[Federal Register Volume 80, Number 13 (Wednesday, January 21, 2015)]
[Proposed Rules]
[Pages 3090-3130]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-29569]
[[Page 3089]]
Vol. 80
Wednesday,
No. 13
January 21, 2015
Part III
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. 80 , No. 13 / Wednesday, January 21, 2015 /
Proposed Rules
[[Page 3090]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2002-0058; FRL-9919-28-OAR]
RIN 2060-AS09
National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters
AGENCY: Environmental Protection Agency.
ACTION: Proposed rule.
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SUMMARY: On January 31, 2013, the Environmental Protection Agency (EPA)
finalized amendments to the national emission standards for the control
of hazardous air pollutants (HAP) from new and existing industrial,
commercial, and institutional boilers and process heaters at major
sources of HAP. Subsequently, the EPA received 10 petitions for
reconsideration of the final rule. The EPA is announcing
reconsideration of and requesting public comment on three issues raised
in the petitions for reconsideration, as detailed in the SUPPLEMENTARY
INFORMATION section of this notice. The EPA is seeking comment only on
these three issues. The EPA will not respond to any comments addressing
any other issues or any other provisions of the final rule.
Additionally, the EPA is proposing amendments and technical corrections
to the final rule to clarify definitions, references, applicability and
compliance issues raised by stakeholders subject to the final rule.
Also, we propose to delete rule provisions for an affirmative defense
for malfunction in light of a recent court decision on the issue.
DATES: Comments. Comments must be received on or before March 9, 2015,
or 30 days after date of public hearing if later.
Public Hearing. If anyone contacts us requesting to speak at a
public hearing by January 26, 2015, a public hearing will be held on
February 5, 2015. If you are interested in attending the public
hearing, contact Ms. Pamela Garrett at (919) 541-7966 or by email at
[email protected] to verify that a hearing will be held.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2002-0058, by one of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov:
Follow the on-line instructions for submitting comments.
Email: [email protected]. Include docket ID No. EPA-
HQ-OAR-2002-0058 in the subject line of the message.
Fax: (202) 566-9744, Attention Docket ID No. EPA-HQ-OAR-
2002-0058.
Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Mail Code 28221T, Attention Docket ID No. OAR-2002-0058, 1200
Pennsylvania Avenue NW., Washington, DC 20460. The EPA requests a
separate copy also be sent to the contact person identified below (see
FOR FURTHER INFORMATION CONTACT).
Hand/Courier Delivery: EPA Docket Center, Room 3334, EPA
WJC West Building, 1301 Constitution Avenue NW., Washington, DC 20004,
Attention Docket ID No. EPA-HQ-OAR-2002-0058. Such deliveries are only
accepted during the Docket's normal hours of operation, and special
arrangements should be made for deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2002-0058. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
on-line at 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 www.regulations.gov
or email. The www.regulations.gov Web site is an ``anonymous access''
system, which means the EPA will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an email comment directly to the EPA without going through
www.regulations.gov, your email 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, the 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 the EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, the 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: If anyone contacts the EPA requesting a public
hearing by January 26, 2015, the public hearing will be held on
February 5, 2015 at the EPA's campus at 109 T.W. Alexander Drive,
Research Triangle Park, North Carolina. The hearing will begin at 10:00
a.m. (Eastern Standard Time) and conclude at 5:00 p.m. (Eastern
Standard Time). There will be a lunch break from 12:00 p.m. to 1:00
p.m. Please contact Ms. Pamela Garrett at 919-541-7966 or at
[email protected] to register to speak at the hearing or to
inquire as to whether or not a hearing will be held. The last day to
pre-register in advance to speak at the hearing will be February 2,
2015. Additionally, requests to speak will be taken the day of the
hearing at the hearing registration desk, although preferences on
speaking times may not be able to be fulfilled. If you require the
service of a translator or special accommodations such as audio
description, please let us know at the time of registration. If you
require an accommodation, we ask that you pre-register for the hearing,
as we may not be able to arrange such accommodations without advance
notice. The hearing will provide interested parties the opportunity to
present data, views or arguments concerning the proposed action. The
EPA will make every effort to accommodate all speakers who arrive and
register. Because the hearing is being held at a U.S. government
facility, individuals planning to attend the hearing should be prepared
to show valid picture identification to the security staff in order to
gain access to the meeting room. Please note that the REAL ID Act,
passed by Congress in 2005, established new requirements for entering
federal facilities. If your driver's license is issued by Alaska,
American Samoa, Arizona, Kentucky, Louisiana, Maine, Massachusetts,
Minnesota, Montana, New York, Oklahoma or the state of Washington, you
must present an additional form of identification to enter the federal
building. Acceptable alternative forms of identification include:
Federal employee badges, passports, enhanced driver's licenses and
military identification cards. In addition, you will need to obtain a
property pass for any personal belongings you bring with you. Upon
leaving the building, you will be required to return this property pass
to the security desk. No large signs will be allowed in the building,
cameras may only be used outside of the building and demonstrations
will not be allowed on federal property for security reasons. The EPA
may ask clarifying questions during the oral presentations, but will
not respond to the presentations at that time. Written statements and
supporting information submitted during the comment period will be
considered with the same weight
[[Page 3091]]
as oral comments and supporting information presented at the public
hearing. A hearing will not be held unless requested.
Docket: All documents in the docket are listed in the
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.
Publicly available docket materials are available either electronically
in www.regulations.gov or in hard copy at the EPA Docket Center (EPA/
DC), Room 3334, EPA WJC West Building, 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. Jim Eddinger, Energy Strategies
Group, Sector Policies and Programs Division (D243-01), Environmental
Protection Agency, Research Triangle Park, North Carolina 27711;
telephone number: (919) 541-5426; facsimile number: (919) 541-5450;
email address: [email protected].
SUPPLEMENTARY INFORMATION: Organization of this Document. The following
outline is provided to aid in locating information in the preamble.
I. General Information
A. What is the source of authority for the reconsideration
action?
B. What entities are potentially affected by the reconsideration
action?
C. What should I consider as I prepare my comments for the EPA?
II. Background
III. Discussion of the Issues under Reconsideration
A. Startup and Shutdown Provisions
B. CO Limits Based on a Minimum CO Level of 130 ppm
C. Use of PM CPMS Including Consequences of Exceeding the
Operating Parameter
IV. Technical Corrections and Clarifications
V. Affirmative Defense for Violation of Emission Standards During
Malfunction
VI. Solicitation of Public Comment and Participation
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. General Information
A. What is the source of authority for the reconsideration action?
The statutory authority for this action is provided by sections 112
and 307(d)(7)(B) of the Clean Air Act as amended (42 U.S.C. 7412 and
7607(d)(7)(B)).
B. What entities are potentially affected by the reconsideration
action?
Categories and entities potentially regulated by this action
include:
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Category NAICS Code \1\ Examples of potentially regulated entities
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Any industry using a boiler or process heater 211 Extractors of crude petroleum and natural gas.
as defined in the final 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.
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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 boiler or process heater is regulated
by this action, you should examine the applicability criteria in 40 CFR
63.7485. 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).
C. What should I consider as I prepare my comments for the EPA?
Submitting CBI. Do not submit this information to the EPA through
regulations.gov or email. 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 the 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. Send or deliver information
identified as CBI to only the following address: Mr. Jim Eddinger, c/o
OAQPS Document Control Officer (Mail Drop C404-02), U.S. EPA, Research
Triangle Park, NC 27711, Attention Docket ID No. EPA-HQ-OAR-2002-0058.
Docket. The docket number for this notice is Docket ID No. EPA-HQ-
OAR-2002-0058.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of this notice will be posted on the WWW through the
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Technology Transfer Network Web site (TTN Web). Following signature,
the EPA will post a copy of this notice at http://www.epa.gov/ttn/atw/boiler/boilerpg.html. The TTN provides information and technology
exchange in various areas of air pollution control.
II. Background
On March 21, 2011, the EPA promulgated national emissions standards
for hazardous air pollutants (NESHAP) for the Major Source Boilers and
Process Heaters source category. The EPA received a number of petitions
for reconsideration on that action, and granted reconsideration on
certain issues raised in the petitions. On January 31, 2013, the EPA
promulgated amendments to the NESHAP for new and existing industrial,
commercial, and institutional boilers and process heaters located at
major sources (78 FR 7138). Following promulgation of the January 31,
2013, final rule, the EPA received 10 petitions for reconsideration
pursuant to section 307(d)(7)(B) of the Clean Air Act (CAA). The EPA
received petitions dated March 28, 2013, from New Hope Power Company
and the Sugar Cane Growers Cooperative of Florida. The EPA received a
petition dated March 29, 2013, from the Eastman Chemical Company. The
EPA received petitions dated April 1, 2013, from Earthjustice, on
behalf of Sierra Club, Clean Air Council, Partnership for Policy
Integrity, Louisiana Environmental Action Network, and Environmental
Integrity Project; American Forest and Paper Association on behalf of
American Wood Council, National Association of Manufacturers, Biomass
Power Association, Corn Refiners Association, National Oilseed
Processors Association, Rubber Manufacturers Association, Southeastern
Lumber Manufacturers Association, and U.S. Chamber of Commerce; the
Florida Sugar Industry; Council of Industrial Boiler Owners, American
Municipal Power, Inc., and American Chemistry Council; American
Petroleum Institute; and the Utility Air Regulatory Group which also
submitted a supplemental petition on July 3, 2013. Finally, the EPA
received a petition dated July 2, 2013, from the Natural Environmental
Development Association's Clean Air Project and the Council of
Industrial Boiler Owners. The petitions are available for review in the
rulemaking docket (see Docket ID No. EPA-HQ-OAR-2002-0058).
On August 5, 2013, the EPA issued letters to the petitioners
granting reconsideration on three specific issues raised in the
petitions for reconsideration and indicating that the agency would
issue a Federal Register notice regarding the reconsideration
process.\1\ This action requests comment on the three issues for which
the EPA granted reconsideration and proposes certain revisions to the
definitions of startup and shutdown and the work practices that apply
during startup and shutdown periods. Additionally, the letters
indicated that the EPA intends to make certain clarifying changes and
corrections to the final rule, some of which were also raised in the
petitions for reconsideration. This action proposes revisions to the
regulatory text that would make those clarifications and corrections.
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\1\ The EPA is still reviewing the other issues raised in the
petitions for reconsideration and is not taking any action at this
time with respect to those issues.
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III. Discussion of the Issues Under Reconsideration
The EPA took final action on its proposed amendments to the March
2011 NESHAP on January 31, 2013, (78 FR 7138) to address certain issues
raised in the petitions for reconsideration of the 2011 NESHAP.
The January 31, 2013, amendments revised, among other things, the
definitions of ``startup'' and ``shutdown'' as well as the work
practice requirements for the startup and shutdown periods. The
amendments also established a carbon monoxide (CO) threshold level as
an appropriate minimum maximum achievable control technology (MACT)
floor level that adequately assures sources will be controlling organic
HAP emissions to MACT levels. The amendments also replaced the
requirement for certain units to install and operate a continuous
emission monitoring system (CEMS) measuring particulate matter (PM)
emissions with a requirement to install and operate a PM continuous
parameter monitoring system (CPMS) which established reporting
requirements for deviations and established conditions under which PM
CPMS deviations would constitute a presumptive violation of the NESHAP.
The EPA received petitions for reconsideration of certain aspects of
these requirements, and granted reconsideration of the following three
issues on August 5, 2013, to provide an additional opportunity for
public comment:
Definition of startup and shutdown periods and the work
practices that apply during such periods;
Revised CO limits based on a minimum CO level of 130 parts
per million (ppm); and
The use of PM CPMS, including the consequences of
exceeding the operating parameter.
The reconsideration petitions stated that the public lacked
sufficient opportunity to comment on these provisions. Although these
provisions were established after consideration of public comments
received on the proposed rule, the EPA is granting reconsideration on
these issues in order to allow an additional opportunity for comment.
These issues are discussed in more detail in the following sections.
For the startup and shutdown provisions, the EPA is proposing
certain revisions to the definitions of startup and shutdown and to the
work practice standard that applies during the startup and shutdown
periods. The proposed revision to the definition of startup is the
addition of an alternate definition of startup. The revision to the
work practice standard that applies during the startup period is the
addition of an alternate work practice provision regarding the engaging
of control devices that applies during startup periods. The EPA is not
proposing revisions to the CO limits or the use of PM CPMS, but will
consider any input that we receive in this additional public comment
opportunity.
Additionally, the EPA is proposing certain clarifying changes and
corrections to the final rule, some of which were also raised in the
petitions for reconsideration. Specifically, these are: (1) Clarify
issues related to the applicability of the major source boiler rule to
natural gas-fired electric utility steam generating units (EGUs); (2)
clarify the compliance date for coal- or oil-fired EGUs that become
subject to the major source boiler rule; (3) correct a conversion error
in the MACT floor calculation for existing hybrid suspension grate
boilers; (4) clarify certain recordkeeping requirements, including, for
example, those related to records for periods of startup and shutdown
for boilers and process heaters in the Gas 1 subcategory. The EPA also
proposes to clarify and correct certain inadvertent inconsistencies in
the final rule regulatory text, such as removal of unnecessary
references to statistical equations, inclusion of averaging time for
operating load limits in Table 8 to the final rule, and correction of
the compliance date for new sources to reflect the effective date of
the final rule.
A. Startup and Shutdown Provisions
The EPA received petitions asserting that the public lacked an
opportunity to comment on the startup and shutdown provisions amended
in the January
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2013, final rule. Specifically, petitioners asserted that the
definitions of ``startup'' and ``shutdown'' in the amended final rule
failed to address restarts of process heaters and that the provisions
for work practice standards did not adequately address fuels considered
``clean'' and operational limitations for certain pollution control
devices.
In response to petitions for reconsideration received on the March
2011 NESHAP, the EPA proposed definitions of ``startup'' and
``shutdown'' in December 2011 that were based on load specifications.
The EPA received comments on the proposed definitions stating that load
specifications within the definitions were inconsistent with either
safe or normal (proper) operation of the various types of boilers and
process heaters encountered within the source category. As the basis
for defining periods of startup and shutdown, a number of commenters
suggested that the EPA instead use the achievement of various steady-
state conditions. The definitions in the January 2013 final rule
addressed these comments by defining startup and shutdown based on the
time during which fuel is fired in a boiler or process heater for the
purpose of supplying steam or heat for heating and/or producing
electricity or for any other purpose. As explained in the preamble to
the January 2013 final rule, the EPA believes these definitions are
appropriate because boilers and process heaters function to provide
steam or heat; therefore, boilers and process heaters should be
considered to be operating normally at all times steam or heat of the
proper pressure, temperature and flow rate is being supplied to a
common header system or energy user(s) for use as either process steam
or for the cogeneration of electricity.
The EPA also proposed work practices for startup and shutdown
periods in the December 2011 notice, which generally required employing
good combustion practices. In the January 2013 final rule, the EPA
revised the proposed work practice standards after consideration of
comments received. Among other things, the revised final work practice
standards required sources to combust clean fuels during startup and
shutdown periods and required sources to engage air pollution control
devices (APCDs) when coal, biomass or heavy oil are fired in the boiler
or process heater. (See 78 FR 7198-99.)
We are granting reconsideration on the definitions of startup and
shutdown and the work practices that apply during these periods that
are in the January 2013 final rule and are also proposing certain
revisions to these aspects of the startup and shutdown provisions that
are in the January 2013 final rule. We are also proposing an alternate
definition of startup and an alternate work practice provision
regarding the engaging of pollution control devices.
1. Definitions
We are soliciting comment on the definition of startup and shutdown
that were promulgated in the January 2013 final rule, with the
clarifying revisions explained below. We are proposing to revise the
definitions of startup and shutdown in this reconsideration notice as
set forth in 40 CFR 63.7575. Petitioners asserted that the final rule's
definitions of startup and shutdown were not sufficiently clear. We are
proposing to revise the definitions as explained below.
a. Definition of Startup Period. In addition to soliciting public
comment on the definition of startup contained in the January 2013
final rule, the EPA is proposing to add an alternate definition to the
definition of startup that is in the January 2013 final rule. We are
proposing to allow sources to use either definition of startup when
complying with the startup requirements. As explained in more detail
below, under the alternate definition, startup would end four hours
after the unit begins supplying useful thermal energy.
Specifically, the EPA is proposing the alternate definition to
clarify that, in terms of the first-ever firing of fuel, startup begins
when fuel is fired for the purpose of supplying useful thermal energy
(such as steam or heat) for heating, process, cooling, and/or producing
electricity and to clarify that startup ends 4 hours after when the
boiler or process heater makes useful thermal energy. The proposed
clarification regarding the end of startup would apply to first-ever
startups as well as startups occurring after shutdown events. With
regard to when startup begins after a shutdown event, the alternate
definition is the same as the definition in the January 31, 2013, final
rule. That is, startup begins with the firing of fuel in a boiler for
any purpose after a shutdown event.
In this alternate definition, we are proposing the clarification
regarding the first-ever firing of fuel to address implementation
issues regarding ``pre-startup'' activities that are done as part of
installing a new boiler or process heater. Under the January 2013
definition of ``startup,'' a new boiler or process heater would be
considered to have started up, and be subject to the rule, when it
first fires fuel ``for any purpose.'' However, a newly installed unit
needs to be tested to ensure that it was properly installed and will
operate as it was designed and that all associated components were also
properly installed and will operate as designed. The EPA did not intend
for the startup period to begin when newly installed units first fire
fuel for testing or other pre-startup purposes because such firing of
fuel does not represent normal operation of the unit.
The EPA is also proposing in the alternate definition to replace
the term ``steam and heat'' in the January 2013 definition of startup
with the term ``useful thermal energy.'' This proposed revision would
apply to first-ever startups as well as startups after shutdown events
and is intended to address the issue raised by petitioners that the
language in the January 2013 definition regarding the end of the
startup period is ambiguous since once fuel is fired some steam or heat
is generated but not in useful or controllable quantities. The
petitioners comment that it takes time for steam and process fluid to
be heated to adequate temperatures and pressures for beneficial use and
that steam or heat should not be construed to be supplied until it is
of adequate temperature and pressure. The EPA agrees with petitioners
that the startup period should not end until such time as fuel is fired
resulting in steam or heat that is useful thermal energy because it
takes time for steam and process fluids to be heated to adequate
temperatures and pressures for beneficial use. We believe the
appropriate criteria for ending startup in the definition should be
when useful steam is supplied. This proposed change doesn't alter EPA's
determination that it is not technically feasible to require stack
testing, in particular, to complete the multiple required test runs
during periods of startup and shutdown due to physical limitations and
the short duration of startup and shutdown periods.
In order to clarify the term ``useful thermal energy,'' we are
proposing a definition for ``useful thermal energy'' as follows:
Useful thermal energy means energy (i.e., steam, hot water, or
process heat) that meets the minimum operating temperature and/or
pressure required by any energy use system that uses energy provided by
the affected boiler or process heater.
The EPA received several petitions for reconsideration of the
definition of startup in the January 2013 final rule. The petitioners
commented that this definition does not account for a wide range of
boilers that operationally are
[[Page 3094]]
still in startup mode even after some steam or heat is supplied to the
plant. Specifically, the petitioners commented that what constitutes
``startup'' for all boilers varies widely. For example, petitioners
claimed that some boilers begin to supply steam or heat for some
purposes onsite before they have achieved necessary temperature or load
to engage emission controls.
The petitioners commented that according to the final rule, a
boiler supplying even a small amount of steam would no longer be in
startup and would be required at that point in time to engage emission
controls. However, petitioners noted that according to equipment
specifications and established safe boiler operations, a boiler
operator should not engage emission controls until specific parameters
are met.
The petitioners expressed that, above all, the boiler/process
heater operator's primary concern during startup is safety. The startup
procedures must ensure that the equipment is brought up to normal
operating conditions in a safe manner, and startup ends when the
boiler/process heater and its controls are fully functional. The end of
startup occurs when safe, stable operating conditions are reached,
after emissions controls are properly operating. The startup provisions
should not include requirements that could affect safe operating
practices.
The EPA agrees with the petitioners that the startup period should
not end until such time that all control devices have reached stable
conditions. The EPA has very limited information specifically for
industrial boilers on the hours needed for controls to reach stable
conditions after the start of supplying useful thermal energy. However,
the EPA does have information for EGUs on the hours to stable control
operation after the start of electricity generation. Using hour-by-hour
emissions and operation data for EGUs reported to the agency under the
Acid Rain Program, we found that controls used on the best performing
12 percent EGUs reach stable operation within 4 hours after the start
of electricity generation. See technical support document titled
``Assessment of Startup Period at Coal-Fired Electric Generating
Units--Revised'' in the docket. Since the types of controls used on
EGUs are similar to those used on industrial boilers and the start of
electricity generation is similar to the start of supplying useful
thermal energy, we believe that the controls on the best performing
industrial boilers would also reach stable operation within 4 hours
after the start of supplying useful thermal energy and have included
this timeframe in the proposed alternate definition.\2\ This conclusion
is supported by the very limited information (13 units) the EPA does
have on industrial boilers and by information submitted by the Council
of Industrial Boiler Owners obtained from an informal survey of its
members on the time needed to reach stable conditions during startup.
We welcome comment and additional information on this point during the
public comment period.
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\2\ It is important to remember that the hour at which startup
ends is the hour at which reporting for the purpose of determining
compliance begins. Therefore, sources must collect and report
operating limit data following the end of startup. These data are
used in calculating whether a source is in compliance with the 30-
day average operating limits.
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b. Definition of Shutdown. In today's action, the EPA is proposing
to revise the definition of shutdown in the January 2013 final rule.
The EPA is proposing to clarify that shutdown begins when the boiler or
process heater no longer makes useful thermal energy and ends when the
boiler or process heater no longer makes useful thermal energy and no
fuel is fired in the boiler or process heater. Specifically, the EPA is
proposing to revise the regulatory text to replace the term ``steam and
heat'' with the term ``useful thermal energy'' to address the same
issue as raised by petitioners regarding the language in the definition
of ``startup'' described above. The EPA did not intend for the shutdown
period to begin until such time as fuel is no longer fired for the
purpose of creating useful thermal energy.
The EPA received several petitions for reconsideration of the
definition of shutdown in the January 2013 final rule. The petitioners
expressed concerns that the definition is problematic for units firing
solid fuels on a grate or in a fluidized bed combustor where the
residual material in the unit keeps burning after fuel feed to the unit
is stopped. In this case, petitioners explained that fuel is still
burning (``being fired'') in the unit despite the fact that load
reduction is occurring, additional fuel is not being fed, and the
shutdown process has clearly begun. For this reason, petitioners
recommend that the shutdown definition be revised to state that
shutdown begins either when none of the steam and heat from the boiler
or process heater is supplied for heating and/or producing electricity
or when fuel is no longer being fed to the boiler or process heater and
that shutdown ends when there is both no steam or heat being supplied
and no fuel being combusted in the boiler or process heater.
