[Federal Register Volume 81, Number 178 (Wednesday, September 14, 2016)]
[Rules and Regulations]
[Pages 63112-63131]
[FR Doc No: 2016-21334]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2006-0790; FRL-9951-64-OAR]
RIN 2060-AS10

National Emission Standards for Hazardous Air Pollutants for Area
Sources: Industrial, Commercial, and Institutional Boilers

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 announced
reconsideration on January 21, 2015, that pertain to certain aspects of
the February 1, 2013, final amendments to the ``National Emission
Standards for Hazardous Air Pollutants for Area Sources: Industrial,
Commercial, and Institutional Boilers'' (Area Source Boilers Rule). The
EPA is retaining the subcategory and separate requirements for limited-
use boilers, consistent with the February 2013 final rule. In addition,
the EPA is amending three reconsidered provisions regarding: The
alternative particulate matter (PM) standard for new oil-fired boilers;
performance testing for PM for certain boilers based on their initial
compliance test; and fuel sampling for mercury (Hg) for certain coal-
fired boilers based on their initial compliance demonstration,
consistent with the alternative provisions for which comment was
solicited in the January 2015 proposal. The EPA is making minor changes
to the proposed definitions of startup and shutdown based on comments
received. This final action also addresses a limited number of
technical corrections and clarifications on the rule, including removal
of the affirmative defense for malfunction in light of a court decision
on the issue. These corrections will clarify and improve the
implementation of the February 2013 final Area Source Boilers Rule. In
this action, the EPA is also denying the requests for reconsideration
with respect to the issues raised in the petitions for reconsideration
of the final Area Source Boilers Rule for which reconsideration was not
granted.

DATES: This final rule is effective on September 14, 2016.

ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2006-0790. All documents in the docket are
listed on the http://www.regulations.gov Web site. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information or other information whose disclosure
is restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy

form. Publicly available docket materials are available either
electronically through 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: Ms. Mary Johnson, Energy Strategies
Group, Sector Policies and Programs Division (D243-01), Environmental
Protection Agency, Research Triangle Park, North Carolina 27711;
telephone number:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; email
address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:
    Acronyms and Abbreviations. A number of acronyms and abbreviations
are used in this preamble. While this may not be an exhaustive list, to
ease the reading of this preamble and for reference purposes, the
following terms and acronyms are defined as follows:

ACC American Chemistry Council
AF&PA American Forest and Paper Association
Btu British thermal unit
CAA Clean Air Act
CEMS Continuous emissions monitoring systems
CFR Code of Federal Regulations
CIBO Council of Industrial Boiler Owners
CO Carbon monoxide
CRA Congressional Review Act
EGU Electric Utility Steam Generating Unit
EPA U.S. Environmental Protection Agency
GACT Generally available control technology
HAP Hazardous air pollutant(s)
Hg Mercury
ICI Industrial, Commercial, and Institutional
ICR Information collection request
MACT Maximum achievable control technology
MMBtu/hr Million British thermal units per hour
NAICS North American Industrial Classification System
NESHAP National Emission Standards for Hazardous Air Pollutants
NRDC Natural Resources Defense Council
NSPS New Source Performance Standards
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
PM Particulate matter
ppm Parts per million
PRA Paperwork Reduction Act
RFA Regulatory Flexibility Act
The Court United States Court of Appeals for the District of
Columbia Circuit
TSM Total selected metals
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 on Issues Reconsidered
    A. Definitions of Startup and Shutdown
    B. Alternative PM Standard for New Oil-Fired Boilers That
Combust Low-Sulfur Oil
    C. Establishment of a Subcategory and Separate Requirements for
Limited-Use Boilers
    D. Establishment of a Provision That Eliminates Further
Performance Testing for PM for Certain Boilers Based on Their
Initial Compliance Test
    E. Establishment of a Provision That Eliminates Further Fuel
Sampling for Mercury for Certain Coal-Fired Boilers Based on Their
Initial Compliance Demonstration
IV. Technical Corrections and Clarifications
    A. Affirmative Defense for Violation of Emission Standards
During Malfunction
    B. Definition of Coal
    C. Other Corrections and Clarifications
V. Other Actions We Are Taking
    A. Request for Reconsideration of the Energy Assessment
Requirement
    B. Request for Clarification of the Averaging Period for CO
VI. Impacts Associated With 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)
    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
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                                      North
                                    American
                                   Industrial    Examples of potentially
            Category             Classification     regulated entities
                                      System
                                  (NAICS) code
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Any area source facility using              321  Manufacturers of lumber
 a boiler as defined in the                  11   and wood products.
 final rule.                                     Agriculture,
                                                  greenhouses.
                                            311  Food manufacturing.
                                            327  Nonmetallic mineral
                                                  product manufacturing.
                                            424  Wholesale trade,
                                                  nondurable goods.
                                            531  Real estate.
                                            611  Educational services.
                                            813  Religious, civic,
                                                  professional, and
                                                  similar organizations.
                                             92  Public administration.
                                            722  Food services and
                                                  drinking places.
                                             62  Health care and social
                                                  assistance.
                                          22111  Electric power
                                                  generation.
------------------------------------------------------------------------

    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 63.11193 of subpart JJJJJJ. If you have any questions regarding the
applicability of this final action to a particular entity, consult
either the air permitting authority for the entity or your EPA Regional
representative as listed in 40 CFR 63.13 (General Provisions).

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

    The docket number for this final action regarding the Area Source
Boilers Rule (40 CFR part 63, subpart JJJJJJ) is Docket ID No. EPA-HQ-
OAR-2006-0790.
    In addition to being available in the docket, an electronic copy of
this document will also be available on the World Wide Web (WWW).
Following signature, a copy of this document will be posted at https://www3.epa.gov/ttn/atw/boiler/boilerpg.html.

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
the U.S. Court of Appeals for the District of Columbia Circuit (the
Court) by November 13, 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
control of hazardous air pollutants (HAP) from industrial, commercial,
and institutional (ICI) boilers located at area sources of HAP--the
Area Source Boilers Rule (76 FR 15554). On February 1, 2013, the EPA
promulgated final amendments to the Area Source Boilers Rule (78 FR
7488). Following that action, the Administrator received three
petitions for reconsideration that identified certain issues that
petitioners claimed warranted further opportunity for public comment.
    The EPA received a petition dated April 1, 2013, from the American
Forest and Paper Association (AF&PA), on their behalf and on behalf of
the 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 the U.S. Chamber of Commerce. The
EPA received a petition dated April 2, 2013, from the Council of
Industrial Boiler Owners (CIBO) and the American Chemistry Council
(ACC). Finally, the EPA received a petition dated April 2, 2013, from
Earthjustice, on behalf of the Sierra Club, Clean Air Council,
Partnership for Policy Integrity, Louisiana Environmental Action
Network and the Environmental Integrity Project.
    In response to the petitions, the EPA reconsidered and requested
comment on five provisions of the February 1, 2013, final amendments to
the Area Source Boilers Rule. The EPA published the proposed notice of
reconsideration in the Federal Register on January 21, 2015 (80 FR
2871).
    In this rulemaking, the EPA is taking final action with respect to
the five issues raised by petitioners in their petitions for
reconsideration on the 2013 final amendments to the Area Source Boilers
Rule and for which reconsideration was granted. Section III of this
preamble presents the EPA's final decision on these issues and
discusses our rationale for the decisions. 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. Most of the
corrections and clarifications remain the same as described in the
proposed notice of reconsideration on January 21, 2015, and those
changes are being finalized without further discussion. However, the
EPA has refined its approach to some issues 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 and are discussed in
section IV of this preamble. For a complete summary of the comments
received and our responses thereto, please refer to the document
``Response to 2015 Reconsideration Comments for Industrial, Commercial,
and Institutional Boilers at Area Sources: National Emission Standards
for Hazardous Air Pollutants'' located in the docket.

III. Summary of Final Action on Issues Reconsidered

    The five reconsideration issues for which amendments are being
finalized in this rulemaking are: (1) Definitions of startup and
shutdown; (2) alternative PM standard for new oil-fired boilers that
combust low-sulfur oil; (3) establishment of a subcategory and separate
requirements for limited-use boilers; (4) provision that eliminates
further performance testing for PM for certain boilers based on their
initial compliance test; and (5) provision that eliminates further fuel
sampling for Hg for certain coal-fired boilers based on their initial
compliance demonstration. Each of these issues is discussed in detail
in the following sections of this preamble.

A. Definitions of Startup and Shutdown

    In the February 1, 2013, final amendments to the Area Source
Boilers Rule, the EPA finalized revisions to the definitions of startup
and shutdown, 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 public lacked an opportunity to comment
on the amended definitions and that the definitions were not
sufficiently clear. In response to these petitions, in the January 21,
2015, proposed notice of reconsideration (80 FR 2871), we solicited
comment on the definitions of startup and shutdown that were
promulgated in the February 2013 final rule as well as additional
revisions we proposed to make to those definitions. Specifically, we
proposed to revise the February 2013 definition of startup to include
an alternate definition of startup. The alternate definition clarified
when startup begins for new boilers to address pre-startup testing
activities that are done as part of installing a new boiler and when
startup ends for first-ever startups as well as startups occurring
after shutdown events. The alternate definition of startup as well as
the definition of shutdown 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 this 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 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 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 for the purpose of supplying useful thermal energy for heating,
cooling, or process purposes or for producing electricity, and ending 4
hours after the boiler supplies useful thermal energy for those
purposes.
    In the February 1, 2013, final rule, the EPA defined ``shutdown''
to mean the cessation of operation of a boiler for any purpose, and
said this period begins either when none of the steam or heat 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, 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 no longer makes useful thermal energy
(rather than referring to steam or heat supplied by the boiler) for
heating, cooling, or process purposes or generates electricity, or when
no fuel is being fed to the boiler, whichever is earlier. In this
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 no longer supplies
useful thermal energy (such as steam or hot water) for heating,
cooling, or process purposes or generates electricity, or when no fuel
is being fed to the boiler, whichever is earlier. Under this
definition, shutdown ends when the boiler no longer supplies useful
thermal energy (such as steam or hot water) for heating, cooling, or
process purposes or generates electricity, and no fuel is being
combusted in the boiler.
    The EPA received several comments on the proposed definitions of
``useful thermal energy,'' ``startup,'' and ``shutdown.''
1. Useful Thermal Energy
    Several commenters supported the amended definitions of startup and
shutdown that 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 commenter requested that the EPA add the term ``flow rate'' to
the definition of useful thermal energy, consistent with discussion in
the preamble to the proposed notice of reconsideration (80 FR 2874).
The EPA recognizes the importance of flow rate as a parameter for
determining when useful thermal energy is being supplied by a boiler
and has added this term to the definition of useful thermal energy in
the final rule.

