38508 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
ENVIRONMENTAL PROTECTION 
AGENCY 
40 CFR Part 63 
[EPA–HQ–OAR–2018–0794; FRL–6716.3– 
02–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 : Final rule. 
SUMMARY : This action finalizes 
amendments to the national emission standards for hazardous air pollutants (NESHAP) for the Coal- and Oil-Fired Electric Utility Steam Generating Units (EGUs) source category. These final amendments are the result of the EPA’s review of the 2020 Residual Risk and Technology Review (RTR). The changes, which were proposed under the technology review in April 2023, include amending the filterable particulate matter (fPM) surrogate emission standard for non-mercury metal hazardous air pollutants (HAP) for existing coal-fired EGUs, the fPM emission standard compliance demonstration requirements, and the mercury (Hg) emission standard for lignite-fired EGUs. Additionally, the EPA is finalizing a change to the definition of ‘‘startup.’’ The EPA did not propose, and is not finalizing, any changes to the 2020 Residual Risk Review. 
DATES : This final rule is effective on July 
8, 2024. The incorporation by reference of certain material listed in the rule was approved by the Director of the Federal Register as of April 16, 2012. 
ADDRESSES : The U.S. Environmental 
Protection Agency (EPA) has established a docket for this action under Docket ID No. EPA–HQ–OAR–2018–0794. All documents in the docket are listed on the https://www.regulations.gov 
website. Although listed, some information is not publicly available, e.g., Confidential Business Information 
or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through https://www.regulations.gov, or in hard copy at 
the EPA Docket Center, WJC West Building, Room Number 3334, 1301 Constitution Ave. NW, Washington, DC. The Public Reading Room hours of operation are 8:30 a.m. to 4:30 p.m. Eastern Standard Time (EST), Monday through Friday. The telephone number for the Public Reading Room is (202) 566–1744, and the telephone number for the EPA Docket Center is (202) 566– 1742. 
FOR FURTHER INFORMATION CONTACT : For 
questions about this final action contact Sarah Benish, Sector Policies and Programs Division (D243–01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, P.O. Box 12055, Research Triangle Park, North Carolina 27711; telephone number: (919) 541–5620; and email address: benish.sarah@epa.gov. 
SUPPLEMENTARY INFORMATION : 
Preamble acronyms and 
abbreviations. 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: 
APH air preheater 
Btu British Thermal Units CAA Clean Air Act CEMS continuous emission monitoring 
system 
EGU electric utility steam generating unit 
EIA Energy Information Administration ESP electrostatic precipitator FF fabric filter FGD flue gas desulfurization fPM filterable particulate matter GWh gigawatt-hour HAP hazardous air pollutant(s) HCl hydrogen chloride HF hydrogen fluoride Hg mercury Hg
0elemental Hg vapor 
Hg2+divalent Hg 
HgCl 2mercuric chloride 
Hgpparticulate bound Hg 
HQ hazard quotient ICR Information Collection Request IGCC integrated gasification combined 
cycle 
IPM Integrated Planning Model IRA Inflation Reduction Act lb pounds LEE low emitting EGU MACT maximum achievable control 
technology 
MATS Mercury and Air Toxics Standards MMacf million actual cubic feet MMBtu million British thermal units of 
heat input 
MW megawatt NAICS North American Industry 
Classification System 
NESHAP national emission standards for 
hazardous air pollutants 
NO
Xnitrogen oxides 
NRECA National Rural Electric Cooperative 
Association 
OMB Office of Management and Budget PM particulate matter PM
2.5fine particulate matter PM CEMS particulate matter continuous 
emission monitoring systems 
REL reference exposure level 
RFA Regulatory Flexibility Act RIA Regulatory Impact Analysis 
RIN Regulatory Information Number RTR residual risk and technology review SC–CO
2social cost of carbon 
SO 2sulfur dioxide 
TBtu trillion British thermal units of heat 
input 
tpy tons per year UMRA Unfunded Mandates Reform Act WebFIRE Web Factor Information Retrieval 
System 
Background information. On April 24, 
2023, the EPA proposed revisions to the 
Coal- and Oil-Fired EGU NESHAP based on our review of the 2020 RTR. In this action, we are finalizing revisions to the rule, commonly known as the Mercury and Air Toxics Standards (MATS). We summarize some of the more significant comments regarding the proposed rule that were received during the public comment period and provide our responses in this preamble. A summary of all other public comments on the proposal and the EPA’s responses to those comments is available in National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review Proposed Rule Response to Comments, Docket ID No. EPA–HQ– 
OAR–2018–0794. A ‘‘track changes’’ version of the regulatory language that incorporates the changes in this action is available in the docket. 
Organization of this document. The 
information in this preamble is organized as follows: 
I. General Information 
A. Executive Summary 
B. Does this action apply to me? C. Where can I get a copy of this document 
and other related information? 
D. Judicial Review and Administrative 
Reconsideration 
II. Background 
A. What is the authority for this action? B. What is the Coal- and Oil-Fired EGU 
source category and how does the NESHAP regulate HAP emissions from the source category? 
C. Summary of the 2020 Residual Risk 
Review 
D. Summary of the 2020 Technology 
Review 
E. Summary of the EPA’s Review of the 
2020 RTR and the 2023 Proposed Revisions to the NESHAP 
III. What is included in this final rule? 
A. What are the final rule amendments 
based on the technology review for the Coal- and Oil-Fired EGU source category? 
B. What other changes have been made to 
the NESHAP? 
C. What are the effective and compliance 
dates of the standards? 
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1The term ‘‘major source’’ means any stationary 
source or group of stationary sources located within 
a contiguous area and under common control that emits or has the potential to emit considering controls, in the aggregate, 10 tons per year or more of any hazardous air pollutant or 25 tons per year or more of any combination of hazardous air pollutants. 42 U.S.C. 7412(a)(1). IV. What is the rationale for our final 
decisions and amendments to the 
filterable PM (as a surrogate for non-Hg HAP metals) standard and compliance options from the 2020 Technology Review? 
A. What did we propose pursuant to CAA 
Section 112(d)(6) for the Coal- and Oil- Fired EGU source category? 
B. How did the technology review change 
for the Coal- and Oil-Fired EGU source category? 
C. What key comments did we receive on 
the filterable PM and compliance options, and what are our responses? 
D. What is the rationale for our final 
approach and decisions for the filterable PM (as a surrogate for non-Hg HAP metals) standard and compliance demonstration options? 
V. What is the rationale for our final 
decisions and amendments to the Hg 
emission standard for lignite-fired EGUs from review of the 2020 Technology Review? 
A. What did we propose pursuant to CAA 
section 112(d)(6) for the lignite-fired EGU subcategory? 
B. How did the technology review change 
for the lignite-fired EGU subcategory? 
C. What key comments did we receive on 
the Hg emission standard for lignite-fired EGUs, and what are our responses? 
D. What is the rationale for our final 
approach and decisions for the lignite- fired EGU Hg standard? 
VI. What is the rationale for our other final 
decisions and amendments from review of the 2020 Technology Review? 
A. What did we propose pursuant to CAA 
section 112(d)(6) for the other NESHAP requirements? 
B. How did the technology review change 
for the other NESHAP requirements? 
C. What key comments did we receive on 
the other NESHAP requirements, and what are our responses? 
D. What is the rationale for our final 
approach and decisions regarding the other NESHAP requirements? 
VII. Startup Definition for the Coal- and Oil- 
Fired EGU Source Category 
A. What did we propose for the Coal- and 
Oil-Fired EGU source category? 
B. How did the startup provisions change 
for the Coal- and Oil-Fired EGU source category? 
C. What key comments did we receive on 
the startup provisions, and what are our responses? 
D. What is the rationale for our final 
approach and final decisions for the startup provisions? 
VIII. What other key comments did we 
receive on the proposal? 
IX. Summary of Cost, Environmental, and 
Economic Impacts and Additional Analyses Conducted 
A. What are the affected facilities? 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? 
X. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory 
Planning and Review and Executive 
Order 14094: Modernizing 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) and 1 CFR Part 51 
J. Executive Order 12898: Federal Actions 
To Address Environmental Justice in Minority Populations and Low-Income Populations and Executive Order 14096: Revitalizing Our Nation’s Commitment to Environmental Justice for All 
K. Congressional Review Act (CRA) 
I. General Information 
A. Executive Summary 1. Background and Purpose of the 
Regulatory Action 
Exposure to hazardous air pollutants 
(‘‘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. These adverse effects can be particularly acute for communities living near sources of HAP. 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 based on maximum achievable control technology (known as ‘‘MACT’’ standards) for major sources
1of 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 nonair quality health and environmental impacts and energy requirements, determines is achievable.’’ 42 U.S.C. 7412(d)(2). The EPA is further required to ‘‘review, and revise’’ those standards every 8 years 
‘‘as necessary (taking into account developments in practices, processes, and control technologies).’’ Id. 7412(d)(6). 
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 two parts: (1) a finding that it is not appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112; and (2) the RTR for the 2012 MATS Final Rule. 
The EPA reviewed both parts of the 
2020 Final Action. The results of the EPA’s review of the first part, finding it is appropriate and necessary to regulate EGUs under CAA section 112, 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 HAP emissions, improved methods of operation, and risk-related information to further inform the EPA’s review of the second part, the 2020 MATS RTR. The EPA proposed amendments to the RTR on April 24, 2023 (88 FR 24854) (2023 Proposal) and 
this action finalizes those amendments and presents the final results of the EPA’s review of the MATS RTR. 
2. Summary of Major Provisions of the 
Regulatory Action 
Coal- and oil-fired EGUs remain one 
of the largest domestic emitters of Hg and many other HAP, including many of the non-Hg HAP metals—including lead, arsenic, chromium, nickel, and cadmium—and hydrogen chloride (HCl). Exposure to these HAP, at certain levels and duration, is associated with a variety of adverse health effects. In the 2012 MATS Final Rule, the EPA established numerical standards for Hg, non-Hg HAP metals, and acid gas HAP emissions from coal- and oil-fired EGUs. The EPA also established work practice standards for emissions of organic HAP. To address emissions of non-Hg HAP 
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2The ten non-Hg HAP metals are antimony, 
arsenic, beryllium, cadmium, chromium, cobalt, 
lead, manganese, nickel, and selenium. 
3In order to qualify for fPM LEE status, an EGU 
must demonstrate that its fPM emission rate is 
below 50 percent of standard (or 0.015 lb/MMBtu) from quarterly stack tests for 3 consecutive years. Once a source achieves LEE status for fPM, the source must conduct stack testing every 3 years to demonstrate that its emission rate remains below 50 percent of the standard. 4The emission limits for the individual non-Hg 
HAP metals and the total non-Hg HAP metals have been reduced by two-thirds, consistent with the revision of the fPM emission limit from 0.030 lb/ MMBtu to 0.010 lb/MMBtu. metals, the EPA established individual 
emission limits for each of the 10 non- Hg HAP metals
2emitted from coal- and 
oil- fired EGUs. Alternatively, affected sources could meet an emission standard for ‘‘total non-Hg HAP metals’’ by summing the emission rates of each of the non-Hg HAP metals or meet a fPM emission standard as a surrogate for the non-Hg HAP metals. For existing coal- fired EGUs, almost every unit has chosen to demonstrate compliance with the non-Hg HAP metals surrogate fPM emission standard of 0.030 pounds (lb) of fPM per million British thermal units of heat input (lb/MMBtu). 
Pursuant to CAA section 112(d)(6), 
the EPA reviewed developments in the costs of control technologies, and the effectiveness of those technologies, as well as the costs of meeting a fPM emission standard that is more stringent than 0.030 lb/MMBtu and the other statutory factors. Based on that review, the EPA is finalizing, as proposed, a revised non-Hg HAP metal surrogate fPM emission standard for all existing coal-fired EGUs of 0.010 lb/MMBtu. This strengthened standard will ensure that the entire fleet of coal-fired EGUs is performing at the fPM pollution control levels currently achieved by the vast majority of regulated units. The EPA further concludes that it is the lowest level currently compatible with the use of PM CEMS for demonstrating compliance. 
Relatedly, the EPA is also finalizing a 
revision to the requirements for demonstrating compliance with the revised fPM emission standard. Currently, affected EGUs that do not qualify for the low emitting EGU (LEE) program for fPM
3can demonstrate 
compliance with the fPM standard either by conducting quarterly performance testing (i.e., quarterly stack 
testing) or by using particulate matter (PM) continuous emission monitoring systems (PM CEMS). PM CEMS confer significant benefits, including increased transparency regarding emissions performance for sources, regulators, and the surrounding communities; and real- time identification of when control technologies are not performing as expected, allowing for quicker repairs. After considering updated information on the costs for quarterly performance testing compared to the costs of PM CEMS and the measurement capabilities of PM CEMS, as well as the many benefits of using PM CEMS, the EPA is finalizing, as proposed, a requirement that all coal- and oil-fired EGUs demonstrate compliance with the revised fPM emission standard by using PM CEMS. As the EPA explained in the 2023 Proposal, by requiring facilities to use PM CEMS, the current compliance method for the LEE program becomes superfluous since LEE is an optional program in which stack testing occurs infrequently, and the revised fPM limit is below the current fPM LEE program limit. Therefore, the EPA is finalizing, as proposed, the removal of the fPM LEE program. 
Based on comments received during 
the public comment period, the EPA is not removing, but instead revising the alternative emission limits for the individual non-Hg HAP metals such as lead, arsenic, chromium, nickel, and cadmium and for the total non-Hg HAP metals proportional to the finalized fPM emission limit of 0.010 lb/MMBtu.
4 
Owners and operators of EGUs seeking to use these alternative standards must request and receive approval to use a HAP metal continuous monitoring system (CMS) as an alternative test method under 40 CFR 63.7(f). 
The EPA is also finalizing, as 
proposed, a more protective Hg emission standard for existing lignite- fired EGUs, requiring that such lignite- fired EGUs meet the same Hg emission standard as EGUs firing other types of coal (i.e., bituminous and 
subbituminous), which is 1.2 lb of Hg per trillion British thermal units of heat input (lb/TBtu) or an alternative output- based standard of 0.013 lb per gigawatt- hour (lb/GWh). Finally, the EPA is finalizing, as proposed, the removal of the second option for defining the startup period for MATS-affected EGUs. 
The EPA did not propose and is not 
finalizing modifications to the HCl emission standard (nor the alternative sulfur dioxide (SO
2) emission standard), 
which serves as a surrogate for all acid 
gas HAP (HCl, hydrogen fluoride (HF), selenium dioxide (SeO
2)) for existing 
coal-fired EGUs. The EPA proposed to require PM CEMS for existing integrated gasification combined cycle (IGCC) EGUs but is not finalizing this requirement due to technical issues calibrating CEMS on these types of EGUs and the related fact that fPM emissions from IGCCs are very low. 
In establishing the final standards, as 
discussed in detail in sections IV., V., VI., and VII. of this preamble, the EPA considered the statutory direction and factors laid out by Congress in CAA section 112. Separately, pursuant to Executive Order 12866 and Executive Order 14904, the EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, Regulatory Impact Analysis for the Final 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–24–005), is available in the docket, and is briefly summarized in sections I.A.3. and IX. of this preamble. 
3. Costs and Benefits 
In accordance with Executive Order 
12866 and 14094, the EPA prepared a 
Regulatory Impact Analysis (RIA). The RIA presents estimates of the emission, cost, and benefit impacts of this final rulemaking for the 2028 to 2037 period; those estimates are summarized in this section. 
The power industry’s compliance 
costs are represented in the RIA as the projected change in electric power 
generation costs between the baseline and final rule scenarios. The quantified emission estimates presented in the RIA include changes in pollutants directly covered by this rule, such as Hg and non-Hg HAP metals, and changes in other pollutants emitted from the power sector due to the compliance actions projected under this final rule. The cumulative projected national-level emissions reductions over the 2028 to 2037 period under the finalized requirements are presented in table 1. The supporting details for these estimates can be found in the RIA. 
BILLING CODE 6560–50–P 
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5See section II.B.2. for discussion of the public 
health and environmental hazards associated with HAP emissions from coal- and oil-fired EGUs and 
discussion on the limitations to monetizing and quantifying benefits from HAP reductions. See also National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Revocation of the 2020 Reconsideration and Affirmation of the Appropriate and Necessary Supplemental Finding, 88 FR 13956, 13970–73 (March 6, 2023). 
The EPA expects that emission 
reductions under the final rulemaking 
will result in reduced exposure to Hg and non-Hg HAP metals. The EPA also projects health benefits due to improvements in particulate matter with a diameter of 2.5 micrometers or less (PM
2.5) and ozone and climate benefits 
from reductions in carbon dioxide (CO 2) 
emissions. The EPA also anticipates benefits from the increased transparency to the public, the assurance that standards are being met continuously, and the accelerated identification of anomalous emissions due to requiring 
PM CEMS in this final rule. 
The EPA estimates negative net 
monetized benefits of this rule (see table 2 below). However, the benefit estimates informing this result represent only a partial accounting of the potential benefits of this final rule. Several categories of human welfare and climate benefits are unmonetized and are thus 
not directly reflected in the quantified net benefit estimates (see section IX.B. in this preamble and section 4 of the RIA for more details). In particular, estimating the economic benefits of reduced exposure to HAP generally has proven difficult for a number of reasons: it is difficult to undertake epidemiologic studies that have sufficient power to quantify the risks associated with HAP exposures experienced by U.S. populations on a daily basis; data used to estimate exposures in critical microenvironments are limited; and there remains insufficient economic research to support valuation of HAP 
benefits made even more challenging by the wide array of HAP and possible HAP effects.
5In addition, due to data limitations, the EPA is also unable to 
quantify potential emissions impacts or monetize potential benefits from continuous monitoring requirements. 
The present value (PV) and equivalent 
annual value (EAV) of costs, benefits, and net benefits of this rulemaking over the 2028 to 2037 period in 2019 dollars are shown in table 2. In this table, results are presented using a 2 percent discount rate. Results under other discount rates and supporting details for the estimates can be found in the RIA. 
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ER07MY24.065</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 1. Cumulative Projected Emissions Reductions under the Final Rule, 2028 to 2037a 
Pollutant Emissions Reductions 
Hg (pounds) 9,500 
PM2.s (tons) 5,400 
S02 (tons) 770 
NOx (tons) 220 
CO2 (thousand tons) 650 
non-Hg HAP metals (tons)b 49 
a Values rounded to two significant figures. 
b The non-Hg HAP metals are antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, 
manganese, nickel, and selenium. 38512 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
BILLING CODE 6560–50–C 
The EPA notes that analysis of such 
impacts is distinct from the 
determinations finalized in this action under CAA section 112, which are based on the statutory factors the EPA discusses in section II.A. and sections IV. through VII. below. 
B. Does this action apply to me? 
Regulated entities. The source 
category that is the subject of this action 
is coal- and oil-fired EGUs regulated by NESHAP under 40 CFR part 63, subpart UUUUU, commonly known as MATS. The North American Industry Classification System (NAICS) codes for the coal- and oil-fired EGU source category are 221112, 221122, and 921150. This list of NAICS codes is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by the final action for the source category listed. To determine whether your facility is affected, you should examine the applicability criteria in the appropriate NESHAP. If you have any questions regarding the applicability of any aspect of this NESHAP, please contact the appropriate person listed in the preceding 
FOR FURTHER INFORMATION  
CONTACT section of this preamble. C. Where can I get a copy of this 
document and other related information? 
In addition to being available in the 
docket, an electronic copy of this final action will also be available on the 
internet. Following signature by the EPA Administrator, the EPA will post a copy of this final action at: https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics- standards. Following publication in the 
Federal Register, the EPA will post the Federal Register version and key technical documents at this same website. 
Additional information is available on 
the RTR website at https://www.epa.gov/stationary-sources-air- pollution/risk-and-technology-review- national-emissions-standards-hazardous. This information includes 
an overview of the RTR program and links to project websites for the RTR source categories. 
D. Judicial Review and Administrative 
Reconsideration 
Under CAA section 307(b)(1), judicial 
review of this final action is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit (the Court) by July 8, 2024. Under CAA section 307(b)(2), the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce the requirements. 
Section 307(d)(7)(B) of the CAA 
further provides that only an objection to a rule or procedure that was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review. This section also provides a mechanism for the EPA to reconsider the rule if the person raising an objection can demonstrate to the Administrator that it was impracticable to raise such objection within the period for public comment or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule. Any person seeking to make such a demonstration should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, WJC South Building, 1200 Pennsylvania Ave., NW, Washington, DC 20460, with a copy to both the person(s) listed in the preceding 
FOR FURTHER INFORMATION  
CONTACT section, and the Associate 
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ER07MY24.066</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 2. Projected Benefits, Costs, and Net Benefits under the Final Rule, 2028 to 2037 
(millions of 2019 dollars, discounted to 2023t 
2% Discount Rate 
PV EAV 
Ozone-and PM2.s-related 300 33 Health Benefits 
Climate Benefitsb 130 14 
Compliance Costs 860 96 
Net Benefitsc -440 -49 
Benefits from reductions of about 900 to 1000 pounds of Hg 
annually 
Benefits from reductions of about 4 to 7 tons of non-Hg 
Non-Monetized Benefits HAP metals annually 
Benefits from the increased transparency, compliance 
assurance, and accelerated identification of anomalous 
emission anticipated from requiring PM CEMS 
a Values rounded to two significant figures. Totals may not appear to add correctly due to 
rounding. 
b Climate benefits are based on reductions in CO2 emissions and are calculated using three 
different estimates of the SC-CO2 (under 1.5 percent, 2.0 percent, and 2.5 percent near-term 
Ramsey discount rates). For the presentational purposes of this table, we show the climate 
benefits associated with the SC-CO2 at the 2 percent near-term Ramsey discount rate. 
c Several categories of benefits remain unmonetized and are thus not reflected in the table. 38513 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
6Specifically, 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. 42 U.S.C. 7412(d)(3). 
For new sources MACT shall not be less stringent than the emission control that is achieved in practice by the best controlled similar source. Id. 
7For 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. General Counsel for the Air and 
Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave. NW, Washington, DC 20460. 
II. Background A. What is the statutory authority for 
this action? 
1. Statutory Language 
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 major sources control HAP emissions at the level achieved by the best-performing sources, referred to as the 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 the emission standards should be revised 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 primary subject of this final rule. 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 nonair quality health and environmental impacts and energy requirements, determines is achievable.’’ (emphasis added). These standards are commonly referred to as MACT standards. CAA section 112(d)(3) establishes a minimum control level for MACT standards, known as the MACT ‘‘floor.’’
6In 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.
7 
For categories of major sources and 
any area source categories subject to MACT standards, the next stage in standard-setting focuses on identifying and addressing any remaining (i.e., ‘‘residual’’) risk pursuant to CAA section 112(f)(2). The residual risk review requires the EPA to update standards if needed to provide an ample margin of safety to protect public health. 
Concurrent with that review, and then 
at least every 8 years thereafter, CAA section 112(d)(6) requires the EPA to review standards promulgated under CAA section 112 and revise them ‘‘as necessary (taking into account developments in practices, processes, and control technologies).’’ See Portland Cement Ass’n v. EPA, 665 F.3d 177, 189 
(D.C. Cir. 2011) (‘‘Though EPA must review and revise standards ‘no less often than every eight years,’ 42 U.S.C. 7412(d)(6), nothing prohibits EPA from reassessing its standards more often.’’). In conducting this review, which we call the ‘‘technology review,’’ the EPA is not required to recalculate the MACT floors that were established in earlier rulemakings. Natural Resources Defense 
Council (NRDC) v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008); Association of Battery Recyclers, Inc. v. EPA, 716 F.3d 
667 (D.C. Cir. 2013). The EPA may consider cost in deciding whether to revise the standards pursuant to CAA section 112(d)(6). See e.g., Nat’l Ass’n for Surface Finishing, v. EPA, 795 F.3d 
1, 11 (D.C. Cir. 2015). The EPA is required to address regulatory gaps, such as missing MACT standards for listed air toxics known to be emitted from the source category. Louisiana Environmental Action Network (LEAN) v. EPA, 955 F.3d 1088 (D.C. Cir. 2020). 
The residual risk review and the technology review are distinct requirements and are both mandatory. 
In this action, the EPA is finalizing 
amendments to the MACT standards based on two independent sources of authority: (1) its review of the 2020 Final Action’s risk and technology review pursuant to the EPA’s statutory authority under CAA section 112, and (2) the EPA’s inherent authority to reconsider previous decisions and to revise, replace, or repeal a decision to the extent permitted by law and supported by a reasoned explanation. FCC v. Fox Television Stations, Inc., 556 
U.S. 502, 515 (2009); see also Motor Vehicle Mfrs. Ass’n v. State Farm 
Mutual Auto. Ins. Co., 463 U.S. 29, 42 (1983). 
2. Statutory Structure and Legislative 
History 
In addition to the text of the specific 
subsections of CAA section 112 discussed above, the statutory structure and legislative history of CAA section 112 further support the EPA’s authority to take this action. Throughout CAA section 112 and its legislative history, Congress made clear its intent to quickly secure large reductions in the volume of HAP emissions from stationary sources based on technological developments in control technologies because of its 
recognition of the hazards to public health and the environment that result from exposure to such emissions. CAA section 112 and its legislative history also reveal Congress’s understanding that fully characterizing the risks posed by HAP emissions was exceedingly difficult. Thus, Congress purposefully replaced a regime that required the EPA to make an assessment of risk in the first instance, with one in which Congress determined risk existed and directed the EPA to make swift and substantial reductions based upon the most stringent standards technology could achieve. 
Specifically, in 1990, Congress 
radically transformed section 112 of the CAA and its treatment of HAP through the Clean Air Act Amendments, by 
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8Congress recognized as much: ‘‘The 
Administrator may take the cost of achieving the 
maximum emission reduction and any non-air quality health and environmental impacts and energy requirements into account when determining the emissions limitation which is achievable for the sources in the category or subcategory. Cost considerations are reflected in the selection of emissions limitations which have been achieved in practice (rather than those which are merely theoretical) by sources of a similar type or character.’’ A Legislative History of the Clean Air Act Amendments of 1990 (CAA Legislative History), Vol 5, pp. 8508–8509 (CAA Amendments of 1989; p. 168–169; Report of the Committee on 
Environment and Public Works S. 1630). amending CAA section 112 to be a 
technology-driven standard setting provision as opposed to the risk-based one that Congress initially promulgated in the 1970 CAA. The legislative history of the 1990 Amendments indicates Congress’s dissatisfaction with the EPA’s slow pace addressing HAP under the 1970 CAA: ‘‘In theory, [hazardous air pollutants] were to be stringently controlled under the existing Clean Air Act section 112. However, . . . only 7 of the hundreds of potentially hazardous air pollutants have been regulated by EPA since section 112 was enacted in 1970.’’ H.R. Rep. No. 101– 490, at 315 (1990); see also id. at 151 
(noting that in 20 years, the EPA’s establishment of standards for only seven HAP covered ‘‘a small fraction of the many substances associated . . . with cancer, birth defects, neurological damage, or other serious health impacts.’’). 
In enacting the 1990 Amendments 
with respect to the control of HAP, Congress noted that ‘‘[p]ollutants controlled under [section 112] tend to be less widespread than those regulated [under other sections of the CAA], but are often associated with more serious health impacts, such as cancer, neurological disorders, and reproductive dysfunctions.’’ Id. at 315. 
In its substantial 1990 Amendments, Congress itself listed 189 HAP (CAA section 112(b)) and set forth a statutory structure that would ensure swift regulation of a significant majority of these HAP emissions from stationary sources. Specifically, after defining major and area sources and requiring the EPA to list all major sources and many area sources of the listed pollutants (CAA section 112(c)), the new CAA section 112 required the EPA to establish technology-based emission standards for listed source categories on a prompt schedule and to revisit those technology-based standards every 8 years on an ongoing basis (CAA section 112(d) (emission standards); CAA section 112(e) (schedule for standards and review)). The 1990 Amendments also obligated the EPA to conduct a one- time evaluation of the residual risk within 8 years of promulgation of technology-based standards. CAA section 112(f)(2). 
In setting the standards, CAA section 
112(d) requires the EPA to establish technology-based standards that achieve the ‘‘maximum degree of reduction,’’ ‘‘including a prohibition on such emissions where achievable.’’ CAA section 112(d)(2). Congress specified that the maximum degree of reduction 
must be at least as stringent as the average level of control achieved in practice by the best performing sources 
in the category or subcategory based on emissions data available to the EPA at the time of promulgation. This technology-based approach enabled the EPA to swiftly set standards for source categories without determining the risk or cost in each specific case, as the EPA had done prior to the 1990 Amendments. In other words, this approach to regulation quickly required that all major sources and many area sources of HAP meet an emission standard consistent with the top performers in each category, which had the effect of obtaining immediate reductions in the volume of HAP emissions from stationary sources. The statutory requirement that sources obtain levels of emission limitation that have actually been achieved by existing sources, instead of levels that could theoretically be achieved, inherently reflects a built-in cost consideration.
8 
Further, after determining the 
minimum stringency level of control, or MACT floor, CAA section 112(d)(2) directs the EPA to ‘‘require the maximum degree of reduction in emissions of the hazardous air pollutants subject to this section (including a prohibition on such emissions, where achievable)’’ that the EPA determines are achievable after considering the cost of achieving such standards and any non-air-quality health and environmental impacts and energy requirements of additional control. In doing so, the statute further specifies in CAA section 112(d)(2) that the EPA should consider requiring sources to apply measures that, among other things, ‘‘reduce the volume of, or eliminate emissions of, such pollutants . . . ’’ (CAA section 112(d)(2)(A)), ‘‘enclose systems or processes to eliminate emissions’’ (CAA section 112(d)(2)(B)), and ‘‘collect, capture, or treat such pollutants when released . . . ’’ (CAA section 112(d)(2)(C)). The 1990 Amendments also built in a regular review of new technologies and a one- time review of risks that remain after imposition of MACT standards. CAA section 112(d)(6) requires the EPA to evaluate every NESHAP no less often 
than every 8 years to determine whether additional control is necessary after taking into consideration ‘‘developments in practices, processes, and control technologies,’’ separate from its obligation to review residual risk. CAA section 112(f) requires the EPA to ensure within 8 years of promulgating a NESHAP that the risks are acceptable and that the MACT standards provide an ample margin of safety. 
The statutory requirement to establish 
technology-based standards under CAA section 112 eliminated the requirement for the EPA to identify hazards to public health and the environment in order to justify regulation of HAP emissions from stationary sources, reflecting Congress’s judgment that such emissions are inherently dangerous. See S. Rep. No. 101–228, at 148 (‘‘The MACT standards are based on the performance of technology, and not on the health and environmental effects of the [HAP].’’). The technology review required in CAA section 112(d)(6) further mandates that the EPA continually reassess standards to determine if additional reductions can be obtained, without evaluating the specific risk associated with the HAP emissions that would be reduced. Notably, Congress required the EPA to conduct the CAA section 112(d)(6) review of what additional reductions may be obtained based on new technology even after the EPA has conducted the one-time CAA section 112(f)(2) risk review and determined that the existing standard will protect the public with an ample margin of safety. The two requirements are distinct, and both are mandatory. 
B. What is the Coal- and Oil-Fired EGU 
source category and how does the NESHAP regulate HAP emissions from the source category? 
1. Summary of Coal- and Oil-Fired EGU 
Source Category and NESHAP Regulations 
The EPA promulgated the Coal- and 
Oil-Fired EGU NESHAP (commonly referred to as MATS) on February 16, 2012 (77 FR 9304) (2012 MATS Final Rule). The standards are codified at 40 CFR part 63, subpart UUUUU. The coal- and oil-fired electric utility industry consists of facilities that burn coal or oil 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 
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9U.S. EPA. 1997, Mercury Study Report to 
Congress, EPA–452/R–97–003 (December 1997); see 
also 76 FR 24976 (May 3, 2011); 80 FR 75029 
(December 1, 2015). after May 3, 2011. An EGU is a 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 electric output to any utility power distribution system for sale is also considered an EGU. The 2012 MATS Final 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.’’ In 2028, the EPA expects the source category covered by this MACT standard to include 314 coal-fired steam generating units (140 GW at 157 facilities), 58 oil-fired steam generating units (23 GW at 35 facilities), and 5 IGCC units (0.8 GW at 2 facilities). 
For coal-fired EGUs, the 2012 MATS 
Final 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
2that may be 
used as a surrogate for acid gas HAP for those coal-fired EGUs with flue gas desulfurization (FGD) systems and SO
2 
CEMS installed and operational. Standards for fPM serve as a surrogate for the non-Hg HAP metals. Work practice standards limit formation and emissions of organic HAP. 
For oil-fired EGUs, the 2012 MATS 
Final 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 also serve as a surrogate for total HAP metals, with standards for total and individual HAP metals provided as alternative equivalent standards. Work practice standards limit formation and emissions of organic HAP. 
MATS includes standards for existing 
and new EGUs for eight subcategories: three 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 seven of the subcategories are 
subject to numeric emission limits for all the pollutants described above except for organic HAP (limited-use liquid oil-fired EGUs are not subject to numeric emission limits). 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 and additional information of the history and other requirements of the 2012 MATS Final Rule are available in the 2023 Proposal preamble (88 FR 24854). 
2. Public Health and Environmental 
Hazards Associated With Emissions From Coal- and Oil-Fired EGUs 
Coal- and oil-fired EGUs are a 
significant source of numerous HAP that are associated with adverse effects to human health and the environment, including Hg, HF, HCl, selenium, arsenic, chromium, cobalt, nickel, hydrogen cyanide, beryllium, and cadmium emissions. Hg is a persistent and bioaccumulative toxic metal that, once released from power plants into the ambient air, can be readily transported and deposited to soil and aquatic environments where it is transformed by microbial action into methylmercury.
9Methylmercury 
bioaccumulates in the aquatic food web eventually resulting in highly concentrated levels of methylmercury within the larger and longer-living fish (e.g., carp, catfish, trout, and perch), 
which can then be consumed by humans. 
Of particular concern is chronic 
prenatal exposure via maternal consumption of foods containing methylmercury. Elevated exposure has been associated with developmental neurotoxicity and manifests as poor performance on neurobehavioral tests, particularly on tests of attention, fine motor function, language, verbal memory, and visual-spatial ability. Evidence also suggests potential for adverse effects on the cardiovascular system, adult nervous system, and immune system, as well as potential for causing cancer. Because the impacts of the neurodevelopmental effects of methylmercury are greatest during periods of rapid brain development, developing fetuses, infants, and young children are particularly vulnerable. Children born to populations with high fish consumption (e.g., people 
consuming fish as a dietary staple) or impaired nutritional status may be especially susceptible to adverse neurodevelopmental outcomes. These dietary and nutritional risk factors are 
often particularly pronounced in vulnerable communities with people of color and low-income populations that have historically faced economic and environmental injustice and are overburdened by cumulative levels of pollution. In addition to adverse neurodevelopmental effects, there is evidence that exposure to methylmercury in humans and animals can have adverse effects on both the developing and adult cardiovascular system. 
Along with the human health hazards 
associated with methylmercury, it is well-established that birds and mammals are also exposed to methylmercury through fish consumption (Mercury Study). At higher levels of exposure, the harmful effects of methylmercury include slower growth and development, reduced reproduction, and premature mortality. The effects of methylmercury on wildlife are variable across species but have been observed in the environment for numerous avian species and mammals including polar bears, river otters, and panthers. 
EGUs are also the largest source of 
HCl, HF, and selenium emissions, and are a major source of metallic HAP emissions including arsenic, chromium, nickel, cobalt, and others. Exposure to these HAP, depending on exposure duration and levels of exposures, is associated with a variety of adverse health effects. These adverse health effects may include chronic health disorders (e.g., pneumonitis, decreased 
pulmonary function, pneumonia, or lung damage; detrimental effects on the central nervous system; damage to the kidneys) and alimentary effects (such as nausea and vomiting). As of 2021, three of the key metal HAP emitted by EGUs (arsenic, chromium, and nickel) have been classified as human carcinogens, while three others (cadmium, selenium, and lead) are classified as probable human carcinogens. Overall (metal and nonmetal), the EPA has classified four of the HAP emitted by EGUs as human carcinogens and five as probable human carcinogens. 
While exposure to HAP is associated 
with a variety of adverse effects, quantifying the economic value of these impacts remains challenging. 
Epidemiologic studies, which report a central estimate of population-level risk, are generally used in an air pollution benefits assessment to estimate the number of attributable cases of events. Exposure to HAP is typically more uneven and more highly concentrated among a smaller number of individuals than exposure to criteria pollutants. 
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Hence, conducting an epidemiologic 
study for HAP is inherently more challenging; for starters, the small population size means such studies often lack sufficient statistical power to detect effects (particularly outcomes like cancer, for which there can exist a multi-year time lag between exposure and the onset of the disease). By contrast, sufficient power generally exists to detect effects for criteria pollutants because exposures are ubiquitous and a variety of methods exist to characterize this exposure over space and time. 
For the reasons noted above, 
epidemiologic studies do not generally exist for HAP. Instead, the EPA tends to rely on experimental animal studies to identify the range of effects which may be associated with a particular HAP exposure. Human controlled clinical studies are often limited due to ethical barriers (e.g., knowingly exposing 
someone to a carcinogen). Generally, robust data are needed to quantify the magnitude of expected adverse impacts 
from varying exposures to a HAP. These data are necessary to provide a foundation for quantitative benefits analyses but are often lacking for HAP, 
made even more challenging by the wide array of HAP and possible noncancer HAP effects. 
Finally, estimating the economic 
value of HAP is made challenging by the human health endpoints affected. For example, though EPA can quantify the number and economic value of HAP- attributable deaths resulting from cancer, it is difficult to monetize the value of reducing an individual’s potential cancer risk attributable to a 
lifetime of HAP exposure. An alternative approach of conducting willingness to pay studies specifically on risk reduction may be possible, but such studies have not yet been pursued. 
C. Summary of the 2020 Residual Risk 
Review 
As required by CAA section 112(f)(2), 
the EPA conducted the residual risk review (2020 Residual Risk Review) in 2020, 8 years after promulgating the 2012 MATS Final Rule, and presented the results of the 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 3 of this document, 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 (Document ID No. EPA–HQ–OAR–2018–0794–4553). The EPA summarized the results and findings of the 2020 Residual Risk 
Review in the preamble of the 2023 Proposal (88 FR 24854), and additional information concerning the residual risk review can be found in our National- Scale Mercury Risk Estimates for Cardiovascular and Neurodevelopmental Outcomes for the National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Revocation of the 2020 Reconsideration, and Affirmation of the Appropriate and Necessary Finding; Notice of Proposed Rulemaking memorandum (Document ID No. EPA– HQ–OAR–2018–0794–4605). 
BILLING CODE 6560–50–P 
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BILLING CODE 6560–50–C 
D. 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 2012 MATS Final Rule was promulgated. Control technologies typically used to minimize emissions of pollutants that have numeric emission limits under the 2012 MATS Final Rule include electrostatic precipitators (ESPs) and fabric filters (FFs) for control of fPM as a surrogate for non-Hg HAP metals; wet scrubbers, dry scrubbers, and dry sorbent injection for control of acid gases (SO
2, HCl, and 
HF); and activated carbon injection (ACI) and other Hg-specific technologies for control of Hg. The EPA determined that the 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 2012 MATS Final 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 2012 MATS Final 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 
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ER07MY24.067</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 3. Coal-and Oil-Fired EGU Inhalation Risk Assessment Results in the 2020 Final 
Action (85 FR 31286; May 22, 2020) 
Maximum 
Population at Screening 
Number Maximum Individual Increased Risk of Acute 
of Cancer Risk (in 1 Cancer :::0: l-in-1 Annual Cancer Incidence Maximum Chronic Noncancer 
!Facilities 1 million) 2 million ( cases per year) N oncancer TOSHI 3 HQ4 
Based on 
Based on ... Based on ... Based on ... Based on ... Actual 
Emissions 
Level 
322 Actual Allowable Actual Allowable Actual Allowable Actual Allowable 
Emissions Emissions Emissions Emissions Emissions Emissions !Emissions Emissions 
Level 
Level Level Level Level Level Level Level 
HQREL= 
9 10 193,000 636,000 0.04 0.1 0.2 0.4 0.09 
(arsenic) 
1 Number of facilities evaluated in the risk analysis. At the time of the risk analysis there were an 
estimated 323 facilities in the Coal-and Oil-Fired EGU source category; however, one facility is 
located in Guam, which was beyond the geographic range of the model used to estimate risks. 
Therefore, the Guam facility was not modeled and the emissions for that facility were not 
included in the assessment. 
2 Maximum individual excess lifetime cancer risk due to HAP emissions from the source 
category. 
3 Maximum target organ-specific hazard index (TOSHI). The target organ systems with the 
highest TOSHI for the source category are respiratory and immunological. 
4 The maximum estimated acute exposure concentration was divided by available short-term 
threshold values to develop an array of hazard quotient (HQ) values. HQ values shown use the 
lowest available acute threshold value, which in most cases is the reference exposure level 
(REL). When an HQ exceeds 1, we also show the HQ using the next lowest available acute dose­
response value. 38518 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
10See Document ID No. EPA–HQ–OAR–2018– 
0794–4565 at https://www.regulations.gov. control technologies and, thus, did not 
propose changes to any 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 (Document 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). 
E. Summary of the EPA’s Review of the 
2020 RTR and the 2023 Proposed Revisions to the NESHAP 
Pursuant to CAA section 112(d)(6), 
the EPA conducted a review of the 2020 Technology Review and presented the results of this review, along with our proposed decisions, in the 2023 Proposal. The results of the technology review are presented briefly below in this preamble. More detail on the proposed technology review is in the memorandum 2023 Technology Review 
for the Coal- and Oil-Fired EGU Source Category (‘‘2023 Technical Memo’’) 
(Document ID No. EPA–HQ–OAR– 2018–0794–5789). 
Based on the results of the technology 
review, the EPA proposed to lower the fPM standard, the surrogate for non-Hg HAP metals, for coal-fired EGUs from 0.030 lb/MMBtu to 0.010 lb/MMBtu. The Agency solicited comment on the control technology effectiveness and cost assumptions used in the proposed rule, as well as on a more stringent fPM limit of 0.006 lb/MMBtu or lower. Additionally, the Agency proposed to require the use of PM CEMS for all coal- fired, oil-fired, and IGCC EGUs for demonstrating compliance with the fPM standard. As the Agency proposed to require PM CEMS for compliance demonstration, we also proposed to remove the LEE option, a program based on infrequent stack testing, for fPM and non-Hg HAP metals. As EGUs would be 
required to demonstrate compliance with PM CEMS, the Agency also proposed to remove the alternate emission standards for non-Hg HAP metals and total HAP metals, 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 solicited comment on prorated metal limits (adjusted proportionally according to the level of the final fPM standard), 
should the Agency not finalize the removal of the non-Hg HAP metals limits. 
The Agency also proposed to lower 
the Hg emission standard for lignite- fired EGUs from 4.0 lb/TBtu to 1.2 lb/ TBtu and solicited comment on the performance of Hg controls and on cost and effectiveness of control strategies to meet more stringent Hg standards. Lastly, the EPA did not identify new developments in control technologies or 
improved methods of operation that would warrant revisions to the Hg emission standards for non-lignite EGUs, for the organic HAP work practice standards, for the acid gas standards, or for standards for oil-fired EGUs. Therefore, the Agency did not propose changes to these standards in the 2023 Proposal but did solicit comment on the EPA’s proposed findings that no revisions were warranted and on the appropriateness of the existing standards. 
Additionally, the EPA proposed to 
remove one of the two options for defining the startup period for MATS- affected EGUs. 
In the 2023 Proposal, the EPA 
determined not to reopen the 2020 Residual Risk Review, and accordingly did not propose any revisions to that review. As the EPA explained in the proposal, the EPA found in the 2020 RTR that risks from the Coal- and Oil- Fired EGU source category due to emissions of air toxics are acceptable and that the existing NESHAP provides an ample margin of safety to protect public health. As noted in the proposal, 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. The EPA granted in part the environmental organizations’ petition which sought the EPA’s review of startup and shutdown provisions in the 2023 Proposal, 88 FR 24885, and the EPA continues to review and will respond to other aspects of the petition in a separate action.
10 
III. What is included in this final rule? 
This action finalizes the EPA’s 
determinations pursuant to the RTR provisions of CAA section 112 for the Coal- and Oil-Fired EGU source category and amends the Coal- and Oil-Fired EGU NESHAP based on those determinations. This action also finalizes changes to the definition of startup for this rule. This final rule includes changes to the 2023 Proposal 
after consideration of comments received during the public comment period described in sections IV., V., VI., and VII. of this preamble. 
A. What are the final rule amendments 
based on the technology review for the Coal- and Oil-Fired EGU source category? 
We determined that there are 
developments in practices, processes, and control technologies that warrant revisions to the MACT standards for this source category. Therefore, to satisfy the requirements of CAA section 112(d)(6), we are revising the MACT standards by revising the fPM limit for existing coal- fired EGUs from 0.030 lb/MMBtu to 0.010 lb/MMBtu and requiring the use of PM CEMS for coal and oil-fired EGUs to demonstrate compliance with the revised fPM standard, as proposed. We are also finalizing, as proposed, a Hg limit for lignite-fired EGUs of 1.2 lb/ TBtu, which aligns with the existing Hg limit that has been in effect for other coal-fired EGUs since 2012. This revised Hg limit for lignite-fired EGUs is more stringent than the limit of 4.0 lb/TBtu that was finalized for such units in the 2012 MATS Final Rule. The rationale for these changes is discussed in more detail in sections IV. and V. below. 
Based on comments received during 
the public comment period, the EPA is not finalizing the proposed removal of the non-Hg HAP metals limits for existing coal-fired EGUs (see section V.). Additionally, this final rule is requiring the use of PM CEMS for compliance demonstration for coal- and oil-fired EGUs (excluding EGUs in the limited- use liquid oil-fired subcategory), but not for IGCC EGUs (see section VI.). 
Because this final rule includes 
revisions to the emissions standards for fPM as a surrogate for non-Hg HAP metals for existing coal-fired EGUs, the fPM emission standard compliance 
demonstration requirements, the Hg emission standard for lignite-fired EGUs, and the definition of ‘‘startup,’’ the EPA intends each portion of this rule to be severable from each other as it is multifaceted and addresses several distinct aspects of MATS for independent reasons. This includes the revised emission standard for fPM as a surrogate for non-Hg HAP metals and the fPM compliance demonstration requirement to utilize PM CEMS. While the EPA considered the technical feasibility of PM CEMS in establishing the revised fPM standard, the EPA finds there are independent reasons for adopting each revision to the standards, and that each would continue to be workable without the other in the place. 
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1177 FR 9406. 
12https://www.epa.gov/enforcement/ 
enforcement-response-policy-mercury-and-air- 
toxics-standard-mats. The EPA intends that the various 
pieces of this package be considered 
independent of each other. For example, the EPA notes that our judgments regarding developments in fPM control technology for the revised fPM standard as a surrogate for non-Hg HAP metals largely reflect that the fleet was reporting fPM emission rates well below the current standard and with lower costs than estimated during promulgation of the 2012 MATS Final Rule; while our judgments regarding the ability for lignite-fired EGUs to meet the same standard for Hg emissions as other coal- and oil-fired EGUs rest on a separate analysis specific to lignite-fired units. Thus, the revised fPM surrogate emissions standard is feasible and appropriate even absent the revised Hg standard for lignite-fired units, and vice versa. Similarly, the EPA is finalizing changes to the fPM compliance demonstration requirement based on the technology’s ability to provide increased transparency for owners and operators, regulators, and the public; and the EPA is finalizing changes to the startup definition based on considerations raised by environmental groups in petitions for reconsideration. Both of these actions are independent from the EPA’s revisions to the fPM surrogate standard, and the Hg standard for lignite-fired units. Accordingly, the EPA finds that each set of standards is severable from each other set of standards. 
Finally, the EPA finds that 
implementation of each set of standards, compliance demonstration requirements, and revisions to the startup definition are independent. That is, a source can abide by any one of these individual requirements without abiding by any others. Thus, the EPA’s overall approach to this source category continues to be fully implementable even in the absence of any one or more of the elements included in this final rule. 
Thus, the EPA has independently 
considered and adopted each portion of this final rule (including the revised fPM emission standard as a surrogate for non-Hg HAP metals, the fPM compliance demonstration requirement, the revised Hg emission standard for lignite-fired units, and the revised startup definition) and each is severable should there be judicial review. If a court were to invalidate any one of these elements of the final rule, the EPA intends the remainder of this action to remain effective. Importantly, the EPA designed the different elements of this final rule to function sensibly and 
independently. Further, the supporting bases for each element of the final rule reflect the Agency’s judgment that the 
element is independently justified and appropriate, and that each element can function independently even if one or more other parts of the rule has been set aside. 
B. What other changes have been made 
to the NESHAP? 
