adsorbents in Liquids and
Gases,’’ NUCON 11B28, August 1995.)
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additional cost of adopting this work
practice. The annualized cost of the
carbon adsorber bed system to treat the
refinery gas prior to combustion is
estimated to be about 1.6 billion dollars
with a mercury emission reduction of
0.8 tons. The results indicated that
while additional mercury emissions
reductions would be realized, the costs
would be too high to consider it a
feasible beyond-the-floor option. Nonair
quality health, environmental impacts,
and energy effects were not significant
factors, because there would be little
difference in the nonair quality health
and environmental impacts of requiring
the installation of carbon bed adsorbers.
Therefore, we are not proposing
installation of a carbon adsorber bed
system as a beyond-the-floor
requirement.
F. Should EPA consider different
subcategories for solid fuel boilers and
process heaters?
The boilers and process heaters
source category is tremendously
heterogeneous. EPA has attempted to
identify subcategories that provide the
most reasonable basis for grouping and
estimating the performance of generally
similar units using the available data.
We believe that the subcategories we
selected are appropriate.
EPA requests comments on whether
additional or different subcategories
should be considered. Comments
should include detailed information
regarding why a new or different
subcategory is appropriate (based on the
available data or adequate data
submitted with the comment), how EPA
should define any additional/different
subcategories, how EPA should account
for varied or changing fuel mixtures,
and how EPA should use the available
data to determine the MACT floor for
any new or different categories.
G. How did EPA determine the proposed
emission limitations for new units?
All standards established pursuant to
section 112 of the CAA must reflect
MACT, the maximum degree of
reduction in emissions of air pollutants
that the Administrator, taking into
consideration the cost of achieving such
emissions reductions, and any nonair
quality health and environmental
impacts and energy requirements,
determines is achievable for each
category. The CAA specifies that MACT
for new boilers and process heaters shall
not be less stringent than the emission
control that is achieved in practice by
the best-controlled similar source. This
minimum level of stringency is the
MACT floor for new units. However,
EPA may not consider costs or other
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32027
impacts in determining the MACT floor.
EPA must consider cost, nonair quality
health and environmental impacts, and
energy requirements in connection with
any standards that are more stringent
than the MACT floor (beyond-the-floor
controls).
H. How did EPA determine the MACT
floor for new units?
Similar to the MACT floor process
used for existing units, the approach for
determining the MACT floor must be
based on available emissions test data.
Using such an approach, we calculated
the MACT floor for a subcategory of
sources by ranking the emission test
results from units within the
subcategory from lowest to highest to
identify the best controlled similar
source. The MACT floor limits for each
of the HAP and HAP surrogates (PM,
mercury, CO, HCl, and D/F) are
calculated based on the performance
(numerical average) of the lowest
emitting (best controlled) source for
each pollutant in each of the
subcategories.
The MACT floor limits for new
sources were calculated using the same
formula as was used for existing
sources. However, as was the case for
the existing MACT floor analysis, we
determined that it was inappropriate to
use only this MACT floor approach to
determine variability and to establish
emission limits for new boilers and
process heaters. The main problem with
using only the HAP emissions test data
is that the data may not reflect the
variability of fuel-related HAP from the
best controlled similar source over the
long term. Based on our current
information, fuel-related HAP levels in
the various fuels can vary significantly
over time. The variations in fuel-related
HAP inputs directly translate to a
variability of fuel-related HAP stack
emissions.
As previously discussed above, we
account for variability of the bestcontrolled source in setting floors, not
only because variability is an element of
performance, but because it is
reasonable to assess best performance
over time. If we do not account for this
variability, we would expect that even
the best controlled similar source would
potentially exceed the floor emission
levels a significant part of the time
which would mean that their variability
was not properly accounted for when
setting the floor. We calculated the
MACT floor based on the UPL (upper
99th percentile) as described earlier
from the average performance of the best
controlled similar source, Students
t-factor, and the total variability of the
best-controlled source.
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This approach reasonably ensures that
the emission limit selected as the MACT
floor adequately represents the average
level of control actually achieved by the
best controlled similar source,
considering ordinary operational
variability.
A detailed discussion of the MACT
floor methodology is presented in the
memorandum ‘‘MACT Floor Analysis
for the Industrial, Commercial, and
Institutional Boilers and Process Heaters
National Emission Standards for
Hazardous Air Pollutants’’ in the docket.
The approach that we use to calculate
the MACT floors for new sources is
somewhat different from the approach
that we use to calculate the MACT
floors for existing sources. While the
MACT floors for existing units are
intended to reflect the performance
achieved by the average of the best
performing 12 percent of sources, the
MACT floors for new units are meant to
reflect the emission control that is
achieved in practice by the best
controlled source. Thus, for existing
units, we are concerned about
estimating the central tendency of a set
of multiple units, while for new units,
we are concerned about estimating the
level of control that is representative of
that achieved by a single best controlled
source. As with the analysis for existing
sources, the new unit analysis must
account for variability. To accomplish
this for new sources, for the fuel
dependent HAP emissions, we
determined what the best controlled
source has achieved in light of the
inherent and unavoidable variations in
the HAP content of the fuel that such
unit might potentially use. For non-fuel
dependent HAP emissions, on the other
hand, we look at the inherent variability
of the control technology used by the
best-controlled source in the
subcategory. These approaches,
respectively, represent the most
reasonable way to estimate performance
for purposes of establishing MACT
floors for new units, given the data
available.
For fuel dependent HAP emissions
(mercury and HCl), we calculated the
variability factor by looking at data on
HAP variability in fuel obtained through
our information collection request. We
derived the fuel dependent variability
factor by dividing the highest observed
HAP concentration by the lowest
observed HAP concentration from the
fuel analyses from the best-controlled
source. Once we calculated the fuel
dependent variability factors, we
applied these factors to the average
measured emissions performance of the
best controlled similar source to derive
the MACT floor level of control. This
approach reasonably estimates the best
source’s level of emissions, adjusted for
unavoidable variation in fuel
characteristics which have a direct
impact on emissions.
1. Determination of MACT for the FuelRelated HAP
In developing the MACT floor for the
fuel-related HAP (PM, HCl, and
mercury), as described earlier, we are
using PM as a surrogate for non-mercury
metallic HAP and HCl as a surrogate for
the acid gases. Table 5 presents for each
subcategory and fuel-related HAP the
average emission level of the best
controlled similar source and the MACT
floor (99 percent UPL) which includes
the variability across the best controlled
similar source and the long term
variability of that source.
TABLE 5—SUMMARY OF MACT FLOOR RESULTS FOR THE FUEL-RELATED HAP FOR NEW SOURCES
PM
Lb/MMBtu
Subcategory
Parameter
Units designed for Coal firing ...............................
Avg of top performer ............................................
99% UPL of top performer (test runs) .................
Avg of top performer ............................................
99% UPL of top performer (test runs) .................
Avg of top performer ............................................
99% UPL of top performer (test runs) .................
Avg of top performer ............................................
99% UPL of top performer (test runs) .................
Units designed for Biomass firing .........................
Units designed for Liquid Fuel firing .....................
Units designed for other gas firing .......................
2. Determination of MACT for Organic
HAP
In developing the MACT floor for
organic HAP, as described earlier, we
are using CO as a surrogate for nondioxin organic HAP. Table 6 presents
for each subcategory and CO and D/F
the average emission level of the best
controlled similar source and the MACT
0.000396
0.000928
0.00216
0.00711
0.000511
0.00154
0.00042
0.0024
Mercury
Lb/MMBtu
1.18E–07
3.89E–07
9.73E–08
1.86E–07
5.87E–08
2.47E–07
8.25E–08
1.86E–07
HCl
Lb/MMBtu
3.85E–05
5.21E–05
7.85E–04
3.07E–03
3.99E–04
9.80E–04
1.70E–06
2.50E–06
floor (99 percent UPL) which includes
the variability across the best controlled
similar source and the long term
variability of that source.
TABLE 6—SUMMARY OF MACT FLOOR RESULTS FOR THE ORGANIC HAP FOR NEW SOURCES
CO
(ppm @ 3
percent oxygen)
Subcategory
Parameter
Stoker—Coal ............................................................
4.29
6.53
8.26
*39.9
25.0
*97.5
920
*3730
25.8
34.2
352
*1050
110
1.52E–03
2.82E–03
9.05E–06
2.54E–05
1.04E–03
1.47E–03
1.52E–05
4.86E–05
2.27E–03
6.48E–03
9.52E–03
2.79E–02
2.42E–04
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
Fluidized Bed—Coal .................................................
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Dioxin/Furan
(TEQ)
(ng/dscm @ 7
percent oxygen)
PC—Coal ..................................................................
Stoker—Biomass ......................................................
Fluidized Bed—Biomass ..........................................
Suspension Burner/Dutch Oven. ..............................
Fuel Cell—Biomass ..................................................
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TABLE 6—SUMMARY OF MACT FLOOR RESULTS FOR THE ORGANIC HAP FOR NEW SOURCES—Continued
Subcategory
CO
(ppm @ 3
percent oxygen)
Parameter
Units designed for Liquid fuel firing ..........................
Units designed for other gases firing .......................
Dioxin/Furan
(TEQ)
(ng/dscm @ 7
percent oxygen)
*264
0.125
0.125
0.0129
0.0129
4.17E–04
1.09E–03
1.52E–03
2.67E–03
8.28E–03
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
Avg of top performer ................................................
99% UPL of top performer (test runs) ......................
* Value is higher than existing floor limit in the same subcategory. Therefore defaulted to existing floor limit for the same subcategory.
For organic HAP, as previously
discussed above for the fuel-related, we
account for variability in setting floors,
not only because variability is an
element of performance, but because it
is reasonable to assess best performance
over time. Here, we know that CO (as a
surrogate for non-dioxin organic HAP)
emissions does not vary significantly
over the operating range of the unit.
Thus, we have not added any additional
operational variability to account for
operation at lower capacity rates.
We are proposing a work practice
standard under section 112(h) that
would require an annual tune-up for
new boilers and process heaters
combusting natural gas or refinery gas.
These boilers and process heaters are
units included in the Gas 1 and metal
processing furnace subcategories. We
are specifically seeking comment on
whether the application of measurement
methodology to sources in this
subcategory is impracticable due to
technological or economic limitations,
as specified in section 112(h)(2)(B).
This proposal for new boilers and
process heaters combusting natural gas
or refinery gas is based on the same
reasons discussed previously for
existing boilers and process heaters
combusting natural gas or refinery gas.
That is, we believe that proposing
emission standards for new gas-fired
boilers and process heaters that result in
the need to employ the same emission
control system as needed for the other
fuel types would have the negative
benefit of providing a disincentive for
switching to gas as a control technique
(and a pollution prevention technique)
for boilers and process heaters in the
other fuel subcategories. In addition,
emission limits on gas-fired boilers and
process heaters may have the negative
benefit of providing an incentive for a
facility to switch from gas (considered a
‘‘clean’’ fuel) to a ‘‘dirtier’’ but cheaper
fuel (i.e., coal). It would be inconsistent
with the emissions reductions goals of
the CAA, and of section 112 in
particular, to adopt requirements that
would result in an overall increase in
HAP emissions. We are soliciting
comment on the extent to which new
facilities would be expected to switch
away from natural gas to a ‘‘dirtier’’ fuel
if emissions limits for new such
facilities are adopted.
Thus, a work practice, as discussed
above for existing boilers and process
heaters combusting natural gas or
refinery gas, is being proposed to limit
the emission of HAP for new natural
gas-fired and refinery gas-fired boilers
and process heaters.
We request comments on whether the
emission limits listed in Table 7 of this
preamble for new units in the Gas 1 and
Metal Process Furnace subcategories
should be promulgated. Comments
should include detailed information
regarding why emission limits for these
gas-fired boilers and process heaters are
appropriate.
TABLE 7—SUMMARY OF MACT FLOOR RESULTS FOR NEW UNITS IN THE GAS 1 AND METAL PROCESS FURNACE
SUBCATEGORIES
Subcategory
PM
Lb/MMBtu
Parameter
Mercury
Lb/MMBtu
HCl
LB/MMBtu
Dioxin/Furan
(Total TEQ)
(ng/dscm @
7 percent
oxygen)
CO
(ppm @
3 percent
oxygen)
Units designed for NG/RG
firing.
Avg of top performer ..........
0.00013
9.4E–08
7.3E–05
5
0.0026
0.0005
2.0E–07
0.0002
20
0.01
Metal Process Furnaces .....
99% UPL of top (test runs)
=
Avg of top performer ..........
99% UPL of top (test runs)
=
0.0065
0.02
3.3E–08
2.0E–07
8.6E–05
0.0002
0.5
2
0.0026
0.004
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I. How did EPA consider beyond-thefloor for new units?
The MACT floor level of control for
new units is based on the emission
control that is achieved in practice by
the best controlled similar source within
each of the subcategories. No
technologies were identified that would
achieve HAP reduction greater than the
new source floors for the subcategories.
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Fuel switching to natural gas is a
potential regulatory option beyond the
new source floor level of control that
would reduce HAP emissions from nongas-fired units. However, based on
current trends within the industry, EPA
projects that the majority of new boilers
and process heaters will be built to fire
natural gas as opposed to solid and
liquid fuels such that the overall
emissions reductions associated with
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this option would be minimal. In
addition, natural gas supplies are not
available in some areas, and supplies to
industrial customers can be limited
during periods when natural gas
demand exceeds supply. Thus, this
potential control option may be
unavailable to many sources in practice.
Limited emissions reductions in
combination with the high cost of fuel
switching and considerations about the
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availability and technical feasibility of
fuel switching makes this an
unreasonable regulatory option that was
not considered further.14 Nonair quality
health, environmental impacts, and
energy effects were not significant
factors. No beyond-the-floor options for
gas-fired boilers were identified.
An energy assessment is a beyondthe-floor standard being proposed for
existing facilities. However, we are not
proposing it as a beyond-the-floor
option for new major source facilities
since we believe it would not be cost
effective because most projected new
boilers or process heaters will be
installed at existing major source facility
which would have already conducted
an energy assessment as required by this
proposed rule. We also believe that any
new greenfield major source facility
having boilers or process heaters will be
designed to operate with energy
efficiency.
Based on the analysis discussed
above, EPA decided to not go beyond
the MACT floor level of control for new
sources in this proposed rule. A detailed
description of the beyond-the-floor
consideration is in the memorandum
‘‘Methodology for Estimating Cost and
Emissions Impacts for Industrial,
Commercial, Institutional Boilers and
Process Heaters National Emission
Standards for Hazardous Air Pollutants’’
in the docket.
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J. Consideration of whether to set
standards for HCl and other acid gases
under section 112(d)(4)
We are proposing to set a
conventional MACT standard for HCl
and, for the reasons explained
elsewhere in today’s notice, are
proposing that the HCl limit also serve
as a surrogate for other acid gas HAP.
We also considered whether it was
appropriate to exercise our discretionary
authority to establish health-based
emission standards under section
112(d)(4) for HCl and each of the other
relevant HAP acid gases: Chlorine (Cl2),
hydrogen fluoride (HF), and hydrogen
cyanide (HCN) 15 (since if it were
regulated under section 112(d)(4), HCl
may no longer be the appropriate
surrogate for these other HAPs).16 This
14 Memorandum ‘‘Development (2010) of Fuel
Switching Costs and Emission Reductions for
Industrial, Commercial, and Institutional Boilers
and Process Heaters National Emission Standards
for Hazardous Air Pollutants,’’ April 2010.
15 Before considering whether to exercise her
discretion under section 112(d)(4) for a particular
pollutant, the Administrator must first conclude
that a health threshold has been established for the
pollutant.
16 HCl can serve as a surrogate for the other acid
gases in a technology-based MACT standard,
because the control technology that would be used
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section sets forth the requirements of
section 112(d)(4), our analysis of the
information available to us that
informed the decision on whether to
exercise discretion, questions regarding
the application of 112(d)(4) and
solicitation of comments, and explains
how this case relates to prior decisions
EPA has made under section 112(d)(4)
with respect to HCl.
As a general matter, section 112(d)
requires MACT standards at least as
stringent as the MACT floor to be set for
all HAP emitted from major sources.
However, section 112(d)(4) provides
that for HAP with established health
thresholds, the Administrator has the
discretionary authority to consider such
health thresholds when establishing
emission standards under section
112(d). This provision is intended to
allow EPA to establish emission
standards other than conventional
MACT standards, in cases where a less
stringent emission standard will still
ensure that the health threshold will not
be exceeded, with an ample margin of
safety. In order to exercise this
discretion, EPA must first conclude that
the HAP at issue has an established
health threshold and must then provide
for an ample margin of safety when
considering the health threshold to set
an emission standard.
The legislative history of section
112(d)(4) indicates that Congress did not
intend for this provision to provide a
mechanism for EPA to delay issuance of
emission standards for sources of HAPs.
Finally, the legislative history also
indicates that a health-based emission
limit under section 112(d)(4) should be
set at the level at which no observable
effects occur, with an ample margin of
safety. S. Rep. 101–228 at 171–72.
It is clear the Administrator may
exercise her discretionary authority
under 112(d)(4) only with respect to
pollutants with an health threshold.
Where there is an established threshold,
the Administrator interprets section
112(d)(4) to allow her to weigh
additional factors, beyond any
established health threshold, in making
a judgment whether to set a standard for
a specific pollutant based on the
threshold, or instead follow the
traditional path of developing a MACT
standard after determining a MACT
floor. In deciding whether to exercise
to control HCl would also reduce the other acid
gases. By contrast, HCl would not be an appropriate
surrogate for a health-based emission standard that
is protective against the potential adverse health
effects from the other acid gases, because these
gases (e.g., HCN) can act on biological organisms in
a different manner than HCl, and each of the acid
gases affects human health with a different doseresponse relationship.
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her discretion for a threshold pollutant
for a given source category, the
Administrator interprets section
112(d)(4) to allow her to take into
account factors such as the following:
The potential for cumulative adverse
health effects due to concurrent
exposure to other HAPs with similar
biological endpoints, from either the
same or other source categories, where
the concentration of the threshold
pollutant emitted from the given source
category is below the threshold; the
potential impacts on ecosystems of
releases of the pollutant; and reductions
in criteria pollutant emissions and other
co-benefits that would be achieved via
the MACT standard. Each of these
factors is directly relevant to the health
and environmental outcomes at which
section 112 of the Clean Air Act is
fundamentally aimed. If the
Administrator does determine that it is
appropriate to set a standard based on
a health threshold, she must develop
emission standards that will ensure the
public will not be exposed to levels of
the pertinent HAP in excess of the
health threshold, with an ample margin
of safety.
EPA has exercised its discretionary
authority under section 112(d)(4) in a
handful of prior actions setting
emissions standards for other major
source categories, including the
emissions standards issued in 2004 for
commercial and industrial boilers and
process heaters, which were vacated on
other grounds by the U.S. Court of
Appeals for the D.C. Circuit. In both the
Pulp and Paper MACT, 63 FR at 18765
(April 15, 1998), and Lime
Manufacturing MACT, 67 FR at 78054
(December 20, 2002), EPA invoked
112(d)(4) for HCl emissions for discrete
units within the facility. In those
actions, EPA concluded that HCl had an
established health threshold (in those
cases it was interpreted as the reference
concentration for chronic effects, or RfC)
and was not classified as a human
carcinogen. In light of the absence of
evidence of carcinogenic risk, the
availability of information on noncarcinogenic effects, and the limited
potential health risk associated with the
discrete units being regulated, EPA
concluded that it was appropriate to
exercise its discretion under section
112(d)(4) for HCl under the
circumstances of those actions. EPA did
not set an emission standard based on
the health threshold; rather, the exercise
of EPA’s discretion in those cases in
effect exempted HCl from the MACT
requirement. In a more recent action,
EPA decided not to propose a healthbased emission standard for HCl
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emissions under section 112(d)(4) for
Portland Cement facilities, 74 FR at
21154 (May 6, 2009). EPA has never
implemented a NESHAP that used
section 112(d)(4) with respect to HF, Cl2
or HCN.17
Since any emission standard under
section 112(d)(4) must consider the
established health threshold level, with
an ample margin of safety, in this
rulemaking EPA has considered the
adverse health effects of the HAP acid
gases, beginning with HCl. Research
indicates that HCl is associated with
chronic respiratory toxicity. In the case
of HCl, this means that chronic
inhalation of HCl can cause tissue
damage in humans. Among other things,
it is corrosive to mucous membranes
and can cause damage to eyes, nose,
throat, and the upper respiratory tract as
well as pulmonary edema, bronchitis,
gastritis, and dermatitis. Considering
this respiratory toxicity, EPA has
established a chronic reference
concentration (RfC) for the inhalation of
HCl of 20 μg/m3. An RfC is defined as
an estimate (with uncertainty spanning
perhaps an order of magnitude) of a
continuous inhalation exposure to the
human population (including sensitive
subgroups 18) that is likely to be without
an appreciable risk of deleterious effects
during a lifetime. The development of
the RfC for HCl reflected data only on
its chronic respiratory toxicity. It did
not take into account effects associated
with acute exposure,19 and, in this
situation, the IRIS health assessment did
not evaluate the potential
carcinogenicity of HCl (on which there
are very limited studies). As a reference
value for a single pollutant, the RfC also
did not reflect any potential cumulative
or synergistic effects of an individual’s
exposure to multiple HAPs or to a
combination of HAPs and criteria
pollutants. As the RfC calculation
focused on health effects, it did not take
into account the potential
environmental impacts of HCl.
With respect to the potential health
effects of HCl, we know the following:
17 EPA has not classified HF, chlorine gas, or HCN
with respect to carcinogenicity. However, at this
time the Agency is not aware of any data that would
suggest any of these HAPs are carcinogens.
18 ‘‘Sensitive subgroups’’ may refer to particular
life stages, such as children or the elderly, or to
those with particular medical conditions, such as
asthmatics.
19 California EPA considered acute toxicity and
established a 1-hour reference exposure level (REL)
of 2.1 mg/m3. An REL is the concentration level at
or below which no adverse health effects are
anticipated for a specified exposure duration. RELs
are designed to protect the most sensitive
individuals in the population by the inclusion of
margins of safety.
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1. Chronic exposure to concentrations
at or below the RfC is not expected to
cause chronic respiratory effects;
2. Little research has been conducted
on its carcinogenicity. The one
occupational study of which we are
aware found no evidence of
carcinogenicity;
3. There is a significant body of
scientific literature addressing the
health effects of acute exposure to HCl
(California Office of Health Hazard
Assessment, 2008. Acute Toxicity
Summary for Hydrogen Chloride,
https://www.oehha.ca.gov/air/hot_spots/
2008/AppendixD2_final.pdf#page=112
EPA, 2001). However, we currently lack
information on the peak short-term
emissions of HCl from boilers, which
might allow us to determine whether a
chronic health-based emission standard
for HCl would ensure that acute
exposures will not pose any health
concerns;
4. We are aware of no studies
explicitly addressing the toxicity of
mixtures of HCl with other respiratory
irritants. However, many of the other
HAPs (and criteria pollutants) emitted
by boilers also are respiratory irritants,
and in the absence of information on
interactions, EPA assumes an additive
cumulative effect (Supplementary
Guidance for Conducting Health Risk
Assessment of Chemical Mixtures.
https://cfpub.epa.gov/ncea/cfm/
recordisplay.cfm?deid=20533). The fact
that boilers can be located among a wide
variety of industrial facilities makes
predicting and assessing all possible
mixtures of HCl and other emitted air
pollutants difficult, if not impossible.
In addition to potential health
impacts, the Administrator also has
evaluated the potential for
environmental impacts when
considering whether to exercise her
discretion under section 112(d)(4). The
legislative history states that employing
a section 112(d)(4) standard rather than
a conventional MACT standard ‘‘shall
not result in adverse environmental
effects which would otherwise be
reduced or eliminated.’’ S. Rep. 101–228
at 171. When HCl gas encounters water
in the atmosphere, it forms an acidic
solution of hydrochloric acid. In areas
where the deposition of acids derived
from emissions of sulfur and nitrogen
oxides are causing aquatic and/or
terrestrial acidification, with
accompanying ecological impacts, the
deposition of hydrochloric acid could
exacerbate these impacts. Being mindful
of the legislative history, it is
appropriate to consider potential
adverse environmental effects in
addition to adverse health effects when
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setting an emission standard for HCl
under section 112(d)(4).
Because the statute requires an ample
margin of safety, it would be reasonable
to set any section 112(d)(4) emission
standard for a pollutant with a health
threshold at a level that at least assures
that, for the sources in the controlled
category or subcategory, persons
exposed to emissions of the pollutant
would not experience the adverse health
effects on which the threshold is based.
In the case of this proposed rulemaking,
we have concluded that we do not have
sufficient information at this time to
establish what the health-based
emission standards would be for HCl or
the other acid gases. Public comments
are invited on our information and
conclusion.
When Congress established the
technology-based MACT program in the
1990 Clean Air Act Amendments, it
recognized the challenges involved in
evaluating health risk. Determining an
emission standard that will protect the
public health with an ample margin of
safety is complex, in part because of the
limited data available on cumulative
impacts. In order to assess the feasibility
of health-based standards in this rule,
the agency believes it would need
additional facility-specific emissions
information. Such information would
enable us to develop model plants for
the eleven subcategories considered in
the proposed rule and allow us to
conduct the dispersion modeling
necessary to establish health-based
emission limits. These limits would
need to be established to ensure that
exposure is below the health threshold
for sources in the subcategory, and
account for the possibility of multiple
exposures from co-located sources as
well as potential short-term increases in
emissions for these sources and their
short-term impacts. Currently, the
Agency has very limited information on
facility-specific emissions, plant
configurations, and overall fence-line
characteristics for this large and diverse
source category. This information is a
precondition to establishing healthbased emission standards that provide
an ample margin of safety. To this end,
the Agency is requesting information on
these factors from the regulated
community and others to allow us to
evaluate the appropriateness and
viability of health-based emission
limits.
EPA specifically requests comment on
the following issues. Additional
information on these issues is important
to implement section 112(d)(4) in a
reasonable and appropriate manner, if
we were to establish emissions
standards under that provision. First,
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EPA requests comment on whether it
would be appropriate to establish
section 112(d)(4) standards for each acid
gas described above, or whether EPA
could set a single 112(d)(4) standard for
one of the acid gases as a surrogate for
the other acid gases. Commenters who
believe a surrogate would be
appropriate should also address the
mechanism that should be used to
determine the appropriate surrogate. In
order to set individual standards under
section 112(d)(4) for each acid gas, we
would need to be able to conclude that
each has an appropriate health
threshold, that there is no scientific
evidence that they are carcinogenic, and
that the emission standard for each uses
the best available science to consider
the possibility of toxicologic
interactions with the other emitted
gases. Alternatively, if we were to
establish a health-based emission
standard for one of the acid gases as a
surrogate for the others, in addition to
the above considerations, we would
need to demonstrate, based on a
knowledge of the effectiveness of
scrubbers for controlling each of the
acid gases, that the surrogate emission
standard effectively ensures that
ambient levels of each of the other acid
gases do not exceed their respective
chronic health thresholds.
EPA also solicits comments on
whether there would be an additive
effect if individual section 112(d)(4)
standards are established for each acid
gas, and if so, how we would simulate
that effect. Individual acid gas standards
under section 112(d)(4) would likely be
established using the hazard quotient
(HQ) approach, under which we would
develop the ratio of the maximum
ambient level to the chronic threshold.
However, this approach would not by
itself account for potential toxicologic
interactions. Since all of the acid gases
are respiratory irritants, one way to
account for potential toxicologic
interactions of these pollutants would
be the use of the hazard index (HI)
approach, as described in EPA’s
‘‘Guideline for the Health Risk
Assessment of Chemical Mixtures.’’ EPA
requests comment on that approach, and
on whether there are any other
approaches to address such additive
effects.
Additionally, EPA requests comment
on whether we should consider the
affected sources (boilers) by themselves,
or whether we should consider all HAP
emissions at the facility when
developing a 112(d)(4) standard. Given
that section 112(d)(4) requires an ‘‘ample
margin of safety,’’ EPA believes it should
consider all reasonable circumstances in
order to ensure such a margin. Since
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boilers are, in many cases, located at
industrial sites with significant
additional sources of HAP (e.g.,
petroleum refineries, furniture
manufacturers, etc.), EPA requests
comment on how we should consider
the potential interactions of acid gases
with other emitted respiratory irritants
at these locations if we were to develop
emission limits under section 112(d)(4).
Commenters are requested to provide
any actual data that is available to make
this type of demonstration. If no data are
available, we request comment on
whether such a demonstration could be
made using a bounding calculation.
EPA also requests comment on
whether we should consider HAP
emissions from neighboring facilities,
and, if so, what the geographic scope of
such consideration should be (e.g., 1
km, 3 km, etc.). We note that
consideration of emissions from nearby
facilities is a more difficult task than
consideration of facility-wide emissions,
since it requires information on all
potential HAP emissions near all of the
locations with boilers. Therefore, we
request comment on whether such
emissions should be considered in
setting section 112(d)(4) emissions
standards, and if so, how they should be
considered. For example, the
consideration could be limited in
geographic scope (e.g., a radius of 3 km),
or could be based on ‘‘average’’ or ‘‘highend’’ ambient levels of respiratory
irritants seen in recent monitoring data
or modeled estimates, since site-specific
data might not be available on all
respiratory irritants.
Further, EPA requests comment on
how to appropriately simulate all
reasonable facility/exposure situations
(e.g., using worst-case facility emissions
coupled with worst-case population
proximity, average emissions and
population, or 90th percentile emissions
and population). Such a simulation
could be based on a sequential
examination of the facilities with the
highest-emitting boilers on-site using
site-specific data, or it could use
screening or bounding methodologies
with high-end or worst-case exposure
assumptions to remove facilities from a
more site-specific examination. We
request comment on these and other
approaches.
Finally, we considered the fact that
setting conventional MACT standards
for HCl as well as PM (as a surrogate for
metals including manganese) would
result in significant reductions in
emissions of other pollutants, most
notably SO2, non-condensable PM, and
other non-HAP acid gases (e.g.,
hydrogen bromide) and would likely
also result in additional reductions in
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emissions of mercury and other HAP
metals (e.g., selenium). The additional
reductions of SO2 alone attributable to
the proposed MACT standard for HCl
are estimated to be 340,000 tons per
year in the third year following
promulgation of the proposed HCl
standard. These are substantial
reductions with substantial public
health benefits. Although MACT
standards may directly address only
HAPs, not criteria pollutants, Congress
did recognize, in the legislative history
to section 112(d)(4), that MACT
standards would have the collateral
benefit of controlling criteria pollutants
as well and viewed this as an important
benefit of the air toxics program.20
Therefore, even where EPA concludes a
HAP has a health threshold, the Agency
may consider such benefits as a factor
in determining whether to exercise its
discretion under section 112(d)(4).
Given the limitations of the currently
available information (i.e., the HAP mix
where boilers are located, and the
cumulative health impacts from colocated sources), the environmental
effects of HCl, and the significant cobenefits of setting a conventional MACT
standard for HCl, the Administrator is
proposing not to exercise her discretion
to use section 112(d)(4).
This conclusion is not contrary to
EPA’s prior decisions where we found
it appropriate to exercise the discretion
to invoke the authority in section
112(d)(4) for HCl, since the
circumstances in this case differ from
previous considerations. Boilers and
process heaters differ from the other
source categories for which EPA has
exercised its authority under section
112(d)(4) in ways that affect
consideration of any health threshold
for HCl. Commercial and industrial
boilers and process heaters are much
more likely to be co-located with
multiple other sources of HAPs than are
pulp and paper mills and lime
manufacturing facilities. In addition,
boilers and process heaters are often
located at facilities in heavily populated
urban areas where many other sources
of HAPs exist. These factors make an
analysis of the health impact of
emissions from these sources on the
exposed population significantly more
complex than for many other source
categories, and therefore make it more
difficult to establish an ample margin of
safety.
Given the particular complexities of
this source category (the location of
boilers and process heaters near other
significant sources of HAP emissions
20 See S. Rep. No. 101–228, 101st Cong. 1st sess.
At 172
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and the use of HCl as a surrogate for
other HAPs), we solicit comment on all
of the conclusions in this section,
including the way the agency has used
112(d)(4) previously, and in particular
whether it would be feasible and
appropriate to establish such a standard
and, if so, the methodology by which it
could be established.
K. How did we select the compliance
requirements?
We are proposing testing, monitoring,
notification, and recordkeeping
requirements that are adequate to assure
continuous compliance with the
requirement of this proposed rule.
These requirements are described in
detail in sections IV.K to IV.N. We
selected these requirements based upon
our determination of the information
necessary to ensure that the emission
standards and work practices are being
followed and that emission control
devices and equipment are maintained
and operated properly. These proposed
requirements ensure compliance with
this proposed rule without imposing a
significant additional burden for
facilities that must implement them.
We are proposing that compliance
with the emission limits for PM, HCl,
mercury, CO, and D/F be demonstrated
by an initial performance test. To ensure
continuous compliance with the
proposed PM, HCl, and mercury
emission limits, this proposed rule
would require continuous parameter
monitoring of control devices and
recordkeeping. Additionally, this
proposed rule would require annual
performance tests to ensure, on an
ongoing basis, that the air pollution
control device is operating properly and
its performance has not deteriorated. If
initial compliance with the mercury
and/or HCl emission limits are
demonstrated by a fuel analysis
performance test, this proposed rule
would require fuel analyses monthly,
with compliance determined based on
an annual average.
We evaluated the feasibility and cost
of applying PM CEMS to boilers and
process heaters. CEMS have been used
in Europe to monitor PM emissions
from a variety of industrial sources.
Several electric utility companies in the
United States have now installed or are
planning to install PM CEMS. In
recognition of the fact that PM CEMS
are commercially available, EPA
developed and promulgated
Performance Specifications (PS) for PM
CEMS (69 FR 1786, January 12, 2004).
PS for PM CEMS are established under
PS–11 in appendix B to 40 CFR part 60
for evaluating the acceptability of a PM
CEM used for determining compliance
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with the emission standards on a
continuous basis. For PM CEM
monitoring, capital costs were estimated
to be $88,000 per unit and annualized
costs were estimated to be $33,000 per
unit. We determined that requiring PM
CEMS for units with heat input capacity
greater or equal to 250 MMBtu/hr and
combusting either coal, biomass, or oil
is a reasonable monitoring option. We
are requesting comment on the
application of PM CEMS to boilers and
process heaters, and the use of data from
such systems for compliance
determinations under this proposed
rule.
We reviewed cost information for CO
CEMS to make the determination on
whether to require CO CEMS or
conducting annual CO testing to
demonstrate continuous compliance
with the CO emission limit. In
evaluating the available cost
information, we determined that
requiring CO CEMS for units with heat
input capacities greater or equal to 100
MMBtu/hr is reasonable. This proposed
rule would require units with heat input
capacities less than 100 MMBtu/hr to
conduct initial and annual performance
(stack) tests.
The majority of test methods that this
proposed rule would require for the
performance stack tests have been
required under many other EPA
standards. The only applicable
voluntary consensus standard identified
is ASTM Method D6784–02 (Ontario
Hydro). The majority of emissions tests
upon which the proposed emission
limits are based were conducted using
these test methods.
When a performance test is
conducted, we are proposing that
parameter operating limits be
determined during the tests.
Performance tests to demonstrate
compliance with any applicable
emission limits are either stack tests or
fuel analysis or a combination of both.
To ensure continuous compliance
with the proposed emission limits and/
or operating limits, this proposed rule
would require continuous parameter
monitoring of control devices and
recordkeeping. We selected the
following requirements based on
reasonable cost, ease of execution, and
usefulness of the resulting data to both
the owners or operators and EPA for
ensuring continuous compliance with
the emission limits and/or operating
limits.
We are proposing that certain
parameters be continuously monitored
for the types of control devices
commonly used in the industry. These
parameters include opacity monitoring
except for wet scrubbers; pH, pressure
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drop and liquid flowrate for wet
scrubbers; and sorbent injection rate for
dry scrubbers. You must also install a
bag leak detection system for fabric
filters. If you cannot monitor opacity for
control systems with an ESP then you
must monitor the secondary current and
voltage or total power input for the ESP.
These monitoring parameters have been
used in other standards for similar
industries. The values of these
parameters are established during the
initial or most recent performance test
that demonstrates compliance. These
values are your operating limits for the
control device.
You would be required to set
parameters based on 4-hour block
averages during the compliance test,
and demonstrate continuous
compliance by monitoring 12-hour
block average values for most
parameters. We selected this averaging
period to reflect operating conditions
during the performance test to ensure
the control system is continuously
operating at the same or better level as
during a performance test demonstrating
compliance with the emission limits.
