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Proposed Rule2023-07383

National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review

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Published

April 24, 2023

Issuing agencies

Environmental Protection Agency

Abstract

The EPA is proposing to amend the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired Electric Utility Steam Generating Units (EGUs), commonly known as the Mercury and Air Toxics Standards (MATS). Specifically, the EPA is proposing to amend the surrogate standard for non-mercury (Hg) metal HAP (filterable particulate matter (fPM)) for existing coal-fired EGUs; the fPM compliance demonstration requirements; the Hg standard for lignite- fired EGUs; and the definition of startup. These proposed amendments are the result of the EPA's review of the May 22, 2020 residual risk and technology review (RTR) of MATS.

Full Text

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[Federal Register Volume 88, Number 78 (Monday, April 24, 2023)]
[Proposed Rules]
[Pages 24854-24896]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2023-07383]

[[Page 24853]]

Vol. 88

Monday,

No. 78

April 24, 2023

Part II

Environmental Protection Agency

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40 CFR Part 63

National Emission Standards for Hazardous Air Pollutants: Coal- and
Oil-Fired Electric Utility Steam Generating Units Review of the
Residual Risk and Technology Review; Proposed Rule

Federal Register / Vol. 88, No. 78 / Monday, April 24, 2023 /
Proposed Rules

[[Page 24854]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2018-0794; FRL-6716.3-01-OAR]
RIN 2060-AV53

National Emission Standards for Hazardous Air Pollutants: Coal-
and Oil-Fired Electric Utility Steam Generating Units Review of the
Residual Risk and Technology Review

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The EPA is proposing to amend the National Emission Standards
for Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired Electric
Utility Steam Generating Units (EGUs), commonly known as the Mercury
and Air Toxics Standards (MATS). Specifically, the EPA is proposing to
amend the surrogate standard for non-mercury (Hg) metal HAP (filterable
particulate matter (fPM)) for existing coal-fired EGUs; the fPM
compliance demonstration requirements; the Hg standard for lignite-
fired EGUs; and the definition of startup. These proposed amendments
are the result of the EPA's review of the May 22, 2020 residual risk
and technology review (RTR) of MATS.

DATES:
Comments. Comments must be received on or before June 23, 2023.
Under the Paperwork Reduction Act (PRA), comments on the information
collection provisions are best assured of consideration if the Office
of Management and Budget (OMB) receives a copy of your comments on or
before May 24, 2023.
Public hearing. The EPA will hold a virtual public hearing on May
9, 2023. See SUPPLEMENTARY INFORMATION for information on requesting
and registering for a public hearing.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2018-0794, by any of the following methods:
<bullet> Federal eRulemaking Portal: <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>
(our preferred method). Follow the online instructions for submitting
comments.
<bullet> Email: <a href="/cdn-cgi/l/email-protection#b8d995d9d6dc95ca95dcd7dbd3ddccf8ddc8d996dfd7ce">[email&#160;protected]</a>. Include Docket ID No. EPA-
HQ-OAR-2018-0794 in the subject line of the message.
<bullet> Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2018-0794.
<bullet> Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Docket ID No. EPA-HQ-OAR-2018-0794, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington, DC 20460.
<bullet> Hand/Courier Delivery: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except federal holidays).
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the SUPPLEMENTARY
INFORMATION section of this document.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Sarah Benish, 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: (919) 541-5620; and email address:
<a href="/cdn-cgi/l/email-protection#177572797e647f39647665767f5772677639707861">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. The public hearing will be
held via virtual platform on May 9, 2023 and will convene at 11 a.m.
Eastern Time (ET) and conclude at 7 p.m. ET. If the EPA receives a high
volume of registrations for the public hearing, we may continue the
public hearing on May 10, 2023. The EPA may close a session 15 minutes
after the last pre-registered speaker has testified if there are no
additional speakers. The EPA will announce further details at <a href="https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards">https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards</a>.
The EPA will begin pre-registering speakers for the hearing no
later than 1 business day following publication of this document in the
Federal Register. The EPA will accept registrations on an individual
basis. To register to speak at the virtual hearing, please use the
online registration form available at <a href="https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards">https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards</a> or contact the
public hearing team at (888) 372-8699 or by email at
<a href="/cdn-cgi/l/email-protection#6a393a3a2e1a1f08060309020f0b1803040d2a0f1a0b440d051c">[email&#160;protected]</a>. The last day to pre-register to speak at the
hearing will be May 8, 2023. Prior to the hearing, the EPA will post a
general agenda that will list pre-registered speakers in approximate
order at: <a href="https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards">https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards</a>.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearings to run either ahead of schedule or behind schedule.
Each commenter will have 4 minutes to provide oral testimony. The
EPA encourages commenters to provide the EPA with a copy of their oral
testimony by submitting the text of your oral testimony as written
comments to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
Please note that any updates made to any aspect of the hearing will
be posted online at <a href="https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards">https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards</a>. While the EPA expects the
hearing to go forward as described in this section, please monitor our
website or contact the public hearing team at (888) 372-8699 or by
email at <a href="/cdn-cgi/l/email-protection#cc9f9c9c88bcb9aea0a5afa4a9adbea5a2ab8ca9bcade2aba3ba">[email&#160;protected]</a> to determine if there are any
updates. The EPA does not intend to publish a document in the Federal
Register announcing updates.
If you require the services of an interpreter or special
accommodation such as audio description, please pre-register for the
hearing with the public hearing team and describe your needs by May 1,
2023. The EPA may not be able to arrange accommodations without
advanced notice.
Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2018-0794.\1\ All documents in the docket are
listed in <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>. Although listed, some
information is not publicly available, e.g., Confidential Business

[[Page 24855]]

Information (CBI) 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. With the exception of such material, publicly available docket
materials are available electronically in <a href="http://Regulations.gov">Regulations.gov</a>.
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\1\ As explained in a memorandum to the docket, the docket for
this action includes the documents and information, in whatever
form, in Docket ID Nos. EPA-HQ-OAR-2009-0234 (National Emission
Standards for Hazardous Air Pollutants for Coal- and Oil-fired
Electric Utility Steam Generating Units), EPA-HQ-OAR-2002-0056
(National Emission Standards for Hazardous Air Pollutants for
Utility Air Toxics; Clean Air Mercury Rule (CAMR)), and Legacy
Docket ID No. A-92-55 (Electric Utility Hazardous Air Pollutant
Emission Study). See memorandum titled Incorporation by reference of
Docket Number EPA-HQ-OAR-2009-0234, Docket Number EPA-HQ-OAR-2002-
0056, and Docket Number A-92-55 into Docket Number EPA-HQ-OAR-2018-
0794 (Docket ID Item No. EPA-HQ-OAR-2018-0794-0005).
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Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2018-0794. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, including any personal
information provided, unless the comment includes information claimed
to be CBI or other information whose disclosure is restricted by
statute. Do not submit electronically to <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>
any information that you consider to be CBI or other information whose
disclosure is restricted by statute. This type of information should be
submitted as discussed in the Submitting CBI section of this document.
The EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system). For additional submission methods, the full EPA
public comment policy, information about CBI or multimedia submissions,
and general guidance on making effective comments, please visit <a href="https://www.epa.gov/dockets/commenting-epa-dockets">https://www.epa.gov/dockets/commenting-epa-dockets</a>.
The <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> website allows you to submit your
comment anonymously, which means the EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to the EPA without going through
<a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
digital storage media you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should not include special characters or any form of encryption and be
free of any defects or viruses. For additional information about the
EPA's public docket, visit the EPA Docket Center homepage at <a href="https://www.epa.gov/dockets">https://www.epa.gov/dockets</a>.
Submitting CBI. Do not submit information containing CBI to the EPA
through <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information on any
digital storage media that you mail to the EPA, note the Docket ID No.,
mark the outside of the digital storage media as CBI, and identify
electronically within the digital storage media the specific
information that is claimed as CBI. In addition to one complete version
of the comments that includes information claimed as CBI, you must
submit a copy of the comments that does not contain the information
claimed as CBI directly to the public docket through the procedures
outlined in Instructions section of this document. If you submit any
digital storage media that does not contain CBI, mark the outside of
the digital storage media clearly that it does not contain CBI and note
the Docket ID No. Information not marked as CBI will be included in the
public docket and the EPA's electronic public docket without prior
notice. Information marked as CBI will not be disclosed except in
accordance with procedures set forth in 40 Code of Federal Regulations
(CFR) part 2.
Our preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol (FTP),
or other online file sharing services (e.g., Dropbox, OneDrive, Google
Drive). Electronic submissions must be transmitted directly to the
OAQPS CBI Office at the email address <a href="/cdn-cgi/l/email-protection#dcb3bdadacafbfbeb59cb9acbdf2bbb3aa">[email&#160;protected]</a>, and as
described above, should include clear CBI markings and note the Docket
ID No. If assistance is needed with submitting large electronic files
that exceed the file size limit for email attachments, or if you do not
have your own file sharing service, please email <a href="/cdn-cgi/l/email-protection#c6a9a7b7b6b5a5a4af86a3b6a7e8a1a9b0">[email&#160;protected]</a> to
request a file transfer link. If sending CBI information through the
postal service, please send it to the following address: OAQPS Document
Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711, Attention Docket ID No.
EPA-HQ-OAR-2018-0794. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
Preamble acronyms and abbreviations. Throughout this document the
use of ``we,'' ``us,'' or ``our'' is intended to refer to the EPA. We
use 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:

Btu British Thermal Units
CAA Clean Air Act
CBI Confidential Business Information
CEMS continuous emissions monitoring systems
CFR Code of Federal Regulations
CO<INF>2</INF> carbon dioxide
CPMS continuous parameter monitoring system
EAV equivalent annualized value
ECMPS Emissions Collection and Monitoring Plan System
EGU electric utility steam generating unit
EIA Energy Information Administration
EJ environmental justice
EPA Environmental Protection Agency
ESP electrostatic precipitator
FF fabric filter
FGD flue gas desulfurization
fPM filterable particulate matter
GWh gigawatt-hour
HAP hazardous air pollutant(s)
HCl hydrogen chloride
HF hydrogen fluoride
Hg mercury
Hg\0\ elemental Hg vapor
HQ hazard quotient
IGCC integrated gasification combined cycle
IPM Integrated Planning Model
lb Pounds
LEE low emitting EGU
MACT maximum achievable control technology
MATS Mercury and Air Toxics Standards
MM million
MW megawatt
NAICS North American Industry Classification System
NEEDS National Electric Energy Data System
NESHAP National Emission Standards for Hazardous Air Pollutants
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
PDF Portable Document Format
PM particulate matter
ppm parts per million
PV present value
RIA regulatory impact analysis
RTR residual risk and technology review
SC-CO<INF>2</INF> social cost of carbon
SO<INF>2</INF> sulfur dioxide
tpy tons per year
TBtu trillion British thermal units
WebFIRE Web Factor Information Retrieval System

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

I. Executive Summary
A. Background and Purpose of the Regulatory Action

[[Page 24856]]

B. Summary of the Major Provisions of the Regulatory Action
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
III. Background
A. What is the authority for this action?
B. What is this source category and how does the current NESHAP
regulate its HAP emissions?
C. What data collection activities were conducted to support
this proposed action?
D. What other relevant background information and data are
available?
E. How does the EPA perform the technology review?
IV. Review of 2020 Residual Risk and Technology Review
A. Summary of the 2020 Residual Risk Review
B. Summary of the 2020 Technology Review
V. Analytical Results and Proposed Decisions
A. Review of the 2020 Residual Risk Review
B. Review of the 2020 Technology Review
C. What are the results and proposed decisions based on our
technology review, and what is the rationale for those decisions?
D. What other actions are we proposing, and what is the
rationale for those actions?
E. What compliance dates are we proposing, and what is the
rationale for the proposed compliance dates?
VI. Summary of Cost, Environmental, and Economic Impacts
A. What are the affected sources?
B. What are the air quality impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits?
F. What analysis of environmental justice did we conduct?
VII. Request for Comments
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations

I. Executive Summary

A. Background and Purpose of the Regulatory Action

Exposure to hazardous air pollution (``HAP,'' sometimes known as
toxic air pollution, including Hg, chromium, arsenic, and lead) can
cause a range of adverse health effects including harming people's
central nervous system; damage to their kidneys; and cancer.
Recognizing the dangers posed by HAP, Congress enacted Clean Air Act
(CAA) section 112. Under CAA section 112, the EPA is required to set
standards (known as ``MACT'' (maximum achievable control technology)
standards) for major sources of HAP that ``require the maximum degree
of reduction in emissions of the hazardous air pollutants . . .
(including a prohibition on such emissions, where achievable) that the
Administrator, taking into consideration the cost of achieving such
emission reduction, and any non-air quality health and environmental
impacts and energy requirements, determines is achievable.'' 42 U.S.C.
7412(d)(2). To ensure a minimum level (or ``floor'') of emissions
reductions, Congress required that MACT standards for existing sources
``shall not be less stringent than . . . the average emission
limitation achieved by the best performing 12 percent of existing
sources''; and MACT standards for new sources ``shall not be less
stringent than the emission control that is achieved in practice by the
best controlled similar source[.]'' 42 U.S.C. 7412(d)(3). These
requirements effectively obligated all sources to reduce emissions as
well as the best sources in their category. Congress did not stop
there, however. First, it required the EPA, 8 years after setting the
standard, to address any residual risks posed by the source category
(called the ``residual risk review''). Second, and as explained in more
detail below, it required the EPA, at least every 8 years on an ongoing
basis, to review and revise as necessary the MACT standard taking into
account developments in practices, processes and control technologies
(called the ``technology review''). For EGUs, Congress also required
the EPA to make a one-time determination of whether it is ``appropriate
and necessary'' to regulate this source category under CAA section 112.
The EPA found regulation of EGUs ``appropriate and necessary'' in 2000
and reaffirmed that finding in 2012 and 2016. MACT standards were
originally set for EGUs in 2012, and those standards remain in place
today. In 2020, the EPA conducted the 8-year residual risk and
technology review and determined not to update the MACT standard.
On January 20, 2021, President Biden signed Executive Order 13990,
``Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis'' (86 FR 7037; January 25, 2021). The
Executive order, among other things, instructed the EPA to review the
2020 final 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'' (85 FR 31286; May 22, 2020) (2020 Final Action) and
to consider publishing a notice of proposed rulemaking suspending,
revising, or rescinding that action. The 2020 Final Action included a
finding that it is not appropriate and necessary to regulate coal- and
oil-fired EGUs under CAA section 112 as well as the RTR for the MATS
rule. The results of the EPA's review of the 2020 appropriate and
necessary finding were proposed on February 9, 2022 (87 FR 7624) (2022
Proposal) and finalized on March 6, 2023 (88 FR 13956). In the 2022
Proposal, the EPA also solicited information on the performance and
cost of new or improved technologies that control hazardous air
pollutant (HAP) emissions, improved methods of operation, and risk-
related information to further inform the EPA's review of the 2020 MATS
RTR. This action presents the proposed results of the EPA's review of
the MATS RTR.
In particular, with respect to the standard for fPM (as a surrogate
for non-Hg metals), and the standard for Hg from EGUs that burn lignite
coal, the EPA proposes to conclude that developments since 2012--and in
particular the fact that the majority of sources are vastly
outperforming the MACT standards with control technologies that are
cheaper and more effective than the EPA forecast while a smaller number
of sources' performance lags behind--warrant strengthening these
standards. While the 2012 MATS drove critical HAP reductions at much
lower cost than estimated, coal-fired EGUs still emit a substantial
amount of HAP and developments since 2012 provide opportunities to
address these emissions and ensure that all coal-fired EGUs are
performing at levels achievable by the fleet. These proposed revisions
would ensure that the EPA's standards continue to fulfill Congress's
direction to require the maximum degree of reduction of HAP while
taking into account the statutory factors.