The EPA agrees with the petitioners' concerns and intended that the
shutdown period would begin when fuel is no longer being fired for the
purpose of creating useful thermal energy. The proposed revisions would
address the concern raised by the petitioner. The proposed revision is
appropriate because as the petitioners commented, for certain types of
boilers where the fuel is combusted on a grate or bed, fuel firing may
be considered to continue even after fuel feed to the unit is stopped.
2. Work Practice Standards
In today's action, the EPA is proposing to revise the work practice
standards in the January 2013 final rule that apply during periods of
startup and shutdown. Specifically, the EPA is proposing revisions to
the list of ``clean fuel'' in the January 2013 final rule and is
proposing an alternate work practice requirement for periods of startup
and shutdown. Sources would have the choice of complying with the work
practice requirement contained in the January 2013 final rule or the
alternate work practice requirement proposed in today's action.
Additionally, EPA is proposing a process through which sources can seek
an extension of the time period by which the alternate work practice
provision requires PM controls to be engaged, based on documented
safety considerations. Finally, EPA is proposing certain recordkeeping
and monitoring requirements that would apply to sources that choose to
comply with the alternate work practice. These proposed provisions are
described in more detail below.
a. Clean Fuel Requirement. The January 2013 final rule requires
sources to startup on ``clean fuel.'' The definition of ``clean fuel''
includes several fuels but does not include coal or biomass or other
solid fuels that many sources use during boiler startup. In the
December 2011 proposed rule, we solicited comment on ``whether other
work practices should be required during startup and shutdown,
including requirements to operate using specific fuels to reduce
emissions during such periods.''
In a petition for reconsideration, the petitioners claimed that the
list of clean fuels, as written, is too narrow. They requested that the
EPA expand the list to include all gaseous fuels meeting the ``other
gas 1'' classification as well as biodiesel, as distillate oil is
sometimes a biodiesel blend. They also requested that fuels that meet
the total selected metals (TSM), hydrogen chloride (HCl),
[[Page 3095]]
and mercury emission limits using fuel analysis should be added to the
list of clean fuels. Dry biomass (less than 20-percent moisture
content) should also be added to the list of clean fuels because they
claim it will burn cleaner than other solid fuels. Specifically, they
claim that it is a clean fuel for startup because it exhibits low HCl,
mercury and CO emissions due to its chloride, mercury, and moisture
content, and PM emissions would likely be below the dry biomass
subcategory PM limit. Therefore, the petition states that it is a
reasonable work practice for solid fuel boilers to burn only dry
biomass as clean fuel during startup. In addition, the petition
recommends that permitting authorities should have the flexibility to
approve other clean fuels that EPA may not have considered (e.g., other
renewable fuels).
We are proposing two changes to the list of clean fuels for
starting up a boiler or process heater. We agree that the list should
include all gaseous fuels meeting the ``other gas 1'' classification.
Also, we agree that any fuels that meet the applicable TSM, HCl and
mercury emission limits using fuel analysis should be added to the list
of clean fuels because their mercury, HCl and metals emissions would be
in compliance with the applicable emission limits without the use of
control devices. Sources would demonstrate compliance either through
fuel analysis for the relevant parameters or stack testing. The EPA
does not believe it is necessary to revise the regulatory text of the
``clean fuel'' definition to specifically include biodiesel on the list
since the definition of ``distillate oil'' in the rule includes
biodiesel.
b. Engaging Pollution Control Devices. The January 2013 final rule
required boilers and process heaters when they start firing coal/solid
fossil fuel, biomass/bio-based solids, heavy liquid fuel or gas 2
(other) gases to engage applicable pollution control devices except for
limestone injection in fluidized bed combustion (FBC) boilers, dry
scrubbers, fabric filters, selective non-catalytic reduction (SNCR) and
selective catalytic reduction (SCR), which must start as expeditiously
as possible. The EPA received several petitions for reconsideration of
this aspect of the work practice standard.
The petitioners expressed concerns that the requirement for
engaging applicable control devices does not accommodate potential
safety problems relative to electrostatic precipitator (ESP) operation.
Comments and recommended manufacturer operating procedures provided to
the EPA during the comment period for the December 2011 proposal
explained the potential hazards associated with ESP energization when
unburned fuel may be present with oxygen levels high enough that the
mixture can be in the flammable range. The petitioners referenced these
comments and requested that the EPA needs to reconsider this safety
issue and revise the requirements to include ESP energization with the
other controls that are to be started as expeditiously as possible
rather than when solid fuel firing is first started. In addition, they
claim that the ESP cannot practically be engaged until a certain flue
gas temperature is reached. Specifically, they claim that premature
starting of this equipment will lead to short-term stability problems
that could result in unsafe actions and longer term degradation of ESP
performance due to fouling, increased chances of wire damage, or
increased corrosion within the chambers. They also state that vendors
providing this equipment incorporate these safety and operational
concerns into their standard operating procedures. For example, they
claim that some ESPs have oxygen sensors and alarms that shut down the
ESP at high flue gas oxygen levels to avoid a fire in the unit. The
oxygen level is typically high during startup, so the ESP may not
engage due to these safety controls until more stable operating
conditions are reached. Therefore, the petitioners request that ESPs be
included in the list of air pollution controls that must be started as
expeditiously as possible.
Considering the petitioners' comments, the EPA is proposing an
alternate work practice requirement for operating air pollution control
devices during periods of startup as follows.
Boilers and process heaters owners and operators shall, when firing
coal/solid fossil fuel, biomass/bio-based solids, heavy liquid fuel or
gas 2 (other) gases, vent emissions to the main stack(s) and engage all
of the applicable control devices so as to comply with the emission
limits within 4 hours of start of supplying useful thermal energy.
Owners and operators must effect PM control within one hour of first
firing coal/solid fossil fuel, biomass/bio-based solids, heavy liquid
fuel or gas 2 (other) gases. Owners and operators must start all
applicable control devices as expeditiously as possible, but, in any
case, when necessary to comply with other standards applicable to the
source by a permit limit or a rule other than this subpart that require
operation of the control devices.
The EPA believes that the control technology operation related
requirements we are proposing are practicable and broadly applicable.
Owners and operators of boilers and process heaters have options to
minimize any potential for detrimental impacts on hardware and any
safety concerns, such as using clean fuels until appropriate flue gas
conditions have been reached and then switching to the primary fuel. In
addition, we are proposing in the alternate work practice requirement
that owners and operators of boilers and process heaters, if they have
an applicable emission limit, must develop and implement a written
startup and shutdown plan (SSP) according to the requirements in Table
3 to this subpart and that the SSP must be maintained onsite and
available upon request for public inspection. Also in the alternate
work practice requirement, we are proposing to allow a source to
request a unit-specific case-by-case extension to the 1-hour period for
engaging the PM controls. However, the EPA will only consider
extensions for units that can provide evidence of a documented
manufacturer-identified safety issue and can provide proof that the PM
control device is adequately designed and sized to meet the filterable
PM emission limit. In its request for the case-by-case determination,
the owner/operator must provide, among other materials, documentation
that: (1) The unit is using clean fuels to the maximum extent possible
to alleviate or prevent the safety issue prior to the combustion of
coal/solid fossil fuel, biomass/bio-based solids, heavy liquid fuel or
gas 2 (other) gases in the unit, (2) the source has explicitly followed
the manufacturer's procedures to alleviate or prevent the safety issue,
(3) details the manufacturer's statement of concern, and (4) provides
evidence that the PM control device is adequately designed and sized to
meet the PM emission limit.
In order to clarify that the work practice does not supersede any
other standard or requirements to which the affected source is subject,
the EPA is including in the proposed alternate work practice provision
a requirement that requires control devices to operate when necessary
to comply with other standards (e.g., new source performance standards,
state regulations) applicable to the source that require operation of
the control device.
In addition, to ensure compliance with the proposed definition of
startup and the work practice standard that applies during startup
periods, we are proposing that certain events and parameters be
monitored and recorded during the startup periods. These events include
the time when firing (i.e., feeding) starts for coal/solid fossil fuel,
[[Page 3096]]
biomass/bio-based solids, heavy liquid fuel or gas 2 (other) gases; the
time when useful thermal energy is first supplied; and the time when
the PM controls are engaged. The parameters to be monitored and
recorded include the hourly steam temperature, hourly steam pressure,
hourly flue gas temperature, and all hourly average CMS data (e.g.,
CEMS, PM CPMS, continuous opacity monitoring systems (COMS), ESP total
secondary electric power input, scrubber pressure drop, scrubber liquid
flow rate) collected during each startup period to confirm that the
control devices are engaged.
We request comments on (1) the startup and shutdown provisions
(definitions and work practices) in the January 2013 final rule, (2)
the proposed alternate definition for ``startup'' and the proposed
alternate work practice (item 5.c.(2) of Table 3 of proposed rule) for
the startup period, and (3) the recordkeeping requirements being
proposed for the startup periods.
B. CO Limits Based on a Minimum CO Level of 130 ppm
In the January 2013 final rule, EPA established a CO emission limit
for certain subcategories at a level of 130 ppm, based on an analysis
of CO levels and associated organic HAP emissions reductions. See 78 FR
7144. The EPA received a petition for reconsideration of these CO
limits in the January 2013 final rule. The petitioner claimed that
these limits do not satisfy the statutory requirement that the MACT
standard for existing sources is no less stringent than the average
emission limitation achieved by the best performing twelve percent of
units in the subcategory and that EPA's rationale for adopting these
limits is unrelated to this statutory MACT requirement.
The EPA revised these particular CO limits in the January 2013
final rule in part based on comments received during the comment period
for the December 2011 proposed rule stating that a CO emission standard
no lower than 100 ppm, corrected to 7-percent oxygen, is adequate to
assure complete control of organic HAP.
As explained in the preamble to the January 2013 final rule,
formaldehyde was selected as the basis of the organic HAP comparison
because it was the most prevalent organic HAP in our emission database
and a large number (over 300) of paired test runs existed for CO and
formaldehyde. The linear relationship between CO and formaldehyde
emissions exhibits a high correlation for CO levels above 150 ppm,
supporting the selection of CO as a surrogate for organic HAP
emissions. In assessing the correlation between CO and formaldehyde, a
trend can be seen that formaldehyde levels are lowest when CO emissions
are in the range of 150 to 300 ppm. At levels lower than 150 ppm, the
mean levels of formaldehyde appear to increase. Based on this analysis,
we promulgated a minimum MACT floor level for CO of 130 ppm, at 3-
percent oxygen, (which is equivalent to 100 ppm corrected to 7-percent
oxygen) which we believe is protective of human health and the
environment.
The EPA does not believe the petitioners have provided sufficient
justification that the revised CO limits in the January 2013 final rule
do not satisfy the CAA's statutory floor requirements, and the EPA
continues to believe that these standards do in fact satisfy the CAA's
floor requirements. CAA section 112(d)(3) states that emission
standards for existing sources shall not be less stringent, and may be
more stringent than ``the average emission limitation achieved by the
best performing sources (for which the Administrator has emission
information).'' If ``lowest emitting'' is used as the measure for
determining ``best performing'' sources, then the 130 ppm standard does
satisfy the CAA's floor requirements. When the available formaldehyde
emission information is ranked and the best performing 12 percent
identified, the mathematical average of the best performing units'
corresponding CO emission levels is 240 ppm which is in the range,
previously indicated, that formaldehyde emission levels are lowest.
However, in consideration of the fact that the public lacked the
opportunity to comment on the CO emission limits established at the
level of 130 ppm, corrected to 3-percent oxygen, the EPA has granted
reconsideration on the CO emission limits established at the level of
130 ppm, corrected to 3-percent oxygen, to provide an additional
opportunity for public comment on those limits. The EPA is not
soliciting comment on any other CO limits, or on other issues relating
to establishment of CO limits, including the question of whether EPA
should establish work practice standards for CO instead of numeric
limits.
If, after evaluating all comments and data received on this issue,
the EPA determines that amendments to the CO emission limits
established at the level of 130 ppm, corrected to 3-percent oxygen, may
be appropriate, we will propose such amendments in a future regulatory
action.
C. Use of PM CPMS Including Consequences of Exceeding the Operating
Parameter
The January 2013 amended final rule requires units combusting solid
fossil fuel or heavy liquid with heat input capacities of 250 million
British thermal units per hour (MMBtu/hr) or greater to install,
maintain, and operate PM CPMS. The provisions regarding PM CPMS in the
January 2013 final rule are consistent with regulations for similarly-
sized commercial and industrial solid waste incinerator units, Portland
cement kilns, and EGUs subject to the Mercury and Air Toxics Standards
(MATS) Rule.
The March 21, 2011, final rule required boilers with a heat input
rate greater than 250 MMBtu/hr from solid fuel and/or residual oil to
install and operate a PM CEMS to demonstrate compliance with the
applicable PM emission limit. In petitions for reconsideration to the
March 2011 final rule, petitioners objected to this requirement,
claiming that the EPA had failed to consider the ability of PM CEMS to
meet the required Performance Specification 11 (PS 11) criteria, or to
accurately measure PM, at the levels of the proposed standards. In the
December 2011 Reconsideration proposal, the EPA acknowledged
petitioners' concerns regarding application of PM CEMS technology to
various types of boilers, and concluded that for coal- and oil-fired
boilers PM CEMS would best be employed as parametric monitors (i.e., as
a PM CPMS). Specifically, rather than correlate the PM CEMS to the EPA
reference method using PS 11, the EPA proposed that sources establish a
site-specific enforceable operating limit in terms of the PM CPMS
output during the initial and periodic performance tests, and meet that
operating limit on a 30-day rolling average basis. However, commenters
objected to the EPA's proposal to impose an enforceable site-specific
operating limit based on output during a short-term stack test which
would not capture the variability in PM CPMS output that may occur
during operations consistent with the PM limit.
In the January 2013 final rule, the EPA finalized the requirement
for use of a PM CPMS, but added provisions allowing sources a certain
number of exceedances of the operating parameter limit before an
exceedance would be presumed to be a violation, and allowing certain
low emitting sources to ``scale'' their site-specific operating limit
to 75 percent of the emission standard. Specifically, under the January
2013 final rule, boilers opting to
[[Page 3097]]
use PM CPMS will establish an operating limit as the average parameter
value (in terms of raw output from a PM CEMS) obtained during the
performance test and, if the boiler did not exceed 75 percent of the
emission limit during the performance test, the boiler may linearly
scale the average parameter value up to 75 percent of the limit to
obtain a new scaled parameter. Compliance with the parameter limit is
determined on a 30-boiler-operating-day rolling average basis. For any
exceedance of the 30-boiler-operating-day PM CPMS value, the owner or
operator must (1) inspect the control device within 48 hours and, if a
cause is identified, take corrective action as soon as possible, and
(2) conduct a new performance test to verify or reestablish the
operating limit within 30 calendar days. Additional exceedances that
occur between the original exceedance and the performance test do not
trigger another test. Up to four performance tests may be triggered in
a 12-month rolling period without additional consequences. However,
each additional performance test that is triggered would constitute a
separate presumptive violation.
The EPA received a petition for reconsideration on the use of PM
CPMS. Specifically, the petitioner stated that while the option has the
advantage of avoiding the testing issues associated with PS 11
correlations of PM CEMS, absent that correlation the parameter is
nothing more than an indicator that PM may be increasing or decreasing.
Therefore, while it is useful as a tool to identify the need for
investigation and corrective action, the petitioner does not believe it
is an appropriate tool to establish a violation as long as the
requirement for corrective action is met.
The petitioner claimed that any affected boiler that tests at its
normal operating condition to establish a PM CPMS operating limit could
be testing at a level well below the applicable emission limit. For
such a boiler, the petitioner does not believe there is any basis to
assume that an exceedance (or even multiple exceedances) of a 30-
boiler-operating-day rolling average parameter limit indicates that the
emission limit was exceeded, or that controls were not operated
properly. Rather, the petitioner claims, it simply means that emissions
on average probably were above the level of emissions during the last
successful performance test. Unless the source has collected data to
determine what PM CPMS parameter level is equivalent to a violation of
the emission standard, the petitioner states that there is no basis to
suggest that any parameter exceedance is a violation. The petitioner
also argued that if a source that has invested in a PM CPMS is
conducting appropriate investigations and corrective action in response
to parameter exceedances, there is no basis to label the source a
violator as a result of its fourth successful performance test in a 12-
month period.
In its petition for reconsideration, the petitioner also expressed
concerns about the scaling procedure that the EPA added to that rule in
an attempt to address the fact that ``actual stack emissions of PM
could still be well below the limit.'' The petitioner expressed
appreciation of the EPA's attempt to address that issue for industrial
boilers by also allowing scaling of the as-tested parameter value.
However, the petitioner claims that EPA's use of 75 percent of the
emission level as the upper point is arbitrary and still puts sources
that are operating with significant compliance margin at risk of a
violation. For a scaled limit to justify a violation, the petitioner
believes that the EPA must establish not only the consistency of the
uncorrelated measurements over time, but allow scaling up to 100
percent of the emission limit. Only at that point would there be a
reasonable basis to conclude that a performance test might have failed.
In sum, the petitioner claimed that for PM CPMS to be useful as an
alternative to stack testing for compliance with the alternate TSM
standards or PM CEMS, the EPA must (1) allow scaling up to 100 percent
of the emission limit, and (2) remove its definition of a violation in
favor of a pure investigation and corrective action approach.
The EPA is not proposing to revise the PM CPMS provisions in the
January 31, 2013, final rule. The basis for the inclusion of the
definition of a violation is that the site-specific CPMS limit could
represent an emissions level higher than the proposed numerical
emissions limit since the PM CPMS operating limit corresponds to the
highest of the three runs collected during the Method 5 performance
test. Second, the PM CPMS operating limit reflects a 30-day average
that should represent an actual emissions level lower than the three
test run numerical emissions limit since variability is mitigated over
time. Consequently, we believe that there should be few if any
deviations from the 30-day parametric limit and there is a reasonable
basis for presuming that deviations that lead to multiple performance
tests to represent poor control device performance and to be a
violation of the standard. We continue to believe that there should be
few if any deviations from the 30-day parametric limit and that there
is a reasonable basis for presuming that deviations that lead to
multiple performance tests represent poor control device performance
and therefore constitute a presumptive violation of the standard,
particularly since that presumption can be rebutted. Therefore, we
continue to believe that PM CPMS deviations leading to more than four
required performance tests in a 12-month process operating period
should be presumed a violation of this standard, subject to the
source's ability to rebut that presumption with information about
process and control device operations in addition to the Method 5
performance test results. Therefore, the EPA is not proposing to revise
that PM CPMS provision in the January 2013 final rule.
Based on an extensive analysis (see S. Johnson's memo
``Establishing an Operating Limit for PM CPMS'', November 2012, docket
ID number EPA-HQ-OAR-2011-0817-0840), we also continue to believe a
scaling factor of 75 percent of the emission limit as a benchmark is
appropriate and are not proposing to revise that provision of the
January 2013 final rule. We recognized that non-linear instruments
provide increased uncertainty in estimating PM concentrations above the
performance test data point and, after considering several options, we
determined that the 75-percent scaling cap was appropriate for
protecting the emission standard in this regard. This option provided
flexibility for low emitting and well-operated sources, and was
determined to be a reasonable compromise between flexibility for the
regulated source and assurance that the emission standard is met.
Seventy-five percent of the emission limit is an already-established
threshold in the Standards of Performance for New Stationary Sources
and Emission Guidelines for Existing Sources: Commercial and Industrial
Solid Waste Incineration Unit (76 FR 15757) to determine the frequency
of subsequent compliance testing. In that rule, owners or operators of
sources were able to reduce their performance test frequency when
emissions were equivalent with or below 75 percent of the limits.
Otherwise, performance testing was to occur at the normal frequency
prescribed in the rule. We believe this threshold can be used in
conjunction within a PM CPMS scaling factor, as results above 75
percent of the equivalent emissions limit would be ineligible for
scaling factor use and could lead to increased performance testing and
potentially to a presumptive
[[Page 3098]]
violation, while results equivalent with or below 75 percent of the
emissions limit would be eligible for scaling factor use and provide
greater operational flexibility for sources demonstrating compliance at
lower emission rates.
For these reasons, the EPA is not proposing to revise the
requirements in 40 CFR 63.7440(a)(18) for demonstrating continuous PM
emission compliance using a PM CPMS. However, the EPA is soliciting
additional comment on these requirements in today's action. The EPA
welcomes comments on these provisions, including whether the provisions
are necessary or appropriate. If a commenter suggests revisions to the
provisions, the commenter should provide detailed information
supporting any such revision.
IV. Technical Corrections and Clarifications
We are proposing several technical corrections. These amendments
are being proposed to correct inadvertent errors that were promulgated
in the final rule and to make the rule language consistent with
provisions addressed through this reconsideration. We are soliciting
comment only on whether the proposed changes provide the intended
accuracy, clarity and consistency. These proposed changes are described
in Table 1 of this preamble. We request comment on all of these
proposed changes.
Table 1--Miscellaneous Proposed Technical Corrections to 40 CFR Part 63,
Subpart DDDDD
------------------------------------------------------------------------
Section of subpart DDDDD Description of proposed correction
------------------------------------------------------------------------
40 CFR 63.7491(a)............ Revise the language in this paragraph to
clarify that natural gas-fired EGUs as
defined in subpart UUUUU are not subject
to the rule if firing at least 90
percent natural gas.
40 CFR 63.7491(j)............ Revise this paragraph to include the
words ``and process heaters'' to clarify
that it also applies to process heaters.
40 CFR 63.7491(l)............ Revise this paragraph to include the
words ``and process heaters'' to clarify
that it also applies to process heaters.
40 CFR 63.7491(n)............ Insert paragraph (n) which was in amended
final rule but inadvertently had the
wrong amendatory instruction to be
included in the CFR.
40 CFR 63.7495(a)............ Revise this paragraph to correctly
include the effective date (April 1,
2013) instead of the publication date
(January 31, 2013) of the amendments.
40 CFR 63.7495(e)............ Revise this paragraph to add the language
which was in amended final rule but
inadvertently had the wrong amendatory
instruction to be included in the CFR.
40 CFR 63.7495(f)............ Revise this paragraph to correctly list
the date (January 31, 2016) after which
existing EGUs that become subject to the
rule must be in compliance.
40 CFR 63.7495(h) and (i).... Insert these paragraphs to clarify when
existing and new affected units that
switch subcategories due to fuel switch
or physical change must be in compliance
with the provisions of the new
subcategory.
40 CFR 63.7500(a)............ Revise this paragraph to delete the comma
after ``paragraphs (b).''
40 CFR 63.7500(a)(1)(ii)..... Revise this paragraph by adding the words
``on or'' to include May 20, 2011.
40 CFR 63.7500(a)(1)(iii).... Revise this paragraph by adding the words
``on or'' to include December 23, 2011
and to correctly include the effective
date (April 1, 2013) instead of the
publication date (January 31, 2013) of
the amendments.
