[Federal Register Volume 85, Number 73 (Wednesday, April 15, 2020)]
[Rules and Regulations]
[Pages 20838-20855]
[FR Doc No: 2020-07878]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2018-0794; FRL-10007-26-OAR]
RIN 2060-AU48

National Emission Standards for Hazardous Air Pollutants: Coal-
and Oil-Fired Electric Utility Steam Generating Units--Subcategory of
Certain Existing Electric Utility Steam Generating Units Firing Eastern
Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air
Pollutants

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: The U.S. Environmental Protection Agency (EPA) is taking final
action establishing a subcategory of certain existing electric utility
steam generating units (EGUs) firing eastern bituminous coal refuse
(EBCR) for acid gas hazardous air pollutant (HAP) emissions that was
noticed in a February 7, 2019, proposed rule titled ``National Emission
Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric
Utility Steam Generating Units--Reconsideration of Supplemental Finding
and Residual Risk and Technology Review'' (2019 Proposal). After
consideration of public comments, the EPA has determined that there is
a need for such a subcategory under the National Emission Standards for
Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired EGUs,
commonly known as the Mercury and Air Toxics Standards (MATS), and the
Agency is establishing acid gas HAP emission standards applicable only
to the new subcategory. The EPA's final decisions on the other two
distinct actions in the 2019 Proposal (i.e., reconsideration of the
2016 Supplemental Finding that it is appropriate and necessary to
regulate EGUs under Clean Air Act (CAA) section 112 and the residual
risk and technology review of MATS) will be announced in a separate
final action.

DATES: This final rule is effective on April 15, 2020.

ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2018-0794. All documents in the docket are
listed on the https://www.regulations.gov/ website. Although listed,
some information is not publicly available, e.g., confidential business
information or other information whose disclosure is restricted by
statute. Certain other material, such as copyrighted material, is not
placed on the internet and will be publicly available only in hard copy
form. Publicly available docket materials are available either
electronically through https://www.regulations.gov/, or in hard copy at
the EPA Docket Center, Room Number 3334, WJC West Building, 1301
Constitution Ave. NW, Washington, DC. The Public Reading Room hours of
operation are 8:30 a.m. to 4:30 p.m., Eastern Standard Time (EST),
Monday through Friday. The telephone number for the Public Reading Room
is<PHONE_NUMBER>, and the telephone number for the EPA Docket Center
is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: For questions about this final action,
contact Mary Johnson, Sector Policies and Programs Division (D243-01),
Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711;
telephone number:<PHONE_NUMBER>; and email address:
<EMAIL_ADDRESS>For information about the applicability of the
NESHAP to a particular entity, contact your EPA Regional representative
as listed in 40 CFR 63.13 (General Provisions).

SUPPLEMENTARY INFORMATION:
    Preamble acronyms and abbreviations. The EPA uses multiple acronyms
and terms in this preamble. While this list may not be exhaustive, to
ease the reading of this preamble and for reference purposes, the EPA
defines the following terms and acronyms here:

ARIPPA Appalachian Region Independent Power Producers Association
CAA Clean Air Act
CEMS continuous emissions monitoring systems
CFR Code of Federal Regulations
CRA Congressional Review Act
DSI dry sorbent injection
EBCR eastern bituminous coal refuse
ECMPS Emissions Collection and Monitoring Plan System
EGU electric utility steam generating unit
EPA Environmental Protection Agency
FBC fluidized bed combustors

FGD flue gas desulfurization
HAP hazardous air pollutant(s)
HCl hydrochloric acid
Hg mercury
ICR Information Collection Request
lb pound
lb/MMBtu pounds per million British thermal units
lb/MWh pounds per megawatt-hour
MACT maximum achievable control technology
MATS Mercury and Air Toxics Standards
MMBtu million British thermal units
MW megawatt
MWh megawatt-hour
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
PM particulate matter
PM2.5 fine particulate matter
PRA Paperwork Reduction Act
RFA Regulatory Flexibility Act
SDA spray dryer absorbers
SO2 sulfur dioxide
tpy tons per year
UMRA Unfunded Mandates Reform Act

Organization of this document. The information in this preamble is
organized as follows:

I. General Information
    A. Executive Summary
    B. Does this action apply to me?
    C. Where can I get a copy of this document and other related
information?
    D. Judicial Review and Administrative Reconsideration
II. Background
III. Summary of Final Action
    A. Basis for Subcategory
    B. Subcategory Emission Standards
IV. Summary of Cost, Environmental, and Economic Impacts and
Additional Analyses Conducted
    A. What are the affected sources?
    B. What are the air quality impacts?
    C. What are the compliance cost impacts?
    D. What are the economic impacts?
    E. What are the forgone benefits?
V. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
    C. Paperwork Reduction Act (PRA)
    D. Regulatory Flexibility Act (RFA)
    E. Unfunded Mandates Reform Act (UMRA)
    F. Executive Order 13132: Federalism
    G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    J. National Technology Transfer and Advancement Act (NTTAA)
    K. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
    L. Congressional Review Act (CRA)

I. General Information

A. Executive Summary

    In the 2012 MATS rulemaking, the EPA established one subcategory of
coal-fired EGUs for purposes of regulating acid gas HAP emissions. The
Agency specifically rejected a request from some commenters for a
separate acid gas HAP standard for all coal refuse-fired EGUs because
we determined that the emissions of such HAP from some units combusting
coal refuse were among the best performing sources for acid gas HAP as
determined consistent with CAA section 112(d)(3). The EPA has
reevaluated the data available when the 2012 MATS rule was established,
in addition to new data generated since promulgation of that rule, and
we now recognize that there are differences in the acid gas HAP
emissions from EGUs firing EBCR as compared to EGUs firing other types
of coal, including those firing types of coal refuse other than EBCR.
Specifically, the EPA recognizes that there are differences between
anthracite coal refuse and bituminous coal refuse, and that the type of
fuel used leads to differences in the acid gas HAP emissions from EGUs
firing those respective fuels. In the February 7, 2019 Proposal (84 FR
2670), the EPA explained that these differences in acid gas HAP
emissions support the establishment of a subcategory for such sources
and solicited comment on the need to establish a subcategory of certain
existing EGUs firing EBCR for acid gas HAP emissions and on potential
emissions standards for affected EGUs in that subcategory. After
reviewing public comments and other available information, the EPA
concludes that such a subcategory is warranted. Thus, this final action
establishes a subcategory of certain existing EBCR-fired EGUs for
emissions of hydrochloric acid (HCl) and sulfur dioxide
(SO2)--both of which serve as a surrogate for all acid gas
HAP emitted from EGUs under MATS. Under CAA section 112(d)(1), the EPA
has the discretion to ``. . . distinguish among classes, types, and
sizes of sources within a category or subcategory in establishing . . .
standards.'' Further, when separate subcategories are established, the
minimum level of control, referred to as the ``maximum achievable
control technology (MACT) floor,'' is determined separately for each
subcategory.
    The EPA has determined that emission limits reflecting a more
stringent (i.e., ``beyond-the-floor'') level of control than the MACT
floor level of control are appropriate for the new subcategory. The
SO2 emission standard (set in pounds (lb) SO2/
million British thermal units (MMBtu)) that the EPA is promulgating
here is an emission rate that the currently operating EBCR-fired EGUs
have demonstrated an ability to achieve based on their emissions data
and considering cost and non-air quality related environmental
factors.\1\ The EPA does not have corresponding emissions data for HCl
\2\ or output-based emissions of SO2 (i.e., lb
SO2/megawatt-hour (MWh)) and, therefore, the EPA has
established the final beyond-the-floor standards for SO2 (in
lb/MWh) and for HCl (in both lb/MMBtu and lb/MWh) consistent with the
percentage reduction in the SO2 lb/MMBtu emissions rate
between the MACT floor value and the beyond-the-floor value. This
action establishes the following emission limits for the subcategory of
existing EBCR-fired EGUs: \3\
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    \1\ For context, the 2012 final MATS emission standard for
SO2 is 2.0E-1 lb/MMBtu.
    \2\ For MATS, affected sources may report emissions of either
SO2 or HCl. Most MATS-affected EGUs report emissions of
SO2 because they already have the monitoring
infrastructure to do so, since most already report SO2
emissions under the EPA's Acid Rain Program.
    \3\ Continuous compliance with the emission limits is required
to be demonstrated on a 30-boiler operating day rolling average
basis.

HCl: 4.0E-2 lb/MMBtu or 4.0E-1 lb/MWh
SO2: \4\ 6.0E-1 lb/MMBtu or 9.0 lb/MWh.
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    \4\ As is the requirement for all coal-fired EGUs subject to
MATS, the alternate SO2 limit may be used if the EGU has
some form of flue gas desulfurization (FGD) system and
SO2 continuous emissions monitoring systems (CEMS) and
both are installed and operated at all times.

    A further description of what the EPA is promulgating here, the
rationale for the final decisions, and discussion of the key comments
received regarding the need for such a subcategory and the acid gas HAP
emission standards appropriate for that subcategory are provided in
section III of this preamble.

B. Does this action apply to me?

    Categories and entities potentially regulated by this action are
shown in Table 1 of this preamble.

 Table 1--Neshap and Industrial Source Categories Affected by This Final
                                 Action
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               NESHAP and source  category                NAICS code \a\
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Coal- and Oil-Fired EGUs................................  221112, 221122
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\a\ North American Industry Classification System.

    Table 1 of this preamble is not intended to be exhaustive, but
rather to provide a guide for readers regarding entities likely to be
affected by the final action for the source category listed.
Specifically, entities that own and/or operate certain existing EBCR-
fired EGUs subject to the NESHAP for Coal- and Oil-Fired EGUs (40 CFR
part 63, subpart UUUUU) will be affected by this final action. To
determine whether your facility is affected, you should examine the
applicability criteria in the NESHAP for Coal- and Oil-Fired EGUs and
the amendatory text of this final action. If you have any questions
regarding the applicability of any aspect of this NESHAP, please
contact the appropriate person listed in the preceding FOR FURTHER
INFORMATION CONTACT section of this preamble.

C. Where can I get a copy of this document and other related
information?

    In addition to being available in the docket, an electronic copy of
this action is available on the internet. Following signature by the
EPA Administrator, the EPA will post a copy of this final action at
https://www.epa.gov/mats/regulatory-actions-final-mercury-and-air-toxics-standards-mats-power-plants. Following publication in the
Federal Register, the EPA will post the Federal Register version of the
final rule and key technical documents at this same website.