The EPA is finalizing, as proposed, 
the removal of the work practice standards of paragraph (2) of the definition of ‘‘startup’’ in 40 CFR 63.10042. 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). 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 final rule requires that all EGUs use the work practice standards in paragraph (1) of the definition of ‘‘startup,’’ which is already being used by the majority of EGUs. 
C. What are the effective and 
compliance dates of the standards? 
The revisions to the MACT standards 
being promulgated in this action are effective on July 8, 2024. The compliance date for affected coal-fired sources to comply with the revised fPM limit of 0.010 lb/MMBtu and for lignite- fired sources to meet the lower Hg limit of 1.2 lb/TBtu is 3 years after the effective date of the final rule. The Agency believes this timeline is as expeditious as practicable considering the potential need for some sources to upgrade or replace pollution controls. 
As discussed elsewhere in this preamble, we are adding a requirement that compliance with the fPM limit be demonstrated using PM CEMS. Based on comments received during the comment period and our understanding of suppliers of PM CEMS, the EPA is finalizing the requirement that affected sources use PM CEMS for compliance demonstration by 3 years after the effective date of the final rule. The compliance date for existing affected sources to comply with amendments pertaining to the startup definition is 180 days after the effective date of the final rule, as few EGUs are affected, and changes needed to comply with paragraph (1) of startup are achievable by all EGUs at little to no additional expenditures. All affected facilities remain subject to the current requirements of 40 CFR part 63, subpart UUUUU, until the applicable 
compliance date of the amended rule. 
The EPA has considered the concerns 
raised by commenters that these compliance deadlines could affect electric reliability and concluded that given the flexibilities detailed further in this section, the requirements of the final rule for existing sources can be met without adversely impacting electric reliability. In particular, the EPA notes the flexibility of permitting authorities to allow, if warranted, a fourth year for compliance under CAA section 112(i)(3)(B). This flexibility, if needed, would address many of the concerns that commenters raised. Furthermore, in the event that an isolated, localized concern were to emerge that could not be addressed solely through the 1-year extension under CAA section 112(i)(3), the CAA provides additional flexibilities to bring sources into compliance while maintaining reliability. 
The EPA notes that similar concerns 
regarding reliability were raised about the 2012 MATS Final Rule—a rule that projected the need for significantly greater installation of controls and other capital investments than this current revision. In the 2012 MATS Final Rule, the EPA emphasized that most units should be able to comply with the requirements of the final rule within 3 years. However, the EPA also made it clear that permitting authorities have the authority to grant a 1-year compliance extension where necessary, in a range of situations described in the 
2012 MATS Final Rule preamble.
11The 
EPA’s Office of Enforcement and Compliance Assurance (OECA) also issued the MATS Enforcement Response policy (Dec. 16, 2011)
12which 
described the approach regarding the issue of CAA section 113(a) administrative orders with respect to the sources that must operate in noncompliance with the MATS rule for up to 1 year to address specific documented reliability concerns. While several affected EGUs requested and were granted a 1-year CAA section 112(i)(3)(B) compliance extension by their permitting authority, OECA only issued five administrative orders in connection with the Enforcement Response policy. The 2012 MATS Final Rule was ultimately implemented over the 2015—2016 timeframe without challenges to grid reliability. 
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IV. What is the rationale for our final 
decisions and amendments to the filterable PM (as a surrogate for non-Hg HAP metals) standard and compliance options from the 2020 Technology 
Review? 
In this section, the EPA provides 
descriptions of what we proposed, what we are finalizing, our rationale for the final decisions and amendments, and a summary of key comments and responses related to the emission standard for fPM, non-Hg HAP metals, and the compliance demonstration options. For all comments not discussed in this preamble, comment summaries and the EPA’s responses can be found in the comment summary and response document National Emission Standards 
for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review Proposed Rule Response to Comments, available in the docket. 
Based on its review, the EPA is 
finalizing a revised non-Hg HAP metal surrogate fPM emission standard for all existing coal-fired EGUs of 0.010 lb/ MMBtu and is requiring that all coal- and oil-fired EGUs demonstrate compliance with the revised fPM emission standard by using PM CEMS. The revised fPM standard will ensure that the entire fleet of coal-fired EGUs achieves performance levels that are consistent with those of the vast majority of regulated units operating today—i.e., that the small minority of 
units that currently emit significantly higher levels of HAP than their peers use proven technologies to reduce their HAP to the levels achieved by the rest of the fleet. Further, the EPA finds that a 0.010 lb/MMBtu fPM emission standard is the lowest level currently compatible with PM CEMS for demonstrating compliance, which the EPA finds provides significant benefits including increased transparency regarding emissions performance for sources, regulators, and the surrounding communities; and real-time identification of when control technologies are not performing as expected, allowing for quicker repairs. In addition, the rule’s current requirement to shift electronic reporting of PM CEMS data to the Emissions Collection and Monitoring Plan System (ECMPS) will enable regulatory authorities, nearby citizens, and others, including members of the public and media, to quickly and easily locate, review, and download fPM emissions using simple, user-directed inquiries. An enhanced, web-based version of ECMPS (ECMPS 2.0) is currently being prepared that will ease data editing, 
importing, and exporting and is expected to be available prior to the date by which EGUs are required to use PM CEMS. 
A. What did we propose pursuant to 
CAA section 112(d)(6) for the Coal- and Oil-Fired EGU source category? 
1. Proposed Changes to the Filterable 
PM Standard 
The EPA proposed to lower the fPM 
limit, a surrogate for total non-Hg HAP 
metals, for coal-fired EGUs from 0.030 lb/MMBtu to 0.010 lb/MMBtu. The EPA further solicited comment on an emission standard of 0.006 lb/MMBtu or lower. The EPA did not propose any changes to the fPM emission standard for oil-fired EGUs or for IGCC units. The EPA also proposed to remove the total and individual non-Hg HAP metals emission limits. The EPA also solicited comment on adjusting the total and individual non-Hg HAP metals emission limits proportionally to the revised fPM limit rather than eliminating the limits altogether. 
2. Proposed Changes to the 
Requirements for Compliance Demonstration 
The EPA proposed to require that all 
coal- and oil-fired EGUs (IGCC units are discussed in section VI.) use PM CEMS to demonstrate compliance with the fPM emission limit. The EPA also proposed to remove the option of demonstrating compliance using infrequent stack testing and the LEE program (where stack testing occurs quarterly for 3 years, then every third year thereafter) for both PM and non-Hg HAP metals. 
B. How did the technology review 
change for the Coal- and Oil-Fired EGU source category? 
1. Filterable PM Emission Standard 
Commenters provided both 
supportive and opposing arguments for 
issues regarding the fPM limit that were presented in the proposed review of the 2020 Technology Review. Comments received on the proposed fPM limit for coal-fired EGUs, along with additional analyses, did not change the Agency’s conclusions that were presented in the 2023 Proposal, and, therefore, the Agency is finalizing the 0.010 lb/ MMBtu fPM emission limit for existing coal-fired EGUs, as proposed. 
Additionally, commenters urged the 
Agency to retain the option of complying with individual non-Hg HAP metal (e.g., lead, arsenic, chromium, 
nickel, and cadmium) emission rates or with a total non-Hg HAP metal emission rate. After consideration of public comments, the Agency is finalizing updated limits for non-Hg HAP metals and total non-Hg HAP metals that have been reduced proportional to the reduction of the fPM emission limit from 0.030 lb/MMBtu to the new final fPM emission limit of 0.010 lb/MMBtu. EGU owners or operators who would choose to comply with the non-Hg HAP metals emission limits instead of the fPM limit must request and receive approval of a non-Hg HAP metal CMS as an alternative test method (e.g., multi-metal CMS) under the provisions of 40 CFR 63.7(f). 
2. Compliance Demonstration Options 
Comments received on the 
compliance demonstration options for 
coal- and oil-fired EGUs also did not change the results of the technology review, therefore the Agency is finalizing the use of PM CEMS for compliance demonstration purposes and removing the fPM and non-Hg HAP metals LEE options for all coal-fired EGUs and for oil-fired EGUs (except those in the limited use liquid oil-fired EGU subcategory). The Agency received comments that some PM CEMS that are currently correlated for the 0.030 lb/ MMBtu fPM emission limit may experience some difficulties should re- correlation be necessary at a lower fPM standard. Based on these comments and on additional review of PM CEMS test reports, as mentioned in sections IV.C.2. and IV.D.2., the Agency has made minor technical revisions to shift the basis of correlation testing from sampling a minimum volume per run to collecting a minimum mass or minimum sample volume per run and has adjusted the quality assurance (QA) criterion otherwise associated with the new emission limit. These changes will enable PM CEMS to be properly certified for use in demonstrating compliance with the lower fPM standard with a high degree of accuracy and reliability. 
C. What key comments did we receive 
on the filterable PM and compliance options, and what are our responses? 
1. Comments on the Filterable PM 
Emission Standard 
Comment: Some commenters 
supported the proposed fPM limit of 0.010 lb/MMBtu as reasonable and achievable, noting that this limit is slightly greater than the fPM emission limit required for new and reconstructed units. Additionally, commenters stated CAA section 112 was intended to improve the performance of lagging industrial sources and that a 
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13Technical Comments on National Emission 
Standards for Hazardous Air Pollutants: Coal- and 
Oil-fired Electric Utility Steam Generating Units Review of Residual Risk and Technology. Cichanowicz, et al. June 19, 2023. Attachment A to 
Document ID No. EPA–HQ–OAR–2018–0794–5994. standard that falls far behind what the 
vast majority of sources have already achieved, as the current standard does, is inadequate. Other commenters opposed the proposed fPM limit of 0.010 lb/MMBtu as too stringent. For instance, some commenters stated that the EPA did not provide adequate support for the proposed limit. Other commenters stated that the fact that the vast majority of units are achieving emission rates below the current limit does not constitute ‘‘developments in practices, processes, and control technologies.’’ 
Response: The EPA disagrees that the 
Agency has not adequately supported the proposed fPM limit. As described in the proposal preamble, the Agency conducted a review of the 2020 Technology Review pursuant to CAA section 112(d)(6), which focused on identifying and evaluating developments in practices, processes, and control technologies for the emission sources in the source category that occurred since promulgation of the 2012 MATS Final Rule. Based on that review, the EPA found that a majority of sources were not only reporting fPM emissions significantly below the current emission limit, but also that the fleet achieved lower fPM rates at lower costs than the EPA estimated when it promulgated the 2012 MATS Final Rule. The EPA explains these findings in more detail in section IV.D.1. of this preamble and elsewhere in the record. Further, the EPA finds that there are technological developments and improvements in PM control technology, which also controls non-Hg HAP metals, since the 2012 MATS Final Rule that informed the 2023 Proposal and this action, as discussed further in section IV.D.1. below. For example, industry has implemented ‘‘best practices’’ for monitoring ESP operation more carefully, and more durable materials have been adopted for FFs since the 2012 MATS Final Rule. The EPA also finds that these are cognizable developments for purposes of CAA section 112(d)(6). As other commenters noted, in National Association for Surface Finishing v. EPA, 795 F.3d 1, 11 
(D.C. Cir. 2015), the D.C. Circuit found that the EPA ‘‘permissibly identified and took into account cognizable developments’’ based on the EPA’s interpretation of the term as ‘‘not only wholly new methods, but also technological improvements.’’ Similarly, here the EPA identified a clear trend in control efficiency, costs, and technological improvements, which the EPA is accounting for in this action. Further, as discussed elsewhere in this section and in section IV.D.1. of this 
preamble, the EPA finds case law and substantial administrative precedent support the EPA’s decision to update the fPM limit based upon these developments. 
Comment: Many commenters 
recommended that the EPA add a compliance margin in its achievability assumptions. These commenters conveyed that most EGUs typically operate well below the limit to allow for a compliance margin in the event of an equipment malfunction or failure, which they encouraged the EPA to consider when setting new limits. These commenters claimed that with a proposed fPM limit of 0.010 lb/MMBtu, an appropriate design margin of 20 percent necessitates that control technologies must be able to achieve a limit of 0.008 lb/MMBtu or lower in practice. They also expressed concerns that the EPA did not take design margin into consideration in the cost analysis. They stated that by not including the need for a design margin, which the EPA has acknowledged the need for in at least two of the Agency’s publications (NESHAP Analysis of Control Technology Needs for Revised Proposed Emission Standards for New Source Coal-fired EGUs, Document ID No. EPA–HQ–OAR–2009–0234–20223 and PM CEMS Capabilities Summary for Performance Specification 11, NSPS, and MACT Rules, Document ID No. EPA–HQ–OAR–2018–0794–5828), the EPA underpredicted the number of units that would require retrofits. These commenters stated that the combination of a very low fPM limit and having to account for the measurement uncertainty and correlation methodology of PM CEMS would likely necessitate an ‘‘operational target limit’’ of 50 percent of the applicable limit. Some commenters referenced the National Rural Electric Cooperative Association (NRECA) technical evaluation for the 2023 Proposal titled Technical Comments on National Emissions Standard for Hazardous Air Pollutants: Coal- and Oil-fired Electric Utility Steam Generating Units Review of Residual Risk and Technology.
13 
They said that, even using the EPA’s unrealistic ‘‘baseline fPM rates’’ and the lowest possible compliance margin of 20 percent, the NRECA technical evaluation estimated that 37 units— almost twice as many as the EPA’s estimate—would be required to take substantial action to comply with the 
proposed limit. 
Response: The EPA agrees that most 
facility operators normally target an emission level below the emission limit by incorporating a compliance margin or margin of error in case of equipment malfunctions or failures. As the commenters noted, the Agency has previously recognized that some operators target an emission level 20 to 50 percent below the limit. However, no commenters provided data to suggest that ESPs or FF are unable to achieve a lower fPM limit. Furthermore, the Agency does not prescribe specifically how an EGU controls its emissions or how the unit operates. The choice to target a lower-level emission rate for a compliance margin is the sole decision of owners and operators. For facilities with more than one EGU in the same subcategory, owners or operators may find emissions averaging (40 CFR 63.10009), coupled with or without a compliance margin, could help the facility attain and maintain emission limits as an effective, low-cost approach. Additionally, no commenters provided data to indicate that every owner or operator aims to comply with the fPM limit with the same compliance margin. Because some operators might aim for a larger compliance margin than others, it would be difficult to select a particular assumption about compliance margin for the cost analysis. Every operator plans for compliance differently and the EPA cannot know every operator’s plans for a compliance margin. Even if the EPA were to assume a 20 percent compliance margin in its evaluation of PM controls, the results of the analysis would not change the EPA’s decision to adopt a lower fPM limit. Specifically, a 20 percent compliance margin assumption to a fPM limit of 0.010 lb/MMBtu would increase the number of affected EGUs from 33 to 53 (14.1 to 23.9 GW affected capacity) and the annual compliance costs from $87.2M to $147.7M. The number of EGUs that demonstrated an ability to meet the lower fPM limit, but do not do so on average and therefore would require O&M, would increase from 17 to 27 (including the compliance margin). Similarly, the number of ESP upgrades (previously 11) and bag upgrades (previously 3) would also increase (to 20 and 4, respectively). There would be no change in the number of new FF installs. Therefore, cost-effectiveness values for fPM and individual and total non-Hg HAP metals would only increase slightly. Moreover, the 30- boiler operating day averaging period using PM CEMS for compliance 
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14For the revised fPM analysis, the EPA uses two 
methods to assess the performance of the fleet: 
average and the 99th percentile of the lowest quarter of data. Values reported here use the average fPM rate for each EGU. 15Petroleum Refinery Sector Risk and Technology 
Review and New Source Performance Standards, 80 FR 75178, 75201 (December 1, 2015). 
16National Emission Standards for Hazardous 
Air Pollutants: Taconite Iron Ore Processing Residual Risk and Technology Review, 85 FR 45476, 45483 (July 28, 2020). 
17National Emission Standards for Hazardous 
Air Pollutants: Integrated Iron and Steel Manufacturing Facilities Residual Risk and Technology Review, 85 FR 42074, 42088 (July 13, 2020). 
18National Emission Standards for Hazardous 
Air Pollutants for the Portland Cement Manufacturing Industry and Standards of Performance for Portland Cement Plants, 78 FR 10006, 10021 (February 12, 2013). demonstration provides flexibility for 
owners and operators to account for equipment malfunctions, operational variability, and other issues. Lastly, as described in the 2023 Proposal, and updated here, the vast majority of coal- fired EGUs are reporting fPM emissions well below the revised fPM limit. For instance, the median fPM rate of the 296 coal-fired EGUs assessed in the 2024 Technical Memo is 0.004 lb/MMBtu,
14 
or 60 percent below the revised fPM limit of 0.010 lb/MMBtu. The median fPM rate of a quarter of the best performing sources (N=74) is 0.002 lb/ MMBtu, about 80 percent below the revised fPM limit of 0.010 lb/MMBtu. Therefore, for these reasons, the EPA disagrees with commenters that a compliance margin needs to be considered in the cost analysis. 
The updated PM analysis, detailed in 
the memorandum 2024 Update to the 2023 Proposed Technology Review for the Coal- and Oil-Fired EGU Source Category (‘‘2024 Technical Memo’’) 
available in the docket, estimates that the number of EGUs that will need to improve their fPM emission rate to achieve a 0.010 lb/MMBtu limit has increased from the 20 EGUs assumed in the 2023 Proposal to 33 EGUs, which is more consistent with the NRECA technical evaluation estimate of 37 EGUs. This increase is a result of updated methodology that utilizes both the lowest achieved fPM rate (i.e., the 
lowest quarter’s 99th percentile) and the average fPM rate across all quarterly data when assessing PM upgrade and costs assumptions for the evaluated limits. The Agency disagrees with the commenters, however, that the 37 EGUs in the NRECA technical evaluation would require ‘‘substantial action to comply with the proposed standard.’’ In the Agency’s revised analysis, only 13 EGUs would require capital investments to meet a fPM limit of 0.010 lb/MMBtu. Of these, only two EGUs at one facility (Colstrip) currently without the most effective PM controls are projected to require installation of a FF, the costliest PM control upgrade option, to meet 0.010 lb/MMBtu. The remaining nine EGUs projected by the EPA to require capital investments are estimated to require various levels of ESP upgrades. The EPA estimates that more than half (20 EGUs) would be able to comply without any capital investments and would instead require improvements to their existing FF or ESP as they have already demonstrated the ability to meet 
the limit, but do not do so on average. 
Comment: Some commenters stated 
that cost effectiveness is an important consideration in technology reviews under CAA section 112(d)(6) and acknowledged that the EPA undertook cost-effectiveness analyses for the three fPM standards on which the Agency sought comment. However, the commenters stated, the NRECA technical evaluation found meaningful errors in the EPA’s cost analysis, including unreasonably low capital cost estimates for ESP rebuilds and a failure to consider the variability of fPM due to changes in operation or facility design, by not utilizing a compliance margin. They asserted that these errors resulted in sizeable cost-effectiveness underestimates that eroded the EPA’s overall determination that the proposed fPM limit is cost-effective. These commenters also asserted that the EPA’s rationale was arbitrary on its face because it reversed, without explanation, the EPA’s prior acknowledgements that a cost- effectiveness analysis should account for the cost effectiveness of controls at each affected facility and not simply on an aggregate nationwide basis. They stated that facility-specific costs should factor into the EPA’s assessment of what is ‘‘necessary’’ pursuant to the provisions of CAA section 112(d)(6) and CAA section 112(f)(2). 
Some commenters asserted that, even 
using the EPA’s cost-effectiveness figures, the proposed 0.010 lb/MMBtu limit is not cost-effective. These commenters stated that the EPA’s proposal to revise the fPM standard to 0.010 lb/MMBtu based on a cost- effectiveness estimate of up to $14.7 million per ton of total non-Hg HAP metals removed (equivalent to $44,900 per ton of fPM removed) is inconsistent with the EPA’s prior actions because the cost-effectiveness estimate is substantially higher than estimates the Agency has previously found to be not cost-effective. They further said that, in the past, the EPA has decided against revising fPM standards based on cost- effectiveness estimates substantially lower than the cost-effectiveness estimates here. They said that the EPA should follow these precedents and acknowledge that $12.2 to $14.7 million per ton of non-Hg HAP metals reduced is not cost-effective. They argued that the Agency should not finalize the proposed standard of 0.010 lb/MMBtu for that reason. Further, these commenters argued that the alternative, more stringent limit of 0.006 lb/MMBtu 
is even less cost-effective at $25.6 million per ton of non-Hg HAP metals reduced, so it should not be considered 
either. 
The commenters provided the 
following examples of previous rulemakings where EPA found controls to not be cost-effective: 
•In the Petroleum Refinery Sector 
technology review,
15the EPA declined 
to revise the fPM emission limit for existing fluid catalytic cracking units after finding that it would cost $10 million per ton of total non-Hg HAP metals reduced (in that case, equivalent to $23,000 per ton of fPM reduced), which was not cost-effective. 
•In the Iron Ore Processing 
technology review,
16the EPA declined 
to revise the non-Hg HAP metals limit after finding that installing wet scrubbers would cost $16 million per ton of non-Hg HAP metals reduced, which was not cost-effective. 
•In the Integrated Iron and Steel 
Manufacturing Facilities technology review,
17the EPA declined to revise the 
non-Hg HAP metals limit after finding that upgrading all fume/flame suppressants at blast furnaces to baghouses would cost $7 million per ton of non-Hg HAP metals reduced, which was not cost-effective. The Agency made a similar finding for a proposed limit that would have cost $14,000 per ton of volatile HAP reduced. 
•In the Portland Cement 
Manufacturing beyond-the-floor analysis,
18the EPA declined to impose 
a more stringent non-Hg HAP metals limit because it resulted in ‘‘significantly higher cost effectiveness for PM than EPA has accepted in other NESHAP.’’ The EPA noted in that rulemaking that it had previously 
‘‘reject[ed] $48,501 per ton of PM as not cost-effective for PM,’’ and noted prior EPA statements in a subsequent rulemaking providing that $268,000 per ton of HAP removed was a higher cost- effectiveness estimate than the EPA had accepted in other NESHAP rulemakings. 
In contrast, other commenters focused 
on the EPA’s estimated cost-effective estimates for fPM (which is a surrogate for non-Hg HAP metals) and argued that 
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19Assessment of Potential Revisions to the 
Mercury and Air Toxics Standards. Andover 
Technology Partners. June 15, 2023. Docket ID No. EPA–HQ–OAR–2018–0794. Also available at https://www.andovertechnology.com/wp-content/ uploads/2023/06/C_ 23_CAELP_ Final.pdf. 
20National Emission Standards for Hazardous 
Air Pollutants: Ferroalloys Production, 80 FR 37381 
(June 30, 2015). 
21National Emission Standards for Hazardous 
Air Pollutants: Secondary Lead Smelting, 76 FR 
29032 (May 19, 2011). those estimates were substantially lower 
than estimates that the EPA has considered to be cost-effective in other technology reviews. Therefore, these commenters concluded that the EPA should strengthen the limit to at least 0.010 lb/MMBtu. These commenters also pointed to a 2023 report by Andover Technology Partners
19that 
found that the cost to comply with an emission limit of 0.006 lb/MMBtu on a fleetwide basis was significantly less than the costs estimated by the EPA. Andover Technology Partners attributed this difference ‘‘to the assumptions EPA made regarding the potential emission reductions from ESP upgrades, which result in a much higher estimate of baghouse retrofits in EPA’s analysis for an emission rate of 0.006 lb/MMBtu.’’ These commenters stated that meeting the lower emission limit of 0.006 lb/ MMBtu is technologically feasible using currently available controls, and they urged the EPA to adopt this limit. They stated that although cost effectiveness is less relevant in the CAA section 112 context than for other CAA provisions, the $103,000 per ton of fPM and $209,000 per ton of filterable fine PM
2.5 
estimates that the EPA calculated for the 0.006 lb/MMBtu limit were reasonable and comparable to past practice in technology reviews under CAA section 112(d)(6). They noted that the EPA has previously found a control measure that resulted in an inflation-adjusted cost of $185,000 per ton of PM
2.5reduced to be 
cost-effective for the ferroalloys production source category
20and 
proposed a limit for secondary lead smelting sources that cost an inflation- adjusted $114,000 per ton of fPM reduced.
21They argued that, using the 
Andover Technology Partners cost estimates, the 0.006 lb/MMBtu limit has even better cost-effectiveness estimates at about $72,000 per ton of fPM reduced and $146,000 per ton of filterable PM
2.5 
reduced. These commenters noted that the EPA also calculated cost effectiveness based on allowable emissions (i.e., assuming emission 
reductions achieved if all evaluated EGUs emit at the maximum allowable amount of fPM, or 0.030 lb/MMBtu) at $1,610,000 per ton, showing that a limit of 0.006 lb/MMBtu allows far less pollution at low cost to the power sector. They concluded that all these metrics and approaches to considering costs show that a fPM limit of 0.006 lb/ MMBtu would require cost-effective reductions and can be achieved at a reasonable cost that would not jeopardize the power sector’s function. 
Additionally, some commenters cited 
Sierra Club v. Costle, 657 F.2d 298, 330 
(D.C. Cir. 1981), and said the case supports the EPA’s discretion to weigh cost, energy, and environmental impacts, recognizing the Agency’s authority to take these factors into account ‘‘in the broadest sense at the national and regional levels and over time as opposed to simply at the plant level in the immediate present.’’ These commenters said that the EPA has the authority to require costs that are reasonable for the industry even if they are not reasonable for every facility. These commenters acknowledged that the EPA has discretion to consider cost effectiveness under CAA section 112(d)(2), citing NRDC v. EPA, 749 F.3d 
1055, 1060–61 (D.C. Cir. 2014), but argued that the dollar-per-ton cost- effectiveness metric is less relevant under CAA section 112 than under other CAA provisions because the Agency is not charged with equitably distributing the costs of emission reductions through a uniform compliance strategy, as the EPA has done in its transport rules. The commenters concluded that the Agency should require maximum reductions of HAP emissions from each regulated source category and has no authority to balance cost effectiveness across industries. 
Response: In this action, the EPA is 
acting under its authority in CAA section 112(d)(6) to ‘‘review, and revise as necessary (taking into account developments in practices, processes, and control technologies), emission standards’’ promulgated under CAA section 112. As the EPA explained in the 2023 Proposal, this technology review is separate and distinct from other standard-setting provisions under CAA section 112, such as establishing MACT floors, conducting the beyond- the-floor analysis, and reviewing residual risk. 
Regarding the comments that the EPA 
underestimated costs to an extent that 
undermines the EPA’s overall cost- effectiveness assumptions, the EPA disagrees that the Agency underestimated the typical costs of ESP rebuilds. The commenters provided cost examples from only two facilities to support their assertions regarding the costs of ESP rebuilds. The costs provided for one of those facilities, Labadie, were not the costs associated 
with an ESP rebuild, but instead were the costs associated with the full replacement of an ESP. The commenter stated that, ‘‘Ameren retrofitted the entire ESP trains on two units in 2014/ 2015. On each of these units two of the three original existing ESPs had to be abandoned and one of the existing ESPs was retrofitted with new power supplies and flue gas flow modifications. A new state-of-the-art ESP was added to each unit to supplement the retrofitted ESPs.’’ An ESP replacement is different from an ESP rebuild, and therefore the costs of an ESP replacement do not inform the costs of an ESP rebuild. The ESP rebuild cost provided for the other facility, Petersburg, was less than the EPA’s final assumption regarding the typical cost of an ESP rebuild on a capacity-weighted average basis. Neither of these examples provided by the commenter demonstrate that the EPA underestimated costs. For these reasons, the EPA disagrees with these commenters. Additionally, the EPA disagrees with these commenters that the Agency must add a compliance margin in its cost assumptions. As described above, the Agency does not prescribe specifically how an EGU must be controlled or how it must be operated, and the choice of overcompliance is at the sole discretion of the owners and operators. 
Generally, the EPA agrees with 
commenters that cost effectiveness, i.e., the costs per unit of emissions reduction, is a metric that the EPA consistently considers, often alongside other cost metrics, in CAA section 112 rulemakings where it can consider costs, e.g., beyond-the-floor analyses and 
technology reviews, and agrees with commenters who recognize that the Agency has discretion in how it considers statutory factors under CAA section 112(d)(6), including costs. See e.g., Association of Battery Recyclers, Inc. v. EPA, 716 F.3d 667, 673–74 (D.C. 
Cir. 2013) (allowing that the EPA may consider costs in conducting technology reviews under CAA section 112(d)(6)); see also Nat’l Ass’n for Surface Finishing v. EPA, 795 F.3d 1, 11 (D.C. 
Cir. 2015). The EPA acknowledges that the cost-effectiveness values for these standards are higher than cost- effectiveness values that the EPA concluded were not cost-effective and weighed against implementing more stringent standards for some prior rules. The EPA disagrees, however, that there is any particular threshold that renders 
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22See e.g., National Emissions Standards for 
Hazardous Air Pollutants: Ferroalloys Production, 
80 FR 37366, 37381 (June 30, 2015) (‘‘[I]t is important to note that there is no bright line for determining acceptable cost effectiveness for HAP metals. Each rulemaking is different and various factors must be considered.’’). 
23National Emission Standards for Hazardous 
Air Pollutants: Ferroalloys Production, 79 FR 60238, 60273 (October 6, 2014). 24Petroleum Refinery Sector Risk and Technology 
Review and New Source Performance Standards, 80 FR 75178, 75201 (December 1, 2015). 
252020 National Emissions Inventory (NEI) Data; 
https://www.epa.gov/air-emissions-inventories/ 2020-national-emissions-inventory-nei-data. 
26National Emission Standards for Hazardous 
Air Pollutants: Integrated Iron and Steel Manufacturing Facilities Residual Risk and Technology Review, 85 FR 42074, 42088 (July 13, 2020). 
27National Emission Standards for Hazardous 
Air Pollutants for the Portland Cement Manufacturing Industry and Standards of Performance for Portland Cement Plants, 78 FR 10006, 10020–10021 (February 12, 2013). 
28In addition, while commenters are correct that 
the EPA determined not to adopt more stringent controls under the iron ore processing technology review, the aspects of the rulemaking that the commenters cite to concerned whether additional controls were necessary to provide an ample margin of safety under a residual risk review. In that instance, the EPA determined not to implement more stringent standards under the risk review based on the installation of wet ESPs in addition to wet scrubbers, based on the EPA’s determination that such improvements were not necessary to provide an ample margin of safety to protect public health. See National Emission Standards for Hazardous Air Pollutants: Taconite Iron Ore Processing Residual Risk and Technology Review, 84 FR 45476, 45483 (July 28, 2020). a rule cost-effective or not.22The EPA’s 
prior findings about cost effectiveness in 
other rules were specific to those rulemakings and the industries at issue in those rules. As commenters have pointed out, in considering cost effectiveness, the EPA will often consider what estimates it has deemed cost-effective in prior rulemakings. However, the EPA routinely views cost effectiveness in light of other factors, such as other relevant costs metrics (e.g., total costs, annual costs, and costs 
compared to revenues), impacts to the regulated industry, and industry- specific dynamics to determine whether there are ‘‘developments in practices, processes, and control technologies’’ that warrant updates to emissions standards pursuant to CAA section 112(d)(6). Some commenters, pointing to prior CAA section 112 rulemakings where the EPA chose not to adopt more stringent controls, mischaracterized cost effectiveness as the sole criterion in those decisions. These commenters omitted any discussion of other relevant factors from those rulemakings that, in addition to cost effectiveness, counseled the EPA against adopting more stringent standards. For example, in the 2014 Ferroalloys rulemaking that commenters cited to, the EPA rejected a potential control option due to questions about technical feasibility and significant economic impacts the option would create for the industry, including potential facility closures that would impact significant portions of industry production.
23In contrast here, the 
controls at issue are technically feasible (they are used at facilities throughout the country) and will not have significant effects on the industry. Indeed, the EPA does not project that the final revisions to MATS will result in incremental changes in operational coal-fired capacity. 
Similarly, in the other rulemakings 
these commenters pointed to, where the EPA found similar cost-effectiveness values to those that the EPA identified for the revised fPM standard here, there are distinct aspects of those rulemakings and industries that distinguish those prior actions from this rulemaking. In the 2015 Petroleum Refineries rulemaking, the EPA considered the cost effectiveness of developments at only two facilities to decide whether to 
deploy a standard across the much wider industry.
24Here in contrast, the 
EPA is basing updates to fPM standards for coal-fired EGUs on developments across the majority of the industry and the performance of the fleet as a whole, which has demonstrated the achievability of a more stringent standard. Additionally, there are inherent differences between the power sector and other industries that similarly distinguish prior actions from this rulemaking. For example, because of the size of the power sector (314 coal- fired EGUs at 157 facilities), and because this source category is one of the largest stationary source emitters of Hg, arsenic, and HCl and is one of the largest regulated stationary source emitters of total HAP,
25even 
considering that this rule affects only a fraction of the sector, the estimated HAP reductions in this final rule (8.3 tpy) are higher than those in the prior rulemakings cited by the commenters (as are the estimated PM reductions (2,537 tpy) used as a surrogate for non- Hg HAP metals). In contrast, in the 2020 Integrated Iron and Steel Manufacturing rulemaking, the source category covered 
included only 11 facilities, and the estimated reductions the EPA considered would have removed 3 tpy of HAP and 120 tpy of PM.
26Likewise, 
in the 2013 Portland Cement rulemaking, the EPA determined not to pursue more stringent controls for the sector after finding the standard would only result in 138 tpy of nationwide PM reductions and that there was a high cost for such modest reductions.
27Here, 
the EPA estimates significantly greater HAP emission reductions, and fPM emission reductions that are orders of magnitude greater than both prior rulemakings.
28 There are also unique attributes of the 
power sector that the EPA finds support 
the finalization of revised standards for fPM and non-Hg HAP metals despite the relatively high cost-effectiveness values of this rulemaking as compared to other CAA section 112 rulemakings. As the EPA has demonstrated throughout this record, there are hundreds of EGUs regulated under MATS with well- performing control equipment that are already reporting emission rates below the revised standards, whereas only a handful of facilities with largely outdated or underperforming controls are emitting significantly more than their peers. That means that the communities located near these handful of facilities may experience exposure to higher levels of toxic metal emissions 
than communities located near similarly sized well-controlled plants. This is what the revised standards seek to remedy, and as discussed throughout this record, this goal is consistent with the EPA’s authority under CAA section 112(d)(6) and the purpose of CAA section 112 more generally. 
U.S. EGUs are a major source of HAP 
metals emissions including arsenic, beryllium, cadmium, chromium, cobalt, lead, nickel, manganese, and selenium. Some HAP metals emitted by U.S. EGUs are known to be persistent and bioaccumulative and others have the potential to cause cancer. Exposure to these HAP metals, depending on exposure duration and levels of exposures, is associated with a variety of adverse health effects. These adverse health effects may include chronic health disorders (e.g., irritation of the 
lung, skin, and mucus membranes; decreased pulmonary function, pneumonia, or lung damage; detrimental effects on the central nervous system; damage to the kidneys; and alimentary effects such as nausea and vomiting). The emissions reductions projected under this final rule from the use of PM controls are expected to reduce exposure of individuals residing near these facilities to non-Hg HAP metals, including carcinogenic HAP. 
EGUs projected to be impacted by the 
revised fPM standards represent a small fraction of the total number of the coal- fired EGUs (11 percent for the 0.010 lb/ MMBtu fPM limit). In addition, many regulated facilities are electing to retire 
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29See, e.g., National Emission Standards for 
Hazardous Air Pollutants: Refractory Products 
Manufacturing Residual Risk and Technology Review, 86 FR 66045 (November 19, 2021); National 
Emission Standards for Hazardous Air Pollutants: Site Remediation Residual Risk and Technology Review, 85 FR 41680 (July 10, 2020); National 
Emission Standards for Hazardous Air Pollutants: Organic Liquids Distribution (Non-Gasoline) Residual Risk and Technology Review, 85 FR 40740, 40745 (July 7, 2020); National Emission Standards for Hazardous Air Pollutants: Generic Maximum Achievable Control Technology Standards Residual Risk and Technology Review for Ethylene Production, 85 FR 40386, 40389 (July 6, 2020); National Emission Standards for Hazardous Air Pollutants for Chemical Recovery Combustion Sources at Kraft, Soda, Sulfite, and Stand-Alone Semichemical Pulp Mills, 82 FR 47328 (October 11, 2017); National Emission Standards for Hazardous Air Pollutants: Generic Maximum Achievable Control Technology Standards; and Manufacture of Amino/Phenolic Resins, 79 FR 60898, 60901 (October 8, 2014). 30National Emission Standards for Hazardous 
Air Pollutant Emissions: Group I Polymers and Resins; Marine Tank Vessel Loading Operations; Pharmaceuticals Production; and the Printing and Publishing Industry, 76 FR 22566, 22577 (April 21, 2011). 
31See, e.g., National Emission Standards for 
Organic Hazardous Air Pollutants From the Synthetic Organic Chemical Manufacturing Industry, 71 FR 76603, 76606 (December 21, 2006); 
see also Proposed Rules: National Emission Standards for Halogenated Solvent Cleaning, 73 FR 
62384, 62404 (October 20, 2008). 
32National Emissions Standards for Hazardous 
Air Pollutants: Secondary Lead Smelting, 77 FR 
556, 564 (January 5, 2012). 
33See section II.A.2. above for further discussion 
of the statutory structure and legislative history of CAA section 112. due to factors independent of the EPA’s 
regulations, and the EPA typically has more information on plant retirements for this sector than other sectors regulated under CAA section 112. Both of these factors contribute to relatively higher cost-effectiveness estimates in this rulemaking as compared to other sectors where the EPA is not able to account for facility retirements and factor in shorter amortization periods for the price of controls. 
While some commenters stated that 
meeting an even lower emission limit of 0.006 lb/MMBtu is technologically feasible using currently available controls, the Agency declines to finalize this limit primarily due to the technological limitations of PM CEMS at this lower emission limit (as discussed in more detail in sections IV.C.2. and IV.D.2. below). Additionally, the EPA considered the higher costs associated with a more stringent standard as compared to the final standard presented in section IV.D.1. 
Finally, as mentioned in the Response 
to Comments document, the EPA finds that use of PM CEMS, which provide continuous feedback with respect to fPM variability, in lieu of quarterly fPM emissions testing, will render moot the commenter’s suggestion that margin of compliance has not been taken into account. 
Comment: Some commenters argued 
that the low residual risks the EPA found in its review of the 2020 Residual Risk Review obviate the need for the EPA to revise the standards under the separate technology review, and that residual risk should be a relevant aspect of the EPA’s technology review of coal- and oil-fired EGUs. These commenters argued that it is arbitrary and capricious for the EPA to impose high costs on facilities, which they claimed will only result in marginal emission reductions, when the EPA determined there is not an unreasonable risk to the environment or public health. 
Other commenters agreed with the 
EPA’s ‘‘two-pronged’’ interpretation that 
CAA section 112(d)(6) provides authorities to the EPA that are distinct from the EPA’s risk-based authorities under CAA section 112(f)(2). These commenters said that if the criteria under CAA section 112(d)(6) are met, the EPA must update the standards to reflect new developments independent of the risk assessment process under CAA section 112(f)(2). They said the technology-based review conducted under CAA section 112(d)(6) need not account for any information learned during the residual risk review under CAA section 112(f)(2) unless that information pertains to statutory factors under CAA section 112(d)(6), such as 
costs. They concluded that CAA section 112(d)(6) requires the EPA to promulgate the maximum HAP reductions possible where achievable at reasonable cost and is separate from the EPA’s residual risk analysis. 
Response: The EPA has an 
independent statutory authority and obligation to conduct the technology review separate from the EPA’s authority to conduct a residual risk review, and the Agency agrees with commenters that recognized that the EPA is not required to account for information obtained during a residual risk review in conducting a technology review. The EPA’s finding that there is an ample margin of safety under the residual risk review in no way interferes with the EPA’s obligation to require more stringent standards under the technology review where developments warrant such standards. The D.C. Circuit has recognized the CAA section 112(d)(6) technology review and 112(f)(2) residual review are ‘‘distinct, parallel analyses’’ that the EPA undertakes ‘‘[s]eparately.’’ Nat’l Ass’n for Surface Finishing v. EPA, 795 F.3d 
1, 5 (D.C. Cir. 2015). In other recent residual risk and technology reviews, the EPA determined additional controls were warranted under technology reviews pursuant to CAA section 112(d)(6) although the Agency determined additional standards were not necessary to maintain an ample margin of safety under CAA section 112(f)(2).
29The EPA has also made clear 
that the Agency ‘‘disagree[s] with the 
view that a determination under CAA section 112(f) of an ample margin of safety and no adverse environmental effects alone will, in all cases, cause us to determine that a revision is not necessary under CAA section 112(d)(6).’’
30While the EPA has 
considered risks as a factor in some 
previous technology reviews,31that 
does not compel the Agency to do so in this rulemaking. Indeed, in other instances, the EPA has adopted the same standards under both CAA sections 112(f)(2) and 112(d)(6) based on independent rationales where necessary to provide an ample margin of safety and because it is technically appropriate and necessary to do so, emphasizing the independent authority of the two statutory provisions.
32 
The language and structure of CAA 
section 112, along with its legislative history, further underscores the independent nature of these two provisions.
33While the EPA is only 
required to undertake the risk review once (8 years after promulgation of the original MACT standards), it is required to undertake the technology review multiple times (at least every 8 years after promulgation of the original MACT standard). That Congress charged the EPA to ensure an ample margin of safety through the risk review, yet still required the technology review to be conducted on a periodic basis, demonstrates that Congress anticipated that the EPA would strengthen standards based on technological developments even after it had concluded there was an ample margin of safety. CAA section 112’s overarching charge to the EPA to ‘‘require the maximum degree of reduction in emissions of the hazardous air 
pollutants subject to this section (including a prohibition on such emissions)’’ further demonstrates that Congress sought to minimize the emission of hazardous air pollution wherever feasible independent of a finding of risk. Moreover, as discussed supra, in enacting the 1990 CAA 
Amendments, Congress purposefully replaced the previous risk-based approach to establishing standards for HAP with a technology-driven approach. This technology-driven 
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34The EPA projected that the 2012 MATS Final 
Rule would drive the installation of an additional 
20 GW of dry FGD (dry scrubbers), 44 GW of DSI, 99 GW of additional ACI, 102 GW of additional FFs, 63 GW of scrubber upgrades, and 34 GW of ESP upgrades. While a subsequent analysis found that the industry ultimately installed fewer controls than was projected, the control installations that occurred following the promulgation of the 2012 MATS Final Rule were still significantly greater than the installations that are estimated to occur as a result of this final rule (where, for example, the EPA estimates that less than 2 GW of capacity would install FF technology for compliance). approach recognizes the ability for the 
EPA to achieve substantial reductions in HAP based on technological improvements without the inherent difficulty in quantifying risk associated with HAP emission exposure given the complexities of the pathways through which HAP cause harm and insufficient availability of data to quantify their effects discussed in section II.B.2. Independent of risks, it would be inconsistent with the text, structure, and legislative history for the EPA to conclude that Congress intended the statute’s technology-based approach to be sidelined after the EPA had concluded the risk review. 
Comment: Some commenters 
expressed concern that some portion of affected units could simply retire instead of coming into compliance with new requirements, potentially occurring before new generation could be built to replace the lost generation. During this period, a lack of dispatchable generation could significantly increase the likelihood of outages, particularly during periods of severe weather. In addition, some commenters argued that revising the fPM limit was unnecessary as there is a continuing downward trend in HAP emissions from early retirements of coal-fired EGUs, whereas accelerating this trend could have potential adverse effects on reliability. Some commenters also stated that as more capacity and generation is shifted away from coal-fired EGUs due to the Inflation Reduction Act (IRA) and other regulatory and economic factors, the total annual fPM and HAP emissions from industry will decline, regardless of whether the fPM limit is made more stringent. 
Response: The EPA disagrees that this 
rule would threaten resource adequacy or otherwise degrade electric system reliability. Commenters provided no credible information supporting the argument that this final rule would result in a significant number of retirements or a larger amount of capacity needing controls. The Agency estimates that this rule will require additional fPM control at less than 12 GW of operable capacity in 2028, which is about 11 percent of the total coal-fired EGU capacity projected to operate in that year. The units requiring additional fPM controls are projected to generate less than 1.5 percent of total generation in 2028. Moreover, the EPA does not project that any EGUs will retire in response to the standards promulgated in this final rule. Because the EPA projects no incremental changes in existing operational capacity to occur in response to the final rule, the EPA does not anticipate this rule will have any 
implications for resource adequacy. 
Nevertheless, it is possible that some 
EGU owners may conclude that retiring a particular EGU and replacing it with new capacity is a more economic option from the perspective of the unit’s customers and/or owners than making investments in new emissions controls at the unit. The EPA understands that before implementing such a retirement decision, the unit’s owner will follow the processes put in place by the relevant regional transmission organization (RTO), balancing authority, or state regulator to protect electric system reliability. These processes typically include analysis of the potential impacts of the proposed EGU retirement on electrical system reliability, identification of options for mitigating any identified adverse impacts, and, in some cases, temporary provision of additional revenues to support the EGU’s continued operation until longer-term mitigation measures can be put in place. No commenter stated that this rule would somehow authorize any EGU owner to unilaterally retire a unit without following these processes, yet some commenters nevertheless assume without any rationale that is how multiple EGU owners would proceed, in violation of their obligations to RTOs, balancing authorities, or state regulators relating to the provision of reliable electric service. 
In addition, the Agency has granted 
the maximum time allowed for compliance under CAA section 112(i)(3) of 3 years, and individual facilities may seek, if warranted, an additional 1-year extension of the compliance date from their permitting authority pursuant to CAA section 112(i)(3)(B). The construction of any additional pollution control technology that EGUs might install for compliance with this rule can be completed within this time and will not require significant outages beyond what is regularly scheduled for typical maintenance. Facilities may also obtain, if warranted, an emergency order from the Department of Energy pursuant to section 202(c) of the Federal Power Act (16 U.S.C. 824a(c)) that would allow the facility to temporarily operate notwithstanding environmental limits when the Secretary of Energy 
determines doing so is necessary to address a shortage of electric energy or other electric reliability emergency. 
Further, despite the comments 
asserting concerns over electric system reliability, no commenter cited a single instance where implementation of an EPA program caused an adverse reliability impact. Indeed, similar claims made in the context of the EPA’s prior CAA rulemakings have not been 
borne out in reality. For example, in the stay litigation over the Cross-State Air Pollution Rule (CSAPR), claims were made that allowing the rule to go into effect would compromise reliability. Yet in the 2012 ozone season starting just over 4 months after the rule was stayed, 
EGUs covered by CSAPR collectively emitted below the overall program budgets that the rule would have imposed in that year if the rule had been allowed to take effect, with most individual states emitting below their respective state budgets. Similarly, in the litigation over the 2015 Clean Power Plan, assertions that the rule would threaten electric system reliability were made by some utilities or their representatives, yet even though the Supreme Court stayed the rule in 2016, the industry achieved the rule’s emission reduction targets years ahead of schedule without the rule ever going into effect. See West Virginia v. EPA, 
142 S. Ct. 2587, 2638 (2022) (Kagan, J., dissenting) (‘‘[T]he industry didn’t fall short of the [Clean Power] Plan’s goal; rather, the industry exceeded that target, all on its own ....  A t  the time of the repeal . . . ‘there [was] likely to be no difference between a world where the [Clean Power Plan was] implemented and one where it [was] not.’ ’’) (quoting 84 FR 32561). In other words, the claims that these rules would have had adverse reliability impacts proved to be groundless. 
The EPA notes that similar concerns 
regarding reliability were raised about the 2012 MATS Final Rule—a rule that projected the need for significantly greater installation of controls and other capital investments than this current revision.
34As with the current rule, the 
flexibility of permitting authorities to allow a fourth year for compliance was available in a broad range of situations, and in the event that an isolated, localized concern were to emerge that could not be addressed solely through the 1-year extension under CAA section 112(i)(3), the CAA provides flexibilities to bring sources into compliance while maintaining reliability. We have seen no evidence in the last decade to suggest 
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3588 FR 33245 (May 23, 2023). 
3688 FR 18824, 18837 (March 29, 2023). 37In this final rule, the EPA reviewed fPM 
compliance data for 296 coal-fired EGUs expected 
to be operational on January 1, 2029. This review is explained in detail in the 2024 Technical Memo. that the implementation of MATS 
caused power sector adequacy and reliability problems, and only a handful of sources obtained administrative orders under the enforcement policy issued with MATS to provide relief to reliability critical units that could not comply with the rule by 2016. 
