[Federal Register Volume 80, Number 224 (Friday, November 20, 2015)]
[Rules and Regulations]
[Pages 72789-72837]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-29186]



[[Page 72789]]

Vol. 80

Friday,

No. 224

November 20, 2015

Part II





 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; Final Rule

Federal Register / Vol. 80 , No. 224 / Friday, November 20, 2015 / 
Rules and Regulations

[[Page 72790]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2002-0058; FRL-9936-20-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 (EPA).

ACTION: Final rule; notice of final action on reconsideration.

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SUMMARY: This action sets forth the Environmental Protection Agency's 
(EPA's) final decision on the issues for which it granted 
reconsideration on January 21, 2015, that pertain to certain aspects of 
the January 31, 2013, final amendments to the ``National Emission 
Standards for Hazardous Air Pollutants for Major Sources: Industrial, 
Commercial, and Institutional Boilers and Process Heaters'' (Boiler 
MACT). The EPA is retaining a minimum carbon monoxide (CO) limit of 130 
parts per million (ppm) and the particulate matter (PM) continuous 
parameter monitoring system (CPMS) requirements, consistent with the 
January 2013 final rule. The EPA is making minor changes to the 
proposed definitions of startup and shutdown and work practices during 
these periods, based on public comments received. Among other things, 
this final action addresses a number of technical corrections and 
clarifications of the rule. These corrections will clarify and improve 
the implementation of the January 2013 final Boiler MACT, but do not 
have any effect on the environmental, energy, or economic impacts 
associated with the proposed action. This action also includes our 
final decision to deny the requests for reconsideration with respect to 
all issues raised in the petitions for reconsideration of the final 
Boiler MACT for which we did not grant reconsideration.

DATES: This rule is effective November 20, 2015.

ADDRESSES: Docket ID No. EPA-HQ-OAR-2002-0058 contains supporting 
information for this action on the Boiler MACT. All documents in the 
docket are listed in the http://www.regulations.gov index. Although 
listed in the index, some information is not publicly available, e.g., 
confidential business information or other information whose disclosure 
is restricted by statute. Certain other material, such as copyrighted 
material, will be publicly available only in hard copy. Publicly 
available docket materials are available either electronically in 
http://www.regulations.gov or in hard copy at the EPA Docket Center, 
EPA/DC, EPA WJC West Building, Room 3334, 1301 Constitution Ave. NW., 
Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 
p.m., Monday through Friday, excluding legal holidays. The telephone 
number for the Public Reading Room is (202) 566-1744 and the telephone 
number for the Docket Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: 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; fax 
number: (919) 541-5450; email address: [email protected].

SUPPLEMENTARY INFORMATION:
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

ACC American Chemistry Council
AF&PA American Forest and Paper Association
API American Petroleum Institute
CAA Clean Air Act
CEMS Continuous emissions monitoring systems
CFR Code of Federal Regulations
CIBO/ACC Council of Industrial Boiler Owners
CISWI Commercial and Industrial Solid Waste Incineration
CO Carbon monoxide
CO2 Carbon dioxide
CPMS Continuous parameter monitoring systems
CRA Congressional Review Act
EGU Electric Utility Steam Generating Unit
EPA U.S. Environmental Protection Agency
ESP Electrostatic precipitator
FSI Florida Sugar Industry
HCl Hydrogen chloride
Hg Mercury
HSG Hybrid suspension/grate
ICI Industrial, Commercial, Institutional
ICR Information collection request
MACT Maximum achievable control technology
MATS Mercury Air Toxics Standards
mmBtu/hr Million British thermal units per hour
NAICS North American Industrial Classification System
NEDACAP Natural Environmental Development Association's Clean Air 
Project
NESHAP National emission standards for hazardous air pollutants
NHPC New Hope Power Company
NOX Nitrogen oxides
NSPS New source performance standards
NTTAA National Technology Transfer and Advancement Act
O2 Oxygen
OMB Office of Management and Budget
ORD EPA Office of Research and Development
PAH Polycyclic aromatic hydrocarbons
PCB Polychlorinated biphenyls
PM Particulate matter
POM Polycyclic organic matter
ppm Parts per million
SO2 Sulfur dioxide
SSM Startup, shutdown, and malfunction
SSP Startup and shutdown plan
the Court United States Court of Appeals for the District of 
Columbia Circuit
TSM Total selected metals
TTN Technology Transfer Network
UARG Utility Air Regulatory Group
UMRA Unfunded Mandates Reform Act
U.S.C. United States Code
WWW World Wide Web

    Organization of this Document. The following outline is provided to 
aid in locating information in this preamble.

I. General Information
    A. Does this action apply to me?
    B. How do I obtain a copy of this document and other related 
information?
    C. Judicial Review
II. Background Information
III. Summary of Final Action and Significant Changes Since Proposal
    A. Definition of Startup and Shutdown Periods and the Work 
Practices That Apply During Such Periods
    B. Revised CO Limits Based on a Minimum CO Level of 130 ppm
    C. PM CPMS
IV. Technical Corrections and Clarifications
    A. Opacity Is an Operating Parameter
    B. CO Monitoring and Moisture Corrections
    C. Affirmative Defense for Violation of Emission Standards 
During Malfunction
    D. Definition of Coal
    E. Other Corrections and Clarifications
V. Other Actions We Are Taking
    A. Petitioners' Comments Impacted by Technical Corrections
    B. Petitions Related to Ongoing Litigation
    C. Other Petitions
VI. Impacts of This Final Rule
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 (NTTAA)

[[Page 72791]]

    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act (CRA)

I. General Information

A. Does this action apply to me?

    Categories and entities potentially affected by this 
reconsideration action include those listed in Table 1 of this 
preamble:

                       Table 1--Regulated Entities
------------------------------------------------------------------------
                                 North American
                                   Industrial           Examples of
           Category              Classification    potentially regulated
                                 System (NAICS)           entities
                                    code \a\
------------------------------------------------------------------------
Any industry using a boiler                   211  Extractors of crude
 or process heater as defined                       petroleum and
 in the final rule.                                 natural gas.
                                              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.
------------------------------------------------------------------------
\a\ North American Industrial 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 
final action. To determine whether your facility would be affected by 
this final action, you should examine the applicability criteria in 40 
CFR 63.7490 of subpart DDDDD. If you have any questions regarding the 
applicability of this final action to a particular entity, contact the 
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.

B. How do I obtain a copy of this document and other related 
information?

    The docket number for this final action regarding the Major Source 
Boiler MACT (40 CFR part 63, subpart DDDDD) is Docket ID No. EPA-HQ-
OAR-2002-0058.
    World Wide Web. In addition to being available in the docket, an 
electronic copy of this final action is available on the Technology 
Transfer Network (TTN) Web site. Following signature, the EPA posted a 
copy of the final action at http://www.epa.gov/ttn/atw/boiler/boilerpg.html. The TTN provides information and technology exchange in 
various areas of air pollution control.

C. Judicial Review

    Under Clean Air Act (CAA) section 307(b)(1), judicial review of 
this final rule is available only by filing a petition for review in 
United States Court of Appeals for the District of Columbia Circuit 
(the Court) by January 19, 2016. Under CAA section 307(d)(7)(B), only 
an objection to this final rule that was raised with reasonable 
specificity during the period for public comment can be raised during 
judicial review. Note, under CAA section 307(b)(2), the requirements 
established by this final rule may not be challenged separately in any 
civil or criminal proceedings brought by the EPA to enforce these 
requirements.

II. Background Information

    On March 21, 2011, the EPA established final emission standards for 
industrial, commercial, and institutional (ICI) boilers and process 
heaters at major sources to meet hazardous air pollutant (HAP) 
standards reflecting the application of maximum achievable control 
technology (MACT)--the Boiler MACT (76 FR 15608). On January 31, 2013, 
the EPA promulgated final amendments to the Boiler MACT (78 FR 7138). 
Following that action, the Administrator received 13 petitions for 
reconsideration that identified certain issues that petitioners claimed 
warranted further opportunity for public comment.
    The EPA received petitions dated March 28, 2013, from New Hope 
Power Company (NHPC) and the Sugar Cane Growers Cooperative of Florida. 
The EPA received a petition dated March 29, 2013, from the Eastman 
Chemical Company (Eastman). 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 (hereinafter referred to 
as Sierra Club); 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 
(hereinafter referred to as AF&PA); the Florida Sugar Industry (FSI); 
Council of Industrial Boiler Owners, American Municipal Power, Inc., 
and American Chemistry Council (hereinafter referred to as CIBO/ACC); 
American Petroleum Institute (API); and the Utility Air Regulatory 
Group (UARG) 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 
(NEDACAP) and CIBO. The EPA received revised petitions from CIBO/ACC on 
July 1, 2014, and on July 11, 2014, from Eastman. Both of these were 
revised to withdraw one of the issues raised in their initial 
submittal.
    In response to the petitions, the EPA reconsidered and requested 
comment on several provisions of the January 31, 2013, final amendments 
to the Boiler MACT. The EPA published the proposed notice of 
reconsideration in the Federal Register on January 21, 2015 (80 FR 
3090).

III. Summary of Final Action and Significant Changes Since Proposal

    In this notice, we are finalizing amendments associated with 
certain

[[Page 72792]]

issues raised by petitioners in their petitions for reconsideration on 
the 2013 final amendments to the Boiler MACT. These provisions are: (1) 
Definitions of startup and shutdown periods and the work practices that 
apply during such periods; (2) CO limits based on a minimum CO level of 
130 ppm; and (3) the use of PM CPMS, including the consequences of 
exceeding the operating parameter. Additionally, the EPA is finalizing 
the technical corrections and clarifications that were proposed to 
correct inadvertent errors in the final rule and to provide the 
intended accuracy, clarity, and consistency, as well as correcting 
various typographical errors identified in the rule as published in the 
Code of Federal Regulations (CFR).
    Most of these changes are very similar to those described in the 
proposed notice of reconsideration on January 21, 2015 (80 FR 3090). 
However, the EPA has made some changes in this final rule after 
consideration of the public comments received on the proposed notice of 
reconsideration. The changes are to clarify applicability and 
implementation issues raised by the commenters. We address several 
significant comments in this preamble. For a complete summary of the 
comments received and our responses thereto, please refer to the 
memorandum ``Response to 2015 Reconsideration Comments for Industrial, 
Commercial, and Institutional Boilers and Process Heaters National 
Emission Standards for Hazardous Air Pollutants'' located in the docket 
for this rulemaking.

A. Definition of Startup and Shutdown Periods and the Work Practices 
That Apply During Such Periods

1. Definitions
    In the January 31, 2013, final amendments to the Boiler MACT, the 
EPA finalized revisions to the definition of startup and shutdown 
periods, which were based on the time during which fuel is fired in the 
affected unit for the purpose of supplying steam or heat for heating 
and/or producing electricity or for any other purpose. Petitioners 
asserted that the definitions were not sufficiently clear. In response 
to these petitions, we proposed an alternative definition of startup in 
the January 21, 2015, proposed notice of reconsideration (80 FR 3093). 
This alternative definition clarified pre-startup testing activities 
and also expanded to allow for startup after a shutdown event instead 
of solely the initial startup of the affected unit. The alternative 
definition of startup as well as the definition of shutdown also 
incorporated a new term ``useful thermal energy'' to replace the term 
``steam and heat'' to address petitioners' concerns of an ambiguous end 
of the startup period.
    In today's action, the EPA is adopting two alternative definitions 
of ``startup,'' consistent with the proposed rule. The first definition 
defines ``startup'' to mean the first-ever firing of fuel, or the 
firing of fuel after a shutdown event, in a boiler or process heater 
for the purpose of supplying useful thermal energy for heating and/or 
producing electricity or for any other purpose. Under this definition, 
startup ends when any of the useful thermal energy from the boiler or 
process heater is supplied for heating, producing electricity, or any 
other purpose. The EPA is also adopting an alternative definition of 
``startup'' which defines the period as beginning with the first-ever 
firing of fuel, or the firing of fuel after a shutdown event, in a 
boiler or process heater for the purpose of supplying useful thermal 
energy for heating, cooling, or process purposes or for producing 
electricity, and ending four hours after the boiler or process heater 
supplies useful thermal energy for those purposes. Sources 
demonstrating compliance using the alternative definition will be 
required to meet enhanced recordkeeping provisions. These enhancements 
will document when useful thermal energy is provided, what fuels are 
used during startup, parametric monitoring data to verify relevant 
controls are engaged, and the time when PM controls are engaged.
    In the January 31, 2013 final rule, the EPA defined ``shutdown'' to 
mean the cessation of operation of a boiler or process heater for any 
purpose, and said this period begins either when none of the steam from 
the boiler is supplied for heating and/or producing electricity or for 
any other purpose, or when no fuel is being fired in the boiler or 
process heater, whichever is earlier. The EPA received petitions for 
reconsideration of this definition, asking that the agency clarify the 
term. The EPA proposed a definition of ``shutdown'' in January 2015 
which clarified that shutdown begins when the boiler or process heater 
no longer makes useful thermal energy (rather than referring to steam 
supplied by the boiler) 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. In today's action, the EPA is 
adopting a definition of ``shutdown'' that is consistent with the 
proposal, with some minor clarifying revisions. ``Shutdown'' is defined 
to begin when the boiler or process heater no longer supplies useful 
thermal energy (such as heat or steam) for heating, cooling, or process 
purposes and/or generation of electricity, or when no fuel is being fed 
to the boiler or process heater, whichever is earlier.
    The EPA received several comments on the proposed edits to the 
definitions of ``useful thermal energy,'' ``startup,'' and 
``shutdown.''
a. Useful Thermal Energy
    Several comments supported the alternative definitions of startup 
and shutdown to include the concept of useful thermal energy, which 
recognizes that small amounts of steam or heat may be produced when 
starting up a unit, but the amounts would be insufficient to operate 
processing equipment and insufficient to safely initiate pollution 
controls.
    One comment stated that an alternative work practice period between 
the start of fuel combustion until 4 hours after useful thermal energy 
is supplied is unlawful because the EPA may set work practice standards 
only for categories or subcategories of sources, not for periods of 
operation. The comment further noted that work practice standards are 
allowed only if pollution is not emitted through a conveyance or the 
application of measurement methodology to a particular class of sources 
is not practicable, and the EPA has not stated either of these to be 
the case. The comment also claimed that, because the EPA has changed 
and extended startup and shutdown periods, the EPA must determine that 
emissions measurement is impracticable during startup and shutdown as 
they are now defined, which the EPA has not done.
    The EPA recognizes the unique characteristics of ICI boilers and 
has retained the alternative definition, which incorporates the term 
``useful thermal energy'' in the final rule, with some slight 
adjustments, as discussed below. The EPA disagrees with the commenter 
that the reference to ``a particular class of sources'' in CAA section 
112(h)(2) limits the EPA's authority to determine, for a category or 
subcategory of sources, that it is infeasible to prescribe or enforce 
an emission standard for those sources during certain identifiable time 
periods, such as startup and shutdown. Contrary to the commenter's 
assertion, the EPA did make a determination under CAA section 112(h) 
that it is not feasible to prescribe or enforce a numeric standard 
during periods of startup and shutdown, because the application of 
measurement methodology is impracticable due to technological and 
economic limitations.

[[Page 72793]]

Information provided on the amount of time required for startup and 
shutdown of boilers and process heaters indicates that the application 
of measurement methodology for these sources using the required 
procedures, which would require more than 12 continuous hours in 
startup or shutdown mode to satisfy all of the sample volume 
requirements in the rule, is impracticable. In addition, the test 
methods are required to be conducted under isokinetic conditions (i.e., 
steady-state conditions in terms of exhaust gas temperature, moisture, 
flow rate), which is difficult to achieve during these periods where 
conditions are constantly changing. Moreover, accurate HAP data from 
those periods is unlikely to be available from either emissions testing 
(which is designed for periods of steady state operation) or monitoring 
instrumentation such as continuous emissions monitoring systems (CEMS) 
(which are designed for measurements occurring during periods other 
than during startup or shutdown when emissions flow are stable and 
consistent). Upon review of this information, the EPA determined that 
it is not 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. Based on these specific facts for the Boilers and 
Process Heater source category, the EPA developed a separate standard 
for these periods, and we are finalizing amendments to the work 
practice standards to meet this requirement. As detailed in the 
response to this commenter in the 2013 final amendments to the Boiler 
MACT (EPA-HQ-OAR-2002-0058-3511-A1), the EPA continues to maintain that 
testing is impracticable during periods of startup and shutdown, 
despite the revisions to the definitions for the two terms as finalized 
in this action. We set standards based on available information as 
contemplated by CAA section 112. Compliance with the numeric emission 
limits (i.e., PM or total selected metals (TSM), hydrogen chloride 
(HCl), mercury (Hg), and CO) are demonstrated by conducting performance 
stack tests. The revised definitions of startup and shutdown better 
reflect when steady-state conditions are achieved, which are required 
to yield meaningful results from current testing protocols.
    Several comments requested that the EPA add the term ``flow rate'' 
to the definition of useful thermal energy, consistent with the 
preamble to the proposed notice of reconsideration (80 FR 3093). The 
EPA recognizes the importance of flow rate as a parameter for 
determining when useful thermal energy is being supplied by a boiler or 
process heater and has added this term to the definition in the final 
rule.
    Two comments argued that for the alternative definitions of startup 
and shutdown to be useful, the term ``useful thermal energy'' must 
incorporate a primary purpose component that assures that the 4-hour 
startup period is not triggered until useful energy is supplied to the 
most demanding end use of the boiler. Several comments agreed with the 
EPA that startup ``should not end until such time that all control 
devices have reached stable conditions'' (see 80 FR 3094, column 1), 
but noted that the time frame of 4 hours after a unit supplies useful 
thermal energy is not workable for some boilers due to site-specific 
factors and technology differences. One commenter agreed with the EPA 
that the variation of practices and capabilities among fossil-fuel 
fired boilers warrants longer periods when work practices apply in lieu 
of ICI MACT emission limits.
    The EPA agrees that the definition of ``useful thermal energy'' 
could be further clarified; however, we disagree that basing the end of 
startup on a primary purpose approach which considers the most 
demanding end use is an appropriate approach. Often times, ICI boilers 
can serve more than one purpose. As long as the boiler is providing 
useful thermal energy to one of its intended purposes, the unit is 
supplying ``useful thermal energy.'' The final definition of ``useful 
thermal energy'' incorporates the term ``flow'' to more appropriately 
reflect when the energy is provided for any primary purpose of the 
unit. We believe that supplying energy at the minimum temperature, 
pressure, and flow to any energy use system is the primary purpose of 
any unit.
b. Startup
    Several comments claimed that even with an alternative definition 
of startup to incorporate the term ``useful thermal energy,'' the first 
definition remains unworkable. The act of supplying heat, steam, or 
electricity does not represent the functional end of the startup 
period, and some processes are designed such that downstream equipment 
receives heat and/or steam when fuel is being burned during startup of 
the boilers and/or process heaters.
    The EPA has adjusted the first definition of startup to replace 
``steam'' with ``useful thermal energy''. Additionally, the term 
``useful thermal energy'' was revised to incorporate a minimum flowrate 
to more appropriately reflect when the energy is provided for any 
primary purpose of the unit. Together, these changes alleviate the 
concerns of when the startup period functionally ends. 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.
c. Shutdown
    Several comments supported the EPA's proposed definition of 
shutdown, because the proposed revisions now adequately address the 
circumstances for some affected units where fuel remaining in the unit 
on a grate or elsewhere continues to combust although fuel has been cut 
off and useful thermal energy is no longer generated. Two comments 
suggested that the definition could be clarified to recognize that the 
shutdown period begins when no useful steam or electricity is 
generated, or when fuel is no longer being combusted in the boiler. 
After the shutdown period ends, some steam may still be generated 
temporarily, even though the steam is not useful thermal energy (i.e., 
the steam does not meet the minimum operating temperature, pressure, 
and flow rate).
    The EPA has adjusted the definition of shutdown to replace the 
phrase ``makes useful thermal energy'' to ``supplies useful thermal 
energy.'' The shutdown period begins when no useful steam or 
electricity is generated, or when fuel is no longer being combusted in 
the boiler. The term ``supplies'' is the preferred phrase in the 
definition of shutdown instead of ``makes'' to be consistent with the 
definition of startup, and is a more accurate term to use to describe 
the function of the boiler or process heater.
2. Work Practices
    The EPA is adopting work practices that apply during the periods of 
startup and shutdown which reflect the emissions performance achieved 
by the best performing units. These work practices include use of clean 
fuels during startup and shutdown. In addition, under the alternate 
work practice, sources must engage all applicable control devices so 
that the emissions standards are met no later than four hours after the 
start of supplying useful thermal energy and must engage PM controls 
within one hour of first feeding non-clean fuels.