2. Startup

    One commenter stated 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 commenter 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 alternate definition, which incorporates the term
``useful thermal energy'' in the final rule, with some slight
adjustments, as discussed previously. 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 emission
standard during periods of startup and shutdown because the application
of measurement methodology is impracticable due to technological and
economic limitations. Specifically, the March 2011 final rule required
a work practice standard for coal-fired boilers during periods of
startup and shutdown. See 76 FR 15576-15577. 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 are difficult to achieve during these periods of startup and
shutdown where conditions are constantly changing. 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 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 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 coal-fired boilers in the boilers
source category, the EPA established a separate work practice standard
for startup and shutdown periods.\1\ The Court of Appeals recently
approved the EPA's approach to developing a start-up work practice and
to making a (non)feasibility determination in United States Sugar Corp
v. EPA (No. 11-1108, D.C. Cir., July 29, 2016) (slip op. at 155). We
continue to conclude that testing is impracticable during periods of
startup and shutdown as those terms are defined in this final action.
We set standards based on available information as contemplated by CAA
section 112. Compliance with the numeric emission limits (i.e., PM, Hg,
and carbon monoxide (CO)) is 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.
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    \1\ Coal-fired boilers are the only subcategory for which we set
maximum achievable control technology (MACT)-based standards. The
requisite findings under CAA section 112(h) for work practices are
only necessary for the large coal-fired boiler subcategory. For
large new oil-fired and biomass-fired boilers, the EPA set generally
available control technology (GACT) management practice standards
under CAA section 112(d)(5). The provisions of CAA section 112(h) do
not apply to setting GACT standards.
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    Several commenters agreed with the EPA that startup ``should not
end until such time that all control devices have reached stable
conditions'' (see 80 FR 2875, column 2), but questioned the EPA's
analysis of data from electric utility steam generating units (EGUs) to
determine the alternate startup definition and disagreed with the EPA's
conclusion that 4 hours is an appropriate length of time for startup.
The commenters stated that a work practice approach during startup and
shutdown is appropriate and should be site-specific due to the many
designs and applications of industrial boilers. One commenter provided
information obtained from an informal survey of its members for 76
units on the time needed to reach stable conditions during startup
(CIBO data).
    As stated in the January 2015 proposal, the EPA had very limited
information specifically for industrial boilers on the hours needed for
controls to reach stable conditions after the start of supplying useful
thermal energy.

However, the EPA did have information for EGUs on the hours to stable
control operation after the start of electricity generation. Given that
the startup provisions need to be based on ``best performers,'' we
found that controls used on the best performing 12-percent EGUs reach
stable operation within 4 hours after the start of electricity
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 continue to believe that the controls on the best performing
industrial boilers would also reach stable operation within 4 hours
after the start of supplying useful thermal energy and have included
this timeframe in the final alternate definition. This conclusion was
supported by the limited information (13 units) the EPA had on
industrial boilers and by CIBO data (76 units).\2\
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    \2\ See EPA's July 2016 memorandum, ``Assessment of Startup
Period for Industrial Boilers,'' available in the rulemaking docket
(Docket ID No. EPA-HQ-OAR-2006-0790).
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    One commenter suggested that the first definition of startup be
revised to incorporate the term ``useful thermal energy'' to clarify
that startup has ended when the boiler is supplying steam or heat at
the proper temperature, pressure, and flow to the energy use systems
being served, not immediately after supplying any amount of heat for
any incidental purpose.
    The EPA has adjusted the first definition of startup to replace
``steam or heat'' with ``useful thermal energy (such as steam or hot
water)'' consistent with the terminology in the alternate definition.
Additionally, the term ``useful thermal energy'' was revised to
incorporate a minimum flow rate 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 should be considered to be operating normally at all
times energy (i.e., steam or hot water) 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.
3. Shutdown
    Multiple commenters supported the EPA's proposed definition of
shutdown. One commenter noted the revised definition's accommodation of
the fact that combustion does not end when the fuel feed is turned off
in a grate system because fuel remaining on a grate continues to
combust although fuel has been cut off. To further clarify that the
shutdown period begins when no useful steam or electricity is
generated, or when fuel is no longer being combusted in the boiler, the
EPA has adjusted the definition of shutdown to replace the phrase
``makes useful thermal energy'' to ``supplies useful thermal energy.''
The term ``supplies'' best serves the intended meaning of the
definition of shutdown and, in addition, is consistent with the
definition of startup.

B. Alternative PM Standard for New Oil-Fired Boilers That Combust Low-
Sulfur Oil

    In the February 1, 2013, final amendments to the Area Source
Boilers Rule, the EPA added a new provision that specifies that certain
new or reconstructed oil-fired boilers with heat input capacity of 10
million British thermal units per hour (MMBtu/hr) or greater that
combust low-sulfur oil meet GACT for PM, providing the type of fuel
combusted is monitored and recorded on a monthly basis. Specifically,
the provision applies to boilers combusting only oil that contains no
more than 0.50 weight percent sulfur or a mixture of 0.50 weight
percent sulfur oil with other fuels not subject to a PM emission limit
under this subpart and that do not use a post-combustion technology
(except a wet scrubber) to reduce PM or sulfur dioxide emissions. The
EPA received a petition asserting that the public lacked an opportunity
to comment on the new provision for low-sulfur liquid burning boilers
as well as the definition of low-sulfur liquid fuel. In response to the
petition, in the January 21, 2015, proposal, we solicited comment on
the February 2013 provision, as well as on (1) whether and, if so, to
what extent, burning low-sulfur liquid fuels, as defined under the
final rule, would control the urban metal HAP for which the category of
sources was listed and for which PM serves as a surrogate (i.e., Hg,
arsenic, beryllium, cadmium, lead, chromium, manganese, nickel) and (2)
whether the final rule's definition of low-sulfur would allow emissions
to exceed the final rule's emission limit for PM (i.e., 0.03 pound
(lb)/MMBtu).
    We also solicited comment on an alternative PM standard for new
oil-fired boilers that combust ``ultra-low-sulfur liquid fuel,'' which
would be defined as fuel containing no more than 15 parts per million
(ppm) sulfur, citing the threshold in the National Emission Standards
for Hazardous Air Pollutants for Reciprocating Internal Combustion
Engines (RICE NESHAP) and the National Emission Standards for Hazardous
Air Pollutants for Major Sources: Industrial, Commercial, and
Institutional Boilers and Process Heaters (Boiler MACT). Specifically,
we requested comment on an alternative provision to the February 2013
final rule's alternative PM standard for new oil-fired boilers that
combust low-sulfur oil that would specify that new or reconstructed
oil-fired boilers with heat input capacity of 10 MMBtu/hr or greater
that combust only ultra-low-sulfur liquid fuel meet GACT for PM
providing the type of fuel combusted is monitored and recorded on a
monthly basis. We also requested comment on whether and, if so, to what
extent burning ultra-low-sulfur liquid fuels (i.e., distillate oil that
has less than or equal to 15 ppm sulfur) would control the urban metal
HAP for which the category of sources were listed.
    In this action, the EPA is finalizing an alternative PM standard
for new oil-fired boilers that combust ultra-low-sulfur liquid fuel, as
described immediately above and in the January 2015 proposal, in place
of the February 2013 final rule's alternative PM standard for new oil-
fired boilers that combust low-sulfur oil, as discussed later in this
section of the preamble.
    Several commenters agreed with the provision that specifies that
boilers combusting low-sulfur oil meet GACT for PM, consistent with the
exemption for low-sulfur oil burning boilers in 40 CFR part 60, subpart
Dc. One commenter asserted that PM emissions from oil-fired boilers are
a function of the sulfur content of the fuel and, because low-sulfur
oil has lower PM than high sulfur oil, it necessarily has lower HAP as
well. However, another commenter, reiterating many points made in its
petition for reconsideration on this topic, asserted that the
alternative PM standard for new oil-fired boilers that combust low-
sulfur oil is unlawful and arbitrary because the EPA has not shown that
the use of low-sulfur liquid fuels will provide meaningful reductions
of the urban metal HAP for which area source boilers were listed under
CAA section 112(c)(3), and, therefore, its use cannot be GACT.
    Two commenters disagreed with the alternative PM standard for new
oil-fired boilers that combust low-sulfur oil, as defined in the Area
Source Boilers Rule (i.e., oil that contains no more than 0.50 weight
percent sulfur). The commenters suggested that fuel oils with a sulfur
content of 0.50 weight percent correspond to residual oils, which are
associated with higher HAP emissions. The commenters claimed that the
rule's definition of low sulfur is