40 CFR 63.7500(f)............ Revise this paragraph to clarify that
only items 5 and 6 of Table 3 apply
during periods of startup and shutdown.
40 CFR 63.7505(a)............ Revise this paragraph by adding the words
``emission and operating'' to clarify
the limits that apply at all times.
40 CFR 63.7505(c)............ Revise this paragraph by adding the word
``stack'' to clarify that the
performance testing referred to is
performance stack testing.
40 CFR 63.7510(a)(2)(ii)..... Revise this paragraph to clarify our
intent on fuel type for the analysis
requirements for gaseous fuels.
40 CFR 63.7510(a)............ Revise this paragraph by adding the word
``stack'' to clarify that the
performance tests referred to are
performance stack test.
40 CFR 63.7510(c)............ Revise this paragraph to correct the
reference to tables 1 and 2, not 12.
40 CFR 63.7510(e)............ Revise this paragraph to remove reference
to paragraph (j) for the one-time energy
assessment because paragraph (j) only
repeat the compliance date as indicated
in paragraph (e) and to pluralize the
word ``demonstration.''
40 CFR 63.7510(g)............ Revise this paragraph to correct the
references to 40 CFR 63.7515(d), not 40
CFR 63.7540(a) to clarify the
appropriate schedule for conducting
periodic tune-ups.
40 CFR 63.7510(i)............ Revise this paragraph to correctly list
the initial compliance date (January 31,
2016).
40 CFR 63.7510(k)............ Add this paragraph to clarify the
appropriate schedule for conducting
performance tests after a switch in
subcategory.
40 CFR 63.7515(d)............ Revise this paragraph to clarify that the
first annual, biennial, or 5-year tune-
up must be no later than 13 months, 25
months, or 61 months, respectively,
either after April 1, 2013, or the
initial startup of the new or
reconstructed affected source, whichever
is later.
40 CFR 63.7515(h)............ Revise this paragraph to clarify that
``performance tests'' refers to both
stack tests and fuel analyses.
40 CFR 63.7521(a)............ Revise this paragraph to clarify that
gaseous and liquid fuels are not exempt
from the sampling requirements in Table
6 of the rule.
40 CFR 63.7521(c)(1)(ii)..... Revise this paragraph to remove the
requirement to collect monthly samples
at 10-day intervals because it is
inconsistent with the requirement for
monthly fuel analysis in 40 CFR
63.7515(e).
40 CFR 63.7521(f)............ Revise this paragraph to clarify that the
two methods listed in Table 6 for
determining the mercury concentration
for other gas 1 fuels are alternatives.
40 CFR 63.7521(g)............ Revise this paragraph to remove the
requirement to submit for review and
approval a site-specific fuel analysis
plan for other gas 1 fuels because
paragraph (g)(1) requires the plan to be
submitted for review and approval only
if an alternative analytical method
other than those required by Table 6 is
intended to be used.
40 CFR 63.7521(h)............ Revise this paragraph to remove the
reference to sampling procedures listed
in Table 6 because there are no sampling
procedures listed in Table 6 for gaseous
fuel.
40 CFR 63.7522(c)............ Revise this paragraph by changing wording
from ``January 31, 2013'' (publication
date of the amendments) to ``April 1,
2013'' (the effective date of the
amendments.
40 CFR 63.7522(d)............ Revise this paragraph by changing wording
from ``operating'' to ``subject to
numeric emission limits'' to clarify
that the numeric emission limits do not
apply during startup and shutdown
periods.
40 CFR 63.7522(j)(1)......... Revise Equation 6 to delete ``nanograms
per dry standard cubic meter (ng/dscm)''
from both EN and Eli since there are not
numeric emission limits for dioxin.
[[Page 3099]]
40 CFR 63.7525(a)............ Revise the paragraph to clarify that the
procedures for installing oxygen
analyzer system or CO CEMS do not
include paragraph (a)(7) because (a)(7)
does not require the installation of an
oxygen trim system.
40 CFR 63.7525(a), (a)(1), Revise these paragraphs to clarify that
(a)(2), (a)(3), and (a)(5). carbon dioxide may be used as an
alternative to using oxygen in
correcting the measured CO CEMS data
without petitioning for an alternative
monitoring procedure.
40 CFR 63.7525(a)(7)......... Revise this paragraph to clarify the
oxygen set point for a source not
required to conduct a CO performance
test.
40 CFR 63.7525(b) and (b)(1). Remove the word ``certify'' because there
is no certification procedure for PM
CPMS.
40 CFR 63.7525(b)(1)(iii).... Revise this paragraph to clarify that the
0.5 milligram per actual cubic meter is
the detection limit.
40 CFR 63.7525(g)(3)......... Revise this paragraph to clarify that the
pH monitor is to be calibrated each day
and not performance evaluated which is
covered in 40 CFR 63.7525(g)(4).
40 CFR 63.7525(m)............ Revise this paragraph to clarify that 40
CFR 63.7525(m) is only applicable if the
source elects to use an SO2 CEMS to
demonstrate compliance with the HCl
emission limit and to clarify that the
SO2 CEMS can be certified according to
either part 60 or part 75.
40 CFR 63.7530............... Revise equations 7, 8, and 9 to clarify
that for ``Qi'' the highest content of
chlorine, mercury, and TSM is used only
for initial compliance and the actual
fraction is used for continuous
compliance demonstration.
40 CFR 63.7530(a)............ Revise this paragraph to clarify which
fuels are exempt from analysis by cross-
referencing 40 CFR 63.7510(a)(2),
instead of only 40 CFR 63.7510(a)(2)
(i).
40 CFR 63.7530(b)............ Revise this paragraph by adding the word
``stack'' to clarify that the
performance testing referred to is
performance stack testing.
40 CFR 63.7530(b)(4)(iii) to Revise the numbering of these paragraphs
(viii). to correct sequence.
40 CFR 63.7530(c)(3)......... Revise the reference to Equation 11 to be
Equation 15, to accommodate the change
in numbering of equations.
40 CFR 63.7530(c)(4)......... Revise the reference to Equation 11 to be
Equation 15, to accommodate the change
in numbering of equations.
40 CFR 63.7530(c)(5)......... Revise the reference to Equation 11 to be
Equation 15, to accommodate the change
in numbering of equations.
40 CFR 63.7530(d)............ Amend this paragraph to clarify that the
requirement to include a signed
statement that the tune-up was conducted
is applicable to all existing units.
40 CFR 63.7530(e)............ Amend this paragraph to clarify that the
energy assessment is also considered to
have been completed if the maximum
number of on-site technical hours
specified in the definition of energy
assessment applicable to the facility
has been expended.
40 CFR 63.7530(h)............ Revise this paragraph to clarify that
both items 5 and 6 of Table 3 apply
during periods of startup and shutdown.
40 CFR 63.7530(i)(3)......... Revise this paragraph to read ``maximum''
instead of ``minimum'' to be consistent
with item 10 of Table 4 to subpart
DDDDD.
40 CFR 63.7533(e)............ Revise this paragraph by changing wording
from ``operating'' to ``subject to
numeric emission limits'' to clarify
that the numeric emission limits do not
apply during startup and shutdown
periods.
40 CFR 63.7535(c)............ Amend this paragraph to clarify that data
recorded during periods of startup and
shutdown may not be used to report
emissions or operating levels.
40 CFR 63.7535(d)............ Amend this paragraph to clarify that data
recorded during periods of startup and
shutdown may not be used to report
emissions or operating levels and that
the report for reporting periods when
the monitoring system is out of control
is the facility's ``semi-annual''
report.
40 CFR 63.7540(a)(2)......... Revise the reference to 40 CFR 63.7550(c)
to 40 CFR 63.7555(d).
40 CFR 63.7540(a)(3) and Revise the reference to Equation 12 to
(a)(3)(iii). Equation 16, to accommodate the change
in numbering of equations.
40 CFR 63.7540(a)(5) and Revise the reference to Equation 13 to
(a)(5)(iii). Equation 17, to accommodate the change
in numbering of equations.
40 CFR 63.7540(a)(8)(ii)..... Revise this paragraph by changing wording
from ``operating'' to ``subject to
numeric emission limits'' to clarify
that the numeric emission limits do not
apply during startup and shutdown
periods.
40 CFR 63.7540(a)(10)........ Amend this paragraph to clarify that the
tune-up must be conducted while burning
the type of fuel that provided the
majority of the heat input over the 12
months prior to the tune-up.
40 CFR 63.7540(a)(10)(vi).... Revise paragraph to remove the word
``annual'' because not all facilities
will necessarily be subject to an annual
tune-up requirement.
40 CFR 63.7540(a)(17) and Revise the reference to Equation 14 to
(a)(17)(iii). Equation 18, to accommodate the change
in numbering of equations.
40 CFR 63.7540(a)(19)(iii)... Revise the reference from paragraph (i)
to paragraph (v).
40 CFR 63.7540(d)............ Revise the reference to item 5 of Table 3
to items 5 and 6 of Table 3 to
accommodate the splitting of the work
practice for startup and shutdown into
two separate items in Table 3.
40 CFR 63.7545(e)(8)(i)...... Revise this paragraph by changing the
wording from ``complies with'' to
``completed'' to add clarity.
40 CFR 63.7545(h)............ Revise this paragraph to clarify the
paragraph also applies to process
heaters.
40 CFR 63.7550(b)............ Revise this paragraph to clarify that
units subject only to both the energy
assessment and tune-up requirements may
submit only an annual, biennial, or 5-
year compliance report.
40 CFR 63.7550(b)(1), (b)(2), Revise these paragraphs to add the word
(b)(3), and (b)(4). ``semi-annual'' to clarify that the
compliance report initially discussed in
each paragraph is the semi-annual report
required for units subject to emission
limits.
40 CFR 63.7550(b)(1)......... Revise this paragraph to change the
reporting period end dates to be
consistent with the dates in 40 CFR
63.7550(b)(3).
40 CFR 63.7550 (c)(1)........ Revise this paragraph to remove the word
``a,'' to change the wording from
``they'' to ``you'' and to add reference
to 40 CFR 63.7550(c)(5)(xvii).
40 CFR 63.7550 (c)(2) and Revise these paragraphs to add reference
(c)(3). to 40 CFR 63.7550(c)(5)(xvii).
40 CFR 63.7550 (c)(3)........ Revise this paragraph to add reference to
40 CFR 63.7550(c)(5)(viii).
40 CFR 63.7550 (c)(2), (c)(3) Revise these paragraphs to change the
and (c)(4). wording from ``a facility is'' to ``you
are'' and ``they'' to ``you.''
40 CFR 63.7550 (c)(4)........ Revise the paragraph to include reference
to paragraph (c)(5)(xii).
[[Page 3100]]
40 CFR 63.7550(c)(5)(viii)... Revise the reference to Equation 12 to
Equation 16, the reference to Equation
13 to Equation 17, and the reference to
Equation 14 to Equation 18, to
accommodate the change in numbering of
equations.
40 CFR 63.7550(d)............ Revise this paragraph to clarify that
deviations from the work practice
standards for periods of startup and
shutdown must also be included in the
compliance report.
40 CFR 63.7550(h)............ Revise the paragraph to update electronic
reporting requirements.
40 CFR 63.7555(a)(3)......... Redesignating paragraph 63.7550(d)(3) as
new paragraph 63.7550(a)(3) because
limited use units are not subject to
emission limits.
40 CFR 63.7555(d)(4)......... Change the reference to Equation 12 to
Equation 16, to accommodate the change
in numbering of equations.
40 CFR 63.7555(d)(5)......... Change the reference to Equation 13 to
Equation 17, to accommodate the change
in numbering of equations.
40 CFR 63.7555(d)(9)......... Change the reference to Equation 14 to
Equation 18, to accommodate the change
in numbering of equations.
40 CFR 63.7555(i) and (j).... Delete paragraphs because paragraphs (i)
and (j) are identical to paragraphs
(d)(10) and (d)(11) to be consistent
with the intent of the amendments to
limit these reporting requirements to
units subject to emission limits.
40 CFR 63.7575............... Revise the definition of ``Coal'' to
clarify that coal derived liquids are
considered to be a liquid fuel type.
Add new definition of ``Fossil fuel'' to
clarify what is meant by ``fossil fuel''
in the definition of ``Electric utility
steam generating unit.''
Revise the definition of ``Limited-use
boiler or process heater'' to remove the
word ``average'' to eliminate confusion
regarding its use in the definition and
maintain consistent terminology within
the subpart.
Revise the definition of ``Load
fraction'' to clarify how load fraction
is determined for a boiler or process
heater cofiring natural gas.
Revise the definition of ``Oxygen trim
system'' to include draft controller and
to clarify that it is a system that
maintains the desired excess air level
over the operating load range.
Revise the definition of ``Steam output''
to clarify how steam output is
determined for multi-function units and
units supplying steam to a common
header.
Revise the definition of ``Temporary
boiler'' to clarify that the definition
is also applicable to process heaters.
Table 1 to subpart DDDDD..... Revise the subcategory ``Stokers designed
to burn coal/solid fossil fuel'' to
clarify that the subcategory includes
``other combustors'' consistent with the
stokers designed to burn biomass
subcategories.
Add footnote ``d'' to clarify that carbon
dioxide may be used as an alternative to
using oxygen in correcting the measured
CO CEMS data without petitioning for an
alternative monitoring procedure.
Table 2 to subpart DDDDD..... Revise the subcategory ``Stokers designed
to burn coal/solid fossil fuel'' to
clarify that the subcategory includes
``other combustors'' consistent with the
stokers designed to burn biomass
subcategories.
Revise the CO emission limit for hybrid
suspension grate units to account for a
conversion error in the emission
database that inadvertently resulted in
a source incorrectly being a best
performing unit.
Revise items 14.b and 16.b to add the
reference to footnote ``a.''
Add footnote ``c'' to clarify that carbon
dioxide may be used as an alternative to
using oxygen in correcting the measured
CO CEMS data without petitioning for an
alternative monitoring procedure.
Table 3 to subpart DDDDD..... Revise item 4 to clarify that
``operates'' does not require the energy
management program to be implemented in
perpetuity and that an energy management
program developed according to ENERGY
STAR guidelines would also satisfy the
requirement.
Revise item 4e to read ``program''
instead of ``practices'' to be
consistent with the definition of
``Energy management program'' in Sec.
63.7575.
Table 4 to subpart DDDDD..... Revise certain items in the table to
clarify the applicability of the
parameter operating limits also apply to
process heaters.
Revise item 4 to clarify that item 4.a.
is applicable to dry ESP and item 4.b.
is applicable to wet ESP systems.
Table 5 to subpart DDDDD..... Revise the heading of the third column to
clarify that the requirement to use a
specified method may not be appropriate
in all cases.
Add the missing footnote ``\a\
Incorporated by reference, see 40 CFR
63.14''
Table 6 to subpart DDDDD..... Revise items 1, 2, and 4 to remove
reference to the equations cited in 40
CFR 63.7530 for demonstrating only
initial compliance.
Revise items 1.c, 2.c, and 4.c to remove
the listed method for liquid samples to
be consistent with 40 CFR 63.7521(a).
Revise item 3 to clarify that the two
methods listed are alternatives.
Revise the title to item 4 to remove
``for solid fuels'' to clarify that item
4. is applicable to also liquid fuel
types.
Table 7 to subpart DDDDD..... Revise item 1.a.i.(1) to clarify that TSM
performance test are also included.
Revise items 2.a.i. and 2.a.i.(1) to
remove ``pressure drop'' to be
consistent with 40 CFR 63.7530(b).
Revise items 2.b.i.(1)(c) and
3.a.i.(1)(c) to clarify that ``load
fraction'' is as defined in 40 CFR
63.7575.
Revise item 2.c.i(1)(b) to read
``highest'' instead of ``lowest'' to be
consistent with item 10 of Table 4 to
subpart DDDDD.
Revise item 4 to read ``Carbon monoxide
for which compliance is demonstrated by
a performance test'' to clarify that
this operating limit is not applicable
for source complying with the CO CEMS
based limits.
Table 8 to subpart DDDDD..... Revise item 3 to change the reference to
40 CFR 63.7540(a)(9) to 40 CFR
63.7540(a)(7).
Revise item 9.a to change the reference
to 40 CFR 63.7525(a)(2) to 40 CFR
63.7525(a)(7).
Revise item 11.c to read ``highest''
instead of ``minimum'' to be consistent
with item 10 of Table 4 to subpart
DDDDD.
Revise the operating load compliance
provisions (item 10) to be consistent
with 40 CFR 63.7525(d).
Table 9 to subpart DDDDD..... Revise Table 9 to subpart DDDDD to
clarify that it is deviations from the
work practice standards for periods of
startup and shutdown that are to be
included.
Table 11 to subpart DDDDD.... Revise Table 11 to subpart DDDDD to be
consistent with the final amended rule
because of incorrect amendatory
instructions.
Table 12 to subpart DDDDD.... Revise Table 12 to subpart DDDDD to be
consistent with the final amended rule
because of incorrect amendatory
instructions.
------------------------------------------------------------------------
[[Page 3101]]
V. Affirmative Defense for Violation of Emission Standards During
Malfunction
In several prior CAA section 112 and CAA section 129 rules,
including this rule, the EPA had included an affirmative defense to
civil penalties for violations caused by malfunctions in an effort to
create a system that incorporates some flexibility, recognizing that
there is a tension, inherent in many types of air regulation, to ensure
adequate compliance while simultaneously recognizing that despite the
most diligent of efforts, emission standards may be violated under
circumstances entirely beyond the control of the source. Although the
EPA recognized that its case-by-case enforcement discretion provides
sufficient flexibility in these circumstances, it included the
affirmative defense to provide a more formalized approach and more
regulatory clarity. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011,
1057-58 (D.C. Cir. 1978) (holding that an informal case-by-case
enforcement discretion approach is adequate); but see Marathon Oil Co.
v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more
formalized approach to consideration of ``upsets beyond the control of
the permit holder.''). Under the EPA's regulatory affirmative defense
provisions, if a source could demonstrate in a judicial or
administrative proceeding that it had met the requirements of the
affirmative defense in the regulation, civil penalties would not be
assessed. Recently, the United States Court of Appeals for the District
of Columbia Circuit vacated an affirmative defense in one of the EPA's
CAA section 112 regulations. NRDC v. EPA, 749 F.3d 1055 (D.C. Cir.,
2014) (vacating affirmative defense provisions in CAA section 112 rule
establishing emission standards for Portland cement kilns). The court
found that the EPA lacked authority to establish an affirmative defense
for private civil suits and held that under the CAA, the authority to
determine civil penalty amounts in such cases lies exclusively with the
courts, not the EPA. Specifically, the court found: ``As the language
of the statute makes clear, the courts determine, on a case-by-case
basis, whether civil penalties are `appropriate.' '' See NRDC, 2014
U.S. App. LEXIS 7281 at *21 (``[U]nder this statute, deciding whether
penalties are `appropriate' . . . is a job for the courts, not EPA.'').
In light of NRDC, the EPA is proposing to remove the regulatory
affirmative defense provision in the current rule.
In the event that a source fails to comply with the applicable CAA
section 112 standards as a result of a malfunction event, the EPA would
determine an appropriate response based on, among other things, the
good faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
The EPA would also consider whether the source's failure to comply with
the CAA section 112 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).
Further, to the extent the EPA files an enforcement action against
a source for violation of an emission standard, the source can raise
any and all defenses in that enforcement action and the federal
district court will determine what, if any, relief is appropriate. The
same is true for citizen enforcement actions. Cf. NRDC at 1064
(arguments that violation was caused by unavoidable technology failure
can be made to the courts in future civil cases when the issue arises).
Similarly, the presiding officer in an administrative proceeding can
consider any defense raised and determine whether administrative
penalties are appropriate.
VI. Solicitation of Public Comment and Participation
The EPA seeks full public participation in arriving at its final
decisions. At this time, the EPA is only proposing alternatives to the
final rule's definitions of startup and shutdown, the work practices
that apply during those periods, and recordkeeping requirements for
startup periods. The EPA is not proposing any other specific revisions
to the reconsideration issues. However, the EPA requests public comment
on the three issues under reconsideration.
Additionally, the EPA is making certain clarifying changes and
corrections to the final rule. We are soliciting comments on whether
the proposed changes provide the intended accuracy, clarity and
consistency. The EPA is also proposing to amend the final rule by
removing the affirmative defense provision. We request comment on all
of these proposed changes.
The EPA is seeking comment only on the specific three issues, the
clarifying changes and corrections, and the amendments described in
this notice. The EPA will not respond to any comments addressing any
other issues or any other provisions of the final rule or any other
rule.
VII. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is not a significant regulatory action and was
therefore not submitted to the Office of Management and Budget (OMB)
for review.
B. Paperwork Reduction Act (PRA)
This action does not impose any new information collection burden
under PRA. With this action, the EPA is seeking additional comments on
three aspects of the final amended NESHAP for industrial, commercial,
and institutional boilers and process heaters located at major sources
of HAP with proposing only minor changes to the rule to correct and
clarify implementation issues raised by stakeholders. However, the
Office of Management and Budget (OMB) has previously approved the
information collection requirements contained in the existing
regulations under the provisions of the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. and has assigned OMB control number 2060-0551. The
OMB control numbers for the EPA's regulations in 40 CFR are listed in
40 CFR part 9.
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. This
action will not impose any requirements on small entities. This action
seeks comment on three aspects of the final NESHAP for industrial,
commercial, and institutional boilers and process heaters located at
major sources of HAP as well as proposing minor changes to the rule to
correct and clarify implementation issues raised by stakeholders.
We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act (UMRA)
This action does not contain any unfunded mandates as described in
UMRA, 2 U.S.C. 1531-1538. The action imposes no enforceable duty on any
[[Page 3102]]
state, local or tribal governments or the private sector.
This action seeks comment on three aspects of the final NESHAP for
industrial, commercial, and institutional boilers and process heaters
located at major sources of HAP with proposing minor changes to the
rule to correct and clarify implementation issues raised by
stakeholders.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government. This
action seeks comment on three aspects of the final NESHAP for
industrial, commercial, and institutional boilers and process heaters
located at major sources of HAP without proposing any changes to the
rule. Thus, Executive Order 13132 does not apply to this action.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and state and local
governments, the EPA specifically solicits comment on this proposed
action from state and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175. This action 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. Thus, Executive Order 13175 does
not apply to this action.
The EPA specifically solicits additional comment on this proposed
action from tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it does not concern an environmental
health risk or safety risk.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution or use of energy.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113, Section 12(d), 15 U.S.C. 272
note) directs the EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical. The VCS are technical
standards (e.g., materials specifications, test methods, sampling
procedures and business practices) that are developed or adopted by VCS
bodies. The NTTAA directs the EPA to provide Congress, through OMB,
explanations when the agency does not use available and applicable VCS.
This action does not involve technical standards. Therefore, the
EPA did not consider the use of any VCS.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
The EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. This action seeks comment on three aspects of the final
NESHAP for industrial, commercial, and institutional boilers and
process heaters located at major sources of HAP with proposing minor
changes to the rule to correct and clarify implementation issues raised
by stakeholders.
