[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 [www.gpo.gov]
[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:
     Federal eRulemaking Portal: https://www.regulations.gov/ 
(our preferred method). Follow the online instructions for submitting 
comments.
     Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2018-0794 in the subject line of the message.
     Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2018-0794.
     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.
     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 https://www.regulations.gov/, 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: 
[email protected].

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 https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards.
    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 https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards or contact the 
public hearing team at (888) 372-8699 or by email at 
[email protected]. 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: https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards.
    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 https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards. 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 [email protected] 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 https://www.regulations.gov/. 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 Regulations.gov.
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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 https://www.regulations.gov/, 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 https://www.regulations.gov/ 
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 https://www.epa.gov/dockets/commenting-epa-dockets.
    The https://www.regulations.gov/ 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 
https://www.regulations.gov/, 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 https://www.epa.gov/dockets.
    Submitting CBI. Do not submit information containing CBI to the EPA 
through https://www.regulations.gov/. 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 [email protected], 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 [email protected] 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
CO2 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-CO2 social cost of carbon
SO2 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 (SeO2)), 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: https://www.epa.gov/fera/dose-response-assessment-assessing-health-risks-associated-exposure-hazardous-air-pollutants.
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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, 
SeO2, in the condensible PM fraction. SeO2 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.
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    \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).
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    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 (SO2) emission standard), 
which serves as a surrogate for all acid gas HAP (HCl, HF, 
SeO2) for existing coal-fired EGUs. An evaluation of recent 
compliance data for HCl and/or SO2 emissions revealed that 
approximately two-thirds of coal-fired EGUs operate at or below the 
alternative SO2 emission standard of 2.0E-01 lb 
SO2/MMBtu (SO2 may be used as an alternative 
surrogate for acid gas HAP at coal-fired EGUs with operational flue gas 
desulfurization (FGD) systems and SO2 CEMS). Approximately 
one-third of coal-fired EGUs have a SO2 emission rate above 
the current SO2 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 
https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards. 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 https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards.

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 SO2 that may be used 
as a surrogate for acid gas HAP for those coal-fired EGUs with FGD 
systems and SO2 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 SO2 
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\
---------------------------------------------------------------------------

    \10\ See https://www.epa.gov/airmarkets/power-sector-modeling-platform-v515.
    \11\ See https://ampd.epa.gov/ampd/.
    \12\ See https://cfpub.epa.gov/webfire; https://www.epa.gov/electronic-reporting-air-emissions/webfire.
    \13\ See https://www.eia.gov/electricity/data/eia923/.
    \14\ See https://www3.epa.gov/airtoxics/utility/utilitypg.html.
---------------------------------------------------------------------------

    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'':
     Any add-on control technology or other equipment that was 
not identified and considered during development of the original MACT 
standards;
     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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

     Any work practice or operational procedure that was not 
identified or considered during development of the original MACT 
standards;
     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
     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).
     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 (SO2, 
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\
---------------------------------------------------------------------------

    \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 
www.regulations.gov.
---------------------------------------------------------------------------

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, SeO2). 
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.
---------------------------------------------------------------------------

    \19\ See https://www.andovertechnology.com/wp-content/uploads/2021/08/PM-and-Hg-Controls_CAELP_20210819.pdf.
---------------------------------------------------------------------------

    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 https://www.epa.gov/sites/default/files/2015-11/documents/matsriafinal.pdf 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 https://www.epa.gov/sites/default/files/2015-07/documents/suppdoc410mats.pdf 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.
---------------------------------------------------------------------------

    \23\ See https://www.andovertechnology.com/wp-content/uploads/2021/08/PM-and-Hg-Controls_CAELP_20210819.pdf.
    \24\ https://www.nrdc.org/resources/coal-fired-power-plant-hazardous-air-pollution-emissions-and-pollution-control-data.
---------------------------------------------------------------------------

    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 www.reginfo.gov,\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 www.epri.com/research/products/1017574.
    \32\ See Quantitative Aerosol Generator (QAG) for Calibration of 
Particulate Monitors: 2014 Technical Update, available at 
www.epri.com/research/products/3002003343.
---------------------------------------------------------------------------

    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'' (Hgp), 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 
(HgCl2) 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 Hgp. 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 HgCl2 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, 
SO2, and nitrogen oxides (NOX). Particulate-bound 
Hg (Hgp) is effectively removed along with PM in PM control 
equipment such as FFs and ESPs. Soluble Hg\2+\ compounds (such as 
HgCl2) can be effectively captured in wet FGD systems. And, 
while a selective catalytic reduction (SCR) system that has been 
installed for NOX 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 
https://www.epa.gov/sites/default/files/2019-12/documents/2017_full_report.pdf 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 
https://www3.epa.gov/airmarkets/progress/reports/pdfs/2021_full_report.pdf 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, 
NOX, SO2). 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: https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6.

                             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
                                                                                 duct work
                                                                                 upstream of
                                                                                 the air
                                                                                 heaters. The
                                                                                 scrubber
                                                                                 system also
                                                                                 reduces Hg
                                                                                 emissions.
----------------------------------------------------------------------------------------------------------------
Note: ACI = activated carbon injection; SDA = spray dryer absorber (dry scrubber); FF = fabric filter; ESPC =
  cold side electrostatic precipitator; WFGD = wet flue gas desulfurization scrubber; SNCR = selective non-
  catalytic reduction (NOX control); reagent injection = sorbent injection into fluidized bed combustor.

    Most, but not all, of the EGUs utilized a combination of the use of 
a chemical additive and injection of a sorbent as their Hg control 
strategy. One facility in North Dakota (Antelope Valley) uses a liquid 
sorbent that is injected to the SO2 scrubber (spray dryer 
absorber, SDA). Many of the EGUs used ``refined coal.'' Refined coal is 
typically produced by mixing proprietary additives to feedstock coal to 
help capture emissions when the coal is burned. For example, these 
additives may promote the oxidation of Hg to Hg\2+\ compounds for 
capture in downstream control equipment (e.g., FGD scrubbers, PM 
control devices). Several of the facilities noted that use of refined 
coal as a part of their Hg control strategy was discontinued at the end 
of 2021 when the refined coal production tax credit (created by the 
American Jobs Creation Act of 2004) expired. According to a U.S. 
Government Accountability Office audit report, refined coal producers 
claimed approximately $8.9 billion in tax credits between 2010 and 
2020.
    According to fuel use information supplied to EIA (on form 923), 13 
of 22 EGUs that were designed to burn lignite utilized refined coal to 
some extent in 2021, as summarized in Table 7. EIA form 923 does not 
specify the type of coal that is ``refined'' when reporting boiler or 
generator fuel use. For this technology review, the EPA has assumed 
that the facilities have utilized ``refined lignite,'' as reported in 
fuel receipts on EIA form 923. However, several ``lignite-fired EGUs'' 
located in Texas reported very high use of subbituminous coal in 2021 
(ranging from 76 percent up to > 99 percent).

                                  Table 7--2021 Fuel Use At Lignite-Fired EGUs
----------------------------------------------------------------------------------------------------------------
                                    Distillate      Natural gas    Lignite coal    Refined coal    Subbituminous
           Plant name              fuel oil  (%)        (%)             (%)             (%)          coal  (%)
----------------------------------------------------------------------------------------------------------------
Antelope Valley 1...............             0.0             0.6             5.8            93.5             0.0
Antelope Valley 2...............             0.0             0.6             5.8            93.5             0.0
Coal Creek 1....................             0.1             0.0             0.0            99.9             0.0
Coal Creek 2....................             0.1             0.0             0.0            99.9             0.0
Coyote 1........................             0.3             0.0            99.7             0.0             0.0
Leland Olds 1...................             0.3             0.0            37.6            62.1             0.0
Leland Olds 2...................             0.3             0.0             6.2            93.6             0.0
Milton R Young 1................             0.4             0.0            17.0            82.6             0.0
Milton R Young 2................             0.2             0.0            12.1            87.6             0.0
Spiritwood Station 1............             0.0            35.6             0.0            64.4             0.0
Limestone 1.....................             0.0             0.2             0.0             0.0            99.8
Limestone 2.....................             0.0             0.8             0.0             0.0            99.2
Major Oak Power 1...............             0.0             0.2            99.8             0.0             0.0
Major Oak Power 2...............             0.0             0.0           100.0             0.0             0.0
Martin Lake 1...................             0.1             0.0            23.5             0.0            76.4
Martin Lake 2...................             0.1             0.0            22.4             0.0            77.5
Martin Lake 3...................             0.1             0.0            19.2             0.0            80.6
Oak Grove 1.....................             0.0             1.9             3.4            94.7             0.0
Oak Grove 2.....................             0.0             0.0             3.7            96.3             0.0
Red Hills Generating Facility 1.             0.0             0.3             0.0            99.7             0.0
Red Hills Generating Facility 2.             0.0             0.3             0.0            99.7             0.0
San Miguel 1....................             0.2             0.0            99.8             0.0             0.0
----------------------------------------------------------------------------------------------------------------

e. CAA Section 112(d)(6) Technology Review of the Hg Standards
i. Review of the Hg Emission Standard for Non-Lignite-Fired EGUs
    The final MATS Hg emission limit for EGUs firing non-lignite coals 
(i.e., bituminous and subbituminous coals) is 1.2 lb Hg/TBtu. To review 
that emission standard, the EPA evaluated the 2021 performance of EGUs 
firing non-lignite coals and found that EGUs firing primarily 
bituminous coal emitted Hg at an average annual rate of 0.4 lb Hg/TBtu 
(with a range of roughly 0.2 to 1.2 lb Hg/TBtu). EGUs firing primarily 
subbituminous coal in 2021 (not including those EGUs that are permitted 
to burn lignite but burned a significant amount of subbituminous coal) 
emitted Hg at an average annual rate of 0.6 lb Hg/TBtu (with a range of 
0.1 to 1.2 lb/TBtu). This represents a control range of 98 to 77 
percent (assuming an average inlet concentration of 5.5 lb/TBtu). The 
EPA has information on the control configurations of these non-lignite

[[Page 24879]]

EGUs. However, because the non-lignite-fired EGUs were not included in 
the limited CAA section 114 information collection, the EPA does not 
have detailed information on the type of sorbent injected (e.g., 
activated carbon or non-carbonaceous; pre-halogenated, etc.). The EPA 
also does not have detailed information on the injection rate of 
sorbents used for Hg control (if any). Similarly, the EPA does not have 
information on the type of quantity of chemical additives used (if 
any). However, the bituminous coal-fired EGUs are already achieving an 
average annual rate of 0.4 lb/TBtu and the subbituminous coal-fired 
EGUs are already achieving an average annual rate of 0.6 lb/TBtu. The 
typical Hg control performance curves for sorbent injection show a 
leveling off such that increasing the amount of sorbent results in 
diminishing improvement in Hg control. Based on full-scale 
demonstration testing of Hg sorbents, this leveling off typically takes 
place somewhere greater than 90 percent capture. Without knowing the 
type of sorbent being injected or the rate of the sorbent injection, it 
is difficult to determine whether additional emission reductions could 
be achieved in a cost-effective manner. For bituminous coal-fired EGUs 
that do not utilize sorbent injection but rely on co-benefit control 
from equipment installed for criteria pollutants, it is difficult to 
determine whether additional Hg emission reduction could be obtained in 
a cost-effective manner with knowledge of the levels of Hg control 
achieved in each of the installed controls and, if chemical additives 
are injected, the type and rate of chemical additive injection. For 
those reasons, the EPA is not proposing to adjust the Hg emission 
standard for non-lignite-fired EGUs at this time. However, the EPA 
solicits comment on the performance of Hg controls for non-lignite-
fired EGUs, including information on the type and injection rate of 
sorbents used for Hg control, as well as the possibility of additional 
cost-effective measures to further reduce Hg from equipment installed 
for criteria pollutants. The EPA also seeks comment on whether there 
would be a reasonably efficient way to more thoroughly survey the types 
of controls--including the types of sorbents used and their injection 
rates--used to limit Hg emissions at non-lignite-fired EGUs, and 
whether conducting such additional information collection would be 
worthwhile.
    In addition, the EPA notes that several states have adopted Hg 
reduction standards that go beyond the 2012 MATS Final Rule in their 
reduction target. For instance, Connecticut, Minnesota, Montana, New 
York, Oregon, and Utah all established input-based Hg limits below 1.2 
lb/TBtu. For further detail on all 18 states with existing Hg emissions 
limits, see Chapter 3 of EPA's IPM documentation, available in the 
docket. The EPA solicits information about the cost and effectiveness 
of control strategies that EGUs in these states utilize to meet more 
stringent Hg emission standards than those promulgated in the 2012 MATS 
Final Rule, as well as any other available control strategies that the 
EPA should consider and their costs.
ii. Review of the Hg Emission Standard for Lignite-Fired EGUs
    The final MATS Hg emission limit for EGUs firing lignite coal is 
4.0 lb Hg/TBtu--more than three times the standard for non-lignite 
coal. To review that emission standard, the EPA evaluated the data 
obtained in the 2022 CAA section 114 data survey along with the 
emissions data reported to the EPA and the fuel use data submitted to 
EIA. The 2021 performance of lignite-fired EGUs (including those 
permitted to burn lignite but that utilized significant amounts of 
subbituminous coal in 2021) is shown in Table 8 below. The table shows 
a ``Hg Inlet'' level which reflects the maximum Hg content of the range 
of feedstock coals that the EPA assumes is available to each of the 
plants in the Integrated Planning Model, IPM,\37\ the estimated control 
(percentage) needed to meet an emission standard of 4.0 lb Hg/TBtu (the 
current standard for lignite-fired EGUs) and the estimated control 
(percentage) to meet an emission standard of 1.2 lb Hg/TBtu (the 
current standard for non-lignite-fired EGUs). The table also shows the 
estimated 2021 Hg inlet concentration from actual 2021 fuel usage (as 
mentioned earlier, some units utilized significant quantities of non-
lignite fuel, e.g., subbituminous coal, natural gas, etc.) and the 2021 
Hg emissions reported to the EPA. The EPA then estimated the apparent 
level of Hg control for 2021 and the level of control that would been 
needed to achieve the emission standard applicable to the non-lignite-
firing EGUs (1.2 lb Hg/TBtu).
---------------------------------------------------------------------------

    \37\ Discussion of how these assumptions were developed for use 
in the EPA's IPM modeling is available in Chapter 7 of the IPM 
Documentation.