too lenient and that boilers combusting fuel oils with 0.50 weight
percent sulfur may have PM emissions that exceed the PM emission limit.
One of the commenters provided data showing a range of PM emissions
between 0.035 to 0.062 lb/MMBtu for four boilers burning oil containing
0.5 weight percent sulfur. On the contrary, one commenter provided
graphs of PM emissions data for oil-fired boilers indicating that most
of the PM emissions from the boilers burning #2 oil were below the PM
emission limit of 0.03 lb/MMBtu.
    Several commenters supported an alternative PM standard for new
oil-fired boilers combusting ultra-low-sulfur fuels containing no more
than 15 ppm sulfur. Another commenter argued that the EPA must show
that the use of ultra-low-sulfur liquid fuels will substantially reduce
emissions of the urban metal HAP for which area source boilers were
listed. The commenter noted that the EPA's finding that use of ultra-
low-sulfur fuel significantly reduces emissions of hazardous metals
when used in engines, as referenced in the January 2015 proposal, does
not support such a conclusion with regard to use of ultra-low-sulfur
fuel in area source boilers.
    Based on our review of data in the record, additional data obtained
from public sources, and public comments, the EPA is finalizing an
alternative PM standard that specifies that new or reconstructed oil-
fired boilers with heat input capacity of 10 MMBtu/hr or greater that
combust only ultra-low-sulfur liquid fuel meet GACT for PM providing
the type of fuel combusted is monitored and recorded on a monthly
basis. If the source intends to burn a fuel other than ultra-low-sulfur
liquid fuel or gaseous fuels as defined in 40 CFR part 63, subpart
JJJJJJ, they are required to conduct a performance test within 60 days
of burning the new fuel. New or reconstructed oil-fired boilers that
commenced construction or reconstruction on or before publication of
this final action and that are currently meeting the alternative PM
standard for low-sulfur oil burning boilers are provided 3 years from
publication of this action before becoming subject to the PM emission
limit, providing them time to decide how to comply (i.e., combust only
ultra-low-sulfur liquid fuel or conduct a performance test
demonstrating compliance).
    We have determined that PM emissions from boilers firing liquid
fuels containing 0.50 weight percent sulfur as allowed under the
February 2013 alternative PM standard may exceed the Area Source
Boilers Rule PM limit for oil-fired boilers of 0.03 lb/MMBtu, but that
PM emissions from boilers firing liquid fuels containing equal to or
less than 15 ppm sulfur (i.e., ultra-low-sulfur liquid fuel) will not
exceed the PM limit. A review of information regarding liquid fuel
sulfur content and PM emissions levels in the records for the boiler
rules found that of the 10 liquid fuel area source boilers that
reported PM emissions that exceeded the PM limit in their information
collection request (ICR) responses, none fired liquid fuel with sulfur
content less than 15 ppm. However, one boiler with emissions exceeding
the PM limit (i.e., 0.061 lb/MMBtu) reported that the level of sulfur
in their fuel was 0.2 weight percent, a level that is above 15 ppm
(0.0015 weight percent), but below the low-sulfur liquid fuel threshold
of 0.50 weight percent in the 2013 final rule. Based on these data,
along with comments indicating that boilers burning oil containing 0.50
percent sulfur can emit PM at levels above the PM limit, the EPA
concludes that the rule's definition of low-sulfur (i.e., 0.50 weight
percent) would potentially allow emissions exceeding the PM emission
limit, but that boilers burning oil containing no more than 15 ppm
sulfur would not emit PM at levels above the PM limit.
    In addition, we have determined that burning ultra-low-sulfur
liquid fuel controls urban metal HAP. The ultra-low-sulfur liquid fuel
threshold of 15 ppm sulfur we are adopting in the final Area Source
Boilers Rule is consistent with the sulfur threshold in the Boiler MACT
that allows for a reduced PM (or, alternatively, total selected metals
(TSM)) testing frequency for light liquid boilers. Further, the PM
emission limit for light liquid boilers at major sources is
significantly lower than the limit for area source oil-fired boilers
(0.0079 lb/MMBtu (existing units) and 0.0011 lb/MMBtu (new units)
instead of 0.03 lb/MMBtu). A review of available information for major
source boilers burning ultra-low-sulfur liquid fuel identified one
major source facility that reported fuel analyses for TSM (i.e.,
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and
selenium) and Hg, and those fuel analyses showed that each boiler had
TSM and Hg emissions below detection limits and the applicable Boiler
MACT TSM and Hg emission limits. The fact that boilers burning ultra-
low-sulfur liquid fuel have the ability to meet the TSM and Hg limits
based on the best-performing major source boilers provides sound
support for our determination that the use of ultra-low-sulfur liquid
fuel in area source boilers will reduce emissions of urban metal HAP.
    A detailed discussion of our findings is included in the ``Response
to 2015 Reconsideration Comments for Industrial, Commercial, and
Institutional Boilers at Area Sources: National Emission Standards for
Hazardous Air Pollutants'' located in the docket.

C. Establishment of a Subcategory and Separate Requirements for
Limited-Use Boilers

    In the February 1, 2013, final amendments to the Area Source
Boilers Rule, the EPA established a limited-use boiler subcategory that
includes any boiler that burns any amount of solid or liquid fuels and
has a federally enforceable average annual capacity factor of no more
than 10 percent. Separate requirements for this subcategory of boilers
that operate on a limited basis were also established. Specifically,
limited-use boilers are required to complete a tune-up every 5 years.
The EPA received a petition asserting that the public lacked an
opportunity to comment on the new limited-use boiler subcategory, as
well as the tune-up requirement established for the new subcategory. In
response to the petition, in the January 21, 2015, proposal, we
solicited comment regarding whether the separate requirements for a
limited-use boiler subcategory are necessary or appropriate. The EPA is
retaining the limited-use boiler subcategory and its separate
requirements, as discussed later in this section of the preamble.
    Multiple commenters agreed that separate requirements for limited-
use boilers are appropriate. One commenter asserted that limited-use
boilers qualify for subcategorization due to unique operating
characteristics that merit class and type distinctions allowed under
CAA section 112(d)(1). Two commenters explained that these units spend
a larger percentage of time starting up and shutting down than regular-
use boilers which causes their emissions profiles to be different, and
many pollution control technologies are difficult to use or ineffective
during startup and shutdown and would be cost-prohibitive to install
and use. One commenter stated that the designation of a limited-use
boiler subcategory is appropriately consistent with the similar
subcategory for seasonal boilers. Several commenters stated that a
limited-use boiler subcategory is appropriately consistent with the
similar limited-use subcategory in the Boiler MACT.

    Multiple commenters supported the 5-year tune-up requirement for
limited-use boilers. Two commenters stated that it would be illogical
to require such boilers to comply with the same tune-up schedule as
other boilers, which is every 2 years, given their limited operational
time and intermittent operating schedules. One commenter claimed that
more frequent tune-ups would not provide any meaningful environmental
benefits given the limited operating profiles of limited-use units,
noting that despite the 5-year tune-up frequency, limited-use boilers
will still conduct tune-ups after less operating time than boilers in
other subcategories.
    One commenter objected to the EPA's decision to create a separate
subcategory for these boilers and for requiring nothing more than one
tune-up every 5 years for these boilers. The commenter stated that the
limited-use boilers subcategory is unlawful and arbitrary because the
EPA is not distinguishing between different classes, types, or sizes of
sources and has not explained why boilers operating for fewer total
hours during the year is a distinction that requires differential
treatment. The commenter further stated that infrequent tune-ups are
neither a control technology nor a management practice that will reduce
emissions and that nothing in the record demonstrates that the
requirement to conduct a tune-up every 5 years will actually reduce
emissions of HAP. The commenter asserted that in light of the
determination that more frequent tune-ups are GACT for other area
boilers, it is unlawful and arbitrary for the EPA to require tune-ups
for limited-use boilers only every 5 years.
    The EPA has retained the subcategory and separate requirements for
limited-use boilers as finalized in the February 2013 final rule. We
disagree with the comments objecting to the limited-use boiler
subcategory and the requirement that limited-use boilers complete a
tune-up every 5 years. The EPA has concluded that limited-use boilers
are a unique class of unit based on the unique way in which they are
used (i.e., they operate for unpredictable periods of time, limited
hours, and at less than full load in many cases) and has determined
that regulating these units with periodic tune-up work practice and
management practice requirements will limit HAP by ensuring that these
units operate at peak efficiency during the limited hours that they do
operate. In the preamble to the June 4, 2010, proposed standards for
area source boilers, the EPA explained that a boiler tune-up provides
potential savings from energy efficiency improvements and pollution
prevention, and that improvement in energy efficiency results in
decreased fuel use which results in a corresponding decrease in
emissions (both HAP and non-HAP) from the boiler (75 FR 31908).
Specifically, for any boiler conducting a tune-up, a 1-percent gain in
combustion efficiency was estimated, resulting in an estimated 1-
percent emissions reduction of all pollutants.\3\
---------------------------------------------------------------------------

    \3\ ``Revised Methodology for Estimating Impacts from
Industrial, Commercial, Institutional Boilers at Area Sources of
Hazardous Air Pollutant Emissions'' (Docket entry: EPA-HQ-OAR-2006-
0790-2314).
---------------------------------------------------------------------------

    The EPA continues to conclude, as previously stated in the February
2013 final rule, that establishing a limited-use subcategory was
reasonable. First, we pointed out that it is technically infeasible to
test these limited-use boilers since these units serve as back-up
energy sources and their operating schedules can be intermittent and
unpredictable. Next, we pointed out that boilers that operate no more
than 10 percent of the year (i.e., a limited-use boiler) would operate
for no more than 6 months in between tune-ups on a 5-year tune-up
cycle. We then explained that the brief period of operations for these
limited-use boilers is even less than the number of operating months
that seasonal boilers and full-time boilers will operate between tune-
ups. Finally, we noted that the irregular schedule of operations also
makes it difficult to schedule more frequent tune-ups.