To demonstrate continuous
compliance with the emission and
operating limits, you would also need
daily records of the quantity, type, and
origin of each fuel burned and hours of
operation of the affected source. If you
are complying with the chlorine fuel
input option, you must keep records of
the calculations supporting your
determination of the chlorine content in
the fuel.
If a source elected to demonstrate
compliance with the HCl or mercury
limit by using fuel which has a
statistically lower pollutant content
than the emission limit, we are
proposing that the source’s operating
limit is the emission limit of the
applicable pollutant. Under this option,
a source is not required to conduct
performance stack tests. If a source
demonstrates compliance with the HCl
or mercury limit by using fuel with a
statistically higher pollutant content
than the applicable emission limit, but
performance tests demonstrate that the
source can meet the emission limits,
then the source’s operating limits are
the operating limits of the control
device (if used) and the fuel pollutant
content of the fuel type/mixture burned.
This proposed rule would specify the
testing methodology and procedures
and the initial and continuous
compliance requirements to be used
when complying with the fuel analysis
options. Fuel analysis tests for total
chloride, gross calorific value, mercury,
sample collection, and sample
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preparation are included in this
proposed rule.
If you elect to comply based on fuel
analysis, you will be required to
statistically analyze, using the z-test, the
data to determine the 90th percentile
confidence level. It is the 90th
percentile confidence level that is
required to be used to determine
compliance with the applicable
emission limit. The statistical approach
is required to assist in ensuring
continuous compliance by statistically
accounting for the inherent variability
in the fuel type.
We are proposing that a source be
required to recalculate the fuel pollutant
content only if it burns a new fuel type
or fuel mixture and conduct another
performance test if the results of
recalculating the fuel pollutant content
are higher than the level established
during the initial performance test.
For boilers and process heaters with
heat input capacities greater or equal to
100 MMBtu/hr, we are proposing that
CO be continuously monitored to
demonstrate that average CO emissions,
on a 30-day rolling average, are at or
below the proposed CO limit.
For boilers and process heaters with
heat input capacities between 10 and
100 MMBtu/hr, we are proposing that a
performance stack test of CO emissions
be conducted to demonstrate
compliance with the CO emission limit.
L. What alternative compliance
provisions are being proposed?
We are proposing that owners and
operators of existing affected sources
may demonstrate compliance by
emissions averaging for units at the
affected source that are within a single
subcategory.
As part of the EPA’s general policy of
encouraging the use of flexible
compliance approaches where they can
be properly monitored and enforced, we
are including emissions averaging in
this proposed rule. Emissions averaging
can provide sources the flexibility to
comply in the least costly manner while
still maintaining regulation that is
workable and enforceable. Emissions
averaging would not be applicable to
new sources and could only be used
between boilers and process heaters in
the same subcategory at a particular
affected source. Also, owners or
operators of existing sources subject to
the Industrial Boiler NSPS (40 CFR part
60, subparts Db and Dc) would be
required to continue to meet the PM
emission standard of that NSPS
regardless of whether or not they are
using emissions averaging.
Emissions averaging would allow
owners and operators of an affected
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source to demonstrate that the source
complies with the proposed emission
limits by averaging the emissions from
an individual affected unit that is
emitting above the proposed emission
limits with other affected units at the
same facility that are emitting below the
proposed emission limits.
This proposed rule includes an
emissions averaging compliance
alternative because emissions averaging
represents an equivalent, more flexible,
and less costly alternative to controlling
certain emission points to MACT levels.
We have concluded that a limited form
of averaging could be implemented that
would not lessen the stringency of the
MACT floor limits and would provide
flexibility in compliance, cost and
energy savings to owners and operators.
We also recognize that we must ensure
that any emissions averaging option can
be implemented and enforced, will be
clear to sources, and most importantly,
will be no less stringent than unit by
unit implementation of the MACT floor
limits.
EPA has concluded that it is
permissible to establish within a
NESHAP a unified compliance regimen
that permits averaging within an
affected source across individual
affected units subject to the standard
under certain conditions. Averaging
across affected units is permitted only if
it can be demonstrated that the total
quantity of any particular HAP that may
be emitted by that portion of a
contiguous major source that is subject
to the NESHAP will not be greater under
the averaging mechanism than it could
be if each individual affected unit
complied separately with the applicable
standard. Under this test, the practical
outcome of averaging is equivalent to
compliance with the MACT floor limits
by each discrete unit, and the statutory
requirement that the MACT standard
reflect the maximum achievable
emissions reductions is, therefore, fully
effectuated.
In past rulemakings, EPA has
generally imposed certain limits on the
scope and nature of emissions averaging
programs. These limits include: (1) No
averaging between different types of
pollutants, (2) no averaging between
sources that are not part of the same
affected source, (3) no averaging
between individual sources within a
single major source if the individual
sources are not subject to the same
NESHAP, and (4) no averaging between
existing sources and new sources.
This proposed rule would fully satisfy
each of these criteria. First, emissions
averaging would only be permitted
between individual sources at a single
existing affected source, and would only
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be permitted between individual
sources subject to the boiler and process
heater NESHAP. Further, emissions
averaging would not be permitted
between two or more different affected
sources. Finally, new sources could not
use emissions averaging. Accordingly,
we have concluded that the averaging of
emissions across affected units is
consistent with the CAA. In addition,
the proposed rule would require each
facility that intends to utilize emission
averaging to submit an emission
averaging plan, which provides
additional assurance that the necessary
criteria will be followed. In this
emission averaging plan, the facility
must include the identification of (1) all
units in the averaging group, (2) the
control technology installed, (3) the
process parameter that will be
monitored, (4) the specific control
technology or pollution prevention
measure to be used, (5) the test plan for
the measurement of the HAP being
averaged, and (6) the operating
parameters to be monitored for each
control device. Upon receipt, the
regulatory authority would not be able
to approve an emission averaging plan
containing averaging between emissions
of different types of pollutants or
between sources in different
subcategories.
This proposed rule would also
exclude new affected sources from the
emissions averaging provision. EPA
believes emissions averaging is not
appropriate for new sources because it
is most cost effective to integrate stateof-the-art controls into equipment
design and to install the technology
during construction of new sources. One
reason we allow emissions averaging is
to give existing sources flexibility to
achieve compliance at diverse points
with varying degrees of add-on control
already in place in the most costeffective and technically reasonable
fashion. This flexibility is not needed
for new sources because they can be
designed and constructed with
compliance in mind.
With concern about the equivalency
of emissions reductions from averaging
and non-averaging in mind, we are also
proposing under the emission averaging
provision caps on the current emissions
from each of the sources in the
averaging group. The emissions for each
unit in the averaging group would be
capped at the emission level being
achieved on the effective date of the
final rule. These caps would ensure that
emissions do not increase above the
emission levels that sources currently
are designed, operated, and maintained
to achieve. In the absence of
performance tests, in documenting these
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caps, these sources will document the
type, design, and operating specification
of control devices installed on the
effective date of the final rule to ensure
that existing controls are not removed or
operated less efficiently. By including
this provision in this proposed rule, we
would further ensure that emission
averaging results in environmental
benefits equivalent to or better than
without emission averaging.
In addition, we are proposing that a
discount factor of ten percent would be
applied when emissions averaging is
used. This discount factor will further
ensure that averaging will be at least as
stringent as the MACT floor limits in the
absence of averaging. The EPA is
soliciting comment on use of a discount
factor and whether ten percent is the
appropriate discount factor. The
emissions averaging provision would
not apply to individual units if the unit
shares a common stack with units in
other subcategories, because in that
circumstance it is not possible to
distinguish the emissions from each
individual unit.
The emissions averaging provisions in
this proposed rule are based in part on
the emissions averaging provisions in
the Hazardous Organic NESHAP (HON).
The legal basis and rational for the HON
emissions averaging provisions were
provided in the preamble to the final
HON (59 FR 19425, April 22, 1994).
M. How did EPA determine compliance
times for the proposed rule?
Section 112 of the CAA specifies the
dates by which affected sources must
comply with the emission standards.
New or reconstructed units must be in
compliance with this proposed rule
immediately upon startup or [DATE
THE FINAL RULE IS PUBLISHED IN
THE FEDERAL REGISTER], whichever
is later. Existing sources are allowed 3
years to comply with the final rule. This
is the maximum period allowed by the
CAA. We believe that 3 years for
compliance is necessary to allow
adequate time to design, install and test
control systems that will be retrofitted
onto existing boilers, as well as obtain
permits for the use of add-on controls.
N. How did EPA determine the required
records and reports for this proposed
rule?
You would be required to comply
with the applicable requirements in the
NESHAP General Provisions, subpart A
of 40 CFR part 63, as described in Table
10 of the proposed subpart DDDDD. We
evaluated the General Provisions
requirements and included those we
determined to be the minimum
notification, recordkeeping, and
reporting necessary to ensure
compliance with, and effective
enforcement of, this proposed rule.
We are also requiring that you keep
daily records of the total fuel use by
each affected source, subject to an
emission limit or work practice
standard, along with a description of the
fuel, the total fuel usage amounts and
units of measure, and information on
the supplier and original source of the
fuel. This information is necessary to
ensure that the affected source is
complying with the emission limits
from the correct subcategory.
We would require additional
recordkeeping if you chose to comply
with the chlorine or mercury fuel input
option. You would need to keep records
of the calculations and supporting
information used to develop the
chlorine or mercury fuel input operating
limit.
O. How does this proposed rule affect
permits?
The CAA requires that sources subject
to this proposed rule be operated
pursuant to a permit issued under EPAapproved State operating permit
program. The operating permit programs
are developed under title V of the CAA
and the implementing regulations under
40 CFR parts 70 and 71. If you are
operating in the first 3 years of your
operating permit, you will need to
obtain a revised permit to incorporate
this proposed rule. If you are in the last
2 years of your operating permit, you
will need to incorporate this proposed
rule into the next renewal of your
permit.
P. Alternate Standard for Consideration
As discussed above, EPA is proposing
a definition of non-hazardous solid
waste under RCRA in a concurrent
notice. The proposed CAA section
112(d) standards for boilers and process
heaters were developed considering that
proposed definition of solid waste.
Therefore, the emission limits presented
in Tables 1 through 5 above are based
on subcategories established
considering sources that are ICI boilers
and process heaters under the proposed
definition of solid waste under RCRA.
However, the RCRA proposal also
identifies and solicits comment on an
alternative approach for defining solid
waste, under which more units would
be considered solid waste incineration
units than under the proposed
definition. As such, the alternative
approach for defining solid waste under
RCRA would result in a different,
smaller population of units being
covered by Boiler MACT. Consistent
with EPA’s solicitation of comment on
an alternative proposed definition of
solid waste under RCRA, we calculated
MACT floors using emission rates for
units that would be ICI boilers and
process heaters under that alternative
definition, using the same statistical
procedures that were used to calculate
the standards that are being proposed.
Table 6 reflects that calculation of
MACT floor limits for the existing
source subcategories that would be
changed by the alternative definition of
solid waste identified in the concurrent
RCRA proposal, compared to the
proposed definition of solid waste in
that proposal. The MACT floor limits for
the remaining existing source
subcategories (Gas 1, Gas 2, and Liquid)
would not change under the alternative
definition of solid waste on which EPA
is soliciting comment in the concurrent
RCRA proposal, and are therefore not
included in Table 8 because the MACT
floor limits for those subcategories
would be the same under the alternative
definition of solid waste as under the
proposed definition.
TABLE 8—EXISTING MACT FLOOR LIMITS USING THE ‘‘ALTERNATIVE APPROACH’’ UNDER CONSIDERATION AND COMMENT
IN THE CONCURRENTLY PROPOSED RCRA RULE
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[Pounds per million British thermal units]
Particulate
matter (PM)
Subcategory
Existing—Coal Stoker ......................................................
Existing—Coal Fluidized Bed ..........................................
Existing—Pulverized Coal ................................................
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Frm 00031
Hydrogen
chloride (HCl)
0.03
0.03
0.03
Fmt 4701
0.02
0.02
0.02
Sfmt 4702
Carbon
monoxide
(CO) (ppm
@ 3% oxygen)
Mercury
(Hg)
4.0E–06
4.0E–06
4.0E–06
E:\FR\FM\04JNP5.SGM
04JNP5
40
50
90
Dioxins/
Furans
(total TEQ)
(ng/dscm)
commat; 7% O2
0.003
0.008
0.004
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TABLE 8—EXISTING MACT FLOOR LIMITS USING THE ‘‘ALTERNATIVE APPROACH’’ UNDER CONSIDERATION AND COMMENT
IN THE CONCURRENTLY PROPOSED RCRA RULE—Continued
[Pounds per million British thermal units]
Particulate
matter (PM)
Subcategory
Existing—Biomass
Existing—Biomass
Existing—Biomass
Existing—Biomass
Stoker ................................................
Fluidized Bed ....................................
Suspension Burner/Dutch Oven .......
Fuel Cells ..........................................
Comparing the emissions limits in
Table 1 (based on the proposed
definition of solid waste) with those in
Table 8 (based on the alternative
definition of solid waste), the MACT
emission limits for PM and mercury for
the biomass subcategories would be less
stringent if they are based on the
alternative definition of solid waste
while the HCl emission limits for the
coal and biomass subcategories would
be more stringent if they are based on
the alternative definition.
The potential emissions reductions if
the MACT floor limits are calculated
based on the alternative definition of
solid waste would be generally lower
than the potential emissions reductions
for MACT floors based on the proposed
definition of solid waste, because 280
Hydrogen
chloride (HCl)
0.02
0.02
0.02
0.02
Carbon
monoxide
(CO) (ppm
@ 3% oxygen)
Mercury
(Hg)
0.03
0.03
0.03
0.03
fewer boilers and process heaters would
be subject to the boiler and process
heater MACT standards under the
alternative definition. These units
would instead be considered CISWI
units under the alternative definition of
solid waste. For example, mercury
emissions reduction would be 7 tons per
year based on the alternative definition
of solid waste (compared to 8 tons per
year based on the proposed definition)
and HCl emissions reduction would be
5,100 tons per year based on the
alternative definition (compared to
37,000 tons per year based on the
proposed definition). Most (181) of the
280 units that would be considered
CISWI units under the alternative
definition of solid waste proposed
under RCRA are biomass-fired boilers or
Dioxins/
Furans
(total TEQ)
(ng/dscm)
commat; 7% O2
180
10,650
1,060
460
0.00005
0.1
0.3
0.02
5.0E–07
5.0E–07
5.0E–07
5.0E–07
process heaters, with the others being in
the coal and liquid fuel subcategories.
The resulting total national cost
impact for existing boilers and process
heaters of the proposed emission limits
based on the alternative definition of
solid waste would be 8.0 billion dollars
in capital expenditures and 2.4 billion
dollars per year in total annual costs.
This compares to $9.5 billion in capital
costs and $2.9 billion in annual costs
under the proposed definition of solid
waste in the RCRA proposed rule. Table
9 of this preamble shows the capital and
annual cost impacts for each
subcategory under the alternative
definition of solid waste. Costs include
testing and monitoring costs, but not
recordkeeping and reporting costs.
TABLE 9—SUMMARY OF CAPITAL AND ANNUAL COSTS FOR EXISTING SOURCES UNDER THE ALTERNATIVE SOLID WASTE
DEFINITION
Source
Subcategory
Estimated/
projected
number of
affected units
Existing Units ....................................
Coal units ..........................................
Biomass units ...................................
Liquid units .......................................
Gas (NG/RG) units ...........................
Gas (other) units ...............................
ALL ...................................................
525 ....................................................
239 ....................................................
791 ....................................................
11,524 ...............................................
196 ....................................................
1,551 facilities ...................................
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Energy Assessment ..........................
A discussion of the methodology used
to estimate cost impacts is presented in
‘‘Methodology and Results of Estimating
the Cost of Complying with the
Industrial, Commercial, and
Institutional Boiler and Process Heater
NESHAP (2010)’’ in the Docket.
We are soliciting public comments on
the emission limits listed in Table 6 of
this preamble, consistent with EPA’s
solicitation of comments on the
alternative definition of solid waste
concurrently proposed under RCRA. As
explained above, the MACT floor limits
proposed today are based on the
proposed definition of solid waste
under RCRA. However, because EPA is
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seeking comment on an alternative
definition of solid waste under RCRA,
the Agency believes it is necessary to
also solicit comment on what the MACT
floor limits would be based on the
universe of sources that would be
subject to the boiler and process heater
MACT under that alternative definition.
V. Impacts of the Proposed Rule
A. What are the air impacts?
Table 10 of this preamble illustrates,
for each basic fuel subcategory, the
emissions reductions achieved by the
proposed rule (i.e., the difference in
emissions between a boiler or process
heater controlled to the floor level of
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Capital
costs
(106$)
3,861
1,250
1,352
75
1,476
Annualized
cost
(106$/yr)
1,508
317
417
259
434
24.9
control and boilers or process heaters at
the current baseline) for new and
existing sources. Nationwide emissions
of selected HAP (i.e., HCl, HF, mercury,
metals, and VOC) will be reduced by
43,000 tons per year for existing units
and 15 tons per year for new units.
Emissions of HCl will be reduced by
37,000 tons per year for existing units
and 9 tons per year for new units.
Emissions of mercury will be reduced
by 8 tons per year for existing units and
2.6 pounds per year for new units.
Emissions of filterable PM will be
reduced by 50,100 tons per year for
existing units and 130 tons per year for
new units. Emissions of non-mercury
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metals (i.e., antimony, arsenic,
beryllium, cadmium, chromium, cobalt,
lead, manganese, nickel, and selenium)
will be reduced by 3,200 tons per year
for existing units and will be reduced by
0.6 ton per year for new units. In
addition, emissions of SO2 are estimated
to be reduced by 340,000 tons per year
for existing sources and 500 tons per
year for new sources. Emissions of
dioxin/furans, on a total mass basis, will
be reduced by 722 grams per year for
existing units and 1 gram per year for
new units. A discussion of the
methodology used to estimate emissions
and emissions reductions is presented
in ‘‘Estimation of Baseline Emissions
and Emissions Reductions for
Industrial, Commercial, and
Institutional Boilers and Process Heaters
(2010)’’ in the docket.
TABLE 10—SUMMARY OF EMISSIONS REDUCTIONS FOR EXISTING AND NEW SOURCES
[Tons/yr]
Source
Subcategory
Existing Units ................................
Coal units ......................................
Biomass units ...............................
Liquid units ...................................
Gas 1 (NG/RG) units ....................
Gas 2 (other) units .......................
Coal units ......................................
Biomass units ...............................
Liquid units ...................................
Gas 1 units ...................................
Gas 2 units ...................................
New Units .....................................
a Includes
Non
mercury
metals a
PM
35,450
520
840
9
220
0
0
9
0.01
1
17,000
22,500
10,400
130
0
0
0
130
0.1
4
770
230
2,200
1.2
0
0
0
0.6
0.001
0.01
Mercury
7.1
0.2
0.00005
0.01
0.2
0
0
0.0007
0.000008
0.0006
VOC
490
760
290
72
170
0
0
3
0.01
1
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
B. What are the water and solid waste
impacts?
erowe on DSK5CLS3C1PROD with PROPOSALS5
HCl
C. What are the energy impacts?
The EPA estimated the additional
water usage that would result from
installing wet scrubbers to meet the
emission limits for HCl would be 2,400
million gallons per year for existing
sources and 200,000 gallons per year for
new sources. In addition to the
increased water usage, an additional 730
million gallons per year of wastewater
would be produced for existing sources
and 140,000 gallons per year for new
sources. The annual costs of treating the
additional wastewater are $4.0 million
for existing sources and $774 for new
sources. These costs are accounted for
in the control costs estimates.
The EPA estimated the additional
solid waste that would result from the
MACT floor level of control to be 81,000
tons per year for existing sources and
149,800 tons per year for new sources.
Solid waste is generated from flyash and
dust captured in PM and mercury
controls as well as from spent carbon
that is injected into exhaust streams or
used to filter gas streams. The costs of
handling the additional solid waste
generated are $3.4 million for existing
sources and $6.3 million for new
sources. These costs are also accounted
for in the control costs estimates.
A discussion of the methodology used
to estimate impacts is presented in
‘‘Estimation of Impacts for Industrial,
Commercial, and Institutional Boilers
and Process Heaters NESHAP (2010)’’ in
the Docket.
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The EPA expects an increase of
approximately 2.995 million kilowatt
hours (kWh) in national annual energy
usage as a result of the proposed rule.
Of this amount, 2,944 million kWh
would be from existing sources and 11
million kWh are estimated from new
sources. The increase results from the
electricity required to operate control
devices, such as wet scrubbers,
electrostatic precipitators, and fabric
filters which are expected to be installed
to meet the proposed rule. Additionally,
the EPA expects work practice
standards such as boilers tune-ups and
combustion controls will improve the
efficiency of boilers, resulting in an
estimated fuel savings of 42 trillion BTU
each year from existing sources and an
additional 100,000 million BTU each
year. This fuel savings estimate includes
only those fuel savings resulting from
gas, liquid, and coal fuels and it is based
on the assumption that the work
practice standards will achieve 1
percent improvement in efficiency.
D. What are the control costs?
To estimate the national cost impacts
of the proposed rule for existing
sources, we developed average baseline
emission factors for each fuel type/
control device combination based on the
emission data obtained and contained in
the Boiler MACT emission database. If
a unit reported emission data, we
assigned its unit-specific emission data
as its baseline emissions. For units that
did not report emission data, we
assigned the appropriate emission
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Sfmt 4702
factors to each existing unit in the
inventory database, based on the
average emission factors for boilers with
similar fuel, design, and control devices.
We then compared each unit’s baseline
emission factors to the proposed MACT
floor emission limit to determine if
control devices were needed to meet the
emission limits. The control analysis
considered fabric filters, carbon bed
adsorbers, and activated carbon
injection to be the primary control
devices for mercury control,
electrostatic precipitators for units
meeting mercury limits but requiring
additional control to meet the PM
limits, wet scrubbers to meet the HCl
limits, tune-ups, replacement burners,
and combustion controls for CO and
organic HAP control, and carbon
injection for dioxin/furan control. We
identified where one control device
could achieve reductions in multiple
pollutants, for example a fabric filter
was expected to achieve both PM and
mercury control in order to avoid
overestimating the costs. We also
included costs for testing and
monitoring requirements contained in
the proposed rule. The resulting total
national cost impact of the proposed
rule is 9.5 billion dollars in capital
expenditures and 3.2 billion dollars per
year in total annual costs. Considering
estimated fuel savings resulting from
work practice standards and combustion
controls, the total annualized costs are
reduced to 2.9 billion dollars. The total
capital and annual costs include costs
for control devices, work practices,
testing and monitoring. Table 11 of this
preamble shows the capital and annual
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cost impacts for each subcategory. Costs
include testing and monitoring costs,
but not recordkeeping and reporting
costs.
TABLE 11—SUMMARY OF CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES
Source
Subcategory
Existing Units ..........................................
Coal units ................................................
Biomass units .........................................
Liquid units .............................................
Gas (NG/RG) units .................................
Gas (other) units .....................................
ALL .........................................................
Coal units ................................................
Biomass units .........................................
Liquid units .............................................
Gas (NG/RG) units .................................
Gas (other) units .....................................
578
420
826
11,532
199
....................
0
0
11
33
2
Energy Assessment ................................
New Units ...............................................
Using Department of Energy
projections on fuel expenditures, the
number of additional boilers that could
be potentially constructed was
estimated. The resulting total national
cost impact of the proposed rule in the
3rd year is 17 million dollars in capital
expenditures and 6.2 million dollars per
year in total annual costs, when
considering a 1 percent fuel savings.
Potential control device cost savings
and increased recordkeeping and
reporting costs associated with the
emissions averaging provisions in the
proposed rule are not accounted for in
either the capital or annualized cost
estimates.
A discussion of the methodology used
to estimate cost impacts is presented in
‘‘Methodology and Results of Estimating
the Cost of Complying with the
Industrial, Commercial, and
Institutional Boiler and Process Heater
NESHAP (2010)’’ in the Docket.
E. What are the economic impacts?
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Capital
costs
(106$)
Testing and
monitoring
annualized
costs
(106$/yr)
4,468
2,003
1,389
75
1,554
....................
0
0
12
0.2
5.5
62.4
35.5
27.4
0
10.4
......................
0
0
0.5
0
0.14
Estimated/
projected
number of
affected
units
The economic impact analysis (EIA)
that is included in the RIA shows that
the expected prices for industrial sectors
could be 0.01 percent higher and
domestic production may fall by about
0.01 percent. Because of higher
domestic prices imports may rise by
0.01 percent. In addition, impacts to
affected energy markets show that prices
may rise by 0.04 percent.
Social costs are estimated to also be
$2.9 billion in 2008 dollars. This is
estimated to be made up of a $0.8
billion loss in domestic consumer
surplus, a $2.5 billion loss in domestic
producer surplus, a $0.1 billion increase
in rest of the world surplus, and a $0.4
billion in net fuel savings not modeled
in a way that can be used to attribute it
to consumers and producers.
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EPA performed a screening analysis
for impacts on small entities by
comparing compliance costs to sales/
revenues (e.g., sales and revenue tests).
EPA’s analysis found the tests were
typically higher than 3 percent for small
entities included in the screening
analysis. EPA has prepared an Initial
Regulatory Flexibility Analysis (IRFA)
that discusses alternative regulatory or
policy options that minimize the rule’s
small entity impacts. It includes key
information about key results from the
Small Business Advocacy Review
(SBAR) panel.
Precise job effect estimates cannot be
estimated with certainty. Morgenstern et
al. (2002) identify three economic
mechanisms by which pollution
abatement activities can indirectly
influence jobs:
• Higher production costs raise
market prices, higher prices reduce
consumption, and employment within
an industry falls (‘‘demand effect’’);
• Pollution abatement activities
require additional labor services to
produce the same level of output (‘‘cost
effect’’); and
• Post regulation production
technologies may be more or less labor
intensive (i.e., more/less labor is
required per dollar of output) (‘‘factorshift effect’’).
Several empirical studies, including
Morgenstern et al. (2002), suggest the
net employment decline is zero or
economically small (e.g., Cole and
Elliot, 2007; Berman and Bui, 2001).
However, others show the question has
not been resolved in the literature
(Henderson, 1996; Greenstone, 2002).
Morgenstern’s paper uses a six-year
panel (U.S. Census data for plant-level
prices, inputs (including labor), outputs,
and environmental expenditures) to
econometrically estimate the production
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Fmt 4701
Sfmt 4702
Annualized
cost
(106$/yr)
(considering
fuel savings)
1,619
609
419
(260)
459
26
0
0
6.1
0.01
1.7
technologies and industry-level demand
elasticities. Their identification strategy
leverages repeat plant-level observations
over time and uses plant-level and year
fixed effects (e.g., plant and time
dummy variables). After estimating their
model, Morgenstern show and compute
the change in employment associated
with an additional $1 million ($1987) in
environmental spending. Their
estimates covers four manufacturing
industries (pulp and paper, plastics,
petroleum, and steel) and Morgenstern,
et al. present results separately for the
cost, factor shift, and demand effects, as
well as the net effect. They also estimate
and report an industry-wide average
parameter that combines the four
industry-wide estimates and weighting
them by each industry’s share of
environmental expenditures.
EPA has most often estimated
employment changes associated with
plant closures due to environmental
regulation or changes in output for the
regulated industry (EPA, 1999a; EPA,
2000). This analysis goes beyond what
EPA has typically done in two ways.
First, because the multimarket model
provides estimates for changes in output
for sectors not directly regulated, we
were able to estimate a more
comprehensive ‘‘demand effect.’’
Secondly, parameters estimated in the
Morgenstern paper were used to
estimate all three effects (‘‘demand,’’
‘‘cost,’’ and ‘‘factor shift’’). This transfer
of results from the Morgenstern study is
uncertain but avoids ignoring the ‘‘cost
effect’’ and the ‘‘factor-shift effect.’’
We calculated ‘‘demand effect’’
employment changes by assuming that
the number of jobs changes
proportionally with multi-market
model’s simulated output changes.
These results were calculated for all
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sectors in the EPA model that show a
change in output. The total job losses
are estimated to be approximately 6,000.
We also calculated a similar ‘‘demand
effect’’ estimate that used the
Morgenstern paper. To do this, we
multiplied the point estimate for the
total demand effect (¥3.56 jobs per
million ($1987) of environmental
compliance expenditure) by the total
environmental compliance expenditures
used in the partial equilibrium model.
For example, the job loss estimate is
approximately 7,000 jobs (¥3.56 × $3.5
billion × 0.60).21
We also present the results of using
the Morgenstern paper to estimate
employment ‘‘cost’’ and ‘‘factor-shift’’
effects (Table 1). Although using the
Morgenstern parameters to estimate
these ‘‘cost’’ and ‘‘factor-shift’’
employment changes is uncertain, it is
helpful to compare the potential job
gains from these effects to the job losses
associated with the ‘‘demand’’ effect.
Table 1 shows that using the
Morgenstern point estimates of
parameters to estimate the ‘‘cost’’ and
‘‘factor shift’’ employment gains may be
greater than the employment losses
using either of the two ways of
estimating ‘‘demand’’ employment
losses. The 95 percent confidence
intervals are shown for all of the
estimates based on the Morgenstern
parameters. As shown, at the 95%
confidence level, we cannot be certain
if net employment changes are positive
or negative.
Although the Morgenstern paper
provides additional information about
the potential job effects of
environmental protection programs,
there are several qualifications EPA
considered as part of the analysis. First,
EPA has used the weighted average
parameter estimates for a narrow set of
manufacturing industries (pulp and
paper, plastics, petroleum, and steel).
Absent other data and estimates, this
approach seems reasonable and the
estimates come from a respected peerreviewed source. However, EPA
acknowledges the proposed rule covers
a broader set of industries not
considered in original empirical study.
By transferring the estimates to other
industrial sectors, we make the
assumption that estimates are similar in
size. In addition, EPA assumes also that
Morgenstern et al.’s estimates derived
from the 1979–1991 still applicable for
policy taking place in 2013, almost 20
years later. Second, the multi-market
model only considers near term
employment effects in a U.S. economy
where production technologies are
fixed. As a result, the modeling system
32039
places more emphasis on the short term
‘‘demand effect’’ whereas the
Morgenstern paper emphasizes other
important long term responses. For
example, positive job gains associated
with ‘‘factor shift effects’’ are more
plausible when production choices
become more flexible over time and
industries can substitute labor for other
production inputs. Third, the
Morgenstern paper estimates rely on
sector demand elasticities that are
different from the demand elasticity
parameters used in the multi-market
model. As a result, the demand effects
are not directly comparable with the
demand effects estimated by the multimarket model. Fourth, Morgenstern
identifies the industry average as
economically and statistically
insignificant effect (i.e., the point
estimates are small, measured
imprecisely, and not distinguishable
from zero.) EPA acknowledges this fact
and has reported the 95 percent
confidence intervals in Table 1. Fifth,
Morgenstern’s methodology assumes
large plants bear most of the regulatory
costs. By transferring the estimates, EPA
assumes a similar distribution of
regulatory costs by plant size and that
the regulatory burden does not
disproportionately fall on smaller
plants.
TABLE 12—EMPLOYMENT CHANGES: 2013
Estimation method
1,000 Jobs
Partial equilibrium model (multiple markets) (demand effect only) .......................................................................................................
Literature-based estimate (net effect [A + B + C below]) .....................................................................................................................
A. Literature-based estimate: Demand effect ................................................................................................................................
B. Literature-based estimate: Cost effect .......................................................................................................................................
C. Literature-based estimate: Factor shift effect ............................................................................................................................
¥5
+3
(¥6 to +12)
¥7
(¥15 to +1)
+5
(+2 to +8)
+5
(0 to +10)
NOTE: Totals may not add due to independent rounding. 95 percent confidence intervals for literature-based estimates are shown in
parenthesis.
F. What are the social costs and benefits
of this proposed rule?
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We estimate the monetized benefits of
this proposed regulatory action to be
$17 billion to $41 billion (2008$, 3
percent discount rate) in the
21 Since Morgenstern’s analysis reports
environmental expenditures in $1987, we make an
inflation adjustment the engineering cost analysis
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implementation year (2013). The
monetized benefits of the proposed
regulatory action at a 7 percent discount
rate are $15 billion to $37 billion
(2008$). Using alternate relationships
between PM2.5 and premature mortality
supplied by experts, higher and lower
benefits estimates are plausible, but
most of the expert-based estimates fall
between these two estimates.22 A
summary of the monetized benefits
estimates at discount rates of 3 percent
and 7 percent is in Table 13 of this
preamble.
using GDP implicit price deflator (64.76/108.48) =
0.60).
22 Roman et al., 2008. Expert Judgment
Assessment of the Mortality Impact of Changes in
Ambient Fine Particulate Matter in the U.S.
Environ. Sci. Technol., 42, 7, 2268—2274.
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TABLE 13—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE PROPOSED BOILER MACT FOR MAJOR
SOURCES IN 2013
[Billions of 2008$] 1
Estimated
emission
reductions
(tons per
year)
Total monetized benefits
(3% discount rate)
Total monetized benefits
(7% discount rate)
PM2.5 .........................................................
PM2.5 Precursors
SO2 ....................................................
VOC ...................................................
29,020
$6.6 to $16 ................................................
$6.0 to $15.
339,996
1,786
$10 to $25 .................................................
$0.002 to $0.005 .......................................
$9.1 to $22.
$0.002 to $0.005.
Total ............................................
....................
$17 to $41 .................................................
$15 to $37.
1All estimates are for the implementation year (2013), and are rounded to two significant figures so numbers may not sum across rows. All fine
particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form PM2.5. Benefits from reducing hazardous air pollutants (HAPs) are not included.
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These benefits estimates represent the
total monetized human health benefits
for populations exposed to less PM2.5 in
2013 from controls installed to reduce
air pollutants in order to meet these
standards. These estimates are
calculated as the sum of the monetized
value of avoided premature mortality
and morbidity associated with reducing
a ton of PM2.5 and PM2.5 precursor
emissions. To estimate human health
benefits derived from reducing PM2.5
and PM2.5 precursor emissions, we
utilized the general approach and
methodology on the laid out in Fann et
al. (2009).23
To generate the benefit-per-ton
estimates, we used a model to convert
emissions of direct PM2.5 and PM2.5
precursors into changes in ambient
PM2.5 levels and another model to
estimate the changes in human health
associated with that change in air
quality. Finally, the monetized health
benefits were divided by the emission
reductions to create the benefit-per-ton
estimates. Even though we assume that
all fine particles have equivalent health
effects, the benefit-per-ton estimates
vary between precursors because each
ton of precursor reduced has a different
propensity to form PM2.5. For example,
SOX has a lower benefit-per-ton estimate
than direct PM2.5 because it does not
form as much PM2.5, thus the exposure
would be lower, and the monetized
health benefits would be lower.
For context, it is important to note
that the magnitude of the PM benefits is
largely driven by the concentration
response function for premature
mortality. Experts have advised EPA to
consider a variety of assumptions,
including estimates based both on
empirical (epidemiological) studies and
judgments elicited from scientific
experts, to characterize the uncertainty
in the relationship between PM2.5
concentrations and premature mortality.
For this proposed rule we cite two key
empirical studies, one based on the
American Cancer Society cohort
study 24 and the extended Six Cities
cohort study.25 In the RIA for this
proposed rule, which is available in the
docket, we also include benefits
estimates derived from expert
judgments and other assumptions.
This analysis does not include the
type of detailed uncertainty assessment
found in the 2006 PM2.5 NAAQS RIA
because we lack the necessary air
quality input and monitoring data to run
the benefits model. However, the 2006
PM2.5 NAAQS benefits analysis 26
provides an indication of the sensitivity
of our results to various assumptions.
It should be emphasized that the
monetized benefits estimates provided
above do not include benefits from
several important benefit categories,
including reducing other air pollutants,
ecosystem effects, and visibility
impairment. The benefits from reducing
carbon monoxide and hazardous air
pollutants have not been monetized in
this analysis, including reducing
330,000 tons of carbon monoxide,
37,000 tons of HCl, 1,000 tons of HF
each year, 7.5 tons of mercury, 3,200
tons of other metals, and 720 grams of
dioxins/furans each year. Although we
do not have sufficient information or
modeling available to provide
monetized estimates for this
rulemaking, we include a qualitative
assessment of the health effects of these
air pollutants in the Regulatory Impact
Analysis (RIA) for this proposed rule,
which is available in the docket.