                                       Table 8--Hg Emissions and Control Performance of Lignite-Fired EGUs in 2021
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Est Hg control  Est Hg control    Est 2021 Hg                                     Est 2021 Hg
               Plant name                 Hg inlet  (lb/  at 4.0 lb/TBtu  at 1.2 lb/TBtu    inlet  (lb/   2021 Hg outlet    Est 2021 Hg   control at 1.2
                                               TBtu)            (%)             (%)            TBtu)         (lb/TBtu)     control  (%)    lb/TBtu  (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Antelope Valley #1......................            7.81            48.8            84.6            7.76            2.87            63.0            84.5
Antelope Valley #2......................            7.81            48.8            84.6            7.76            2.74            64.6            84.5
Coal Creek #1...........................            7.81            48.8            84.6            7.80            3.62            53.6            84.6
Coal Creek #2...........................            7.81            48.8            84.6            7.80            3.89            50.2            84.6
Coyote..................................            7.81            48.8            84.6            7.79            3.17            59.2            84.6
Leland Olds #1..........................            7.81            48.8            84.6            7.79            2.51            67.8            84.6
Leland Olds #2..........................            7.81            48.8            84.6            7.79            3.02            61.3            84.6
Milton R Young #1.......................            7.81            48.8            84.6            7.78            3.23            58.4            84.6
Milton R Young #2.......................            7.81            48.8            84.6            7.79            3.20            58.9            84.6
Spiritwood Station......................            7.81            48.8            84.6            5.03            1.86            63.1            76.1
Limestone #1............................           14.88            73.1            91.9            6.24            0.94            84.9            80.8
Limestone #2............................           14.88            73.1            91.9            6.20            1.59            74.4            80.7
Major Oak #1............................           14.65            72.7            91.8           14.62            1.24            91.5            91.8
Major Oak #2............................           14.65            72.7            91.8           14.65            1.31            91.1            91.8
Martin Lake #1..........................           14.65            72.7            91.8            8.22            2.32            71.8            85.4
Martin Lake #2..........................           14.65            72.7            91.8            8.13            2.99            63.2            85.2
Martin Lake #3..........................           14.65            72.7            91.8            7.85            3.04            61.3            84.7

[[Page 24880]]

 
Oak Grove #1............................           14.88            73.1            91.9           14.60            2.01            86.2            91.8
Oak Grove #2............................           14.88            73.1            91.9           14.88            2.59            82.6            91.9
Red Hills #1............................           12.44            67.8            90.4           12.40            1.33            89.3            90.3
Red Hills #2............................           12.44            67.8            90.4           12.40            1.35            89.1            90.3
San Miguel..............................           14.65            72.7            91.8           14.62            2.81            80.8            91.8
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As can be seen in the table, all lignite-fired EGUs are estimated 
to meet the current standard by achieving a level of control of less 
than 75 percent. The average reported 2021 Hg emission rate for 
lignite-fired EGUs located in North Dakota was 3.0 lb Hg/TBtu with an 
average control of 83.7 percent. The average reported 2021 Hg emission 
rate for lignite-fired EGUs located in Texas and Mississippi was 2.0 lb 
Hg/TBtu (with an average control of 88.2 percent).
f. Proposed Revision of the Hg Emission Standard for Lignite-Fired EGUs
    Several commenters have provided information on new developments in 
Hg control technology. One commenter \38\ indicated that improvements 
in halogen and ACI technologies have significantly lowered the costs of 
those pollution control systems. The use of computational fluid 
dynamics and physical modeling has also improved pollutant capture and 
reduced sorbent consumption. The commenter further noted that ACI 
systems operate more reliably, and many users utilize technology to 
improve the dispersion of sorbents in flue gas for better performance. 
After reviewing the available literature and other studies and 
available information, the assumptions made regarding Hg control in the 
2012 MATS Final Rule, and the information obtained from compliance 
reports and the 2022 CAA section 114 information collection, the EPA 
has determined that there are developments in practices, processes, and 
control technologies since 2012 that warrant consideration of revising 
the Hg standards for lignite-fired EGUs. As explained below, the EPA 
has further determined that available controls and methods of operation 
that will allow lignite-fired EGUs to meet the same Hg emission 
standard that is being met by EGUs firing on non-lignite coals, and 
that the costs of doing so are reasonable.\39\ Therefore, the EPA is 
proposing to revise the Hg emission standard for lignite-fired EGUs to 
1.2E-06 lb/MMBtu.
---------------------------------------------------------------------------

    \38\ See EPA-HQ-OAR-2018-0794-1171.
    \39\ As discussed in section V.B above, prior CAA section 
112(d)(2) technology reviews conducted by the EPA establish that 
obtaining better information on performance of controls can provide 
the basis for updates to standards under a technology review.
---------------------------------------------------------------------------

i. Both Lignite and Subbituminous Coal Are Low Rank Coals With Low 
Halogen Content
    Coal is classified into four main types, or ranks: \40\ anthracite, 
bituminous, subbituminous, and lignite. The ranking depends on heating 
value of the coal. Anthracite has the highest heating value of all 
ranks of coal and is mostly used by the metals industry (it is rarely 
using for power production). Anthracite accounted for less than 1 
percent of the coal mined in the U.S. in 2021. Bituminous coal is also 
considered a ``high rank coal'' because of its higher heating value. It 
is the most abundant rank of domestic coal and accounted for about 45 
percent of total U.S. coal production in 2021. Bituminous coal is used 
to generate electricity and in other industries.
---------------------------------------------------------------------------

    \40\ ``Coal Explained, Types of Coal'' Energy Information 
Administration, available at www.eia.gov/energyexplained/coal and in 
the rulemaking docket.
---------------------------------------------------------------------------

    Subbituminous coal and lignite are referred to as ``low rank 
coals.'' They both have lower heating values than bituminous coal. 
Subbituminous coal accounted for about 46 percent of total U.S. coal 
production in 2021, with the vast majority produced in the Powder River 
Basin (PRB) of Wyoming and Montana. Lignite has the lowest energy 
content of all coal ranks. Lignite accounted for about 8 percent of 
total U.S. coal production in 2021.\41\ About 56 percent was mined in 
North Dakota (Fort Union lignite) and about 36 percent was mined in 
Texas (Gulf Coast lignite).
---------------------------------------------------------------------------

    \41\ EIA Annual Coal Report 2021, October 2022, https://www.eia.gov/coal/annual/pdf/acr.pdf.
---------------------------------------------------------------------------

    Chlorine is the most abundant halogen in coal. Bromine may also be 
present in coal but is typically in much lower concentrations than 
chlorine.\42\ Low-rank coals such as lignite and subbituminous 
generally have lower chlorine contents than higher rank coals such as 
bituminous coal.\43\
---------------------------------------------------------------------------

    \42\ See Figure 5 in the U.S. Geological Survey publication 
``Mercury and Halogens in Coal--Their Role in Determining Mercury 
Emissions From Coal Combustion'' available at https://pubs.usgs.gov/fs/2012/3122/pdf/FS2012-3122_Web.pdf.
    \43\ Id.
---------------------------------------------------------------------------

    As mentioned earlier, the halogen content of the coal--especially 
chlorine--largely influences the oxidation state of Hg in the flue gas 
stream. As a result, the halogen content of the coal directly 
influences the ability to capture and contain the Hg before it is 
emitted into the atmosphere. As explained earlier, ash from lignite and 
subbituminous coals tends to be more alkaline (relative to that from 
bituminous coal) due to the lower amounts of sulfur and halogen and the 
presence of 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\. This makes control of Hg from both 
subbituminous coal-fired EGUs and lignite-fired EGUs more challenging 
than the control of Hg from bituminous coal-fired EGUs. However, 
because control strategies and technologies were developed to introduce 
halogens to the flue gas stream, EGUs firing subbituminous coals have 
been able to meet the 1.2 lb/TBtu emission standard in the 2012 MATS 
Final Rule. As mentioned earlier, EGUs firing subbituminous coal in 
2021 emitted Hg at an average annual rate of 0.6 lb Hg/TBtu with 
measured values as low as 0.1 lb/TBtu. Clearly EGUs firing 
subbituminous coal have found control options to meet--and exceed--the 
1.2 lb/TBtu emission standard despite the challenges presented by the 
low natural halogen content of the coal and production of difficult-to-
control elemental Hg vapor in the flue gas stream.

[[Page 24881]]

ii. The Hg Content of Fort Union Lignite and PRB Subbituminous Coal Are 
Similar
    As can be seen in Table 8 above, for the 2012 MATS Final Rule, the 
EPA estimated the Fort Union lignite-fired EGUs inlet Hg concentration 
at up to 7.8 lb/TBtu and estimated the inlet Hg concentration of 
subbituminous coal-fired EGUs at up to 8.65 lb/TBtu. These values are 
very similar to results from a published study that found the average 
Hg concentration of Fort Union lignite and PRB subbituminous coals to 
be very similar. The study found that the Fort Union lignite samples 
contained an average of 8.5 lb/TBtu and the PRB subbituminous coal 
samples contained an average of 7.5 lb/TBtu.\44\ Despite the 
similarities in Hg content, halogen content, and alkalinity between 
Fort Union lignite and PRB subbituminous coal, EGUs firing 
subbituminous coal in 2021 emitted Hg at an average annual rate of 0.6 
lb Hg/TBtu while those firing on Fort Union lignite emitted Hg at an 
average annual rate of 3.0 lb Hg/TBtu. While the EGUs firing Fort Union 
lignite at an average emission rate of 3.0 lb Hg/TBtu are complying 
with the 2012 MATS Final Rule emission standard of 4.0 lb Hg/TBtu, it 
is difficult to justify why those units should not meet a similar level 
of Hg control as that of the EGUs firing PRB subbituminous coal given 
the similarities between the two fuels--especially the similarities in 
Hg content, halogen content, and alkalinity.
---------------------------------------------------------------------------

    \44\ ``Mercury in North Dakota lignite'', Katrinak, K.A.; 
Benson, S.A.; Henke, K.R.; Hassett, D.J.; Fuel Processing 
Technology, 39, 35, 1994.
---------------------------------------------------------------------------

iii. The Hg Content of Gulf Coast Lignite Is Greater Than That of Fort 
Union Lignite; and Several Lignite-Fired EGUs in Texas Have Co-Fired 
Significant Quantities of Subbituminous Coal
    The Hg content of Gulf Coast lignite tends to be higher than that 
of the Fort Union lignite. As can be seen in Table 8 above, for the 
2012 MATS Final Rule, the EPA estimated the inlet Hg concentration for 
Gulf Coast lignite-fired EGUs at an average inlet Hg concentration of 
up to 14.9 lb/TBtu (as compared to average inlet Hg concentrations of 
up to 7.8 lb/TBtu for Fort Union lignite). Despite the higher Hg 
content in Gulf Coast lignite, EGUs permitted as lignite-fired had, in 
2021, an average Hg emission rate of 2.0 lb/TBtu--which was lower than 
the 2021 average emission rate of EGUs firing Fort Union lignite (at 
3.0 lb/TBtu). This is due, in part, because some EGUs in Texas that are 
permitted as lignite-fired units (and thus subject to the Hg emission 
standard of 4.0 lb/TBtu) were, in 2021, firing significant amounts of 
subbituminous coal. Firing high levels of non-lignite coal (in some 
cases greater than 99 percent non-lignite coal), while remaining 
subject to the less stringent Hg emission standard for the subcategory 
of lignite-fired EGUs seems to fit the scenario that the EPA expressed 
concern about in the 2012 MATS Final Rule preamble--that ``sources to 
potentially meet the definition by combusting very small amounts of low 
rank virgin coal [lignite].'' See 77 FR 9379.
iv. The Proposed More Stringent Hg Emission Standard Can Be Achieved, 
Cost-Effectively, Using Available Control Technology
    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 lb/MMacf for units with ESPs and injection 
rates of 2.0 lb/MMacf for units with baghouses (also known as FF). Yet, 
in responses to the CAA section 114 information survey, only one 
facility (Oak Grove) explicitly indicated use of brominated activated 
carbon. Oak Grove units #1 and #2 (both using FF for PM control) 
reported use of brominated activated carbon at an average injection 
rate of less than 0.5 lb/MMacf for operation at capacity factor greater 
than 70 percent. The Oak Grove units fired, in 2021, using mostly 
refined coal.\45\ That injection rate is considerably less than the 2.0 
lb/MMacf assumed.
---------------------------------------------------------------------------

    \45\ EIA form 923 does not specify the rank of coal that is 
``refined'' in boiler or generator fuel data. For this technology 
review, the EPA has assumed that facilities reporting the use of 
refined coal have utilized ``refined lignite,'' which was confirmed 
in EIA form 923 fuel receipts and costs.
---------------------------------------------------------------------------

    From the CAA 114 information survey, the average injection rate 
reported for non-halogenated sorbents was 2.5 lb/MMacf. The average 
sorbent injection rate ranged from 10-65 percent of the maximum design 
sorbent injection rate (the average was 36 percent of the maximum 
design rate). As mentioned earlier, most sources utilized a control 
strategy of sorbent injection coupled with chemical (usually 
halogenated) additives. In the beyond-the-floor analysis in the 2012 
MATS Final Rule, we noted that the results from various demonstration 
projects suggests that greater than 90 percent Hg control can be 
achieved at lignite-fired units using brominated activated carbon 
sorbent at an injection rate of 2.0 lb/MMacf for units with installed 
FFs for PM control and at an injection rate of 3.0 lb/MMacf for units 
with installed ESPs for PM control. As shown in Table 8 above, all 
units (in 2021) would have needed to control their Hg emissions to less 
than 92 percent to meet an emission standard of 1.2 lb/TBtu. Based on 
this, we expect that the units could meet the proposed, more stringent, 
emission standard of 1.2 lb/TBtu by utilizing brominated activated 
carbon at the injection rates suggested in the beyond-the-floor memo 
\46\ from the 2012 MATS Final Rule.
---------------------------------------------------------------------------

    \46\ See Docket ID No. EPA-HQ-OAR-2009-0234-20130 at 
regulations.gov.
---------------------------------------------------------------------------