[[Page 72794]]

a. Clean Fuels
    In the January 31, 2013, final amendments to the Boiler MACT, the 
EPA finalized a definition of ``clean fuels'' that could be used during 
periods of startup and shutdown to satisfy the clean fuels requirement. 
Petitioners claimed that the list of ``clean fuels'' was too narrow. In 
response to these petitions, the EPA proposed revisions to this term in 
the January 21, 2015, notice of reconsideration to include ``other gas 
1'' fuels, as well as any fuels that meet the applicable TSM, HCl, and 
Hg emission limits based on fuel analysis. In today's action, the EPA 
is finalizing these proposed revisions to the definition of ``clean 
fuels'' and also adding ``clean dry biomass'' to the definition of 
``clean fuels.''
    The EPA received several comments on the proposed changes to the 
definition of clean fuels. Several comments supported the EPA's 
proposal to expand the list of eligible clean fuels for starting up a 
boiler or process heater to include all gaseous fuels meeting the 
``other gas 1'' classification and any fuel that meets the applicable 
TSM, HCl, and Hg emission limits using fuel analysis. Another comment 
claimed that the EPA had not shown that boilers burning ``clean fuels'' 
or those fuels newly added to the ``clean fuels'' list (i.e., other gas 
1) can meet CO standards or that emissions of organic HAP will not 
increase. This comment suggested that allowing sources to emit more CO 
or organic HAP than is permitted by the standards, is not ``consistent 
with'' CAA section 112(d), and is, therefore, unlawful. This comment 
also expressed concerns that broadening the ``clean fuel'' definition 
would allow sources to burn tires as ``clean fuel,'' provided that they 
meet fuel analysis requirements for Hg, TSM, and HCl despite the fact 
that burning tires plainly increases polycyclic aromatic hydrocarbons 
(PAH).
    Based on the comments received, the EPA is finalizing an expanded 
list of clean fuels to add any fuels that meet the applicable TSM, HCl 
and Hg emission limits based on fuel analysis. The EPA disagrees with 
the comment that the clean fuels requirement is inconsistent with CAA 
section 112(d) because it fails to address emissions of CO or organic 
HAP. These pollutants are byproducts of the combustion process, and, 
therefore, emissions are not fuel-dependent and cannot be measured 
through fuel analysis. For instance, the formation of POM is 
effectively reduced by good combustion practices (i.e., proper air to 
fuel ratios). In addition, because these pollutants are byproducts of 
the combustion process, the EPA does not expect most units to require 
post-combustion controls to meet the CO limits once the startup period 
has ended, but instead will comply by conducting the required tune-up 
(which serves to reduce HAP emissions at all times, including during 
startup and shutdown), and adopting other combustion best practices. In 
contrast, the EPA expects many units to install one or more post-
combustion controls to reduce emissions of HCl, Hg, or non-Hg metallic 
HAP. Because CO and organic HAP are combustion byproducts, emissions of 
CO and organic HAP are likely to vary little among boilers during 
startup since combustion practices during that period tend to be 
similar and well-controlled in order to prevent thermal stresses, and 
are not dependent on the fuel being combusted, unlike Hg, HCl, and 
other hazardous metals. Therefore, it is reasonable for EPA to conclude 
that emissions during startup will reflect the maximum degree of 
reduction of CO and organic HAP, as well as other HAP, achieved during 
startup. For these reasons, today's action retains the proposed 
requirements to qualify as a clean fuel through fuel analysis data.
    Regarding the commenter's concerns with tires, specifically, the 
EPA has reviewed the fuel analysis data for tire derived fuel for HCl, 
Hg, and TSM emissions submitted in the databases used in the final 
rule. None of the samples indicate that tires could demonstrate 
compliance with the TSM limit for solid fossil fuels. Thus, the EPA 
believes that tires would not qualify as a ``clean fuel.''
    Two commenters asked the EPA to include dry biomass (i.e., moisture 
content less than 20 percent) in the list of clean fuels allowed during 
startup and shutdown. The commenters noted that the chemical makeup and 
combustion characteristics are similar to paper and cardboard which are 
currently included. Further, dry biomass has low chloride, Hg, and 
moisture content, burns cleaner than other solid fuels, and produces 
low HCl, Hg, and CO. The list of clean fuels was expanded to include 
``clean dry biomass.'' The EPA has reviewed boiler information 
collection request (ICR) fuel analysis data and AP-42 emission factor 
data for wood combustion. The ICR fuel analysis data for solid fuels 
often exclude numeric values for certain metallic HAP that were 
reported as below detection levels. These data show that clean dry 
biomass can meet the Hg and HCl limits for solid fuels and the TSM 
levels in dry biomass are 6 times lower than in solid fossil fuels. 
Therefore, the EPA has finalized the list of clean fuels to include 
clean dry biomass. The EPA added the phrase ``clean dry biomass'' to 
Table 3 to subpart DDDDD of part 63, item 5.b. The EPA also defined 
this new term for this subpart drawing on similarly defined term in the 
``Identification of Non-Hazardous Secondary Materials That Are Solid 
Waste'' rulemaking. Under the final rule, clean dry biomass fuels are 
now categorically accepted as clean fuels and do not need to 
demonstrate that the fuel meets the TSM, Hg, and HCl emission limits 
with each new fuel shipment.
    Based on comments received to clarify how the ``clean fuel'' 
provision works, the EPA also made several corrections in the final 
rule. Text in 40 CFR 63.7555(d)(11) is added to acknowledge the 
possibility for additional clean fuels. Language in 40 CFR 
63.7555(d)(11) was revised to replace the phrase ``coal/solid fossil 
fuel, biomass/bio-based solids, heavy liquid fuel, or gas 2 (other) 
gases'' with ``fuels that are not clean fuel.''
    For consistency, the phrase ``coal/solid fossil fuel, biomass/bio-
based solids, heavy liquid fuel, or gas 2 (other) gases'' was replaced 
with ``fuels that are not clean fuel'' in Table 3 to subpart DDDDD of 
part 63, items 5.c and 6.
b. Engaging Pollution Controls
    The January 2013 final amendments to the Boiler MACT included a 
provision for 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, and 
selective catalytic reduction, which must start as expeditiously as 
possible. The EPA received several petitions for reconsideration of 
this aspect of the work practice standard expressing safety concerns 
with engaging electrostatic precipitator (ESP) control devices. These 
petitions urged the EPA to revise 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 response to these petitions, the January 2015 proposal included 
an alternate requirement to engage all control devices so as to comply 
with the emission limits within 4 hours of start of supplying useful 
thermal energy. Under the proposal, owners or operators would be 
required to engage PM control within 1 hour of first firing coal/solid

[[Page 72795]]

fossil fuel, biomass/bio-based solids, heavy liquid fuel, or gas 2 
(other) gases. Owners or operators using this alternative would have to 
develop and implement a written startup and shutdown plan (SSP) and the 
SSP must be maintained on site and available upon request for public 
inspection. The EPA also proposed to allow a source to request a case-
by-case extension to the 1-hour period for engaging the PM controls 
based on evidence of a documented manufacturer-identified safety issue 
and proof that the PM control device is adequately designed and sized 
to meet the filterable PM emission limit. The EPA is adopting the 
proposed requirements with minor revisions.
    The EPA received several comments on the proposed revisions for 
engaging pollution controls. One comment supported the EPA's 
recognition that some HAP emission control technologies require 
specific operating conditions before being engaged and should be 
excluded from operation as soon as primary fuel firing begins. Several 
comments requested that the EPA add ESPs to the list of controls that 
must be started as expeditiously as possible, noting that the 1-hour 
requirement for engaging ESPs is unreasonable. Another comment 
considered the EPA's decision to set a less stringent work practice 
standard that allows boilers to operate without pollution controls to 
be inconsistent with CAA section 112(d)(2) and arbitrary. This 
commenter also considered the requirement to engage applicable 
pollution controls ``as expeditiously as possible'' within the startup 
period to be inconsistent with CAA section 112(d) and unlawful, as well 
as arbitrary and capricious. The commenter states that it is not 
acceptable for a standard to allow sources to do whatever is 
``possible'' for them. The commenter stated that the point of a 
national standard is to set one limit that governs all the sources to 
which it applies.
    The EPA has established a work practice for periods of startup and 
shutdown because it is infeasible to measure emissions during these 
periods. Moreover, accurate HAP data from those periods are unlikely to 
be available from either emissions testing (which is designed for 
periods of steady state operation) or monitoring instrumentation such 
as CEMS (which are designed for measurements occurring during periods 
other than during startup or shutdown when emissions flow is stable and 
consistent). The work practice for PM controls was established by 
evaluating the performance of the best performing sources as determined 
by the EPA. For the Mercury and Air Toxics Standards (MATS), the EPA 
conducted an analysis of nitrogen oxide (NOX) and sulfur 
dioxide (SO2) CEMS data from electric utility steam 
generating units (EGUs) to determine the best performing sources with 
respect to NOX and SO2 emissions (79 FR 68779 
November 19, 2014). The best performing sources are those whose control 
devices are operational within 4 hours of starting electrical 
generation. 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 four hours after the start of 
supplying useful thermal energy and have included this timeframe in the 
proposed alternate definition. This conclusion was supported by the 
limited information (13 units) the EPA did have on industrial boilers 
and by information (76 units) submitted by CIBO obtained from an 
informal survey of its members on the time needed to reach stable 
conditions during startup. The time reported, in the CIBO survey 
summary, to reach stable operation after coming online (supplying 
useful thermal energy) of the best performing units ranged from 1 to 4 
hours. See the docketed memorandum ``2015 Assessment of Startup Period 
for Industrial Boilers.''
    The EPA also maintains that the best performers are able to engage 
their PM control devices within 1 hour of coal, biomass, or residual 
oil combustion. In the January 2013 final Boiler MACT rule and in the 
January 2015 reconsideration proposal, the EPA stated that once an 
affected unit starts firing coal, biomass, or heavy liquid fuel, all of 
the applicable control devices had to be engaged (with certain listed 
exceptions). The listed exceptions did not include ESP for controls of 
PM emissions and, thus, the EPA's intent was that ESP controls would be 
engaged (i.e., operational) at the moment non-clean fuel are fired. We 
did receive comments making us question the ability of most affected 
units to engage their ESP controls so quickly after first firing non-
clean fuel. These comments suggested that there may need to be some 
flexibility. For this reason, we are providing a 1-hour period of time 
following the initiation of firing of non-clean fuels before PM 
controls must be engaged. Therefore, we are finalizing as part of the 
alternative work practice that PM control must be engaged within 1 hour 
of the time non-clean fuels are introduced into the affected unit. We 
have also added requirements to document that PM control is being 
achieved through the operation of the PM controls. The requirement to 
engage and operate the PM controls within 1 hour of non-clean fuels 
being charged to the units is intended to ensure that PM and HAP 
reductions will occur as quickly as possible after primary fuel 
combustion begins. We continue to believe that sources will be able to 
engage and operate their controls to comply with the standards at the 
end of startup, and that sources can make physical and/or operational 
changes at the facility to ensure compliance at the end of startup. As 
noted before, the EPA believes it appropriate to base its startup and 
shutdown work practices on those practices employed by the best 
performers. Because the above information indicates that ESPs can be 
energized within 1 hour of coal firing being started, we are finalizing 
that PM controls must be engaged within 1 hour of starting to fire non-
clean fuels.
    Several commenters were also concerned with compliance deadlines 
and asked the EPA to provide and finalize a more streamlined procedure 
for units needing more than 1 hour to safely initiate PM control during 
startup. They were concerned that their case-by-case extensions would 
not be approved by the local authority by the compliance deadlines, 
considering that the EPA must finalize this rule before it is adopted 
by the state.
    The EPA is finalizing the provision allowing an owner or operator 
to apply for a boiler-specific case-by-case alternative timeframe with 
the requirement to engage PM control devices within 1 hour of firing 
non-clean fuels. However, the delegated authority will only consider 
such requests for boilers that can provide evidence of a documented 
manufacturer-identified safety issue, proof that the PM control device 
is adequately designed and sized to meet the final PM emission limit, 
and that it can demonstrate it is unable to safely engage and operate 
the PM controls. In its request for the case-by-case determination, the 
owner or operator must provide, among other materials, documentation 
that: (1) The boiler is using clean fuels to the maximum extent 
possible to bring the boiler and PM control device up to the 
temperature necessary to alleviate or prevent the safety issues prior 
to the combustion of non-clean fuels in the boiler, (2) the boiler has 
explicitly followed the manufacturer's procedures to alleviate

[[Page 72796]]

or prevent the safety issue, (3) the source provides details of the 
manufacturer's statement of concern, and (4) the source provides 
evidence that the PM control device is adequately designed and sized to 
meet the final PM emission limit. In addition, the source will have to 
indicate the other measures it will implement to limit HAP emissions 
during periods of startup and shutdown to ensure a control level 
consistent with the final work practice requirements.
    The EPA is finalizing a provision, 40 CFR 63.7555(d)(13), that 
provides that an owner or operator may apply for an alternative 
timeframe with the PM controls requirement to the permitting authority. 
We recognize that there may be very limited circumstances that compel 
an alternative approach for a specific unit. The EPA has added language 
to Table 3 to subpart DDDDD of part 63, item 5.c to clarify that a 
written SSP must be developed. Text was added to Table 3 to subpart 
DDDDD of part 63--footnote ``a'' to acknowledge that an alternative 
timeframe to the PM controls requirement can be granted by the EPA or 
the appropriate state, local, or tribal permitting authority that has 
been delegated authority.

B. Revised CO Limits Based on a Minimum CO Level of 130 ppm

    In the January 2013 final amendments to the Boiler MACT, the 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 
emission reductions. The January 2015 proposal retained these emission 
limits, but requested additional data to support whether or not these 
limits were appropriate or should be modified. The EPA is retaining 
these limits, as discussed below.
    The EPA received numerous comments supporting the minimum CO level 
of 130 ppm, adjusted to 3-percent oxygen (O2). These 
comments agreed that the level selected was within the range of where 
the relationship between CO and organic HAP breaks down. Many of these 
comments also noted that the level was consistent with other EPA 
regulations for hazardous waste combustors and industrial furnace 
rules.
    One comment disagreed that the minimum CO level of 130 ppm reflects 
the CO emissions achieved by the best performers in this subcategory, 
and contended that this level does not satisfy the requirements of CAA 
section 112(d)(3). This comment also disagreed with the use of 
formaldehyde as a surrogate for other organic HAPs and provided 
supporting evidence.\1\ The commenter concluded that formaldehyde 
emissions are formed differently than polychlorinated biphenyls (PCBs) 
and PAHs, and they noted that combustion practices that reduce 
emissions of PCBs and PAHs (i.e. extremely high temperatures) can 
increase emissions of CO. The comments also noted that the gaseous 
properties of formaldehyde emissions differ from PCBs and PAH 
emissions, which are particles.
---------------------------------------------------------------------------

    \1\ See Exhibit A from commenter, EPA-HQ-OAR-2002-0058-3919-A1.
---------------------------------------------------------------------------

    After consideration of the comments received, the EPA is 
maintaining a minimum level of 130 ppm CO at 3-percent O2. 
The issue of whether or not CO is an appropriate surrogate for 
formaldehyde (a representative organic HAP in boiler emissions), or 
non-dioxin organic HAP in general, is outside the scope of this 
reconsideration, since the reconsideration solicited comment only on 
the CO limits established at 130 ppm, not on the broader issue of using 
CO as a surrogate for organic HAP. Moreover, the appropriateness of CO 
as a surrogate is currently part of ongoing litigation before the Court 
(United States Sugar Corporation v. EPA, pending case No. 11-1108). As 
noted in the final amendments to the Boiler MACT (78 FR 7145 January 
31, 2013), the EPA selected formaldehyde ``. . . as the basis of the 
organic HAP comparison because it is the most prevalent organic HAP in 
the emission database and a large number of paired tests existed for 
boilers and process heaters for CO and formaldehyde.'' As for the 
additional evidence submitted with the comments, we do not disagree 
that the gaseous properties of formaldehyde emissions differ from PCBs 
and PAH emissions. However, the surrogacy testing conducted by the 
EPA's Office of Research and Development (ORD) clearly show a high 
correlation between CO and PAH, similar to the correlation between 
formaldehyde and CO. Furthermore, as shown in figure 2 of the technical 
report provided in Attachment A to the commenter letter, PAH emissions 
decrease with increasing O2 levels, but then increase with 
higher levels of excess O2, similar to the trend we saw in 
our assessment of the correlation between CO and formaldehyde.

C. PM CPMS

    The March 2011 Boiler MACT final rule required units greater than 
250 million British thermal units per hour (MMBtu/hr) combusting solid 
fossil fuel or heavy liquid to install, maintain, and operate PM CEMS 
to demonstrate compliance with the applicable PM emission limit (see 76 
FR 15615, March 21, 2011). In response to petitions for reconsideration 
challenging PM CEMS, the EPA finalized a CPMS for demonstrating 
continuous compliance with the PM standards in the January 2013 final 
amendments to the Boiler MACT. The CPMS requirement allowed sources a 
number of exceedances of the operating limit before the exceedance 
would be presumed to be a violation, and also allowed certain low 
emitting sources to ``scale'' their site-specific operating limit to 75 
percent of the emission standard. The EPA received petitions for 
reconsideration on the PM CPMS provisions and proposed these provisions 
again in January 2015 to provide additional opportunity for comment.
    Several comments expressed concern about the cost and burden of the 
PM CPMS requirements. The combination of periodic compliance emissions 
testing and continuous monitoring of operational and parametric control 
measure conditions is appropriate for assuring continuous compliance 
with the emissions limitations. Without recurring testing, the EPA 
would have no way to know if parameter ranges established during 
initial performance testing remained viable in the future.
    Several comments also contended that the CPMS limit should be based 
on the highest reading during the initial performance test instead of 
the average of the readings during each of the three test runs. The EPA 
disagrees with the commenters. Requiring PM CPMS to correspond to the 
average of three PM test runs rather than the single highest test run 
during the performance test alleviates the potential for setting an 
operating limit that corresponds to an emissions result higher than the 
emission standard, which could occur if the limit corresponded to the 
highest reading.\2\ The EPA reiterates the statement in the January 
2015 preamble that a 4th deviation of the PM CPMS operating limit in a 
12-month period is a presumptive violation of the emissions standard. 
However, this is just a presumption which may be rebutted with evidence 
from the process controls, control monitoring parameters, repair logs, 
and associated Method 5 performance tests. In addition, the operating 
limit is based on a 30-day rolling average, which provides for 
additional cushion on variability of PM

[[Page 72797]]

readings beyond just the initial performance test.
---------------------------------------------------------------------------

    \2\ S. Johnson, memo to Docket ID No. EPA-HQ-OAR-2011-0817, 
``Establishing an Operating Limit for PM CPMS,'' November 2012.
---------------------------------------------------------------------------

    Based on comments, the EPA is maintaining the PM CPMS requirement 
as promulgated with minor adjustments as discussed below.
    One commenter requested that the word ``certify'' be removed from 
40 CFR 63.7525(b) and (b)(1). The EPA agrees that a PM CPMS is not a 
``certified'' instrument, in that it is not certified through a 
performance specification. We have removed this language from the final 
rule.

IV. Technical Corrections and Clarifications

    In the January 21, 2015, notice of reconsideration, the EPA also 
proposed to correct typographical errors and clarify provisions of the 
final rule that may have been unclear. This section of the preamble 
summarizes the significant changes made to the proposed corrections and 
clarifications, as well as corrections and clarifications being 
finalized based on comment.

A. Opacity Is an Operating Parameter

    Commenters contended that the opacity operating limit of 10-percent 
may be an appropriate indicator of compliance with the applicable 
Boiler MACT PM limits for some boilers, but it is not an appropriate 
indicator of compliance for all boilers in all solid fuel 
subcategories.
    Commenters also contend that the 10-percent opacity level is an 
``operating limit,'' not an emission limit, and is utilized as an 
indicator of compliance with the Boiler MACT PM limit. Operating limit 
requirements are provided in Table 4 to subpart DDDDD of part 63, and 
include opacity. Emission limits are included in Tables 1 and 2 to 
subpart DDDDD of part 63 and do not include opacity. Commenters added 
that the language in 40 CFR 63.7500(a)(2) creates a conflict. By 
requiring a facility to request an alternate opacity parameter limit 
via 40 CFR 63.6(h)(9), the commenters claim that the EPA will be 
subjecting units to a more stringent PM standard than the established 
MACT floor because this process will not be feasible to complete prior 
to the compliance date. To resolve this issue, commenters asked that 
the EPA delete 40 CFR 63.7570(b)(2) so it will be clear that a request 
for an alternate opacity operating parameter limit is accomplished 
under 40 CFR 63.8(f) per 40 CFR 63.7570(b)(4) and 40 CFR 63.7500(a)(2).
    The EPA agrees that the variation in PM limits for various solid 
fuel subcategories warrants some flexibility and similar variation in 
opacity limits. Opacity serves as a surrogate indicator of PM 
emissions, but was not intended by the EPA as an emission limit under 
the rule. Rather, it was intended to be an operating limit, which is 
established on a source-specific basis. Therefore we are revising the 
opacity operating limit such that affected facilities will have the 
option to comply with the 10-percent operating limit or a site-specific 
value established during the performance test based on the highest 
hourly average, which is consistent with how the other operating limits 
are established.
    To implement this change in the final rule, 40 CFR 63.7570(b) is 
revised to remove the text currently in paragraph (b)(2), and the 
phrase ``or the highest hourly average opacity reading measured during 
the performance test run demonstrating compliance with the PM (or TSM) 
emission limitation'' is added to Table 4 to subpart DDDDD of part 63, 
item 3; Table 4 to subpart DDDDD of part 63, item 6; and Table 8 to 
subpart DDDDD of part 63, item 1.c. Table 7 to subpart DDDDD of part 63 
is expanded to include the process for establishing operating limits 
and item c is added.