Comment: Commenters suggested that 
the EPA use its authority to create subcategories of affected facilities that elect to permanently retire by the compliance date as the Agency has taken in similar proposed rulemakings affecting coal- and oil-fired EGUs. Commenters stated the EPA should subcategorize those sources that have adopted enforceable retirement dates and not subject those sources to any final rule requirements. They indicated that the EPA is fully authorized to subcategorize these units under CAA section 112(d)(1). Commenters asked that the EPA consider other simultaneous rulemakings, such as the proposed Greenhouse Gas Standards and Guidelines for Fossil Fuel Power Plants,
35where the EPA proposed that 
EGUs that elect to shut down by January 1, 2032, must maintain their recent historical carbon dioxide (CO
2) emission 
rate via routine maintenance and operating procedures (i.e., no 
degradation of performance). Commenters also referenced the retirement date of December 31, 2032, in the EPA Office of Water’s proposed Effluent Limitation Guidelines.
36 
Commenters claimed that creating a 
subcategory for units facing near-term retirements that harmonizes the retirement dates with other rulemakings would greatly assist companies with moving forward on retirement plans without running the risk of being forced to retire early, which could create reliability concerns or, in the alternative, forced to deliberate whether to install controls and delaying retirement to recoup investments in the controls. Commenters also suggested that EGUs with limited continued 
operation be allowed to continue to perform quarterly stack testing to demonstrate compliance with the fPM limitations (rather than having to install PM CEMS). Commenters suggested that imposing different standards on these subcategories should continue the status quo for these units until retirement. Commenters claimed that it would make no sense for the EPA to require an EGU slated to retire in the near term to expend substantial resources on controls in the interim since these sources are very unlikely to find it viable to construct significant control 
upgrades for a revised standard that would become effective in mid-2027, only 5 years before the unit’s permanent retirement. Commenters further noted if the EPA does not establish such a subcategory or take other action to ensure these units are not negatively impacted by the rulemaking, the retirement of some units could be accelerated due to the costs of installing a PM CEMS and the need to rebuild or upgrade an existing ESP or install a FF to supplement an existing ESP. Commenters stated that the EPA cannot ignore the need for a coordinated retirement of thermal generating capacity while new generation sources come online to avoid detrimental impacts to grid reliability. 
Commenters suggested that if the EPA 
decides to proceed with finalizing the revised standards in the 2023 Proposal, the Agency should create a subcategory for coal-fired EGUs that elect by the compliance date of the revised standards (i.e., mid-2027) to retire the 
units by December 31, 2032, or January 1, 2032, if the EPA prefers to tie the 2023 Proposal to the proposed Emission Guidelines instead of the Effluent Limitation Guidelines, and maintain the current MATS standards for this subcategory of units. Commenters requested that the EPA coordinate the required retirement date for the 2023 Proposal with other rules so that all retirement dates align. Commenters reiterated that the EPA has multiple authorities with overlapping statutory timelines that affect commenters’ plans regarding the orderly retirement of coal- fired EGUs and their ability to continue the industry’s clean energy transformation while providing the reliability and affordability that their customers demand. Commenters suggested that EGUs that plan to retire by 2032 should have the opportunity to seek a waiver from PM CEMS installation altogether and continue quarterly stack testing during the remaining life of the unit. They also suggested that if a unit does not retire by the specified date, it should be required to immediately cease operation or meet the standards of the rule. Commenters stated that under this recommendation an EGU’s failure to comply would then be a violation of the 2023 Proposal’s final rule subject to enforcement. 
Response: In response to commenters’ 
concerns, the EPA evaluated the feasibility of creating a subcategory for facilities with near-term retirements but disagrees with commenters that such a 
subcategory is appropriate for this rulemaking. In particular, the EPA found that, based on its own assessment and that of commenters, only a few facilities would likely be eligible for a near-term retirement subcategory and that it would not significantly reduce the costs of the revised standards. According to the EPA’s assessment, 67 of the 296 EGUs assessed
37have 
announced retirements between 2029 and 2032—less than one-quarter of the fleet—and all but three of those EGUs (at two facilities) have already demonstrated the ability to comply with the 0.010 lb/MMBtu fPM standard on average. Additionally, these three EGUs already use PM CEMS to demonstrate compliance, therefore the comment requesting a waiver of PM CEMS installations for EGUs with near-term retirements is not relevant. Because the EPA’s analysis led the Agency to conclude that there would be little utility to a near-term retirement subcategory and it would not change the costs of the rule in a meaningful way, the EPA determined not to create a retirement subcategory for the fPM standard. In addition, the EPA notes that allowing units to operate without the best performing controls for an additional number of years would lead to higher levels of non-Hg HAP metals emissions and continued exposure to those emissions in the communities around these units during that timeframe. Regarding a fPM compliance requirement subcategory for EGUs with near-term retirements, the Agency estimates 26 of 67 EGUs are already using PM CEMS for compliance demonstration and finds that the costs to install PM CEMS for facilities with near-term retirements are reasonable. The Agency finds that the transparency provided by PM CEMS and the increased ability to quickly detect and correct potential control or operational problems using PM CEMS furthers Congress’s goal to ensure that emission reductions are consistently maintained and makes PM CEMS the best choice for this rule’s compliance monitoring for all EGUs. 
2. Comments on the Proposed Changes 
to the Compliance Demonstration Options 
Comment: The Agency received both 
supportive and opposing comments requiring the use of PM CEMS for compliance demonstration. Supportive commenters stated the EPA must require the use of PM CEMS to monitor their emissions of non-Hg HAP metals 
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38Analysis of PM and Hg Emissions and Controls 
from Coal-Fired Power Plants. Andover Technology 
Partners. August 19, 2021. Document ID No. EPA– HQ–OAR–2018–0794–4583. 39Assessment of Potential Revisions to the 
Mercury and Air Toxics Standards. Andover Technology Partners. June 15, 2023. Docket ID No. EPA–HQ–OAR–2018–0794. June 2023. Also available at https://www.andovertechnology.com/ wp-content/uploads/2023/06/C_ 23_CAELP_
Final.pdf. 
40See for example the PM CEMS Thirty Boiler 
Operating Day Rolling Average Reports for Duke’s Roxboro Steam Electric Plant in North Carolina and at Minnesota Power’s Boswell Energy Center in Minnesota. These reports and those from other EGUs reporting emission levels at or lower than 0.010 lb/MMBtu are available electronically by searching in the EPA’s Web Factor Information Retrieval System (WebFIRE) Report Search and Retrieval portion of the Agency’s WebFIRE internet website at https://cfpub.epa.gov/webfire/reports/ esearch.cfm. as PM CEMS are now more widely 
deployed than when MATS was first promulgated, and experience with PM CEMS has enabled operators to more promptly detect and correct problems with pollution controls as compared to other monitoring and testing options allowed under MATS (i.e., periodic 
stack testing and parametric monitoring for PM), thereby lowering HAP emissions. They said that the fact that PM CEMS have been used to demonstrate compliance in a majority of units in the eight best performing deciles
38provides strong evidence that 
PM CEMS can be used effectively to measure low levels of PM emissions. 
Opposing commenters urged the EPA 
to retain all current options for demonstrating compliance with non-Hg HAP metal standards, including quarterly PM and metals testing, LEE, and PM CPMS. These commenters said removing these compliance flexibility options goes beyond the scope of the RTR and does not address why the reasons these options were originally included in MATS are no longer valid. Commenters said they have previously raised concerns about PM CEMS that the EPA has avoided by stating that CEMS are not the only compliance method for PM. They stated that previously, the EPA has determined these compliance methods were both adequate and frequent enough to demonstrate compliance. 
Response: The Agency disagrees with 
commenters who suggests that the rule should retain all previous options for demonstrating compliance with either the individual metals, total metals, or fPM limits. Congress intended for CAA section 112 to achieve significant reductions of HAP, and the EPA agrees with other commenters that the use of CEMS in general and PM CEMS in particular enables owners or operators to detect and quickly correct control device or process issues in many cases before the issues become compliance problems. Consistent with the discussion contained in the 2023 Proposal (88 FR 24872), the Agency finds the transparency and ability to quickly detect and correct potential control or operational problems furthers Congress’s goal to ensure that emission reductions are consistently maintained and makes PM CEMS the best choice for this rule’s compliance monitoring. 
Comment: Some commenters objected 
to the EPA’s proposal to require the use of PM CEMS for purposes of demonstrating compliance with the revised fPM standard, stating that the requirements of Performance Specification 11 of 40 CFR part 60, appendix B (PS–11) will become extremely hard to satisfy at the low emission limits proposed. For PS–11, relative correlation audit (RCA), and relative response audit (RRA), the tolerance interval and confidence interval requirements are expressed in terms of the emission standard that applies to the source. The commenters reviewed test data from operating units and found significantly higher PS–11 failure (>80 percent), RCA failure (>80 percent), and RRA failure (60 percent) rates at the more stringent proposed emission limits. They stated that the cost, complexity, and failure rate of equipment calibration remains one of the biggest challenges with the use of PM CEMS and therefore other compliance demonstration methods should be retained. Commenters also noted that repeated tests due to failure could result in higher total emissions from the units. 
Response: The Agency is aware of 
concerns by some commenters that PM CEMS currently correlated for the 0.030 lb/MMBtu fPM emission limit may experience difficulties should re- correlation be necessary; and those concerns are also ascribed to yet-to-be installed PM CEMS. In response to those concerns, the Agency has shifted the basis of correlation testing from requiring only the collection of a minimum volume per run to also allowing the collection of a minimum mass per run and has adjusted the QA criterion otherwise associated with the new emission limit. These changes will ease the transition for coal- and oil-fired EGUs using only PM CEMS for compliance demonstration purposes. The first change, allowing the facility to choose either the collection of a minimum mass per run or a minimum volume per run, should reduce high- level correlation testing duration, addressing other concerns about extended runtimes with degraded emissions control or increased emissions, and should reduce correlation testing costs. The second change, adjusting the QA criteria, is consistent with other approaches the Agency has used when lower ranges of instrumentation or methods are employed. For example, in section 13.2 of Performance Specification 2 (40 CFR part 60, appendix B) the QA criteria for the relative accuracy test audit for SO
2 
and Nitrogen Oxide CEMS are relaxed as the emission limit decreases. This is accomplished at lower emissions by allowing a larger criterion or by 
modifying the calculation and allowing a less stringent number in the denominator. With these changes to the QA criteria and correlation procedures, the EPA believes EGUs will be able to use PM CEMS to demonstrate compliance at the revised level of the fPM standard. 
Comment: Some commenters asserted 
that if the EPA finalizes the requirement 
to demonstrate compliance using PM CEMS, EGUs will not be able to comply with a lower fPM limit on a continuous basis and that accompanying a lower limit with more restrictive monitoring requirements adds to the regulatory burden of affected sources and permitting authorities. 
Response: The EPA disagrees with 
commenters’ claim that that EGUs will not be able to demonstrate compliance continuously with a fPM limit of 0.010 lb/MMBtu. The EPA believes that CEMS in general and PM CEMS in particular enable owners and operators to detect and quickly correct control device or process issues in many cases before the issues become compliance problems. Contrary to the commenter’s assertion that EGUs will not be able to comply with a lower fPM limit on a continuous basis, as mentioned in the June 2023 Andover Technology Partners analysis,
39over 80 percent of EGUs 
using PM CEMS for compliance purposes have already been able to achieve and are reporting and certifying consistent achievement of fPM rates below 0.010 lb/MMBtu.
40The EPA is 
unaware of any additional burden experienced by those EGU owners or operators or their regulatory authorities with regard to PM CEMS use at these lower emission levels, and does not expect additional burden to be placed on EGU owners or operators with regard to PM CEMS from application of the revised emission limit. However, this final rule incorporates approaches, such as switching from a minimum sample volume per run to collection of a 
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41See 88 FR 24872. 42As noted in section III.A. above, there are 
nonetheless independent reasons for adopting both 
the revision to the fPM standard and the PM CEMS compliance demonstration requirement and each of these changes would continue to be workable without the other in effect, such that the EPA finds the two revisions are severable from each other. minimum mass sample or mass volume 
per run and adjusting the PM CEMS QA acceptability criteria, to reduce the challenges with using PM CEMS. Moreover, the 30-boiler-operating-day averaging period of the limit provides flexibility for owners and operators to account for equipment malfunctions and other issues. Consistent with the discussion in the 2023 Proposal,
41the 
Agency finds that PM CEMS are the best choice for this rule’s compliance monitoring as they provide increased emissions transparency, ability for EGU owner/operators to quickly detect and correct potential control or operational problems, and greater assurance of continuous compliance. While PM CEMS can produce values at lower levels provided correlations are developed appropriately, the Agency established the final fPM limit of 0.010 lb/MMBtu after considering factors such as run times necessary to develop correlations, potential random error effects, and costs. 
Comment: Commenters stated that the 
EPA’s cost estimates contradict the Agency’s suggestion that the use of PM CEMS is a more cost-effective monitoring approach than quarterly testing, especially for units that qualify as LEE. They said that the EPA used estimates from the Institute of Clean Air Companies (ICAC) or Envea/Altech which do not include numerous costs associated with PM CEMS that make them not cost-effective, such as the cost of intermittent stack testing associated with the PS–11 correlations and the ongoing costs of RCAs and RRA, which are a large part of the costs associated with PM CEMS and would rise substantially in conjunction with the proposed new PM limits. The commenters said that the ICAC estimated range of PM CEMS installation costs are particularly understated and outdated and should be ignored by the Agency. They said that the EPA estimates may also understate PM CEMS cost by assuming the most commonly used light scattering based PM CEMS will be used for all applications. The commenters said that while more expensive, a significant number of beta gauge PM CEMS are used for MATS compliance, especially where PM spiking is used for PS–11 correlation and RCA testing and that this higher degree of accuracy from beta 
gauge PM CEMS may be needed for sources without a margin of compliance under the new, more stringent emission limit. 
Response: The EPA disagrees with the 
commenters’ suggestion that the Agency is required to select the most cost- 
effective approach for compliance monitoring. Rather, the Agency selects the approach that best provides assurance that emission limits are met. PM CEMS annual costs represent a very small fraction of a typical coal-fired EGU’s operating costs and revenues. As described in the Ratio of Revised Estimated Non-Beta Gauge PM CEMS EUAC to 2022 Average Coal-Fired EGU Gross Profit memorandum, available in the docket, if all coal-fired EGUs were to purchase and install new PM CEMS, the Equivalent Uniform Annual Cost (EUAC) would represent less than four hundredths of a percent of the average annual operating expenses from coal- fired EGUs. 
Further, as described in the Revised 
Estimated Non-Beta Gauge PM CEMS and Filterable PM Testing Costs technical memorandum, available in the rulemaking docket, the EPA calculated average costs for PM CEMS and quarterly testing from values submitted by commenters in response to the proposal’s solicitation, which are discussed in section IV.D. of the preamble. Based on the commenters’ suggestions, these revised costs include the costs of intermittent stack testing associated with the PS–11 correlations and ongoing costs of RCAs and RRAs. While the average EUAC for PM CEMS exceeds the average annual cost of quarterly stack emission testing, the cost for PM CEMS does not include important additional benefits associated with providing continuous emissions data to EGU owners or operators, regulators, nearby community members, or the general public. As a reminder, the EPA is not obligated to choose the most inexpensive approach for compliance demonstrations, particularly when all benefits are not monetized, even though costs can be an important consideration. Consistent with the discussion contained in the 2023 Proposal at 88 FR 24872, the Agency finds the increased transparency of EGU fPM emissions and the ability to quickly detect and correct potential control or operational problems, along with greater assurance of continuous compliance makes PM CEMS the best choice for this rule’s compliance monitoring. 
The Agency acknowledges the 
commenters’ suggestions that EGU owners or operators may find that using beta gauge PM CEMS is most appropriate for the lower fPM emission limit in the rule; such suggestions are consistent with the Agency’s view, as expressed in 88 FR 24872. However, the Agency believes other approaches, 
including spiking, can also ease correlation testing for PM CEMS. Moreover, the Agency anticipates that 
the new fPM limit will increase demand for, and perhaps spur increased production of, beta gauge PM CEMS. 
D. What is the rationale for our final 
approach and decisions for the filterable PM (as a surrogate for non-Hg HAP metals) standard and compliance demonstration options? 
The EPA is finalizing a lower fPM 
emission standard of 0.010 lb/MMBtu for coal-fired EGUs, as a surrogate for non-Hg HAP metals, and the use of PM CEMS for compliance demonstration purposes for coal- and oil-fired EGUs (with the exception of limited-use liquid oil-fired EGUs) based on developments in the performance of sources within the category since the EPA finalized MATS and the advantages conferred by using CEMS for compliance. As described in the 2023 Proposal, non-Hg HAP metals are predominately a component of fPM, and control of fPM results in concomitant reduction of non-Hg HAP metals (with the exception of Se, which may be present in the filterable fraction or in the condensable fraction as the acid gas, SeO
2). The EPA observes that 
since MATS was finalized, the vast 
majority of covered units have significantly outperformed the standard, with a small number of units lagging behind and emitting significantly higher levels of these HAP in communities surrounding those units. The EPA deems it appropriate to require these lagging units to bring their pollutant control performance up to that of their peers. Moreover, the EPA concludes that requiring use of PM CEMS for compliance yields manifold benefits, including increased emissions transparency and data availability for owners and operators and for nearby communities. 
The EPA’s conclusions with regard to 
the fPM standard and requirement to use PM CEMS for compliance demonstration are closely related, both in terms of CAA section 112(d)(6)’s direction for the EPA to reduce HAP emissions based on developments in practices, processes, and control technologies, and in terms of technical compatibility.
42The EPA finds that the 
manifold benefits of PM CEMS render it appropriate to promulgate an updated fPM emission standard as a surrogate for non-Hg HAP metals for which PM CEMS can be used to monitor 
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43WebFIRE includes data submitted to the EPA 
from the Electronic Reporting Tool (ERT) and is 
searchable at https://cfpub.epa.gov/webfire/reports/ esearch.cfm. 44Analysis of PM and Hg Emissions and Controls 
from Coal-Fired Power Plants. Andover Technology Partners. August 19, 2021. Document ID No. EPA– HQ–OAR–2018–0794–4583. 45EPA’s CAA section 112(f)(2) quantitative risk 
assessments evaluate cancer risk associated with a lifetime of exposure to HAP emissions from each source in the source category, the potential for HAP exposure to cause adverse chronic (or long-term) noncancer health effects, and the potential for HAP compliance. However, as the fPM limit 
is lowered, operators may encounter difficulties establishing and maintaining existing correlations for the PM CEMS and may therefore be unable to provide accurate values necessary for compliance. The EPA has determined, based on comments and on the additional analysis described below, that the lowest possible fPM limit considering these challenges at this time is 0.010 lb/MMBtu with adjusted QA criteria. Therefore, the EPA determined that this two-pronged approach— requiring PM CEMS in addition to a lower fPM limit—is the most stringent option that balances the benefits of using PM CEMS with the emission reductions associated with the tightened fPM emission standard. Further, the EPA finds that the more stringent limit of 0.006 lb/MMBtu fPM cannot be adequately monitored with PM CEMS at this time, because the random error component of measurement uncertainty from correlation stack testing is too large and the QA criteria passing rate for PM CEMS is too small to provide accurate (and therefore enforceable) compliance values. Below, we further describe our rationale for each change. 
1. Rationale for the Final Filterable PM 
Emission Standard 
In the 2023 Proposal, the Agency 
proposed a lower fPM emission standard for coal-fired EGUs as a surrogate for non-Hg HAP metals based on developments in practices, processes, and control technologies pursuant to CAA section 112(d)(6), including the EPA’s assessment of the differing performance of sources within the category and updated information about the cost of controls. As described in the 2023 Proposal, non-Hg HAP metals are predominately a component of fPM, and control of fPM results in reduction of non-Hg HAP metals (with the exception of Se, which may be present in the filterable fraction or in the condensable fraction as the acid gas, SeO
2). 
In conducting this technology review, 
the EPA found important developments that informed its proposal. First, from reviewing historical information contained in WebFIRE,
43the EPA 
observed that most EGUs were reporting fPM emission rates well below the 0.030 lb/MMBtu standard. The fleet was achieving these performance levels at lower costs than estimated during promulgation of the 2012 MATS Final Rule. Second, there are technical developments and improvements in PM control technology since the 2012 MATS Final Rule that informed the 2023 Proposal.
44For example, while 
ESP technology has not undergone fundamental changes since 2011, industry has learned and adopted ‘‘best practices’’ associated with monitoring ESP operation more carefully since the 2012 MATS Final Rule. For FFs, more durable materials have been developed since the 2012 MATS Final Rule, which are less likely to fail due to chemical, thermal, or abrasion failure and create risks of high PM emissions. For instance, fiberglass (once the most widely used material) has largely been replaced by more reliable and easier to clean materials, which are more costly. Coated fabrics, such as Teflon or P84 felt, also clean easier than other fabrics, which can result in less frequent cleaning, reducing the wear that could damage filter bags and reduce the effectiveness of PM capture. 
To examine potential revisions, the 
EPA evaluated fPM compliance data for the coal-fired fleet and evaluated the control efficiency and costs of PM controls to achieve a lower fPM standard. Based on comments received on the 2023 Proposal, the EPA reviewed additional fPM compliance data for 62 EGUs at 33 facilities (see 2024 Technical Memo and attachments for detailed information). The review of additional fPM compliance data showed that more EGUs had previously demonstrated an ability to meet a lower fPM rate, as shown in figure 4 of the 2024 Technical Memo. Compared to the 2023 Proposal where 91 percent of existing capacity demonstrated an ability to meet 0.010 lb/MMBtu, the updated analysis showed that 93 percent are demonstrating the ability to meet 0.010 lb/MMBtu with existing controls. The EPA received comments on the cost assumptions for upgrading PM controls and found that the costs estimated at proposal were not only too high, but that the cost effectiveness of PM upgrades was also underestimated (i.e., the standard is 
more cost-effective than the EPA believed at proposal). 
The EPA is finalizing the fPM 
emission limit of 0.010 lb/MMBtu with adjusted QA criteria, based on developments since 2012, for the reasons described in this final rule and in the 2023 Proposal as the lowest achievable fPM limit that allows for the use of PM CEMS for compliance demonstration purposes. First, this level of control ensures that the highest emitters bring their performance to a level where the vast majority of the fleet is already performing. For example, as described above, the majority of the existing coal-fired fleet subject to this final rule has previously demonstrated an ability to comply with the lower 0.010 lb/MMBtu fPM limit at least 99 percent of the time during one quarter, in addition to meeting the lower fPM limit on average across all quarters assessed. The Agency estimates that only 33 EGUs are currently operating above this revised limit. Compared to some of the best performing EGUs, the 33 EGUs requiring additional PM control upgrades or maintenance are more likely to have an ESP instead of a FF and to demonstrate compliance using intermittent stack testing. In addition, most of these EGUs have operated at a higher level of utilization than the coal-fired fleet on average. 
Second, as discussed in section II.A.2. 
above, Congress updated CAA section 112 in the 1990 Clean Air Act Amendments to achieve significant reductions in HAP emissions, which it recognized are particularly harmful pollutants, and implemented a regime under which Congress directed the EPA to make swift and substantial reductions to HAP based upon the most stringent standards technology could achieve. This is evidenced by Congress’s charge to the EPA to ‘‘require the maximum degree of reduction in emissions of hazardous air pollutants (including a prohibition on such emissions),’’ that is achievable accounting for ‘‘the cost of achieving such emission reduction, and any non-air quality health and environmental impacts and energy requirements. . . .’’ CAA section 112(d)(2). Further, by creating separate and distinct requirements for the EPA to consider updates to CAA section 112 pursuant to both technology review under CAA section 112(d)(6) and residual risk review under CAA section 112(f)(2), Congress anticipated that the EPA would strengthen standards pursuant to technology reviews ‘‘as necessary (taking into account developments in practices, processes, and control technologies),’’ CAA section 112(d)(6), even after the EPA concluded there was an ample margin of safety based on the risks that the EPA can quantify.
45As the EPA explained in the 
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exposure to cause adverse acute (or short-term) 
noncancer health effects. 
46See, e.g., National Emission Standards for 
Hazardous Air Pollutants: Site Remediation Residual Risk and Technology Review, 85 FR 41680, 41698 (July 10, 2020) (proposed 84 FR 46138, 46161; September 3, 2019)) (requiring 
compliance with more stringent equipment leak definitions under a technology review, which were widely adopted by industry); National Emissions Standards for Mineral Wool Production and Fiberglass Manufacturing, 80 FR 45280, 45307 (July 29, 2015) (adopting more stringent limits for glass- melting furnaces under a technology review where the EPA found that ‘‘all glass-melting furnaces were achieving emission reductions that were well below the existing MACT standards regardless of the control technology in use’’); National Emissions Standards for Hazardous Air Pollutants From Secondary Lead Smelting, 77 FR 556, 564 (January 5, 2012) (adopting more stringent stack lead emission limit under a technology review ‘‘based on emissions data collected from industry, which indicated that well-performing baghouses currently used by much of the industry are capable of achieving outlet lead concentrations significantly lower than the [current] limit.’’). 
47See figure 4 of the 2024 Technical Memo. 
48See Document CLT–1T Testimony, CLT–11, 
and CL–12 in Docket 190882 at https://www.utc.wa.gov/documents-and-proceedings/dockets. 
49See NorthWestern Energy’s Annual PCCAM 
Filing and Application for Approval of Tariff Changes, Docket No. 2019.09.058, Final Order 7708f paragraph 21 (November 18, 2020) (noting that ‘‘Colstrip has a history of operating very close to the upper end limit’’), available at https://reddi.mt.gov/ prweb. 
50For reference, a dekatherm is equivalent to one 
million Btus (MMBtu). 51See Document ID No. EPA–HQ–OAR–2018– 
5984 at https://www.regulations.gov. proposal, the EPA does consider costs, 
technical feasibility, and other factors when evaluating whether it is necessary to revise existing emission standards under CAA section 112(d)(6) to ensure the standards ‘‘require the maximum degree of emissions reductions . . . achievable.’’ CAA section 112(d)(2). The text, structure, and history of this provision demonstrate Congress’s direction to the EPA to require reduction in HAP where technology is available to do so and the EPA accounts for the other statutory factors. 
Accordingly, the EPA finds that 
bringing this small number of units to the performance levels of the rest of the fleet serves Congress’s mandate to the EPA in CAA section 112(d)(6) to continually consider developments ‘‘that create opportunities to do even better.’’ See LEAN, 955 F.3d at 1093. As 
such, the EPA has a number of times in the past updated its MACT standards to reflect developments where the majority of sources were already outperforming the original MACT standards.
46Indeed, 
this final rule is consistent with the EPA’s authority pursuant to CAA section 112(d)(6) to take developments in practices, processes, and control technologies into account to determine if more stringent standards are achievable than those initially set by the EPA in establishing MACT floors, based on developments that occurred in the interim. See LEAN v. EPA, 955 F.3d 
1088, 1097–98 (D.C. Cir. 2020). 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, and those controls are of reasonable cost, sources should be required to use them. 
The fleet has been able to ‘‘over 
comply’’ with the existing fPM standard due to the very high PM control 
effectiveness of well-performing ESPs and FFs, often exceeding 99.9 percent. But the performance of a minority of units lags well behind the vast majority of the fleet. As indicated by the two highest fPM rates,
47EGUs without the 
most effective PM controls have not been able to demonstrate fPM rates comparable to the rest of the fleet. Specifically, the Colstrip facility, a 1,500 MW subbituminous-fired power plant located in Colstrip, Montana, operates the only two coal-fired EGUs in the country without the most modern PM controls (i.e., ESP or FF). Instead, 
this facility utilizes venturi wet scrubbers as its primary PM control technology and has struggled to meet the original 0.030 lb/MMBtu fPM limit, even while employing emissions 
averaging across the operating EGUs at the facility. Colstrip is also the only facility where the EPA estimates the current controls would be unable to meet a lower fPM limit. Specifically, the 2018 second quarter compliance stack tests showed average fPM emission rates above the 0.030 lb/MMBtu fPM limit, in violation of its Air Permit. Talen Energy, one of the owners of the facility, agreed to pay $450,000 to settle these air quality violations.
48As a result, the 
plant was offline for approximately 2.5 months while the plant’s operator worked to correct the problem. Comments from Colstrip’s majority owners discuss the efforts this facility has undergone to improve their wet PM scrubbers, which they state remove 99.7 percent of the fly ash particulate but agree with the EPA that additional controls would be needed to meet a 0.010 lb/MMBtu limit. However, as stated in NorthWestern Energy’s Annual PCCAM Filing and Application of Tariff Changes,
49‘‘Colstrip has a history of 
operating very close to the upper end limit: for 43 percent of the 651 days of compliance preceding the forced outage its [Weighted Average Emission Rate or] WAER was within 0.03 lb/dekatherm
50 
of the limit [. . . to comply with the Air Permit and MATS, Colstrip’s WAER must be equal to or less than 0.03 lb/ dekatherm].’’ The Northern Cheyenne Reservation 
is 20 miles from the Colstrip facility and 
the Tribe exercised its authority in 1977 to require additional air pollution controls on the new Colstrip units (Colstrip 3 and 4, the same EGUs still operating today), recognizing the area as a Class I airshed under the CAA. According to comments submitted by the Northern Cheyenne Tribe, their tribal members—both those living on the Reservation and those living in the nearby community of Colstrip—have been disproportionally impacted by exposure to HAP emissions from the Colstrip facility.
51 
The EPA believes a fPM emission 
limit of 0.010 lb/MMBtu appropriately takes into consideration the costs of controls. 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. Costs of PM upgrades are much lower than the EPA estimated in 2012, and the Agency revised its costs assumptions as described in the 2024 Technical Memo, available in the docket. Table 4 of this document summarizes the updated cost effectiveness of the three fPM emission limits considered in the 2023 Proposal for the existing coal-fired fleet. For the purpose of estimating cost effectiveness, the analysis presented in this table, described in detail in the 2023 and 2024 Technical Memos, is based on the observed emission rates of all existing coal-fired EGUs except for those that have announced plans to retire by the end of 2028. The analysis presented in table 4 estimated the costs associated for each unit to upgrade their existing PM controls to meet a lower fPM standard. In the cases where existing PM controls would not achieve the necessary reductions, unit-specific FF install costs were estimated. Unlike the cost and benefit projections presented in the RIA, 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 IRA, future regulatory actions, or changes in economic conditions. For example, of the more than 14 GW of coal-fired capacity that the EPA estimates would require control improvements to achieve the final fPM rate, less than 12 GW is projected to be 
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52See, e.g., National Emission Standards for 
Hazardous Air Pollutants: Mercury Cell Chlor- 
Alkali Plants Residual Risk and Technology Review, 87 FR 27002, 27008 (May 6, 2022) (considered 
annual costs and average capital costs per facility in technology review and beyond-the-floor analysis); National Emission Standards for 
Hazardous Air Pollutants: Primary Copper Smelting Residual Risk and Technology Review and Primary Copper Smelting Area Source Technology Review, operational in 2028 (see section 3 of the 
RIA for this final rule). 
BILLING CODE 6560–50–P 
BILLING CODE 6560–50–C 
The EPA has updated its costs 
analyses for this final rule based on 
comments received and additional data review, which is described in more detail in the 2024 Technical Memo available in the docket. In response to commenters stating that the use of the lowest quarter’s 99th percentile, or the lowest achievable fPM rate, is not indicative of overall EGU operation and emission performance, the EPA added a review of average fPM rates. In these updated analyses, both the lowest quarter’s 99th percentile and the average fPM rate must be below the potential fPM limit for the EPA to assume no additional upgrades are needed to meet a revised limit. If an EGU has previously demonstrated an ability to meet a potential lower fPM limit, but the average fPM rate is greater than the potential limit, the analysis for the final rule has been updated to assume increased bag replacement frequency (for units with FFs) or operation and maintenance costing $100,000/year 
(2022$). This additional cost represents increased vigilance in maintaining ESP performance and includes technician labor to monitor performance of the ESP and to periodically make typical repairs (e.g., replacement of failed insulators, 
damaged electrodes or other internals that may fail, repairing leaks in the ESP casing, ductwork, or expansion joints, and periodic testing of ESP flow balance and any needed adjustments). 
Additionally, the Agency received 
comments that the PM upgrade costs 
estimated at proposal were too high on a dollar per ton basis and these costs have been updated and are provided in the 2024 Technical Memo. Specifically, commenters demonstrated that the observed percent reductions in fPM attributable to ESP upgrades were significantly greater than the percent reductions that the EPA had assumed for the proposed rule. Additionally, commenters demonstrated that ESP performance guarantees for coal-fired utility boilers were much lower than the 
EPA was aware of at proposal. These updates, as well as improving our methodology which increases the number of EGUs estimated to need PM upgrades, slightly lower the dollar per ton estimates from what was presented in the 2023 Proposal. 
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).
52As much of the 
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ER07MY24.068</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 4. Summary of the Updated Cost Effectiveness Analysis for Three Potential fPM 
Limits1 
Potential fPM emission limit (lb/MMBtu) 
0.015 0.010 0.006 
Affected Units 11 (4.7) 33 (14.1) 94 (41.3) 
(Capacity, GW) 
Annual Cost ($M, 38.8 87.2 398.8 
2019 dollars) 
fPM Reductions ( tov) 1,258 2,526 5,849 
Total Non-Hg HAP 3.0 8.3 22.7 
Metals Reductions 
(tpy) 
Total Non-Hg HAP 13,050 10,500 17,500 
Metals Cost 
Effectiveness 
($k/ton) 
Total Non-Hg HAP 6,500 5,280 8,790 
Metals Cost 
Effectiveness ($/lb) 
1 This analysis used reported fPM compliance data for 296 coal-fired EGUs to develop unit­
specific average and lowest achieved fPM rate values to determine if the unit, with existing PM 
controls, could achieve a lower fPM limit. Using the compliance data, the EPA evaluated costs to 
upgrade existing PM controls, or if necessary, install new controls in order to meet a lower fPM 
limit. 38533 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
87 FR 1616, 1635 (proposed January 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 RTR and Standards of Performance for Phosphate Processing, 80 FR 50386, 50398 (August 19, 2015) (considered total annual costs and capital costs compliance costs and annualized costs for technology review and beyond the floor analysis); National Emissions Standards for Hazardous Air Pollutants: 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); National 
Emission Standards for Hazardous Air Pollutants: Off-Site Waste and Recovery Operations, 80 FR 14248, 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); National Emission Standards for Hazardous Air Pollutant Emissions: Hard and Decorative Chromium Electroplating and Chromium Anodizing Tanks; and Steel Pickling- HCl Process Facilities and Hydrochloric Acid Regeneration Plants, 77 FR 58220, 58226 (September 19, 2012) (considered total annual costs and capital costs in technology review); Oil and 
Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews, 77 FR 49490, 49523 (August 16, 2012) (considered total capital costs and annualized costs and capital costs in technology review). C.f. NRDC v. EPA, 749 F.3d 
1055, 1060 (D.C. Cir. 2014). 
53See Cost TSD for 2022 Proposal at Document 
ID No. EPA–HQ–OAR–2018–0794–4620 at https:// 
www.regulations.gov. 542019 dollars were used for consistency with the 
2023 Proposal. 55See note 50, above, for examples of other costs 
metrics the EPA has considered in prior CAA section 112 rulemakings. fleet is already reporting fPM emission 
rates below 0.010 lb/MMBtu, both the total costs and non-Hg HAP metal reductions of the revised limit are modest in context of total PM upgrade control costs and emissions of the coal fleet. The cost-effectiveness estimate for EGUs reporting average fPM rates above the final fPM emission limit of 0.010 lb/ MMBtu is $10,500,000/ton of non-Hg HAP metals, slightly lower than the range presented in the 2023 Proposal. 
Further, the EPA finds that costs for 
facilities to meet the revised fPM emission limit represent a 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 Final Rule relative to the typical annual revenues, capital expenditures, and total (capital and production) expenditures.
53 
87 FR 7648–7659 (February 9, 2022); 80 FR 37381 (June 30, 2015). Using electricity sales data from the U.S. Energy Information Administration (EIA), the EPA updated the analysis presented in the 2022 Proposal. We find revenues from retail electricity sales increased from $333.5 billion in 2000 to a peak of $429.6 billion in 2008 (an increase of about 29 percent during this period) and slowly declined since to a post-2011 low of $388.6 billion in 2020 (a decrease of about 10 percent from its peak during this period) in 2019 dollars.
54Revenues increased in 2022 to 
nearly the same amount as the 2008 peak ($427.8 billion). The annual control cost estimate for the final fPM standard based on the cost-effectiveness analysis in table 4 (see section 1c of the 2024 Technical Memo) of this document is a very small share of total power sector sales (about 0.03 percent of the lowest year 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 estimates. Therefore, as in previous CAA section 112 rulemakings, the EPA considered costs in many ways, including cost effectiveness, the total capital costs of proposed measures, annual costs, and costs compared to total revenues to determine the appropriateness of the revised fPM standard under the CAA section 112(d)(6) technology review, and determined the costs are reasonable. 
In this final rule, the EPA finds that 
costs of the final fPM standard are reasonable, and that the revised fPM standard appropriately balances the EPA’s obligation under CAA section 112 to achieve the maximum degree of emission reductions considering statutory factors, including costs. Further, the EPA finds that its consideration of costs is consistent with D.C. Circuit precedent, which has found that CAA section 112(d)(2) expressly authorizes cost consideration in other aspects of the standard-setting process, 
such as CAA section 112(d)(6), see Association of Battery Recyclers, Inc. v. EPA, 716 F.3d 667, 673–74 (D.C. Cir. 
2013), and that CAA section 112 does not mandate a specific method of cost analysis in an analogous situation when considering the beyond-the-floor review. See NACWA v. EPA, 734 F.3d 
1115, 1157 (D.C. Cir. 2013) (finding the statute did not ‘‘mandate a specific method of cost analysis’’); see also NRDC v. EPA, 749 F.3d 1055, 1060–61 
(D.C. Cir. 2014). 
As discussed in section IV.C.1. in 
response to comments regarding the relatively higher dollar per ton cost effectiveness of the final fPM standard, the EPA finds that in the context of this industry and this rulemaking, the updated standards are an appropriate exercise of the EPA’s standard setting authority pursuant to the CAA section 112(d)(6) technology review. As commenters rightly note, the EPA routinely considers the cost effectiveness of potential standards 
where it can consider costs under CAA section 112, e.g., in conducting beyond- 
the-floor analyses and technology reviews, to determine the achievability of a potential control option. And the D.C. Circuit recognized that the EPA’s interpretation of costs as ‘‘allowing consideration of cost effectiveness was reasonable.’’ NRDC v. EPA, 749 F.3d 
1055, 1060–61 (D.C. Cir. 2014) (discussing the EPA’s consideration of cost effectiveness pursuant to a CAA section 112(d)(2) beyond-the-floor analysis). However, cost effectiveness is not the sole factor that the EPA considers when determining the achievability of a potential standard in conducting a technology review, nor is cost effectiveness the only value that the EPA considers with respect to costs.
55 
Some commenters pointed to other rulemakings (which are discussed in section IV.C.1. above) where the EPA determined not to pursue potential control options with relatively higher cost-effectiveness estimates as compared to prior CAA section 112 rulemakings. However, there were other factors that the EPA considered, in addition to cost effectiveness, that counseled against pursuing such updates. In this rulemaking, the EPA finds that several factors discussed throughout this record make promulgation of the new fPM standard appropriate under CAA section 
112(d)(6). First, a wide majority of units have invested in the most-effective PM controls and are already demonstrating compliance with the new fPM standard and at lower costs than assumed during promulgation of the original MATS fPM emission limit. Of the 33 EGUs that the EPA estimated would require control improvements to meet a 0.010 lb/ MMBtu fPM standard, only two are not using the most effective PM control technologies available. The EPA assumed that these two units would need to install FFs to achieve the 0.010 lb/MMBtu emission standard, and the cost of those FF retrofits accounts for 42 percent of the total annualized costs presented in table 4. Further, 11 EGUs that the EPA assumed would require different levels of ESP upgrades to meet the 0.010 lb/MMBtu emission standard (all of which have announced retirement dates between 2031 and 2042 resulting in shorter assumed amortization periods) account for about 57 percent of the total annualized costs. The remaining 1 percent of the total annualized costs are associated with 10 EGUs with existing FFs that the EPA 
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56This is a fact which Congress recognized in 
requiring the EPA to first determine whether 
regulation of coal-fired EGUs was ‘‘appropriate and necessary’’ under CAA section 112(n)(1)(A) before proceeding to regulate such facilities under CAA section 112’s regulatory scheme. 57Run durations greater than 4 hours would 
ensure adequate sample collection and lower random error contributions to measurement uncertainty for a limit of 0.006 lb/MMBtu. The EPA aims to keep run durations as short as possible, generally at least one but no more than 4 hours in length, in order to minimize impacts to the facility (e.g., overall testing campaign testing costs, 
employee focused attention and safety). assumes will require bag upgrades or 
increased bag changeouts and 10 EGUs that are assumed to need additional operation and maintenance of existing ESPs, which is further explained in the 2024 Technical Memo. Since only a small handful of units emit significantly more than peer facilities, the Agency finds these upgrades appropriate. Additionally, the size and unique nature of the coal-fired power sector, and the emission reductions that will be achieved by the new standard, in addition to the costs, make promulgation of the new standard appropriate under CAA section 112(d)(6). 
The power sector also operates 
differently than other industries regulated under CAA section 112.
56For 
example, the power sector is publicly regulated, with long-term decision- making and reliability considerations made available to the public; it is a data- rich sector, which generally allows the EPA access to better information to inform its regulation; and the sector is in the midst of an energy generation transition leading to plant retirements that are independent of EPA regulation. Because of the relative size of the power sector, while cost effectiveness of the final standard is relatively high as compared to prior CAA section 112 rulemakings involving other industries, costs represent a much smaller fraction of industry revenue. 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 emission reductions achieved by each final fPM standard in table 4 of this document would also be an overestimate. 
As demonstrated in the proposal, the 
power sector, as a whole, is achieving fPM emission rates that are well below the 0.030 lb/MMBtu standard from the 2012 Final MATS Rule, with the exception of a few outlier facilities. The EPA estimates that only one facility (out of the 151 evaluated coal-fired facilities), which does not have the most modern PM pollution controls and has been unable to demonstrate an ability to meet a lower fPM limit, will be required to install the most-costly upgrade to meet the revised standards, which significantly drives up the cost of this final rule. However, the higher costs for one facility to install demonstrated improvements to its control technology 
should not prevent the EPA from establishing achievable standards for the sector under the EPA’s CAA section 112(d)(6) authority. Instead, the EPA finds that it is consistent with its CAA section 112(d)(6) authority to consider the performance of the industry at large. The average fPM emissions of the industry demonstrate the technical feasibility of higher emitting facilities to meet the new standard and shows there are proven technologies that if installed at these units will allow them to significantly lower fPM and non-Hg HAP metals emissions. 
In this rulemaking, the EPA also 
determined not to finalize a more stringent standard for fPM emissions, such as a limit of 0.006 lb/MMBtu or lower, which the EPA took comment on in the 2023 Proposal. The EPA declines to finalize an emission standard of 0.006 lb/MMBtu or lower primarily due to technical limitations in using PM CEMS for compliance demonstration purposes described in the next section. The EPA has determined that a fPM emission standard of 0.010 lb/MMBtu is the lowest that would also allow the use of PM CEMS for compliance demonstration. Additionally, the EPA also considered the overall higher costs associated with a more stringent standard as compared to the final standard, which the EPA considered under the technology review. 
Additionally, compliance with a fPM 
emission limit of 0.006 lb/MMBtu could only be demonstrated using periodic stack testing that would require test run durations longer than 4 hours
57and 
would not provide the source, the public, and regulatory authorities with continuous, transparent data for all periods of operation. Establishing a fPM limit of 0.006 lb/MMBtu while maintaining the current compliance demonstration flexibilities of quarterly ‘‘snapshot’’ stack testing would, theoretically, result in greater emission reductions; however, the measured emission rates are only representative of rates achieved at optimized conditions at full load. While coal-fired EGUs have historically provided baseload generation, they are being dispatched much more as load following generating sources due to the shift to more available and cheaper natural gas and renewable generation. As such, traditional generation assets—such as coal-fired EGUs—will likely continue to 
have more startup and shutdown periods, more periods of transient operation as load following units, and increased operation at minimum levels, all of which can produce higher PM emission rates. Maintaining the status quo with quarterly stack testing will likely mischaracterize emissions during these changing operating conditions. Thus, while a fPM emission limit of 0.006 lb/MMBtu paired with use of quarterly stack testing may appear to be more stringent than the 0.010 lb/MMBtu standard paired with use of PM CEMS that the EPA is finalizing in this rule, there is no way to confirm emission reductions during periods in between quarterly tests when emission rates may be higher. Therefore, the Agency is finalizing a fPM limit of 0.010 lb/ MMBtu with the use of PM CEMS as the only means of compliance demonstration. The EPA has determined that this combination of fPM limit and compliance demonstration represents the most stringent available option taking into account the statutory considerations. 
The EPA also determined not to 
finalize a fPM standard of 0.015 lb/ MMBtu, which the EPA took comment on in the 2023 Proposal, because the EPA determined that a standard of 0.010 lb/MMBtu is appropriate for the reasons discussed above. 
In this rule, the EPA is also reaching 
a different conclusion from the 2020 Technology Review with respect to the fPM emission standard and requirements to utilize PM CEMS. As discussed in section II.D. above, the 2020 Technology Review did not consider developments in the cost and effectiveness of proven technologies to control fPM as a surrogate for non-Hg HAP metals emissions, nor did the EPA evaluate the current performance of emission reduction control equipment and strategies at existing MATS-affected EGUs. In this rulemaking, in which the EPA reviewed the findings of the 2020 Technology Review, the Agency determined there are important developments regarding the emissions performance of the coal-fired EGU fleet, and the costs of achieving that performance that are appropriate for the EPA to consider under its CAA section 
112(d)(6) authority, and which are the basis for the revised emissions standards the EPA is promulgating through this final rule. 
The 2012 MATS Final Rule contains 
emission limits for both individual and total non-Hg HAP metals (e.g., lead, 
arsenic, chromium, nickel, and cadmium), as well as emission limits for fPM. Those non-Hg HAP metals 
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58The EPA explains additional analyses of PM 
CEMS in the memos titled Suitability of PM CEMS 
Use for Compliance Determination for Various Emissions Levels and Summary of Review of 36 PM 
CEMS Performance Test Reports versus PS11 and Procedure 2 of 40 CFR part 60, appendices B and F, respectively, which are available in the docket. 59The EPA notes that the fPM standard [0.010 lb/ 
MMBtu] is based on hourly averages obtained from PM CEMS over 30 boiler operating days [see 40 CFR 63.10021(b)]. 
60Method 5I is one of the EPA’s reference test 
methods for PM. See 40 CFR part 60, appendix A. 
61See Revised Estimated Non-Beta Gauge PM 
CEMS and Filterable PM Testing Costs memorandum, available in the docket. emission limits serve as alternative 
emission limits because fPM was found to be a surrogate for either individual or total non-Hg HAP metals emissions. While EGU owners or operators may choose to demonstrate compliance with either the individual or total non-Hg HAP metals emission limits, the EPA is aware of just one owner or operator who has provided non-Hg HAP metals data— both individual and total—along with fPM data, for compliance demonstration purposes. This is for a coal refuse-fired EGU with a generating capacity of 46.1 MW. Given that owners or operators of all the other EGUs that are subject to the requirements in MATS have chosen to demonstrate compliance with only the fPM emission limit, the EPA proposed to remove the total and individual non- Hg HAP metals emission limits from all existing MATS-affected EGUs and solicited comment on our proposal. In the alternative, the EPA took comment on whether to retain total and/or individual non-Hg HAP metals emission limits that have been lowered proportionally to the revised fPM limit (i.e., revised lower by two-thirds to be 
consistent with the revision of the fPM standard from 0.030 lb/MMBtu to 0.010 lb/MMBtu). 
Commenters urged the EPA to retain 
the non-Hg HAP metals limits, arguing it is incongruous for the EPA to eliminate the measure for the pollutants that are the subject of regulation under CAA section 112(d)(6), notwithstanding the fact that the fPM limit serves as a more easily measurable surrogate for these HAP metals. Additionally, some commenters stated that the inability to monitor HAP metals directly will significantly impair the EPA’s ability to revise emission standards in the future. 
After considering comments, the EPA 
determined to promulgate revised total and individual non-Hg HAP metals emission limits for coal-fired EGUs that are lowered proportionally to the revised fPM standard. Just as this rule requires owners or operators to demonstrate continuous compliance with fPM limits, owners or operators who choose to demonstrate compliance with these alternative limits will need to utilize approaches that can measure non-Hg HAP metals on a continuous basis—meaning that intermittent emissions testing using Reference Method 29 will not be a suitable approach. Owners or operators may petition the Administrator to utilize an alternative test method that relies on continuous monitoring (e.g., multi-metal 
CMS) under the provisions of 40 CFR 63.7(f). The EPA disagrees with the suggestion that failure to monitor HAP metals directly could impair the ability 
to revise those standards in the future. 