    To determine the cost-effectiveness of that strategy, we calculated 
the incremental cost-effectiveness (cost per lb of Hg controlled) for a 
model 800 MW lignite-fired EGU. We calculated the incremental cost of 
injecting non-brominated activated carbon sorbent at a sufficiently 
large injection rate of 5.0 lb/MMacf to achieve an emission rate of 1.2 
lb/TBtu versus the cost to meet an emission rate of 4.0 lb/TBtu using 
non-brominated activated carbon sorbent at an emission rate of 2.5 lb/
MMacf. For an 800 MW lignite-fired EGU, the incremental cost 
effectiveness was $8,703 per incremental lb of Hg removed. The actual 
cost-effectiveness is likely lower than this value as it is unlikely 
that sources will need to inject brominated activated carbon sorbent at 
rates as high as 5.0 lb/MMacf (the Oak Grove units were injecting less 
than 0.5 lb/MMacf) and is well below the cost that the EPA has found to 
be acceptable in previous rulemakings (e.g., $27,500/lb Hg was proposed 
to be cost-effective for the Primary Copper RTR (87 FR 1616); 
approximately $27,000/lb Hg was found to be cost-effective in the 
beyond-the-floor analysis supporting the 2012 MATS Final Rule \47\).
---------------------------------------------------------------------------

    \47\ Ibid.
---------------------------------------------------------------------------

    In summary, the EPA is proposing to revise the Hg emission standard 
for lignite-fired EGUs from 4.0E-06 lb/MMBtu to 1.2E-06 lb/MMBtu, which 
is the same Hg emission limit that non-lignite-fired EGUs must meet. We 
are proposing to revise this emission standard while recognizing that 
Hg from the combustion of lignite is challenging to capture because of 
the lack of naturally occurring halogen in the fuel and because of the 
natural alkalinity of the resulting fly ash. However, Hg from the 
combustion of subbituminous coal is similarly challenging to capture 
for the same reasons. Yet, EGUs firing subbituminous coal in 2021 
emitted Hg at an average rate of 0.6 lb/TBtu and some as low as 0.1 lb/
TBtu. From the CAA section 114 information survey, very few lignite-
fired EGUs are using the control technology that the EPA identified as 
the most effective for Hg control in the 2012 MATS Final Rule,

[[Page 24882]]

brominated ACI, which many demonstration projects have shown can 
achieve Hg control of greater than 90 percent. Although we are not 
proposing to mandate the use of any particular control technology, we 
have shown that use of brominated activated carbon sorbent injection 
can be used to cost-effectively meet the more stringent emission.
    We also considered the energy implications and non-air 
environmental impacts of this proposed revision of the Hg emission 
standard for lignite-fired EGUs. We do not anticipate any energy 
implications from this proposed revision as most units are already 
using sorbent injection technology as part of the Hg control strategy 
and we do not project significant changes in unit operations as a 
result of the proposed revision. Regarding the non-air environmental 
impact, we anticipate that there may be positive non-air environmental 
impacts. The current strategies employed by most lignite-fired EGUs 
involve the injection of oxidizing halogen additives and, separately, 
injection of sorbent (typically non-brominated activated carbon). 
Because homogeneous (gas-phase) oxidation of Hg\0\ is kinetically 
limited, most of the Hg\0\ oxidation is thought to occur as 
heterogeneous (solid-phase) reactions resulting from halogens or other 
oxidants attached to flue gas solids (e.g., unburned carbon, other). 
This is essentially a two-step process where the injected (or natural) 
halogen (chloride or bromide) must first attach to a flue gas solid and 
then contact and react with gas-phase Hg\0\. The addition of sorbent 
that has already been pre-halogenated (most often brominated) is more 
efficient as the first step occurs prior to injection. This means that 
less bromine will be unutilized and captured in a downstream control 
device or potentially included in the plant water effluent discharge. 
The EPA requests comment on its expectation that most EGUs (including 
lignite-fired EGUs) will no longer use ``refined coal'' due to the 
expiration of the refined coal tax credit. The amount of Br on 
brominated activated carbon is much less than that used to produce 
refine coal, and Br is retained on the activated carbon sorbent where 
it reacts with gas phase Hg and is captured by downstream control 
devices. Thus, the EPA believes that cross-media transfers of bromine 
to receiving waterbodies and emitted to the atmosphere, especially when 
wet FGD is not employed, are not expected (or would certainly be lower) 
with the use of brominated sorbents as compared to use of refined coal 
and that any negative health, ecological, and productivity effects 
associated with bromine transfer to water effluent will be minimized or 
avoided, especially given the EPA's proposed zero-discharge 
requirements under the Clean Water Act (88 FR 18824; March 29, 2023).
4. No Revisions to Work Practice Standards for Organic HAP
    Following promulgation of the 2020 Final Action, in which the EPA 
found no developments in new technology or methods of operation that 
would result in cost-effective emission reductions of organic HAP and 
thus did not revise the work practice standards for organic HAP, the 
EPA received a petition for reconsideration that, in relevant part, 
requested the EPA to reconsider work practice standards for organic 
HAP.\48\ Our review of new technology and of methods of operation 
conducted as part of this technology review proposal also found no 
developments that would result in cost-effective emission reductions of 
organic HAP. Likewise, we are not proposing revisions to the organic 
HAP work practice standards finalized in the 2012 MATS Final Rule.\49\ 
The EPA acknowledges that it received a petition for reconsideration 
from environmental organizations that, in relevant part, sought the 
EPA's reconsideration of organic HAP work practice standards, which the 
EPA continues to review and will respond to in a separate action.\50\
---------------------------------------------------------------------------

    \48\ See Docket ID No. EPA-HQ-OAR-2018-0794-4565 at 
www.regulations.gov.
    \49\ See 40 CFR 63.9991, Table 3.
    \50\ See Docket ID No. EPA-HQ-OAR-2018-0794-4565 at 
www.regulations.gov.
---------------------------------------------------------------------------

5. No Proposed Revisions to the Acid Gas Standards for Coal-Fired EGUs
    The EPA evaluated the use of control technologies and strategies 
that are commonly used for control of acid gas HAP (e.g., HCl, HF). 
These control technologies and strategies include the use of wet FGD 
scrubbers, spray drier absorber (SDA) scrubbers, reagent injection (for 
fluidized combustors), dry sorbent injection (DSI), and use of low 
sulfur or low halogen fuels. As described in section III of this 
preamble, EGUs in six subcategories are subject to numeric emission 
limits for acid gas HAP (e.g., HCl, HF). Emission standards for HCl 
serve as a surrogate for all acid gas HAP, with an alternate standard 
for SO2 that may be used as a surrogate for the acid gas HAP 
at coal-fired EGUs with operational FGD systems and SO2 
CEMS.
    When the EPA finalized the 2012 MATS Final Rule, the primary air 
pollution control devices installed at EGUs for the control of acid 
gases were wet scrubbers (wet FGD), dry scrubbers (dry FGD or spray 
dryer absorber, SDA), and reagent injection (at fluidized bed 
combustors). These technologies are still in wide use for acid gas HAP 
control. An additional acid gas control technology--dry sorbent 
injection (DSI)--was in limited use in the power sector at the time the 
MATS rule was finalized but has seen increased use since (approximately 
20 percent of EGUs operating in 2021 utilized DSI for acid gas control 
for one reason or another).
    A wet FGD scrubber uses an alkaline liquid slurry (usually a 
limestone or lime slurry) to remove acidic gases from an exhaust 
stream. The acid gases react with the alkaline compounds in the slurry 
and are removed as scrubber solids (e.g., CaSO3 or 
CaSO4) or may be captured due to their solubility in the 
scrubber slurry. Most wet FGD scrubbers have SO2 removal 
efficiencies exceeding 90 percent and perform even better for HCl and 
HF. Dry FGD scrubbers (SDA) are an acid gas pollution control system 
where an alkaline sorbent slurry is injected into the flue gas stream 
to react with and neutralize acid gases in the exhaust stream forming a 
dry powder material which is then captured in a downstream PM control 
device (usually an FF). Alkaline sorbent injection systems (reagent 
injection) are also used in fluidized bed combustors (FBC) and 
circulating fluidized bed (CFB) boilers for control of acid gases. In 
that use, the alkaline sorbent (usually powdered limestone) is injected 
into the combustion chamber with the primary fuel. Dry sorbent 
injection (DSI) is an add-on air pollution control system in which a 
dry alkaline powdered sorbent (typically sodium- or calcium-based) is 
injected into the flue gas steam upstream of a PM control device to 
react with and neutralize acid gases in the exhaust stream forming a 
dry powder material that may be removed in a primary or secondary PM 
control device. The EPA evaluated the use of these control technologies 
(wet FGD scrubbers, SDA, reagent injection, and DSI), and the strategic 
use of low sulfur or low halogen fuels.
    The EPA reviewed compliance data for SO2 and/or HCl, as 
shown in Figure 3 of the Technical Memo, showing EGUs with highest 
SO2 emissions in 2021 to those with the lowest 
SO2 emissions in 2021. Approximately two-thirds of coal-
fired EGUs have demonstrated compliance with the

[[Page 24883]]

alternative SO2 emission standard rather than the HCl 
emission limit. About one-third of EGUs have demonstrated compliance 
with the primary acid gas emission limit for HCl. And some sources have 
reported emissions data that demonstrates compliance with either of the 
standards. The emission rates for HCl that are shown in Figure 3 of the 
Technical Memo distinguish between EGUs that utilize some sort of acid 
gas control system--which would be a wet FGD scrubber, a dry scrubber 
(an SDA), reagent injection or DSI--and EGUs that do not have a wet FGD 
scrubber or an SDA and do not utilize either reagent injection or DSI. 
All of the EGUs with no acid gas controls are units that were firing 
subbituminous coal and were likely able to demonstrate compliance with 
the HCl emission standard due to the low natural chlorine content and 
high alkalinity of most subbituminous coals.
    All sources submit SO2 emissions data to comply with 
other CAA requirements (e.g., the Acid Rain Program). As mentioned 
earlier, some sources submitted emissions data that demonstrates 
compliance with either the HCl standard or the alternative 
SO2 standard. The average SO2 emission rate for 
units at or below the alternative SO2 emission limit was 
9.0E-02 lb SO2/MMBtu, which is approximately 55 percent 
below the SO2 emission limit of 2.0E-01 lb SO2/
MMBtu. The average HCl emission rate for units demonstrating compliance 
with the SO2 standard but also reporting HCl emissions was 
4.0E-04 lb HCl/MMBtu, which is approximately 80 percent below the HCl 
emission limit of 2.0E-03 lb HCl/MMBtu. This result is consistent with 
the EPA's rationale for establishing the alternative SO2 
emission limit--because HCl emissions are much more easily controlled 
than SO2 emissions (HCl and HF are much more reactive and 
much more water soluble than SO2), controlling emissions of 
SO2 using FGD controls very effectively controls emissions 
of HCl. Note that an EGU may demonstrate compliance with the acid gas 
surrogate SO2 standard only if the unit has some type of 
installed acid gas control and an operational SO2 CEMS.
    The EPA looked further at the HCl emissions of the EGUs operating 
in 2021 with and without acid gas controls. The average emission rate 
of EGUs with no add-on acid gas control was 8.0E-04 lb HCl/MMBtu, which 
is 60 percent below the SO2 emission limit.
    The EPA looked closer at the relative performance of acid gas 
controls for HCl emissions. The best performing EGUs tend to be those 
that utilize either wet or dry FGD scrubbers, with units utilizing 
sorbent injection emitting at slightly higher rates. The units that 
utilize DSI with an FF tend to have lower HCl emissions than those that 
utilize DSI with an ESP. This is an expected outcome as the filter cake 
on the FF provides great opportunity for contact with the gas phase 
acid gases.
    Overall, the EPA has evaluated acid gas emissions data from MATS-
affected EGUs and have determined that some units have demonstrated 
compliance with the primary HCl emission standard using acid gas 
control technologies (wet FGD scrubbers, SDA, reagent injection, and 
DSI) and through the strategic use of low-halogen, high-alkalinity 
fuels. Other units have demonstrated compliance with acid gas emission 
limits by meeting or exceeding the alternative surrogate SO2 
emission standard. The average HCl emission rates for units with add-on 
acid gas controls was 4.0E-04 lb HCl/MMBtu which is approximately 80 
percent below the MATS HCl emission limit. The average HCl emission 
rates for units with no add-on acid gas controls was 8.0E-04 lb HCl/
MMBtu (approximately 60 percent below the MATS HCl emission limit). It 
is not clear that improvements in a wet or dry FGD scrubber would 
result in additional HCl emission reductions since HCl emissions are 
already much easier to control than SO2 emissions. The EPA 
does not have information on the sorbent injection rates for DSI 
systems; so, we cannot assess whether increased sorbent injection would 
result in additional HCl emission reductions. Units using DSI in 
combination with an ESP would almost certainly see improved performance 
if they were to replace the ESP with a FF. However, that small 
incremental reduction in HCl emissions would come at a high cost and 
would certainly not be a cost-effective option.
    In the 2020 Technology Review, the EPA concluded that ``the 
existing acid gas pollution control technologies that are currently in 
use are well-established and provide the capture efficiencies necessary 
for compliance with the promulgated MATS rule limits.'' Comments 
received during the 2020 Proposal did not provide any new practices, 
processes, or control technologies for acid gas control. One commenter 
noted that ``in the short time since the RTR was finalized, there have 
been no developments in practices, processes, or control technologies, 
nor any new technologies or practices for the control of . . . acid gas 
HAP'' (Docket ID No. EPA-HQ-OAR-2018-5121). Another commenter pointed 
to an independent comprehensive report to show acid gas emission 
controls had better performance and lower capital costs than the EPA 
assumed in the 2011 modeling (Docket ID No. EPA-HQ-OAR-2018-0794-4962). 
That report suggested control technology improvements to acid gas 
controls to achieve revised HCl emission standards of 1.0E-03 lb HCl/
MMBtu, 6.0E-04 lb HCl/MMBtu, and 1.0E-05 lb HCl/MMBtu through addition 
of new DSI systems, upgrades to existing DSI systems, upgrades to 
existing wet and dry scrubbers, and, for the most stringent options, 
installation of new FFs. However, as mentioned earlier--and as detailed 
further in the Technical Memo--it is not clear that such improvements 
targeting acid gases would result in corresponding reductions in HCl or 
HF emissions, as emissions of HCl and HF are already much easier to 
control than emissions of SO2.
    In summary, the EPA has not identified any new control technologies 
or any improvements to existing acid gas controls that would result in 
additional cost-effective acid gas HAP emission reductions from coal-
fired EGUs and is, therefore, not proposing revisions to the acid gas 
emission standards or for the surrogate SO2 emission 
standard. However, the EPA solicits comment on any new practices, 
processes, or technologies for control of acid gas HAP emissions, 
including any information on whether increased sorbent injection rates 
(for sources using DSI or SDA controls) would result in additional HCl 
emission reductions, that could inform the potential for additional 
cost-effective acid gas HAP emission reductions from coal-fired EGUs.
6. No Proposed Revisions to Standards for Continental Liquid Oil-Fired 
EGUs
    The annual capacity factors of most continental liquid oil-fired 
units are low. Based on available data reported to the EIA and the 
EPA's Clean Air Markets Program Data (CAMPD), in 2021 the average 
annual capacity factor for liquid oil-fired units was 3 percent. 
Additionally, there were only two continental liquid oil-fired units 
identified with 2-year capacity factors greater than 8 percent. Those 
two units primarily fire natural gas but had heat input-based 
percentages of fuel oil firing that were about 16 percent in at least 
one of the years from 2019 through 2021 (i.e., slightly above the 15 
percent that would qualify them as oil-fired units). Therefore, it is 
likely that there are very few continental liquid oil-fired units that 
would be outside of the definition