List of Subjects in 40 CFR Part 63
Environmental Protect, Administrative practice and procedure, Air
pollution control, Hazardous substances, Intergovernmental relations,
Reporting and recordkeeping requirements.
Dated: December 1, 2014.
Gina McCarthy,
Administrator.
For the reasons cited in the preamble, title 40, chapter I, part 63
of the Code of Federal Regulations is proposed to be amended as
follows:
PART 63-- NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
1. The authority for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart DDDDD--[Amended]
0
2. Section 63.7491 is amended by:
0
a. Revising paragraphs (a), (j) and (l).
0
b. Adding paragraph (n).
The revisions and addition read as follows:
Sec. 63.7491 Are any boilers or process heaters not subject to this
subpart?
* * * * *
(a) An electric utility steam generating unit (EGU) covered by
subpart UUUUU of this part or a natural gas-fired EGU as defined in
subpart UUUUU of this part firing at least 90 percent natural gas on an
annual heat input basis.
* * * * *
(j) Temporary boilers and process heaters as defined in this
subpart.
* * * * *
(l) Any boiler or process heater specifically listed as an affected
source in any standard(s) established under section 129 of the Clean
Air Act.
* * * * *
(n) Residential boilers as defined in this subpart.
0
3. Section 63.7495 is amended by:
0
a. Revising paragraphs (a) and (e).
0
b. Adding paragraphs (h) and (i).
The revisions and additions read as follows:
Sec. 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 April 1, 2013, or upon startup of
your boiler or process heater, whichever is later.
* * * * *
(e) If you own or operate an industrial, commercial, or
institutional
[[Page 3103]]
boiler or process heater and would be subject to this subpart except
for the exemption in Sec. 63.7491(l) for commercial and industrial
solid waste incineration units covered by part 60, subpart CCCC or
subpart DDDD, and you cease combusting solid waste, you must be in
compliance with this subpart and are no longer subject to part 60,
subparts CCCC or DDDD beginning on the effective date of the switch as
identified under the provisions of Sec. 60.2145(a)(2) and (3) or Sec.
60.2710(a)(2) and (3).
* * * * *
(h) If you own or operate an existing industrial, commercial, or
institutional boiler or process heater and have switch fuels or made a
physical change to the boiler or process heater that resulted in the
applicability of a different subcategory after January 31, 2016, you
must be in compliance with the applicable existing source provisions of
this subpart on the effective date of the fuel switch or physical
change.
(i) If you own or operate a new industrial, commercial, or
institutional boiler or process heater and have switch fuels or made a
physical change to the boiler or process heater that resulted in the
applicability of a different subcategory, you must be in compliance
with the applicable new source provisions of this subpart on the
effective date of the fuel switch or physical change.
* * * * *
0
4. Section 63.7500 is amended by revising paragraphs (a)(1) and (f) to
read as follows:
Sec. 63.7500 What emission limitations, work practice standards, and
operating limits must I meet?
(a) * * *
(1) You must meet each emission limit and work practice standard in
Tables 1 through 3, and 11 through 13 to this subpart that applies to
your boiler or process heater, for each boiler or process heater at
your source, except as provided under Sec. 63.7522. The output-based
emission limits, in units of pounds per million Btu of steam output, in
Tables 1 or 2 to this subpart are an alternative applicable only to
boilers and process heaters that generate either steam, cogenerate
steam with electricity, or both. The output-based emission limits, in
units of pounds per megawatt-hour, in Tables 1 or 2 to this subpart are
an alternative applicable only to boilers that generate only
electricity. Boilers that perform multiple functions (cogeneration and
electricity generation) or supply steam to common heaters would
calculate a total steam energy output using equation 21 of Sec.
63.7575 to demonstrate compliance with the output-based emission
limits, in units of pounds per million Btu of steam output, in Tables 1
or 2 to this subpart. If you operate a new boiler or process heater,
you can choose to comply with alternative limits as discussed in
paragraphs (a)(1)(i) through (a)(1)(iii) of this section, but on or
after January 31, 2016, you must comply with the emission limits in
Table 1 to this subpart.
(i) If your boiler or process heater commenced construction or
reconstruction after June 4, 2010 and before May 20, 2011, you may
comply with the emission limits in Table 1 or 11 to this subpart until
January 31, 2016.
(ii) If your boiler or process heater commenced construction or
reconstruction on or after May 20, 2011 and before December 23, 2011,
you may comply with the emission limits in Table 1 or 12 to this
subpart until January 31, 2016.
(iii) If your boiler or process heater commenced construction or
reconstruction on or after December 23, 2011 and before April 1, 2013,
you may comply with the emission limits in Table 1 or 13 to this
subpart until January 31, 2016.
* * * * *
(f) These standards apply at all times the affected unit is
operating, except during periods of startup and shutdown during which
time you must comply only with items 5 and 6 of Table 3 to this
subpart.
* * * * *
Sec. 63.7501 [Removed]
0
5. Section 63.7501 is removed.
0
6. Section 63.7505 is amended by revising paragraphs (a) and (c) and
adding paragraph (e) to read as follows:
Sec. 63.7505 What are my general requirements for complying with this
subpart?
(a) You must be in compliance with the emission limits, work
practice standards, and operating limits in this subpart. These
emission and operating limits apply to you at all times the affected
unit is operating except for the periods noted in Sec. 63.7500(f).
* * * * *
(c) You must demonstrate compliance with all applicable emission
limits using performance stack testing, fuel analysis, or continuous
monitoring systems (CMS), including a continuous emission monitoring
system (CEMS), continuous opacity monitoring system (COMS), continuous
parameter monitoring system (CPMS), or particulate matter continuous
parameter monitoring system (PM CPMS), where applicable. You may
demonstrate compliance with the applicable emission limit for hydrogen
chloride (HCl), mercury, or total selected metals (TSM) using fuel
analysis if the emission rate calculated according to Sec. 63.7530(c)
is less than the applicable emission limit. (For gaseous fuels, you may
not use fuel analyses to comply with the TSM alternative standard or
the HCl standard.) Otherwise, you must demonstrate compliance for HCl,
mercury, or TSM using performance stack testing, if subject to an
applicable emission limit listed in Tables 1, 2, or 11 through 13 to
this subpart.
* * * * *
(e) If you have an applicable emission limit, you must develop a
site-specific monitoring plan for work practice monitoring during
startup periods according to the requirements in Table 3 to this
subpart. The site-specific monitoring plan for startup periods must be
maintained onsite and available upon request for public inspection.
* * * * *
0
7. Section 63.7510 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(2)(ii), (c), (e),
(g), and (i) .
0
b. Adding paragraph (k).
The revisions and addition read as follows:
Sec. 63.7510 What are my initial compliance requirements and by what
date must I conduct them?
(a) For each boiler or process heater that is required or that you
elect to demonstrate compliance with any of the applicable emission
limits in Tables 1 or 2 or 11 through 13 of this subpart through
performance (stack) testing, your initial compliance requirements
include all the following:
* * * * *
(2) * * *
(ii) When natural gas, refinery gas, or other Gas 1 fuels are co-
fired with other fuels, you are not required to conduct a fuel analysis
of those Gas 1 fuels according to Sec. 63.7521 and Table 6 to this
subpart. If gaseous fuels other than natural gas, refinery gas, or
other Gas 1 fuels are co-fired with other fuels and those non-Gas 1
gaseous fuels are subject to another subpart of this part, part 60,
part 61, or part 65, you are not required to conduct a fuel analysis of
those non-Gas 1 fuels according to Sec. 63.7521 and Table 6 to this
subpart.
* * * * *
(c) If your boiler or process heater is subject to a carbon
monoxide (CO) limit, your initial compliance demonstration for CO is to
conduct a performance test
[[Page 3104]]
for CO according to Table 5 to this subpart or conduct a performance
evaluation of your continuous CO monitor, if applicable, according to
Sec. 63.7525(a). Boilers and process heaters that use a CO CEMS to
comply with the applicable alternative CO CEMS emission standard listed
in Tables 1, 2, or 11 through 13 to this subpart, as specified in Sec.
63.7525(a), are exempt from the initial CO performance testing and
oxygen concentration operating limit requirements specified in
paragraph (a) of this section.
* * * * *
(e) For existing affected sources (as defined in Sec. 63.7490),
you must complete the initial compliance demonstrations, as specified
in paragraphs (a) through (d) of this section, no later than 180 days
after the compliance date that is specified for your source in Sec.
63.7495 and according to the applicable provisions in Sec. 63.7(a)(2)
as cited in Table 10 to this subpart, except as specified in paragraph
(j) of this section. You must complete an initial tune-up by following
the procedures described in Sec. 63.7540(a)(10)(i) through (vi) no
later than the compliance date specified in Sec. 63.7495, except as
specified in paragraph (j) of this section. You must complete the one-
time energy assessment specified in Table 3 to this subpart no later
than the compliance date specified in Sec. 63.7495.
* * * * *
(g) For new or reconstructed affected sources (as defined in Sec.
63.7490), you must demonstrate initial compliance with the applicable
work practice standards in Table 3 to this subpart within the
applicable annual, biennial, or 5-year schedule as specified in Sec.
63.7515(d) following the initial compliance date specified in Sec.
63.7495(a). Thereafter, you are required to complete the applicable
annual, biennial, or 5-year tune-up as specified in Sec. 63.7515(d).
* * * * *
(i) For an existing EGU that becomes subject after January 31,
2016, you must demonstrate compliance within 180 days after becoming an
affected source.
* * * * *
(k) For affected sources, as defined in Sec. 63.7490, that switch
subcategory consistent with Sec. 63.7545(h) after the initial
compliance date, you must demonstrate compliance within 60 days of the
effective date of the switch, unless you had previously conducted your
compliance demonstration for this subcategory within the previous 12
months.
0
8. Section 63.7515 is amended by revising paragraphs (d) and (h) to
read as follows:
Sec. 63.7515 When must I conduct subsequent performance tests, fuel
analyses, or tune-ups?
* * * * *
(d) If you are required to meet an applicable tune-up work practice
standard, you must conduct an annual, biennial, or 5-year performance
tune-up according to Sec. 63.7540(a)(10), (11), or (12), respectively.
Each annual tune-up specified in Sec. 63.7540(a)(10) must be no more
than 13 months after the previous tune-up. Each biennial tune-up
specified in Sec. 63.7540(a)(11) must be conducted no more than 25
months after the previous tune-up. Each 5-year tune-up specified in
Sec. 63.7540(a)(12) must be conducted no more than 61 months after the
previous tune-up. For a new or reconstructed affected source (as
defined in Sec. 63.7490), the first annual, biennial, or 5-year tune-
up must be no later than 13 months, 25 months, or 61 months,
respectively, after April 1, 2013 or the initial startup of the new or
reconstructed affected source, whichever is later.
* * * * *
(h) If your affected boiler or process heater is in the unit
designed to burn light liquid subcategory and you combust ultra-low
sulfur liquid fuel, you do not need to conduct further performance
tests (stack tests or fuel analyses) if the pollutants measured during
the initial compliance performance tests meet the emission limits in
Tables 1 or 2 of this subpart providing you demonstrate ongoing
compliance with the emissions limits by monitoring and recording the
type of fuel combusted on a monthly basis. If you intend to use a fuel
other than ultra-low sulfur liquid fuel, natural gas, refinery gas, or
other gas 1 fuel, you must conduct new performance tests within 60 days
of burning the new fuel type.
* * * * *
0
9. Section 63.7521 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (c)(1).
0
c. Revising paragraph (f) introductory text.
0
d. Revising paragraph (g) introductory text.
0
e. Revising paragraph (h).
The revisions read as follows:
Sec. 63.7521 What fuel analyses, fuel specification, and procedures
must I use?
(a) For solid and liquid fuels, you must conduct fuel analyses for
chloride and mercury according to the procedures in paragraphs (b)
through (e) of this section and Table 6 to this subpart, as applicable.
For solid fuels and liquid fuels, you must also conduct fuel analyses
for TSM if you are opting to comply with the TSM alternative standard.
For gas 2 (other) fuels, you must conduct fuel analyses for mercury
according to the procedures in paragraphs (b) through (e) of this
section and Table 6 to this subpart, as applicable. (For gaseous fuels,
you may not use fuel analyses to comply with the TSM alternative
standard or the HCl standard.) For purposes of complying with this
section, a fuel gas system that consists of multiple gaseous fuels
collected and mixed with each other is considered a single fuel type
and sampling and analysis is only required on the combined fuel gas
system that will feed the boiler or process heater. Sampling and
analysis of the individual gaseous streams prior to combining is not
required. You are not required to conduct fuel analyses for fuels used
for only startup, unit shutdown, and transient flame stability
purposes. You are required to conduct fuel analyses only for fuels and
units that are subject to emission limits for mercury, HCl, or TSM in
Tables 1 and 2 or 11 through 13 to this subpart. Gaseous and liquid
fuels are exempt from the sampling requirements in paragraphs (c) and
(d) of this section.
* * * * *
(c) * * *
(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 6-inch wide sample from the full
cross-section 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 one-hour intervals during the
testing period for sampling during performance stack testing.
* * * * *
(f) To demonstrate that a gaseous fuel other than natural gas or
refinery gas qualifies as an other gas 1 fuel, as defined in Sec.
63.7575, you must conduct a fuel specification analyses for mercury
according to the procedures in paragraphs (g) through (i) of this
section and Table 6 to this subpart, as applicable, except as specified
in paragraph (f)(1) through (4) of this section, or as an alternative
where fuel specification analysis is not practical,
[[Page 3105]]
you must measure mercury concentration in the exhaust gas when firing
only the gaseous fuel to be demonstrated as an other gas 1 fuel in the
boiler or process heater according to the procedures in Table 6 to this
subpart.
* * * * *
(g) You must develop a site-specific fuel analysis plan for other
gas 1 fuels according to the following procedures and requirements in
paragraphs (g)(1) and (2) of this section.
* * * * *
(h) You must obtain a single fuel sample for each fuel type for
fuel specification of gaseous fuels.
* * * * *
0
10. Section 63.7522 is amended by revising paragraphs (c), (d), (i),
and (j)(1) to read as follows:
Sec. 63.7522 Can I use emissions averaging to comply with this
subpart?
* * * * *
(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 April 1, 2013 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 April 1,
2013.
(d) The averaged emissions rate from the existing boilers and
process heaters participating in the emissions averaging option must
not exceed 90 percent of the limits in Table 2 to this subpart at all
times the affected units are subject to numeric emission limits
following the compliance date specified in Sec. 63.7495.
* * * * *
(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 purposes of this subpart and comply with
the requirements of this subpart as if the group were a single unit.
(j) * * *
(1) Conduct performance tests according to procedures specified in
Sec. 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 of this
section.
[GRAPHIC] [TIFF OMITTED] TP21JA15.000
Where:
En = HAP emission limit, pounds per million British thermal units
(lb/MMBtu) or parts per million (ppm).
ELi = Appropriate emission limit from Table 2 to this subpart for
unit i, in units of lb/MMBtu or ppm.
Hi = Heat input from unit i, MMBtu.
* * * * *
0
11. Section 63.7525 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1), (a)(2)
introductory text, (a)(3), (a)(5), and (a)(7).
0
b. Revising paragraphs (b) introductory text and (b)(1).
0
c. Revising paragraph (g)(3).
0
d. Revising paragraphs (m) introductory text and (m)(2).
The revisions to read as follows:
Sec. 63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If your boiler or process heater is subject to a CO emission
limit in Tables 1, 2, or 11 through 13 to this subpart, you must
install, operate, and maintain an oxygen analyzer system, as defined in
Sec. 63.7575, or install, certify, operate and maintain continuous
emission monitoring systems for CO and oxygen (or carbon dioxide
(CO2)) according to the procedures in paragraphs (a)(1)
through (6) of this section.
(1) Install the CO CEMS and oxygen (or CO2) analyzer by
the compliance date specified in Sec. 63.7495. The CO and oxygen (or
CO2) levels shall be monitored at the same location at the
outlet of the boiler or process heater.
(2) To demonstrate compliance with the applicable alternative CO
CEMS emission standard listed in Tables 1, 2, or 11 through 13 to this
subpart, you must install, certify, operate, and maintain a CO CEMS and
an oxygen analyzer according to the applicable procedures under
Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B;
part 75 of this chapter (if an CO2 analyzer is used); the
site-specific monitoring plan developed according to Sec. 63.7505(d);
and the requirements in Sec. 63.7540(a)(8) and paragraph (a) of this
section. Any boiler or process heater that has a CO CEMS that is
compliant with Performance Specification 4, 4A, or 4B at 40 CFR part
60, appendix B, a site-specific monitoring plan developed according to
Sec. 63.7505(d), and the requirements in Sec. 63.7540(a)(8) and
paragraph (a) of this section must use the CO CEMS to comply with the
applicable alternative CO CEMS emission standard listed in Tables 1, 2,
or 11 through 13 to this subpart.
* * * * *
(3) Complete a minimum of one cycle of CO and oxygen (or
CO2) CEMS operation (sampling, analyzing, and data
recording) for each successive 15-minute period. Collect CO and oxygen
(or CO2) data concurrently. Collect at least four CO and
oxygen (or CO2) CEMS data values representing the four 15-
minute periods in an hour, or at least two 15-minute data values during
an hour when CEMS calibration, quality assurance, or maintenance
activities are being performed.
* * * * *
(5) Calculate one-hour arithmetic averages, corrected to 3 percent
oxygen (or corrected to an CO2 percentage determined to be
equivalent to 3 percent oxygen) from each hour of CO CEMS data in parts
per million CO concentration. The one-hour arithmetic averages required
shall be used to calculate the 30-day or 10-day rolling average
emissions. Use Equation 19-19 in section 12.4.1 of Method 19 of 40 CFR
part 60, appendix A-7 for calculating the average CO concentration from
the hourly values.
* * * * *
(7) Operate an oxygen trim system with the oxygen level set no
lower than the lowest hourly average oxygen concentration measured
during the most recent CO performance test as the operating limit for
oxygen according to Table 7 to this subpart, or if the facility is not
required to conduct a performance test, set the oxygen level to the
oxygen concentration measured during the most recent tune-up to
optimize CO to manufacturer's specification.
(b) If your boiler or process heater is in the unit designed to
burn coal/solid fossil fuel subcategory or the unit designed to burn
heavy liquid
[[Page 3106]]
subcategory and has an average annual heat input rate greater than 250
MMBtu per hour from solid fossil fuel and/or heavy liquid, and you
demonstrate compliance with the PM limit instead of the alternative TSM
limit, you must install, maintain, and operate a PM CPMS monitoring
emissions discharged to the atmosphere and record the output of the
system as specified in paragraphs (b)(1) through (4) of this section.
As an alternative to use of a PM CPMS to demonstrate compliance with
the PM limit, you may choose to use a PM CEMS. If you choose to use a
PM CEMS to demonstrate compliance with the PM limit instead of the
alternative TSM limit, you must install, certify, maintain, and operate
a PM CEMS monitoring emissions discharged to the atmosphere and record
the output of the system as specified in paragraph (b)(5) through (8)
of this section. For other boilers or process heaters, you may elect to
use a PM CPMS or PM CEMS operated in accordance with this section in
lieu of using other CMS for monitoring PM compliance (e.g., bag leak
detectors, ESP secondary power, PM scrubber pressure). Owners of
boilers and process heaters who elect to comply with the alternative
TSM limit are not required to install a PM CPMS.
(1) Install, operate, and maintain your PM CPMS according to the
procedures in your approved site-specific monitoring plan developed in
accordance with Sec. 63.7505(d), the requirements in Sec.
63.7540(a)(9), and paragraphs (b)(1)(i) through (iii) of this section.
(i) The operating principle of the PM CPMS must be based on in-
stack or extractive light scatter, light scintillation, beta
attenuation, or mass accumulation detection of PM in the exhaust gas or
representative exhaust gas sample. The reportable measurement output
from the PM CPMS must be expressed as milliamps.
(ii) The PM CPMS must have a cycle time (i.e., period required to
complete sampling, measurement, and reporting for each measurement) no
longer than 60 minutes.
(iii) The PM CPMS must have a documented detection limit of 0.5
milligram per actual cubic meter, or less.
* * * * *
(g) * * *
(3) Calibrate the pH monitoring system in accordance with your
monitoring plan at least once each process operating day.
* * * * *
(m) If your unit is subject to a HCl emission limit in Tables 1, 2,
or 11 through 13 of this subpart and you have an acid gas wet scrubber
or dry sorbent injection control technology and you elect to use an
SO2 CEMS to demonstrate continuous compliance with the HCl
emission limit, you must install the monitor at the outlet of the
boiler or process heater, downstream of all emission control devices,
and you must install, certify, operate, and maintain the CEMS according
to either part 60 or part 75 of this chapter.
(1) * * *
(2) For on-going quality assurance (QA), the SO2 CEMS
must meet either the applicable daily and quarterly requirements in
Procedure 1 of appendix F of part 60 or the applicable daily,
quarterly, and semiannual or annual requirements in sections 2.1
through 2.3 of appendix B to part 75 of this chapter, with the
following addition: You must perform the linearity checks required in
section 2.2 of appendix B to part 75 of this chapter if the
SO2 CEMS has a span value of 30 ppm or less.
* * * * *
0
12. Section 63.7530 is amended by:
0
a. Revising paragraphs (a).
0
b. Revising paragraph (b) introductory text.
0
c. Revising paragraphs (b)(1)(iii), (b)(2)(iii), and (b)(3)(iii).
0
d. Revising paragraph (b)(4)(ii)(F).
0
e. Redesignating paragraphs (b)(4)(iii) through (b)(4)(viii) as
(b)(4)(iv) through (b)(4)(ix) and adding new paragraph (b)(4)(iii).
0
f. Revising paragraphs (c)(3), (c)(4), and (c)(5).
0
g. Revising paragraph (d).
0
h. Revising paragraph (e).
0
i. Revising paragraph (h).
0
j. Revising paragraph (i)(3).
The revisions and addition read as follows:
Sec. 63.7530 How do I demonstrate initial compliance with the
emission limitations, fuel specifications and work practice standards?
(a) You must demonstrate initial compliance with each emission
limit that applies to you by conducting initial performance tests and
fuel analyses and establishing operating limits, as applicable,
according to Sec. 63.7520, paragraphs (b) and (c) of this section, and
Tables 5 and 7 to this subpart. The requirement to conduct a fuel
analysis is not applicable for units that burn a single type of fuel,
as specified by Sec. 63.7510(a)(2). If applicable, you must also
install, operate, and maintain all applicable CMS (including CEMS,
COMS, and CPMS) according to Sec. 63.7525.
(b) If you demonstrate compliance through performance stack
testing, you must establish each site-specific operating limit in Table
4 to this subpart that applies to you according to the requirements in
Sec. 63.7520, Table 7 to this subpart, and paragraph (b)(4) of this
section, as applicable. You must also conduct fuel analyses according
to Sec. 63.7521 and establish maximum fuel pollutant input levels
according to paragraphs (b)(1) through (3) of this section, as
applicable, and as specified in Sec. 63.7510(a)(2). (Note that Sec.
