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

Federal RegisterApr 24, 2023

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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.

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: a-and-r-docket@epa.gov.

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:

benish.sarah@epa.gov.

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

SPPDpublichearing@epa.gov.

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

SPPDpublichearing@epa.gov

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.

All documents in the docket are listed in

https://www.regulations.gov/.

Although listed, some information is not publicly available,

e.g.,

Confidential Business

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

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).

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

oaqpscbi@epa.gov,

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

oaqpscbi@epa.gov

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

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

elemental Hg vapor

HQ hazard quotient

IGCC integrated gasification combined cycle

IPM Integrated Planning Model

lb Pounds

LEE low emitting EGU

MACT maximum achievable control technology

MATS Mercury and Air Toxics Standards

MM million

MW megawatt

NAICS North American Industry Classification System

NEEDS National Electric Energy Data System

NESHAP National Emission Standards for Hazardous Air Pollutants

OAQPS Office of Air Quality Planning and Standards

OMB Office of Management and Budget

PDF Portable Document Format

PM particulate matter

ppm parts per million

PV present value

RIA regulatory impact analysis

RTR residual risk and technology review

SC-CO

social cost of carbon

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

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.

B. Summary of the Major Provisions of the Regulatory Action

The 2012 MATS Final Rule established emission standards to limit emissions of HAP from coal- and oil-fired EGUs. The rule required that affected sources limit emissions of Hg, of non-Hg metal HAP (

e.g.,

chromium, nickel, arsenic, lead), acid gas HAP (

e.g.,

hydrogen chloride (HCl), hydrogen fluoride (HF), selenium dioxide (SeO

)), 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.

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.

77 FR 9310.

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.

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)

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).

Total PM is composed of the filterable PM fraction (fPM) and the condensible PM fraction. In establishing fPM as a surrogate for the non-Hg metal HAP, the EPA explained that most of the non-Hg metal HAP are present overwhelmingly in the fPM fraction. Selenium may be present in both the fPM fraction and/or as the acid gas, SeO

, in the condensible PM fraction. SeO

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.

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.

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.

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).

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

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.

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

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

startup as either the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Under the first option, startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use). In the second option, startup is defined as the period in which operation of an EGU is initiated for any purpose, and startup begins with either the firing of any fuel in an EGU for the purpose of producing electricity or useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes (other than the first-ever firing of fuel in a boiler following construction of the boiler) or for any other purpose after a shutdown event. Under the second option, startup ends 4 hours after the EGU generates electricity that is sold or used for any other purpose (including on-site use), or 4 hours after the EGU makes useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes, whichever is earlier. The EPA is proposing to remove the second option, which is currently being used by fewer than 10 EGUs as discussed in section V.D.1 of this preamble.

The EPA is not proposing to modify the HCl emission standard (nor the alternative sulfur dioxide (SO

) emission standard), which serves as a surrogate for all acid gas HAP (HCl, HF, SeO

) for existing coal-fired EGUs. An evaluation of recent compliance data for HCl and/or SO

emissions revealed that approximately two-thirds of coal-fired EGUs operate at or below the alternative SO

emission standard of 2.0E-01 lb SO

/MMBtu (SO

may be used as an alternative surrogate for acid gas HAP at coal-fired EGUs with operational flue gas desulfurization (FGD) systems and SO

CEMS). Approximately one-third of coal-fired EGUs have a SO

emission rate above the current SO

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

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.”

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.

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.

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

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)

EPA,

529 F.3d 1077, 1084 (D.C. Cir. 2008);

Association of Battery Recyclers, Inc.

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

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)

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

Fox Television Stations, Inc.,

556 U.S. 502, 515 (2009);

see also New Jersey

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

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.

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.

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,

within 8 years of promulgating the standards, to conduct the residual risk and technology reviews. Congress thus contemplated that well after the EPA determined the regulation of EGUs was appropriate and necessary and well after the EPA set initial standards in accordance with the floor and beyond-the-floor requirements in CAA section 112(d)(2), that at least every 8 years thereafter on a continuing basis, the EPA would review and revise those standards as necessary taking into account developments in practices, processes, and control technologies. The EPA has conducted over 100 technology reviews and has regularly updated emissions standards for HAP based upon the technology review.