B. CO Monitoring and Moisture Corrections

    Commenters asked that since the applicable CO emission limits of 
the rule are expressed on a ``dry'' basis, the EPA should include 
additional provisions in the final rule to allow carbon dioxide 
(CO2) CEMS to be used without petitioning for alternative 
monitoring procedures. Commenters also observed that 40 CFR 
63.7525(a)(2) cross-references other requirements, including 40 CFR 
part 75, which do not address CO monitoring and do not fully address 
the moisture correction.
    Language is added to 40 CFR 63.7525(a)(2)(vi) to clarify 
requirements when CO2 is used to correct CO emissions and 
CO2 is measured on a wet basis.
    It is also acknowledged that CO concentration on a dry basis 
corrected to 3-percent O2 can be calculated using data from 
the CO2 CEMS and equations contained in EPA Method 19 
instead of during the initial compliance test. Language is added to 
Table 1 to subpart DDDDD of part 63, as well as footnote ``d'' and 
footnote ``c'' in the following tables: Table 2, Table 12, and Table 13 
to subpart DDDDD of part 63.

C. Affirmative Defense for Violation of Emission Standards During 
Malfunction

    The EPA received numerous comments on its proposal to remove from 
the current rule the affirmative defense to civil penalties for 
violations caused by malfunctions. Several commenters supported the 
removal of the affirmative defense for malfunctions. Other commenters 
opposed the removal of the affirmative defense provision.
    First, commenters (AF&PA and Georgia-Pacific) urged the EPA to 
publish a new or supplemental statement of basis and purpose for the 
proposed rule that explains (and allows for public comment on) the 
appropriateness of applying the boiler/process heater emission 
standards to malfunction periods without an affirmative defense 
provision.
    Second, a commenter (AF&PA) argued the affirmative defense was 
something that the EPA considered necessary when the current standards 
were promulgated; it was part of the statement of basis and purpose for 
the standards required to publish under CAA section 307(d)(6)(A).
    Third, commenters (CIBO/ACC) argued that the EPA should not remove 
the affirmative defense until the issue is resolved by the Court. 
Furthermore commenters argued the NRDC Court decision that the EPA 
cites as the reason for eliminating the affirmative defense provisions 
does not compel the EPA's proposed action here to remove the 
affirmative defense in this rule.
    Fourth, several commenters argued that without affirmative defense, 
or adjusted standards, the final rule provides sources no means of 
demonstrating compliance during malfunctions.
    Fifth, commenters (AF&PA, Class of '85 Regulatory Response Group, 
CIBO/ACC, American Electric Power, NHPC) urged the EPA to establish 
work practice standards that would apply during periods of malfunction 
instead of the emission rate limits or a combination of work practices 
and alternative numerical emission limitation. The EPA can address 
malfunctions using the authority Congress gave it in CAA sections 
112(h) and 302(k) to substitute a design, equipment, work practice, or 
operational standard for a numerical emission limitation.
    The Court recently vacated an affirmative defense in one of the 
EPA's CAA section 112(d) regulations. NRDC v. EPA, No. 10-1371 (D.C. 
Cir. April 18, 2014) 2014 U.S. App. LEXIS 7281 (vacating affirmative 
defense provisions in the CAA section 112(d) 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

[[Page 72798]]

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' in a given private civil suit is a job for the courts, 
not EPA.''). As a result, the EPA is not including a regulatory 
affirmative defense provision in the final rule. The EPA notes that 
removal of the affirmative defense does not in any way alter a source's 
compliance obligations under the rule, nor does it mean that such a 
defense is never available.
    Second, the EPA notes that the issue of establishing a work 
practice standard for periods of malfunctions or developing standards 
consistent with performance of best performing sources under all 
conditions, including malfunctions, was raised previously; see the 
discussion in the March 21, 2011 preamble to the final rule (76 FR 
15613). In the most recent notice of proposed reconsideration (80 FR 
3090, January 21, 2015), the EPA proposed to remove the affirmative 
defense provision, in light of the NRDC decision. The EPA did not 
propose or solicit comment on any revisions to the requirement that 
emissions standards be met at all times, or on alternative standards 
during periods of malfunctions. Therefore, the question of whether the 
EPA can and should establish different standards during malfunction 
periods, including work practice standards, is outside the scope of 
this final reconsideration action. The EPA further notes that this 
issue is currently before the Court in the pending case United States 
Sugar Corporation v. EPA, pending case No. 11-1108.
    Finally, in the event that a source fails to comply with an 
applicable CAA section 112(d) standard as a result of a malfunction 
event, the EPA's ability to exercise its case-by-case enforcement 
discretion to determine an appropriate response provides sufficient 
flexibility in such circumstances as was explained in the preamble to 
the proposed rule. Further, as the Court recognized, in an EPA or 
citizen enforcement action, the Court has the discretion to consider 
any defense raised and determine whether penalties are appropriate. Cf. 
NRDC, 2014 U.S. App. LEXIS 7281 at *24 (arguments that violation were 
caused by unavoidable technology failure can be made to the courts in 
future civil cases when the issue arises). The same is true for the 
presiding officer in EPA administrative enforcement actions.

D. Definition of Coal

    The last part of the definition of coal published in the final 
amendments to the Boiler MACT on January 31, 2013 (78 FR 7186), reads 
as follows: ``Coal derived gases are excluded from this definition [of 
coal].'' In the January 2015 proposal (80 FR 3090), the EPA proposed to 
modify this definition to read as follows: ``Coal derived gases and 
liquids are excluded from this definition [of coal].'' The EPA 
characterized its proposed change to the definition as one of several 
``clarifying changes and corrections.'' This proposed change was based 
on a question received on whether coal-derived liquids were meant to be 
included in the coal definition.
    The EPA received several comments disagreeing with the proposed 
change to the definition of coal, and indicating such a change would 
have a substantive effect on some affected facilities. One commenter 
who operates a facility with coal-derived liquids contended that the 
composition and emission profile of these liquids more closely resemble 
the coal from which they are derived than any of light or heavy liquid 
fuels used to set standards for the liquid fuel categories. The 
commenter added that the delegated authority for this facility, North 
Dakota Department of Health, accepted an applicability determination 
for the facility to classify the coal derived liquid fuels as the coal/
solid-fossil fuel subcategory. This commenter also noted that coal-
derived liquid fuels are treated as coal/solid fossils in other related 
rules such as 40 CFR part 60, subpart Db.
    Based on these comments, the EPA is not finalizing any changes to 
the definition of coal. The definition published on January 31, 2013 
(78 FR 7186), remains unchanged. As noted by the commenters, treating 
coal liquids as coal is consistent with the ICI boiler NSPS (40 CFR 
part 60, subpart Db), and EPA agrees with the commenters that coal 
derived liquids are more similar to coal solid fuels than liquid fuels.

E. Other Corrections and Clarifications

    In finalizing the rule, the EPA is addressing several other 
technical corrections and clarifications in the regulatory language 
based on public comments that were received in response to the January 
2015 proposal and other feedback as a result of implementing the rule. 
In addition to the changes outlined in Table 1 of the January 21, 2015, 
proposed notice of reconsideration (80 FR 3098), the EPA is finalizing 
several other changes, as outlined in Table 2 of this preamble.

   Table 2--Summary of Technical Corrections and Clarifications Since
                          January 2015 Proposal
------------------------------------------------------------------------
 Section of subpart DDDDD (40 CFR     Description of correction (40 CFR
             part 63)                             part 63)
------------------------------------------------------------------------
63.7495(h)........................   Replaced ``January 31,
                                     2016'' with ``the compliance date
                                     of this subpart'' to cover sources
                                     that might be making changes
                                     between January 31, 2016, and the
                                     extended compliance date of January
                                     31, 2017.
63.7500(a)(1).....................   Fixed the term ``common
                                     heaters'' to ``common headers.''
63.7515(e)........................   Revised to clarify that a
                                     source may take multiple samples
                                     during a month and the 14-day
                                     separation does not apply.
63.7521(g)(2)(ii).................   Replaced the word
                                     ``notification'' with the word
                                     ``identification'' so the sentence
                                     reads as follows: ``For each
                                     anticipated fuel type, the
                                     identification of whether you or a
                                     fuel supplier will be conducting
                                     the fuel specification analysis.''
63.7521(g)(2)(vi).................   Revised this paragraph to
                                     indicate that, when using a fuel
                                     supplier's fuel analysis, the owner
                                     or operator is not required to
                                     submit the information in 40 CFR
                                     63.7521(g)(2)(iii). Commenters
                                     found difficulties when they
                                     purchased fuel from another source.
63.7525(a)(2)(vi).................   Language was added because
                                     40 CFR part 75 does not address CO
                                     monitoring and does not fully
                                     address the moisture correction.
                                     See section IV.B of the preamble.
63.7525(b) and (b)(1).............   Removed the word certify
                                     since PM CPMS does not have a
                                     performance specification. See
                                     section III.C of the preamble.

[[Page 72799]]

 
63.7525(g)(3).....................   Revised the 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).
63.7530(c)(3), (c)(4), and (c)(5).   Revised equations 7, 8, and
                                     9 to clarify that for ``Qi'' the
                                     highest content of chlorine, Hg,
                                     and TSM is used only for initial
                                     compliance and the actual fraction
                                     is used for continuous compliance
                                     demonstration.
63.7530(d)........................   Paragraphs 63.7530(d) and
                                     63.7545(e)(8)(i) contained
                                     requirements that were similar in
                                     that they both required the
                                     submittal of a signed statement or
                                     certification of compliance that an
                                     initial tune-up of the subject unit
                                     has been completed.
                                     Paragraph 63.7530(d) was
                                     deleted and 63.7545(e)(8)(i) was
                                     modified to clarify that the
                                     requirement to include a signed
                                     statement that the tune-up was
                                     conducted is applicable to all of
                                     the boilers and process heaters
                                     covered by 40 CFR part 63, subpart
                                     DDDDD.
63.7530(e)........................   Amended 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.
63.7540(a)(2).....................   Corrected the typographical
                                     error in the proposed regulatory
                                     text so that it has the proper
                                     cross-reference: 40 CFR 63.7555(d).
63.7540(a)(10)(i).................   Revised to provide owners
                                     and operators the flexibility to
                                     perform burner inspections at any
                                     time prior to tune-up.
63.7540(a)(12)....................   Revised this paragraph to
                                     clarify the O2 set point for a
                                     source not subject to emission
                                     limits.
63.7540(a)(14)(i) and (15)(i).....   Clarified the length of the
                                     performance test depending on the
                                     basis of the rolling average for
                                     each operating parameter, for
                                     internal rule consistency.
63.7545(e)........................   Clarification that
                                     notification for these sources is
                                     due within 60 days.
63.7545(e)(2)(iii)................   Added a requirement to
                                     state the basis of the 30-day
                                     rolling average for each operating
                                     parameter, for internal rule
                                     consistency.
63.7545(e)(8)(i)..................   Paragraphs 63.7530(d) and
                                     63.7545(e)(8)(i) contained
                                     requirements that were similar in
                                     that they both required the
                                     submittal of a signed statement or
                                     certification of compliance that an
                                     initial tune-up of the subject unit
                                     has been completed.
                                     Paragraph 63.7530(d) was
                                     deleted and 63.7545(e)(8)(i) was
                                     modified to clarify that the
                                     requirement to include a signed
                                     statement that the tune-up was
                                     conducted is applicable to all of
                                     the boilers and process heaters
                                     covered by 40 CFR part 63, subpart
                                     DDDDD.
63.7550(b)(1).....................   Clarified that the first
                                     reporting period for units
                                     submitting an annual, biennial, or
                                     5 year compliance report ends on
                                     December 31 within 1, 2, or 5
                                     years, as applicable, after the
                                     initial compliance date.
63.7550(b)(5).....................   Paragraph was included in
                                     the March 2011 rule and in the
                                     December 2011 reconsideration
                                     proposal, but inadvertently removed
                                     from the January 2013 final. The
                                     text has been reinserted.
63.7550(c)(5)(xvi)................   Clarification that a
                                     rolling average is not an
                                     arithmetic mean. An arithmetic mean
                                     requires more space in a data
                                     acquisition system and more effort
                                     to review the information for
                                     accuracy. Furthermore, the intent
                                     is that ALL readings for CEMS and
                                     only deviations for non-CEMS are
                                     required.
63.7555(d)(11) and (12)...........   Text added to clarify that
                                     the new requirements apply only if
                                     startup definition 2 is selected.
                                     Changed from ``fired'' to
                                     ``fed'' to alleviate concerns about
                                     units firing solid fuels on a grate
                                     or in a FBC where the residual
                                     material in the unit keeps burning
                                     after fuel feed to the unit is
                                     stopped.
                                     Changed from the list of
                                     fuels (``coal/solid fossil fuel,
                                     biomass/biobased solids, heavy
                                     liquid fuel, or gas 2 (other)
                                     gases'') to ``fuels that are not
                                     clean fuels'' as an acknowledgement
                                     that additional clean fuels could
                                     be named.
63.7570(b)(1).....................   Removed ``non-opacity''
                                     since opacity is not an emission
                                     limit, but instead an operating
                                     limit.
                                     Added ``except as specified
                                     in Sec.   63.7555(d)(13)'' to
                                     clarify the procedures for
                                     requesting an alternative timeframe
                                     with the PM controls requirement to
                                     the permitting authority.
63.7575...........................   Revised definition of
                                     energy assessment to include both
                                     process heaters and boilers.
63.7575...........................   Revised definition of
                                     minimum sorbent injection rate to
                                     clarify that the ratio of sorbent
                                     to sulfur applies only to fluidized
                                     bed boilers that do not have
                                     sorbent injection systems
                                     installed.
63.7575...........................   Revised definition of 30-
                                     day rolling average for internal
                                     rule consistency.
                                     Revised definition of
                                     liquid fuel to remove ``comparable
                                     fuels as defined under 40 CFR
                                     261.38.'' This section of the part
                                     261 was vacated by the Court.
63.7575...........................   Edited definition of
                                     operating day and added a
                                     definition of rolling average to
                                     clarify the procedures for
                                     demonstration of compliance.
Table 1 to subpart DDDDD             Revised footnote ``c'' to
 (footnotes c and d).                change ``January 31, 2013'' to
                                     ``April 1, 2013'' to make
                                     consistent with effective date of
                                     final rule.

[[Page 72800]]

 
                                     Revised footnote ``d'' to
                                     clarify that CO concentration on a
                                     dry basis corrected to 3-percent O2
                                     can be calculated using data from
                                     the CO2 CEMS and equations
                                     contained in EPA Method 19 instead
                                     of an initial compliance test.
                                     This revision also applies
                                     to footnote ``c'' in the following
                                     tables: Table 2, Table 12, and
                                     Table 13 to subpart DDDDD.
Table 4 to subpart DDDDD..........   Items 3, 4, and 6, insert
                                     ``or the highest hourly average
                                     opacity reading measured during the
                                     performance test run demonstrating
                                     compliance with the PM (or TSM)
                                     emission limitation'' to be
                                     consistent with other operating
                                     limits.
                                     Item 7, insert 30-day
                                     rolling average before the term
                                     ``operating load'' since the load
                                     parameter includes an averaging
                                     time.
                                     Added a footnote to clarify
                                     that an acid gas scrubber is a
                                     control device that uses an
                                     alkaline solution.
Tables 4 and 8 to subpart DDDDD...   Continuous compliance is
                                     based on monthly fuel analysis and
                                     there are no operating limits
                                     related to fuel. Fuel analysis
                                     language is deleted from Table 4,
                                     item 7 and moved to Table 8, line
                                     8.
Table 6 to subpart DDDDD..........   Clarification: References
                                     to Equations 7, 8, and 9 in 40 CFR
                                     63.7530 are incorrect in items 1.g,
                                     2.g, and 4.g of Table 6.
                                     Move EPA Method 1631, EPA
                                     Method 1631E, and EPA 821-R-01-013
                                     from line 1.a to 1.f because these
                                     methods cover the analytical
                                     method, not the sample collection
                                     method.
                                     Remove ASTM D4177 and D4057
                                     from line 1.e and 2.e because these
                                     are sampling methods, not methods
                                     for determining moisture.
Table 7 to subpart DDDDD (item 5).   Revised Table 7--item 5 by
                                     adding ``highest hourly'' to
                                     resolve an inconsistency with Table
                                     4--item 8 and Table 8--item 10.
                                     Added a footnote to clarify
                                     how to set operating parameters
                                     when multiple tests are conducted.
                                     Added a footnote to clarify
                                     that future tests can confirm
                                     operating scenarios.
Table 8 to subpart DDDDD (lines      Revised to clarify how to
 9.c, 10.c, and 11.c; footnotes).    set operating parameters, such as
                                     load, when multiple performance
                                     test conditions are required. The
                                     wording in Table 8, lines 9.c,
                                     10.c, and 11.c was revised to be
                                     consistent with the wording in
                                     lines 2.c, 4.c, 5.c, 6.c, and 7.c.
Table 10 to subpart DDDDD.........   For 63.6(g), revised the
                                     3rd column to say ``Yes, except
                                     Sec.   63.7555(d)(13) specifies the
                                     procedure for application and
                                     approval of an alternative
                                     timeframe with the PM controls
                                     requirement in the startup work
                                     practice (2).'' The edit is
                                     consistent with the revision to 40
                                     CFR 63.7555(d)(13).
                                     For 63.6(h)(2) to (h)(9),
                                     revised the 3th column to say
                                     ``No.'' The edit is consistent with
                                     the revision to 40 CFR 63.7570(b).
Table 13 to subpart DDDDD.........   Revise the heading to
                                     change ``January 31, 2013'' to
                                     ``April 1, 2013'' to make
                                     consistent with effective date of
                                     final rule.
------------------------------------------------------------------------

V. Other Actions We Are Taking

    Section 307(d)(7)(B) of the CAA states that ``[o]nly an objection 
to a rule or procedure which was raised with reasonable specificity 
during the period for public comment (including any public hearing) may 
be raised during judicial review. If the person raising an objection 
can demonstrate to the Administrator that it was impracticable to raise 
such objection within such time or if the grounds for such objection 
arose after the period for public comment (but within the time 
specified for judicial review) and if such objection is of central 
relevance to the outcome of the rule, the Administrator shall convene a 
proceeding for reconsideration of the rule and provide the same 
procedural rights as would have been afforded had the information been 
available at the time the rule was proposed. If the Administrator 
refuses to convene such a proceeding, such person may seek review of 
such refusal in the United States court of appeals for the appropriate 
circuit (as provided in subsection (b)).''
    As to the first procedural criterion for reconsideration, a 
petitioner must show why the issue could not have been presented during 
the comment period, either because it was impracticable to raise the 
issue during that time or because the grounds for the issue arose after 
the period for public comment (but within 60 days of publication of the 
final action). The EPA is denying the petitions for reconsideration on 
a number of issues because this criterion has not been met. In many 
cases, the petitions reiterate comments made on the proposed December 
2011 rule during the public comment period for that rule. On those 
issues, the EPA responded to those comments in the final rule and made 
appropriate revisions to the proposed rule after consideration of 
public comments received. It is well established that an agency may 
refine its proposed approach without providing an additional 
opportunity for public comment. See Community Nutrition Institute v. 
Block, 749 F.2d at 58 and International Fabricare Institute v. EPA, 972 
F.2d 384, 399 (D.C. Cir. 1992) (notice and comment is not intended to 
result in ``interminable back-and-forth[,]'' nor is agency required to 
provide additional opportunity to comment on its response to comments) 
and Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 547 
(D.C. Cir. 1983) (``notice requirement should not force an agency 
endlessly to repropose a rule because of minor changes'').
    In the EPA's view, an objection is of central relevance to the 
outcome of the rule only if it provides substantial support for the 
argument that the promulgated regulation should be revised. See Union 
Oil v. EPA, 821 F.2d 768, 683 (D.C. Cir. 1987) (the Court declined to 
remand the rule because petitioners failed to show substantial 
likelihood that the final rule would have

[[Page 72801]]

been changed based on information in the petition). See also the EPA's 
Denial of the Petitions to Reconsider the Endangerment and Cause or 
Contribute Findings for Greenhouse Gases under Section 202 of the Clean 
Air Act, 75 FR at 49556, 49561 (August 13, 2010). See also, 75 FR at 
49556, 49560-49563 (August 13, 2010) and 76 FR at 4780, 4786-4788 
(January 26, 2011) for additional discussion of the standard for 
reconsideration under CAA section 307(d)(7)(B).
    This action includes our final decision to deny the requests for 
reconsideration with respect to all issues raised in the petitions for 
reconsideration of the final boiler and process heater rule for which 
we did not grant reconsideration.
    In this final decision, several changes that are corrections, 
editorial changes, and minor clarifications have been made. These 
changes made petitioners' comments moot. Therefore, we are denying 
reconsideration of these issues, as described below.