63.7510(a)(2) exempts certain fuels from the fuel analysis
requirements.) However, if you switch fuel(s) and cannot show that the
new fuel(s) does (do) not increase the chlorine, mercury, or TSM input
into the unit through the results of fuel analysis, then you must
repeat the performance test to demonstrate compliance while burning the
new fuel(s).
(1) * * *
(iii) You must establish a maximum chlorine input level using
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JA15.001
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 Sec. 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 during the
initial compliance test. 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. For continuous
compliance demonstration, the actual fraction of the fuel burned
during the month would be used.
n = Number of different fuel types burned in your boiler or process
heater for the
[[Page 3107]]
mixture that has the highest content of chlorine.
(2) * * *
(iii) You must establish a maximum mercury input level using
Equation 8 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JA15.002
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 Sec. 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 during the initial
compliance test. 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. For continuous compliance
demonstration, the actual fraction of the fuel burned during the
month would be used.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of mercury.
(3) * * *
(iii) You must establish a maximum TSM input level using Equation 9
of this section.
[GRAPHIC] [TIFF OMITTED] TP21JA15.003
Where:
TSMinput = Maximum amount of TSM entering the boiler or process
heater through fuels burned in units of pounds per million Btu.
TSMi = Arithmetic average concentration of TSM in fuel type, i,
analyzed according to Sec. 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 TSM during the initial
compliance test. 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. For continuous compliance
demonstration, the actual fraction of the fuel burned during the
month would be used.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of TSM.
(4) * * *
(ii) * * *
(F) For PM performance test reports used to set a PM CPMS operating
limit, the electronic submission of the test report must also include
the make and model of the PM CPMS instrument, serial number of the
instrument, analytical principle of the instrument (e.g. beta
attenuation), span of the instruments primary analytical range,
milliamp value equivalent to the instrument zero output, technique by
which this zero value was determined, and the average milliamp signals
corresponding to each PM compliance test run.
(iii) For a particulate wet scrubber, you must establish the
minimum pressure drop and liquid flow rate as defined in Sec. 63.7575,
as your operating limits during the three-run performance test during
which you demonstrate compliance with your applicable limit. If you use
a wet scrubber and you conduct separate performance tests for PM and
TSM emissions, you must establish one set of minimum scrubber liquid
flow rate 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 flow rate and pressure drop operating limits at
the higher of the minimum values established during the performance
tests.
* * * * *
(c) * * *
(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 16 of this section must not exceed the
applicable emission limit for HCl.
[GRAPHIC] [TIFF OMITTED] TP21JA15.004
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 15 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.
(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 17 of this section must not
exceed the applicable emission limit for mercury.
[[Page 3108]]
[GRAPHIC] [TIFF OMITTED] TP21JA15.005
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 15 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.
(5) To demonstrate compliance with the applicable emission limit
for TSM for solid or liquid fuels, the TSM emission rate that you
calculate for your boiler or process heater from solid fuels using
Equation 18 of this section must not exceed the applicable emission
limit for TSM.
[GRAPHIC] [TIFF OMITTED] TP21JA15.006
Where:
Metals = TSM emission rate from the boiler or process heater in
units of pounds per million Btu.
TSMi90 = 90th percentile confidence level concentration of TSM in
fuel, i, in units of pounds per million Btu as calculated according
to Equation 15 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest TSM 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 TSM content.
(d) If you own or operate an existing unit, 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 include with the Notification of Compliance Status a
signed certification that the energy assessment was completed according
to Table 3 to this subpart and that the assessment is an accurate
depiction of your facility at the time of the assessment or that the
maximum number of on-site technical hours specified in the definition
of energy assessment applicable to the facility has been expended.
* * * * *
(h) If you own or operate a unit subject to emission limits in
Tables 1 or 2 or 11 through 13 to this subpart, you must meet the work
practice standard according to Table 3 of this subpart. During startup
and shutdown, you must only follow the work practice standards
according to items 5 and 6 of Table 3 of this subpart.
(i) * * *
(3) You establish a unit-specific maximum SO2 operating
limit by collecting the maximum hourly SO2 emission rate on
the SO2 CEMS during the paired 3-run test for HCl. The
maximum SO2 operating limit is equal to the highest hourly
average SO2 concentration measured during the most recent
HCl performance test.
0
13. Section 63.7533 is amended by revising paragraph (e).
Sec. 63.7533 Can I use efficiency credits earned from implementation
of energy conservation measures to comply with this subpart?
* * * * *
(e) The emissions rate as calculated using Equation 20 of this
section from each existing boiler participating in the efficiency
credit option must be in compliance with the limits in Table 2 to this
subpart at all times the affected unit is subject to numeric emission
limits, following the compliance date specified in Sec. 63.7495.
* * * * *
0
14. Section 63.7535 is amended by revising paragraphs (c) and (d).
Sec. 63.7535 Is there a minimum amount of monitoring data I must
obtain?
* * * * *
(c) You may not use data recorded during periods of startup and
shutdown, monitoring system malfunctions or out-of-control periods,
repairs associated with monitoring system malfunctions or out-of-
control periods, or required monitoring system quality assurance or
control activities in data averages and calculations used to report
emissions or operating levels. You must record and make available upon
request results of CMS performance audits and dates and duration of
periods when the CMS is out of control to completion of the corrective
actions necessary to return the CMS to operation consistent with your
site-specific monitoring plan. You must use all the data collected
during all other periods in assessing compliance and the operation of
the control device and associated control system.
(d) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities (including, as
applicable, system accuracy audits, calibration checks, and required
zero and span adjustments), failure to collect required data is a
deviation of the monitoring requirements. In calculating monitoring
results, do not use any data collected during periods of startup and
shutdown, when the monitoring system is out of control as specified in
your site-specific monitoring plan, while conducting repairs associated
with periods when the monitoring system is out of control, or while
conducting required monitoring system quality assurance or quality
control activities. You must calculate monitoring results using all
other monitoring data collected while the process is operating. You
must report all periods when the monitoring system is out of control in
your semi-annual report.
0
15. Section 63.7540 is amended by:
0
a. Revising paragraph (a)(2) introductory text.
0
b. Revising paragraph (a)(3).
0
c. Revising paragraph (a)(5).
0
d. Revising paragraph (a)(8)(ii).
0
e. Revising paragraph (a)(10) introductory text.
0
f. Revising paragraph (a)(10)(vi) introductory text.
0
g. Revising paragraph (a)(17).
0
h. Revising paragraph (a)(19)(iii).
0
i. Revising paragraph (d).
[[Page 3109]]
The revisions read as follows:
Sec. 63.7540 How do I demonstrate continuous compliance with the
emission limitations, fuel specifications and work practice standards?
(a) * * *
(2) As specified in Sec. 63.7550(d), 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 result in either of the following:
* * * * *
(3) If you demonstrate compliance with an applicable HCl emission
limit through fuel analysis for a solid or liquid fuel and you plan to
burn a new type of solid or liquid fuel, you must recalculate the HCl
emission rate using Equation 16 of Sec. 63.7530 according to
paragraphs (a)(3)(i) through (iii) of this section. You are not
required to conduct fuel analyses for the fuels described in Sec.
63.7510(a)(2)(i) through (iii). You may exclude the fuels described in
Sec. 63.7510(a)(2)(i) through (iii) when recalculating the HCl
emission rate.
(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 Sec. 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 16 of Sec. 63.7530.
The recalculated HCl emission rate must be less than the applicable
emission limit.
* * * * *
(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
17 of Sec. 63.7530 according to the procedures specified in paragraphs
(a)(5)(i) through (iii) of this section. You are not required to
conduct fuel analyses for the fuels described in Sec. 63.7510(a)(2)(i)
through (iii). You may exclude the fuels described in Sec.
63.7510(a)(2)(i) through (iii) when recalculating the mercury emission
rate.
(i) You must determine the mercury 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 Sec. 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 17 of Sec.
63.7530. The recalculated mercury emission rate must be less than the
applicable emission limit.
* * * * *
(8) * * *
(ii) Maintain a CO emission level below or at your applicable
alternative CO CEMS-based standard in Tables 1 or 2 or 11 through 13 to
this subpart at all times the affected unit is subject to numeric
emission limits.
* * * * *
(10) If your boiler or process heater has a heat input capacity of
10 million Btu per hour or greater, you must conduct an annual tune-up
of the boiler or process heater to demonstrate continuous compliance as
specified in paragraphs (a)(10)(i) through (vi) of this section. You
must conduct the tune-up while burning the type of fuel (or fuels in
case of units that routinely burn a mixture) that provided the majority
of the heat input to the boiler or process heater over the 12 months
prior to the tune-up. This frequency does not apply to limited-use
boilers and process heaters, as defined in Sec. 63.7575, or units with
continuous oxygen trim systems that maintain an optimum air to fuel
ratio.
* * * * *
(vi) Maintain on-site and submit, if requested by the
Administrator, a report containing the information in paragraphs
(a)(10)(vi)(A) through (C) of this section,
* * * * *
(17) If you demonstrate compliance with an applicable TSM emission
limit through fuel analysis for solid or liquid fuels, and you plan to
burn a new type of fuel, you must recalculate the TSM emission rate
using Equation 18 of Sec. 63.7530 according to the procedures
specified in paragraphs (a)(5)(i) through (iii) of this section. You
are not required to conduct fuel analyses for the fuels described in
Sec. 63.7510(a)(2)(i) through (iii). You may exclude the fuels
described in Sec. 63.7510(a)(2)(i) through (iii) when recalculating
the TSM emission rate.
(i) You must determine the TSM 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 Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of TSM.
(iii) Recalculate the TSM emission rate from your boiler or process
heater under these new conditions using Equation 18 of Sec. 63.7530.
The recalculated TSM emission rate must be less than the applicable
emission limit.
* * * * *
(19) * * *
* * * * *
(iii) Collect PM CEMS hourly average output data for all boiler
operating hours except as indicated in paragraph (v) of this section.
* * * * *
(d) For startup and shutdown, you must meet the work practice
standards according to items 5 and 6 of Table 3 of this subpart.
* * * * *
0
16. Section 63.7545 is amended by revising paragraphs (e)(8)(i) and (h)
introductory text.
Sec. 63.7545 What notifications must I submit and when?
* * * * *
(e) * * *
(8) * * *
(i) ``This facility completed the required initial tune-up
according to the procedures in Sec. 63.7540(a)(10)(i) through (vi).''
* * * * *
(h) If you have switched fuels or made a physical change to the
boiler or process heater and the fuel switch or physical change
resulted in the applicability of a different subcategory, you must
provide notice of the date upon which you switched fuels or made the
physical change within 30 days of the switch/change. The notification
must identify:
* * * * *
0
17. Section 63.7550 is amended by revising paragraphs (b), (c), (d)
introductory text, (d)(1), and (h) to read as follows:
Sec. 63.7550 What reports must I submit and when?
* * * * *
(b) Unless the EPA Administrator has approved a different schedule
for submission of reports under Sec. 63.10(a), you must submit each
report, according to paragraph (h) of this section, by the date in
Table 9 to this subpart and according to the requirements in paragraphs
(b)(1) through (4) of this section. For units that are subject only to
the energy assessment requirement and a requirement to conduct an
annual, biennial, or 5-year tune-up according to Sec. 63.7540(a)(10),
(11), or (12),
[[Page 3110]]
respectively, and not subject to emission limits or Table 4 operating
limits, you may submit only an annual, biennial, or 5-year compliance
report, as applicable, as specified in paragraphs (b)(1) through (4) of
this section, instead of a semi-annual compliance report.
(1) The first semi-annual compliance report must cover the period
beginning on the compliance date that is specified for each boiler or
process heater in Sec. 63.7495 and ending on June 30 or December 31,
whichever date is the first date that occurs at least 180 days (or 1,
2, or 5 years, as applicable, if submitting an annual, biennial, or 5-
year compliance report) after the compliance date that is specified for
your source in Sec. 63.7495.
(2) The first semi-annual compliance report must be postmarked or
submitted 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 each boiler or process heater in
Sec. 63.7495. The first annual, biennial, or 5-year compliance report
must be postmarked or submitted no later than January 31.
(3) Each subsequent semi-annual 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. Annual,
biennial, and 5-year compliance reports must cover the applicable 1-,
2-, or 5-year periods from January 1 to December 31.
(4) Each subsequent semi-annual compliance report must be
postmarked or submitted no later than July 31 or January 31, whichever
date is the first date following the end of the semiannual reporting
period. Annual, biennial, and 5-year compliance reports must be
postmarked or submitted no later than January 31.
(c) A compliance report must contain the following information
depending on how the facility chooses to comply with the limits set in
this rule.
(1) If the facility is subject to the requirements of a tune up you
must submit a compliance report with the information in paragraphs
(c)(5)(i) through (iii), (xiv) and (xvii) of this section, and
paragraph (c)(5)(iv) of this section for limited-use boiler or process
heater.
(2) If you are complying with the fuel analysis you must submit a
compliance report with the information in paragraphs (c)(5)(i) through
(iii), (vi), (x), (xi), (xiii), (xv), (xvii), (xviii) and paragraph (d)
of this section.
(3) If you are complying with the applicable emissions limit with
performance testing you must submit a compliance report with the
information in (c)(5)(i) through (iii), (vi), (vii), (viii), (ix),
(xi), (xiii), (xv), (xvii), (xviii) and paragraph (d) of this section.
(4) If you are complying with an emissions limit using a CMS the
compliance report must contain the information required in paragraphs
(c)(5)(i) through (iii), (v), (vi), (xi) through (xiii), (xv) through
(xviii), and paragraph (e) of this section.
(5)(i) Company and Facility name and address.
(ii) Process unit information, emissions limitations, and operating
parameter limitations.
(iii) Date of report and beginning and ending dates of the
reporting period.
(iv) The total operating time during the reporting period.
(v) If you use a CMS, including CEMS, COMS, or CPMS, you must
include the monitoring equipment manufacturer(s) and model numbers and
the date of the last CMS certification or audit.
(vi) The total fuel use by each individual boiler or process heater
subject to an emission limit within the reporting period, including,
but not limited to, a description of the fuel, whether the fuel has
received a non-waste determination by the EPA or your basis for
concluding that the fuel is not a waste, and the total fuel usage
amount with units of measure.
(vii) If you are conducting performance tests once every 3 years
consistent with Sec. 63.7515(b) or (c), the date of the last 2
performance tests and a statement as to whether there have been any
operational changes since the last performance test that could increase
emissions.
(viii) A statement indicating that you burned no new types of fuel
in an individual boiler or process heater subject to an emission limit.
Or, if you did burn a new type of fuel and are subject to a HCl
emission limit, you must submit the calculation of chlorine input,
using Equation 7 of Sec. 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 16 of Sec. 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 and are subject to a
mercury emission limit, you must submit the calculation of mercury
input, using Equation 8 of Sec. 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 17 of Sec. 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). If you burned a new type of fuel and
are subject to a TSM emission limit, you must submit the calculation of
TSM input, using Equation 9 of Sec. 63.7530, that demonstrates that
your source is still within its maximum TSM input level established
during the previous performance testing (for sources that demonstrate
compliance through performance testing), or you must submit the
calculation of TSM emission rate, using Equation 18 of Sec. 63.7530,
that demonstrates that your source is still meeting the emission limit
for TSM emissions (for boilers or process heaters that demonstrate
compliance through fuel analysis).
(ix) If you wish to burn a new type of fuel in an individual boiler
or process heater subject to an emission limit and you cannot
demonstrate compliance with the maximum chlorine input operating limit
using Equation 7 of Sec. 63.7530 or the maximum mercury input
operating limit using Equation 8 of Sec. 63.7530, or the maximum TSM
input operating limit using Equation 9 of Sec. 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.
(x) A summary of any monthly fuel analyses conducted to demonstrate
compliance according to Sec. Sec. 63.7521 and 63.7530 for individual
boilers or process heaters subject to emission limits, and any fuel
specification analyses conducted according to Sec. Sec. 63.7521(f) and
63.7530(g).
(xi) 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.
(xii) 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 Sec. 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.
(xiii) If a malfunction occurred during the reporting period, the
report must
[[Page 3111]]
include the number, duration, and a brief description for each type of
malfunction which occurred during the reporting period and which caused
or may have caused any applicable emission limitation to be exceeded.
The report must also include a description of actions taken by you
during a malfunction of a boiler, process heater, or associated air
pollution control device or CMS to minimize emissions in accordance
with Sec. 63.7500(a)(3), including actions taken to correct the
malfunction.
(xiv) Include the date of the most recent tune-up for each unit
subject to only the requirement to conduct an annual, biennial, or 5-
year tune-up according to Sec. 63.7540(a)(10), (11), or (12)
respectively. Include the date of the most recent burner inspection if
it was not done annually, biennially, or on a 5-year period and was
delayed until the next scheduled or unscheduled unit shutdown.
(xv) If you plan to demonstrate compliance by emission averaging,
certify the emission level achieved or the control technology employed
is no less stringent than the level or control technology contained in
the notification of compliance status in Sec. 63.7545(e)(5)(i).
(xvi) For each reporting period, the compliance reports must
include all of the calculated 30 day rolling average values based on
the daily CEMS (CO and mercury) and CPMS (PM CPMS output, scrubber pH,
scrubber liquid flow rate, scrubber pressure drop) data.
(xvii) 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.
(xviii) For each instance of startup or shutdown include the
information required to be monitored, collected, or recorded according
to the requirements of Sec. 63.7555(d).
* * * * *
(d) For each deviation from an emission limit or operating limit in
this subpart that occurs at an individual boiler or process heater
where you are not using a CMS to comply with that emission limit or
operating limit, or from the work practice standards for periods if
startup and shutdown, the compliance report must additionally contain
the information required in paragraphs (d)(1) through (3) of this
section.
(1) A description of the deviation and which emission limit,
operating limit, or work practice standard from which you deviated.
* * * * *
(h) You must submit the reports according to the procedures
specified in paragraphs (h)(1) through (3) of this section.
(1) Within 60 days after the date of completing each performance
test (defined in Sec. 63.2) required by this subpart, you must submit
the results of the performance test, including any associated fuel
analyses, following the procedure specified in either paragraph
(h)(1)(i) or (h)(1)(ii) of this section.
(i) For data collected using test methods supported by the EPA's
Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site
(http://www.epa.gov/ttn/chief/ert/index.html) at the time of the test,
you must submit the results of the performance test to the EPA via the
Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can
be accessed through the EPA's Central Data Exchange (CDX) (www.epa.gov/cdx).) Performance test data must be submitted in a file format
generated through use of the EPA's ERT. Instead of submitting
performance test data in a file format generated through the use of the
EPA's ERT, you may submit an alternate electronic file format
consistent with the extensible markup language (XML) schema listed on
the EPA's ERT Web site, once the XML schema is available. If you claim
that some of the performance test information being submitted is
confidential business information (CBI), you must submit a complete
file generated through the use of the EPA's ERT (or an alternate
electronic file consistent with the XML schema listed on the EPA's ERT
Web site once the XML schema is available), including information
claimed to be CBI, on a compact disc, flash drive or other commonly
used electronic storage media to the EPA. The electronic media must be
clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office,
Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old
Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI
omitted must be submitted to the EPA via the EPA's CDX as described
earlier in this paragraph.
(ii) For data collected using test methods that are not supported
by the EPA's ERT as listed on the EPA's ERT Web site, you must submit
the results of the performance test to the Administrator at the
appropriate address listed in Sec. 63.13.
(2) Within 60 days after the date of completing each CEMS
performance evaluation (as defined in 63.2), you must submit the
results of the performance evaluation following the procedure specified
in either paragraph (h)(2)(i) or (h)(2)(ii) of this section.
(i) For performance evaluations of continuous monitoring systems
measuring relative accuracy test audit (RATA) pollutants that are
supported by the EPA's ERT as listed on the EPA's ERT Web site at the
time of the test, you must submit the results of the performance
evaluation to the EPA via the CEDRI. (CEDRI can be accessed through the
EPA's CDX.) Performance evaluation data must be submitted in a file
format generated through the use of the EPA's ERT. Instead of
submitting performance evaluation data in a file format generated
through the use of the EPA's ERT, you may submit an alternate
electronic file format consistent with the XML schema listed on the
EPA's ERT Web site, once the XML schema is available. If you claim that
some of the performance evaluation information being submitted is CBI,
you must submit a complete file generated through the use of the EPA's
ERT (or an alternate electronic file consistent with the XML schema
listed on the EPA's ERT Web site once the XML schema is available),
including information claimed to be CBI, on a compact disc, flash drive
or other commonly used electronic storage media to the EPA. The
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAPQS/CORE CBI Office, Attention: Group Leader, Measurement Policy
Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or
alternate file with the CBI omitted must be submitted to the EPA via
the EPA's CDX as described earlier in this paragraph.
(ii) For any performance evaluations of continuous monitoring
systems measuring RATA pollutants that are not supported by the EPA's
ERT as listed on the ERT Web site, you must submit the results of the
performance evaluation to the Administrator at the appropriate address
listed in Sec. 63.13.
(3) You must submit all reports required by Table 9 of this subpart
electronically to the EPA via the CEDRI. (CEDRI can be accessed through
the EPA's CDX.) You must use the appropriate electronic report in CEDRI
for this subpart. Instead of using the electronic report in CEDRI for
this subpart, you may submit an alternate electronic file consistent
with the XML schema listed on the CEDRI Web site (http://www.epa.gov/ttn/chief/cedri/index.html), once the XML schema is available. If the
reporting form specific to this subpart is not available in CEDRI at
the time that the report is due, you must submit the report to the
Administrator at the appropriate address listed in Sec. 63.13. You
must
[[Page 3112]]
begin submitting reports via CEDRI no later than 90 days after the form
becomes available in CEDRI.
0
18. Section 63.7555 is amended by:
0
a. Adding paragraph (a)(3).
0
b. Removing paragraph (d)(3).
0
c. Redesignating paragraphs (d)(4) through (d)(11) as paragraphs (d)(3)
through (d)(10).
0
d. Revising newly designated paragraphs (d)(3), (d)(4), and (d)(8).
0
e. Adding new paragraphs (d)(11) and (12).
0
f. Removing paragraphs (i) and (j).
The revisions and additions read as follows:
Sec. 63.7555 What records must I keep?
(a) * * *
(3) For units in the limited use subcategory, you must keep a copy
of the federally enforceable permit that limits the annual capacity
factor to less than or equal to 10 percent and fuel use records for the
days the boiler or process heater was operating.
* * * * *
(d) * * *
(3) A copy of all calculations and supporting documentation of
maximum chlorine fuel input, using Equation 7 of Sec. 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 emission
rates, using Equation 16 of Sec. 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.
(4) A copy of all calculations and supporting documentation of
maximum mercury fuel input, using Equation 8 of Sec. 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 17 of Sec. 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.