3. Executive Order 13990

On January 20, 2021, President Biden signed Executive Order 13990, “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.” The Executive order, among other things, instructs the EPA to review the 2020 Final Action titled, “National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Reconsideration of Supplemental Finding and Residual Risk and Technology Review” (85 FR 31286; May 22, 2020) and consider publishing a notice of proposed rulemaking suspending, revising, or rescinding that action.

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

The NESHAP for the coal- and oil-fired EGU source category (commonly referred to as MATS) were initially promulgated on February 16, 2012 (77 FR 9304) (2012 MATS Final Rule), under title 40 part 63, subpart UUUUU. The MATS rule was amended on April 19, 2012 (77 FR 23399), to correct typographical errors and certain preamble text that was inconsistent with regulatory text; on April 24, 2013 (78 FR 24073), to update certain emission limits and monitoring and testing requirements applicable to new sources; on November 19, 2014 (79 FR 68777), to revise definitions for startup and shutdown and to finalize work practice standards and certain monitoring and testing requirements applicable during periods of startup and shutdown; and on April 6, 2016 (81 FR 20172), to correct conflicts between preamble and regulatory text and to clarify regulatory text. In addition, the electronic reporting requirements of the rule were amended on March 24, 2015 (80 FR 15510), to allow for the electronic submission of Portable Document Format (PDF) versions of certain reports until April 16, 2017, while the EPA's Emissions Collection and Monitoring Plan System (ECMPS) is revised to accept all reporting that is required by the rule, and on April 6, 2017 (82 FR 16736), and on July 2, 2018 (83 FR 30879), to extend the interim submission of PDF versions of reports through June 30, 2018, and July 1, 2020, respectively.

The MATS rule applies to coal- and oil-fired EGUs located at both major and area sources of HAP emissions. An existing affected source is the collection of coal- or oil-fired EGUs in a subcategory within a single contiguous area and under common control. A new affected source is each coal- or oil-fired EGU for which construction or reconstruction began after May 3, 2011. As previously stated in section II of this preamble, an EGU is a fossil fuel-fired combustion unit of more than 25 MW that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MW electric output to any utility power distribution system for sale is also considered an EGU. The MATS rule defines additional terms for determining rule applicability, including, but not limited to, definitions for “coal-fired electric utility steam generating unit,” “oil-fired electric utility steam generating unit,” and “fossil fuel-fired.” Certain types of electric generating units are not subject to 40 CFR part 63, subpart UUUUU: any unit designated as a major source stationary combustion turbine subject to subpart YYYY of 40 CFR part 63 and any unit designated as an area source stationary combustion turbine, other than an IGCC unit; any EGU that is not a coal- or oil-fired EGU and that meets the definition of a natural gas-fired EGU in 40 CFR 63.10042; any EGU greater than 25 MW that has the capability of combusting either coal or oil, but does not meet the definition of a coal- or oil-fired EGU because it did not fire sufficient coal or oil to satisfy the average annual heat input requirement set forth in the definitions for coal-fired and oil-fired EGUs in 40 CFR 63.10042; and any electric steam generating unit combusting solid waste (

i.e.,

a solid waste incineration unit) subject to standards established under sections 129 and 111 of the CAA.

For coal-fired EGUs, the rule established standards to limit emissions of Hg, acid gas HAP (

e.g.,

HCl, HF), non-Hg HAP metals (

e.g.,

nickel, lead, chromium), and organic HAP (

e.g.,

formaldehyde, dioxin/furan). Emission standards for HCl serve as a surrogate for the acid gas HAP, with an alternate standard for SO

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

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.

Table 1—Emission Limits for Existing Affected EGUs

Subcategory

Pollutant

Emission limit

Any coal-fired unit firing any rank of coal

a. fPM

3.0E-2 lb/MMBtu or 3.0E-1 lb/MWh.