The social costs of this proposed
rulemaking are estimated to be $2.9
billion (2008$) in the implementation
year, and the monetized benefits are $17
billion to $41 billion (2008$, 3 percent
discount rate) for that same year. The
benefits at a 7 percent discount rate are
$15 billion to $37 billion (2008$). Thus,
net benefits of this rulemaking are
estimated at $14 billion to $38 billion
(2008$, 3 percent discount rate) and $12
billion to $34 billion (2008$, 7 percent
discount rate). EPA believes that the
benefits of the proposed rule are likely
to exceed the costs even when taking
into account the uncertainties in the
cost and benefit estimates. A summary
of the monetized benefits, social costs,
and net benefits at discount rates of 3
percent and 7 percent is in Table 14 of
this preamble.
23 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009.
‘‘The influence of location, source, and emission
type in estimates of the human health benefits of
reducing a ton of air pollution.’’ Air Qual Atmos
Health (2009) 2:169–176.
24 Pope et al., 2002. ‘‘Lung Cancer,
Cardiopulmonary Mortality, and Long-term
Exposure to Fine Particulate Air Pollution.’’ Journal
of the American Medical Association. 287:1132–
1141.
25 Laden et al., 2006. ‘‘Reduction in Fine
Particulate Air Pollution and Mortality.’’ American
Journal of Respiratory and Critical Care Medicine.
173:667–672.
26 U.S. Environmental Protection Agency, 2006.
Final Regulatory Impact Analysis: PM2.5 NAAQS.
Prepared by Office of Air and Radiation. October.
Available on the Internet at https://www.epa.gov/ttn/
ecas/ria.html.
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TABLE 14—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER MACT (MAJOR
SOURCES) IN 2013
[Millions of 2008$] 1
3% Discount rate
7% Discount rate
Proposed Option
Total Monetized Benefits 2 ......................................................................
$17 to $41 .....................................
$15 to $37.
.................................................................................
$2.9 ................................................
$2.9.
Net Benefits .............................................................................................
$14 to $38 .....................................
$12 to $34.
Non-monetized Benefits ..........................................................................
340,000 tons of carbon monoxide.
37,000 tons of HCl.
1,000 tons of HF.
7.5 tons of mercury.
3,200 tons of other metals.
720 grams of dioxins/furans.
Health effects from NO2 and SO2 exposure.
Ecosystem effects.
Visibility impairment.
Total Social
Costs 3
Proposed Option with Alternate Solid Waste Definition
Total Monetized Benefits 2 ......................................................................
$3.1 to $7.7 ...................................
$2.8 to $6.9.
Total Social Costs 3 .................................................................................
$2.2 ................................................
$2.2.
Net Benefits .............................................................................................
$0.93 to $5.5 .................................
$0.64 to $4.7.
Non-monetized Benefits ..........................................................................
280,000 tons of carbon monoxide.
5,100 tons of HCl.
1,100 tons of HF.
7.1 tons of mercury.
1,600 tons of other metals.
290 grams of dioxins/furans.
Health effects from NO2 and SO2 exposure.
Ecosystem effects.
Visibility impairment.
1 All
estimates are for the implementation year (2015), and are rounded to two significant figures.
total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of directly emitted PM2.5 and PM2.5 precursors such as NOX and SO2. It is important to note that the monetized benefits include many but not all health effects
associated with PM2.5 exposure.
3 The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs
for both discount rates.
2 The
For more information on the benefits
analysis, please refer to the RIA for this
rulemaking, which is available in the
docket.
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VI. Public Participation and Requests
for Comment
We request comment on all aspects of
this proposed rule.
In 2004 we published a final rule for
boilers and process heaters located at
major source facilities (69 FR 55218,
September 13, 2004). The final rule was
vacated and remanded by the Court on
June 19, 2007. We are reissuing our
proposal, in response to the Court’s
decisions, in this notice. We received
many comments on that vacated rule
during its rulemaking and have
attempted to take all those comments
into account in this action. This
proposal includes a variety of changes
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from the vacated rule, mostly centered
on emission limits for the various HAP
and subcategories.
During this rulemaking, we conducted
outreach to small entities and convened
a Small Business Advocacy Review
(SBAR) Panel to obtain advice and
recommendation of representatives of
the small entities that potentially would
be subject to the requirements of this
proposed rule. As part of the SBAR
Panel process we conducted outreach
with representatives from various small
entities that would be affected by this
proposed rule. We met with these small
entity representatives (SERs) to discuss
the potential rulemaking approaches
and potential options to decrease the
impact of the rulemaking on their
industries/sectors. We distributed
outreach materials to the SERs; these
materials included background on the
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rulemaking, possible regulatory
approaches, preliminary cost and
economic impacts, and possible
rulemaking alternatives. We met with
SERs from the industries that will be
impacted directly by this proposed rule
to discuss the outreach materials and
receive feedback on the approaches and
alternatives detailed in the outreach
packet. The Panel received written
comments from the SERs following the
meeting in response to discussions at
the meeting and the questions posed to
the SERs by the Agency. The SERs were
specifically asked to provide comment
on regulatory alternatives that could
help to minimize the rule’s impact on
small businesses.
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VII. Relationship of This Proposed
Action to Section 112(c)(6) of the CAA
Section 112(c)(6) of the CAA requires
EPA to identify categories of sources of
seven specified pollutants to assure that
sources accounting for not less than 90
percent of the aggregate emissions of
each such pollutant are subject to
standards under CAA Section 112(d)(2)
or 112(d)(4). EPA has identified
‘‘Industrial Coal Combustion,’’
‘‘Industrial Oil Combustion,’’ Industrial
Wood/Wood Residue Combustion,’’
‘‘Commercial Coal Combustion,’’
‘‘Commercial Oil Combustion,’’ and
‘‘Commercial Wood/Wood Residue
Combustion’’ as source categories that
emits two of the seven CAA Section
112(c)(6) pollutants: POM and mercury.
(The POM emitted is composed of 16
polyaromatic hydrocarbons and
extractable organic matter.) In the
Federal Register notice Source Category
Listing for Section 112(d)(2) Rulemaking
Pursuant to Section 112(c)(6)
Requirements, 63 FR 17838, 17849,
Table 2 (1998), EPA identified
‘‘Industrial Coal Combustion,’’
‘‘Industrial Oil Combustion,’’ ‘‘Industrial
Wood/Wood Residue Combustion,’’
‘‘Commercial Coal Combustion,’’
‘‘Commercial Oil Combustion,’’ and
‘‘Commercial Wood/Wood Residue
Combustion’’ as source category ‘‘subject
to regulation’’ for purposes of CAA
Section 112(c)(6) with respect to the
CAA Section 112(c)(6) pollutants that
these units emit.
Specifically, as byproducts of
combustion, the formation of POM is
effectively reduced by the combustion
and post-combustion practices required
to comply with the CAA Section 112
standards. Any POM that do form
during combustion are further
controlled by the various postcombustion controls. The add-on PM
control systems (either fabric filter or
wet scrubber) and activated carbon
injection in the fabric filter-based
systems further reduce emissions of
these organic pollutants, and also
reduce mercury emissions, as is
evidenced by performance data.
Specifically, the emission tests obtained
at currently operating units show that
the proposed MACT regulations will
reduce mercury emissions by about 86
percent. It is, therefore, reasonable to
conclude that POM emissions will be
substantially controlled. Thus, while
this proposed rule does not identify
specific numerical emission limits for
POM, emissions of POM are, for the
reasons noted below, nonetheless
‘‘subject to regulation’’ for purposes of
Section 112(c)(6) of the CAA.
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In lieu of establishing numerical
emissions limits for pollutants such as
POM, we regulate surrogate substances.
While we have not identified specific
numerical limits for POM, we believe
CO serves as an effective surrogate for
this HAP, because CO, like POM, is
formed as a byproduct of combustion.
Consequently, we have concluded
that the emissions limits for CO
function as a surrogate for control of
POM, such that it is not necessary to
propose numerical emissions limits for
POM with respect to boilers and process
heaters to satisfy CAA Section 112(c)(6).
To further address POM and mercury
emissions, this proposed rule also
includes an energy assessment
provision that encourages modifications
to the facility to reduce energy demand
that lead to these emissions.
VIII. Statutory and Executive Order
Reviews
A. Executive Order 12866, Regulatory
Planning and Review
Under Executive Order 12866 (58 FR
51735, October 4, 1993), this action is
an ‘‘economically significant regulatory
action’’ because it is likely to have an
annual effect on the economy of $100
million or more or adversely affect in a
material way the economy, a sector of
the economy, productivity, competition,
jobs, the environment, public health or
safety, or State, local, or tribal
governments or communities.
Accordingly, EPA submitted this
action to the Office of Management and
Budget (OMB) for review under EO
12866 and any changes in response to
OMB recommendations have been
documented in the docket for this
action. For more information on the
costs and benefits for this rule, please
refer to Table 14 of this preamble.
B. Executive Order 13132, Federalism
Executive Order 13132 (64 FR 43255,
August 10, 1999), requires EPA to
develop an accountable process to
ensure ‘‘meaningful and timely input by
State and local officials in the
development of regulatory policies that
have federalism implications.’’ ‘‘Policies
that have federalism implications’’ is
defined in the Executive Order to
include regulations that 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.
This proposed rule does not have
federalism implications. It will not have
substantial direct effects on the States,
on the relationship between the national
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government and the States, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in
Executive Order 13132. Thus, Executive
Order 13132 does not apply to this
proposed rule. In the spirit of Executive
Order 13132, and consistent with EPA
policy to promote communications
between EPA and State and local
governments, EPA specifically solicited
comment on this proposed rule from
State and local officials.
C. Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
Executive Order 13175 (65 FR 67249,
November 9, 2000), requires EPA to
develop an accountable process to
ensure ‘‘meaningful and timely input by
tribal officials in the development of
regulatory policies that have tribal
implications.’’ This proposed rule does
not have tribal implications, as specified
in Executive Order 13175 (65 FR 67249,
November 9, 2000). 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 Executive Order 13175.
This proposed rule imposes
requirements on owners and operators
of specified area sources and not tribal
governments. We do not know of any
industrial, commercial, or institutional
boilers owned or operated by Indian
tribal governments. However, if there
are any, the effect of this proposed rule
on communities of tribal governments
would not be unique or
disproportionate to the effect on other
communities. Thus, Executive Order
13175 does not apply to this proposed
rule. EPA specifically solicits additional
comment on this proposed rule from
tribal officials.
D. Executive Order 13045, Protection of
Children From Environmental Health
Risks and Safety Risks
Executive Order 13045 (62 FR 19885,
April 23, 1997) applies to any rule that:
(1) Is determined to be ‘‘economically
significant’’ as defined under Executive
Order 12866, and (2) concerns an
environmental health or safety risk that
EPA has reason to believe may have a
disproportionate effect on children. If
the regulatory action meets both criteria,
the Agency must evaluate the
environmental health or safety effects of
this planned rule on children, and
explain why this planned regulation is
preferable to other potentially effective
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and reasonably feasible alternatives
considered by the Agency.
This proposed rule is not subject to
Executive Order 13045 because the
Agency does not believe the
environmental health risks or safety
risks addressed by this action present a
disproportionate risk to children. The
reason for this determination is that this
proposed rule is based solely on
technology performance.
The public is invited to submit
comments or identify peer-reviewed
studies and data that assess effects of
early life exposure to this proposed rule.
E. Unfunded Mandates Reform Act of
1995
Title II of the Unfunded Mandates
Reform Act of 1995 (UMRA), Public
Law 104–4, establishes requirements for
Federal agencies to assess the effects of
their regulatory actions on State, local,
and tribal governments and the private
sector. Under section 202 of the UMRA,
we generally must prepare a written
statement, including a cost-benefit
analysis, for proposed and final rules
with ‘‘Federal mandates’’ that may result
in expenditures to State, local, and
tribal governments, in the aggregate, or
to the private sector, of $100 million or
more in any 1 year. Before promulgating
a rule for which a written statement is
needed, section 205 of the UMRA
generally requires us to identify and
consider a reasonable number of
regulatory alternatives and adopt the
least costly, most cost-effective or least
burdensome alternative that achieves
the objectives of the rule. The
provisions of section 205 do not apply
when they are inconsistent with
applicable law. Moreover, section 205
allows us to adopt an alternative other
than the least costly, most cost-effective
or least burdensome alternative if the
Administrator publishes with the final
rule an explanation why that alternative
was not adopted. Before we establish
any regulatory requirements that may
significantly or uniquely affect small
governments, including tribal
governments, we must develop a small
government agency plan under section
203 of the UMRA. The plan must
provide for notifying potentially
affected small governments, enabling
officials of affected small governments
to have meaningful and timely input in
the development of regulatory proposals
with significant Federal
intergovernmental mandates, and
informing, educating, and advising
small governments on compliance with
the regulatory requirements.
We have determined that this
proposed rule contains a Federal
mandate that may result in expenditures
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of $100 million or more for State, local,
and Tribal governments, in the
aggregate, or the private sector in any 1
year. Accordingly, we have prepared a
written statement entitled ‘‘Unfunded
Mandates Reform Act Analysis for the
Proposed Industrial Boilers and Process
Heaters NESHAP’’ under section 202 of
the UMRA which is summarized below.
1. Statutory Authority
As discussed in section I of this
preamble, the statutory authority for this
proposed rulemaking is section 112 of
the CAA. Title III of the CAA
Amendments was enacted to reduce
nationwide air toxic emissions. Section
112(b) of the CAA lists the 188
chemicals, compounds, or groups of
chemicals deemed by Congress to be
HAP. These toxic air pollutants are to be
regulated by NESHAP.
Section 112(d) of the CAA directs us
to develop NESHAP which require
existing and new major sources to
control emissions of HAP using MACT
based standards. This NESHAP applies
to all industrial, commercial, and
institutional boilers and process heaters
located at major sources of HAP
emissions.
In compliance with section 205(a) of
the UMRA, we identified and
considered a reasonable number of
regulatory alternatives. Additional
information on the costs and
environmental impacts of these
regulatory alternatives is presented in
the docket.
The regulatory alternative upon
which the proposed rule is based
represents the MACT floor for industrial
boilers and process heaters and, as a
result, it is the least costly and least
burdensome alternative.
2. Social Costs and Benefits
The regulatory impact analysis
prepared for the proposed rule
including the Agency’s assessment of
costs and benefits, is detailed in the
‘‘Regulatory Impact Analysis for the
Proposed Industrial Boilers and Process
Heaters MACT’’ in the docket. Based on
estimated compliance costs associated
with the proposed rule and the
predicted change in prices and
production in the affected industries,
the estimated social costs of the
proposed rule are $2.9 billion (2008
dollars).
It is estimated that 3 years after
implementation of the proposed rule,
HAPs would be reduced by thousands
of tons, including reductions in
hydrochloric acid, hydrogen fluoride,
metallic HAP including mercury, and
several other organic HAP from boilers
and process heaters. Studies have
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determined a relationship between
exposure to these HAP and the onset of
cancer, however, the Agency is unable
to provide a monetized estimate of the
HAP benefits at this time. In addition,
there are significant reductions in PM2.5
and in SO2 that would occur, including
29 thousand tons of PM2.5 and 340
thousand tons of SO2. These reductions
occur within 3 years after the
implementation of the proposed
regulation and are expected to continue
throughout the life of the affected
sources. The major health effect
associated with reducing PM2.5 and
PM2.5 precursors (such as SO2) is a
reduction in premature mortality. Other
health effects associated with PM2.5
emission reductions include avoiding
cases of chronic bronchitis, heart
attacks, asthma attacks, and work-lost
days (i.e., days when employees are
unable to work). While we are unable to
monetize the benefits associated with
the HAP emissions reductions, we are
able to monetize the benefits associated
with the PM2.5 and SO2 emissions
reductions. For SO2 and PM2.5, we
estimated the benefits associated with
health effects of PM but were unable to
quantify all categories of benefits
(particularly those associated with
ecosystem and visibility effects). Our
estimates of the monetized benefits in
2013 associated with the
implementation of the proposed
alternative is a range from $17 billion
(2008 dollars) to $41 billion (2008
dollars) when using a 3 percent
discount rate (or from $15 billion (2008
dollars) to $37 billion (2008 dollars)
when using a 7 percent discount rate).
This estimate, at a 3 percent discount
rate, is about $14 billion (2008 dollars)
to $38 billion (2008 dollars) higher than
the estimated social costs shown earlier
in this section. The general approach
used to value benefits is discussed in
more detail earlier in this preamble. For
more detailed information on the
benefits estimated for the proposed
rulemaking, refer to the RIA in the
docket.
3. Future and Disproportionate Costs
The Unfunded Mandates Act requires
that we estimate, where accurate
estimation is reasonably feasible, future
compliance costs imposed by the
proposed rule and any disproportionate
budgetary effects. Our estimates of the
future compliance costs of the proposed
rule are discussed previously in this
preamble.
We do not believe that there will be
any disproportionate budgetary effects
of the proposed rule on any particular
areas of the country, State or local
governments, types of communities
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(e.g., urban, rural), or particular industry
segments. See the results of the
‘‘Economic Impact Analysis of the
Proposed Industrial Boilers and Process
Heaters NESHAP,’’ the results of which
are discussed previously in this
preamble.
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4. Effects on the National Economy
The Unfunded Mandates Act requires
that we estimate the effect of the
proposed rule on the national economy.
To the extent feasible, we must estimate
the effect on productivity, economic
growth, full employment, creation of
productive jobs, and international
competitiveness of the U.S. goods and
services, if we determine that accurate
estimates are reasonably feasible and
that such effect is relevant and material.
The nationwide economic impact of
the proposed rule is presented in the
‘‘Economic Impact Analysis for the
Industrial Boilers and Process Heaters
MACT’’ in the docket. This analysis
provides estimates of the effect of the
proposed rule on some of the categories
mentioned above. The results of the
economic impact analysis are
summarized previously in this
preamble. The results show that there
will be a small impact on prices and
output, and little impact on
communities that may be affected by the
proposed rule. In addition, there should
be little impact on energy markets (in
this case, coal, natural gas, petroleum
products, and electricity). Hence, the
potential impacts on the categories
mentioned above should be small.
5. Consultation With Government
Officials
The Unfunded Mandates Act requires
that we describe the extent of the
Agency’s prior consultation with
affected State, local, and tribal officials,
summarize the officials’ comments or
concerns, and summarize our response
to those comments or concerns. In
addition, section 203 of the UMRA
requires that we develop a plan for
informing and advising small
governments that may be significantly
or uniquely impacted by a proposal.
Although the proposed rule does not
affect any State, local, or Tribal
governments, we have consulted with
State and local air pollution control
officials. We also have held meetings on
the proposed rule with many of the
stakeholders from numerous individual
companies, environmental groups,
consultants and vendors, labor unions,
and other interested parties. We have
added materials to the Air Docket to
document these meetings.
In addition, we have determined that
the proposed rule contains no regulatory
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requirements that might significantly or
uniquely affect small governments.
While some small governments may
have some sources affected by the
proposed rule, the impacts are not
expected to be significant. Therefore,
today’s proposed rule is not subject to
the requirements of section 203 of the
UMRA.
F. Regulatory Flexibility Act (RFA), as
Amended by the Small Business
Regulatory Enforcement Fairness Act of
1996 (SBREFA), 5 U.S.C. 601 et seq.
The RFA generally requires an agency
to prepare a regulatory flexibility
analysis of any rule subject to notice
and comment rulemaking requirements
under the Administrative Procedure Act
or any other statute unless the agency
certifies that the rule will not have a
significant economic impact on a
substantial number of small entities.
Small entities include small businesses,
small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts
of today’s proposed rule on small
entities, small entity is defined as: (1) A
small business according to Small
Business Administration (SBA) size
standards by the North American
Industry Classification System category
of the owning entity. The range of small
business size standards for the 40
affected industries ranges from 500 to
1,000 employees, except for petroleum
refining and electric utilities. In these
latter two industries, the size standard
is 1,500 employees and a mass
throughput of 75,000 barrels/day or less,
and 4 million kilowatt-hours of
production or less, respectively; (2) a
small governmental jurisdiction that is a
government of a city, county, town,
school district or special district with a
population of less than 50,000; and (3)
a small organization that is any not-forprofit enterprise which is independently
owned and operated and is not
dominant in its field.
Because an initial screening analysis
for impact on small entities indicated a
likely significant impact for substantial
numbers, EPA convened a SBAR Panel
to obtain advice and recommendation of
representatives of the small entities that
potentially would be subject to the
requirements of this rule.
(a) Panel Process and Panel Outreach
As required by section 609(b) of the
RFA, as amended by SBREFA, EPA also
has conducted outreach to small entities
and on January 22, 2009 EPA’s Small
Business Advocacy Chairperson
convened a Panel under section 609(b)
of the RFA. In addition to the Chair, the
Panel consisted of the Director of the
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Sector Policies and Programs Division
within EPA’s Office of Air and
Radiation, the Chief Counsel for
Advocacy of the Small Business
Administration, and the Administrator
of the Office of Information and
Regulatory Affairs within the Office of
Management and Budget.
As part of the SBAR Panel process we
conducted outreach with
representatives from 14 various small
entities that would be affected by this
rule. The small entity representatives
(SERs) included associations
representing schools, churches, hotels/
motels, wood product facilities and
manufacturers of home furnishings. We
met with these SERs to discuss the
potential rulemaking approaches and
potential options to decrease the impact
of the rulemaking on their industries/
sectors. We distributed outreach
materials to the SERs; these materials
included background on the
rulemaking, possible regulatory
approaches, preliminary cost and
economic impacts, and possible
rulemaking alternatives. The Panel met
with SERs from the industries that will
be impacted directly by this rule on
February 10, 2009 to discuss the
outreach materials and receive feedback
on the approaches and alternatives
detailed in the outreach packet. (EPA
also met with SERs on November 13,
2008 for an initial outreach meeting.)
The Panel received written comments
from the SERs following the meeting in
response to discussions at the meeting
and the questions posed to the SERs by
the Agency. The SERs were specifically
asked to provide comment on regulatory
alternatives that could help to minimize
the rule’s impact on small businesses.
(1) Panel Recommendations for Small
Business Flexibilities
The Panel recommended that EPA
consider and seek comment on a wide
range of regulatory alternatives to
mitigate the impacts of the rulemaking
on small businesses, including those
flexibility options described below. The
following section summarizes the SBAR
Panel recommendations. EPA has
proposed provisions consistent with
four of the Panel’s recommendations.
Consistent with the RFA/SBREFA
requirements, the Panel evaluated the
assembled materials and small-entity
comments on issues related to elements
of the IRFA. A copy of the Final Panel
Report (including all comments
received from SERs in response to the
Panel’s outreach meeting as well as
summaries of both outreach meetings
that were held with the SERs is
included in the docket for this proposed
rule. A summary of the Panel
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recommendations is detailed below. As
noted above, this proposal includes
proposed provisions for all but one of
the Panel recommendations.
(a) Work Practice Standards
The panel recommended that EPA
consider requiring annual tune-ups,
including standardized criteria
outlining proper tune-up methods
targeted at smaller boiler operators. The
panel further recommended that EPA
take comment on the efficacy of energy
assessments/audits at improving
combustion efficiency and the cost of
performing the assessments, especially
to smaller boiler operators.
A work practice standard, instead of
MACT emission limits, may be
proposed if it can be justified under
section 112(h) of the CAA, that is, it is
impracticable to enforce the emission
standards due to technical or economic
limitations. Work practice standards
could reduce fuel use and improve
combustion efficiency which would
result in reduced emissions.
In general, SERs commented that a
regulatory approach to improve
combustion efficiency, such as work
practice standards, would have positive
impacts with respect to the environment
and energy use and save on compliance
costs. The SERs were concerned with
work practice standards that would
require energy assessments and
implementation of assessment findings.
The basis of these concerns rested upon
the uncertainty that there is no
guarantee that there are available funds
to implement a particular assessment’s
findings.
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(b) Subcategorization
The Panel recommended that EPA
allow subcategorizations suggested by
the SERs, unless EPA finds that a
subcategorization is inconsistent with
the Clean Air Act.
SERs commented that
subcategorization is a key concept that
could ensure that like boilers are
compared with similar boilers so that
MACT floors are more reasonable and
could be achieved by all units within a
subcategory using appropriate emission
reduction strategies. SERs commented
that EPA should subcategorize based on
fuel type, boiler type, duty cycle, and
location.
(c) Health Based Compliance
Alternatives (HBCA)
The Panel recommended that EPA
adopt the HBCA as a regulatory
flexibility option for the Boiler MACT
rulemaking. The panel recognized,
however, that EPA has concerns about
its legal authority to provide an HBCA
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under the Clean Air Act, and EPA may
ultimately determine that this flexibility
is inconsistent with the Clean Air Act.
SERs commented that adopting an
HBCA would perhaps be the most
important step EPA could take to
mitigate the serious financial harm the
Boiler MACT would otherwise inflict on
small entities using solid fuels
nationwide and, therefore, HBCA
should be a critical component of any
future rule to lessen impact on small
entities.
(d) Emissions Averaging
The Panel recommended that EPA
consider a provision for emission
averaging and long averaging times for
the proposed emission limits.
SERs commented that a measure EPA
should consider to lessen the regulatory
burden of complying with Boiler MACT
is to allow emissions averaging at
sources with multiple regulated units.
SERs commented that another approach
that can aide small entity compliance is
to set longer averaging times (i.e., 30days or more) rather than looking at a
mere 3-run (hour) average for
performance. Given the inherent
variability in boiler performance, an
annual or quarterly averaging period for
all HAP would prevent a single spike in
emissions from throwing a unit into
non-compliance.
(e) Compliance Costs
The Panel recommended that EPA
carefully weigh the potential burden of
compliance requirements and consider
for small entities options such as,
emission averaging within facility,
reduced monitoring/testing
requirements, or allowing more time for
compliance.
SERs noted that recordkeeping
activities, as written in the vacated
boiler MACT, would be especially
challenging for small entities that do not
have a dedicated environmental affairs
department.
G. Paperwork Reduction Act
The information collection
requirements in the proposed rule will
be submitted for approval to the Office
of Management and Budget under the
Paperwork Reduction Act, 44 U.S.C.
3501 et seq. An Information Collection
Request (ICR) document has been
prepared by EPA (ICR No. 2028.05).
The information requirements are
based on notification, recordkeeping,
and reporting requirements in the
NESHAP General Provisions (40 CFR
part 63, subpart A), which are
mandatory for all operators subject to
national emission standards. These
recordkeeping and reporting
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requirements are specifically authorized
by section 114 of the CAA (42 U.S.C.
7414). All information submitted to EPA
pursuant to the recordkeeping and
reporting requirements for which a
claim of confidentiality is made is
safeguarded according to Agency
policies set forth in 40 CFR part 2,
subpart B.
The proposed rule would require
maintenance inspections of the control
devices but would not require any
notifications or reports beyond those
required by the General Provisions. The
recordkeeping requirements require
only the specific information needed to
determine compliance.
The annual monitoring, reporting, and
recordkeeping burden for this collection
(averaged over the first 3 years after the
effective date of the standards) is
estimated to be $87.6 million. This
includes 208,832 labor hours per year at
a total labor cost of $19.8 million per
year, and total non-labor capital costs of
$67.8 million per year. This estimate
includes initial and annual performance
test, conducting and documenting an
energy assessment, conducting and
documenting a tune-up, semiannual
excess emission reports, maintenance
inspections, developing a monitoring
plan, notifications, and recordkeeping.
Monitoring, testing, tune-up and energy
assessment costs and cost were also
included in the cost estimates presented
in the control costs impacts estimates in
section IV.D of this preamble. The total
burden for the Federal government
(averaged over the first 3 years after the
effective date of the standard) is
estimated to be 93,648 hours per year at
a total labor cost of $4.9 million per
year.
Burden means the total time, effort, or
financial resources expended by persons
to generate, maintain, retain, or disclose
or provide information to or for a
Federal agency. This includes the time
needed to review instructions; develop,
acquire, install, and utilize technology
and systems for the purposes of
collecting, validating, and verifying
information, processing and
maintaining information, and disclosing
and providing information; adjust the
existing ways to comply with any
previously applicable instructions and
requirements; train personnel to be able
to respond to a collection of
information; search data sources;
complete and review the collection of
information; and transmit or otherwise
disclose the information.
An Agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
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numbers for our regulations are listed in
40 CFR part 9 and 48 CFR chapter 15.
To comment on EPA’s need for this
information, the accuracy of the
provided burden estimates, and any
suggested methods for minimizing
respondent burden, including the use of
automated collection techniques, EPA
has established a public docket for this
action, which includes this ICR, under
Docket ID number EPA–HQ–OAR–
2002–0058. Submit any comments
related to the ICR to EPA and OMB. See
ADDRESSES section at the beginning of
this preamble for where to submit
comments to EPA. Send comments to
OMB at the Office of Information and
Regulatory Affairs, Office of
Management and Budget, 725 17th
Street, NW., Washington, DC 20503,
Attention: Desk Office for EPA. Since
OMB is required to make a decision
concerning the ICR between 30 and 60
days after June 4, 2010, a comment to
OMB is best assured of having its full
effect if OMB receives it by July 6, 2010.
The final rule will respond to any OMB
or public comments on the information
collection requirements contained in
this proposal.
H. National Technology Transfer and
Advancement Act
Section 12(d) of the National
Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104–113;
15 U.S.C. 272 note) directs the EPA to
use voluntary consensus standards in
their regulatory and procurement
activities unless to do so would be
inconsistent with applicable law or
otherwise impractical. Voluntary
consensus standards are technical
standards (e.g., materials specifications,
test methods, sampling procedures,
business practices) developed or
adopted by one or more voluntary
consensus bodies. The NTTAA directs
EPA to provide Congress, through
annual reports to the Office of
Management and Budget, with
explanations when an agency does not
use available and applicable voluntary
consensus standards.
This rulemaking involves technical
standards. The EPA cites the following
standards in the proposed rule: EPA
Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D,
17, 19, 26, 26A, 29 of 40 CFR part 60.
Consistent with the NTTAA, EPA
conducted searches to identify
voluntary consensus standards in
addition to these EPA methods. No
applicable voluntary consensus
standards were identified for EPA
Methods 2F, 2G, 5D, and 19. The search
and review results have been
documented and are placed in the
docket for the proposed rule.
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The three voluntary consensus
standards described below were
identified as acceptable alternatives to
EPA test methods for the purposes of
the proposed rule.
The voluntary consensus standard
ASME PTC 19–10–1981–Part 10, ‘‘Flue
and Exhaust Gas Analyses,’’ is cited in
the proposed rule for its manual method
for measuring the oxygen, carbon
dioxide, and carbon monoxide content
of exhaust gas. This part of ASME PTC
19–10–1981—Part 10 is an acceptable
alternative to Method 3B.
The voluntary consensus standard
ASTM D6522–00, ‘‘Standard Test
Method for the Determination of
Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions
from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers
and Process Heaters Using Portable
Analyzers’’ is an acceptable alternative
to EPA Method 3A for identifying
carbon monoxide and oxygen
concentrations for the proposed rule
when the fuel is natural gas.
The voluntary consensus standard
ASTM Z65907, ‘‘Standard Method for
Both Speciated and Elemental Mercury
Determination,’’ is an acceptable
alternative to EPA Method 29 (portion
for mercury only) for the purpose of the
proposed rule. This standard can be
used in the proposed rule to determine
the mercury concentration in stack gases
for boilers with rated heat input
capacities of greater than 250 MMBtu
per hour.
In addition to the voluntary
consensus standards EPA uses in the
proposed rule, the search for emissions
measurement procedures identified 15
other voluntary consensus standards.
The EPA determined that 13 of these 15
standards identified for measuring
emissions of the HAP or surrogates
subject to emission standards in the
proposed rule were impractical
alternatives to EPA test methods for the
purposes of the rule. Therefore, EPA
does not intend to adopt these standards
for this purpose. The reasons for this
determination for the 13 methods are
discussed below.
The voluntary consensus standard
ASTM D3154–00, ‘‘Standard Method for
Average Velocity in a Duct (Pitot Tube
Method),’’ is impractical as an
alternative to EPA Methods 1, 2, 3B, and
4 for the purposes of the proposed
rulemaking since the standard appears
to lack in quality control and quality
assurance requirements. Specifically,
ASTM D3154–00 does not include the
following: (1) Proof that openings of
standard pitot tube have not plugged
during the test; (2) if differential
pressure gauges other than inclined
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manometers (e.g., magnehelic gauges)
are used, their calibration must be
checked after each test series; and
(3) the frequency and validity range for
calibration of the temperature sensors.
The voluntary consensus standard
ASTM D3464–96 (2001), ‘‘Standard Test
Method Average Velocity in a Duct
Using a Thermal Anemometer,’’ is
impractical as an alternative to EPA
Method 2 for the purposes of the
proposed rule primarily because
applicability specifications are not
clearly defined, e.g., range of gas
composition, temperature limits. Also,
the lack of supporting quality assurance
data for the calibration procedures and
specifications, and certain variability
issues that are not adequately addressed
by the standard limit EPA’s ability to
make a definitive comparison of the
method in these areas.
The voluntary consensus standard
ISO 10780:1994, ‘‘Stationary Source
Emissions–Measurement of Velocity
and Volume Flowrate of Gas Streams in
Ducts,’’ is impractical as an alternative
to EPA Method 2 in the proposed rule.
The standard recommends the use of an
L-shaped pitot, which historically has
not been recommended by EPA. The
EPA specifies the S-type design which
has large openings that are less likely to
plug up with dust.
The voluntary consensus standard,
CAN/CSA Z223.2–M86(1999), ‘‘Method
for the Continuous Measurement of
Oxygen, Carbon Dioxide, Carbon
Monoxide, Sulphur Dioxide, and Oxides
of Nitrogen in Enclosed Combustion
Flue Gas Streams,’’ is unacceptable as a
substitute for EPA Method 3A since it
does not include quantitative
specifications for measurement system
performance, most notably the
calibration procedures and instrument
performance characteristics. The
instrument performance characteristics
that are provided are nonmandatory and
also do not provide the same level of
quality assurance as the EPA methods.
For example, the zero and span/
calibration drift is only checked weekly,
whereas the EPA methods requires drift
checks after each run.
Two very similar voluntary consensus
standards, ASTM D5835–95 (2001),
‘‘Standard Practice for Sampling
Stationary Source Emissions for
Automated Determination of Gas
Concentration,’’ and ISO 10396:1993,
‘‘Stationary Source Emissions: Sampling
for the Automated Determination of Gas
Concentrations,’’ are impractical
alternatives to EPA Method 3A for the
purposes of the proposed rule because
they lack in detail and quality
assurance/quality control requirements.
Specifically, these two standards do not
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include the following: (1) Sensitivity of
the method; (2) acceptable levels of
analyzer calibration error; (3) acceptable
levels of sampling system bias; (4) zero
drift and calibration drift limits, time
span, and required testing frequency;
(5) a method to test the interference
response of the analyzer; (6) procedures
to determine the minimum sampling
time per run and minimum
measurement time; and
(7) specifications for data recorders, in
terms of resolution (all types) and
recording intervals (digital and analog
recorders, only).
The voluntary consensus standard
ISO 12039:2001, ‘‘Stationary Source
Emissions—Determination of Carbon
Monoxide, Carbon Dioxide, and
Oxygen—Automated Methods,’’ is not
acceptable as an alternative to EPA
Method 3A. This ISO standard is similar
to EPA Method 3A, but is missing some
key features. In terms of sampling, the
hardware required by ISO 12039:2001
does not include a 3-way calibration
valve assembly or equivalent to block
the sample gas flow while calibration
gases are introduced. In its calibration
procedures, ISO 12039:2001 only
specifies a two-point calibration while
EPA Method 3A specifies a three-point
calibration. Also, ISO 12039:2001 does
not specify performance criteria for
calibration error, calibration drift, or
sampling system bias tests as in the EPA
method, although checks of these
quality control features are required by
the ISO standard.
The voluntary consensus standard
ASME PTC–38–80 R85 (1985),
‘‘Determination of the Concentration of
Particulate Matter in Gas Streams,’’ is
not acceptable as an alternative for EPA
Method 5 because ASTM PTC–38–80 is
not specific about equipment
requirements, and instead presents the
options available and the pro’s and
con’s of each option. The key specific
differences between ASME PTC–38–80
and the EPA methods are that the ASME
standard: (1) Allows in-stack filter
placement as compared to the out-ofstack filter placement in EPA Methods
5 and 17; (2) allows many different
types of nozzles, pitots, and filtering
equipment; (3) does not specify a filter
weighing protocol or a minimum
allowable filter weight fluctuation as in
the EPA methods; and (4) allows filter
paper to be only 99 percent efficient, as
compared to the 99.95 percent
efficiency required by the EPA methods.