D. Judicial Review and Administrative Reconsideration

    Under CAA section 307(b)(1), judicial review of this final action
is available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit (hereafter
referred to as ``the D.C. Circuit,'' or ``the Court'') by June 15,
2020. 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 the requirements.
    Section 307(d)(7)(B) of the CAA further provides that only 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. This section also
provides a mechanism for the EPA to reconsider the rule if the person
raising an objection can demonstrate to the Administrator that it was
impracticable to raise such objection within the period for public
comment 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.
Any person seeking to make such a demonstration should submit a
Petition for Reconsideration to the Office of the Administrator, U.S.
EPA, Room 3000, WJC South Building, 1200 Pennsylvania Ave. NW,
Washington, DC 20460, with a copy to both the person(s) listed in the
preceding FOR FURTHER INFORMATION CONTACT section of this preamble, and
the Associate General Counsel for the Air and Radiation Law Office,
Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200
Pennsylvania Ave. NW, Washington, DC 20460.

II. Background

    The NESHAP for Coal- and Oil-Fired EGUs (commonly referred to as
MATS) was proposed on May 3, 2011 (76 FR 24976), under title 40, part
63, subpart UUUUU. In that proposal, the EPA proposed a single acid gas
HAP emission standard for all coal-fired power plants--using HCl as a
surrogate for all acid gas HAP. The EPA also proposed an alternative
equivalent emission standard for SO2 as a surrogate for all
the acid gas HAP for coal-fired EGUs with FGD systems and
SO2 CEMS installed and operational at all times.
SO2 is also an acidic gas--though not a HAP--and the
controls used for SO2 emission reduction are also effective
at controlling the acid gas HAP emitted by EGUs. Further, most, if not
all, affected EGUs already measure and report SO2 emissions
as a requirement of the EPA's Acid Rain Program, 40 CFR part 75.
    The Appalachian Region Independent Power Producers Association
(ARIPPA) \5\ submitted comments on the 2011 MATS proposal arguing that
the characteristics of all coal refuse made achievement of the standard
too costly for its members and requested that the EPA create a
subcategory for all EGUs burning coal refuse. The EPA determined that
there was no basis to create such a subcategory and, on February 16,
2012 (77 FR 9304), finalized emission standards for both HCl and
SO2 that apply to all coal-fired EGUs, including the coal
refuse-fired units subject to this final action. ARIPPA, along with
other petitioners, challenged the EPA's determination in the D.C.
Circuit, and the Court upheld the final rule. White Stallion Energy
Center, et. al. v. EPA, 748 F.3d 1222, 1249-50 (D.C. Cir. 2014).
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    \5\ ARIPPA is a non-profit trade association comprised of
independent electric power producers, environmental remediators, and
service providers located in Pennsylvania and West Virginia that use
coal refuse as a primary fuel to generate electricity.
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    In addition to challenging the final rule, ARIPPA also petitioned
the EPA for reconsideration, again requesting a subcategory for the
acid gas standards for facilities combusting all types of coal refuse.
The EPA denied the Petition for Reconsideration on grounds that ARIPPA
had adequate opportunity to comment on the ability of coal refuse-fired
facilities to comply with the final standard. Furthermore, the EPA
determined that the ARIPPA petition did not present any new information
to support a change in the previous determination regarding the
appropriateness of a subcategory for the acid gas HAP standard. ARIPPA
subsequently sought judicial review of the denial of the Petition for
Reconsideration. ARIPPA v. EPA, No. 15-1180 (D.C. Cir.).\6\ In
petitioner's briefs, ARIPPA claimed that the EPA had misunderstood its
reconsideration petition and pointed to a distinction between the
control of acid gas HAP emissions from units burning anthracite coal
refuse and those burning bituminous coal refuse. See Industry Pets. Br.
at 35-36, ARIPPA, No. 15-1180 (D.C. Cir. filed December 6, 2016). The
EPA disagrees with the assertion that the Agency misunderstood the
basis for ARIPPA's reconsideration petition as we could not find a
single statement in the rulemaking record that clearly or even vaguely
requested a separate acid gas HAP limit based on the distinction
between anthracite coal refuse and bituminous coal refuse. Nonetheless,
the EPA has since looked at emissions data from these sources and
observed that there are differences in emissions based on the type of
coal refuse used, and, consequently, recognized the differences in the
2019 Proposal.\7\ Specifically, the EPA recognized that there are
differences between anthracite coal refuse and bituminous coal refuse,
and that the type of fuel used leads to differences in the acid gas HAP

emissions from EGUs firing those respective fuels. The Agency also
noted that the differences may impact the unit's ability to control
those emissions. Additionally, the EPA recognized that there are
differences between western bituminous coal refuse and subbituminous
coal refuse as compared to EBCR and announced in the 2019 Proposal that
it was considering establishing a subcategory of certain existing EGUs
firing EBCR for emissions of acid gas HAP. The proposal solicited
comment on whether establishment of such a subcategory is needed and on
the acid gas HAP emission standards that would be established if such a
subcategory was created. 84 FR 2700-2703.
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    \6\ ARIPPA's petition for review is currently being held in
abeyance. ARIPPA v. EPA, No. 15-1180, Order, No. 1672985 (April 27,
2017).
    \7\ The analysis is summarized in a separate memorandum titled
HCl and SO2 Emissions for Coal Refuse-Fired EGUs,
available in Docket ID No. EPA-HQ-OAR-2018-0794.
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III. Summary of Final Action

    After considering and evaluating comments and data provided in
response to the solicitation of comment on establishing a subcategory
of certain existing EGUs firing EBCR for emissions of acid gas HAP in
its 2019 Proposal, the EPA is taking final action to establish a
separate subcategory to address the issue. In this final action, the
EPA is establishing a subcategory of certain existing EGUs firing EBCR
for emissions of acid gas HAP and acid gas HAP emission standards that
are applicable to the new subcategory. The final rule defines Eastern
bituminous coal refuse (EBCR) to mean coal refuse generated from the
mining of bituminous coal in Pennsylvania and West Virginia. The final
rule defines Unit designed for eastern bituminous coal refuse (EBCR)
subcategory to mean any existing (i.e., construction was commenced on
or before May 3, 2011) coal-fired EGU with a net summer capacity of no
greater than 150 megawatts (MW) that is designed to burn and that is
burning 75 percent or more (by heat input) eastern bituminous coal
refuse on a 12-month rolling average basis. The 150 MW net summer
capacity level selected by the EPA limits the universe of sources that
are in the new subcategory to only those EGUs identified in Table 2 to
this preamble. Net summer capacity is the maximum output that
generating equipment can supply to system load at the time of summer
peak demand (period of June 1 through September 30). The 75 percent or
more heat input requirement selected by the EPA is consistent with the
Federal Energy Regulatory Commission requirement that to be considered
a qualifying facility under the Public Utility Regulatory Policies Act,
as the EGUs in the new subcategory are, at least 75 percent of the heat
content must come from coal refuse.
    The existing EBCR-fired EGUs in the new subcategory being
established in this action are listed in Table 2 of this preamble and
the applicable HCl and SO2 limits being finalized in this
action are provided in Table 3 of this preamble. Four existing EBCR-
fired EGUs at two facilities that were listed in the 2019 Proposal as
being part of the new subcategory, if established, are no longer part
of the subcategory. The EPA has learned that the Cambria facility shut
down in June 2019, and the facility and surrounding property have been
sold to a salvage company which plans to dismantle the facility over
time.\8\ The EPA has also learned that the Morgantown Energy facility
will be transformed into a natural gas-fueled steam-only production
facility, and the closure of the waste coal-fired boilers and complete
transformation of the facility to steam-only production are expected to
be completed by early to mid-2020.\9\
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    \8\ See https://www.tribdem.com/news/cambria-cogen-plant-to-be-leveled-after-shutting-down-over/article_005a162c-2381-11ea-8c53-5b85339774fd.html.
    \9\ See https://www.nsenergybusiness.com/news/starwood-energy-terminates-eepa/.

                                     Table 2--EBCR-Fired EGUs in Subcategory
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                                                                                2016 average
                                                                                Summer          monthly
         ORIS plant code \a\                     EGU                  State        capacity (MW)    generation
                                                                                (MWh) \b\
----------------------------------------------------------------------------------------------------------------
10143................................  Colver Power Project...  PA                           110          60,905
10151................................  Grant Town Power Plant   WV                            40          28,010
                                        Unit 1A.
10151................................  Grant Town Power Plant   WV                            40          28,010
                                        Unit 1B.
10603................................  Ebensburg Power........  PA                            50          16,258
50974................................  Scrubgrass Generating    PA                            42          17,377
                                        Company LP Unit 1.
50974................................  Scrubgrass Generating    PA                            42          17,377
                                        Company LP Unit 2.
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\a\ Unique plant identification code assigned by the Department of Energy's Energy Information Administration
  (EIA).
\b\ 2016 annual generation is based on plant-level data reported on EIA Form 923, and annual totals are divided
  evenly to estimate 2016 average monthly generation. Unit-level estimates assume that generation is split
  evenly between all units at each plant.

 Table 3--Acid Gas Emission Limitations for EBCR-Fired EGUs Subcategory
------------------------------------------------------------------------
                                            Emission limit \a\
           Subcategory           ---------------------------------------
                                          HCl               SO2 \b\
------------------------------------------------------------------------
Existing Eastern Bituminous Coal  4.0E-2 lb/MMBtu...  6.0E-1 lb/MMBtu
 Refuse-Fired EGUs.
                                  or                  or
                                  4.0E-1 lb/MWh.....  9.0 lb/MWh
------------------------------------------------------------------------
\a\ Units of emission limits:
lb/MMBtu = pounds pollutant per million British thermal units fuel
  input; and
lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
\b\ Alternate SO2 limit may be used if the EGU has some form of FGD
  system and SO2 CEMS installed.