Total non-Hg HAP metals

5.0E-5 lb/MMBtu or 5.0E-1 lb/GWh.

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.

2.0E-1 lb/MMBtu or 1.5 lb/MWh.

Coal-fired unit low rank virgin coal

c. Hg

1.2 lb/TBtu or 1.3E-2 lb/GWh.

Coal-fired unit low rank virgin coal

c. Hg

4.0 lb/TBtu or 4.0E-2 lb/GWh.

IGCC unit

a. fPM

4.0E-2 lb/MMBtu or 4.0E-1 lb/MWh.

Total non-Hg HAP metals

6.0E-5 lb/MMBtu or 5.0E-1 lb/GWh.

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—continental (excluding limited-use liquid oil-fired subcategory units)

a. fPM

3.0E-2 lb/MMBtu or 3.0E-1 lb/MWh.

Total HAP metals

8.0E-4 lb/MMBtu or 8.0E-3 lb/MWh.

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.

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-continental (excluding limited-use liquid oil-fired subcategory units)

a. fPM

3.0E-2 lb/MMBtu or 3.0E-1 lb/MWh.

Total HAP metals

6.0E-4 lb/MMBtu or 7.0E-3 lb/MWh.

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.

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 unit

a. fPM

8.0E-3 lb/MMBtu or 9.0E-2 lb/MWh.

Total non-Hg HAP metals

4.0E-5 lb/MMBtu or 6.0E-1 lb/GWh.

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.

3.0E-1 lb/MMBtu or 2.0 lb/MWh.

c. Hg

2.0E-1 lb/TBtu or 2.0E-3 lb/GWh.

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).

Alternate SO

limit may be used if the EGU has some form of FGD system and SO

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.

Affected sources are required to use the 40 CFR part 75-based ECMPS

for reporting emissions and related data either directly for EGUs that use Hg, HCl, HF, or SO

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).

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

and emissions test data collected from an ICR in 2010 (2010 ICR) when promulgating the 2011 Proposal.

See

https://www.epa.gov/airmarkets/power-sector-modeling-platform-v515.

See

https://ampd.epa.gov/ampd/.

See

https://cfpub.epa.gov/webfire; https://www.epa.gov/electronic-reporting-air-emissions/webfire.

See

https://www.eia.gov/electricity/data/eia923/.

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

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;

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)

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]

Number of

facilities

Maximum individual cancer risk

(in 1 million)

Based on . . .

Actual

emissions

level

Allowable emissions level

Population at increased risk of cancer ≥1-in-1 million

Based on . . .

Actual

emissions

level

Allowable emissions level

Annual cancer incidence

(cases per year)

Based on . . .

Actual

emissions

level

Allowable emissions level

Maximum chronic noncancer TOSHI

Based on . . .

Actual

emissions

level

Allowable emissions level

Maximum screening acute noncancer HQ

Based on

actual emissions level

332

193,000

636,000

0.04

0.1

0.2

0.4

REL

= 0.09

(arsenic)

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.

Maximum individual excess lifetime cancer risk due to HAP emissions from the source category.

Maximum target organ-specific hazard index (TOSHI). The target organ systems with the highest TOSHI for the source category are respiratory and immunological.

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.

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.

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

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

industrial pond, and, therefore, was removed from the assessment.

Methylmercury emissions from two facilities exceeded the Tier 2 screen for a surface soil NOAEL for avian ground insectivores (woodcock) benchmark by a maximum screening value of 2. Other surface soil benchmarks for methylmercury, such as the NOAEL for mammalian insectivores and the threshold level for the invertebrate community, were not exceeded. Given the low Tier 2 maximum screening value of 2 for methylmercury, and the fact that only the most protective benchmark was exceeded, a Tier 3 environmental risk screen was not conducted for methylmercury.

For lead, we did not estimate any exceedances of the secondary lead NAAQS. For HCl and HF, the average modeled concentration around each facility (

i.e.,

the average concentration of all off-site data points in the modeling domain) did not exceed any ecological benchmark. In addition, each individual modeled concentration of HCl and HF (

i.e.,

each off-site data point in the modeling domain) was below the ecological benchmarks for all facilities.