The voluntary consensus standard
ASTM D3685/D3685M–98, ‘‘Test
Methods for Sampling and
Determination of Particulate Matter in
Stack Gases,’’ is similar to EPA Methods
5 and 17, but is lacking in the following
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areas that are needed to produce quality,
representative particulate data:
(1) Requirement that the filter holder
temperature should be between 120°C
and 134°C, and not just ‘‘above the acid
dew-point;’’ (2) detailed specifications
for measuring and monitoring the filter
holder temperature during sampling;
(3) procedures similar to EPA Methods
1, 2, 3, and 4, that are required by EPA
Method 5; (4) technical guidance for
performing the Method 5 sampling
procedures, e.g., maintaining and
monitoring sampling train operating
temperatures, specific leak check
guidelines and procedures, and use of
reagent blanks for determining and
subtracting background contamination;
and (5) detailed equipment and/or
operational requirements, e.g.,
component exchange leak checks, use of
glass cyclones for heavy particulate
loading and/or water droplets, operating
under a negative stack pressure,
exchanging particulate loaded filters,
sampling preparation and
implementation guidance, sample
recovery guidance, data reduction
guidance, and particulate sample
calculations input.
The voluntary consensus standard
ISO 9096:1992, ‘‘Determination of
Concentration and Mass Flow Rate of
Particulate Matter in Gas Carrying
Ducts—Manual Gravimetric Method,’’ is
not acceptable as an alternative for EPA
Method 5. Although sections of ISO
9096 incorporate EPA Methods 1, 2, and
5 to some degree, this ISO standard is
not equivalent to EPA Method 5 for
collection of particulate matter. The
standard ISO 9096 does not provide
applicable technical guidance for
performing many of the integral
procedures specified in Methods 1, 2,
and 5. Major performance and
operational details are lacking or
nonexistent, and detailed quality
assurance/quality control guidance for
the sampling operations required to
produce quality, representative
particulate data (e.g., guidance for
maintaining and monitoring train
operating temperatures, specific leak
check guidelines and procedures, and
sample preparation and recovery
procedures) are not provided by the
standard, as in EPA Method 5. Also,
details of equipment and/or operational
requirements, such as those specified in
EPA Method 5, are not included in the
ISO standard, e.g., stack gas moisture
measurements, data reduction guidance,
and particulate sample calculations.
The voluntary consensus standard
CAN/CSA Z223.1–M1977, ‘‘Method for
the Determination of Particulate Mass
Flows in Enclosed Gas Streams,’’ is not
acceptable as an alternative for EPA
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32047
Method 5. Detailed technical procedures
and quality control measures that are
required in EPA Methods 1, 2, 3, and 4
are not included in CAN/CSA Z223.1.
Second, CAN/CSA Z223.1 does not
include the EPA Method 5 filter
weighing requirement to repeat
weighing every 6 hours until a constant
weight is achieved. Third, EPA Method
5 requires the filter weight to be
reported to the nearest 0.1 mg, while
CAN/CSA Z223.1 requires only to the
nearest 0.5 mg. Also, CAN/CSA Z223.1
allows the use of a standard pitot for
velocity measurement when plugging of
the tube opening is not expected to be
a problem. Whereas, EPA Method 5
requires an S-shaped pitot.
The voluntary consensus standard EN
1911–1,2,3 (1998), ‘‘Stationary Source
Emissions-Manual Method of
Determination of HCl—Part 1: Sampling
of Gases Ratified European Text—Part 2:
Gaseous Compounds Absorption
Ratified European Text—Part 3:
Adsorption Solutions Analysis and
Calculation Ratified European Text,’’ is
impractical as an alternative to EPA
Methods 26 and 26A. Part 3 of this
standard cannot be considered
equivalent to EPA Method 26 or 26A
because the sample absorbing solution
(water) would be expected to capture
both HCl and chlorine gas, if present,
without the ability to distinguish
between the two. The EPA Methods 26
and 26A use an acidified absorbing
solution to first separate HCl and
chlorine gas so that they can be
selectively absorbed, analyzed, and
reported separately. In addition, in EN
1911 the absorption efficiency for
chlorine gas would be expected to vary
as the pH of the water changed during
sampling.
The voluntary consensus standard EN
13211 (1998), is not acceptable as an
alternative to the mercury portion of
EPA Method 29 primarily because it is
not validated for use with impingers, as
in the EPA method, although the
method describes procedures for the use
of impingers. This European standard is
validated for the use of fritted bubblers
only and requires the use of a side
(split) stream arrangement for isokinetic
sampling because of the low sampling
rate of the bubblers (up to 3 liters per
minute, maximum). Also, only two
bubblers (or impingers) are required by
EN 13211, whereas EPA Method 29
require the use of six impingers. In
addition, EN 13211 does not include
many of the quality control procedures
of EPA Method 29, especially for the use
and calibration of temperature sensors
and controllers, sampling train assembly
and disassembly, and filter weighing.
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Two of the 15 voluntary consensus
standards identified in this search were
not available at the time the review was
conducted for the purposes of the
proposed rule because they are under
development by a voluntary consensus
body: ASME/BSR MFC 13M, ‘‘Flow
Measurement by Velocity Traverse,’’ for
EPA Method 2 (and possibly 1); and
ASME/BSR MFC 12M, ‘‘Flow in Closed
Conduits Using Multiport Averaging
Pitot Primary Flowmeters,’’ for EPA
Method 2.
Section 63.7520 and Tables 4A
through 4D to subpart DDDDD, 40 CFR
part 63, list the EPA testing methods
included in the proposed rule. Under
§ 63.7(f) and § 63.8(f) of subpart A of the
General Provisions, a source may apply
to EPA for permission to use alternative
test methods or alternative monitoring
requirements in place of any of the EPA
testing methods, performance
specifications, or procedures.
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I. Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
Executive Order 13211, (66 FR 28355,
May 22, 2001), provides that agencies
shall prepare and submit to the
Administrator of the Office of
Information and Regulatory Affairs,
Office of Management and Budget, a
Statement of Energy Effects for certain
actions identified as significant energy
actions. Section 4(b) of Executive Order
13211 defines ‘‘significant energy
actions’’ as ‘‘any action by an agency
(normally published in the Federal
Register) that promulgates or is
expected to lead to the promulgation of
a final rule or regulation, including
notices of inquiry, advance notices of
proposed rulemaking, and notices of
proposed rulemaking: (1)(i) That is a
significant regulatory action under
Executive Order 12866 or any successor
order, and (ii) is likely to have a
significant adverse effect on the supply,
distribution, or use of energy; or (2) that
is designated by the Administrator of
the Office of Information and Regulatory
Affairs as a significant energy action.’’
The proposed rule is not a ‘‘significant
regulatory action’’ because it is not
likely to have a significant adverse effect
on the supply, distribution, or use of
energy. The basis for the determination
is as follows.
We estimate a 0.14% price increase
for the energy sector and a 0.07%
percentage change in production. We
estimate a 0.18% increase in energy
imports. For more information on the
estimated energy effects, please refer to
the economic impact analysis for the
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proposed rule. The analysis is available
in the public docket.
Therefore, we conclude that the
proposed rule when implemented is not
likely to have a significant adverse effect
on the supply, distribution, or use of
energy.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Executive Order 12898 (59 FR 7629,
February 16, 1994) establishes Federal
executive policy on environmental
justice (EJ). Its main provision directs
Federal agencies, to the greatest extent
practicable and permitted by law, to
make 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, low-income, and Tribal
populations in the United States.
This proposed action establishes
national emission standards for new and
existing industrial, commercial,
institutional boilers and process heaters
that combust non-waste materials (i.e.
natural gas, process gas, fuel oil,
biomass, and coal) and that are located
at a major source. The EPA estimates
that there are approximately 13,555
units located at 1,608 facilities covered
by this rule.
The proposed rule will reduce
emissions of all the listed HAP that
come from boilers and process heaters.
This includes metals (mercury, arsenic,
beryllium, cadmium, chromium, lead,
manganese, nickel, and selenium),
organics (POM, acetaldehyde, acrolein,
benzene, dioxins, ethylene dichloride,
formaldehyde, and PCB), hydrochloric
acid, and hydrofluoric acid. Adverse
health effects from these pollutants
include cancer, irritation of the lungs,
skin, and mucus membranes; effects on
the central nervous system, damage to
the kidneys, and other acute health
disorders. The rule will also result in
substantial reductions of criteria
pollutants such as carbon monoxide
(CO), nitrogen oxides (NOX), particulate
matter (PM), and sulfur dioxide (SO2).
Sulfur dioxide and NO2 are precursors
for the formation of PM2.5 and ozone.
Reducing these emissions will reduce
ozone and PM2.5 formation and
associated health effects, such as adult
premature mortality, chronic and acute
bronchitis, asthma, and other
respiratory and cardiovascular diseases.
(Please refer to the RIA contained in the
docket for this rulemaking.)
Pursuant to E.O. 12898 EPA has
undertaken to determine the aggregate
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demographic makeup of the
communities near affected sources. This
analysis used ‘‘proximity-to-a-source’’ to
identify the populations considered to
be living near affected sources, such that
they have notable exposures to current
emissions from these sources. In this
approach EPA reviewed the
distributions of different sociodemographic groups in the locations of
the expected emission reductions from
this rule. The review identified those
census blocks within a circular distance
of 3 miles of affected sources and
determined the demographic and socioeconomic composition (e.g. race,
income, education, etc) of these census
blocks. The radius of 3 miles (or
approximately 5 kilometers) has been
used in other demographic analyses
focused on areas around potential
sources.27 28 29 30 In addition, air
modeling experience has shown that
beyond 3 miles the influence of an
individual source of emissions can
generally be considered to be small,
both in absolute terms and relative to
the influence of other sources (assuming
there are other sources in the area, as is
typical in urban areas).
EPA’s demographic analysis showed
that major source boilers are located in
areas where minorities’ share of the
population living within a three-mile
buffer is higher than the national
average. For these same areas, the
percent of the population below the
poverty line is also higher than the
national average.31 Based on the fact
that the rule does not allow emission
increases, the EPA has determined that
the proposed rule will not have
disproportionately high and adverse
human health or environmental effects
on minority, low-income, or Tribal
populations. However, to the extent that
any minority, low income, or Tribal
subpopulation is disproportionately
impacted by the current emissions as a
result of the proximity of their homes to
these sources, that subpopulation also
27 U.S. GAO (Government Accountability Office).
Demographics of People Living Near Waste
Facilities. Washington DC: Government Printing
Office; 1995.
28 Mohai P, Saha R. ‘‘Reassessing Racial and
Socio-economic Disparities in Environmental
Justice Research’’. Demography. 2006;43(2): 383–
399.
29 Mennis J. ‘‘Using Geographic Information
Systems to Create and Analyze Statistical Surfaces
of Populations and Risk for Environmental Justice
Analysis’’. Social Science Quarterly,
2002;83(1):281–297.
30 Bullard RD, Mohai P, Wright B, Saha R, et al.
Toxic Waste and Race at Twenty 1987–2007. United
Church of Christ. March, 2007.
31 The results of the demographic analysis are
presented in ‘‘Review of Environmental Justice
Impacts’’, April 2010, a copy of which is available
in the docket.
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stands to see increased environmental
and health benefit from the emissions
reductions called for by this rule.
EPA defines ‘‘Environmental Justice’’
to include meaningful involvement of
all people regardless of race, color,
national origin, or income with respect
to the development, implementation,
and enforcement of environmental laws,
regulations, and polices. To promote
meaningful involvement, EPA has
developed a communication and
outreach strategy to ensure that
interested communities have access to
this proposed rule, are aware of its
content, and have an opportunity to
comment during the comment period.
During the comment period, EPA will
publicize the rulemaking via EJ
newsletters, Tribal newsletters, EJ
listservs, and the Internet, including the
Office of Policy, Economics, and
Innovation’s (OPEI) Rulemaking
Gateway Web site (https://
yosemite.epa.gov/opei/RuleGate.nsf/).
EPA will also provide general
rulemaking fact sheets (e.g., why is this
important for my community) for EJ
community groups and conduct
conference calls with interested
communities. In addition, state and
federal permitting requirements will
provide state and local governments and
members of affected communities the
opportunity to provide comments on the
permit conditions associated with
permitting the sources affected by this
rulemaking.
What This Subpart Covers
63.7480 What is the purpose of this
subpart?
63.7485 Am I subject to this subpart?
63.7490 What is the affected source of this
subpart?
63.7491 Are any boilers or process heaters
not subject to this subpart?
63.7495 When do I have to comply with
this subpart?
List of Subjects in 40 CFR Part 63
Environmental protection,
Administrative practice and procedure,
Air pollution control, Hazardous
substances, Intergovernmental relations,
Reporting and recordkeeping
requirements.
Continuous Compliance Requirements
63.7535 How do I monitor and collect data
to demonstrate continuous compliance?
63.7540 How do I demonstrate continuous
compliance with the emission
limitations and work practice standards?
63.7541 How do I demonstrate continuous
compliance under the emission
averaging provision?
Dated: April 29, 2010.
Lisa P. Jackson,
Administrator.
For the reasons stated in the
preamble, title 40, chapter I, part 63 of
the Code of the Federal Regulations is
proposed to be amended as follows:
PART 63—[AMENDED]
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Authority: 42 U.S.C. 7401, et seq.
2. Part 63 is amended by revising
subpart DDDDD to read as follows:
Subpart DDDDD—National Emission
Standards for Hazardous Air Pollutants
for Major Sources: Industrial,
Commercial, and Institutional Boilers
and Process Heaters
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General Compliance Requirements
63.7505 What are my general requirements
for complying with this subpart?
Testing, Fuel Analyses, and Initial
Compliance Requirements
63.7510 What are my initial compliance
requirements and by what date must I
conduct them?
63.7515 When must I conduct subsequent
performance tests or fuel analyses?
63.7520 What stack tests and procedures
must I use for the performance tests?
63.7521 What fuel analyses and procedures
must I use for the performance tests?
63.7522 Can I use emission averaging to
comply with this subpart?
63.7525 What are my monitoring,
installation, operation, and maintenance
requirements?
63.7530 How do I demonstrate initial
compliance with the emission
limitations and work practice standards?
Notifications, Reports, and Records
63.7545 What notifications must I submit
and when?
63.7550 What reports must I submit and
when?
63.7555 What records must I keep?
63.7560 In what form and how long must I
keep my records?
Other Requirements and Information
63.7565 What parts of the General
Provisions apply to me?
63.7570 Who implements and enforces this
subpart?
63.7575 What definitions apply to this
subpart?
1. The authority citation for part 63
continues to read as follows:
Sec.
Emission Limitations and Work Practice
Standards
63.7499 What are the subcategories of
boilers and process heaters?
63.7500 What emission limitations, work
practice standards, and operating limits
must I meet?
Tables to Subpart DDDDD of Part 63
Table 1 to Subpart DDDDD of Part 63—
Emission Limits for New or
Reconstructed Boilers and Process
Heaters
Table 2 to Subpart DDDDD of Part 63—
Emission Limits for Existing Boilers and
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Process Heaters (Units with heat input
capacity of 10 million Btu per hour or
greater)
Table 3 to Subpart DDDDD of Part 63—Work
Practice Standards
Table 4 to Subpart DDDDD of Part 63—
Operating Limits for Boilers and Process
Heaters
Table 5 to Subpart DDDDD of Part 63—
Performance Testing Requirements
Table 6 to Subpart DDDDD of Part 63—Fuel
Analysis Requirements
Table 7 to Subpart DDDDD of Part 63—
Establishing Operating Limits
Table 8 to Subpart DDDDD of Part 63—
Demonstrating Continuous Compliance
Table 9 to Subpart DDDDD of Part 63—
Reporting Requirements
Table 10 to Subpart DDDDD of Part 63—
Applicability of General Provisions to
Subpart DDDDD
What This Subpart Covers
§ 63.7480
subpart?
What is the purpose of this
This subpart establishes national
emission limitations and work practice
standards for hazardous air pollutants
(HAP) emitted from industrial,
commercial, and institutional boilers
and process heaters located at major
sources of HAP. This subpart also
establishes requirements to demonstrate
initial and continuous compliance with
the emission limitations and work
practice standards.
§ 63.7485
Am I subject to this subpart?
You are subject to this subpart if you
own or operate an industrial,
commercial, or institutional boiler or
process heater as defined in § 63.7575
that is located at, or is part of, a major
source of HAP as defined in § 63.2 or
§ 63.761 (40 CFR part 63, subpart HH,
National Emission Standards for
Hazardous Air Pollutants from Oil and
Natural Gas Production Facilities),
except as specified in § 63.7491.
§ 63.7490 What is the affected source of
this subpart?
(a) This subpart applies to new,
reconstructed, and existing affected
sources as described in paragraphs (a)(1)
and (2) of this section.
(1) The affected source of this subpart
is the collection of all existing
industrial, commercial, and institutional
boilers and process heaters within a
subcategory located at a major source as
defined in § 63.7575.
(2) The affected source of this subpart
is each new or reconstructed industrial,
commercial, or institutional boiler or
process heater located at a major source
as defined in § 63.7575.
(b) A boiler or process heater is new
if you commence construction of the
boiler or process heater after June 4,
2010, and you meet the applicability
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criteria at the time you commence
construction.
(c) A boiler or process heater is
reconstructed if you meet the
reconstruction criteria as defined in
§ 63.2, you commence reconstruction
after June 4, 2010, and you meet the
applicability criteria at the time you
commence reconstruction.
(d) A boiler or process heater is
existing if it is not new or reconstructed.
§ 63.7491 Are any boilers or process
heaters not subject to this subpart?
The types of boilers and process
heaters listed in paragraphs (a) through
(j) of this section are not subject to this
subpart.
(a) An electric utility steam generating
unit.
(b) A recovery boiler or furnace
covered by 40 CFR part 63, subpart MM.
(c) A boiler or process heater that is
used specifically for research and
development. This does not include
units that provide heat or steam to a
process at a research and development
facility.
(d) A hot water heater as defined in
this subpart.
(e) A refining kettle covered by 40
CFR part 63, subpart X.
(f) An ethylene cracking furnace
covered by 40 CFR part 63, subpart YY.
(g) Blast furnace stoves as described
in the EPA document, entitled ‘‘National
Emission Standards for Hazardous Air
Pollutants (NESHAP) for Integrated Iron
and Steel Plants—Background
Information for Proposed Standards,’’
(EPA–453/R–01–005).
(h) Any boiler or process heater
specifically listed as an affected source
in another standard(s) under 40 CFR
part 63.
(i) Temporary boilers as defined in
this subpart.
(j) Blast furnace gas fuel-fired boilers
and process heaters as defined in this
subpart.
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§ 63.7495 When do I have to comply with
this subpart?
(a) If you have a new or reconstructed
boiler or process heater, you must
comply with this subpart by [DATE THE
FINAL RULE IS PUBLISHED IN THE
FEDERAL REGISTER] or upon startup of
your boiler or process heater, whichever
is later.
(b) If you have an existing boiler or
process heater, you must comply with
this subpart no later than [3 YEARS
AFTER DATE THE FINAL RULE IS
PUBLISHED IN THE FEDERAL
REGISTER].
(c) If you have an area source that
increases its emissions or its potential to
emit such that it becomes a major source
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of HAP, paragraphs (c)(1) and (2) of this
section apply to you.
(1) Any new or reconstructed boiler or
process heater at the existing source
must be in compliance with this subpart
upon startup.
(2) Any existing boiler or process
heater at the existing source must be in
compliance with this subpart within 3
years after the source becomes a major
source.
(d) You must meet the notification
requirements in § 63.7545 according to
the schedule in § 63.7545 and in subpart
A of this part. Some of the notifications
must be submitted before you are
required to comply with the emission
limits and work practice standards in
this subpart.
Emission Limitations and Work
Practice Standards
§ 63.7499 What are the subcategories of
boilers and process heaters?
(a) The subcategories of boilers and
process heaters are:
(1) Pulverized coal units,
(2) Stokers designed to burn coal,
(3) Fluidized bed units designed to
burn coal,
(4) Stokers designed to burn biomass,
(5) Fluidized bed units designed to
burn biomass,
(6) Suspension burners/Dutch Ovens
designed to burn biomass,
(7) Fuel Cells designed to burn
biomass,
(8) Units designed to burn liquid fuel,
(9) Units designed to burn natural gas/
refinery gas,
(10) Units designed to burn other
gases, and
(11) Metal process furnaces.
(b) Each subcategory is defined in
§ 63.7575.
§ 63.7500 What emission limits, work
practice standards, and operating limits
must I meet?
(a) You must meet the requirements in
paragraphs (a)(1) and (2) of this section.
You must meet these requirements at all
times.
(1) You must meet each emission
limit and work practice standard in
Table 1 through 3 to this subpart that
applies to your boiler or process heater,
for each boiler or process heater at your
source, except as provided under
§ 63.7522.
(2) You must meet each operating
limit in Table 4 to this subpart that
applies to your boiler or process heater.
If you use a control device or
combination of control devices not
covered in Table 4 to this subpart, or
you wish to establish and monitor an
alternative operating limit and
alternative monitoring parameters, you
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must apply to the United States
Environmental Protection Agency (EPA)
Administrator for approval of
alternative monitoring under § 63.8(f).
(b) As provided in § 63.6(g), EPA may
approve use of an alternative to the
work practice standards in this section.
General Compliance Requirements
§ 63.7505 What are my general
requirements for complying with this
subpart?
(a) You must be in compliance with
the emission limits and operating limits
in this subpart. These limits apply to
you at all times.
(b) At all times you must operate and
maintain any affected source, including
associated air pollution control
equipment and monitoring equipment,
in a manner consistent with safety and
good air pollution control practices for
minimizing emissions. The general duty
to minimize emissions does not require
you to make any further efforts to
reduce emissions if levels required by
this standard have been achieved.
Determination of whether such
operation and maintenance procedures
are being used will be based on
information available to the
Administrator which may include, but
is not limited to, monitoring results,
review of operation and maintenance
procedures, review of operation and
maintenance records, and inspection of
the source.
(c) You can demonstrate compliance
with the applicable emission limit for
HCl or mercury using fuel analysis if the
emission rate calculated according to
§ 63.7530(d) is less than the applicable
emission limit. Otherwise, you must
demonstrate compliance for HCl or
mercury using performance stack
testing. You must demonstrate
compliance with all other applicable
limits using performance stack testing,
or the continuous monitoring system
(CMS) where applicable.
(d) If you demonstrate compliance
with any applicable emission limit
through performance stack testing, you
must develop a site-specific monitoring
plan according to the requirements in
paragraphs (d)(1) through (4) of this
section. This requirement also applies to
you if you petition the EPA
Administrator for alternative monitoring
parameters under § 63.8(f).
(1) For each CMS required in this
section, you must develop, and submit
to the permitting authority for approval
upon request, a site-specific monitoring
plan that addresses paragraphs (d)(1)(i)
through (iii) of this section. You must
submit this site-specific monitoring
plan, if requested, at least 60 days before
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your initial performance evaluation of
your CMS.
(i) Installation of the CMS sampling
probe or other interface at a
measurement location relative to each
affected process unit such that the
measurement is representative of
control of the exhaust emissions (e.g.,
on or downstream of the last control
device);
(ii) Performance and equipment
specifications for the sample interface,
the pollutant concentration or
parametric signal analyzer, and the data
collection and reduction systems; and
(iii) Performance evaluation
procedures and acceptance criteria (e.g.,
calibrations).
(2) In your site-specific monitoring
plan, you must also address paragraphs
(d)(2)(i) through (iii) of this section.
(i) Ongoing operation and
maintenance procedures in accordance
with the general requirements of
§ 63.8(c)(1)(i) and (ii), (c)(3), and
(c)(4)(ii);
(ii) Ongoing data quality assurance
procedures in accordance with the
general requirements of § 63.8(d); and
(iii) Ongoing recordkeeping and
reporting procedures in accordance with
the general requirements of § 63.10(c),
(e)(1), and (e)(2)(i).
(3) You must conduct a performance
evaluation of each CMS in accordance
with your site-specific monitoring plan.
(4) You must operate and maintain
the CMS in continuous operation
according to the site-specific monitoring
plan.
Testing, Fuel Analyses, and Initial
Compliance Requirements
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§ 63.7510 What are my initial compliance
requirements and by what date must I
conduct them?
(a) For affected sources that elect to
demonstrate compliance with any of the
emission limits of this subpart through
performance stack testing, your initial
compliance requirements include
conducting performance stack tests
according to § 63.7520 and Table 5 to
this subpart, conducting a fuel analysis
for each type of fuel burned in your
boiler or process heater according to
§ 63.7521 and Table 6 to this subpart,
establishing operating limits according
to § 63.7530 and Table 7 to this subpart,
and conducting CMS performance
evaluations according to § 63.7525. For
affected sources that burn a single type
of fuel, you are exempted from the
initial compliance requirements of
conducting a fuel analysis for each type
of fuel burned in your boiler or process
heater according to § 63.7521 and Table
6 to this subpart.
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(b) For affected sources that elect to
demonstrate compliance with the
emission limits for HCl or mercury
through fuel analysis, your initial
compliance requirement is to conduct a
fuel analysis for each type of fuel
burned in your boiler or process heater
according to § 63.7521 and Table 6 to
this subpart and establish operating
limits according to § 63.7530 and Table
8 to this subpart.
(c) If your boiler or process heater has
a heat input capacity less than 100
MMBtu per hour, your initial
compliance demonstration for CO is
conducting a performance stack test for
CO according to Table 5 to this subpart.
If your boiler or process heater has a
heat input capacity of 100 MMBtu per
hour or greater, your initial compliance
demonstration for CO is conducting a
performance evaluation of your
continuous emission monitoring system
for CO according to § 63.7525(a).
(d) If your boiler or process heater has
a heat input capacity of 250 MMBtu per
hour or greater and combusts coal,
biomass, or residual oil, your initial
compliance demonstration for PM is
conducting a performance evaluation of
your continuous emission monitoring
system for PM according to § 63.7525(b).
(e) For existing affected sources, you
must demonstrate initial compliance no
later than 180 days after the compliance
date that is specified for your source in
§ 63.7495 and according to the
applicable provisions in § 63.7(a)(2) as
cited in Table 10 to this subpart.
(f) If your new or reconstructed
affected source commenced
construction or reconstruction between
June 4, 2010 and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER],
you must demonstrate initial
compliance with either the proposed
emission limits or the promulgated
emission limits no later than 180 days
after [DATE 60 DAYS AFTER
PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER] or within
180 days after startup of the source,
whichever is later, according to
§ 63.7(a)(2)(ix).
(g) If your new or reconstructed
affected source commenced
construction or reconstruction between
June 4, 2010, and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER],
and you chose to comply with the
proposed emission limits when
demonstrating initial compliance, you
must conduct a second compliance
demonstration for the promulgated
emission limits within 3 years after
[DATE 60 DAYS AFTER PUBLICATION
OF THE FINAL RULE IN THE FEDERAL
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32051
REGISTER] or within 3 years after
startup of the affected source, whichever
is later.
(h) If your new or reconstructed
affected source commences construction
or reconstruction after [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER],
you must demonstrate initial
compliance with the promulgated
emission limits no later than 180 days
after startup of the source.
§ 63.7515 When must I conduct
subsequent performance tests or fuel
analyses?
(a) You must conduct all applicable
performance tests according to § 63.7520
on an annual basis, unless you follow
the requirements listed in paragraphs (b)
through (e) of this section. Annual
performance tests must be completed
between 10 and 12 months after the
previous performance test, unless you
follow the requirements listed in
paragraphs (b) through (e) of this
section.
(b) You can conduct performance
stack tests less often for a given
pollutant if your performance stack tests
for the pollutant for at least 3
consecutive years show that your
emissions are at or below 75 percent of
the emission limit, and if there are no
changes in the operation of the affected
source or air pollution control
equipment that could increase
emissions. In this case, you do not have
to conduct a performance test for that
pollutant for the next 2 years. You must
conduct a performance test during the
third year and no more than 36 months
after the previous performance test. This
reduced testing option does not apply to
performance stack tests for dioxin/furan.
If you elect to demonstrate compliance
using emission averaging under
§ 63.7522, you must continue to conduct
performance stack tests annually.
(c) If your boiler or process heater
continues to meet the emission limit for
the pollutant, you may choose to
conduct performance stack tests for the
pollutant every third year if your
emissions are at or below 75 percent of
the emission limit, and if there are no
changes in the operation of the affected
source or air pollution control
equipment that could increase
emissions, but each such performance
test must be conducted no more than 36
months after the previous performance
test. This reduced testing option does
not apply to performance stack tests for
dioxin/furan. If you elect to demonstrate
compliance using emission averaging
under § 63.7522, you must continue to
conduct performance stack tests
annually.
E:\FR\FM\04JNP5.SGM
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(d) If a performance test shows
emissions exceeded 75 percent of the
emission limit, you must conduct
annual performance tests for that
pollutant until all performance tests
over a consecutive 3-year period show
compliance.
(e) If you are required to meet an
applicable work practice standard, you
must conduct annual performance tuneups according to § 63.7520. Each annual
tune-up must be conducted between 10
and 12 months after the previous tuneup.
(f) If you demonstrate compliance
with the mercury or HCl based on fuel
analysis, you must conduct a monthly
fuel analysis according to § 63.7521 for
each type of fuel burned. If you burn a
new type of fuel, you must conduct a
fuel analysis before burning the new
type of fuel in your boiler or process
heater. You must still meet all
applicable continuous compliance
requirements in § 63.7540.
(g) You must report the results of
performance tests (stack test and fuel
analyses) within 60 days after the
completion of the performance tests.
This report must also verify that the
operating limits for your affected source
have not changed or provide
documentation of revised operating
parameters established according to
§ 63.7530 and Table 7 to this subpart, as
applicable. The reports for all
subsequent performance tests must
include all applicable information
required in § 63.7550.
erowe on DSK5CLS3C1PROD with PROPOSALS5
§ 63.7520 What stack tests and procedures
must I use for the performance tests?
(a) You must conduct all performance
tests according to § 63.7(c), (d), (f), and
(h). You must also develop a sitespecific test plan according to the
requirements in § 63.7(c).
(b) You must conduct each
performance test according to the
requirements in Table 5 to this subpart.
(c) You must conduct each
performance stack test under the
specific conditions listed in Tables 5
and 7 to this subpart. You must conduct
performance stack tests at the maximum
normal operating load while burning the
type of fuel or mixture of fuels that has
the highest content of chlorine and
mercury, and you must demonstrate
initial compliance and establish your
operating limits based on these tests.
These requirements could result in the
need to conduct more than one
performance test.
(d) You must conduct three separate
test runs for each performance test
required in this section, as specified in
§ 63.7(e)(3). Each test run must last at
least 4 hours.
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(e) To determine compliance with the
emission limits, you must use the
F-Factor methodology and equations in
sections 12.2 and 12.3 of EPA Method
19 of appendix A to part 60 of this
chapter to convert the measured
particulate matter concentrations, the
measured HCl concentrations, and the
measured mercury concentrations that
result from the initial performance test
to pounds per million Btu heat input
emission rates using F-factors.
§ 63.7521 What fuel analyses and
procedures must I use for the performance
tests?
(a) You must conduct performance
fuel analysis tests according to the
procedures in paragraphs (b) through (e)
of this section and Table 6 to this
subpart, as applicable.
(b) You must develop and submit a
site-specific fuel analysis plan to the
EPA Administrator for review and
approval according to the following
procedures and requirements in
paragraphs (b)(1) and (2) of this section.
(1) You must submit the fuel analysis
plan no later than 60 days before the
date that you intend to demonstrate
compliance.
(2) You must include the information
contained in paragraphs (b)(2)(i)
through (vi) of this section in your fuel
analysis plan.
(i) The identification of all fuel types
anticipated to be burned in each boiler
or process heater.
(ii) For each fuel type, the notification
of whether you or a fuel supplier will
be conducting the fuel analysis.
(iii) For each fuel type, a detailed
description of the sample location and
specific procedures to be used for
collecting and preparing the composite
samples if your procedures are different
from paragraph (c) or (d) of this section.
Samples should be collected at a
location that most accurately represents
the fuel type, where possible, at a point
prior to mixing with other dissimilar
fuel types.
(iv) For each fuel type, the analytical
methods from Table 6, with the
expected minimum detection levels, to
be used for the measurement of chlorine
or mercury.
(v) If you request to use an alternative
analytical method other than those
required by Table 6 to this subpart, you
must also include a detailed description
of the methods and procedures that you
are proposing to use. Methods in Table
6 shall be used until the requested
alternative is approved.
(vi) If you will be using fuel analysis
from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel
supplier must use the analytical
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Fmt 4701
Sfmt 4702
methods required by Table 6 to this
subpart.
(c) At a minimum, you must obtain
three composite fuel samples for each
fuel type according to the procedures in
paragraph (c)(1) or (2) of this section.
(1) If sampling from a belt (or screw)
feeder, collect fuel samples according to
paragraphs (c)(1)(i) and (ii) of this
section.
(i) Stop the belt and withdraw a 6inch wide sample from the full crosssection of the stopped belt to obtain a
minimum two pounds of sample. You
must collect all the material (fines and
coarse) in the full cross-section. You
must transfer the sample to a clean
plastic bag.
(ii) Each composite sample will
consist of a minimum of three samples
collected at approximately equal 1-hour
intervals during the testing period.
(2) If sampling from a fuel pile or
truck, you must collect fuel samples
according to paragraphs (c)(2)(i) through
(iii) of this section.
(i) For each composite sample, you
must select a minimum of five sampling
locations uniformly spaced over the
surface of the pile.
(ii) At each sampling site, you must
dig into the pile to a depth of 18 inches.
You must insert a clean flat square
shovel into the hole and withdraw a
sample, making sure that large pieces do
not fall off during sampling.
(iii) You must transfer all samples to
a clean plastic bag for further
processing.
(d) You must prepare each composite
sample according to the procedures in
paragraphs (d)(1) through (7) of this
section.
(1) You must thoroughly mix and
pour the entire composite sample over
a clean plastic sheet.
(2) You must break sample pieces
larger than 3 inches into smaller sizes.
(3) You must make a pie shape with
the entire composite sample and
subdivide it into four equal parts.
(4) You must separate one of the
quarter samples as the first subset.
(5) If this subset is too large for
grinding, you must repeat the procedure
in paragraph (d)(3) of this section with
the quarter sample and obtain a onequarter subset from this sample.
(6) You must grind the sample in a
mill.
(7) You must use the procedure in
paragraph (d)(3) of this section to obtain
a one-quarter subsample for analysis. If
the quarter sample is too large,
subdivide it further using the same
procedure.
(e) You must determine the
concentration of pollutants in the fuel
(mercury and/or chlorine) in units of
E:\FR\FM\04JNP5.SGM
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Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules
n
n
i =1
i =1
AveWeightedEmissions = 0.90 × ∑ (Er × Hm) ÷ ∑ Hm
Where:
Ave Weighted Emissions = Average weighted
emissions for particulate matter, HCl, or
mercury, in units of pounds per million
Btu of heat input.
Er = Emission rate (as calculated according
to Table 5 to this subpart for particulate
matter, HCl, or mercury or by fuel
analysis for HCl or mercury as calculated
by the applicable equation in
§ 63.7530(c)) for unit, i, for particulate
matter, HCl, or mercury, in units of
pounds per million Btu of heat input.
Hm = Maximum rated heat input capacity of
unit, i, in units of million Btu per hour.
n = Number of units participating in the
emissions averaging option.
0.90 = Required discount factor.
(2) If you are not capable of
monitoring heat input, and the boiler
n
generates steam, you may use Equation
2 of this section as an alternative to
using Equation 1 of this section to
demonstrate that the particulate matter,
HCl, and mercury emissions from all
existing units participating in the
emissions averaging option do not
exceed the emission limits in Table 2 to
this subpart.
n
i =1
(Eq. 1)
i =1
AveWeightedEmissions = 0.90 × ∑ (Er × Sm × Cfi ) ÷ ∑ Sm × Cfi
Where:
Ave Weighted Emissions = Average weighted
emission level for PM, HCl, or mercury,
in units of pounds per million Btu of
heat input.
Er = Emission rate (as calculated according
to Table 5 to this subpart for particulate
matter, HCl, or mercury or by fuel
analysis for HCl or mercury as calculated
by the applicable equation in
§ 63.7530(c)) for unit, i, for particulate
matter, HCl, or mercury, in units of
pounds per million Btu of heat input.