[[Page 24857]]

B. Summary of the Major Provisions of the Regulatory Action

The 2012 MATS Final Rule established emission standards to limit
emissions of HAP from coal- and oil-fired EGUs. The rule required that
affected sources limit emissions of Hg, of non-Hg metal HAP (e.g.,
chromium, nickel, arsenic, lead), acid gas HAP (e.g., hydrogen chloride
(HCl), hydrogen fluoride (HF), selenium dioxide (SeO<INF>2</INF>)), and
organic HAP (e.g., formaldehyde, dioxins/furans). Since MATS was
promulgated in 2012, power sector emissions of Hg, acid gas HAP, and
non-Hg metal HAP have decreased by about 86 percent, 96 percent, and 81
percent, respectively, as compared to 2010 emissions levels (See Table
4 at 84 FR 2689, February 7, 2019). Still, coal- and oil-fired EGUs
remain the largest domestic emitter of Hg and many other HAP, including
many of the non-Hg HAP metals and HCl. Exposure to these HAP, at
certain levels and duration, is associated with a variety of adverse
health effects. These adverse health effects may include irritation of
the lung, skin, and mucus membranes; detrimental effects on the central
nervous system; damage to the kidneys; alimentary effects such as
nausea and vomiting; and cancer.\2\ See 77 FR 9310 for a fuller
discussion of the health effects associated with these pollutants.
Three of the key metal HAP emitted by EGUs (inorganic arsenic (As),
hexavalent chromium (Cr), and nickel compounds (Ni)) have been
classified as human carcinogens, while two others (cadmium (Cd) and
selenium (Se)) are classified as probable human carcinogens.\3\
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\2\ 77 FR 9310.
\3\ U.S. EPA. Table 1. Prioritized Chronic Dose-Response Values
for Screening Risk Assessments. Available at: <a href="https://www.epa.gov/fera/dose-response-assessment-assessing-health-risks-associated-exposure-hazardous-air-pollutants">https://www.epa.gov/fera/dose-response-assessment-assessing-health-risks-associated-exposure-hazardous-air-pollutants</a>.
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To address emissions of these non-Hg metal HAP, MATS sets
individual emission limits for each of the 10 non-Hg metals emitted
from coal- and oil-fired EGUs. Alternatively, affected sources may meet
an emission standard for ``total non-Hg metals'' by summing the
emission rates of each of the non-Hg metals. The MATS rule also allows
affected sources to meet a filterable PM (fPM) \4\ emission standard as
a surrogate for the non-Hg metals. For existing coal-fired EGUs, most
units have chosen to demonstrate compliance with the non-Hg metal HAP
surrogate fPM emission standard of 3.0E-02 pounds of fPM per million
British thermal units of heat input (lb/MMBtu).
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\4\ Total PM is composed of the filterable PM fraction (fPM) and
the condensible PM fraction. In establishing fPM as a surrogate for
the non-Hg metal HAP, the EPA explained that most of the non-Hg
metal HAP are present overwhelmingly in the fPM fraction. Selenium
may be present in both the fPM fraction and/or as the acid gas,
SeO<INF>2</INF>, in the condensible PM fraction. SeO<INF>2</INF> is
an acid gas HAP and is well controlled by the emission limit for
acid gas HAP. In addition, using fPM as the surrogate will allow the
use of continuous PM monitoring systems, which measure filterable
(but not total) PM, thereby providing a more continuous measure of
compliance.
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CAA section 112(d)(2) directs the EPA to require the maximum degree
of HAP emission reductions achievable, taking into account certain
considerations, and CAA section 112(d)(3) sets the floor for emission
standards based on the reductions achieved by the best performing
sources. The MATS was based upon the EPA's analysis under CAA sections
112(d)(2) and (d)(3) in 2012. CAA section 112(d)(6) further requires
the EPA, at least every 8 years, to review and revise standards taking
into account developments in practices, processes and control
technologies. After reviewing developments in the current emission
levels of fPM from existing coal-fired EGUs, the costs of control
technologies, and the effectiveness of those technologies, as well as
the costs of meeting a standard that is more stringent than 3.0E-02 lb/
MMBtu and the other statutory factors, the EPA is proposing to revise
the non-Hg metal surrogate fPM emission standard for all existing coal-
fired EGUs to a more stringent fPM emission standard of 1.0E-02 lb/
MMBtu, which is comparable to the MATS new source standard for fPM.\5\
The EPA is also soliciting comment on opportunities to revise the MATS
fPM emission standard to an even more stringent level of 6.0E-03 lb/
MMBtu.
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\5\ The fPM standard for new coal-fired EGU is 9.0E-02 lb/MWh,
which is an output-based emission standard. See 78 FR 24073. This
emission is equivalent for a new coal-fired EGU with a heat rate of
9.0 MMBtu/MWh (9,000 Btu/kWh).
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The EPA is also proposing a revision to the requirements for
demonstrating compliance with the fPM emission standard. Currently,
EGUs that do not qualify for the low emitting EGU (LEE) program can
demonstrate compliance with the fPM standard either by conducting
quarterly performance testing (i.e., quarterly stack testing) or by
using PM continuous emission monitoring systems (PM CEMS). After
considering updated information on the costs for quarterly performance
testing compared to the costs of PM CEMS and on the measurement
capabilities of PM CEMS, as well as other benefits of using PM CEMS,
which include increased transparency and accelerated identification of
anomalous emissions, the EPA is proposing to require that all coal-
fired EGUs demonstrate compliance with the fPM emission standard by
using PM CEMS. Accordingly, because almost all regulated sources have
chosen to demonstrate compliance with the non-Hg HAP metal standards by
demonstrating compliance with the surrogate fPM standard and because of
the benefits of PM CEMS use for demonstrating compliance, the EPA is
proposing to remove the total and individual non-Hg metals emission
limits from MATS. Requiring the use of PM CEMS, if finalized, would
also render the current compliance method for the LEE program
superfluous, since LEE is an optional stack testing program and the
considered fPM limits are both below the current fPM LEE program limit
of 1.5E-02 lb/MMBtu (i.e., 50 percent of the current fPM standard).
Therefore, the EPA also proposes to remove fPM, as well as the total
and individual non-Hg HAP metals, from the LEE program.
The EPA is also proposing to establish a more protective Hg
emission standard for existing lignite-fired EGUs. Currently, existing
lignite-fired EGUs must meet a Hg emission standard of 4.0E-06 lb/MMBtu
\6\ or an alternative output-based emission standard of 4.0E-02 pounds
of Hg per gigawatt-hour output (lb/GWh). The EPA recently collected
information on current Hg emission levels and controls for lignite-
fired EGUs from information provided routinely to the EPA and to the
Energy Information Administration (EIA) and by using the information
collection authority provided under CAA section 114. That information
showed developments that demonstrate that lignite-fired EGUs can
achieve a Hg emission rate that is much lower than the current
standard, and that there are cost-effective control technologies and
methods of operation that are available to achieve a more stringent
standard. Accordingly, the EPA is proposing that lignite-fired EGUs
must meet the same Hg emission standard as EGUs firing other types of
coal (i.e., bituminous, and subbituminous) which is 1.2 lb/TBtu or an
alternative output-based standard of 1.3E-02 lb/GWh. The EPA is not
proposing to revise the current Hg emission standard for existing EGUs
firing non-lignite coal.
---------------------------------------------------------------------------

\6\ The emission standard of 4.0E-06 lb/MMBtu is more often
written as 4.0 lb/TBtu (pounds of Hg per trillion British thermal
units).
---------------------------------------------------------------------------

Finally, the EPA is proposing to remove one of the two options for
defining the startup period for MATS-affected EGUs. The first option
defines

[[Page 24858]]

startup as either the first-ever firing of fuel in a boiler for the
purpose of producing electricity, or the firing of fuel in a boiler
after a shutdown event for any purpose. Under the first option, startup
ends when any of the steam from the boiler is used to generate
electricity for sale over the grid or for any other purpose (including
on-site use). In the second option, startup is defined as the period in
which operation of an EGU is initiated for any purpose, and startup
begins with either the firing of any fuel in an EGU for the purpose of
producing electricity or useful thermal energy (such as heat or steam)
for industrial, commercial, heating, or cooling purposes (other than
the first-ever firing of fuel in a boiler following construction of the
boiler) or for any other purpose after a shutdown event. Under the
second option, startup ends 4 hours after the EGU generates electricity
that is sold or used for any other purpose (including on-site use), or
4 hours after the EGU makes useful thermal energy (such as heat or
steam) for industrial, commercial, heating, or cooling purposes,
whichever is earlier. The EPA is proposing to remove the second option,
which is currently being used by fewer than 10 EGUs as discussed in
section V.D.1 of this preamble.
The EPA is not proposing to modify the HCl emission standard (nor
the alternative sulfur dioxide (SO<INF>2</INF>) emission standard),
which serves as a surrogate for all acid gas HAP (HCl, HF,
SeO<INF>2</INF>) for existing coal-fired EGUs. An evaluation of recent
compliance data for HCl and/or SO<INF>2</INF> emissions revealed that
approximately two-thirds of coal-fired EGUs operate at or below the
alternative SO<INF>2</INF> emission standard of 2.0E-01 lb
SO<INF>2</INF>/MMBtu (SO<INF>2</INF> may be used as an alternative
surrogate for acid gas HAP at coal-fired EGUs with operational flue gas
desulfurization (FGD) systems and SO<INF>2</INF> CEMS). Approximately
one-third of coal-fired EGUs have a SO<INF>2</INF> emission rate above
the current SO<INF>2</INF> standard, but instead operate in compliance
with the primary acid gas HAP limit for HCl of 2.0E-03 lb HCl/MMBtu,
with most using an FGD system and/or by firing coal with low chlorine
content and high alkalinity. The EPA did not identify any new
technologies or developments in existing technologies that would
achieve additional emission reductions. Based on this review, the EPA
is not proposing revisions to the acid gas HAP emission standards for
coal-fired EGUs.
The EPA is unaware of any new coal- or oil-fired EGUs in
development and has not projected any new coal- or oil-fired EGUs in
EPA modeling to support various power sector-related rulemakings. For
that reason, the EPA has not reviewed and is not proposing any
revisions to the MATS new source emission standards. In some cases,
however, proposed revisions to existing source emission standards may
be more stringent than the corresponding new source emission standard.
In those instances, the EPA has addressed that illogical outcome by
proposing to revise the corresponding new source standard to be at
least as stringent as the proposed revision to the existing source
standard.
The EPA is also not proposing to revise MATS emission standards for
existing Integrated Gasification Combined Cycle (IGCC) EGUs, nor to the
MATS emission standards for any of the subcategories of existing oil-
fired EGUs.
In addition to generally soliciting comments on all aspects of this
proposed action, the EPA has identified several aspects of the proposal
on which comments are specifically requested.
In selecting a proposed standard, as discussed in detail below, the
EPA considered the statutory direction and factors laid out by Congress
in CAA section 112. Separately, pursuant to E.O. 12866, the EPA
prepared an analysis of the potential costs and benefits associated
with this action. This analysis, ``Regulatory Impact Analysis for the
Proposed National Emission Standards for Hazardous Air Pollutants:
Coal- and Oil-Fired Electric Utility Steam Generating Units Review of
the Residual Risk and Technology Review'' (Ref. EPA-452/R-23-002), is
available in the docket, and is briefly summarized here and in section
VI of this preamble.

II. General Information

A. Does this action apply to me?

The source category that is the subject of this proposal is coal-
and oil-fired EGUs regulated under 40 CFR part 63, subpart UUUUU. The
North American Industry Classification System (NAICS) codes for the
coal- and oil-fired EGU industry are 221112, 221122, and 921150. This
list of categories and NAICS codes is not intended to be exhaustive,
but rather provides a guide for readers regarding the entities that
this proposed action is likely to affect. The proposed standards, once
promulgated, will be directly applicable to the affected sources.
Federal, state, local, and tribal government entities that own and/or
operate EGUs subject to 40 CFR part 63, subpart UUUUU would be affected
by this proposed action. The coal- and oil-fired EGU source category
was added to the list of categories of major and area sources of HAP
published under section 112(c) of the CAA on December 20, 2000 (65 FR
79825). CAA section 112(a)(8) defines an EGU as any fossil fuel-fired
combustion unit of more than 25 megawatts (MW) that serves a generator
that produces electricity for sale. A unit that cogenerates steam and
electricity and supplies more than one-third of its potential electric
output capacity and more than 25 MW electrical output to any utility
power distribution system for sale is also considered an EGU.

B. 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 proposed action at
<a href="https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards">https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards</a>. Following publication in the Federal Register, the
EPA will post the Federal Register version of the proposal and key
technical documents at this same website.
A memorandum showing the rule edits that would be necessary to
incorporate the changes proposed in this action to 40 CFR part 63,
subpart UUUUU is available in the docket for this action (Docket ID No.
EPA-HQ-OAR-2018-0794). Following signature by the EPA Administrator,
the EPA also will post a copy of this document to <a href="https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards">https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards</a>.

III. Background

A. What is the authority for this action?

1. Statutory Authority
The statutory authority for this action is provided by sections 112
and 301 of the CAA, as amended (42 U.S.C. 7401 et seq.). Section 112 of
the CAA establishes a multi-stage regulatory process to develop
standards for emissions of HAP from stationary sources. Generally,
during the first stage Congress directed the EPA to establish
technology-based standards to ensure that all sources control pollution
at the level achieved by the best-performing sources, referred to as
the maximum achievable control technology (MACT). After the first
stage, Congress directed the EPA to review those standards periodically
to determine whether they should be strengthened. Within 8 years after
promulgation of the standards, the EPA must evaluate the MACT standards
to determine whether additional standards are needed to address any

[[Page 24859]]

remaining risk associated with HAP emissions. This second stage is
commonly referred to as the ``residual risk review.'' In addition, the
CAA also requires the EPA to review standards set under CAA section 112
on an ongoing basis no less than every 8 years and revise the standards
as necessary taking into account any ``developments in practices,
processes, and control technologies.'' This review is commonly referred
to as the ``technology review,'' and is the subject of this proposal.
The discussion that follows identifies the most relevant statutory
sections and briefly explains the contours of the methodology used to
implement these statutory requirements.
In the first stage of the CAA section 112 standard-setting process,
the EPA promulgates technology-based standards under CAA section 112(d)
for categories of sources identified as emitting one or more of the HAP
listed in CAA section 112(b). Sources of HAP emissions are either major
sources or area sources, and CAA section 112 establishes different
requirements for major source standards and area source standards.
``Major sources'' are those that emit or have the potential to emit 10
tons per year (tpy) or more of a single HAP or 25 tpy or more of any
combination of HAP. All other sources are ``area sources.'' For major
sources, CAA section 112(d)(2) provides that the technology-based
NESHAP must reflect ``the maximum degree of reduction in emissions of
the [HAP] subject to this section (including a prohibition on such
emissions, where achievable) that the Administrator, taking into
consideration the cost of achieving such emission reduction, and any
non-air quality health and environmental impacts and energy
requirements, determines is achievable.'' These standards are commonly
referred to as MACT standards. CAA section 112(d)(3) also establishes a
minimum control level for MACT standards, known as the MACT ``floor.''
\7\ In certain instances, as provided in CAA section 112(h), the EPA
may set work practice standards in lieu of numerical emission
standards. The EPA must also consider control options that are more
stringent than the floor. Standards more stringent than the floor are
commonly referred to as ``beyond-the-floor'' standards. For area
sources, CAA section 112(d)(5) allows the EPA to set standards based on
generally available control technologies or management practices (GACT
standards) in lieu of MACT standards.\8\
---------------------------------------------------------------------------

\7\ Specifically, for existing sources, the MACT ``floor'' shall
not be less stringent than the average emission reduction achieved
by the best performing 12 percent of existing sources. For new
sources MACT shall not be less stringent than the emission control
that is achieved in practice by the best controlled similar source.
\8\ For categories of area sources subject to GACT standards,
there is no requirement to address residual risk, but, similar to
the major source categories, the technology review is required.
---------------------------------------------------------------------------

For categories of major sources and any area source categories
subject to MACT standards, the next stage in standard-setting focuses
on identifying and addressing any remaining (i.e., ``residual'') risk
pursuant to CAA section 112(f)(2). The residual risk review requires
the EPA to update standards if needed to provide an ample margin of
safety to protect public health.
Concurrent with that review, and then at least every 8 years
thereafter, CAA section 112(d)(6) requires the EPA to review standards
promulgated under CAA section 112 and revise them ``as necessary
(taking into account developments in practices, processes, and control
technologies).'' See Portland Cement Ass'n v. EPA, 665 F.3d 177, 189
(D.C. Cir. 2011) (``Though EPA must review and revise standards `no
less often than every eight years,' 42 U.S.C. 7412(d)(6), nothing
prohibits EPA from reassessing its standards more often.''). In
conducting this review, which we call the ``technology review,'' the
EPA is not required to recalculate the MACT floors that were
established in earlier rulemakings. Natural Resources Defense Council
(NRDC) v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008); Association of
Battery Recyclers, Inc. v. EPA, 716 F.3d 667 (D.C. Cir. 2013). The EPA
may consider cost in deciding whether to revise the standards pursuant
to CAA section 112(d)(6). See e.g., Nat'l Ass'n for Surface Finishing
v. EPA, 795 F.3d 1, 11 (D.C. Cir. 2015). The EPA is required to address
regulatory gaps, such as missing MACT standards for listed air toxics
known to be emitted from the source category. Louisiana Environmental
Action Network (LEAN) v. EPA, 955 F.3d 1088 (D.C. Cir. 2020).
In this action, the EPA is proposing to reconsider the 2020 Final
Action's risk and technology review pursuant to the EPA's inherent
authority to reconsider previous decisions and to revise, replace, or
repeal a decision to the extent permitted by law and supported by a
reasoned explanation. FCC v. Fox Television Stations, Inc., 556 U.S.
502, 515 (2009); see also Motor Vehicle Mfrs. Ass'n v. State Farm
Mutual Auto. Ins. Co., 463 U.S. 29, 42 (1983).
2. EGU Regulation Under CAA Section 112
Congress enacted a special provision concerning coal- and oil-fired
EGU HAP emission regulations in the 1990 CAA Amendments under section
112(n)(1)(a) of the CAA that is not applicable to other source
categories. This provision required the EPA to conduct a study to
evaluate the hazards to public health that are reasonably anticipated
to occur as a result of HAP emissions from EGUs, and to make a one-time
finding of whether to regulate EGUs under CAA section 112 if the EPA
found that doing so was ``appropriate and necessary.'' 42 U.S.C.
7412(n)(1)(A) (the ``appropriate and necessary finding''). Once this
one-time finding was made, if the decision was to regulate, Congress
subjected EGUs to the same standards and procedures as other source
categories. Id. (``The Administrator shall regulate electric utility
steam generating units under this section'' if he finds doing so is
``appropriate and necessary.''); see also New Jersey v. EPA, 517 F.3d
574 (D.C. Cir. 2008) (establishing that, on the applicability of CAA
section 112(c)(9)'s delisting requirements, coal- and oil-fired EGUs
are treated similarly as other CAA section 112 regulated sources once
listed under CAA section 112(c)).
The EPA originally made the appropriate and necessary finding in
2000. This was followed by a series of affirmations and reversals of
this finding, as well as a Supreme Court decision that required the EPA
to consider the costs of regulation in making this finding. See
Michigan v. EPA, 576 U.S. 743 (2015). On February 9, 2022, the EPA
published a notice of proposed rulemaking reaffirming that it remains
appropriate and necessary to regulate HAP, including Hg, from coal- and
oil-fired EGUs after considering cost.\9\ The EPA's consideration of
costs in its decision to reaffirm the appropriate and necessary finding
was based on estimated and realized costs from the first stage of CAA
section 112 regulation, i.e., establishing MACT-based standards and
determining whether additional ``beyond-the-floor'' standards are
needed to address remaining risk.
---------------------------------------------------------------------------

\9\ For further discussion on the history of the CAA section
112(n)(1)(A) appropriate and necessary finding, please refer to the
EPA's February 9, 2022 proposal (87 FR 7624).
---------------------------------------------------------------------------

Consistent with Congress's direction, after making the appropriate
and necessary finding, the EPA treated EGUs like all other source
categories. As required by CAA section 112(d)(2), the EPA first set a
floor based on the best 12 percent of performers, and then conducted a
beyond-the-floor analysis. That inquiry led to the current MATS,
established in 2012. As explained above, the CAA then required the EPA,

[[Page 24860]]

within 8 years of promulgating the standards, to conduct the residual
risk and technology reviews. Congress thus contemplated that well after
the EPA determined the regulation of EGUs was appropriate and necessary
and well after the EPA set initial standards in accordance with the
floor and beyond-the-floor requirements in CAA section 112(d)(2), that
at least every 8 years thereafter on a continuing basis, the EPA would
review and revise those standards as necessary taking into account
developments in practices, processes, and control technologies. The EPA
has conducted over 100 technology reviews and has regularly updated
emissions standards for HAP based upon the technology review.
3. Executive Order 13990
On January 20, 2021, President Biden signed Executive Order 13990,
``Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis.'' The Executive order, among other things,
instructs the EPA to review the 2020 Final Action 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'' (85 FR
31286; May 22, 2020) and consider publishing a notice of proposed
rulemaking suspending, revising, or rescinding that action.