D. Establishment of a Provision That Eliminates Further Performance
Testing for PM for Certain Boilers Based on Their Initial Compliance
Test

    In the February 1, 2013, final amendments to the Area Source
Boilers Rule, the EPA added a new provision that specifies that further
PM emissions testing does not need to be conducted if, when
demonstrating initial compliance with the PM emission limit, the
performance test results show that the PM emissions from the affected
boiler are equal to or less than half of the applicable PM emission
limit. The EPA received a petition asserting that the public lacked
opportunity to comment on the new provision that eliminates further
performance testing for PM for certain boilers based on their initial
compliance test. In response to the petition, in the January 21, 2015,
proposal, we solicited comment on the February 2013 provision,
specifically requesting comment and supporting information on the
magnitude and range of variability in PM and urban metal HAP emissions
from individual boilers. More specifically, we requested comment on
whether the emissions variability at an individual boiler could result
in an exceedance of the PM limit by such boiler whose PM emissions are
demonstrated to be equal to or less than half of the PM emission limit
(i.e., a doubling or more of PM emissions). We also requested comment
on whether a requirement to burn only the fuel types and mixtures used
to demonstrate that a boiler's PM emissions are equal to or less than
half of the PM limit would limit PM emissions variability.
    The EPA also solicited comment on an alternative provision that
would specify less frequent performance testing for PM based on the
initial compliance test. Instead of eliminating further PM performance
testing, the alternative provision would specify that when
demonstrating initial compliance with the PM emission limit, if the
performance test results show that the PM emissions from the affected
boiler are equal to or less than half of the applicable PM emission
limit, additional PM emissions testing would not need to be conducted
for 5 years. We stated that, in such instances, the owner or operator
would be required to continue to comply with all applicable operating
limits and monitoring requirements. We requested comment on also
including a requirement that the owner or operator only burn the fuel
types and fuel mixtures used to demonstrate that the PM emissions from
the affected boiler are equal to or less than half of the applicable PM
emission limit.
    In this action, the EPA is finalizing the alternative provision
that requires further PM performance testing every 5 years for certain
boilers based on their initial compliance test, as described
immediately above and in the January 2015 proposal, in place of the
February 2013 final rule's provision that eliminated further PM
performance testing for such boilers, as discussed later in this
section of the preamble. As also discussed in this section of the
preamble, we are finalizing a requirement that a PM performance test
must be conducted if the owner or operator decides to use a fuel type,
other than ultra-low-sulfur liquid fuel or gaseous fuels, that was not
used when demonstrating that the PM emissions from their boiler were
equal to or less than half of the PM emission limit.
    Several commenters agreed with the provision that eliminates
further PM performance testing when initial compliance tests show that
PM emissions are equal to or less than half of the limit and that
requires the owner

or operator to continue to comply with all applicable operating limits
and monitoring requirements. One commenter agreed with the provision
eliminating further PM performance testing as long as the owner or
operator is required to burn only the fuel types and mixtures used
during the initial testing. Two commenters noted that the provision
promotes good PM performance from new boilers while acknowledging that
some boilers are inherently low-emitting and should be spared the
expense of ongoing performance testing where operations remain
consistent. One commenter stated that by setting the threshold at equal
to or less than half of the emission limit, there is sufficient buffer
against the limit to account for any variability in emission levels,
and added that because the unit must continue to comply with operating
limits and monitoring requirements, there are safeguards to ensure
there are no changes in operation of the boiler or air pollution
control equipment that could increase emissions. Another commenter
claimed that the provision is in line with other MACT standards and new
source performance standards (NSPS) which require only one initial
performance test unless there is a physical change to the control
device, and added that HAP emissions change only when operating
parameters change or when design changes occur.
    Two commenters objected to the provision that eliminates further PM
performance testing when initial compliance tests show that PM
emissions are equal to or less than half of the limit. One commenter
claimed that there are no requirements to prevent the facility from
changing the fuel type and fuel mixture from those used in the initial
compliance testing and a change in fuel type or mixture could result in
an increase in PM emissions. Another commenter asserted that it is
arbitrary to conclude that a source that measures low emissions in one
test will have emissions below the limit thereafter. The commenter
claimed that many boilers burn combinations of fuels of varying
proportions (e.g., biomass and coal), and because sources are allowed
to change their fuel mix within a given fuel type and to change their
fuel supplier without changing subcategories, PM emissions from an
individual source are likely to be highly variable. The commenter
further noted that the EPA has routinely acknowledged the variability
inherent in industrial boiler emissions, and that EPA data demonstrate
that PM emissions from boilers are highly variable.
    For the same reasons, these two commenters also objected to the
alternative provision that would require less frequent (once every 5
years) PM performance testing when initial compliance tests show that
PM emissions are equal to or less than half of the limit in lieu of
totally eliminating further PM performance testing. One commenter,
however, provided an alternative recommendation that eliminates further
PM testing as long as sources whose initial compliance testing showed
PM emissions equal to or less than half of the limit continue to
combust the same fuel type and mixture used during the initial
compliance testing. Under the commenter's alternative, if the source
elects to change the fuel type or mixture being combusted, the source
would be required to demonstrate compliance with the PM emission limit
no more than 60 days after the change in fuel type or mixture.
    Based on our review of the public comments and data available on PM
and metallic HAP emissions for which PM serves as a surrogate, the EPA
is finalizing the provision that specifies that further PM emissions
testing does not need to be conducted for 5 years if, when
demonstrating initial compliance with the PM emission limit, the
performance test results show that the PM emissions from the affected
boiler are equal to or less than half of the applicable PM emission
limit. In such instances, the owner or operator would be required to
continue to comply with all applicable operating limits and monitoring
requirements. If the source burns a new type of fuel other than ultra-
low-sulfur liquid fuel or gaseous fuels, then a new performance test is
required within 60 days of burning the new fuel type. New or
reconstructed boilers that commenced construction or reconstruction on
or before publication of this final action and that previously
demonstrated that their PM emissions were equal to or less than half of
the PM emission limit are provided 5 years from publication of this
action before they are required to conduct a performance test unless a
new type of fuel, other than ultra-low-sulfur liquid fuel or gaseous
fuels, is burned. In that situation, a new performance test is required
within 60 days of burning the new fuel type. Boilers with test results
that show that PM emissions are greater than half of the PM emission
limit are required to conduct PM testing every 3 years.
    We have concluded that a provision that reduces the frequency of
testing, rather than eliminates further testing, is more appropriate
and environmentally protective for long-term compliance with the PM
emission limit, but still provides compliance flexibility for low-
emitting boilers. A review of PM emissions information in the records
for the boiler rules identified several instances where PM emissions
variability at an individual major source boiler was such that the
minimum test average was below half of the Area Source Boilers Rule PM
emission limit and the maximum test average was above the emission
limit. Specifically, of 40 coal-fired major source boilers with
multiple PM test events, four had such an instance. An investigation
into urban metal HAP emission variability informed the EPA that
metallic HAP emissions from individual boilers, for which PM serves as
a surrogate, can vary and further supports our conclusion that periodic
testing is necessary to provide compliance assurance that changes in
operation of the boiler or air pollution control equipment have not
increased PM emissions. Examination of the variability in non-Hg
metallic HAP emissions at individual boilers showed average ratios of
maximum emission rates to minimum emission rates for major source
boilers with multiple test results for TSM to be 2.79 for biomass-fired
boilers and 2.55 for coal-fired boilers, and showed emission ratios for
cadmium and lead for several biomass-fired area source boilers with
multiple test results that ranged from 1.00 to 7.28 for cadmium and
1.00 to 6.40 for lead. Because PM is a surrogate for Hg for biomass-
and oil-fired area source boilers, Hg variability at individual boilers
was also examined, showing emission ratios of 4.6 for an area source
biomass-fired boiler with multiple Hg fuel analysis samples and 3.2 and
16.2 for area source biomass-fired boilers with multiple Hg performance
tests.
    The January 2015 proposal requested comment on whether a
requirement to burn only the fuel types and mixtures used to
demonstrate that a boiler's PM emissions are equal to or less than half
of the PM limit would limit PM emissions variability and also requested
comment on including such a requirement. For the same reasons the EPA
concluded that periodic testing (i.e., every 5 years) for these low-
emitting boilers is necessary to provide long-term compliance assurance
(i.e., the intra-unit variability in PM and metal HAP emissions
identified based on a review of the public comments and available
data), we have concluded that introduction of a new fuel type, other
than ultra-low-sulfur liquid fuel or

gaseous fuels, in between the 5-year tests requires a new performance
test within 60 days of burning a new fuel type. 40 CFR 63.11212(c)
requires that performance stack tests be conducted while burning the
type of fuel or mixture of fuels that have the highest emissions
potential for each regulated pollutant. The burning of a new fuel type,
whether alone or in a mixture of fuels, could potentially increase
emissions. Thus, we believe that this new requirement to test when a
new fuel type is burned, along with the requirement in 40 CFR
63.11212(c) to test while burning the type of fuel or mixture of fuels
that have the highest emissions potential, will limit PM emissions
variability.
    A detailed discussion of our findings is included in the ``Response
to 2015 Reconsideration Comments for Industrial, Commercial, and
Institutional Boilers at Area Sources: National Emission Standards for
Hazardous Air Pollutants'' located in the docket.

E. Establishment of a Provision That Eliminates Further Fuel Sampling
for Mercury for Certain Coal-Fired Boilers Based on Their Initial
Compliance Demonstration