    Sources in the new subcategory must comply with the applicable HCl
or SO2 requirements no later than the effective date of this
final rule. Sources must demonstrate that compliance has been achieved,
by conducting the required performance tests and other activities as
specified in 40 CFR part 60, subpart UUUUU, no later than 180 days
after the compliance date. To demonstrate initial compliance using
either an HCl or SO2 CEMS, the initial performance test

consists of 30-boiler operating days. If the CEMS is certified prior to
the compliance date, the test begins with the first operating day on or
after that date. If the CEMS is not certified prior to the compliance
date, the test begins with the first operating day after certification
testing is successfully completed. Continuous compliance with the newly
established emission limits is required to be demonstrated on a 30-
boiler operating day rolling average basis.
    The EPA's final decisions regarding establishing a subcategory for
certain existing EGUs that fire EBCR and the acid gas HAP standards
applicable to the new subcategory are provided later in this section of
this preamble. Specifically, the EPA's rationale for the final
decisions and discussion relating to the key comments received
regarding the need for such a subcategory and the attendant acid gas
HAP emission standards are provided. A summary of all significant
public comments regarding the EPA's consideration of establishing such
a subcategory and the EPA's responses to those comments is available in
the document titled Summary of Public Comments and Responses Regarding
Establishment of a Subcategory and Acid Gas HAP Emission Standards for
Certain Existing Eastern Bituminous Coal Refuse-Fired EGUs (response to
comments document), Docket ID No. EPA-HQ-OAR-2018-0794. A ``track
changes'' version of the regulatory language that incorporates the
changes in this action is also available in the docket for this action.

A. Basis for Subcategory

    Under CAA section 112(d)(1), the Administrator has discretion to
``* * * distinguish among classes, types, and sizes of sources within a
category or subcategory in establishing * * *'' standards. Based on the
EPA's better understanding of the differences in anthracite coal refuse
and bituminous coal refuse, and the acid gas HAP emissions profile
associated with each, the EPA has now determined that, contrary to its
earlier position, it is appropriate to establish a new subcategory for
certain units firing EBCR. Specifically, the EPA is establishing a new
subcategory for certain units with a net summer capacity of 150 MW or
lower that fire EBCR because there are differences between emissions of
acid gas HAP from these units and larger units burning EBCR and units
burning other types of coal, including other types of coal refuse. See
U.S. Sugar Corp. v. EPA, 830 F.3d 579, 656 (DC Cir. 2016) (finding that
``[s]ection 7412(d) gives the EPA discretion to create subcategories
based on boiler type, and nothing in the statute forecloses the Agency
from doing so based on the type of fuel a boiler was designed to
burn.''). Units in this new subcategory of EGUs are smaller, were
designed to burn EBCR, and were constructed in close proximity to
legacy piles of EBCR for the primary purposes of reclaiming abandoned
mining sites while reducing the environmental hazards attendant to such
piles of coal refuse. The EPA cannot predict with certainty what the
industry response would be absent the establishment of a new
subcategory as discussed in greater detail elsewhere in this preamble
and in a docketed memorandum on expected costs and benefits. Among
those possible outcomes, many industry commenters and others have
suggested that some--and maybe all--of the affected sources would shut
down.\10\ If that is the case, then the establishment of this new
subcategory will allow those units to continue to achieve both of their
purposes of reclaiming abandoned mining sites and preserving the
environmental benefits of repurposing coal refuse, while also
maintaining emissions of acid gas HAP at levels similar to current
emissions levels.\11\
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    \10\ While the EPA cannot predict with certainty what the
industry response would be in the absence of a new subcategory,
commenters' claims that the units would shut down is plausible.
Coal-fired power plants are currently facing tremendous competitive
pressures. As a result, coal's share of total U.S. electricity
generation has been declining for over a decade, while generation
from natural gas and renewables has increased significantly. A large
number of coal units--especially smaller ones like the EBCR-fired
EGUs--have retired since 2010. As mentioned earlier, four of the ten
units that were identified as affected by this action in the 2019
Proposal have now either retired or announced plans to convert to
natural gas.
    \11\ EBCR-fired EGUs were designed to achieve a control level
generally at or exceeding 90 percent SO2 reduction (see
EPA Docket ID Item Nos. EPA-HQ-OAR-2018-0794-1125, EPA-HQ-OAR-2018-
0794-1154, and EPA-HQ-OAR-2018-0794-1187).
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    Immediately below and in the response to comments document, we
discuss in more detail the basis for the new subcategory and address
the significant comments on the new subcategory.
    As stated in the 2019 Proposal, the EPA finds that the emissions of
acid gas HAP from EGUs firing EBCR are distinct from acid gas HAP
emissions from EGUs firing other types of coal--including other forms
of coal refuse. Specifically, the EPA recognized in the 2019 Proposal
that there are differences between anthracite coal refuse and
bituminous coal refuse, and that the type of fuel used leads to
differences in the acid gas HAP emissions from EGUs firing those
respective fuels. Bituminous coals (and, thus, bituminous coal refuse)
from the Appalachian and Interior Regions of the U.S. have higher
sulfur and chlorine contents than anthracite or coals of all types from
the Western Region of the U.S. (and, thus, anthracite coal refuse or
western bituminous and subbituminous coal refuse), and these
differences lead to differences in emissions of acid gas HAP. These
differences between the types of coal refuse used by EGUs to generate
electricity may also impact a unit's ability to control those
emissions. All coal refuse fuels are fired in fluidized bed combustors
(FBC) that use limestone injection to reduce SO2 emissions
and to increase heat transfer efficiency. The EPA has been informed
that limestone injection technology is generally adequate to allow EGUs
that are firing anthracite coal refuse and western coal refuse to meet
the 2012 final MATS alternative surrogate emission standard of 2.0E-1
lb/MMBtu for SO2.\12\ This is because anthracite coals are
naturally much lower in impurities (including sulfur and chlorine) and
western coals (western bituminous coal and subbituminous coal) have
lower sulfur and chlorine content and higher free alkalinity (which can
act as a natural sorbent to neutralize acid gases produced in the
combustion process). The same is not generally true for EGUs combusting
EBCR. Because all existing EGUs firing anthracite coal refuse and
western bituminous coal refuse are currently emitting SO2 at
rates that are below the 2012 final MATS emission standard for
SO2 and the existing EGU firing subbituminous coal refuse is
currently emitting HCl at a rate that is below the 2012 final MATS
emission standard for HCl, the EPA believes there is no need to broaden
the subcategory to include those units.
---------------------------------------------------------------------------

    \12\ See Table 2 to subpart UUUUU of 40 CFR part 63.
---------------------------------------------------------------------------

    The EBCR-fired EGUs that will be included in the new subcategory
are also small units (all have capacities less than 120 MW and most are
less than 100 MW). As contemplated in the 2019 Proposal, this final
rule excludes the two EBCR-fired EGUs at the Seward Generating Station
in Pennsylvania from the new subcategory. 84 FR 2702. Those units are
the newest and, at 260 MW each, are, by far, the largest coal refuse-
fired EGUs. The Seward units were also designed and constructed with
downstream acid gas controls already incorporated, so they do not have
the space limitations and other configurational challenges that may

affect other smaller existing EBCR-fired EGUs attempting to retrofit
air pollution controls. Retrofitting air pollution controls to an
existing EGU can often be challenging due to lack of available space
within the facility and the potential need to re-route the exhaust gas
stream to accommodate such equipment configurational changes. Control
equipment that results in pressure drop along the exhaust stream can
challenge existing blowers. These challenges and space limitations can
be considered in the design of a new facility. The Seward units were
among the best performing EGUs--with respect to HCl emissions--when the
EPA developed the final MATS emission standards and, based on MATS
compliance reports for the Seward EGUs, currently emit HCl at well
below the final MATS HCl standard of 2.0E-3 lb/MMBtu, applicable to
coal-fired EGUs.\13\
---------------------------------------------------------------------------

    \13\ Ibid.
---------------------------------------------------------------------------

    In response to the 2019 Proposal's solicitation of comment, the EPA
received comments both supporting and opposing the establishment of a
subcategory of certain existing EGUs firing EBCR for emissions of acid
gas HAP.
    Several commenters pointed out the environmental benefits provided
by EBCR-fired EGUs in the coal regions where they are located.
Specifically, commenters pointed out that removal of coal refuse piles
reduces surface and groundwater pollution from acidic drainage and
reduces uncontrolled emissions of air pollutants that are released from
self-ignited internal smoldering of the coal refuse piles. In addition,
commenters pointed out that the alkaline ash produced by EBCR-fired
EGUs is used to reclaim mining-affected lands by returning them to a
productive use. Commenters further noted that the Pennsylvania
Department of Environmental Protection has standards governing such
beneficial use of coal ash in mine land reclamation (Title 25 PA Code,
Chapter 290).\14\
---------------------------------------------------------------------------

    \14\ See https://www.dep.pa.gov/Business/Land/Mining/BureauofMiningPrograms/Pages/CoalAshBeneficialUse.aspx.
---------------------------------------------------------------------------

    Several commenters asserted that the 2012 final MATS limits for
acid gas HAP and their SO2 surrogate are not achievable by
EBCR-fired EGUs and do not reflect the design, functionality, and
economics of those units. Commenters stated that while limestone
injection into the unit's combustion zone controls SO2 and
HCl emissions to a certain extent, there are operational and design
limitations on the EGUs' ability to provide an adequate amount of
limestone to reduce SO2 and HCl emissions beyond a certain
point. Commenters further stated that the reduction of SO2
and acid gases through increased injection of limestone is asymptotic,
and significant additional limestone does not result in further
significant acid gas emission reduction. Commenters explained that the
configuration of the EGUs and their combustion zone physically limit
the amount of material that the unit can hold, which impacts and limits
the amount of coal refuse and limestone that can be injected into the
unit. Commenters explained, for example, that increasing the amount of
limestone injected to achieve the 2012 final MATS SO2
emission limit could result in less coal refuse being fired. This would
result in a corresponding reduction in steam production and electricity
generation, making it uneconomic to operate in the current power
market.
    The EPA does not have detailed information regarding the specific
amount of limestone that is injected into the EBCR-fired EGUs. However,
the Agency acknowledges that it is current industry practice to inject
limestone into the FBC in amounts based on an optimized calcium-to-
sulfur (Ca:S) molar ratio. Therefore, the optimum limestone injection
amount will vary with the sulfur content of the coal refuse being
burned. Along with the coal (fuel) and limestone that are injected and
utilized, the fluidized bed units also contain an inert bed material
(e.g., sand or other). There is a limit to the amount of solid
material--i.e., the sand, the coal refuse, coal ash, and limestone--
that can be in the combustor. An increase in limestone injection may
necessarily result in a decrease in coal refuse utilization.
Utilization of the limestone for acid gas neutralization is dependent
upon decomposition (calcination) of the limestone to lime and
subsequent reaction of the lime with the acid gases via the following
reactions:

CaCO3 + heat [rarr] CaO + CO2
SO2 + CaO [rarr] CaSO3
2HCl + CaO [rarr] CaCl2 + H2O