* * * * *
(8) A copy of all calculations and supporting documentation of
maximum TSM fuel input, using Equation 9 of Sec. 63.7530, that were
done to demonstrate continuous compliance with the TSM 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 TSM emission rates,
using Equation 18 of Sec. 63.7530, that were done to demonstrate
compliance with the TSM emission limit. Supporting documentation should
include results of any fuel analyses and basis for the estimates of
maximum TSM fuel input or TSM 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 TSM fuel input, or TSM emission rates, for each boiler and
process heater.
* * * * *
(11) For each startup period, you must maintain records of the time
that clean fuel combustion begins; the time when firing (i.e., feeding)
start for coal/solid fossil fuel, biomass/bio-based solids, heavy
liquid fuel, or gas 2 (other) gases; the time when useful thermal
energy is first supplied; and the time when the PM controls are
engaged.
(12) For each startup period, you must maintain records of the
hourly steam temperature, hourly steam pressure, hourly steam flow,
hourly flue gas temperature, and all hourly average CMS data (e.g.,
CEMS, PM CPMS, COMS, ESP total secondary electric power input, scrubber
pressure drop, scrubber liquid flow rate) collected during each startup
period to confirm that the control devices are engaged. In addition, if
compliance with the PM emission limit is demonstrated using a PM
control device, you must maintain records as specified in paragraphs
(d)(12)(i) through (iii) of this section.
(i) For a boiler or process heater with an electrostatic
precipitator, record the number of fields in service, as well as each
field's secondary voltage and secondary current during each hour of
startup.
(ii) For a boiler or process heater with a fabric filter, record
the number of compartments in service, as well as the differential
pressure across the baghouse during each hour of startup.
(iii) For a boiler or process heater with a wet scrubber needed for
filterable PM control, record the scrubber liquid to fuel ratio and the
differential pressure of the liquid during each hour of startup.
* * * * *
0
19. Section 63.7575 is amended by:
0
a. Revising the definitions for ``Coal,'' ``Limited-use boiler or
process heater,'' ``Load fraction,'' ``Oxygen trim system,''
``Shutdown,'' ``Startup,'' ``Steam output,'' and ``Temporary boiler.''
0
b. Adding in alphabetical order definitions for ``Fossil fuel'' and
``Useful thermal energy.''
0
c. Removing the definition for ``Affirmative defense.''
The revisions read as follows:
Sec. 63.7575 What definitions apply to this subpart?
* * * * *
Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by ASTM D388 (incorporated by reference, see
Sec. 63.14), coal refuse, and petroleum coke. For the purposes of this
subpart, this definition of ``coal'' includes synthetic fuels derived
from coal, including but not limited to, solvent-refined coal, coal-oil
mixtures, and coal-water mixtures. Coal derived gases and liquids are
excluded from this definition.
* * * * *
Fossil fuel means natural gas, oil, coal, and any form of solid,
liquid, or gaseous fuel derived from such material.
* * * * *
Limited-use boiler or process heater means any boiler or process
heater that burns any amount of solid, liquid, or gaseous fuels and has
a federally enforceable annual capacity factor of no more than 10
percent.
* * * * *
Load fraction means the actual heat input of a boiler or process
heater divided by heat input during the performance test that
established the minimum sorbent injection rate or minimum activated
carbon injection rate, expressed as a fraction (e.g., for 50 percent
load the load fraction is 0.5). For boilers and process heaters that
co-fire natural gas or refinery gas with a solid or liquid fuel, the
load fraction is determined by the actual heat input of the solid or
liquid fuel divided by heat input of the solid or liquid fuel fired
during the performance test (e.g., if the performance test was
conducted at 100 percent solid fuel firing, for 100 percent
[[Page 3113]]
load firing 50 percent solid fuel and 50 percent natural gas the load
fraction is 0.5).
* * * * *
Oxygen trim system means a system of monitors that is used to
maintain excess air at the desired level in a combustion device over
its operating load range. A typical system consists of a flue gas
oxygen and/or CO monitor that automatically provides a feedback signal
to the combustion air controller or draft controller.
* * * * *
Shutdown means the period in which cessation of operation of a
boiler or process heater is initiated for any purpose. Shutdown begins
when the boiler or process heater no longer makes useful thermal energy
(such as heat or steam) for heating, cooling, or process purposes and/
or generates electricity or when no fuel is being fed to the boiler or
process heater, whichever is earlier. Shutdown ends when the boiler or
process heater no longer makes useful thermal energy (such as steam or
heat) for heating, cooling, or process purposes and/or generates
electricity, and no fuel is being combusted in the boiler or process
heater.
* * * * *
Startup means:
(1) Either the first-ever firing of fuel in a boiler or process
heater for the purpose of supplying steam or heat for heating and/or
producing electricity, or for any other purpose, or the firing of fuel
in a boiler after a shutdown event for any purpose. Startup ends when
any of the steam or heat from the boiler or process heater is supplied
for heating, and/or producing electricity, or for any other purpose, or
(2) The period in which operation of a boiler or process heater is
initiated for any purpose. Startup begins with either the first-ever
firing of fuel in a boiler or process heater for the purpose of
supplying useful thermal energy (such as steam or heat) for heating,
cooling or process purposes, or producing electricity, or the firing of
fuel in a boiler or process heater for any purpose after a shutdown
event. Startup ends four hours after when the boiler or process heater
makes useful thermal energy (such as heat or steam) for heating,
cooling, or process purposes, or generates electricity, whichever is
earlier.
Steam output means:
(1) For a boiler that produces steam for process or heating only
(no power generation), the energy content in terms of MMBtu of the
boiler steam output,
(2) For a boiler that cogenerates process steam and electricity
(also known as combined heat and power), the total energy output, which
is the sum of the energy content of the steam exiting the turbine and
sent to process in MMBtu and the energy of the electricity generated
converted to MMBtu at a rate of 10,000 Btu per kilowatt-hour generated
(10 MMBtu per megawatt-hour), and
(3) For a boiler that generates only electricity, the alternate
output-based emission limits would be the appropriate emission limit
from Table 1 or 2 of this subpart in units of pounds per million Btu
heat input (lb per MWh).
(4) For a boiler that performs multiple functions and produces
steam to be used for any combination of (1), (2) and (3) that includes
electricity generation (3), the total energy output, in terms of MMBtu
of steam output, is the sum of the energy content of steam sent
directly to the process and/or used for heating (S1), the
energy content of turbine steam sent to process plus energy in
electricity according to (2) above (S2), and the energy
content of electricity generated by a electricity only turbine as (3)
above (S3) and would be calculated using Equation 21 of this
section. In the case of boilers supplying steam to one or more common
heaters, S1, S2, and MW(3) for each
boiler would be calculated based on the its (steam energy) contribution
(fraction of total stam energy) to the common heater.
[GRAPHIC] [TIFF OMITTED] TP21JA15.007
Where:
SOM = Total steam output for multi-function boiler, MMBtu
S1 = Energy content of steam sent directly to the process
and/or used for heating, MMBtu
S2 = Energy content of turbine steam sent to the process
plus energy in electricity according to (2) above, MMBtu
MW(3) = Electricity generated according to (3) above, MWh
CFn = Conversion factor for the appropriate subcategory for
converting electricity generated according to (3) above to
equivalent steam energy, MMBtu/MWh
CFn for emission limits for boilers in the unit designed to burn
solid fuel subcategory = 10.8
CFn PM and CO emission limits for boilers in one of the
subcategories of units designed to burn coal = 11.7
CFn PM and CO emission limits for boilers in one of the
subcategories of units designed to burn biomass = 12.1
CFn for emission limits for boilers in one of the subcategories of
units designed to burn liquid fuel = 11.2
CFn for emission limits for boilers in the unit designed to burn gas
2 (other) subcategory = 6.2
* * * * *
Temporary boiler means any gaseous or liquid fuel boiler or process
heater that is designed to, and is capable of, being carried or moved
from one location to another by means of, for example, wheels, skids,
carrying handles, dollies, trailers, or platforms. A boiler or process
heater is not a temporary boiler or process heater if any one of the
following conditions exists:
(1) The equipment is attached to a foundation.
(2) The boiler or process heater or a replacement remains at a
location within the facility and performs the same or similar function
for more than 12 consecutive months, unless the regulatory agency
approves an extension. An extension may be granted by the regulating
agency upon petition by the owner or operator of a unit specifying the
basis for such a request. Any temporary boiler or process heater that
replaces a temporary boiler or process heater at a location and
performs the same or similar function will be included in calculating
the consecutive time period.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another within the
facility but continues to perform the same or similar function and
serve the same electricity, process heat, steam, and/or hot water
system in an attempt to circumvent the residence time requirements of
this definition.
* * * * *
Useful thermal energy means energy (i.e., steam, hot water, or
process heat) that meets the minimum operating temperature and/or
pressure required by any energy use system that uses energy provided by
the affected boiler or process heater.
* * * * *
0
20. Table 1 to subpart DDDDD of part 63 is revised to read as follows:
[[Page 3114]]
Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or Reconstructed Boilers and Process Heaters
As Stated in Sec. 63.7500, You Must Comply With the Following Applicable Emission Limits:
[Units with heat input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
Or the emissions
The emissions must must not exceed the
If your boiler or process For the not exceed the following Using this specified
heater is in this subcategory following following emission alternative output- sampling volume or
. . . pollutants . . limits, except based limits, except test run duration .
. during startup and during startup and . .
shutdown . . . shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl......... 2.2E-02 lb per MMBtu 2.5E-02 lb per MMBtu For M26A, collect a
designed to burn solid fuel.. of heat input. of steam output or minimum of 1 dscm
0.28 lb per MWh. per run; for M26
collect a minimum
of 120 liters per
run.
b. Mercury..... 8.0E-07 \a\ lb per 8.7E-07 \a\ lb per For M29, collect a
MMBtu of heat input. MMBtu of steam minimum of 4 dscm
output or 1.1E-05 per run; for M30A
\a\ lb per MWh. or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
2. Units designed to burn a. Filterable 1.1E-03 lb per MMBtu 1.1E-03 lb per MMBtu Collect a minimum of
coal/solid fossil fuel. PM (or TSM). of heat input; or of steam output or 3 dscm per run.
(2.3E-05 lb per 1.4E-02 lb per MWh;
MMBtu of heat or (2.7E-05 lb per
input). MMBtu of steam
output or 2.9E-04
lb per MWh).
3. Pulverized coal boilers a. Carbon 130 ppm by volume on 0.11 lb per MMBtu of 1 hr minimum
designed to burn coal/solid monoxide (CO) a dry basis steam output or 1.4 sampling time.
fossil fuel. (or CEMS). corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(320 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
30-day rolling
average).
4. Stokers/others designed to a. CO (or CEMS) 130 ppm by volume on 0.12 lb per MMBtu of 1 hr minimum
burn coal/solid fossil fuel. a dry basis steam output or 1.4 sampling time.
corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(340 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
30-day rolling
average).
5. Fluidized bed units a. CO (or CEMS) 130 ppm by volume on 0.11 lb per MMBtu of 1 hr minimum
designed to burn coal/solid a dry basis steam output or 1.4 sampling time.
fossil fuel. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(230 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
30-day rolling
average).
6. Fluidized bed units with a. CO (or CEMS) 140 ppm by volume on 1.2E-01 lb per MMBtu 1 hr minimum
an integrated heat exchanger a dry basis of steam output or sampling time.
designed to burn coal/solid corrected to 3 1.5 lb per MWh; 3-
fossil fuel. percent oxygen, 3- run average.
run average; or
(150 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
30-day rolling
average).
7. Stokers/sloped grate/ a. CO (or CEMS) 620 ppm by volume on 5.8E-01 lb per MMBtu 1 hr minimum
others designed to burn wet a dry basis of steam output or sampling time.
biomass fuel. corrected to 3 6.8 lb per MWh; 3-
percent oxygen, 3- run average.
run average; or
(390 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
30-day rolling
average).
b. Filterable 3.0E-02 lb per MMBtu 3.5E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(2.6E-05 lb per 4.2E-01 lb per MWh;
MMBtu of heat or (2.7E-05 lb per
input). MMBtu of steam
output or 3.7E-04
lb per MWh).
8. Stokers/sloped grate/ a. CO.......... 460 ppm by volume on 4.2E-01 lb per MMBtu 1 hr minimum
others designed to burn kiln- a dry basis of steam output or sampling time.
dried biomass fuel. corrected to 3 5.1 lb per MWh.
percent oxygen.
b. Filterable 3.0E-02 lb per MMBtu 3.5E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(4.0E-03 lb per 4.2E-01 lb per MWh;
MMBtu of heat or (4.2E-03 lb per
input). MMBtu of steam
output or 5.6E-02
lb per MWh).
[[Page 3115]]
9. Fluidized bed units a. CO (or CEMS) 230 ppm by volume on 2.2E-01 lb per MMBtu 1 hr minimum
designed to burn biomass/bio- a dry basis of steam output or sampling time.
based solids. corrected to 3 2.6 lb per MWh; 3-
percent oxygen, 3- run average.
run average; or
(310 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
30-day rolling
average).
b. Filterable 9.8E-03 lb per MMBtu 1.2E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 3 dscm per run.
(8.3E-05 \a\ lb per 0.14 lb per MWh; or
MMBtu of heat (1.1E-04 \a\ lb per
input). MMBtu of steam
output or 1.2E-03
\a\ lb per MWh).
10. Suspension burners a. CO (or CEMS) 2,400 ppm by volume 1.9 lb per MMBtu of 1 hr minimum
designed to burn biomass/bio- on a dry basis steam output or 27 sampling time.
based solids. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(2,000 ppm by
volume on a dry
basis corrected to
3 percent oxygen
\d\, 10-day rolling
average).
b. Filterable 3.0E-02 lb per MMBtu 3.1E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(6.5E-03 lb per 4.2E-01 lb per MWh;
MMBtu of heat or (6.6E-03 lb per
input). MMBtu of steam
output or 9.1E-02
lb per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS) 330 ppm by volume on 3.5E-01 lb per MMBtu 1 hr minimum
designed to burn biomass/bio- a dry basis of steam output or sampling time.
based solids. corrected to 3 3.6 lb per MWh; 3-
percent oxygen, 3- run average.
run average; or
(520 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
10-day rolling
average).
b. Filterable 3.2E-03 lb per MMBtu 4.3E-03 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 3 dscm per run.
(3.9E-05 lb per 4.5E-02 lb per MWh;
MMBtu of heat or (5.2E-05 lb per
input). MMBtu of steam
output or 5.5E-04
lb per MWh).
12. Fuel cell units designed a. CO.......... 910 ppm by volume on 1.1 lb per MMBtu of 1 hr minimum
to burn biomass/bio-based a dry basis steam output or sampling time.
solids. corrected to 3 1.0E+01 lb per MWh.
percent oxygen.
b. Filterable 2.0E-02 lb per MMBtu 3.0E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(2.9E-05 \a\ lb per 2.8E-01 lb per MWh;
MMBtu of heat or (5.1E-05 lb per
input). MMBtu of steam
output or 4.1E-04
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS) 1,100 ppm by volume 1.4 lb per MMBtu of 1 hr minimum
boiler designed to burn on a dry basis steam output or 12 sampling time.
biomass/bio-based solids. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(900 ppm by volume
on a dry basis
corrected to 3
percent oxygen \d\,
30-day rolling
average).
b. Filterable 2.6E-02 lb per MMBtu 3.3E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 3 dscm per run.
(4.4E-04 lb per 3.7E-01 lb per MWh;
MMBtu of heat or (5.5E-04 lb per
input). MMBtu of steam
output or 6.2E-03
lb per MWh).
14. Units designed to burn a. HCl......... 4.4E-04 lb per MMBtu 4.8E-04 lb per MMBtu For M26A: Collect a
liquid fuel. of heat input. of steam output or minimum of 2 dscm
6.1E-03 lb per MWh. per run; for M26,
collect a minimum
of 240 liters per
run.
b. Mercury..... 4.8E-07 \a\ lb per 5.3E-07 \a\ lb per For M29, collect a
MMBtu of heat input. MMBtu of steam minimum of 4 dscm
output or 6.7E-06 per run; for M30A
\a\ lb per MWh. or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
[[Page 3116]]
15. Units designed to burn a. CO.......... 130 ppm by volume on 0.13 lb per MMBtu of 1 hr minimum
heavy liquid fuel. a dry basis steam output or 1.4 sampling time.
corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average.
b. Filterable 1.3E-02 lb per MMBtu 1.5E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 3 dscm per run.
(7.5E-05 lb per 1.8E-01 lb per MWh;
MMBtu of heat or (8.2E-05 lb per
input). MMBtu of steam
output or 1.1E-03
lb per MWh).
16. Units designed to burn a. CO.......... 130 ppm by volume on 0.13 lb per MMBtu of 1 hr minimum
light liquid fuel. a dry basis steam output or 1.4 sampling time.
corrected to 3 lb per MWh.
percent oxygen.
b. Filterable 1.1E-03 \a\ lb per 1.2E-03 \a\ lb per Collect a minimum of
PM (or TSM). MMBtu of heat MMBtu of steam 3 dscm per run.
input; or (2.9E-05 output or 1.6E-02
lb per MMBtu of \a\ lb per MWh; or
heat input). (3.2E-05 lb per
MMBtu of steam
output or 4.0E-04
lb per MWh).
17. Units designed to burn a. CO.......... 130 ppm by volume on 0.13 lb per MMBtu of 1 hr minimum
liquid fuel that are non- a dry basis steam output or 1.4 sampling time.
continental units. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average based
on stack test.
b. Filterable 2.3E-02 lb per MMBtu 2.5E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 4 dscm per run.
(8.6E-04 lb per 3.2E-01 lb per MWh;
MMBtu of heat or (9.4E-04 lb per
input). MMBtu of steam
output or 1.2E-02
lb per MWh).
18. Units designed to burn a. CO.......... 130 ppm by volume on 0.16 lb per MMBtu of 1 hr minimum
gas 2 (other) gases. a dry basis steam output or 1.0 sampling time.
corrected to 3 lb per MWh.
percent oxygen.
b. HCl......... 1.7E-03 lb per MMBtu 2.9E-03 lb per MMBtu For M26A, Collect a
of heat input. of steam output or minimum of 2 dscm
1.8E-02 lb per MWh. per run; for M26,
collect a minimum
of 240 liters per
run.
c. Mercury..... 7.9E-06 lb per MMBtu 1.4E-05 lb per MMBtu For M29, collect a
of heat input. of steam output or minimum of 3 dscm
8.3E-05 lb per MWh. per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\, collect
a minimum of 3
dscm.
d. Filterable 6.7E-03 lb per MMBtu 1.2E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 3 dscm per run.
(2.1E-04 lb per 7.0E-02 lb per MWh;
MMBtu of heat or (3.5E-04 lb per
input). MMBtu of steam
output or 2.2E-03
lb per MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provisions of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
\c\ If your affected source is a new or reconstructed affected source that commenced construction or
reconstruction after June 4, 2010, and before January 31, 2013, you may comply with the emission limits in
Tables 11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, you must comply
with the emission limits in Table 1 to this subpart.
\d\ An owner or operator may request that compliance with the carbon monoxide emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen
and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
0
21. Table 2 to subpart DDDDD of part 63 is revised to read as follows:
[[Page 3117]]
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing Boilers and Process Heaters
As Stated in Sec. 63.7500, You Must Comply With the Following Applicable Emission Limits:
[Units with heat input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
The emissions must
The emissions must not exceed the
If your boiler or process For the not exceed the following Using this specified
heater is in this subcategory following following emission alternative output- sampling volume or
. . . pollutants . . limits, except based limits, except test run duration .
. during startup and during startup and . .
shutdown . . . shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl......... 2.2E-02 lb per MMBtu 2.5E-02 lb per MMBtu For M26A, Collect a
designed to burn solid fuel. of heat input. of steam output or minimum of 1 dscm
0.27 lb per MWh. per run; for M26,
collect a minimum
of 120 liters per
run.
b. Mercury..... 5.7E-06 lb per MMBtu 6.4E-06 lb per MMBtu For M29, collect a
of heat input. of steam output or minimum of 3 dscm
7.3E-05 lb per MWh. per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
2. Units design to burn coal/ a. Filterable 4.0E-02 lb per MMBtu 4.2E-02 lb per MMBtu Collect a minimum of
solid fossil fuel. PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(5.3E-05 lb per 4.9E-01 lb per MWh;
MMBtu of heat or (5.6E-05 lb per
input). MMBtu of steam
output or 6.5E-04
lb per MWh).
3. Pulverized coal boilers a. CO (or CEMS) 130 ppm by volume on 0.11 lb per MMBtu of 1 hr minimum
designed to burn coal/solid a dry basis steam output or 1.4 sampling time.
fossil fuel. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(320 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
30-day rolling
average).
4. Stokers/others designed to a. CO (or CEMS) 160 ppm by volume on 0.14 lb per MMBtu of 1 hr minimum
burn coal/solid fossil fuel. a dry basis steam output or 1.7 sampling time.
corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(340 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
30-day rolling
average).
5. Fluidized bed units a. CO (or CEMS) 130 ppm by volume on 0.12 lb per MMBtu of 1 hr minimum
designed to burn coal/solid a dry basis steam output or 1.4 sampling time.
fossil fuel. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(230 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
30-day rolling
average).
6. Fluidized bed units with a. CO (or CEMS) 140 ppm by volume on 1.3E-01 lb per MMBtu 1 hr minimum
an integrated heat exchanger a dry basis of steam output or sampling time.
designed to burn coal/solid corrected to 3 1.5 lb per MWh; 3-
fossil fuel. percent oxygen, 3- run average.
run average; or
(150 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
30-day rolling
average).
7. Stokers/sloped grate/ a. CO (or CEMS) 1,500 ppm by volume 1.4 lb per MMBtu of 1 hr minimum
others designed to burn wet on a dry basis steam output or 17 sampling time.
biomass fuel. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(720 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
30-day rolling
average).
b. Filterable 3.7E-02 lb per MMBtu 4.3E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(2.4E-04 lb per 5.2E-01 lb per MWh;
MMBtu of heat or (2.8E-04 lb per
input). MMBtu of steam
output or 3.4E-04
lb per MWh).
8. Stokers/sloped grate/ a. CO.......... 460 ppm by volume on 4.2E-01 lb per MMBtu 1 hr minimum
others designed to burn kiln- a dry basis of steam output or sampling time.
dried biomass fuel. corrected to 3 5.1 lb per MWh.
percent oxygen.
b. Filterable 3.2E-01 lb per MMBtu 3.7E-01 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 1 dscm per run.
(4.0E-03 lb per 4.5 lb per MWh; or
MMBtu of heat (4.6E-03 lb per
input). MMBtu of steam
output or 5.6E-02
lb per MWh).