    In the February 1, 2013, final amendments to the Area Source
Boilers Rule, the EPA added a new provision that specifies that further
fuel analysis sampling does not need to be conducted if, when
demonstrating initial compliance with the Hg emission limit based on
fuel analysis, the Hg constituents in the fuel or fuel mixture are
measured to be equal to or less than half of the Hg emission limit. The
EPA received a petition asserting that the public lacked an opportunity
to comment on the new provision that eliminates further fuel sampling
for Hg for certain coal-fired boilers based on their initial compliance
demonstration. In response to the petition, in the January 21, 2015,
proposal, we solicited comment on the February 2013 provision,
specifically requesting comment and supporting information on the
magnitude and range of variability in Hg content in coal that is likely
to be combusted in an individual boiler. More specifically, we
requested comment on whether the variability within a specific fuel
type or fuel mixture could result in an exceedance of the Hg limit by a
boiler in the coal subcategory whose Hg content in their fuel or fuel
mixture are demonstrated to be equal to or less than half of the Hg
emission limit (i.e., a doubling or more of Hg emissions).
    The EPA also solicited comment on an alternative provision that
would specify less frequent fuel analysis sampling for Hg based on the
initial compliance demonstration. Instead of eliminating further fuel
analysis sampling for Hg, the alternative provision would specify that
when demonstrating initial compliance with the Hg emission limit based
on fuel analysis, if the Hg constituents in the fuel or fuel mixture
are measured to be equal to or less than half of the Hg emission limit,
additional fuel analysis sampling for Hg would not need to be conducted
for 12 months. We stated that, in such instances, the owner or operator
would be required to continue to comply with all applicable operating
limits and monitoring requirements, which include only burning the fuel
types and fuel mixtures used to demonstrate compliance and keeping
monthly records of fuel use.
    In this action, the EPA is finalizing the alternative provision
that requires further fuel analysis sampling for Hg every 12 months for
certain coal-fired boilers based on their initial compliance
demonstration, as described immediately above and in the January 2015
proposal, in place of the February 2013 final rule's provision that
eliminated further fuel analysis sampling for Hg for such boilers, as
discussed later in this section of the preamble.
    Three commenters agreed with the provision that eliminates further
fuel sampling for Hg for coal-fired boilers when initial compliance
demonstrations based on fuel analysis show that the Hg constituents in
their fuel or fuel mixture are equal to or less than half of the Hg
emission limit and that requires the owner or operator to continue to
comply with all applicable operating limits and monitoring
requirements. Two commenters stated that the coal Hg content data in
the EPA's Boiler MACT survey database support the provision in that the
majority of the data is lower than the Hg emission limit for area
source coal-fired boilers. The commenters noted that the provision
promotes use of low-mercury coal, one stating that the Hg content in
petroleum coke has very little variability and referencing a particular
facility where the Hg content is well below the Hg limit. One commenter
further stated that the provision eliminates unnecessary reporting
without compromising the environmental and health benefits of the Area
Source Boilers Rule. Another commenter noted that for units complying
with the Hg limit, subsequent fuel analysis would not provide
additional useful information, is unnecessary, and the costs are
unwarranted.
    One commenter supported the alternative provision that would
require less frequent (once every 12 months) fuel analysis sampling for
Hg when initial compliance demonstrations based on fuel analysis show
that the Hg constituents in the fuel or fuel mixture are equal to or
less than half of the limit in lieu of totally eliminating further fuel
sampling for Hg.
    One commenter objected to a provision that eliminates or reduces
further fuel sampling for Hg when initial compliance demonstrations
based on fuel analysis show that the Hg constituents in the fuel or
fuel mixture are equal to or less than half of the limit. The commenter
asserted that because the EPA has promulgated MACT standards for coal-
fired boilers at area sources, it is arbitrary and unlawful to not
require monitoring sufficient to assure compliance with the standards.
The commenter further asserted that a single fuel analysis showing Hg
content at or below half of the limit does not assure compliance with
the standard in perpetuity, particularly in light of the high
variability of the Hg content of the fuels burned. The commenter added
that sources are allowed to burn highly non-homogenous fuels without
changing subcategories, which enables a high degree of variability in
emissions, and that many coal-fired boilers co-fire biomass of varying
proportions. The commenter included their analysis of EPA fuel analysis
data for major and area source boilers that shows that 22.5 percent of
sources experienced sufficient variability in the Hg content of their
coal to obtain a result in one fuel analysis low enough to exempt them
from any future fuel sampling, while another analysis at the same
facility exceeds the provision's Hg content limit. The commenter
asserted that biomass fuels also have a large range of variability in
Hg content.
    Based on our review of the public comments and the data available
for quantifying variability in coal Hg content, the EPA is finalizing
the provision that specifies that further fuel analysis sampling for Hg
does not need to be conducted for 12 months if, when demonstrating
initial compliance with the Hg emission limit based on fuel analysis,
the Hg constituents in the fuel or fuel mixture are measured to be
equal to or less than half of the Hg emission limit. New or
reconstructed boilers that commenced construction or reconstruction on
or before publication of this final action and that previously
demonstrated that the Hg constituents in their fuel or fuel mixture
were equal

to or less than half of the Hg emission limit are provided 12 months
from publication of this action before they are required to conduct
fuel analysis sampling for Hg. The owner or operator is required to
continue to comply with all applicable operating limits and monitoring
requirements, which include only burning the fuel types and fuel
mixtures used to demonstrate compliance and keeping monthly records of
fuel use. As specified in 40 CFR 63.11220, a fuel analysis must be
conducted before burning a new type of fuel or fuel mixture. Boilers
with fuel analysis results that show that Hg constituents in the fuel
or fuel mixture are greater than half of the Hg emission limit are
required to conduct quarterly sampling.
    A review of Hg fuel analysis data for area source coal-fired
boilers informed the EPA that Hg content in coal combusted in
individual boilers can vary by more than a factor of two. Specifically,
of ten coal-fired boilers with multiple fuel analysis samples, four had
ratios of maximum to minimum Hg emission rates that were greater than
two (i.e., 2.2, 3.0, 5.8, and 11.2). In addition, two of the boilers
had fuel samples with Hg content that were less than half of the
emission limit but other samples with Hg content that exceeded the
emission limit. Based on this information, the EPA does not believe
that finalizing a provision that eliminates further fuel analysis
sampling for Hg based on a single demonstration is appropriate or
environmentally protective for long-term compliance, but has concluded
that it is appropriate to provide some compliance flexibility by
reducing periodic fuel sampling for boilers combusting coal with low Hg
content to every 12 months.
    A detailed discussion of our findings is included in the ``Response
to 2015 Reconsideration Comments for Industrial, Commercial, and
Institutional Boilers at Area Sources: National Emission Standards for
Hazardous Air Pollutants'' located in the docket.

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 refinements made to the proposed corrections and
clarifications, as well as corrections and clarifications being
finalized based on comment.

A. 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, a commenter (AF&PA) 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 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 (CIBO/ACC and AF&PA) argued the Natural
Resources Defense Council (NRDC) Court decision that the EPA cites as
the reason for eliminating the affirmative defense provisions does not
compel the EPA's action to remove the affirmative defense in this rule.
    Fourth, commenters (CIBO/ACC and AF&PA) argued that without
affirmative defense or adjusted standards, the final rule provides
sources no means of demonstrating compliance during malfunctions.
    Fifth, commenters (CIBO/ACC, AF&PA, and Class of '85 Regulatory
Response Group) 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 limitations. Commenters noted that 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
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
15560). In the most recent notice of proposed reconsideration (80 FR
2871, 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.
    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 (or other delegated or approved authority'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 other delegated or
approved authority) 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. The EPA notes that the Court in United States
Sugar Corp v. EPA (No. 11-1108, D.C. Cir., July 29, 2016) (slip op. at
34-36) rejected challenges to the EPA's approach of applying limits
during periods of malfunctions, not establishing a separate work
practice, and relying on enforcement discretion in individual cases.

B. Definition of Coal

    The last part of the definition of coal published in the March 21,
2011, final rule (76 FR 15554) reads as follows: ``Coal derived gases
are excluded from this definition [of coal].'' In the January 2015
proposal (80 FR 2871), 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 a comment disagreeing with the proposed change to
the definition of coal. The commenter (CIBO/ACC) asserted that the
revised definition is not logically consistent with the other fuel
definitions and irrationally recategorizes specific units as liquid
fuel fired where a data analysis would rationally lead them to
remaining in the solid fuel category. Specifically, the commenter
contended that it is illogical to treat coal derived liquids
differently than coal-water mixtures and coal-oil mixtures, both of
which are included in the proposed revised definition of ``coal.'' The
commenter explained that coal-water mixtures and coal-oil mixtures are
both included in the definition and both are utilized as liquid oil or
gas replacements fuels, similar to utilization of coal derived liquids.
    The EPA also proposed the same modification to the definition of
coal included in the Boiler MACT (80 FR 3090, January 21, 2015) and
subsequently received several comments disagreeing with the proposed
change in that action that we also believe are appropriate to consider
in this action. Specifically, one commenter who operates a facility
with coal derived liquids contended that the composition and emission
profile of coal derived liquids more closely resemble the coal from
which they are derived than liquid fuels. The 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 March 21, 2011 (76
FR 15554) 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 the EPA agrees with the commenters that coal derived
liquids are more similar to coal solid fuels than liquid fuels.

C. 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,
proposal (80 FR 2879), the EPA is finalizing several other changes, as
outlined in Table 2 as follows:

   Table 2--Summary of Technical Corrections and Clarifications Since
                          January 2015 Proposal
------------------------------------------------------------------------
  Section of subpart JJJJJJ            Description of correction
------------------------------------------------------------------------
63.11195(c)..................   Revised the paragraph to remove
                                ``unless such units do not combust
                                hazardous waste and combust comparable
                                fuels.'' The comparable fuels exclusion
                                codified in 40 CFR 261.38 was vacated by
                                the Court.
63.11223(c)..................   Revised the paragraph to clarify
                                the oxygen level set point for a source
                                not subject to emission limits. The
                                following sentence was added at the end
                                of the paragraph, ``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.'' This clarification was
                                made instead of the proposed
                                clarification to 63.11224(a)(7).
63.11225(e)..................   Revised the paragraph to include
                                current electronic reporting procedures.
63.11237.....................   Revised the definition of
                                ``Liquid fuel'' to remove the phrase
                                ``and comparable fuels as defined under
                                40 CFR 261.38.'' The comparable fuels
                                exclusion codified in 40 CFR 261.38 was
                                vacated by the Court.
                                Revised the definition of
                                ``Voluntary consensus standards (VCS)''
                                to correct typographical errors.
------------------------------------------------------------------------

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 petition for reconsideration on
one issue (i.e., Authority to Require an Energy Assessment) because
this criterion has not been met. With respect to that issue, the
petition reiterates comments made on the June 4, 2010, proposed rule
during the public comment period for that rule. 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 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 CAA, 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).
    In this final decision, several changes that are corrections,
editorial changes, and minor clarifications have been made. In one
instance, one of those changes made a petitioner's issue (i.e.,
Averaging Period for CO) moot. Therefore, we are denying
reconsideration of that issue.

A. Request for Reconsideration of the Energy Assessment Requirement

    The petitioner (AF&PA) alleged that a beyond-the-floor requirement
of an energy assessment is outside the EPA's authority to set emissions
standards under CAA section 112(d)(1) ``for each category or
subcategory of major sources and area sources.'' The petition contends
that 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 petitioner 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. The petition contends that, 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.
    While the petition refers to not only boilers, but also ``process
heaters,'' the EPA has defined the source category for the Area Source
Boilers Rule to include only specified types of boilers and, therefore,
those are the only sources for which the EPA has set standards under
this rule. The petitioner has not demonstrated that it was
impracticable to comment on these issues during the public comment
period on the proposed Area Source Boilers Rule. In fact, petitioners
provided the same comments during that comment period, and subsequently
challenged the EPA's establishment of the energy assessment
requirement. The Court in United States Sugar Corp. v. EPA (No. 11-
1108, D.C. Cir., July 29, 2016)(slip op. at 52) rejected challenges to
the energy assessment rule both as a beyond the floor MACT standard and
as a GACT standard. Therefore, the EPA is denying the petition for
reconsideration of this issue.