[[Page 24884]]

of the limited-use liquid oil-fired subcategory.
    Furthermore, for the continental liquid oil-fired units with 
available data that are likely limited-use units, the cumulative 
percentage of heat input from residual fuel oil in 2021 was 32 percent, 
the heat input of distillate fuel oil was 4 percent, and the heat input 
from natural gas was 64 percent. Because the capacity factors of most 
continental liquid oil-fired units are low, and most combustion by 
those units is using fuel (i.e., natural gas) with low metallic HAP 
emission rates, the EPA is not proposing changes to the total HAP 
metals (which includes Hg), nor to the standards for the individual HAP 
metals, nor to the HAP metal surrogate fPM emission standard for 
continental liquid oil-fired electricity generating units.
    However, given there have been several recent temporary and 
localized increases in oil combustion at continental liquid oil-fired 
EGUs during periods of extreme weather conditions, such as the 2023 
polar vortex in New England, the EPA seeks comment on whether the 
current definition of the limited-use liquid oil-fired subcategory 
remains appropriate or if, given the increased reliance on oil-fired 
generation during periods of extreme weather, a period other than the 
current 24-month period or a different threshold would be more 
appropriate for the current definition. The EPA also seeks comment on 
the appropriateness of including new HAP standards for EGUs subject to 
the limited use liquid oil-fired subcategory, as well as on the means 
of demonstrating compliance with the new HAP standards. For example, in 
order to reduce HAP emissions during periods of extreme weather 
conditions, it may be appropriate for limited-use liquid oil-fired EGUs 
to use distillate fuel oil instead of residual oil, or to switch from 
residual oil to cleaner fuels after a certain number of hours of 
operation, or to be subject to an annual or seasonal limit of residual 
oil firing. The EPA solicits comment on each of these options.
    The EPA also solicits comment on establishing a HAP emission limit 
on liquid oil-fired EGUs (including those in the limited-use 
subcategory and those located in non-continental areas) where 
compliance would be demonstrated through fuel sampling and analysis. 
The EPA seeks comment from the regulated community, citizens, and 
regulatory authorities on the need for a revision to the limited-use 
oil-fired subcategory definition and on additional, cost-effective 
methods to minimize HAP emissions during periods of limited operation.
7. No Proposed Revisions to Standards for Non-Continental Liquid Oil-
Fired EGUs
    Hawaiian Electric Company (HECO) operates 12 liquid oil-fired 
boilers at its Waiau Generating Station (Pearl City, HI) and at its 
Kahe Generating Station (Kapolei, HI). Their average capacity factor in 
2021 was 29.6 percent (on a net basis) and they fire on residual fuel 
oil. HECO has, in compliance reports, reported fPM emission rates to 
the EPA that are below the fPM emission rate of 3.0E-02 lb/MMBtu.
    In Puerto Rico, there are 14 liquid oil-fired MATS-affected EGUs 
(3,552 MW total capacity) at four separate facilities operated by the 
Puerto Rico Electric Power Authority (PREPA). The EGUs operate using 
residual fuel oil and do not currently have any emission controls for 
NOX, PM or SO2. At least two of the units have 
dual fuel capabilities and have operated on high levels of natural gas. 
There is limited stack testing data available, but testing done in 2021 
and 2022 indicated fPM emission rates ranging from 2.6E-02 lb/MMBtu to 
2.9E-02 lb/MMBtu, a range that is just below the fPM emission rate of 
3.0E-02 lb/MMBtu.
    As mentioned earlier in section IV.A of this preamble summarizing 
the 2020 Residual Risk Review, the results of the chronic inhalation 
cancer risk assessment based on actual emissions indicated that the 
estimated maximum individual lifetime cancer risk (cancer MIR) was 9-
in-1 million, with nickel emissions from oil-fired EGUs at these four 
facilities in Puerto Rico 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. The estimated maximum chronic noncancer TOSHI for the 
source category was 0.2 (respiratory), which was driven by emissions of 
nickel and cobalt from the oil-fired EGUs.
    Since these oil-fired EGUs do not have installed control devices 
for HAP metals (PM controls), there is no opportunity to improve their 
performance in the same ways the EPA found available to some coal-fired 
EGUs. PREPA has recently proposed near-term retirement dates (by 2026) 
for 10 of the 14 oil-fired EGUs with two of the other four remaining 
boilers burning mostly natural gas.
    Because of the low capacity factors of the Hawaii oil-fired EGUs 
and the near-term retirement dates of most of the Puerto Rico liquid 
oil-fired EGUs and plans for a transition to greater use of natural gas 
for the remaining boilers, the EPA is not proposing to revise emission 
standards for non-continental oil-fired EGUs.
    However, the EPA seeks comment on whether the fPM surrogate 
emission standard is appropriate for these non-continental liquid oil-
fired EGUs. As mentioned, the largest risks identified in the 2020 RTR 
were associated with nickel emissions from residual oil-fired EGUs 
located in Puerto Rico. The EPA solicits comment on eliminating or 
revising the fPM standard for existing non-continental sources, and, 
instead, requiring these EGUs to comply with the existing emission 
limits for the individual metals, including nickel. In addition, the 
EPA also seeks comment on the appropriateness of including new HAP 
standards for EGUs in Puerto Rico and Hawaii, as well as other non-
continental U.S. areas, such as Guam and the Virgin Islands, and the 
means of demonstrating compliance with the new HAP standards. For 
example, the EPA seeks input on whether, in order to reduce HAP 
emissions and associated risks in these places, oil-fired EGUs should 
be required to switch from residual oil to cleaner fuels, or to switch 
to cleaner fuels after a certain number of hours of operation, or 
should be subject to an annual limit of residual oil firing. The EPA 
solicits comment on whether compliance with a HAP metal emission limit 
could be demonstrated by fuel sampling and analysis. The EPA solicits 
comment on the need for additional, cost-effective methods to minimize 
HAP emissions in non-continental states and territories--including 
Hawaii, Puerto Rico, the U.S. Virgin Islands, and Guam. We solicit 
comment on any special considerations--including the availability of 
clean fuels such as distillate fuel oil and natural gas--in non-
continental areas.
8. No Proposed Revisions to Standards for IGCC EGUs
    The EPA is aware of two existing IGCC facilities that meet the 
definition of an IGCC EGU. The Edwardsport Power Station, located in 
Knox County, Indiana, includes two IGCC EGUs that had 2021 average 
capacity factors of approximately 85 percent and 67 percent. The Polk 
Power Station, located in Polk County, Florida, had a 2021 average 
capacity factor of approximately 70 percent, but burned only natural 
gas in 2021.

[[Page 24885]]

    While this subcategory has a less stringent fPM standard of 4.0E-02 
lb/MMBtu (as compared to that of coal-fired EGUs), recent compliance 
data indicates fPM emissions well below the most stringent standard 
option of 6.0E-03 lb/MMBtu that was evaluated for coal-fired EGUs. 
Since there are only two IGCC EGU facilities, and the EPA is unaware of 
any developments in the HAP emission controls used at IGCC units, the 
EPA is not proposing to revise any of the emission standards for this 
subcategory. However, the EPA is proposing that the affected facilities 
must install a PM CEMS to demonstrate compliance with the existing fPM 
limit. Further, the EPA solicits comment on cost-effective methods to 
achieve additional HAP emission reductions from this subcategory.

D. What other actions are we proposing, and what is the rationale for 
those actions?

    In addition to the proposed actions described above, we are 
proposing additional revisions to the NESHAP.
1. Startup Requirements
    In the Reconsideration of Certain Startup/Shutdown Issues: National 
Emission Standards for Hazardous Air Pollutants From Coal- and Oil-
Fired Electric Utility Steam Generating Units and Standards of 
Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional and Small Industrial-Commercial-Institutional 
Steam Generating Units (79 FR 68777; November 19, 2014), the EPA took 
final action on its reconsideration of the startup and shutdown 
provisions by adding an alternative work practice standard for startup 
periods. That alternative work practice standard, referred to as 
paragraph (2) of the definition of ``startup'', required clean fuel use 
to the maximum extent possible, operation of PM control devices within 
1 hour of introduction of primary fuel (i.e., coal, residual oil, or 
solid oil-derived fuel) to the EGU, collection and submission of 
records of clean fuel use and emissions control device capabilities and 
operation, as well as adherence to applicable numerical standards 
within 4 hours of the generation of electricity or thermal energy for 
use either on site or for sale over the grid (i.e., the end of startup) 
and to continue to maximize clean fuel use throughout that period. The 
EPA provided this alternative work practice because many commenters 
asserted it would be difficult, if not impossible, for their EGUs to 
meet the already-promulgated startup work practices.\51\ In Chesapeake 
Climate Action Network v. EPA, the D.C. Circuit remanded the 
alternative work practice standard for startup and shutdown to the EPA 
for reconsideration based on a petition for reconsideration from 
environmental groups. 952 F.3d 310 (D.C. Cir. 2020). In this action, 
and in conjunction with the EPA's authority pursuant to CAA section 
112(d)(6), the EPA is granting in part petitions for reconsideration 
which sought the EPA's review of startup and shutdown provisions.\52\ 
As part of our obligation to address the remand on this issue, we 
reviewed the information available to us. As discussed below, that 
information shows that the conditions contained in the alternative work 
practice standard do not represent what the best performers are able to 
do; moreover, as a practical matter, few EGUs have chosen to use the 
alternative work practice standard.
---------------------------------------------------------------------------

    \51\ See Assessment of Startup Period at Coal-Fired Electric 
Generating Units, available at Docket ID No. EPA-HQ-OAR-2009-0234-
20378.
    \52\ See Docket ID No. EPA-HQ-OAR-2018-0794-4565 at 
www.regulations.gov; see also Chesapeake Climate Action Network v. 
EPA, 952 F.3d 310 (D.C. Cir. 2020).
---------------------------------------------------------------------------

    The EPA was able to identify 14 EGUs with the ability to generate 
up to 8.4 GW that chose to use the alternative work practice for 
startup periods. As shown in Table 9 below, six of those EGUs with the 
ability to generate up to 3.2 GW have retired and one of those EGUs 
with the ability to generate up to 0.7 GW will retire by 2025.

                     Table 9--EGUs Relying on Paragraph (2) of the Definition of ``Startup''
----------------------------------------------------------------------------------------------------------------
           EGU name                  Unit          ORIS code          MW             Notes             Fuel
----------------------------------------------------------------------------------------------------------------
Prairie State Generating.....  1..............           55856             877  ...............  Bituminous.
Prairie State Generating.....  2..............           55856             877  ...............  Bituminous.
Brame Energy Center..........  Rodemacher 2...            6190             552  ...............  Subbituminous.
Brame Energy Center..........  Madison 3-1....            6190             600  ...............  Petroleum coke,
                                                                                                  coal.
Brame Energy Center..........  Madison 3-2....            6190             600  ...............  Petroleum coke,
                                                                                                  coal.
Dolet Hills..................  1..............              51             720  Retired 2021...  Lignite.
Sherburne....................  3..............            6090           938.7  Retires 2034...  Subbituminous.
Westwood.....................  1..............           50611              36  ...............  Waste coal.
Centralia....................  BW21...........            3845           729.9  Retired 2020...  Subbituminous.
Centralia....................  BW22...........            3845           729.9  Retires 2025...  Subbituminous.
St Johns River...............  1..............             207             679  Retired 2018...  Bituminous.
St Johns River...............  2..............             207             679  Retired 2018...  Bituminous.
HMP&L Station 2..............  H1.............            1382             200  Retired 2019...  Bituminous.
HMP&L Station 2..............  H2.............            1382             200  Retired 2019...  Bituminous.
----------------------------------------------------------------------------------------------------------------

    After the planned retirements in 2025, just seven EGUs with the 
ability to generate up to 4.5 GW will remain; this represents less than 
0.4 percent of electrical generation from all affected sources and less 
than 1.7 percent of the 278 GW of coal-fired and other, non-natural gas 
fossil-fired electrical generation available in 2022. We solicit 
comment on whether we have identified all of the EGUs relying on 
paragraph (2) of the definition of ``startup'', as well as their 
associated retirement dates as reported to the Department of Energy's 
EIA. Commenters, particularly owners or operators of affected EGUs, 
should provide us with corrected information as, or if, necessary. 
Despite comments from EGU owners or operators and their industry 
representatives opposing use of paragraph (1) of the definition of 
``startup'', the owners or operators of coal- and oil-fired EGUs that 
generated over 98 percent of electricity in 2022 have made the 
requisite adjustments, whether through greater clean fuel capacity, 
better tuned equipment, better trained staff, a more efficient or 
better design structure, or a combination of factors, to be able to 
meet the requirements of paragraph (1) of the definition of 
``startup.''