A. Petitioners' Comments Impacted by Technical Corrections

1. Operating Capacity Limitation
    Issue 1: The petitioners (AF&PA, CIBO/ACC) requested that the EPA 
resolve language conflicts in Tables 4, 7, and 8. Specifically, they 
claimed there is a conflict as to whether you use the highest hourly 
average operating load times 1.1 as the operating limit or the test 
average operating load times 1.1 as the operating limit. The 
petitioners contended that Table 7 to subpart DDDDD of part 63, item 5 
should be revised to clearly state that the limit is set based on the 
highest hourly average during the performance test times 1.1.
    Response to Issue 1: Item 5.c of Table 7 to subpart DDDDD of part 
63 has been revised to correctly state, consistent with Tables 4 and 8 
to subpart DDDDD of part 63, that the highest hourly average of the 
three test run averages during the performance test should be 
multiplied by 1.1 (110 percent) and used as your operating limit. The 
petitioners' comments are, therefore, now moot and we are denying 
reconsideration on this issue.
2. Averaging Time for Operating Load Limits
    Issue 2: Petitioners (CIBO/ACC) requested clarification of 
operating load limits. The rule implies that the 110-percent load limit 
established during a performance test is instantaneous. The area source 
ICI boiler rule operating load requirement includes a 30-day rolling 
average period (see Table 7 to subpart DDDDD of part 63, Item 9-78 FR 
7521). By contrast, the EPA did not add the 30-day rolling average to 
the Boiler MACT rule operating load requirement (see Table 8 to subpart 
DDDDD of part 63, Item 10-78 FR 7205). The EPA did, however, add the 
30-day average to other requirements (see Table 8 to subpart DDDDD of 
part 63, items 2, 4, 5, 6, 7, 9, 11-78 FR 7204-7205).
    The petitioners note that operating parameter limits were raised in 
public comments submitted on the 2013 Boiler MACT. Specifically, a 
commenter (AF&PA) requested a change be made in Table 4 to subpart 
DDDDD of part 63, item 8 (add ``30-day average'' prior to ``operating 
load''). The operating parameter ranges are established using test data 
obtained at steady state, so a 30-day averaging period allows for some 
fluctuations that will occur over the range of operating conditions.
    Response to Issue 2: Table 8 to subpart DDDDD of part 63 has been 
amended to clarify that operating load compliance is demonstrated with 
a 30-day average, as specified in 40 CFR 63.7525(d). Table 4 to subpart 
DDDDD of part 63, item 7 (previously item 8 as noted by the 
petitioner), has also been clarified to reflect that the affected 
source must maintain the 30-day rolling average operating load of each 
unit. The petitioners' comments are, therefore, now moot and we are 
denying reconsideration on this issue.
3. A Gas Fired Boiler, Capacity >25MW, Is an EGU, It Is Not Subject to 
UUUUU, and Should Not Be Subject to the Boiler MACT
    Issue 3: Petitioners (UARG/NHPC) alleged that the EPA has broadened 
the applicability of 40 CFR part 63, subpart DDDDD with regard to EGUs 
by stating that only ``[a]n electric utility steam generating unit 
(EGU) covered by subpart UUUUU of [part 63]'' is ``not subject to'' the 
Boiler MACT. Because 40 CFR part 63, subpart UUUUU does not cover all 
EGUs, the language in 40 CFR 63.7491(a) seems unlawful because it 
suggests that some boilers that are EGUs could be subject to 40 CFR 
part 63, subpart DDDDD. Under 40 CFR 63.9983(b), natural gas-fired EGUs 
(as defined in 40 CFR part 63, subpart UUUUU) are not subject to 40 CFR 
part 63, subpart UUUUU, but would not seem to be exempt from 40 CFR 
part 63, subpart DDDDD. Narrowing the exclusion in 40 CFR 63.7491(a) 
cannot be a ``logical outgrowth'' of the proposed rule.
    The petitioners point out that ``Natural gas-fired electric utility 
steam generating unit'' is defined in 40 CFR part 63, subpart UUUUU as 
``an electric utility steam generating unit meeting the definition of 
`fossil fuel-fired' that is not a coal-fired, oil-fired, or integrated 
gasification combined cycle (IGCC) electric utility steam generating 
unit and that burns natural gas for more than 10.0 percent of the 
average annual heat input during any 3 consecutive calendar years or 
for more than 15.0 percent of the annual heat input during any one 
calendar year'' 40 CFR 63.10042. As a result, natural gas-fired EGUs 
for purposes of 40 CFR part 63, subpart UUUUU include those units that 
combust only natural gas as well as those units that combust natural 
gas for more than the proportion(s) specified in 40 CFR 63.10042 and 
some other fuel(s) (e.g., oil) for the remainder of heat input, as long 
as they are not an IGCC unit and do not combust coal or oil in 
sufficient quantity to meet the definition of ``coal-fired'' or ``oil-
fired'' EGU.
    The petitioners refer to CAA section 112(n)(1)(A), which requires 
the EPA to conduct a health study of the effects of EGU HAP emissions 
prior to regulating HAP emissions from EGUs under CAA section 112. 
Then, if EGU HAP emissions pose a threat to public health, the EPA can 
regulate those emissions only as ``appropriate and necessary.'' The EPA 
already has regulated under 40 CFR part 63, subpart UUUUU all those 
EGUs for which the Administrator has made the statutorily required 
finding under CAA section 112(n)(1)(A)--i.e., coal-fired and oil-fired 
EGUs; the EPA has no basis to regulate any other EGU under 40 CFR part 
63, subpart DDDDD. That conclusion is consistent with the EPA's March 
21, 2011, final rule and proposed rule on reconsideration, both of 
which made clear that no boiler meeting the definition of EGU was 
subject to 40 CFR part 63, subpart DDDDD.
    Petitioners also allege that issues regarding the EGU definition in 
40 CFR part 63, subpart DDDDD were raised in public comments submitted 
on the 2013 Boiler MACT. Specifically, the commenter (UARG) requested 
that the EGU definition in 40 CFR part 63, subpart DDDDD be consistent 
with relevant definitions in 40 CFR part 63, subpart UUUUU, and remain 
that way even after the EPA finalizes its revisions to 40 CFR part 63, 
subpart UUUUU. The EPA should revise the definition in 40 CFR 63.7575 
of subpart DDDDD to incorporate, rather than restate, the definition of 
applicable ``fossil fuel-fired'' EGU in 40 CFR 63.10042 of the MATS 
rule.
    Response to Issue 3: As stated in the June 2010 proposal (75 FR 
32016), it is and has always been the EPA's intent that biomass boilers 
are regulated under

[[Page 72802]]

either the Boiler MACT or the area source ICI boiler rules. The 2010 
Boiler MACT proposal stated:

    The CAA specifically requires that fossil fuel-fired steam 
generating units of more than 25 megawatts that produce electricity 
for sale (i.e., utility boilers) be reviewed separately by EPA. 
Consequently, this proposed rule would not regulate fossil fuel-
fired utility boilers greater than 25 megawatts, but would regulate 
fossil fuel-fired units less than 25 megawatts and all utility 
boilers firing a non-fossil fuel that is not a solid waste.

    The Boiler MACT defines the biomass/bio-based solid subcategory as 
any boiler or process heater that burns at least 10-percent biomass or 
bio-based solids on an annual heat input basis. The EPA disagrees with 
the commenter who recommends that EPA simply adopt provisions from the 
MATS rule into the Boiler MACT rule. We considered what would be the 
maximum amount of fuel that can be co-fired in a boiler that is 
designed to burn a different fuel type. We are aware that boilers are 
designed for specific fuel types and will frequently encounter 
operational problems if a fuel with characteristics other than those 
originally specified is fired in amounts above a certain level. The 
purpose of 63.7491(a) is, in part, to identify a threshold of natural 
gas operation above which EPA is reasonably certain that the unit is 
designed to operate on natural gas. At a level below that threshold, 
the EPA cannot be certain that the unit is not of a different type, 
designed to burn other fuels. In this final rule, the EPA edited text 
in 40 CFR 63.7491(a) from ``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.'' to ``. . . at least . . . 
85 percent . . .'' This change was made to address variation in heat 
input of biomass fuels. This clarification does not change the 
underlying applicability of biomass EGU boilers under the Boiler MACT 
rule.
    With respect to the petitioners' reference to CAA section 
112(n)(1)(A), the EPA disagrees that this provision is relevant here, 
as biomass boilers are not EGUs, but instead are classified as ICI 
boilers. Therefore, because the petitioners did not demonstrate that it 
was impracticable to comment on this issue during the comment period on 
the 2010 proposed rule, the EPA is denying reconsideration on this 
issue.
4. Use of the Publication Date Rather Than the Effective Date of the 
Rule To Establish Various Compliance and Reporting Dates
    Issue 4: Petitioner (API) alleged that the compliance schedules are 
based on the date of publication rather than the effective date. Using 
the publication date rather than the effective date conflicts with 
certain CAA provisions and certain 40 CFR, part 63 general provisions.
    Response to Issue 4: With respect to existing units, the 
petitioner's allegation is incorrect. Section 112(i)(3)(A) of the CAA 
states ``After the effective date of any emission standard . . . the 
Administrator shall establish a compliance date . . . for . . . 
existing source, which shall provide for compliance as expeditiously as 
practicable, but in no event later than 3 years after the effective 
date . . .'' However, it is appropriate that compliance provisions 
applicable to new units should be based on the effective date because, 
otherwise, as stated in 40 CFR 63.7495(a), new units would be required 
to comply with the subpart by the publication date even though the 
amendments have not yet taken effect. Wherever January 31, 2013, was 
specified for new affected units as a compliance date or a basis for 
compliance activity, the date has been revised to April 1, 2013. The 
petitioner's comments are, therefore, now moot and we are denying 
reconsideration on this issue.
5. Existing EGUs That Become Subject to the Boiler MACT After January 
31, 2013 Do Not Get the Intended 180-Day Period for Demonstrating 
Compliance
    Issue 5: Petitioner (UARG, supplemental July 3, 2013, petition) 
objected to the language in 40 CFR 63.7510(i), which states that ``For 
an existing EGU that becomes subject after January 31, 2013, you must 
demonstrate compliance within 180 days after becoming an affected 
source'' (78 FR 7165). The petitioner argued the provision is 
inconsistent with the existing source compliance dates in 40 CFR 
63.7495(b) and (f), which require compliance by January 31, 2016, and 
the existing source deadline for demonstrating compliance in 40 CFR 
63.7510(e), which requires completion of the initial compliance 
demonstration within 180 days after the January 31, 2016, compliance 
date (78 FR at 7162-63, 7165).
    Response to Issue 5: For consistency and to correct the inadvertent 
error of failing to change the date, the compliance date in 40 CFR 
63.7510(i) has been revised from 2013 to 2016. The petitioner's 
comments are, therefore, now moot and we are denying reconsideration on 
this issue.
6. Using Fuel Analysis Rather Than Performance Testing Required Use of 
the 90th Percentile Confidence Level; a Monthly Average Is More 
Appropriate
    Issue 6: Petitioner (Eastman) requested clarification of the 
methodology that provides facilities with multiple combustion units the 
ability to demonstrate compliance with the limits through emissions 
averaging across affected units. Specifically, the petitioner urged 
modification of Table 6 to 40 CFR part 63, subpart DDDDD to delete 
references to equations requiring use of the 90th percentile.
    Response to Issue 6: Edits to Table 6 to subpart DDDDD of 40 CFR 
part 63 have been made to delete the inadvertent references to 
equations requiring the use of the 90th percentile. These equations are 
required only for determining initial compliance as specified in 40 CFR 
63.7530(c). The petitioner's comments are, therefore, now moot and we 
are denying reconsideration on this issue.
7. Gas 1 Unit Requirements
    Issue 7: Petitioner (CIBO/NEDACAP) alleged that to meet 40 CFR 
63.7555(i) and (j) recordkeeping requirements, each regulated gas 1 
boiler, regardless of size, needs electronic controls, a recording 
device, individual gas meters, and sensors to detect both steam/hot 
water flow and fuel cycling events. The petitioner further claimed that 
records of startup and shutdown for gas 1 units are irrelevant to 
emission control or enforcement of the Boiler MACT requirements because 
their installation and operation provide no environmental benefits.
    Response to Issue 7: The startup and shutdown recordkeeping 
provisions in 40 CFR 63.7555(i) and (j) have been removed. These 
paragraphs were inadvertently not deleted when the rule was amended. 
These paragraphs were intended to be deleted because 40 CFR 63.7555(d) 
was amended incorporating these recordkeeping requirements. These 
recordkeeping requirements are intended only for sources subject to 
emission standards, whereas 40 CFR 63.7555(i) and (j) have the 
unintended purpose of requiring sources not subject to emission 
standards to startup and shutdown recordkeeping requirements. The 
petitioner's comments are, therefore, now moot and we are denying 
reconsideration on this issue.

[[Page 72803]]

8. Gas 1 Reporting Requirements
    Issue 8: Petitioner (CIBO/NEDACAP) asked for clarity with respect 
to the operating time reporting in 40 CFR 63.7550(c)(5)(iv) for gas 1 
units. Specifically, ``operating time'' is not a defined term and it is 
unclear whether operating time must be reported separately for each 
unit. Furthermore, the petitioner alleged that operating time (like 
records of startup and shutdown) adds no information that is useful in 
determining compliance, nor is it useful in calculating emissions from 
reported units, since emissions are related to fuel combusted, not to 
total operating time.
    Response to Issue 8: Operating time reporting in 40 CFR 
63.7550(c)(5)(iv) has been removed from 40 CFR 63.7550(c)(1), which 
effectively removes the reporting requirement for gas 1 units. The 
petitioner's comments are, therefore, now moot and we are denying 
reconsideration on this issue.
9. Sampling for Other Gas 1 Fuels
    Issue 9: Petitioner (CIBO/NEDACAP) asked for clarifying text in 40 
CFR 62.7521 to parallel Table 6 to subpart DDDDD of part 63, item 3.b 
alternative compliance approach for cases where sampling and analysis 
of the fuel gas itself are not possible or practical.
    Response to Issue 9: Text describing the compliance procedures, 
applicable to other gas 1 fuels in 40 CFR 63.7521(f), has been amended 
as a technical correction. When the rule was amended the EPA added a 
second compliance procedure that was intended to be an alternative 
approach but the amendments inadvertently failed to add the ``or'' 
after the first compliance procedure. The petitioner's comments are, 
therefore, now moot and we are denying reconsideration on this issue.
10. Fuel Analysis Plan for Gas 1 Sampling
    Issue 10: Petitioner (CIBO/NEDACAP) alleged that the Fuel Analysis 
Plan requirements for other gas 1 fuels are more onerous than those 
required for solid and liquid fuels. There is no logical reason to 
require submission of the fuel analysis plan to the Administrator for 
review and approval for other gas 1 fuels when only alternative 
analytical methods listed in Table 6 to subpart DDDDD of part 63 are 
used; 40 CFR 63.7521(g) should be amended.
    Response to Issue 10: Administrator review and approval for other 
gas 1 fuels requirement in 40 CFR 63.7521(g) has been revised to 
clarify the intended scope of the Fuel Analysis Plan requirements and 
to be consistent with 40 CFR 63.7521(b)(1). As specified in 40 CFR 
63.7521(b)(1), a fuel analysis plan is required to be submitted for 
Administrator review and approval only when alternative methods other 
than those listed in Table 6 to subpart DDDDD of part 63 are used. The 
petitioner's comments are, therefore, now moot and we are denying 
reconsideration on this issue.
11. Affirmative Defense
    Issue 11: Petitioner (FSI) asked that the EPA amend the affirmative 
defense provisions included in 40 CFR 63.7501 or otherwise clarify in 
the rule the scope of the affirmative defense for violations that occur 
during malfunctions. The petitioner also asked that subpart A of 40 CFR 
part 63, which defines emission standard as ``a national standard, 
limitation, prohibition, or other regulation promulgated in a subpart 
of this part pursuant to sections 112(d), 112(h), or 112(f) of the 
Act,'' provide additional guidance concerning the proper interpretation 
of 40 CFR 63.7501.
    Response to Issue 11: The EPA has removed affirmative defense 
provisions from 40 CFR part 63, subpart DDDDD, as discussed in section 
IV.C of this preamble. Because the petitioner has not demonstrated that 
it was impracticable to comment on this issue during the public comment 
period on the December 2011 proposed rule, and because the issue is now 
moot, the EPA is denying this petition.

B. Petitions Related to Ongoing Litigation

1. Authority To Require an Energy Assessment
    Issue 12: Petitioners (AF&PA/FSI) alleged that a beyond the floor 
requirement of an energy assessment is outside EPA's authority for 
setting emissions standards under CAA section 112(d)(1) ``for each 
category or subcategory of major sources and area sources.'' The EPA 
has defined the source category for these rules to include only 
specified types of boilers and process heaters and, therefore, those 
are the only sources for which the EPA may set standards under these 
rules.
    The petitioners also alleged that the energy assessment requirement 
is not an ``emissions standard'' as that term is defined in the CAA 
and, therefore, the EPA does not have authority to prescribe such 
requirements. Furthermore, as a practical matter, even if energy 
efficiency projects are implemented, there is no guarantee that there 
will be a corresponding reduction in HAP emissions from affected 
boilers and process heaters.
    Response to Issue 12: Petitioners have not demonstrated that it was 
impracticable to comment on these issues during the public comment 
period on the proposed Boiler MACT. In fact, petitioners provided the 
same comments during that comment period, and subsequently challenged 
EPA's establishment of the energy assessment requirement. That issue is 
currently pending before the Court in U.S. Sugar v. EPA (No. 11-1108). 
Therefore the EPA is denying the petition for reconsideration of this 
issue.
2. Energy Assessment Requirement
    Issue 13: Issues regarding the owner or operator obligations after 
the energy assessment is completed were raised in public comments 
submitted on the 2013 Boiler MACT. Specifically, commenters (AF&PA/FSI) 
asked that the EPA confirm that the Boiler MACT does not require a 
facility owner or operator to implement any of the recommendations 
contained in the energy assessment report.
    Response to Issue 13: Comments on this issue have been previously 
submitted and the EPA responded to those comments. AF&PA made this same 
comment during the public comment period on the Boiler MACT, and the 
EPA responded to that in the Beyond-the-Floor Analysis Section (pp. 
1428-1702) of the February 2011 Response To Comment document, 
explaining that the rule does not require owners and operators to 
implement the recommendations of the energy assessment, but that the 
EPA expects that sources will do so in order to realize the cost 
savings from those recommendations. Because petitioners have not 
demonstrated that it was impracticable to comment on these issues 
during the public comment period on the proposed Boiler MACT, the EPA 
is denying the petition for reconsideration of this issue.