B. What is this source category and how does the current NESHAP
regulate its HAP emissions?

The NESHAP for the coal- and oil-fired EGU source category
(commonly referred to as MATS) were initially promulgated on February
16, 2012 (77 FR 9304) (2012 MATS Final Rule), under title 40 part 63,
subpart UUUUU. The MATS rule was amended on April 19, 2012 (77 FR
23399), to correct typographical errors and certain preamble text that
was inconsistent with regulatory text; on April 24, 2013 (78 FR 24073),
to update certain emission limits and monitoring and testing
requirements applicable to new sources; on November 19, 2014 (79 FR
68777), to revise definitions for startup and shutdown and to finalize
work practice standards and certain monitoring and testing requirements
applicable during periods of startup and shutdown; and on April 6, 2016
(81 FR 20172), to correct conflicts between preamble and regulatory
text and to clarify regulatory text. In addition, the electronic
reporting requirements of the rule were amended on March 24, 2015 (80
FR 15510), to allow for the electronic submission of Portable Document
Format (PDF) versions of certain reports until April 16, 2017, while
the EPA's Emissions Collection and Monitoring Plan System (ECMPS) is
revised to accept all reporting that is required by the rule, and on
April 6, 2017 (82 FR 16736), and on July 2, 2018 (83 FR 30879), to
extend the interim submission of PDF versions of reports through June
30, 2018, and July 1, 2020, respectively.
The MATS rule applies to coal- and oil-fired EGUs located at both
major and area sources of HAP emissions. An existing affected source is
the collection of coal- or oil-fired EGUs in a subcategory within a
single contiguous area and under common control. A new affected source
is each coal- or oil-fired EGU for which construction or reconstruction
began after May 3, 2011. As previously stated in section II of this
preamble, an EGU is a fossil fuel-fired combustion unit of more than 25
MW that serves a generator that produces electricity for sale. A unit
that cogenerates steam and electricity and supplies more than one-third
of its potential electric output capacity and more than 25 MW electric
output to any utility power distribution system for sale is also
considered an EGU. The MATS rule defines additional terms for
determining rule applicability, including, but not limited to,
definitions for ``coal-fired electric utility steam generating unit,''
``oil-fired electric utility steam generating unit,'' and ``fossil
fuel-fired.'' Certain types of electric generating units are not
subject to 40 CFR part 63, subpart UUUUU: any unit designated as a
major source stationary combustion turbine subject to subpart YYYY of
40 CFR part 63 and any unit designated as an area source stationary
combustion turbine, other than an IGCC unit; any EGU that is not a
coal- or oil-fired EGU and that meets the definition of a natural gas-
fired EGU in 40 CFR 63.10042; any EGU greater than 25 MW that has the
capability of combusting either coal or oil, but does not meet the
definition of a coal- or oil-fired EGU because it did not fire
sufficient coal or oil to satisfy the average annual heat input
requirement set forth in the definitions for coal-fired and oil-fired
EGUs in 40 CFR 63.10042; and any electric steam generating unit
combusting solid waste (i.e., a solid waste incineration unit) subject
to standards established under sections 129 and 111 of the CAA.
For coal-fired EGUs, the rule established standards to limit
emissions of Hg, acid gas HAP (e.g., HCl, HF), non-Hg HAP metals (e.g.,
nickel, lead, chromium), and organic HAP (e.g., formaldehyde, dioxin/
furan). Emission standards for HCl serve as a surrogate for the acid
gas HAP, with an alternate standard for SO<INF>2</INF> that may be used
as a surrogate for acid gas HAP for those coal-fired EGUs with FGD
systems and SO<INF>2</INF> CEMS installed and operational. Standards
for fPM serve as a surrogate for the non-Hg HAP metals, with standards
for total non-Hg HAP metals and individual non-Hg HAP metals provided
as alternative equivalent standards. Work practice standards limit
formation and emissions of organic HAP.
For oil-fired EGUs, the rule established standards to limit
emissions of HCl and HF, total HAP metals (e.g., Hg, nickel, lead), and
organic HAP (e.g., formaldehyde, dioxin/furan). Standards for fPM serve
as a surrogate for total HAP metals, with standards for total HAP
metals and individual HAP metals provided as alternative equivalent
standards. Work practice standards limit formation and emissions of
organic HAP.
The MATS rule includes standards for existing and new EGUs for
seven subcategories: two for coal-fired EGUs, one for IGCC EGUs, one
for solid oil-derived fuel-fired EGUs (i.e., petroleum coke-fired), and
three for liquid oil-fired EGUs. EGUs in six of the subcategories are
subject to numeric emission limits for all the pollutants described
above except for organic HAP. Emissions of organic HAP are regulated by
a work practice standard that requires periodic combustion process
tune-ups. EGUs in the subcategory of limited-use liquid oil-fired EGUs
with an annual capacity factor of less than 8 percent of its maximum or
nameplate heat input are also subject to a work practice standard
consisting of periodic combustion process tune-ups but are not subject
to any numeric emission limits. Emission limits for existing EGUs are
summarized in Table 1.

[[Page 24861]]

Table 1--Emission Limits for Existing Affected EGUs
------------------------------------------------------------------------
Subcategory Pollutant Emission limit \1\
------------------------------------------------------------------------
Any coal-fired unit firing any a. fPM............ 3.0E-2 lb/MMBtu or
rank of coal. 3.0E-1 lb/MWh.
OR OR
Total non-Hg HAP 5.0E-5 lb/MMBtu or
metals. 5.0E-1 lb/GWh.
OR OR
Individual HAP ..................
metals:
Antimony, Sb...... 8.0E-1 lb/TBtu or
8.0E-3 lb/GWh.
Arsenic, As....... 1.1 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...... 2.8 lb/TBtu or
3.0E-2 lb/GWh.
Cobalt, Co........ 8.0E-1 lb/TBtu or
8.0E-3 lb/GWh.
Lead, Pb.......... 1.2 lb/TBtu or
2.0E-2 lb/GWh.
Manganese, Mn..... 4.0 lb/TBtu or
5.0E-2 lb/GWh.
Nickel, Ni........ 3.5 lb/TBtu or
4.0E-2 lb/GWh.
Selenium, Se...... 5.0 lb/TBtu or
6.0E-2 lb/GWh.
b. HCl............ 2.0E-3 lb/MMBtu or
2.0E-2 lb/MWh.
OR OR
SO2 \2\........... 2.0E-1 lb/MMBtu or
1.5 lb/MWh.
Coal-fired unit low rank virgin c. Hg............. 1.2 lb/TBtu or
coal. 1.3E-2 lb/GWh.
Coal-fired unit low rank virgin c. Hg............. 4.0 lb/TBtu or
coal. 4.0E-2 lb/GWh.
IGCC unit....................... a. fPM............ 4.0E-2 lb/MMBtu or
4.0E-1 lb/MWh.
OR OR
Total non-Hg HAP 6.0E-5 lb/MMBtu or
metals. 5.0E-1 lb/GWh.
OR OR
Individual HAP ..................
metals:
Antimony, Sb...... 1.4 lb/TBtu or
2.0E-2 lb/GWh.
Arsenic, As....... 1.5 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...... 2.9 lb/TBtu or
3.0E-2 lb/GWh.
Cobalt, Co........ 1.2 lb/TBtu or
2.0E-2 lb/GWh.
Lead, Pb.......... 1.9E+2 lb/MMBtu or
1.8 lb/MWh.
Manganese, Mn..... 2.5 lb/TBtu or
3.0E-2 lb/GWh.
Nickel, Ni........ 6.5 lb/TBtu or
7.0E-2 lb/GWh.
Selenium, Se...... 2.2E+1 lb/TBtu or
3.0E-1 lb/GWh.
b. HCl............ 5.0E-4 lb/MMBtu or
5.0E-3 lb/MWh.
c. Hg............. 2.5 lb/TBtu or
3.0E-2 lb/GWh.
Liquid oil-fired unit-- a. fPM............ 3.0E-2 lb/MMBtu or
continental (excluding limited- 3.0E-1 lb/MWh.
use liquid oil-fired
subcategory units).
OR OR
Total HAP metals.. 8.0E-4 lb/MMBtu or
8.0E-3 lb/MWh.
OR OR
Individual HAP ..................
metals:
Antimony, Sb...... 1.3E+1 lb/TBtu or
2.0E-1 lb/GWh.
Arsenic, As....... 2.8 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...... 5.5 lb/TBtu or
6.0E-2 lb/GWh.
Cobalt, Co........ 2.1E+1 lb/TBtu or
3.0E-1 lb/GWh.
Lead, Pb.......... 8.1 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
1.1 lb/GWh.
Selenium, Se...... 3.3 lb/TBtu or
4.0E-2 lb/GWh.
Hg................ 2.0E-1 lb/TBtu or
2.0E-3 lb/GWh.
b. HCl............ 2.0E-3 lb/MMBtu or
1.0E-2 lb/MWh.
c. HF............. 4.0E-4 lb/MMBtu or
4.0E-3 lb/MWh.
Liquid oil-fired unit--non- a. fPM............ 3.0E-2 lb/MMBtu or
continental (excluding limited- 3.0E-1 lb/MWh.
use liquid oil-fired
subcategory units).
OR OR
Total HAP metals.. 6.0E-4 lb/MMBtu or
7.0E-3 lb/MWh.
OR OR
Individual HAP ..................
metals:
Antimony, Sb...... 2.2 lb/TBtu or
2.0E-2 lb/GWh.
Arsenic, As....... 4.3 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
1.4 lb/GWh.
Lead, Pb.......... 4.9 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
4.1 lb/GWh.
Selenium, Se...... 9.8 lb/TBtu or
2.0E-1 lb/GWh.

[[Page 24862]]

Hg................ 4.0E-2 lb/TBtu or
4.0E-4 lb/GWh.
b. HCl............ 2.0E-4 lb/MMBtu or
2.0E-3 lb/MWh.
c. HF............. 6.0E-5 lb/MMBtu or
5.0E-4 lb/MWh.
Solid oil-derived fuel-fired a. fPM............ 8.0E-3 lb/MMBtu or
unit. 9.0E-2 lb/MWh.
OR OR
Total non-Hg HAP 4.0E-5 lb/MMBtu or
metals. 6.0E-1 lb/GWh.
OR OR
Individual HAP ..................
metals
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........ 1.1 lb/TBtu or
2.0E-2 lb/GWh.
Lead, Pb.......... 8.0E-1 lb/TBtu or
2.0E-2 lb/GWh.
Manganese, Mn..... 2.3 lb/TBtu or
4.0E-2 lb/GWh.
Nickel, Ni........ 9.0 lb/TBtu or
2.0E-1 lb/GWh.
Selenium, Se...... 1.2 lb/TBtu 2.0E-2
lb/GWh.
b. HCl............ 5.0E-3 lb/MMBtu or
8.0E-2 lb/MWh.
OR OR
SO2 \2\........... 3.0E-1 lb/MMBtu or
2.0 lb/MWh.
c. Hg............. 2.0E-1 lb/TBtu or
2.0E-3 lb/GWh.
------------------------------------------------------------------------
\1\ Units of emission limits:
lb/MMBtu = pounds pollutant per million British thermal units fuel
input;
lb/TBtu = pounds pollutant per trillion British thermal units fuel
input;
lb/MWh = pounds pollutant per megawatt-hour electric output (gross); and
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
\2\ Alternate SO2 limit may be used if the EGU has some form of FGD
system and SO2 CEMS installed.

C. What data collection activities were conducted to support this
proposed action?

On February 9, 2022, the EPA published a notice of proposed
rulemaking reaffirming that it remains appropriate and necessary to
regulate coal- and oil-fired EGUs under CAA section 112 after
considering the cost of regulation. In that same action, the EPA
solicitated information on the cost and performance of new or improved
technologies that control HAP emissions, on improved methods of
operation, and on risk-related information to further inform the EPA's
assessment of the MATS RTR. Generally, commenters were unaware of new
technologies, but indicated that current technologies are more widely
used, more effective, and cheaper than at the time of the adoption of
MATS. Specific data or information used to support this action are
discussed in more detail in section V of this preamble.
The EPA also issued a limited request for information pursuant to
section 114 of the CAA to obtain information related to HAP emissions
from coal- and oil-fired EGUs to inform the technology review under CAA
section 112(d)(6). Specifically, the EPA collected information and data
related to Hg emissions and control technologies for lignite-fired
EGUs. The CAA section 114 survey and responses are available in the
docket for this action.

D. What other relevant background information and data are available?

The EPA used multiple sources of information to support this
proposed action. A comprehensive list of facilities and EGUs that are
subject to the MATS rule was compiled primarily using the list from the
2020 Final Action and publicly available information reported to the
EPA and information contained in the EPA's National Electric Energy
Data System (NEEDS) database.\10\ Affected sources are required to use
the 40 CFR part 75-based ECMPS \11\ for reporting emissions and related
data either directly for EGUs that use Hg, HCl, HF, or SO<INF>2</INF>
CEMS or Hg sorbent traps for compliance purposes or indirectly as PDF
files for EGUs that use performance test results, PM continuous
parameter monitoring system (CPMS) data, or PM CEMS for compliance
purposes. Directly submitted data are maintained in ECMPS; indirectly
submitted data are maintained in Web Factor Information Retrieval
System (WebFIRE).\12\ The NEEDS database contains generation unit
information used in the EPA's power sector modeling. Other sources used
include the U.S. Department of Energy's EIA list of fuel consumption
reported for 2021 under Form EIA-923 \13\ and emissions test data
collected from an ICR in 2010 (2010 ICR) when promulgating the 2011
Proposal.\14\
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\10\ See <a href="https://www.epa.gov/airmarkets/power-sector-modeling-platform-v515">https://www.epa.gov/airmarkets/power-sector-modeling-platform-v515</a>.
\11\ See <a href="https://ampd.epa.gov/ampd/">https://ampd.epa.gov/ampd/</a>.
\12\ See <a href="https://cfpub.epa.gov/webfire">https://cfpub.epa.gov/webfire</a>; <a href="https://www.epa.gov/electronic-reporting-air-emissions/webfire">https://www.epa.gov/electronic-reporting-air-emissions/webfire</a>.
\13\ See <a href="https://www.eia.gov/electricity/data/eia923/">https://www.eia.gov/electricity/data/eia923/</a>.
\14\ See <a href="https://www3.epa.gov/airtoxics/utility/utilitypg.html">https://www3.epa.gov/airtoxics/utility/utilitypg.html</a>.
---------------------------------------------------------------------------

In conducting the technology review, the EPA examined information
submitted to the EPA's ECMPS as well as information that supports
previous 40 CFR part 63, subpart UUUUU actions to identify technologies
currently being used by affected EGUs and to determine if there have
been developments in practices, processes, or control technologies. In
addition to the ECMPS data, we reviewed regulatory actions for similar
combustion sources and conducted a review of literature published by
industry organizations, technical journals, and government
organizations.

E. How does the EPA perform the technology review?

Our technology review primarily focuses on the identification and
evaluation of developments in practices, processes, and control
technologies that have occurred since the MACT standards were
promulgated. Where we identify such developments, we analyze

[[Page 24863]]

the technical feasibility, estimated costs, energy implications, non-
air environmental impacts, and potential emissions reductions of more
stringent standards, to ensure that the MACT standards continue to
fulfill Congress's direction to require the maximum degree of reduction
of HAP taking into account the statutory factors. This analysis informs
our decision of whether it is ``necessary'' to revise the emissions
standards. In addition, we typically consider the appropriateness of
applying controls to new sources versus retrofitting existing sources.
For this exercise, we consider any of the following to be a
``development'':
<bullet> Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
standards;
<bullet> Any improvements in add-on control technology or other
equipment (that were identified and considered during development of
the original MACT standards) that could result in additional emission
reductions; \15\
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\15\ This may include getting new or better information about
the performance of an add-on or existing control technology (e.g.,
emissions data from affected sources showing an add-on control
technology performs better than anticipated during development of
the rule).
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<bullet> Any work practice or operational procedure that was not
identified or considered during development of the original MACT
standards;
<bullet> Any process change or pollution prevention alternative
that could be broadly applied to the industry and that was not
identified or considered during development of the original MACT
standards; and
<bullet> Any significant changes in the cost (including cost
effectiveness) of applying controls (including controls the EPA
considered during the development of the original MACT standards).
<bullet> Any operational changes or other factors that were not
considered during the development of the original MACT standards.
In addition to reviewing the practices, processes, and control
technologies that were considered at the time we originally developed
(or last updated) the NESHAP, we review a variety of data sources in
our investigation of potential practices, processes, or controls to
consider. We also review the NESHAP and the available data to determine
if there are any unregulated emissions of HAP within the source
category and evaluate this data for use in developing new emission
standards. When reviewing MACT standards, the EPA is required to
address regulatory gaps, such as missing standards for listed air
toxics known to be emitted from the source category, and any new MACT
standards must be established under CAA sections 112(d)(2) and (3), or,
in specific circumstances, CAA sections 112(d)(4) or (h). Louisiana
Environmental Action Network (LEAN) v. EPA, 955 F.3d 1088 (D.C. Cir.
2020). See sections III.C and III.D of this preamble for information on
the specific data sources that were reviewed as part of the technology
review.

IV. Review of 2020 Residual Risk and Technology Review

A. Summary of the 2020 Residual Risk Review

Pursuant to CAA section 112(f)(2), the EPA conducted a residual
risk review (2020 Residual Risk Review) and presented the results of
this review, along with our decisions regarding risk acceptability,
ample margin of safety, and adverse environmental effects, in the 2020
Final Action. The results of the risk assessment are presented briefly
in Table 2, and in more detail in the document titled Residual Risk
Assessment for the Coal- and Oil-Fired EGU Source Category in Support
of the 2020 Risk and Technology Review Final Rule (risk document for
the final rule), available in the docket (Docket ID No. EPA-HQ-OAR-
2018-0794-4553).