B. Request for Clarification of the Averaging Period for CO

    One petitioner (AF&PA) requested clarification in Table 1 to
subpart JJJJJJ of part 63. Specifically, Items 1 and 2 in Table 1
specify that units can comply with the CO limit using a 3-run average
or a 10-day rolling average (when using CO CEMS). The Item 6 entry for
CO does not include the averaging period text. The petitioner requested
that text be added to Table 1, Item 6 that clarifies the averaging
period for the CO limit (i.e., ``3-run average or 10-day rolling
average'').
    Item 6 of Table 1 to subpart JJJJJJ of part 63 has been amended to
clarify that either a 3-run average or a 10-day rolling average is an
appropriate averaging period for the CO emission limit. The
petitioner's comments are, therefore, now moot and we are denying
reconsideration on this issue.

VI. Impacts Associated With This Final Rule

    This action finalizes certain provisions and makes technical and
clarifying corrections, but does not promulgate substantive changes to
the February 2013 final Area Source Boilers Rule (78 FR 7488). The EPA
is finalizing the definitions of startup and shutdown that were
promulgated in the February 2013 final rule along with revisions we
proposed to make to those definitions, including an alternate
definition of startup, and minor adjustments based on public comments.
The revisions to the definitions of startup and shutdown clarify the
beginning and end of startup and shutdown periods, but do not change
the regulatory requirements that apply during those periods or the
boilers that are subject to those requirements. We are retaining the
subcategory and separate requirements for limited-use boilers,
consistent with the February 2013 final rule. The EPA is amending the
reconsidered provisions regarding the alternative PM standard for new
oil-fired boilers that combust low-sulfur oil, the elimination of
further performance testing for PM for certain boilers based on their
initial compliance test, and the elimination of further fuel sampling
for Hg for certain coal-fired boilers based on their initial compliance
demonstration, consistent with the alternative provisions for which
comment was solicited in the January 2015 proposal.
    Promulgation of the amendments contained in this action does not
change the coverage of the final rule nor does it affect the estimated
emission reductions, control costs or the benefits of the rule in
substance compared to the March 2011 final rule. The EPA explained in
the preamble to the February 2013 final rule that promulgated
amendments, including this action's five reconsidered provisions, that
those amendments did not impose any additional regulatory requirements
beyond those imposed by the March 2011 final rule and, in fact, would
result in a decrease in burden. We further explained that, as compared
to the control costs estimated for the March 2011 final rule, the
February 2013 final action would not result in any meaningful change in
capital and annual cost. See 78 FR 7503. Similarly, although this
action amends three of the reconsidered provisions, it does not impose
any additional regulatory requirements beyond those imposed by the
March 2011 final rule and would result in a decrease in that burden. As
discussed in detail in sections III.B, D, and E of this preamble, the
three amended provisions regard compliance flexibilities provided in
the February 2013 final rule that we have now determined need to be
adjusted to be more environmentally protective and ensure compliance
with the CAA. Thus, when compared to the February 2013 provisions, the
amended provisions could result in minimal additional impacts on
boilers that choose to comply with the amended provisions. In that they
are compliance flexibilities and a facility's ability to use the

provisions will be on a site-specific basis, the EPA cannot anticipate
who will be in a position to use the provisions. We, however, can
generally describe what those potential impacts would be.
    As discussed in section III.B of this preamble, the EPA is
finalizing an alternative PM standard that specifies that new or
reconstructed boilers that combust only ultra-low-sulfur liquid fuel
(i.e., a distillate oil that has less than or equal to 15 ppm sulfur)
meet GACT for PM in place of the February 2013 final rule's alternative
PM standard for new or reconstructed oil-fired boilers that combust
low-sulfur oil (i.e., oil that contains no more than 0.50 weight
percent sulfur). The provision being finalized that specifies that
certain boilers meet GACT for PM and, thus, are not subject to the PM
emission limit, potentially applies to the subset of oil-fired boilers
that are subject to PM emission limits (i.e., new and reconstructed
boilers with heat input capacity of 10 MMBtu/hr or greater), including
boilers currently meeting the alternative PM standard for boilers that
combust low-sulfur oil. The provision being finalized may result in a
minimal increase in burden on that subset of sources, when compared to
the February 2013 provision that specified that low-sulfur oil-burning
boilers meet GACT for PM and are not subject to the PM emission limit.
Boilers currently meeting the alternative PM standard for low-sulfur
oil burning boilers are provided 3 years from publication of this
action before becoming subject to the PM emission limit, providing them
time to decide how to comply (i.e., combust only ultra-low-sulfur
liquid fuel or conduct a performance stack test demonstrating
compliance with the PM emission limit). A number of such boilers,
however, would not experience any increase in burden if they were
meeting the February 2013 provision by burning ultra-low-sulfur liquid
fuel. Specifically, this would be the situation in states such as New
York, Connecticut, and New Jersey, which currently limit the sulfur
content in oil used for heating purposes to less than 15 ppm. Oil-fired
boilers in Maine, Massachusetts, and Vermont used for heating will
become subject to 15 ppm sulfur requirements in 2018, which is within
the 3-year compliance period provided to boilers currently meeting the
alternative PM standard for low-sulfur oil burning boilers. The burden
associated with the provision being finalized is still less than the
burden that was imposed by the March 2011 final rule which required all
oil-fired boilers subject to a PM emission limit to conduct performance
stack testing for PM every 3 years.
    As discussed in section III.D of this preamble, the EPA is
finalizing a provision that specifies that when demonstrating initial
compliance with the PM emission limit, if performance test results show
that PM emissions from an affected boiler are equal to or less than
half of the applicable PM emission limit, additional PM emissions
testing does not need to be conducted for 5 years in place of the
February 2013 final rule's provision that eliminated further PM
performance testing for such boilers. The provision being finalized
that allows certain boilers to conduct PM emissions testing every 5
years potentially applies to the subset of boilers that are subject to
PM emission limits (i.e., new and reconstructed boilers with heat input
capacity of 10 MMBtu/hr or greater), including boilers that previously
demonstrated that their PM emissions were equal to or less than half of
the PM emission limit. The provision being finalized will result in a
minimal increase in burden on that subset of sources, when compared to
the February 2013 provision that eliminated further PM emissions
testing for such sources, in that they will be required to conduct a
performance stack test for PM every 5 years. The burden associated with
the provision being finalized is still less than the burden that was
imposed by the March 2011 final rule which required all boilers subject
to a PM emission limit to conduct performance stack testing for PM
every 3 years.
    As discussed in section III.E of this preamble, the EPA is
finalizing a provision that specifies that when demonstrating initial
compliance with the Hg emission limit based on fuel analysis, if the Hg
constituents in the fuel or fuel mixture are measured to be equal to or
less than half of the Hg emission limit, additional fuel analysis
sampling for Hg would not need to be conducted for 12 months in place
of the provision that eliminated further fuel sampling for such
boilers. The provision being finalized that allows certain boilers to
conduct fuel analysis sampling for Hg every 12 months potentially
applies to the subset of boilers that are subject to Hg emission limits
(i.e., coal-fired boilers with heat input capacity of 10 MMBtu/hr or
greater), including boilers that previously demonstrated that the Hg
constituents in their fuel or fuel mixture were equal to or less than
half of the Hg emission limit. The provision being finalized will
result in a minimal increase in burden on that subset of sources, when
compared to the February 2013 provision that eliminated further fuel
analysis sampling for Hg for such sources, in that they will be
required to conduct fuel analysis sampling for Hg every 12 months. The
burden associated with the provision being finalized is still less than
the burden that was imposed by the March 2011 final rule which required
all boilers that demonstrated compliance with the Hg emission limit
based on fuel analysis to conduct fuel analysis sampling for Hg on a
monthly basis.

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 which finalizes certain provisions and makes technical
and clarifying corrections will result in no significant changes to the
information collection requirements of the promulgated rule and will
have no increased impact on the information collection estimate of
projected cost and hour burden made and approved by OMB. The EPA
explained in the preamble to the February 2013 final rule that
promulgated amendments, including this action's five reconsidered
provisions, that those amendments did not impose any additional
regulatory requirements beyond those imposed by the March 2011 final
rule and, in fact, would result in a decrease in burden. Accordingly,
the ICR was not revised as a result of the February 2013 final rule.
Similarly, although this action amends three of the reconsidered
provisions, it does not impose any additional regulatory requirements
beyond those imposed by the March 2011 final rule and would result in a
decrease in that burden. The three amended provisions regard compliance
flexibilities that allow reduced performance stack testing and/or fuel
sampling for certain boilers. Therefore, the ICR has not been revised
as a result of this action. The OMB has previously approved the
information collection activities contained in the existing regulations
and has assigned OMB control number 2060-0668.

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. In
making this determination, the impact of concern is any significant
adverse economic impact on small entities. The small entities subject
to the requirements of this action are owners and operators of coal-,
biomass-, and oil-fired boilers located at area sources of HAP
emissions. The EPA explained in the preamble to the February 2013 final
rule that promulgated amendments to the March 2011 final rule that
those amendments were closely related to the final Area Source Boilers
Rule, which the EPA signed on February 21, 2011, and that took effect
on May 20, 2011. We further explained that the EPA prepared a final
regulatory flexibility analysis in connection with the final Area
Source Boilers Rule and, therefore, pursuant to section 605(c), the EPA
was not required to complete a final regulatory flexibility analysis
for the February 2013 final rule. (78 FR 7503-7504, February 1, 2013.)
This action finalizes certain provisions and makes technical and
clarifying corrections, but does not promulgate substantive changes to
the February 2013 final Area Source Boilers Rule. Further, as explained
in section VI of this preamble, the February 2013 final rule that
promulgated amendments, including this action's reconsidered
provisions, did not impose any additional regulatory requirements
beyond those imposed by the March 2011 final rule and, in fact, would
result in a decrease in burden. Similarly, although this action amends
three of the reconsidered provisions, it does not impose any additional
regulatory requirements beyond those imposed by the March 2011 final
rule and would result in a decrease in that burden.

D. Unfunded Mandates Reform Act (UMRA)

    This final action does not contain an unfunded mandate of $100
million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action
finalizes certain provisions and makes technical and clarifying
corrections, but does not promulgate substantive changes to the
February 2013 final Area Source Boilers Rule.

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 finalizes certain provisions and
makes technical and clarifying corrections, but does not promulgate
substantive changes to the February 2013 final Area Source Boilers
Rule. 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 an environmental
health risk or safety risk.