Sm = Maximum steam generation by unit, i,
in units of pounds.
Cf = Conversion factor, calculated from the
most recent compliance test, in units of
million Btu of heat input per pounds of
steam generated for unit, i.
0.90 = Required discount factor.
(f) You must demonstrate compliance
on a monthly basis determined at the
end of every month (12 times per year)
n
i =1
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AveWeightedEmissions = 0.90 × ∑ (Er × Hb) ÷ ∑ Hb
Where:
Ave Weighted Emissions = monthly average
weighted emission level for particulate
matter, HCl, or mercury, in units of
pounds per million Btu of heat input.
Er = Emission rate, (as calculated during the
most recent compliance test, (as
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PO 00000
calculated according to Table 5 to this
subpart for particulate matter, HCl, or
mercury or by fuel analysis for HCl or
mercury as calculated by the applicable
equation in § 63.7530(c)) for unit, i, for
particulate matter, HCl, or mercury, in
Frm 00049
Fmt 4701
according to paragraphs (f)(1) through
(3) of this section. The first monthly
period begins on the compliance date
specified in § 63.7495.
(1) For each calendar month, you
must use Equation 3 of this section to
calculate the monthly average weighted
emission rate using the actual heat
capacity for each existing unit
participating in the emissions averaging
option.
n
i =1
(Eq. 2)
Sfmt 4702
(Eq. 3)
units of pounds per million Btu of heat
input.
Hb = The average heat input for each
calendar month of boiler, i, in units of
million Btu.
n = Number of units participating in the
emissions averaging option.
E:\FR\FM\04JNP5.SGM
04JNP5
EP04JN10.005</MATH>
(a) As an alternative to meeting the
requirements of § 63.7500 for particulate
matter, HCl, or mercury on a boiler or
process heater-specific basis, if you have
more than one existing boiler or process
heater in any subcategory located at
your facility, you may demonstrate
compliance by emission averaging, if
your averaged emissions are within 90
percent of the applicable emission limit,
according to the procedures in this
section.
(b) Separate stack requirements. For a
group of two or more existing boilers or
DAYS AFTER PUBLICATION OF THE
FINAL RULE IN THE FEDERAL
REGISTER] .
(d) The averaged emissions rate from
the existing boilers and process heaters
participating in the emissions averaging
option must be in compliance with the
limits in Table 2 to this subpart at all
times following the compliance date
specified in § 63.7495.
(e) You must demonstrate initial
compliance according to paragraph
(e)(1) or (2) of this section.
(1) You must use Equation 1 of this
section to demonstrate that the
particulate matter, HCl, and mercury
emissions from all existing units
participating in the emissions averaging
option do not exceed the emission
limits in Table 2 to this subpart.
EP04JN10.004</MATH>
§ 63.7522 Can I use emission averaging to
comply with this subpart?
process heaters in the same subcategory
that each vent to a separate stack, you
may average particulate matter, HCl,
and mercury emissions to demonstrate
compliance with the limits in Table 2 to
this subpart if you satisfy the
requirements in paragraphs (c), (d), (e),
(f), and (g) of this section.
(c) For each existing boiler or process
heater in the averaging group, the
emission rate achieved during the initial
compliance test for the HAP being
averaged must not exceed the emission
level that was being achieved on [THE
DATE 30 DAYS AFTER PUBLICATION
OF THE FINAL RULE IN THE FEDERAL
REGISTER] or the control technology
employed during the initial compliance
test must not be less effective for the
HAP being averaged than the control
technology employed on [THE DATE 30
EP04JN10.003</MATH>
pounds per million Btu of each
composite sample for each fuel type
according to the procedures in Table 6
to this subpart.
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Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules
0.90 = Required discount factor.
Equation 4 of this section as an
alternative to using Equation 3 of this
section to calculate the monthly
weighted emission rate using the actual
(2) If you are not capable of
monitoring heat input, you may use
n
n
i =1
steam generation from the units
participating in the emissions averaging
option.
i =1
AveWeightedEmissions = 0.90 × ∑ (Er × Sa × Cfi ) ÷ ∑ Sa × Cfi
Where:
Ave Weighted Emissions = monthly average
weighted emission level for PM, HCl, or
mercury, in units of pounds per million
Btu of heat input.
Er = Emission rate, (as calculated during the
most recent compliance test (as
calculated according to Table 5 to this
subpart for particulate matter, HCl, or
mercury or by fuel analysis for HCl or
mercury as calculated by the applicable
equation in § 63.7530(c)) for unit, i, for
particulate matter, HCl, or mercury, in
units of pounds per million Btu of heat
input.
Sa = Actual steam generation for each
calendar month by boiler, i, in units of
pounds.
Cf = Conversion factor, as calculated during
the most recent compliance test, in units
of million Btu of heat input per pounds
of steam generated for unit, i.
0.90 = Required discount factor.
(3) Until 12 monthly weighted average
emission rates have been accumulated,
(Eq. 4)
calculate and report only the monthly
average weighted emission rate
determined under paragraph (f)(1) or (2)
of this section. After 12 monthly
weighted average emission rates have
been accumulated, for each subsequent
calendar month, use Equation 5 of this
section to calculate the 12-month rolling
average of the monthly weighted
average emission rates for the current
month and the previous 11 months.
n
Eavg = ∑ ERi ÷ 12
(Eq. 5)
(g) You must develop, and submit to
the applicable regulatory authority for
review and approval upon request, an
implementation plan for emission
averaging according to the following
procedures and requirements in
paragraphs (g)(1) through (4).
(1) You must submit the
implementation plan no later than 180
days before the date that the facility
intends to demonstrate compliance
using the emission averaging option.
(2) You must include the information
contained in paragraphs (g)(2)(i) through
(vii) of this section in your
implementation plan for all emission
sources included in an emissions
average:
(i) The identification of all existing
boilers and process heaters in the
averaging group, including for each
either the applicable HAP emission
level or the control technology installed
as of [DATE 60 DAYS AFTER
PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER] and the
date on which you are requesting
emission averaging to commence;
(ii) The process parameter (heat input
or steam generated) that will be
monitored for each averaging group;
(iii) The specific control technology or
pollution prevention measure to be used
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for each emission boiler or process
heater in the averaging group and the
date of its installation or application. If
the pollution prevention measure
reduces or eliminates emissions from
multiple boilers or process heaters, the
owner or operator must identify each
boiler or process heater;
(iv) The test plan for the measurement
of particulate matter, HCl, or mercury
emissions in accordance with the
requirements in § 63.7520;
(v) The operating parameters to be
monitored for each control system or
device consistent with 63.7500 and
Table 4, and a description of how the
operating limits will be determined;
(vi) If you request to monitor an
alternative operating parameter
pursuant to § 63.7525, you must also
include:
(A) A description of the parameter(s)
to be monitored and an explanation of
the criteria used to select the
parameter(s); and
(B) A description of the methods and
procedures that will be used to
demonstrate that the parameter
indicates proper operation of the control
device; the frequency and content of
monitoring, reporting, and
recordkeeping requirements; and a
demonstration, to the satisfaction of the
applicable regulatory authority, that the
proposed monitoring frequency is
sufficient to represent control device
operating conditions; and
(vii) A demonstration that compliance
with each of the applicable emission
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Fmt 4701
Sfmt 4702
limit(s) will be achieved under
representative operating conditions.
(3) The regulatory authority shall
review and approve or disapprove the
plan according to the following criteria:
(i) Whether the content of the plan
includes all of the information specified
in paragraph (g)(2) of this section; and
(ii) Whether the plan presents
sufficient information to determine that
compliance will be achieved and
maintained.
(4) The applicable regulatory
authority shall not approve an emission
averaging implementation plan
containing any of the following
provisions:
(i) Any averaging between emissions
of differing pollutants or between
differing sources; or
(ii) The inclusion of any emission
source other than an existing unit in the
same subcategory.
(h) Common stack requirements. For a
group of two or more existing affected
units, each of which vents through a
single common stack, you may average
particulate matter, HCl and mercury
emissions to demonstrate compliance
with the limits in Table 2 to this subpart
if you satisfy the requirements in
paragraph (i) or (j) of this section.
(i) For a group of two or more existing
units in the same subcategory, each of
which vents through a common
emissions control system to a common
stack, that does not receive emissions
from units in other subcategories or
categories, you may treat such averaging
group as a single existing unit for
E:\FR\FM\04JNP5.SGM
04JNP5
EP04JN10.006</MATH>
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Where:
Eavg = 12-month rolling average emission
rate, (pounds per million Btu heat input)
ERi = Monthly weighted average, for month
‘‘i’’, (pounds per million Btu heat
input)(as calculated by (f)(1) or (2))
EP04JN10.007</MATH>
i =1
purposes of this subpart and comply
with the requirements of this subpart as
if the group were a single unit.
(j) For all other groups of units subject
to paragraph (h) of this section, the
owner or operator may elect to:
(1) Conduct performance tests
according to procedures specified in
§ 63.7520 in the common stack if
affected units from other subcategories
vent to the common stack. The emission
limits that the group must comply with
are determined by the use of equation 6.
n
n
i =1
i =1
En = ∑ (ELi × Hi) ÷ ∑ Hi
(Eq. 6)
Where:
En = HAP emission limit, lb/MMBtu, ppm, or
ng/dscm;
ELi = Appropriate emission limit from Table
2 to this subpart for unit i, in units of lb/
MMBtu, ppm or ng/dscm;
Hi = Heat input from unit i, MMBtu;
(2) Conduct performance tests
according to procedures specified in
§ 63.7520 in the common stack. If
affected units from nonaffected units
vent to the common stack, the units
from nonaffected units must be shut
down or vented to a different stack
during the performance test); and
(3) Meet the applicable operating limit
specified in § 63.7540 and Table 8 to
this subpart for each emissions control
system (except that, if each unit venting
to the common stack has an applicable
opacity operating limit, then a single
continuous opacity monitoring system
may be located in the common stack
instead of in each duct to the common
stack).
(k) Combination requirements. The
common stack of a group of two or more
existing boilers or process heaters in the
same subcategory subject to paragraph
(h) of this section may be treated as a
separate stack for purposes of paragraph
(b) of this section and included in an
emissions averaging group subject to
paragraph (b) of this section.
erowe on DSK5CLS3C1PROD with PROPOSALS5
§ 63.7525 What are my monitoring,
installation, operation, and maintenance
requirements?
(a) If your boiler or process heater has
a heat input capacity of 100 MMBtu per
hour or greater, you must install,
operate, and maintain a continuous
emission monitoring system (CEMS) for
CO and oxygen according to the
procedures in paragraphs (a)(1) through
(6) of this section by the compliance
date specified in § 63.7495. The CO and
oxygen shall be monitored at the same
location at the outlet of the boiler or
process heater.
(1) Each CEMS must be installed,
operated, and maintained according to
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the applicable procedures under
Performance Specification (PS) 3 or 4A
of 40 CFR part 60, appendix B, and
according to the site-specific monitoring
plan developed according to
§ 63.7505(d).
(2) You must conduct a performance
evaluation of each CEMS according to
the requirements in § 63.8 and
according to PS 4A of 40 CFR part 60,
appendix B.
(3) Each CEMS must complete a
minimum of one cycle of operation
(sampling, analyzing, and data
recording) for each successive 15minute period.
(4) The CEMS data must be reduced
as specified in § 63.8(g)(2).
(5) You must calculate and record a
30-day rolling average emission rate on
a daily basis. A new 30-day rolling
average emission rate is calculated as
the average of all of the hourly CO
emission data for the preceding 30
operating days.
(6) For purposes of calculating data
averages, you must use all the data
collected during all periods in assessing
compliance. Any period for which the
monitoring system is out of control and
data are not available for required
calculations constitutes a deviation from
the monitoring requirements.
(b) If your boiler or process heater has
a heat input capacity of 250 MMBtu per
hour or greater and combusts coal,
biomass, or residual oil, you must
install, certify, maintain, and operate a
CEMS measuring PM emissions
discharged to the atmosphere and
record the output of the system as
specified in paragraphs (b)(1) through
(b)(6) of this section.
(1) Each CEMS shall be installed,
certified, operated, and maintained
according to the requirements in
§ 63.7540(a)(8).
(2) The initial performance evaluation
shall be completed no later than 180
days after the date of initial startup of
a new unit or within 180 days of the
compliance date for an existing unit, as
specified under § 63.7495 of this
subpart.
(3) Compliance with the applicable
emissions limit shall be determined
based on the 24-hour daily (block)
average of the hourly arithmetic average
emissions concentrations using the
continuous monitoring system outlet
data. The 24-hour block arithmetic
average emission concentration shall be
calculated using EPA Reference Method
19 of appendix A of 40 CFR part 60.
(4) Obtain valid CEMS hourly
averages for all operating hours on a 30day rolling average basis. At least two
data points per hour shall be used to
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Sfmt 4702
32055
calculate each 1-hour arithmetic
average.
(5) The 1-hour arithmetic averages
required shall be expressed in lb/
MMBtu and shall be used to calculate
the boiler operating day daily arithmetic
average emissions.
(6) When PM emissions data are not
obtained because of CEMS breakdowns,
repairs, calibration checks, and zero and
span adjustments, emissions data shall
be obtained by using other monitoring
systems as approved by the
Administrator or EPA Reference Method
19 of appendix A of 40 CFR part 60 to
provide, as necessary, valid emissions
data for all operating hours per 30-day
rolling average.
(c) If you have an applicable opacity
operating limit, you must install,
operate, certify and maintain each
continuous opacity monitoring system
(COMS) according to the procedures in
paragraphs (c)(1) through (7) of this
section by the compliance date specified
in § 63.7495.
(1) Each COMS must be installed,
operated, and maintained according to
PS 1 of 40 CFR part 60, appendix B.
(2) You must conduct a performance
evaluation of each COMS according to
the requirements in § 63.8 and
according to PS 1 of 40 CFR part 60,
appendix B.
(3) As specified in § 63.8(c)(4)(i), each
COMS must complete a minimum of
one cycle of sampling and analyzing for
each successive 10-second period and
one cycle of data recording for each
successive 6-minute period.
(4) The COMS data must be reduced
as specified in § 63.8(g)(2).
(5) You must include in your sitespecific monitoring plan procedures and
acceptance criteria for operating and
maintaining each COMS according to
the requirements in § 63.8(d). At a
minimum, the monitoring plan must
include a daily calibration drift
assessment, a quarterly performance
audit, and an annual zero alignment
audit of each COMS.
(6) You must operate and maintain
each COMS according to the
requirements in the monitoring plan
and the requirements of § 63.8(e). You
must identify periods the COMS is out
of control including any periods that the
COMS fails to pass a daily calibration
drift assessment, a quarterly
performance audit, or an annual zero
alignment audit. Any 6-minute period
for which the monitoring system is out
of control and data are not available for
required calculations constitutes a
deviation from the monitoring
requirements.
(7) You must determine and record all
the 6-minute averages (and 1-hour block
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averages as applicable) collected for
periods during which the COMS is not
out of control.
(d) If you have an operating limit that
requires the use of a CMS, you must
install, operate, and maintain each
continuous parameter monitoring
system (CPMS) according to the
procedures in paragraphs (d)(1) through
(5) of this section by the compliance
date specified in § 63.7495.
(1) The CPMS must complete a
minimum of one cycle of operation for
each successive 15-minute period. You
must have a minimum of four
successive cycles of operation to have a
valid hour of data.
(2) Except for monitoring
malfunctions, associated repairs, and
required quality assurance or control
activities (including, as applicable,
calibration checks and required zero
and span adjustments), you must
conduct all monitoring in continuous
operation at all times that the unit is
operating. A monitoring malfunction is
any sudden, infrequent, not reasonably
preventable failure of the monitoring to
provide valid data. Monitoring failures
that are caused in part by poor
maintenance or careless operation are
not malfunctions.
(3) For purposes of calculating data
averages, you must not use data
recorded during monitoring
malfunctions, associated repairs, out of
control periods, or required quality
assurance or control activities. You
must use all the data collected during
all other periods in assessing
compliance. Any 15-minute period for
which the monitoring system is out-ofcontrol and data are not available for
required calculations constitutes a
deviation from the monitoring
requirements.
(4) You must determine the 3-hour
block average of all recorded readings,
except as provided in paragraph (c)(3) of
this section.
(5) You must record the results of
each inspection, calibration, and
validation check.
(e) If you have an operating limit that
requires the use of a flow measurement
device, you must meet the requirements
in paragraphs (d) and (e)(1) through (4)
of this section.
(1) You must locate the flow sensor
and other necessary equipment in a
position that provides a representative
flow.
(2) You must use a flow sensor with
a measurement sensitivity of 2 percent
of the flow rate.
(3) You must reduce swirling flow or
abnormal velocity distributions due to
upstream and downstream disturbances.
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(4) You must conduct a flow sensor
calibration check at least semiannually.
(f) If you have an operating limit that
requires the use of a pressure
measurement device, you must meet the
requirements in paragraphs (d) and (f)(1)
through (6) of this section.
(1) Locate the pressure sensor(s) in a
position that provides a representative
measurement of the pressure.
(2) Minimize or eliminate pulsating
pressure, vibration, and internal and
external corrosion.
(3) Use a gauge with a minimum
tolerance of 1.27 centimeters of water or
a transducer with a minimum tolerance
of 1 percent of the pressure range.
(4) Check pressure tap pluggage daily.
(5) Using a manometer, you must
check gauge calibration quarterly and
transducer calibration monthly.
(6) Conduct calibration checks any
time the sensor exceeds the
manufacturer’s specified maximum
operating pressure range or install a new
pressure sensor.
(g) If you have an operating limit that
requires the use of a pH measurement
device, you must meet the requirements
in paragraphs (d) and (g)(1) through (3)
of this section.
(1) Locate the pH sensor in a position
that provides a representative
measurement of scrubber effluent pH.
(2) Ensure the sample is properly
mixed and representative of the fluid to
be measured.
(3) Check the pH meter’s calibration
on at least two points every 8 hours of
process operation.
(h) If you have an operating limit that
requires the use of equipment to
monitor voltage and secondary
amperage (or total power input) of an
electrostatic precipitator (ESP), you
must use voltage and secondary current
monitoring equipment to measure
voltage and secondary current to the
ESP.
(i) If you have an operating limit that
requires the use of equipment to
monitor sorbent injection rate (e.g.,
weigh belt, weigh hopper, or hopper
flow measurement device), you must
meet the requirements in paragraphs (c)
and (i)(1) through (3) of this section.
(1) Locate the device in a position(s)
that provides a representative
measurement of the total sorbent
injection rate.
(2) Install and calibrate the device in
accordance with manufacturer’s
procedures and specifications.
(3) At least annually, calibrate the
device in accordance with the
manufacturer’s procedures and
specifications.
(j) If you elect to use a fabric filter bag
leak detection system to comply with
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the requirements of this subpart, you
must install, calibrate, maintain, and
continuously operate a bag leak
detection system as specified in
paragraphs (j)(1) through (8) of this
section.
(1) You must install and operate a bag
leak detection system for each exhaust
stack of the fabric filter.
(2) Each bag leak detection system
must be installed, operated, calibrated,
and maintained in a manner consistent
with the manufacturer’s written
specifications and recommendations
and in accordance with the guidance
provided in EPA–454/R–98–015,
September 1997.
(3) The bag leak detection system
must be certified by the manufacturer to
be capable of detecting particulate
matter emissions at concentrations of 10
milligrams per actual cubic meter or
less.
(4) The bag leak detection system
sensor must provide output of relative
or absolute particulate matter loadings.
(5) The bag leak detection system
must be equipped with a device to
continuously record the output signal
from the sensor.
(6) The bag leak detection system
must be equipped with an alarm system
that will sound automatically when an
increase in relative particulate matter
emissions over a preset level is detected.
The alarm must be located where it is
easily heard by plant operating
personnel.
(7) For positive pressure fabric filter
systems that do not duct all
compartments of cells to a common
stack, a bag leak detection system must
be installed in each baghouse
compartment or cell.
(8) Where multiple bag leak detectors
are required, the system’s
instrumentation and alarm may be
shared among detectors.
§ 63.7530 How do I demonstrate initial
compliance with the emission limits and
work practice standards?
(a) You must demonstrate initial
compliance with each emission limit
that applies to you by conducting initial
performance tests (performance stack
tests and fuel analyses) and establishing
operating limits, as applicable,
according to § 63.7520, paragraph (c) of
this section, and Tables 5 and 7 to this
subpart.
(b) If you demonstrate compliance
through performance stack testing, you
must establish each site-specific
operating limit in Table 2 to this subpart
that applies to you according to the
requirements in § 63.7520, Table 7 to
this subpart, and paragraph (c)(4) of this
section, as applicable. You must also
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conduct fuel analyses according to
§ 63.7521 and establish maximum fuel
pollutant input levels according to
paragraphs (c)(1) through (3) of this
section, as applicable.
(1) You must establish the maximum
chlorine fuel input (Cinput) during the
initial performance testing according to
the procedures in paragraphs (c)(1)(i)
through (iii) of this section.
(i) You must determine the fuel type
or fuel mixture that you could burn in
your boiler or process heater that has
the highest content of chlorine.
(ii) During the performance testing for
HCl, you must determine the fraction of
the total heat input for each fuel type
burned (Qi) based on the fuel mixture
that has the highest content of chlorine,
and the average chlorine concentration
of each fuel type burned (Ci).
(iii) You must establish a maximum
chlorine input level using Equation 7 of
this section.
n
Clinpunt = ∑ (Ci × Qi)
(Eq. 7)
i =1
Where:
Clinput = Maximum amount of chlorine
entering the boiler or process heater
through fuels burned in units of pounds
per million Btu.
Ci = Arithmetic average concentration of
chlorine in fuel type, i, analyzed
according to § 63.7521, in units of
pounds per million Btu.
Qi = Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest content of chlorine. If
you do not burn multiple fuel types
during the performance testing, it is not
necessary to determine the value of this
term. Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
32057
mixture that has the highest content of
chlorine.
(2) You must establish the maximum
mercury fuel input level (Mercuryinput)
during the initial performance testing
using the procedures in paragraphs
(c)(3)(i) through (iii) of this section.
(i) You must determine the fuel type
or fuel mixture that you could burn in
your boiler or process heater that has
the highest content of mercury.
(ii) During the compliance
demonstration for mercury, you must
determine the fraction of total heat
input for each fuel burned (Qi) based on
the fuel mixture that has the highest
content of mercury, and the average
mercury concentration of each fuel type
burned (HGi).
(iii) You must establish a maximum
mercury input level using Equation 8 of
this section.
n
Mercuryinput = ∑ (HGi × Qi)
(Eq. 8)
i =1
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or process heater that would result in
the maximum emission rates of the
pollutants that you elect to demonstrate
compliance through fuel analysis.
(2) You must determine the 90th
percentile confidence level fuel
pollutant concentration of the
composite samples analyzed for each
fuel type using the one-sided z-statistic
test described in Equation 9 of this
section.
(Eq. 9)
(3) To demonstrate compliance with
the applicable emission limit for HCl,
the HCl emission rate that you calculate
for your boiler or process heater using
Equation 10 of this section must not
exceed the applicable emission limit for
HCl.
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04JNP5
EP04JN10.011</MATH>
P90 = mean + ( SD × t )
Where:
P90 = 90th percentile confidence level
pollutant concentration, in pounds per
million Btu.
mean = Arithmetic average of the fuel
pollutant concentration in the fuel
samples analyzed according to § 63.7521,
in units of pounds per million Btu.
SD = Standard deviation of the pollutant
concentration in the fuel samples
analyzed according to § 63.7521, in units
of pounds per million Btu.
t = t distribution critical value for 90th
percentile (0.1) probability for the
appropriate degrees of freedom (number
of samples minus one) as obtained from
a Distribution Critical Value Table.
EP04JN10.010</MATH>
(3) You must establish parameter
operating limits according to paragraphs
(c)(4)(i) through (iv) of this section.
(i) For a wet scrubber, you must
establish the minimum scrubber effluent
pH, liquid flowrate, and pressure drop
as defined in § 63.7575, as your
operating limits during the three-run
performance test. If you use a wet
scrubber and you conduct separate
performance tests for particulate matter,
HCl, and mercury emissions, you must
establish one set of minimum scrubber
effluent pH, liquid flowrate, and
pressure drop operating limits. The
minimum scrubber effluent pH
operating limit must be established
during the HCl performance test. If you
conduct multiple performance tests, you
must set the minimum liquid flowrate
and pressure drop operating limits at
the highest minimum values established
during the performance tests.
(ii) For an electrostatic precipitator,
you must establish the minimum
voltage and secondary current (or total
power input), as defined in § 63.7575, as
your operating limits during the threerun performance test.
(iii) For a dry scrubber, you must
establish the minimum sorbent injection
rate for each sorbent, as defined in
§ 63.7575, as your operating limit during
the three-run performance test.
(iv) The operating limit for boilers or
process heaters with fabric filters that
choose to demonstrate continuous
compliance through bag leak detection
systems is that a bag leak detection
system be installed according to the
requirements in § 63.7525, and that each
fabric filter must be operated such that
the bag leak detection system alarm
does not sound more than 5 percent of
the operating time during a 6-month
period.
(c) If you elect to demonstrate
compliance with an applicable emission
limit through fuel analysis, you must
conduct fuel analyses according to
§ 63.7521 and follow the procedures in
paragraphs (c)(1) through (5) of this
section.
(1) If you burn more than one fuel
type, you must determine the fuel
mixture you could burn in your boiler
EP04JN10.009</MATH>
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Where:
Mercuryinput = Maximum amount of mercury
entering the boiler or process heater
through fuels burned in units of pounds
per million Btu.
HGi = Arithmetic average concentration of
mercury in fuel type, i, analyzed
according to § 63.7521, in units of
pounds per million Btu.
Qi = Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest mercury content. If you
do not burn multiple fuel types during
the performance test, it is not necessary
to determine the value of this term.
Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
mixture that has the highest content of
mercury.
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Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules
n
HCl = ∑ (C 90i × Qi × 1.028)
(Eq. 10)
(4) To demonstrate compliance with
the applicable emission limit for
mercury, the mercury emission rate that
you calculate for your boiler or process
heater using Equation 11 of this section
must not exceed the applicable emission
limit for mercury.
n
Mercury = ∑ (HG90i × Qi )
(Eq. 11)
i =1
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Where:
Mercury = Mercury emission rate from the
boiler or process heater in units of
pounds per million Btu.
HGi90 = 90th percentile confidence level
concentration of mercury in fuel, i, in
units of pounds per million Btu as
calculated according to Equation 8 of
this section.
Qi = Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest mercury content. If you
do not burn multiple fuel types, it is not
necessary to determine the value of this
term. Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
mixture that has the highest mercury
content.
(d) If you own or operate an existing
unit with a heat input capacity of 10
million Btu per hour or less, you must
submit a signed statement in the
Notification of Compliance Status report
that indicates that you conducted a
tune-up of the unit.
(e) You must submit the energy
assessment report, along with a signed
certification that the assessment is an
accurate depiction of your facility.
(f) You must submit the Notification
of Compliance Status containing the
results of the initial compliance
demonstration according to the
requirements in § 63.7545(e).
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Continuous Compliance Requirements
§ 63.7535 How do I monitor and collect
data to demonstrate continuous
compliance?
(a) You must monitor and collect data
according to this section and the sitespecific monitoring plan required by
§ 63.7505(d).
(b) Except for monitor malfunctions,
associated repairs, and required quality
assurance or control activities
(including, as applicable, calibration
checks and required zero and span
adjustments), you must monitor
continuously (or collect data at all
required intervals) at all times that the
affected source is operating.
(c) You may not use data recorded
during monitoring malfunctions,
associated repairs, or required quality
assurance or control activities in data
averages and calculations used to report
emission or operating levels. You must
use all the data collected during all
other periods in assessing the operation
of the control device and associated
control system.
§ 63.7540 How do I demonstrate
continuous compliance with the emission
limits and work practice standards?
(a) You must demonstrate continuous
compliance with each emission limit,
operating limit, and work practice
standard in Tables 1 through 3 to this
subpart that applies to you according to
the methods specified in Table 8 to this
subpart and paragraphs (a)(1) through
(10) of this section.
(1) Following the date on which the
initial performance test is completed or
is required to be completed under
§§ 63.7 and 63.7510, whichever date
comes first, you must not operate above
any of the applicable maximum
operating limits or below any of the
applicable minimum operating limits
listed in Table 4 to this subpart at any
times. Operation above the established
maximum or below the established
minimum operating limits shall
constitute a deviation of established
operating limits. Operating limits must
be confirmed or reestablished during
performance tests.
(2) As specified in § 63.7550(c), you
must keep records of the type and
amount of all fuels burned in each
boiler or process heater during the
reporting period to demonstrate that all
fuel types and mixtures of fuels burned
would either result in lower emissions
of HCl and mercury, than the applicable
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emission limit for each pollutant (if you
demonstrate compliance through fuel
analysis), or result in lower fuel input
of chlorine and mercury than the
maximum values calculated during the
last performance tests (if you
demonstrate compliance through
performance stack testing).
(3) If you demonstrate compliance
with an applicable HCl emission limit
through fuel analysis and you plan to
burn a new type of fuel, you must
recalculate the HCl emission rate using
Equation 9 of § 63.7530 according to
paragraphs (a)(3)(i) through (iii) of this
section.
(i) You must determine the chlorine
concentration for any new fuel type in
units of pounds per million Btu, based
on supplier data or your own fuel
analysis, according to the provisions in
your site-specific fuel analysis plan
developed according to § 63.7521(b).
(ii) You must determine the new
mixture of fuels that will have the
highest content of chlorine.
(iii) Recalculate the HCl emission rate
from your boiler or process heater under
these new conditions using Equation 9
of § 63.7530. The recalculated HCl
emission rate must be less than the
applicable emission limit.
(4) If you demonstrate compliance
with an applicable HCl emission limit
through performance testing and you
plan to burn a new type of fuel or a new
mixture of fuels, you must recalculate
the maximum chlorine input using
Equation 5 of § 63.7530. If the results of
recalculating the maximum chlorine
input using Equation 5 of § 63.7530 are
higher than the maximum chlorine
input level established during the
previous performance test, then you
must conduct a new performance test
within 60 days of burning the new fuel
type or fuel mixture according to the
procedures in § 63.7520 to demonstrate
that the HCl emissions do not exceed
the emission limit. You must also
establish new operating limits based on
this performance test according to the
procedures in § 63.7530(c).
(5) If you demonstrate compliance
with an applicable mercury emission
limit through fuel analysis, and you
plan to burn a new type of fuel, you
must recalculate the mercury emission
rate using Equation 11 of § 63.7530
according to the procedures specified in
paragraphs (a)(7)(i) through (iii) of this
section.
(i) You must determine the mercury
concentration for any new fuel type in
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EP04JN10.012</MATH>
Where:
HCl = HCl emission rate from the boiler or
process heater in units of pounds per
million Btu.
Ci90 = 90th percentile confidence level
concentration of chlorine in fuel type, i,
in units of pounds per million Btu as
calculated according to Equation 8 of
this section.
Qi= Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest content of chlorine. If
you do not burn multiple fuel types, it
is not necessary to determine the value
of this term. Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
mixture that has the highest content of
chlorine.
1.028 = Molecular weight ratio of HCl to
chlorine.
EP04JN10.013</MATH>
i =1
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units of pounds per million Btu, based
on supplier data or your own fuel
analysis, according to the provisions in
your site-specific fuel analysis plan
developed according to § 63.7521(b).
(ii) You must determine the new
mixture of fuels that will have the
highest content of mercury.
(iii) Recalculate the mercury emission
rate from your boiler or process heater
under these new conditions using
Equation 11 of § 63.7530. The
recalculated mercury emission rate must
be less than the applicable emission
limit.
(6) If you demonstrate compliance
with an applicable mercury emission
limit through performance testing, and
you plan to burn a new type of fuel or
a new mixture of fuels, you must
recalculate the maximum mercury input
using Equation 7 of § 63.7530. If the
results of recalculating the maximum
mercury input using Equation 7 of
§ 63.7530 are higher than the maximum
mercury input level established during
the previous performance test, then you
must conduct a new performance test
within 60 days of burning the new fuel
type or fuel mixture according to the
procedures in § 63.7520 to demonstrate
that the mercury emissions do not
exceed the emission limit. You must
also establish new operating limits
based on this performance test
according to the procedures in
§ 63.7530(c).
(7) If your unit is controlled with a
fabric filter, and you demonstrate
continuous compliance using a bag leak
detection system, you must initiate
corrective action within 1 hour of a bag
leak detection system alarm and
complete corrective actions as soon as
practical, and operate and maintain the
fabric filter system such that the alarm
does not sound more than 5 percent of
the operating time during a 6-month
period. You must also keep records of
the date, time, and duration of each
alarm, the time corrective action was
initiated and completed, and a brief
description of the cause of the alarm
and the corrective action taken. You
must also record the percent of the
operating time during each 6-month
period that the alarm sounds. In
calculating this operating time
percentage, if inspection of the fabric
filter demonstrates that no corrective
action is required, no alarm time is
counted. If corrective action is required,
each alarm shall be counted as a
minimum of 1 hour. If you take longer
than 1 hour to initiate corrective action,
the alarm time shall be counted as the
actual amount of time taken to initiate
corrective action.
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(8) If you are required to install a
CEMS according to § 63.7525(a), then
you must meet the requirements in
paragraphs (a)(8)(i) through (iii) of this
section.
(i) You must continuously monitor
CO according to §§ 63.7525(a) and
63.7535.
(ii) Maintain a CO emission level
below or at your applicable CO standard
in Tables 1 or 2 to this subpart at all
times.
(iii) Keep records of CO levels
according to § 63.7555(b).
(9) The owner or operator of an
affected source using a CEMS measuring
PM emissions to meet requirements of
this subpart shall install, certify,
operate, and maintain the CEMS as
specified in paragraphs (a)(9)(i) through
(a)(9)(iv) of this section.
(i) The owner or operator shall
conduct a performance evaluation of the
CEMS according to the applicable
requirements of § 60.13 of 40 CFR,
Performance Specification 11 in
appendix B of 40 CFR part 60, and
procedure 2 in appendix F of 40 CFR
part 60.
(ii) During each PM correlation testing
run of the CEMS required by
Performance Specification 11 in
appendix B of 40 CFR part 60, PM and
O2 (or CO2) data shall be collected
concurrently (or within a 30- to 60minute period) by both the CEMS and
conducting performance tests using
Method 5 or 5B of appendix A–3 of 40
CFR part 60 or Method 17 of appendix
A–6 of 40 CFR part 60.
(iii) Quarterly accuracy
determinations and daily calibration
drift tests shall be performed in
accordance with procedure 2 in
appendix F of 40 CFR part 60. Relative
Response Audits must be performed
annually and Response Correlation
Audits must be performed every 3 years.
(iv) After December 31, 2011, within
60 days after the date of completing
each performance evaluation conducted
to demonstrate compliance with this
subpart, the owner or operator of the
affected facility must submit the test
data to EPA by successfully entering the
data electronically into EPA’s WebFIRE
database through EPA’s Central Data
Exchange. The owner or operator of an
affected facility shall enter the test data
into EPA’s data base using the
Electronic Reporting Tool (ERT) or other
compatible electronic spreadsheet.
(10) If your boiler or process heater is
in either the Gas 1 (NG/RG) or Metal
Process Furnace subcategories and have
a heat input capacity of 10 million Btu
per hour or greater, you must conduct
a tune-up of the boiler or process heater
annually to demonstrate continuous
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32059
compliance as specified in paragraphs
(a)(10)(i) through (a)(10)(vi) of this
section.
(i) Inspect the burner, and clean or
replace any components of the burner as
necessary;
(ii) Inspect the flame pattern and
make any adjustments to the burner
necessary to optimize the flame pattern
consistent with the manufacturer’s
specifications;
(iii) Inspect the system controlling the
air-to-fuel ratio, and ensure that it is
correctly calibrated and functioning
properly;
(iv) Minimize total emissions of CO
consistent with the manufacturer’s
specifications;
(v) Measure the concentration in the
effluent stream of CO in parts per
million, by volume, dry basis (ppmvd),
before and after the adjustments are
made; and
(vi) Maintain on-site and submit, if
requested by the Administrator, an
annual report containing the
information in paragraphs (a)(10)(vi)(A)
through (C) of this section,
(A) The concentrations of CO in the
effluent stream in ppmvd, and oxygen
in percent dry basis, measured before
and after the adjustments of the boiler;
(B) A description of any corrective
actions taken as a part of the
combustion adjustment; and
(C) The type and amount of fuel used
over the 12 months prior to the annual
adjustment.