Based on the results of the environmental risk screening analysis, we did not expect an adverse environmental effect as a result of HAP emissions from the coal- and oil-fired EGU source category.

5. Facility-Wide Risk Results

An assessment of risk from facility-wide emissions was performed to provide context for the source category risks. Based on facility-wide emissions estimates developed using the same estimates of actual emissions for emissions sources in the source category, and emissions data from the 2014 National Emissions Inventory (NEI) (version 2) for the sources outside the source category, the estimated cancer MIR was 9-in-1 million, and nickel emissions from oil-fired EGUs were the major contributor to the risk. The total estimated cancer incidence based on facility-wide emissions was 0.04 excess cancer cases per year, or one excess case in every 25 years. Approximately 203,000 people were estimated to have cancer risks at or above 1-in-1 million from HAP emitted from all sources at the facilities in this source category. The estimated maximum chronic noncancer TOSHI posed by facility-wide emissions was 0.2 (respiratory), driven by emissions of nickel and cobalt from oil-fired EGUs. No one was exposed to TOSHI levels above 1 based on facility-wide emissions. These results were very similar to those based on actual emissions from the source category because there was not significant collocation of other sources with EGUs.

6. Decisions Regarding Risk Acceptability, Ample Margin of Safety, and Adverse Environmental Effect

In determining whether residual risks are acceptable for this source category in accordance with CAA section 112, the EPA considered all available health information and risk estimation uncertainty. The results of the risk analysis indicated that both the actual and allowable inhalation cancer risks to the individual most exposed were below 100-in-1 million, which is the presumptive limit of acceptability. Also, the highest chronic noncancer TOSHI and the highest acute noncancer HQ were below 1, indicating low likelihood of adverse noncancer effects from inhalation exposures. There were also low risks associated with ingestion, with the highest cancer risk being less than 50-in-1 million based on a conservative screening assessment, and the highest noncancer hazard being less than 1 based on a site-specific multipathway assessment. Considering this information, the EPA determined in 2020 that the residual risks of HAP emissions from the coal- and oil-fired EGU source category were acceptable.

We then considered whether the current standards provided an ample margin of safety to protect public health and whether more stringent standards were necessary to prevent an adverse environmental effect by taking into consideration costs, energy, safety, and other relevant factors. In determining whether the standards provided an ample margin of safety to protect public health, we examined the same risk factors that we investigated for our acceptability determination and we also considered the costs, technological feasibility, and other relevant factors related to emissions control options that might reduce risk associated with emissions from the source category. In our analysis, we considered the results of the technology review, risk assessment, and other aspects of our MACT rule review to determine whether there were any cost-effective controls or other measures that would reduce emissions further to provide an ample margin of safety. The risk analysis indicated that the risks from the source category are low for both cancer and noncancer health effects. Thus, we determined in 2020 that the current MATS requirements provided an ample margin of safety to protect public health in accordance with CAA section 112.

Based on the results of our environmental risk screening assessment, we also determined in 2020 that more stringent standards were not necessary to prevent an adverse environmental effect.

B. Summary of the 2020 Technology Review

Pursuant to CAA section 112(d)(6), the EPA conducted a technology review (2020 Technology Review) in the 2020 Final Action, which focused on identifying and evaluating developments in practices, processes, and control technologies for the emission sources in the source category that occurred since the MATS rule was promulgated. Control technologies typically used to minimize emissions of pollutants that have numeric emission limits under the MATS rule include electrostatic precipitators (ESPs) and fabric filters (FFs) for control of non-Hg HAP metals; wet scrubbers and dry scrubbers for control of acid gases (SO

, 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

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).

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.

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.

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).