C. Other Petitions

1. Expanded Exemption for Limited Use Units
    Issue 14: Petitioner (Sierra Club) objected to the 2013 Boiler MACT 
proposed rule, which revised the definition of ``limited-use units'' to 
include all units that operate at 10 percent of their full annual 
capacity (78 FR 7144). A unit that operated full time at 10-percent 
capacity would qualify, as would a unit that operated for one-third of 
the year at 30-percent capacity. The petitioner also disputed the EPA's 
finding that ``it is technically infeasible

[[Page 72804]]

to schedule stack testing for these limited use units since these units 
serve as back up energy sources and their operating schedules can be 
intermittent and unpredictable.''
    Response to Issue 14: The EPA is denying the petition for 
reconsideration on this issue because the petitioner previously 
submitted comments on this issue, and the EPA responded to those 
comments in finalizing the definition of a limited use unit at that 
time (76 FR 15633, March 21, 2011).
    The 2013 revision in the final amendments to the Boiler MACT was a 
logical outgrowth of the comments received during the public comment 
period. See NRDC v. Thomas, 838 F.2d 1224, 1242 (D.C. Cir. 1988) and 
Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d at 547 (the 
agency may make changes to proposed rule without triggering new round 
of comments, where changes are logical outgrowth of proposal and 
comments).
2. Failure to Set Standards Requiring MACT (i.e., Beyond the Floor)
    Issue 15: Petitioner (Sierra Club) asserted that the EPA failed to 
assure that the standards it revised in the final rule reflect the 
maximum achievable degree of reduction in emissions, as required by CAA 
section 112(d)(2). The commenter noted that for existing sources, 10 of 
the Hg standards, five of the PM standards, and 11 of the CO limits 
were revised in the final rule. The petitioner also noted that two of 
the PM limits and 11 of the CO limits for new sources were weakened in 
the final rule. The petitioner asserted that the EPA did not propose 
any of these changes, nor did it discuss them in its proposed rule (78 
FR 7145).
    Response to Issue 15: The EPA is denying the petition for 
reconsideration on this issue because the changes to the standards 
between the 2011 and 2013 final rules were based only on changes to the 
underlying dataset to reflect unit shutdowns or corrections to emission 
test run data and on changes made to the subcategories after 
consideration of comments received on the proposed rule. These changes 
were discussed in the MACT Floor Memorandum for the final rule (See 
Docket ID No.: EPA-HQ-2002-0058-3836), as well as documented in the 
database for the final rule (See Docket ID No.: EPA-HQ-OAR-2002-0058-
3835). There were no significant changes to the methodology used to 
calculate the MACT standards. Therefore, the petition does not raise an 
issue of central relevance to this rulemaking as it does not 
demonstrate that there is a substantial likelihood that the final rule 
would have changed based on the information in the petition.
3. Beyond the Floor PM Standards
    Issue 16: The petitioner (Sierra Club) objected to the EPA's final 
``beyond the floor'' PM standards for certain categories of new biomass 
units. The petitioner claimed that the EPA did not provide an 
explanation of its conclusion that ``[w]e did not identify any beyond 
the floor options for existing source PM limits or new and existing 
limits for other pollutants as technically feasible or cost effective'' 
(78 FR 7145). The petitioner alleged that such cursory and unexplained 
conclusion that no beyond the floor standards are technically feasible 
or cost effective is both unlawful and arbitrary. Moreover, the 
petitioner also alleges that because the EPA did not propose the 
standards contained in the 2013 rule and did not discuss changing the 
level of these standards in its proposed rule, it was ``impracticable'' 
to object to the EPA's failure to set more stringent standards during 
the public comment period. 42 United States Code (U.S.C.) 
7607(d)(7)(B). Likewise, the petitioner indicated it was impracticable 
to object to the EPA's rationale for not setting more stringent 
standards.
    Response to Issue 16: The EPA disagrees with the petitioner's claim 
that we failed to set standards based on the degree of emission 
reduction that can be achieved. The EPA must consider cost, non-air 
quality health and environmental impacts, and energy requirements in 
connection with any standards that are more stringent than the MACT 
floor (beyond the floor controls). The EPA's beyond the floor analysis 
did evaluate these factors in determining PM standards for certain 
categories of new biomass units.
    To the extent the petitioner is concerned about the degree of 
emission reduction that can be achieved, that issue does not warrant 
reconsideration. The EPA made changes based on new data and changes to 
subcategories, but the methodology essentially remained the same, 
including the beyond the floor methodology in the final rule. The 
petitioner did not provide data or information that was unavailable at 
the time the EPA proposed the rule. Therefore, the EPA is denying 
reconsideration of this issue.
4. No Allowance for Liquid Firing in Gas 1 or Gas 2 Units; Other 
Subcategories Allow for Less Than 10 Percent Annual Heat Input
    Issue 17: Petitioners (API, CIBO/ACC) contended that the gas 1 
subcategory should place no restriction on liquid (e.g., oil) firing 
during startup. In the 2013 final amendments to the Boiler MACT, there 
is no allowance for liquid fuel firing in units in the gas 1 or gas 2 
subcategories except under the gas curtailment or interruption 
provisions, whereas other subcategories allow use of liquid fuels for 
less than 10-percent annual heat input basis (78 FR 7193). The 
definition for the gas 1 subcategory should read ``Unit designed to 
burn gas 1 subcategory includes any boiler or process heater that burns 
at least 90-percent natural gas, refinery gas, and/or other gas 1 fuels 
on a heat input basis on an annual average and less than 10 percent of 
any solid or liquid fuel.'' The definitional change would simplify the 
process of determining whether a unit qualifies for the gas 1 
subcategory.
    Issues regarding the consistency between the exempt unit 
description in 40 CFR part 63, subpart DDDDD and the definition of an 
oil-fired EGU in 40 CFR part 63, subpart UUUUU were raised in public 
comments submitted on the 2013 Boiler MACT. Specifically, a commenter 
(DTE Energy) argued that subpart UUUUU allows for ``high'' usage in one 
calendar year without becoming an affected unit so long as the 10-
percent annual average heat input during 3 consecutive calendar years 
is not exceeded.
    Response to Issue 17: Because the EPA received comments that gas 1 
subcategory units should allow for limited use of liquid fuel in the 
June 4, 2010, proposal and petitioners have not demonstrated that it 
was impractical for them to comment, we are denying the petition for 
reconsideration on this issue.
    In addition, the petitioners have provided no new data or 
information that calls into question the underlying determination.
5. Refine and Clarify the Scope of the Subcategory for Hybrid 
Suspension/Grate Boilers
    Issue 18: Petitioner (SugarCane Growers) asked that the definition 
of a hybrid suspension/grate (HSG) boiler needs clarification; there 
are facilities that are unsure whether their boilers fit within the HSG 
subcategory. Specifically, the petitioner requested that the definition 
add a phrase referring to the fact that an HSG boiler is ``highly 
integrated into the production process via steam connections with the 
sugar mill and the boiler primarily combusts fuels that are generated 
on-site by the mill.''
    Response to Issue 18: The EPA has made a minor technical correction 
to the final HSG boiler definition that helps clarify the intent of the 
subcategory. The

[[Page 72805]]

moisture content threshold of 40 percent on an as-fired annual heat 
input basis is to be demonstrated by monthly fuel analysis. By 
requiring demonstration on a monthly fuel analysis, the moisture in the 
fuel piles will need to be consistently high from month to month in 
order to meet the 40 percent moisture threshold. Beyond this minor 
clarification, the EPA is denying this petition for reconsideration 
because the petition does not demonstrate that the petitioner lacked 
the opportunity to comment on this definition, and we continue to 
believe that the definition is specifically clear as to whether 
specific boilers fit within the definition. The definition reflects a 
logical outgrowth of the comments received during the comment period. 
(see 76 FR 15634, March 21, 2011).
6. Applicability Based on Commercial and Industrial Solid Waste 
Incineration (CISWI) Recordkeeping Requirements
    Issue 19: The petitioner (API) alleged that it is unreasonable to 
have Boiler MACT applicability determined based on a recordkeeping 
requirements contained in the CISWI rule, and added that nothing in the 
Boiler MACT proposal requested comment on the CISWI definition of 
traditional fuels. The petitioner alleged that any unit that uses any 
material not specifically listed in the traditional fuels definition is 
a CISWI unit, rather than a Boiler MACT unit, unless it keeps specific 
records that the CISWI rule requires. The definitions of CISWI unit in 
the February 7, 2013, final amendments to the CISWI NSPS standard and 
the associated emission guideline include the sentence ``If the 
operating unit burns materials other than traditional fuels as defined 
in Sec.  241.2 that have been discarded, and you do not keep and 
produce records as required by [Sec.  60.2740(u) or Sec.  60.2175(v)], 
the operating unit is a CISWI unit.''
    Response to Issue 19: The EPA is denying this petition because it 
is not of central relevance. The issue addresses recordkeeping 
requirements in the CISWI rule, not requirements in the Boiler MACT. To 
ensure that owners or operators of units combusting materials review 
and apply the non-waste provisions in the Solid Waste Definition Rule, 
the EPA requires owners or operators that combust materials that are 
not clearly listed as traditional fuels document how the materials meet 
the legitimacy criteria and/or the processing requirements in the Solid 
Waste Definition Rule. Failure of a source owner or operator to 
correctly apply the non-waste criteria would result in incorrect self-
assessments as to whether their combustion units are subject to CISWI. 
Requiring sources to document how the non-waste criteria apply to the 
materials combusted will both improve self-assessments of 
applicability, and will assist the EPA and states in the proper 
identification of sources subject to CISWI.
7. Definitions for Rolling Averages Are Inconsistent With Other Rule 
Requirements, and Increase Burdens
    Issue 20: The petitioner (API) alleged that both 10- and 30-day 
rolling average definitions, if read literally, say owners or operators 
must average a total of 240 or 720 hours of valid data, regardless of 
the calendar period they span, rather than requiring that only hours 
within the last 240 or 720 calendar hours that contain valid data be 
averaged. As a result, since the number of hours of valid data over any 
calendar period is constantly varying, the time period covered by each 
average will vary. Individual hours will be counted in varying numbers 
of averages, and all units at a facility will end up on different, 
constantly varying averaging schedules. This approach is also 
inconsistent with the definition of ``daily block average,'' which 
calls for averaging all valid data occurring within each daily 24-hour 
period and includes other averaging requirements. Revisions to the 
definitions of 10-day rolling average and 30-day rolling average should 
be amended.
    Response to Issue 20: The EPA is denying this petition because it 
is not of central relevance to this rulemaking for the reasons set 
forth below. The definitions of 10- and 30-day rolling averages include 
the word ``valid.'' Valid data excludes hours during startup and 
shutdown and data collected during periods when the monitoring system 
is out of control as specified in your site-specific monitoring plan. 
Further, the 30-day rolling average for CO CEMS has been revised to 
clarify that for CO CEMS, the 720 hours should be consecutive, but not 
necessarily continuous to reflect intermittent operations.
8. CO Limits for Hybrid Suspension Grate Boilers
    Issue 21: The petitioner (FSI) alleged that the CO CEMS emission 
limit for existing HSG boilers is set at the same level as the CO CEMS 
limit for new HSG boilers, because the EPA has CO CEMS data for only 
one HSG boiler. The CO CEMS limit for existing boilers should be 
revised to account for the variability in the emissions data for 
existing HSG boilers, as reflected by the EPA's stack test data for 
such boilers.
    Response to Issue 21: CO CEM data were only available for one unit. 
Therefore, the alternative CO CEMS-based limit is the same for both new 
and existing units. The petitioner could have provided additional data 
to the EPA prior to the close of the comment period for the final rule. 
Indeed, the EPA modified several emission limits upon receipt of new 
data. Setting emission limits based on available data is consistent 
with MACT floor methodology. Therefore, the EPA is denying the petition 
for reconsideration.
9. Correction of Math Error
    Issue 22: The petitioner (FSI) alleged that a math (i.e., 
conversion) error was committed when converting stack test data within 
the EPA's emissions database. According to the petitioner, this error 
significantly affected the EPA's determination of the MACT floor for CO 
emissions from the existing HSG boilers. The petitioner stated that the 
EPA should correct this error and then use its existing emissions 
database to re-determine the CO emission limit for existing HSG 
boilers. The petitioner calculated a revised CO emission limit for 
existing HSG boilers of 3,500 ppm by dry volume at 3-percent 
O2.
    Response to Issue 22: As discussed in section IV.E of this 
preamble, the EPA has finalized the correction to the CO limit for this 
subcategory.
10. Conducting Tune-ups at Seasonally Operated Boilers
    Issue 23: The petitioner (FSI) alleged that collecting meaningful 
CO data before and after an annual tune-up will be problematic because 
HSG boilers are operated on a seasonal basis and the annual tune-ups 
will be performed between the annual harvest seasons. With regard to 
these seasonally operated boilers, the Boiler MACT should explicitly 
acknowledge that the ``before'' measurement will be taken at the end of 
one harvest season and the ``after'' measurement will be taken at the 
beginning of a different harvest.
    Response to Issue 23: The EPA is denying reconsideration on this 
issue. The EPA believes the rule is sufficiently clear on the timing of 
a tune-up and refers the petitioner to 40 CFR 63.7540(a)(10). If the 
unit is not operating on the required date for a tune-up (i.e., because 
it is a seasonal boiler, or because it is down for maintenance, for 
example), the tune-up must be conducted within 30 days of startup. 
Before and after measurements are not seasons apart, instead they are 
within minutes or hours (depending on how long it takes to make 
adjustments). See the tune-up guide for additional

[[Page 72806]]

guidance (http://www.epa.gov/ttn/atw/boiler/imptools/boiler_tune-up_guide-v1.pdf).

VI. Impacts of This Final Rule

    This action finalizes certain provisions and makes technical and 
clarifying corrections, but does not promulgate substantive changes to 
the January 2013 final Boiler MACT (78 FR 7138). Therefore, there are 
no environmental, energy, or economic impacts associated with this 
final action. The impacts associated with the Boiler MACT are discussed 
in detail in the January 2013 final amendments to the Boiler MACT.

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 the PRA. OMB has previously approved the information collection 
activities contained in the existing regulations (40 CFR part 63, 
subpart DDDDD) and has assigned OMB control number 2060-0551. This 
action is believed to result in no changes to the information 
collection requirements of the January 2013 final amendments to the 
Boiler MACT, so that the information collection estimate of project 
cost and hour burden from the final Boiler MACT have not been revised.

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 
finalizes the EPA's response to petitions for reconsideration on three 
issues of the Boiler MACT as well as minor changes to the rule to 
correct and clarify implementation issues raised by stakeholders.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain any unfunded mandate as described in 
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect 
small governments. This rule promulgates amendments to the January 2013 
final Boiler MACT provisions, but the amendments are mainly 
clarifications to existing rule language to aid in implementation, or 
are being made to maintain consistency with other, more recent, 
regulatory actions. Therefore, the action imposes no enforceable duty 
on any state, local, or tribal governments or the private sector.

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.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175. It will not have substantial direct effects on 
tribal governments, on the relationship between the federal government 
and Indian tribes, or on the distribution of power and responsibilities 
between the federal government and Indian tribes, as specified in 
Executive Order 13175. This action clarifies certain components of the 
January 2013 final Boiler MACT. Thus, Executive Order 13175 does not 
apply to this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 as applying only 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 any such 
environmental health risks or safety risks.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 because it is 
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act (NTTAA)

    This action does not involve any new technical standards from those 
contained in the March 21, 2011, final rule. Therefore, the EPA did not 
consider the use of any voluntary consensus standards. See 76 FR 15660-
15662 for the NTTAA discussion in the March 21, 2011, final rule.

J. Executive Order 12898: Federal Actions to Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes the human health or environmental risk addressed 
by this action will not have potential disproportionately high and 
adverse human health or environmental effects on minority, low-income, 
or indigenous populations because it does not affect the level of 
protection provided to human health or the environment.
    The environmental justice finding in the January 2013 final 
amendments to the Boiler MACT remain relevant in this action, which 
finalizes three aspects of the Boiler MACT as well as finalizing minor 
changes to the rule to correct and clarify implementation issues raised 
by stakeholders.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is not a ``major rule'' as defined by 5 
U.S.C. 804(2).

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Hazardous substances.

    Dated: November 5, 2015.
Gina McCarthy,
Administrator.

    For the reasons cited in the preamble, title 40, chapter I, part 63 
of the Code of Federal Regulations is 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 revising paragraphs (a), (j), and (l) 
and adding paragraph (n) to read as follows:

[[Page 72807]]

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 85 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 revising paragraphs (a), (e), and (f) 
and adding paragraphs (h) and (i) to 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 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).
    (f) If you own or operate an existing EGU that becomes subject to 
this subpart after January 31, 2016, you must be in compliance with the 
applicable existing source provisions of this subpart on the effective 
date such unit becomes subject to this subpart.
* * * * *
    (h) If you own or operate an existing industrial, commercial, or 
institutional boiler or process heater and have switched fuels or made 
a physical change to the boiler or process heater that resulted in the 
applicability of a different subcategory after the compliance date of 
this subpart, 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 switched 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) 
introductory text, (a)(1)(ii), (a)(1)(iii), 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 headers 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 (iii) of this section, but on or after 
January 31, 2016, you must comply with the emission limits in Table 1 
to this subpart.
* * * * *
    (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 and Reserved]

0
5. Section 63.7501 is removed and reserved.

0
6. Section 63.7505 is amended by revising paragraphs (a), (c), and (d) 
introductory text 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), 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.
    (d) If you demonstrate compliance with any applicable emission 
limit through performance testing and subsequent compliance with 
operating limits through the use of CPMS, or with a CEMS or COMS, you 
must develop a site-specific monitoring plan according to the 
requirements in paragraphs (d)(1) through (4) of this section for the 
use of any CEMS, COMS, or CPMS. This requirement also applies to you if 
you petition the EPA Administrator for alternative monitoring 
parameters under Sec.  63.8(f).
* * * * *

[[Page 72808]]

    (e) If you have an applicable emission limit, and you choose to 
comply using definition (2) of ``startup'' in Sec.  63.7575, you must 
develop and implement a written startup and shutdown plan (SSP) 
according to the requirements in Table 3 to this subpart. The SSP must 
be maintained onsite and available upon request for public inspection.

0
7. Section 63.7510 is amended by revising paragraphs (a) introductory 
text, (a)(2)(ii), (c), (e), (g), and (i) and adding paragraph (k) to 
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 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 
subcategories 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), (e), 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.
    (e) If you demonstrate compliance with the mercury, HCl, or TSM 
based on fuel analysis, you must conduct a monthly fuel analysis 
according to Sec.  63.7521 for each type of fuel burned that is subject 
to an emission limit in Tables 1, 2, or 11 through 13 to this subpart. 
You may comply with this monthly requirement by completing the fuel 
analysis any time within the calendar month as long as the analysis is 
separated from the previous analysis by at least 14 calendar days. If 
you burn a new type of fuel, you must conduct a fuel analysis before 
burning the new type of fuel in your boiler or process heater. You must 
still meet all applicable continuous compliance requirements in Sec.  
63.7540. If each of 12 consecutive monthly fuel analyses demonstrates 
75 percent or less of the compliance level, you may decrease the fuel 
analysis frequency to quarterly for that fuel. If any quarterly sample 
exceeds 75 percent of the compliance level or you begin burning a new 
type of fuel, you must return to monthly monitoring for that fuel, 
until 12 months of fuel analyses are again less than 75 percent of the 
compliance level. If sampling is conducted on one day per month, 
samples should be no less than 14 days apart, but if multiple samples 
are taken per month, the 14-day restriction does not apply.
* * * * *
    (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).

[[Page 72809]]

0
b. Revising paragraph (c) introductory text.
0
c. Revising paragraph (c)(1)(ii).
0
d. Revising paragraph (f) introductory text.
0
e. Revising paragraphs (g) introductory text, (g)(2)(ii), and 
(g)(2)(vi).
0
f. 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) You must obtain composite fuel samples for each fuel type 
according to the procedures in paragraph (c)(1) or (2) of this section, 
or the methods listed in Table 6 to this subpart, or use an automated 
sampling mechanism that provides representative composite fuel samples 
for each fuel type that includes both coarse and fine material. At a 
minimum, for demonstrating initial compliance by fuel analysis, you 
must obtain three composite samples. For monthly fuel analyses, at a 
minimum, you must obtain a single composite sample. For fuel analyses 
as part of a performance stack test, as specified in Sec.  63.7510(a), 
you must obtain a composite fuel sample during each performance test 
run.
    (1) * * *
    (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, 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.
* * * * *
    (2) * * *
    (ii) For each anticipated fuel type, the identification of whether 
you or a fuel supplier will be conducting the fuel specification 
analysis.
* * * * *
    (vi) If you will be using fuel analysis from a fuel supplier in 
lieu of site-specific sampling and analysis, the fuel supplier must use 
the analytical methods required by Table 6 to this subpart. When using 
a fuel supplier's fuel analysis, the owner or operator is not required 
to submit the information in Sec.  63.7521(g)(2)(iii).
    (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:
0
a. Revising paragraphs (c), (d), (f)(1) introductory text, (g)(1), 
(g)(3) introductory text, and (i).
0
b. Revising parameters ``En'' and ``ELi'' of Equation 6 in paragraph 
(j)(1).
    The revisions 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.
* * * * *
    (f) * * *
    (1) For each calendar month, you must use Equation 3a or 3b or 3c 
of this section to calculate the average weighted emission rate for 
that month. Use Equation 3a and the actual heat input for the month for 
each existing unit participating in the emissions averaging option if 
you are complying with emission limits on a heat input basis. Use 
Equation 3b and the actual steam generation for the month if you are 
complying with the emission limits on a steam generation (output) 
basis. Use Equation 3c and the actual electrical generation for the 
month if you are complying with the emission limits on an electrical 
generation (output) basis.
* * * * *
    (g) * * *
    (1) If requested, you must submit the implementation plan no later 
than 180 days before the date that the facility intends to demonstrate 
compliance using the emission averaging option.
* * * * *
    (3) If submitted upon request, the Administrator shall review and 
approve or disapprove the plan according to the following criteria:
* * * * *
    (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) * * *
* * * * *

[[Page 72810]]

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.
* * * * *

0
11. Section 63.7525 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1), (a)(2) 
introductory text, (a)(3), and (a)(5).
0
b. Adding paragraph (a)(2)(vi).
0
c. Revising paragraphs (b) introductory text, (b)(1) introductory text, 
and (b)(1)(iii).
0
d. Revising paragraphs (g)(3) and (4).
0
e. Revising paragraphs (m) introductory text and (m)(2).
    The revisions and addition 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. An owner or operator may 
request an alternative test method under Sec.  63.7 of this chapter, in 
order that compliance with the CO emissions limit be determined using 
CO2 as a diluent correction in place of oxygen at 3 percent. 
EPA Method 19 F-factors and EPA Method 19 equations must be used to 
generate the appropriate CO2 correction percentage for the 
fuel type burned in the unit, and must also take into account that the 
3 percent oxygen correction is to be done on a dry basis. The 
alternative test method request must account for any CO2 
being added to, or removed from, the emissions gas stream as a result 
of limestone injection, scrubber media, etc.
    (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.
* * * * *
    (vi) When CO2 is used to correct CO emissions and 
CO2 is measured on a wet basis, correct for moisture as 
follows: Install, operate, maintain, and quality assure a continuous 
moisture monitoring system for measuring and recording the moisture 
content of the flue gases, in order to correct the measured hourly 
volumetric flow rates for moisture when calculating CO concentrations. 
The following continuous moisture monitoring systems are acceptable: A 
continuous moisture sensor; an oxygen analyzer (or analyzers) capable 
of measuring O2 both on a wet basis and on a dry basis; or a 
stack temperature sensor and a moisture look-up table, i.e., a 
psychrometric chart (for saturated gas streams following wet scrubbers 
or other demonstrably saturated gas streams, only). The moisture 
monitoring system shall include as a component the automated data 
acquisition and handling system (DAHS) for recording and reporting both 
the raw data (e.g., hourly average wet-and dry basis O2 
values) and the hourly average values of the stack gas moisture content 
derived from those data. When a moisture look-up table is used, the 
moisture monitoring system shall be represented as a single component, 
the certified DAHS, in the monitoring plan for the unit or common 
stack.
    (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.
* * * * *
    (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 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, and 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.
* * * * *
    (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 and according to the