[[Page 3118]]
9. Fluidized bed units a. CO (or CEMS) 470 ppm by volume on 4.6E-01 lb per MMBtu 1 hr minimum
designed to burn biomass/bio- a dry basis of steam output or sampling time.
based solid. corrected to 3 5.2 lb per MWh; 3-
percent oxygen, 3- run average.
run average; or
(310 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
30-day rolling
average).
b. Filterable 1.1E-01 lb per MMBtu 1.4E-01 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 1 dscm per run.
(1.2E-03 lb per 1.6 lb per MWh; or
MMBtu of heat (1.5E-03 lb per
input). MMBtu of steam
output or 1.7E-02
lb per MWh).
10. Suspension burners a. CO (or CEMS) 2,400 ppm by volume 1.9 lb per MMBtu of 1 hr minimum
designed to burn biomass/bio- on a dry basis steam output or 27 sampling time.
based solid. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(2,000 ppm by
volume on a dry
basis corrected to
3 percent
oxygen,\c\ 10-day
rolling average).
b. Filterable 5.1E-02 lb per MMBtu 5.2E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(6.5E-03 lb per 7.1E-01 lb per MWh;
MMBtu of heat or (6.6E-03 lb per
input). MMBtu of steam
output or 9.1E-02
lb per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS) 770 ppm by volume on 8.4E-01 lb per MMBtu 1 hr minimum
designed to burn biomass/bio- a dry basis of steam output or sampling time.
based solid. corrected to 3 8.4 lb per MWh; 3-
percent oxygen, 3- run average.
run average; or
(520 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
10-day rolling
average).
b. Filterable 2.8E-01 lb per MMBtu 3.9E-01 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 1 dscm per run.
(2.0E-03 lb per 3.9 lb per MWh; or
MMBtu of heat (2.8E-03 lb per
input). MMBtu of steam
output or 2.8E-02
lb per MWh).
12. Fuel cell units designed a. CO.......... 1,100 ppm by volume 2.4 lb per MMBtu of 1 hr minimum
to burn biomass/bio-based on a dry basis steam output or 12 sampling time.
solid. corrected to 3 lb per MWh.
percent oxygen.
b. Filterable 2.0E-02 lb per MMBtu 5.5E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(5.8E-03 lb per 2.8E-01 lb per MWh;
MMBtu of heat or (1.6E-02 lb per
input). MMBtu of steam
output or 8.1E-02
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS) 3,500 ppm by volume 3.5 lb per MMBtu of 1 hr minimum
units designed to burn on a dry basis steam output or 39 sampling time.
biomass/bio-based solid. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average; or
(900 ppm by volume
on a dry basis
corrected to 3
percent oxygen,\c\
30-day rolling
average).
b. Filterable 4.4E-01 lb per MMBtu 5.5E-01 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 1 dscm per run.
(4.5E-04 lb per 6.2 lb per MWh; or
MMBtu of heat (5.7E-04 lb per
input). MMBtu of steam
output or 6.3E-03
lb per MWh).
14. Units designed to burn a. HCl......... 1.1E-03 lb per MMBtu 1.4E-03 lb per MMBtu For M26A, collect a
liquid fuel. of heat input. of steam output or minimum of 2 dscm
1.6E-02 lb per MWh. per run; for M26,
collect a minimum
of 240 liters per
run.
b. Mercury..... 2.0E-06 \a\ lb per 2.5E-06 \a\ lb per For M29, collect a
MMBtu of heat input. MMBtu of steam minimum of 3 dscm
output or 2.8E-05 per run; for M30A
lb per MWh. or M30B collect a
minimum sample as
specified in the
method, for ASTM
D6784, \b\ collect
a minimum of 2
dscm.
[[Page 3119]]
15. Units designed to burn a. CO.......... 130 ppm by volume on 0.13 lb per MMBtu of 1 hr minimum
heavy liquid fuel. a dry basis steam output or 1.4 sampling time.
corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average.
b. Filterable 6.2E-02 lb per MMBtu 7.5E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 1 dscm per run.
(2.0E-04 lb per 8.6E-01 lb per MWh;
MMBtu of heat or (2.5E-04 lb per
input). MMBtu of steam
output or 2.8E-03
lb per MWh).
16. Units designed to burn a. CO.......... 130 ppm by volume on 0.13 lb per MMBtu of 1 hr minimum
light liquid fuel. a dry basis steam output or 1.4 sampling time.
corrected to 3 lb per MWh.
percent oxygen.
b. Filterable 7.9E-03 \a\ lb per 9.6E-03 \a\ lb per Collect a minimum of
PM (or TSM). MMBtu of heat MMBtu of steam 3 dscm per run.
input; or (6.2E-05 output or 1.1E-01
lb per MMBtu of \a\ lb per MWh; or
heat input). (7.5E-05 lb per
MMBtu of steam
output or 8.6E-04
lb per MWh).
17. Units designed to burn a. CO.......... 130 ppm by volume on 0.13 lb per MMBtu of 1 hr minimum
liquid fuel that are non- a dry basis steam output or 1.4 sampling time.
continental units. corrected to 3 lb per MWh; 3-run
percent oxygen, 3- average.
run average based
on stack test.
b. Filterable 2.7E-01 lb per MMBtu 3.3E-01 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input; or of steam output or 2 dscm per run.
(8.6E-04 lb per 3.8 lb per MWh; or
MMBtu of heat (1.1E-03 lb per
input). MMBtu of steam
output or 1.2E-02
lb per MWh).
18. Units designed to burn a. CO.......... 130 ppm by volume on 0.16 lb per MMBtu of 1 hr minimum
gas 2 (other) gases. a dry basis steam output or 1.0 sampling time.
corrected to 3 lb per MWh.
percent oxygen.
b. HCl......... 1.7E-03 lb per MMBtu 2.9E-03 lb per MMBtu For M26A, collect a
of heat input. of steam output or minimum of 2 dscm
1.8E-02 lb per MWh. per run; for M26,
collect a minimum
of 240 liters per
run.
c. Mercury..... 7.9E-06 lb per MMBtu 1.4E-05 lb per MMBtu For M29, collect a
of heat input. of steam output or minimum of 3 dscm
8.3E-05 lb per MWh. per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784,\b\ collect a
minimum of 2 dscm.
d. Filterable 6.7E-03 lb per MMBtu 1.2E-02 lb per MMBtu Collect a minimum of
PM (or TSM). of heat input or of steam output or 3 dscm per run.
(2.1E-04 lb per 7.0E-02 lb per MWh;
MMBtu of heat or (3.5E-04 lb per
input). MMBtu of steam
output or 2.2E-03
lb per MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provisions of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years
must show that your emissions are at or below 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec. 63.14.
\c\ An owner or operator may request that compliance with the carbon monoxide emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen
and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
0
22. Table 3 to subpart DDDDD of part 63 is amended by revising the
entry for ``4,'' ``5,'' and ``6'' to read as follows:
[[Page 3120]]
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
[As stated in Sec. 63.7500, you must comply with the following
applicable work practice standards:]
------------------------------------------------------------------------
If your unit is . . . You must meet the following . . .
------------------------------------------------------------------------
4. An existing boiler or Must have a one-time energy assessment
process heater located at a performed by a qualified energy
major source facility, not assessor. An energy assessment completed
including limited use units. on or after January 1, 2008, that meets
or is amended to meet the energy
assessment requirements in this table,
satisfies the energy assessment
requirement. A facility that operated
under an energy management program
developed according to the ENERGY STAR
guidelines for energy management or
compatible with ISO 50001 for at least
one year between January 1, 2008 and the
compliance date specified in Sec.
63.7495 that includes the affected units
also satisfies the energy assessment
requirement. The energy assessment must
include the following with extent of the
evaluation for items a. to e.
appropriate for the on-site technical
hours listed in Sec. 63.7575:
a. A visual inspection of the boiler or
process heater system.
b. An evaluation of operating
characteristics of the boiler or process
heater systems, specifications of energy
using systems, operating and maintenance
procedures, and unusual operating
constraints.
c. An inventory of major energy use
systems consuming energy from affected
boilers and process heaters and which
are under the control of the boiler/
process heater owner/operator.
d. A review of available architectural
and engineering plans, facility
operation and maintenance procedures and
logs, and fuel usage.
e. A review of the facility's energy
management program and provide
recommendations for improvements
consistent with the definition of energy
management program, if identified.
f. A list of cost-effective energy
conservation measures that are within
the facility's control.
g. A list of the energy savings potential
of the energy conservation measures
identified.
h. A comprehensive report detailing the
ways to improve efficiency, the cost of
specific improvements, benefits, and the
time frame for recouping those
investments.
5. An existing or new boiler a. You must operate all CMS during
or process heater subject to startup.
emission limits in Table 1
or 2 or 11 through 13 to
this subpart during startup.
b. For startup of a boiler or process
heater, you must use one or a
combination of the following clean
fuels: Natural gas, synthetic natural
gas, propane, other Gas 1 fuels,
distillate oil, syngas, ultra-low sulfur
diesel, fuel oil-soaked rags, kerosene,
hydrogen, paper, cardboard, refinery
gas, liquefied petroleum gas, and any
fuels meeting the appropriate HCl,
mercury and TSM emission standards by
fuel analysis.
c. You have the option of complying using
either of the following work practice
standards.
(1) If you start firing coal/solid fossil
fuel, biomass/bio-based solids, heavy
liquid fuel, or gas 2 (other) gases, you
must vent emissions to the main stack(s)
and engage all of the applicable control
devices except limestone injection in
fluidized bed combustion (FBC) boilers,
dry scrubber, fabric filter, selective
non-catalytic reduction (SNCR), and
selective catalytic reduction (SCR). You
must start your limestone injection in
FBC boilers, dry scrubber, fabric
filter, SNCR, and SCR systems as
expeditiously as possible. Startup ends
when steam or heat is supplied for any
purpose, OR
(2) If you choose to comply using
definition (2) of ``startup'' in Sec.
63.7575, once you start firing (i.e.,
feeding) coal/solid fossil fuel, biomass/
bio-based solids, heavy liquid fuel, or
gas 2 (other) gases, you must vent
emissions to the main stack(s) and
engage all of the applicable control
devices so as to comply with the
emission limits within 4 hours of start
of supplying useful thermal energy. You
must effect PM control within one hour
of first firing coal/solid fossil fuel,
biomass/bio-based solids, heavy liquid
fuel, or gas 2 (other) gases \a\. You
must start all applicable control
devices as expeditiously as possible,
but, in any case, when necessary to
comply with other standards applicable
to the source by a permit limit or a
rule other than this subpart that
require operation of the control
devices.
d. You must comply with all applicable
emission limits at all times except
during startup and shutdown periods at
which time you must meet this work
practice. You must collect monitoring
data during periods of startup, as
specified in Sec. 63.7535(b). You must
keep records during periods of startup.
You must provide reports concerning
activities and periods of startup, as
specified in Sec. 63.7555.
6. An existing or new boiler You must operate all CMS during shutdown.
or process heater subject to While firing coal/solid fossil fuel,
emission limits in Tables 1 biomass/bio-based solids, heavy liquid
or 2 or 11 through 13 to fuel, or gas 2 (other) gases during
this subpart during shutdown. shutdown, you must vent emissions to the
main stack(s) and operate all applicable
control devices, except limestone
injection in FBC boilers, dry scrubber,
fabric filter, SNCR, and SCR but, in any
case, when necessary to comply with
other standards applicable to the source
that require operation of the control
device.
If, in addition to the fuel used prior to
initiation of shutdown, another fuel
must be used to support the shutdown
process, that additional fuel must be
one or a combination of the following
clean fuels: Natural gas, synthetic
natural gas, propane, other Gas 1 fuels,
distillate oil, syngas, ultra-low sulfur
diesel, refinery gas, and liquefied
petroleum gas.
You must comply with all applicable
emissions limits at all times except for
startup or shutdown periods conforming
with this work practice. You must
collect monitoring data during periods
of shutdown, as specified in Sec.
63.7535(b). You must keep records during
periods of shutdown. You must provide
reports concerning activities and
periods of shutdown, as specified in
Sec. 63.7555.
------------------------------------------------------------------------
\a\ The source may request a variance with the PM controls requirement.
The source must provide evidence that (1) meeting the ``fuel firing +
1 hour'' requirement violates manufacturer's recommended operation and/
or safety requirements, and (2) the PM control device is appropriately
designed and sized to meet the filterable PM emission limit.
[[Page 3121]]
0
23. Table 4 to subpart DDDDD of part 63 is revised to read as follows:
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers and
Process Heaters
[As stated in Sec. 63.7500, you must comply with the applicable
operating limits:]
------------------------------------------------------------------------
When complying with a Table
1, 2, 11, 12, or 13 numerical You must meet these operating limits . .
emission limit using . . . .
------------------------------------------------------------------------
1. Wet PM scrubber control on Maintain the 30-day rolling average
a boiler or process heater pressure drop and the 30-day rolling
not using a PM CPMS. average liquid flow rate at or above the
lowest one-hour average pressure drop
and the lowest one-hour average liquid
flow rate, respectively, measured during
the most recent performance test
demonstrating compliance with the PM
emission limitation according to Sec.
63.7530(b) and Table 7 to this subpart.
2. Wet acid gas (HCl) Maintain the 30-day rolling average
scrubber control on a boiler effluent pH at or above the lowest one-
or process heater not using hour average pH and the 30-day rolling
a HCl CEMS. average liquid flow rate at or above the
lowest one-hour average liquid flow rate
measured during the most recent
performance test demonstrating
compliance with the HCl emission
limitation according to Sec.
63.7530(b) and Table 7 to this subpart.
3. Fabric filter control on a a. Maintain opacity to less than or equal
boiler or process heater not to 10 percent opacity (daily block
using a PM CPMS. average); or
b. Install and operate a bag leak
detection system according to Sec.
63.7525 and operate the fabric filter
such that the bag leak detection system
alert is not activated more than 5
percent of the operating time during
each 6-month period.
4. Electrostatic precipitator a. This option is for boilers and process
control on a boiler or heaters that operate dry control systems
process heater not using a (i.e., an ESP without a wet scrubber).
PM CPMS. Existing and new boilers and process
heaters must maintain opacity to less
than or equal to 10 percent opacity
(daily block average).
b. This option is only for boilers and
process heaters not subject to PM CPMS
or continuous compliance with an opacity
limit (i.e., dry ESP). Maintain the 30-
day rolling average total secondary
electric power input of the
electrostatic precipitator at or above
the operating limits established during
the performance test according to Sec.
63.7530(b) and Table 7 to this subpart.
5. Dry scrubber or carbon Maintain the minimum sorbent or carbon
injection control on a injection rate as defined in Sec.
boiler or process heater not 63.7575 of this subpart.
using a mercury CEMS.
6. Any other add-on air This option is for boilers and process
pollution control type on a heaters that operate dry control
boiler or process heater not systems. Existing and new boilers and
using a PM CPMS. process heaters must maintain opacity to
less than or equal to 10 percent opacity
(daily block average).
7. Fuel analysis............. Maintain the fuel type or fuel mixture
such that the applicable emission rates
calculated according to Sec.
63.7530(c)(1), (2) and/or (3) is less
than the applicable emission limits.
8. Performance testing....... For boilers and process heaters that
demonstrate compliance with a
performance test, maintain the operating
load of each unit such that it does not
exceed 110 percent of the highest hourly
average operating load recorded during
the most recent performance test.
9. Oxygen analyzer system.... For boilers and process heaters subject
to a CO emission limit that demonstrate
compliance with an O2 analyzer system as
specified in Sec. 63.7525(a), maintain
the 30-day rolling average oxygen
content at or above the lowest hourly
average oxygen concentration measured
during the most recent CO performance
test, as specified in Table 8. This
requirement does not apply to units that
install an oxygen trim system since
these units will set the trim system to
the level specified in Sec.
63.7525(a).
10. SO2CEMS.................. For boilers or process heaters subject to
an HCl emission limit that demonstrate
compliance with an SO2CEMS, maintain the
30-day rolling average SO2emission rate
at or below the highest hourly average
SO2concentration measured during the
most recent HCl performance test, as
specified in Table 8.
------------------------------------------------------------------------
0
24. Table 5 to subpart DDDDD of part 63 is amended by revising the
heading to the third column and adding the footnote ``a'' to read as
follows:
Table 5 to Subpart DDDDD of Part 63--Performance Testing Requirements
[As stated in Sec. 63.7520, you must comply with the following
requirements for performance testing for existing, new or reconstructed
affected sources:]
------------------------------------------------------------------------
To conduct a performance test
for the following pollutant . . You must . . . Using, as
. appropriate . . .
------------------------------------------------------------------------
* * * * *
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec. 63.14.
0
25. Table 6 to subpart DDDDD of part 63 is revised to read as follows:
[[Page 3122]]
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
[As stated in Sec. 63.7521, you must comply with the following requirements for fuel analysis testing for
existing, new or reconstructed affected sources. However, equivalent methods (as defined in Sec. 63.7575) may
be used in lieu of the prescribed methods at the discretion of the source owner or operator:]
----------------------------------------------------------------------------------------------------------------
To conduct a fuel analysis for the
following pollutant . . . You must . . . Using . . .
----------------------------------------------------------------------------------------------------------------
1. Mercury......................... a. Collect fuel samples.... Procedure in Sec. 63.7521(c) or ASTM D5192
\a\, or ASTM D7430 \a\, or ASTM D6883 \a\, or
ASTM D2234/D2234M \a\ (for coal) or EPA 1631
or EPA 1631E or ASTM D6323 \a\ (for solid),
or EPA 821-R-01-013 (for liquid or solid), or
ASTM D4177 \a\ (for liquid), or ASTM D4057
\a\ (for liquid), or equivalent.
b. Composite fuel samples.. Procedure in Sec. 63.7521(d) or equivalent.
c. Prepare composited fuel EPA SW-846-3050B \a\ (for solid samples), ASTM
samples. D2013/D2013M \a\ (for coal), ASTM D5198 \a\
(for biomass), or EPA 3050 \a\ (for solid
fuel), or EPA 821-R-01-013 \a\ (for liquid or
solid), or equivalent.
d. Determine heat content ASTM D5865 \a\ (for coal) or ASTM E711 \a\
of the fuel type. (for biomass), or ASTM D5864 \a\ for liquids
and other solids, or ASTM D240 \a\ or
equivalent.
e. Determine moisture ASTM D3173 \a\, ASTM E871 \a\, or ASTM D5864
content of the fuel type. \a\, or ASTM D240, or ASTM D95 \a\ (for
liquid fuels), or ASTM D4006 \a\ (for liquid
fuels), or ASTM D4177 \a\ (for liquid fuels)
or ASTM D4057 \a\ (for liquid fuels), or
equivalent.
f. Measure mercury ASTM D6722 \a\ (for coal), EPA SW-846-7471B
concentration in fuel \a\ (for solid samples), or EPA SW-846-7470A
sample. \a\ (for liquid samples), or equivalent.
g. Convert concentration Equation 8 in Sec. 63.7530.
into units of pounds of
mercury per MMBtu of heat
content.
2. HCl............................. a. Collect fuel samples.... Procedure in Sec. 63.7521(c) or ASTM D5192
\a\, or ASTM D7430 \a\, or ASTM D6883 \a\, or
ASTM D2234/D2234M \a\ (for coal) or ASTM
D6323 \a\ (for coal or biomass), ASTM D4177
\a\ (for liquid fuels) or ASTM D4057 \a\ (for
liquid fuels), or equivalent.
b. Composite fuel samples.. Procedure in Sec. 63.7521(d) or equivalent.
c. Prepare composited fuel EPA SW-846-3050B \a\ (for solid samples), ASTM
samples. D2013/D2013M \a\ (for coal), or ASTM D5198
\a\ (for biomass), or EPA 3050 \a\ or
equivalent.
d. Determine heat content ASTM D5865 \a\ (for coal) or ASTM E711 \a\
of the fuel type. (for biomass), ASTM D5864, ASTM D240 \a\ or
equivalent.
e. Determine moisture ASTM D3173 \a\ or ASTM E871 \a\, or D5864 \a\,
content of the fuel type. or ASTM D240 \a\, or ASTM D95 \a\ (for liquid
fuels), or ASTM D4006 \a\ (for liquid fuels),
or ASTM D4177 \a\ (for liquid fuels) or ASTM
D4057 \a\ (for liquid fuels) or equivalent.
f. Measure chlorine EPA SW-846-9250 \a\, ASTM D6721 \a\, ASTM
concentration in fuel D4208 \a\ (for coal), or EPA SW-846-5050 \a\
sample. or ASTM E776 \a\ (for solid fuel), or EPA SW-
846-9056 \a\ or SW-846-9076 \a\ (for solids
or liquids) or equivalent.
g. Convert concentrations Equation 7 in Sec. 63.7530.
into units of pounds of
HCl per MMBtu of heat
content.
3. Mercury Fuel Specification for a. Measure mercury Method 30B (M30B) at 40 CFR part 60, appendix
other gas 1 fuels. concentration in the fuel A-8 of this chapter or ASTM D5954 \a\, ASTM
sample and convert to D6350 \a\, ISO 6978-1:2003(E) \a\, or ISO
units of micrograms per 6978-2:2003(E) \a\, or EPA-1631 \a\ or
cubic meter, or. equivalent.
b. Measure mercury Method 29, 30A, or 30B (M29, M30A, or M30B) at
concentration in the 40 CFR part 60, appendix A-8 of this chapter
exhaust gas when firing or Method 101A or Method 102 at 40 CFR part
only the other gas 1 fuel 61, appendix B of this chapter, or ASTM
is fired in the boiler or Method D6784 \a\ or equivalent.
process heater.
4. TSM............................. a. Collect fuel samples.... Procedure in Sec. 63.7521(c) or ASTM D5192
\a\, or ASTM D7430 \a\, or ASTM D6883 \a\, or
ASTM D2234/D2234M \a\ (for coal) or ASTM
D6323 \a\ (for coal or biomass), or ASTM
D4177 \a\, (for liquid fuels)or ASTM D4057
\a\ (for liquid fuels), or equivalent.
b. Composite fuel samples.. Procedure in Sec. 63.7521(d) or equivalent.
c. Prepare composited fuel EPA SW-846-3050B \a\ (for solid samples), ASTM
samples. D2013/D2013M \a\ (for coal), ASTM D5198 \a\
or TAPPI T266 \a\ (for biomass), or EPA 3050
\a\ or equivalent.
d. Determine heat content ASTM D5865 \a\ (for coal) or ASTM E711 \a\
of the fuel type. (for biomass), or ASTM D5864 \a\ for liquids
and other solids, or ASTM D240 \a\ or
equivalent.
e. Determine moisture ASTM D3173 \a\ or ASTM E871 \a\, or D5864, or
content of the fuel type. ASTM D240 \a\, or ASTM D95 \a\ (for liquid
fuels), or ASTM D4006 \a\ (for liquid fuels),
or ASTM D4177 \a\ (for liquid fuels) or ASTM
D4057 \a\ (for liquid fuels), or equivalent.
f. Measure TSM ASTM D3683 \a\, or ASTM D4606 \a\, or ASTM
concentration in fuel D6357 \a\ or EPA 200.8 \a\ or EPA SW-846-6020
sample. \a\, or EPA SW-846-6020A \a\, or EPA SW-846-
6010C \a\, EPA 7060 \a\ or EPA 7060A \a\ (for
arsenic only), or EPA SW-846-7740\a\ (for
selenium only).
g. Convert concentrations Equation 9 in Sec. 63.7530.
into units of pounds of
TSM per MMBtu of heat
content.