2. Rationale for the Final Compliance 
Demonstration Options 
In the 2023 Proposal, the EPA 
proposed to require that coal- and oil- fired EGUs utilize PM CEMS to demonstrate compliance with the fPM standard used as a surrogate for non-Hg HAP metals. The EPA proposed the requirement for PM CEMS based on its assessment of costs of PM CEMS versus stack testing, and the many other benefits of using PM CEMS including increased transparency and accelerated identification of anomalous emissions. In particular, the EPA noted the ability for PM CEMS to provide continuous feedback on control device and plant operations and to provide EGU owners and operators, regulatory authorities, and members of nearby communities with continuous assurance of compliance with emissions limits as an important benefit. Further, the EPA explained in the 2023 Proposal that PM CEMS are currently in use by approximately one-third of the coal- fired fleet, and that PM CEMS can provide low-level measurements of fPM 
from existing EGUs. 
After considering comments and 
conducting further analysis,
58the EPA 
is finalizing the use of PM CEMS for compliance demonstration purposes for coal- and oil-fired EGUs pursuant to its CAA section 112(d)(6) authority. As discussed in section IV.D.1. above, Congress intended for CAA section 112 to achieve significant reductions in HAP, which it recognized as particularly harmful pollutants. The EPA finds that the benefits of PM CEMS to provide real-time information to owners and operators (who can promptly address any problems with emissions control equipment), to regulators, to adjacent communities, and to the general public, further Congress’s goal to ensure that emission reductions are consistently maintained. The EPA determined not to require PM CEMS for existing IGCC EGUs, described in section VI.D., due to technical issues calibrating CEMS on these types of EGUs due to the difficulty in preparing a correlation range because these EGUs are unable to de-tune their fPM controls and their existing emissions are less than one-tenth of the final emission limit. Further, the EPA finds additional authority to require the use of PM CEMS 
under CAA section 114(a)(1)(C), which allows that the EPA may require a facility that ‘‘may have information necessary for the purposes set forth in this subsection, or who is subject to any requirement of this chapter’’ to ‘‘install, use, and maintain such monitoring equipment’’ on a ‘‘on a one-time, periodic or continuous basis.’’ 114(a)(1)(C). 
From the EPA’s review of PM CEMS, 
the Agency determined that a fPM 
standard of 0.010 lb/MMBtu with adjusted QA criteria—used to verify consistent correlation of CEMS data initially and over time—is the lowest fPM emission limit possible at this time with use of PM CEMS.
59PM CEMS 
correlated using these values will ensure accurate measurements—either above, at, or below this emission limit. As discussed in section IV.D.1. above, one of the reasons the EPA determined not to finalize a more stringent standard for fPM is because it would prove challenging to verify accurate measurement of fPM using PM CEMS. Specifically, as mentioned in the Suitability of PM CEMS Use for Compliance Determination for Various Emission Levels, memorandum, available in the docket, no fPM standard more stringent than 0.010 lb/MMBtu with adjusted QA criteria is expected to have acceptable passing rates for the QA checks or acceptable random error for reference method testing. 
At proposal, the EPA estimated that 
the EUAC of PM CEMS was $60,100 (88 FR 24873). Based on comments the EPA received on the costs and capabilities of PM CEMS and additional analysis the EPA conducted, the EPA determined that the revised EUAC of PM CEMS is higher than estimated at proposal. The EPA now estimates that the EUAC of non-beta gauge PM CEMS is $72,325, which is 17 percent less than what was estimated for the 2012 MATS Final Rule. That amount is somewhat greater than the revised estimated costs of infrequent emission testing (generally quarterly)—the revised average estimated costs of such infrequent emissions testing using EPA Method 5I
60is $60,270.61 
In choosing a compliance 
demonstration requirement, the EPA considers multiple factors, including 
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62See Third Quarter 2023 p.m. CEMS Thirty 
Boiler Operating Day Rolling Average Reports for 
Iatan Generating Station units 1 and 2, Missouri; Marshall Steam Station units 1 and 3, North Carolina; Kyger Creek Station unit 3, Ohio; Virginia City Hybrid Energy Center units 1 and 2, Virginia; and Ghent Generating Station unit 1, Kentucky. These reports are available electronically by searching in the WebFIRE Report Search and Retrieval portion of the Agency’s WebFIRE internet website at https://cfpub.epa.gov/webfire/reports/ esearch.cfm. 
63The 30-day rolling average emission rate was 
calculated by taking daily fPM rate averages over a 30-day operating period while filtering out hourly fPM data during periods of startup and shutdown. costs, benefits of the compliance 
technique, technical feasibility and commercial availability of the compliance method, ability of personnel to conduct the compliance method, and continuity of data used to assure compliance. PM CEMS are readily available and in widespread use by the electric utility industry, as evidenced by the fact that over 100 EGUs already utilize PM CEMS for compliance demonstration purposes. Moreover, the electric utility industry and its personnel have demonstrated the ability to install, operate, and maintain numerous types of CEMS—including PM CEMS. As mentioned earlier, EGU owners and/or operators who chose PM CEMS for compliance demonstration have attested in their submitted reports to the suitability of their PM CEMS to measure at low emission levels, certifying fPM emissions lower than 0.010 lb/MMBtu with their existing correlations developed using emission levels at 0.030 lb/MMBtu. The EPA conducted a review of eight EGUs with varying fPM control devices that rely on PM CEMS that showed certified emissions ranging from approximately 0.002 lb/MMBtu to approximately 0.007 lb/MMBtu. The EPA’s review analyzed 30 boiler operating day rolling averages obtained from reports posted to WebFIRE for the third quarter of 2023 from these eight EGUs.
62 
As described in the Summary of 
Review of 36 PM CEMS Performance Test Reports versus PS11 and Procedure 2 of 40 CFR part 60, Appendices B and F memorandum, available in the docket, 
the EPA investigated how well a sample of EGUs using PM CEMS for compliance purposes would meet initial and ongoing QA requirements at various emission limit levels, even though no change in actual EGU operation occurred. As described in the aforementioned Suitability of PM CEMS 
Use for Compliance Determination for 
Various Emission Levels memorandum, as the emission limit is lowered, the ability to meet both components necessary to correlate PM CEMS— acceptable random error and QA passing rate percentages—becomes more difficult. Based on this additional analysis and review, the EPA determined to finalize requirements to 
use PM CEMS with adjusted QA criteria and a 0.010 lb/MMBtu fPM emission limit as the most stringent limit possible with PM CEMS. 
Use of PM CEMS can provide EGU 
owners or operators with an increased ability to detect and correct potential problems before degradation of emission control equipment, reduction or cessation of electricity production, or exceedances of regulatory emission standards. As mentioned in the Ratio of Revised Estimated Non-Beta Gauge PM CEMS EUAC to 2022 Average Coal-Fired EGU Gross Profit memorandum, using PM CEMS can be advantageous, particularly since their EUAC is offset if their use allows owners or operators to avoid 3 or more hours of generating downtime per year. 
In deciding whether to finalize the 
proposal to use PM CEMS as the only compliance demonstration method for non-IGCC coal- and oil-fired EGUs, the Agency assessed the costs and benefits afforded by requiring use of only PM CEMS as compared to continuing the current compliance demonstration flexibilities (i.e., allowing use of either 
PM CEMS or infrequent PM emissions stack testing). As mentioned above, the average annual cost for quarterly stack testing provided by commenters is about $12,000 less than the EUAC for PM CEMS. While no estimate of quantified benefits was provided by commenters, the EPA recognizes that the 35,040 15- minute values provided by a PM CEMS used at an EGU operating during a 1- year period is over 243 times as much information as is provided by quarterly testing with three 3-hour run durations. This additional, timely information provided by PM CEMS affords the adjacent communities, the general public, and regulatory authorities with assurances that emission limits and operational processes remain in compliance with the rule requirements. It also provides EGU owners or operators with the ability to quickly detect, identify, and correct potential control device or operational problems before those problems become compliance issues. When establishing emission standards under CAA section 112, the EPA must select an approach to compliance demonstration that best 
assures compliance is being achieved. 
The continuous monitoring of fPM 
required in this rule provides several benefits which are not quantified in this rule, including greater certainty, accuracy, transparency, and granularity in fPM emissions information than exists today. Continuous measurement of emissions accounts for changes to processes and fuels, fluctuations in load, operations of pollution controls, 
and equipment malfunctions. By measuring emissions across all operations, power plant operators and regulators can use the data to ensure controls are operating properly and to assess compliance with relevant standards. Because CEMS enable power 
plant operators to quickly identify and correct problems with pollution control devices, it is possible that continuous monitoring could lead to lower fPM emissions for periods of time between otherwise required intermittent testing, currently up to 3 years for some units. 
To illustrate the potentially 
substantial differences in fPM emissions between intermittent and continuous monitoring, the EPA analyzed emissions at several EGUs for which both intermittent and continuous monitoring data are available. This analysis is provided in the 2024 Technical Memo, available in the rulemaking docket. For example, one 585-MW bituminous-fired EGU, with a cold-side ESP for PM control, has achieved LEE status for fPM and is currently required to demonstrate compliance with an emission standard of 0.015 lb/MMBtu using intermittent stack testing every 3 years. In the most recent LEE compliance report, submitted on February 25, 2021, the unit submitted the result of an intermittent stack test with an emission rate of 0.0017 lb/MMBtu. In the subsequent 36 months over which this unit is currently not subject to any further compliance testing, continuous monitoring demonstrates that the fPM emission rate increased substantially. At one point, the continuously monitored 30-day rolling average emissions rate
63 
was nine times higher than the intermittent stack test average, reaching the fPM LEE limit of 0.015 lb/MMBtu. In this example, the actual continuously monitored daily average emissions rate over the February 2021 to April 2023 period ranged from near-zero to 0.100 lb/MMBtu. Emissions using either the stack test average or hourly PM CEMS data were calculated for 2022 for this unit. Both approaches indicate fPM emissions well below the allowable levels for a fPM limit of 0.010 lb/ MMBtu, while estimates using PM CEMS are about 2.5 times higher than the stack test estimate. Additional examples of differences between intermittent stack testing and continuous monitoring are provided in the 2024 Technical Memo, including for periods when PM CEMS data is lower 
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64See Case Study 2 in the 2024 Technical Memo, 
which shows long time periods of PM CEMS data 
below the most recent RRA. Note this unit uses PM CEMS for compliance with the fPM standard, so the RRA is used as an indicator of stack test results. 65The EPA referred to this subcategory in the 
final rule as ‘‘units designed for low rank virgin 
coal.’’ The EPA went on to specify that such a unit is designed to burn and 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) and that is constructed and operates at or near the mine that produces such coal. The EPA also finalized an alternative output- based emission standard of 0.040 lb/GWh. Currently, the approximately 22 units that are permitted as lignite-fired EGUs are located exclusively in North Dakota, Texas, and Mississippi. 66As stated in the 2023 Proposal, when proposed 
revisions to existing source emission standards are more stringent than the corresponding new source emission standard, the EPA proposes to revise the corresponding new source standard to be at least as stringent as the proposed revision to the existing source standard. This is the case with the Hg emission standard for new lignite-fired sources, which will be adjusted to be as stringent as the existing source standard. than the stack test averages,64which 
further illustrate real-life scenarios in 
which fPM emissions for compliance methods may be substantially different. 
The potential reduction in fPM and 
non-Hg HAP metals emission resulting from the information provided by continuous monitoring coupled with corrective actions by plant operators could be sizeable over the total capacity that the EPA estimates would install PM CEMS under this rule (nearly 82 GW). Furthermore, the potential reduction in non-Hg HAP metal emissions would likely reduce exposures to people living in proximity to the coal-fired EGUs potentially impacted by the amended fPM standards. The EPA has found that populations living near coal-fired EGUs have a higher percentage of people living below two times the poverty level than the national average. 
In addition to significant value of 
further pollution abatement, the CEMS data are transparent and accessible to regulators, stakeholders, and the public, fostering greater accountability. 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. This transparency is facilitated by a requirement for electronic reporting of fPM emissions data by the source to the EPA. This emissions data, once submitted, becomes accessible and downloadable—along with other operational and emissions data (e.g., for 
SO
2, CO 2, NO X, Hg, etc.) for each 
covered source. 
On balance, the Agency finds that the 
benefits of emissions transparency and the continuous information stream provided by PM CEMS coupled with the ability to quickly detect and correct problems outweigh the minor annual cost differential from quarterly stack testing. The EPA is finalizing, as proposed, the use of PM CEMS to demonstrate compliance with the fPM emission standards for coal- and oil- fired EGUs (excluding IGCC units and limited-use liquid-oil-fired EGUs). 
More information on the proposed 
technology review can be found in the 2023 Technical Memo (Document ID No. EPA–HQ–OAR–2018–0794–5789), in the preamble for the 2023 Proposal (88 FR 24854), and the 2024 Technical Memo, available in the docket. For the reasons discussed above, pursuant to CAA section 112(d)(6), the EPA is finalizing, as proposed, the use of PM CEMS (with adjusted QA criteria as a result of review of comments) for the compliance demonstration of the fPM emission standard (as a surrogate for non-Hg HAP metal) for coal- and oil- fired EGUs, and the removal of the fPM and non-Hg HAP metals LEE provisions. 
V. What is the rationale for our final 
decisions and amendments to the Hg emission standard for lignite-fired EGUs from review of the 2020 Technology Review? 
A. What did we propose pursuant to 
CAA section 112(d)(6) for the lignite- fired EGU subcategory? 
In the 2012 MATS Final Rule, the 
EPA finalized a Hg emission standard of 4.0E-06 lb/MMBtu (4.0 lb/TBtu) for a subcategory of existing lignite-fired EGUs.
65The EPA also finalized a Hg 
emission standard of 1.2E-06 lb/MMBtu (1.2 lb/TBtu) for coal-fired EGUs not firing lignite (i.e., for EGUs firing 
anthracite, bituminous coal, subbituminous coal, or coal refuse); and the EPA finalized a Hg emission output- based standard for new lignite-fired EGUs of 0.040 lb/GWh and a Hg emission output-based standard for new non-lignite-fired EGUs of 2.0E-04 lb/ GWh. In 2013, the EPA reconsidered the Hg emission standard for new non- lignite-fired EGUs and revised the output-based standard to 0.003 lb/GWh (see 78 FR 24075). 
As explained in the 2023 Proposal, Hg 
emissions from the power sector have declined since promulgation of the 2012 MATS Final Rule with the installation 
of Hg-specific and other control technologies and 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 (or permitted to burn lignite) accounted for a disproportionate amount of the total Hg emissions in 2021. As shown in table 5 in the 2023 Proposal (88 FR 24876), 16 of the top 20 Hg-emitting EGUs in 2021 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. 
Prior to the 2023 Proposal, the EPA 
assembled information on developments in Hg emission rates and installed controls at lignite-fired EGUs from operational and emissions information that is provided routinely to the EPA for demonstration of compliance with MATS and from information provided to the EIA. In addition, the EPA’s final decisions were informed by information that was submitted as part of a CAA section 114 information survey (2022 ICR). The EPA also revisited information that was used in establishing the emission standards in the 2012 Final MATS Rule and considered information that was submitted during the public comment period for the 2023 Proposal. From that information, the EPA determined, as explained in the 2023 Proposal, that there are available cost-effective control technologies and improved methods of operation that would allow existing lignite-fired EGUs to achieve a more stringent Hg emission standard. As such, the EPA proposed a revised Hg emission standard for existing EGUs firing lignite (i.e., for those in the ‘‘units 
designed for low rank virgin coal’’ subcategory). Specifically, the EPA proposed that such lignite-fired units must meet the same emission standard as existing EGUs firing other types of coal (e.g., anthracite, bituminous coal, 
subbituminous coal, and coal refuse), which is 1.2 lb/TBtu (or an alternative output-based standard of 0.013 lb/ GWh). The EPA did not propose to revise the Hg emission standards either for existing EGUs firing non-lignite coal or for new non-lignite coal-fired EGUs.
66 
B. How did the technology review change for the lignite-fired EGU subcategory? 
The outcome of the technology review 
for the Hg standard for existing lignite- fired EGUs has not changed since the 2023 Proposal. However, in response to comments, the EPA expanded its review to consider additional coal compositional data and the impact of sulfur trioxide (SO
3) in the flue gas. 
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67Analysis of PM and Hg Emissions and Controls 
from Coal-Fired Power Plants. Andover Technology 
Partners. August 19, 2021. Document ID No. EPA– HQ–OAR–2018–0794–4583. 
68https://www.eia.gov/electricity/data/eia923/ . C. What key comments did we receive 
on the Hg emission standard for lignite- fired EGUs, and what are our responses? 
The Agency received both supportive 
and critical comments on the proposed revision to the Hg emission standard for existing lignite-fired EGUs. Some commenters agreed with the EPA’s decision to not propose revisions to the Hg emission standards for non-lignite- fired EGUs, while others disagreed. Significant comments are summarized below, and the Agency’s responses are provided. 
Comment: Several commenters stated 
that industry experience confirms that stringent limits on power plant Hg emissions can be readily achieved at lower-than-predicted costs and thus should be adopted nationally through CAA section 112(d)(6). They said that at least 14 states have, for years, enforced state-based limits on power plant Hg emissions, and nearly every one of those states has imposed more stringent emission limits than those proposed in 
this rulemaking or in the final 2012 MATS Final Rule. The commenters said that these lower emissions limits have resulted in significant and meaningful Hg emission reductions, which have proven to be both achievable and cost- effective. 
Some commenters recommended that 
the EPA revise the Hg limits to levels that are much more stringent than existing or proposed standards for both EGUs firing non-lignite coals and those firing lignite. They claimed that more stringent Hg emission standards are supported by developments in practices, processes, and control technologies. They pointed to a 2021 report by Andover Technology Partners, which details advances in control technologies that support more stringent Hg standards for all coal-fired EGUs.
67 
These advances include advanced activated carbon sorbents with higher capture capacity at lower injection rates and carbon sorbents that are tolerant of flue gas species. 
Response: The EPA has taken these 
comments and the referenced information into consideration when establishing the final emission standards. The EPA disagrees that the Agency should, in this final rule, revise the Hg limits for all coal-fired EGUs to levels more stringent than the current or proposed standards. The Agency did not propose in the 2023 Proposal to revise the Hg emission standard for ‘‘not-low- rank coal units’’ (i.e., those EGUs that are firing on coals other than lignite) 
and did not suggest an emission standard for lignite-fired EGUs more stringent than the 1.2 lb/TBtu emission standard that was proposed. However, the EPA will continue to review emission standards and other rule requirements as part of routine CAA section 112(d)(6) technology reviews, which are required by statute to be conducted at least every 8 years. If we determine in subsequent CAA section 112(d)(6) technology reviews that further revisions to Hg emission standards (or to standards for other HAP or surrogate pollutants) are warranted, then we will propose revisions at that time. We discuss the rationale for the final emission standards in section V.D. of this preamble and in more detail in the 2024 Technical Memo. 
Comment: Several commenters 
challenged the data that the EPA used in the CAA 112(d)(6) technology review. Commenters stated that the information collected by the EPA via the CAA section 114 request consisted of 17 units each submitting two 1-week periods of data and associated operational data preselected by the EPA, and that only a limited number of the EGUs reported burning only lignite. Other EGUs reported burning primarily refined coal, co-firing with natural gas, and firing or co-firing with large amounts of subbituminous coal (referencing table 7 in the 2023 Proposal). Commenters stated that if the EPA’s intent was to assess the Hg control performance of lignite-fired EGUs, then the EGUs evaluated should have burned only lignite, not refined coal, subbituminous coal, or natural gas. 
Response: The EPA disagrees with the 
commenters’ argument that the Agency should have only considered emissions and operational data from EGUs that were firing only lignite. The EPA’s intent was to evaluate the Hg emission control performance of units that are permitted to burn lignite and are thus subject to a Hg emission standard of 4.0 lb/TBtu. According to fuel use information supplied to EIA on form 923,
6813 of 22 EGUs that were designed 
to burn lignite utilized ‘‘refined coal’’ to some extent in 2021, as summarized in table 7 in the 2023 Proposal preamble (88 FR 24878). EIA form 923 does not specify the type of coal that is ‘‘refined’’ when reporting boiler or generator fuel use. For the technology review, the EPA 
assumed that the facilities utilized ‘‘refined lignite,’’ as reported in fuel receipts on EIA form 923. In any case, firing of refined lignite or subbituminous coal or co-firing with natural gas or fuel oil are considered to be Hg emission reduction strategies for a unit that is subject to an emission standard of 4.0 lb/TBtu, which was based on the use of lignite as its fuel. 
In a related context, in U.S. Sugar 
Corp. v. EPA, the D.C. Circuit held that 
the EPA could not exclude unusually high performing units within a subcategory from the Agency’s determination of MACT floor standards for a subcategory pursuant to CAA section 112(d)(3). 830 F.3d 579, 631–32 (D.C. Cir. 2016) (finding ‘‘an unusually high-performing source should be considered[,]’’ in determining MACT floors for a subcategory, and that ‘‘its performance suggests that a more stringent MACT standard is appropriate.’’). While the technology review at issue here is a separate and distinct analysis from the MACT floor setting requirements at issue in U.S. Sugar v. EPA, similarly here the EPA 
finds it is appropriate to consider emissions from all units that are permitted to burn lignite and are therefore subject to the prior Hg emission standard of 4.0 lb/TBtu and are part of the lignite-fired EGU subcategory, for the purposes of determining whether more stringent standards are appropriate under a technology review. However, while the EPA has considered the emissions performance of all units within the lignite-fired EGU subcategory, it is not the performance of units that are firing or co-firing with other non-lignite fuels that provide the strongest basis for the more stringent standard. Rather, the most convincing evidence to support the more stringent standard is that there are EGUs that are permitted to fire lignite—and are only firing lignite—that have demonstrated an ability to meet the more stringent standard of 1.2 lb/ TBtu. 
Comment: Several commenters 
claimed that, rather than using actual measured Hg concentrations in lignite that had been provided in the CAA section 114 request responses (and elsewhere), the EPA used Integrated Planning Model (IPM) data to assign inlet Hg concentrations to various lignite-fired EGUs. Some commenters asserted that the actual concentration of Hg in lignite is higher than those assumed by the EPA and that there is considerable variability in the concentration of Hg in the lignite used in these plants. As a result, the commenters claimed, the percent Hg capture needed to achieve the proposed 1.2 lb/TBtu emission standard would be higher than that assumed by the EPA in the 2023 Proposal. 
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69See Tables 8 and 9 from ‘‘Analysis of PM and 
Hg Emissions and Controls from Coal-Fired Power 
Plants’’, Andover Technology Partners (August 2021); available in the rulemaking docket at Docket ID: EPA–HQ–OAR–2018–4583. Response: In the 2023 Proposal, the 
EPA assumed a Hg inlet concentration 
(i.e., concentration of Hg in the fuel) that 
reflected the maximum Hg content of the range of feedstock coals that the EPA assumes is available to each of the plants in the IPM. In response to comments received on the proposal, the EPA has modified the Hg inlet concentration assumptions for each unit to reflect measured Hg concentrations in lignite using information provided by commenters and other sources, including measured Hg concentrations in fuel samples from the Agency’s 1998 Information Collection Request (1998 ICR). This is explained in additional detail below in section V.D.1. and in a supporting technical memorandum titled 1998 ICR Coal Data Analysis 
Summary of Findings. However, this adjustment in the assumed concentration of Hg in the various fuels did not change the EPA’s overall conclusion that there are available controls and improved methods of operation that will allow lignite-fired EGUs to meet a more stringent Hg emission standard of 1.2 lb/TBtu. 
Comment: Some commenters claimed 
that the Agency failed to account for compositional differences in lignite as compared to those of other types of coal—especially in comparison to subbituminous coal. 
Response: The EPA disagrees with 
these commenters. In the 2023 Proposal, the EPA emphasized the similarities between lignite and subbituminous coal—especially regarding the fuel properties that most impact the control of Hg. The EPA noted that lignite and subbituminous coal are both low rank coals with low halogen content and explained that the halogen content of the coal—especially chlorine—strongly influences the oxidation state of Hg in the flue gas stream and, thereby, directly influences the ability to capture and contain the Hg before it is emitted into the atmosphere. The EPA further noted that the fly ashes from lignite and subbituminous coals tend to be more alkaline (relative to that from bituminous coal) due to the lower amounts of sulfur and halogen and to the presence of a more alkaline and reactive (non-glassy) form of calcium in the ash. Due to the natural alkalinity, subbituminous and lignite fly ashes can effectively neutralize the limited free halogen in the flue gas and prevent oxidation of gaseous elemental Hg vapor (Hg
0). This lack of free halogen in the 
flue gas challenges the control of Hg from both subbituminous coal-fired EGUs and lignite-fired EGUs as 
compared to the Hg control of EGUs firing bituminous coal. The EPA noted in the 2023 Proposal, however, that 
control strategies and control technologies have been developed and utilized to introduce halogens to the flue gas stream, and that EGUs firing subbituminous coals have been able to meet (and oftentimes emit at emission rates that are considerably lower than) the 1.2 lb/TBtu emission standard in the 2012 MATS Final Rule. Therefore, while the EPA acknowledges that there are differences in the composition of the various coal types, there are available control technologies that allow EGUs firing any of those coal types to achieve an emission standard of 1.2 lb/TBtu. The EPA further notes that North Dakota and Texas lignites are much more similar in composition and in other properties to Wyoming subbituminous coal than either coal type is to eastern bituminous coal. Both lignite and subbituminous coal are lower heating value fuels with high alkaline content and low natural halogen. In contrast, eastern bituminous coals are higher heating value fuels with high natural halogen content and low alkalinity. But while Wyoming subbituminous coal is much more similar to lignite than it is to eastern bituminous coals, EGUs firing subbituminous coal must meet the same Hg emission standard (1.2 lb/TBtu) as EGUs firing bituminous coal. The EPA further acknowledges the differences in sulfur content between subbituminous coal and lignite and its impact is discussed in the following comment summary and response. 
Comment: Some commenters claimed 
that the EPA did not account for the impacts of the higher sulfur content of lignite as compared to that of subbituminous coal, and that such higher sulfur content leads to the presence of additional SO
3in the flue 
gas stream. The commenters noted that the presence of SO
3is known to 
negatively impact the effectiveness of activated carbon for Hg control. 
Response: The EPA agrees with the 
commenters that the Agency did not fully address the potential impacts of SO
3on the control of Hg from lignite- 
fired EGUs in the 2023 Proposal. However, in response to these comments, the EPA conducted a more robust evaluation of the impact of SO
3 
in the flue gas of lignite-fired EGU and determined that it does not affect our previous determination that there are control technologies and methods of operation that are available to EGUs firing lignite that would allow them to meet a Hg emission standard of 1.2 lb/ TBtu—the same emission standard that must be met by EGUs firing all other 
types of coal. As discussed in more detail below, the EPA determined that there are commercially available 
advanced ‘‘SO
3tolerant’’ Hg sorbents 
and other technologies that are specifically designed for Hg capture in high SO
3flue gas environments. These 
advanced sorbents allow for capture of Hg in the presence of SO
3and other 
challenging flue gas environments at costs that are consistent with the use of conventional pre-treated activated carbon sorbents.
69The EPA has 
considered the additional information regarding the role of flue gas SO
3on Hg 
control and the information on the availability of advanced ‘‘SO
3tolerant’’ 
Hg sorbents and other control technologies and finds that this new information does not change the Agency’s determination that a Hg emission standard of 1.2 lb/TBtu is achievable for lignite-fired EGUs. 
Comment: Several commenters noted 
the EPA made improper assumptions to reach the conclusion that the revised Hg emissions limit is achievable and claimed that none of the 22 lignite-fired EGUs are currently in compliance with the proposed 1.2 lb/TBtu Hg emission standard and that the EPA has not shown that any EGU that is firing lignite has demonstrated that it can meet the proposed Hg emission standard. 
Response: The EPA disagrees with 
commenters’ assertion and maintains that the Agency properly determined that the proposed, more stringent Hg emission standard can be achieved, cost-effectively, using available control technologies and improved methods of operation. Further, the EPA notes that, contrary to commenters’ claim, there are, in fact, EGUs firing lignite that have demonstrated an ability to meet the more stringent 1.2 lb/TBtu Hg emission standard. Twin Oaks units 1 and 2 are lignite-fired EGUs operated by Major Oak Power, LLC, and located in Robertson County, Texas. In the 2023 Proposal (see 88 FR 24879 table 8), we showed that 2021 average Hg emission rates for Twin Oaks 1 and 2 (listed in the table as Major Oak #1 and Major Oak #2) were 1.24 lb/TBtu and 1.31 lb/TBtu, respectively, which are emission rates that are just slightly above the final emission limit. Both units at Major Oak have qualified for LEE status for Hg. To demonstrate LEE status for Hg an EGU owner/operator must conduct an initial EPA Method 30B test over 30 days and follow the calculation procedures in the final rule to document a potential to emit (PTE) that is less than 10 percent of the applicable Hg emissions limit (for 
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70See page 1–1 of the 2023 Compliance Reports 
for Twin Oaks 1 and 2 available in the rulemaking 
docket at EPA–HQ–OAR–2018–0794. 
71Choctaw Generation LP leases and operates the 
Red Hills Power Plant. The plant supplies 
electricity to the Tennessee Valley Authority (TVA) under a 30-year power purchase agreement. The lignite output from the adjacent mine is 100 percent dedicated to the power plant. https://www.purenergyllc.com/projects/choctaw- generation-lp-red-hills-power-plant/#page-content. lignite-fired EGUs this would be a rate 
of 0.40 lb/TBtu) or less than 29 lb of Hg 
per year. If an EGU qualifies as a LEE for Hg, then the owner/operator must conduct subsequent performance tests on an annual basis to demonstrate that the unit continues to qualify. In their most recent compliance reports
70(dated 
November 14, 2023), Major Oak Power, LLC, summarized the performance testing. Between August 1 and September 19, 2023, Major Oak Power, LLC, personnel performed a series of performance tests for Hg on Twin Oaks units 1 and 2. The average Hg emissions rate for the 30-boiler operating day performance tests was 1.1 lb/TBtu for unit 1 and 0.91 lb/TBtu for unit 2. The EGUs demonstrated LEE status by showing that each of the units has a Hg PTE of less than 29 lb per year. Further, in LEE demonstration testing for the previous year (2022), Major Oak Power, LLC, found that the average Hg emissions rate for the 30-boiler operating day performance test was 0.86 lb/TBtu for unit 1 and 0.63 lb/TBtu for unit 2. 
In the 2023 LEE demonstration 
compliance report, Twin Oaks unit 1 was described as a fluidized bed boiler that combusts lignite and is equipped with fluidized bed limestone (FBL) injection for SO
2control, selective non- 
catalytic reduction (SNCR) for control of nitrogen oxides (NO
X), and a baghouse 
(FF) for PM control. In addition, unit 1 has an untreated activated carbon injection (UPAC) system as well as a brominated powdered activated carbon (BPAC) injection system for absorbing vapor phase Hg in the effluent upstream of the baghouse. Twin Oaks unit 2 is described in the same way. 
Similarly, Red Hills units 1 and 2, 
located in Choctaw County, Mississippi,
71also demonstrated 2021 
annual emission rates while firing lignite from an adjacent mine of 1.33 lb/ TBtu and 1.35 lb/TBtu, which are reasonably close to the proposed Hg emission standard of 1.2 lb/TBtu to demonstrate achievability. In 2022, average Hg emission rates for Red Hills unit 1 and unit 2, again while firing Mississippi lignite, were 1.73 lb/TBtu and 1.75 lb/TBtu, respectively. The EPA also notes that, as shown below in table 5, lignite mined in Mississippi has the highest average Hg content—as compared to lignites mined in Texas and North Dakota. 
The performance of Twin Oaks units 
1 and 2 and Red Hills Generating Facility units 1 and 2 clearly demonstrate the achievability of the proposed 1.2 lb/TBtu emission standard by lignite-fired EGUs. However, even if there were no lignite-fired EGUs that are meeting (or have demonstrated an ability to meet) the more stringent Hg emission standard, that would not mean that the more stringent emission standard was not achievable. Most Hg control technologies are ‘‘dial up’’ technologies—for example, sorbents or chemical additives have injection rates that can be ‘‘dialed’’ up or down to achieve a desired Hg emission rate. In response to the EPA’s 2022 CAA section 114 information request, some responding owners/operators indicated that sorbent injection rates were set to maintain a Hg emission rate below the 4.0 lb/TBtu emission limit. In some instances, operators of EGUs reported that they were not injecting any Hg sorbent and were able to meet the less stringent emission standard. Most units that are permitted to meet a Hg emission standard of 4.0 lb/TBtu have no reason to ‘‘over control’’ since doing so by injecting more sorbent would increase their operating costs. So, it is unsurprising that many units that are permitted to fire lignite have reported Hg emission rates between 3.0 and 4.0 lb/TBtu. 
While most lignite-fired EGUs have 
no reason to ‘‘over control’’ beyond their permitted emission standard of 4.0 lb/ TBtu, Twin Oaks units 1 and 2 do have such motivation. As mentioned earlier, those sources have achieved LEE status for Hg (by demonstrating a Hg PTE of less than 29 lb/yr) and they must conduct annual performance tests to show that the units continue to qualify. According to calculations provided in their annual LEE certification, to maintain LEE status, the units could emit no more than 1.79 lb/TBtu and maintain a PTE of less than 29 lb/TBtu. So, the facilities are motivated to over control beyond 1.79 lb/TBtu (which, as described earlier in this preamble, they have consistently done). 
Comment: To highlight the difference 
in the ability of lignite-fired and 
subbituminous-fired EGUs to control Hg, one commenter created a table to show a comparison between the Big Stone Plant (an EGU located in South Dakota firing subbituminous coal) and Coyote Station (an EGU located in North Dakota firing lignite). Additionally, the commenter included figures showing rolling 30-boiler operating day average Hg emission rates and the daily average ACI feed rates for Big Stone and Coyote EGUs for years 2021–2022. Their table showed that Big Stone and Coyote are similarly configured plants that utilize the same halogenated ACI for Hg control. The commenters said, however, that Coyote Station’s average sorbent feed rate on a lb per million actual cubic feet (lb/MMacf) basis is more than three times higher than that for Big Stone, yet Coyote Station’s average Hg emissions on a lb/TBtu basis are more than five times higher than Big Stone. 
Response: The EPA agrees that the Big 
Stone and Coyote Station units referenced by the commenter are similarly sized and configured EGUs, with the Big Stone unit in South Dakota firing subbituminous coal and the Coyote Station unit in North Dakota firing lignite. However, there are several features of the respective units that can have an impact on the control of Hg. First, and perhaps the most significant, the Big Stone unit has a selective catalytic reduction (SCR) system installed for control of NOx. The presence of an SCR is known to enhance the control of Hg—especially in the presence of chemical additives. The Coyote Station EGU does not have an installed SCR. Further, both EGUs have a dry FGD scrubber and FF baghouse installed for SO
2/acid gas and fPM 
control. The average sulfur content of North Dakota lignite is approximately 2.5 times greater than that of Wyoming subbituminous coal. However, the average SO
2emissions from the Coyote 
Station EGU (0.89 lb/MMBtu) were approximately 10 times higher than the SO
2emissions from the Big Stone EGU 
(0.09 lb/MMBtu). The Big Stone dry scrubber/FF was installed in 2015; while the dry scrubber/FF at Coyote Station was installed in 1981— approximately 31 years earlier. So, considering the presence of an SCR— which is known to enhance Hg control—and newer and better performing downstream controls, it is unsurprising that there are differences in the control of Hg at the two EGUs. In addition, since the Coyote Station has been subject to a Hg emission standard of 4.0 lb/TBtu, there would be no reason for the operators to further optimize its control system to achieve a lower emission rate. And, as numerous commenters noted, the Hg content of North Dakota is higher than that of Wyoming subbituminous coal. 
Comment: Some commenters claimed 
that the EPA has not adequately justified a reversal in the previous policy to establish a separate subcategory for lignite-fired EGUs. 
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Response: In developing the 2012 
Final MATS Rule, the EPA examined 
the EGUs in the top performing 12 percent of sources for which the Agency had Hg emissions data. In examining that data, the EPA observed that there were no lignite-fired EGUs among the top performing 12 percent of sources for Hg emissions. The EPA then determined that this indicated that there is a difference in the Hg emissions from lignite-fired EGUs when compared to the Hg emissions from EGUs firing other coal types (that were represented among the top performing 12 percent). That determination was not based on any unique property or characteristic of lignite—only on the observation that there were no lignite-fired EGUs among the best performing 12 percent of sources (for which the EPA had Hg emissions data). In fact, as noted in the preamble for the 2012 Final MATS Rule, the EPA ‘‘believed at proposal that the boiler size was the cause of the different Hg emissions characteristics.’’ See 77 FR 9378. 
The EPA ultimately concluded that it 
is appropriate to continue to base the subcategory definition, at least in part, on whether the EGUs were ‘‘designed to burn and, in fact, did burn low rank- virgin coal’’ (i.e., lignite), but that it is 
not appropriate to continue to use the boiler size criteria (i.e., the height-to- 
depth ratio). However, the EPA ultimately finalized the ‘‘unit designed for low rank virgin coal’’ subcategory based on the characteristics of the EGU—not on the properties of the fuel. ‘‘We are finalizing that the EGU is considered to be in the ‘‘unit designed for low rank virgin coal’’ subcategory if the EGU: (1) meets the final definitions of ‘‘fossil fuel-fired’’ and ‘‘coal-fired electric utility steam generating unit;’’ and (2) is designed to burn and 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) and that is constructed and operates at or near the mine that produces such coal.’’ See 77 FR 9369. 
While, in the 2012 MATS Final Rule, 
the EPA based the lignite-fired EGU subcategory on the design and operation of the EGUs, the EPA did not attribute the observed differences in Hg emissions to any unique characteristic(s) of lignite. As the EPA clearly noted in the 2023 Proposal, there are, in fact, characteristics of lignite that make the control of Hg more challenging. These include the low natural halogen content, the high alkalinity of the fly ash, the sulfur content, the relatively higher Hg 
content, and the relatively higher variability of Hg content. However, as the EPA has explained, these 
characteristics that make the control of Hg more challenging are also found in non-lignite fuels. Subbituminous coals also have low natural halogen content and high fly ash alkalinity. Eastern and central bituminous coals also have high sulfur content. Bituminous and anthracitic waste coals (coal refuse) have very high and variable Hg content. EGUs firing any of these non-lignite coals have been subject to—and have demonstrated compliance with—the more stringent Hg emission standard of 1.2 lb/TBtu. 
The EPA has found it appropriate to 
reverse the previous policy because the decision to subcategorize ‘‘units designed for low rank virgin coal’’ in the 2012 MATS Final Rule was based a determination that there were differences in Hg emissions from lignite- fired EGUs as compared to EGUs firing non-lignite coals. That perceived difference was based on an observation that there were no lignite-fired EGUs in the top performing 12 percent of EGUs for which the Agency had Hg emissions data and on an assumption that the perceived difference in emissions was somehow related to the design and operation of the EGU. The EPA is unaware of any distinguishing features of EGUs that were designed to burn lignite that would impact the emissions of Hg. Further, the EPA does not now view the fact that there were no lignite- fired EGUs in the population of the best- performing 12 percent of EGUs for which the Agency had Hg emissions data to represent a ‘‘difference in emissions.’’ 
But, on re-examination of the data, the 
EPA has concluded that the Hg emissions from the 2010 ICR for the lignite-fired EGUs were not clearly distinctive from the Hg emissions from 
EGUs firing non-lignite coal. In setting the emission standards for the 2012 MATS Final Rule, the EPA had available and useable Hg emissions data from nearly 400 coal-fired EGUs (out of the 1,091 total coal-fired EGUs operating at that time). However, the EPA only had available and useable data from nine lignite-fired EGUs with reported floor Hg emissions ranging from 1.0 to 10.9 lb/TBtu. But these were not outlier emission rates. EGUs firing bituminous coal reported Hg emissions as high as 30.0 lb/TBtu; and those firing subbituminous coal reported Hg emissions as high as 9.2 lb/TBtu. 
D. What is the rationale for our final 
approach and decisions for the lignite- fired EGU Hg standard? 
In the 2023 Proposal, the EPA 
proposed to determine that there are developments in available control technologies and methods of operation that would allow lignite-fired EGUs to meet a more stringent Hg emission standard of 1.2 lb/TBtu—the same Hg emission standard that must be met by coal-fired EGUs firing non-lignite coals (e.g., anthracite, bituminous coal, 
subbituminous coal, coal refuse, etc.). After consideration of public comments received on the proposed revision of the Hg emission standard, the EPA continues to find that the evidence supports that there are commercially available control technologies and improved methods of operation that allow lignite-fired EGUs to meet the more stringent Hg emission standard that the EPA proposed. As noted above, lignite-fired EGUs also comprise some of the largest sources of Hg emissions within this source category and are responsible for a disproportionate share of Hg emissions relative to their generation. While previous EPA assessments have shown that current modeled exposures [of Hg] are well below the reference dose (RfD), we conclude that further reductions of Hg emissions from lignite-fired EGUs covered in this final action should further reduce exposures including for the subsistence fisher sub-population. This anticipated exposure is of particular importance to children, infants, and the developing fetus given the developmental neurotoxicity of Hg. Therefore, in this final action, the EPA is revising the Hg emission standard for lignite-fired EGUs from the 4.0 lb/TBtu standard that was finalized in the 2012 MATS Final Rule to the more stringent emission standard of 1.2 lb/TBtu, as proposed. The rationale for the Agency’s final determination is provided below. 
In this final rule, the EPA is also 
reaching a different conclusion from the 2020 Technology Review with respect to the Hg emission standard for lignite- fired EGUs. As discussed in section II.D. above, the 2020 Technology Review did not evaluate the current performance of emission reduction control equipment and strategies at existing lignite-fired EGUs. Nor did the 2020 Technology Review specifically address the discrepancy between Hg emitted from lignite-fired EGUs and non-lignite coal- fired EGUs or consider the improved performance of injected sorbents or chemical additives, or the development of SO
3-tolerant sorbents. Based on the 
EPA’s review in this rulemaking which considered such information, the Agency determined that there are available control technologies that allow EGUs firing lignite to achieve an emission standard of 1.2 lb/TBtu, 
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72Technical Support Document ‘‘1998 ICR Coal 
Data Analysis Summary of Findings’’ available in 
the rulemaking docket at EPA–HQ–OAR–2018– 0794. 
73In 2022, over 99 percent of all lignite was 
mined in North Dakota (56.2 percent), Texas (35.9 percent), and Mississippi (7.1 percent). Small amounts (less than 1 percent) of lignite were also mined in Louisiana and Montana. See Table 6. 
‘‘Coal Production and Number of Mines by State and Coal Rank’’ from EIA Annual Coal Report, available at https://www.eia.gov/coal/annual/. consistent with the Hg emission 
standard required for non-lignite coal- fired EGUs, which the EPA is finalizing pursuant to its CAA section 112(d)(6) authority. 
1. Mercury Content of Lignite 
For analyses supporting the proposal, 
the EPA assumed ‘‘Hg Inlet’’ levels (i.e., 
Hg concentration in inlet fuel) that are consistent with those assumed in the Agency’s power sector model (IPM) and then adjusted accordingly to reflect the 2021 fuel blend for each unit. Several commenters indicated that the Hg content of lignite fuels is much higher and has greater variability than the EPA assumed. 
To support the development of the 
NESHAP for the Coal- and Oil-Fired EGU source category, the Agency conducted a 2-year data collection effort which was initiated in 1998 and completed in 2000 (1998 ICR). The ICR had three main components: (1) identifying all coal-fired units owned and operated by publicly owned utility companies, federal power agencies, rural electric cooperatives, and investor- owned utility generating companies; (2) obtaining accurate information on the amount of Hg contained in the as-fired coal used by each electric utility steam generating unit with a capacity greater than 25 MW electric, as well as accurate information on the total amount of coal burned by each such unit; and (3) obtaining data by coal sampling and stack testing at selected units to characterize Hg reductions from 
representative unit configurations. 
The ICR captured the origin of the 
coal burned, and thus provided a pathway for linking emission properties to coal basins. The 1998–2000 ICR resulted in more than 40,000 data points indicating the coal type, sulfur content, Hg content, ash content, chlorine content, and other characteristics of coal burned at coal-fired utility boilers greater than 25 MW. 
Annual fuel characteristics and 
delivery data reported on EIA form 923 also provide continual data points on 
coal heat content, sulfur content, and geographic origin, which are used as a check against characteristics initially identified through the 1998 ICR. 
For this final rule, the EPA re- 
evaluated the 1998 ICR data.
72 
Specifically, the EPA evaluated the coal Hg data to characterize the Hg content of lignite, which is mined in North Dakota, Texas, and Mississippi, and to characterize by seam and by coal delivered to a specific plant.
73The 
results are presented as a range of Hg content of the lignites as well as the mean and median Hg content. The EPA also compared the fuel characteristics of lignites mined in North Dakota, Texas, and Mississippi against coals mined in Wyoming (subbituminous coal), Pennsylvania (mostly upper Appalachian bituminous coal), and Kentucky (mostly lower Appalachian bituminous coal). The Agency also included in the re-evaluation, coal analyses that were submitted in public comments by North American Coal (NA Coal). In addition to the Hg content, the analysis included the heating value and the sulfur, chlorine, and ash content for each coal that is characterized. 
The analysis showed that lignite 
mined in North Dakota had a mean Hg content of 9.7 lb/TBtu, a median Hg content of 8.5 lb/TBtu, and a Hg content range of 2.2 to 62.1 lb/TBtu. Other characteristics of North Dakota lignite include an average heating value (dry basis) of 10,573 Btu/lb, an average sulfur content of 1.19 percent, an average ash content of 13.5 percent, and an average chlorine content of 133 parts per million (ppm). In response to comments on the 
2023 Proposal, for analyses supporting this final action, the EPA has revised the assumed Hg content of lignite mined in North Dakota to 9.7 lb/TBtu versus the 7.81 lb/TBtu assumed in the 2023 Proposal. 
Similarly, the analysis showed that 
lignite mined in Texas had a mean and median Hg content of 25.0 lb/TBtu and 23.8 lb/TBtu, respectively, and a Hg content range from 0.7 to 92.0 lb/TBtu. Other characteristics include an average heating value (dry basis) of 9,487 Btu/ lb, an average sulfur content of 1.42 percent, an average ash content of 24.6 percent, and an average chlorine content of 233 ppm. In response to comments on the 2023 Proposal, for analyses supporting this final action, the EPA has revised the assumed Hg content of lignite mined in Texas to 25.0 lb/TBtu versus the range of 14.65 to 14.88 lb/ TBtu that was assumed for the 2023 Proposal. 
Lignite mined in Mississippi had the 
highest mean Hg content at 34.3 lb/TBtu and the second highest median Hg emissions rate, 30.1 lb/TBtu. The Hg content ranged from 3.6 to 91.2 lb/TBtu. Lignite from Mississippi had an average heating value (dry basis) of 5,049 Btu/ lb and a sulfur content of 0.58 percent. In response to comments submitted on the 2023 Proposal, for analyses supporting this final action, the EPA assumed a Hg content of 34.3 lb/TBtu for lignite mined in Mississippi versus the 12.44 lb/TBtu assumed for the proposal. 
The EPA 1998 ICR dataset did not 
contain information on lignite from Mississippi, which resulted in a smaller number of available data points (227 in Mississippi lignite versus 864 for North Dakota lignite and 943 for Texas lignite). Table 5 of this document more fully presents the characteristics of lignite from North Dakota, Texas, and 
Mississippi. 
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Coals mined in Kentucky, 
Pennsylvania, and Wyoming were also 
analyzed for comparison. The types of coal (all non-lignite) included bituminous, bituminous-high sulfur, bituminous-low sulfur, subbituminous, anthracite, waste anthracite, waste bituminous, and petroleum coke. Bituminous coal accounted for 92 percent of the data points from Kentucky and 75 percent of the data points from Pennsylvania. Subbituminous coal accounted for 96 percent of the data points from 
Wyoming. 
Bituminous coals from Kentucky had 
a mean Hg emissions content of 7.2 lb/ TBtu (ranging from 0.7 to 47.4 lb/TBtu), an average heating value (dry basis) of 13,216 Btu/lb, an average sulfur content of 1.43 percent, an average ash content of 10.69 percent, and an average chlorine content of 1,086 ppm. 
Bituminous coals from Pennsylvania 
had a mean Hg emissions rate of 14.5 lb/ 
TBtu (ranging from 0.1 to 86.7 lb/TBtu), an average heating value (dry basis) of 13,635 Btu/lb, an average sulfur content of 1.88 percent, an average ash content 
of 10.56 percent, and an average chlorine content of 1,050 ppm. 
Subbituminous coals from Wyoming 
had a mean Hg rate of 5.8 lb/TBtu, an average heating value (dry basis) of 12,008 Btu/lb, an average sulfur content of 0.44 percent, an average ash content of 7.19 percent, and an average chlorine content of 127 ppm. Table 6 of this 
document shows the characteristics of bituminous coal from Kentucky and Pennsylvania and subbituminous coal from Wyoming. 