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

    This action is not 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 15588
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 that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations and/or indigenous peoples, as
specified in Executive Order 12898 (59 FR 7629, February 16, 1994). The
environmental justice finding in the February 2013 final Area Source
Boilers Rule (78 FR 7504, February 1, 2013) remains relevant in this
action which finalizes certain provisions and makes technical and
clarifying corrections, but does not promulgate substantive changes to
the February 2013 final Area Source Boilers Rule.

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 63

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

    Dated: August 23, 2016.
Gina McCarthy,
Administrator.

    For the reasons stated 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 citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart JJJJJJ--[AMENDED]

0
2. Section 63.11195 is amended by revising paragraphs (c) and (k) to
read as follows:

Sec.  63.11195  Are any boilers not subject to this subpart?

* * * * *
    (c) A boiler required to have a permit under section 3005 of the
Solid Waste Disposal Act or covered by subpart EEE of this part (e.g.,
hazardous waste boilers).
* * * * *
    (k) An electric utility steam generating unit (EGU) as defined in
this subpart.

0
3. Section 63.11210 is amended by:
0
a. Revising paragraphs (b) and (e);
0
b. Redesignating paragraphs (f) through (j) as paragraphs (g) through
(k);
0
c. Adding a new paragraph (f); and
0
d. Revising the newly designated paragraphs (j) introductory text, (k)
introductory text, and (k)(1) and (2).

    The revisions and addition read as follows:

Sec.  63.11210  What are my initial compliance requirements and by what
date must I conduct them?

* * * * *
    (b) For existing affected boilers that have applicable emission
limits, you must demonstrate initial compliance with the applicable
emission limits no later than 180 days after the compliance date that
is specified in Sec.  63.11196 and according to the applicable
provisions in Sec.  63.7(a)(2), except as provided in paragraph (k) of
this section.
* * * * *
    (e) For new or reconstructed oil-fired boilers that commenced
construction or reconstruction on or before September 14, 2016, that
combust only oil that contains no more than 0.50 weight percent sulfur
or a mixture of 0.50 weight percent sulfur oil with other fuels not
subject to a particulate matter (PM) emission limit under this subpart
and that do not use a post-combustion technology (except a wet
scrubber) to reduce PM or sulfur dioxide emissions, you are not subject
to the PM emission limit in Table 1 of this subpart until September 14,
2019, providing you monitor and record on a monthly basis the type of
fuel combusted. If you intend to burn a new type of fuel or fuel
mixture that does not meet the requirements of this paragraph, you must
conduct a performance test within 60 days of burning the new fuel. On
and after September 14, 2019, you are subject to the PM emission limit
in Table 1 of this subpart and you must demonstrate compliance with the
PM emission limit in Table 1 no later than March 12, 2020.
    (f) For new or reconstructed boilers that combust only ultra-low-
sulfur liquid fuel as defined in Sec.  63.11237, you are not subject to
the PM emission limit in Table 1 of this subpart providing you monitor
and record on a monthly basis the type of fuel combusted. If you intend
to burn a fuel other than ultra-low-sulfur liquid fuel or gaseous fuels
as defined in Sec.  63.11237, you must conduct a performance test
within 60 days of burning the new fuel.
* * * * *
    (j) For boilers located at existing major sources of HAP that limit
their potential to emit (e.g., make a physical change or take a permit
limit) such that the existing major source becomes an area source, you
must comply with the applicable provisions as specified in paragraphs
(j)(1) through (3) of this section.
* * * * *
    (k) For existing affected boilers that have not operated on solid
fossil fuel, biomass, or liquid fuel between the effective date of the
rule and the compliance date that is specified for your source in Sec.
63.11196, you must comply with the applicable provisions as specified
in paragraphs (k)(1) through (3) of this section.
    (1) You must complete the initial compliance demonstration, if
subject to the emission limits in Table 1 to this subpart, as specified
in paragraphs (a) and (b) of this section, no later than 180 days after
the re-start of the affected boiler on solid fossil fuel, biomass, or
liquid fuel and according to the applicable provisions in Sec.
63.7(a)(2).
    (2) You must complete the initial performance tune-up, if subject
to the tune-up requirements in Sec.  63.11223, by following the
procedures described in Sec.  63.11223(b) no later than 30 days after
the re-start of the affected boiler on solid fossil fuel, biomass, or
liquid fuel.
* * * * *

0
4. Section 63.11214 is amended by revising paragraphs (a) through (c)
to read as follows:

Sec.  63.11214  How do I demonstrate initial compliance with the work
practice standard, emission reduction measures, and management
practice?

    (a) If you own or operate an existing or new coal-fired boiler with
a heat input capacity of less than 10 million Btu per hour, you must
conduct a performance tune-up according to Sec.  63.11210(c) or (g), as
applicable, and Sec.  63.11223(b). If you own or operate an existing
coal-fired boiler with a heat input capacity of less than 10 million
Btu per hour, you must submit a signed statement in the Notification of
Compliance Status report that indicates that you conducted an initial
tune-up of the boiler.
    (b) If you own or operate an existing or new biomass-fired boiler
or an existing or new oil-fired boiler, you must conduct a performance
tune-up according to Sec.  63.11210(c) or (g), as applicable, and Sec.
63.11223(b). If you own or operate an existing biomass-fired boiler or
existing oil-fired boiler, you must submit a signed statement in the
Notification of Compliance Status report that indicates that you
conducted an initial tune-up of the boiler.
    (c) If you own or operate an existing affected boiler with a heat
input capacity of 10 million Btu per hour or greater, you must submit a
signed certification in the Notification of Compliance Status report
that an energy assessment of the boiler and its energy use systems was
completed according to Table 2 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.
* * * * *

0
5. Section 63.11220 is revised read as follows:

Sec.  63.11220  When must I conduct subsequent performance tests or
fuel analyses?

    (a) If your boiler has a heat input capacity of 10 million Btu per
hour or greater, you must conduct all applicable performance (stack)
tests according to Sec.  63.11212 on a triennial basis, except as
specified in paragraphs (b) through (e) of this section. Triennial
performance tests must be completed no more than 37 months after the
previous performance test.
    (b) For new or reconstructed boilers that commenced construction or
reconstruction on or before September 14, 2016, when demonstrating
initial compliance with the PM emission limit, if your boiler's
performance test results show that your PM emissions are equal to or
less than half of the PM emission limit, you do not need to conduct
further performance tests for PM until September 14, 2021, but must
continue to comply with all applicable operating limits and monitoring
requirements and must comply with the provisions as specified in
paragraphs (b)(1) through (4) of this section.
    (1) A performance test for PM must be conducted by September 14,
2021.
    (2) If your performance test results show that your PM emissions
are equal to or less than half of the PM emission limit, you may choose
to conduct performance tests for PM every fifth year. Each such
performance test must be conducted no more than 61 months after the
previous performance test.
    (3) If you intend to burn a new type of fuel other than ultra-low-
sulfur liquid fuel or gaseous fuels as defined in Sec.  63.11237, you
must conduct a performance test within 60 days of burning the new fuel
type.
    (4) If your performance test results show that your PM emissions
are greater than half of the PM emission limit, you must conduct
subsequent performance tests on a triennial basis as specified in
paragraph (a) of this section.
    (c) For new or reconstructed boilers that commenced construction or
reconstruction after September 14, 2016, when demonstrating initial
compliance with the PM emission limit, if your boiler's performance
test results show that your PM emissions are equal to or

less than half of the PM emission limit, you may choose to conduct
performance tests for PM every fifth year, but must continue to comply
with all applicable operating limits and monitoring requirements and
must comply with the provisions as specified in paragraphs (c)(1)
through (3) of this section.
    (1) Each such performance test must be conducted no more than 61
months after the previous performance test.
    (2) If you intend to burn a new type of fuel other than ultra-low-
sulfur liquid fuel or gaseous fuels as defined in Sec.  63.11237, you
must conduct a performance test within 60 days of burning the new fuel
type.
    (3) If your performance test results show that your PM emissions
are greater than half of the PM emission limit, you must conduct
subsequent performance tests on a triennial basis as specified in
paragraph (a) of this section.
    (d) If you demonstrate compliance with the mercury emission limit
based on fuel analysis, you must conduct a fuel analysis according to
Sec.  63.11213 for each type of fuel burned as specified in paragraphs
(d)(1) through (3) of this section. If you plan to burn a new type of
fuel or fuel mixture, you must conduct a fuel analysis before burning
the new type of fuel or mixture in your boiler. You must recalculate
the mercury emission rate using Equation 1 of Sec.  63.11211. The
recalculated mercury emission rate must be less than the applicable
emission limit.
    (1) For existing boilers and new or reconstructed boilers that
commenced construction or reconstruction on or before September 14,
2016, when demonstrating initial compliance with the mercury emission
limit, if the mercury constituents in the fuel or fuel mixture are
measured to be equal to or less than half of the mercury emission
limit, you do not need to conduct further fuel analysis sampling until
September 14, 2017, but must continue to comply with all applicable
operating limits and monitoring requirements and must comply with the
provisions as specified in paragraphs (d)(1)(i) and (ii) of this
section.
    (i) Fuel analysis sampling for mercury must be conducted by
September 14, 2017.
    (ii) If your fuel analysis results show that the mercury
constituents in the fuel or fuel mixture are equal to or less than half
of the mercury emission limit, you may choose to conduct fuel analysis
sampling for mercury every 12 months.
    (2) For new or reconstructed boilers that commenced construction or
reconstruction after September 14, 2016, when demonstrating initial
compliance with the mercury emission limit, if the mercury constituents
in the fuel or fuel mixture are measured to be equal to or less than
half of the mercury emission limit, you may choose to conduct fuel
analysis sampling for mercury every 12 months, but must continue to
comply with all applicable operating limits and monitoring
requirements.
    (3) When demonstrating compliance with the mercury emission limit,
if the mercury constituents in the fuel or fuel mixture are greater
than half of the mercury emission limit, you must conduct quarterly
sampling.
    (e) For existing affected boilers that have not operated on solid
fossil fuel, biomass, or liquid fuel since the previous compliance
demonstration and more than 3 years have passed since the previous
compliance demonstration, you must complete your subsequent compliance
demonstration no later than 180 days after the re-start of the affected
boiler on solid fossil fuel, biomass, or liquid fuel.