Table 2--Coal- and Oil-Fired EGU Inhalation Risk Assessment Results in the 2020 Final Action
[85 FR 31286; May 22, 2020]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Maximum individual cancer risk Population at increased risk Annual cancer incidence (cases Maximum chronic noncancer Maximum
(in 1 million) \2\ of cancer >=1-in-1 million per year) TOSHI \3\ screening
-------------------------------------------------------------------------------------------------------------------------------- acute
Based on . . . Based on . . . Based on . . . Based on . . . noncancer HQ
-------------------------------------------------------------------------------------------------------------------------------- \4\
Number of facilities \1\ ---------------
Actual Allowable Actual Allowable Actual Allowable Actual Allowable Based on
emissions emissions emissions emissions emissions emissions emissions emissions actual
level level level level level level level level emissions
level
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
332............................................. 9 10 193,000 636,000 0.04 0.1 0.2 0.4 HQREL = 0.09
(arsenic)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Number of facilities evaluated in the risk analysis. At the time of the risk analysis there were an estimated 323 facilities in the Coal- and Oil-Fired EGU source category; however, one
facility is located in Guam, which was beyond the geographic range of the model used to estimate risks. Therefore, the Guam facility was not modeled and the emissions for that facility were
not included in the assessment.
\2\ Maximum individual excess lifetime cancer risk due to HAP emissions from the source category.
\3\ Maximum target organ-specific hazard index (TOSHI). The target organ systems with the highest TOSHI for the source category are respiratory and immunological.
\4\ The maximum estimated acute exposure concentration was divided by available short-term threshold values to develop an array of hazard quotient (HQ) values. HQ values shown use the lowest
available acute threshold value, which in most cases is the reference exposure level (REL). When an HQ exceeds 1, we also show the HQ using the next lowest available acute dose-response
value.

1. Chronic Inhalation Risk Assessment Results
The results of the chronic inhalation cancer risk assessment based
on actual emissions, as shown in Table 2 of this preamble, indicated
that the estimated maximum individual lifetime cancer risk (cancer MIR)
was 9-in-1 million, with nickel emissions from certain oil-fired EGUs
as the major contributor to the risk. The total estimated cancer
incidence from this source category was 0.04 excess cancer cases per
year, or one excess case in every 25 years. Approximately 193,000
people were estimated to have cancer risks at or above 1-in-1 million
from HAP emitted from the facilities in this source category.\16\ The
estimated maximum chronic noncancer TOSHI for the source category was
0.2 (respiratory), which was driven by emissions of nickel and cobalt
from oil-fired EGUs. No one was exposed to TOSHI levels above 1 based
on actual emissions from sources regulated under this source category.
---------------------------------------------------------------------------

\16\ There were four facilities in the source category with
cancer risk at or above 1-in-1 million, and all of them were
facilities with oil-fired EGUs located in Puerto Rico.
---------------------------------------------------------------------------

The EPA also evaluated the cancer risk at the maximum emissions
allowed by the MACT standard (i.e., ``allowable emissions''). As shown
in Table 2 of this preamble, based on allowable emissions, the
estimated cancer MIR

[[Page 24864]]

was 10-in-1 million, and, as before, nickel emissions from oil-fired
EGUs were the major contributor to the risk. The total estimated cancer
incidence from this source category, considering allowable emissions,
was 0.1 excess cancer cases per year, or one excess case in every 10
years. Based on allowable emissions, approximately 636,000 people were
estimated to have cancer risks at or above 1-in-1 million from HAP
emitted from the facilities in this source category. The estimated
maximum chronic noncancer TOSHI for the source category was 0.4
(respiratory) based on allowable emissions, driven by emissions of
nickel and cobalt from oil-fired EGUs. No one was exposed to TOSHI
levels above 1 based on allowable emissions.
2. Screening Level Acute Risk Assessment Results
Because of the conservative nature of the acute inhalation
screening assessment and the variable nature of emissions and potential
exposures, acute impacts are screened on an individual pollutant basis,
not using the TOSHI approach. Table 2 of this preamble provides the
worst-case acute HQ (based on the REL) of 0.09, driven by emissions of
arsenic. There were no facilities that have acute HQs (based on the REL
or any other reference values) greater than 1. For more detailed acute
risk results, refer to the risk document available in the docket
(Docket ID No. EPA-HQ-OAR-2018-0794-4553).
3. Multipathway Risk Screening and Site-Specific Assessment Results
Potential multipathway health risks under a fisher and gardener
scenario were evaluated using a three-tier screening assessment of the
HAP known to be persistent and bio-accumulative in the environment (PB-
HAP) emitted by facilities in the coal- and oil-fired EGU source
category. This evaluation resulted in a site-specific assessment of Hg
using the EPA's Total Risk Integrated Methodology.Fate, Transport, and
Ecological Exposure (TRIM.FaTE) model for one location (three
facilities located in North Dakota) as further described below. Of the
322 MATS-affected facilities modeled, 307 facilities had reported
emissions of carcinogenic PB-HAP (arsenic, dioxins, and polycyclic
organic matter (POM)) that exceeded a Tier 1 cancer screening value of
1, which corresponds to an upper bound maximum excess lifetime cancer
risk that may be greater than 1-in-1 million. This source category also
had 235 facilities reporting emissions of non-carcinogenic PB-HAP
(lead, Hg, and cadmium) that exceeded an upper bound Tier 1 noncancer
screening value of 1, which corresponds to a HQ of 1 For facilities
that exceeded a Tier 1 multipathway screening value of 1, we used
additional facility site-specific information to perform a refined
screening assessment through Tiers 2 and 3, as necessary, to determine
the maximum chronic cancer and noncancer impacts for the source
category. For cancer, the highest Tier 2 screening value for the
gardener scenario (rural) was 200 driven by arsenic emissions. This
screening value was reduced to 50 after accounting for plume rise in
our Tier 3 screen. Because this screening value was much lower than
100-in-1 million, and because we expected the actual risk from a site-
specific assessment to further lower the Tier 2 screening value by a
factor of 50, we decided not to perform a site-specific assessment for
cancer. For noncancer, the highest Tier 2 screening value was 30 (for
Hg) for the fisher scenario, with four facilities having screening
values greater than 20. These screening values were reduced to 9 or
lower after the plume rise stage of Tier 3.
Because the final stage of Tier 3 (time-series) was unlikely to
reduce the highest Hg screening values to 1, we conducted a site-
specific multipathway assessment of Hg emissions for this source
category. Analysis of the facilities with the highest Tier 2 and Tier 3
screening values helped identify the location for the site-specific
assessment and the facilities to model with TRIM.FaTE. The assessment
considered the effect that multiple facilities within the source
category may have on common lakes. The three facilities selected were
located near Underwood, North Dakota. All three facilities had Tier 2
screening values greater than or equal to 20. Two of the facilities
were near each other (16 kilometers (km) apart). The third facility was
more distant, about 20 to 30 km from the other facilities, but it was
included in the analysis because it is within the 50-km modeling domain
of the other facilities and because it had an elevated Tier 2 screening
value. We expected that the exposure scenarios we assessed for these
facilities are among the highest, if not the highest, that might be
encountered for other facilities in this source category based upon
their Hg emissions and their respective Tier 2 screening values and
aggregate impacts to common lakes. The refined site-specific
multipathway assessment estimated an HQ of 0.06 for Hg for the three
facilities assessed. We believed the assessment represented the highest
potential for Hg hazards through fish consumption for the source
category based upon an upper-end fish ingestion rate of 373 grams/day.
In evaluating the potential multipathway risk from emissions of
lead compounds, rather than developing a screening threshold emission
rate, we compared maximum estimated chronic inhalation exposure
concentrations to the level of the current National Ambient Air Quality
Standards (NAAQS) for lead (0.15 micrograms per cubic meter). Values
below the level of the primary (health-based) lead NAAQS were
considered to have a low potential for multipathway risk. We did not
estimate any exceedances of the lead NAAQS in this source category, the
maximum predicted Pb screen concentration over a 3-month period for
this source category was equal to 0.005 micrograms per cubic meter,
significantly below the Pb NAAQS.
4. Environmental Risk Screening Results
An environmental risk screening assessment for the coal- and oil-
fired EGU source category was conducted for the following pollutants:
arsenic, cadmium, dioxins/furans, HCl, HF, lead, Hg (methylmercury and
mercuric chloride), and POMs. In the Tier 1 screening analysis for PB-
HAP (other than lead, which was evaluated differently), POM emissions
had no exceedances of any of the ecological benchmarks evaluated.
Arsenic and dioxin/furan emissions had Tier 1 exceedances for surface
soil benchmarks. Cadmium and methylmercury emissions had Tier 1
exceedances for surface soil and fish benchmarks. Divalent Hg emissions
had Tier 1 exceedances for sediment and surface soil benchmarks.
A Tier 2 screening analysis was performed for arsenic, cadmium,
dioxins/furans, divalent Hg, and methylmercury emissions. In the Tier 2
screening analysis, arsenic, cadmium, and dioxin/furan emissions had no
exceedances of any of the ecological benchmarks evaluated. Divalent Hg
emissions from two facilities exceeded the Tier 2 screen for a sediment
threshold level benchmark by a maximum screening value of 2.
Methylmercury emissions from the same two facilities exceeded the Tier
2 screen for a fish (avian/piscivores) no-observed-adverse-effect-level
(NOAEL) (merganser) benchmark by a maximum screening value of 2. A Tier
3 screening assessment was performed to verify the existence of the
lake associated with these screening values, and it was found to be
located on-site and is a man-made

[[Page 24865]]

industrial pond, and, therefore, was removed from the assessment.
Methylmercury emissions from two facilities exceeded the Tier 2
screen for a surface soil NOAEL for avian ground insectivores
(woodcock) benchmark by a maximum screening value of 2. Other surface
soil benchmarks for methylmercury, such as the NOAEL for mammalian
insectivores and the threshold level for the invertebrate community,
were not exceeded. Given the low Tier 2 maximum screening value of 2
for methylmercury, and the fact that only the most protective benchmark
was exceeded, a Tier 3 environmental risk screen was not conducted for
methylmercury.
For lead, we did not estimate any exceedances of the secondary lead
NAAQS. For HCl and HF, the average modeled concentration around each
facility (i.e., the average concentration of all off-site data points
in the modeling domain) did not exceed any ecological benchmark. In
addition, each individual modeled concentration of HCl and HF (i.e.,
each off-site data point in the modeling domain) was below the
ecological benchmarks for all facilities.
Based on the results of the environmental risk screening analysis,
we did not expect an adverse environmental effect as a result of HAP
emissions from the coal- and oil-fired EGU source category.
5. Facility-Wide Risk Results
An assessment of risk from facility-wide emissions was performed to
provide context for the source category risks. Based on facility-wide
emissions estimates developed using the same estimates of actual
emissions for emissions sources in the source category, and emissions
data from the 2014 National Emissions Inventory (NEI) (version 2) for
the sources outside the source category, the estimated cancer MIR was
9-in-1 million, and nickel emissions from oil-fired EGUs were the major
contributor to the risk. The total estimated cancer incidence based on
facility-wide emissions was 0.04 excess cancer cases per year, or one
excess case in every 25 years. Approximately 203,000 people were
estimated to have cancer risks at or above 1-in-1 million from HAP
emitted from all sources at the facilities in this source category. The
estimated maximum chronic noncancer TOSHI posed by facility-wide
emissions was 0.2 (respiratory), driven by emissions of nickel and
cobalt from oil-fired EGUs. No one was exposed to TOSHI levels above 1
based on facility-wide emissions. These results were very similar to
those based on actual emissions from the source category because there
was not significant collocation of other sources with EGUs.
6. Decisions Regarding Risk Acceptability, Ample Margin of Safety, and
Adverse Environmental Effect
In determining whether residual risks are acceptable for this
source category in accordance with CAA section 112, the EPA considered
all available health information and risk estimation uncertainty. The
results of the risk analysis indicated that both the actual and
allowable inhalation cancer risks to the individual most exposed were
below 100-in-1 million, which is the presumptive limit of
acceptability. Also, the highest chronic noncancer TOSHI and the
highest acute noncancer HQ were below 1, indicating low likelihood of
adverse noncancer effects from inhalation exposures. There were also
low risks associated with ingestion, with the highest cancer risk being
less than 50-in-1 million based on a conservative screening assessment,
and the highest noncancer hazard being less than 1 based on a site-
specific multipathway assessment. Considering this information, the EPA
determined in 2020 that the residual risks of HAP emissions from the
coal- and oil-fired EGU source category were acceptable.
We then considered whether the current standards provided an ample
margin of safety to protect public health and whether more stringent
standards were necessary to prevent an adverse environmental effect by
taking into consideration costs, energy, safety, and other relevant
factors. In determining whether the standards provided an ample margin
of safety to protect public health, we examined the same risk factors
that we investigated for our acceptability determination and we also
considered the costs, technological feasibility, and other relevant
factors related to emissions control options that might reduce risk
associated with emissions from the source category. In our analysis, we
considered the results of the technology review, risk assessment, and
other aspects of our MACT rule review to determine whether there were
any cost-effective controls or other measures that would reduce
emissions further to provide an ample margin of safety. The risk
analysis indicated that the risks from the source category are low for
both cancer and noncancer health effects. Thus, we determined in 2020
that the current MATS requirements provided an ample margin of safety
to protect public health in accordance with CAA section 112.
Based on the results of our environmental risk screening
assessment, we also determined in 2020 that more stringent standards
were not necessary to prevent an adverse environmental effect.

B. Summary of the 2020 Technology Review

Pursuant to CAA section 112(d)(6), the EPA conducted a technology
review (2020 Technology Review) in the 2020 Final Action, which focused
on identifying and evaluating developments in practices, processes, and
control technologies for the emission sources in the source category
that occurred since the MATS rule was promulgated. Control technologies
typically used to minimize emissions of pollutants that have numeric
emission limits under the MATS rule include electrostatic precipitators
(ESPs) and fabric filters (FFs) for control of non-Hg HAP metals; wet
scrubbers and dry scrubbers for control of acid gases (SO<INF>2</INF>,
HCl, and HF); and activated carbon injection (ACI) for control of Hg.
The EPA determined that existing air pollution control technologies
that were in use were well-established and provided the capture
efficiencies necessary for compliance with the MATS emission limits.
Based on the effectiveness and proven reliability of these control
technologies, and the relatively short period of time since the
promulgation of the MATS rule, the EPA did not identify any
developments in practices, processes, or control technologies, nor any
new technologies or practices, for the control of non-Hg HAP metals,
acid gas HAP, or Hg. However, in the 2020 Technology Review, the EPA
did not consider developments in the cost and effectiveness of these
proven technologies, nor did the EPA evaluate the current performance
of emission reduction control equipment and strategies at existing
MATS-affected EGUs, to determine whether revising the standards was
warranted. Organic HAP, including emissions of dioxins and furans, are
regulated by a work practice standard that requires periodic burner
tune-ups to ensure good combustion. The EPA found that this work
practice continued to be a practical approach to ensuring that
combustion equipment was maintained and optimized to run to reduce
emissions of organic HAP and continued to be more effective than
establishing a numeric standard that cannot reliably be measured or
monitored. Based on the effectiveness and proven reliability of the
work practice standard, and the relatively short amount of time since
the

[[Page 24866]]

promulgation of the MATS rule, the EPA did not identify any
developments in work practices nor any new work practices or
operational procedures for this source category regarding the
additional control of organic HAP.
After conducting the 2020 Technology Review, the EPA did not
identify developments in practices, processes, or control technologies
and, thus, did not propose changes to emission standards or other
requirements. More information concerning that technology review is in
the memorandum titled Technology Review for the Coal- and Oil-Fired EGU
Source Category, available in the docket (Docket ID No. EPA-HQ-OAR-
2018-0794-0015), and in the February 7, 2019, proposed rule. 84 FR
2700. On May 20, 2020, the EPA finalized the first technology review
required by CAA section 112(d)(6) for the coal- and oil-fired EGU
source category regulated under MATS. Based on the results of that
technology review, the EPA found that no revisions to MATS were
warranted. See 85 FR 31314 (May 22, 2020).

V. Analytical Results and Proposed Decisions

As described in section IV, the EPA conducted a residual risk
review under CAA section 112(f) and presented results of the review in
the 2020 Final Action. Executive Order 13990, ``Protecting Public
Health and the Environment and Restoring Science to Tackle the Climate
Crisis'' required the EPA to review the 2020 Final Action and consider
publishing a notice of proposed rulemaking suspending, revising, or
rescinding the 2020 Final Action. As part of this effort, the EPA
solicited information to inform a review of the MATS RTR in the 2022
Proposal affirming it is appropriate and necessary to regulate coal-
and oil-fired EGUs under CAA section 112. The EPA summarizes the
results of the review of the RTR and proposed decisions consequent of
the review below and requests comment on specific considerations. In
addition to generally soliciting comments on all aspects of this
proposed action, the EPA is requesting public comment on specific
issues as described below. In addition, the EPA is granting in part
certain petitions for reconsideration on the Agency's prior
rulemakings, which are discussed in further detail below.