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

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

EPA,

795 F3d 1, 11-12 (D.C. Cir 2015).

For example, in the 2014 technology review for Ferroalloys Production, the EPA found that PM emission levels were well below the MACT standards established in the original 1999 NESHAP. These findings “demonstrate[d] that the add-on emission control technology (venturi scrubber, positive pressure FF, negative pressure FF) used to control emissions from the furnaces are quite effective in reducing PM (used as a surrogate for metal HAP) and that all of the facilities have emissions well below the current limits.” See 79 FR 60271 (October 6, 2014). Therefore, the EPA determined that it was appropriate to revise the PM limits for furnaces. Similarly, in the 2017 technology review for Wool Fiberglass Manufacturing, the EPA found that formaldehyde emissions had decreased by approximately 95 percent since promulgation of the MACT Standards in the original 1999 NESHAP due to “(1) Improvements in control technology (

e.g.,

improved bag materials, replacement of older baghouses) and (2) the use of electrostatic precipitators,” as well as upgraded pollution prevention practices (

i.e.,

development and use non-phenol-formaldehyde binders). See 82 FR 40975 (August 29, 2017). Although the EPA declined to lower the formaldehyde limit in this case, it was only because the source category had already upgraded the technology (

i.e.,

non-phenol-formaldehyde binders), resulting in major sources becoming area sources that were no longer subject to the NESHAP.

As in those cases, here many commenters provided data showing that control technologies are more widely used, more effective, and cheaper than at the time EPA promulgated MATS. For example, commenters explained that, due to the many options that are available to control Hg emissions (

e.g.,

control equipment, activated carbon, reagents and sorbents, as well as fuel blending, non-carbon or improvements to carbon-based solvents, wet and dry scrubber additives, oxidizing coal additives, and existing control optimization) and a “robust industry of technology suppliers that drive innovation through internal research and development,” the costs of compliance for end users has decreased over time (Docket ID No. EPA-HQ-OAR-2018-0794-4940). Similarly, commenters noted that the large number of EGUs that are outperforming the current Hg and fPM standards would support a decision to revise the standards (Docket ID No. EPA-HQ-OAR-2018-0794-4962). Specific comments leading to our proposed decisions are detailed below, and a summary of this technology review is provided in the memorandum “2023 Technology Review for the Coal- and Oil-Fired EGU Source Category,” which can be found in Docket ID No. EPA-HQ-OAR-2018-0794. Based on our review of the 2020 Technology Review, the EPA is proposing to revise the current standards as discussed below.

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

This section summarizes the EPA's changes to the 2020 technology review and proposed decisions. Where the EPA has identified developments in practices, processes, or controls, we analyzed the technical feasibility, estimated costs, energy implications, and non-air environmental impacts, as well as the potential emission reductions associated with each development. In addition, we reviewed a variety of data sources in our investigation of developments in practices, processes, or controls. See section III of this preamble for information on the specific data sources that were reviewed as part of the technology review.

1. Filterable Particulate Matter (fPM) Emission Limit (as a Surrogate for Non-Hg HAP Metals)

As described in section III of this preamble, EGUs in six subcategories are subject to numeric emission limits for each of the individual non-Hg metal HAP. Alternatively, certain affected EGUs can choose to demonstrate compliance with an alternative total non-Hg metal HAP emission limit. Finally, affected EGUs can demonstrate compliance with an alternative fPM emission limit that serves as a surrogate for total non-Hg metal HAP. The EPA chose fPM as a surrogate for non-Hg metal HAP in the original MATS rulemaking because non-Hg metal HAP are predominantly a component of the filterable fraction of total PM (which is comprised of a filterable fraction and a condensable fraction), and control of fPM results in co-reduction of non-Hg metal HAP (with the exception of Se, which may be present in the filterable fraction or in the condensable fraction as the acid gas, SeO

). 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

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.

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.

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

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.

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.

EP24AP23.000

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.

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.

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.

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.

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

submitted to the EPA in response to the 2020 Proposal presented an updated UPL (using 2019 data compiled by Natural Resources Defense Council (NRDC)

) 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.

See

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

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).

Table 3—Summary of Cost Effectiveness Analysis for Three Potential

PM Emission Limits

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

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).

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.

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

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.

(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.

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

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

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.

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.

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

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,

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,

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.

See the supporting statement 2137ss06.docx in ICR reference number 201202-2060-005 at OMB Control Number 2060-0567.