    The necessary calcination of the limestone and the desulfurization
reactions occur within specific temperature ranges (typically around ~
900 [deg]Celsius or 1,650 [deg]F) and the FBC operators must utilize
sufficient fuel to maintain the boiler in the optimum temperature
range. Lower temperatures result in insufficient calcination and lower
boiler efficiency. Higher temperatures can result in materials
sintering, which results in lower desulfurization capacity.
    Commenters also noted concerns that a significant increase in
limestone injection for control of SO2 emissions could
negatively impact the ability to beneficially use the combustion fly
ash.\15\ For example, for certain uses, the Pennsylvania Department of
Environmental Protection Guidelines for Beneficial Use of Coal Ash at
Coal Mines \16\ warns that mixing of coal ash with conventional
alkaline materials (e.g., limestone, lime, hydrated lime) may increase
the likelihood of the coal ash becoming cementitious and reduce the
neutralizing ability of the coal ash and the conventional material. In
such cases, the captured fly ash would have to be disposed of in a
lined landfill rather than beneficially reused. Commenters also
contended that EBCR-fired EGUs may have to consider switching from EBCR
as the primary fuel to firing less EBCR along with a lower sulfur fuel
as a means of reducing SO2 emissions to meet the 2012 final
MATS SO2 emission limit. Commenters stated that such
practice, in addition to being uneconomical, could reduce EBCR usage to
below the minimum 75-percent coal refuse heat input requirement to be
considered a qualifying facility under the Public Utility Regulatory
Policies Act. Commenters claimed that both approaches described earlier
(i.e., increased limestone injection and fuel switching) undermine the
environmental benefits realized by the EBCR-fired EGUs through clean-up
of waste coal refuse sites.
---------------------------------------------------------------------------

    \15\ The combustion ash is beneficially used on mine sites to
fill pits, create or amend soil, and as a low-permeability or high
alkalinity material. In Pennsylvania the regulations governing the
beneficial use of coal ash are available at 25 PA Code Chapter 290.
See http://www.dep.pa.gov/Business/Land/Mining/BureauofMiningPrograms/Pages/CoalAshBeneficialUse.aspx.
    \16\ Pennsylvania Department of Environmental Protection Bureau
of Mining Programs; Document Number: 563-2112-228; Guidelines for
Beneficial Use of Coal Ash at Coal Mines; Effective date: December
17, 2016.
---------------------------------------------------------------------------

    One commenter stated that regardless of limestone addition and fuel
switching, meeting the 2012 final MATS SO2 limit would
require additional control technology and likely result in permanent
retirement of the facility. Several commenters pointed out that they
are not aware of any retrofit installation of back-end scrubbing
technology or a back-end dry sorbent injection (DSI) system for an
EBCR-fired EGU. Commenters asserted that downstream acid gas controls
cannot be considered technically or economically feasible for EBCR-
fired EGUs and provided information regarding evaluation of such
technologies.

Commenters claimed that adding on back-end control equipment would
boost sulfur capture, but the capital and operating costs increases
would not be supported by power sales revenues. Commenters further
claimed that in addition to being cost prohibitive for the small EBCR
units, control strategies such as wet FGD scrubbers and spray dryer
absorbers (SDA) present installation difficulties given layout of the
facilities, local topography, and needs of the systems to interface
with existing EGU equipment.\17\ Although commenters acknowledged that
DSI systems do not present such technical challenges with deployment,
they pointed out other problems associated with the alkaline sorbents
(typically sodium- or calcium-based) injected in such systems. Several
commenters stated that coal refuse-fired EGUs currently achieve
extremely efficient mercury (Hg) control due, at least in part, to the
relatively high levels of chlorine in coal refuse which can promote the
oxidation of the Hg to the divalent form. This, coupled with the higher
levels of unburned carbon in the fly ash, allows the Hg to be more
readily captured in the downstream baghouse (i.e., fabric filter
particulate matter (PM) control device) and not emitted through the
stack. Commenters explained that reducing the amount of chlorine (or
HCl) in the flue gas prior to the oxidation reaction can have the
effect of increasing Hg emissions from the facility. One commenter
stated that their testing of both sodium- and calcium-based sorbents
injected at the inlet of the baghouse (essentially in a DSI
configuration) resulted in an increase in Hg emissions by a factor of 4
to 40 times resulting in levels exceeding the 2012 final MATS Hg
emission limit.\18\ Therefore, the commenter asserted that, even if
technically feasible, the use of DSI could affect the unit's ability to
meet other MATS emission limits. Several commenters stated that the
potential for DSI technology to have a negative impact on the ability
to use combustion ash for mine site reclamation and restoration
activities would remove it as a viable alternative. Commenters
explained that use of sodium-based sorbents (e.g., trona or sodium
bicarbonate) could alter the leaching characteristics of the ash such
that it would no longer be of beneficial use and would have to be
disposed of in a lined landfill. One commenter stated that testing at
their facility confirmed such a change in the quality of the ash to the
point that it was at risk of failing to satisfy leaching requirements
of the standards for beneficial use in mine land reclamation.
Commenters claimed that ash disposal costs, especially when considering
the significant quantity of ash generated, would far exceed the revenue
generated through the sale of electricity. Commenters also pointed out
that significant environmental benefits provided by EBCR-fired EGUs
would be eliminated if the ash cannot be beneficially used.
---------------------------------------------------------------------------

    \17\ See EPA Docket ID Item Nos. EPA-HQ-OAR-2018-0794-1154 and
EPA-HQ-OAR-2018-0794-1160 for additional discussion of commenters'
claims of physical and configurational difficulties in installing
downstream control technologies.
    \18\ This testing is described in materials provided to the EPA
by ARIPPA during a March 13, 2013, meeting. The materials are
available in the previous MATS rulemaking Docket ID Item No. EPA-HQ-
OAR-2009-0234-20338 and in the current Docket ID No. EPA-HQ-OAR-
2018-0794.
---------------------------------------------------------------------------

    Several commenters asserted that there is no justification for
establishing a subcategory of certain existing EGUs firing EBCR for
emissions of acid gas HAP. Commenters claimed that the EPA has not
provided a valid technical basis for the subcategory, stating that
while the EPA has said that eastern bituminous coal is distinguished by
higher sulfur content and lesser content of free alkali, the EPA offers
nothing to distinguish the EGUs it would subcategorize from other EGUs
burning the same coals and subject to MATS. Commenters further claimed
that there is no basis for a subcategory for EBCR-fired EGUs because
some of those EGUs currently emit SO2 at rates below the
2012 final MATS SO2 limit and have shown that the current
standards are achievable because there are technologies that are
feasible. Commenters stated that the assessment of the need for a
subcategory cannot reasonably be based on data for the period of
January 2015 through June 2018, terminating before EGUs reported
results of installed pollution controls. Commenters added that even if
limestone injection alone is not adequate to meet the MATS limits, the
fact that certain EGUs would need to install additional controls is not
a valid basis for a subcategory. Commenters also added that the EPA may
not subcategorize based on cost, even if some add-on controls would be
particularly expensive, and the EPA may not alter the MACT floor
because some sources may not be able to meet it. Commenters further
stated that the EPA notes that the use of some sorbents may negatively
impact the salability of fly ash, but commenters contend that losing
the ability to sell the ash--a consequence for all EGUs using DSI, not
just those using eastern bituminous coal-waste--does not suggest any
basis in the class, type, or size of the EGUs at the six plants that
might allow the EPA to set different standards for those EGUs.
Commenters pointed to a plant within the proposed subcategory that they
contend demonstrates that units can meet the MATS acid gas limits while
still re-using their ash. Commenters refuted the EPA's assertion that
use of DSI technology results in a considerable increase in Hg
emissions and would require the use of additional Hg controls, and,
further, stated that even if true, it provides no lawful basis for the
subcategory. Commenters pointed to EBCR-fired EGUs that they contend
not only can meet both the MATS acid gas and Hg limits, they can
achieve such low emissions of Hg that they qualify for low-emitting EGU
status (i.e., their emissions are less than 10 percent of the MATS
limit) without any Hg-specific controls. Commenters added that CAA
section 112 does not permit the EPA to loosen emission limitations
based on the EPA's desired control configuration.
    The EPA disagrees with comments opposed to establishing a new
subcategory of certain existing EGUs firing EBCR for emissions of acid
gas HAP. Under CAA section 112(d)(1), the Administrator has the
discretion to `` * * * distinguish among classes, types, and sizes of
sources within a category or subcategory in establishing * * * ''
standards. The EPA generally establishes subcategories to address
differences between units that make the nature of the HAP emissions
different or if there are technical feasibility issues associated with
different emission control approaches. Normally, the basis for
subcategorizing (e.g., type of unit) must be related to an effect on
emissions, rather than some difference which does not affect emissions
performance. EGUs are generally designed for a particular type of fuel,
and the type of fuel being burned can impact the degree of combustion
and the level and type of HAP emissions because the amount of fuel-
borne HAP such as acid gases is primarily dependent upon the
composition of the fuel. In addition, the type of fuel and attendant
unit design can limit the availability and functionality of different
types of controls, particularly for existing sources that must retrofit
if add-on controls are required. Finally, the D.C. Circuit recently
confirmed that the EPA may establish a subcategory based on the type of
fuel a boiler is designed to burn. See U.S. Sugar Corp. v. EPA, 830
F.3d at 656. Consistent with the statute and case law, the EPA is
establishing a subcategory based on the

size (boiler 150 MW or less) and type (boiler designed to burn EBCR) to
address the different acid gas HAP emissions from such sources.
    To inform our consideration, the EPA reviewed EGU design, operating
information, air emissions data compiled from the 2010 Information
Collection Request (ICR) that was used by the EPA during development of
the 2012 MATS final rule, and other available information for coal-
fired EGUs in the source category. The EPA found that there are
significant design and operational differences in coal-fired EGUs that
are based on the expected source of fuel and the design of the unit
that affect the levels of emissions of HCl and SO2--both of
which serve as a surrogate for all acid gas HAP emitted from coal-fired
EGUs under MATS. These differences support our decision to establish a
subcategory for existing EGUs that burn EBCR and have a net summer
capacity of 150 MW or lower. Specifically, the emissions data for HCl
and SO2 show a distinguishable difference in performance
exists between coal-fired units with a net summer capacity of no
greater than 150 MW designed to burn EBCR and other coal-fired units,
including units that burn coal refuse other than EBCR.19 20
Because the EBCR-fired units have different emission characteristics
for acid gas HAP, the EPA has determined that units that are designed
to burn EBCR, and actually burn at least 75-percent EBCR, are a
different type of unit and should be subcategorized for acid gas HAP
emissions.\21\
---------------------------------------------------------------------------