(11) If your boiler or process heater
has a heat input capacity of less than 10
million Btu per hour, you must conduct
a tune-up of the boiler or process heater
biennially to demonstrate continuous
compliance as specified in paragraphs
(a)(10)(i) through (a)(10)(vi) of this
section.
(b) You must report each instance in
which you did not meet each emission
limit and operating limit in Tables 1
through 4 to this subpart that apply to
you. These instances are deviations
from the emission limits in this subpart.
These deviations must be reported
according to the requirements in
§ 63.7550.
§ 63.7541 How do I demonstrate
continuous compliance under the emission
averaging provision?
(a) Following the compliance date, the
owner or operator must demonstrate
compliance with this subpart on a
continuous basis by meeting the
requirements of paragraphs (a)(1)
through (5) of this section.
(1) For each calendar month,
demonstrate compliance with the
average weighted emissions limit for the
existing units participating in the
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emissions averaging option as
determined in § 63.7522(f) and (g);
(2) You must maintain the applicable
opacity limit according to paragraphs
(a)(2)(i) through (ii) of this section.
(i) For each existing unit participating
in the emissions averaging option that is
equipped with a dry control system and
not vented to a common stack, maintain
opacity at or below the applicable limit.
(ii) For each group of units
participating in the emissions averaging
option where each unit in the group is
equipped with a dry control system and
vented to a common stack that does not
receive emissions from nonaffected
units, maintain opacity at or below the
applicable limit at the common stack;
(3) For each existing unit participating
in the emissions averaging option that is
equipped with a wet scrubber, maintain
the 3-hour average parameter values at
or below the operating limits
established during the most recent
performance test; and
(4) For each existing unit participating
in the emissions averaging option that
has an approved alternative operating
plan, maintain the 3-hour average
parameter values at or below the
operating limits established in the most
recent performance test.
(5) For each existing unit participating
in the emissions averaging option
venting to a common stack
configuration containing affected units
from other subcategories, maintain the
appropriate operating limit for each unit
as specified in Table 4 to this subpart
that applies.
(b) Any instance where the owner or
operator fails to comply with the
continuous monitoring requirements in
paragraphs (a)(1) through (5) of this
section is a deviation.
Notification, Reports, and Records
erowe on DSK5CLS3C1PROD with PROPOSALS5
§ 63.7545 What notifications must I submit
and when?
(a) You must submit all of the
notifications in §§ 63.7(b) and (c), 63.8
(e), (f)(4) and (6), and 63.9 (b) through
(h) that apply to you by the dates
specified.
(b) As specified in § 63.9(b)(2), if you
startup your affected source before
[DATE 60 DAYS AFTER PUBLICATION
OF THE FINAL RULE IN THE FEDERAL
REGISTER], you must submit an Initial
Notification not later than 120 days after
[DATE 60 DAYS AFTER PUBLICATION
OF THE FINAL RULE IN THE FEDERAL
REGISTER].
(c) As specified in § 63.9(b)(4) and
(b)(5), if you startup your new or
reconstructed affected source on or after
[DATE 60 DAYS AFTER PUBLICATION
OF THE FINAL RULE IN THE FEDERAL
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REGISTER], you must submit an Initial
Notification not later than 15 days after
the actual date of startup of the affected
source.
(d) If you are required to conduct a
performance test you must submit a
Notification of Intent to conduct a
performance test at least 30 days before
the performance test is scheduled to
begin.
(e) If you are required to conduct an
initial compliance demonstration as
specified in § 63.7530(a), you must
submit a Notification of Compliance
Status according to § 63.9(h)(2)(ii). For
each initial compliance demonstration,
you must submit the Notification of
Compliance Status, including all
performance test results and fuel
analyses, before the close of business on
the 60th day following the completion
of the performance test and/or other
initial compliance demonstrations
according to § 63.10(d)(2). The
Notification of Compliance Status report
must contain all the information
specified in paragraphs (e)(1) through
(9) of this section, as applicable.
(1) A description of the affected
source(s) including identification of
which subcategory the source is in, the
design capacity of the source, a
description of the add-on controls used
on the source, description of the fuel(s)
burned, including whether the fuel(s)
were determined by you or EPA through
a petition process to be a non-waste
under 40 CFR 241.3, whether the fuel(s)
were processed from discarded nonhazardous secondary materials within
the meaning of 40 CFR 241.3, and
justification for the selection of fuel(s)
burned during the performance test.
(2) Summary of the results of all
performance tests (stack tests and fuel
analyses) and calculations conducted to
demonstrate initial compliance
including all established operating
limits.
(3) A summary of the CO emissions
monitoring data and the maximum CO
emission levels recorded during the
performance test to show that you have
met any applicable emission standard in
Table 1 or 2 to this subpart.
(4) Identification of whether you plan
to demonstrate compliance with each
applicable emission limit through
performance stack testing or fuel
analysis.
(5) Identification of whether you plan
to demonstrate compliance by emissions
averaging.
(6) A signed certification that you
have met all applicable emission limits
and work practice standards.
(7) If you had a deviation from any
emission limit, work practice standard,
or operating limit, you must also submit
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a description of the deviation, the
duration of the deviation, and the
corrective action taken in the
Notification of Compliance Status
report.
(f) If you operate a natural gas-fired
boiler or process heater that is subject to
this subpart, and you intend to use a
fuel other than natural gas or equivalent
to fire the affected unit, you must
submit a notification of alternative fuel
use within 48 hours of the declaration
of a period of natural gas curtailment or
supply interruption, as defined in
§ 63.7575. The notification must include
the information specified in paragraphs
(f)(1) through (5) of this section.
(1) Company name and address.
(2) Identification of the affected unit.
(3) Reason you are unable to use
natural gas or equivalent fuel, including
the date when the natural gas
curtailment was declared or the natural
gas supply interruption began.
(4) Type of alternative fuel that you
intend to use.
(5) Dates when the alternative fuel use
is expected to begin and end.
§ 63.7550
when?
What reports must I submit and
(a) You must submit each report in
Table 9 to this subpart that applies to
you.
(b) Unless the EPA Administrator has
approved a different schedule for
submission of reports under § 63.10(a),
you must submit each report by the date
in Table 9 to this subpart and according
to the requirements in paragraphs (b)(1)
through (5) of this section.
(1) The first compliance report must
cover the period beginning on the
compliance date that is specified for
your affected source in § 63.7495 and
ending on June 30 or December 31,
whichever date is the first date that
occurs at least 180 days after the
compliance date that is specified for
your source in § 63.7495.
(2) The first compliance report must
be postmarked or delivered no later than
July 31 or January 31, whichever date is
the first date following the end of the
first calendar half after the compliance
date that is specified for your source in
§ 63.7495.
(3) Each subsequent compliance
report must cover the semiannual
reporting period from January 1 through
June 30 or the semiannual reporting
period from July 1 through December
31.
(4) Each subsequent compliance
report must be postmarked or delivered
no later than July 31 or January 31,
whichever date is the first date
following the end of the semiannual
reporting period.
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(5) For each affected source that is
subject to permitting regulations
pursuant to 40 CFR part 70 or 40 CFR
part 71, and if the permitting authority
has established dates for submitting
semiannual reports pursuant to 40 CFR
70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the
first and subsequent compliance reports
according to the dates the permitting
authority has established instead of
according to the dates in paragraphs
(b)(1) through (4) of this section.
(c) The compliance report must
contain the information required in
paragraphs (c)(1) through (9) of this
section.
(1) Company name and address.
(2) Statement by a responsible official
with that official’s name, title, and
signature, certifying the truth, accuracy,
and completeness of the content of the
report.
(3) Date of report and beginning and
ending dates of the reporting period.
(4) The total fuel use by each affected
source subject to an emission limit, for
each calendar month within the
semiannual reporting period, including,
but not limited to, a description of the
fuel, whether the fuel has received a
non-waste determination by EPA or
your basis for concluding that the fuel
is not a waste, and the total fuel usage
amount with units of measure.
(5) A summary of the results of the
annual performance tests and
documentation of any operating limits
that were reestablished during this test,
if applicable. If you are conducting stack
tests once every three years consistent
with § 63.7515(b) or (c), the date of the
last three stack tests, a comparison of
the emission level you achieved in the
last three stack tests to the 90 percent
emission limit threshold required in
§ 63.7515(b) or (c), and a statement as to
whether there have been any
operational changes since the last stack
test that could increase emissions.
(6) A signed statement indicating that
you burned no new types of fuel. Or, if
you did burn a new type of fuel, you
must submit the calculation of chlorine
input, using Equation 5 of § 63.7530,
that demonstrates that your source is
still within its maximum chlorine input
level established during the previous
performance testing (for sources that
demonstrate compliance through
performance testing) or you must submit
the calculation of HCl emission rate
using Equation 9 of § 63.7530 that
demonstrates that your source is still
meeting the emission limit for HCl
emissions (for boilers or process heaters
that demonstrate compliance through
fuel analysis). If you burned a new type
of fuel, you must submit the calculation
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of mercury input, using Equation 7 of
§ 63.7530, that demonstrates that your
source is still within its maximum
mercury input level established during
the previous performance testing (for
sources that demonstrate compliance
through performance testing), or you
must submit the calculation of mercury
emission rate using Equation 11 of
§ 63.7530 that demonstrates that your
source is still meeting the emission limit
for mercury emissions (for boilers or
process heaters that demonstrate
compliance through fuel analysis).
(7) If you wish to burn a new type of
fuel and you cannot demonstrate
compliance with the maximum chlorine
input operating limit using Equation 5
of § 63.7530 or the maximum mercury
input operating limit using Equation 7
of § 63.7530, you must include in the
compliance report a statement
indicating the intent to conduct a new
performance test within 60 days of
starting to burn the new fuel.
(8) If there are no deviations from any
emission limits or operating limits in
this subpart that apply to you, a
statement that there were no deviations
from the emission limits or operating
limits during the reporting period.
(9) If there were no deviations from
the monitoring requirements including
no periods during which the CMSs,
including CEMS, COMS, and CPMS,
were out of control as specified in
§ 63.8(c)(7), a statement that there were
no deviations and no periods during
which the CMS were out of control
during the reporting period.
(d) For each deviation from an
emission limit or operating limit in this
subpart that occurs at an affected source
where you are not using a CMS to
comply with that emission limit or
operating limit, the compliance report
must additionally contain the
information required in paragraphs
(d)(1) through (4) of this section.
(1) The total operating time of each
affected source during the reporting
period.
(2) A description of the deviation and
which emission limit or operating limit
from which you deviated.
(3) Information on the number,
duration, and cause of deviations
(including unknown cause), as
applicable, and the corrective action
taken.
(4) A copy of the test report if the
annual performance test showed a
deviation from the emission limits.
(e) For each deviation from an
emission limit, operating limit, and
monitoring requirement in this subpart
occurring at an affected source where
you are using a CMS to comply with
that emission limit or operating limit,
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you must include the information
required in paragraphs (e) (1) through
(12) of this section. This includes any
deviations from your site-specific
monitoring plan as required in
§ 63.7505(d).
(1) The date and time that each
deviation started and stopped and
description of the nature of the
deviation (i.e., what you deviated from).
(2) The date and time that each CMS
was inoperative, except for zero (lowlevel) and high-level checks.
(3) The date, time, and duration that
each CMS was out of control, including
the information in § 63.8(c)(8).
(4) The date and time that each
deviation started and stopped, and
whether each deviation occurred during
a period of startup, shutdown, or
malfunction or during another period.
(5) A summary of the total duration of
the deviation during the reporting
period and the total duration as a
percent of the total source operating
time during that reporting period.
(6) An analysis of the total duration of
the deviations during the reporting
period into those that are due to startup,
shutdown, control equipment problems,
process problems, other known causes,
and other unknown causes.
(7) A summary of the total duration of
CMSs downtime during the reporting
period and the total duration of CMS
downtime as a percent of the total
source operating time during that
reporting period.
(8) An identification of each
parameter that was monitored at the
affected source for which there was a
deviation.
(9) A brief description of the source
for which there was a deviation.
(10) A brief description of each CMS
for which there was a deviation.
(11) The date of the latest CMS
certification or audit for the system for
which there was a deviation.
(12) A description of any changes in
CMSs, processes, or controls since the
last reporting period for the source for
which there was a deviation.
(f) Each affected source that has
obtained a title V operating permit
pursuant to 40 CFR part 70 or 40 CFR
part 71 must report all deviations as
defined in this subpart in the
semiannual monitoring report required
by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A). If an affected source
submits a compliance report pursuant to
Table 9 to this subpart along with, or as
part of, the semiannual monitoring
report required by 40 CFR
70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), and the compliance
report includes all required information
concerning deviations from any
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emission limit, operating limit, or work
practice requirement in this subpart,
submission of the compliance report
satisfies any obligation to report the
same deviations in the semiannual
monitoring report. However, submission
of a compliance report does not
otherwise affect any obligation the
affected source may have to report
deviations from permit requirements to
the permit authority.
(g) In addition to the information
required in § 63.9(h)(2), your
notification must include the following
certification(s) of compliance, as
applicable, and signed by a responsible
official:
(1) ‘‘This facility complies with the
requirements in § 63.7540(a)(10) to
conduct an annual tune-up of the unit’’.
(2) ‘‘This facility has had an energy
assessment performed according to
§ 63.7530(e).’’
(3) ‘‘No secondary materials that are
solid waste were combusted in any
affected unit.’’
(h) After December 31, 2011, within
60 days after the date of completing
each performance evaluation conducted
to demonstrate compliance with this
subpart, the owner or operator of the
affected facility must submit the test
data to EPA by entering the data
electronically into EPA’s WebFIRE data
base through EPA’s Central Data
Exchange. The owner or operator of an
affected facility shall enter the test data
into EPA’s data base using the
Electronic Reporting Tool or other
compatible electronic spreadsheet. Only
performance evaluation data collected
using methods compatible with ERT are
subject to this requirement to be
submitted electronically into EPA’s
WebFIRE database.
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§ 63.7555
What records must I keep?
(a) You must keep records according
to paragraphs (a)(1) and (2) of this
section.
(1) A copy of each notification and
report that you submitted to comply
with this subpart, including all
documentation supporting any Initial
Notification or Notification of
Compliance Status or semiannual
compliance report that you submitted,
according to the requirements in
§ 63.10(b)(2)(xiv).
(2) Records of performance stack tests,
fuel analyses, or other compliance
demonstrations, performance
evaluations, and opacity observations as
required in § 63.10(b)(2)(viii).
(b) For each CEMS, CPMS, and
COMS, you must keep records
according to paragraphs (b)(1) through
(5) of this section.
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(1) Records described in
§ 63.10(b)(2)(vi) through (xi).
(2) Monitoring data for continuous
opacity monitoring system during a
performance evaluation as required in
§ 63.6(h)(7)(i) and (ii).
(3) Previous (i.e., superseded)
versions of the performance evaluation
plan as required in § 63.8(d)(3).
(4) Request for alternatives to relative
accuracy test for CEMS as required in
§ 63.8(f)(6)(i).
(5) Records of the date and time that
each deviation started and stopped, and
whether the deviation occurred during a
period of startup, shutdown, or
malfunction or during another period.
(c) You must keep the records
required in Table 8 to this subpart
including records of all monitoring data
and calculated averages for applicable
operating limits such as opacity,
pressure drop, and pH to show
continuous compliance with each
emission limit and operating limit that
applies to you.
(d) For each boiler or process heater
subject to an emission limit, you must
also keep the records in paragraphs
(d)(1) through (5) of this section.
(1) You must keep records of monthly
fuel use by each boiler or process heater,
including the type(s) of fuel and
amount(s) used.
(2) If you combust non-hazardous
secondary materials that have been
determined not to be solid waste
pursuant to 40 CFR 41.3(b)(1), you must
keep a record which documents how the
secondary material meets each of the
legitimacy criteria. If you combust a fuel
that has been processed from a
discarded non-hazardous secondary
material pursuant to 40 CFR 241.3(b)(2),
you must keep records as to how the
operations that produced the fuel
satisfies the definition of processing in
40 CFR 241.2. If the fuel received a nonwaste determination pursuant to the
petition process submitted under 40
CFR 241.3(c), you must keep a record
which documents how the fuel satisfies
the requirements of the petition process.
(3) You must keep records of monthly
hours of operation by each boiler or
process heater. This requirement applies
only to limited-use boilers and process
heaters.
(4) A copy of all calculations and
supporting documentation of maximum
chlorine fuel input, using Equation 5 of
§ 63.7530, that were done to
demonstrate continuous compliance
with the HCl emission limit, for sources
that demonstrate compliance through
performance testing. For sources that
demonstrate compliance through fuel
analysis, a copy of all calculations and
supporting documentation of HCl
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emission rates, using Equation 9 of
§ 63.7530, that were done to
demonstrate compliance with the HCl
emission limit. Supporting
documentation should include results of
any fuel analyses and basis for the
estimates of maximum chlorine fuel
input or HCl emission rates. You can
use the results from one fuel analysis for
multiple boilers and process heaters
provided they are all burning the same
fuel type. However, you must calculate
chlorine fuel input, or HCl emission
rate, for each boiler and process heater.
(5) A copy of all calculations and
supporting documentation of maximum
mercury fuel input, using Equation 7 of
§ 63.7530, that were done to
demonstrate continuous compliance
with the mercury emission limit for
sources that demonstrate compliance
through performance testing. For
sources that demonstrate compliance
through fuel analysis, a copy of all
calculations and supporting
documentation of mercury emission
rates, using Equation 11 of § 63.7530,
that were done to demonstrate
compliance with the mercury emission
limit. Supporting documentation should
include results of any fuel analyses and
basis for the estimates of maximum
mercury fuel input or mercury emission
rates. You can use the results from one
fuel analysis for multiple boilers and
process heaters provided they are all
burning the same fuel type. However,
you must calculate mercury fuel input,
or mercury emission rates, for each
boiler and process heater.
(6) If consistent with § 63.7555(b) and
(c), you choose to stack test less
frequently than annually, you must keep
annual records that document that your
emissions in the previous stack test(s)
were less than 90 percent of the
applicable emission limit, and
document that there was no change in
source operations including fuel
composition and operation of air
pollution control equipment that would
cause emissions of the relevant
pollutant to increase within the past
year.
(7) If you operate a gaseous fuel unit
that is subject to the emission limits
specified in Table 1 or 2 to this subpart,
and you intend to use a fuel other than
natural gas or equivalent to fire the
affected unit, you must keep records of
the information required by the
notification under § 63.7550, and
records of the total hours per calendar
year that liquid fuel is burned.
(e) If you elect to average emissions
consistent with § 63.7522, you must
additionally keep a copy of the emission
averaging implementation plan required
in § 63.7522(g), all calculations required
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under § 63.7522, including daily records
of heat input or steam generation, as
applicable, and monitoring records
consistent with § 63.7541.
§ 63.7560 In what form and how long must
I keep my records?
(a) Your records must be in a form
suitable and readily available for
expeditious review, according to
§ 63.10(b)(1).
(b) As specified in § 63.10(b)(1), you
must keep each record for 5 years
following the date of each occurrence,
measurement, maintenance, corrective
action, report, or record.
(c) You must keep each record on site
for at least 2 years after the date of each
occurrence, measurement, maintenance,
corrective action, report, or record,
according to § 63.10(b)(1). You can keep
the records off site for the remaining 3
years.
Other Requirements and Information
§ 63.7565 What parts of the General
Provisions apply to me?
Table 10 to this subpart shows which
parts of the General Provisions in
§§ 63.1 through 63.15 apply to you.
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§ 63.7570 Who implements and enforces
this subpart?
(a) This subpart can be implemented
and enforced by U.S. EPA, or a
delegated authority such as your State,
local, or tribal agency. If the EPA
Administrator has delegated authority to
your State, local, or tribal agency, then
that agency (as well as the U.S. EPA) has
the authority to implement and enforce
this subpart. You should contact your
EPA Regional Office to find out if this
subpart is delegated to your State, local,
or tribal agency.
(b) In delegating implementation and
enforcement authority of this subpart to
a State, local, or tribal agency under 40
CFR part 63, subpart E, the authorities
listed in paragraphs (b)(1) through (5) of
this section are retained by the EPA
Administrator and are not transferred to
the State, local, or tribal agency,
however, the U.S. EPA retains oversight
of this subpart and can take enforcement
actions, as appropriate.
(1) Approval of alternatives to the
non-opacity emission limits and work
practice standards in § 63.7500(a) and
(b) under § 63.6(g).
(2) Approval of alternative opacity
emission limits in § 63.7500(a) under
§ 63.6(h)(9).
(3) Approval of major change to test
methods in Table 5 to this subpart
under § 63.7(e)(2)(ii) and (f) and as
defined in § 63.90, and alternative
analytical methods requested under
63.7521(b)(2).
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(4) Approval of major change to
monitoring under § 63.8(f) and as
defined in § 63.90, and approval of
alternative operating parameters under
63.7500(a)(2) and 63.7522(g)(2).
(5) Approval of major change to
recordkeeping and reporting under
§ 63.10(e) and as defined in § 63.90.
§ 63.7575
subpart?
What definitions apply to this
Terms used in this subpart are
defined in the Clean Air Act (CAA), in
§ 63.2 (the General Provisions), and in
this section as follows:
Bag leak detection system means a
group of instruments that are capable of
monitoring particulate matter loadings
in the exhaust of a fabric filter (i.e.,
baghouse) in order to detect bag failures.
A bag leak detection system includes,
but is not limited to, an instrument that
operates on electrodynamic,
triboelectric, light scattering, light
transmittance, or other principle to
monitor relative particulate matter
loadings.
Biomass fuel means but is not limited
to, wood residue, and wood products
(e.g., trees, tree stumps, tree limbs, bark,
lumber, sawdust, sanderdust, chips,
scraps, slabs, millings, and shavings);
animal manure, including litter and
other bedding materials; vegetative
agricultural and silvicultural materials,
such as logging residues (slash), nut and
grain hulls and chaff (e.g., almond,
walnut, peanut, rice, and wheat),
bagasse, orchard prunings, corn stalks,
coffee bean hulls and grounds. This
definition of biomass fuel is not
intended to suggest that these materials
are or are not solid waste.
Blast furnace gas fuel-fired boiler or
process heater means an industrial/
commercial/institutional boiler or
process heater that receives 90 percent
or more of its total heat input (based on
an annual average) from blast furnace
gas.
Boiler means an enclosed device
using controlled flame combustion and
having the primary purpose of
recovering thermal energy in the form of
steam or hot water. A device
combusting solid waste, as defined in 40
CFR 241.3, is not a boiler. Waste heat
boilers are excluded from this
definition.
Boiler system means the boiler and
associated components, such as, the
feedwater system, the combustion air
system, the fuel system (including
burners), blowdown system, combustion
control system, and energy consuming
systems.
Coal means all solid fuels classifiable
as anthracite, bituminous, subbituminous, or lignite by the American
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Society for Testing and Materials in
ASTM D388–991.1, ‘‘Standard
Specification for Classification of Coals
by Rank’’ 1 (incorporated by reference,
see § 63.14(b)), coal refuse, and
petroleum coke. Synthetic fuels derived
from coal for the purpose of creating
useful heat including, but not limited to,
solvent-refined coal, coal-oil mixtures,
and coal-water mixtures, for the
purposes of this subpart. Coal derived
gases are excluded from this definition.
Coal refuse means any by-product of
coal mining or coal cleaning operations
with an ash content greater than 50
percent (by weight) and a heating value
less than 13,900 kilojoules per kilogram
(6,000 Btu per pound) on a dry basis.
Commercial/institutional boiler
means a boiler used in commercial
establishments or institutional
establishments such as medical centers,
research centers, institutions of higher
education, hotels, and laundries to
provide electricity, steam, and/or hot
water.
Common stack means the exhaust of
emissions from two or more affected
units through a single flue.
Cost-effective energy conservation
measure means a measure that is
implemented to improve the energy
efficiency of the boiler or facility that
has a payback (return of investment)
period of two years or less.
Deviation. (1) Deviation means any
instance in which an affected source
subject to this subpart, or an owner or
operator of such a source:
(i) Fails to meet any requirement or
obligation established by this subpart
including, but not limited to, any
emission limit, operating limit, or work
practice standard; or
(ii) Fails to meet any term or
condition that is adopted to implement
an applicable requirement in this
subpart and that is included in the
operating permit for any affected source
required to obtain such a permit.
(2) A deviation is not always a
violation. The determination of whether
a deviation constitutes a violation of the
standard is up to the discretion of the
entity responsible for enforcement of the
standards.
Distillate oil means fuel oils,
including recycled oils, that comply
with the specifications for fuel oil
numbers 1 and 2, as defined by the
American Society for Testing and
Materials in ASTM D396–02a,
‘‘Standard Specifications for Fuel
Oils’’ 1 (incorporated by reference, see
§ 63.14(b)).
Dry scrubber means an add-on air
pollution control system that injects dry
alkaline sorbent (dry injection) or sprays
an alkaline sorbent (spray dryer) to react
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with and neutralize acid gas in the
exhaust stream forming a dry powder
material. Sorbent injection systems in
fluidized bed boilers and process
heaters are included in this definition.
Dutch oven means a unit having a
refractory-walled cell connected to a
conventional boiler setting. Fuel
materials are introduced through an
opening in the roof of the Dutch oven
and burn in a pile on its floor.
Electric utility steam generating unit
means a fossil fuel-fired combustion
unit of more than 25 megawatts that
serves a generator that produces
electricity for sale. A fossil fuel-fired
unit that cogenerates steam and
electricity and supplies more than onethird of its potential electric output
capacity and more than 25 megawatts
electrical output to any utility power
distribution system for sale is
considered an electric utility steam
generating unit.
Electrostatic precipitator means an
add-on air pollution control device used
to capture particulate matter by charging
the particles using an electrostatic field,
collecting the particles using a grounded
collecting surface, and transporting the
particles into a hopper.
Energy assessment means an in-depth
assessment of a facility to identify
immediate and long-term opportunities
to save energy, focusing on the steam
and process heating systems which
involves a thorough examination of
potential savings from energy efficiency
improvements, waste minimization and
pollution prevention, and productivity
improvement.
Equivalent means the following only
as this term is used in Table 6 to subpart
DDDDD:
(1) An equivalent sample collection
procedure means a published voluntary
consensus standard or practice (VCS) or
EPA method that includes collection of
a minimum of three composite fuel
samples, with each composite
consisting of a minimum of three
increments collected at approximately
equal intervals over the test period.
(2) An equivalent sample compositing
procedure means a published VCS or
EPA method to systematically mix and
obtain a representative subsample (part)
of the composite sample.
(3) An equivalent sample preparation
procedure means a published VCS or
EPA method that: Clearly states that the
standard, practice or method is
appropriate for the pollutant and the
fuel matrix; or is cited as an appropriate
sample preparation standard, practice or
method for the pollutant in the chosen
VCS or EPA determinative or analytical
method.
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(4) An equivalent procedure for
determining heat content means a
published VCS or EPA method to obtain
gross calorific (or higher heating) value.
(5) An equivalent procedure for
determining fuel moisture content
means a published VCS or EPA method
to obtain moisture content. If the sample
analysis plan calls for determining
metals (especially the mercury,
selenium, or arsenic) using an aliquot of
the dried sample, then the drying
temperature must be modified to
prevent vaporizing these metals. On the
other hand, if metals analysis is done on
an ‘‘as received’’ basis, a separate aliquot
can be dried to determine moisture
content and the metals concentration
mathematically adjusted to a dry basis.
(6) An equivalent pollutant (mercury)
determinative or analytical procedure
means a published VCS or EPA method
that clearly states that the standard,
practice, or method is appropriate for
the pollutant and the fuel matrix and
has a published detection limit equal to
or lower than the methods listed in
Table 6 to subpart DDDDD for the same
purpose.
Fabric filter means an add-on air
pollution control device used to capture
particulate matter by filtering gas
streams through filter media, also
known as a baghouse.
Federally enforceable means all
limitations and conditions that are
enforceable by the EPA Administrator,
including the requirements of 40 CFR
parts 60 and 61, requirements within
any applicable State implementation
plan, and any permit requirements
established under 40 CFR 52.21 or
under 40 CFR 51.18 and 40 CFR 51.24.
Fuel type means each category of fuels
that share a common name or
classification. Examples include, but are
not limited to, bituminous coal,
subbituminous coal, lignite, anthracite,
biomass, residual oil. Individual fuel
types received from different suppliers
are not considered new fuel types.
Fluidized bed boiler means a boiler
utilizing a fluidized bed combustion
process.
Fluidized bed combustion means a
process where a fuel is burned in a bed
of granulated particles which are
maintained in a mobile suspension by
the forward flow of air and combustion
products.
Fuel cell means a boiler type in which
the fuel is dropped onto suspended
fixed grates and is fired in a pile. The
refractory-lined fuel cell uses
combustion air preheating and
positioning of secondary and tertiary air
injection ports to improve boiler
efficiency.
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Gaseous fuel includes, but is not
limited to, natural gas, process gas,
landfill gas, coal derived gas, refinery
gas, and biogas. Blast furnace gas is
exempted from this definition.
Heat input means heat derived from
combustion of fuel in a boiler or process
heater and does not include the heat
input from preheated combustion air,
recirculated flue gases, or exhaust gases
from other sources such as gas turbines,
internal combustion engines, kilns, etc.
Hot water heater means a closed
vessel with a capacity of no more than
120 U.S. gallons in which water is
heated by combustion of gaseous or
liquid fuel and is withdrawn for use
external to the vessel at pressures not
exceeding 160 psig, including the
apparatus by which the heat is
generated and all controls and devices
necessary to prevent water temperatures
from exceeding 210 ° F (99 ° C).
Industrial boiler means a boiler used
in manufacturing, processing, mining,
and refining or any other industry to
provide steam, hot water, and/or
electricity.
Liquid fuel includes, but is not
limited to, distillate oil, residual oil, onspec used oil, and biodiesel.
Liquid fuel subcategory includes any
boiler or process heater of any design
that burns more than 10 percent liquid
fuel and less than 10 percent solid fuel,
on an annual heat input basis.
Metal process furnaces include
natural gas-fired annealing furnaces,
preheat furnaces, reheat furnaces, aging
furnaces, and heat treat furnaces.
Minimum pressure drop means 90
percent of the test average pressure drop
measured according to Table 7 to this
subpart during the most recent
performance test demonstrating
compliance with the applicable
emission limit.
Minimum scrubber effluent pH means
90 percent of the test average effluent
pH measured at the outlet of the wet
scrubber according to Table 7 to this
subpart during the most recent
performance test demonstrating
compliance with the applicable
hydrogen chloride emission limit.
Minimum scrubber flow rate means 90
percent of the test average flow rate
measured according to Table 7 to this
subpart during the most recent
performance test demonstrating
compliance with the applicable
emission limit.
Minimum sorbent injection rate
means 90 percent of the test average
sorbent (or activated carbon) injection
rate for each sorbent measured
according to Table 7 to this subpart
during the most recent performance test
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demonstrating compliance with the
applicable emission limits.
Minimum voltage or amperage means
90 percent of the test average voltage or
amperage to the electrostatic
precipitator measured according to
Table 7 to this subpart during the most
recent performance test demonstrating
compliance with the applicable
emission limits.
Natural gas means:
(1) A naturally occurring mixture of
hydrocarbon and nonhydrocarbon gases
found in geologic formations beneath
the earth’s surface, of which the
principal constituent is methane; or
(2) Liquid petroleum gas, as defined
by the American Society for Testing and
Materials in ASTM D1835–03a,
‘‘Standard Specification for Liquid
Petroleum Gases’’ (incorporated by
reference, see § 63.14(b)).
Opacity means the degree to which
emissions reduce the transmission of
light and obscure the view of an object
in the background.
Particulate matter means any finely
divided solid or liquid material, other
than uncombined water, as measured by
the test methods specified under this
subpart, or an alternative method.
Period of natural gas curtailment or
supply interruption means a period of
time during which the supply of natural
gas to an affected facility is halted for
reasons beyond the control of the
facility. An increase in the cost or unit
price of natural gas does not constitute
a period of natural gas curtailment or
supply interruption.
Process heater means an enclosed
device using controlled flame, that is
not a boiler, and the unit’s primary
purpose is to transfer heat indirectly to
a process material (liquid, gas, or solid)
or to a heat transfer material for use in
a process unit, instead of generating
steam. Process heaters are devices in
which the combustion gases do not
directly come into contact with process
materials. A device combusting solid
waste, as defined in 40 CFR 241.3, is not
a process heater. Process heaters do not
include units used for comfort heat or
space heat, food preparation for on-site
consumption, or autoclaves.
Pulverized coal boiler means a boiler
in which pulverized coal is introduced
into an air stream that carries the coal
to the combustion chamber of the boiler
where it is fired in suspension.
Qualified personnel means specialists
in evaluating energy systems, such as
those who have successfully completed
the DOE Qualified Specialist program
for all systems, Certified Energy
Manager certified by the Association of
Energy Engineers, or the equivalent.
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Residual oil means crude oil, and all
fuel oil numbers 4, 5 and 6, as defined
by the American Society for Testing and
Materials in ASTM D396–02a,
‘‘Standard Specifications for Fuel Oils 1’’
(incorporated by reference, see
§ 63.14(b)).
Responsible official means
responsible official as defined in 40 CFR
70.2.
Stoker means a unit consisting of a
mechanically operated fuel feeding
mechanism, a stationary or moving grate
to support the burning of fuel and admit
undergrate air to the fuel, an overfire air
system to complete combustion, and an
ash discharge system. There are two
general types of stokers: Underfeed and
overfeed. Overfeed stokers include mass
feed and spreader stokers.
Suspension boiler means a unit
designed to feed the fuel by means of
fuel distributors. The distributors inject
air at the point where the fuel is
introduced into the boiler in order to
spread the fuel material over the boiler
width. The drying (and much of the
combustion) occurs while the material
is suspended in air. The combustion of
the fuel material is completed on a grate
or floor below. Suspension boilers
almost universally are designed to have
high heat release rates to quickly dry the
wet fuel as it is blown into the boilers.
Temporary boiler means any gaseous
or liquid fuel boiler that is designed to,
and is capable of, being carried or
moved from one location to another. A
temporary boiler that remains at a
location for more than 180 consecutive
days is no longer considered to be a
temporary boiler. Any temporary boiler
that replaces a temporary boiler at a
location and is intended to perform the
same or similar function will be
included in calculating the consecutive
time period.
Tune-up means adjustments made to
a boiler in accordance with procedures
supplied by the manufacturer (or an
approved specialist) to optimize the
combustion efficiency.
Unit designed to burn biomass
subcategory includes any boiler or
process heater that burns at least 10
percent biomass, but less than 10
percent coal, on a heat input basis on an
annual average, either alone or in
combination with liquid fuels or
gaseous fuels.
Unit designed to burn coal
subcategory includes any boiler or
process heater that burns any coal alone
or at least 10 percent coal on a heat
input basis on an annual average in
combination with biomass, liquid fuels,
or gaseous fuels.
Unit designed to burn gas 1 (NG/RG)
subcategory includes any boiler or
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process heater that burns at least 90
percent natural gas and/or refinery gas
on a heat input basis on an annual
average.
Unit designed to burn gas 2 (other)
subcategory includes any boiler or
process heater that burns gaseous fuels
other than natural gas and/or refinery
gas not combined with any solid or
liquid fuels.
Unit designed to burn oil subcategory
includes any boiler or process heater
that burns any liquid fuel, but less than
10 percent solid fuel on a heat input
basis on an annual average, either alone
or in combination with gaseous fuels.
Gaseous fuel boilers and process heaters
that burn liquid fuel during periods of
gas curtailment, gas supply emergencies
or for periodic testing of liquid fuel not
to exceed a combined total of 48 hours
during any calendar year are not
included in this definition.
Voluntary Consensus Standards or
VCS mean technical standards (e.g.,
materials specifications, test methods,
sampling procedures, business
practices) developed or adopted by one
or more voluntary consensus bodies.
EPA/OAQPS has by precedent only
used VCS that are written in English.
Examples of VCS bodies are: American
Society of Testing and Materials
(ASTM), American Society of
Mechanical Engineers (ASME),
International Standards Organization
(ISO), Standards Australia (AS), British
Standards (BS), Canadian Standards
(CSA), European Standard (EN or CEN)
and German Engineering Standards
(VDI). The types of standards that are
not considered VCS are standards
developed by: The U.S. states, e.g.,
California (CARB) and Texas (TCEQ);
industry groups, such as American
Petroleum Institute (API), Gas
Processors Association (GPA), and Gas
Research Institute (GRI); and other
branches of the U.S. government, e.g.,
Department of Defense (DOD) and
Department of Transportation (DOT).