A. Review of the 2020 Residual Risk Review

The EPA has reviewed the 2020 Residual Risk Review as directed by
E.O. 13990. This included a review of the 2020 residual risk assessment
described in Docket ID No. EPA-HQ-OAR-2018-0794-0014 and consideration
of comments received in response to the 2022 Proposal. The EPA did not
receive any new information in response to the 2022 Proposal that would
affect the EPA's 2020 residual risk analysis or the decisions emanating
from that analysis. In reviewing the 2020 residual risk analysis, the
EPA has determined that the risk analysis was a rigorous and robust
analytical review using approaches and methodologies that are
consistent with those that have been utilized in residual risk analyses
and reviews for other industrial sectors. In addition, the results of
the 2020 residual risk assessment, as summarized in section IV.A of
this preamble, indicated low residual risk from the coal- and oil-fired
EGU source category. For these reasons, we are not proposing any
revisions to the 2020 Residual Risk Review. Although we are not
reopening the 2020 determination of whether residual risks would alone
be sufficient under the CAA to necessitate new standards, the EPA
acknowledges that the revised standards being proposed under this
technology review, as explored below, will likely reduce HAP exposures
to affected populations. In recognition of the hazardous nature of
these HAP, Congress intentionally created a two-pronged structure for
updating standards for toxic air pollutants that requires the EPA to
continue assessing opportunities to strengthen the standards under CAA
section 112(d)(6) even after residual risks have been addressed under
CAA section 112(f)(2).\17\ Under this structure, recognizing the value
of reducing any exposure to HAP where feasible, the EPA is obligated to
update standards where either the EPA finds it is necessary to provide
an ample margin of safety to protect public health or where the EPA
finds it is necessary taking into account developments in practices,
processes, and control technologies. The EPA also acknowledges that it
received a petition for reconsideration from environmental
organizations that, in relevant part, sought the EPA's reconsideration
of certain aspects of the 2020 Residual Risk Review, which the EPA
continues to review and will respond to in a separate action.\18\
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\17\ The EPA has long considered these two inquiries
independent. See, e.g., Mineral Wool Production and Wool Fiberglass
Manufacturing, 80 FR 45280, 45292 (July 29, 2015) (explaining CAA
section 112(d)(6) and 112(f)(2) ``standards rest on independent
statutory authorities and independent rationales.''); see also Ass'n
of Battery Recyclers, Inc. v. EPA, 716 F.3d 667, 672 (D.C. Cir.
2013) (CAA section 112(d)(6) ``directs EPA to take into account
developments in practices, processes, and control technologies, . .
. not risk reduction achieved by the additional controls.'')
(internal quotation omitted). Indeed, the EPA has strengthened
standards based upon its technology review while finding residual
risks acceptable numerous times. See, e.g., Site Remediation, 85 FR
41680 (July 10, 2020); Organic Liquids Distribution, 85 FR 40740
(July 7, 2020); Ethylene Production, 85 FR 40386 (July 6, 2020);
Pulp Mills, 82 FR 47328 (Oct. 11, 2017); Acrylic and Modacrylic
Fibers Production, 79 FR 60898 (Oct. 8, 2014); Natural Gas
Processing Plants, 77 FR 49400 (Aug. 16, 2012); Wood Furniture
Manufacturing Operations, 76 FR 72052 (Nov. 21, 2011).
\18\ See Docket ID No. EPA-HQ-OAR-2018-0794-4565 at
<a href="http://www.regulations.gov">www.regulations.gov</a>.
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B. Review of the 2020 Technology Review

The EPA's review of the 2020 Technology Review included evaluating
the technology review described in Docket ID No. EPA-HQ-OAR-2018-0794-
0015 and comments related to potential practices, processes, or
controls received as part of the 2022 Proposal. The review also focused
on the identification and evaluation of any developments in practices,
processes, and control technologies that have occurred since
finalization of the MATS rule in 2012 and since publishing the 2020
Technology Review. As explained in detail herein, based on this
information, the EPA now concludes that developments in the costs and
effectiveness of control technologies and the related fact that
emissions performance still varies significantly, warrant revising
certain MACT standards.
Technology reviews can, and often do, include obtaining better
information about the performance of a control technology (e.g.,
emissions data from affected sources) showing that an add-on technology
that was identified and considered during the development of the
original MACT standards works better (e.g., gets more emissions
reductions or costs less) than anticipated. In fact, considering data
on outperforming sources and cost and effectiveness of existing
controls is well established. See, e.g., Coke Oven Batteries, 69 FR
48338, 48351 (August 9, 2014) (``[A]lthough no new control technologies
have been developed since the original standards were promulgated, our
review of emissions data revealed that existing MACT track batteries
can achieve a level of control for door leaks and topside leaks more
stringent than that required by the 1993 national emission standards .
. . through diligent work practices to identify and stop leaks.'');
Site Remediation, 85 FR 41680, 41690 (July 10, 2020) (noting that
commenters had not identified developments like a reduction in costs);
Petroleum

[[Page 24867]]

Refineries, 80 FR 75178, 75201 (December 1, 2015); Mineral Wood
Production and Fiberglass Manufacturing, 80 FR 45280, 45284-85 (July
29, 2015); see also Nat'l Ass'n for Surface Finishing v. EPA, 795 F3d
1, 11-12 (D.C. Cir 2015).
For example, in the 2014 technology review for Ferroalloys
Production, the EPA found that PM emission levels were well below the
MACT standards established in the original 1999 NESHAP. These findings
``demonstrate[d] that the add-on emission control technology (venturi
scrubber, positive pressure FF, negative pressure FF) used to control
emissions from the furnaces are quite effective in reducing PM (used as
a surrogate for metal HAP) and that all of the facilities have
emissions well below the current limits.'' See 79 FR 60271 (October 6,
2014). Therefore, the EPA determined that it was appropriate to revise
the PM limits for furnaces. Similarly, in the 2017 technology review
for Wool Fiberglass Manufacturing, the EPA found that formaldehyde
emissions had decreased by approximately 95 percent since promulgation
of the MACT Standards in the original 1999 NESHAP due to ``(1)
Improvements in control technology (e.g., improved bag materials,
replacement of older baghouses) and (2) the use of electrostatic
precipitators,'' as well as upgraded pollution prevention practices
(i.e., development and use non-phenol-formaldehyde binders). See 82 FR
40975 (August 29, 2017). Although the EPA declined to lower the
formaldehyde limit in this case, it was only because the source
category had already upgraded the technology (i.e., non-phenol-
formaldehyde binders), resulting in major sources becoming area sources
that were no longer subject to the NESHAP.
As in those cases, here many commenters provided data showing that
control technologies are more widely used, more effective, and cheaper
than at the time EPA promulgated MATS. For example, commenters
explained that, due to the many options that are available to control
Hg emissions (e.g., control equipment, activated carbon, reagents and
sorbents, as well as fuel blending, non-carbon or improvements to
carbon-based solvents, wet and dry scrubber additives, oxidizing coal
additives, and existing control optimization) and a ``robust industry
of technology suppliers that drive innovation through internal research
and development,'' the costs of compliance for end users has decreased
over time (Docket ID No. EPA-HQ-OAR-2018-0794-4940). Similarly,
commenters noted that the large number of EGUs that are outperforming
the current Hg and fPM standards would support a decision to revise the
standards (Docket ID No. EPA-HQ-OAR-2018-0794-4962). Specific comments
leading to our proposed decisions are detailed below, and a summary of
this technology review is provided in the memorandum ``2023 Technology
Review for the Coal- and Oil-Fired EGU Source Category,'' which can be
found in Docket ID No. EPA-HQ-OAR-2018-0794. Based on our review of the
2020 Technology Review, the EPA is proposing to revise the current
standards as discussed below.

C. What are the results and proposed decisions based on our technology
review, and what is the rationale for those decisions?

This section summarizes the EPA's changes to the 2020 technology
review and proposed decisions. Where the EPA has identified
developments in practices, processes, or controls, we analyzed the
technical feasibility, estimated costs, energy implications, and non-
air environmental impacts, as well as the potential emission reductions
associated with each development. In addition, we reviewed a variety of
data sources in our investigation of developments in practices,
processes, or controls. See section III of this preamble for
information on the specific data sources that were reviewed as part of
the technology review.
1. Filterable Particulate Matter (fPM) Emission Limit (as a Surrogate
for Non-Hg HAP Metals)
As described in section III of this preamble, EGUs in six
subcategories are subject to numeric emission limits for each of the
individual non-Hg metal HAP. Alternatively, certain affected EGUs can
choose to demonstrate compliance with an alternative total non-Hg metal
HAP emission limit. Finally, affected EGUs can demonstrate compliance
with an alternative fPM emission limit that serves as a surrogate for
total non-Hg metal HAP. The EPA chose fPM as a surrogate for non-Hg
metal HAP in the original MATS rulemaking because non-Hg metal HAP are
predominantly a component of the filterable fraction of total PM (which
is comprised of a filterable fraction and a condensable fraction), and
control of fPM results in co-reduction of non-Hg metal HAP (with the
exception of Se, which may be present in the filterable fraction or in
the condensable fraction as the acid gas, SeO<INF>2</INF>).
Additionally, not all fuels emit the same type and amount of non-Hg
metal HAP, but most generally emit fPM that includes some amount and
combination of all the non-Hg metal HAP. Lastly, the use of fPM as a
surrogate eliminates the cost of performance testing to demonstrate
compliance with numerous standards for individual non-Hg metal HAP
(Docket ID No. EPA-HQ-OAR-2009-0234). For these reasons, the EPA
focused its review on the fPM emissions of coal-fired EGUs as a
surrogate for non-Hg metal HAP.
In the 2020 Technology Review, the EPA did not identify any
developments in practices, processes, or control technologies for non-
Hg metal HAP or fPM. The assessment of implementation and developments
in non-Hg metal HAP metal is summarized in the memorandum, ``Technology
Review for the Coal- and Oil-Fired EGU Source Category,'' which is
included in Docket ID No. EPA-HQ-OAR-2018-0794-0015. The 2020 review
simply presented a list of PM control technologies used by coal-fired
EGUs in operation, finding that the units primarily employ ESPs and
FFs, and did not identify any new control technologies to reduce non-Hg
metal HAP. That review did not consider or discuss the costs or
performance of already-installed controls nor discuss or analyze
opportunities for improved performance. In the 2020 Technology Review,
the EPA concluded that ``[t]he PM air pollution control device
technologies that are currently in use are well-established and provide
the capture efficiencies necessary for compliance with the subpart
UUUUU [MATS] filterable PM limits.'' In the 2022 Proposal, the EPA
solicited information on the cost and performance of new or improved
control technologies that control HAP emissions and improved methods of
operation.
In this review of the RTR, and consistent with some past technology
reviews, the EPA assessed the performance of the sources in the source
category compared to current standards, and the EPA accordingly
expanded upon the 2020 Final Action's technology review to assess the
fPM emission performance of the fleet. This review included evaluating
the control efficiency and costs of common control systems used for fPM
control, primarily ESPs and FFs, detailed in the memorandum (Technical
Memo), ``2023 Technology Review for the Coal- and Oil-Fired EGU Source
Category,'' which is included in Docket ID No. EPA-HQ-OAR-2018-0794. As
part of this effort, the EPA reviewed more recent fPM compliance data
that was not available during the 2020 Final Action. Although

[[Page 24868]]

our review of fPM compliance data for coal-fired EGUs indicated no new
practices, processes, or control technologies for non-Hg metal HAP, it
revealed two important developments that inform the EPA's decision to
propose revisions to the standard. First, it revealed that most
existing coal-fired EGUs are reporting fPM well below the current fPM
emission limit of 3.0E-02 lb/MMBtu. Information we received in response
to the 2022 Proposal similarly noted that the fleet is reporting much
lower fPM rates than what is currently allowed. Second, it revealed
that the fleet is achieving these performance levels at lower costs
than assumed during promulgation of the original MATS fPM emission
limit. More specifically, one commenter presented its fleetwide
evaluation using data from 100 coal units in the PJM Interconnection
and in the Electric Reliability Council of Texas (ERCOT) markets. The
commenter's analysis suggested that only 42 EGUs would require
additional capital or operating costs to meet a more stringent fPM
limit of 7.0E-03 lb/MMBtu, while 79 EGUs would incur those costs to
meet a limit of 3.75E-03 lb/MMBtu. The commenter's analysis suggested
that most units would incur costs in the range of $0/kW to $75/kW
(Docket ID No. EPA-HQ-OAR-2018-0794-5121). Other commenters pointed to
an independent report finding that units are doing ``just enough'' to
satisfy the MATS limits and that EGUs can achieve fPM emission rates at
or below 7.0E-03 lb/MMBtu with relatively low capital cost upgrades to
pollution control systems.\19\ Commenters also cited studies finding
the actual costs of complying with air pollution regulations are often
substantially lower than pre-compliance estimates assumed in the 2012
MATS Final Rule.
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\19\ See <a href="https://www.andovertechnology.com/wp-content/uploads/2021/08/PM-and-Hg-Controls_CAELP_20210819.pdf">https://www.andovertechnology.com/wp-content/uploads/2021/08/PM-and-Hg-Controls_CAELP_20210819.pdf</a>.
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Figure 1 shows that all coal-fired EGUs are reporting fPM emissions
well below the current MATS limit of 3.0E-02 lb/MMBtu, and that 91
percent of EGUs are reporting fPM emissions at levels lower than a
third of the current limit. In fact, the average reported fPM rate of
the EGUs assessed in Figure 1 is 4.8E-03 lb/MMBtu, which is 84 percent
below the MATS current limit (the median is 4.0E-03 lb/MMBtu, or 87
percent below the MATS current limit). The EPA evaluated the fPM
emission performance of EGUs and binned them by quartiles. The average
fPM emission rate reported by the best performing 25 percent was 1.4E-
03 lb/MMBtu. Of the best performing 50 percent of EGUs assessed, the
average fPM emission rate was 2.4E-03 lb/MMBtu and the average fPM rate
reported by the best 75 percent was 3.1E-03 lb/MMBtu. Of the best
performing 95 percent, the average fPM emission rate was 4.2E-03 lb/
MMBtu. Even the higher emitting units, with reported rates above the
current fPM LEE standard, are performing 30 percent to 43 percent below
the current standard. Even so, the handful of the worst performing EGUs
are reporting fPM at rates approximately three to four times the fleet
average.
Because an evaluation of compliance data showed that a significant
portion of coal-fired EGUs are performing well below the allowed
emission limit (Figure 1), and because the EPA obtained information
indicating lower costs to improve controls to achieve additional fPM
emission reductions than assumed during promulgation of the original
MATS fPM emission limit, the EPA concluded that there were developments
that warranted an examination of whether to revise the standard.
To examine potential revisions, the EPA used representative fPM
emissions as a surrogate for total non-Hg metal HAP to evaluate three
more stringent emission limits. The fPM emission limits that were
evaluated are (1) 1.5E-02 lb/MMBtu, which is 50 percent of the current
limit and the qualifying emission rate for the LEE program (2) 1.0E-02
lb/MMBtu, which is comparable to the MATS new source fPM emission
limit; and (3) 6.0E-03 lb/MMBtu, which is the average fPM emission rate
from the 2010 ICR. Currently, 96 percent of existing coal-fired
capacity without known retirement plans before the proposed compliance
period \20\ already have demonstrated an emission rate of 1.5E-02 lb/
MMBtu or lower, 91 percent of existing coal-fired capacity have
demonstrated an emission rate of 1.0E-02 lb/MMBtu or lower, and 72
percent of existing coal-fired capacity have demonstrated an emission
rate of 6.0E-03 lb/MMBtu or lower. As mentioned above, the average fPM
rate of the best performing 95 percent of EGUs was 4.2E-03 lb/MMBtu,
below the most stringent option analyzed of 6.0E-03 lb/MMBtu. The EPA
evaluated reductions of the 10 individual non-Hg metal HAP, total non-
Hg metal HAP, and fPM and the associated costs for each unit to achieve
each of the three fPM emission limits listed above.
---------------------------------------------------------------------------

\20\ If the proposed revised emission limits are finalized,
affected EGUs will have up to 3 years after the effective date of
the rule amendments to demonstrate compliance with the revised
emission limits.
[GRAPHIC] [TIFF OMITTED] TP24AP23.000

[[Page 24869]]

Figure 1--fPM rate distribution for affected coal-fired EGUs in the
continental U.S. in reference to the three considered fPM limit
(horizontal dashed lines): 1.5E-02 lb/MMBtu, 1.0E-02 lb/MMBtu, and
6.0E-03 lb/MMBtu. Percentages represent the amount of existing capacity
achieving each of the limits. More information available in the
Technical Memo supporting this action.