[[Page 72811]]

manufacturer's instructions. Clean the pH probe at least once each 
process operating day. Maintain on-site documentation that your 
calibration frequency is sufficient to maintain the specified accuracy 
of your device.
    (4) Conduct a performance evaluation (including a two-point 
calibration with one of the two buffer solutions having a pH within 1 
of the pH of the operating limit) of the pH monitoring system in 
accordance with your monitoring plan at the time of each performance 
test but no less frequently than annually.
* * * * *
    (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.
* * * * *
    (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 paragraph (a) and paragraph (b) introductory text.
0
b. Revising parameter ``Qi'' of Equation 7 in paragraph (b)(1)(iii), 
Equation 8 in paragraph (b)(2)(iii), and Equation 9 in paragraph 
(b)(3)(iii).
0
c. Revising parameter ``n'' of Equation 14 in paragraph (b)(4)(ii)(D).
0
d. Revising paragraph (b)(4)(ii)(F).
0
e. Redesignating paragraphs (b)(4)(iii) through (viii) as paragraphs 
(b)(4)(iv) through (ix) and adding new paragraph (b)(4)(iii).
0
f. Revising parameters ``Ci90'' and ``Qi'' of Equation 16 in paragraph 
(c)(3), parameters ``Hgi90'' and ``Qi'' of Equation 17 in paragraph 
(c)(4), and parameters ``TSMi90'' and ``Qi'' of Equation 18 in 
paragraph (c)(5).
0
g. Removing and reserving paragraph (d).
0
h. Revising paragraphs (e), (h), and (i)(3).
    The revisions and additions 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) * * *

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 
should be used.
* * * * *
    (2) * * *
    (iii) * * *
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 
should be used.
* * * * *
    (3) * * *
    (iii) * * *

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 
should be used.
* * * * *
    (4) * * *
    (ii) * * *
    (D) * * *
n = is the number of valid hourly parameter values collected over the 
previous 30 operating days.
* * * * *
    (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

[[Page 72812]]

drop operating limits at the higher of the minimum values established 
during the performance tests.
    (iv) For an electrostatic precipitator (ESP) operated with a wet 
scrubber, you must establish the minimum total secondary electric power 
input, as defined in Sec.  63.7575, as your operating limit during the 
three-run performance test during which you demonstrate compliance with 
your applicable limit. (These operating limits do not apply to ESP that 
are operated as dry controls without a wet scrubber.)
    (v) For a dry scrubber, you must establish the minimum sorbent 
injection rate for each sorbent, as defined in Sec.  63.7575, as your 
operating limit during the three-run performance test during which you 
demonstrate compliance with your applicable limit.
    (vi) For activated carbon injection, you must establish the minimum 
activated carbon injection rate, as defined in Sec.  63.7575, as your 
operating limit during the three-run performance test during which you 
demonstrate compliance with your applicable limit.
    (vii) The operating limit for boilers or process heaters with 
fabric filters that demonstrate continuous compliance through bag leak 
detection systems is that a bag leak detection system be installed 
according to the requirements in Sec.  63.7525, and that each fabric 
filter must be operated such that the bag leak detection system alert 
is not activated more than 5 percent of the operating time during a 6-
month period.
    (viii) For a minimum oxygen level, if you conduct multiple 
performance tests, you must set the minimum oxygen level at the lower 
of the minimum values established during the performance tests.
    (ix) The operating limit for boilers or process heaters that 
demonstrate continuous compliance with the HCl emission limit using a 
SO2 CEMS is to install and operate the SO2 
according to the requirements in Sec.  63.7525(m) establish a maximum 
SO2 emission rate equal to the highest hourly average 
SO2 measurement during the most recent three-run performance 
test for HCl.
    (c) * * *
    (3) * * *
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. For continuous compliance 
demonstration, the actual fraction of the fuel burned during the month 
should be used.
* * * * *
    (4) * * *
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. For continuous compliance 
demonstration, the actual fraction of the fuel burned during the month 
should be used.
* * * * *
    (5) * * *
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. For continuous compliance 
demonstration, the actual fraction of the fuel burned during the month 
should be used.
* * * * *
    (e) You must include with the Notification of Compliance Status a 
signed certification that either 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 HCl 
performance test.

0
13. Section 63.7533 is amended by revising paragraph (e) to read as 
follows:


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) to 
read as follows:


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

[[Page 72813]]

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).
0
b. Revising paragraphs (a)(3) introductory text and (a)(3)(iii).
0
c. Revising paragraphs (a)(5) introductory text and (a)(5)(iii).
0
d. Revising paragraph (a)(8)(ii).
0
e. Revising paragraph (a)(10) introductory text.
0
f. Revising paragraph (a)(10)(i).
0
g. Revising paragraph (a)(10)(vi) introductory text.
0
h. Revising paragraphs (a)(12).
0
i. Revising paragraphs (a)(14)(i) and (a)(15)(i).
0
j. Revising paragraphs (a)(17) introductory text and (a)(17)(iii).
0
k. Revising paragraph (a)(18)(i).
0
l. Revising paragraph (a)(19)(iii).
0
m. Revising paragraph (d).
    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.  63.7555(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:
    (i) Equal to or lower emissions of HCl, mercury, and TSM than the 
applicable emission limit for each pollutant, if you demonstrate 
compliance through fuel analysis.
    (ii) Equal to or lower fuel input of chlorine, mercury, and TSM 
than the maximum values calculated during the last performance test, if 
you demonstrate compliance through performance testing.
    (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.
* * * * *
    (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.
* * * * *
    (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.
    (i) As applicable, inspect the burner, and clean or replace any 
components of the burner as necessary (you may perform the burner 
inspection any time prior to the tune-up or delay the burner inspection 
until the next scheduled unit shutdown). Units that produce electricity 
for sale may delay the burner inspection until the first outage, not to 
exceed 36 months from the previous inspection. At units where entry 
into a piece of process equipment or into a storage vessel is required 
to complete the tune-up inspections, inspections are required only 
during planned entries into the storage vessel or process equipment;
* * * * *
    (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,
* * * * *
    (12) If your boiler or process heater has a continuous oxygen trim 
system that maintains an optimum air to fuel ratio, or a heat input 
capacity of less than or equal to 5 million Btu per hour and the unit 
is in the units designed to burn gas 1; units designed to burn gas 2 
(other); or units designed to burn light liquid subcategories, or meets 
the definition of limited-use boiler or process heater in Sec.  
63.7575, you must conduct a tune-up of the boiler or process heater 
every 5 years as specified in paragraphs (a)(10)(i) through (vi) of 
this section to demonstrate continuous compliance. You may delay the 
burner inspection specified in paragraph (a)(10)(i) of this section 
until the next scheduled or unscheduled unit shutdown, but you must 
inspect each burner at least once every 72 months. If an oxygen trim 
system is utilized on a unit without emission standards to reduce the 
tune-up frequency to once every 5 years, set the oxygen level no lower 
than the oxygen concentration measured during the most recent tune-up.
* * * * *
    (14) * * *
    (i) Operate the mercury CEMS in accordance with performance 
specification 12A of 40 CFR part 60, appendix B or operate a sorbent 
trap based integrated monitor in accordance with performance 
specification 12B of 40 CFR part 60, appendix B. The duration of the 
performance test must be 30 operating days if you specified a 30 
operating day basis in Sec.  63.7545(e)(2)(iii) for mercury CEMS or it 
must be 720 hours if you specified a 720 hour basis in Sec.  
63.7545(e)(2)(iii) for mercury CEMS. For each day in which the unit 
operates, you must obtain hourly mercury concentration data, and stack 
gas volumetric flow rate data.
* * * * *
    (15) * * *
    (i) Operate the continuous emissions monitoring system in 
accordance with the applicable performance specification in 40 CFR part 
60, appendix B. The duration of the performance test must be 30 
operating

[[Page 72814]]

days if you specified a 30 operating day basis in Sec.  
63.7545(e)(2)(iii) for HCl CEMS or it must be 720 hours if you 
specified a 720 hour basis in Sec.  63.7545(e)(2)(iii) for HCl CEMS. 
For each day in which the unit operates, you must obtain hourly HCl 
concentration data, and stack gas volumetric flow rate data.
* * * * *
    (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.
* * * * *
    (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.
* * * * *
    (18) * * *
    (i) To determine continuous compliance, you must record the PM CPMS 
output data for all periods when the process is operating and the PM 
CPMS is not out-of-control. You must demonstrate continuous compliance 
by using all quality-assured hourly average data collected by the PM 
CPMS for all operating hours to calculate the arithmetic average 
operating parameter in units of the operating limit (milliamps) on a 
30-day rolling average basis.
* * * * *
    (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) introductory 
text, (e)(8)(i), adding paragraph (e)(2)(iii), and revising paragraph 
(h) introductory text to read as follows:


Sec.  63.7545  What notifications must I submit and when?

* * * * *
    (e) If you are required to conduct an initial compliance 
demonstration as specified in Sec.  63.7530, you must submit a 
Notification of Compliance Status according to Sec.  63.9(h)(2)(ii). 
For the initial compliance demonstration for each boiler or process 
heater, you must submit the Notification of Compliance Status, 
including all performance test results and fuel analyses, before the 
close of business on the 60th day following the completion of all 
performance test and/or other initial compliance demonstrations for all 
boiler or process heaters at the facility according to Sec.  
63.10(d)(2). The Notification of Compliance Status report must contain 
all the information specified in paragraphs (e)(1) through (8) of this 
section, as applicable. If you are not required to conduct an initial 
compliance demonstration as specified in Sec.  63.7530(a), the 
Notification of Compliance Status must only contain the information 
specified in paragraphs (e)(1) and (8) of this section and must be 
submitted within 60 days of the compliance date specified at Sec.  
63.7495(b).
* * * * *
    (2) * * *
    (iii) Identification of whether you are complying the arithmetic 
mean of all valid hours of data from the previous 30 operating days or 
of the previous 720 hours. This identification shall be specified 
separately for each operating parameter.
* * * * *
    (8) * * *
    (i) ``This facility completed the required initial tune-up for all 
of the boilers and process heaters covered by 40 CFR part 63 subpart 
DDDDD at this site 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)(1) 
through (4), (c)(5)(viii) and (xvi), adding paragraph (c)(5)(xviii), 
and revising paragraph (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 
a requirement to conduct subsequent annual, biennial, or 5-year tune-up 
according to Sec.  63.7540(a)(10), (11), or (12), 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 after 
the compliance date that is specified for your source in Sec.  63.7495. 
If submitting an annual, biennial, or 5-year compliance report, the 
first 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 December 31 within 1, 2, or 5 years, as 
applicable, 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.
    (5) For each affected source that is subject to permitting 
regulations pursuant to part 70 or part 71 of this

[[Page 72815]]

chapter, and if the permitting authority has established dates for 
submitting semiannual reports pursuant to 70.6(a)(3)(iii)(A) or 
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance 
reports according to the dates the permitting authority has established 
in the permit instead of according to the dates in paragraphs (b)(1) 
through (4) of this section.
    (c) * * *
    (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) of this section, (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) * * *
    (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).
* * * * *
    (xvi) For each reporting period, the compliance reports must 
include all of the calculated 30 day rolling average values for CEMS 
(CO, HCl, SO2, and mercury), 10 day rolling average values 
for CO CEMS when the limit is expressed as a 10 day instead of 30 day 
rolling average, and the PM CPMS data.
* * * * *
    (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 (as defined in Sec.  63.2) required by this subpart, you must 
submit the results of the performance tests, including any fuel 
analyses, following the procedure specified in either paragraph 
(h)(1)(i) or (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), 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) (https://cdx.epa.gov/).) 
Performance test data must be submitted in a file format generated 
through use of the EPA's ERT or an electronic file format consistent 
with the extensible markup language (XML) schema listed on the EPA's 
ERT Web site. 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, 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 at the time of the 
test, 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 (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 evaluation, 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 or an alternate file 
format consistent with the XML schema listed on the EPA's ERT

[[Page 72816]]

Web site. If you claim that some of the performance evaluation 
information being transmitted 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, 
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 at the time of the evaluation, 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 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 (11) as paragraphs (d)(3) 
through (10).
0
d. Revising newly designated paragraphs (d)(3), (d)(4), and (d)(8).
0
e. Adding new paragraph (d)(11) and paragraphs (d)(12) and (d)(13).
0
f. Removing paragraphs (i) and (j).
    The additions and revisions 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, for units selecting paragraph (2) of 
the definition of ``startup'' in Sec.  63.7575 you must maintain 
records of the time that clean fuel combustion begins; the time when 
you start feeding fuels that are not clean fuels; the time when useful 
thermal energy is first supplied; and the time when the PM controls are 
engaged.
    (12) If you choose to rely on paragraph (2) of the definition of 
``startup'' in Sec.  63.7575, 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's liquid flow rate and the 
pressure drop during each hour of startup.
    (13) If you choose to use paragraph (2) of the definition of 
``startup'' in Sec.  63.7575 and you find that you are unable to safely 
engage and operate your PM control(s) within 1 hour of first firing of 
non-clean fuels, you may choose to rely on paragraph (1) of

[[Page 72817]]

definition of ``startup'' in Sec.  63.7575 or you may submit to the 
delegated permitting authority a request for a variance with the PM 
controls requirement, as described below.
    (i) The request shall provide evidence of a documented 
manufacturer-identified safety issue.
    (ii) The request shall provide information to document that the PM 
control device is adequately designed and sized to meet the applicable 
PM emission limit.
    (iii) In addition, the request shall contain documentation that:
    (A) The unit is using clean fuels to the maximum extent possible to 
bring the unit and PM control device up to the temperature necessary to 
alleviate or prevent the identified safety issues prior to the 
combustion of primary fuel;
    (B) The unit has explicitly followed the manufacturer's procedures 
to alleviate or prevent the identified safety issue; and
    (C) Identifies with specificity the details of the manufacturer's 
statement of concern.
    (iv) You must comply with all other work practice requirements, 
including but not limited to data collection, recordkeeping, and 
reporting requirements.
* * * * *

0
19. Section 63.7570 is amended by revising paragraph (b) to read as 
follows:


Sec.  63.7570  Who implements and enforces this subpart?

* * * * *
    (b) In delegating implementation and enforcement authority of this 
subpart to a state, local, or tribal agency under 40 CFR part 63, 
subpart E, the authorities listed in paragraphs (b)(1) through (4) of 
this section are retained by the EPA Administrator and are not 
transferred to the state, local, or tribal agency, however, the EPA 
retains oversight of this subpart and can take enforcement actions, as 
appropriate.
    (1) Approval of alternatives to the emission limits and work 
practice standards in Sec.  63.7500(a) and (b) under Sec.  63.6(g), 
except as specified in Sec.  63.7555(d)(13).
    (2) Approval of major change to test methods in Table 5 to this 
subpart under Sec.  63.7(e)(2)(ii) and (f) and as defined in Sec.  
63.90, and alternative analytical methods requested under Sec.  
63.7521(b)(2).
    (3) Approval of major change to monitoring under Sec.  63.8(f) and 
as defined in Sec.  63.90, and approval of alternative operating 
parameters under Sec. Sec.  63.7500(a)(2) and 63.7522(g)(2).
    (4) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(e) and as defined in Sec.  63.90.

0
20. Section 63.7575 is amended by:
0
a. Revising the definition for ``30-day rolling average.''
0
b. Removing the definition for ``Affirmative defense.''
0
c. Adding in alphabetical order a definition for ``Clean dry biomass.''
0
d. Revising the definition for ``Energy assessment.''
0
e. Adding in alphabetical order a definition for ``Fossil fuel.''
0
f. Revising the definitions for ``Hybrid suspension grate boiler,'' 
``Limited-use boiler or process heater,'' ``Liquid fuel,'' ``Load 
fraction,'' ``Minimum sorbent injection rate,'' ``Operating day,'' and 
``Oxygen trim system.''
0
g. Adding in alphabetical order a definition for ``Rolling average''.
0
h. Revising the definitions for ``Shutdown,'' ``Startup,'' ``Steam 
output,'' and ``Temporary boiler.''
0
i. Adding in alphabetical order a definition for ``Useful thermal 
energy.''
    The revisions and additions read as follows:


Sec.  63.7575  What definitions apply to this subpart?

* * * * *
    30-day rolling average means the arithmetic mean of the previous 
720 hours of valid CO CEMS data. The 720 hours should be consecutive, 
but not necessarily continuous if operations were intermittent. For 
parameters other than CO, 30-day rolling average means either the 
arithmetic mean of all valid hours of data from 30 successive operating 
days or the arithmetic mean of the previous 720 hours of valid 
operating data. Valid data excludes hours during startup and shutdown, 
data collected during periods 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, and periods when this 
unit is not operating.
* * * * *
    Clean dry biomass means any biomass-based solid fuel that have not 
been painted, pigment-stained, or pressure treated, does not contain 
contaminants at concentrations not normally associated with virgin 
biomass materials and has a moisture content of less than 20 percent 
and is not a solid waste.
* * * * *
    Energy assessment means the following for the emission units 
covered by this subpart:
    (1) The energy assessment for facilities with affected boilers and 
process heaters with a combined heat input capacity of less than 0.3 
trillion Btu (TBtu) per year will be 8 on-site technical labor hours in 
length maximum, but may be longer at the discretion of the owner or 
operator of the affected source. The boiler system(s), process 
heater(s), and any on-site energy use system(s) accounting for at least 
50 percent of the affected boiler(s) energy (e.g., steam, hot water, 
process heat, or electricity) production, as applicable, will be 
evaluated to identify energy savings opportunities, within the limit of 
performing an 8-hour on-site energy assessment.
    (2) The energy assessment for facilities with affected boilers and 
process heaters with a combined heat input capacity of 0.3 to 1.0 TBtu/
year will be 24 on-site technical labor hours in length maximum, but 
may be longer at the discretion of the owner or operator of the 
affected source. The boiler system(s), process heater(s), and any on-
site energy use system(s) accounting for at least 33 percent of the 
energy (e.g., steam, hot water, process heat, or electricity) 
production, as applicable, will be evaluated to identify energy savings 
opportunities, within the limit of performing a 24-hour on-site energy 
assessment.
    (3) The energy assessment for facilities with affected boilers and 
process heaters with a combined heat input capacity greater than 1.0 
TBtu/year will be up to 24 on-site technical labor hours in length for 
the first TBtu/yr plus 8 on-site technical labor hours for every 
additional 1.0 TBtu/yr not to exceed 160 on-site technical hours, but 
may be longer at the discretion of the owner or operator of the 
affected source. The boiler system(s), process heater(s), and any on-
site energy use system(s) accounting for at least 20 percent of the 
energy (e.g., steam, process heat, hot water, or electricity) 
production, as applicable, will be evaluated to identify energy savings 
opportunities.
    (4) The on-site energy use systems serving as the basis for the 
percent of affected boiler(s) and process heater(s) energy production 
in paragraphs (1), (2), and (3) of this definition may be segmented by 
production area or energy use area as most logical and applicable to 
the specific facility being assessed (e.g., product X manufacturing 
area; product Y drying area; Building Z).
* * * * *

[[Page 72818]]

    Fossil fuel means natural gas, oil, coal, and any form of solid, 
liquid, or gaseous fuel derived from such material.
* * * * *
    Hybrid suspension grate boiler means a boiler designed with air 
distributors to spread the fuel material over the entire width and 
depth of the boiler combustion zone. The biomass fuel combusted in 
these units exceeds a moisture content of 40 percent on an as-fired 
annual heat input basis as demonstrated by monthly fuel analysis. The 
drying and much of the combustion of the fuel takes place in 
suspension, and the combustion is completed on the grate or floor of 
the boiler. Fluidized bed, dutch oven, and pile burner designs are not 
part of the hybrid suspension grate boiler design category.
* * * * *
    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.
    Liquid fuel includes, but is not limited to, light liquid, heavy 
liquid, any form of liquid fuel derived from petroleum, used oil, 
liquid biofuels, biodiesel, and vegetable oil.
    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 load firing 
50 percent solid fuel and 50 percent natural gas the load fraction is 
0.5).
* * * * *
    Minimum sorbent injection rate means:
    (1) The load fraction multiplied by the lowest hourly average 
sorbent injection rate for each sorbent measured according to Table 7 
to this subpart during the most recent performance test demonstrating 
compliance with the applicable emission limits; or
    (2) For fluidized bed combustion not using an acid gas wet scrubber 
or dry sorbent injection control technology to comply with the HCl 
emission limit, the lowest average ratio of sorbent to sulfur measured 
during the most recent performance test.
* * * * *
    Operating day means a 24-hour period between 12 midnight and the 
following midnight during which any fuel is combusted at any time in 
the boiler or process heater unit. It is not necessary for fuel to be 
combusted for the entire 24-hour period. For calculating rolling 
average emissions, an operating day does not include the hours of 
operation during startup or shutdown.
* * * * *
    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.
* * * * *
    Rolling average means the average of all data collected during the 
applicable averaging period. For demonstration of compliance with a CO 
CEMS-based emission limit based on CO concentration a 30-day (10-day) 
rolling average is comprised of the average of all the hourly average 
concentrations over the previous 720 (240) operating hours calculated 
each operating day. To demonstrate compliance on a 30-day rolling 
average basis for parameters other than CO, you must indicate the basis 
of the 30-day rolling average period you are using for compliance, as 
discussed in Sec.  63.7545(e)(2)(iii). If you indicate the 30 operating 
day basis, you must calculate a new average value each operating day 
and shall include the measured hourly values for the preceding 30 
operating days. If you select the 720 operating hours basis, you must 
average of all the hourly average concentrations over the previous 720 
operating hours calculated each operating day.
    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 supplies 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 supplies 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 useful thermal energy 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 useful thermal energy 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 
supplies 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 paragraphs (1), (2), and (3) of 
this definition that includes electricity generation of paragraph (3) 
of this definition, 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

[[Page 72819]]

according to paragraph (2) of this definition (S2), and the 
energy content of electricity generated by a electricity only turbine 
as paragraph (3) of this definition (MW(3)) 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 steam 
energy) to the common heater.
[GRAPHIC] [TIFF OMITTED] TR20NO15.000


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 paragraph (3) 
of this definition, MWh
CFn = Conversion factor for the appropriate subcategory for 
converting electricity generated according to paragraph (3) of this 
definition 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, flow, and/
or pressure required by any energy use system that uses energy provided 
by the affected boiler or process heater.
* * * * *

0
21. Table 1 to subpart DDDDD of part 63 is amended by:
0
a. Revising rows ``3.a'', ``4.a'', ``5.a'', ``6.a'', ``7.a'', ``9.a'', 
``10.a'', ``11.a'', and ``13.a''.
0
b. Revising footnote ``c''; and
0
c. Adding footnote ``d''.
    The revisions and addition read as follows:
    As stated in Sec.  63.7500, you must comply with the following 
applicable emission limits:

    Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or Reconstructed Boilers and Process Heaters
                     [Units with heat input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
                                                                           Or the emissions
                                                      The emissions must    must not exceed
                                                        not exceed the       the following        Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this subcategory . . .     pollutants . . .     limits, except       based limits,    volume or test run
                                                      during startup and     except during      duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
3. Pulverized coal boilers        a. Carbon monoxide  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 designed to burn coal/solid       (CO) (or CEMS).     on a dry basis      of steam output     sampling time.
 fossil fuel.                                          corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (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   0.12 lb per MMBtu   1 hr minimum
 burn coal/solid fossil fuel.                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (340 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).