This does not preclude EPA from using
standards developed by groups that are
not VCS bodies within their rule. When
this occurs, EPA has done searches and
reviews for VCS equivalent to these
non-EPA methods.
Waste heat boiler means a device that
recovers normally unused energy and
converts it to usable heat. Waste heat
recovery boilers incorporating duct or
supplemental burners that are designed
to supply 50 percent or more of the total
rated heat input capacity of the waste
heat boiler are not considered waste
heat boilers, but are considered boilers.
Waste heat boilers are also referred to as
heat recovery steam generators.
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Waste heat process heater means an
enclosed device that recovers normally
unused energy and converts it to usable
heat. Waste heat process heaters
incorporating duct or supplemental
burners that are designed to supply 50
percent or more of the total rated heat
input capacity of the waste heat process
heater are not considered waste heat
process heaters, but are considered
process heaters. Waste heat process
heaters are also referred to as
recuperative process heaters.
Wet scrubber means any add-on air
pollution control device that mixes an
aqueous stream or slurry with the
exhaust gases from a boiler or process
heater to control emissions of
particulate matter and/or to absorb and
neutralize acid gases, such as hydrogen
chloride.
Work practice standard means any
design, equipment, work practice, or
operational standard, or combination
thereof, that is promulgated pursuant to
section 112(h) of the CAA.
Tables to Subpart DDDDD of Part 63
As stated in § 63.7500, you must
comply with the following applicable
emission limits:
TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
You must meet the following emission limits and work practice
standards . . .
1. Pulverized coal ............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
0.001 lb per MMBtu of heat input.
0.00006 lb per MMBtu of heat input.
2.0E–06 lb per MMBtu of heat input.
90 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.001 lb per MMBtu of heat input.
0.00006 lb per MMBtu of heat input.
2.0E–06 lb per MMBtu of heat input.
7 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.001 lb per MMBtu of heat input.
0.00006 lb per MMBtu of heat input.
2.0E–06 lb per MMBtu of heat input.
30 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.00003 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.008 lb per MMBtu of heat input.
0.004 lb per MMBtu of heat input.
2.0E–07 lb per MMBtu of heat input.
560 ppm by volume on a dry basis corrected to 3 percent oxygen
(30-day rolling average for units 100 MMBtu/hr or greater, 3-run
average for units less than 100 MMBtu/hr).
0.00005 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.008 lb per MMBtu of heat input.
0.004 lb per MMBtu of heat input.
2.0E–07 lb per MMBtu of heat input.
40 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.007 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.008 lb per MMBtu of heat input.
0.004 lb per MMBtu of heat input.
2.0E–07 lb per MMBtu of heat input.
1,010 ppm by volume on a dry basis corrected to 3 percent oxygen
(30-day rolling average for units 100 MMBtu/hr or greater, 3-run
average for units less than 100 MMBtu/hr).
0.03 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.008 lb per MMBtu of heat input.
0.004 lb per MMBtu of heat input.
2.0E–07 lb per MMBtu of heat input.
270 ppm by volume on a dry basis corrected to 3 percent oxygen
(30-day rolling average for units 100 MMBtu/hr or greater, 3-run
average for units less than 100 MMBtu/hr).
0.0005 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.002 lb per MMBtu of heat input.
0.0004 lb per MMBtu of heat input.
3.0E–07 lb per MMBtu of heat input.
1 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.
2. Stokers designed to burn coal ....
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
3. Fluidized bed units designed to
burn coal.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
4. Stokers designed to burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
5. Fluidized bed units designed to
burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
Suspension
burners/Dutch
Ovens designed to burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
7. Fuel cells designed to burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
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6.
8. Units designed to burn liquid fuel
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
e. Dioxin/Furan ..............................
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TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS—Continued
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
You must meet the following emission limits and work practice
standards . . .
9. Units designed to burn other
gases.
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
0.003 lb per MMBtu of heat input.
3.0E–06 lb per MMBtu of heat input.
2.0E–07 lb per MMBtu of heat input.
1 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.009 ng/dscm (TEQ) corrected to 7 percent oxygen.
e. Dioxin/Furan ..............................
As stated in § 63.7500, you must
comply with the following applicable
emission limits:
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS
[Units with heat input capacity of 10 million Btu per hour or greater]
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
You must meet the following emission limits and work practice
standards . . .
1. Pulverized coal ............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
0.02 lb per MMBtu of heat input.
0.02 lb per MMBtu of heat input.
3.0E–06 lb per MMBtu of heat input.
90 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.004 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.02 lb per MMBtu of heat input.
0.02 lb per MMBtu of heat input.
3.0E–06 lb per MMBtu of heat input.
50 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.003 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.02 lb per MMBtu of heat input.
0.02 lb per MMBtu of heat input.
3.0E–06 lb per MMBtu of heat input.
30 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.02 lb per MMBtu of heat input.
0.006 lb per MMBtu of heat input.
9.0E–07 lb per MMBtu of heat input.
560 ppm by volume on a dry basis corrected to 3 percent oxygen
(30-day rolling average for units 100 MMBtu/hr or greater, 3-run
average for units less than 100 MMBtu/hr).
0.004 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.02 lb per MMBtu of heat input.
0.006 lb per MMBtu of heat input.
9.0E–07 lb per MMBtu of heat input.
250 ppm by volume on a dry basis corrected to 3 percent oxygen
(30-day rolling average for units 100 MMBtu/hr or greater, 3-run
average for units less than 100 MMBtu/hr).
0.02 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.02 lb per MMBtu of heat input.
0.006 lb per MMBtu of heat input.
9.0E–07 lb per MMBtu of heat input.
1,010 ppm by volume on a dry basis corrected to 3 percent oxygen
(30-day rolling average for units 100 MMBtu/hr or greater, 3-run
average for units less than 100 MMBtu/hr).
0.03 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.02 lb per MMBtu of heat input.
0.006 lb per MMBtu of heat input.
9.0E–07 lb per MMBtu of heat input.
270 ppm by volume on a dry basis corrected to 3 percent oxygen
(30-day rolling average for units 100 MMBtu/hr or greater, 3-run
average for units less than 100 MMBtu/hr).
0.02 ng/dscm (TEQ) corrected to 7 percent oxygen.
2. Stokers designed to burn coal ....
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
3. Fluidized bed units designed to
burn coal.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
4. Stokers designed to burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
5. Fluidized bed units designed to
burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
Suspension
burners/Dutch
Ovens designed to burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
7. Fuel cells designed to burn biomass.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
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e. Dioxin/Furan ..............................
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TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS—
Continued
[Units with heat input capacity of 10 million Btu per hour or greater]
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
You must meet the following emission limits and work practice
standards . . .
8. Units designed to burn liquid fuel
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
0.004 lb per MMBtu of heat input.
0.0009 lb per MMBtu of heat input.
4.0E–06 lb per MMBtu of heat input.
1 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.002 ng/dscm (TEQ) corrected to 7 percent oxygen.
0.05 lb per MMBtu of heat input.
3.0E–06 lb per MMBtu of heat input.
2.0E–07 lb per MMBtu of heat input.
1 ppm by volume on a dry basis corrected to 3 percent oxygen (30day rolling average for units 100 MMBtu/hr or greater, 3-run average for units less than 100 MMBtu/hr).
0.009 ng/dscm (TEQ) corrected to 7 percent oxygen.
9. Units designed to burn other
gases.
e. Dioxin/Furan ..............................
a. Particulate Matter ......................
b. Hydrogen Chloride ....................
c. Mercury ......................................
d. CO .............................................
e. Dioxin/Furan ..............................
As stated in §§ 63.11202 and
63.11203, you must comply with the
following applicable work practice
standards:
TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS
If your boiler is . . .
You must meet the following . . .
1. An existing boiler or process heater with heat
input capacity of less than 10 million Btu per
hour.
2. A new or existing boiler or process heater in
either the Gas 1 or Metal Process Furnace
subcategory with heat input capacity of 10
million Btu per hour or greater.
3. An existing boiler located at a major source
facility.
Conduct a tune-up of the boiler biennially as specified in § 63.7540.
Conduct a tune-up of the boiler annually as specified in § 63.7540.
Must have an energy assessment performed on the major source facility by qualified personnel which includes:
(a) a visual inspection of the boiler system.
(b) establish operating characteristics of the facility, energy system specifications, operating and maintenance procedures, and unusual operating constraints,
(c) identify major energy consuming systems,
(d) a review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage,
(e) a list of major energy conservation measures,
(f) the energy savings potential of the energy conservation measures identified, and
(g) a comprehensive report detailing the ways to improve efficiency, the cost of specific
improvements, benefits, and the time frame for recouping those investments, and
(h) a facility energy management program developed according to the ENERGY STAR
guideline for energy management.
As stated in § 63.7500, you must
comply with the applicable operating
limits:
TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS
You must meet these operating limits . . .
1. Wet scrubber control ......................................
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If you demonstrate compliance using . . .
a. Maintain the minimum pressure drop and liquid flow-rate at or above the operating levels
established during the performance test according to § 63.7530(c) and Table 7 to this subpart.
a. Install and operate a bag leak detection system according to § 63.7525 and operate the fabric filter such that the bag leak detection system alarm does not sound more than 5 percent
of the operating time during each 6-month period; or
b. This option is for boilers and process heaters that operate dry control systems. Existing and
new boilers and process heaters must maintain opacity to less than or equal to 10 percent
(daily block average).
a. This option is for boilers and process heaters that operate dry control systems. Existing and
new boilers and process heaters must maintain opacity to less than or equal to 10 percent
opacity (daily block average); or
2. Fabric filter control ..........................................
3. Electrostatic precipitator control .....................
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TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS—Continued
If you demonstrate compliance using . . .
You must meet these operating limits . . .
4. Dry scrubber or carbon injection control ........
5. Any other control type ....................................
6. Fuel analysis ...................................................
As stated in § 63.7520, you must
comply with the following requirements
b. This option is only for boilers and process heaters that operate additional wet control systems. Maintain the minimum voltage and secondary current or total power input of the electrostatic precipitator at or above the operating limits established during the performance test
according to § 63.7530(c) and Table 7 to this subpart.
Maintain the minimum sorbent or carbon injection rate at or above the operating levels established during the performance test according to § 63.7530(c) and Table 7 to this subpart.
This option is for boilers and process heaters that operate dry control systems. Existing and
new boilers and process heaters must maintain opacity to less than or equal to 10 percent
opacity (daily block average).
Maintain the fuel type or fuel mixture such that the applicable emission rates calculated according to § 63.7530(d)(3), (4) and/or (5) is less than the applicable emission limits.
for performance test for existing, new or
reconstructed affected sources:
TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS
To conduct a performance test for
the following pollutant . . .
You must . . .
Using . . .
1. Particulate Matter .....................
a. Select sampling ports location and
the number of traverse points.
b. Determine velocity and volumetric
flow-rate of the stack gas.
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
d. Measure the moisture content of the
stack gas.
e. Measure the particulate matter emission concentration.
f. Convert emissions concentration to lb
per MMBtu emission rates.
a. Select sampling ports location and
the number of traverse points.
b. Determine velocity and volumetric
flow-rate of the stack gas.
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
d. Measure the moisture content of the
stack gas.
e. Measure the hydrogen chloride emission concentration.
f. Convert emissions concentration to lb
per MMBtu emission rates.
a. Select sampling ports location and
the number of traverse points.
b. Determine velocity and volumetric
flow-rate of the stack gas.
c. Determine oxygen and carbon dioxide concentrations of the stack gas.
d. Measure the moisture content of the
stack gas.
e. Measure the mercury emission concentration.
Method 1 in appendix A to part 60 of this chapter.
2. Hydrogen chloride ....................
3. Mercury .....................................
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4. CO ............................................
5. Dioxin/Furan .............................
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f. Convert emissions concentration to lb
per MMBtu emission rates.
a. Select the sampling ports location
and the number of traverse points.
b. Determine oxygen and carbon dioxide concentrations of the stack gas.
c. Measure the moisture content of the
stack gas.
d. Measure the CO emission concentration.
a. Select the sampling ports location
and the number of traverse points.
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Method 2, 2F, or 2G in appendix A to part 60 of this chapter.
Method 3A or 3B in appendix A to part 60 of this chapter, or
ASME PTC 19, Part 10 (1981) (IBR, see § 63.14(i)).
Method 4 in appendix A to part 60 of this chapter.
Method 5 or 17 (positive pressure fabric filters must use Method
5D) in appendix A to part 60 of this chapter.
Method 19 F-factor methodology in appendix A to part 60 of this
chapter.
Method 1 in appendix A to part 60 of this chapter.
Method 2, 2F, or 2G in appendix A to part 60 of this chapter.
Method 3A or 3B in appendix A to part 60 of this chapter, or
ASME PTC 19, Part 10 (1981) (IBR, see § 63.14(i)).
Method 4 in appendix A to part 60 of this chapter.
Method 26 or 26A in appendix A to part 60 of this chapter.
Method 19 F-factor methodology in appendix A to part 60 of this
chapter.
Method 1 in appendix A to part 60 of this chapter.
Method 2, 2F, or 2G in appendix A to part 60 of this chapter.
Method 3A or 3B in appendix A to part 60 of this chapter, or
ASME PTC 19, Part 10 (1981) (IBR, see § 62.14(i)).
Method 4 in appendix A to part 60 of this chapter.
Method 29 in appendix A to part 60 of this chapter or Method
101A in appendix B to part 61 of this chapter or ASTM Method
D6784–02 (IBR, see § 63.14(b)).
Method 19 F-factor methodology in appendix A to part 60 of this
chapter.
Method 1 in appendix A to part 60 of this chapter.
Method 3A or 3B in appendix A to part 60 of this chapter, or
ASTM D6522–00 (IBR, see § 63.14(b)), or ASME PTC 19, Part
10 (1981) (IBR, see § 63.14(i)).
Method 4 in appendix A to part 60 of this chapter.
Method 10 in appendix A to part 60 of this chapter.
Method 1 in appendix A to part 60 of this chapter.
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TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued
To conduct a performance test for
the following pollutant . . .
You must . . .
Using . . .
b. Determine oxygen and carbon dioxide concentrations of the stack gas.
Method 3A or 3B in appendix A to part 60 of this chapter, or
ASTM D6522–00 (IBR, see § 63.14(b)), or ASME PTC 19, Part
10 (1981) (IBR, see § 63.14(i)).
Method 4 in appendix A to part 60 of this chapter.
c. Measure the moisture content of the
stack gas.
d. Measure the dioxin/furans emission
concentration.
As stated in § 63.7521, you must
comply with the following requirements
for fuel analysis testing for existing, new
Method l in appendix A to part 60 of this chapter.
or reconstructed affected sources.
However, equivalent methods may be
used in lieu of the prescribed methods
at the discretion of the source owner or
operator:
TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS
To conduct a fuel analysis for the
following pollutant . . .
You must . . .
Using . . .
1. Mercury .....................................
a. Collect fuel samples ..........................
Procedure in § 63.7521(c) or ASTM D2234–D2234M–03 (for coal)
(IBR, see § 63.14(b)) or ASTM D6323–98 (2003) (for biomass)
(IBR, See § 63.14(b)) or equivalent.
Procedure in § 63.7521(d) or equivalent.
SW–846–3050B (for solid samples) or SW–846–3020A (for liquid
samples) or ASTM D2013–04 (for coal) (IBR, see § 63.14(b)) or
ASTM D5198–92 (2003) (for biomass) (IBR, see § 63.14(b)) or
equivalent.
ASTM D5865–04 (for coal) (IBR, see § 63.24(b)) or ASTM E711–
87 (for biomass) (IBR, see § 63.14(b)) or equivalent.
ASTM D3173–03 (IBR, see § 63.14(b)) or ASTM E871–82 (1998)
(IBR, see § 63.14(b)) or equivalent.
ASTM D6722–01 (for coal) (IBR, see § 6314(b)) or SW–846–
7471A (for solid samples) or SW–846–7470A (for liquid samples or equivalent.
b. Composite fuel samples ....................
c. Prepare composited fuel samples .....
d. Determine heat content of the fuel
type.
e. Determine moisture content of the
fuel type.
f. Measure mercury concentration in
fuel sample.
2. Hydrogen Chloride ...................
g. Convert concentration into units of
pounds of pollutant per MMBtu of
heat content.
a. Collect fuel samples ..........................
b. Composite fuel samples ....................
c. Prepare composited fuel samples .....
d. Determine heat content of the fuel
type * * *.
e. Determine moisture content of the
fuel type.
f. Measure chlorine concentration in
fuel sample.
g. Convert concentrations into units of
pounds of pollutant per MMBtu of
heat content.
Procedure in § 63.7521(c) or ASTM D2234–D2234M–03 (for coal)
(IBR, see § 63.14(b)) or ASTM D6323–98 (2003) (for biomass)
(IBR, see § 63.14(b)) or equivalent.
Procedure in § 63.7521(d) or equivalent.
SW–846–3050B (for solid samples) or SW–846–3020A (for liquid
samples) or ASTM D2013–04 (for coal) (IBR, see § 63.14(b)) or
ASTM D5198–92 (2003) (for biomass) (IBR, see § 63.14(b)) or
equivalent.
ASTM D5865–04 (for coal) (IBR, see § 63.14(b)) or ASTM E711–
87 (1996) (for biomass) (IBR, see § 63.14(b)) or equivalent.
ASTM D3173–03 (IBR, see § 63.14(b)) or ASTM E871–82 (1998)
or equivalent.
SW–846–9250 or ASTM D6721–01 (for coal) or ASTM E776–87
(1996) (for biomass) (IBR, see § 63.14(b)) or equivalent.
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As stated in § 63.7520, you must
comply with the following requirements
for establishing operating limits:
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TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS
If you have an applicable
emission limit for . . .
And your operating limits
are based on . . .
You must . . .
Using . . .
According to the following
requirements . . .
1. Particulate matter or
mercury.
a. Wet scrubber operating
parameters.
i. Establish a site-specific
minimum pressure drop
and minimum flow rate
operating limit according
to § 63.7530(c).
(1) Data from the pressure
drop and liquid flow rate
monitors and the particulate matter or mercury
performance test.
b. Electrostatic precipitator
operating parameters
(option only for units
with additional wet
scrubber control).
i. Establish a site-specific
minimum voltage and
secondary current or
total power input according to § 63.7530(c).
(1) Data from the pressure
drop and liquid flow rate
monitors and the particulate matter or mercury
performance test.
a. Wet scrubber operating
parameters.
i. Establish a site-specific
minimum pressure drop
and minimum flow rate
operating limit according
to § 63.7530(c).
(1) Data from the pH,
pressure drop, and liquid
flow-rate monitors and
the hydrogen chloride
performance test.
b. Dry scrubber operating
parameters.
i. Establish a site-specific
minimum sorbent injection rate operating limit
according to
§ 63.7530(c).
(1) Data from the sorbent
injection rate monitors
and hydrogen chloride
performance test.
(a) You must collect pressure drop and liquid
flow-rate data every 15
minutes during the entire
period of the performance tests;
(b) Determine the average
pressure drop and liquid
flow-rate for each individual test run in the
three-run performance
test by computing the
average of all the 15minute readings taken
during each test run.
(a) You must collect voltage and secondary current or total power input
data every 15 minutes
during the entire period
of the performance
tests;
(b) Determine the average
voltage and secondary
current or total power
input for each individual
test run in the three-run
performance test by
computing the average
of all the 15-minute
readings taken during
each test run.
(a) You must collect pH,
pressure drop, and liquid
flow-rate data every 15
minutes during the entire
period of the performance tests;
(b) Determine the average
pH, pressure drop, and
liquid flow-rate for each
individual test run in the
three-run performance
test by computing the
average of all the 15minute readings taken
during each test run.
(a) You must collect sorbent injection rate data
every 15 minutes during
the entire period of the
performance tests;
(b) Determine the average
sorbent injection rate for
each individual test run
in the three-run performance test by computing
the average of all the
15-minute readings
taken during each test
run.
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2. Hydrogen Chloride ........
As stated in § 63.7540, you must show
continuous compliance with the
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TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE
If you must meet the following operating limits
or work practice
standards . . .
1. Opacity ............................................................
2. Fabric Filter Bag Leak Detection Operation ...
3. Wet Scrubber Pressure Drop and Liquid
Flow-rate.
4. Wet Scrubber pH ............................................
5. Dry Scrubber Sorbent or Carbon Injection
Rate.
6. Electrostatic Precipitator Secondary Current
and Voltage or Total Power Input.
7. Fuel Pollutant Content ....................................
You must demonstrate continuous compliance by . . .
a. Collecting the opacity monitoring system data according to §§ 63.7525(b) and 63.7535; and
b. Reducing the opacity monitoring data to 6-minute averages; and
c. Maintaining opacity to less than or equal to 10 percent (daily block average).
Installing and operating a bag leak detection system according to § 63.7525 and operating the
fabric filter such that the requirements in § 63.7540(a)(9) are met.
a. Collecting the pressure drop and liquid flow rate monitoring system data according to
§§ 63.7525 and 63.7535; and
b. Reducing the data to 12-hour block averages; and
c. Maintaining the 12-hour average pressure drop and liquid flow-rate at or above the operating limits established during the performance test according to § 63.7530(c).
a. Collecting the pH monitoring system data according to §§ 63.7525 and 63.7535; and
b. Reducing the data to 12-hour block averages; and
c. Maintaining the 12-hour average pH at or above the operating limit established during the
performance test according to § 63.7530(c).
a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber
according to §§ 63.7525 and 63.7535; and
b. Reducing the data to 12-hour block averages; and
c. Maintaining the 12-hour average sorbent or carbon injection rate at or above the operating
limit established during the performance test according to §§ 63.7530(c).
a. Collecting the secondary current and voltage or total power input monitoring system data
for the electrostatic precipitator according to §§ 63.7525 and 63.7535; and
b. Reducing the data to 12-hour block averages; and
c. Maintaining the 12-hour average secondary current and voltage or total power input at or
above the operating limits established during the performance test according to
§§ 63.7530(c).
a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission limit according to § 63.7530(c) or (d) as applicable; and
b. Keeping monthly records of fuel use according to § 63.7540(a).
As stated in § 63.7550, you must
comply with the following requirements
for reports:
TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS
The report must contain . . .
You must submit the report . . .
1. Compliance report .........................................
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You must submit a(n) . . .
a. Information required in § 63.7550(c)(1)
through (11); and
b. If there are no deviations from any emission limitation (emission limit and operating
limit) that applies to you and there are no
deviations from the requirements for work
practice standards in Table 8 to this subpart
that apply to you, a statement that there
were no deviations from the emission limitations and work practice standards during
the reporting period. If there were no periods during which the CMSs, including continuous emissions monitoring system, continuous opacity monitoring system, and operating parameter monitoring systems, were
out-of-control as specified in § 63.8(c)(7), a
statement that there were no periods during
which the CMSs were out-of-control during
the reporting period; and
Semiannually according to the requirements in
§ 63.7550(b).
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TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS—Continued
You must submit a(n) . . .
The report must contain . . .
2. An immediate startup, shutdown, and malfunction report if you had a startup, shutdown, or malfunction during the reporting period that is not consistent with your startup,
shutdown, and malfunction plan, and the
source exceeds any applicable emission limitation in the relevant emission standard.
You must submit the report . . .
c. If you have a deviation from any emission
limitation (emission limit and operating limit)
or work practice standard during the reporting period, the report must contain the information in § 63.7550(d). If there were periods
during which the CMSs, including continuous emissions monitoring system, continuous opacity monitoring system, and operating parameter monitoring systems, were
out-of-control, as specified in § 63.8(c)(7),
the report must contain the information in
§ 63.7550(e); and
d. If you had a startup, shutdown, or malfunction during the reporting period and you
took actions consistent with your startup,
shutdown, and malfunction plan, the compliance report must include the information in
§ 63.10(d)(5)(i).
a. Actions taken for the event; and
b. The information in § 63.10(d)(5)(ii) ...............
i. By fax or telephone within 2 working days
after starting actions inconsistent with the
plan; and
ii. By letter within 7 working days after the end
of the event unless you have made alternative arrangements with the permitting authority.
As stated in § 63.7565, you must
comply with the applicable General
Provisions according to the following:
TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD
Citation
§ 63.1
§ 63.2
§ 63.3
§ 63.4
§ 63.5
Subject
..................................................................
..................................................................
..................................................................
..................................................................
..................................................................
§ 63.6(a), (b)(1)–(b)(5), (b)(7), (c), (f)(2)–(3), (g),
(h)(2)–(h)(9), (i), (j).
§ 63.6(e)(1), (e)(3), (f)(1), and (h)(1) ..................
Applies to subpart DDDDD
Applicability ......................................................
Definitions ........................................................
Units and Abbreviations ...................................
Prohibited Activities and Circumvention ..........
Preconstruction Review and Notification Requirements.
Compliance with Standards and Maintenance
Requirements.
Startup, shutdown, and malfunction requirements and Opacity/Visible Emission Limits.
Performance Testing Requirements ................
§ 63.8 ..................................................................
§ 63.9 ..................................................................
§ 63.10(a), (b)(1), (b)(2)(i)–(iii), (b)(2)(vi)–(xiv),
(c), (d)(1)–(2), (e), and (f).
§ 63.10(b)(2)(iv)–(v), (b)(3), and (d)(3)–(5) .........
§ 63.10(c)(15) .....................................................
§ 63.11 ................................................................
§ 63.12 ................................................................
§ 63.13–63.16 .....................................................
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§ 63.7(a), (b), (c), (d), (e)(2)–(e)(9), (f), (g), and
(h).
§ 63.7(e)(1) .........................................................
Monitoring Requirements .................................
Notification Requirements ................................
Recordkeeping and Reporting Requirements
§ 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).
Conditions for conducting performance tests.
..........................................................................
Allows use of SSM plan ...................................
Control Device Requirements ..........................
State Authority and Delegation ........................
Addresses, Incorporation by Reference, Availability of Information, Performance Track
Provisions.
Reserved ..........................................................
Yes.
Yes. Additional terms defined in § 63.7575.
Yes.
Yes.
Yes.
Yes.
No. Standards apply at all times, including
during startup, shutdown, and malfunction
events.
Yes.
No. Subpart DDDDD specifies conditions for
conducting performance tests at § 63.7520.
Yes.
Yes.
Yes.
No.
No.
No.
Yes.
Yes.
No.
[FR Doc. 2010–10827 Filed 6–3–10; 8:45 am]
BILLING CODE 6560–50–P
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]]>Agencies
[Federal Register Volume 75, Number 107 (Friday, June 4, 2010)]
[Proposed Rules]
[Pages 32006-32073]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-10827]
[[Page 32005]]
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Part V
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters; Proposed Rule
Federal Register / Vol. 75 , No. 107 / Friday, June 4, 2010 /
Proposed Rules
[[Page 32006]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2002-0058; FRL-9148-5]
RIN 2060-AG69
National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: On September 13, 2004, under authority of section 112 of the
Clean Air Act, EPA promulgated national emission standards for
hazardous air pollutants for new and existing industrial/commercial/
institutional boilers and process heaters. On June 19, 2007, the United
States Court of Appeals for the District of Columbia Circuit vacated
and remanded the national emission standards for hazardous air
pollutants for industrial/commercial/institutional boilers and process
heaters.
In response to the court's vacatur and remand, this action would
require all major sources to meet hazardous air pollutants emissions
standards reflecting the application of the maximum achievable control
technology. The proposed rule would protect air quality and promote
public health by reducing emissions of the hazardous air pollutants
listed in section 112(b)(1) of the Clean Air Act.
We are also proposing that existing major source facilities with an
affected boiler undergo an energy assessment on the boiler system to
identify cost-effective energy conservation measures.
DATES: Comments must be received on or before July 19, 2010. Under the
Paperwork Reduction Act, comments on the information collection
provisions are best assured of having full effect if the Office of
Management and Budget (OMB) receives a copy of your comments on or
before July 6, 2010.
Public Hearing. We will hold a public hearing concerning this
proposed rule and the interrelated proposed Boiler area source, CISWI,
and RCRA rules, discussed in this proposal and published in the
proposed rules section of today's Federal Register, on June 21, 2010.
Persons requesting to speak at a public hearing must contact EPA by
June 14, 2010.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2002-0058, by one of the following methods:
https://www.regulations.gov. Follow the instructions for
submitting comments.
https://www.epa.gov/oar/docket.html. Follow the
instructions for submitting comments on the EPA Air and Radiation
Docket Web site.
E-mail: Comments may be sent by electronic mail (e-mail)
to a-and-r-docket@epa.gov, Attention Docket ID No. EPA-HQ-OAR-2002-
0058.
Fax: Fax your comments to: (202) 566-9744, Docket ID No.
EPA-HQ-OAR-2002-0058.
Mail: Send your comments to: EPA Docket Center (EPA/DC),
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania
Ave., NW., Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2002-0058.
Please include a total of two copies. In addition, please mail a copy
of your comments on the information collection provisions to the Office
of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA,
725 17th St., NW., Washington, DC 20503.
Hand Delivery or Courier: Deliver your comments to: EPA
Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW.,
Washington, DC 20460. Such deliveries are only accepted during the
Docket's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holiday), and special arrangements
should be made for deliveries of boxed information.
Instructions: All submissions must include agency name and docket
number or Regulatory Information Number (RIN) for this rulemaking. All
comments will be posted without change and may be made available online
at https://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
confidential business information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through https://www.regulations.gov or e-mail. The https://www.regulations.gov Web site
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through https://www.regulations.gov, your e-mail address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses.
Public Hearing: We will hold a public hearing concerning this
proposed rule on June 21, 2010. Persons interested in presenting oral
testimony at the hearing should contact Ms. Pamela Garrett, Energy
Strategies Group, at (919) 541-7966 by June 14, 2010. The public
hearing will be held in the Washington DC area at a location and time
that will be posted at the following Web site: https://www.epa.gov/airquality/combustion. Please refer to this Web site to confirm the
date of the public hearing as well. If no one requests to speak at the
public hearing by June 14, 2010 then the public hearing will be
cancelled and a notification of cancellation posted on the following
Web site: https://www.epa.gov/airquality/combustion.
Docket: All documents in the docket are listed in the https://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., 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 Ave., 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: Mr. Brian Shrager, 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)
541-7689; Fax number (919) 541-5450; E-mail address:
shrager.brian@epa.gov.
SUPPLEMENTARY INFORMATION: The information presented in this preamble
is organized as follows:
I. General Information
A. Does this action apply to me?
[[Page 32007]]
B. What should I consider as I prepare my comments to EPA?
C. Where can I get a copy of this document?
D. When would a public hearing occur?
II. Background Information
A. What is the statutory authority for the proposed rule?
B. Summary of the Natural Resources Defense Council v. EPA
Decision
C. Summary of Other Related Court Decisions
D. EPA's Response to the Vacatur
E. What is the relationship between the proposed rule and other
combustion rules?
F. What are the health effects of pollutants emitted from
industrial/commercial/institutional boilers and process heaters?
III. Summary of the Proposed Rule
A. What source categories are affected by the proposed rule?
B. What is the affected source?
C. Does the proposed rule apply to me?
D. What emission limitations and work practice standards must I
meet?
E. What are the startup, shutdown, and malfunction (SSM)
requirements?
F. What are the testing and initial compliance requirements?
G. What are the continuous compliance requirements?
H. What are the notification, recordkeeping and reporting
requirements?
I. Submission of Emissions Test Results to EPA
IV. Rationale for the Proposed Rule
A. How did EPA determine which sources would be regulated under
the proposed rule?
B. How did EPA select the format for the proposed rule?
C. How did EPA determine the proposed emission limitations for
existing units?
D. How did EPA determine the MACT floor for existing units?
E. How did EPA consider beyond-the-floor for existing units?
F. Should EPA consider different subcategories for solid fuel
boilers and process heaters?
G. How did EPA determine the proposed emission limitations for
new units?
H. How did EPA determine the MACT floor for new units?
I. How did EPA consider beyond-the-floor for new units?
J. What other compliance alternatives were considered?
K. How did we select the compliance requirements?
L. What alternative compliance provisions are being proposed?
M. How did EPA determine compliance times for the proposed rule?
N. How did EPA determine the required records and reports for
this proposed rule?
O. How does the proposed rule affect permits?
P. Alternative Standard for Consideration
V. Impacts of the Proposed Rule
A. What are the air impacts?
B. What are the water and solid waste impacts?
C. What are the energy impacts?
D. What are the control costs?
E. What are the economic impacts?
F. What are the social costs and benefits of the proposed rule?
VI. Public Participation and Request for Comment
VII. Relationship of the Proposed Action to Section 112(c)(6) of the
CAA
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review
B. Executive Order 13132, Federalism
C. Executive Order 13175, Consultation and Coordination With
Indian Tribal Governments
D. Executive Order 13045, Protection of Children From
Environmental Health Risks and Safety Risks
E. Unfunded Mandates Reform Act of 1995
F. Regulatory Flexibility Act as Amended by the Small Business
Regulatory Enforcement Fairness Act (RFA) of 1996 SBREFA), 5 U.S.C.
601 et seq.
G. Paperwork Reduction Act
H. National Technology Transfer and Advancement Act
I. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. General Information
A. Does this action apply to me?
The regulated categories and entities potentially affected by the
proposed standards include:
----------------------------------------------------------------------------------------------------------------
Category NAICS code \1\ Examples of potentially regulated entities
----------------------------------------------------------------------------------------------------------------
Any industry using a boiler or 211 Extractors of crude petroleum and natural gas.
process heater as defined in
the proposed rule.
321 Manufacturers of lumber and wood products.
322 Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries, and manufacturers of coal products.
316, 326, 339 Manufacturers of rubber and miscellaneous plastic products.
331 Steel works, blast furnaces.
332 Electroplating, plating, polishing, anodizing, and coloring.
336 Manufacturers of motor vehicle parts and accessories.
221 Electric, gas, and sanitary services.
622 Health services.
611 Educational services.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides 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 63.7485 of subpart DDDDD
(National Emission Standards for Hazardous Air Pollutants (NESHAP) for
Industrial, Commercial, and Institution Boilers and Process Heaters).
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
63.13 of subpart A (General Provisions).
B. What should I consider as I prepare my comments to EPA?
Do not submit information containing CBI to EPA through https://www.regulations.gov or e-mail. Send or deliver information identified
as CBI only to the following address: Roberto Morales, OAQPS Document
Control Officer (C404-02), Office of Air Quality Planning and
Standards, U.S.
[[Page 32008]]
Environmental Protection Agency, Research Triangle Park, North Carolina
27711, Attention: Docket ID EPA-HQ-OAR-2002-0058. Clearly mark the part
or all of the information that you claim to be CBI. For CBI information
in a disk or CD-ROM that you mail to EPA, mark the outside of the disk
or CD-ROM as CBI and then identify electronically within the disk or
CD-ROM the specific information that is claimed as CBI. In addition to
one complete version of the comment that includes information claimed
as CBI, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2.
C. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this proposed action will also be available on the World Wide Web (WWW)
through the Technology Transfer Network (TTN). Following signature, a
copy of the proposed 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.
D. When would a public hearing occur?
We will hold a public hearing concerning this proposed rule on June
21, 2010. Persons interested in presenting oral testimony at the
hearing should contact Ms. Pamela Garrett, Energy Strategies Group, at
(919) 541-7966 by June 14, 2010. The public hearing will be held in the
Washington, DC area at a location and time that will be posted at the
following Web site: https://www.epa.gov/airquality/combustion. Please
refer to this Web site to confirm the date of the public hearing as
well. If no one requests to speak at the public hearing by June 14,
2010, then the public hearing will be cancelled and a notification of
cancellation posted on the following Web site: https://www.epa.gov/airquality/combustion.
II. Background Information
A. What is the statutory authority for this proposed rule?
Section 112(d) of the Clean Air Act (CAA) requires EPA to set
emissions standards for hazardous air pollutants (HAP) emitted by major
stationary sources based on the performance of the maximum achievable
control technology (MACT). The MACT standards for existing sources must
be at least as stringent as the average emissions limitation achieved
by the best performing 12 percent of existing sources (for which the
Administrator has emissions information) or the best performing 5
sources for source categories with less than 30 sources (CAA section
112(d)(3)(A) and (B)). This level of minimum stringency is called the
MACT floor. For new sources, MACT standards must be at least as
stringent as the control level achieved in practice by the best
controlled similar source (CAA section 112(d)(3)). EPA also must
consider more stringent ``beyond-the-floor'' control options. When
considering beyond-the-floor options, EPA must consider not only the
maximum degree of reduction in emissions of HAP, but must take into
account costs, energy, and nonair environmental impacts when doing so.