Several commenters claimed that one 
of the factors that contributes to the challenge of controlling Hg emissions from EGUs firing lignite is the variability of the Hg content in lignite. However, as can be seen in table 5 and table 6 of this document, all coal types examined by the EPA contain a variable content of Hg. The compliance demonstration requirements in the 2012 MATS Final Rule were designed to accommodate the variability of Hg in coal by requiring compliance with the respective Hg emission standards over a 30-operating-day rolling average period. When examining the Hg emissions for EGUs firing on the various coal types (including those firing Wyoming subbituminous coal, which has the lowest mean and median Hg content and the narrowest range of Hg content), daily emissions often exceed the applicable emission standard (sometimes considerably). However, averaging emissions over a rolling 30- operating-day period effectively dampens the impacts of fuel Hg content 
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ER07MY24.069</GPH> ER07MY24.070</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 5. Characteristics of Lignite mined in North Dakota, Texas, and Mississippi from the 
EPA 1998 ICR Dataset 
North Dakota Texas Mississippi 
Number of data points 864 943 227 
Range of Hg content (lblTBtu) 2.2-62.1 0.7 -92.0 3.6-91.2 
Mean Hg content (lblTBtu) 9.7 25.0 34.3 
Median Hg content (lblTBtu) 8.5 23.8 30.1 
Heating value average (Btu/lb, dry) 10,573 9,486 5,049 
Sulfur content average(%, dry) 1.12 1.42 0.58 
Ash content average (%, dry) 13.54 24.60 NIA 
Chlorine content average ( ppm, dry) 133 232 NIA 
Table 6. Characteristics of Bituminous and Subbituminous Coals mined in Kentucky, 
Pennsylvania, and Wyoming from the EPA 1998 ICR Dataset 
Kentucky Pennsylvania Wyoming 
(Bituminous) (Bituminous) (Sub bituminous) 
Number of data points 5,340 3,072 6,467 
Range of Hg content (lblTBtu) 0.7-47.4 0.1 -86.7 0.7 -40.7 
Mean Hg content (lblTBtu) 7.2 14.5 5.8 
Median Hg content (lblTBtu) 6.7 9.7 2.4 
Heating value average (Btu/lb, 
dry) 13,216 13,635 12,008 
Sulfur content average(%, dry) 1.43 1.88 0.44 
Ash content average (%, dry) 10.69 10.56 7.19 
Chlorine content average (ppm, 
dry) 1,086 1,050 127 38544 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
variability. For example, in figure 1 (a 
graph) of this document, the 2022 Hg emissions from Dave Johnston unit 
BW41, a unit firing subbituminous coal, are shown. The graph shows both the daily Hg emissions and the 30- 
operating-day rolling average Hg emissions. As can be seen in the graph, 
the daily Hg emissions very often exceed the 1.2 lb/TBtu emission rate; however, the 30-operating-day rolling average is consistently below the emission limit (the annual average emission rate is 0.9 lb/TBtu). 
BILLING CODE 6560–50–P 
A similar effect can be seen with the 
2022 daily and 30-operating-day rolling average Hg emissions from Leland Olds unit 1, an EGU firing North Dakota lignite, shown in figure 2 of this document. 
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ER07MY24.071</GPH>khammond on DSKJM1Z7X2PROD with RULES43.5 
Dave Johnston Unit BW41 
3.0 
2.5 -Hg Rate (lb/TBtu) 
-Hg Rate -30 day rolling (lb/Tbtu) 
1.0 
0.5 
o.o 
Days in Calendar Vear 2022 
Figure 1. 2022 Daily and 30-Day Rolling Average Hg Emission Rates (lb/TBtu) 
From Dave Johnston Unit BW41, a subbituminous-fired EGU in Wyoming. 38545 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
BILLING CODE 6560–50–C 
As with the EGU firing subbituminous 
coal, the daily Hg emissions very often 
exceed the emission limit (in this case 4.0 lb/TBtu); however, the 30-operating- day rolling average is consistently below the applicable emission limit (the 2022 annual average emission rate for Leland Olds unit 1 is 2.3 lb/TBtu). 
2. The Impact of Halogen Content of 
Lignite on Hg Control 
In the 2023 Proposal, the EPA 
explained that during combustion of coal, the Hg contained in the coal is volatilized and converted to Hg
0vapor 
in the high-temperature regions of the 
boiler. Hg0vapor is difficult to capture 
because it is typically nonreactive and insoluble in aqueous solutions. However, under certain conditions, the Hg
0vapor in the flue gas can be 
oxidized to divalent Hg (Hg2+). The Hg2+ 
can bind to the surface of solid particles (e.g., fly ash, injected sorbents) in the 
flue gas stream, often referred to as ‘‘particulate bound Hg’’ (Hg
p) and be 
removed in a downstream PM control device. Certain oxidized Hg compounds that are water soluble may be further removed in a downstream wet scrubber. The presence of chlorine in gas-phase equilibrium favors the formation of mercuric chloride (HgCl
2) at flue gas 
cleaning temperatures. However, Hg0 
oxidation reactions are kinetically limited as the flue gas cools, and as a result Hg may enter the flue gas cleaning device(s) as a mixture of Hg
0, Hg2+ 
compounds, and Hg p. 
This partitioning into various species 
of Hg has considerable influence on selection of Hg control approaches. In tables 5 and 6 of this document, the chlorine content of bituminous coals mined in Kentucky and Pennsylvania averaged 1,086 ppm and 1,050 ppm, respectively. In comparison, the average chlorine content of Wyoming subbituminous coal is 127 ppm; while the chlorine contents of lignite mined in North Dakota and Texas are 133 ppm and 232 ppm, respectively. In general, because of the presence of higher amounts of halogen (especially chlorine) in bituminous coals, most of the Hg in the flue gas from bituminous coal-fired boilers is in the form of Hg
2+ 
compounds, typically HgCl 2, and is 
more easily captured in downstream control equipment. Conversely, both subbituminous coal and lignite have lower natural 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
0and 
is more challenging to control in downstream control equipment. 
While some bituminous coal-fired 
EGUs require the 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 described above, the Hg in the flue gas for EGUs firing subbituminous coal or lignite tends to be in the nonreactive Hg
0vapor phase due to lack of available 
free halogen to promote the oxidation reaction. To alleviate this challenge, activated carbon and other sorbent providers and control technology vendors have developed methods to introduce halogen into the flue gas to improve the control of Hg emissions from EGUs firing subbituminous coal and lignite. This is 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. In the 
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ER07MY24.072</GPH>khammond on DSKJM1Z7X2PROD with RULES410.0 
9.0 
8.0 
a 1.0 
CIC 
~ 6.0 
.. 
C o 5.0 
'iii 
.!!! E 4.0 
w 
~ 3.0 
2.0 
1.0 
0.0 Leland Olds Unit 1 
-Hg Rate (lb/TBtu) 
-30-day rolling avg (lb/TBtu) 
Days in Calendar Year 2022 
Figure 2. Daily and 30-Day Rolling Average Hg Emission Rates (lb/TBtu) from Leland 
Olds Unit 1, lignite-fired EGU in North Dakota. 38546 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
74The mention of specific products by name does 
not imply endorsement by the EPA. The EPA does 
not endorse or promote any particular control technology. The EPA mentions specific product names here to emphasize the broad range of products and vendors offering sulfur tolerant Hg control technologies. 
75https://www.aecom.com/wp-content/uploads/ 
2019/07/10_ EUEC_ P_PT_Brochure_ HBS_
InjectionTechnology_ 20160226_ singles.pdf. 76https://www.calgoncarbon.com/app/uploads/ 
DS-FLUEST15-EIN-E1.pdf. 
77https://www.babcock.com/assets/PDF- 
Downloads/Emissions-Control/E101-3200-Mercury- 
and-HAPs-Emissions-Control-Brochure-Babcock- Wilcox.pdf. 
78ME2C 2016 Corporate Brochure, available in 
the rulemaking docket at EPA–HQ–OAR–2018– 0794. 
79https://norit.com/application/power-steel- 
cement/power-plants. 2022 CAA section 114 information 
collection, almost all the lignite-fired units reported use of some sort of halogen additive or injection as part of their Hg control strategy by using refined coal (which typically has added halogen), bromide or chloride chemical additives, pre-halogenated sorbents, and/or oxidizing agents. Again, low chlorine content in the fuel is a challenge that is faced by EGUs firing either subbituminous coals or lignite, and EGUs firing subbituminous coal have been subject to a Hg emission standard of 1.2 lb/TBtu since the MATS rule was finalized in 2012. 
3. The Impact of SO
3on Hg Control 
Some commenters noted that the EPA 
did not account for the impacts of the 
higher sulfur content of lignite as compared to that of subbituminous coal, and that such higher sulfur content leads to the presence of additional SO
3 
in the flue gas stream. As shown in table 5 and table 6 of this document, while the halogen content of subbituminous coal and lignite is similar, the average sulfur content of lignite is more like that of bituminous coal mined in Kentucky and Pennsylvania. 
During combustion, most of the sulfur 
in coal is oxidized into SO
2, and only 
a small portion is further oxidized to SO
3in the boiler. In response to 
environmental requirements, many EGUs have installed SCR systems for NO
Xcontrol and FGD systems for SO 2 
control. One potential consequence of an SCR retrofit is an increase in the amount of SO
3in the flue gas 
downstream of the SCR due to catalytic oxidation of SO
2. Fly ash and 
condensed SO 3are the major 
components of flue gas that contribute to the opacity of a coal plant’s stack emissions and the potential to create a visible sulfuric acid ‘‘blue plume.’’ In addition, higher SO
3levels can 
adversely affect many aspects of plant operation and performance, including corrosion of downstream equipment and fouling of the air preheater (APH). This is primarily an issue faced by EGUs firing bituminous coal. EGUs fueled by subbituminous coal and lignite do not typically have the same problem with blue plume formation. Of the EGUs that are designed to fire lignite, only Oak Grove units 1 and 2, located in Texas, have an installed SCR for NO
Xcontrol. 
Several lignite-fired EGUs utilize SNCR systems for NO
Xcontrol, which are less 
effective for NO Xcontrol as compared to 
SCR systems. Several commenters claimed that SCR is not a viable NO
X 
control technology for EGUs firing North Dakota lignite because of catalyst fouling from the high sodium content of 
the fuel and resulting fly ash. 
Coal 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 coals and lignite 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—and, as noted by commenters—the presence of sodium compounds in the ash. The natural alkalinity of the subbituminous and lignite fly ash may effectively neutralize the limited free halogen in the flue gas and prevent oxidation of the Hg
0. 
However, the natural alkalinity also helps to minimize the impact of SO
3, 
because a common control strategy for SO
3is the injection of alkaline sorbents 
(dry sorbent injection, DSI). 
Still, as commenters correctly noted, 
the presence of SO 3in the flue gas 
stream is also known to negatively impact the effectiveness of sorbent injection for Hg control. This impact has been known for some time, and control technology researchers and vendors have developed effective controls and strategies to minimize the impact of SO
3.74As noted above, coal-fired EGUs 
utilizing bituminous coal—which also experience significant rates of SO
3 
formation in the flue gas stream—have also successfully demonstrated the application of Hg control technologies to meet a standard of 1.2 lb/TBtu. 
The AECOM patented SBS 
Injection
TM(‘‘sodium-based solution’’) 
technology has been developed for control of SO
3, and co-control of Hg has 
also been demonstrated. A sodium- based solution is injected into the flue gas, typically ahead of the APH or, if present, the SCR. By removing SO
3prior 
to these devices, many of the adverse effects of SO
3can be successfully 
mitigated. AECOM has more recently introduced their patented HBS Injection
TMtechnology for effective Hg 
oxidation and control.75This new process injects halogen salt solutions 
into the flue gas, which react in-situ to form halogen species that effectively oxidize Hg. The HBS Injection
TMcan be 
co-injected with the SBS InjectionTMfor 
effective SO 3control and Hg oxidation/ 
control. 
Other vendors also offer technologies 
to mitigate the impact of SO 3on Hg 
control from coal combustion flue gas streams. For example, Calgon Carbon offers their ‘‘sulfur tolerant’’ Fluepac ST, which is a brominated powdered activated carbon specially formulated to enhance Hg capture in flue gas treatment applications with elevated levels of SO
3.76In testing in a 
bituminous coal combustion flue gas stream containing greater than 10 ppm SO
3, the Fluepac ST was able to achieve 
greater than 90 percent Hg control at injection rates of a third or less as compared to injection rates using the standard brominated sorbent. 
Babcock & Wilcox (B&W) offers dry 
sorbent injection systems that remove SO
3before the point of activated carbon 
sorbent injection to mitigate the impact of SO
3.77Midwest Energy Emissions 
Corporation (ME 2C) offers ‘‘high-grade 
sorbent enhancement additives— injected into the boiler in minimal amounts’’ that work in conjunction with proprietary sorbent products to ensure 
maximum Hg capture. ME
2C claims that 
their Hg control additives and proprietary sorbent products are ‘‘high- sulfur-tolerant and SO
3-tolerant 
sorbents.’’78 
Cabot Norit Activated Carbon is the 
largest producer of powdered activated carbon worldwide.
79Cabot Norit offers 
different grades of their DARCO® 
powdered activated carbon (PAC) for Hg removal at power plants. These grades include non-impregnated PAC which are ideal when most of the Hg is in the oxidized state; impregnated PAC for removing oxidized and Hg
0from flue 
gas; special impregnated PAC used in conjunction with DSI systems (for control of acid gases); and special impregnated ‘‘sulfur resistant’’ PAC for flue gases that contains higher concentrations of acidic gases like SO
3. 
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80https://www.advancedemissionssolutions.com/ 
ADES-Investors/ada-products-and-services/ 
default.aspx. Similarly, ADA–ES offers FastPACTM 
Platinum 80,80an activated carbon 
sorbent that was specifically engineered 
for SO 3tolerance and for use in 
applications where SO 3levels are high. 
So, owner/operators of lignite-fired EGUs can choose from a range of technologies and technology providers that offer Hg control options in the presence of SO
3. The EPA also notes 
that SO 3is more often an issue with 
EGUs firing eastern bituminous coal—as those coals typically have higher sulfur content and lower ash alkalinity. Those bituminous coal-fired EGUs are subject to—and have demonstrated compliance 
with—an emission standard of 1.2 lb/ TBtu. 
4. Cost Considerations for the More 
Stringent Hg Emission Standard 
From the 2022 CAA section 114 
information survey, most lignite-fired EGUs utilized a control strategy that included sorbent injection coupled with chemical additives (usually halogens). In the beyond-the-floor analysis in the 2012 MATS Final Rule, we noted that the results from various demonstration projects suggested that greater than 90 percent Hg control can be achieved at lignite-fired units using brominated activated carbon sorbents at an injection rate of 2.0 lb/MMacf (i.e., 2.0 pounds of 
sorbent injected per million actual cubic 
feet of flue gas) for units with installed FFs for PM control and at an injection rate of 3.0 lb/MMacf for units with installed ESPs for PM control. As shown in table 7 of this document, all units (in 2022) would have needed to control their Hg emissions to 95 percent or less 
to meet an emission standard of 1.2 lb/ TBtu. Based on this, we expect that the units could meet the final, more stringent, emission standard of 1.2 lb/ TBtu by utilizing brominated activated carbon at the injection rates suggested in the beyond-the-floor memorandum from the 2012 MATS Final Rule. 
BILLING CODE 6560–50–P 
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81Estimated Hg inlet values are based on fuel use 
data from EIA Form 923 and assumed Hg content 
of coals as shown in Table 5 and Table 6 in this preamble. 
BILLING CODE 6560–50–C 
To determinethe cost effectiveness of 
that strategy, we calculated the cost per 
lb of Hg controlled for a model 800 MW lignite-fired EGU, as described in the 2024 Technical Memo. We calculated the cost of injecting brominated activated carbon sorbent at injection rates suggested in the beyond-the-floor memorandum from the 2012 MATS Final Rule (i.e., 2.0 lb/MMacf and 3.0 lb/ 
MMacf) and at a larger injection rate of 5.0 lb/MMacf to achieve an emission rate of 1.2 lb/TBtu. We also calculated 
the incremental cost to meet the more stringent emission rate of 1.2 lb/TBtu 
versus the cost to meet an emission rate of 4.0 lb/TBtu using non-brominated activated carbon sorbent at an emission rate of 2.5 lb/MMacf. For an 800 MW lignite-fired EGU, the cost effectiveness of using the brominated carbon sorbent at an injection rate of 3.0 lb/MMacf was $3,050 per lb of Hg removed while the incremental cost effectiveness was $10,895 per incremental lb of Hg removed at a brominated activated carbon injection rate of 3.0 lb/MMacf. The cost effectiveness of using the brominated carbon sorbent at an injection rate of 5.0 lb/MMacf was 
$5,083 per lb of Hg removed while the incremental cost effectiveness was $28,176 per incremental lb of Hg removed. The actual cost effectiveness is likely lower than either of these estimates as it is unlikely that sources will need to inject brominated activated carbon sorbent at rates as high as 5.0 lb/ MMacf (from the 2022 CAA section 114 information collection, the Oak Grove units were injecting less than 0.5 lb/ MMacf) and is either well below or reasonably consistent with the cost effectiveness that the EPA has found to 
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ER07MY24.073</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 7. Measured Hg Emissions and Estimated Control Performance of Lignite-Fired 
EGUs in2022 
Estimated Estimated Estimated 2022 
2022 Hg Hg Hg Measured Estimated 
EGU Inlet81 Control Control Hg 2022 Hg 
(lb/TBtu) (%) at 4.0 (%) at 1.2 Emissions Control(%) 
lb/TBtu lb/TBtu (lb/TBtu) 
North Dakota EGUs 
Antelope Valley 1 11.2 64.4 89.3 3.03 73.0 
Antelope Valley 2 11.2 64.4 89.3 3.00 73.3 
Coal Creek 1 9.7 58.7 87.6 3.43 64.6 
Coal Creek 2 9.7 58.7 87.6 3.87 60.1 
Coyote 1 9.7 58.6 87.6 2.28 76.4 
Leland Olds 1 11.3 64.5 87.6 2.34 79.3 
Leland Olds 2 11.3 64.5 87.6 3.10 72.5 
Milton R Young 1 9.7 58.6 87.6 3.02 68.8 
Milton RY oung 2 9.7 58.6 87.6 3.00 69.0 
Spiritwood Station 1 9.2 56.5 87.0 2.14 76.8 
Texas and Mississippi EGUs 
Limestone 1 * 5.8 30.7 79.2 0.78 86.5 
Limestone 2* 5.8 30.7 79.2 0.85 85.3 
Major Oak Power 1 24.9 84.0 95.2 0.86 96.5 
Major Oak Power 2 24.9 84.0 95.2 0.63 97.5 
Martin Lake 1 * 5.8 31.0 79.3 1.53 73.6 
Martin Lake 2 * 5.8 31.0 79.3 2.50 56.9 
Martin Lake 3 * 5.8 31.0 79.3 2.36 59.3 
Oak Grove 1 24.8 83.9 95.2 2.53 89.8 
Oak Grove 2 24.8 83.9 95.2 2.23 91.0 
San Miguel 1 28.9 86.2 95.9 3.03 89.5 
Red Hills 1 22.9 82.6 94.8 1.73 92.5 
Red Hills 2 22.9 82.6 94.8 1.75 92.4 
* These units, which are permitted to fire lignite, utilized primarily subbituminous coal in 2022. 38549 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
82For example, the EPA proposed that $27,500 
per lb of Hg removed was cost-effective for the 
Primary Copper RTR (87 FR 1616); and approximately $27,000 per lb of Hg ($2021) was found to be cost-effective in the beyond-the-floor analysis supporting the 2012 MATS Final Rule. 83Oil-fired EGUs burning residual fuel oil have 
generally higher emission rates of HAP compared to that from the use of other types of fuel. be acceptable in previous rulemakings 
for Hg controls.82 
In addition to cost effectiveness, the 
EPA finds that the revised Hg emission standard for lignite-fired units appropriately considers the costs of controls, both total costs and as a fraction of total revenues, along with other factors that the EPA analyzed pursuant to its CAA section 112(d)(6) authority. Similar to the revised fPM emission standard (as a surrogate for non-Hg HAP metals) discussed in section IV. of this preamble, the EPA anticipates that the total costs of controls (which consists of small annual incremental operating costs) to comply with the revised Hg emission standard will be a small fraction of the total revenues for the impacted lignite-fired units. The EPA expects that sources will be able to meet the revised emission standard using existing controls (e.g., using existing sorbent injection equipment), and that significant additional capital investment is unlikely. If site-specific conditions necessitate minor capital improvements to the ACI control technology, it is important to note that any incremental capital would be small relative to ongoing sorbent costs accounted for in this analysis. Further, in addition to the EPA finding that costs are reasonable for the revised Hg standard for lignite-fired EGUs, the revised standard will also bring these higher emitting sources of Hg emission in line with Hg emission rates that are achieved by non-lignite- fired EGUs. As mentioned earlier in this preamble, in 2021, lignite-fired EGUs were responsible for almost 30 percent of all Hg emitted from coal-fired EGUs while generating about 7 percent of total megawatt-hours. 
Despite the known differences in the 
quality and composition of the various coal types, the EPA can find no compelling reasons why EGUs that are firing lignite cannot meet the same emission limit as EGUs that are firing other types of coal (e.g., eastern and 
western bituminous coal, subbituminous coal, and anthracitic and bituminous waste coal). Each of the coal types/ranks has unique compositions and properties. Low halogen content in coal is known to make Hg capture more challenging. But, both lignites and subbituminous coals have low halogen content with higher alkaline content. Lignites tend to have average higher Hg 
content than subbituminous and bituminous coals—especially lignites mined in Mississippi and Texas. However, waste coals (anthracitic and bituminous coal refuse) tend to have the highest average Hg content. Lignites tend to have higher sulfur content than that of subbituminous coals and the sulfur in the coal can form SO
3in the 
flue gas. This SO 3is known to make Hg 
capture using sorbent injection more challenging. However, bituminous coals and waste coals have similar or higher levels of sulfur. The formation of SO
3is 
more significant with these coals. Despite all the obstacles and challenges presented to EGUs firing non-lignite coals, all of those EGUs have been subject to the more stringent Hg emission limit of 1.2 lb/TBtu—and emit at or below that emission limit since the rule was fully implemented. Advanced, better performing Hg controls— including ‘‘SO
3tolerant’’ sorbents—are 
available to allow lignite-fired EGUs to also emit at or below the more stringent Hg emission limit of 1.2 lb/TBtu. As mentioned earlier in this preamble, in 2021, lignite-fired EGUs were responsible for almost 30 percent of all Hg emitted from coal-fired EGUs while generating about 7 percent of total megawatt-hours. 
VI. What is the rationale for our other 
final decisions and amendments from review of the 2020 Technology Review? 
A. What did we propose pursuant to 
CAA section 112(d)(6) for the other NESHAP requirements? 
The EPA did not propose any changes 
to the organic HAP work practice standards, acid gas standards, continental liquid oil-fired EGU standards, non-continental liquid oil- fired EGUs, limited-use oil-fired EGU standards, or standards for IGCC EGUs. The EPA proposed to require that IGCC EGUs use PM CEMS for compliance demonstration with their fPM standard. 
The EPA did note in the 2023 
Proposal that there have been several recent temporary and localized increases in oil combustion at continental liquid oil-fired EGUs during periods of extreme weather conditions, such as the 2023 polar vortex in New England. As such, the EPA solicited comment on whether the current definition of the limited-use liquid oil- fired subcategory remains appropriate or if, given the increased reliance on oil- fired generation during periods of extreme weather, a period other than the current 24-month period or a different threshold would be more appropriate for the current definition. The EPA also solicited comment on the appropriateness of including new HAP standards for EGUs subject to the limited use liquid oil-fired subcategory, as well as on the means of demonstrating compliance with the new HAP standards. 
B. How did the technology review 
change for the other NESHAP requirements? 
The technology review for the organic 
HAP work practice standards, acid gas standards, and standards for oil-fired EGUs has not changed from the proposal. 
The proposed technology review with 
respect to the use of PM CEMS for compliance demonstration by IGCC EGUs has changed due to comments received on the very low fPM emission rates and on technical challenges with certifying PM CEMS on IGCC EGUs. Therefore, the Agency is not finalizing the required use of PM CEMS for compliance demonstration with the fPM emission standard at IGCC EGUs. 
C. What key comments did we receive 
on the other NESHAP requirements, and what are our responses? 
Comment: Commenters urged the EPA 
to retain the current definition of the limited-use liquid oil-fired subcategory and not to impose new HAP standards on EGUs in this subcategory, given that there are already limits on the amount of fuel oil that can be burned. Commenters noted that the Agency has not identified any justification for the costs required for implementation and compliance with new HAP standards for limited-use liquid oil-fired EGUs. Some commenters alleged that any changes to the existing HAP standards for EGUs in the limited-use liquid oil-fired subcategory may complicate reliability management during cold winter spells or other extreme weather events. 
Response: The Agency did not 
propose changes to the limited-use liquid oil-fired EGU subcategory or to the requirements for such units. To evaluate the potential HAP emission impact of liquid oil-fired EGUs
83during 
extreme weather events, the Agency reviewed the 2022 fPM emissions of 11 liquid oil-fired EGUs in the Northeast U.S. that were operated during December 2022 Winter Storm Elliot, as described in the 2024 Technical Memo. The review found that total non-Hg HAP metal emissions during 2022 from the 11 oil-fired EGUs in New England were very small—approximately 70 times lower than the non-Hg HAP metal emissions estimated from oil-fired units 
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84See Residual Risk Assessment for the Coal- and 
Oil-Fired EGU Source Category in Support of the 
2019 Risk and Technology Review Proposed Rule (Docket ID No. EPA–HQ–OAR–2018–0794–0014). 85See Document ID No. EPA–HQ–OAR–2018– 
0794–4565 at https://www.regulations.gov. in Puerto Rico, which were among the 
facilities with the highest (but acceptable) residual risk in the 2020 Residual Risk Review.
84The EPA will 
continue to monitor the emissions from the dispatch of limited-use liquid oil- fired EGUs—especially during extreme weather events. 
In addition, the Agency reviewed the 
performance of PM CEMS for compliance demonstration at oil-fired EGUs. Given the higher emission rates and limits from this subcategory of EGUs, the Agency did not find any of the correlation issues with the use of PM CEMS with oil-fired EGUs similar to those that were discussed earlier for coal-fired EGUs. Moreover, the benefits of PM CEMS use that were described earlier (i.e., emissions transparency, 
operational feedback, etc.) translate well to oil-fired EGUs; therefore, the EPA is finalizing the requirement for oil-fired EGUs (excluding limited-use liquid oil- fired EGUs) to use PM CEMS for compliance demonstration, as proposed. 
Comment: One commenter 
recommended that units involved with carbon capture and sequestration (CCS) projects retain the option to use stack testing for compliance demonstration. They said that PM emissions would be measured from the stack downstream of the carbon capture system (they specifically mentioned the carbon capture system being contemplated to be built to capture CO
2emission from 
the Milton R. Young Station facility in North Dakota). The commenters said that PM CEMS correlation testing will cause operational impacts on the CCS operations due to operational changes or reduced control efficiencies that temporarily increase PM emissions for long time periods, resulting in CCS operations being adversely affected or even shut down for long periods. 
Response: The Agency disagrees with 
the commenter’s recommendation that units utilizing a carbon capture system should be able to continue to use periodic stack testing for compliance demonstration. At the present time, the many ways that CCS can be employed and deployed at coal-fired EGUs supports the use of PM CEMS for compliance purposes. For example, measures (such as a bypass stack) are available that would minimize the operational impacts on the carbon capture system and would allow for proper PM CEMS correlations. Furthermore, the Agency finds that the increased transparency and the improved ability to detect and correct 
potential control or operational problems offered by PM CEMS, as well as the greater assurance of continuous compliance, outweigh the minor operational impacts potentially experienced. To the extent that a specific coal- or oil-fired EGU utilizing CCS wishes to use an alternative test method for compliance demonstration purposes, its owner or operator may submit a request to the Administrator under the provisions of 40 CFR 63.7(f). 
D. What is the rationale for our final 
approach and decisions regarding the other NESHAP requirements? 
The Agency did not receive comments 
that led to any changes in the outcome of the technology review for other NESHAP requirements as presented in the 2023 Proposal. The Agency did not propose any changes for the current requirements for organic HAP work practice standards, acid gas standards, or standards for oil-fired EGUs and therefore no changes are being finalized. 
The EPA is aware of two existing 
IGCC facilities that meet the definition of an IGCC EGU. The Edwardsport Power Station, located in Knox County, Indiana, includes two IGCC EGUs that had 2021 average capacity factors of approximately 85 percent and 67 percent. These EGUs have LEE qualification for PM, with most current test results of 0.0007 and 0.0003 lb/ MMBtu, respectively. The Polk Power Station, located in Polk County, Florida, had a 2021 average capacity factor of approximately 70 percent but burned only natural gas in 2021 (i.e., operating 
essentially as a natural gas combined cycle turbine EGU). Before this EGU switched to pipeline quality natural gas as a fuel, it qualified for PM LEE status in 2018; to the extent that the EGU again operates as an IGCC, it could continue to claim PM LEE status. While this 
subcategory has a less stringent fPM standard of 0.040 lb/MMBtu (as compared to that of coal-fired EGUs), recent compliance data indicate fPM emissions well below the most stringent standard option of 0.006 lb/MMBtu that was evaluated for coal-fired EGUs. 
The EPA is not finalizing the required 
use of PM CEMS for compliance demonstration for IGCC EGUs due to technical limitations expressed by commenters. For example, commenters noted that due to differences in stack design, the only possible installation space for a PM CEMS on an IGCC facility is on a stack with elevated grating, exposing the instrument to the elements, which would impact the sensitivity and accuracy of a PM CEMS. Additionally, there are no PM control devices at an IGCC unit available for de- tuning, which is necessary for establishing a correlation curve under PS–11. The EPA has considered these comments and agrees with these noted challenges to the use of PM CEMS at IGCC EGUs and, for those reasons, the EPA is not finalizing the proposed requirement for IGCCs to use PM CEMS for compliance demonstration, thus IGCCs will continue to demonstrate compliance via fPM emissions testing. As a result of comments we received on coal-fired run durations and our consideration on those comments, along with the low levels of reported emissions, the EPA determined that owners or operators of IGCCs will need to ensure each run has a minimum sample volume of 2 dscm or a minimum mass collection of 3 milligrams. In addition, IGCC EGUs will continue to be able to obtain and maintain PM LEE status. 
VII. Startup Definition for the Coal- and 
Oil-Fired EGU Source Category 
A. What did we propose for the Coal- 
and Oil-Fired EGU source category? 
In the 2023 Proposal, the EPA 
proposed to remove the alternative work practice standards, i.e., those contained 
in paragraph (2) of the definition of ‘‘startup’’ in 40 CFR 63.10042 from the rule based on a petition for reconsideration from environmental groups that was remanded to the EPA in Chesapeake Climate Action Network v. EPA, 952 F.3d 310 (D.C. Cir. 2020), and 
responding in part to a separate petition for reconsideration from environmental groups, that sought the EPA’s reconsideration of certain aspects of the 2020 Residual Risk Review.
85The first 
option under paragraph (1) 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. 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 onsite 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 
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event. Startup ends 4 hours after the 
EGU generates electricity that is sold or used for any purpose (including onsite use), or 4 hours after the EGU makes useful thermal energy for industrial, commercial, heating, or cooling purposes, whichever is earlier. 
As described in the 2023 Proposal, the 
Agency proposed to remove paragraph (2) of the definition of ‘‘startup’’ as part of our obligation to address the remand on this issue. In addition, as the majority of EGUs currently rely on work practice standards under paragraph (1) of the definition of ‘‘startup,’’ we believe this change is achievable by all EGUs and would result in little to no additional expenditures, especially since the additional reporting and recordkeeping requirements associated with use of paragraph (2) would no longer apply. Lastly, the time period for engaging PM or non-Hg HAP metal controls after non-clean fuel use, as well as for full operation of PM or non-Hg HAP metal controls, is expected to be 
reduced when transitioning to paragraph (1), therefore increasing the duration in which pollution controls are employed and lowering emissions. 
B. How did the startup provisions 
change for the Coal- and Oil-Fired EGU source category? 
The EPA is finalizing the amendment 
to remove paragraph (2) from the definition of ‘‘startup’’ as proposed. 
C. What key comments did we receive 
on the startup provisions, and what are our responses? 
We received both supportive and 
adverse comments on the proposed removal of paragraph (2) of the definition of ‘‘startup.’’ The summarized comments and the EPA’s responses are provided in the National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review Proposed Rule Response to Comments document. The most significant adverse comments and the EPA’s responses are provided below. 
Comment: Commenters recommended 
that the 4-hour startup definition should continue to be allowed as removing it for simplicity is not an adequate justification. They said the EPA is conflating the MACT standard-setting process with this RTR process. Although the EPA notes that the best performing 12 percent of sources do not need this alternative startup definition, commenters stated that this change is beyond the scope of the technology review. Commenters asserted that the EPA’s determination that only eight EGUs are currently using that option is 
insufficient justification for eliminating the definition. Given that the 2023 Proposal did not identify any flaws with the current definition, the commenters stated that the EPA should explain why elimination of the 4-hour definition from MATS is appropriate when there are units currently relying on it. Commenters also stated that the EPA should consider providing reasonable exemptions for the EGUs that currently use that definition, thus gradually phasing out the definition without imposing any additional compliance burdens. The commenters also argued that with potentially lower fPM standards, more facilities may need the additional flexibility allowed by this definition of startup as their margin of compliance is reduced. They noted that startup or non-steady state operation is not conducive to CEMS accuracy and that it may create false reporting of emissions data biased either high or low depending on the actual conditions. 
Commenters stated that several 
facilities are currently required to use the 4-hour startup definition per federal consent decrees or state agreements. They said such a scenario provides clear justification for a limited exemption, as MATS compliance should not result in an EGU violating its consent decree. Commenters noted other scenarios where state permits have special conditions with exemptions from emission limits during ramp-up or ramp-down periods. They said many facilities alleviate high initial emissions by using alternate fuels to begin the combustion process, which has been demonstrated as a Best Management Practice and to lower emissions. Commenters noted that the permit modification process, let alone any physical or operational modifications to the facility, could take significantly longer than the 180-day compliance deadline, depending on public comments, meetings, or contested hearing requests made during the permit process. 
Commenters stated the startup 
definition paragraph (2) has seen limited use due to the additional reporting requirements that the EPA imposed on sources that chose to use the definition, which they believe are unnecessary and should be removed from the rule. The commenters said that the analysis the EPA conducted during the startup/shutdown reconsideration in response to Chesapeake Climate Action Network v. EPA, 952 F.3d 310 (D.C. Cir. 
2020) showed that the definition was reasonable, and they argued that the 
definition may be needed if the EPA further reduces the limits, given the transitory nature of unit and control 
operation during these periods. Commenters also stated that the startup definition paragraph (2) is beneficial to units that require extended startups. They said including allowances for cold startup conditions could allow some EGUs to continue operation until more compliant generation is built, which would help facilitate a smooth transition to newer plants that meet the requirements without risking the reliability of the electric grid. Commenters also noted that some control devices, such as ESPs, may not be operating fully even when the plant begins producing electricity. 
Commenters stated that the EPA 
should consider allowing the use of diluent cap values from 40 CFR part 75. As these are limited under MATS, commenters noted that startup and shutdown variations are more pronounced than if diluent caps were to be allowed. They said that with a lower emissions limitation, the diluent cap would mathematically correct for calculation inaccuracies inherent in emission rate calculation immediately following startup. Commenters stated that relative accuracy test audits (RATA) must be conducted at greater than 50 percent load under 40 CFR part 60 and at normal operating load under 40 CFR part 75. They said that it is not reasonable to require facilities to certify their CEMS, including PM CEMS, at greater than 50 percent capacity and use it for compliance at less than 50 percent capacity. Commenters stated that startups have constantly changing flow and temperatures that do not allow compliance tests to be conducted during these periods. 
Response: The Agency disagrees with 
the commenters who suggest that the 4- hour startup duration should be retained. As mentioned in the 2023 Proposal (88 FR 24885), owners or operators of coal- and oil-fired EGUs that generated over 98 percent of electricity in 2022 have made the requisite adjustments, whether through greater clean fuel capacity, better tuned equipment, better trained staff, a more efficient and/or better design structure, or a combination of factors, to be able to meet the requirements of paragraph (1) of the startup definition. This ability points out an improvement in operation that all EGUs should be able to meet at little to no additional expenditure, since the additional recordkeeping and reporting provisions associated with the work practice standards of paragraph (2) of the startup definition were more expensive than the requirements of 
paragraph (1) of the definition. As mentioned with respect to gathering 
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experience with PM CEMS, the Agency 
believes owners or operators of the 8 EGUs relying on the 4-hour startup period can build on their startup experience gained since finalization of the 2012 MATS Final Rule, along with the experience shared by some of the other EGUs that have been able to conform with startup definition paragraph (1), as well as the experience to be obtained in the period yet remaining before compliance is required; such experience could prove key to aiding source owners or operators in their shift from reliance on startup definition paragraph (2) to startup definition paragraph (1). Should EGU owners or operators find that their attempts to rely on startup definition (1) are unsuccessful after application of that experience, they may request of the Administrator the ability to use an alternate non-opacity standard, as described in the NESHAP general provisions at 40 CFR 63.6(g). Before the Administrator’s approval can be granted, the EGU owner or operator’s request must appear in the Federal Register for the opportunity for notice 
and comment by the public, as required in 40 CFR 63.6(g)(1). 
Regarding consent decrees or state 
agreements for requirements other than those contained in this rule, while the rule lacks the ability to revise such agreements, the EPA recommends that EGU owners or operators contact the other parties to see what, if any, revisions could be made. Nonetheless, the Agency expects EGU source owners or operators to comply with the revised startup definition by the date specified in this rule. Given the concern expressed by the commenters for some sources, the Agency expects such source owners or operators to begin negotiations with other parties for other non-rule obligations to begin early enough to be completed prior to the compliance date specified in this rule. 
The Agency disagrees with the 
commenters’ suggestions that startup definition paragraph (2)’s reporting requirements were too strict to be used. That suggestion is not consistent with the number of commenters who claimed to need to use paragraph (2) of the startup definition, even though only 2.5 percent of EGUs currently rely on this startup definition. The Agency’s experience is that almost all EGU source owners or operators have been able to adjust their unit operation such that adherence to startup definition paragraph (1) reduced, if not eliminated, the concern by some about use of startup definition paragraph (1). As 
mentioned earlier in this document, the better performers in the coal-fired EGU source category no longer need to have, 
or use, paragraph (2) of the startup definition after gaining experience with using paragraph (1). 
The Agency disagrees with the 
commenter’s suggestion that the diluent cap values allowed for use by 40 CFR part 75 be included in the rule, because diluent cap values are already allowed for use during startup and shutdown periods per 40 CFR 63.10007(f)(1). Note that while emission values are to be recorded and reported during startup and shutdown periods, they are not to be used in compliance calculations per 40 CFR 63.10020(e). In addition to diluent cap use during startup and shutdown periods, section 6.2.2.3 of appendix C to 40 CFR part 63, subpart UUUUU allows diluent cap use for PM CEMS during any periods when oxygen or CO
2values exceed or dip below, 
respectively, the cap levels. Diluent cap use for other periods from other regulations are not necessary for MATS. The Agency does not understand the commenter’s suggestion concerning the load requirement for a RATA. The Agency believes the commenter may have mistaken HCl CEMS requirements, which use RATAs but were not proposed to be changed, with PM CEMS requirements, which do not use RATAs. Since PM CEMS are not subject to RATAs and the Agency did not propose changes to requirements for HCl CEMS, the comment on RATAs being conducted at greater than 50 percent 
load is moot. The EPA is finalizing the removal of startup definition paragraph (2), as proposed. 
D. What is the rationale for our final 
approach and final decisions for the startup provisions? 
The EPA is finalizing the removal of 
paragraph (2) of the definition of ‘‘startup’’ in 40 CFR 63.10042 consistent with reasons described in the 2023 Proposal. As the majority of EGUs are already relying on the work practice standards in paragraph (1) of the startup definition, the EPA finds that such a change is achievable within the 180-day compliance timeline by all EGUs at little to no additional expenditure since the additional reporting and recordkeeping provisions under paragraph (2) were more expensive than paragraph (1). Additionally, the time period for engaging pollution controls for PM or non-Hg HAP metals is expected to be reduced when transitioning to paragraph (1), therefore increasing the duration in which pollution controls are employed and lowering emissions. VIII. What other key comments did we 
receive on the proposal? 
Comment: Some commenters argued 
that it is well-established that cost is a major consideration in rulemakings reviewing existing NESHAP under CAA section 112(d)(6). In particular, commenters cited to Michigan v. EPA, 
576 U.S. 743, 759 (2015), to support the argument that the EPA must consider the costs of the regulation in relation to the benefits intended by the statutory requirement mandating this regulation, that is, the benefits of the HAP reductions. Commenters stated that the EPA should not seek to impose the excessive costs associated with this action as there would be no benefit associated with reducing HAP. The commenters said that the EPA certainly should not do so for an industry that is rapidly reducing its emissions because it is on the way to retiring most, if not all, units in the source category in little over a decade. The commenters also claimed that as Michigan held that cost 
and benefits must be considered in determining whether it is ‘‘appropriate’’ to regulate EGUs under CAA section 112 in the first place, it necessarily follows that the same threshold must also apply when the EPA subsequently reviews the standards. 
Response: The EPA agrees that it is 
appropriate to take costs into consideration in deciding whether it is necessary to revise an existing NESHAP under CAA section 112(d)(6). As explained in the 2023 Proposal and this document, the EPA has carefully considered the costs of compliance and the effects of those costs on the industry. Although the commenters seem to suggest that the EPA should weigh the costs and benefits of the revisions to the standard, we do not interpret the comments as arguing that the EPA should undertake a formal benefit cost analysis but rather the commenters believe that the EPA should instead limit its analysis supporting the standard to HAP emission reductions. Our consideration of costs in this rulemaking is consistent with the Supreme Court’s direction in Michigan where the Court noted that ‘‘[i]t will be up to the Agency to decide (as always, within the limits of reasonable interpretation) how to account for cost,’’ 576 U.S. 743, 759 (2015), and with comments arguing that the EPA should focus its decision-making on the standard on the anticipated reductions in HAP. 
In Michigan, the Supreme Court 
concluded that the EPA erred when it concluded it could not consider costs when deciding as a threshold matter 
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86As of 2023, three of the HAP metals or their 
compounds emitted by EGUs (arsenic, chromium, 
and nickel) are classified as carcinogenic to humans. More details are available in section II.B.2. and Chapter 4.2.2 of the RIA. 
87See also National Emission Standards for 
Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Revocation of the 2020 Reconsideration and Affirmation of the Appropriate and Necessary Supplemental Finding, 88 FR 13956, 13970–73 (March 6, 2023) (for additional discussion regarding the limitations to monetizing and quantifying most benefits from HAP reductions in the 2023 rulemaking finalizing the appropriate and necessary finding). 
88The number of coal-fired affected EGUs is 
larger than the 296 coal-fired EGUs assessed for the fPM standard in section IV. because it includes four EGUs that burn petroleum coke (which are a separate subcategory for MATS) and 14 EGUs without fPM compliance data available on the EPA’s Compliance and Emissions Data Reporting Interface (CEDRI), https://www.epa.gov/electronic- reporting-air-emissions/cedri. whether it is ‘‘appropriate and 
necessary’’ under CAA section 112(n)(1)(A) to regulate HAP from EGUs, despite the relevant statutory provision containing no specific reference to cost. 576 U.S. at 751. In doing so, the Court held that the EPA ‘‘must consider cost—including, most importantly, cost of compliance—before deciding whether regulation is appropriate and necessary’’ under CAA section 112. Id. at 759. In examining the 
language of CAA section 112(n)(1)(A), the Court concluded that the phrase ‘‘appropriate and necessary’’ was ‘‘capacious’’ and held that ‘‘[r]ead naturally in the present context, the phrase ‘appropriate and necessary’ requires at least some attention to cost.’’ Id. at 752. As is clear from the record 
for this rulemaking, the EPA has carefully considered cost in reaching its decision to revise the NESHAP in this action. 
The EPA has also taken into account 
the numerous HAP-related benefits of the final rule in deciding to take this action. These benefits include not only the reduced exposure to Hg and non-Hg HAP metals, but also the additional transparency provided by PM CEMS for communities that live near sources of HAP, and the assurance PM CEMS will provide that the standards are being met on a continuous basis. As discussed in section II.B.2., and section IX.E. many of these important benefits are not able to be monetized. Although this rule will result in the reduction of HAP, including Hg, lead, arsenic, chromium, nickel, and cadmium, data limitations prevent the EPA from assigning monetary value to those reductions. In addition, there are several benefits associated with the use of PM CEMS which are not quantified in this rule. 
While the Court’s examination of 
CAA section 112(n)(a)(1) in Michigan considered a different statutory provision than CAA section 112(d)(6) under which the EPA is promulgating this rulemaking, the EPA has nonetheless satisfied the Court’s directive to consider costs, both in the context of the individual revisions to MATS (as directed by the language of the statute) and in the context of the rulemaking as a whole. Moreover, while the EPA is not required to undertake a ‘‘formal cost benefit analysis in which each advantage and disadvantage [of a regulation] is assigned a monetary value,’’ Michigan, 576 U.S. at 759, the 
EPA has contemplated and carefully considered both the advantages and disadvantages of the revisions it is finalizing here, including qualitative 
and quantitative benefits of the regulation and the costs of compliance. IX. Summary of Cost, Environmental, and Economic Impacts and Additional Analyses Conducted 
The following analyses of costs and 
benefits, and environmental, economic, and environmental justice impacts are presented for the purpose of providing the public with an understanding of the potential consequences of this final action. The EPA notes that analysis of such impacts is distinct from the determinations finalized in this action under CAA section 112, which are based on the statutory factors the EPA discussed in section II.A. and sections IV. through VII. 
The EPA’s obligation to conduct an 
analysis of the potential costs and benefits under Executive Order 12866, discussed in this section and section X.A., is distinct from its obligation in setting standards under CAA section 112 to take costs into account. As explained above, the EPA considered costs in multiple ways in choosing appropriate standards consistent with the requirements of CAA section 112. The benefit-cost analysis is performed to comply with Executive Order 12866. The EPA, however, did not rely on that analysis in choosing the appropriate standard here, consistent with the Agency’s longstanding interpretation of the statute. As discussed at length in section II.B.2. above and in the EPA’s 2023 final rulemaking finalizing the appropriate and necessary finding (88 FR 13956), historically there have been significant challenges in monetizing the benefits of HAP reduction. Important categories of benefits from reducing HAP cannot be monetized, making benefit-cost analysis ill-suited to the EPA’s decision making on regulating HAP emissions under CAA section 112. Further, there are also unquantified emission reductions anticipated from installing PM CEMS, as discussed in section IX.E. For this reason, combined with Congress’s recognition of the particular dangers posed by HAP and consequent direction to the EPA to reduce emissions of these pollutants to the ‘‘maximum degree,’’ the EPA does not at this time believe it is appropriate to rely on the results of the monetized benefit-cost analysis when setting the standards. 
As noted in section X.A. below, the 
EPA projects that the net monetized benefits of this rule are negative. Many of the benefits of this rule discussed at length in this section and elsewhere in this record, however, were not monetized. This rule will result in the reduction of HAP, including Hg, lead, arsenic, chromium, nickel, and cadmium,
86consistent with Congress’s 
direction in CAA section 112 discussed in section II.A. of this final rule. At this time, data limitations prevent the EPA from assigning monetary value to those reductions, as discussed in section II.B.2. above.
87In addition, the benefits 
of the additional transparency provided by the requirement to use PM CEMS for communities that live near sources of HAP, and the assurance PM CEMS provide that the standards are being met on a continuous basis were not monetized due to data limitations. While the EPA does not believe benefit- cost analysis is the right way to determine the appropriateness of a standard under CAA section 112, the EPA notes that when all of the costs and benefits are considered (including non- monetized benefits), this final rule is a worthwhile exercise of the EPA’s CAA section 112(d)(6) authority. 
A. What are the affected facilities? 
The EPA estimates that there are 314 
coal-fired EGUs
88and 58 oil-fired EGUs 
that will be subject to this final rule by 
the compliance date. 
