[Federal Register Volume 81, Number 178 (Wednesday, September 14, 2016)]
[Rules and Regulations]
[Pages 63112-63131]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[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

[[Page 63113]]

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: (919) 541-5025; fax number: (919) 541-5450; email 
address: [email protected].

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.
------------------------------------------------------------------------


[[Page 63114]]

    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/

[[Page 63115]]

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.

[[Page 63116]]

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

[[Page 63117]]

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.

[[Page 63118]]

    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

[[Page 63119]]

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

[[Page 63120]]

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

[[Page 63121]]

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

[[Page 63122]]

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

[[Page 63123]]

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

[[Page 63124]]

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.

[[Page 63125]]

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).

[[Page 63126]]

    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

[[Page 63127]]

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

[[Page 63128]]

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

[[Page 63129]]

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 
1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, 
Switzerland, +41 22 749 01 11, http://www.iso.org/iso/home.htm), 
Standards Australia (AS Level 10, The Exchange Centre, 20 Bridge 
Street, Sydney, GPO Box 476, Sydney NSW 2001, +61 2 9237 6171 http://www.standards.org.au), British Standards Institution (BSI, 389 Chiswick 
High Road, London, W4 4AL, United Kingdom, +44 (0)20 8996 9001, http://www.bsigroup.com), Canadian Standards Association (CSA, 5060 Spectrum 
Way, Suite 100, Mississauga, Ontario L4W 5N6, Canada, 800-463-6727, 
http://www.csa.ca), European Committee for Standardization (CEN CENELEC 
Management Centre Avenue Marnix 17 B-1000 Brussels, Belgium +32 2 550 
08 11, http://www.cen.eu/cen), and German Engineering Standards (VDI 
Guidelines Department, P.O. Box 10 11 39 40002, Duesseldorf, Germany, 
+49 211 6214-230, http://www.vdi.eu). The types of standards that are 
not considered VCS are standards developed by: the United States, e.g., 
California Air Resources Board (CARB) and Texas Commission on 
Environmental Quality (TCEQ); industry groups, such as American 
Petroleum Institute (API), Gas Processors Association (GPA), and Gas 
Research Institute (GRI); and other branches of the U.S. Government, 
e.g., Department of Defense (DOD) and Department of Transportation 
(DOT). This does not preclude EPA from using standards developed by 
groups that are not VCS bodies within their rule. When this occurs, EPA 
has done searches and reviews for VCS equivalent to these non-EPA 
methods.
* * * * *

0
12. Table 1 to Subpart JJJJJJ of Part 63 is amended by revising the 
entry 6 to read as follows:
* * * * *

[[Page 63130]]



          Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
------------------------------------------------------------------------
                                                   You must achieve less
                                                    than or equal to the
                                For the following    following emission
   If your boiler is in this     pollutants . . .  limits, except during
       subcategory . . .                             periods of startup
                                                     and shutdown . . .
 
------------------------------------------------------------------------
 
                              * * * * * * *
6. Existing coal-fired boilers  a. Mercury.......  2.2E-05 lb per MMBtu
 with heat input capacity of    b. CO............   of heat input.
 10 MMBtu/hr or greater that                       420 ppm by volume on
 do not meet the definition of                      a dry basis
 limited-use boiler.                                corrected to 3
                                                    percent oxygen (3-
                                                    run average or 10-
                                                    day rolling
                                                    average).
------------------------------------------------------------------------


0
13. Table 2 to Subpart JJJJJJ of Part 63 is amended by revising the 
entry 16 to read as follows:

 Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards, Emission
              Reduction Measures, and Management Practices
------------------------------------------------------------------------
  If your boiler is in this
      subcategory . . .            You must meet the following . . .
------------------------------------------------------------------------
 
                              * * * * * * *
16. Existing coal-fired,       Must have a one-time energy assessment
 biomass-fired, or oil-fired    performed by a qualified energy
 boilers (units with heat       assessor. An energy assessment completed
 input capacity of 10 MMBtu/    on or after January 1, 2008, that meets
 hr and greater), not           or is amended to meet the energy
 including limited-use          assessment requirements in this table
 boilers.                       satisfies the energy assessment
                                requirement. Energy assessor approval
                                and qualification requirements are
                                waived in instances where past or
                                amended energy assessments are used to
                                meet the energy assessment requirements.
                                A facility that operated under an energy
                                management program developed according
                                to the ENERGY STAR guidelines for energy
                                management or compatible with ISO 50001
                                for at least 1 year between January 1,
                                2008, and the compliance date specified
                                in Sec.   63.11196 that includes the
                                affected units also satisfies the energy
                                assessment requirement. The energy
                                assessment must include the following
                                with extent of the evaluation for items
                                (1) to (4) appropriate for the on-site
                                technical hours listed in Sec.
                                63.11237:
                                 (1) A visual inspection of the boiler
                               system,
                                 (2) An evaluation of operating
                               characteristics of the affected boiler
                               systems, specifications of energy use
                               systems, operating and maintenance
                               procedures, and unusual operating
                               constraints,
                                 (3) An inventory of major energy use
                               systems consuming energy from affected
                               boiler(s) and which are under control of
                               the boiler owner or operator,
                                 (4) A review of available architectural
                               and engineering plans, facility operation
                               and maintenance procedures and logs, and
                               fuel usage,
                                 (5) A list of major energy conservation
                               measures that are within the facility's
                               control,
                                 (6) A list of the energy savings
                               potential of the energy conservation
                               measures identified, and
                                 (7) A comprehensive report detailing
                               the ways to improve efficiency, the cost
                               of specific improvements, benefits, and
                               the time frame for recouping those
                               investments.
------------------------------------------------------------------------


0
14. Table 6 to Subpart JJJJJJ of Part 63 is amended by revising the 
entry 2 to read as follows:
* * * * *

                                           Table 6 to Subpart JJJJJJ of Part 63--Establishing Operating Limits
--------------------------------------------------------------------------------------------------------------------------------------------------------
 If you have an applicable emission    And your operating limits                                                              According to the following
           limit for . . .                 are based on . . .             You must . . .                Using . . .                  requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
                                                                      * * * * * * *
2. Mercury..........................  Dry sorbent or activated     Establish a site-specific    Data from the sorbent or     (a) You must collect
                                       carbon injection rate        minimum sorbent or           activated carbon injection   sorbent or activated
                                       operating parameters.        activated carbon injection   rate monitors and the        carbon injection rate data
                                                                    rate operating limit         mercury performance stack    every 15 minutes during
                                                                    according to Sec.            tests.                       the entire period of the
                                                                    63.11211(b).                                              performance stack tests;

[[Page 63131]]

 
                                                                                                                             (b) Determine the average
                                                                                                                              sorbent or activated
                                                                                                                              carbon injection rate for
                                                                                                                              each individual test run
                                                                                                                              in the three-run
                                                                                                                              performance stack test by
                                                                                                                              computing the average of
                                                                                                                              all the 15-minute readings
                                                                                                                              taken during each test
                                                                                                                              run.
                                                                                                                             (c) When your unit operates
                                                                                                                              at lower loads, multiply
                                                                                                                              your sorbent or activated
                                                                                                                              carbon injection rate by
                                                                                                                              the load fraction, as
                                                                                                                              defined in Sec.
                                                                                                                              63.11237, to determine the
                                                                                                                              required injection rate.
 
                                                                      * * * * * * *
--------------------------------------------------------------------------------------------------------------------------------------------------------

[FR Doc. 2016-21334 Filed 9-13-16; 8:45 am]
 BILLING CODE 6560-50-P