[[Page 72820]]

 
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (230 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
6. Fluidized bed units with an    a. CO (or CEMS)...  140 ppm by volume   1.2E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3      output or 1.5 lb
 fossil fuel.                                          percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (150 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
7. Stokers/sloped grate/others    a. CO (or CEMS)...  620 ppm by volume   5.8E-01 lb per      1 hr minimum
 designed to burn wet biomass                          on a dry basis      MMBtu of steam      sampling time.
 fuel.                                                 corrected to 3      output or 6.8 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (390 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
 
                                                  * * * * * * *
9. Fluidized bed units designed   a. CO (or CEMS)...  230 ppm by volume   2.2E-01 lb per      1 hr minimum
 to burn biomass/bio-based                             on a dry basis      MMBtu of steam      sampling time.
 solids.                                               corrected to 3      output or 2.6 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (310 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
 
                                                  * * * * * * *
10. Suspension burners designed   a. CO (or CEMS)...  2,400 ppm by        1.9 lb per MMBtu    1 hr minimum
 to burn biomass/bio-based                             volume on a dry     of steam output     sampling time.
 solids.                                               basis corrected     or 27 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\d\ 10-day
                                                       rolling average).
 
                                                  * * * * * * *
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  330 ppm by volume   3.5E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solids.                                         corrected to 3      output or 3.6 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (520 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\d\ 10-day
                                                       rolling average).
 
                                                  * * * * * * *
13. Hybrid suspension grate       a. CO (or CEMS)...  1,100 ppm by        1.4 lb per MMBtu    1 hr minimum
 boiler designed to burn biomass/                      volume on a dry     of steam output     sampling time.
 bio-based solids.                                     basis corrected     or 12 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
 

[[Page 72821]]

 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
 * * * * * * *
\c\ If your affected source is a new or reconstructed affected source that commenced construction or
  reconstruction after June 4, 2010, and before April 1, 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 an alternative test method under Sec.   63.7 of this chapter, in order that
  compliance with the carbon monoxide emissions limit be determined using carbon dioxide as a diluent correction
  in place of oxygen at 3%. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
  appropriate CO2 correction percentage for the fuel type burned in the unit, and must also take into account
  that the 3% oxygen correction is to be done on a dry basis. The alternative test method request must account
  for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
  scrubber media, etc.


0
22. Table 2 to subpart DDDDD of part 63 is amended by revising the rows 
``3.a'', ``4.a'', ``5.a'', ``6.a'', ``7.a'', ``9.a'', ``10.a'', 
``11.a'', ``13.a'', ``14.b'', and ``16.b'' and adding footnote ``c'' to 
read as follows:
    As stated in Sec.  63.7500, you must comply with the following 
applicable emission limits:

          Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing Boilers and Process Heaters
                     [Units with heat input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
                                                                          The emissions must
                                                      The emissions must    not exceed the
                                                        not exceed the         following          Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this subcategory . . .     pollutants . . .     limits, except       based limits,    volume or test run
                                                      during startup and     except during      duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
3. Pulverized coal boilers        a. CO (or CEMS)...  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 designed to burn coal/solid                           on a dry basis      of steam output     sampling time.
 fossil fuel.                                          corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (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   0.14 lb per MMBtu   1 hr minimum
 burn coal/solid fossil fuel.                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.7 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (340 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.12 lb per MMBtu   1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (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   1.3E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3      output or 1.5 lb
 fossil fuel.                                          percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (150 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).

[[Page 72822]]

 
7. Stokers/sloped grate/others    a. CO (or CEMS)...  1,500 ppm by        1.4 lb per MMBtu    1 hr minimum
 designed to burn wet biomass                          volume on a dry     of steam output     sampling time.
 fuel.                                                 basis corrected     or 17 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or (720
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
 
                                                  * * * * * * *
9. Fluidized bed units designed   a. CO (or CEMS)...  470 ppm by volume   4.6E-01 lb per      1 hr minimum
 to burn biomass/bio-based solid.                      on a dry basis      MMBtu of steam      sampling time.
                                                       corrected to 3      output or 5.2 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (310 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
 
                                                  * * * * * * *
10. Suspension burners designed   a. CO (or CEMS)...  2,400 ppm by        1.9 lb per MMBtu    1 hr minimum
 to burn biomass/bio-based solid.                      volume on a dry     of steam output     sampling time.
                                                       basis corrected     or 27 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\c\ 10-day
                                                       rolling average).
 
                                                  * * * * * * *
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  770 ppm by volume   8.4E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solid.                                          corrected to 3      output or 8.4 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (520 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen,\c\ 10-day
                                                       rolling average).
 
                                                  * * * * * * *
13. Hybrid suspension grate       a. CO (or CEMS)...  3,500 ppm by        3.5 lb per MMBtu    1 hr minimum
 units designed to burn biomass/                       volume on a dry     of steam output     sampling time.
 bio-based solid.                                      basis corrected     or 39 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
 
                                                  * * * * * * *
14. Units designed to burn        b. Mercury........  2.0E-06 \a\ lb per  2.5E-06 \a\ lb per  For M29, collect a
 liquid fuel.                                          MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              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 72823]]

 
                                                  * * * * * * *
16. Units designed to burn light  b. Filterable PM    7.9E-03 \a\ lb per  9.6E-03 \a\ lb per  Collect a minimum
 liquid fuel.                      (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (6.2E-    output or 1.1E-01   run.
                                                       05 lb per MMBtu     \a\ lb per MWh;
                                                       of heat input).     or (7.5E-05 lb
                                                                           per MMBtu of
                                                                           steam output or
                                                                           8.6E-04 lb per
                                                                           MWh).
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
* * * * * * *
\c\ An owner or operator may request an alternative test method under Sec.   63.7 of this chapter, in order that
  compliance with the carbon monoxide emissions limit be determined using carbon dioxide as a diluent correction
  in place of oxygen at 3%. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
  appropriate CO2 correction percentage for the fuel type burned in the unit, and must also take into account
  that the 3% oxygen correction is to be done on a dry basis. The alternative test method request must account
  for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
  scrubber media, etc.


0
23. Table 3 to subpart DDDDD of part 63 is amended by revising the 
entries for ``4,'' ``5,'' and ``6'' and adding footnote ``a'' to read 
as follows:
    As stated in Sec.  63.7500, you must comply with the following 
applicable work practice standards:

      Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
------------------------------------------------------------------------
       If your unit is . . .          You must meet the following . . .
------------------------------------------------------------------------
 
                              * * * * * * *
4. An existing boiler or process    Must have a one-time energy
 heater located at a major source    assessment performed by a qualified
 facility, not including limited     energy assessor. An energy
 use units.                          assessment completed 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.

[[Page 72824]]

 
5. An existing or new boiler or     a. You must operate all CMS during
 process heater subject to           startup.
 emission limits in Table 1 or 2    b. For startup of a boiler or
 or 11 through 13 to this subpart    process heater, you must use one or
 during startup.                     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, clean dry
                                     biomass, 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 choose to comply using
                                     definition (1) of ``startup'' in
                                     Sec.   63.7575, once you start
                                     firing fuels that are not clean
                                     fuels, 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, and selective catalytic
                                     reduction (SCR). You must start
                                     your limestone injection in FBC
                                     boilers, dry scrubber, fabric
                                     filter, 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 to
                                     feed fuels that are not clean
                                     fuels, 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 engage and operate PM
                                     control within one hour of first
                                     feeding fuels that are not clean
                                     fuels\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. You must develop and
                                     implement a written startup and
                                     shutdown plan, as specified in Sec.
                                       63.7505(e).
                                    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 or     You must operate all CMS during
 process heater subject to           shutdown.
 emission limits in Tables 1 or 2   While firing fuels that are not
 or 11 through 13 to this subpart    clean fuels during shutdown, you
 during shutdown.                    must vent emissions to the main
                                     stack(s) and operate all applicable
                                     control devices, except limestone
                                     injection in FBC boilers, dry
                                     scrubber, fabric filter, 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\ As specified in Sec.   63.7555(d)(13), the source may request an
  alternative timeframe with the PM controls requirement to the
  permitting authority (state, local, or tribal agency) that has been
  delegated authority for this subpart by EPA. The source must provide
  evidence that (1) it is unable to safely engage and operate the PM
  control(s) to meet the ``fuel firing + 1 hour'' requirement and (2)
  the PM control device is appropriately designed and sized to meet the
  filterable PM emission limit. It is acknowledged that there may be
  another control device that has been installed other than ESP that
  provides additional PM control (e.g., scrubber).


0
24. Table 4 to subpart DDDDD of part 63 is revised to read as follows:
    As stated in Sec.  63.7500, you must comply with the applicable 
operating limits:

  Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers and
                             Process Heaters
------------------------------------------------------------------------
 When complying with a Table 1, 2,
 11, 12, or 13 numerical emission   You must meet these operating limits
         limit using . . .                          . . .
------------------------------------------------------------------------
1. Wet PM scrubber control on a     Maintain the 30-day rolling average
 boiler or process heater not        pressure drop and the 30-day
 using a PM CPMS.                    rolling 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 performance test demonstrating
                                     compliance with the PM emission
                                     limitation according to Sec.
                                     63.7530(b) and Table 7 to this
                                     subpart.

[[Page 72825]]

 
2. Wet acid gas (HCl) scrubber \a\  Maintain the 30-day rolling average
 control on a boiler or process      effluent pH at or above the lowest
 heater not using a HCl CEMS.        one-hour average pH and the 30-day
                                     rolling average liquid flow rate at
                                     or above the lowest one-hour
                                     average liquid flow rate measured
                                     during the 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
 boiler or process heater not        equal to 10 percent opacity or the
 using a PM CPMS.                    highest hourly average opacity
                                     reading measured during the
                                     performance test run demonstrating
                                     compliance with the PM (or TSM)
                                     emission limitation (daily block
                                     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
 control on a boiler or process      process heaters that operate dry
 heater not using a PM CPMS.         control systems (i.e., an ESP
                                     without a wet scrubber). Existing
                                     and new boilers and process heaters
                                     must maintain opacity to less than
                                     or equal to 10 percent opacity or
                                     the highest hourly average opacity
                                     reading measured during the
                                     performance test run demonstrating
                                     compliance with the PM (or TSM)
                                     emission limitation (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
 injection control on a boiler or    carbon injection rate as defined in
 process heater not using a          Sec.   63.7575 of this subpart.
 mercury CEMS.
6. Any other add-on air pollution   This option is for boilers and
 control type on a boiler or         process heaters that operate dry
 process heater not using a PM       control systems. Existing and new
 CPMS.                               boilers and process heaters must
                                     maintain opacity to less than or
                                     equal to 10 percent opacity or the
                                     highest hourly average opacity
                                     reading measured during the
                                     performance test run demonstrating
                                     compliance with the PM (or TSM)
                                     emission limitation (daily block
                                     average).
7. Performance testing............  For boilers and process heaters that
                                     demonstrate compliance with a
                                     performance test, maintain the 30-
                                     day rolling average operating load
                                     of each unit such that it does not
                                     exceed 110 percent of the highest
                                     hourly average operating load
                                     recorded during the performance
                                     test.
8. 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 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).
9. SO2 CEMS.......................  For boilers or process heaters
                                     subject to an HCl emission limit
                                     that demonstrate compliance with an
                                     SO2 CEMS, maintain the 30-day
                                     rolling average SO2 emission rate
                                     at or below the highest hourly
                                     average SO2 concentration measured
                                     during the HCl performance test, as
                                     specified in Table 8.
------------------------------------------------------------------------
\a\ A wet acid gas scrubber is a control device that removes acid gases
  by contacting the combustion gas with an alkaline slurry or solution.
  Alkaline reagents include, but not limited to, lime, limestone and
  sodium.


0
25. Table 5 to subpart DDDDD of part 63 is amended by revising the 
heading to the third column and adding footnote ``a'' to read as 
follows:
    As stated in Sec.  63.7520, you must comply with the following 
requirements for performance testing for existing, new or reconstructed 
affected sources:

  Table 5 to Subpart DDDDD of Part 63--Performance Testing Requirements
------------------------------------------------------------------------
  To conduct a performance test
 for the following pollutant . .    You  must . . .        Using, as
                .                                      appropriate . . .
------------------------------------------------------------------------
 
                               * * * * *
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.


0
26. Table 6 to subpart DDDDD of part 63 is revised to read as follows:
    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:

[[Page 72826]]



     Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
------------------------------------------------------------------------
To conduct a fuel analysis for
 the following pollutant . . .    You must . . .        Using . . .
 
------------------------------------------------------------------------
1. Mercury....................  a. Collect fuel    Procedure in Sec.
                                 samples.           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
                                                    solid), or ASTM
                                                    D4177 \a\ (for
                                                    liquid), or ASTM
                                                    D4057 \a\ (for
                                                    liquid), or
                                                    equivalent.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.7521(d) or
                                                    equivalent.
                                c. Prepare         EPA SW-846-3050B \a\
                                 composited fuel    (for solid samples),
                                 samples.           ASTM 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  ASTM D5865 \a\ (for
                                 content of the     coal) or ASTM E711
                                 fuel type.         \a\ (for biomass),
                                                    or ASTM D5864 \a\
                                                    for liquids and
                                                    other solids, or
                                                    ASTM D240 \a\ or
                                                    equivalent.
                                e. Determine       ASTM D3173,\a\ ASTM
                                 moisture content   E871,\a\ or ASTM
                                 of the fuel type.  D5864,\a\ or ASTM
                                                    D240, or ASTM D95
                                                    \a\ (for liquid
                                                    fuels), or ASTM
                                                    D4006 \a\ (for
                                                    liquid fuels), or
                                                    equivalent.
                                f. Measure         ASTM D6722 \a\ (for
                                 mercury            coal), EPA SW-846-
                                 concentration in   7471B \a\ or EPA
                                 fuel sample.       1631 or EPA 1631E
                                                    (for solid samples),
                                                    or EPA SW-846-7470A
                                                    \a\ (for liquid
                                                    samples), or EPA 821-
                                                    R-01-013 (for liquid
                                                    or solid), or
                                                    equivalent.
                                g. Convert         For fuel mixtures use
                                 concentration      Equation 8 in Sec.
                                 into units of      63.7530.
                                 pounds of
                                 mercury per
                                 MMBtu of heat
                                 content.
2. HCl........................  a. Collect fuel    Procedure in Sec.
                                 samples.           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  Procedure in Sec.
                                 samples.           63.7521(d) or
                                                    equivalent.
                                c. Prepare         EPA SW-846-3050B \a\
                                 composited fuel    (for solid samples),
                                 samples.           ASTM D2013/D2013M
                                                    \a\ (for coal), or
                                                    ASTM D5198 \a\ (for
                                                    biomass), or EPA
                                                    3050 \a\ or
                                                    equivalent.
                                d. Determine heat  ASTM D5865 \a\ (for
                                 content of the     coal) or ASTM E711
                                 fuel type.         \a\ (for biomass),
                                                    ASTM D5864, ASTM
                                                    D240 \a\ or
                                                    equivalent.
                                e. Determine       ASTM D3173 \a\ or
                                 moisture content   ASTM E871,\a\ or
                                 of the fuel type.  D5864,\a\ or ASTM
                                                    D240,\a\ or ASTM D95
                                                    \a\ (for liquid
                                                    fuels), or ASTM
                                                    D4006 \a\ (for
                                                    liquid fuels), or
                                                    equivalent.
                                f. Measure         EPA SW-846-9250,\a\
                                 chlorine           ASTM D6721,\a\ ASTM
                                 concentration in   D4208 \a\ (for
                                 fuel sample.       coal), or EPA SW-846-
                                                    5050 \a\ 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         For fuel mixtures use
                                 concentrations     Equation 7 in Sec.
                                 into units of      63.7530 and convert
                                 pounds of HCl      from chlorine to HCl
                                 per MMBtu of       by multiplying by
                                 heat content.      1.028.
3. Mercury Fuel Specification   a. Measure         Method 30B (M30B) at
 for other gas 1 fuels.          mercury            40 CFR part 60,
                                 concentration in   appendix A-8 of this
                                 the fuel sample    chapter or ASTM
                                 and convert to     D5954,\a\ ASTM
                                 units of           D6350,\a\ ISO 6978-
                                 micrograms per     1:2003(E),\a\ or ISO
                                 cubic meter, or    6978-2:2003(E),\a\
                                                    or EPA-1631 \a\ or
                                                    equivalent.
                                b. Measure         Method 29, 30A, or
                                 mercury            30B (M29, M30A, or
                                 concentration in   M30B) at 40 CFR part
                                 the exhaust gas    60, appendix A-8 of
                                 when firing only   this chapter or
                                 the other gas 1    Method 101A or
                                 fuel is fired in   Method 102 at 40 CFR
                                 the boiler or      part 61, appendix B
                                 process heater.    of this chapter, or
                                                    ASTM Method D6784
                                                    \a\ or equivalent.
4. TSM........................  a. Collect fuel    Procedure in Sec.
                                 samples.           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  Procedure in Sec.
                                 samples.           63.7521(d) or
                                                    equivalent.
                                c. Prepare         EPA SW-846-3050B \a\
                                 composited fuel    (for solid samples),
                                 samples.           ASTM D2013/D2013M
                                                    \a\ (for coal), ASTM
                                                    D5198 \a\ or TAPPI
                                                    T266 \a\ (for
                                                    biomass), or EPA
                                                    3050 \a\ or
                                                    equivalent.
                                d. Determine heat  ASTM D5865 \a\ (for
                                 content of the     coal) or ASTM E711
                                 fuel type.         \a\ (for biomass),
                                                    or ASTM D5864 \a\
                                                    for liquids and
                                                    other solids, or
                                                    ASTM D240 \a\ or
                                                    equivalent.
                                e. Determine       ASTM D3173 \a\ or
                                 moisture content   ASTM E871,\a\ or
                                 of the fuel type.  D5864, 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 TSM     ASTM D3683,\a\ or
                                 concentration in   ASTM D4606,\a\ or
                                 fuel sample.       ASTM D6357 \a\ or
                                                    EPA 200.8 \a\ or EPA
                                                    SW-846-6020,\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         For fuel mixtures use
                                 concentrations     Equation 9 in Sec.
                                 into units of      63.7530.
                                 pounds of TSM
                                 per MMBtu of
                                 heat content.
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.