[[Page 24886]]

    Consistent with the MACT emission standard setting requirement for 
using the average of the best performing 12 percent of sources to 
establish emission standards, we propose to remove the alternative work 
practice standards, i.e., those contained in paragraph (2) of the 
definition of ``startup'', from the rule. As demonstrated by the 
majority of EGUs currently relying on the work practice standards in 
paragraph (1) of the definition of ``startup'', we believe such a 
change is achievable by all EGUs; further, we expect such a change 
would result in little to no additional expenditure since the 
additional recordkeeping and reporting provisions associated with the 
work practice standards of paragraph (2) of the definition of 
``startup'' were more expensive than the requirements of paragraph (1) 
of the definition of ``startup.'' We solicit comment on our proposal to 
remove the work practice standards of paragraph (2) of the definition 
of ``startup.''
2. Removing Non-Hg Metals Limits
    The current MATS rule contains individual and total non-Hg metals 
emissions limits, as well as fPM emission limits. Those fPM emission 
limits serve as alternative emission limits because fPM was found to be 
a surrogate for either individual or total non-Hg metals emissions. As 
explained and used above to quantify individual and total non-Hg metals 
reductions from our proposed fPM emission limit revision, the 
relationship between individual and total non-Hg metals and fPM was 
determined by EGU fuel type and control device using data collected by 
the 2010 ICR.\53\ While EGU owners or operators have the ability to use 
individual or total non-Hg metals emissions as the compliance method 
for the 358 EGUs when this action takes effect and with generation of 
at least 25 MW,\54\ we are aware of just one owner or operator who 
provides non-Hg metals data--both individual and total--along with fPM 
data for compliance purposes for one waste coal-fired EGU with 
generating capacity of 46.1 MW. Given that owners or operators of the 
other EGUs applicable to MATS have chosen to demonstrate compliance 
with only the fPM emission limit, we propose to remove the non-Hg 
metals emission limits--both individual and total--from MATS. Removal 
of the non-Hg metals emission limits renders the LEE option for non-Hg 
metals (individual and total) obsolete and the EPA is proposing to 
remove those standards as well. Removal of the non-Hg metals emissions 
limits simplifies the compliance determination path for EGU owners or 
operators and reduces the amount of regulatory text, making the rule 
clearer yet continuing to ensure that non-Hg metals emissions remain 
below limits on an ongoing basis, particularly when the fPM is measured 
as proposed with PM CEMS, given that non-Hg metals emissions provided 
for one EGU are obtained via quarterly stack testing. We solicit 
comment on the number of EGUs that currently rely on non-Hg metals 
emissions measurement for MATS compliance purposes; to the extent that 
other EGU owners or operators rely on non-Hg metals emissions for 
compliance purposes, please be sure to identify each EGU, its nameplate 
generating capacity, its anticipated or announced retirement date (if 
applicable), and its Office of Regulatory Information Systems (ORIS) 
Code. We solicit comment on our proposal to remove the non-Hg metals 
emission limits from all existing MATS-affected EGUs.
---------------------------------------------------------------------------

    \53\ See Emission Factor Development for RTR Risk Modeling 
Dataset for Coal- and Oil-fired EGUs, available at https://www.regulations.gov at Docket ID No. EPA-HQ-OAR-2018-0794-0010.
    \54\ Data obtained from the Emissions and Generation Resource 
Integrated Database (eGRID), available at https://www.epa.gov/egrid.
---------------------------------------------------------------------------

    If we were to change our position by deciding against removing the 
non-Hg metals emission limits from MATS and if our proposal to revise 
the fPM emission limits was accepted, we would develop non-Hg emission 
limits by multiplying the revised fPM emission limit by each individual 
(or total) non-Hg PM ratio identified in the aforementioned Emission 
Factor Development for RTR Risk Modeling Dataset for Coal- and Oil-
fired EGUs memorandum.\55\ The resulting values would become the 
individual non-Hg metals emission limits; their sum would become the 
total non-Hg metals emission limit. We solicit comment on our proposed 
approach to develop non-Hg metals emission limits in the event that our 
preferred approach--removing the non-Hg metals emission limits--is not 
selected. Note that should our proposed approach to remove non-Hg 
metals emission limits from MATS not be finalized, we would need to 
adjust the compliance determination method because the current 
quarterly emissions testing would not be consistent with the continuous 
monitoring and compliance determination method afforded by acceptance 
of our proposal to require use of PM CEMS for compliance with the fPM 
emission limit. At least one CEMS manufacturer offers a multi-metals 
instrument that would be suitable or could be adjusted to account for 
appropriate detection levels for ongoing compliance purposes. In 
addition, were our proposal to remove non-Hg metals from the rule not 
finalized, very frequent emissions testing, perhaps on the order of 
weekly, might be able to provide more information on compliance status. 
While not continuous, as provided by CEMS, such information would be 
more frequent than provided by the quarterly emissions testing required 
by the rule. We solicit comment on appropriate means to determine 
compliance with non-Hg metals emission limits, provided our proposed 
approach--removal of non-Hg metals emission limits--is not finalized. 
Please include in your comments information related to the frequency of 
collected data, the continuity of data supplied by your suggested means 
of compliance, and initial and ongoing annual costs of your suggested 
means of compliance.
---------------------------------------------------------------------------

    \55\ See https://www.regulations.gov at Docket ID No. EPA-HQ-
OAR-2018-0794-0010.
---------------------------------------------------------------------------

3. Removing Use of PM CPMS for Compliance Determinations
    Use of PM CPMS for compliance purposes appears to be limited to 
four EGUs at one site in South Carolina, and these EGUs account for 
less than 0.5 percent of all EGUs in operation. According to submitted 
reports, each of the EGUs relies on an instrument (Sick Maihak RWE-200) 
which provides a milliamp signal that is used to develop an ongoing 
operating limit; this instrument is advertised by its maker to be able 
to serve as a PM CEMS with little to no modification, meaning that the 
instrument can provide direct measurement of fPM in terms of the 
emission standard--pounds per million BTU. Given that PM CPMS use costs 
more than PM CEMS use, that PM CPMS does not provide continuous values 
in terms of the emission standard, that PM CPMS is rarely in use among 
EGUs, and that the existing PM CPMS can be used as PM CEMS, we propose 
to remove the ability to use PM CPMS for compliance purposes in MATS. 
The EPA solicits comment on the use of PM CPMS for compliance purposes; 
to the extent there are other EGU owners or operators using PM CPMS, 
commenters should identify each EGU, along with its ORIS code and MW 
nameplate capacity, as well as the PM CPMS manufacturer and model in 
use. The EPA also solicits comment on the proposal to replace PM CPMS 
with PM CEMS for compliance use in MATS; when providing comments, 
please provide detailed costs--including initial instrument cost, 
installation cost, and operating and maintenance costs--as well as a 
description of ongoing

[[Page 24887]]

operating activities from those EGUs with existing PM CPMS used for 
compliance purposes.

E. What compliance dates are we proposing, and what is the rationale 
for the proposed compliance dates?

    The EPA is proposing to revise the fPM emission limit for existing 
coal-fired EGUs and the Hg emission limit for lignite-fired EGUs. The 
EPA is proposing up to 3 years after the effective date for EGUs 
subject to MATS to meet these new emission limits. However, the EPA 
solicits comment on whether more than 1 year is needed to comply 
considering the potential need to upgrade control systems. In addition, 
the EPA is proposing that affected EGUs demonstrate compliance with the 
fPM emission limit using PM CEMS, removing the alternative compliance 
options. Sources must demonstrate that compliance has been achieved, by 
conducting the required performance tests, and other activities as 
specified in 40 CFR part 63, subpart UUUUU, including a minimum 
sampling collection time of 3 hours per run, no later than 3 years 
after the promulgation date. To demonstrate initial compliance using PM 
CEMS, the initial performance test consists of 30-boiler operating 
days. If the PM CEMS is certified prior to the compliance date, the 
test begins with the first operating day on or after that date. If the 
PM CEMS is not certified prior to the compliance date, the test begins 
with the first operating day after certification testing is 
successfully completed. Continuous compliance with the revised fPM 
emission limit is required to be demonstrated on a 30-boiler operating 
day rolling average basis, defined in 40 CFR 63.10021(b), as the 
arithmetic average emissions rates over the last continuous 30 days 
provided the boiler was operating. The EPA proposes to remove the use 
of PM CPMS for compliance determinations and the non-Hg metal emission 
limits--both individual and total--3 years after the promulgation date. 
The EPA considers 3 years to be as expedient as can be required 
considering the potential need to upgrade or replace monitoring 
systems. The EPA solicits comment on whether 3 years is an appropriate 
amount of time for EGUs to upgrade or replace monitoring systems, and 
whether quarterly stack testing should continue to apply for EGUs that 
have a binding commitment to permanently cease operations in the near 
term. Additionally, the EPA proposes to remove fPM and the total and 
individual non-Hg HAP metals from the LEE program no later than 3 years 
after the promulgation date to align with the proposed compliance 
method of PM CEMS. Lastly, the EPA is proposing to remove the 
alternative work practice standard in paragraph (2) of the definition 
of ``startup.'' The EPA proposes that affected sources must utilize 
paragraph (1) of the definition of ``startup'' as specified in 40 CFR 
part 63, subpart UUUUU, no later than 180 days after the effective 
date.

VI. Summary of Cost, Environmental, and Economic Impacts

    In accordance with E.O. 12866 and 13563, the guidelines of OMB 
Circular A-4, and EPA's Guidelines for Preparing Economic Analyses,\56\ 
the EPA prepared an RIA for this proposal. The RIA analyzes the 
benefits and costs associated with the projected emissions reductions 
under the proposed requirements, a less stringent set of requirements, 
and a more stringent set of requirements to inform the EPA and the 
public about these projected impacts.
---------------------------------------------------------------------------

    \56\ U.S. EPA (2014). Guidelines for Preparing Economic 
Analyses. U.S. EPA. Washington, DC, U.S. Environmental Protection 
Agency, Office of Policy, National Center for Environmental 
Economics.
---------------------------------------------------------------------------

    We start this section of the preamble describing how the RIA for 
this proposed rule structured the proposed and less and more stringent 
regulatory options in the RIA. The proposed regulatory option in the 
RIA includes the proposed revision to the fPM standard to 0.010 lb/
MMBtu, in which fPM is a surrogate for non-Hg metal HAP, the proposed 
revision to the Hg standard for lignite-fired EGUs to 1.2 lb/TBtu, the 
proposal to require PM CEMS to demonstrate compliance, and the removal 
of the startup definition number two. The more stringent regulatory 
option examined in the RIA tightens the proposed revision to the fPM 
standard to 0.006 lb/MMBtu. The other three proposed amendments are not 
changed in the more stringent regulatory option examined in the RIA. 
Finally, the less stringent regulatory option examined in the RIA 
assumed the fPM and Hg limits remain unchanged and examines just the 
proposed PM CEMS requirement and removal of startup definition number 
two.

A. What are the affected sources?

    The EPA estimates that there are 302 coal- and 56 oil-fired EGUs 
that will be subject to the MATS rule by the compliance date.

B. What are the air quality impacts?

    The EPA estimated emissions reductions under the proposed rule for 
the years 2028, 2030, and 2035 based upon IPM projections. The EPA also 
used IPM to estimate emissions reductions for the more stringent 
regulatory option examined in the RIA. The less stringent regulatory 
option presented in the RIA has no quantified emissions reductions 
associated with the proposed requirements for PM CEMS and the removal 
of startup definition number two that constitute the less stringent 
regulatory option presented in the RIA.
    The emissions reduction estimates presented in the RIA include 
reductions in pollutants directly targeted by this rule, such as Hg, 
and changes in other pollutants emitted from the power sector as a 
result of the compliance actions projected under this proposed rule. 
Table 10 presents the projected emissions reductions under the proposed 
rule.

       Table 10--Projected EGU Emissions in the Baseline and Under the Proposed Rule: 2028, 2030, and 2035
----------------------------------------------------------------------------------------------------------------
                                                                               Emissions reductions
                                                                 -----------------------------------------------
                              Year                                                Less stringent  More stringent
                                                                   Proposed rule    regulatory      regulatory
                                                                                      option          option
----------------------------------------------------------------------------------------------------------------
                                                    Hg (lbs.)
----------------------------------------------------------------------------------------------------------------
2028............................................................            62.0             0.0           208.0
2030............................................................            67.0             0.0           169.0
2035............................................................            82.0             0.0           168.0
----------------------------------------------------------------------------------------------------------------

[[Page 24888]]

 
                                               PM (thousand tons)
----------------------------------------------------------------------------------------------------------------
2028............................................................             0.4             0.0             2.6
2030............................................................             0.4             0.0             1.5
2035............................................................             0.8             0.0             1.3
----------------------------------------------------------------------------------------------------------------
                                               SO (thousand tons)
----------------------------------------------------------------------------------------------------------------
2028............................................................             0.9             0.0            11.6
2030............................................................             0.5             0.0             0.3
2035............................................................             1.5             0.0             8.8
----------------------------------------------------------------------------------------------------------------
                                         Ozone-season NO (thousand tons)
----------------------------------------------------------------------------------------------------------------
2028............................................................             0.2             0.0             7.2
2030............................................................             0.4             0.0             5.1
2035............................................................             3.2             0.0             5.6
----------------------------------------------------------------------------------------------------------------
                                            Annual NO (thousand tons)
----------------------------------------------------------------------------------------------------------------
2028............................................................             0.4             0.0            18.1
2030............................................................             0.8             0.0             9.5
2035............................................................             3.4             0.0             8.7
----------------------------------------------------------------------------------------------------------------
                                               HCl (thousand tons)
----------------------------------------------------------------------------------------------------------------
2028............................................................             0.0             0.0             0.2
2030............................................................             0.0             0.0             0.1
2035............................................................             0.0             0.0             0.1
----------------------------------------------------------------------------------------------------------------
                                            CO (million metric tons)
----------------------------------------------------------------------------------------------------------------
2028............................................................             0.2             0.0            21.9
2030............................................................             0.8             0.0             8.7
2035............................................................             4.6             0.0             2.9
----------------------------------------------------------------------------------------------------------------

    Section 3 of the RIA presents a detailed discussion of the 
emissions projections under the regulatory options as described in the 
RIA. Section 3 also describes the compliance actions that are projected 
to produce the emissions reductions in Table 10. Please see section 
VI.E of this preamble and section 4 of the RIA for detailed discussions 
of the projected health, welfare, and climate benefits of these 
emissions reductions.