0
6. Section 63.11221 is amended by revising paragraph (c) to read as
follows:

Sec.  63.11221  Is there a minimum amount of monitoring data I must
obtain?

* * * * *
    (c) You may not use data collected 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
quality control activities in calculations used to report emissions or
operating levels. Any such periods must be reported according to the
requirements in Sec.  63.11225. You must use all the data collected
during all other periods in assessing the operation of the control
device and associated control system.
* * * * *

0
7. Section 63.11222 is amended by revising paragraph (a)(2) to read as
follows:

Sec.  63.11222  How do I demonstrate continuous compliance with the
emission limits?

    (a) * * *
    (2) If you have an applicable mercury or PM emission limit, you
must keep records of the type and amount of all fuels burned in each
boiler during the reporting period. If you have an applicable mercury
emission limit, you must demonstrate that all fuel types and mixtures
of fuels burned would result in lower emissions of mercury than the
applicable emission limit (if you demonstrate compliance through fuel
analysis), or result in lower fuel input of mercury than the maximum
values calculated during the last performance stack test (if you
demonstrate compliance through performance stack testing).
* * * * *

0
8. Section 63.11223 is amended by revising paragraph (c) to read as
follows:

Sec.  63.11223  How do I demonstrate continuous compliance with the
work practice and management practice standards?

* * * * *
    (c) Boilers with an oxygen trim system that maintains an optimum
air-to-fuel ratio that would otherwise be subject to a biennial tune-up
must conduct a tune-up of the boiler every 5 years as specified in
paragraphs (b)(1) through (7) of this section. Each 5-year tune-up must
be conducted no more than 61 months after the previous tune-up. For a
new or reconstructed boiler with an oxygen trim system, the first 5-
year tune-up must be no later than 61 months after the initial startup.
You may delay the burner inspection specified in paragraph (b)(1) of
this section and inspection of the system controlling the air-to-fuel
ratio specified in paragraph (b)(3) of this section until the next
scheduled unit shutdown, but you must inspect each burner and system
controlling the air-to-fuel ratio 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.
* * * * *

0
9. Section 63.11225 is amended by revising paragraphs (a)(4)
introductory text, (b) introductory text, (c)(2)(iv), (e), and (g)
introductory text to read as follows:

Sec.  63.11225  What are my notification, reporting, and recordkeeping
requirements?

    (a) * * *
    (4) You must submit the Notification of Compliance Status no later
than 120 days after the applicable compliance date specified in Sec.
63.11196 unless you own or operate a new boiler subject only to a
requirement to conduct a biennial or 5-year tune-up or you must conduct
a performance stack test. If you own or operate a new boiler subject to
a requirement to conduct a tune-up, you are not required to prepare and
submit a Notification of Compliance Status for the tune-up. If you must
conduct a performance stack test, you must submit the Notification of
Compliance Status within 60 days of completing the performance stack
test. You must submit the Notification of Compliance

Status in accordance with paragraphs (a)(4)(i) and (vi) of this
section. The Notification of Compliance Status must include the
information and certification(s) of compliance in paragraphs (a)(4)(i)
through (v) of this section, as applicable, and signed by a responsible
official.
* * * * *
    (b) You must prepare, by March 1 of each year, and submit to the
delegated authority upon request, an annual compliance certification
report for the previous calendar year containing the information
specified in paragraphs (b)(1) through (4) of this section. You must
submit the report by March 15 if you had any instance described by
paragraph (b)(3) of this section. For boilers that are subject only to
the energy assessment requirement and/or a requirement to conduct a
biennial or 5-year tune-up according to Sec.  63.11223(a) and not
subject to emission limits or operating limits, you may prepare only a
biennial or 5-year compliance report as specified in paragraphs (b)(1)
and (2) of this section.
* * * * *
    (c) * * *
    (2) * * *
    (iv) For each boiler subject to an emission limit in Table 1 to
this subpart, you must keep records of monthly fuel use by each boiler,
including the type(s) of fuel and amount(s) used. For each new oil-
fired boiler that meets the requirements of Sec.  63.11210(e) or (f),
you must keep records, on a monthly basis, of the type of fuel
combusted.
* * * * *
    (e)(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 associated
fuel analyses, following the procedure specified in either paragraph
(e)(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
(https://www3.epa.gov/ttn/chief/ert/ert_info.html) at the time of the
test, you must submit the results of the performance test to the EPA
via the Compliance and Emissions Data Reporting Interface (CEDRI).
(CEDRI can be accessed through the EPA's Central Data Exchange (CDX)
(https://cdx.epa.gov/).) Performance test data must be submitted in a
file format generated through the use of the EPA's ERT or an alternate
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/
OAQPS/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 Sec.  63.2), you must submit the
results of the performance evaluation following the procedure specified
in either paragraph (e)(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 Web site.
If you claim that some of the performance evaluation information being
submitted is CBI, you must submit a complete file generated through the
use of the EPA's ERT or an alternate electronic file consistent with
the XML schema listed on the EPA's ERT Web site, including information
claimed to be CBI, on a compact disc, flash drive, or other commonly
used electronic storage media to the EPA. The electronic storage media
must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/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 EPA's 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.
* * * * *
    (g) If you have switched fuels or made a physical change to the
boiler and the fuel switch or change resulted in the applicability of a
different subcategory within this subpart, in the boiler becoming
subject to this subpart, or in the boiler switching out of this subpart
due to a fuel change that results in the boiler meeting the definition
of gas-fired boiler, as defined in Sec.  63.11237, or you have taken a
permit limit that resulted in you becoming subject to this subpart or
no longer being subject to this subpart, you must provide notice of the
date upon which you switched fuels, made the physical change, or took a
permit limit within 30 days of the change. The notification must
identify:
* * * * *

Sec.  63.11226  [Removed and Reserved]

0
10. Section 63.11226 is removed and reserved.

0
11. Section 63.11237 is amended by:
0
a. Removing the definition of ``Affirmative defense'';
0
b. Adding in alphabetical order a definition for ``Annual capacity
factor'';
0
c. Revising the definition of ``Dry scrubber'';
0
d. Adding in alphabetical order a definition for ``Fossil fuel'';
0
e. Revising the definitions of ``Gas-fired boiler'', ``Limited-use
boiler'', ``Liquid fuel'', ``Load fraction'', ``Oxygen trim system'',
``Shutdown'', and ``Startup'';
0
f. Adding in alphabetical order definitions for ``Ultra-low-sulfur
liquid fuel'' and ``Useful thermal energy''; and
0
g. Revising the definition of ``Voluntary Consensus Standards (VCS)''.
    The revisions and additions read as follows:

Sec.  63.11237  What definitions apply to this subpart?

* * * * *
    Annual capacity factor means the ratio between the actual heat
input to a boiler from the fuels burned during a calendar year and the
potential heat input to the boiler had it been operated for 8,760 hours
during a year at the

maximum steady state design heat input capacity.
* * * * *
    Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react with and neutralize acid gas in the
exhaust stream forming a dry powder material. Sorbent injection systems
used as control devices in fluidized bed boilers are included in this
definition. A dry scrubber is a dry control system.
* * * * *
    Fossil fuel means natural gas, oil, coal, and any form of solid,
liquid, or gaseous fuel derived from such material.
* * * * *
    Gas-fired boiler includes any boiler that burns gaseous fuels not
combined with any solid fuels and burns liquid fuel only during periods
of gas curtailment, gas supply interruption, startups, or for periodic
testing, maintenance, or operator training on liquid fuel. Periodic
testing, maintenance, or operator training on liquid fuel shall not
exceed a combined total of 48 hours during any calendar year.
* * * * *
    Limited-use boiler means any boiler that burns any amount of solid
or liquid fuels and has a federally enforceable annual capacity factor
of no more than 10 percent.
    Liquid fuel includes, but is not limited to, distillate oil,
residual oil, any form of liquid fuel derived from petroleum, used oil
meeting the specification in 40 CFR 279.11, liquid biofuels, biodiesel,
and vegetable oil.
    Load fraction means the actual heat input of a boiler 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 that co-fire natural 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).
* * * * *
    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 carbon monoxide monitor that automatically provides a
feedback signal to the combustion air controller or draft controller.
* * * * *
    Shutdown means the period in which cessation of operation of a
boiler is initiated for any purpose. Shutdown begins when the boiler no
longer supplies useful thermal energy (such as steam or hot water) for
heating, cooling, or process purposes or generates electricity, or when
no fuel is being fed to the boiler, whichever is earlier. Shutdown ends
when the boiler no longer supplies useful thermal energy (such as steam
or hot water) for heating, cooling, or process purposes or generates
electricity, and no fuel is being combusted in the boiler.
* * * * *
    Startup means:
    (1) Either the first-ever firing of fuel in a boiler for the
purpose of supplying useful thermal energy (such as steam or hot water)
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 (such as steam or
hot water) from the boiler is supplied for heating and/or producing
electricity, or for any other purpose, or
    (2) The period in which operation of a boiler is initiated for any
purpose. Startup begins with either the first-ever firing of fuel in a
boiler for the purpose of supplying useful thermal energy (such as
steam or hot water) for heating, cooling or process purposes or
producing electricity, or the firing of fuel in a boiler for any
purpose after a shutdown event. Startup ends 4 hours after when the
boiler supplies useful thermal energy (such as steam or hot water) for
heating, cooling, or process purposes or generates electricity,
whichever is earlier.
* * * * *
    Ultra-low-sulfur liquid fuel means a distillate oil that has less
than or equal to 15 parts per million (ppm) sulfur.
    Useful thermal energy means energy (i.e., steam or hot water) that
meets the minimum operating temperature, flow, and/or pressure required
by any energy use system that uses energy provided by the affected
boiler.
* * * * *
    Voluntary Consensus Standards (VCS) mean technical standards (e.g.,
materials specifications, test methods, sampling procedures, business
practices) developed or adopted by one or more voluntary consensus
bodies. EPA/Office of Air Quality Planning and Standards, by precedent,
has only used VCS that are written in English. Examples of VCS bodies
are: American Society of Testing and Materials (ASTM, 100 Barr Harbor
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959,
(800) 262-1373, http://www.astm.org), American Society of Mechanical
Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-
2763, http://www.asme.org), International Standards Organization (ISO