[[Page 72827]]


0
27. Table 7 to subpart DDDDD of part 63 is revised to read as follows:
    As stated in Sec.  63.7520, you must comply with the following 
requirements for establishing operating limits:

                     Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits a b
----------------------------------------------------------------------------------------------------------------
                                  And your operating                                           According to the
    If you have an applicable      limits are based     You must . . .        Using . . .          following
    emission limit for . . .           on . . .                                                  requirements
----------------------------------------------------------------------------------------------------------------
1. PM, TSM, or mercury..........  a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       scrubber pressure   collect scrubber
                                   parameters.         minimum scrubber    drop and liquid     pressure drop and
                                                       pressure drop and   flow rate           liquid flow rate
                                                       minimum flow rate   monitors and the    data every 15
                                                       operating limit     PM, TSM, or         minutes during
                                                       according to Sec.   mercury             the entire period
                                                         63.7530(b).       performance test.   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. Electrostatic    i. Establish a      (1) Data from the   (a) You must
                                   precipitator        site-specific       voltage and         collect secondary
                                   operating           minimum total       secondary           voltage and
                                   parameters          secondary           amperage monitors   secondary
                                   (option only for    electric power      during the PM or    amperage for each
                                   units that          input according     mercury             ESP cell and
                                   operate wet         to Sec.             performance test.   calculate total
                                   scrubbers).         63.7530(b).                             secondary
                                                                                               electric power
                                                                                               input data 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.
                                  c. Opacity........  i. Establish a      (1) Data from the   (a) You must
                                                       site-specific       opacity             collect opacity
                                                       maximum opacity     monitoring system   readings every 15
                                                       level.              during the PM       minutes during
                                                                           performance test.   the entire period
                                                                                               of the
                                                                                               performance
                                                                                               tests.
                                                                                              (b) Determine the
                                                                                               average hourly
                                                                                               opacity reading
                                                                                               for each
                                                                                               performance test
                                                                                               run by computing
                                                                                               the hourly
                                                                                               averages using
                                                                                               all of the 15-
                                                                                               minute readings
                                                                                               taken during each
                                                                                               performance test
                                                                                               run.
                                                                                              (c) Determine the
                                                                                               highest hourly
                                                                                               average opacity
                                                                                               reading measured
                                                                                               during the test
                                                                                               run demonstrating
                                                                                               compliance with
                                                                                               the PM (or TSM)
                                                                                               emission
                                                                                               limitation.
2. HCl..........................  a. Wet scrubber     i. Establish site-  (1) Data from the   (a) You must
                                   operating           specific minimum    pH and liquid       collect pH and
                                   parameters.         effluent pH and     flow-rate           liquid flow-rate
                                                       flow rate           monitors and the    data every 15
                                                       operating limits    HCl performance     minutes during
                                                       according to Sec.   test.               the entire period
                                                         63.7530(b).                           of 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.

[[Page 72828]]

 
                                  b. Dry scrubber     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       sorbent injection   collect sorbent
                                   parameters.         minimum sorbent     rate monitors and   injection rate
                                                       injection rate      HCl or mercury      data every 15
                                                       operating limit     performance test.   minutes during
                                                       according to Sec.                       the entire period
                                                         63.7530(b). If                        of the
                                                       different acid                          performance
                                                       gas sorbents are                        tests.
                                                       used during the                        (b) Determine the
                                                       HCl performance                         hourly average
                                                       test, the average                       sorbent injection
                                                       value for each                          rate by computing
                                                       sorbent becomes                         the hourly
                                                       the site-specific                       averages using
                                                       operating limit                         all of the 15-
                                                       for that sorbent.                       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      (1) Data from SO2   (a) You must
                                   Maximum             site-specific       CEMS and the HCl    collect the SO2
                                   SO2emission rate.   maximum             performance test.   emissions data
                                                       SO2emission rate                        according to Sec.
                                                       operating limit                           63.7525(m)
                                                       according to Sec.                       during the most
                                                         63.7530(b).                           recent HCl
                                                                                               performance
                                                                                               tests.
                                                                                              (b) The maximum
                                                                                               SO2emission rate
                                                                                               is equal to the
                                                                                               highest hourly
                                                                                               average
                                                                                               SO2emission rate
                                                                                               measured during
                                                                                               the most recent
                                                                                               HCl performance
                                                                                               tests.
3. Mercury......................  a. Activated        i. Establish a      (1) Data from the   (a) You must
                                   carbon injection.   site-specific       activated carbon    collect activated
                                                       minimum activated   rate monitors and   carbon injection
                                                       carbon injection    mercury             rate data every
                                                       rate operating      performance test.   15 minutes during
                                                       limit according                         the entire period
                                                       to Sec.                                 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.

[[Page 72829]]

 
4. Carbon monoxide for which      a. Oxygen.........  i. Establish a      (1) Data from the   (a) You must
 compliance is demonstrated by a                       unit-specific       oxygen analyzer     collect oxygen
 performance test.                                     limit for minimum   system specified    data every 15
                                                       oxygen level        in Sec.             minutes during
                                                       according to Sec.   63.7525(a).         the entire period
                                                         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      (1) Data from the   (a) You must
 compliance is demonstrated by a   process heater      unit specific       operating load      collect operating
 performance test.                 operating load.     limit for maximum   monitors or from    load or steam
                                                       operating load      steam generation    generation data
                                                       according to Sec.   monitors.           every 15 minutes
                                                         63.7520(c).                           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
                                                                                               highest hourly
                                                                                               average of the
                                                                                               three test run
                                                                                               averages during
                                                                                               the performance
                                                                                               test, and
                                                                                               multiply this by
                                                                                               1.1 (110 percent)
                                                                                               as your operating
                                                                                               limit.
----------------------------------------------------------------------------------------------------------------
\a\ Operating limits must be confirmed or reestablished during performance tests.
\b\ 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. For a minimum
  oxygen level, if you conduct multiple performance tests, you must set the minimum oxygen level at the lower of
  the minimum values established during the performance tests.


0
28. Table 8 to subpart DDDDD of part 63 is amended by:
0
a. Revising the entries for rows ``1.c'' and ``3.''
0
b. Adding row ``8.d''.
0
c. Revising the entries for rows``9.a,'' ``9.c,'' ``10,'' and ``11.c.''
    The revisions and addition read as follows:
    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:

Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
------------------------------------------------------------------------
  If you must meet the following
 operating limits or work practice     You must demonstrate continuous
          standards . . .                    compliance by . . .
------------------------------------------------------------------------
 
                              * * * * * * *
1. Opacity........................  c. Maintaining daily block average
                                     opacity to less than or equal to 10
                                     percent or the highest hourly
                                     average opacity reading measured
                                     during the performance test run
                                     demonstrating compliance with the
                                     PM (or TSM) emission limitation.
 
                              * * * * * * *
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.
 
                              * * * * * * *
8. Emission limits using fuel       d. Calculate the HCI, mercury, and/
 analysis.                           or TSM emission rate from the
                                     boiler or process heater in units
                                     of lb/MMBtu using Equation 15 and
                                     Equations 17, 18, and/or 19 in Sec.
                                       63.7530.

[[Page 72830]]

 
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).
 
                              * * * * * * *
11. SO2 emissions using SO2 CEMS..  c. Maintain the 30-day rolling
                                     average oxygen content at or above
                                     the lowest hourly average oxygen
                                     level measured during the 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
                                    c. 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
                                     performance test according to Sec.
                                      63.7520(c).
 
                              * * * * * * *
                                    c. Maintaining the 30-day rolling
                                     average SO2 CEMS emission rate to a
                                     level at or below the highest
                                     hourly SO2 rate measured during the
                                     HCl performance test according to
                                     Sec.   63.7530.
------------------------------------------------------------------------


0
29. Table 9 to subpart DDDDD of part 63 is amended by revising the 
entries for ``1.b'' and ``1.c'' to read as follows:
    As stated in Sec.  63.7550, you must comply with the following 
requirements for reports:

                           Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
----------------------------------------------------------------------------------------------------------------
                                                                                                 You must submit
        You must submit a(n)                        The report must contain . . .                 the report . .
                                                                                                        .
----------------------------------------------------------------------------------------------------------------
1. Compliance report................  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
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


0
30. Table 10 to subpart DDDDD of part 63 is amended by revising the 
rows associated with ``Sec.  63.6(g)'' and ``Sec.  63.6(h)(2) to 
(h)(9)'' to read as follows:
    As stated in Sec.  63.7565, you must comply with the applicable 
General Provisions according to the following:

[[Page 72831]]



           Table 10 to Subpart DDDDD of Part 63--Applicability of General Provisions to Subpart DDDDD
----------------------------------------------------------------------------------------------------------------
                Citation                            Subject                     Applies to subpart DDDDD
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Sec.   63.6(g)..........................  Use of alternative           Yes, except Sec.   63.7555(d)(13)
                                           standards.                   specifies the procedure for application
                                                                        and approval of an alternative timeframe
                                                                        with the PM controls requirement in the
                                                                        startup work practice (2).
 
                                                  * * * * * * *
Sec.   63.6(h)(2) to (h)(9).............  Determining compliance with  No. Subpart DDDDD specifies opacity as an
                                           opacity emission standards.  operating limit not an emission
                                                                        standard.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


0
31. Table 11 to subpart DDDDD of part 63 is revised to read as follows:

 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,         Using this specified
     in this subcategory . . .          pollutants . . .      except during periods  sampling volume or test run
                                                                 of startup and             duration . . .
                                                                 shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories        a. HCl................  0.022 lb per MMBtu of   For M26A, collect a minimum
 designed to burn solid fuel.                                 heat input.             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 minimum
 designed to burn solid fuel that                             MMBtu of heat input.    of 4 dscm per run; for
 combust at least 10 percent                                                          M30A or M30B, collect a
 biomass/bio-based solids on an                                                       minimum sample as
 annual heat input basis and less                                                     specified in the method;
 than 10 percent coal/solid fossil                                                    for ASTM D6784 \b\ collect
 fuels on an annual heat input                                                        a minimum of 4 dscm.
 basis.
3. Units in all subcategories        a. Mercury............  2.0E-06 lb per MMBtu    For M29, collect a minimum
 designed to burn solid fuel that                             of heat input.          of 4 dscm per run; for
 combust at least 10 percent coal/                                                    M30A or M30B, collect a
 solid fossil fuels on an annual                                                      minimum sample as
 heat input basis and less than 10                                                    specified in the method;
 percent biomass/bio-based solids                                                     for ASTM D6784 \b\ collect
 on an annual heat input basis.                                                       a minimum of 4 dscm.
4. Units design to burn coal/solid   a. Filterable PM (or    1.1E-03 lb per MMBtu    Collect a minimum of 3 dscm
 fossil fuel.                         TSM).                   of heat input; or       per run.
                                                              (2.3E-05 lb per MMBtu
                                                              of heat input).
5. Pulverized coal boilers designed  a. Carbon monoxide      130 ppm by volume on a  1 hr minimum sampling time.
 to burn coal/solid fossil fuel.      (CO) (or CEMS).         dry basis corrected
                                                              to 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 time.
 solid fossil fuel.                                           dry basis corrected
                                                              to 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).

[[Page 72832]]

 
7. Fluidized bed units designed to   a. CO (or CEMS).......  130 ppm by volume on a  1 hr minimum sampling time.
 burn coal/solid fossil fuel.                                 dry basis corrected
                                                              to 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 time.
 integrated heat exchanger designed                           dry basis corrected
 to burn coal/solid fossil fuel.                              to 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 time.
 designed to burn wet biomass fuel.                           dry basis corrected
                                                              to 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    Collect a minimum of 2 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (2.6E-05 lb per MMBtu
                                                              of heat input).
10. Stokers/sloped grate/others      a. CO.................  560 ppm by volume on a  1 hr minimum sampling time.
 designed to burn kiln-dried                                  dry basis corrected
 biomass fuel.                                                to 3 percent oxygen,
                                                              3-run average.
                                     b. Filterable PM (or    3.0E-02 lb per MMBtu    Collect a minimum of 2 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (4.0E-03 lb per MMBtu
                                                              of heat input).
11. Fluidized bed units designed to  a. CO (or CEMS).......  230 ppm by volume on a  1 hr minimum sampling time.
 burn biomass/bio-based solids.                               dry basis corrected
                                                              to 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    Collect a minimum of 3 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (8.3E-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 time.
 burn biomass/bio-based solids.                               a dry basis corrected
                                                              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    Collect a minimum of 2 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (6.5E-03 lb per MMBtu
                                                              of heat input).

[[Page 72833]]

 
13. Dutch Ovens/Pile burners         a. CO (or CEMS).......  1,010 ppm by volume on  1 hr minimum sampling time.
 designed to burn biomass/bio-based                           a dry basis corrected
 solids.                                                      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    Collect a minimum of 3 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (3.9E-05 lb per MMBtu
                                                              of heat input).
14. Fuel cell units designed to      a. CO.................  910 ppm by volume on a  1 hr minimum sampling time.
 burn biomass/bio-based solids.                               dry basis corrected
                                                              to 3 percent oxygen,
                                                              3-run average.
                                     b. Filterable PM (or    2.0E-02 lb per MMBtu    Collect a minimum of 2 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (2.9E-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 time.
 designed to burn biomass/bio-based                           a dry basis corrected
 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    Collect a minimum of 3 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (4.4E-04 lb per MMBtu
                                                              of heat input).
16. Units designed to burn liquid    a. HCl................  4.4E-04 lb per MMBtu    For M26A: Collect a minimum
 fuel.                                                        of heat input.          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 minimum
                                                              MMBtu of heat input.    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 time.
 liquid fuel.                                                 dry basis corrected
                                                              to 3 percent oxygen,
                                                              3-run average.
                                     b. Filterable PM (or    1.3E-02 lb per MMBtu    Collect a minimum of 3 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (7.5E-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 time.
 liquid fuel.                                                 dry basis corrected
                                                              to 3 percent oxygen,
                                                              3-run average.
                                     b. Filterable PM (or    2.0E-03 \a\ lb per      Collect a minimum of 3 dscm
                                      TSM).                   MMBtu of heat input;    per run.
                                                              or (2.9E-05 lb per
                                                              MMBtu of heat input).
19. Units designed to burn liquid    a. CO.................  130 ppm by volume on a  1 hr minimum sampling time.
 fuel that are non-continental                                dry basis corrected
 units.                                                       to 3 percent oxygen,
                                                              3-run average based
                                                              on stack test.
                                     b. Filterable PM (or    2.3E-02 lb per MMBtu    Collect a minimum of 4 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (8.6E-04 lb per MMBtu
                                                              of heat input).

[[Page 72834]]

 
20. Units designed to burn gas 2     a. CO.................  130 ppm by volume on a  1 hr minimum sampling time.
 (other) gases.                                               dry basis corrected
                                                              to 3 percent oxygen,
                                                              3-run average.
                                     b. HCl................  1.7E-03 lb per MMBtu    For M26A, Collect a minimum
                                                              of heat input.          of 2 dscm per run; for
                                                                                      M26, collect a minimum of
                                                                                      240 liters per run.
                                     c. Mercury............  7.9E-06 lb per MMBtu    For M29, collect a minimum
                                                              of heat input.          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    Collect a minimum of 3 dscm
                                      TSM).                   of heat input; or       per run.
                                                              (2.1E-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 an alternative test method under Sec.   63.7 of this chapter, in order that
  compliance with the carbon monoxide emissions limit be determined using carbon dioxide as a diluent correction
  in place of oxygen at 3%. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
  appropriate CO2 correction percentage for the fuel type burned in the unit, and must also take into account
  that the 3% oxygen correction is to be done on a dry basis. The alternative test method request must account
  for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
  scrubber media, etc.


0
32. 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).
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).

[[Page 72835]]

 
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        b. Filterable PM (or    basis corrected to 3        time.
 biomass fuel.                       TSM).                  percent oxygen, 3-run      Collect a minimum of 2
                                                            average.                    dscm per run.
                                                           3.0E-02 lb per MMBtu of
                                                            heat input; or (4.0E-03
                                                            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.     b. Filterable PM (or    basis corrected to 3        time.
                                     TSM).                  percent oxygen, 3-run      Collect a minimum of 2
                                                            average.                    dscm per run.
                                                           2.0E-02 lb per MMBtu of
                                                            heat input; or (2.9E-05
                                                            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.
                                    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, 3-run
                                                            average.
                                    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).

[[Page 72836]]

 
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, 3-run
                                                            average.
                                    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 an alternative test method under Sec.   63.7 of this chapter, in order that
  compliance with the carbon monoxide emissions limit be determined using carbon dioxide as a diluent correction
  in place of oxygen at 3%. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
  appropriate CO2 correction percentage for the fuel type burned in the unit, and must also take into account
  that the 3% oxygen correction is to be done on a dry basis. The alternative test method request must account
  for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
  scrubber media, etc.


0
33. Table 13 to subpart DDDDD of part 63 is amended by:
0
a. Revising the heading of the table.
0
b. Revising rows ``2.a'', ``3.a'', ``4.a'', ``5.a'', ``6.a'', ``8.a'', 
``9.a'', ``10.a'', ``12.a'', ``14.a'', ``15.a'', and ``16.a''.
0
c. Adding footnote ``c''.
    The revisions and addition read as follows:

 Table 13 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
     Heaters That Commenced Construction or Reconstruction After December 23, 2011, and Before April 1, 2013
----------------------------------------------------------------------------------------------------------------
                                                                The emissions must not
                                                                 exceed the following      Using this specified
If your boiler or process heater is     For the following      emission limits, except      sampling volume or
     in this subcategory . . .          pollutants . . .      during periods of startup    test run duration . .
                                                                  and shutdown . . .                 .
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
2. Pulverized coal boilers designed  a. Carbon monoxide      130 ppm by volume on a dry   1 hr minimum sampling
 to burn coal/solid fossil fuel.      (CO) (or CEMS).         basis corrected to 3         time.
                                                              percent oxygen, 3-run
                                                              average; or (320 ppm by
                                                              volume on a dry basis
                                                              corrected to 3 percent
                                                              oxygen,\c\ 30-day rolling
                                                              average).
 
                                                  * * * * * * *
3. 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).
 
                                                  * * * * * * *
4. 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).
 
                                                  * * * * * * *
5. Fluidized bed units with an       a. CO (or CEMS).......  140 ppm by volume on a dry   1 hr minimum sampling
 integrated heat exchanger designed                           basis corrected to 3         time.
 to burn coal/solid fossil fuel.                              percent oxygen, 3-run
                                                              average; or (150 ppm by
                                                              volume on a dry basis
                                                              corrected to 3 percent
                                                              oxygen,\c\ 30-day rolling
                                                              average).

[[Page 72837]]

 
 
                                                  * * * * * * *
6. 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 (410 ppm by
                                                              volume on a dry basis
                                                              corrected to 3 percent
                                                              oxygen,\c\ 10-day rolling
                                                              average).
 
                                                  * * * * * * *
8. Fluidized bed units designed to   a. CO (or CEMS).......  230 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).
 
                                                  * * * * * * *
9. 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).
 
                                                  * * * * * * *
10. Dutch Ovens/Pile burners         a. CO (or CEMS).......  810 ppm by volume on a dry   1 hr minimum sampling
 designed to burn biomass/bio-based                           basis corrected to 3         time.
 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).
 
                                                  * * * * * * *
12. Hybrid suspension grate boiler   a. CO (or CEMS).......  1,500 ppm by volume on a     1 hr minimum sampling
 designed to burn biomass/bio-based                           dry basis corrected to 3     time.
 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).
 
                                                  * * * * * * *
14. Units designed to burn heavy     a. CO (or CEMS).......  130 ppm by volume on a dry   1 hr minimum sampling
 liquid fuel.                                                 basis corrected to 3         time.
                                                              percent oxygen, 3-run
                                                              average; or (18 ppm by
                                                              volume on a dry basis
                                                              corrected to 3 percent
                                                              oxygen,\c\ 10-day rolling
                                                              average).
 
                                                  * * * * * * *
15. Units designed to burn light     a. CO (or CEMS).......  130 \a\ ppm by volume on a   1 hr minimum sampling
 liquid fuel.                                                 dry basis corrected to 3     time.
                                                              percent oxygen; or (60 ppm
                                                              by volume on a dry basis
                                                              corrected to 3 percent
                                                              oxygen,\c\ 1-day block
                                                              average).
 
                                                  * * * * * * *
16. 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; or (91 ppm by volume
                                                              on a dry basis corrected
                                                              to 3 percent oxygen, 3-
                                                              hour rolling average).
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
* * * * * * *
\c\ An owner or operator may request an alternative test method under Sec.   63.7 of this chapter, in order that
  compliance with the carbon monoxide emissions limit be determined using carbon dioxide as a diluent correction
  in place of oxygen at 3%. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
  appropriate CO2 correction percentage for the fuel type burned in the unit, and must also take into account
  that the 3% oxygen correction is to be done on a dry basis. The alternative test method request must account
  for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection,
  scrubber media, etc.

[FR Doc. 2015-29186 Filed 11-19-15; 8:45 am]
BILLING CODE 6560-50-P