C. What are the cost impacts?

    The power industry's compliance costs are represented in this 
analysis as the change in electric power generation costs between the 
baseline and policy scenarios. In simple terms, these costs are an 
estimate of the increased power industry expenditures required to 
implement the proposed requirements. The compliance cost estimates were 
developed with EPA's Power Sector Modeling Platform v6 using IPM, a 
state-of-the-art, peer-reviewed dynamic, deterministic linear 
programming model of the contiguous U.S. electric power sector. IPM 
provides forecasts of least cost capacity expansion, electricity 
dispatch, and emission control strategies while meeting electricity 
demand and various environmental, transmission, dispatch, and 
reliability constraints. IPM's least-cost dispatch solution is designed 
to ensure generation resource adequacy, either by using existing 
resources or through the construction of new resources. IPM addresses 
reliable delivery of generation resources for the delivery of 
electricity between the 78 IPM regions, based on current and planned 
transmission capacity, by setting limits to the ability to transfer 
power between regions using the bulk power transmission system. The 
model includes state-of-the-art estimates of the cost and performance 
of air pollution control technologies with respect to Hg and other HAP 
controls.
    We estimate the present value (PV) of the projected compliance 
costs over the 2028 to 2037 period, as well as estimate the equivalent 
annual value (EAV) of the flow of the compliance costs over this 
period. All dollars are in 2019 dollars. Consistent with Executive 
Order 12866 guidance, we estimate the PV and EAV using 3 and 7 percent 
discount rates. Table 11 presents the estimates of compliance costs 
across the regulatory options examined in the RIA.

[[Page 24889]]



        Table 11--Projected Compliance Costs of the Proposed Rule, Less Stringent Alternative, and More Stringent Alternative, 2028 Through 2037
                                                         [Millions 2019$, discounted to 2023] a
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                         3% Discount rate                                7% Discount rate
                                                         -----------------------------------------------------------------------------------------------
                                                             Proposed     Less stringent  More stringent     Proposed     Less stringent  More stringent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Present Value (PV)......................................             330             -45           4,600             230             -31           3,400
Equivalent Annualized Value (EAV).......................              38            -5.2             540              33            -4.5             490
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values have been rounded to two significant figures.

    The PV of the compliance costs for the proposal, discounted at the 
3 percent rate, is estimated to be about $330 million, with an EAV of 
about $38 million. At the 7 percent discount rate, the PV of the 
compliance costs of the proposal is estimated to be about $230 million, 
with an EAV of about $33 million. For a detailed description of these 
compliance cost projections, please see section 3 of the RIA, which is 
available in the docket for this action.

D. What are the economic impacts?

    This proposed action has energy market implications. The power 
sector analysis supporting this action indicates that there are 
important power sector impacts that are worth noting, although they are 
small relative to recent market-driven changes in the sector and 
compared to some other EPA air regulatory actions for EGUs.
    There are several small national changes in energy prices projected 
to result from the proposed revisions to the MATS rule. Retail 
electricity prices are projected to increase in the contiguous U.S. by 
an average of less than 0.1 percent in 2028, 2030, and 2035. In 2035, 
the delivered natural gas price is anticipated to increase by less than 
0.1 percent in response to the proposed rule. There are several other 
types of energy impacts associated with the proposed revisions to MATS. 
Some coal-fired capacity, about 500 MW (less than 1 percent of 
operational coal capacity), is projected to become uneconomic to 
maintain by 2028. Coal production for use in the power sector is not 
projected to change significantly by 2028.
    The short-term estimates for employment needed to design, 
construct, and install the control equipment in the 3-year period 
before the compliance date are also provided using an approach that 
estimates employment impacts for the environmental protection sector 
based on projected changes from IPM on the number and scale of 
pollution controls and labor intensities in relevant sectors. Finally, 
some of the other types of employment impacts that will be ongoing are 
estimated using IPM outputs and labor intensities, as reported in 
section 5 of the RIA.

E. What are the benefits?

    Pursuant to E.O. 12866, the RIA for this action analyzes the 
benefits associated with the projected emissions reductions under this 
proposal to inform the EPA and the public about these projected 
impacts. This proposed rule is projected to reduce emissions of Hg and 
non-Hg metal HAP, PM2.5, SO2, NOX, and 
CO2 nationwide. The potential impacts of these emissions 
reductions are discussed in detail in section 4 of the RIA.
    The projected reductions in Hg emissions should reduce the 
bioconcentration of methylmercury in fish in nearby waterbodies. 
Subsistence fishing is associated with vulnerable populations, 
including minorities and those of low socioeconomic status. 
Methylmercury exposure to subsistence fishers from lignite-fired units 
is below the current reference dose (RfD) for methylmercury 
neurodevelopmental toxicity. The EPA considers exposures at or below 
the RfD are unlikely to be associated with appreciable risk of 
deleterious effects across the population. However, no RfD defines an 
exposure level corresponding to zero risk; moreover, the RfD does not 
represent a bright line above which individuals are at risk of adverse 
effects. In addition, there was no evidence of a threshold for 
methylmercury-related neurotoxicity within the range of exposures in 
the Faroe Islands study which served as the primary basis for the 
RfD.\57\ Reductions in Hg emissions from lignite-fired facilities 
should further reduce exposure to methylmercury for subsistence fisher 
sub-populations located in the vicinity of these facilities. The 
projected reductions in non-Hg metal HAP may lead to reduced exposure 
to carcinogenic metal HAP for residential populations near these 
facilities, which should help the EPA maintain an ample margin of 
safety. Furthermore, there is the potential for reductions in Hg and 
non-Hg HAP emissions to enhance ecosystem services and improve 
ecological outcomes, both of which can have positive economic effects 
although it is difficult to estimate these benefits and consequently 
they have not been included in the set of quantified benefits.
---------------------------------------------------------------------------

    \57\ U.S. EPA. 2001. IRIS Summary for Methylmercury. U.S. 
Environmental Protection Agency, Washington, DC. (USEPA, 2001).
---------------------------------------------------------------------------

    The proposed rule is expected to reduce emissions of direct 
PM2.5, NOX, and SO2 nationally 
throughout the year. Because NOX and SO2 are also 
precursors to secondary formation of ambient PM2.5, reducing 
these emissions would reduce human exposure to ambient PM2.5 
throughout the year and would reduce the incidence of PM2.5-
attributable health effects. This proposed rule is also expected to 
reduce ozone-season NOX emissions nationally. In the 
presence of sunlight, NOX and volatile organic compounds 
(VOCs) can undergo a chemical reaction in the atmosphere to form ozone. 
Reducing NOX emissions in most locations reduces human 
exposure to ozone and the incidence of ozone-related health effects, 
though the degree to which ozone is reduced will depend in part on 
local concentration levels of VOCs.
    The health effect endpoints, effect estimates, benefit unit-values, 
and how they were selected, are described in the TSD titled Estimating 
PM2.5- and Ozone-Attributable Health Benefits, which is referenced in 
the RIA for this action. Our approach for updating the endpoints and to 
identify suitable epidemiologic studies, baseline incidence rates, 
population demographics, and valuation estimates is summarized in 
section 4 of the RIA. This proposed rule is projected to reduce 
PM2.5 and ozone concentrations, producing a projected PV of 
monetized health benefits of about $1.9 billion, with an EAV of about 
$220 million discounted at 3 percent.
    Because of projected changes in dispatch under the proposed 
requirements, the proposed rule is also projected to reduce 
CO2 emissions. The EPA estimated the climate benefits from

[[Page 24890]]

this proposed rule using estimates of the social cost of greenhouse 
gases (SC-GHG), specifically the social cost of carbon (SC-
CO2). The SC-CO2 is the monetary value of the net 
harm to society associated with a marginal increase in CO2 
emissions in a given year, or the benefit of avoiding that increase. In 
principle, SC-CO2 includes the value of all climate change 
impacts (both negative and positive), including (but not limited to) 
changes in net agricultural productivity, human health effects, 
property damage from increased flood risk natural disasters, disruption 
of energy systems, risk of conflict, environmental migration, and the 
value of ecosystem services. The SC-CO2, therefore, reflects 
the societal value of reducing emissions of the gas in question by one 
metric ton and is the theoretically appropriate value to use in 
conducting benefit-cost analyses of policies that affect CO2 
emissions. In practice, data and modeling limitations naturally 
restrain the ability of SC-CO2 estimates to include all the 
important physical, ecological, and economic impacts of climate change, 
such that the estimates are a partial accounting of climate change 
impacts and will therefore, tend to be underestimates of the marginal 
benefits of abatement. The EPA and other Federal agencies began 
regularly incorporating SC-GHG estimates in their benefit-cost analyses 
conducted under E.O. 12866 \58\ since 2008, following a Ninth Circuit 
Court of Appeals remand of a rule for failing to monetize the benefits 
of reducing CO2 emissions in a rulemaking process.
---------------------------------------------------------------------------

    \58\ Benefit-cost analyses have been an integral part of 
executive branch rulemaking for decades. Presidents since the 1970s 
have issued executive orders requiring agencies to conduct analysis 
of the economic consequences of regulations as part of the 
rulemaking development process. E.O. 12866, released in 1993 and 
still in effect today, requires that for all economically 
significant regulatory actions, an agency provide an assessment of 
the potential costs and benefits of the regulatory action, and that 
this assessment include a quantification of benefits and costs to 
the extent feasible.
---------------------------------------------------------------------------

    We estimate the global social benefits of CO2 emission 
reductions expected from the proposed rule using the SC-GHG estimates 
presented in the February 2021 TSD: Social Cost of Carbon, Methane, and 
Nitrous Oxide Interim Estimates under E.O. 13990. These SC-GHG 
estimates are interim values developed under E.O. 13990 for use in 
benefit-cost analyses until updated estimates of the impacts of climate 
change can be developed based on the best available climate science and 
economics. We have evaluated the SC-GHG estimates in the TSD and have 
determined that these estimates are appropriate for use in estimating 
the global social benefits of CO2 emission reductions 
expected from this proposed rule. After considering the TSD, and the 
issues and studies discussed therein, the EPA finds that these 
estimates, while likely an underestimate, are the best currently 
available SC-GHG estimates. These SC-GHG estimates were developed over 
many years using a transparent process, peer-reviewed methodologies, 
the best science available at the time of that process, and with input 
from the public. As discussed in section 4.4 of the RIA, these interim 
SC-CO2 estimates have a number of limitations, including 
that the models used to produce them do not include all of the 
important physical, ecological, and economic impacts of climate change 
recognized in the climate-change literature and that several modeling 
input assumptions are outdated. As discussed in the February 2021 TSD, 
the Interagency Working Group on the Social Cost of Greenhouse Gases 
(IWG) finds that, taken together, the limitations suggest that these 
SC-CO2 estimates likely underestimate the damages from 
CO2 emissions. The IWG is currently working on a 
comprehensive update of the SC-GHG estimates (under E.O. 13990) taking 
into consideration recommendations from the National Academies of 
Sciences, Engineering and Medicine, recent scientific literature, 
public comments received on the February 2021 TSD and other input from 
experts and diverse stakeholder groups. The EPA is participating in the 
IWG's work. In addition, while that process continues, the EPA is 
continuously reviewing developments in the scientific literature on the 
SC-GHG, including more robust methodologies for estimating damages from 
emissions, and looking for opportunities to further improve SC-GHG 
estimation going forward. Most recently, the EPA has developed a draft 
updated SC-GHG methodology within a sensitivity analysis in the RIA of 
the EPA's November 2022 supplemental proposal for oil and gas standards 
that is currently undergoing external peer review and a public comment 
process. See section 4.4 of the RIA for more discussion of this effort.
    Table 12 presents the estimated PV and EAV of the projected health 
and climate benefits across the regulatory options examined in the RIA 
in 2019 dollars discounted to 2023. The table includes benefit 
estimates for the less and more stringent regulatory options examined 
in the RIA for this proposal.

            Table 12--Projected Benefits of the Proposed Rule, Less Stringent Alternative, and More Stringent Alternative, 2028 Through 2037
                                                         [Millions 2019$, discounted to 2023] a
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Present value (PV)
                                                         -----------------------------------------------------------------------------------------------
                                                                         3% Discount rate                              7% Discount rate \d\
                                                         -----------------------------------------------------------------------------------------------
                                                             Proposed     Less stringent  More stringent     Proposed     Less stringent  More stringent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Health Benefits \c\.....................................           1,900             0.0          11,000           1,200             0.0           7,100
Climate Benefits \d\....................................           1,400             0.0           3,200       \d\ 1,400         \d\ 0.0       \d\ 3,200
                                                         -----------------------------------------------------------------------------------------------
    Benefits \e\........................................           3,300             0.0          14,000           2,600             0.0          10,000
--------------------------------------------------------------------------------------------------------------------------------------------------------


 
                                                                                         Equal annualized value (EAV) \b\
                                                         -----------------------------------------------------------------------------------------------
                                                                         3% Discount rate                              7% Discount rate \d\
                                                         -----------------------------------------------------------------------------------------------
                                                             Proposed     Less stringent  More stringent     Proposed     Less stringent  More stringent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Health Benefits \c\.....................................             220             0.0           1,300             170             0.0           1,000
Climate Benefits \d\....................................             170             0.0             380         \d\ 170         \d\ 0.0         \d\ 380
                                                         -----------------------------------------------------------------------------------------------

[[Page 24891]]

 
    Benefits \e\........................................             390             0.0           1,700             330             0.0           1,400
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values have been rounded to two significant figures. Rows may not appear to sum correctly due to rounding.
\b\ The EAV of benefits are calculated over the 10-year period from 2028 to 2037.
\c\ The projected monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The projected
  health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent.
\d\ Climate benefits are based on reductions in CO2 emissions and are calculated using four different estimates of the social cost of carbon dioxide (SC-
  CO2): model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate. For the presentational
  purposes of this table, we show the climate benefits associated with the average SC-CO2 at a 3 percent discount rate, but the Agency does not have a
  single central SC-CO2 point estimate. Climate benefits in this table are discounted using a 3 percent discount rate to obtain the PV and EAV estimates
  in the table. We emphasize the importance and value of considering the benefits calculated using all four SC-CO2 estimates. Section 4.4 of the RIA
  presents estimates of the projected climate benefits of this proposal using all four rates. We note that consideration of climate benefits calculated
  using discount rates below 3 percent, including 2 percent and lower, is warranted when discounting intergenerational impacts.
\e\ Several categories of benefits remain unmonetized and are thus not directly reflected in the quantified benefit estimates in the table. Non-
  monetized benefits include benefits from reductions in Hg and non-Hg metal HAP emissions and from the increased transparency and accelerated
  identification of anomalous emission anticipated from requiring CEMS.