    \19\ As discussed earlier in this section of this preamble, the
subcategory being established in this final rule excludes the two
EBCR-fired EGUs at the Seward Generating Station, which are 260 MW
each, from the new subcategory.
    \20\ See the memorandum titled HCl and SO2 Emissions
for Coal Refuse-Fired EGUs, available in Docket ID No. EPA-HQ-OAR-
2018-0794.
    \21\ For all other HAP from these two subcategories of coal-
fired units, the data did not show any difference in the level of
the HAP emissions and, therefore, we have determined that it is not
reasonable to establish separate emissions limits for the other HAP.
---------------------------------------------------------------------------

    The determination that EBCR-fired EGUs have different emission
characteristics for acid gas HAP is reasonably based on the same 2010
ICR dataset used to establish the bases of subcategories and standards
in the 2012 MATS final rule. An examination of the data shows that
there were no coal-fired units with a net summer capacity of 150 MW or
less designed to burn EBCR among the top performing 12 percent of coal-
fired units for emissions of HCl or SO2, even though the EPA
used 12 percent of the entire source category (130 units) to establish
the acid gas HAP standard for coal-fired EGUs. There were, however,
EGUs firing bituminous coal, subbituminous coal, and lignite among the
top performing units for HCl and EGUs firing bituminous, subbituminous,
lignite, and non-EBCR coal refuse among the top performers for
SO2. The EPA points out that the assessment of the need for
a subcategory was not based on data for the period of January 2015
through June 2018 as suggested by commenters. As discussed in section
III.B of this preamble, those data were used to determine the
SO2 lb/MMBtu emission rate for beyond-the-floor level of
control. The EPA disagrees with commenters' assertions that the fact
that some EBCR-fired EGUs have met the 2012 final MATS SO2
limit means the new subcategory is unreasonable. The EPA is aware of
EGUs at two plants \22\ that have been able to meet the 2012 final MATS
SO2 limit. Historical SO2 emissions data reported
to the EPA's Emissions Collection and Monitoring Plan System (ECMPS)
for those EGUs shows that those plants had lower SO2
emissions than other EBCR-fired EGUs. Thus, the additional
SO2 emissions reductions required for those EGUs to meet the
2012 final MATS SO2 limit are more likely to be achievable
through means such as increased limestone injection and fuel switching
without the limitations described by several commenters and summarized
earlier in this section of the preamble. The EPA's understanding,
however, is that the operational changes made to those EGUs with
historically lower SO2 emissions in order to meet the 2012
final MATS SO2 limit result in less EBCR being disposed of
and are not economically feasible in the long term. One facility has
met the SO2 limit by injecting more limestone and the other
facility has met the limit by co-firing lower sulfur coal. Similarly,
the ability of those same units to meet the 2012 final MATS acid gas
HAP limit as well as the Hg limit or to meet the 2012 final MATS acid
gas HAP limit while still re-using their ash does not mean a separate
subcategory is unwarranted or unreasonable. The information in the
record supports a conclusion that the existing EGUs in the new
subcategory are different from a fuel and design perspective and it is
reasonable to establish a new subcategory based on the size and type of
unit. In addition, this new subcategory is also reasonable because the
alternative is to maintain a standard that requires the sources to
operate in a manner that undermines the purpose for which they were
constructed and may be technologically infeasible for certain units in
the subcategory. Specifically, the coal refuse-fired EGUs at issue were
constructed at or near legacy piles of EBCR for the primary purposes of
reducing the health and environmental hazards associated with the coal
piles and using the resultant coal ash to reclaim abandoned mining
sites. The commenters in support of the rule provided information
indicating the reasons the new subcategory is warranted and how
requiring compliance with the 2012 MATS limit for acid gas HAP would
undermine the continued viability of the EBCR-fired EGUs to perform
both of these functions.
---------------------------------------------------------------------------

    \22\ Neither of these two plants with EBCR-fired EGUs that have
met the 2012 final MATS SO2 limit are the Seward
Generating Station discussed earlier in this section of this
preamble.
---------------------------------------------------------------------------

    For all these reasons, we do not agree that the commenters have
raised any significant objections to the EPA's determination that it is
reasonable and appropriate to establish a new subcategory for EBCR-
fired EGUs. Accordingly, we are finalizing the new subcategory.

B. Subcategory Emission Standards

    As noted in the 2019 Proposal, the EPA conducted an analysis to
determine the numerical acid gas emission standards for the subcategory
of certain existing EGUs that fire EBCR should such a subcategory be
established.\23\ The EPA explained that it determined the MACT floor
and the beyond-the-floor (i.e., more stringent than the MACT floor)
levels of control for HCl and SO2 emissions. The EPA further
explained that the SO2 lb/MMBtu emission rate for beyond-
the-floor level of control was determined for each currently operating
EBCR-fired EGU using monthly SO2 data available in the EPA's
ECMPS for the period of January 2015 through June 2018.\24\ The EPA
stated that if a beyond-the-floor (with floor at 1.0 lb/MMBtu)
SO2 emissions limit was established, it would likely be in
the range of 0.60-0.70 lb/MMBtu; a limit that, on average, the
currently operating EBCR-fired EGUs have demonstrated an ability to

achieve based on their monthly emissions data for January 2015 through
June 2018. The EPA explained that due to data limitations (i.e., no HCl
lb/MMBtu or lb/MWh emissions data have been submitted for the currently
operating EBCR-fired EGUs, and SO2 lb/MWh emissions data are
available for only two of the currently operating EBCR-fired EGUs),
this same beyond-the-floor methodology used to determine the beyond-
the-floor standards for SO2 in lb/MMBtu could not be used to
evaluate beyond-the-floor standards for SO2 in lb/MWh or for
HCl in either lb/MMBtu or lb/MWh. The EPA, therefore, further explained
that it determined that beyond-the-floor standards for those
pollutants, if established, should reasonably be set based on the same
percentage reduction as the SO2 lb/MMBtu described earlier
(i.e., the 40-percent reduction in the emissions rate for
SO2 between the calculated MACT floor value of 1.0 lb/MMBtu
and the beyond-the-floor value of 0.60 lb/MMBtu). The EPA solicited
comment on the analysis conducted to determine the numerical acid gas
emission standards and, on its methodology, and results. Table 4 of
this preamble shows the results of the MACT floor and beyond-the-floor
analyses as discussed in the 2019 Proposal.
---------------------------------------------------------------------------

    \23\ The analysis is summarized in a separate memorandum titled
NESHAP for Coal- and Oil-Fired EGUs: MACT Floor Analysis and Beyond
the MACT Floor Analysis for Subcategory of Existing Eastern
Bituminous Coal Refuse-Fired EGUs Under Consideration, available in
Docket ID No. EPA-HQ-OAR-2018-0794.
    \24\ At the time of the 2019 Proposal's analysis, SO2
data through June 2018 were available. Data that have become
available only after the 2019 Proposal is not a necessary basis of
our discussion of that Proposal or the EPA's final action here, but
it generally corroborates the basis already available and noticed to
the public in February 2019. New data that have since become
available to the EPA are discussed later in this section of this
preamble.

           Table 4--MACT Floor and Beyond-the-Floor Results for Potential EBCR-Fired EGUs Subcategory
----------------------------------------------------------------------------------------------------------------
           Subcategory                 Parameter                    HCl                          SO2
----------------------------------------------------------------------------------------------------------------
Existing Eastern Bituminous Coal  Number in MACT       5...........................  5
 Refuse-Fired EGUs.                Floor.
                                  99% UPL \a\ of Top   6.0E-2 lb/MMBtu.............  1.0 lb/MMBtu
                                   5 (i.e., MACT       6.0E-1 lb/MWh...............  15 lb/MWh
                                   floor).
                                  Beyond-the-floor     4.0E-2 lb/MMBtu.............  6.0E-1 lb/MMBtu
                                   Standard.           4.0E-1 lb/MWh...............  9.0 lb/MWh
----------------------------------------------------------------------------------------------------------------
\a\ Upper prediction limit.

    Immediately below and in the response to comments document, we
discuss in more detail the basis for the acid gas HAP emission
standards that are applicable to the new subcategory and address the
significant comments on the standards for the new subcategory.
    In response to the 2019 Proposal's solicitation of comment, the EPA
received comments both supporting and opposing its analysis to
determine the numerical acid gas emission standards for a subcategory
of existing EBCR-fired EGUs. Several commenters agreed with the
methodology that the EPA used to determine the MACT floor and beyond-
the-floor levels of control for emissions of SO2 and HCl.
Commenters further stated that an SO2 limit of 0.6 lb/MMBtu,
as discussed in the 2019 Proposal, is reasonable, technologically and
economically defensible, and would allow facilities to continue
providing multimedia environmental benefits from coal refuse
reclamation and remediation of mining-affected lands. Other commenters
disagreed with the EPA's analyses of the MACT floor and beyond-the-
floor levels of control and the resulting emission limits presented in
the 2019 Proposal. Specifically, commenters disagreed with the data
used in the analyses, claiming that it is not representative of the
emissions reductions achieved in practice by the best-performing
sources because it excludes time periods when controls were installed.
In addition, commenters stated that the beyond-the-floor analysis fails
to recognize that each plant in the subcategory already has acid gas
controls sufficient to meet the current standard and, instead, assumes
that such controls are infeasible. Further, commenters stated that the
only relevant cost for purposes of any beyond-the-floor standard is the
cost of operating (rather than installing) the control.
    The EPA disagrees with those comments opposing the data used in the
MACT floor and beyond-the-floor analyses and the resulting emission
limits. The MACT floor analyses for HCl and SO2 for the
subcategory of EBCR-fired EGUs are reasonably based on the same 2010
ICR dataset and methodology used to determine MACT floor emission
values for pollutants regulated under the 2012 MATS final rule. HCl and
SO2 emissions data for the EBCR-fired EGUs that were
operating at the time of the 2012 MATS final rule were used to
calculate separate existing source MACT floors for HCl in lb/MMBtu and
lb/MWh and SO2 in lb/MMBtu and lb/MWh. Thus, the MACT floor
analysis and resulting floor values are consistent with how MACT floors
for other HAP emissions standards were calculated and are
representative of the HCl and SO2 emissions reductions
achieved in practice by the best-performing EBCR-fired EGUs at that
time, irrespective of the means that the reductions were achieved.
    The beyond-the-floor analysis and resulting beyond-the-floor
emission limit for SO2 lb/MMBtu are reasonably based on the
extensive data available in the EPA's ECMPS for each currently
operating EBCR-fired EGU. As described in the 2019 Proposal, an
SO2 emission limit of 0.6 lb/MMBtu is a limit that the
currently operating EBCR-fired EGUs have demonstrated an ability to
achieve based on their monthly emissions data for January 2015 through
June 2018. Any means being used to control acid gases during that time
period would be reflected in the average SO2 lb/MMBtu
emission rate for those EBCR-fired EGUs. Thus, the EPA's analysis does
not exclude time periods when controls were installed. We note,
however, that we are unaware of any EBCR-fired EGUs that have installed
any downstream acid gas controls in addition to limestone injection
into the FBC in response to the 2012 MATS rule. Further, the EPA has
confirmed that extending the time horizon through March 2019 to include
emissions data that have become available since the analysis for the
2019 Proposal would not result in changes to average SO2 lb/
MMBtu emission rates for the currently operating EBCR-fired EGUs nor to
the SO2 emission limit of 0.6 lb/MMBtu that, on average,
those EGUs have achieved for that time period.\25\
---------------------------------------------------------------------------