The EPA discussed the opportunity for improved performance of
existing fPM control technologies in the 2012 MATS Final Rule. In the
regulatory impact analysis (RIA) supporting the 2012 MATS Final Rule,
the EPA estimated that 34 gigawatts (GW) of coal-fired EGU capacity
would perform ESP upgrades as part of their fPM emission limit
compliance strategy.\21\ EPA's methodology was based on historic PM
emission rates and reported control efficiencies and is explained in
the IPM 4.10 Supplemental Documentation for MATS.\22\ Depending on the
incremental fPM reduction needed to bring a unit into compliance, units
with existing ESPs for PM control were assigned either a FF retrofit or
one of three tiered ESP upgrades to bring them into compliance. In
response to the solicitation in the 2022 Proposal, commenters provided
detailed information on updated costs for similar upgrades for improved
ESP performance. Using that data and additional information from one of
the EPA's engineering consultants, the EPA evaluated revised costs to
upgrade existing PM controls. The cost effectiveness estimates
presented in this section are based on an assumption that eight units
would need to upgrade existing ESPs to comply with a revised fPM
emission standard of 1.5E-02 lb/MMBtu, that 20 units would need to
implement similar ESP upgrades to comply with a revised fPM emission
standard of 1.0E-02 lb/MMBtu, and that 65 units would need to install a
new FF or modify an existing FF to meet a revised fPM emission limit of
6.0E-03 lb/MMBtu.
---------------------------------------------------------------------------

\21\ Regulatory Impact Analysis for the Final Mercury and Air
Toxics Standards, available <a href="https://www.epa.gov/sites/default/files/2015-11/documents/matsriafinal.pdf">https://www.epa.gov/sites/default/files/2015-11/documents/matsriafinal.pdf</a> and in the rulemaking docket.
\22\ See Table 5-25 in Documentation Supplement for EPA Base
Case v.4.10_MATS--Updates for Final Mercury and Air Toxics Standards
(MATS) Rule available at <a href="https://www.epa.gov/sites/default/files/2015-07/documents/suppdoc410mats.pdf">https://www.epa.gov/sites/default/files/2015-07/documents/suppdoc410mats.pdf</a> and in the rulemaking docket.
---------------------------------------------------------------------------

In this proposal, the EPA proposes to set an fPM emission limit of
1.0E-02 lb/MMBtu (0.010 lb/MMBtu) and seeks comment on whether its
control technology effectiveness and cost assumptions are correct, and
whether it should finalize a more stringent standard. The EPA's
decision to propose a standard of 1.0E-02 lb/MMBtu is based on several
factors. First, this level of control would ensure that the very worst
performers bring their performance level up to where the vast majority
of the fleet is performing. The EPA notes that Figure 1 shows a ``knee
in the curve'' that starts before 1.0E-02 lb/MMBtu, with coal-fired
EGUs above that rate emitting substantially more pollution than those
below it. Bringing this small number of sources (9 percent of coal-
fired EGU capacity) to the performance of the rest of the fleet serves
Congress's mandate to the EPA to continually consider developments and
to ensure that standards account for developments ``that create
opportunities to do even better.'' See LEAN, 955 F.3d at 1093. As
discussed above in section V.B. of this document, the EPA has a number
of times in the past updated its MACT standards to reflect developments
where the majority of sources is vastly outperforming the original MACT
standards.
According to comments received in response to the solicitation in
the 2022 Proposal, since the MATS Final Rule was promulgated in 2012,
improvements to existing PM controls to comply with the MATS fPM
standard were achieved at lower costs than had been projected by the
EPA. The commenter also noted that industry installed far fewer FFs
than the EPA projected and that there were a smaller number of ESP
upgrades than projected. The 2012 MATS Final Rule used the Upper
Predictive Limit (UPL) to establish the fPM emission limit of 3.0E-02
lb/MMBtu for existing coal-fired EGUs. The UPL considers the average of
the best performing EGUs, but also includes an allowance for variation
that is determined by a confidence level that the UPL will not be
exceeded. A report \23\ submitted to the EPA in response to the 2020
Proposal presented an updated UPL (using 2019 data compiled by Natural
Resources Defense Council (NRDC) \24\) of 5.0E-03 lb/MMBtu, about one-
sixth of the EPA's 2011 estimate of 3.0E-02 lb/MMBtu. The updated 5.0E-
03 lb/MMBtu UPL value was attributed to updated fPM rates that were
lower on average and reflected less variability in emissions for each
individual EGU. More specifically, according to the commenter, the
lower fPM emissions and thus lower UPL were attributed to: (1) greater
attention to fPM emissions due to the monitoring and reporting
requirements of MATS; (2) efforts to restore ESPs and other equipment
to original designed performance levels; (3) modest improvements to
ESPs when needed, such as addition of high frequency transformer
rectifier (TR) sets; and (4) efforts to minimize the wear and tear on
filter bags and increased attention to FF operation. Developments in
the technology, including better performance at lower costs, combined
with improved variability assumptions updated since promulgation of the
2012 MATS Final Rule, presents an opportunity to strengthen the MACT
standard for fPM.
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\23\ See <a href="https://www.andovertechnology.com/wp-content/uploads/2021/08/PM-and-Hg-Controls_CAELP_20210819.pdf">https://www.andovertechnology.com/wp-content/uploads/2021/08/PM-and-Hg-Controls_CAELP_20210819.pdf</a>.
\24\ <a href="https://www.nrdc.org/resources/coal-fired-power-plant-hazardous-air-pollution-emissions-and-pollution-control-data">https://www.nrdc.org/resources/coal-fired-power-plant-hazardous-air-pollution-emissions-and-pollution-control-data</a>.
---------------------------------------------------------------------------

Second, the EPA believes that a fPM emission limit of 1.0E-02 lb/
MMBtu appropriately takes into account the costs of control. The EPA
evaluated the costs to improve current PM control systems and the cost
to install better performing PM controls (i.e., a new FF) to achieve a
more stringent emission limit. As noted above, data received since 2012
demonstrates that the costs of PM control upgrades are likely much
lower than the EPA estimated in 2012. Table 3 summarizes the estimated
cost-effectiveness of the three emission limits evaluated for the
existing fleet. For the purpose of estimating cost-effectiveness, the
analysis presented in this table is based on the observed emissions
rates of all existing coal-fired EGUs except for those that have
announced plans to retire by the end of 2028. Note that, unlike the
cost and benefit projections presented in the RIA for this proposed
rule, the estimates in this table do not account for any future changes
in the composition of the operational coal-fired EGU fleet that are
likely to occur by 2028 as a result of other factors affecting the
power sector, such as the Inflation Reduction Act (IRA), future
regulatory actions, or changes in economic conditions. Of the over 9 GW
of coal-fired capacity that the EPA estimates would require control
improvements to achieve the proposed fPM rate, less than 5 GW is
projected to be operational in 2028 (see section 3 of the RIA for this
proposal).

[[Page 24870]]

Table 3--Summary of Cost Effectiveness Analysis for Three Potential fPM Emission Limits \1\
----------------------------------------------------------------------------------------------------------------
Potential fPM emission limit (lb/MMBtu)
-----------------------------------------------
1.5E-02 1.0E-02 6.0E-03
----------------------------------------------------------------------------------------------------------------
Affected Units (Capacity, GW)................................... 8 (4.02) 20 (9.34) 65 (32.9)
Annual Cost ($M)................................................ 13.9-19.3 77.3-93.2 633
fPM Reductions (tons/year)...................................... 463 2,074 6,163
Total non-Hg metal HAP Reductions (tons/year)................... 1.41 6.34 24.7
Total non-Hg metal HAP Cost Effectiveness ($k/ton).............. 9,860-13,700 12,200-14,700 25,600
Total non-Hg metal HAP Cost Effectiveness--Allowable ($k/ton)... 35.4-49.1 197-238 1,610
----------------------------------------------------------------------------------------------------------------
\1\ Note that these values represent annual cost and projected emission reductions assuming the affected coal-
fired EGUs operate consistent with their operation in their lowest quarter (see Technical Memo accompanying
this action for more information).

The cost estimates presented in this table could be overestimated
for a number of reasons, and the EPA seeks comment on these cost and
cost-effectiveness estimates and how they may change over time.
Additionally, the information in Table 3 shows that coal-fired EGUs
have demonstrated an ability to meet these limits with existing control
technology. It is possible that some EGUs with the same or similar
technologies may be able to achieve a lower fPM rate at significantly
lower cost than assumed here, and possibly without any additional
capital investments. Furthermore, since the EGU-specific fPM emissions
rate is calculated using the largest 1 percent of fPM rates for the
quarter with the lowest emissions, some EGUs may readily achieve lower
fPM rates with improved operation. While such factors could likely
lower the overall cost estimates and improve cost-effectiveness, this
table presents estimates based on the best information available to the
EPA at this time.
The EPA considers costs in various ways, depending on the rule and
affected sector. For example, the EPA has considered, in previous CAA
section 112 rulemakings, cost-effectiveness, the total capital costs of
proposed measures, annual costs, and costs compared to total revenues
(e.g., cost to revenue ratios).\25\ Because much of the fleet is
already reporting fPM rates below 6.0E-03 lb/MMBtu, both the total
costs and the total fPM and non-Hg metal HAP reductions for the three
potential emission limits are modest in the context of the total
control costs and emissions of the coal fleet. The cost-effectiveness
estimates for EGUs reporting fPM rates above 6.0E-03 lb/MMBtu to
achieve similar performance as the rest of the fleet range from
$9,860,000 to $25,600,000 per ton of non-Hg metal HAP for the three
potential emission limits.
---------------------------------------------------------------------------

\25\ See, e.g., Mercury Cell Chlor-Alkali Plants Residual, 87 FR
27002, 27008 (May 6, 2022) (considered annual costs and average
capital costs per facility in technology review and beyond-the-floor
analysis); Primary Copper Smelting, 87 FR 1616, 1635 (proposed Jan.
11, 2022) (considered total annual costs and capital costs, annual
costs, and costs compared to total revenues in proposed beyond-the-
floor analysis); Phosphoric Acid Manufacturing and Phosphate
Fertilizer Production Phosphate Fertilizer Production Plants and
Phosphoric Acid Manufacturing Plants, 80 FR 50386, 50398 (Aug. 19,
2015) (considered total annual costs and capital costs compliance
costs and annualized costs for technology review and beyond the
floor analysis); Ferroalloys Production, 80 FR 37366, 37381 (June
30, 2015) (considered total annual costs and capital costs, annual
costs, and costs compared to total revenues in technology review);
Off-site Waste Recovery, 80 FR 14251, 14254 (March 18, 2015)
(considered total annual costs and capital costs, and average annual
costs and capital costs and annualized costs per facility in
technology review); Chromium Electroplating, 77 FR 58225, 58226
(Sept. 19, 2012) (considered total annual costs and capital costs in
technology review); Oil and Natural Gas, 77 FR 49490, 49523 (Aug.
16, 2012) (considered total capital costs and annualized costs and
capital costs in technology review). C.f. NRDC v. EPA, 749 F.3d
1055, 1060 (D.C. Cir. 2014 . . .
---------------------------------------------------------------------------

For this proposal, the costs--either the annual control cost
estimates presented above in Table 3 or the projected total annual
system-wide compliance costs presented in Table 3-4 in the RIA--
represent a very small fraction of typical capital and total
expenditures for the power sector. In the 2022 Proposal (reaffirming
the appropriate and necessary finding), the EPA evaluated the
compliance costs that were projected in the 2012 MATS rule relative to
the typical annual revenues, capital expenditures, and total (capital
and production) expenditures.\26\ (January 11, 2022); 80 FR 37381 (June
30, 2015). Using electricity sales data from the U.S. EIA, the analysis
in the 2022 Proposal demonstrated that revenues from retail electricity
sales increased from $276.2 billion in 2000 to a peak of $356.6 billion
in 2008 (an increase of about 29 percent during this period) and have
slowly declined since to a post-2011 low of $331.0 billion in 2019 (a
decrease of about 7 percent from its peak during this period) in 2007
dollars. The annual control cost estimates for this proposal based on
the cost-effectiveness analysis in Table 3 constitute at most about 0.2
percent of sector sales at their lowest over the 2000 to 2019 period.
Making similar comparisons of the estimated capital and total
compliance costs to historical trends in sector-level capital and
production costs, respectively, would yield similarly small values.
Because this cost-effectiveness evaluation only considers improved fPM
control needed at a few units and not the entire fleet, we also
evaluated an alternative cost-effectiveness approach that considers
allowable emissions, assuming emission reductions achieved if all
evaluated EGUs emit the maximum allowable amount of fPM (i.e., at the
current standard of 3.0E-02 lb/MMBtu), and the associated costs for
EGUs to comply with the three potential fPM standards. Using this
approach, the EPA estimates the cost-effectiveness (based on allowable
rather than actual emissions) of control of non-Hg HAP metals to range
from $35,400/ton to $49,100/ton for a 1.5E-02 lb/MMBtu emission limit,
from $197,000/ton to $238,000/ton for a 1.0E-02 lb/MMBtu emission
limit, and $1,610,000/ton for a 6.0E-03 lb/MMBtu emission limit.
---------------------------------------------------------------------------

\26\ See Cost TSD for 2022 Proposal at Docket ID No. EPA-HQ-OAR-
2018-0794-4620 at regulations.gov.
---------------------------------------------------------------------------

The EPA strives to minimize the uncertainty and the costs
associated with the measurements used to demonstrate compliance with
emission limits. For fPM measurements, the EPA believes that
appropriate approaches to minimizing both uncertainty and costs would
include limiting sampling times to 3 hours per run and maintaining the
random error contribution to the tolerance given to PM CEMS--which is
one component of uncertainty--consistent with that of existing fPM
emission limits. The impact of sampling times and random errors on
measurable emission limits is described in the ``PM CEMS Random Error
Contribution by Emission Limit'' memorandum, available in the
rulemaking docket. The

[[Page 24871]]

EPA believes that available PM CEMS will be able to accurately measure
the proposed fPM emission limit of 1.0E-02 lb/MMBtu, as the average
random error contribution is under that of existing emission limits.
Although sources have reported fPM values as low as 2.0E-04 lb/MMBtu,
given the 3-hour sampling duration and the current fPM detection limit,
the EPA currently believes, as described in the memorandum, that some
PM CEMS may struggle to meet the EPA's guideline for average random
error contribution to the PM CEMS tolerance to demonstrate compliance
with a fPM emission limit of 6.0E-03 lb/MMBtu or lower. The EPA
solicits comment on the implications for the costs of measuring
emissions to demonstrate compliance--whether through stack testing or
PM CEMS--of alternate emission limits set at or below 6.0E-03 lb/MMBtu
as compared to the proposed fPM emission limit of 1.0E-02 lb/MMBtu,
including run durations, fPM detection levels, and random error
calculations.
The EPA seeks comment broadly on how we should consider costs in
the context of this rule. Taking all of the foregoing discussion into
account, the EPA believes that the middle option, a limit of 1.0E-02
lb/MMBtu best balances the critical importance of reducing hazardous
emissions pursuant to the EPA's statutory obligations under CAA section
112(d)(6) and ensuring that the worst performers are required to
perform at the level of the remainder of the fleet with the costs of
doing so in the context of this industry. Considering all the cost
metrics, the EPA believes that the cost of the proposed standards is
reasonable, and modest in the context of this industry. Based on the
foregoing discussion and these analyses, the EPA is proposing to revise
the fPM emission limit, as a surrogate for the total non-Hg metal HAP,
to 1.0E-02 lb/MMBtu as supported by our analyses of technical
feasibility, control costs, cost-effectiveness, and economics. The EPA
believes this standard appropriately balances CAA section 112's
direction to achieve the maximum degree of emissions reductions while
taking into account the statutory factors, including cost. The EPA is
further seeking comment on whether a standard of 6.0E-03 lb/MMBtu or
lower (for example 2.4E-03 lb/MMBtu, which is the average emission of
the best performing 50 percent of units evaluated) would represent a
better balancing of the statutory factors.
Indeed, Congress designed CAA section 112 to achieve significant
reductions in HAP emissions, which it recognized are particularly
harmful pollutants. This proposal is consistent with the EPA's
authority pursuant to CAA section 112(d)(6) to take developments in
practices, processes, and control technologies into account to
determine if more stringent standards are achievable than those
initially set by the EPA in establishing MACT floors, based on
developments that occurred in the interim. See LEAN v. EPA, 955 F.3d
1088, 1097-98 (D.C. Cir. 2020). As discussed above in this section, the
EPA finds that the vast majority of existing coal-fired EGUs are
performing well below the 2012 MATS fPM emission requirements, and that
they are achieving these levels at lower costs than the EPA assumed in
the 2012 rulemaking. While this proposal in no way refutes that the
EPA's initial MACT standards were set at correct levels based on the
available information at the time, consistent with CAA section 112's
statutory scheme requiring the EPA to regularly revisit those
standards, the EPA now proposes to find that more stringent standards
are achievable, as chiefly evidenced by the large majority of
facilities that are reporting fPM at emission rates well below the
current standard.
This proposed emission limit is comparable to the new source
standard for fPM in MATS. This proposed emission limit is estimated to
reduce non-Hg metal HAP by 6.34 tons per year (and fPM emissions by
2,074 tons/year) at annual costs between $77.3 and $93.2 million. While
the 2020 Residual Risk Review concluded that the residual risks are at
an acceptable level, Congress required the EPA to conduct technology
reviews on an ongoing basis, at least every 8 years, independent of the
residual risk review.\27\ Moreover, Congress required the EPA to set
the standards at the maximum degree of emissions reductions (including
prohibition on emissions) that is achievable taking into account the
statutory factors. The technological standard approach of CAA section
112 is based on the premise that, to the extent there are controls
available to reduce HAP emissions, sources should be required to use
them. Since 91 percent of the anticipated capacity of the fleet is
already achieving a limit below 1.0E-02 lb/MMBtu, the EPA proposes that
this emissions limit level is technologically feasible and demonstrated
for a range of control configurations. Additionally, this revised limit
would result in significantly lower allowable fPM emissions from the
source category compared to the level of emissions allowed by the 2012
MATS Final Rule and help prevent any emissions increases. The EPA does
not anticipate any significant non-air health, environmental, or energy
impacts as a result of these proposed amendments. Our assessment of
control options, costs, and emission reductions is summarized in the
memorandum ``2023 Technology Review for the Coal- and Oil-Fired EGU
Source Category'' in Docket ID No. EPA-HQ-OAR-2018-0794.
---------------------------------------------------------------------------

\27\ See discussion in section V.A, above.
---------------------------------------------------------------------------

The EPA is not proposing the highest limit examined (1.5E-02 lb/
MMBtu) because it would largely leave in place the status quo, in
which, despite the proven feasibility and effectiveness of control
technologies, a number of sources are lagging far behind. The EPA does
not consider a proposed revision to this standard to be consistent with
its statutory charge.
While the EPA is not proposing the most stringent limit examined
(6.0E-03 lb/MMBtu) or an even more stringent limit, the EPA is taking
comment on whether it should consider finalizing such a standard. Such
a standard would achieve far more emissions reductions than the
emission standards that the EPA is proposing in this action. It would
also ensure that the bottom lowest performing quarter of the fleet
would have to improve their performance to the level already
demonstrated by the remaining three-quarters of the fleet. The EPA
declines to propose 6.0E-03 lb/MMBtu as the primary policy option here
in light of the above presentation of potential costs, including the
EPA's current assessment of measurement uncertainty, when considering
the current fleet. These cost estimates are based on the assumption
that existing ESP-controlled units would need to install a new FF in
order to meet the lower limit, or if existing FF-controlled units do
not meet the more stringent limit, those units would need to upgrade
their FF bags. If these assumptions are unnecessarily conservative, the
total costs and associated cost-effectiveness values may be
considerably lower than estimated. The EPA seeks comment on whether
there are lower cost compliance options for units with existing ESPs.
An additional factor affecting the total estimated compliance cost
is the size and composition of the generating fleet. As noted above,
the cost estimates in Table 3 do not account for market and policy
developments that are likely to further change the universe of
regulated sources and reduce the expected costs of meeting more
protective fPM standards. In the likely case that the power sector's
transition to lower-emitting generation