B. What are the air quality impacts? 
The EPA estimated emission 
reductions under the final rule for the 
years 2028, 2030, and 2035 based upon IPM projections. The quantified emissions estimates were developed with the EPA’s Power Sector Modeling Platform 2023 using IPM, a state-of-the- art, peer-reviewed dynamic, deterministic linear programming model of the contiguous U.S. electric power sector. IPM provides forecasts of least- cost capacity expansion, electricity dispatch, and emission control strategies while meeting electricity demand and various environmental, transmission, dispatch, and reliability constraints. IPM’s least-cost dispatch 
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solution is designed to ensure 
generation resource adequacy, either by using existing resources or through the construction of new resources. IPM addresses reliable delivery of generation resources for the delivery of electricity between the 78 IPM regions, based on current and planned transmission capacity, by setting limits to the ability to transfer power between regions using the bulk power transmission system. 
The model includes state-of-the-art estimates of the cost and performance of air pollution control technologies with 
respect to Hg and other HAP controls. 
The quantified emission reduction 
estimates presented in the RIA include 
reductions in pollutants directly covered by this rule, such as Hg, and changes in other pollutants emitted from the power sector as a result of the compliance actions projected under this final rule. Table 8 of this document presents the projected emissions under the final rule. Note that, unlike the cost- effectiveness analysis presented in sections IV. and V. of this preamble, the 
projections presented in table 8 are incremental to a projected baseline which reflects future changes in the composition of the operational coal- fired EGU fleet that are projected to occur by 2035 as a result of factors affecting the power sector, such as the IRA, promulgated regulatory actions, or changes in economic conditions. 
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In addition to the projected emissions 
impacts presented in table 8, we also estimate that the final rule will reduce at least 7 tons of non-Hg HAP metals in 2028, 5 tons of non-Hg HAP metals in 
2030, and 4 tons of non-Hg HAP metals in 2035. These reductions are composed of reductions in emissions of antimony, 
arsenic, beryllium, cadmium, 
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and 2035a 
Total Emissions 
Change 
Year Baseline Final Rule from % Change 
Baseline 
2028 6,129 5,129 -999 -16% 
Hg (lb) 2030 5,863 4,850 -1,013 -17% 
2035 4,962 4,055 -907 -18% 
2028 70.5 69.7 -0.8 -1.1% 
PM2.s ( thousand tons) 2030 66.3 65.8 -0.5 -0.8% 
2035 50.7 50.2 -0.5 -0.9% 
2028 79.5 77.4 -2.1 -2.6% 
PM10 (thousand tons) 2030 74.5 73.1 -1.3 -1.8% 
2035 56.0 54.8 -1.2 -2.1% 
2028 454.3 454.0 -0.3 -0.1% 
SO2 ( thousand tons) 2030 333.5 333.5 0.0 0.0% 
2035 239.9 239.9 0.0 0.0% 
Ozone-season NOx 2028 189.0 188.8 -0.165 -0.09% 
2030 174.9 175.4 0.488 0.28% (thousand tons) 2035 116.9 119.1 2.282 1.95% 
Annual NOx (thousand 2028 460.5 460.3 -0.283 -0.06% 
2030 392.8 392.7 -0.022 -0.01% tons) 2035 253.4 253.5 0.066 0.03% 
2028 2.5 2.5 0.0 0.0% 
HCl (thousand tons) 2030 2.2 2.2 0.0 0.0% 
2035 1.5 1.5 0.0 0.1% 
CO2 (million metric 2028 1,158.8 1,158.7 -0.1 0.0% 
2030 1,098.3 1,098.3 0.0 0.0% tons) 2035 724.2 724.1 -0.1 0.0% 
a This analysis is limited to the geographically contiguous lower 48 states. 38555 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
89Note that modeled projections include total 
PM 10and total PM 2.5.The EPA estimated non-Hg 
HAP metals reductions by multiplying the ratio of 
non-Hg HAP metals to fPM by modeled projections 
of total PM 10reductions under the rule. The ratios 
of non-Hg HAP metals to fPM were based on analysis of 2010 MATS Information Collection Request (ICR) data. As there may be substantially more fPM than PM
10reduced by the control 
techniques projected to be used under this rule, these estimates of non-Hg HAP metals reductions are likely underestimates. More detail on the 
estimated reduction in non-Hg HAP metals can be found in the docketed memorandum Estimating Non-Hg HAP Metals Reductions for the 2024 Technology Review for the Coal-Fired EGU Source Category. 
90Results using the 2 percent discount rate were 
not included in the proposal for this action. The 
2003 version of OMB’s Circular A–4 had generally recommended 3 percent and 7 percent as default rates to discount social costs and benefits. The analysis of the proposed rule used these two 
recommended rates. In November 2023, OMB finalized an update to Circular A–4, in which it recommended the general application of a 2 percent 
rate to discount social costs and benefits (subject to regular updates). The Circular A–4 update also recommended consideration of the shadow price of capital when costs or benefits are likely to accrue to capital. As a result of the update to Circular A– 4, we include cost and benefits results calculated using a 2 percent discount rate. chromium, cobalt, lead, manganese, 
nickel, and selenium.89 
Importantly, the continuous 
monitoring of fPM required in this rule will likely induce additional emissions reductions that we are unable to quantify. Continuous measurements of emissions accounts for changes to processes and fuels, fluctuations in load, operations of pollution controls, and equipment malfunctions. By measuring emissions across all operations, power plant operators and regulators can use the data to ensure controls are operating properly and to assess compliance with relevant standards. Because CEMS enable power plant operators to quickly identify and correct problems with pollution control devices, it is possible that fPM emissions could be lower than they otherwise would have been for up to 3 months—or up to 3 years if testing less 
frequently under the LEE program—at a time. This potential reduction in fPM 
and non-Hg HAP metals emission resulting from the information provided by continuous monitoring coupled with corrective actions by plant operators could be sizeable over the existing coal- fired fleet and is not quantified in this rulemaking. 
Section 3 of the RIA presents a 
detailed discussion of the emissions projections under the regulatory options as described in the RIA. Section 3 also describes the compliance actions that are projected to produce the emission reductions in table 8 of this preamble. Please see section IX.E. of this preamble and section 4 of the RIA for detailed discussions of the projected health, welfare, and climate benefits of these emission reductions. 
C. What are the cost impacts? 
The power industry’s compliance 
costs are represented in this analysis as 
the change in electric power generation costs between the baseline and policy 
scenarios. In other words, these costs are an estimate of the increased power industry expenditures required to implement the final requirements of this rule. The compliance cost estimates were mainly developed using the EPA’s Power Sector Modeling Platform 2023 using IPM. The incremental costs of the final rule’s PM CEMS requirement were estimated outside of IPM and added to the IPM-based cost estimate presented here and in section 3 of the RIA. 
We estimate the present value (PV) of 
the projected compliance costs over the 2028 to 2037 period, as well as estimate the equivalent annual value (EAV) of the flow of the compliance costs over this period. All dollars are in 2019 dollars. We estimate the PV and EAV using 2, 3, and 7 percent discount rates.
90Table 9 of this document 
presents the estimates of compliance 
costs for the final rule. 
The PV of the compliance costs for 
the final rule, discounted at the 2 
percent rate, is estimated to be about $860 million, with an EAV of about $96 million. At the 3 percent discount rate, the PV of the compliance costs of the final rule is estimated to be about $790 million, with an EAV of about $92 million. At the 7 percent discount rate, the PV of the compliance costs of the rule is estimated to be about $560 million, with an EAV of about $80 million. 
We note that IPM provides the EPA’s 
best estimate of the costs of the rules to the electricity sector and related energy 
sectors (i.e., natural gas, coal mining). 
These compliance cost estimates are used as a proxy for the social cost of the 
rule. For a detailed description of these compliance cost projections, please see section 3 of the RIA, which is available in the docket for this action. 
D. What are the economic impacts? 
The Agency estimates that this rule 
will require additional fPM and/or Hg 
removal at less than 15 GW of operable capacity in 2028, which is about 14 percent of the total coal-fired EGU capacity projected to operate in that year. The units requiring additional fPM and/or Hg removal are projected to generate less than 2 percent of total generation in 2028. Moreover, the EPA does not project that any EGUs will retire in response to the standards promulgated in this final rule. 
Consistent with the small share of 
EGUs required to reduce fPM and/or Hg emissions rates, this final action has limited energy market implications. There are limited impacts on energy prices projected to result from this final 
rule. On a national average basis, 
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Discounted to 2023t 
2% Discount Rate 3% Discount Rate 7% Discount Rate 
PV 860 790 560 
EAV 96 92 80 
a Values have been rounded to two significant figures. 38556 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
91Agency for Toxic Substances and Disease 
Registry (ATSDR). Toxicological Profile for 
Mercury. Public Health Service, U.S. Department of Health and Human Services, Atlanta, GA. 2022. 
92U.S. Environmental Protection Agency. 
Integrated Risk Information System (IRIS) on Methylmercury. National Center for Environmental Assessment, Office of Research and Development, Washington, DC. 2001. 
93U.S. Environmental Protection Agency. 
Integrated Risk Information System (IRIS) on Mercuric Chloride. National Center for Environmental Assessment, Office of Research and Development, Washington, DC. 1995. delivered coal, natural gas, and retail 
electricity prices are not projected to change. The EPA does not project incremental changes in existing operational capacity to occur in response to the final rule. Coal production for use in the power sector is not projected to change significantly by 2028. 
The short-term estimates for 
employment needed to design, construct, and install the control equipment in the 3-year period before the compliance date are also provided using an approach that estimates employment impacts for the environmental protection sector based on projected changes from IPM on the number and scale of pollution controls and labor intensities in relevant sectors. Finally, some of the other types of employment impacts that will be ongoing are estimated using IPM outputs and labor intensities, as reported in section 5 of the RIA. 
E. What are the benefits? 
The RIA for this action analyzes the 
benefits associated with the projected 
emission reductions under this rule. This final rule is projected to reduce emissions of Hg and non-Hg HAP metals, as well as PM
2.5, SO 2, NO Xand 
CO 2nationwide. The potential impacts 
of these emission reductions are discussed in detail in section 4 of the RIA. The EPA notes that the benefits analysis is distinct from the statutory determinations finalized herein, which are based on the statutory factors the EPA is required to consider under CAA section 112. The assessment of benefits described here and in the RIA is presented solely for the purposes of complying with Executive Order 12866, as amended by Executive Order 14094, and providing the public with a complete depiction of the impacts of the rulemaking. 
Hg is a persistent, bioaccumulative 
toxic metal emitted from power plants 
that exists in three forms: gaseous elemental Hg, inorganic Hg compounds, and organic Hg compounds (e.g., methylmercury). Hg can also be emitted in a particle-bound form. Elemental Hg can exist as a shiny silver liquid, but readily vaporizes into air. Airborne elemental Hg does not quickly deposit or chemically react in the atmosphere, resulting in residence times that are long enough to contribute to global scale deposition. Oxidized Hg and particle- bound Hg deposit quickly from the atmosphere impacting local and regional areas in proximity to sources. Methylmercury is formed by microbial action in the top layers of sediment and soils, after Hg has precipitated from the air and deposited into waterbodies or land. Once formed, methylmercury is taken up by aquatic organisms and bioaccumulates up the aquatic food web. Larger predatory fish may have methylmercury concentrations many times that of the concentrations in the freshwater body in which they live. 
All forms of Hg are toxic, and each 
form exhibits different health effects. Acute (short-term) exposure to high levels of elemental Hg vapors results in central nervous system (CNS) effects such as tremors, mood changes, and slowed sensory and motor nerve function. Chronic (long-term) exposure to elemental Hg in humans also affects the CNS, with effects such as erethism (increased excitability), irritability, excessive shyness, and tremors. The major effect from chronic ingestion or inhalation of low levels of inorganic Hg is kidney damage. 
Methylmercury is the most common 
organic Hg compound in the environment. Acute exposure of humans to very high levels of methylmercury results in profound CNS effects such as blindness and spastic quadriparesis. Chronic exposure to methylmercury, most commonly by consumption of fish from Hg contaminated waters, also affects the CNS with symptoms such as paresthesia (a sensation of pricking on the skin), blurred vision, malaise, speech difficulties, and constriction of the visual field. Ingestion of methylmercury can lead to significant developmental effects, such as IQ loss measured by performance on neurobehavioral tests, particularly on tests of attention, fine motor-function, language, and visual spatial ability. In addition, evidence in humans and animals suggests that methylmercury can have adverse effects on both the developing and the adult cardiovascular system, including fatal and non-fatal ischemic heart disease (IHD). Further, nephrotoxicity, immunotoxicity, reproductive effects (impaired fertility), and developmental effects have been observed with methylmercury exposure in animal studies.
91Methylmercury has some 
genotoxic activity and can cause chromosomal damage in several experimental systems. The EPA has concluded that mercuric chloride and methylmercury are possibly carcinogenic to humans.
92 93 The projected emissions reductions of 
Hg are expected to lower deposition of 
Hg into ecosystems and reduce U.S. EGU attributable bioaccumulation of methylmercury in wildlife, particularly for areas closer to the effected units subject to near-field deposition. Subsistence fishing is associated with vulnerable populations. Methylmercury exposure to subsistence fishers from lignite-fired units is below the current RfD for methylmercury neurodevelopmental toxicity. The EPA considers exposures at or below the RfD for methylmercury unlikely to be associated with appreciable risk of deleterious effects across the population. However, the RfD for methylmercury does not represent an exposure level corresponding to zero risk; moreover, the RfD does not represent a bright line above which individuals are at risk of adverse effects. Reductions in Hg emissions from lignite-fired facilities should further reduce exposure to methylmercury for subsistence fisher sub-populations located in the vicinity of these facilities, which are all located in North Dakota, Texas, and Mississippi. 
In addition, U.S. EGUs are a major 
source of HAP metals emissions including selenium, arsenic, chromium, nickel, and cobalt, cadmium, beryllium, lead, and manganese. Some HAP metals emitted by U.S. EGUs are known to be persistent and bioaccumulative and others have the potential to cause cancer. Exposure to these HAP metals, depending on exposure duration and levels of exposures, is associated with a variety of adverse health effects. The emissions reductions projected under 
this final rule are expected to reduce human exposure to non-Hg HAP metals, including carcinogens. 
Furthermore, there is the potential for 
reductions in Hg and non-Hg HAP metal emissions to enhance ecosystem services and improve ecological outcomes. The reductions will potentially lead to positive economic impacts although it is difficult to estimate these benefits and, consequently, they have not been included in the set of quantified benefits. 
As explained in section IX.B., the 
continuous monitoring of fPM required in this rule may induce further reductions of fPM and non-Hg HAP metals than we project in the RIA for 
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94National Academies of Sciences, Engineering, 
and Medicine (National Academies). 2017. Valuing 
Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. National Academies Press. 
95Regulatory Impact Analysis of the Standards of 
Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, Docket ID No. EPA–HQ–OAR–2021–0317, 
December 2023. 
96Supplemental Notice of Proposed Rulemaking 
for Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, 87 FR 74702 (December 6, 2022). 
97https://www.epa.gov/environmental-
economics/scghg-tsd-peer-review. 
98Note that the RIA for the proposal of this 
rulemaking used the SC–CO 2estimates from the 
Interagency Working Group’s (IWG) February 2021 Social Cost of Greenhouse Gases Technical Support Document (TSD) (IWG 2021) to estimate climate benefits. These SC–CO
2estimates were interim 
values recommended for use in benefit-cost analyses until updated estimates of the impacts of climate change could be developed. Estimated 
climate benefits using these interim SC–CO 2values 
(IWG 2021) are presented in Appendix B of the RIA for this final rulemaking for comparison purposes. 
99Supplementary Material for the Regulatory 
Impact Analysis for the Final Rulemaking, ‘‘Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review,’’ EPA Report on the Social Cost of 
Greenhouse Gases: Estimates Incorporating Recent Scientific Advances, Docket ID No. EPA–HQ–OAR– 2021–0317, November 2023. this action. As a result, there may be 
additional unquantified beneficial health impacts from these potential reductions. The continuous monitoring of fPM required in this rule is also likely to provide several additional benefits to the public which are not quantified in this rule, including greater certainty, accuracy, transparency, and granularity in fPM emissions information than exists today. 
The rule is also expected to reduce 
emissions of direct PM
2.5, NO X, and SO 2 
nationally throughout the year. Because NO
Xand SO 2are also precursors to 
secondary formation of ambient PM 2.5, 
reducing these emissions would reduce human exposure to ambient PM
2.5 
throughout the year and would reduce the incidence of PM
2.5-attributable 
health effects. The rule is also expected to reduce ozone-season NO
Xemissions 
nationally in most years of analysis. In the presence of sunlight, NO
X, and 
volatile organic compounds (VOCs) can undergo a chemical reaction in the atmosphere to form ozone. Reducing NO
Xemissions in most locations 
reduces human exposure to ozone and reduces the incidence of ozone-related health effects, although the degree to which ozone is reduced will depend in 
part on local concentration levels of VOCs. 
The health effect endpoints, effect 
estimates, benefit unit values, and how they were selected, are described in the technical support document titled Estimating PM
2.5minus; and Ozone- 
Attributable Health Benefits (2023). This document describes our peer-reviewed approach for selecting and quantifying adverse effects attributable to air pollution, the demographic and health data used to perform these calculations, and our methodology for valuing these effects. 
Because of projected changes in 
dispatch under the final requirements, the rule is also projected to impact CO
2 
emissions. The EPA estimates the climate benefits of CO
2emission 
reductions expected from the final rule using estimates of the social cost of carbon (SC–CO
2) that reflect recent 
advances in the scientific literature on climate change and its economic 
impacts and that incorporate recommendations made by the National Academies of Science, Engineering, and Medicine.
94The EPA published and 
used these estimates in the RIA for the December 2023 Natural Gas Sector final rule titled Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review (2023 Oil and Natural Gas NSPS/EG).
95The EPA 
solicited public comment on the methodology and use of these estimates in the RIA for the Agency’s December 2022 Oil and Natural Gas Sector supplemental proposal
96that preceded 
the 2023 Oil and Natural Gas NSPS/EG 
and has conducted an external peer review of these estimates. The response to public comments document and the response to peer reviewer recommendations can be found in the docket for the 2023 Oil and Natural Gas NSPS/EG action. Complete information about the peer review process is also available on the EPA’s website.
97 
Section 4.4 within the RIA for this 
final rulemaking provides an overview of the methodological updates incorporated into the SC–CO
2estimates 
used in this final RIA.98A more detailed explanation of each input and the modeling process is provided in the final technical report, EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances.
99 
The SC–CO 2is the monetary value of 
the net harm to society associated with a marginal increase in CO
2emissions in 
a given year, or the benefit of avoiding that increase. In principle, SC–CO
2 
includes the value of all climate change impacts both negative and positive, including, but not limited to, changes in net agricultural productivity, human health effects, property damage from increased flood risk and natural disasters, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services. The SC–CO
2, therefore, reflects 
the societal value of reducing emissions of CO
2by one metric ton and is the 
theoretically appropriate value to use in conducting benefit-cost analyses of policies that affect CO
2emissions. In 
practice, data and modeling limitations restrain the ability of SC–CO
2estimates 
to include all physical, ecological, and economic impacts of climate change, implicitly assigning a value of zero to the omitted climate damages. The estimates are, therefore, a partial accounting of climate change impacts and likely underestimate the marginal benefits of abatement. 
Table 10 of this document presents 
the estimated PV and EAV of the projected health and climate benefits across the regulatory options examined in the RIA in 2019 dollars discounted to 2023. 
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100Monetized climate benefits are discounted 
using a 2 percent discount rate, consistent with the 
EPA’s updated estimates of the SC–CO 2. The 2003 
version of OMB’s Circular A–4 had generally recommended 3 percent and 7 percent as default discount rates for costs and benefits, though as part of the Interagency Working Group on the Social Cost of Greenhouse Gases, OMB had also long recognized that climate effects should be discounted only at appropriate consumption-based discount rates. In November 2023, OMB finalized an update to Circular A–4, in which it 
recommended the general application of a 2 percent discount rate to costs and benefits (subject to 
regular updates), as well as the consideration of the shadow price of capital when costs or benefits are likely to accrue to capital (OMB 2023). Because the SC–CO
2estimates reflect net climate change 
damages in terms of reduced consumption (or monetary consumption equivalents), the use of the social rate of return on capital (7 percent under 
BILLING CODE 6560–50–C 
This final rule is projected to reduce 
PM 2.5and ozone concentrations, 
producing a projected PV of monetized 
health benefits of about $300 million, with an EAV of about $33 million discounted at 2 percent. The projected PV of monetized climate benefits of the final rule is estimated to be about $130 million, with an EAV of about $14 million using the SC–CO
2discounted at 2 percent.100Thus, this final rule would 
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ER07MY24.076</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 10. Projected Benefits of the Final Rule, 2028 through 2037 (Millions 2019$, 
Discounted to 2023)a 
Present Value (PV) 
2% Discount Rate 3% Discount Rate 7% Discount Rate 
Health Benefitsc 300 260 180 
Climate Benefitsd 130 130 130 
Total Monetized 420 390 300 Benefitse 
Equivalent Annual Value (EA v? 
2% Discount Rate 3% Discount Rate 7% Discount Rate 
Health Benefitsc 33 31 25 
Climate Benefitsd 14 14 14 
Total Monetized 47 45 39 Benefits e 
Benefits from reductions of about 900 to 1000 pounds of Hg 
annually 
Benefits from reductions of at least 4 to 7 tons of non-Hg HAP 
Non-Monetized metals annually 
Benefits Benefits from improved water quality and availability 
Benefits from the increased transparency, compliance assurance, 
and accelerated identification of anomalous emission anticipated 
from requiring PM CEMS 
a Values have been rounded to two significant figures. Rows may not appear to sum correctly 
due to rounding. 
b The EAV of benefits are calculated over the 10-year period from 2028 to 2037. 
c The projected monetized air quality-related benefits include those related to public health 
associated with reductions in PM2.s and ozone concentrations. The projected health benefits are 
associated with several point estimates and are presented at real discount rates of 2, 3, and 7 
percent. 
d Monetized climate benefits are based on reductions in CO2 emissions and are calculated using 
three different estimates of the social cost of carbon dioxide (SC-CO2) (under 1.5 percent, 2.0 
percent, and 2.5 percent near-term Ramsey discount rates). For the presentational purposes of 
this table, we show the climate benefits associated with the SC-CO2 at the 2 percent near-term 
Ramsey discount rate. Please see section 4 of the RIA for the full range of monetized climate 
benefit estimates. 
e The list of non-monetized benefits does not include all potential non-monetized benefits. See 
table 4-8 of the RIA for a more complete list. 38559 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
OMB Circular A–4 (2003)) to discount damages 
estimated in terms of reduced consumption would inappropriately underestimate the impacts of climate change for the purposes of estimating the SC–CO
2. See Section 4.4 of the RIA for more 
discussion. 101See https://www.epa.gov/environmental
justice/technical-guidance-assessing- environmental-justice-regulatory-analysis. 102The baseline for proximity analyses is current 
population information, whereas the baseline for 
ozone exposure analyses are the future years in which the regulatory options will be implemented (e.g., 2023 and 2026). generate a PV of monetized benefits of 
$420 million, with an EAV of $47 million discounted at a 2 percent rate. 
At a 3 percent discount rate, this final 
rule is expected to generate projected PV of monetized health benefits of $260 million, with an EAV of about $31 million discounted at 3 percent. Climate benefits remain discounted at 2 percent in this benefits analysis and are estimated to be about $130 million, with an EAV of about $14 million using the SC–CO
2. Thus, this final rule would 
generate a PV of monetized benefits of $390 million, with an EAV of $45 million discounted at a 3 percent rate. 
At a 7 percent discount rate, this final 
rule is expected to generate projected PV of monetized health benefits of $180 million, with an EAV of about $25 million discounted at 7 percent. Climate benefits remain discounted at 2 percent in this benefits analysis and are estimated to be about $130 million, with an EAV of about $14 million using the SC–CO
2. Thus, this final rule would 
generate a PV of monetized benefits of $300 million, with an EAV of $39 million discounted at a 7 percent rate. 
The benefits from reducing Hg and 
non-Hg HAP metals and from unquantified improvements in water quality were not monetized and are therefore not directly reflected in the monetized benefit-cost estimates 
associated with this rulemaking. Potential benefits from the increased transparency and accelerated identification of anomalous emission anticipated from requiring PM CEMS were also not monetized in this analysis and are therefore also not directly reflected in the monetized benefit-cost comparisons. We nonetheless consider these impacts in our evaluation of the net benefits of the rule and find that, if we were able to monetize these beneficial impacts, the final rule would have greater net benefits than shown in table 11 of this document. 
F. What analysis of environmental 
justice did we conduct? 
For purposes of analyzing regulatory 
impacts, the EPA relies upon its June 2016 ‘‘Technical Guidance for Assessing Environmental Justice in Regulatory Analysis,’’ which provides recommendations that encourage analysts to conduct the highest quality analysis feasible, recognizing that data limitations, time, resource constraints, and analytical challenges will vary by media and circumstance. The Technical 
Guidance states that a regulatory action may involve potential EJ concerns if it could: (1) create new disproportionate impacts on communities with EJ concerns; (2) exacerbate existing disproportionate impacts on communities with EJ concerns; or (3) present opportunities to address existing disproportionate impacts on communities with EJ concerns through this action under development. 
The EPA’s EJ technical guidance 
states that ‘‘[t]he analysis of potential EJ 
concerns for regulatory actions should address three questions: (A) Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern in the baseline? (B) Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern for the regulatory option(s) under consideration? (C) For the regulatory option(s) under consideration, are potential EJ concerns created or mitigated compared to the baseline?’’
101 
The environmental justice analysis is 
presented for the purpose of providing the public with as full as possible an understanding of the potential impacts of this final action. The EPA notes that analysis of such impacts is distinct from the determinations finalized in this action under CAA section 112, which are based solely on the statutory factors the EPA is required to consider under that section. To address these questions in the EPA’s first quantitative EJ analysis in the context of a MATS rule, the EPA developed a unique analytical approach that considers the purpose and specifics of this rulemaking, as well as the nature of known and potential disproportionate and adverse exposures and impacts. However, due to data limitations, it is possible that our analysis failed to identify disparities that may exist, such as potential EJ characteristics (e.g., residence of 
historically red-lined areas), environmental impacts (e.g., other 
ozone metrics), and more granular spatial resolutions (e.g., neighborhood 
scale) that were not evaluated. Also due to data and resource limitations, we discuss HAP and climate EJ impacts of this action qualitatively (section 6 of the RIA). 
For this rule, we employ two types of 
analysis to respond to the previous three questions: proximity analyses and exposure analyses. Both types of analysis can inform whether there are 
potential EJ concerns in the baseline (question 1).
102In contrast, only the 
exposure analyses, which are based on future air quality modeling, can inform whether there will be potential EJ concerns after implementation of the regulatory options under consideration (question 2) and whether potential EJ concerns will be created or mitigated compared to the baseline (question 3). While the exposure analysis can respond to all three questions, several caveats should be noted. For example, the air pollutant exposure metrics are limited to those used in the benefits assessment. For ozone, that is the maximum daily 8-hour average, averaged across the April through September warm season (AS–MO3) and for PM
2.5that is the annual average. This 
ozone metric likely smooths potential daily ozone gradients and is not directly relatable to the National Ambient Air Quality Standards (NAAQS), whereas the PM
2.5metric is more similar to the 
long-term PM 2.5standard. The air 
quality modeling estimates are also based on state and fuel level emission data paired with facility-level baseline emissions and provided at a resolution of 12 square kilometers. Additionally, here we focus on air quality changes due to this rulemaking and infer post- policy ozone and PM
2.5exposure 
burden impacts. Note, we discuss HAP and climate EJ impacts of this action qualitatively (section 6 of the RIA). 
Exposure analysis results are 
provided in two formats: aggregated and distributional. The aggregated results provide an overview of potential ozone exposure differences across populations at the national- and state-levels, while the distributional results show detailed information about ozone concentration changes experienced by everyone within each population. 
In section 6 of the RIA, we utilize the 
two types of analysis to address the three EJ questions by quantitatively evaluating: (1) the proximity of affected facilities to various local populations with potential EJ concerns (section 6.4); and (2) the potential for disproportionate ozone and PM
2.5 
concentrations in the baseline and concentration changes after rule implementation across different demographic groups on the basis of race, ethnicity, poverty status, employment status, health insurance status, life expectancy, redlining, Tribal land, age, sex, educational attainment, 
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103Please note that results for ozone and PM 2.5 
exposures should not be extrapolated to other air 
pollutants that were not included in the assessment, including HAP. Detailed EJ analytical results can be found in section 6 of the RIA. and degree of linguistic isolation 
(section 6.5). It is important to note that due to the small magnitude of underlying emissions changes, and the corresponding small magnitude of the ozone and PM
2.5concentration changes, 
the rule is expected to have only a small impact on the distribution of exposures across each demographic group. Each of these analyses should be considered independently of each other, as each was performed to answer separate questions, and is associated with unique limitations and uncertainties. 
Baseline demographic proximity 
analyses can be relevant for identifying populations that may be exposed to local environmental stressors, such as local NO
2and SO 2emitted from affected 
sources in this final rule, traffic, or noise. The baseline analysis indicates that on average the populations living within 10 kilometers of coal plants potentially impacted by the amended fPM standards have a higher percentage of people living below two times the poverty level than the national average. In addition, on average the percentage of the American Indian population living within 10 kilometers of lignite plants potentially impacted by the amended Hg standard is higher than the national average. Assessing these results, we conclude that there may be potential EJ concerns associated with directly emitted pollutants that are affected by the regulatory action (e.g., SO
2) for 
various population groups in the baseline (question 1). However, as proximity to affected facilities does not capture variation in baseline exposure across communities, nor does it indicate that any exposures or impacts will occur, these results should not be interpreted as a direct measure of exposure or impact. 
As HAP exposure results generated as 
part of the 2020 Residual Risk Review were below both the presumptive acceptable cancer risk threshold and noncancer health benchmarks and this regulation should further reduce exposure to HAP, there are no ‘‘disproportionate and adverse effects’’ of potential EJ concern. Therefore, we did not perform a quantitative EJ assessment of HAP risk. However, the potential reduction in non-Hg HAP metal emissions would likely reduce 
exposures to people living nearby coal plants potentially impacted by the amended fPM standards. 
This rule is also expected to reduce 
emissions of direct PM
2.5, NO X, and SO 2 
nationally throughout the year. Because NO
Xand SO 2are also precursors to 
secondary formation of ambient PM 2.5 
and because NO Xis a precursor to ozone 
formation, reducing these emissions would impact human exposure. 
Quantitative ozone and PM 2.5exposure 
analyses can provide insight into all three EJ questions, so they are performed to evaluate potential disproportionate impacts of this rulemaking. Even though both the proximity and exposure analyses can potentially improve understanding of baseline EJ concerns (question 1), the two should not be directly compared. This is because the demographic proximity analysis does not include air quality information and is based on current, not future, population information. 
The baseline analysis of ozone and 
PM
2.5concentration burden responds to 
question 1 from the EPA’s EJ technical guidance more directly than the proximity analyses, as it evaluates a form of the environmental stressor targeted by the regulatory action. Baseline PM
2.5and ozone exposure 
analyses show that certain populations, such as residents of redlined census tracts, those linguistically isolated, Hispanic, Asian, those without a high school diploma, and the unemployed may experience higher ozone and PM
2.5 
exposures as compared to the national average. American Indian, residents of Tribal Lands, populations with higher life expectancy or with life expectancy data unavailable, children, and insured populations may also experience disproportionately higher ozone concentrations than the reference group. Hispanic, Black, below the poverty line, and uninsured populations may also experience disproportionately higher PM
2.5concentrations than the reference 
group. Therefore, also in response to question 1, there likely are potential EJ concerns associated with ozone and PM
2.5exposures affected by the 
regulatory action for population groups of concern in the baseline. However, these baseline exposure results have not been fully explored and additional analyses are likely needed to understand potential implications. Due to the small magnitude of the exposure changes across population demographics associated with the rulemaking relative to the magnitude of the baseline disparities, we infer that post-policy EJ ozone and PM
2.5 
concentration burdens are likely to remain after implementation of the regulatory action or alternative under consideration (question 2). 
Question 3 asks whether potential EJ 
concerns will be created or mitigated as compared to the baseline. Due to the very small magnitude of differences across demographic population post- 
policy ozone and PM
2.5exposure 
impacts, we do not find evidence that potential EJ concerns related to ozone 
and PM 2.5concentrations will be created 
or mitigated as compared to the baseline.
103 
X. Statutory and Executive Order Reviews 
Additional information about these 
statutes and Executive Orders can be found at https://www.epa.gov/laws- regulations/laws-and-executive-orders. 
A. Executive Order 12866: Regulatory 
Planning and Review and Executive Order 14094: Modernizing Regulatory Review 
This action is a ‘‘significant regulatory 
action,’’ as defined under section 3(f)(1) of Executive Order 12866, as amended by Executive Order 14094. Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for Executive Order 12866 review. Documentation of any changes made in response to the Executive Order 12866 review is available in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, Regulatory Impact Analysis for the Final 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–24–005), is briefly summarized in section IX. of this preamble and here. This analysis is also available in the docket. 
Table 11 of this document presents 
the estimated PV and EAV of the monetizable projected health benefits, climate benefits, compliance costs, and net benefits of the final rule in 2019 dollars discounted to 2023. The estimated monetized net benefits are the projected monetized benefits minus the 
projected monetized costs of the final rule. 
Under Executive Order 12866, the 
EPA is directed to consider all of the costs and benefits of its actions, not just those that stem from the regulated pollutant. Accordingly, the projected monetized benefits of the final rule include health benefits associated with projected reductions in PM
2.5and ozone 
concentration. The projected monetized benefits also include climate benefits due to reductions in CO
2emissions. The 
projected health benefits are associated with several point estimates and are presented at real discount rates of 2, 3, and 7 percent. The projected climate 
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benefits in this table are based on 
estimates of the SC–CO 2at a 2 percent 
near-term Ramsey discount rate and are discounted using a 2 percent discount rate to obtain the PV and EAV estimates in the table. The power industry’s compliance costs are represented in this analysis as the change in electric power generation costs between the baseline and policy scenarios. In simple terms, these costs are an estimate of the increased power industry expenditures required to implement the finalized 
requirements and represent the EPA’s best estimate of the social cost of the final rulemaking. 
BILLING CODE 6560–50–P 
BILLING CODE 6560–50–C 
As shown in table 11 of this 
document, this rule is projected to 
reduce PM 2.5and ozone concentrations, producing a projected PV of monetized 
health benefits of about $300 million, with an EAV of about $33 million discounted at 2 percent. The rule is also projected to reduce greenhouse gas emissions in the form of CO
2, producing 
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ER07MY24.077</GPH>khammond on DSKJM1Z7X2PROD with RULES4Table 11. Projected Monetized Benefits, Compliance Costs, and Net Benefits of the Final 
Rule, 2028 through 2037 (Millions 2019$, Discounted to 2023Y 
Present Value (PV) 
2% Discount Rate 3 % Discount Rate 7% Discount Rate 
Health Benefitsc 300 260 180 
Climate Benefitsd 130 130 130 
Compliance Costs 860 790 560 
Net Benefits -440 -400 -260 
Equal Annualized Value (EA v? 
2% Discount Rate 3 % Discount Rate 7% Discount Rate 
Health Benefitsc 33 31 25 
Climate Benefitsd 14 14 14 
Compliance Costs 96 92 80 
Net Benefits -49 -47 -41 
Benefits from reductions of about 900 to 1000 pounds of Hg annually 
Benefits from reductions of at least 4 to 7 tons of non-Hg HAP metals 
annually 
Non-Monetized Benefitse Benefits from improved water quality and availability 
Benefits from the increased transparency, compliance assurance, and 
accelerated identification of anomalous emission anticipated from 
requiring PM CEMS 
a Values have been rounded to two significant figures. Rows may not appear to sum correctly 
due to rounding. 
b The EAV of costs and benefits are calculated over the 10-year period from 2028 to 2037. 
c The projected monetized air quality related benefits include those related to public health 
associated with reductions in PM2.s and ozone concentrations. The projected health benefits are 
associated with several point estimates and are presented at real discount rates of 2, 3, and 7 
percent. 
d Monetized climate benefits are based on reductions in CO2 emissions and are calculated using 
three different estimates of the SC-CO2 (under 1.5 percent, 2.0 percent, and 2.5 percent near­
term Ramsey discount rates). For the presentational purposes of this table, we show the climate 
benefits associated with the SC-CO2 at the 2 percent near-term Ramsey discount rate. Please see 
section 4 of the RIA for the full range of monetized climate benefit estimates. 
e The list of non-monetized benefits does not include all potential non-monetized benefits. See 
table 4-8 of the RIA for a more complete list. 38562 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
104Each facility is a respondent and some 
facilities have multiple EGUs. a projected PV of monetized climate 
benefits of about $130 million, with an EAV of about $14 million using the SC– CO
2discounted at 2 percent. Thus, this 
final rule would generate a PV of monetized benefits of $420 million, with an EAV of $47 million discounted at a 2 percent rate. The PV of the projected compliance costs are $860 million, with an EAV of about $96 million discounted at 2 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of ¥$440 million and EAV of ¥$49 million. 
At a 3 percent discount rate, this rule 
is expected to generate projected PV of monetized health benefits of $260 million, with an EAV of about $31 million. Climate benefits remain discounted at 2 percent in this net benefits analysis. Thus, this final rule would generate a PV of monetized benefits of $390 million, with an EAV of $45 million discounted at a 3 percent rate. The PV of the projected compliance costs are $790 million, with an EAV of $92 million discounted at 3 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of ¥$400 million and an EAV of ¥$47 million. 
At a 7 percent discount rate, this rule 
is expected to generate projected PV of monetized health benefits of $160 million, with an EAV of about $23 million. Climate benefits remain discounted at 2 percent in this net benefits analysis. Thus, this final rule would generate a PV of monetized benefits of $300 million, with an EAV of $39 million discounted at a 3 percent rate. The PV of the projected compliance costs are $560 million, with an EAV of $80 million discounted at 7 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of ¥$260 million and an EAV of ¥$41 million. 
The potential benefits from reducing 
Hg and non-Hg HAP metals and potential improvements in water quality and availability were not monetized and are therefore not directly reflected in the monetized benefit-cost estimates associated with this final rule. Potential benefits from the increased transparency and accelerated identification of 
anomalous emission anticipated from requiring CEMS were also not monetized in this analysis and are therefore also not directly reflected in the monetized benefit-cost comparisons. We nonetheless consider these impacts in our evaluation of the net benefits of the rule and find, if we were able to quantify and monetize these beneficial impacts, the final rule would have greater net benefits than shown in table 11 of this preamble. 
B. Paperwork Reduction Act (PRA) 
The information collection activities 
in this rule have been submitted for 
approval to the OMB under the PRA. The ICR document that the EPA prepared has been assigned EPA ICR number 2137–12. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them. OMB has previously approved the information collection activities contained in the existing regulations and has assigned OMB control number 2060–0567. 
The information collection activities 
in this rule include continuous emission monitoring, performance testing, notifications and periodic reports, recording information, monitoring and the maintenance of records. The information generated by these activities will be used by the EPA to ensure that affected facilities comply with the emission limits and other requirements. Records and reports are necessary to enable delegated authorities to identify affected facilities that may not be in compliance with the requirements. Based on reported information, delegated authorities will decide which units and what records or processes should be inspected. The recordkeeping requirements require only the specific information needed to determine compliance. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). The burden and cost estimates below represent the total burden and cost for the information collection requirements of the NESHAP for Coal- and Oil-Fired EGUs, not just the burden associated with the amendments in this final rule. The incremental cost associated with these amendments is $2.4 million per year. 
Respondents/affected entities: The 
respondents are owners or operators of coal- and oil-fired EGUs. The North American Industry Classification System (NAICS) codes for the coal- and oil-fired EGU industry are 221112, 221122, and 921150. 
Respondent’s obligation to respond: 
Mandatory per 42 U.S.C. 7414 et seq. 
Estimated number of respondents: 
192 per year.
104 
Frequency of response: The frequency 
of responses varies depending on the burden item. Responses include daily calibrations, monthly recordkeeping activities, semiannual compliance reports, and annual reports. 
Total estimated burden: 447,000 
hours (per year). Burden is defined at 5 CFR part 1320.3(b). 
Total estimated cost: $106,600,000 
(per year), includes $53,100,000 in annual labor costs and $53,400,000 annualized capital and operation and maintenance costs. 
An agency may not conduct or 
sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical 
amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule. 
C. Regulatory Flexibility Act (RFA) 
The EPA certifies that this action will 
not have a significant economic impact 
on a substantial number of small entities under the RFA. In the 2028 analysis year, the EPA identified 24 potentially affected small entities operating 45 units at 26 facilities, and of these 24, only one small entity may experience compliance cost increases greater than one percent of revenue under the final rule. Details of this analysis are presented in section 5 of the RIA, which is in the public docket. 
D. Unfunded Mandates Reform Act 
(UMRA) 
This action does not contain an 
unfunded mandate of $100 million or more (adjusted for inflation) as described in UMRA, 2 U.S.C. 1531– 1538, and does not significantly or uniquely affect small governments. The costs involved in this action are estimated not to exceed $100 million or more (adjusted for inflation) in any one year. 
E. Executive Order 13132: Federalism 
This action does not have federalism 
implications. It will not have substantial 
direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. 
F. Executive Order 13175: Consultation 
and Coordination With Indian Tribal Governments 
This action does not have tribal 
implications as specified in Executive 
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Order 13175. The Executive order 
defines tribal implications as ‘‘actions that have substantial direct effects on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes.’’ The amendments in this action would not have a substantial direct effect on one or more tribes, change the relationship between the Federal Government and tribes, or affect the distribution of power and responsibilities between the Federal Government and Indian tribes. Thus, Executive Order 13175 does not apply to this action. 
Although this action does not have 
tribal implications as specified in Executive Order 13175, the EPA consulted with tribal officials during the development of this action. On September 1, 2022, the EPA sent a letter to all federally recognized Indian tribes initiating consultation to obtain input on this action. The EPA did not receive any requests for consultation from Indian tribes. The EPA also participated in the September 2022 National Tribal Air Association EPA Air Policy Update Call to solicit input on this action. 
G. Executive Order 13045: Protection of 
Children From Environmental Health Risks and Safety Risks 
Executive Order 13045 directs Federal 
agencies to include an evaluation of the health and safety effects of the planned regulation on children in federal health and safety standards and explain why the regulation is preferable to potentially effective and reasonably feasible alternatives. This action is subject to Executive Order 13045 because it is a significant regulatory action under section 3(f)(1) of Executive Order 12866. Accordingly, we have evaluated the potential for environmental health or safety effects from exposure to HAP, ozone, and PM
2.5 
on children. The EPA believes that, even though the 2020 residual risk assessment showed all modeled exposures to HAP to be below thresholds for public health concern, the rule should reduce HAP exposure by reducing emissions of Hg and non-Hg HAP with the potential to reduce HAP exposure to vulnerable populations, including children. The action described in this rule is also expected to lower ozone and PM
2.5in many areas, 
including those areas that struggle to attain or maintain the NAAQS, and thus mitigate some pre-existing health risks across all populations evaluated, including children. The results of this evaluation are contained in the RIA and are available in the docket for this action. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use 
This action is not a ‘‘significant 
energy action’’ because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. For 2028, the compliance year for the standards, the EPA does not project a significant change in retail electricity prices on average across the contiguous U.S., coal-fired electricity generation, natural gas-fired electricity generation, or utility power sector delivered natural gas prices. Details of the projected energy effects are presented in section 3 of the RIA, which is in the public docket. 
I. National Technology Transfer and 
Advancement Act (NTTAA) and 1 CFR Part 51 
The following standards appear in the 
amendatory text of this document and were previously approved for the locations in which they appear: ANSI/ ASME PTC 19.10–1981, ASTM D6348– 03(R2010), and ASTM D6784–16. 
J. Executive Order 12898: Federal 
Actions To Address Environmental Justice in Minority Populations and Low-Income Populations and Executive Order 14096: Revitalizing Our Nation’s Commitment to Environmental Justice for All 
The EPA believes that the human 
health or environmental conditions that exist prior to this action result in or have the potential to result in disproportionate and adverse human health or environmental effects on communities with environmental justice concerns. For this rule, we employ the proximity demographic analysis and the PM
2.5and ozone exposure analyses to 
evaluate disproportionate and adverse human health and environmental effects on communities with EJ concerns that exist prior to the action. The proximity demographic analysis indicates that on average the population living within 10 kilometers of coal plants potentially impacted by the fPM standards have a higher percentage of people living below two times the poverty level than the national average. In addition, on average the percentage of the American Indian population living within 10 kilometers of lignite-fired plants potentially impacted by the Hg standard is higher than the national average. Baseline PM
2.5and ozone and exposure 
analyses show that certain populations, such as residents of redlined census tracts, those linguistically isolated, Hispanic, Asian, those without a high school diploma, and the unemployed 
may experience disproportionately higher ozone and PM
2.5exposures as 
compared to the national average. American Indian, residents of Tribal Lands, populations with higher life expectancy or with life expectancy data unavailable, children, and insured populations may also experience disproportionately higher ozone concentrations than the reference group. Hispanics, Blacks, those below the poverty line, and uninsured populations may also experience disproportionately higher PM
2.5concentrations than the 
reference group. 
The EPA believes that this action is 
not likely to change existing disproportionate and adverse effects on communities with environmental justice concerns. Only the exposure analyses, which are based on future air quality modeling, can inform whether there will be potential EJ concerns after implementation of the final rule, and whether potential EJ concerns will be 
created or mitigated. We infer that baseline disparities in ozone and PM
2.5 
concentration burdens are likely to remain after implementation of the final regulatory option due to the small magnitude of the exposure changes across population demographics associated with the rulemaking relative to the baseline disparities. We also do not find evidence that potential EJ concerns related to ozone or PM
2.5 
exposures will be exacerbated or mitigated in the final regulatory option, compared to the baseline due to the very small differences in the magnitude of post-policy ozone and PM
2.5exposure 
impacts across demographic populations. Additionally, the potential reduction in Hg and non-Hg HAP metal emissions would likely reduce exposures to people living nearby coal plants potentially impacted by the amended fPM standards. 
The information supporting this 
Executive Order review is contained in section IX.F. of this preamble and in section 6, Environmental Justice Impacts of the RIA, which is in the public docket (EPA–HQ–OAR–2018– 0794). 
K. Congressional Review Act (CRA) 
This action is subject to the CRA, and 
the EPA will submit a rule report to 
each House of the Congress and to the Comptroller General of the United States. This action meets the criteria set forth in 5 U.S.C. 804(2). 
List of Subjects in 40 CFR Part 63 
Environmental protection, 
Administrative practice and procedures, 
Air pollution control, Hazardous 
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substances, Incorporation by reference, 
Intergovernmental relations, Reporting and recordkeeping requirements. 
Michael S. Regan, 
Administrator. 
For the reasons set forth in the 
preamble, 40 CFR part 63 is amended as 
follows: 
PART 63—NATIONAL EMISSION 
STANDARDS FOR HAZARDOUS AIR POLLUTANTS FOR SOURCE CATEGORIES 
■1. The authority citation for part 63 
continues to read as follows: 
Authority: 42 U.S.C. 7401 et seq. 
Subpart A—General Provisions 
■2. In § 63.14, paragraph (f)(1) is 
amended by removing the text ‘‘tables 4 and 5 to subpart UUUUU’’ and adding, in its place, the text ‘‘table 5 to subpart UUUUU’’. 
Subpart UUUUU—National Emission 
Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units 
■3. Section 63.9991 is amended by 
revising paragraph (a)(2) to read as follows: 
§ 63.9991 What emission limitations, work 
practice standards, and operating limits must I meet? 
(a) * * * 
(2) Before July 6, 2027, you must meet 
each operating limit in Table 4 to this 
subpart that applies to your EGU. 
* * * * * 
■4. Amend § 63.10000 by: 
■a. Revising paragraph (c)(1)(i) and 
paragraph (c)(1)(i)(A); 
■b. Redesignating paragraph (c)(1)(i)(C) 
as paragraph (c)(1)(i)(D); 
■c. Adding new paragraph (c)(1)(i)(C); 
■d. Revising paragraph (c)(1)(iv); 
■e. Adding new paragraphs (c)(1)(iv)(A) 
through (C); 
■f. Revising paragraphs (c)(2)(i) and (ii); 
■g. Revising paragraph (d)(5)(i); and 
■h. Revising paragraph (m) 
introductory text. 
The revisions and additions read as 
follows: 
§ 63.10000 What are my general 
requirements for complying with this subpart? 
* * * * * 
(c) * * * 
(1) * * * (i) For a coal-fired or solid oil-derived 
fuel-fired EGU or IGCC EGU, you may 
conduct initial performance testing in accordance with § 63.10005(h), to determine whether the EGU qualifies as a low emitting EGU (LEE) for one or more applicable emission limits, except as otherwise provided in paragraphs (c)(1)(i)(A) through (C) of this section: 
(A) Except as provided in paragraph 
(c)(1)(i)(D) of this section, you may not pursue the LEE option if your coal-fired, IGCC, or solid oil-derived fuel-fired EGU is equipped with a main stack and a bypass stack or bypass duct configuration that allows the effluent to bypass any pollutant control device. 