    This proposed rule is projected to reduce PM2.5 and 
ozone concentrations, producing a projected PV of monetized health 
benefits of about $1.9 billion, with an EAV of about $220 million 
discounted at 3 percent. The projected PV of monetized climate benefits 
of the proposal are estimated to be about $1.4 billion, with an EAV of 
about $170 million using the SC-CO2 discounted at 3 percent. 
Thus, this proposed rule would generate a PV of monetized benefits of 
$3.3 billion, with an EAV of $390 million discounted at a 3 percent 
rate.
    At a 7 percent discount rate, this proposed rule is expected to 
generate projected PV of monetized health benefits of $1.2 billion, 
with an EAV of about $170 million discounted at 7 percent. Climate 
benefits remain discounted at 3 percent in this benefits analysis and 
are estimated to be about $1.4 billion, with an EAV of about $170 
million using the SC-CO2. Thus, this proposed rule would 
generate a PV of monetized benefits of $2.6 billion, with an EAV of 
$330 million discounted at a 7 percent rate. The potential benefits 
from reducing Hg and non-Hg metal HAP were not monetized and are 
therefore not directly reflected in the monetized benefit-cost 
estimates associated with this proposal. Potential benefits from the 
increased transparency and accelerated identification of anomalous 
emission anticipated from requiring CEMS were also not monetized in 
this analysis and are therefore also not directly reflected in the 
monetized benefit-cost comparisons. We nonetheless consider these 
impacts in our evaluation of the net benefits of the rule and find, if 
we were able to monetize these beneficial impacts, the proposal would 
have greater net benefits than shown in Table 12.

F. What analysis of environmental justice did we conduct?

    Executive Order 12898 directs the EPA to identify the populations 
of concern who are most likely to experience unequal burdens from 
environmental harms; specifically, minority populations, low-income 
populations, and Indigenous peoples.\59\ Additionally, Executive Order 
13985 is intended to advance racial equity and support underserved 
communities through federal government actions.\60\ The EPA defines 
environmental justice (EJ) as the fair treatment and meaningful 
involvement of all people regardless of race, color, national origin, 
or income, with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and policies. The EPA 
further defines the term fair treatment to mean that ``no group of 
people should bear a disproportionate burden of environmental harms and 
risks, including those resulting from the negative environmental 
consequences of industrial, governmental, and commercial operations or 
programs and policies.'' \61\ In recognizing that minority and low-
income populations often bear an unequal burden of environmental harms 
and risks, the EPA continues to consider ways of protecting them from 
adverse public health and environmental effects of air pollution.
---------------------------------------------------------------------------

    \59\ 59 FR 7629, February 16, 1994.
    \60\ 86 FR 7009, January 20, 2021.
    \61\ https://www.epa.gov/environmentaljustice.
---------------------------------------------------------------------------

    The EPA's EJ technical guidance \62\ states that ``[t]he analysis 
of potential EJ concerns for regulatory actions should address three 
questions:
---------------------------------------------------------------------------

    \62\ U.S. Environmental Protection Agency (EPA), 2015. Guidance 
on Considering Environmental Justice During the Development of 
Regulatory Actions.
---------------------------------------------------------------------------

    1. Are there potential EJ concerns associated with environmental 
stressors affected by the regulatory action for population groups of 
concern in the baseline?
    2. Are there potential EJ concerns associated with environmental 
stressors affected by the regulatory action for population groups of 
concern for the regulatory option(s) under consideration?
    3. For the regulatory option(s) under consideration, are potential 
EJ concerns created or mitigated compared to the baseline?''
    To address these questions in the EPA's first quantitative EJ 
analysis in the context of a MATS rule, the EPA developed a unique 
analytical approach that considers the purpose and specifics of the 
proposed rulemaking, as well as the nature of known and potential 
disproportionate and adverse exposures and impacts. However, due to 
data limitations, it is possible that our analysis failed to identify 
disparities that may exist, such as potential EJ characteristics (e.g., 
residence of historically red lined areas), environmental impacts 
(e.g., other ozone metrics), and more granular spatial resolutions 
(e.g., neighborhood scale) that were not evaluated. Also due to data 
and resource limitations, we discuss HAP and climate EJ impacts of this 
action qualitatively (sections 6.3 and 6.6 of the RIA).
    For this proposed rule, we employ two types of analysis to respond 
to the previous three questions: proximity analyses and exposure 
analyses. Both types of analyses can inform whether there are potential 
EJ concerns for population groups of concern in the

[[Page 24892]]

baseline (question 1).\63\ In contrast, only the exposure analyses, 
which are based on future air quality modeling, can inform whether 
there will be potential EJ concerns after implementation of the 
regulatory options under consideration (question 2) and whether 
potential EJ concerns will be created or mitigated compared to the 
baseline (question 3). While the exposure analysis can respond to all 
three questions, several caveats should be noted. For example, the air 
pollutant exposure metrics are limited to those used in the benefits 
assessment. For ozone, that is the maximum daily 8-hour average, 
averaged across the April through September warm season (AS-MO3) and 
for PM2.5 that is the annual average. This ozone metric 
likely smooths potential daily ozone gradients and is not directly 
relatable to the NAAQS, whereas the PM2.5 metric is more 
similar to the long term PM2.5 standard. The air quality 
modeling estimates are also based on state level emission data paired 
with facility-level baseline emissions and provided at a resolution of 
12 km\2\. Additionally, here we focus on air quality changes due to 
this proposed rulemaking and infer post-policy exposure burden impacts.
---------------------------------------------------------------------------

    \63\ The baseline for proximity analyses is current population 
information, whereas the baseline for ozone exposure analyses are 
the future years in which the regulatory options will be implemented 
(e.g., 2023 and 2026).
---------------------------------------------------------------------------

    Exposure analysis results are provided in two formats: aggregated 
and distributional. The aggregated results provide an overview of 
potential ozone exposure differences across populations at the 
national- and state-levels, while the distributional results show 
detailed information about ozone concentration changes experienced by 
everyone within each population.
    In section 6 of the RIA we utilize the two types of analysis to 
address the three EJ questions by quantitatively evaluating: (1) the 
proximity of affected facilities to populations of potential EJ concern 
(section 6.4); and (2) the potential for disproportionate ozone and 
PM2.5 concentrations in the baseline and concentration 
changes after rule implementation across different demographic groups 
(section 6.5). Each of these analyses depends on mutually exclusive 
assumptions, was performed to answer separate questions, and is 
associated with unique limitations and uncertainties.
    Baseline demographic proximity analyses can be relevant for 
identifying populations that may be exposed to local environmental 
stressors, such as local NO2 and SO2 emitted from 
affected sources in this proposed rule, traffic, or noise. The baseline 
analysis indicates that on average the populations living within 10 km 
of coal plants potentially subject to the proposed or alternate 
filterable PM standards have a higher percentage of people living below 
two times the poverty level than the national average. In addition, on 
average the percentage of the Native American population living within 
10 km of lignite plants potentially subject to proposed Hg standard is 
higher than the national average. Relating these results to EJ question 
1, we conclude that there may be potential EJ concerns associated with 
directly emitted pollutants that are affected by the regulatory action 
(e.g., SO2) for certain population groups of concern in the 
baseline (question 1). However, as proximity to affected facilities 
does not capture variation in baseline exposure across communities, nor 
does it indicate that any exposures or impacts will occur, these 
results should not be interpreted as a direct measure of exposure or 
impact.
    As HAP exposure results generated as part of the 2020 Residual Risk 
analysis were below both the presumptive acceptable cancer risk 
threshold and noncancer health benchmarks and this proposed regulation 
should further reduce exposure to HAP, there are no `disproportionate 
and adverse effects' of potential EJ concern. Therefore, we did not 
perform a quantitative EJ assessment of HAP risk.
    This proposed rule is also expected to reduce emissions of direct 
PM2.5, NOX, and SO2 nationally 
throughout the year. Because NOX and SO2 are also 
precursors to secondary formation of ambient PM2.5 and 
NOX is a precursor to ozone formation, reducing these 
emissions would impact human exposure. Quantitative ozone and 
PM2.5 exposure analyses can provide insight into all three 
EJ questions, so they are performed to evaluate potential 
disproportionate impacts of this rulemaking. Even though both the 
proximity and exposure analyses can potentially improve understanding 
of baseline EJ concerns (question 1), the two should not be directly 
compared. This is because the demographic proximity analysis does not 
include air quality information and is based on current, not future, 
population information.
    The baseline analysis of ozone and PM2.5 concentration 
burden responds to question 1 from EPA's EJ Technical Guidance document 
more directly than the proximity analyses, as it evaluates a form of 
the environmental stressor targeted by the regulatory action. Baseline 
ozone and PM2.5 analyses show that certain populations, such 
as Hispanics, Asians, those linguistically isolated, those less 
educated, and children may experience somewhat higher ozone and 
PM2.5 concentrations compared to the national average. 
Therefore, also in response to question 1, there likely are potential 
EJ concerns associated with ozone and PM2.5 exposures 
affected by the regulatory action for population groups of concern in 
the baseline. However, these baseline exposure results have not been 
fully explored and additional analyses are likely needed to understand 
potential implications. Due to the small magnitude of the exposure 
changes across population demographics associated with the rulemaking 
relative to the magnitude of the baseline disparities, we infer that 
post-policy EJ ozone and PM2.5 concentration burdens are 
likely to remain after implementation of the regulatory action or 
alternative under consideration (question 2).
    Question 3 asks whether potential EJ concerns will be created or 
mitigated as compared to the baseline. Due to the very small magnitude 
of differences across demographic population post-policy ozone and 
PM2.5 exposure impacts, we do not find evidence that 
potential EJ concerns related to ozone and PM2.5 
concentrations will be created or mitigated as compared to the 
baseline.\64\
---------------------------------------------------------------------------

    \64\ Please note, exposure results should not be extrapolated to 
other air pollutant. Detailed EJ analytical results can be found in 
Section 6 of the RIA.
---------------------------------------------------------------------------

    Prior to this proposed rule, the EPA initiated a public outreach 
effort to gather input from stakeholder groups likely to be interested 
in this proposed rule. Specifically, the EPA presented on a National EJ 
call on September 20, 2022, to share information about the proposed 
rule and solicit feedback about potential EJ considerations. The 
webinar was attended by individuals representing state governments, 
federally recognized tribes, environmental non-governmental 
organizations, higher education institutions, industry, and the 
EPA.\65\
---------------------------------------------------------------------------

    \65\ This does not constitute the EPA's tribal consultation 
under E.O. 13175, which is described in section VIII.F of this 
proposed rule.

---------------------------------------------------------------------------

[[Page 24893]]

    In addition to the engagement conducted prior to this proposed 
rule, the EPA is providing the public, including those communities 
disproportionately impacted by the burdens of pollution, opportunities 
to engage in the EPA's public comment period for this proposed rule, 
including by hosting a public hearing. This public hearing will occur 
according to the schedule identified in the SUPPLEMENTARY INFORMATION 
under the heading entitled Participation in virtual public hearing of 
this proposed rule.

VII. Request for Comments

    We solicit comments on this proposed action. In addition to general 
comments on this proposed action, we are also interested in additional 
data that may improve the analyses. We are specifically interested in 
receiving any information regarding developments in practices, 
processes, and control technologies that reduce HAP emissions. We are 
also interested in comments on any reliance interests stakeholders may 
have that would be affected by this proposed action.

VIII. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive orders 
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action was submitted to the OMB for review under section 
3(f)(1) of Executive Order 12866. Any changes made in response to 
recommendations received as part of review under Executive Order 12866 
have been documented in the docket. 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 in section VI of this preamble and here.
    Table 13 presents the estimated PV and EAV of the projected health 
benefits, climate benefits, compliance costs, and net benefits of the 
proposed rule in 2019 dollars discounted to 2023. The estimated 
monetized net benefits are the projected monetized benefits minus the 
projected monetized costs of the proposed rule. Table 13 also presents 
results for the less stringent and more stringent alternatives that are 
examined in the RIA for this proposal.
    Under E.O. 12866, the EPA is directed to consider all of the costs 
and benefits of its actions, not just those that stem from the 
regulated pollutant. Accordingly, the projected monetized benefits of 
the proposal include health benefits associated with projected 
reductions in fine particulate matter (PM2.5) and ozone 
concentration. The projected monetized benefits also include climate 
benefits due to reductions in CO2 emissions. The projected 
health benefits are associated with several point estimates and are 
presented at real discount rates of 3 and 7 percent. The projected 
climate benefits in this table are based on estimates of the SC-
CO2 at a 3 percent discount rate and are discounted using a 
3 percent discount rate to obtain the PV and EAV estimates in the 
table. The power industry's compliance costs are represented in this 
analysis as the change in electric power generation costs between the 
baseline and policy scenarios. In simple terms, these costs are an 
estimate of the increased power industry expenditures required to 
implement the proposed requirements and represent the EPA's best 
estimate of the social cost of the proposed rulemaking.

     Table 13--Projected Monetized Benefits, Compliance Costs, and Net Benefits of the Proposed Rule, Less Stringent Alternative, and More Stringent
                                                             Alternative, 2028 Through 2037
                                                        [Millions 2019$, discounted to 2023] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Present value (PV)
                                                         -----------------------------------------------------------------------------------------------
                                                                         3% Discount rate                              7% Discount rate \d\
                                                         -----------------------------------------------------------------------------------------------
                                                             Proposed     Less stringent  More stringent     Proposed     Less stringent  More stringent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Health Benefits \c\.....................................           1,900             0.0          11,000           1,200             0.0           7,100
Climate Benefits \d\....................................           1,400             0.0           3,200       \d\ 1,400         \d\ 0.0       \d\ 3,200
Compliance Costs........................................             330             -45           4,600             230             -31           3,400
                                                         -----------------------------------------------------------------------------------------------
    Net Benefits \e\....................................           3,000              45           9,800           2,400              31           6,900
--------------------------------------------------------------------------------------------------------------------------------------------------------


 
                                                                                         Equal Annualized Value (EAV) \b\
                                                         -----------------------------------------------------------------------------------------------
                                                                         3% Discount rate                              7% Discount rate \d\
                                                         -----------------------------------------------------------------------------------------------
                                                             Proposed     Less stringent  More stringent     Proposed     Less stringent  More stringent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Health Benefits \c\.....................................             220             0.0           1,300             170             0.0           1,000
Climate Benefits \d\....................................             170             0.0             380         \d\ 170         \d\ 0.0         \d\ 380
Compliance Costs........................................              38            -5.2             540              33            -4.5             490
                                                         -----------------------------------------------------------------------------------------------
    Net Benefits \e\....................................             350             5.2           1,100             300             4.5             900
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values have been rounded to two significant figures. Rows may not appear to sum correctly due to rounding.
\b\ The EAV of costs and benefits are calculated over the 10-year period from 2028 to 2037.
\c\ The projected monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The projected
  health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent.