    \25\ Including EBCR-fired EGUs' SO2 emissions data
for the time period of July 2018 through March 2019 results in minor
changes to average SO2 emissions values for some EBCR-
fired EGUs but does not result in a change to the beyond-the-floor
emission limit for SO2 lb/MMBtu. Nevertheless, the more
recent SO2 data is included in an addendum to the 2019
Proposal's analysis, titled NESHAP for Coal- and Oil-Fired EGUs:
Addendum to MACT Floor Analysis and Beyond the MACT Floor Analysis
for Subcategory of Existing Eastern Bituminous Coal Refuse-Fired
EGUs Under Consideration, available in Docket ID No. EPA-HQ-OAR-
2018-0794.
---------------------------------------------------------------------------

    Contrary to some comments, the beyond-the-floor analysis does
recognize that each EBCR-fired EGU in the subcategory has controls to
address acid gas emissions and, as explained earlier, average
SO2 lb/MMBtu emission rates reflect those controls. In
addition, the 2019 Proposal, as well as section

III.A of this preamble, point out that all coal refuse fuels are fired
in FBC that use limestone injection to minimize SO2
emissions and to increase heat transfer efficiency. As discussed in
section III.A of this preamble, commenters have pointed out, however,
that there are limitations on the ability of existing EBCR-fired EGUs
to control acid gas emissions to the level of the 2012 final MATS acid
gas standard by increasing the amount of limestone injected. As such,
the EPA disagrees with comments claiming that the current controls are
sufficient to meet the 2012 final MATS acid gas standard and that,
therefore, the only relevant cost for purposes of any beyond-the-floor
standard is the cost of operating (rather than installing) the control.
As also discussed in section III.A of this preamble, commenters have
pointed out feasibility issues associated with installation and
operation of various downstream acid gas control technologies in order
to meet the 2012 final MATS acid gas standard. For those same reasons,
the EPA determined that downstream acid gas control technologies such
as scrubbers (either wet FGD scrubbers or SDA) or DSI systems are not
beyond-the-floor options for acid gas HAP emissions from the
subcategory of existing EBCR-fired EGUs.\26\
---------------------------------------------------------------------------

    \26\ See, also, the memorandum titled NESHAP for Coal- and Oil-
Fired EGUs: Addendum to MACT Floor Analysis and Beyond the MACT
Floor Analysis for Subcategory of Existing Eastern Bituminous Coal
Refuse-Fired EGUs Under Consideration, available in Docket ID No.
EPA-HQ-OAR-2018-0794.
---------------------------------------------------------------------------

    Based on a review of the public comments and other available
information, the EPA is finalizing HCl and SO2 emission
limits reflecting beyond-the-floor level of control using the
methodology described in the 2019 Proposal and earlier in this section
of the preamble. Specifically, this action establishes the following
emission limits for the new subcategory of existing EBCR-fired EGUs:

HCl: 4.0E-2 lb/MMBtu or 4.0E-1 lb/MWh
SO2: \27\ 6.0E-1 lb/MMBtu or 9.0 lb/MWh
---------------------------------------------------------------------------

    \27\ As is the requirement for all coal-fired EGUs subject to
MATS, the alternate SO2 limit may be used if the EGU has
some form of FGD system and SO2 CEMS and both are
installed and operated at all times. As specified in 40 CFR
63.10000(c)(1)(v) of the 2012 MATS final rule, limestone injection
to an FBC unit is an ``FGD system'' that would allow the EBCR-fired
EGUs to use the alternative SO2 standard.

    The SO2 lb/MMBtu emissions limit is a limit that, on
average, the currently operating EBCR-fired EGUs have achieved based on
their monthly emissions data for January 2015 through June 2018.\28\
Because the EPA does not have such HCl emissions data or SO2
lb/MWh emissions data, beyond-the-floor standards for SO2 in
lb/MWh and for HCl in lb/MMBtu and lb/MWh are based on the percentage
reduction in the SO2 lb/MMBtu emissions rate between the
MACT floor value and the beyond-the-floor value.
---------------------------------------------------------------------------

    \28\ As previously explained in this preamble, at the time of
the 2019 Proposal's analysis, SO2 data through June 2018
were available. Inclusion of data that has become available only
after the 2019 Proposal does not result in a change to the beyond-
the-floor emission limit for SO2 lb/MMBtu. See the
memorandum titled NESHAP for Coal- and Oil-Fired EGUs: Addendum to
MACT Floor Analysis and Beyond the MACT Floor Analysis for
Subcategory of Existing Eastern Bituminous Coal Refuse-Fired EGUs
Under Consideration, available in Docket ID No. EPA-HQ-OAR-2018-
0794.
---------------------------------------------------------------------------

IV. Summary of Cost, Environmental, and Economic Impacts and Additional
Analyses Conducted

A. What are the affected sources?

    Affected sources are EGUs that are in the unit designed for eastern
bituminous coal refuse (EBCR) subcategory, as defined under this final
action. Based on available information, there are six currently
operating EBCR-fired EGUs that are in the newly established subcategory
and subject to the newly established acid gas HAP emission standards.
The six EGUs, located at three facilities in Pennsylvania and one
facility in West Virginia, are listed in Table 2 of this preamble.

B. What are the air quality impacts?

    Absent the subcategory finalized in this action, many affected
EBCR-fired EGUs would likely discontinue operations. Although the new
emission standards will allow higher acid gas HAP and SO2
emissions from these facilities compared to the emission standards in
the original 2012 MATS, emissions of other HAP will not change under
this action. These higher allowable emissions may, however, be
partially offset. In the absence of this rule, closure of the units
would likely result in reduced remediation of abandoned mine lands
(AMLs) and potentially increase the risk and impact of emissions from
refuse piles. Refuse piles at AMLs are prone to spontaneous internal
combustion (smoldering) which emits uncontrolled air pollutants
including acid gases and other HAP, and with less remediation, the
potential for greater emissions from smoldering increases. More
detailed analysis of potential air impacts of this rule is presented in
a docketed memorandum.\29\
---------------------------------------------------------------------------

    \29\ See the memorandum titled Analysis of Potential Costs and
Benefits for the National Emission Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating
Units--Subcategory of Certain Existing Electric Utility Steam
Generating Units Firing Eastern Bituminous Coal Refuse for Emissions
of Acid Gas Hazardous Air Pollutants, available in Docket ID No.
EPA-HQ-OAR-2018-0794
---------------------------------------------------------------------------

C. What are the compliance cost impacts?

    Relative to a baseline in which the subcategory is not finalized
and the existing 2012 MATS acid gas HAP emissions limits are enforced,
the new subcategory could reduce costs by eliminating the need for
investment in additional compliance measures which have not yet been
made by affected units. The magnitude of potential cost reductions is
discussed in a docketed memorandum.\30\
---------------------------------------------------------------------------

    \30\ Ibid.
---------------------------------------------------------------------------

D. What are the economic impacts?

    The impact of the newly finalized subcategory of EBCR-fired EGUs
for emissions of acid gas HAP on the broader electricity sector is
likely to be minor due to the relatively small size of these
facilities. Additionally, the risk of the affected EBCR-fired EGUs
closing because of challenges in meeting MATS acid gas HAP limits is
reduced by the new subcategory. As a result, the coal refuse
reclamation services the units provide are more likely to be sustained
in the future, potentially offsetting reclamation costs that may be
otherwise incurred by the states of Pennsylvania and West Virginia.
Additionally, because of the reduced risk of closure, the acid gas HAP
subcategory finalized in this action could prevent labor market
transitions for individuals who operate and perform support functions
for these facilities. However, it may limit labor market opportunities
that could result from AML reclamation by other means.

E. What are the forgone benefits?

    Absent the subcategory finalized in this action, affected EBCR-
fired EGUs would likely either discontinue operations or perform
compliance measures to comply with the previous MATS acid gas HAP
limits, which would have the effect of reducing acid gas HAP emissions.
The newly finalized subcategory will likely increase emissions of
SO2 relative to a baseline in which the subcategory is not
finalized; this in turn would form fine PM (PM2.5)
concentrations in the atmosphere and potentially adversely affect human
health. The magnitude of those forgone co-benefits depends on the
magnitude of the air quality impacts described earlier. Notably, most
counties in Pennsylvania and bordering

states attain the current PM2.5 National Ambient Air Quality
Standards (NAAQS), set at a level requisite to protect public health
with an adequate margin of safety. The magnitude of potential forgone
benefits is discussed in a docketed memorandum.\31\
---------------------------------------------------------------------------

    \31\ Ibid.
---------------------------------------------------------------------------

    In contrast, if plants continue to operate when they otherwise
would not have absent this action, the continued remediation of AMLs
could provide water quality co-benefits through reductions in toxic
metal leaching and acid mine drainage. As noted earlier, removal of
coal refuse piles reduces surface and groundwater pollution from acidic
drainage and reduces uncontrolled emissions of air pollutants that are
released from self-ignited internal smoldering of the coal refuse
piles. In addition, commenters pointed out that the alkaline ash
produced by EBCR-fired EGUs is used to reclaim mining-affected lands by
returning them to a productive use.
    Remediation of AMLs through the use of waste coal is supported by
the state of Pennsylvania through policies such as tax credits and
treatment of these units as renewable for purposes of the state's
renewable portfolio standard. If these waste coal units are no longer
able to operate, the state will need to find alternative means to
remediate these sites leading to, at best, a delay in these benefits,
if not a loss of these benefits altogether. These benefits are
discussed qualitatively in greater detail in the docketed memorandum.
    As noted earlier, while the EPA cannot predict with certainty what
the industry response would be absent the establishment of a new
subcategory, industry commenters have suggested that some--and maybe
all--of the affected sources would shut down.\32\ If that is the case,
then the establishment of this new subcategory will allow those units
to continue to achieve both of their purposes while also maintaining
emissions of acid gas HAP at levels similar to current emissions
levels.
---------------------------------------------------------------------------

    \32\ See EPA Docket ID Item Nos. EPA-HQ-OAR-2018-0794-1125 and
EPA-HQ-OAR-2018-0794-1154.
---------------------------------------------------------------------------

    While the EPA cannot predict with certainty what the industry
response would be in the absence of a new subcategory, commenters'
claim that the units would shut down is plausible. Coal-fired power
plants are currently facing tremendous competitive pressures. As a
result, coal's share of total U.S. electricity generation has been
declining for over a decade, while generation from natural gas and
renewables has increased significantly. A large number of coal units--
especially smaller ones like the EBCR-fired EGUs--have retired since
2010. Indeed, as mentioned earlier, four of the ten units that were
identified as affected by this action in the 2019 Proposal have now
either retired or announced plans to convert to natural gas.

V. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders
can be found at https://www.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 an economically significant regulatory action that
was submitted to the Office of Management and Budget (OMB) for review.
Any changes made in response to OMB recommendations have been
documented in the docket. The EPA has conducted an analysis of all
reasonably anticipated costs and benefits arising out of this rule,
including those arising out of co-benefits pursuant to Executive Orders
12866 and 13563. That analysis can be found in a separate memorandum
titled Analysis of Potential Costs and Benefits for the National
Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired
Electric Utility Steam Generating Units--Subcategory of Certain
Existing Electric Utility Steam Generating Units Firing Eastern
Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air
Pollutants, that is available in the docket.

B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs

    This action is considered an Executive Order 13771 deregulatory
action. This final rule provides meaningful burden reduction by
revising the acid gas HAP emission standards for a new subcategory of
certain existing EGUs that are currently subject to MATS and does not
impose any additional regulatory requirements on the affected electric
utility industry.

C. Paperwork Reduction Act (PRA)

    This action does not impose any new information collection burden
under the PRA. OMB has previously approved the information collection
activities contained in the existing regulations and has assigned OMB
control number 2060-0567. This action does not impose an information
collection burden because the regulatory changes resulting from this
action do not affect the currently approved information collection
requirements. Specifically, this action establishes acid gas HAP
emission standards for a new subcategory of certain existing EGUs that
are currently subject to MATS and the new emission standards do not
result in any changes to the recordkeeping or reporting requirements
that those impacted EGUs are currently subject to.

D. 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. An agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no
net burden, or otherwise has a positive economic effect on the small
entities subject to the rule. This is a deregulatory action, and the
burden on all entities affected by this final rule, including small
entities, is reduced compared to the 2012 MATS.

E. Unfunded Mandates Reform Act (UMRA)

    This 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. The action imposes
no enforceable duty on any state, local or tribal governments or the
private sector.

F. 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.

G. 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 neither impose substantial direct
compliance costs on tribal governments, nor preempt Tribal law.
Specifically, this action establishes acid gas HAP emission standards
for a new subcategory of certain existing EGUs currently subject to
MATS and located in Pennsylvania and West Virginia, states without any
federally recognized tribal entities. Thus,

Executive Order 13175 does not apply to this action.
    Consistent with the EPA Policy on Consultation and Coordination
with Indian Tribes, the EPA consulted with tribal officials during the
development of this action. The EPA held consultations with the Blue
Lake Rancheria and the Fond du Lac Band of Lake Superior Chippewa on
April 2, 2019, and April 3, 2019, respectively. Neither tribe provided
comments regarding the 2019 Proposal's solicitation of comment on
establishing a subcategory of certain existing EGUs firing EBCR for
acid gas HAP emissions.

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

    This action is not subject to Executive Order 13045 because the EPA
does not believe the environmental health risks or safety risks
addressed by this action present a disproportionate risk to children.
While children may experience forgone benefits as a result of this
action, the potential forgone emission reductions (and related
benefits) from the final amendments are small compared to the overall
emission reductions (and related benefits) from the 2012 MATS.
    Furthermore, this action does not affect the level of public health
and environmental protection already being provided by existing NAAQS
and other mechanisms in the CAA. This action does not affect applicable
local, state, or federal permitting or air quality management programs
that will continue to address areas with degraded air quality and
maintain the air quality in areas meeting current standards. Areas that
need to reduce criteria air pollution to meet the NAAQS will still need
to rely on control strategies to reduce emissions. To the extent that
states use other mechanisms in order to comply with the NAAQS, and
still achieve the criteria pollution reductions that would have
otherwise occurred, this action will not have a disproportionate
adverse effect on children's health.

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

    This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. Further, the EPA concludes that this
action is not likely to have any adverse energy effects because it
establishes acid gas HAP emission standards for a new subcategory of
certain existing EGUs that are currently subject to MATS and does not
impose any additional regulatory requirements on the affected electric
utility industry.

J. National Technology Transfer and Advancement Act (NTTAA)

    This action does not involve technical standards.

K. 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).
While these communities may experience forgone benefits as a result of
this action, the potential forgone emission reductions (and related
benefits) from the final action are small compared to the overall
emission reductions (and related benefits) from the 2012 MATS.
    Moreover, this action does not affect the level of public health
and environmental protection already being provided by existing NAAQS,
including ozone and PM2.5, and other mechanisms in the CAA.
This action does not affect applicable local, state, or federal
permitting or air quality management programs that will continue to
address areas with degraded air quality and maintain the air quality in
areas meeting current standards. Areas that need to reduce criteria air
pollution to meet the NAAQS will still need to rely on control
strategies to reduce emissions.

L. 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. The CRA allows the issuing agency to make a rule
effective sooner than otherwise provided by the CRA if the agency makes
a good cause finding under the provisions of 5 U.S.C. 808(2). The EPA
finds that there is good cause under the provisions of 5 U.S.C. 808(2)
to make this final rule effective without full, prior Congressional
review under 5 U.S.C. 801 and to make the rule effective on April 15,
2020. The EPA finds that it is unnecessary to delay the date this rule
could be effective because the Agency has determined that the owners or
operators of affected MATS sources do not need time to adjust to this
final action. This final action establishes a subcategory of certain
existing EGUs firing EBCR and acid gas HAP emission standards
applicable only to the new subcategory. Sources in the new subcategory
will be subject to an SO2 emissions limit that, on average,
the currently operating six EBCR-fired EGUs have demonstrated an
ability to achieve but, otherwise, will not be subject to any new
regulatory requirements.\33\
---------------------------------------------------------------------------

    \33\ Affected sources may report emissions of either
SO2 or HCl. Most MATS-affected EGUs report emissions of
SO2 because they already report SO2 emissions
under the EPA's Acid Rain Program.
---------------------------------------------------------------------------

    The EPA also finds that it is impracticable to delay the effective
date of this rule. Three of the four facilities with EBCR-fired EGUs in
the new subcategory are subject to EPA-issued Administrative Compliance
Orders that provide interim SO2 emission limits that
terminate on April 15, 2020. Those facilities have asserted that they
cannot meet the 2012 final MATS HCl emission standard, or the 2012
final MATS SO2 acid gas HAP surrogate emission standard,
while burning the coal refuse fuel for which their facilities were
designed. By 11:59 p.m. on April 15, 2020, EBCR-fired EGUs at those
facilities must achieve full compliance with MATS. Absent this final
action's acid gas HAP emission standards for the new subcategory being
effective by that date, EGUs at those three facilities would be subject
to the 2012 final MATS acid gas HAP emission standards that they are
not currently in compliance with, and, thus, in violation of their
Orders. According to the facilities, if subject to the 2012 acid gas
HAP emission standards, they would no longer be in a position to
continue operating their EBCR-fired EGUs and, thus, provide the
environmental benefits associated with removal of coal refuse piles and
reclamation and remediation of mining-affected lands.
    Accordingly, the EPA finds it would be unnecessary and
impracticable to delay the effective date of this action and that there
is good cause to dispense with the opportunity for a 60-day period of
prior Congressional review and to publish this final rule with an
effective date of April 15, 2020.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedures,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.

Andrew Wheeler,
Administrator.

    For the reasons set forth in the preamble, the Environmental
Protection Agency amends 40 CFR part 63 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 UUUUU--National Emission Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating
Units

0
2. Section 63.9982 is amended by revising paragraph (d) to read as
follows:

Sec.  63.9982  What is the affected source of this subpart?

* * * * *
    (d) An EGU is existing if it is not new or reconstructed. An
existing electric steam generating unit that meets the applicability
requirements after April 16, 2012, due to a change in process (e.g.,
fuel or utilization) is considered to be an existing source under this
subpart.

0
3. Section 63.9984 is amended by revising paragraphs (b) and (f) and
adding paragraph (g) to read as follows:

Sec.  63.9984  When do I have to comply with this subpart?

* * * * *
    (b) If you have an existing EGU, you must comply with this subpart
no later than April 16, 2015, except as provided in paragraph (g) of
this section.
* * * * *
    (f) You must demonstrate that compliance has been achieved, by
conducting the required performance tests and other activities, no
later than 180 days after the applicable date in paragraph (a), (b),
(c), (d), (e), or (g) of this section.
    (g) If you own or operate an EGU that is in the Unit designed for
eastern bituminous coal refuse (EBCR) subcategory as defined in Sec.
63.10042, you must comply with the applicable hydrogen chloride (HCl)
or sulfur dioxide (SO2) requirements of this subpart no
later than April 15, 2020.

0
4. Section 63.9990 is amended by revising paragraph (a) to read as
follows:

Sec.  63.9990  What are the subcategories of EGUs?

    (a) Coal-fired EGUs are subcategorized as defined in paragraphs
(a)(1) through (3) of this section and as defined in Sec.  63.10042.
    (1) EGUs designed for coal with a heating value greater than or
equal to 8,300 Btu/lb,
    (2) EGUs designed for low rank virgin coal, and
    (3) EGUs designed for EBCR.
* * * * *

0
5. Section 63.10042 is amended by adding definitions for ``Eastern
bituminous coal refuse (EBCR),'' ``Net summer capacity,'' and ``Unit
designed for eastern bituminous coal refuse (EBCR) subcategory'' in
alphabetical order to read as follows:

Sec.  63.10042  What definitions apply to this subpart?