[[Page 24872]]

is accelerated by the IRA, for example, the total costs and emissions
reductions achieved by each of the three alternative fPM standards
shown in Table 3 would also be an overestimate, and the EPA's judgment
could change about which standard most appropriately balances CAA
section 112's direction to achieve the maximum degree of emissions
reductions while taking into account cost and other the statutory
factors. The EPA seeks comment on how the IRA and other market and
policy developments should inform the Agency's determination.
Additionally, the EPA notes that other future state and federal
policies could affect the size, composition, and fPM emissions rate of
the future coal-fired EGU fleet. The EPA seeks comment on the extent to
which, and how, to take these future policies into account when
considering the total cost and cost effectiveness of a more stringent
fPM emission limit.
The EPA requests public comment on all aspects of this proposed
rule, including our evaluation of the costs and efficacy of control
option assumptions. Among other issues, the EPA requests comment on
whether we have accurately assessed the variability of fPM emissions
and requests information on the costs, pollution reduction benefits,
and cost-effectiveness of applying lower emission limits to sources
subject to MATS; and whether there are other factors the EPA should
consider that would support a lower emission limit, including the
contribution that HAP from these sources make to the overall pollution
burden. The EPA seeks comment on requiring existing coal-fired EGUs to
meet a fPM standard of 6.0E-03 lb/MMBtu or a more stringent standard
considering the higher emission reductions as well as the larger total
costs such a standard would entail to inform our consideration of
whether the more stringent standard would reduce the overall pollution
burden in these communities. The EPA also seeks comment on whether
there are any areas where EPA has overestimated costs, including some
of the generation and storage technologies discussed above as well as
the cost of PM controls themselves.
2. PM Emission Monitoring
Under the current rule, EGU owners or operators may choose among
quarterly testing, PM CEMS, and PM CPMS to demonstrate compliance with
the alternate fPM emission limit in MATS. The initial MATS ICR,
available at <a href="http://www.reginfo.gov">www.reginfo.gov</a>,\28\ anticipated that all EGU owners or
operators would use PM CEMS for compliance purposes and estimated
Equivalent Uniform Annual Cost (EUAC) for the beta gauge PM CEMS to be
$65,388. As mentioned in the 2012 proposed Portland Cement NESHAP,\29\
beta gauge technology, also referred to as beta attenuation, allows PM
CEMS to be much less sensitive to changes in particle characteristics
than light-based PM CEMS technologies such as light-scatter or
scintillation. Beta attenuation PM CEMS extracts a sample from the
stack gas and collects the fPM on filter tape. The device periodically
advances the tape from the sampling mode to an area where the sample is
exposed to beta radiation. The detector measures the amount of beta
radiation emitted by the sample and that amount can be directly related
to the mass of the filter. The unannualized purchase cost for a beta
gauge PM CEMS and its installation were estimated to be $115,267 in the
initial MATS ICR; and the EUAC for beta gauge PM CEMS was estimated to
be less expensive than quarterly EPA Method 5 (M5) testing for fPM.
Even so, not all EGU owners or operators chose the most cost-effective
means of demonstrating compliance with the fPM emission limits. Review
of reports submitted to WebFIRE and ongoing ICR renewals shows PM CEMS
are used for compliance purposes by about one-third of EGU owners or
operators. In addition to being more cost-effective for compliance
purposes, PM CEMS provide regulators and the public, as well as the EGU
owners or operators, direct and continuous measurement of the pollutant
of concern. Such data supply real-time, quality-assured feedback that
can lead to improved control device and power plant operation, which,
in turn, can lead to fPM emission reductions. Moreover, quick detection
of potential problems with PM emissions as provided by PM CEMS, coupled
with appropriate corrective measures, can prevent instances of non-
compliance, which otherwise could go undetected and uncorrected until
the next quarterly PM test. This quicker identification and correction
of high emitting EGUs will lead to less pollution emitted and lower
pollutant exposure for local communities. In addition to significant
value of more efficient pollution abatement, transparency of EGU
emissions as provided by PM CEMS, along with real-time assurance of
compliance has intrinsic value to the public and communities as well as
instrumental value in holding sources accountable.
---------------------------------------------------------------------------

\28\ See the supporting statement 2137ss06.docx in ICR reference
number 201202-2060-005 at OMB Control Number 2060-0567.
\29\ See 77 FR 42375, July 18, 2012.
---------------------------------------------------------------------------

Since promulgation of MATS, two important developments in the PM
CEMS industry have occurred, which the EPA identified as part of this
technology review: cessation of beta gauge PM CEMS manufacturing and
reduced overall costs for non-beta gauge PM CEMS instruments and
installation. These two occurrences have reduced the current one-time
costs for PM CEMS, making their use even more cost-effective. As shown
in Table 4 below, average non-beta gauge instrument and installation
costs obtained from representatives of the Institute of Clean Air
Companies (ICAC), a trade association consisting of air pollution
control and measurement and monitoring system manufacturers and of
environmental equipment and service providers, and from Envea/Altech, a
PM CEMS manufacturer and vendor, show about a 48 percent reduction
(from $109,420 to $57,095) from average comparable costs determined
from the EPA's CEMS Cost Model and Monitoring Cost/Benefit Analysis
Tool (MCAT).

Table 4--Non-Beta Gauge PM CEMS Cost Estimates Using M5I for PS 11
--------------------------------------------------------------------------------------------------------------------------------------------------------
One time costs, $ Annual costs, $
------------------------------------------------------------------------------------------
Data source PM CEMS type Instrument and Other initial Capital Operation and Other annual EUAC, $
installation costs recovery maintenance Audits costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA MCAT...................... In situ.......... 119,295 81,220 22,016 1,558 54,877 11,219 89,670
Extractive....... 152,850 81,220 25,700 2,579 54,877 12,241 95,397
EPA CEMS Cost Model........... In situ.......... 65,107 79,813 15,912 2,689 54,392 6,525 79,518

[[Page 24873]]

Extractive....... 100,427 84,458 20,300 3,689 54,392 7,525 85,906
------------------------------------------------------------------------------------------------------
Average................... ................. 109,420 81,678 20,982 2,629 54,635 9,378 87,623
--------------------------------------------------------------------------------------------------------------------------------------------------------
ICAC.......................... Low.............. 35,000 .............. 3,843 12,000 14,290 .............. 30,133
High............. 40,000 .............. 4,392 12,000 14,290 .............. 30,682
Envea/Altech.................. Dry.............. 34,743 .............. 3,821 .............. 14,290 .............. 18,111
Wet.............. 118,585 .............. 13,020 .............. 14,290 .............. 27,310
------------------------------------------------------------------------------------------------------
Average................... ................. 57,095 .............. 6,269 12,000 14,290 .............. 32,559
--------------------------------------------------------------------------------------------------------------------------------------------------------

Generally, EPA models include other initial costs associated with
PM CEMS installation, including those associated with planning,
selecting equipment, and conducting correlation testing, in its models;
such one-time costs are annualized along with instrument and
installation costs. The proposed lower fPM emission limit will require
longer duration runs for M5 testing and may require the use of M5I,
which was designed for PM CEMS correlation testing at low fPM levels.
Initial costs in Table 4 for M5I emission testing are $58,000; such
testing includes 18 runs of 3-hour duration spread over 9 total days.
PM CEMS correlation testing for the proposed lower fPM levels using M5
is estimated to be $41,000. Of course, the quarterly testing run
durations would need to increase if PM CEMS were not used; annual cost
for M5 testing with 3 hour run duration is estimated to be $85,127
($82,000 for testing, and $3,127 for 24 hours of site technical
support); quarterly testing using M5I with runs of similar duration is
estimated to be $107,127. However, neither ICAC nor Envea/Altech
explicitly included those costs as line items in their estimates. This
does not necessarily mean that such costs have been excluded; if such
costs have been included, then the estimates do not change, but if such
costs have not been included, the estimates may increase. Their average
capital recovery cost, determined from the sum of the instrument,
installation, and other initial costs amortized over 15 years at a 7
percent interest rate, is about 70 percent lower than that obtained
from the average capital recovery cost obtained from the EPA models. As
shown in the table, EPA models also include annual costs for operation
and maintenance, relative response and correlation audits, and other
items such as reporting and recordkeeping. The sum of those items plus
the capital recovery cost yields EUAC of PM CEMS. ICAC includes
operation and maintenance as a line item in its annual costs, but
neither ICAC nor Envea/Altech include audits or other items in their
annual costs estimates. Because EPA believes some EGUs may require PM
spiking--an approach that involves introducing known amounts of fPM to
increase fPM concentration without altering control device equipment--
the EPA added $14,290 (the annualized cost of conducting $35,000 p.m.
spiking every 3 years at an interest rate of 7 percent) to the audit
portion of all entries. As mentioned earlier, omission of specifically
named costs does not necessarily mean that those costs have been
excluded; rather these costs may be included in other listed costs.
Using the data provided and explained above, the average EUAC for PM
CEMS that rely on M5I correlation testing is about 63 percent lower
than the average EUAC from EPA models (from $87,623 to $32,559). Given
that the annual cost of quarterly M5 testing for fPM is now estimated
to be $85,127, annualized other one-time costs and operation and
maintenance, audits, and other annualized costs--if omitted by the
manufacturers--would have to be more than $52,568 for PM CEMS to be
less cost-effective than quarterly testing.
As mentioned in the proposed Portland Cement NESHAP from 10 years
ago (see 77 FR 42374, July 18, 2012), the EPA was aware of the
potential difficulty use of PM CEMS might have created in determining
compliance for that rulemaking due to the low end of emission limits
(0.04 lb/ton clinker, which translates to a range of about 5 to 8 mg/
dscm, depending on particle characteristics) and to the short duration
of emission test runs. The EPA addressed those concerns for that
rulemaking by proposing to raise the emission limit to 0.07 lb/ton
clinker, which translated to a range of about 7 to 14 mg/dscm, and to
no longer require PM CEMS use; instead, owners or operators would use
their PM CEMS as PM CPMS. Even so, the durations of test runs used to
develop the correlation of the instrument with the emissions limit
remained unchanged, at about 1 hour per run. Such short run durations
led to inherent measurement uncertainty accounting for more than half
the emission limit at the expected portland cement plant operating
condition, leading some to question whether values provided by
instrumentation were appropriately related to emissions.
The conditions experienced by portland cement facilities that
required revisions to emission limits and compliance determination
method are not similar to those expected to be faced by EGU owners or
operators subject to MATS. First, the fuel used by coal-fired EGUs is
more uniform and its characteristics are more consistent than those of
the fuel and additive mixtures used by portland cement kilns. Such fuel
combustion particle consistency allows technologies such as light
scattering and scintillation, in addition to beta gauges, to be used by
PM CEMS for compliance determination purposes. Moreover, consistent fPM
particle characteristics for EGUs provide stable correlations for those
EGUs with existing PM CEMS; while the fPM particle characteristics
provide correlations that remain within specifications, as evidenced by
ongoing relative correlation audits, the existing correlations do not
change and can continue to be used now and in the future without having
to develop a new correlation. Second, the proposed MATS emission limit
of 1.0E-02 lb/MMBtu, which translates to about 7.3 mg/dscm, coupled
with a minimum sampling collection time of 3 hours per run, based on a
typical sampling rate of \3/4\ cubic feet per minute, avoids the
measurement problems described by the Portland Cement NESHAP by
reducing the average inherent measurement uncertainty for half of the
proposed emission limit (where the EGU is expected to operate) from
more than 50 to 80 percent. In addition, use of 3 hour

[[Page 24874]]

run durations would allow for a 6.0E-03 lb/MMBtu (or about 4.4 mg/dscm)
MATS emission limit, which the EPA is seeking comment on, to have an
average inherent measurement uncertainty due to random error of 14
percent at the target PM CEMS operational limit of 3.0E-03 lb/MMBtu. As
shown, inherent measurement uncertainty does not appear to be
problematic for the primary proposed emission limit, but, as mentioned
earlier, some PM CEMS may have difficulty meeting the inherent
measurement uncertainty--specifically, the average random error
component--of the alternative proposed emission limit. Note that the
primary proposed MATS emission limit is just above the fPM limit for
new EGUs, as 9.0E-02 lb/MWh on an electrical output basis translates to
about 9.0E-03 lb/MMBtu on a heat input basis. MATS requires use of PM
CEMS for new EGUs, along with minimum sampling collection time of 3
hours per run.\30\ Proposed use of runs of at least 3 hour durations
and emission limits of 1.0E-02 lb/MMBtu would be consistent with run
durations and limits already in MATS. Third, Performance Specification
11 (PS 11), which provides procedures and acceptance criteria for
validating PM CEMS technologies, already anticipates and includes
approaches for developing low-level emission correlations for PM CEMS.
Those techniques include varying process operations; varying fPM
control device conditions; PM spiking zero point methods when the
previous techniques are not able to provide the 3 distinct fPM
concentration levels. As mentioned earlier, average costs for fPM
spiking are about $35,000 every 3 years, or $14,290 annually at an
interest rate of 7 percent, and not every EGU will need to adjust its
existing correlation in order to continue to use its existing PM CEMS
to demonstrate compliance with the proposed limits; however, for
purposes of this proposal, costs for spiking will be included in annual
PM CEMS cost estimates. In addition to these techniques to aid PM CEMS
use for rules with low level emissions, the EPA is aware that the
Electric Power Research Institute (EPRI) began working with an
instrument manufacturer in 2009, prior to MATS promulgation, to develop
a National Institute of Standards and Technology (NIST) traceable
aerosol generator that injects known particle size distribution and
mass into PM CEMS. Such an instrument, known as a Quantitative Aerosol
Generator (QAG), would allow direct PM CEMS calibration, as opposed to
the development of a curve that provides a correlation for the PM
CEMS.\31\ That study relied on six emission rates, four of which were
at or under 5 mg/dscm, and reported successful sample collection and
transport. EPRI continued this work and provided a technical update in
2014,\32\ but the EPA is unaware of specific recommendations or
suggestions regarding QAG application to PM CEMS. While we believe the
use of the QAG could lower fPM monitoring costs for PM CEMS use, we
seek more information on its application for lower fPM limits as
measured by PM CEMS; specifically, we solicit comment on whether
implementation of the QAG is another reason that PM CEMS costs have
decreased.
---------------------------------------------------------------------------

\30\ See Table 1 to subpart UUUUU of 40 CFR part 63. At a
typical sampling rate of \3/4\ cubic foot per minute, a run would
require 3 hours to collect at least 4 cubic meters of sample.
\31\ See A Qualitative Aerosol Generator Designed for
Particulate Matter (PM) Continuous Emissions Monitoring Systems
(CEMS) Calibration, available at <a href="http://www.epri.com/research/products/1017574">www.epri.com/research/products/1017574</a>.
\32\ See Quantitative Aerosol Generator (QAG) for Calibration of
Particulate Monitors: 2014 Technical Update, available at
<a href="http://www.epri.com/research/products/3002003343">www.epri.com/research/products/3002003343</a>.
---------------------------------------------------------------------------

For these reasons, we propose to require the use of PM CEMS as the
method to demonstrate compliance with the fPM emissions limit for coal-
fired and IGCC EGUs pursuant to the EPA's authority under CAA section
112(d)(6). If our proposal is finalized, EGU owners or operators
currently relying on quarterly PM emissions testing would need to
install, operate, and maintain PM CEMS. Such a switch is projected to
be more cost-effective, more informative, and more effective in
assuring compliance than use of quarterly testing. Those EGU owners or
operators already using PM CEMS as their means of compliance
determination would maintain their current approach; while some may
have no need for additional expenditures, the proposal includes the
costs associated with revised and ongoing correlation testing and
spiking for all EGUs. Since a proposed requirement for use of PM CEMS
renders the current compliance option for the LEE program superfluous,
the EPA proposes to remove the individual and total non-Hg metal HAP
and the surrogate fPM from the LEE program for all MATS-affected EGUs
and solicits comments on removing these limits.
The EPA seeks comment on distinctions between portland cement
plants and EGUs that would facilitate PM CEMS use at EGUs.
Specifically, the EPA seeks comment on the ability, type, and
capabilities of PM CEMS to accurately measure fPM emissions at the
levels proposed in this rule. Moreover, the EPA seeks comment on
additional or other approaches that could be employed to facilitate PM
CEMS use for the proposed emission levels. Specific comments on direct
PM CEMS calibration methods, such as the QAG, as well as limitations,
are welcome.
The EPA solicits comment on the availability of beta gauge
instruments, on the current average costs of non-beta gauge PM CEMS
instruments and installation, on ICAC's annual costs, and on Envea/
Altech's annual costs. When commenting on EPA model estimates or ICAC's
or Envea/Altech's estimates, please provide specific PM CEMS instrument
type, manufacturer, and model; cost information broken down by initial
cost including instrument type and installation cost, and annual cost,
including operation and maintenance, audit, and other costs in your
comments. Moreover, please identify in your comments specific items
included in your cost information, such as installation, operation, and
maintenance provisions. The EPA also solicits comment on the cost-
effectiveness of PM CEMS as compared to quarterly PM emissions testing.
Also, the EPA solicits comment on the availability of PM CEMS and their
use for compliance purposes, especially when compared to less frequent,
more expensive measures.
The EPA is aware that some EGUs may be on enforceable schedules to
cease operations, which may be just beyond the three-year compliance
date the EPA proposes for PM CEMS monitoring requirements in section
V.E, below, and that owners or operators of EGUs may be unable to
recoup investments in PM CEMS if the instruments are not in operation
for at least a certain period of time beyond their installation date.
Therefore, the EPA seeks comment on whether EGUs should be able to
continue to use quarterly emissions testing past the proposed
compliance date for a certain period of time or until EGU retirement,
whichever occurs first, provided the EGU is on an enforceable schedule
for ceasing coal- or oil-fired operation. In addition, the EPA seeks
comment on what would qualify as an enforceable schedule, such as that
contained in the Agency's ``EGUs Permanently Ceasing Coal Combustion by
2028'' included in the 2020 Steam Electric ELG Reconsideration Rule (85
FR 64640, 64679, and 64710; 10/13/2020), as well as what the maximum
duration of operation using quarterly emissions testing for compliance
purposes should be.