[[Page 24894]]

 
\d\ Climate benefits are based on reductions in CO2 emissions and are calculated using four different estimates of the social cost of carbon dioxide (SC-
  CO2): model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate. For the presentational
  purposes of this table, we show the climate benefits associated with the average SC-CO2 at a 3 percent discount rate, but the Agency does not have a
  single central SC-CO2 point estimate. Climate benefits in this table are discounted using a 3 percent discount rate to obtain the PV and EAV estimates
  in the table. We emphasize the importance and value of considering the benefits calculated using all four SC-CO2 estimates. Section 4.4 of the RIA
  presents estimates of the projected climate benefits of this proposal using all four rates. We note that consideration of climate benefits calculated
  using discount rates below 3 percent, including 2 percent and lower, is warranted when discounting intergenerational impacts.
\e\ Several categories of benefits remain unmonetized and are thus not directly reflected in the quantified benefit estimates in the table. Non-
  monetized benefits include benefits from reductions in Hg and non-Hg metal HAP emissions and from the increased transparency and accelerated
  identification of anomalous emission anticipated from requiring CEMS.

    As shown in Table 13, this proposed rule is projected to reduce 
PM2.5 and ozone concentrations, producing a projected PV of 
monetized health benefits of about $1.9 billion, with an EAV of about 
$220 million discounted at 3 percent. The proposed rule is also 
projected to reduce greenhouse gas emissions in the form of 
CO2, producing a projected PV of monetized climate benefits 
of about $1.4 billion, with an EAV of about $170 million using the SC-
CO2 discounted at 3 percent. The PV of the projected 
compliance costs are $330 million, with an EAV of about $38 million 
discounted at 3 percent. Combining the projected benefits with the 
projected compliance costs yields a net benefit PV estimate of $3 
billion and EAV of $350 million.
    At a 7 percent discount rate, this proposed rule is expected to 
generate projected PV of monetized health benefits of $1.2 billion, 
with an EAV of about $170 million. Climate benefits remain discounted 
at 3 percent in this net benefits analysis. Thus, this proposed rule 
would generate a PV of monetized benefits of $2.6 billion, with an EAV 
of $340 million discounted at a 7 percent rate. The PV of the projected 
compliance costs are $230 million, with an EAV of $33 million 
discounted at 7 percent. Combining the projected benefits with the 
projected compliance costs yields a net benefit PV estimate of $2.4 
billion and an EAV of $300 million.
    The potential benefits from reducing Hg and non-Hg metal HAP were 
not monetized and are therefore not directly reflected in the monetized 
benefit-cost estimates associated with this proposal. Potential 
benefits from the increased transparency and accelerated identification 
of anomalous emission anticipated from requiring CEMS requiring were 
also not monetized in this analysis and are therefore also not directly 
reflected in the monetized benefit-cost comparisons. We nonetheless 
consider these impacts in our evaluation of the net benefits of the 
rule and find, if we were able to monetize these beneficial impacts, 
the proposal would have greater net benefits than shown in Table 13.

B. Paperwork Reduction Act (PRA)

    OMB has previously approved the information collection activities 
contained in the existing regulations and has assigned OMB control 
number 2060-0567. The information collection activities in this 
proposed rule, which are a revision to the existing approved 
information collection activities, have been submitted for approval to 
the OMB under the PRA. The ICR document that the EPA prepared has been 
assigned EPA ICR number 2137-12. You can find a copy of the ICR in the 
docket for this rule, and it is briefly summarized here.
    The information collection activities in this proposed rule include 
continuous emission monitoring, performance testing, notifications and 
periodic reports, recording information, monitoring and the maintenance 
of records. The information generated by these activities will be used 
by the EPA to ensure that affected facilities comply with the emission 
limits and other requirements. Records and reports are necessary to 
enable delegated authorities to identify affected facilities that may 
not be in compliance with the requirements. Based on reported 
information, delegated authorities will decide which units and what 
records or processes should be inspected. The recordkeeping 
requirements require only the specific information needed to determine 
compliance. These recordkeeping and reporting requirements are 
specifically authorized by CAA section 114 (42 U.S.C. 7414).
    Respondents/affected entities: The respondents are owners or 
operators of coal- and oil-fired EGUs. The NAICS codes for the coal- 
and oil-fired EGU industry are 221112, 221122, and 921150.
    Respondent's obligation to respond: Mandatory per 42 U.S.C. 7414 et 
seq.
    Estimated number of respondents: 187 per year.
    Frequency of response: The frequency of responses varies depending 
on the burden item. Responses include daily calibrations, quarterly 
inspections, and semiannual compliance reports.
    Total estimated burden: 443,000 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $100,100,000 (per year), includes $49,600,000 
annualized capital or operation & maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the EPA's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to the EPA using the docket identified at 
the beginning of this rule. The EPA will respond to any ICR-related 
comments in the final rule. You may also send your ICR-related comments 
to OMB's Office of Information and Regulatory Affairs using the 
interface at https://www.reginfo.gov/public/do/PRAMain. Find this 
particular information collection by selecting ``Currently under 
Review--Open for Public Comments'' or by using the search function. OMB 
must receive comments no later than June 23, 2023.

C. Regulatory Flexibility Act (RFA)

    The EPA certifies that this proposed action will not have a 
significant economic impact on a substantial number of small entities 
under the Regulatory Flexibility Act (RFA). The EPA chose to examine 
the projected impacts of a more stringent regulatory option than 
proposed on small entities in order to present a scenario of ``maximum 
cost impact.'' As projected cost impacts of the proposed rule is 
dominated by cost impacts of the more stringent alternative also 
examined in the RIA, a no SISNOSE conclusion for the more stringent 
option can be extended to the proposed rule and less stringent option.
    In 2028, the EPA identified 26 potentially affected small entities 
operating 41 units at 27 facilities, and of these 26, only two small 
entities may experience compliance cost increases greater than 1 
percent of revenue under the proposed rule, and three small entities 
may experience such increases under the more stringent alternative.

[[Page 24895]]

Details of this analysis are presented in section 5 of the RIA, which 
is in the public docket.

D. Unfunded Mandates Reform Act of 1995 (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. This action imposes 
no enforceable duty on any state, local, or tribal governments or the 
private sector. In light of the interest in this rule among 
governmental entities, the EPA initiated consultation with governmental 
entities. The EPA invited the following 10 national organizations 
representing state and local elected officials to a virtual meeting on 
September 22, 2022: (1) National Governors Association, (2) National 
Conference of State Legislatures, (3) Council of State Governments, (4) 
National League of Cities, (5) U.S. Conference of Mayors, (6) National 
Association of Counties, (7) International City/County Management 
Association, (8) National Association of Towns and Townships, (9) 
County Executives of America, and (10) Environmental Council of States. 
These 10 organizations representing elected state and local officials 
have been identified by the EPA as the ``Big 10'' organizations 
appropriate to contact for purpose of consultation with elected 
officials. Also, the EPA invited air and utility professional groups 
who may have state and local government members, such as the 
Association of Air Pollution Control Agencies, National Association of 
Clean Air Agencies, and others to participate in the meeting. The 
purpose of the consultation was to provide general background on the 
review of the MATS RTR, answer questions, and solicit input from state 
and local governments. Subsequent to the September 22, 2022, meeting, 
the EPA received a letter from the American Public Power Association 
(APPA). The EPA opened a non-rulemaking docket for public input on the 
EPA's efforts to reduce greenhouse gas emissions from new and existing 
fossil fuel-fired EGUs. The APPA letter was submitted to the non-
rulemaking docket. See Docket ID No. EPA-HQ-OAR-2022-0723-0016. In that 
letter, APPA stated that they were not able to identify any new cost-
effective technologies to reduce HAP emissions and that many of the 
current technologies used are state-of-the-art controls that continue 
to reduce HAP emissions. In addition, APPA stated there have been no 
developments in the emission control practices or processes available 
to control HAP emissions during startup and shutdown periods. Also, 
APPA stated that they support the continuation of the 30-day rolling 
average to assure compliance with MATS emission requirements to allow 
for hourly variability caused by unit operation and load requirements, 
including startup and shutdown events.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the National Government and the states, or on the distribution of power 
and responsibilities among the various levels of government.
    The EPA believes, however, that this action may be of interest to 
state and/or local governments. Consistent with the EPA's policy to 
promote communication between the EPA and state and local governments, 
the EPA consulted with representatives of state and local governments 
in the process of developing the proposed amendments to permit them to 
have meaningful and timely input into its development. The EPA's 
consultation regarded planned actions for the review of the MATS RTR. 
The EPA met with 10 national organizations representing state and local 
elected officials to provide general background on the review of the 
MATS RTR, answer questions, and solicit input from state and local 
governments. The UMRA discussion in this preamble includes a 
description of the consultation. In the spirit of E.O. 13132, and 
consistent with EPA policy to promote communications between state and 
local governments, the EPA specifically solicits comment on this 
proposed action from state and local officials.

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

    This action does not have tribal implications as specified in 
Executive Order 13175. The Executive order defines tribal implications 
as ``actions that have substantial direct effects on one or more Indian 
tribes, on the relationship between the Federal Government and Indian 
tribes.'' The amendments proposed in this action would not have a 
substantial direct effect on one or more tribes, change the 
relationship between the Federal Government and tribes, or affect the 
distribution of power and responsibilities between the Federal 
Government and Indian tribes. Thus, Executive Order 13175 does not 
apply to this action.
    Although this action does not have tribal implications as specified 
in Executive Order 13175, the EPA consulted with tribal officials 
during the development of this action. On September 1, 2022, the EPA 
sent a letter to all federally recognized Indian tribes initiating 
consultation to obtain input on this proposal. The EPA did not receive 
any requests from consultation from Indian tribes. The EPA also 
participated in the September 2022 National Tribal Air Association EPA 
Air Policy Update Call to solicit input on this proposed action.

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

    This proposed rule is a ``[c]overed regulatory action'' under 
Executive Order 13045 because it is a significant regulatory action as 
described in section 3(f)(1) of Executive Order 12866, and the EPA 
believes that, even though the residual risk assessment showed all 
modeled exposures to HAP to be below thresholds for public health 
concern, the rule should reduce HAP exposure by reducing emissions of 
Hg and non-Hg HAP with the potential to reduce HAP exposure to 
vulnerable populations including children. Accordingly, we have 
evaluated the potential for environmental health or safety effects from 
exposure to HAP on children. The results of this evaluation are 
contained in the RIA and are available in the docket for this action. 
The EPA believes that the PM2.5-related, ozone-related, and 
CO2-related benefits projected under this proposed rule will 
further improve children's health. Specifically, the PM2.5 
and ozone EJ exposure analyses in section 6 of the RIA suggests that 
nationally, children (ages 0-17) will experience at least as great a 
reduction in annual PM2.5 and ozone exposures as adults 
(ages 18-64) will experience in 2028, 2030 and 2035 under all 
regulatory alternatives of this rulemaking.

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

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. For 2028, the compliance year for the 
proposed standards, the EPA projects a less than 0.1 percent change in 
retail electricity prices on average across the contiguous U.S., a less 
than 0.1 percent reduction in coal-fired electricity generation, and a 
less than 0.1 percent increase in natural gas-fired electricity

[[Page 24896]]

generation. The EPA does not project a significant change in utility 
power sector delivered natural gas prices in 2028. Details of the 
projected energy effects are presented in section 3 of the RIA, which 
is in the public docket.

I. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking does not involve technical standards.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) directs 
federal agencies, to the greatest extent practicable and permitted by 
law, to make EJ part of their mission by identifying and addressing, as 
appropriate, disproportionately high and adverse human health or 
environmental effects of their programs, policies, and activities on 
minority populations (people of color and/or Indigenous peoples) and 
low-income populations.
    HAP risks were below both the presumptive acceptable cancer risk 
threshold and the RfD, and this proposed regulation will likely further 
reduce exposure to HAP. As such, the EPA believes that this action does 
not result in disproportionate and adverse effects on people of color, 
low-income populations, and/or Indigenous peoples.
    The EPA believes that PM2.5 and ozone exposures that 
exist prior to this action result in disproportionate and adverse human 
health or environmental effects on people of color, low-income 
populations and/or Indigenous peoples. Specifically, baseline 
PM2.5 and ozone and exposure analyses show that certain 
populations, such as Hispanics, Asians, those linguistically isolated, 
those less educated, and children may experience disproportionately 
higher ozone and PM2.5 exposures as compared to the national 
average. The EPA believes that this action is not likely to change 
existing disproportionate PM2.5 and ozone exposure impacts 
on people of color, low-income populations and/or Indigenous peoples. 
American Indians may also experience disproportionately higher ozone 
concentrations than the reference group. We do not find evidence that 
potential EJ concerns related to ozone or PM2.5 exposures 
will be meaningfully exacerbated or mitigated in the regulatory 
alternatives under consideration as compared to the baseline due to the 
small magnitude of ozone and PM2.5 concentration changes 
associated with this rule relative to baseline disparities and the very 
small differences in the distributional analyses of post-policy ozone 
and PM2.5 exposure impacts. Importantly, the action 
described in this rule is expected to lower ozone and PM2.5 
in certain areas, and thus mitigate some pre-existing health risks 
across all populations evaluated.
    The documentation for these analyses is contained in section VI.F 
of this this proposed rule and in section 6, Environmental Justice 
Impacts of the RIA, which is in the public docket.

List of Subjects in 40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous 
substances, Reporting and recordkeeping requirements.

Michael S. Regan,
Administrator.
[FR Doc. 2023-07383 Filed 4-21-23; 8:45 am]
BILLING CODE 6560-50-P