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

Data source

PM CEMS type

One time costs,

Instrument and installation

Other initial costs

Annual costs,

Capital

recovery

Operation and maintenance

Audits

Other annual costs

EUAC,

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

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

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.

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.

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,

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.

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.

See

A Qualitative Aerosol Generator Designed for Particulate Matter (PM) Continuous Emissions Monitoring Systems (CEMS) Calibration,

available at

www.epri.com/research/products/1017574.

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.

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

) in the high temperature regions of the boiler. Hg

vapor is difficult to capture because it is typically nonreactive and insoluble in aqueous solutions. However, under certain conditions, the Hg

vapor in the flue gas can be oxidized to divalent Hg (Hg

). The Hg

can bind to the surface of solid particles (

e.g.,

fly ash) in the flue gas stream, often referred to as “particulate bound Hg” (Hg

), and be removed in a downstream PM control device. Oxidized Hg compounds can also be soluble and can be removed in a wet scrubber. The presence of chlorine in gas-phase equilibrium favors the formation of mercuric chloride (HgCl

) at flue gas cleaning temperatures. However, Hg

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

, Hg

compounds, and Hg

. 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

compounds, typically HgCl

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

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

Some coal-fired power plants—especially those firing bituminous coal—achieve some level of Hg emissions control using existing equipment that was installed to remove other pollutants, including PM, SO

, and nitrogen oxides (NO

). Particulate-bound Hg (Hg

) is effectively removed along with PM in PM control equipment such as FFs and ESPs. Soluble Hg

compounds (such as HgCl

) can be effectively captured in wet FGD systems. And, while a selective catalytic reduction (SCR) system that has been installed for NO

control does not itself capture Hg, it can under the right conditions enhance the oxidation of Hg

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

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

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.”

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

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

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.

In 2017, after full implementation of the MATS rule, the EPA estimated Hg emissions had been reduced to 4 tons, an 86 percent decrease.

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.

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.

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).

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.

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

Rank

EGU

Fuel

2021 Hg

emissions

(lb)

State

Coal Creek 2

Lignite

181.8

Coal Creek 1

Lignite

175.6

Oak Grove 2

Lignite

149.8

Martin Lake 3

Lignite/Subbituminous

134.4

Oak Grove 1

Lignite

112.7

Martin Lake 2

Lignite/Subbituminous

111.0

Milton R Young B2

Lignite

103.1

Martin Lake 1

Lignite/Subbituminous

100.7

Antelope Valley B2

Lignite

89.8

Coyote B1

Lignite

79.9

H W Pirkey Power Plant 1 *

Lignite/Subbituminous

71.1

Antelope Valley B1

Lignite

69.6

San Miguel SM-1

Lignite

64.6

Sandy Creek Energy Station S01

Subbituminous

53.5

Limestone LIM2

Lignite/Subbituminous

52.5

Milton R Young B1

Lignite

52.4

Comanche 3

Subbituminous

50.3

Leland Olds 2

Lignite

50.1

James H Miller Jr 3

Subbituminous

42.9

Labadie 2

Subbituminous

42.5

* 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

to provide information on their control configuration for Hg and for other air pollutants (

e.g.,

criteria pollutants such as PM, NO

, SO

). 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.

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

Plant name

State

Capacity

(MW)

Firing

Control configuration

Hg control description

Hg control

Antelope Valley #1

Antelope Valley #2

450

tangent

ACI + SDA + FF

ACI + SDA + FF.

Does not use activated carbon as its sorbent, instead injects a liquid sorbent to the scrubber. The facility stopped using refined coal in December 2021

Nalco non-carbon, non-halogenated liquid sorbent added to dry scrubber; M-Sorb additive (bromide).

Coal Creek #1

Coal Creek #2

574

573

tangent

ACI + ESPC + WFGD

ACI + ESPC + WFGD.

Information not collected in the CAA 114 request.

Coyote

429

cyclone

ACI + SDA + FF

Information not collected in the CAA 114 request.

Leland Olds #1

222

wall

SNCR + ACI +

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