* * * * * 
(C) On or after July 6, 2027, you may 
not pursue the LEE option for filterable 
PM, total non-Hg HAP metals, or individual non-Hg HAP metals for coal- fired and solid oil-derived fuel-fired EGUs. 
* * * * * 
(iv)(A) Before July 6, 2027, if your 
coal-fired or solid oil derived fuel-fired 
EGU does not qualify as a LEE for total non-mercury HAP metals, individual non-mercury HAP metals, or filterable particulate matter (PM), you must demonstrate compliance through an initial performance test and you must monitor continuous performance through either use of a particulate matter continuous parametric monitoring system (PM CPMS), a PM CEMS, or, for an existing EGU, compliance performance testing repeated quarterly. 
(B) On and after July 6, 2027, you may 
not pursue or continue to use the LEE option for your coal-fired or solid oil derived fuel-fired EGU for filterable PM or for non-mercury HAP metals. You must demonstrate compliance through an initial performance test, and you must monitor continuous performance with the applicable filterable PM emissions limit through the use of a PM CEMS or HAP metals CMS. 
(C) If your IGCC EGU does not qualify 
as a LEE for total non-mercury HAP metals, individual non-mercury HAP metals, or filterable PM, you must demonstrate compliance through an initial performance test and you must monitor continuous performance through either use of a PM CPMS, a PM CEMS, or, for an existing EGU, compliance performance testing repeated quarterly. 
* * * * * 
(2) * * * 
(i) For an existing liquid oil-fired unit, 
you may conduct the performance 
testing in accordance with § 63.10005(h), to determine whether the unit qualifies as a LEE for one or more pollutants. For a qualifying LEE for Hg emissions limits, you must conduct a 30-day performance test using Method 30B at least once every 12 calendar months to demonstrate continued LEE status. For a qualifying LEE of any other applicable emissions limits, you must conduct a performance test at least once every 36 calendar months to demonstrate continued LEE status. On or after July 6, 2027, you may not pursue the LEE option for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals. 
(ii) Before July 6, 2027, if your liquid 
oil-fired unit does not qualify as a LEE for total HAP metals (including mercury), individual metals (including mercury), or filterable PM you must demonstrate compliance through an initial performance test and you must monitor continuous performance through either use of a PM CPMS, a PM CEMS, or, for an existing EGU, performance testing conducted quarterly. On and after July 6, 2027, you may not pursue or continue to use the LEE option for your liquid oil-fired EGU for filterable PM or for non-mercury HAP metals. You must demonstrate compliance through an initial performance test, and you must monitor continuous performance with the applicable filterable PM emissions limit through the use of a PM CEMS or HAP metals CMS. 
(d) * * * 
(5) * * * (i) Installation of the CMS or sorbent 
trap monitoring system sampling probe 
or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the 
last control device). See § 63.10010(a) for further details. For PM CPMS installations (which with the exception of IGCC units, are only applicable before July 6, 2027), follow the procedures in § 63.10010(h). 
* * * * * 
(m) Should you choose to rely on 
paragraph (2) of the definition of 
‘‘startup’’ in § 63.10042 for your EGU (only allowed before January 2, 2025), on or before the date your EGU is subject to this subpart, you must install, verify, operate, maintain, and quality assure each monitoring system necessary for demonstrating compliance with the work practice standards for PM or non-mercury HAP metals controls during startup periods and shutdown periods required to comply with § 63.10020(e). On and after January 2, 2025 you will no longer be able to choose paragraph (2) of the ‘‘startup’’ definition in § 63.10042. 
* * * * * 
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■5. Amend § 63.10005 by revising 
paragraphs (a)(1), (b) introductory text, 
(c), (d)(2) introductory text, (h) introductory text, and (h)(1) introductory text to read as follows: 
§ 63.10005 What are my initial compliance 
requirements and by what date must I conduct them? 
(a) * * * 
(1) To demonstrate initial compliance 
with an applicable emissions limit in 
Table 1 or 2 to this subpart using stack testing, the initial performance test generally consists of three runs at specified process operating conditions using approved methods. Before July 6, 2027, if you are required to establish operating limits (see paragraph (d) of this section and Table 4 to this subpart), you must collect all applicable parametric data during the performance test period. On and after July 6, 2027, the requirements in Table 4 are not applicable, with the exception of IGCC units. Also, if you choose to comply with an electrical output-based emission limit, you must collect hourly electrical load data during the test period. 
* * * * * 
(b) Performance testing requirements. 
If you choose to use performance testing 
to demonstrate initial compliance with the applicable emissions limits in Tables 1 and 2 to this subpart for your EGUs, you must conduct the tests according to 40 CFR 63.10007 and Table 5 to this subpart. Notwithstanding these requirements, when Table 5 specifies the use of isokinetic EPA test Method 5, 5I, 5D, 26A, or 29 for a stack test, if concurrent measurement of the stack gas flow rate or moisture content is needed to convert the pollutant concentrations to units of the standard, separate determination of these parameters using EPA test Method 2 or EPA test Method 4 is not necessary. Instead, the stack gas flow rate and moisture content can be 
determined from data that are collected during the EPA test Method 5, 5I, 5D, 6, 26A, or 29 test (e.g., pitot tube (delta 
P) readings, moisture collected in the impingers, etc.). For the purposes of the initial compliance demonstration, you may use test data and results from a performance test conducted prior to the date on which compliance is required as specified in 40 CFR 63.9984, provided that the following conditions are fully met: 
* * * * * 
(c) Operating limits. In accordance 
with § 63.10010 and Table 4 to this 
subpart, you may be required to establish operating limits using PM CPMS and using site-specific monitoring for certain liquid oil-fired units as part of your initial compliance demonstration. With the exception of IGCC units, on and after July 6, 2027, you may not demonstrate compliance with applicable filterable PM emissions limits with the use of PM CPMS or quarterly stack testing, you may only use PM CEMS. 
* * * * * 
(d) * * * 
(2) For affected coal-fired or solid oil- 
derived fuel-fired EGUs that 
demonstrate compliance with the applicable emission limits for total non- mercury HAP metals, individual non- mercury HAP metals, total HAP metals, individual HAP metals, or filterable PM listed in Table 1 or 2 to this subpart using initial performance testing and continuous monitoring with PM CPMS (with the exception of IGCC units, the use of PM CPMS is only allowed before July 6, 2027): 
* * * * * 
(h) Low emitting EGUs. The 
provisions of this paragraph (h) apply to 
pollutants with emissions limits from new EGUs except Hg and to all pollutants with emissions limits from existing EGUs. With the exception of IGCC units, on or after July 6, 2027 you may not pursue the LEE option for filterable PM. You may pursue this compliance option unless prohibited pursuant to § 63.10000(c)(1)(i). 
(1) An EGU may qualify for low 
emitting EGU (LEE) status for Hg, HCl, HF, filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or total HAP metals or individual HAP metals, for liquid oil- fired EGUs) if you collect performance test data that meet the requirements of this paragraph (h) with the exception that on or after July 6, 2027, you may not pursue the LEE option for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals for any existing, new or reconstructed EGUs (this does not apply to IGCC units), and if those data demonstrate: 
* * * * * 
■6. Amend § 63.10006 by revising 
paragraph (a) to read as follows: 
§ 63.10006 When must I conduct 
subsequent performance tests or tune-ups? 
(a) For liquid oil-fired, solid oil- 
derived fuel-fired and coal-fired EGUs 
and IGCC units using PM CPMS before July 6, 2027 to monitor continuous performance with an applicable emission limit as provided for under § 63.10000(c), you must conduct all applicable performance tests according to Table 5 to this subpart and § 63.10007 at least every year. On or after July 6, 2027 you may not use PM CPMS to demonstrate compliance for liquid oil- fired, solid oil-derived fuel-fired and coal-fired EGUs. This prohibition against the use of PM CPMS does not apply to IGCC units. 
* * * * * 
■7. Amend § 63.1007 by revising 
paragraphs (a)(3) and (c) to read as 
follows: 
§ 63.10007 What methods and other 
procedures must I use for the performance tests? 
(a) * * * 
(3) For establishing operating limits 
with particulate matter continuous parametric monitoring system (PM CPMS) to demonstrate compliance with a PM or non-Hg metals emissions limit (the use of PM CPMS is only allowed before July 6, 2027 with the exception of IGCC units), operate the unit at maximum normal operating load conditions during the performance test period. Maximum normal operating load will be generally between 90 and 110 percent of design capacity but should be representative of site specific normal operations during each test run. 
* * * * * 
(c) If you choose the filterable PM 
method to comply with the PM 
emission limit and demonstrate continuous performance using a PM CPMS as provided for in § 63.10000(c), you must also establish an operating limit according to § 63.10011(b), § 63.10023, and Tables 4 and 6 to this subpart. Should you desire to have operating limits that correspond to loads other than maximum normal operating load, you must conduct testing at those other loads to determine the additional operating limits. On and after July 6, 2027, you must demonstrate continuous compliance with the applicable filterable PM emission standard through the use of a PM CEMS (with the exception that IGCC units are not required to use PM CEMS and may continue to use PM CPMS). Alternatively, you may demonstrate continuous compliance with the non-Hg metals emission standard if you request and receive approval for the use of a HAP metals CMS under § 63.7(f). 
* * * * * 
■8. Amend § 63.10010 by revising 
paragraphs (a) introductory text, (h) 
introductory text, (i) introductory text, (j), and (l) introductory text to read as follows: 
§ 63.10010 What are my monitoring, 
installation, operation, and maintenance requirements? 
(a) Flue gases from the affected units 
under this subpart exhaust to the 
atmosphere through a variety of 
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different configurations, including but 
not limited to individual stacks, a common stack configuration or a main stack plus a bypass stack. For the CEMS, PM CPMS (which on or after July 6, 2027 you may not use PM CPMS for filterable PM compliance demonstrations unless it is for an IGCC unit), and sorbent trap monitoring systems used to provide data under this subpart, the continuous monitoring 
system installation requirements for these exhaust configurations are as follows: 
* * * * * 
(h) If you use a PM CPMS to 
demonstrate continuous compliance 
with an operating limit (only applicable before July 6, 2027 unless it is for an IGCC unit), you must install, calibrate, maintain, and operate the PM CPMS and record the output of the system as specified in paragraphs (h)(1) through (5) of this section. 
* * * * * 
(i) If you choose to comply with the 
PM filterable emissions limit in lieu of 
metal HAP limits (which on or after July 6, 2027 you may not use non-mercury metal HAP limits for compliance demonstrations for existing EGUs unless you request and receive approval for the use of a HAP metals CMS under § 63.7(f)), you may choose to install, certify, operate, and maintain a PM CEMS and record and report the output of the PM CEMS as specified in paragraphs (i)(1) through (8) of this section. With the exception of IGCC units, on or after July 6, 2027 owners/ operators of existing EGUs must comply with filterable PM emissions limits in Table 2 of this subpart and demonstrate continuous compliance using a PM CEMS unless you request and receive approval for the use of a HAP metals CMS under § 63.7(f). Compliance with the applicable PM emissions limit in Table 1 or 2 to this subpart is determined on a 30-boiler operating day rolling average basis. 
* * * * * 
(j) You may choose to comply with 
the metal HAP emissions limits using 
CMS approved in accordance with § 63.7(f) as an alternative to the performance test method specified in this rule. If approved to use a HAP metals CMS, the compliance limit will be expressed as a 30-boiler operating day rolling average of the numerical emissions limit value applicable for your unit in tables 1 or 2. If approved, you may choose to install, certify, operate, and maintain a HAP metals CMS and record the output of the HAP metals CMS as specified in paragraphs (j)(1) through (5) of this section. (1)(i) Install, calibrate, operate, and 
maintain your HAP metals CMS according to your CMS quality control program, as described in § 63.8(d)(2). The reportable measurement output from the HAP metals CMS must be expressed in units of the applicable emissions limit (e.g., lb/MMBtu, lb/ 
MWh) and in the form of a 30-boiler operating day rolling average. 
(ii) Operate and maintain your HAP 
metals CMS according to the procedures and criteria in your site specific performance evaluation and quality control program plan required in § 63.8(d). 
(2) Collect HAP metals CMS hourly 
average output data for all boiler operating hours except as indicated in section (j)(4) of this section. 
(3) Calculate the arithmetic 30-boiler 
operating day rolling average of all of the hourly average HAP metals CMS output data collected during all nonexempt boiler operating hours data. 
(4) You must collect data using the 
HAP metals CMS at all times the process unit is operating and at the intervals specified in paragraph (a) of this section, except for required monitoring system quality assurance or quality control activities, and any scheduled maintenance as defined in your site-specific monitoring plan. 
(i) You must use all the data collected 
during all boiler operating hours in assessing the compliance with your emission limit except: 
(A) Any data collected during periods 
of monitoring system malfunctions and repairs associated with monitoring system malfunctions. You must report any monitoring system malfunctions as deviations in your compliance reports under 40 CFR 63.10031(c) or (g) (as applicable); 
(B) Any data collected during periods 
when the monitoring system is out of control as specified in your site-specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or quality control activities conducted during out- of-control periods. You must report any out of control periods as deviations in your compliance reports under 40 CFR 63.10031(c) or (g) (as applicable); 
(C) Any data recorded during required 
monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of emissions (e.g., calibrations, certain 
audits, routine probe maintenance); and 
(D) Any data recorded during periods 
of startup or shutdown. 
(ii) You must record and report the 
results of HAP metals CMS system performance audits, in accordance with 40 CFR 63.10031(k). You must also record and make available upon request the dates and duration of periods when the HAP metals CMS is out of control to completion of the corrective actions necessary to return the HAP metals CMS to operation consistent with your site- specific performance evaluation and quality control program plan. 
* * * * * 
(l) Should you choose to rely on 
paragraph (2) of the definition of 
‘‘startup’’ in § 63.10042 for your EGU (only allowed before January 2, 2025), you must install, verify, operate, maintain, and quality assure each monitoring system necessary for demonstrating compliance with the PM or non-mercury metals work practice standards required to comply with § 63.10020(e). On and after January 2, 2025 you will no longer be able to choose paragraph (2) of the ‘‘startup’’ definition in § 63.10042 for your EGU. 
* * * * * 
■9. Amend § 63.10011 by revising 
paragraphs (b), (g)(3), and (4) 
introductory text to read as follows: 
§ 63.10011 How do I demonstrate initial 
compliance with the emissions limits and work practice standards? 
* * * * * 
(b) If you are subject to an operating 
limit in Table 4 to this subpart, you 
demonstrate initial compliance with HAP metals or filterable PM emission limit(s) through performance stack tests and you elect to use a PM CPMS to demonstrate continuous performance (with the exception of existing IGCC units, on or after July 6, 2027 you may not use PM CPMS for compliance demonstrations with the applicable filterable PM limits and the Table 4 p.m. CPMS operating limits do not apply), or if, for an IGCC unit, and you use quarterly stack testing for HCl and HF plus site-specific parameter monitoring to demonstrate continuous performance, you must also establish a site-specific operating limit, in accordance with § 63.10007 and Table 6 to this subpart. You may use only the parametric data recorded during successful performance tests (i.e., tests that demonstrate 
compliance with the applicable emissions limits) to establish an operating limit. On or after July 6, 2027 you may not use PM CPMS for compliance demonstrations with the applicable filterable PM limits and the Table 6 procedures for establishing PM CPMS operating limits do not apply unless it is an IGCC unit. 
* * * * * 
(g) * * * 
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(3) You must report the emissions 
data recorded during startup and 
shutdown. If you are relying on paragraph (2) of the definition of startup in 40 CFR 63.10042 (only allowed before January 2, 2025), then for startup and shutdown incidents that occur on or prior to December 31, 2023, you must also report the applicable supplementary information in 40 CFR 63.10031(c)(5) in the semiannual compliance report. For startup and shutdown incidents that occur on or after January 1, 2024, you must provide the applicable information in 40 CFR 63.10031(c)(5)(ii) and 40 CFR 63.10020(e) quarterly, in PDF files, in accordance with 40 CFR 63.10031(i). 
(4) If you choose to use paragraph (2) 
of the definition of ‘‘startup’’ in § 63.10042 (only allowed before January 2, 2025), and you find that you are unable to safely engage and operate your particulate matter (PM) control(s) within 1 hour of first firing of coal, residual oil, or solid oil-derived fuel, you may choose to rely on paragraph (1) of definition of ‘‘startup’’ in § 63.10042 or you may submit a request to use an alternative non-opacity emissions standard, as described below. 
* * * * * 
■10. Section 63.10020 is amended by 
revising paragraphs (e) introductory text and (e)(3)(i) introductory text to read as 
follows: 
§ 63.10020 How do I monitor and collect 
data to demonstrate continuous compliance? 
* * * * * 
(e) Additional requirements during 
startup periods or shutdown periods if 
you choose to rely on paragraph (2) of the definition of ‘‘startup’’ in § 63.10042 for your EGU (only allowed before January 2, 2025). 
* * * * * 
(3) * * * 
(i) Except for an EGU that uses PM 
CEMS or PM CPMS to demonstrate 
compliance with the PM emissions limit, or that has LEE status for filterable PM or total non-Hg HAP metals for non- liquid oil-fired EGUs (or HAP metals emissions for liquid oil-fired EGUs), or individual non-mercury metals CMS (except that unless it is for an IGCC unit, on or after July 6, 2027 you may not use PM CPMS for compliance demonstrations with the applicable filterable PM emissions limits, and you may not purse or continue to use the LEE option for filterable PM, total non- Hg HAP metals, or individual non-Hg HAP metals), you must: 
* * * * * ■11. Section 63.10021 is amended by 
revising paragraphs (c) introductory text 
and (i) to read as follows: 
§ 63.10021 How do I demonstrate 
continuous compliance with the emission limitations, operating limits, and work practice standards? 
* * * * * 
(c) If you use PM CPMS data (only 
allowed before July 6, 2027 unless it is 
for an IGCC unit) to measure compliance with an operating limit in Table 4 to this subpart, you must record the PM CPMS output data for all periods when the process is operating and the 
PM CPMS is not out-of-control. You must demonstrate continuous compliance by using all quality-assured hourly average data collected by the PM CPMS for all operating hours to calculate the arithmetic average operating parameter in units of the operating limit (e.g., milliamps, PM 
concentration, raw data signal) on a 30 operating day rolling average basis, updated at the end of each new boiler operating day. Use Equation 9 to determine the 30 boiler operating day average. On or after July 6, 2027 you may not use PM CPMS for compliance demonstrations unless it is for an IGCC unit. 
Where: 
Hpv iis the hourly parameter value for hour 
i and n is the number of valid hourly 
parameter values collected over 30 boiler operating days. 
* * * * * 
(i) Before January 2, 2025, if you are 
relying on paragraph 2 of the definition 
of startup in 40 CFR 63.10042, you must provide reports concerning activities and periods of startup and shutdown that occur on or prior to January 1, 2024, in accordance with 40 CFR 63.10031(c)(5), in your semiannual compliance report. For startup and shutdown incidents that occur on and after January 1, 2024, you must provide the applicable information referenced in 40 CFR 63.10031(c)(5)(ii) and 40 CFR 63.10020(e) quarterly, in PDF files, in accordance with 40 CFR 63.10031(i). On or after January 2, 2025 you may not use paragraph 2 of the definition of startup in 40 CFR 63.10042. ■12. Section 63.10022 is amended by 
revising paragraphs (a)(2) and (3) to read 
as follows: 
§ 63.10022 How do I demonstrate 
continuous compliance under the emissions averaging provision? 
(a) * * * 
(2) For each existing unit participating 
in the emissions averaging option that is 
equipped with PM CPMS, maintain the average parameter value at or below the 
operating limit established during the most recent performance test. On or after July 6, 2027 you may not use PM CPMS for filterable PM compliance demonstrations unless it is for an IGCC unit; 
(3) For each existing unit participating 
in the emissions averaging option venting to a common stack configuration containing affected units from other subcategories, maintain the appropriate operating limit for each unit as specified in Table 4 to this subpart that applies. Since on or after July 6, 2027 you may not use PM CPMS, unless it is for an IGCC unit, for compliance demonstrations with the applicable filterable PM limits, the Table 4 p.m. CPMS operating limits do not apply. 
* * * * * 
■13. Section 63.10023 is amended by 
adding introductory text to the section 
to read as follows: 
§ 63.10023 How do I establish my PM 
CPMS operating limit and determine compliance with it? 
The provisions of this section 
§ 63.10023 are only applicable before 
July 6, 2027 unless it is for an IGCC unit. On or after July 6, 2027 you may not use PM CPMS, unless it is an IGCC unit, for demonstrating compliance with the filterable PM emissions limits of this subpart. 
* * * * * 
■14. Section 63.10030 is amended by 
revising paragraphs (e)(3), (8) 
introductory text, and (8)(i) introductory text to read as follows: 
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§ 63.10030 What notifications must I 
submit and when? 
* * * * * 
(e) * * * 
(3) Identification of whether you plan 
to demonstrate compliance with each 
applicable emission limit through performance testing; fuel moisture analyses; performance testing with operating limits (e.g., use of PM CPMS— 
which on or after July 6, 2027—you may not use for filterable PM compliance demonstrations, unless it is for an IGCC unit); CEMS; or a sorbent trap monitoring system. 
* * * * * 
(8) Identification of whether you plan 
to rely on paragraph (1) or (2) of the 
definition of ‘‘startup’’ in § 63.10042. On or after January 2, 2025 you may not use paragraph (2) of the definition of startup in § 63.10042. 
(i) Before January 2, 2025 should you 
choose to rely on paragraph (2) of the definition of ‘‘startup’’ in § 63.10042 for your EGU, you shall include a report that identifies: 
* * * * * 
■15. Section 63.10031 is amended by 
revising paragraphs (a)(4), (c)(5) 
introductory text, (f)(2), (i), and (k) to read as follows: 
§ 63.10031 What reports must I submit and 
when? 
(a) * * * 
(4) Before July 6, 2027, if you elect to 
demonstrate continuous compliance 
using a PM CPMS, you must meet the electronic reporting requirements of appendix D to this subpart. Except for IGCC units, on or after July 6, 2027 you may not use PM CPMS for compliance demonstrations. Electronic reporting of the hourly PM CPMS output shall begin with the later of the first operating hour on or after January 1, 2024; or the first operating hour after completion of the initial performance stack test that establishes the operating limit for the PM CPMS. 
(c) * * * 
(5) Should you choose to rely on 
paragraph (2) of the definition of 
‘‘startup’’ in § 63.10042 for your EGU (only allowed before January 2, 2025), for each instance of startup or shutdown you shall: 
* * * * * 
(f) * * * 
(2) If, for a particular EGU or a group 
of EGUs serving a common stack, you 
have elected to demonstrate compliance using a PM CEMS, an approved HAP metals CMS, or a PM CPMS (on or after July 6, 2027 you may not use PM CPMS for compliance demonstrations, unless it is for an IGCC unit), you must submit quarterly PDF reports in accordance with paragraph (f)(6) of this section, which include all of the 30-boiler operating day rolling average emission rates derived from the CEMS data or the 30-boiler operating day rolling average responses derived from the PM CPMS data (as applicable). The quarterly reports are due within 60 days after the reporting periods ending on March 31st, June 30th, September 30th, and December 31st. Submission of these quarterly reports in PDF files shall end with the report that covers the fourth calendar quarter of 2023. Beginning with the first calendar quarter of 2024, the compliance averages shall no longer be reported separately, but shall be incorporated into the quarterly compliance reports described in paragraph (g) of this section. In addition to the compliance averages for PM CEMS, PM CPMS, and/or HAP metals CMS, the quarterly compliance reports described in paragraph (g) of this section must also include the 30- (or, if applicable 90-) boiler operating day rolling average emission rates for Hg, HCl, HF, and/or SO
2, if you have 
elected to (or are required to) continuously monitor these pollutants. Further, if your EGU or common stack is in an averaging plan, your quarterly compliance reports must identify all of the EGUs or common stacks in the plan and must include all of the 30- (or 90-) group boiler operating day rolling weighted average emission rates (WAERs) for the averaging group. 
* * * * * 
(i) If you have elected to use 
paragraph (2) of the definition of 
‘‘startup’’ in 40 CFR 63.10042 (only allowed before January 2, 2025), then, for startup and shutdown incidents that occur on or prior to December 31, 2023, you must include the information in 40 CFR 63.10031(c)(5) in the semiannual compliance report, in a PDF file. If you have elected to use paragraph (2) of the definition of ‘‘startup’’ in 40 CFR 63.10042, then, for startup and shutdown event(s) that occur on or after January 1, 2024, you must use the ECMPS Client Tool to submit the information in 40 CFR 63.10031(c)(5) and 40 CFR 63.10020(e) along with each quarterly compliance report, in a PDF file, starting with a report for the first calendar quarter of 2024. The applicable data elements in paragraphs (f)(6)(i) through (xii) of this section must be entered into ECMPS with each startup and shutdown report. 
* * * * * 
(k) If you elect to demonstrate 
compliance using a PM CPMS (on or 
after July 6, 2027 you may not demonstrate compliance with filterable PM emissions limits using a PM CPMS, unless it is for an IGCC unit) or an approved HAP metals CMS, you must submit quarterly reports of your QA/QC activities (e.g., calibration checks, 
performance audits), in a PDF file, beginning with a report for the first quarter of 2024, if the PM CPMS or HAP metals CMS is used for the compliance demonstration in that quarter. Otherwise, submit a report for the first calendar quarter in which the PM CPMS or HAP metals CMS is used to demonstrate compliance. These reports are due no later than 60 days after the end of each calendar quarter. The applicable data elements in paragraph (f)(6)(i) through (xii) of this section must be entered into ECMPS with the PDF report. 
■16. Section 63.10032 is amended by 
revising paragraphs (a) introductory text and (f)(2) introductory text to read as follows: 
§ 63.10032 What records must I keep? 
(a) You must keep records according 
to paragraphs (a)(1) and (2) of this section. If you are required to (or elect to) continuously monitor Hg and/or HCl and/or HF and/or PM emissions, or if you elect to use a PM CPMS (unless it is for an IGCC unit, you may only use PM CPMS before July 6, 2027), you must keep the records required under appendix A and/or appendix B and/or appendix C and/or appendix D to this subpart. If you elect to conduct periodic (e.g., quarterly or annual) performance 
stack tests, then, for each test completed on or after January 1, 2024, you must keep records of the applicable data elements under 40 CFR 63.7(g). You must also keep records of all data elements and other information in appendix E to this subpart that apply to your compliance strategy. 
* * * * * 
(f) * * * 
(2) Should you choose to rely on 
paragraph (2) of the definition of 
‘‘startup’’ in § 63.10042 for your EGU (on or after January 2, 2025 you may not use paragraph (2) of the definition of startup in § 63.10042), you must keep records of: 
* * * * * 
■17. Section 63.10042 is amended by 
revising the definition ‘‘Startup’’ to read 
as follows: 
§ 63.10042 What definitions apply to this 
subpart? 
* * * * * 
Startup means: 
(1) The first-ever firing of fuel in a 
boiler for the purpose of producing 
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electricity, or the firing of fuel in a 
boiler after a shutdown event for any purpose. 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). Any fraction of an hour in which startup occurs constitutes a full hour of startup. 
(2) Alternatively, prior to January 2, 
2025, the period in which operation of an EGU is initiated for any purpose. 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. 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 (16 U.S.C. 796(18)(A) and 18 CFR 292.202(c)), 
whichever is earlier. Any fraction of an hour in which startup occurs constitutes a full hour of startup. 
* * * * * 
■18. Revise table 1 to subpart UUUUU 
of part 63 to read as follows: 
Table 1 to Subpart UUUUU of Part 63— 
Emission Limits for New or Reconstructed EGUs 
As stated in § 63.9991, you must 
comply with the following applicable emission limits: 
If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
1. Coal-fired unit not low rank virgin coal a. Filterable partic-
ulate matter 
(PM).9.0E–2 lb/MWh1... Collect a minimum catch of 6.0 milligrams or a minimum 
sample volume of 4 dscm per run. 
OR OR 
Total non-Hg HAP 
metals.6.0E–2 lb/GWh ..... Collect a minimum of 4 dscm per run. 
OR OR 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... 8.0E–3 lb/GWh.
Arsenic (As) .......... 3.0E–3 lb/GWh.
Beryllium (Be) ....... 6.0E–4 lb/GWh.
Cadmium (Cd) ...... 4.0E–4 lb/GWh.
Chromium (Cr) ...... 7.0E–3 lb/GWh.
Cobalt (Co) ........... 2.0E–3 lb/GWh.
Lead (Pb) .............. 2.0E–2 lb/GWh.
Manganese (Mn) ... 4.0E–3 lb/GWh.
Nickel (Ni) ............. 4.0E–2 lb/GWh.
Selenium (Se) ....... 5.0E–2 lb/GWh.
b. Hydrogen chlo-
ride (HCl).1.0E–2 lb/MWh ..... For Method 26A at appendix A–8 to part 60 of this chap-
ter, collect a minimum of 3 dscm per run. For ASTM D6348–03(Reapproved 2010)
2or Method 320 at ap-
pendix A to part 63 of this chapter, sample for a min-imum of 1 hour. 
OR 
Sulfur dioxide 
(SO 2)3.1.0 lb/MWh ............ SO 2CEMS. 
c. Mercury (Hg) ..... 3.0E–3 lb/GWh ..... Hg CEMS or sorbent trap monitoring system only. 
2. Coal-fired units low rank virgin coal ... a. Filterable partic-
ulate matter (PM).9.0E–2 lb/MWh
1... Collect a minimum catch of 6.0 milligrams or a minimum 
sample volume of 4 dscm per run. 
OR OR 
Total non-Hg HAP 
metals.6.0E–2 lb/GWh ..... Collect a minimum of 4 dscm per run. 
OR OR 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... 8.0E–3 lb/GWh.
Arsenic (As) .......... 3.0E–3 lb/GWh.
Beryllium (Be) ....... 6.0E–4 lb/GWh.
Cadmium (Cd) ...... 4.0E–4 lb/GWh.
Chromium (Cr) ...... 7.0E–3 lb/GWh.
Cobalt (Co) ........... 2.0E–3 lb/GWh.
Lead (Pb) .............. 2.0E–2 lb/GWh.
Manganese (Mn) ... 4.0E–3 lb/GWh.
Nickel (Ni) ............. 4.0E–2 lb/GWh.
Selenium (Se) ....... 5.0E–2 lb/GWh.
b. Hydrogen chlo-
ride (HCl).1.0E–2 lb/MWh ..... For Method 26A, collect a minimum of 3 dscm per run For 
ASTM D6348–03(Reapproved 2010)2or Method 320, 
sample for a minimum of 1 hour. 
OR 
Sulfur dioxide 
(SO 2)3.1.0 lb/MWh ............ SO 2CEMS. 
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
c. Mercury (Hg) ..... Before July 8, 
2024: 4.0E–2 lb/ 
GWh; On or after July 8, 2024: 1.3E–2 lb/GWh.Hg CEMS or sorbent trap monitoring system only. 
3. IGCC unit ........................................... a. Filterable partic-
ulate matter (PM).7.0E–2 lb/MWh
4 
9.0E–2 lb/MWh5.Collect a minimum catch of 3.0 milligrams or a minimum 
sample volume of 2 dscm per run. 
OR OR 
Total non-Hg HAP 
metals.4.0E–1 lb/GWh ..... Collect a minimum of 1 dscm per run. 
OR OR 
Individual HAP 
metals:................................ Collect a minimum of 2 dscm per run. 
Antimony (Sb) ....... 2.0E–2 lb/GWh.
Arsenic (As) .......... 2.0E–2 lb/GWh.
Beryllium (Be) ....... 1.0E–3 lb/GWh.
Cadmium (Cd) ...... 2.0E–3 lb/GWh.
Chromium (Cr) ...... 4.0E–2 lb/GWh.
Cobalt (Co) ........... 4.0E–3 lb/GWh.
Lead (Pb) .............. 9.0E–3 lb/GWh.
Manganese (Mn) ... 2.0E–2 lb/GWh.
Nickel (Ni) ............. 7.0E–2 lb/GWh.
Selenium (Se) ....... 3.0E–1 lb/GWh.
b. Hydrogen chlo-
ride (HCl).2.0E–3 lb/MWh ..... For Method 26A, collect a minimum of 1 dscm per run; for 
Method 26 at appendix A–8 to part 60 of this chapter, collect a minimum of 120 liters per run. 
For ASTM D6348–03(Reapproved 2010)
2or Method 320, 
sample for a minimum of 1 hour. 
OR 
Sulfur dioxide 
(SO 2)3.4.0E–1 lb/MWh ..... SO 2CEMS. 
c. Mercury (Hg) ..... 3.0E–3 lb/GWh ..... Hg CEMS or sorbent trap monitoring system only. 
4. Liquid oil-fired unit—continental (ex-
cluding limited-use liquid oil-fired sub-category units).a. Filterable partic-
ulate matter (PM).3.0E–1 lb/MWh
1... Collect a minimum of 1 dscm per run. 
OR OR 
Total HAP metals .. 2.0E–4 lb/MWh ..... Collect a minimum of 2 dscm per run. 
OR OR 
Individual HAP 
metals:................................ Collect a minimum of 2 dscm per run. 
Antimony (Sb) ....... 1.0E–2 lb/GWh.
Arsenic (As) .......... 3.0E–3 lb/GWh.
Beryllium (Be) ....... 5.0E–4 lb/GWh.
Cadmium (Cd) ...... 2.0E–4 lb/GWh.
Chromium (Cr) ...... 2.0E–2 lb/GWh.
Cobalt (Co) ........... 3.0E–2 lb/GWh.
Lead (Pb) .............. 8.0E–3 lb/GWh.
Manganese (Mn) ... 2.0E–2 lb/GWh.
Nickel (Ni) ............. 9.0E–2 lb/GWh.
Selenium (Se) ....... 2.0E–2 lb/GWh.
Mercury (Hg) ......... 1.0E–4 lb/GWh ..... For Method 30B at appendix A–8 to part 60 of this chap-
ter sample volume determination (Section 8.2.4), the es-timated Hg concentration should nominally be <
1⁄2the 
standard. 
b. Hydrogen chlo-
ride (HCl).4.0E–4 lb/MWh ..... For Method 26A, collect a minimum of 3 dscm per run. 
For ASTM D6348–03(Reapproved 2010)2or Method 
320, sample for a minimum of 1 hour. 
c. Hydrogen fluo-
ride (HF).4.0E–4 lb/MWh ..... For Method 26A, collect a minimum of 3 dscm per run. 
For ASTM D6348–03 (Reapproved 2010)2or Method 
320, sample for a minimum of 1 hour. 
5. Liquid oil-fired unit—non-continental 
(excluding limited-use liquid oil-fired subcategory units).a. Filterable partic-
ulate matter (PM).2.0E–1 lb/MWh
1... Collect a minimum of 1 dscm per run. 
OR OR 
Total HAP metals .. 7.0E–3 lb/MWh ..... Collect a minimum of 1 dscm per run. 
OR OR 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... 8.0E–3 lb/GWh.
VerDate Sep<11>2014 16:50 May 06, 2024 Jkt 262001 PO 00000 Frm 00064 Fmt 4701 Sfmt 4700 E:\FR\FM\07MYR4.SGM 07MYR4khammond on DSKJM1Z7X2PROD with RULES438571 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
Arsenic (As) .......... 6.0E–2 lb/GWh.
Beryllium (Be) ....... 2.0E–3 lb/GWh.
Cadmium (Cd) ...... 2.0E–3 lb/GWh.
Chromium (Cr) ...... 2.0E–2 lb/GWh.
Cobalt (Co) ........... 3.0E–1 lb/GWh.
Lead (Pb) .............. 3.0E–2 lb/GWh.
Manganese (Mn) ... 1.0E–1 lb/GWh.
Nickel (Ni) ............. 4.1E0 lb/GWh.
Selenium (Se) ....... 2.0E–2 lb/GWh.
Mercury (Hg) ......... 4.0E–4 lb/GWh ..... For Method 30B sample volume determination (Section 
8.2.4), the estimated Hg concentration should nominally 
be <1⁄2the standard. 
b. Hydrogen chlo-
ride (HCl).2.0E–3 lb/MWh ..... For Method 26A, collect a minimum of 1 dscm per run; for 
Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
2or Method 320, 
sample for a minimum of 1 hour. 
c. Hydrogen fluo-
ride (HF).5.0E–4 lb/MWh ..... For Method 26A, collect a minimum of 3 dscm per run. 
For ASTM D6348–03 (Reapproved 2010)2or Method 
320, sample for a minimum of 1 hour. 
6. Solid oil-derived fuel-fired unit ........... a. Filterable partic-
ulate matter (PM).3.0E–2 lb/MWh
1... Collect a minimum of 1 dscm per run. 
OR OR 
Total non-Hg HAP 
metals.6.0E–1 lb/GWh ..... Collect a minimum of 1 dscm per run. 
OR OR 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... 8.0E–3 lb/GWh.
Arsenic (As) .......... 3.0E–3 lb/GWh.
Beryllium (Be) ....... 6.0E–4 lb/GWh.
Cadmium (Cd) ...... 7.0E–4 lb/GWh.
Chromium (Cr) ...... 6.0E–3 lb/GWh.
Cobalt (Co) ........... 2.0E–3 lb/GWh.
Lead (Pb) .............. 2.0E–2 lb/GWh.
Manganese (Mn) ... 7.0E–3 lb/GWh.
Nickel (Ni) ............. 4.0E–2 lb/GWh.
Selenium (Se) ....... 6.0E–3 lb/GWh.
b. Hydrogen chlo-
ride (HCl).4.0E–4 lb/MWh ..... For Method 26A, collect a minimum of 3 dscm per run. 
For ASTM D6348–03 (Reapproved 2010)2or Method 
320, sample for a minimum of 1 hour. 
OR 
Sulfur dioxide 
(SO 2)3.1.0 lb/MWh ............ SO 2CEMS. 
c. Mercury (Hg) ..... 2.0E–3 lb/GWh ..... Hg CEMS or Sorbent trap monitoring system only. 
1Gross output. 
2Incorporated by reference, see § 63.14. 
3You may not use the alternate SO 2limit if your EGU does not have some form of FGD system (or, in the case of IGCC EGUs, some other 
acid gas removal system either upstream or downstream of the combined cycle block) and SO 2CEMS installed. 
4Duct burners on syngas; gross output. 
5Duct burners on natural gas; gross output. 
■19. Revise table 2 to subpart UUUUU 
of part 63 to read as follows: Table 2 to Subpart UUUUU of Part 63— 
Emission Limits for Existing EGUs 
As stated in § 63.9991, you must 
comply with the following applicable emission limits:
1 
If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
1. Coal-fired unit not low rank virgin coal a. Filterable partic-
ulate matter 
(PM).Before July 6, 
2027: 3.0E–2 lb/ MMBtu or 3.0E– 1 lb/MWh
2.Before July 6, 2027: Collect a minimum of 1 dscm per 
run. 
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
On or after July 6, 
2027: 1.0E–2 lb/ 
MMBtu or 1.0E– 1 lb/MWh
2.On or after July 6, 2027: Collect a minimum catch of 6.0 
milligrams or a minimum sample volume of 4 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following total non-Hg HAP metals emission limit if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Total non-Hg HAP 
metals.Before July 6, 
2027: 5.0E–5 lb/ MMBtu or 5.0E– 1 lb/GWh.
On or after July 6, 
2027: 1.7E–5 lb/ MMBtu or 1.7E– 1 lb/GWh.Collect a minimum of 1 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following individual HAP metals emis-sions limits if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... Before July 6, 
2027: 8.0E–1 lb/ TBtu or 8.0E–3 lb/GWh.
On or after July 6, 
2027: 2.7E–1 lb/ TBtu or 2.7E–3 lb/GWh.
Arsenic (As) .......... Before July 6, 
2027: 1.1E0 lb/ TBtu or 2.0E–2 lb/GWh.
On or after July 6, 
2027: 3.7E–1 lb/ TBtu or 6.7E–3 lb/GWh.
Beryllium (Be) ....... Before July 6, 
2027: 2.0E–1 lb/ TBtu or 2.0E–3 lb/GWh.
On or after July 6, 
2027: 6.7E–2 lb/ TBtu or 6.7E–4 lb/GWh.
Cadmium (Cd) ...... Before July 6, 
2027: 3.0E–1 lb/ TBtu or 3.0E–3 lb/GWh.
On or after July 6, 
2027: 1.0E–1 lb/ TBtu or 1.0E–3 lb/GWh.
Chromium (Cr) ...... Before July 6, 
2027: 2.8E0 lb/ TBtu or 3.0E–2 lb/GWh.
On or after July 6, 
2027: 9.3E–1 lb/ TBtu or 1.0E–2 lb/GWh.
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
Cobalt (Co) ........... Before July 6, 
2027: 8.0E–1 lb/ 
TBtu or 8.0E–3 lb/GWh.
On or after July 6, 
2027: 2.7E–1 lb/ TBtu or 2.7E–3 lb/GWh.
Lead (Pb) .............. Before July 6, 
2027: 1.2E0 lb/ TBtu or 2.0E–2 lb/GWh.
On or after July 6, 
2027: 4.0E–1 lb/ TBtu or 6.7E–3 lb/GWh.
Manganese (Mn) ... Before July 6, 
2027: 4.0E0 lb/ TBtu or 5.0E–2 lb/GWh.
On or after July 6, 
2027: 1.3E0 lb/ TBtu or 1.7E–2 lb/GWh.
Nickel (Ni) ............. Before July 6, 
2027: 3.5E0 lb/ TBtu or 4.0E–2 lb/GWh.
On or after July 6, 
2027: 1.2E0 lb/ TBtu or 1.3E–2 lb/GWh.
Selenium (Se) ....... Before July 6, 
2027: 5.0E0 lb/ TBtu or 6.0E–2 lb/GWh.
On or after July 6, 
2027: 1.7E0 lb/ TBtu or 2.0E–2 lb/GWh.
b. Hydrogen chlo-
ride (HCl).2.0E–3 lb/MMBtu 
or 2.0E–2 lb/ MWh.For Method 26A at appendix A–8 to part 60 of this chap-
ter, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 320 at ap-
pendix A to part 63 of this chapter, sample for a min-imum of 1 hour. 
OR 
Sulfur dioxide 
(SO 2)4.2.0E–1 lb/MMBtu 
or 1.5E0 lb/MWh.SO2CEMS. 
c. Mercury (Hg) ..... 1.2E0 lb/TBtu or 
1.3E–2 lb/GWh.LEE Testing for 30 days with a sampling period consistent 
with that given in section 5.2.1 of appendix A to this subpart per Method 30B at appendix A–8 to part 60 of this chapter run or Hg CEMS or sorbent trap monitoring system only. 
OR 
1.0E0 lb/TBtu or 
1.1E–2 lb/GWh.LEE Testing for 90 days with a sampling period consistent 
with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. 
2. Coal-fired unit low rank virgin coal .... a. Filterable partic-
ulate matter (PM).Before July 6, 
2027: 3.0E–2 lb/ MMBtu or 3.0E– 1 lb/MWh
2.
On or after July 6, 
2027: 1.0E–2 lb/ MMBtu or 1.0E– 1 lb/MWh
2.Before July 6, 2027: Collect a minimum of 1 dscm per 
run. 
On or after July 6, 2027: Collect a minimum catch of 6.0 
milligrams or a minimum sample volume of 4 dscm per run. 
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following total non-Hg HAP metals 
emission limit if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Total non-Hg HAP 
metals.Before July 6, 
2027: 5.0E–5 lb/ MMBtu or 5.0E– 1 lb/GWh.
On or after July 6, 
2027: 1.7E–5 lb/ MMBtu or 1.7E– 1 lb/GWh.Collect a minimum of 1 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following individual HAP metals emis-sions limits if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... Before July 6, 
2027: 8.0E–1 lb/ TBtu or 8.0E–3 lb/GWh.
On or after July 6, 
2027: 2.7E–1 lb/ TBtu or 2.7E–3 lb/GWh.
Arsenic (As) .......... Before July 6, 
2027: 1.1E0 lb/ TBtu or 2.0E–2 lb/GWh.
On or after July 6, 
2027: 3.7E–1 lb/ TBtu or 6.7E–3 lb/GWh.
Beryllium (Be) ....... Before July 6, 
2027: 2.0E–1 lb/ TBtu or 2.0E–3 lb/GWh.
On or after July 6, 
2027: 6.7E–2 lb/ TBtu or 6.7E–4 lb/GWh.
Cadmium (Cd) ...... Before July 6, 
2027: 3.0E–1 lb/ TBtu or 3.0E–3 lb/GWh.
On or after July 6, 
2027: 1.0E–1 lb/ TBtu or 1.0E–3 lb/GWh.
Chromium (Cr) ...... Before July 6, 
2027: 2.8E0 lb/ TBtu or 3.0E–2 lb/GWh.
On or after July 6, 
2027: 9.3E–1 lb/ TBtu or 1.0E–2 lb/GWh.
Cobalt (Co) ........... Before July 6, 
2027: 8.0E–1 lb/ TBtu or 8.0E–3 lb/GWh.
On or after July 6, 
2027: 2.7E–1 lb/ TBtu or 2.7E–3 lb/GWh.
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
Lead (Pb) .............. Before July 6, 
2027: 1.2E0 lb/ 
TBtu or 2.0E–2 lb/GWh.
On or after July 6, 
2027: 4.0E–1 lb/ TBtu or 6.7E–3 lb/GWh.
Manganese (Mn) ... Before July 6, 
2027: 4.0E0 lb/ TBtu or 5.0E–2 lb/GWh.
On or after July 6, 
2027: 1.3E0 lb/ TBtu or 1.7E–2 lb/GWh.
Nickel (Ni) ............. Before July 6, 
2027: 3.5E0 lb/ TBtu or 4.0E–2 lb/GWh.
On or after July 6, 
2027: 1.2E0 lb/ TBtu or 1.3E–2 lb/GWh.
Selenium (Se) ....... Before July 6, 
2027: 5.0E0 lb/ TBtu or 6.0E–2 lb/GWh.
On or after July 6, 
2027: 1.7E0 lb/ TBtu or 2.0E–2 lb/GWh.
b. Hydrogen chlo-
ride (HCl).2.0E–3 lb/MMBtu 
or 2.0E–2 lb/ MWh.For Method 26A, collect a minimum of 0.75 dscm per run; 
for Method 26 at appendix A–8 to part 60 of this chap-ter, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 320, sample 
for a minimum of 1 hour. 
OR OR 
Sulfur dioxide 
(SO 2)4.2.0E–1 lb/MMBtu 
or 1.5E0 lb/MWh.SO2CEMS. 
c. Mercury (Hg) ..... Before July 6, 
2027: 4.0E0 lb/ TBtu or 4.0E–2 lb/GWh.
On or after July 6, 
2027: 1.2E0 lb/ TBtu or 1.3E–2 lb/GWh.LEE Testing for 30 days with a sampling period consistent 
with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. 
3. IGCC unit ........................................... a. Filterable partic-
ulate matter (PM).4.0E–2 lb/MMBtu 
or 4.0E–1 lb/ MWh
2.Before July 6, 2027: Collect a minimum of 1 dscm per 
run. 
On or after July 6, 2027: Collect a minimum catch of 3.0 
milligrams or a minimum sample volume of 2 dscm per run. 
OR OR 
Total non-Hg HAP 
metals.6.0E–5 lb/MMBtu 
or 5.0E–1 lb/ GWh.Collect a minimum of 1 dscm per run. 
OR OR 
Individual HAP 
metals:................................ Collect a minimum of 2 dscm per run. 
Antimony (Sb) ....... 1.4E0 lb/TBtu or 
2.0E–2 lb/GWh.
Arsenic (As) .......... 1.5E0 lb/TBtu or 
2.0E–2 lb/GWh.
Beryllium (Be) ....... 1.0E–1 lb/TBtu or 
1.0E–3 lb/GWh.
Cadmium (Cd) ...... 1.5E–1 lb/TBtu or 
2.0E–3 lb/GWh.
Chromium (Cr) ...... 2.9E0 lb/TBtu or 
3.0E–2 lb/GWh.
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
Cobalt (Co) ........... 1.2E0 lb/TBtu or 
2.0E–2 lb/GWh.
Lead (Pb) .............. 1.9E+2 lb/TBtu or 
1.8E0 lb/GWh.
Manganese (Mn) ... 2.5E0 lb/TBtu or 
3.0E–2 lb/GWh.
Nickel (Ni) ............. 6.5E0 lb/TBtu or 
7.0E–2 lb/GWh.
Selenium (Se) ....... 2.2E+1 lb/TBtu or 
3.0E–1 lb/GWh.
b. Hydrogen chlo-
ride (HCl).5.0E–4 lb/MMBtu 
or 5.0E–3 lb/ 
MWh.For Method 26A, collect a minimum of 1 dscm per run; for 
Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 320, 
sample for a minimum of 1 hour. 
c. Mercury (Hg) ..... 2.5E0 lb/TBtu or 
3.0E–2 lb/GWh.LEE Testing for 30 days with a sampling period consistent 
with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. 