* * * * *
    Eastern bituminous coal refuse (EBCR) means coal refuse generated
from the mining of bituminous coal in Pennsylvania and West Virginia.
* * * * *
    Net summer capacity means the maximum output, commonly expressed in
megawatts (MW), that generating equipment can supply to system load, as
demonstrated by a multi-hour test, at the time of summer peak demand
(period of June 1 through September 30.) This output reflects a
reduction in capacity due to electricity use for station service or
auxiliaries.
* * * * *
    Unit designed for eastern bituminous coal refuse (EBCR) subcategory
means any existing (i.e., construction was commenced on or before May
3, 2011) coal-fired EGU with a net summer capacity of no greater than
150 MW that is designed to burn and that is burning 75 percent or more
(by heat input) eastern bituminous coal refuse on a 12-month rolling
average basis.
* * * * *

0
6. Table 2 to Subpart UUUUU of Part 63 is revised to read as follows:

Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing EGUs

    As stated in Sec.  63.9991, you must comply with the following
applicable emission limits: \1\

----------------------------------------------------------------------------------------------------------------
                                                                                Using these
                                                                                requirements, as
                                                                   You must meet the        appropriate (e.g.,
                                                                   following emission       specified sampling
 If your EGU is in this subcategory .     For the following         limits and work         volume or test run
                 . .                       pollutants . . .      practice standards . .       duration) and
                                                                           .               limitations with the
                                                                                test methods in Table 5
                                                                                to this Subpart . . .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank        a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 virgin coal.                           particulate matter       1 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  1.1E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.8E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Lead (Pb)..............  1.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  4.0E0 lb/TBtu or 5.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  3.5E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.

                                       Selenium (Se)..........  5.0E0 lb/TBtu or 6.0E-2  .......................
                                                                 lb/GWh.
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 2.0E- For Method 26A at
                                        (HCl).                   2 lb/MWh.                appendix A-8 to part
                                                                                60 of this chapter,
                                                                                collect a minimum of
                                                                                0.75 dscm per run; for
                                                                                Method 26, collect a
                                                                                minimum of 120 liters
                                                                                per run. For ASTM
                                                                                D6348-03 3 or Method
                                                                                320 at appendix A to
                                                                                part 63 of this
                                                                                chapter, sample for a
                                                                                minimum of 1 hour.
                                       OR.....................  .......................  .......................
                                       Sulfur dioxide (SO2) 4.  2.0E-1 lb/MMBtu or       SO2 CEMS.
                                                                 1.5E0 lb/MWh.
                                       c. Mercury (Hg)........  1.2E0 lb/TBtu or 1.3E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with a sampling period
                                                                                consistent with that
                                                                                given in section 5.2.1
                                                                                of appendix A to this
                                                                                subpart per Method 30B
                                                                                at appendix A-8 to
                                                                                part 60 of this
                                                                                chapter run or Hg CEMS
                                                                                or sorbent trap
                                                                                monitoring system
                                                                                only.
                                                                OR                       .......................
                                                                1.0E0 lb/TBtu or 1.1E-2  LEE Testing for 90 days
                                                                 lb/GWh.                  with a sampling period
                                                                                consistent with that
                                                                                given in section 5.2.1
                                                                                of appendix A to this
                                                                                subpart per Method 30B
                                                                                run or Hg CEMS or
                                                                                sorbent trap
                                                                                monitoring system
                                                                                only.
2. Coal-fired unit low rank virgin     a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 coal.                                  particulate matter       1 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  1.1E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.8E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Lead (Pb)..............  1.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  4.0E0 lb/TBtu or 5.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  3.5E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  5.0E0 lb/TBtu or 6.0E-2  .......................
                                                                 lb/GWh.
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 0.75 dscm
                                                                                per run; for Method 26
                                                                                at appendix A-8 to
                                                                                part 60 of this
                                                                                chapter, collect a
                                                                                minimum of 120 liters
                                                                                per run. For ASTM
                                                                                D6348-03 3 or Method
                                                                                320, sample for a
                                                                                minimum of 1 hour.
                                       OR                                                .......................
                                       Sulfur dioxide (SO2) 4.  2.0E-1 lb/MMBtu or       SO2 CEMS.
                                                                 1.5E0 lb/MWh.
                                       c. Mercury (Hg)........  4.0E0 lb/TBtu or 4.0E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with a sampling period
                                                                                consistent with that
                                                                                given in section 5.2.1
                                                                                of appendix A to this
                                                                                subpart per Method 30B
                                                                                run or Hg CEMS or
                                                                                sorbent trap
                                                                                monitoring system
                                                                                only.

3. IGCC unit.........................  a. Filterable            4.0E-2 lb/MMBtu or 4.0E- Collect a minimum of 1
                                        particulate matter       1 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  6.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 2
                                                                                dscm per run.
                                       Antimony (Sb)..........  1.4E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Arsenic (As)...........  1.5E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  1.0E-1 lb/TBtu or 1.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  1.5E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.9E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  1.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Lead (Pb)..............  1.9E+2 lb/TBtu or 1.8E0  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.5E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  6.5E0 lb/TBtu or 7.0E-2  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  2.2E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       b. Hydrogen chloride     5.0E-4 lb/MMBtu or 5.0E- For Method 26A, collect
                                        (HCl).                   3 lb/MWh.                a minimum of 1 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 120 liters per run.
                                                                                For ASTM D6348-03 3 or
                                                                                Method 320, sample for
                                                                                a minimum of 1 hour.
                                       c. Mercury (Hg)........  2.5E0 lb/TBtu or 3.0E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with a sampling period
                                                                                consistent with that
                                                                                given in section 5.2.1
                                                                                of appendix A to this
                                                                                subpart per Method 30B
                                                                                run or Hg CEMS or
                                                                                sorbent trap
                                                                                monitoring system
                                                                                only.
4. Liquid oil-fired unit--continental  a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 (excluding limited-use liquid oil-     particulate matter       1 lb/MWh 2.              dscm per run.
 fired subcategory units).              (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals.......  8.0E-4 lb/MMBtu or 8.0E- Collect a minimum of 1
                                                                 3 lb/MWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 1
                                                                                dscm per run.
                                       Antimony (Sb)..........  1.3E+1 lb/TBtu or 2.0E-  .......................
                                                                 1 lb/GWh.
                                       Arsenic (As)...........  2.8E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  5.5E0 lb/TBtu or 6.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  2.1E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Lead (Pb)..............  8.1E0 lb/TBtu or 8.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.2E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Nickel (Ni)............  1.1E+2 lb/TBtu or 1.1E0  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  3.3E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.
                                       Mercury (Hg)...........  2.0E-1 lb/TBtu or 2.0E-  For Method 30B sample
                                                                 3 lb/GWh.                volume determination
                                                                                (Section 8.2.4), the
                                                                                estimated Hg
                                                                                concentration should
                                                                                nominally be < 1 2 the
                                                                                standard.

                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 1.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 1 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 120 liters per run.
                                                                                For ASTM D6348-03 3 or
                                                                                Method 320, sample for
                                                                                a minimum of 1 hour.
                                       c. Hydrogen fluoride     4.0E-4 lb/MMBtu or 4.0E- For Method 26A, collect
                                        (HF).                    3 lb/MWh.                a minimum of 1 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 120 liters per run.
                                                                                For ASTM D6348-03 3 or
                                                                                Method 320, sample for
                                                                                a minimum of 1 hour.
5. Liquid oil-fired unit--non-         a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 continental (excluding limited-use     particulate matter       1 lb/MWh 2.              dscm per run.
 liquid oil-fired subcategory units).   (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals.......  6.0E-4 lb/MMBtu or 7.0E- Collect a minimum of 1
                                                                 3 lb/MWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 2
                                                                                dscm per run.
                                       Antimony (Sb)..........  2.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Arsenic (As)...........  4.3E0 lb/TBtu or 8.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  6.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  3.1E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Cobalt (Co)............  1.1E+2 lb/TBtu or 1.4E0  .......................
                                                                 lb/GWh.
                                       Lead (Pb)..............  4.9E0 lb/TBtu or 8.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.0E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Nickel (Ni)............  4.7E+2 lb/TBtu or 4.1E0  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  9.8E0 lb/TBtu or 2.0E-1  .......................
                                                                 lb/GWh.
                                       Mercury (Hg)...........  4.0E-2 lb/TBtu or 4.0E-  For Method 30B sample
                                                                 4 lb/GWh.                volume determination
                                                                                (Section 8.2.4), the
                                                                                estimated Hg
                                                                                concentration should
                                                                                nominally be < 1 2 the
                                                                                standard.
                                       b. Hydrogen chloride     2.0E-4 lb/MMBtu or 2.0E- For Method 26A, collect
                                        (HCl).                   3 lb/MWh.                a minimum of 1 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 120 liters per run.
                                                                                For ASTM D6348-03 3 or
                                                                                Method 320, sample for
                                                                                a minimum of 2 hours.
                                       c. Hydrogen fluoride     6.0E-5 lb/MMBtu or 5.0E- For Method 26A, collect
                                        (HF).                    4 lb/MWh.                a minimum of 3 dscm
                                                                                per run. For ASTM
                                                                                D6348-03 3 or Method
                                                                                320, sample for a
                                                                                minimum of 2 hours.
6. Solid oil-derived fuel-fired unit.  a. Filterable            8.0E-3 lb/MMBtu or 9.0E- Collect a minimum of 1
                                        particulate matter       2 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  4.0E-5 lb/MMBtu or 6.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 7.0E-  .......................
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  3.0E-1 lb/TBtu or 5.0E-  .......................
                                                                 3 lb/GWh.
                                       Beryllium (Be).........  6.0E-2 lb/TBtu or 5.0E-  .......................
                                                                 4 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 4.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  8.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 2 lb/GWh.
                                       Cobalt (Co)............  1.1E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.

                                       Lead (Pb)..............  8.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 2 lb/GWh.
                                       Manganese (Mn).........  2.3E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  9.0E0 lb/TBtu or 2.0E-1  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  1.2E0 lb/Tbtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       b. Hydrogen chloride     5.0E-3 lb/MMBtu or 8.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 0.75 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 120 liters per run.
                                                                                For ASTM D6348-03 3 or
                                                                                Method 320, sample for
                                                                                a minimum of 1 hour.
                                       OR                                                .......................
                                       Sulfur dioxide (SO2) 4.  3.0E-1 lb/MMBtu or       SO2 CEMS.
                                                                 2.0E0 lb/MWh.
                                       c. Mercury (Hg)........  2.0E-1 lb/TBtu or 2.0E-  LEE Testing for 30 days
                                                                 3 lb/GWh.                with a sampling period
                                                                                consistent with that
                                                                                given in section 5.2.1
                                                                                of appendix A to this