CAA section 112(c)(6) requires EPA to list categories and
subcategories of sources assuring that sources accounting for not less
than 90 percent of the aggregate emissions of each such pollutant
(alkylated lead compounds; polycyclic organic matter;
hexachlorobenzene; mercury; polychlorinated byphenyls; 2,3,7,8-
tetrachlorodibenzofurans; and 2,3,7,8-tetrachloroidibenzo-p-dioxin) are
subject to standards under subsection 112(d)(2) or (d)(4). Standards
established under CAA section 112(d)(2) must reflect the performance of
MACT. ``Industrial Coal Combustion,'' ``Industrial Oil Combustion,''
``Industrial Wood/Wood Residue Combustion,'' ``Commercial Coal
Combustion,'' ``Commercial Oil Combustion,'' and ``Commercial Wood/Wood
Residue Combustion'' are listed as source categories for regulation
pursuant to CAA section 112(c)(6) due to emissions of polycyclic
organic matter (POM) and mercury (63 FR 17838, 17848, April 10, 1998).
In the documentation for the 112(c)(6) listing, the commercial fuel
combustion categories included institutional fuel combustion (``1990
Emissions Inventory of Section 112(c)(6) Pollutants, Final Report,''
April 1998).
CAA section 129(a)(1)(A) requires EPA to establish specific
performance standards, including emission limitations, for ``solid
waste incineration units'' generally, and, in particular, for ``solid
waste incineration units combusting commercial or industrial waste''
(section 129(a)(1)(D)). Section 129 defines ``solid waste incineration
unit'' as ``a distinct operating unit of any facility which combusts
any solid waste material from commercial or industrial establishments
or the general public.'' Section 129(g)(1). Section 129 also provides
that ``solid waste'' shall have the meaning established by EPA pursuant
to its authority under the Resource Conservation and Recovery Act.
Section 129(g)(6).
In Natural Resources Defense Council v. EPA, 489 F. 3d 1250, 1257-
61 (DC Cir. 2007), the court vacated the Commercial and Industrial
Solid Waste Incineration (CISWI) Definitions Rule, 70 FR 55568
(September 22, 2005), which EPA issued pursuant to CAA section
129(a)(1)(D). In that rule, EPA defined the term ``commercial or
industrial solid waste incineration unit'' to mean a combustion unit
that combusts ``commercial or industrial waste.'' The rule defined
``commercial or industrial waste'' to mean waste combusted at a unit
that does not recover thermal energy from the combustion for a useful
purpose. Under these definitions, only those units that combusted
commercial or industrial waste and were not designed to, or did not
operate to, recover thermal energy from the combustion would be subject
to section 129 standards. The District of Columbia Circuit (DC Circuit)
rejected the definitions contained in the CISWI Definitions Rule and
interpreted the term ``solid waste incineration unit'' in CAA section
129(g)(1) ``to unambiguously include among the incineration units
subject to its standards any facility that combusts any commercial or
industrial solid waste material at all--subject to the four statutory
exceptions identified in [CAA section 129(g)(1).]'' NRDC v. EPA, 489
F.3d 1250, 1257-58.
CAA section 129 covers any facility that combusts any solid waste;
CAA section 112(g)(6) directs the Agency to the Resource Conservation
and Recovery Act (RCRA) in terms of the definition of solid waste. The
Agency is in the process of defining solid waste for purposes of
Subtitle D of RCRA. EPA initiated a rulemaking to define which
secondary materials are ``solid waste'' for purposes of subtitle D
(nonhazardous waste) of RCRA when burned in a combustion unit. (See
Advance Notice of Proposed Rulemaking (74 FR 41, January 2, 2009)
soliciting comment on whether certain secondary materials used as
alternative fuels or ingredients are solid wastes within the meaning of
Subtitle D of RCRA.) If a unit combusts solid waste, it is subject to
CAA section 129 of the Act, unless it falls within one of the four
specified exceptions in CAA section 129(g).
The solid waste definitional rulemaking under RCRA is being
proposed in a parallel action and is
[[Page 32009]]
relevant to this proceeding because some industrial, commercial, or
institutional boilers and process heaters combust secondary materials
as alternative fuels. If industrial, commercial, or institutional
boilers or process heaters combusts secondary materials that are solid
waste under the proposed definitional rule, those units would be
subject to section 129. The units subject to this rule include those
industrial, commercial, or institutional boilers and process heaters
that do not combust solid waste. EPA recognizes that it has imperfect
information on the exact nature of the secondary materials which
boilers and process heaters combust, including, for example, how much
processing of such materials occurs, if any. We nevertheless used the
information currently available to the Agency to determine which
materials are solid waste and, therefore, subject to CAA section 129,
and which are not solid waste and, therefore, subject to CAA section
112.
B. Summary of the Natural Resources Defense Council v. EPA Decision
On September 13, 2004, EPA issued the NESHAP for Industrial,
Commercial, and Institutional Boilers and Process Heaters (40 CFR
55218) (the Boiler MACT). We identified 18 subcategories of boilers and
process heaters emitting four different types of HAPs. See 69 FR
55,223-24. EPA set out to establish the MACT floor for each subcategory
emitting each HAP according to the effectiveness of various add-on
technologies. (See 68 FR 1660, 1674, Jan. 13, 2003 (proposed rule).)
Applying this methodology, EPA set 25 numerical emission standards. The
2004 final rule established emission limitations for particulate matter
(PM), as a surrogate for non-mercury HAP metals, mercury, and hydrogen
chloride (HCl), as a surrogate for acid gas HAP, for existing large
solid fuel-fired sources only. For the remaining 47 boiler subcategory/
HAP emissions, EPA determined that the appropriate MACT floor was ``no
emissions reduction'' because ``the best-performing sources were not
achieving emissions reductions through the use of an emission control
system and there were no other appropriate methods by which boilers and
process heaters could reduce HAP emissions.'' (69 FR 55,233.)
Accordingly, we established no standards. In addition, we set risk-
based standards, also known as health-based compliance alternatives, as
alternatives to the MACT-based standards for hydrogen chloride and
manganese.
EPA issued emissions standards for CISWI units on December 1, 2000,
and as part of that rulemaking, defined the term ``commercial and
industrial waste'' to mean solid waste combusted in an enclosed device
using controlled flame combustion without energy recovery that is a
distinct operating unit of any commercial or industrial facility. In
response to a petition for reconsideration, EPA filed a motion for
voluntary remand, which the court granted on September 6, 2001. On
remand, EPA solicited comments on the CISWI Rule's definitions of
``solid waste,'' ``commercial and industrial waste'' and ``CISWI
unit.'' On September 22, 2005, EPA issued the CISWI Definitions Rule,
which contained definitions that were substantively the same as those
issued before reconsideration. In particular, the 2005 CISWI
Definitions Rule defined ``commercial or industrial waste'' to include
only waste that is combusted at a facility that cannot or does not use
a process that recovers thermal energy from the combustion for a useful
purpose.
EPA received separate petitions from environmental groups,
industry, and municipalities seeking judicial review of the NESHAP for
Industrial, Commercial, and Institutional Boilers and Process Heaters
(Boiler MACT) as well as amendments to definitional terms in the
Standards of Performance for New Stationary Sources and Emission
Guidelines for Existing Sources: Commercial and Industrial Solid Waste
Incineration Units (CISWI Definitions Rule), promulgated pursuant to
CAA section 129. The environmental organizations challenged the CISWI
Definitions Rule on the ground that its definition of ``commercial or
industrial waste'' was inconsistent with the plain language of CAA
section 129 and therefore impermissibly constricted the class of
``solid waste incineration unit[s]'' that were subject to the emission
standards of the CISWI Rule. The environmental groups also challenged
specific emission standards that EPA promulgated in the Boiler MACT and
EPA's methodology for setting them. The municipalities--the American
Municipal Power-Ohio, Inc. and six of its members, the cities of Dover,
Hamilton, Orrville, Painesville, Shelby and St. Mary's--challenged the
Boiler MACT on the grounds that EPA failed to comply with the
requirements of the Regulatory Flexibility Act (RFA) and that the
standards as applied to small municipal utilities are unlawful.
As explained further below, the Court concluded that EPA's
definition of ``commercial or industrial waste,'' as incorporated in
the definition of ``commercial and industrial solid waste incineration
unit'' (CISWI unit), was inconsistent with the plain language of CAA
section 129 and that the CISWI Definitions Rule must, therefore, be
vacated. The Court also vacated and remanded the Boiler MACT, finding
that the Boiler MACT must be substantially revised as a consequence of
the vacatur and remand of the CISWI Definitions Rule.
In its decision, the Court agreed with the environmental
petitioners that EPA's definition of ``commercial or industrial
waste,'' as incorporated in the definition of CISWI units, conflicted
with the plain language of CAA section 129(g)(1). That provision
defines ``solid waste incineration unit'' to mean ``any facility which
combusts any solid waste material'' from certain types of
establishments, with four specific exclusions. The Court stated that,
based on the use of the term ``any'' and the specific exclusions for
only certain types of facilities from the definition of ``solid waste
incineration unit,'' CAA section 129 unambiguously includes among the
incineration units subject to its standards any facility that combusts
any commercial or industrial solid waste material at all--subject only
to the four statutory exclusions. The Court held that the definitions
EPA promulgated in the CISWI Definitions Rule constricted the plain
language of CAA section 129(g)(1), because the CISWI Definitions Rule
excluded from its universe operating units that combusted solid waste
and were designed for or operating with energy recovery.
Having determined that EPA's definition of ``commercial and
industrial solid waste incineration unit'' conflicts with the plain
meaning of CAA section 129 and must, therefore, be vacated, the Court
also vacated the Boiler MACT because it concluded that the Boiler MACT
would need to be revised because the universe of boilers subject to its
standards will be different once EPA revises the CISWI definitions rule
consistent with the Court's opinion. The Court did not address
petitioners' specific challenges to the Boiler MACT.
C. Summary of Other Related Court Decisions
In March 2007, the DC Circuit Court issued an opinion (Sierra Club
v. EPA, 479 F. 3d 875 (DC Cir. 2007) (Brick MACT)) vacating and
remanding CAA section 112(d) MACT standards for the Brick and
Structural Clay Ceramics source categories. Some key holdings in that
case were:
Floors for existing sources must reflect the average
emission limitation achieved by the best-performing 12 percent of
existing sources, not levels
[[Page 32010]]
EPA considers to be achievable by all sources (479 F. 3d at 880-81);
EPA cannot set floors of ``no control.'' The Court
reiterated its prior holdings, including National Lime Association,
confirming that EPA must set floor standards for all HAP emitted by the
major source, including those HAP that are not controlled by at-the-
stack control devices (479 F. 3d at 883);
EPA cannot ignore non-technology factors that reduce HAP
emissions. Specifically, the Court held that ``EPA's decision to base
floors exclusively on technology even though non-technology factors
affect emissions violates the Act.'' (479 F. 3d at 883)
Based on the Brick MACT decision, we believe a source's performance
resulting from the presence or absence of HAP in fuel materials must be
accounted for in establishing floors; i.e., a low emitter due to low
HAP fuel materials can still be a best performer. In addition, the fact
that a specific level of performance is unintended is not a legal basis
for excluding the source's performance from consideration. (National
Lime Ass'n, 233 F. 3d at 640.)
The Brick MACT decision also stated that EPA may account for
variability in setting floors. However, the court found that EPA erred
in assessing variability because it relied on data from the worst
performers to estimate best performers' variability, and held that
``EPA may not use emission levels of the worst performers to estimate
variability of the best performers without a demonstrated relationship
between the two.'' (479 F. 3d at 882.)
The majority opinion in the Brick MACT case does not address the
possibility of subcategorization to address differences in the HAP
content of raw materials. However, in his concurring opinion Judge
Williams stated that EPA's ability to create subcategories for sources
of different classes, size, or type (CAA section 112(d)(1)) may provide
a means out of the situation where the floor standards are achieved for
some sources, but the same floors cannot be achieved for other sources
due to differences in local raw materials whose use is essential. (Id.
At 884-85.9)
A second court opinion is also relevant to this proposal. In Sierra
Club v. EPA, 551 F. 3d 1019 (DC Cir. 2008), the court vacated the
portion of the regulations contained in the General Provisions which
exempt major sources from MACT standards during periods of startup,
shutdown and malfunction (SSM). The regulations (in 40 CFR 63.6(f)(1)
and 63.6(h)(1)) provided that sources need not comply with the relevant
CAA section 112(d) standard during SSM events and instead must
``minimize emissions * * * to the greatest extent which is consistent
with safety and good air pollution control practices.'' The vacated
Boiler MACT did not contain specific provisions covering operation
during SSM operating modes; rather it referenced the now-vacated
exemption in the General Provisions. As a result of the court decision,
we are addressing SSM in this proposed rulemaking. Discussion of this
issue may be found later in this preamble.
D. EPA's Response to the Vacatur
In response to the NRDC v. EPA mandate, we initiated an information
collection effort entitled ``Information Collection Effort for
Facilities with Combustion Units.'' This information collection was
conducted by EPA's Office of Air and Radiation pursuant to CAA section
114 to assist the Administrator in developing emissions standards for
boilers/process heaters and CISWI units (collectively, ``combustion
units'') pursuant to CAA sections 112(d) and 129. CAA section 114(a)
states, in pertinent part:
For the purpose of * * * (iii) carrying out any provision of
this Chapter * * * (1) the Administrator may require any person who
owns or operates any emission source * * * to- * * * (D) sample such
emissions (in accordance with such procedures or methods, at such
locations, at such intervals, during such periods and in such manner
as the Administrator shall prescribe); (E) keep records on control
equipment parameters, production variables or other indirect data
when direct monitoring of emissions is impractical * * * (G) provide
such other information as the Administrator may reasonably require *
* *
There were two components to the information collection. To obtain
the information necessary to identify and categorize all combustion
units potentially affected by the revised standards for boilers/process
heaters and for CISWI units, the first component of the information
collection effort solicited information from all potentially affected
combustion units in the format of an electronic survey. The survey was
submitted to the following facilities: (1) All facilities that
submitted an initial notification for the 2004 boiler MACT standard,
(2) all facilities identified by States as being subject to the 2004
boiler MACT standard, and (3) facilities that are classified as a major
source in their Title V permit that have a boiler or process heater
listed in their permit. The survey was also sent to units covered by
the 2000 CISWI emissions standards (40 CFR part 60 subpart CCCC) and to
facilities that have incineration units (e.g., energy recovery units)
that were listed as exempt under the 2000 CISWI standard. Each facility
was required to complete the survey for all combustion units located at
the facility. The information requested for each combustion unit
included the unit design, operation, air pollution control data, the
fuels/materials burned, and available emissions test data, continuous
emission monitoring (CEM) data, fuel/material analysis data, and
permitted and regulatory emission limits.
The second component of the information collection request effort
consisted of requiring the owners/operators of 169 boilers/process
heaters to conduct emission testing for HAP and HAP surrogates. We
first analyzed the results of the survey to determine if sufficient
emissions data existed to develop emission standards under CAA sections
112(d) for all types of boilers/process heaters, all types of materials
combusted, and all HAP to be regulated. If data were not sufficient,
then we selected pools of candidates to conduct emission testing. We
submitted a list of candidates to stakeholders, including state,
industry, and environmental stakeholders, who had an opportunity to
comment on the technical feasibility, the least-cost impact of the
testing program, and the appropriateness of the testing being
requested. We then made a selection of test sites after taking into
account stakeholder comments. The sites selected were required to
conduct an outlet stack test, consisting of three runs, in accordance
with EPA-approved protocols, for all of the following pollutants: PM
(filterable, condensable, and PM2.5), dioxins/furans (D/F),
hydrogen chloride/hydrogen fluoride, mercury, metals (including
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead,
manganese, nickel, phosphorus, and selenium), carbon monoxide (CO),
total hydrocarbons (THC), formaldehyde, oxides of nitrogen
(NOX), and sulfur dioxide (SO2). Six facilities
(two coal-fired, two biomass-fired, and two gas-fired boilers) were
required to collect CEM data over 30 operating days using mobile CEM
devices for CO, THC, and NOX. The owner/operator of each
selected combustion unit was also required to collect and analyze, in
accordance with acceptable procedures, the material(s) fed to the
combustion unit during each stack test. The results of the stack tests
and the analyses of materials combusted were required to be submitted
to the Agency and are available in the docket and can be
[[Page 32011]]
downloaded at https://www.epa.gov/ttn/atw/boiler/boilerpg.html.
When we compared information on boilers and process heaters from
facilities submitting initial notifications to comply with the vacated
2004 Boiler MACT to the information gathering effort conducted for the
2004 Boiler MACT, a large disparity was identified in the number of
potentially affected units at major sources of HAP. Since the last
combustion unit data gathering effort in 1996, many sources have shut
down, others have selected to operate with a permit limit on their HAP
emissions in order to avoid being subject to the Boiler MACT (i.e.,
synthetic area source), and some units have switched out older solid
fuel units for newer equipment due to increased insurance and
maintenance costs.
Based on the definition of solid waste as set forth in a parallel
proposed action, we revised the population of combustion units subject
to CAA section 129 (because they combust solid waste) and the
population of boilers and process heaters subject to CAA section 112
(because they do not combust solid waste). We then used the new data to
develop a revised NESHAP for boilers and process heaters under CAA
section 112 and revised standards for incineration units covered by CAA
section 129. Specifically, the data provide the Agency with updated
information on the number of potentially affected units, available
emission test data, and fuel/material analysis data to address
variability. We are using all of the information before the
Administrator to calculate the MACT floors, set emission limits, and
evaluate the emission impacts of various regulatory options for these
revised rulemakings.
E. What is the relationship between this proposed rule and other
combustion rules?
The proposed rule regulates source categories covering industrial
boilers, institutional boilers, commercial boilers, and process
heaters. These source categories potentially include combustion units
that are already regulated by other MACT standards. Therefore, we are
excluding from this proposed rule any boiler or process heater that is
subject to regulation under other MACT standards.
In 1986, EPA had codified new source performance standards (NSPS)
for industrial boilers (40 CFR part 60, subparts Db and Dc) and revised
portions of those standards in 1999 and 2006. The NSPS regulates
emissions of PM, SO2, and NOX from boilers
constructed after June 19, 1984. Sources subject to the NSPS will be
subject to the final CAA section 112(d) standards for boilers and
process heaters because it regulates sources of HAP while the NSPS do
not. However, in developing the proposed rule, we considered the
monitoring requirements, testing requirements, and recordkeeping
requirements of the NSPS to avoid duplicating requirements.
This proposed rule addresses the combustion of non-solid waste
materials in boilers and process heaters. If an owner or operator of an
affected source subject to these proposed standards were to start
combusting a solid waste (as defined by the Administrator under RCRA),
the affected source would cease to be subject to this action and would
instead be subject to regulation under CAA section 129. A rulemaking
under CAA section 129 is being proposed in a parallel action and is
relevant to this action because it would apply to boilers and process
heaters located at a major source that combust any solid waste. EPA is
taking comment on whether a boiler or process heater could then opt
back into regulation under this proposed rule by taking a federally
enforceable restriction precluding the future combustion of any solid
waste material.
F. What are the health effects of pollutants emitted from industrial/
commercial/institutional boilers and process heaters?
This proposed rule protects air quality and promotes the public
health by reducing emissions of some of the HAP listed in CAA section
112(b)(1). As noted above, emissions data collected during development
of the proposed rule show that hydrogen chloride emissions represent
the predominant HAP emitted by industrial, commercial, and
institutional (ICI) boilers, accounting for 61 percent of the total HAP
emissions.\1\ ICI boilers and process heaters also emit lesser amounts
of hydrogen fluoride, accounting for about 17 percent of total HAP
emissions, and metals (arsenic, cadmium, chromium, mercury, manganese,
nickel, and lead) accounting for about 6 percent of total HAP
emissions. Organic HAP (formaldehyde, POM, acetaldehyde, benzene)
account for about 15 percent of total HAP emissions. Exposure to these
HAP, depending on exposure duration and levels of exposures, can be
associated with a variety of adverse health effects. These adverse
health effects may include, for example, irritation of the lung, skin,
and mucus membranes, effects on the central nervous system, damage to
the kidneys, and alimentary effects such as nausea and vomiting. We
have classified two of the HAP as human carcinogens (arsenic and
chromium VI) and four as probable human carcinogens (cadmium, lead,
dioxins/furans, and nickel). We do not know the extent to which the
adverse health effects described above occur in the populations
surrounding these facilities. However, to the extent the adverse
effects do occur, this proposed rule would reduce emissions and
subsequent exposures.
---------------------------------------------------------------------------
\1\ See Memorandum ``Methodology for Estimating Impacts from
Industrial, Commercial, Institutional Boilers and Process Heaters at
Major Sources of Hazardous Air Pollutant Emissions'' located in the
docket.
---------------------------------------------------------------------------
III. Summary of This Proposed Rule
This section summarizes the requirements proposed in today's
action. Section IV below provides our rationale for the proposed
requirements.
A. What source categories are affected by this proposed rule?
This proposed rule affects industrial boilers, institutional
boilers, commercial boilers, and process heaters. In this proposed
rule, process heaters are defined as units in which the combustion
gases do not directly come into contact with process material or gases
in the combustion chamber (e.g., indirect fired). Boiler means an
enclosed device using controlled flame combustion and having the
primary purpose of recovering thermal energy in the form of steam or
hot water.
B. What is the affected source?
The affected source is: (1) The collection of all existing
industrial, commercial, or institutional boilers or process heaters
within a subcategory located at a major source facility that do not
combust solid waste or (2) each new or reconstructed industrial,
commercial, or institutional boiler or process heater located at a
major source facility that do not combust solid waste, as that term is
defined by the Administrator under RCRA.
The affected source does not include boilers and process heaters
that are subject to another standard under 40 CFR part 63 or a standard
established under CAA section 129.
C. Does this proposed rule apply to me?
This proposed rule applies to you if you own or operate a boiler or
process heater at a major source meeting the requirements discussed
previously in this preamble. A major source of HAP emissions is any
stationary source or group of stationary sources located within a
contiguous area and under common control that emits or has the
[[Page 32012]]
potential to emit considering controls 10 tons per year or more of any
HAP or 25 tons per year or more of any combination of HAP.
D. What emission limitations and work practice standards must I meet?
We are proposing the emission limits presented in Table 1 of this
preamble. Emission limits were developed for new and existing sources
for eleven subcategories, which we developed based on unit design.
We are proposing that if your new or existing boiler or process
heater burns at least 10 percent coal on an annual average heat input
\2\ basis, the unit is in one of the coal subcategories. If your new or
existing boiler or process heater burns at least 10 percent biomass, on
an annual average heat input basis, and less than 10 percent coal, on
an annual average heat input basis, we are proposing that the unit is
in one of the biomass subcategories. If your new or existing boiler or
process heater burns at least 10 percent liquid fuel (such as
distillate oil, residual oil), and less than 10 percent solid fuel, on
an annual heat input basis, we are proposing that the unit is in the
liquid subcategory. If your new or existing boiler or process heater
burns gaseous fuel and less than 10 percent, on an annual average heat
input basis, of liquid or solid fuel, we are proposing that the unit is
in one of the gas subcategories.
---------------------------------------------------------------------------
\2\ Heat input means heat derived from combustion of fuel in a
boiler or process heater and does not include the heat derived from
preheated combustion air, recirculated flue gases or exhaust gases
from other sources (such as stationary gas turbines, internal
combustion engines, and kilns).
Table 1--Emission Limits for Boilers and Process Heaters
[Pounds per million British thermal units]
----------------------------------------------------------------------------------------------------------------
Carbon Dioxins/
Particulate Hydrogen monoxide (CO) furans (total
Subcategory matter (PM) chloride (HCl) Mercury (Hg) (ppm @3% TEQ) (ng/
oxygen) dscm)
----------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker.......... 0.02 0.02 0.000003 50 0.003
Existing--Coal Fluidized Bed... 0.02 0.02 0.000003 30 0.002
Existing--Pulverized Coal...... 0.02 0.02 0.000003 90 0.004
Existing--Biomass Stoker....... 0.02 0.006 0.0000009 560 0.004
Existing--Biomass Fluidized Bed 0.02 0.006 0.0000009 250 0.02
Existing--Biomass Suspension 0.02 0.006 0.0000009 1010 0.03
Burner/Dutch Oven.............
Existing--Biomass Fuel Cells... 0.02 0.006 0.0000009 270 0.02
Existing--Liquid............... 0.004 0.0009 0.000004 1 0.002
Existing--Gas (Other Process 0.05 0.000003 0.0000002 1 0.009
Gases)........................
New--Coal Stoker............... 0.001 0.00006 0.000002 7 0.003
New--Coal Fluidized Bed........ 0.001 0.00006 0.000002 30 0.00003
New--Pulverized Coal........... 0.001 0.00006 0.000002 90 0.002
New--Biomass Stoker............ 0.008 0.004 0.0000002 560 0.00005
New--Biomass Fluidized Bed..... 0.008 0.004 0.0000002 40 0.007
New--Biomass Suspension Burner/ 0.008 0.004 0.0000002 1010 0.03
Dutch Oven....................
New--Biomass Fuel Cells........ 0.008 0.004 0.0000002 270 0.0005
New--Liquid.................... 0.002 0.0004 0.0000003 1 0.002
New--Gas (Other Process Gases). 0.003 0.000003 0.0000002 1 0.009
----------------------------------------------------------------------------------------------------------------
The proposed emission limits in the above table apply only to
existing boilers and process heaters that have a designed heat input
capacity of 10 million British thermal units (Btu) per hour or greater.
Pursuant to CAA section 112(h), we are proposing a work practice
standard for three particular classes of boilers and process heaters:
Existing units that have a designed heat input capacity of less than 10
million Btu per hour and new and existing units in the Gas 1 (natural
gas/refinery gas) subcategory and in the metal process furnaces
subcategory. The work practice standard being proposed for these
boilers and process heaters would require the implementation of a tune-
up program as described in section III.F of this preamble.
We are also proposing a beyond-the-floor standard for all existing
major source facilities having affected boilers or process heaters that
would require the performance of a one-time energy assessment, as
described in section III.F of this preamble, by qualified personnel, on
the affected boilers and facility to identify any cost-effective energy
conservation measures.
E. What are the startup, shutdown, and malfunction (SSM) requirements?
The United States Court of Appeals for the District of Columbia
Circuit vacated portions of two provisions in EPA's CAA Section 112
regulations governing the emissions of HAP during periods of startup,
shutdown, and malfunction (SSM). Sierra Club v. EPA, 551 F.3d 1019 (DC
Cir. 2008), cert. denied, 2010 U.S. LEXIS 2265 (2010). Specifically,
the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and
40 CFR 63.6(h)(1), that are part of a regulation, commonly referred to
as the ``General Provisions Rule,'' that EPA promulgated under section
112 of the CAA. When incorporated into CAA Section 112(d) regulations
for specific source categories, these two provisions exempt sources
from the requirement to comply with the otherwise applicable CAA
section 112(d) emission standard during periods of SSM.
Consistent with Sierra Club v. EPA, EPA has established standards
in this rule that apply at all times. EPA has attempted to ensure that
we have not incorporated into proposed regulatory language any
provisions that are inappropriate, unnecessary, or redundant in the
absence of an SSM exemption. We are specifically seeking comment on
whether there are any such provisions that we have inadvertently
incorporated or overlooked. We also request comment on whether there
are additional provisions that should be added to regulatory text in
light of the absence of an SSM exemption and provisions related to the
SSM exemption (such as the SSM plan requirement and SSM recordkeeping
and reporting provisions).
In establishing the standards in this rule, EPA has taken into
account startup and shutdown periods and, for the
[[Page 32013]]
reasons explained below, has not established different standards for
those periods. The standards that we are proposing are daily or monthly
averages. Continuous emission monitoring data obtained from best
performing units, and used in establishing the standards, include
periods of startup and shutdown. Boilers, especially solid fuel-fired
boilers, do not normally startup and shutdown more the once per day.
Thus, we are not establishing a separate emission standard for these
periods because startup and shutdown are part of their routine
operations and, therefore, are already addressed by the standards.
Periods of startup, normal operations, and shutdown are all predictable
and routine aspects of a source's operation. We have evaluated whether
it is appropriate to have the same standards apply during startup and
shutdown as applied to normal operations.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a ``sudden, infrequent, and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner * * *'' (40 CFR 63.2). EPA has determined that
malfunctions should not be viewed as a distinct operating mode and,
therefore, any emissions that occur at such times do not need to be
factored into development of CAA section 112(d) standards, which, once
promulgated, apply at all times. It is reasonable to interpret section
112(d) as not requiring EPA to account for malfunctions in setting
emissions standards. For example, we note that Section 112 uses the
concept of ``best performing'' sources in defining MACT, the level of
stringency that major source standards must meet. Applying the concept
of ``best performing'' to a source that is malfunctioning presents
significant difficulties. The goal of best performing sources is to
operate in such a way as to avoid malfunctions of their units.
Moreover, even if malfunctions were considered a distinct operating
mode, we believe it would be impracticable to take malfunctions into
account in setting CAA section 112(d) standards for major source
boilers and process heaters. As noted above, by definition,
malfunctions are sudden and unexpected events and it would be difficult
to set a standard that takes into account the myriad different types of
malfunctions that can occur across all sources in the category.
Moreover, malfunctions can vary in frequency, degree, and duration,
further complicating standard setting.
In the event that a source fails to comply with the applicable CAA
section 112(d) standards as a result of a malfunction event, EPA would
determine an appropriate response based on, among other things, the
good faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
EPA would also consider whether the source's failure to comply with the
CAA section 112(d) standard was, in fact, ``sudden, infrequent, not
reasonably preventable'' and was not instead ``caused in part by poor
maintenance or careless operation.'' 40 CFR 63.2 (definition of
malfunction).
F. What are the testing and initial compliance requirements?
We are proposing that the owner or operator of a new or existing
boiler or process heater must conduct performance tests to demonstrate
compliance with all applicable emission limits. Affected units would be
required to conduct the following compliance tests where applicable:
(1) Conduct initial and annual stack tests to determine compliance
with the PM emission limits using EPA Method 5 or 17.
(2) Conduct initial and annual stack tests to determine compliance
with the mercury emission limits using EPA method 29 or ASTM-D6784-02
(Ontario Hydro Method).
(3) Conduct initial and annual stack tests to determine compliance
with the HCl emission limits using EPA Method 26A or EPA Method 26 (if
no entrained water droplets in the sample).
(4) Use EPA Method 19 to convert measured concentration values to
pound per million Btu values.
(5) Conduct initial and annual test to determine compliance with
the CO emission limits using either EPA Method 10 or a CO CEMS.
(6) Conduct initial and annual test to determine compliance with
the D/F emission limits using EPA Method 23.
As part of the initial compliance demonstration, we are proposing
that you monitor specified operating parameters during the initial
performance tests that you would conduct to demonstrate compliance with
the PM, mercury, D/F, and HCl emission limits. You would calculate the
average parameter values measured during each test run over the three
run performance test. The average of the three average values
(depending on the parameter measured) for each applicable parameter
would establish the site-specific operating limit. The applicable
operating parameters for which operating limits would be required to be
established are based on the emissions limits applicable to your unit
as well as the types of add-on controls on the unit. The following is a
summary of the operating limits that we are proposing to be established
for the various types of the following units:
(1) For boilers and process heaters without wet or dry scrubbers
that must comply with an HCl emission limit, you must measure the
average chlorine content level in the input fuel(s) during the HCl
performance test. This is your maximum chlorine input operating limit.
(2) For boilers and process heaters with wet scrubbers, you must
measure pressure drop and liquid flow rate of the scrubber during the
performance test, and calculate the average value for each test run.
The average of the three test run averages establishes your minimum
site-specific pressure drop and liquid flow rate operating levels. If
different average parameter levels are measured during the mercury, PM
and HCl tests, the highest of the average values becomes your site-
specific operating limit. If you are complying with an HCl emission
limit, you must measure pH of the scrubber effluent during the
performance test for HCl and determine the average for each test run
and the average value for the performance test. This establishes your
minimum pH operating limit.
(3) For boilers and process heaters with sorbent injection, you
would be required to measure the sorbent injection rate for each
sorbent used during the performance tests for HCl, mercury, and D/F and
calculate the average for each sorbent for each test run. The average
of the three test run averages established during the performance tests
would be your site-specific minimum sorbent injection rate operating
limit. If different sorbents and/or injection rates are used during the
mercury, HCl, and D/F tests, the average value for each sorbent becomes
your site-specific operating limit.
(4) For boilers and process heaters with fabric filters in
combination with wet scrubbers, you must measure the pH, pressure drop,
and liquid flowrate of the wet scrubber during the performance test and
calculate the average value for each test run. The minimum test run
average establishes your site-specific pH, pressure drop, and liquid
flowrate operating limits for the wet scrubber. Furthermore, the fabric
filter must be operated such that
[[Page 32014]]
the bag leak detection system alarm does not sound more than 5 percent
of the operating time during any 6-month period unless a CEMS is
installed to measure PM.
(5) For boilers and process heaters with electrostatic
precipitators (ESP) in combination with wet scrubbers, you must measure
the pH, pressure drop, and liquid flow rate of the wet scrubber during
the HCl performance test and you must measure the voltage and current
of the ESP collection fields during the mercury and PM performance
test. You would then be required to calculate the average value of
these parameters for each test run. The average of the three test run
averages would establish your site-specific minimum pH, pressure drop,
and liquid flowrate operating limit for the wet scrubber and the
minimum voltage and current operating limits for the ESP.
(6) For boilers and process heaters that choose to demonstrate
compliance with the mercury emission limit on the basis of fuel
analysis, you would be required to measure the mercury content of the
inlet fuel that was burned during the mercury performance test. This
value is your maximum fuel inlet mercury operating limit.
(7) For boilers and process heaters that choose to demonstrate
compliance with the HCl emission limit on the basis of fuel analysis,
you would be required to measure the chlorine content of the inlet fuel
that was burned during the HCl performance test. This value is your
maximum fuel inlet chlorine operating limit.
These proposed operating limits would not apply to owners or
operators of boilers or process heaters having a heat input capacity of
less than 10 million Btu per hour (MMBtu/h) or boilers or process
heaters of any size which combust natural gas or refinery gas, as
discussed in section IV.D.3 of this preamble. Instead, we are proposing
that owners or operators of such boilers and process heaters submit to
the delegated authority or EPA, as appropriate, if requested,
documentation that a tune-up meeting the requirements of the proposed
rule was conducted. We are proposing that, to comply with the work
practice standard, a tune-up procedure include the following:
(1) Inspect the burner, and clean or replace any components of the
burner as necessary,
(2) Inspect the flame pattern and make any adjustments to the
burner necessary to optimize the flame pattern consistent with the
manufacturer's specifications,
(3) Inspect the system controlling the air-to-fuel ratio, and
ensure that it is correctly calibrated and functioning properly,
(4) Minimize total emissions of CO consistent with the
manufacturer's specifications,
(5) Measure the concentration in the effluent stream of CO in
ppmvd, before and after the adjustments are made,
(6) Submit an annual report containing the concentrations of CO in
the effluent stream in ppmvd, and oxygen in percent dry basis, measured
before and after the adjustments of the boiler, a description of any
corrective actions taken as a part of the combustion adjustment, and
the type and amount of fuel used over the 12 months prior to the annual
adjustment.
Further, all owners or operators of major source facilities having
boilers and process heaters subject to this rule would be required to
submit to the delegated authority or EPA, as appropriate, documentation
that an energy assessment was performed, by qualified personnel, and
the cost-effective energy conservation measures indentified. The
procedures for an energy assessment are:
(1) Conduct a visual inspection of the boiler system.
(2) Establish operating characteristics of the facility, energy
system specifications, operating and maintenance procedures, and
unusual operating constraints,
(3) Identify major energy consuming systems,
(4) Review available architectural and engineering plans, facility
operation and maintenance procedures and logs, and fuel usage,
(5) Identify a list of major energy conservation measures,
(6) Determine the energy savings potential of the energy
conservation measures identified, and
(7) Prepare a comprehensive report detailing the ways to improve
efficiency, the cost of specific improvements, benefits, and the time
frame for recouping those investments.
G. What are the continuous compliance requirements?
To demonstrate continuous compliance with the emission limitations,
we are proposing following requ