----------------------------------------------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec. 63.14.
[[Page 3123]]
0
26. Table 7 to subpart DDDDD of part 63 is revised to read as follows:
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
[As stated in Sec. 63.7520, you must comply with the following requirements for establishing operating
limits:]
----------------------------------------------------------------------------------------------------------------
And your
If you have an applicable operating According to the
emission limit for . . . limits are You must . . . Using . . . following
based on . . . requirements
----------------------------------------------------------------------------------------------------------------
1. PM, TSM, or mercury....... a. Wet scrubber i. Establish a site- (1) Data from the (a) You must collect
operating specific minimum scrubber pressure scrubber pressure
parameters. scrubber pressure drop and liquid drop and liquid
drop and minimum flow rate monitors flow rate data
flow rate operating and the PM, TSM, or every 15 minutes
limit according to mercury performance during the entire
Sec. 63.7530(b). test. period of the
performance tests.
(b) Determine the
lowest hourly
average scrubber
pressure drop and
liquid flow rate by
computing the
hourly averages
using all of the 15-
minute readings
taken during each
performance test.
b. i. Establish a site- (1) Data from the (a) You must collect
Electrostatic specific minimum voltage and secondary voltage
precipitator total secondary secondary amperage and secondary
operating electric power monitors during the amperage for each
parameters input according to PM or mercury ESP cell and
(option only Sec. 63.7530(b). performance test. calculate total
for units that secondary electric
operate wet power input data
scrubbers). every 15 minutes
during the entire
period of the
performance tests.
(b) Determine the
average total
secondary electric
power input by
computing the
hourly averages
using all of the 15-
minute readings
taken during each
performance test.
2. HCl....................... a. Wet scrubber i. Establish site- (1) Data from the pH (a) You must collect
operating specific minimum and liquid flow- pH and liquid flow-
parameters. effluent pH and rate monitors and rate data every 15
flow rate operating the HCl performance minutes during the
limits according to test. entire period of
Sec. 63.7530(b). the performance
tests.
(b) Determine the
hourly average pH
and liquid flow
rate by computing
the hourly averages
using all of the 15-
minute readings
taken during each
performance test.
b. Dry scrubber i. Establish a site- (1) Data from the (a) You must collect
operating specific minimum sorbent injection sorbent injection
parameters. sorbent injection rate monitors and rate data every 15
rate operating HCl or mercury minutes during the
limit according to performance test. entire period of
Sec. 63.7530(b). the performance
If different acid tests.
gas sorbents are
used during the HCl
performance test,
the average value
for each sorbent
becomes the site-
specific operating
limit for that
sorbent.
(b) Determine the
hourly average
sorbent injection
rate by computing
the hourly averages
using all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
lowest hourly
average of the
three test run
averages
established during
the performance
test as your
operating limit.
When your unit
operates at lower
loads, multiply
your sorbent
injection rate by
the load fraction,
as defined in Sec.
63.7575, to
determine the
required injection
rate.
c. Alternative i. Establish a site- (1) Data from SO2 (a) You must collect
Maximum SO2 specific maximum CEMS and the HCl the SO2 emissions
emission rate. SO2 emission rate performance test. data according to
operating limit Sec. 63.7525(m)
according to Sec. during the most
63.7530(b). recent HCl
performance tests.
[[Page 3124]]
(b) The maximum SO2
emission rate is
equal to the
highest hourly
average SO2
emission rate
measured during the
most recent HCl
performance tests.
3. Mercury................... a. Activated i. Establish a site- (1) Data from the (a) You must collect
carbon specific minimum activated carbon activated carbon
injection. activated carbon rate monitors and injection rate data
injection rate mercury performance every 15 minutes
operating limit test. during the entire
according to Sec. period of the
63.7530(b). performance tests.
(b) Determine the
hourly average
activated carbon
injection rate by
computing the
hourly averages
using all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
lowest hourly
average established
during the
performance test as
your operating
limit. When your
unit operates at
lower loads,
multiply your
activated carbon
injection rate by
the load fraction,
as defined in Sec.
63.7575, to
determine the
required injection
rate.
4. Carbon monoxide for which a. Oxygen...... i. Establish a unit- (1) Data from the (a) You must collect
compliance is demonstrated specific limit for oxygen analyzer oxygen data every
by a performance test. minimum oxygen system specified in 15 minutes during
level according to Sec. 63.7525(a). the entire period
Sec. 63.7530(b). of the performance
tests.
(b) Determine the
hourly average
oxygen
concentration by
computing the
hourly averages
using all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
lowest hourly
average established
during the
performance test as
your minimum
operating limit.
5. Any pollutant for which a. Boiler or i. Establish a unit (1) Data from the (a) You must collect
compliance is demonstrated process heater specific limit for operating load operating load or
by a performance test. operating load. maximum operating monitors or from steam generation
load according to steam generation data every 15
Sec. 63.7520(c). monitors. minutes during the
entire period of
the performance
test.
(b) Determine the
average operating
load by computing
the hourly averages
using all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
average of the
three test run
averages during the
performance test,
and multiply this
by 1.1 (110
percent) as your
operating limit.
----------------------------------------------------------------------------------------------------------------
0
27. Table 8 to subpart DDDDD of part 63 is amended by revising the
entry for ``3,'' ``9,'' ``10,'' and ``11'' to read as follows:
[[Page 3125]]
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
[As stated in Sec. 63.7540, you must show continuous compliance with
the emission limitations for each boiler or process heater according to
the following:]
------------------------------------------------------------------------
If you must meet the
following operating limits or You must demonstrate continuous
work practice standards . . . compliance by . . .
------------------------------------------------------------------------
* * * * *
3. Fabric Filter Bag Leak Installing and operating a bag leak
Detection Operation. detection system according to Sec.
63.7525 and operating the fabric filter
such that the requirements in Sec.
63.7540(a)(7) are met.
* * * * *
9. Oxygen content............ a. Continuously monitor the oxygen
content using an oxygen analyzer system
according to Sec. 63.7525(a). This
requirement does not apply to units that
install an oxygen trim system since
these units will set the trim system to
the level specified in Sec.
63.7525(a)(7).
b. Reducing the data to 30-day rolling
averages; and
c. Maintain the 30-day rolling average
oxygen content at or above the lowest
hourly average oxygen level measured
during the most recent CO performance
test.
10. Boiler or process heater a. Collecting operating load data or
operating load. steam generation data every 15 minutes.
b. Reducing the data to 30-day rolling
averages; and
b. Maintaining the 30-day rolling average
operating load such that it does not
exceed 110 percent of the highest hourly
average operating load recorded during
the most recent performance test
according to Sec. 63.7520(c).
11. SO2emissions using a. Collecting the SO2CEMS output data
SO2CEMS. according to Sec. 63.7525;
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
SO2CEMS emission rate to a level at or
below the highest hourly SO2rate
measured during the most recent HCl
performance test according to Sec.
63.7530.
------------------------------------------------------------------------
0
28. Table 9 to subpart DDDDD of part 63 is revised to read as follows:
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
[As stated in Sec. 63.7550, you must comply with the following
requirements for reports:]
------------------------------------------------------------------------
You must submit
You must submit a(n) The report must contain . the report . .
. . .
------------------------------------------------------------------------
1. Compliance report........ a. Information required Semiannually,
in Sec. 63.7550(c)(1) annually,
through (5); and. biennially, or
every 5 years
according to
the
requirements
in Sec.
63.7550(b).
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
for periods of startup
and shutdown in Table 3
to this subpart that
apply to you, a
statement that there
were no deviations from
the emission limitations
and work practice
standards during the
reporting period. If
there were no periods
during which the CMSs,
including continuous
emissions monitoring
system, continuous
opacity monitoring
system, and operating
parameter monitoring
systems, were out-of-
control as specified in
Sec. 63.8(c)(7), a
statement that there
were no periods during
which the CMSs were out-
of-control during the
reporting period; and.
c. If you have a
deviation from any
emission limitation
(emission limit and
operating limit) where
you are not using a CMS
to comply with that
emission limit or
operating limit, or a
deviation from a work
practice standard for
periods of startup and
shutdown, during the
reporting period, the
report must contain the
information in Sec.
63.7550(d); and.
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
Sec. 63.8(c)(7), or
otherwise not operating,
the report must contain
the information in Sec.
63.7550(e).
------------------------------------------------------------------------
* * * * *
0
29. Table 11 to subpart DDDDD of part 63 is revised to read as follows:
[[Page 3126]]
Table 11 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters That Commenced Construction or Reconstruction After June 4, 2010, and Before May 20, 2011
----------------------------------------------------------------------------------------------------------------
The emissions must not
exceed the following
If your boiler or process heater is For the following emission limits, except Using this specified
in this subcategory . . . pollutants . . . during periods of sampling volume or test
startup and shutdown . run duration . . .
. .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl................. 0.022 lb per MMBtu of For M26A, collect a
designed to burn solid fuel. heat input. minimum of 1 dscm per
run; for M26 collect a
minimum of 120 liters
per run.
2. Units in all subcategories a. Mercury............. 8.0E-07 \a\ lb per For M29, collect a
designed to burn solid fuel that MMBtu of heat input. minimum of 4 dscm per
combust at least 10 percent biomass/ run; for M30A or M30B,
bio-based solids on an annual heat collect a minimum
input basis and less than 10 percent sample as specified in
coal/solid fossil fuels on an annual the method; for ASTM
heat input basis. D6784 \b\ collect a
minimum of 4 dscm.
3. Units in all subcategories a. Mercury............. 2.0E-06 lb per MMBtu of For M29, collect a
designed to burn solid fuel that heat input. minimum of 4 dscm per
combust at least 10 percent coal/ run; for M30A or M30B,
solid fossil fuels on an annual heat collect a minimum
input basis and less than 10 percent sample as specified in
biomass/bio-based solids on an the method; for ASTM
annual heat input basis. D6784 \b\ collect a
minimum of 4 dscm.
4. Units design to burn coal/solid a. Filterable PM (or 1.1E-03 lb per MMBtu of Collect a minimum of 3
fossil fuel. TSM). heat input; or (2.3E- dscm per run.
05 lb per MMBtu of
heat input).
5. Pulverized coal boilers designed a. Carbon monoxide (CO) 130 ppm by volume on a 1 hr minimum sampling
to burn coal/solid fossil fuel. (or CEMS). dry basis corrected to time.
3 percent oxygen, 3-
run average; or (320
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 30-
day rolling average).
6. Stokers designed to burn coal/ a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
solid fossil fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (340
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 10-
day rolling average).
7. Fluidized bed units designed to a. CO (or CEMS)........ 130 ppm by volume on a 1 hr minimum sampling
burn coal/solid fossil fuel. dry basis corrected to time
3 percent oxygen, 3-
run average; or (230
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 30-
day rolling average).
8. Fluidized bed units with an a. CO (or CEMS)........ 140 ppm by volume on a 1 hr minimum sampling
integrated heat exchanger designed dry basis corrected to time.
to burn coal/solid fossil fuel. 3 percent oxygen, 3-
run average; or (150
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 30-
day rolling average).
9. Stokers/sloped grate/others a. CO (or CEMS)........ 620 ppm by volume on a 1 hr minimum sampling
designed to burn wet biomass fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (390
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 30-
day rolling average).
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.6E- dscm per run.
05 lb per MMBtu of
heat input).
10. Stokers/sloped grate/others a. CO.................. 560 ppm by volume on a 1 hr minimum sampling
designed to burn kiln-dried biomass dry basis corrected to time.
fuel. 3 percent oxygen.
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (4.0E- dscm per run.
03 lb per MMBtu of
heat input).
[[Page 3127]]
11. Fluidized bed units designed to a. CO (or CEMS)........ 230 ppm by volume on a 1 hr minimum sampling
burn biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen, 3-
run average; or (310
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 30-
day rolling average).
b. Filterable PM (or 9.8E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (8.3E- dscm per run.
05 \a\ lb per MMBtu of
heat input).
12. Suspension burners designed to a. CO (or CEMS)........ 2,400 ppm by volume on 1 hr minimum sampling
burn biomass/bio-based solids. a dry basis corrected time.
to 3 percent oxygen, 3-
run average; or (2,000
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 10-
day rolling average).
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (6.5E- dscm per run.
03 lb per MMBtu of
heat input).
13. Dutch Ovens/Pile burners designed a. CO (or CEMS)........ 1,010 ppm by volume on 1 hr minimum sampling
to burn biomass/bio-based solids. a dry basis corrected time.
to 3 percent oxygen, 3-
run average; or (520
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 10-
day rolling average).
b. Filterable PM (or 8.0E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (3.9E- dscm per run.
05 lb per MMBtu of
heat input).
14. Fuel cell units designed to burn a. CO.................. 910 ppm by volume on a 1 hr minimum sampling
biomass/bio-based solids. dry basis corrected to time.
3 percent oxygen.
b. Filterable PM (or 2.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.9E- dscm per run.
05 lb per MMBtu of
heat input).
15. Hybrid suspension grate boiler a. CO (or CEMS)........ 1,100 ppm by volume on 1 hr minimum sampling
designed to burn biomass/bio-based a dry basis corrected time.
solids. to 3 percent oxygen, 3-
run average; or (900
ppm by volume on a dry
basis corrected to 3
percent oxygen \c\, 30-
day rolling average).
b. Filterable PM (or 2.6E-02 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (4.4E- dscm per run.
04 lb per MMBtu of
heat input).
16. Units designed to burn liquid a. HCl................. 4.4E-04 lb per MMBtu of For M26A: Collect a
fuel. heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run.
b. Mercury............. 4.8E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
17. Units designed to burn heavy a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
liquid fuel. dry basis corrected to time.
3 percent oxygen, 3-
run average.
b. Filterable PM (or 1.3E-02 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (7.5E- dscm per run.
05 lb per MMBtu of
heat input).
18. Units designed to burn light a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
liquid fuel. dry basis corrected to time.
3 percent oxygen.
b. Filterable PM (or 2.0E-03 \a\ lb per Collect a minimum of 3
TSM). MMBtu of heat input; dscm per run.
or (2.9E-05 lb per
MMBtu of heat input).
[[Page 3128]]
19. Units designed to burn liquid a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
fuel that are non-continental units. dry basis corrected to time.
3 percent oxygen, 3-
run average based on
stack test.
b. Filterable PM (or 2.3E-02 lb per MMBtu of Collect a minimum of 4
TSM). heat input; or (8.6E- dscm per run.
04 lb per MMBtu of
heat input).
20. Units designed to burn gas 2 a. CO.................. 130 ppm by volume on a 1 hr minimum sampling
(other) gases. dry basis corrected to time.
3 percent oxygen.
b. HCl................. 1.7E-03 lb per MMBtu of For M26A, Collect a
heat input. minimum of 2 dscm per
run; for M26, collect
a minimum of 240
liters per run.
c. Mercury............. 7.9E-06 lb per MMBtu of For M29, collect a
heat input. minimum of 3 dscm per
run; for M30A or M30B,
collect a minimum
sample as specified in
the method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
d. Filterable PM (or 6.7E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.1E- dscm per run.
04 lb per MMBtu of
heat input).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provision of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
\c\ An owner or operator may request that compliance with the carbon monoxide emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen
and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
0
29. Table 12 to subpart DDDDD of part 63 is revised to read as follows:
Table 12 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters That Commenced Construction or Reconstruction After May 20, 2011, and Before December 23, 2011
----------------------------------------------------------------------------------------------------------------
The emissions must not
exceed the following Using this specified
If your boiler or process heater For the following emission limits, except sampling volume or test
is in this subcategory . . . pollutants . . . during periods of startup run duration . . .
and shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl............... 0.022 lb per MMBtu of heat For M26A, collect a
designed to burn solid fuel. input. minimum of 1 dscm per
run; for M26 collect a
minimum of 120 liters
per run.
b. Mercury........... 3.5E-06 \a\ lb per MMBtu For M29, collect a
of heat input. minimum of 3 dscm per
run; for M30A or M30B,
collect a minimum sample
as specified in the
method; for ASTM D6784
\b\ collect a minimum of
3 dscm.
2. Units design to burn coal/solid a. Filterable PM (or 1.1E-03 lb per MMBtu of Collect a minimum of 3
fossil fuel. TSM). heat input; or (2.3E-05 dscm per run.
lb per MMBtu of heat
input).
3. Pulverized coal boilers a. Carbon monoxide 130 ppm by volume on a dry 1 hr minimum sampling
designed to burn coal/solid (CO) (or CEMS) basis corrected to 3 time.
fossil fuel. percent oxygen, 3-run
average; or (320 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 30-day
rolling average)
4. Stokers designed to burn coal/ a. CO (or CEMS)...... 130 ppm by volume on a dry 1 hr minimum sampling
solid fossil fuel. basis corrected to 3 time.
percent oxygen, 3-run
average; or (340 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 10-day
rolling average)
[[Page 3129]]
5. Fluidized bed units designed to a. CO (or CEMS)...... 130 ppm by volume on a dry 1 hr minimum sampling
burn coal/solid fossil fuel. basis corrected to 3 time.
percent oxygen, 3-run
average; or (230 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 30-day
rolling average)
6. Fluidized bed units with an a. CO (or CEMS)...... 140 ppm by volume on a dry 1 hr minimum sampling
integrated heat exchanger basis corrected to 3 time.
designed to burn coal/solid percent oxygen, 3-run
fossil fuel. average; or (150 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 30-day
rolling average)
7. Stokers/sloped grate/others a. CO (or CEMS)...... 620 ppm by volume on a dry 1 hr minimum sampling
designed to burn wet biomass fuel. basis corrected to 3 time.
percent oxygen, 3-run
average; or (390 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 30-day
rolling average)
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.6E-05 dscm per run.
lb per MMBtu of heat
input)
8. Stokers/sloped grate/others a. CO................ 460 ppm by volume on a dry 1 hr minimum sampling
designed to burn kiln-dried basis corrected to 3 time.
biomass fuel. percent oxygen
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (4.0E-03 dscm per run.
lb per MMBtu of heat
input)
9. Fluidized bed units designed to a. CO (or CEMS)...... 260 ppm by volume on a dry 1 hr minimum sampling
burn biomass/bio-based solids. basis corrected to 3 time.
percent oxygen, 3-run
average; or (310 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 30-day
rolling average)
b. Filterable PM (or 9.8E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (8.3E-05 dscm per run.
\a\ lb per MMBtu of heat
input)
10. Suspension burners designed to a. CO (or CEMS)...... 2,400 ppm by volume on a 1 hr minimum sampling
burn biomass/bio-based solids. dry basis corrected to 3 time.
percent oxygen, 3-run
average; or (2,000 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 10-day
rolling average)
b. Filterable PM (or 3.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (6.5E-03 dscm per run.
lb per MMBtu of heat
input)
11. Dutch Ovens/Pile burners a. CO (or CEMS)...... 470 ppm by volume on a dry 1 hr minimum sampling
designed to burn biomass/bio- basis corrected to 3 time.
based solids. percent oxygen, 3-run
average; or (520 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 10-day
rolling average)
b. Filterable PM (or 3.2E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (3.9E-05 dscm per run.
lb per MMBtu of heat
input)
12. Fuel cell units designed to a. CO................ 910 ppm by volume on a dry 1 hr minimum sampling
burn biomass/bio-based solids. basis corrected to 3 time.
percent oxygen
b. Filterable PM (or 2.0E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (2.9E-05 dscm per run.
lb per MMBtu of heat
input)
13. Hybrid suspension grate boiler a. CO (or CEMS)...... 1,500 ppm by volume on a 1 hr minimum sampling
designed to burn biomass/bio- dry basis corrected to 3 time.
based solids. percent oxygen, 3-run
average; or (900 ppm by
volume on a dry basis
corrected to 3 percent
oxygen \c\, 30-day
rolling average)
b. Filterable PM (or 2.6E-02 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (4.4E-04 dscm per run.
lb per MMBtu of heat
input)
14. Units designed to burn liquid a. HCl............... 4.4E-04 lb per MMBtu of For M26A: Collect a
fuel. heat input. minimum of 2 dscm per
run; for M26, collect a
minimum of 240 liters
per run.
[[Page 3130]]
b. Mercury........... 4.8E-07 \a\ lb per MMBtu For M29, collect a
of heat input. minimum of 4 dscm per
run; for M30A or M30B,
collect a minimum sample
as specified in the
method; for ASTM D6784
\b\ collect a minimum of
4 dscm.
15. Units designed to burn heavy a. CO................ 130 ppm by volume on a dry 1 hr minimum sampling
liquid fuel. basis corrected to 3 time.
percent oxygen, 3-run
average
b. Filterable PM (or 1.3E-02 lb per MMBtu of Collect a minimum of 2
TSM). heat input; or (7.5E-05 dscm per run.
lb per MMBtu of heat
input)
16. Units designed to burn light a. CO................ 130 ppm by volume on a dry 1 hr minimum sampling
liquid fuel. basis corrected to 3 time.
percent oxygen
b. Filterable PM (or 1.3E-03 \a\ lb per MMBtu Collect a minimum of 3
TSM). of heat input; or (2.9E- dscm per run.
05 lb per MMBtu of heat
input)
17. Units designed to burn liquid a. CO................ 130 ppm by volume on a dry 1 hr minimum sampling
fuel that are non-continental basis corrected to 3 time.
units percent oxygen, 3-run
average based on stack
test
b. Filterable PM (or 2.3E-02 lb per MMBtu of Collect a minimum of 4
TSM). heat input; or (8.6E-04 dscm per run.
lb per MMBtu of heat
input)
18. Units designed to burn gas 2 a. CO................ 130 ppm by volume on a dry 1 hr minimum sampling
(other) gases. basis corrected to 3 time.
percent oxygen
b. HCl............... 1.7E-03 lb per MMBtu of For M26A, Collect a
heat input. minimum of 2 dscm per
run; for M26, collect a
minimum of 240 liters
per run.
c. Mercury........... 7.9E-06 lb per MMBtu of For M29, collect a
heat input. minimum of 3 dscm per
run; for M30A or M30B,
collect a minimum sample
as specified in the
method; for ASTM D6784
\b\ collect a minimum of
3 dscm.
d. Filterable PM (or 6.7E-03 lb per MMBtu of Collect a minimum of 3
TSM). heat input; or (2.1E-04 dscm per run.
lb per MMBtu of heat
input)
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provision of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
\c\ An owner or operator may request that compliance with the carbon monoxide emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen
and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
[FR Doc. 2014-29569 Filed 1-20-15; 8:45 am]
BILLING CODE 6560-50-P