4. Liquid oil-fired unit—continental (ex-
cluding limited-use liquid oil-fired sub-category units).a. Filterable partic-
ulate matter (PM).3.0E–2 lb/MMBtu 
or 3.0E–1 lb/ MWh
2.Collect a minimum of 1 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following total non-Hg HAP metals emission limit if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Total HAP metals .. 8.0E–4 lb/MMBtu 
or 8.0E–3 lb/ MWh.Collect a minimum of 1 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following individual HAP metals emis-sions limits if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Individual HAP 
metals:................................ Collect a minimum of 1 dscm per run. 
Antimony (Sb) ....... 1.3E+1 lb/TBtu or 
2.0E–1 lb/GWh.
Arsenic (As) .......... 2.8E0 lb/TBtu or 
3.0E–2 lb/GWh.
Beryllium (Be) ....... 2.0E–1 lb/TBtu or 
2.0E–3 lb/GWh.
Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 
2.0E–3 lb/GWh.
Chromium (Cr) ...... 5.5E0 lb/TBtu or 
6.0E–2 lb/GWh.
Cobalt (Co) ........... 2.1E+1 lb/TBtu or 
3.0E–1 lb/GWh.
Lead (Pb) .............. 8.1E0 lb/TBtu or 
8.0E–2 lb/GWh.
Manganese (Mn) ... 2.2E+1 lb/TBtu or 
3.0E–1 lb/GWh.
Nickel (Ni) ............. 1.1E+2 lb/TBtu or 
1.1E0 lb/GWh.
Selenium (Se) ....... 3.3E0 lb/TBtu or 
4.0E–2 lb/GWh.
Mercury (Hg) ......... 2.0E–1 lb/TBtu or 
2.0E–3 lb/GWh.For Method 30B sample volume determination (Section 
8.2.4), the estimated Hg concentration should nominally be <
1⁄2the standard. 
b. Hydrogen chlo-
ride (HCl).2.0E–3 lb/MMBtu 
or 1.0E–2 lb/ MWh.For Method 26A, collect a minimum of 1 dscm per run; for 
Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 320, 
sample for a minimum of 1 hour. 
c. Hydrogen fluo-
ride (HF).4.0E–4 lb/MMBtu 
or 4.0E–3 lb/ MWh.For Method 26A, collect a minimum of 1 dscm per run; for 
Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 320, 
sample for a minimum of 1 hour. 
5. Liquid oil-fired unit—non-continental 
(excluding limited-use liquid oil-fired subcategory units).a. Filterable partic-
ulate matter (PM).3.0E–2 lb/MMBtu 
or 3.0E–1 lb/ MWh
2.Collect a minimum of 1 dscm per run. 
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following total non-Hg HAP metals 
emission limit if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Total HAP metals .. 6.0E–4 lb/MMBtu 
or 7.0E–3 lb/ MWh.Collect a minimum of 1 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following individual HAP metals emis-sions limits if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Individual HAP 
metals:................................ Collect a minimum of 2 dscm per run. 
Antimony (Sb) ....... 2.2E0 lb/TBtu or 
2.0E–2 lb/GWh.
Arsenic (As) .......... 4.3E0 lb/TBtu or 
8.0E–2 lb/GWh.
Beryllium (Be) ....... 6.0E–1 lb/TBtu or 
3.0E–3 lb/GWh.
Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 
3.0E–3 lb/GWh.
Chromium (Cr) ...... 3.1E+1 lb/TBtu or 
3.0E–1 lb/GWh.
Cobalt (Co) ........... 1.1E+2 lb/TBtu or 
1.4E0 lb/GWh.
Lead (Pb) .............. 4.9E0 lb/TBtu or 
8.0E–2 lb/GWh.
Manganese (Mn) ... 2.0E+1 lb/TBtu or 
3.0E–1 lb/GWh.
Nickel (Ni) ............. 4.7E+2 lb/TBtu or 
4.1E0 lb/GWh.
Selenium (Se) ....... 9.8E0 lb/TBtu or 
2.0E–1 lb/GWh.
Mercury (Hg) ......... 4.0E–2 lb/TBtu or 
4.0E–4 lb/GWh.For Method 30B sample volume determination (Section 
8.2.4), the estimated Hg concentration should nominally be <
1⁄2the standard. 
b. Hydrogen chlo-
ride (HCl).2.0E–4 lb/MMBtu 
or 2.0E–3 lb/ MWh.For Method 26A, collect a minimum of 1 dscm per run; for 
Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 320, 
sample for a minimum of 2 hours. 
c. Hydrogen fluo-
ride (HF).6.0E–5 lb/MMBtu 
or 5.0E–4 lb/ MWh.For Method 26A, collect a minimum of 3 dscm per run. 
For ASTM D6348–03 (Reapproved 2010)
3or Method 
320, sample for a minimum of 2 hours. 
6. Solid oil-derived fuel-fired unit ........... a. Filterable partic-
ulate matter (PM).8.0E–3 lb/MMBtu 
or 9.0E–2 lb/ MWh
2.Before July 6, 2027: Collect a minimum of 1 dscm per 
run. 
On or after July 6, 2027: Collect a minimum catch of 6.0 
milligrams or a minimum sample volume of 4 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following total non-Hg HAP metals emission limit if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Total non-Hg HAP 
metals.4.0E–5 lb/MMBtu 
or 6.0E–1 lb/ GWh.Collect a minimum of 1 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following individual HAP metals emis-sions limits if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... 8.0E–1 lb/TBtu or 
7.0E–3 lb/GWh.
Arsenic (As) .......... 3.0E–1 lb/TBtu or 
5.0E–3 lb/GWh.
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
Beryllium (Be) ....... 6.0E–2 lb/TBtu or 
5.0E–4 lb/GWh.
Cadmium (Cd) ...... 3.0E–1 lb/TBtu or 
4.0E–3 lb/GWh.
Chromium (Cr) ...... 8.0E–1 lb/TBtu or 
2.0E–2 lb/GWh.
Cobalt (Co) ........... 1.1E0 lb/TBtu or 
2.0E–2 lb/GWh.
Lead (Pb) .............. 8.0E–1 lb/TBtu or 
2.0E–2 lb/GWh.
Manganese (Mn) ... 2.3E0 lb/TBtu or 
4.0E–2 lb/GWh.
Nickel (Ni) ............. 9.0E0 lb/TBtu or 
2.0E–1 lb/GWh.
Selenium (Se) ....... 1.2E0 lb/TBtu or 
2.0E–2 lb/GWh.
b. Hydrogen chlo-
ride (HCl).5.0E–3 lb/MMBtu 
or 8.0E–2 lb/ 
MWh.For Method 26A, collect a minimum of 0.75 dscm per run; 
for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 
320, sample for a minimum of 1 hour. 
OR OR 
Sulfur dioxide 
(SO 2)4.3.0E–1 lb/MMBtu 
or 2.0E0 lb/MWh.SO2CEMS. 
c. Mercury (Hg) ..... 2.0E–1 lb/TBtu or 
2.0E–3 lb/GWh.LEE Testing for 30 days with a sampling period consistent 
with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. 
7. Eastern Bituminous Coal Refuse 
(EBCR)-fired unit.a. Filterable partic-
ulate matter (PM).Before July 6, 
2027: 3.0E–2 lb/ MMBtu or 3.0E– 1 lb/MWh
2.
On or after July 6, 
2027: 1.0E–2 lb/ MMBtu or 1.0E– 1 lb/MWh
2.Before July 6, 2027: Collect a minimum of 1 dscm per 
run. 
On or after July 6, 2027: Collect a minimum catch of 6.0 
milligrams or a minimum sample volume of 4 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following total non-Hg HAP metals emission limit if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Total non-Hg HAP 
metals.Before July 6, 
2027: 5.0E–5 lb/ MMBtu or 5.0E– 1 lb/GWh.
On or after July 6, 
2027: 1.7E–5 lb/ MMBtu or 1.7E– 1 lb/GWh.Collect a minimum of 1 dscm per run. 
OR OR On or after July 6, 2027 you may only demonstrate com-
pliance with the following individual HAP metals emis-sions limits if you request and receive approval for the use of a non-Hg HAP metals CMS under 40 CFR 63.7(f). 
Individual HAP 
metals:................................ Collect a minimum of 3 dscm per run. 
Antimony (Sb) ....... Before July 6, 
2027: 8.0E–1 lb/ TBtu or 8.0E–3 lb/GWh.
On or after July 6, 
2027: 2.7E–1 lb/ TBtu or 2.7E–3 lb/GWh.
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
Arsenic (As) .......... Before July 6, 
2027: 1.1E0 lb/ 
TBtu or 2.0E–2 lb/GWh.
On or after July 6, 
2027: 3.7E–1 lb/ TBtu or 6.7E–3 lb/GWh.
Beryllium (Be) ....... Before July 6, 
2027: 2.0E–1 lb/ TBtu or 2.0E–3 lb/GWh.
On or after July 6, 
2027: 6.7E–2 lb/ TBtu or 6.7E–4 lb/GWh.
Cadmium (Cd) ...... Before July 6, 
2027: 3.0E–1 lb/ TBtu or 3.0E–3 lb/GWh.
On or after July 6, 
2027: 1.0E–1 lb/ TBtu or 1.0E–3 lb/GWh.
Chromium (Cr) ...... Before July 6, 
2027: 2.8E0 lb/ TBtu or 3.0E–2 lb/GWh.
On or after July 6, 
2027: 9.3E–1 lb/ TBtu or 1.0E–2 lb/GWh.
Cobalt (Co) ........... Before July 6, 
2027: 8.0E–1 lb/ TBtu or 8.0E–3 lb/GWh.
On or after July 6, 
2027: 2.7E–1 lb/ TBtu or 2.7E–3 lb/GWh.
Lead (Pb) .............. Before July 6, 
2027: 1.2E0 lb/ TBtu or 2.0E–2 lb/GWh.
On or after July 6, 
2027: 4.0E–1 lb/ TBtu or 6.7E–3 lb/GWh.
Manganese (Mn) ... Before July 6, 
2027: 4.0E0 lb/ TBtu or 5.0E–2 lb/GWh.
On or after July 6, 
2027: 1.3E0 lb/ TBtu or 1.7E–2 lb/GWh.
Nickel (Ni) ............. Before July 6, 
2027: 3.5E0 lb/ TBtu or 4.0E–2 lb/GWh.
On or after July 6, 
2027: 1.2E0 lb/ TBtu or 1.3E–2 lb/GWh.
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If your EGU is in this subcategory . . . For the following 
pollutants . . . You must meet the following emission limits and work practice standards ...  Using these requirements, as appropriate (e.g., specified 
sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 
Selenium (Se) ....... Before July 6, 
2027: 5.0E0 lb/ 
TBtu or 6.0E–2 lb/GWh.
On or after July 6, 
2027: 1.7E0 lb/ TBtu or 2.0E–2 lb/GWh.
b. Hydrogen chlo-
ride (HCl).4.0E–2 lb/MMBtu 
or 4.0E–1 lb/ MWh.For Method 26A at appendix A–8 to part 60 of this chap-
ter, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 (Reapproved 2010)
3or Method 320 at ap-
pendix A to part 63 of this chapter, sample for a min-imum of 1 hour. 
OR 
Sulfur dioxide 
(SO 2)4.6E–1 lb/MMBtu or 
9E0 lb/MWh.SO2CEMS. 
c. Mercury (Hg) ..... 1.2E0 lb/TBtu or 
1.3E–2 lb/GWh.LEE Testing for 30 days with a sampling period consistent 
with that given in section 5.2.1 of appendix A to this subpart per Method 30B at appendix A–8 to part 60 of this chapter run or Hg CEMS or sorbent trap monitoring system only. 
OR 
1.0E0 lb/TBtu or 
1.1E–2 lb/GWh.LEE Testing for 90 days with a sampling period consistent 
with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. 
1For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must 
be increased nominally by a factor of 2. With the exception of IGCC units, on or after July 6, 2027 you may not pursue the LEE option for filter-
able PM, total non-Hg metals, and individual HAP metals and you may not comply with the total non-Hg HAP metals or individual HAP metals emissions limits for all existing EGU subcategories unless you request and receive approval for the use of a HAP metals CMS under § 63.7(f). 
2Gross output. 
3Incorporated by reference, see § 63.14. 
4You may not use the alternate SO 2limit if your EGU does not have some form of FGD system and SO 2CEMS installed. 
■20. Revise table 3 to subpart UUUUU 
of part 63 to read as follows: Table 3 to Subpart UUUUU of Part 63— 
Work Practice Standards 
As stated in § 63.9991, you must 
comply with the following applicable work practice standards: 
If your EGU is . . . You must meet the following . . . 
1. An existing EGU ............................................. Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar 
months, or each 48 calendar months if neural network combustion optimization software is 
employed, as specified in § 63.10021(e). 
2. A new or reconstructed EGU ......................... Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar 
months, or each 48 calendar months if neural network combustion optimization software is employed, as specified in § 63.10021(e). 
3. A coal-fired, liquid oil-fired (excluding limited- 
use liquid oil-fired subcategory units), or solid oil-derived fuel-fired EGU during startup.a. Before January 2, 2025 you have the option of complying using either of the following work 
practice standards in paragraphs (1) and (2). On or after January 2, 2025 you may not choose to use paragraph (2) of the definition of startup in § 63.10042 and the following as-sociated work practice standards in paragraph (2). 
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If your EGU is . . . You must meet the following . . . 
(1) If you choose to comply using paragraph (1) of the definition of ‘‘startup’’ in § 63.10042, 
you must operate all CMS during startup. Startup means 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 shut-down event for any purpose. 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). For startup of a unit, you must use clean fuels as defined in § 63.10042 for ignition. Once you convert to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the applicable control technologies except dry scrubber and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to comply with relevant standards ap-plicable during normal operation. You must comply with all applicable emissions limits at all times except for periods that meet the applicable definitions of startup and shutdown in this subpart. You must keep records during startup periods. You must provide reports con-cerning activities and startup periods, as specified in § 63.10011(g) and § 63.10021(h) and (i). If you elect to use paragraph (2) of the definition of startup in 40 CFR 63.10042, you must report the applicable information in 40 CFR 63.10031(c)(5) concerning startup periods as follows: For startup periods that occur on or prior to December 31, 2023, in PDF files in the semiannual compliance report; for startup periods that occur on or after January 1, 2024, quarterly, in PDF files, according to 40 CFR 63.10031(i). 
(2) If you choose to comply using paragraph (2) of the definition of ‘‘startup’’ in § 63.10042, 
you must operate all CMS during startup. You must also collect appropriate data, and you must calculate the pollutant emission rate for each hour of startup. 
For startup of an EGU, you must use one or a combination of the clean fuels defined in 
§ 63.10042 to the maximum extent possible, taking into account considerations such as boil-er or control device integrity, throughout the startup period. You must have sufficient clean fuel capacity to engage and operate your PM control device within one hour of adding coal, residual oil, or solid oil-derived fuel to the unit. You must meet the startup period work prac-tice requirements as identified in § 63.10020(e). 
Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions to the 
main stack(s). You must comply with the applicable emission limits beginning with the hour after startup ends. You must engage and operate your PM control(s) within 1 hour of first fir-ing of coal, residual oil, or solid oil-derived fuel. 
You must start all other applicable control devices as expeditiously as possible, considering 
safety and manufacturer/supplier recommendations, but, in any case, when necessary to comply with other standards made applicable to the EGU by a permit limit or a rule other than this subpart that require operation of the control devices. 
b. Relative to the syngas not fired in the combustion turbine of an IGCC EGU during startup, 
you must either: (1) Flare the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue gas from the duct burners to the heat recovery steam generator. 
c. If you choose to use just one set of sorbent traps to demonstrate compliance with the appli-
cable Hg emission limit, you must comply with the limit at all times; otherwise, you must comply with the applicable emission limit at all times except for startup and shutdown peri-ods. 
d. You must collect monitoring data during startup periods, as specified in § 63.10020(a) and 
(e). You must keep records during startup periods, as provided in §§ 63.10021(h) and 63.10032. You must provide reports concerning activities and startup periods, as specified in §§ 63.10011(g), 63.10021(i), and 63.10031. Before January 2, 2025, if you elect to use para-graph (2) of the definition of startup in 40 CFR 63.10042, you must report the applicable in-formation in 40 CFR 63.10031(c)(5) concerning startup periods as follows: For startup peri-ods that occur on or prior to December 31, 2023, in PDF files in the semiannual compliance report; for startup periods that occur on or after January 1, 2024, quarterly, in PDF files, ac-cording to 40 CFR 63.10031(i). On or after January 2, 2025 you may not use paragraph (2) of the definition of startup in § 63.10042. 
4. A coal-fired, liquid oil-fired (excluding limited- 
use liquid oil-fired subcategory units), or solid oil-derived fuel-fired EGU during shutdown.You must operate all CMS during shutdown. You must also collect appropriate data, and you 
must calculate the pollutant emission rate for each hour of shutdown for those pollutants for which a CMS is used. 
While firing coal, residual oil, or solid oil-derived fuel during shutdown, you must vent emis-
sions to the main stack(s) and operate all applicable control devices and continue to operate those control devices after the cessation of coal, residual oil, or solid oil-derived fuel being fed into the EGU and for as long as possible thereafter considering operational and safety concerns. In any case, you must operate your controls when necessary to comply with other standards made applicable to the EGU by a permit limit or a rule other than this subpart and that require operation of the control devices. 
If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to sup-
port the shutdown process, that additional fuel must be one or a combination of the clean fuels defined in § 63.10042 and must be used to the maximum extent possible, taking into account considerations such as not compromising boiler or control device integrity. 
Relative to the syngas not fired in the combustion turbine of an IGCC EGU during shutdown, 
you must either: (1) Flare the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue gas from the duct burners to the heat recovery steam generator. 
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If your EGU is . . . You must meet the following . . . 
You must comply with all applicable emission limits at all times except during startup periods 
and shutdown periods at which time you must meet this work practice. You must collect 
monitoring data during shutdown periods, as specified in § 63.10020(a). You must keep records during shutdown periods, as provided in §§ 63.10032 and 63.10021(h). Any fraction of an hour in which shutdown occurs constitutes a full hour of shutdown. You must provide reports concerning activities and shutdown periods, as specified in §§ 63.10011(g), 63.10021(i), and 63.10031. Before January 2, 2025, if you elect to use paragraph (2) of the definition of startup in 40 CFR 63.10042, you must report the applicable information in 40 CFR 63.10031(c)(5) concerning shutdown periods as follows: For shutdown periods that occur on or prior to December 31, 2023, in PDF files in the semiannual compliance report; for shutdown periods that occur on or after January 1, 2024, quarterly, in PDF files, accord-ing to 40 CFR 63.10031(i). On or after January 2, 2025 you may not use paragraph (2) of the definition of startup in § 63.10042. 
■21. Revise table 4 to subpart UUUUU 
of part 63 to read as follows: Table 4 to Subpart UUUUU of Part 63— 
Operating Limits for EGUs 
Before July 6, 2027, as stated in 
§ 63.9991, you must comply with the applicable operating limits in table 4. 
However, on or after July 6, 2027 you may not use PM CPMS for compliance demonstrations, unless it is for an IGCC unit. 
If you demonstrate compli-
ance using . . . You must meet these operating limits . . . 
PM CPMS ............................ Maintain the 30-boiler operating day rolling average PM CPMS output determined in accordance with the require-
ments of § 63.10023(b)(2) and obtained during the most recent performance test run demonstrating compliance 
with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oil-fired units), or individual non-mercury HAP metals (individual HAP metals including Hg, for liquid oil-fired units) emissions limitation(s). 
■22. Revise table 5 to subpart UUUUU 
of part 63 to read as follows: Table 5 to Subpart UUUUU of Part 63— 
Performance Testing Requirements 
As stated in § 63.10007, you must 
comply with the following requirements for performance testing for existing, new or reconstructed affected sources:
1 
BILLING CODE 6560–50–P 
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VerDate Sep<11>2014 16:50 May 06, 2024 Jkt 262001 PO 00000 Frm 00077 Fmt 4701 Sfmt 4725 E:\FR\FM\07MYR4.SGM 07MYR4
ER07MY24.101</GPH>khammond on DSKJM1Z7X2PROD with RULES4You must 
perform the 
To conduct following 
a activities, as 
performance Using ... applicable to Using ... 2 
test for the your input-
following or output-
pollutant ... based 
emission limit ... 
1. Filterable Emissions a. Select Method 1 at appendix A-1 to part 60 of this 
Particulate Testing sampling ports chapter. 
matter (PM) location and 
the number of 
traverse points 
b. Determine Method 2, 2A, 2C, 2F, 2G or 2H at appendix A-
velocity and 1 or A-2 to part 60 of this chapter. 
volumetric 
flow-rate of 
the stack gas 
c. Determine Method 3A or 3B at appendix A-2 to part 60 of 
oxygen and this chapter, or ANSI/ASME PTC 19.10-1981. 3 
carbon 
dioxide concentrations 
of the stack 
gas 
d. Measure the Method 4 at appendix A-3 to part 60 of this 
moisture chapter. 
content of the 
stack gas 
Methods 5 and 51 at appendix A-3 to part 60 of 
this chapter. 
e. Measure the For positive pressure fabric filters, Method 5D 
filterable PM at appendix A-3 to part 60 of this chapter for 
concentration filterable PM emissions. 
Note that the Method 5 or 51 front half 
temperature shall be 160° ±14 °C (320° ±25 
OF). 
f. Convert Method 19 F-factor methodology at appendix 
em1ss1ons A-7 to part 60 of this chapter, or calculate using 
concentration mass emissions rate and gross output data (see§ 
to lb/MMBtu 63.10007(e)). 
orlb/MWh 
em1ss1ons 
rates 
OR OR 
PMCEMS a. Install, Performance Specification 11 at appendix B to 
certify, part 60 of this chapter and Procedure 2 at 
operate, and appendix F to part 60 of this chapter. 38584 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
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ER07MY24.102</GPH>khammond on DSKJM1Z7X2PROD with RULES4maintain the 
PMCEMS 
b. Install, Part 75 of this chapter and§ 63.l00l0(a), (b), 
certify, (c), and (d). 
operate, and 
maintain the 
diluent gas, 
flow rate, 
and/or 
moisture 
monitoring 
systems 
c. Convert Method 19 F-factor methodology at appendix 
hourly A-7 to part 60 of this chapter, or calculate using 
em1ss1ons mass emissions rate and gross output data (see§ 
concentrations 63.10007( e )). 
to 30 boiler 
operating day 
rolling 
average 
lb/MMBtuor 
lb/MWh 
em1ss1ons 
rates 
2. Total or Emissions a. Select Method 1 at appendix A-1 to part 60 ofthis 
individual Testing sampling ports chapter. 
non-Hg HAP location and 
metals the number of 
traverse points 
b. Determine Method 2, 2A, 2C, 2F, 2G or 2H at appendix A-
velocity and 1 or A-2 to part 60 of this chapter. 
volumetric 
flow-rate of 
the stack gas 
c. Determine Method 3A or 3B at appendix A-2 to part 60 of 
oxygen and this chapter, or ANSI/ASME PTC 19.10-1981. 3 
carbon 
dioxide 
concentrations 
of the stack 
gas 
d. Measure the Method 4 at appendix A-3 to part 60 of this 
moisture chapter. 
content of the 
stack gas 
e. Measure the Method 29 at appendix A-8 to part 60 of this 
HAP metals chapter. For liquid oil-fired units, Hg is 
em1ss1ons included in HAP metals and you may use 
concentrations Method 29, Method 30B at appendix A-8 to 
and determine part 60 of this chapter; for Method 29, you must 38585 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
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ER07MY24.103</GPH>khammond on DSKJM1Z7X2PROD with RULES4each report the front half and back half results 
individual separately. When using Method 29, report 
HAP metals metals matrix spike and recovery levels. 
em1ss1ons 
concentration, 
as well as the 
total filterable 
HAP metals 
em1ss1ons 
concentration 
and total HAP 
metals 
em1ss1ons 
concentration 
f. Convert Method 19 F-factor methodology at appendix 
em1ss1ons A-7 to part 60 of this chapter, or calculate using 
concentrations mass emissions rate and gross output data (see§ 
(individual 63.10007( e )). 
HAP metals, 
total filterable 
HAP metals, 
and total HAP 
metals) to 
lb/MMBtuor 
lb/MWh 
em1ss1ons 
rates 
3. Hydrogen Emissions a. Select Method 1 at appendix A-1 to part 60 of this 
chloride Testing sampling ports chapter. 
(HCl) and location and 
hydrogen the number of 
fluoride (HF) traverse points 
b. Determine Method 2, 2A, 2C, 2F, 2G or 2H at appendix A-
velocity and 1 or A-2 to part 60 of this chapter. 
volumetric 
flow-rate of 
the stack gas 
c. Determine Method 3A or 3B at appendix A-2 to part 60 of 
oxygen and this chapter, or ANSI/ASME PTC 19.10-1981.3 
carbon dioxide concentrations 
of the stack 
gas 
d. Measure the Method 4 at appendix A-3 to part 60 of this 
moisture chapter. 
content of the 
stack gas 
e. Measure the Method 26 or Method 26A at appendix A-8 to 
HCl and HF part 60 of this chapter or Method 320 at 38586 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
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HCl 
and/or HF 
CEMS emissions 
concentrations 
f. Convert 
emissions 
concentration 
to lb/MMBtu 
orlb/MWh 
em1ss10ns 
rates 
OR 
a. Install, 
certify, 
operate, and 
maintain the 
HCl or HF 
CEMS 
b. Install, 
certify, 
operate, and 
maintain the 
diluent gas, 
flow rate, 
and/or 
moisture appendix A to part 63 of this chapter or ASTM 
D6348-03 Rea roved 20103 with 
(1) the following conditions when using ASTM 
D6348-03 Rea roved 2010: 
(A) The test plan preparation and 
implementation in the Annexes to ASTM 
D6348-03 Reapproved 2010, Sections Al 
throu h A8 are mandato ; 
(B) For ASTM D6348-03 Reapproved 2010 
Annex A5 (Analyte Spiking Technique), the 
percent (%) R must be determined for each 
tar et anal te see E uation A5.5 ; 
(C) For the ASTM D6348-03 Reapproved 
2010 test data to be acceptable for a target 
anal te, %R must be 70% ~R :Sl 30%; and 
(D) The %R value for each compound must be 
reported in the test report and all field 
measurements corrected with the calculated %R 
value for that compound using the following 
e uation: 
(2) spiking levels nominally no greater than two 
times the level corresponding to the applicable 
emission limit. 
Method 26A must be used if there are entrained 
water dro lets in the exhaust stream. 
Method 19 F-factor methodology at appendix 
A-7 to part 60 of this chapter, or calculate using 
mass emissions rate and gross output data (see§ 
63.10007(e)). 
Appendix B of this subpart. 
Part 75 of this chapter and§ 63.l00l0(a), (b), 
(c), and (d). 38587 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
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ER07MY24.105</GPH>khammond on DSKJM1Z7X2PROD with RULES4monitoring 
systems 
c. Convert Method 19 F-factor methodology at appendix 
hourly A-7 to part 60 of this chapter, or calculate using 
em1ss1ons mass emissions rate and gross output data ( see § 
concentrations 63.10007(e)). 
to 30 boiler 
operating day 
rolling 
average 
lb/MMBtuor 
lb/MWh 
em1ss1ons 
rates 
4. Mercury Emissions a. Select Method 1 at appendix A-1 to part 60 of this 
(Hg) Testing sampling ports chapter or Method 30B at Appendix A-8 for 
location and Method 30B point selection. 
the number of 
traverse points 
b. Determine Method 2, 2A, 2C, 2F, 2G or 2H at appendix A-
velocity and 1 or A-2 to part 60 of this chapter. 
volumetric 
flow-rate of 
the stack gas 
c. Determine Method 3A or 3B at appendix A-1 to part 60 of 
oxygen and this chapter, or ANSI/ASME PTC 19.10-1981. 3 
carbon dioxide concentrations 
of the stack 
gas 
d. Measure the Method 4 at appendix A-3 to part 60 of this 
moisture chapter. 
content of the 
stack gas 
Method 30B at appendix A-8 to part 60 of this 
e. Measure the chapter, ASTM D6784, 3 or Method 29 at 
Hg emission appendix A-8 to part 60 of this chapter; for 
concentration Method 29, you must report the front half and 
back half results separately. 
f. Convert Method 19 F-factor methodology at appendix 
emissions A-7 to part 60 of this chapter, or calculate using 
concentration mass emissions rate and gross output data (see§ 
to lb/TBtu or 63.10007(e)). 
lb/GWh 
emission rates 
OR OR 
HgCEMS a. Install, Sections3.2.1 and5.1 ofappendixAofthis 
certify, subpart. 
operate, and 38588 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
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CEMS 
b. Install, Part 75 of this chapter and§ 63.l00l0(a), (b), 
certify, (c), and (d). 
operate, and 
maintain the 
diluent gas, 
flow rate, 
and/or 
moisture 
monitoring 
systems 
c. Convert Section 6 of appendix A to this subpart. 
hourly 
em1ss1ons 
concentrations 
to 30 boiler 
operating day 
rolling 
average 
lb/TBtu or 
lb/GWh 
em1ss1ons 
rates 
OR OR 
Sorbent a. Install, Sections 3.2.2 and 5.2 of appendix A to this 
trap certify, subpart. 
monitoring operate, and 
system maintain the 
sorbent trap 
monitoring 
system 
b. Install, Part 75 of this chapter and§ 63.l00l0(a), (b), 
operate, and (c), and (d). 
maintain the 
diluent gas, 
flow rate, 
and/or 
moisture 
monitoring 
systems 
c. Convert Section 6 of appendix A to this subpart. 
em1ss1ons 
concentrations 
to 30 boiler 
operating day 
rolling 
average 
lb/TBtu or 
lb/GWh 38589 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
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ER07MY24.107</GPH>khammond on DSKJM1Z7X2PROD with RULES4emissions 
rates 
OR OR 
LEE a. Select Single point located at the 10% centroidal area 
testing sampling ports of the duct at a port location per Method 1 at 
location and appendix A-1 to part 60 of this chapter or 
the number of Method 30B at Appendix A-8 for Method 30B 
traverse points point selection. 
b. Determine Method 2, 2A, 2C, 2F, 2G, or 2H at appendix 
velocity and A-1 or A-2 to part 60 of this chapter or flow 
volumetric monitoring system certified per appendix A of 
flow-rate of this subpart. 
the stack gas 
c. Determine Method 3A or 3B at appendix A-1 to part 60 of 
oxygen and this chapter, or ANSI/ASME PTC 19.10-1981, 3 
carbon or diluent gas monitoring systems certified 
dioxide according to part 75 of this chapter. 
concentrations 
of the stack 
gas 
d. Measure the Method 4 at appendix A-3 to part 60 of this 
moisture chapter, or moisture monitoring systems 
content of the certified according to part 75 of this chapter. 
stack gas 
Method 30B at appendix A-8 to part 60 of this 
e. Measure the chapter; perform a 30 operating day test, with a 
Hg emission maximum of 10 operating days per run (i.e., per 
concentration pair of sorbent traps) or sorbent trap monitoring 
system or Hg CEMS certified per appendix A of 
this subpart. 
f. Convert Method 19 F-factor methodology at appendix 
em1ss10ns A-7 to part 60 of this chapter, or calculate using 
concentrations mass emissions rate and gross output data (see§ 
from the LEE 63.10007(e)). 
test to lb/TBtu 
or lb/GWh 
em1ss10ns 
rates 
g. Convert Potential maximum annual heat input in TBtu 
average or potential maximum electricity generated in 
lb/TBtu or GWh. 
lb/GWhHg 
emission rate 
to lb/year, if 
you are 
attempting to 
meet the 29.0 
lb/year 
threshold 38590 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
BILLING CODE 6560–50–C 
1Regarding emissions data collected 
during periods of startup or shutdown, see 
§§ 63.10020(b) and (c) and 63.10021(h). With the exception of IGCC units, on or after July 
6, 2027: You may not use quarterly performance emissions testing to demonstrate compliance with the filterable PM emissions standards and for existing EGUs you may not choose to comply with the total or individual HAP metals emissions limits unless you request and receive 
approval for the use of a HAP metals CMS under § 63.7(f). 
2See tables 1 and 2 to this subpart for 
required sample volumes and/or sampling run times. 
3Incorporated by reference, see § 63.14. 
■23. Revise table 6 to subpart UUUUU 
of part 63 to read as follows: Table 6 to Subpart UUUUU of Part 63— 
Establishing PM CPMS Operating Limits 
Before July 6, 2027, as stated in 
§ 63.10007, you must comply with the following requirements for establishing operating limits in table 6. However, on or after July 6, 2027 you may not use PM CPMS for compliance demonstrations, unless it is for an IGCC unit. 
If you have an 
applicable emission limit for . . . And you choose to establish PM CPMS operating limits, you must . . . And . . . Using . . . According to the following procedures . . . 
Filterable Particulate 
matter (PM), total 
non-mercury HAP metals, individual non-mercury HAP metals, total HAP metals, or individual HAP metals for an EGU.Install, certify, maintain, and 
operate a PM CPMS for monitoring emissions dis-charged to the atmosphere according to § 63.10010(h)(1).Establish a site-spe-
cific operating limit in units of PM CPMS output sig-nal (e.g., milliamps, mg/ acm, or other raw signal).Data from the PM 
CPMS and the PM or HAP metals performance tests.1. Collect PM CPMS output data during 
the entire period of the performance tests. 
2. Record the average hourly PM CPMS 
output for each test run in the perform-ance test. 
3. Determine the PM CPMS operating 
limit in accordance with the require-ments of § 63.10023(b)(2) from data obtained during the performance test demonstrating compliance with the fil-terable PM or HAP metals emissions limitations. 
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ER07MY24.108</GPH>khammond on DSKJM1Z7X2PROD with RULES45. Sulfur SO2 a. Install, Part 75 of this chapter and§ 63.lO0I0(a) and 
dioxide (SO2) CEMS certify, (f). 
operate, and 
maintain the 
CEMS 
b. Install, Part 75 of this chapter and§ 63.lO0lO(a), (b), 
operate, and (c), and (d). 
maintain the 
diluent gas, 
flow rate, 
and/or 
moisture 
monitoring 
systems 
c. Convert Method 19 F -factor methodology at appendix 
hourly A-7 to part 60 of this chapter, or calculate using 
em1ss10ns mass emissions rate and gross output data (see§ 
concentrations 63.10007(e)). 
to 30 boiler 
operating day 
rolling 
average 
lb/MMBtuor 
lb/MWh 
em1ss10ns 
rates 38591 Federal Register / Vol. 89, No. 89 / Tuesday, May 7, 2024 / Rules and Regulations 
■24. Revise table 7 to subpart UUUUU 
of part 63 to read as follows: Table 7 to Subpart UUUUU of Part 63— 
Demonstrating Continuous Compliance 
As stated in § 63.10021, you must 
show continuous compliance with the emission limitations for affected sources 
according to the following: 
If you use one of the following to meet applicable emissions limits, op-
erating limits, or work practice standards . . . You demonstrate continuous compliance by . . . 
1. CEMS to measure filterable PM, SO 2, HCl, HF, or Hg emissions, or 
using a sorbent trap monitoring system to measure Hg.Calculating the 30- (or 90-) boiler operating day rolling arithmetic aver-
age emissions rate in units of the applicable emissions standard 
basis at the end of each boiler operating day using all of the quality assured hourly average CEMS or sorbent trap data for the previous 30- (or 90-) boiler operating days, excluding data recorded during periods of startup or shutdown. 
2. PM CPMS to measure compliance with a parametric operating limit. 
(On or after July 6, 2027 you may not use PM CPMS for compliance demonstrations, unless it is for an IGCC unit.).Calculating the 30- (or 90-) boiler operating day rolling arithmetic aver-
age of all of the quality assured hourly average PM CPMS output data (e.g., milliamps, PM concentration, raw data signal) collected for 
all operating hours for the previous 30- (or 90-) boiler operating days, excluding data recorded during periods of startup or shutdown. 
3. Site-specific monitoring using CMS for liquid oil-fired EGUs for HCl 
and HF emission limit monitoring.If applicable, by conducting the monitoring in accordance with an ap-
proved site-specific monitoring plan. 
4. Quarterly performance testing for coal-fired, solid oil derived fired, or 
liquid oil-fired EGUs to measure compliance with one or more non- PM (or its alternative emission limits) applicable emissions limit in Table 1 or 2, or PM (or its alternative emission limits) applicable emissions limit in Table 2. (On or after July 6, 2027 you may not use quarterly performance testing for filterable PM compliance dem-onstrations, unless it is for an IGCC unit.).Calculating the results of the testing in units of the applicable emis-
sions standard. 
5. Conducting periodic performance tune-ups of your EGU(s) ............... Conducting periodic performance tune-ups of your EGU(s ), as speci-
fied in § 63.10021(e). 
6. Work practice standards for coal-fired, liquid oil-fired, or solid oil-de-
rived fuel-fired EGUs during startup.Operating in accordance with Table 3. 
7. Work practice standards for coal-fired, liquid oil-fired, or solid oil-de-
rived fuel-fired EGUs during shutdown.Operating in accordance with Table 3. 
■25. Revise table 8 to subpart UUUUU 
of part 63 to read as follows: Table 8 to Subpart UUUUU of Part 63— 
Reporting Requirements 
[In accordance with 40 CFR 63.10031, 
you must meet the following reporting requirements, as they apply to your 
compliance strategy] 
You must submit the following reports . . . 
1. The electronic reports required under 40 CFR 63.10031 (a)(1), if you continuously monitor Hg emissions. 
2. The electronic reports required under 40 CFR 63.10031 (a)(2), if you continuously monitor HCl and/or HF emissions. 
Where applicable, these reports are due no later than 30 days after the end of each calendar quarter. 
3. The electronic reports required under 40 CFR 63.10031(a)(3), if you continuously monitor PM emissions. 
Reporting of hourly PM emissions data using ECMPS shall begin with the first operating hour after: January 1, 2024, or the hour of comple-
tion of the initial PM CEMS correlation test, whichever is later. 
Where applicable, these reports are due no later than 30 days after the end of each calendar quarter. 
4. The electronic reports required under 40 CFR 63.10031(a)(4), if you elect to use a PM CPMS (on or after July 6, 2027 you may not use PM 
CPMS for compliance demonstrations, unless it is for an IGCC unit). 
Reporting of hourly PM CPMS response data using ECMPS shall begin with the first operating hour after January 1, 2024, or the first oper-
ating hour after completion of the initial performance stack test that establishes the operating limit for the PM CPMS, whichever is later. 
Where applicable, these reports are due no later than 30 days after the end of each calendar quarter. 
5. The electronic reports required under 40 CFR 63.10031(a)(5), if you continuously monitor SO 2emissions. 
Where applicable, these reports are due no later than 30 days after the end of each calendar quarter. 
6. PDF reports for all performance stack tests completed prior to January 1, 2024 (including 30- or 90-boiler operating day Hg LEE test reports 
and PM test reports to set operating limits for PM CPMS), according to the introductory text of 40 CFR 63.10031(f) and 40 CFR 
63.10031(f)(6). 
For each test, submit the PDF report no later than 60 days after the date on which testing is completed. 
For a PM test that is used to set an operating limit for a PM CPMS, the report must also include the information in 40 CFR 
63.10023(b)(2)(vi). 
For each performance stack test completed on or after January 1, 2024, submit the test results in the relevant quarterly compliance report 
under 40 CFR 63.10031(g), together with the applicable reference method information in sections 17 through 31 of appendix E to this 
subpart. 
7. PDF reports for all RATAs of Hg, HCl, HF, and/or SO 2monitoring systems completed prior to January 1, 2024, and for correlation tests, 
RRAs and/or RCAs of PM CEMS completed prior to January 1, 2024, according to 40 CFR 63.10031(f)(1) and (6). 
For each test, submit the PDF report no later than 60 days after the date on which testing is completed. For each SO
2or Hg system RATA completed on or after January 1, 2024, submit the electronic test summary required by appendix A to 
this subpart or part 75 of this chapter (as applicable) together with the applicable reference method information in sections 17 through 30 
of appendix E to this subpart, either prior to or concurrent with the relevant quarterly emissions report. 
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You must submit the following reports . . . 
For each HCl or HF system RATA, and for each correlation test, RRA, and RCA of a PM CEMS completed on or after January 1, 2024,  
submit the electronic test summary in accordance with section 11.4 of appendix B to this subpart or section 7.2.4 of appendix C to this 
part, as applicable, together with the applicable reference method information in sections 17 through 30 of appendix E to this subpart. 
8. Quarterly reports, in PDF files, that include all 30-boiler operating day rolling averages in the reporting period derived from your PM CEMS, 
approved HAP metals CMS, and/or PM CPMS (on or after July 6, 2027 you may not use PM CPMS, unless it is for an IGCC unit), acco rding 
to 40 CFR 63.10031(f)(2) and (6). These reports are due no later than 60 days after the end of each calendar quarter. 
The final quarterly rolling averages report in PDF files shall cover the fourth calendar quarter of 2023. Starting with the first quarter of 2024, you must report all 30-boiler operating day rolling averages for PM CEMS, approved HAP metals 
CMS, PM CPMS, Hg CEMS, Hg sorbent trap systems, HCl CEMS, HF CEMS, and/or SO
2CEMS (or 90-boiler operating day rolling aver-
ages for Hg systems), in XML format, in the quarterly compliance reports required under 40 CFR 63.10031(g). 
If your EGU or common stack is in an averaging plan, each quarterly compliance report must identify the EGUs in the plan and include all 
of the 30- or 90-group boiler operating day WAERs for the averaging group. 
The quarterly compliance reports must be submitted no later than 60 days after the end of each calendar quarter. 
9. The semiannual compliance reports described in 40 CFR 63.10031(c) and (d), in PDF files, according to 40 CFR 63.10031(f)(4) and (6). The 
due dates for these reports are specified in 40 CFR 63.10031(b). 
The final semiannual compliance report shall cover the period from July 1, 2023, through December 31, 2023. 
10. Notifications of compliance status, in PDF files, according to 40 CFR 63.10031(f)(4) and (6) until December 31, 2023, and according to 40 
CFR 63.10031(h) thereafter. 
11. Quarterly electronic compliance reports, in accordance with 40 CFR 63.10031(g), starting with a report for the first calendar quarter of 2024. 
The reports must be in XML format and must include the applicable data elements in sections 2 through 13 of appendix E to this subpart. 
These reports are due no later than 60 days after the end of each calendar quarter. 
12. Quarterly reports, in PDF files, that include the applicable information in 40 CFR 63.10031(c)(5)(ii) and 40 CFR 63.10020(e) pertaining to 
startup and shutdown events, starting with a report for the first calendar quarter of 2024, if you have elected to use paragraph 2 of the defini-tion of startup in 40 CFR 63.10042 (see 40 CFR 63.10031(i)). On or after January 2, 2025 you may not use paragraph 2 of the definition of startup in 40 CFR 63.10042. 
These PDF reports shall be submitted no later than 60 days after the end of each calendar quarter, along with the quarterly compliance re-
ports required under 40 CFR 63.10031(g). 
13. A test report for the PS 11 correlation test of your PM CEMS, in accordance with 40 CFR 63.10031(j). 
If, prior to November 9, 2020, you have begun using a certified PM CEMS to demonstrate compliance with this subpart, use the EC MPS 
Client Tool to submit the report, in a PDF file, no later than 60 days after that date. 
For correlation tests completed on or after November 9, 2020, but prior to January 1, 2024, submit the report, in a PDF file, no later than 
60 days after the date on which the test is completed. 
For correlation tests completed on or after January 1, 2024, submit the test results electronically, according to section 7.2.4 of appendix C 
to this subpart, together with the applicable reference method data in sections 17 through 31 of appendix E to this subpart. 
14. Quarterly reports that include the QA/QC activities for your PM CPMS (on or after July 6, 2027 you may not use PM CPMS, unless it is for 
an IGCC unit) or approved HAP metals CMS (as applicable), in PDF files, according to 40 CFR 63.10031(k). 
The first report shall cover the first calendar quarter of 2024, if the PM CPMS or HAP metals CMS is in use during that quarter. Otherwise, 
reporting begins with the first calendar quarter in which the PM CPMS or HAP metals CMS is used to demonstrate compliance. 
These reports are due no later than 60 days after the end of each calendar quarter. 
■26. In appendix C to subpart UUUUU: 
■a. Revise sections 1.2, 1.3, 4.1, and 
4.1.1. 
■b. Add sections 4.1.1.1 and 4.2.3. 
■c. Revise sections 5.1.1, 5.1.4, and the 
section heading for section 6. 
The revisions and additions read as 
follows: 
Appendix C to Subpart UUUUU of Part 
63—PM Monitoring Provisions 
1. General Provisions 
* * * * * 
1.2 Initial Certification and 
Recertification Procedures. You, as the owner 
or operator of an affected EGU that uses a PM CEMS to demonstrate compliance with a filterable PM emissions limit in Table 1 or 2 to this subpart must certify and, if applicable, recertify the CEMS according to Performance Specification 11 (PS–11) in appendix B to part 60 of this chapter. Beginning on July 6, 2027, when determining if your PM CEMS meets the acceptance criteria in PS–11, the value of 0.015 lb/MMBtu is to be used in place of the applicable emission standard, or emission limit, in the calculations. 
1.3 Quality Assurance and Quality 
Control Requirements. You must meet the applicable quality assurance requirements of 
Procedure 2 in appendix F to part 60 of this chapter. Beginning on July 6, 2027, when 
determining if your PM CEMS meets the acceptance criteria in Procedure 2, the value of 0.015 lb/MMBtu is to be used in place of the applicable emission standard, or emission limit, in the calculations. 
* * * * * 
4. Certification and Recertification 
Requirements 
4.1 Certification Requirements. You must 
certify your PM CEMS and the other CMS 
used to determine compliance with the applicable emissions standard before the PM CEMS can be used to provide data under this subpart. However, if you have developed and are using a correlation curve, you may continue to use that curve, provided it continues to meet the acceptance criteria in PS–11 and Procedure 2 as discussed below. Redundant backup monitoring systems (if used) are subject to the same certification requirements as the primary systems. 
4.1.1 PM CEMS. You must certify your 
PM CEMS according to PS–11 in appendix B 
to part 60 of this chapter. A PM CEMS that has been installed and certified according to PS–11 as a result of another state or federal regulatory requirement or consent decree prior to the effective date of this subpart shall be considered certified for this subpart if you can demonstrate that your PM CEMS meets the acceptance criteria in PS–11 and 
Procedure 2 in appendix F to part 60 of this chapter. 
4.1.1.1 Beginning on July 6, 2027, when 
determining if your PM CEMS meets the acceptance criteria in PS–11 and Procedure 2 the value of 0.015 lb/MMBtu is to be used in place of the applicable emission standard, or emission limit, in the calculations. 
* * * * * 
4.2 Recertification. 
* * * * * 
4.2.3 Beginning on July 6, 2027 you must 
use the value of 0.015 lb/MMBtu in place of 
the applicable emission standard, or emission limit, in the calculations when determining if your PM CEMS meets the acceptance criteria in PS–11 and Procedure 2. 
* * * * * 
5. Ongoing Quality Assurance (QA) and Data Validation 
* * * * * 
5.1.1 Required QA Tests. Following 
initial certification, you must conduct periodic QA testing of each primary and (if applicable) redundant backup PM CEMS. The required QA tests and the criteria that must be met are found in Procedure 2 of appendix F to part 60 of this chapter 
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(Procedure 2). Except as otherwise provided 
in section 5.1.2 of this appendix, the QA tests shall be done at the frequency specified in Procedure 2. 
* * * * * 
5.1.4 RCA and RRA Acceptability. The 
results of your RRA or RCA are considered acceptable provided that the criteria in section 10.4(5) of Procedure 2 in appendix F 
to part 60 of this chapter are met for an RCA or section 10.4(6) of Procedure 2 in appendix F to part 60 of this chapter are met for an RRA. However, beginning on July 6, 2027 a value of 0.015 lb/MMBtu is to be used in 
place of the applicable emission standard, or emission limit, when determining whether the RCA and RRA are acceptable. 
* * * * * 
6. Data Reduction and Calculations 
* * * * * 
■27. Appendix D to subpart UUUUU of 
part 63 is amended by adding 
introductory text to the appendix to read as follows: Appendix D to Subpart UUUUU of Part 
63—PM CPMS Monitoring Provisions 
On or after July 6, 2027 you may not use 
PM CPMS for compliance demonstrations 
with the applicable filterable PM emissions limits, unless it is for an IGCC unit. 
* * * * * 
[FR Doc. 2024–09148 Filed 5–6–24; 8:45 am] 
BILLING CODE 6560–50–P 
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