[[Page 24875]]

3. Review of the Hg Emission Standards
a. Overview of Hg Emissions From Combustion of Coal
Mercury is a naturally occurring element found in small and varying
quantities in coal. During combustion of coal, Hg is volatilized and
converted to elemental Hg vapor (Hg\0\) in the high temperature regions
of the boiler. Hg\0\ vapor is difficult to capture because it is
typically nonreactive and insoluble in aqueous solutions. However,
under certain conditions, the Hg\0\ vapor in the flue gas can be
oxidized to divalent Hg (Hg\2+\). The Hg\2+\ can bind to the surface of
solid particles (e.g., fly ash) in the flue gas stream, often referred
to as ``particulate bound Hg'' (Hg<INF>p</INF>), and be removed in a
downstream PM control device. Oxidized Hg compounds can also be soluble
and can be removed in a wet scrubber. The presence of chlorine in gas-
phase equilibrium favors the formation of mercuric chloride
(HgCl<INF>2</INF>) at flue gas cleaning temperatures. However, Hg\0\
oxidation reactions are kinetically limited as the flue gas cools and,
as a result, Hg often enters the flue gas cleaning device(s) as a
mixture of Hg\0\, Hg\2+\ compounds, and Hg<INF>p</INF>. This
partitioning into various species of Hg has considerable influence on
selection of Hg control approaches. In general, because of the presence
of higher amounts of halogen (especially chlorine) in bituminous coals,
most of the Hg in the flue gas from bituminous coal-fired boilers is in
the form of Hg\2+\ compounds, typically HgCl<INF>2</INF> and is more
easily captured in downstream control equipment. Conversely, both
subbituminous coal and lignite have lower halogen content, compared to
that of bituminous coals, and the Hg in the flue gas from boilers
firing those fuels tends to be in the form of Hg\0\ and is more
challenging to control in downstream control equipment.
Fly ash is typically classified as acidic (pH less than 7.0),
mildly alkaline (pH greater than 7.0 to 9.0), or strongly alkaline (pH
greater than 9.0). The pH of the fly ash is usually determined by the
calcium/sulfur ratio and the amount of halogen. The ash from bituminous
coals tends to be acidic due to the relatively higher sulfur and
halogen content and the glassy (nonreactive) nature of the calcium
present in the ash. Conversely, the ash from subbituminous and lignite
coals tends to be more alkaline due to the lower amounts of sulfur and
halogen and a more alkaline and reactive (non-glassy) form of calcium
in the ash. The natural alkalinity of the subbituminous and lignite fly
ash can effectively neutralize the limited free halogen in the flue gas
and prevent oxidation of the Hg\0\.
Some coal-fired power plants--especially those firing bituminous
coal--achieve some level of Hg emissions control using existing
equipment that was installed to remove other pollutants, including PM,
SO<INF>2</INF>, and nitrogen oxides (NO<INF>X</INF>). Particulate-bound
Hg (Hg<INF>p</INF>) is effectively removed along with PM in PM control
equipment such as FFs and ESPs. Soluble Hg\2+\ compounds (such as
HgCl<INF>2</INF>) can be effectively captured in wet FGD systems. And,
while a selective catalytic reduction (SCR) system that has been
installed for NO<INF>X</INF> control does not itself capture Hg, it can
under the right conditions enhance the oxidation of Hg\0\ in the flue
gas for increased Hg removal in a downstream PM control device or in a
wet FGD scrubber.
However, because the Hg in their flue gas tends to be present in
the non-reactive Hg\0\ phase, EGUs firing subbituminous coal or lignite
often get little to no control from equipment designed and installed
for other pollutants. While some bituminous coal-fired EGUs require use
of additional Hg-specific control technology, such as injection of a
sorbent or chemical additive, to supplement the control that these
units already achieve from criteria pollutant control equipment, these
Hg-specific control technologies are often required as part of the Hg
emission reduction strategy at EGUs that are firing subbituminous coal
or lignite. As mentioned, the Hg in the flue gas for those EGUs tends
to be in the non-reactive Hg\0\ phase due to lack of free halogen to
promote the oxidation reaction. To alleviate this challenge, activated
carbon and other sorbent providers and control technology vendors
developed methods to introduce halogen into the flue gas to improve the
control of Hg emissions from EGUs firing subbituminous coal and
lignite. This was primarily through the injection of pre-halogenated
(often pre-brominated) activated carbon sorbents or through the
injections of halogen-containing chemical additives along with
conventional sorbents. This challenge to controlling Hg emissions was a
challenge for EGUs firing subbituminous coal and for EGUs firing
lignite.
b. Hg Emission Standards in the 2012 MATS Final Rule
In the 2012 MATS Final Rule, the EPA promulgated a beyond-the-floor
standard for Hg for the subcategory of existing coal-fired units
designed for low rank virgin coal (i.e., lignite) based on the use of
ACI for Hg control. See 77 FR 9304, February 16, 2012. The EPA
established a final Hg emission standard of 4.0 pounds of Hg per
trillion British thermal units of heat input (lb Hg/TBtu) for lignite-
fired utility boilers. The EPA promulgated a final Hg emission standard
for EGUs firing non-lignite coals, including bituminous and
subbituminous coal, of 1.2 lb Hg/TBtu.
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. Any basis for
subcategorization must be related to an effect on HAP emissions that is
due to the difference in class, type, or size of the units. See 76 FR
25036-25037.
When developing the MATS rule, the EPA examined available Hg
emissions data from coal-fired EGUs and found that there were no
lignite-fired EGUs among the top performing 12 percent. The EPA then
determined that the difference in the emissions from the lignite-fired
EGUs was due to a difference in the class, type, or size of those units
and finalized two subcategories of coal-fired EGUs for Hg emissions.
See 76 FR 25036-67. The EPA considered basing the subcategory
definition solely on an EGU (1) being designed to burn lignite and (2)
burning lignite. However, the EPA decided not to do so because of the
concern that such a definition would allow sources to potentially meet
the definition by combusting very small amounts of low rank virgin
lignite. In the preamble of the 2012 MATS Final Rule, the EPA suggested
a scenario where an EGU that was not designed to burn lignite and did
not routinely burn lignite could import one truck full of low rank
virgin coal and burn a very small quantity of it periodically to meet
the subcategory definition. To avoid creating this potential loophole,
the EPA also finalized a requirement that the unit be constructed and
operated at or near a mine containing the low rank virgin coal it
burns. The EPA indicated that the final definition would prevent other
EGUs that are not firing lignite from complying with the less stringent
Hg emission standard. The final definition, as specified in the 2012
MATS Final Rule (77 FR 9369, February 16, 2012), was: ``Unit designed
for low rank virgin coal subcategory means any coal-fired EGU that is
designed to burn and that is burning non-agglomerating virgin coal
having a calorific value (moist, mineral matter-free basis) of less
than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and operates at or
near the mine that produces such coal.''

[[Page 24876]]

c. Beyond-the-Floor Analysis for the 2012 MATS Final Rule
For the 2012 MATS Final Rule, the EPA calculated beyond-the-floor
costs for Hg controls by assuming injection of brominated activated
carbon at a rate of 3.0 pounds of sorbent per million actual cubic feet
of flue gas (lb/MMacf) for lignite-fired EGUs with an ESP for PM
control and at an injection rate of 2.0 lb/MMacf for lignite-fired
units with a baghouse (also known as a fabric filter, FF). The sorbent
injection rate of 2.0 lb/MMacf for lignite-fire units with FFs is
consistent with the rate assumed for all other coal types. The EPA
assumed a sorbent injection rate of 3.0 lb/MMacf for lignite-fired
units with ESPs, which is lower than the sorbent injection rate of 5.0
lb/MMacf that the EPA assumed for EGUs firing using other (non-lignite)
coal types. In the Beyond-the-Floor Memo (see Docket ID No. EPA-HQ-OAR-
2009-0234-20130), the EPA indicated that this lower sorbent injection
rate was appropriate, because a higher rate would likely result in Hg
emission reductions greater than those needed to meet the beyond-the-
floor standard of 4.0 lb/TBtu noting that greater than 90 percent
control can be achieved at lignite-fired units at a 2.0 lb/MMacf
injection rate for units with installed FF and using treated (i.e.,
brominated) activated carbon or at an injection rate of 3.0 lb/MMacf
for units using treated activated carbon with installed ESPs.
Petitioners challenged the beyond-the-floor standard for lignite-
fired EGUs, claiming that the final standard is not achievable because
they asserted that the standard would require unrealistically high
levels of Hg reduction. In White Stallion v. EPA, the Court of Appeals
of the District of Columbia Circuit rejected petitioners' challenge to
the final beyond-the-floor standard on the basis that the EPA had
adequately concluded during the rulemaking process that the standard
for lignite units were achievable if sources increased their use of a
particular control technology, ACI. See White Stallion Energy Center,
LLC v. EPA, 748 F.3d 1222, 1251 (D.C. Cir. 2014).
d. Hg Emission Reductions Since Promulgation of the 2012 MATS Final
Rule
The EPA estimated annual Hg emissions from coal-fired power plants
in 2010 (pre-MATS) to be 29 tons.\33\ In 2017, after full
implementation of the MATS rule, the EPA estimated Hg emissions had
been reduced to 4 tons, an 86 percent decrease.\34\ This decline was
due to the installation and use of Hg controls as well as other
significant changes in the power sector (e.g., coal plant retirements,
increase use of natural gas and renewable energy, etc.) in the same
time period.
---------------------------------------------------------------------------

\33\ Memorandum: Emissions Overview: Hazardous Air Pollutants in
Support of the Final Mercury and Air Toxics Standard. EPA-454/R-11-
014. November 2011; Docket ID No. EPA-HQ-OAR-2009-0234-19914.
\34\ 2017 Power Sector Programs Progress Report; available at
<a href="https://www.epa.gov/sites/default/files/2019-12/documents/2017_full_report.pdf">https://www.epa.gov/sites/default/files/2019-12/documents/2017_full_report.pdf</a> and in the rulemaking docket.
---------------------------------------------------------------------------

i. Hg Emissions From Coal-Fired EGUs in 2021
Hg emission reductions have continued to decline since 2017 as more
coal-fired EGUs have retired or reduced utilization. The EPA estimated
that 2021 Hg emissions from coal-fired EGUs were 3 tons (a 90 percent
decrease compared to pre-MATS levels).\35\ However, units burning
lignite coal (or permitted to burn lignite) accounted for a
disproportionate amount of the total Hg emissions in 2021. As shown in
Table 5 below, 16 of the top 20 Hg-emitting EGUs were lignite-fired
EGUs. Overall, lignite-fired EGUs were responsible for almost 30
percent of all Hg emitted from coal-fired EGUs in 2021, while
generating about 7 percent of total 2021 megawatt-hours. Lignite
accounted for 8 percent of total U.S. coal production in 2021.
---------------------------------------------------------------------------

\35\ 2021 Power Sector Programs Progress Report; available at
<a href="https://www3.epa.gov/airmarkets/progress/reports/pdfs/2021_full_report.pdf">https://www3.epa.gov/airmarkets/progress/reports/pdfs/2021_full_report.pdf</a> and in the rulemaking docket.

Table 5--Top Hg-Emitting EGUs in 2021
----------------------------------------------------------------------------------------------------------------
2021 Hg
Rank EGU Fuel emissions (lb) State
----------------------------------------------------------------------------------------------------------------
1.............................. Coal Creek 2........... Lignite............... 181.8 ND
2.............................. Coal Creek 1........... Lignite............... 175.6 ND
3.............................. Oak Grove 2............ Lignite............... 149.8 TX
4.............................. Martin Lake 3.......... Lignite/Subbituminous. 134.4 TX
5.............................. Oak Grove 1............ Lignite............... 112.7 TX
6.............................. Martin Lake 2.......... Lignite/Subbituminous. 111.0 TX
7.............................. Milton R Young B2...... Lignite............... 103.1 ND
8.............................. Martin Lake 1.......... Lignite/Subbituminous. 100.7 TX
9.............................. Antelope Valley B2..... Lignite............... 89.8 ND
10............................. Coyote B1.............. Lignite............... 79.9 ND
11............................. H W Pirkey Power Plant Lignite/Subbituminous. 71.1 TX
1 *.
12............................. Antelope Valley B1..... Lignite............... 69.6 ND
13............................. San Miguel SM-1........ Lignite............... 64.6 TX
14............................. Sandy Creek Energy Subbituminous......... 53.5 TX
Station S01.
15............................. Limestone LIM2......... Lignite/Subbituminous. 52.5 TX
16............................. Milton R Young B1...... Lignite............... 52.4 ND
17............................. Comanche 3............. Subbituminous......... 50.3 CO
18............................. Leland Olds 2.......... Lignite............... 50.1 ND
19............................. James H Miller Jr 3.... Subbituminous......... 42.9 AL
20............................. Labadie 2.............. Subbituminous......... 42.5 MO
----------------------------------------------------------------------------------------------------------------
* This unit has announced its intention to retire in 2023.

ii. Limited CAA Section 114 Request
In May 2021, pursuant to authority in section 114 of the CAA, 42
U.S.C. 7414(a), the EPA solicited information related to Hg emissions
and Hg control technologies from certain lignite-fired EGUs to inform
this CAA section 112(d)(6) technology review. The selected lignite-
fired EGUs were asked

[[Page 24877]]

to provide information on their control configuration for Hg and for
other air pollutants (e.g., criteria pollutants such as PM,
NO<INF>X</INF>, SO<INF>2</INF>). Selected information on lignite-fired
EGU control configurations that was obtained from the CAA section 114
information request is shown below in Table 6. Additional information
on the location, size (capacity), firing configuration, and control
configuration of lignite-fired EGUs (including those few that were not
included in the CAA section 114 information request) is also included.
The additional information was obtained from the EPA's NEEDS
database.\36\
---------------------------------------------------------------------------

\36\ National Electric Energy Data System (NEEDS) v621 rev: 10-
14-22, available at: <a href="https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6">https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6</a>.

Table 6--Control Configurations for Lignite-Fired EGUs
----------------------------------------------------------------------------------------------------------------
Capacity Control Hg control
Plant name State (MW) Firing configuration description Hg control
----------------------------------------------------------------------------------------------------------------
Antelope Valley #1....... ND 450 tangent...... ACI + SDA + FF.. Does not use Nalco non-
Antelope Valley #2....... ND 450 tangent...... ACI + SDA + FF.. activated carbon, non-
carbon as its halogenated
sorbent, liquid sorbent
instead added to dry
injects a scrubber; M-
liquid sorbent Sorb additive
to the (bromide).
scrubber. The
facility
stopped using
refined coal
in December
2021.
----------------------------------------------------------------------------------------------------------------
Coal Creek #1............ ND 574 tangent...... ACI + ESPC + Information not collected in the
Coal Creek #2............ ND 573 tangent...... WFGD. CAA 114 request.
ACI + ESPC +
WFGD..
----------------------------------------------------------------------------------------------------------------
Coyote................... ND 429 cyclone...... ACI + SDA + FF.. Information not collected in the
CAA 114 request.
----------------------------------------------------------------------------------------------------------------
Leland Olds #1........... ND 222 wall......... SNCR + ACI + Activated ME2C SEA SF10
ESPC + WFGD. carbon and Oxidizer and
oxidizer SB24 Activated
injections for Carbon.
Hg control.
Leland Olds #2........... ND 445 cyclone...... SNCR + ACI +
ESPC + WFGD.
----------------------------------------------------------------------------------------------------------------
Milton R Young #1........ ND 237 cyclone...... SNCR + ACI + Hg controlled DARCO Hg-H non-
Milton R Young #2........ ND 447 cyclone...... ESPC + WFGD. by Powdered halogenated
SNCR + ACI + Activated Powdered
ESPC + WFGD.. Carbon Activated
Injection plus Carbon + ADA M-
Oxidizing Prove
Agent/Halogen additive.
Injection
System.
----------------------------------------------------------------------------------------------------------------
Spiritwood Station....... ND 92 FBC.......... SNCR + ACI + SDA Hg emissions Activated
+ FF. are controlled Carbon sorbent
by activated (not
carbon specified).
injection
system and a
CEMS. The
activated
carbon
injection feed
rate is
adjusted to
maintain
emissions
below the 4.0
lb/TBtu
standard.
----------------------------------------------------------------------------------------------------------------
Limestone #1............. TX 831 tangent...... SNCR + ACI + Information not collected in the
....... ......... ............. ESPC + WFGD. CAA 114 request.
Limestone #2............. TX 858 tangent...... SNCR + ACI +
ESPC + WFGD.
----------------------------------------------------------------------------------------------------------------
Major Oak #1............. TX 152 FBC.......... Reagent Hg is Cabot DARCO Hg-
Major Oak #2............. TX 153 FBC.......... Injection + controlled by H non-
SNCR + ACI + FF. the Brominated AC
Reagent introduction + ADA-ES M-
Injection + of activated Prove
SNCR + ACI + carbon into additive.
FF.. each boiler
duct directly
in front of
the baghouse.
A halogen fuel
additive is
also applied
to the lignite
before it
enters the day
silos.
----------------------------------------------------------------------------------------------------------------
Martin Lake #1........... TX 800 tangent...... ACI + ESPC + Brominated ME2C SEA
Martin Lake #2........... TX 805 tangent...... WFGD. additive process (non-
Martin Lake #3........... TX 805 tangent...... ACI + ESPC + injected into Brominated AC
WFGD.. the furnace + chemical
ACI + ESPC + and activated additive).
WFGD.. carbon
injected
upstream of
the air
heater. In
2020 and 2021
Refined Coal
System applied
an aqueous
bromine salt
solution to
the coal.
--------------------------------------------------------------------------------------
Oak Grove #1............. TX 855 tangent...... SCR + ACI + FF + Brominated ADA-CS Br-AC.
Oak Grove #2............. TX 855 wall......... WFGD. activated
SCR + ACI + FF + carbon
WFGD.. injected
downstream of
the air
heater. From
2018 to 2021,
the unit was
equipped with
a Refined Coal
System for Hg
control. This
system applied
an aqueous
bromine salt
solution to
the coal
downstream of
the crusher.
The refined
coal system is
no longer in
service.
----------------------------------------------------------------------------------------------------------------
Red Hills #1............. MS 220 FBC.......... Reagent Hg is ADA-CS non-Br
Red Hills #2............. MS 220 FBC.......... Injection + ACI controlled by AC + ADA-ES
+ FF. injection of M45 liquid
Reagent activated additive.
Injection + ACI carbon into
+ FF.. each boiler
duct directly
in front of
the baghouse.
A fuel
additive is
also applied
to the lignite
before it
enters the day
silos. The
application of
fuel additives
ended in
December 2021.
----------------------------------------------------------------------------------------------------------------

[[Page 24878]]

San Miguel............... TX 391 wall......... SNCR + ACI + Hg is captured ME2C SEA
ESPC + WFGD. using a process (non-
sorbent Br AC + powder-
enhanced based chemical
additive (SEA) additive).
injected onto
the lignite at
the pulverizer
feeders or
directly into
the furnace to
promote the
oxidation and
capture of Hg.
This is
followed by an
ACI system
located in the
boiler exit

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