[Federal Register Volume 89, Number 89 (Tuesday, May 7, 2024)]
[Rules and Regulations]
[Pages 38508-38593]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-09148]
[[Page 38507]]
Vol. 89
Tuesday,
No. 89
May 7, 2024
Part IV
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants: Coal- and
Oil-Fired Electric Utility Steam Generating Units Review of the
Residual Risk and Technology Review; Final Rule
Federal Register / Vol. 89 , No. 89 / Tuesday, May 7, 2024 / Rules
and Regulations
[[Page 38508]]
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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.
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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:
[email protected].
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\0\ elemental Hg vapor
Hg\2+\ divalent Hg
HgCl2 mercuric chloride
Hgp particulate 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
NOX nitrogen oxides
NRECA National Rural Electric Cooperative Association
OMB Office of Management and Budget
PM particulate matter
PM2.5 fine 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-CO2 social cost of carbon
SO2 sulfur 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?
[[Page 38509]]
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 \1\ of HAP
that ``require the maximum degree of reduction in emissions of the
hazardous air pollutants . . . (including a prohibition on such
emissions, where achievable) that the Administrator, taking into
consideration the cost of achieving such emission reduction, and any
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).
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\1\ The 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).
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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
[[Page 38510]]
metals, the EPA established individual emission limits for each of the
10 non-Hg HAP metals \2\ emitted 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).
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\2\ The ten non-Hg HAP metals are antimony, arsenic, beryllium,
cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
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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 \3\ can 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.
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\3\ In 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.
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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).
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\4\ The 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.
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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
(SO2) emission standard), which serves as a surrogate for
all acid gas HAP (HCl, hydrogen fluoride (HF), selenium dioxide
(SeO2)) 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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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 (PM2.5) and ozone
and climate benefits from reductions in carbon dioxide (CO2)
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.\5\ In addition, due to data limitations, the EPA
is also unable to quantify potential emissions impacts or monetize
potential benefits from continuous monitoring requirements.
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\5\ See 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).
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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.
[[Page 38512]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.066
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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
[[Page 38513]]
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.'' \6\ In certain instances, as provided in CAA
section 112(h), the EPA may set work practice standards in lieu of
numerical emission standards. The EPA must also consider control
options that are more stringent than the floor. Standards more
stringent than the floor are commonly referred to as ``beyond-the-
floor'' standards. For area sources, CAA section 112(d)(5) allows the
EPA to set standards based on generally available control technologies
or management practices (GACT standards) in lieu of MACT standards.\7\
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\6\ Specifically, for existing sources, the MACT ``floor'' shall
not be less stringent than the average emission reduction achieved
by the best performing 12 percent of existing sources. 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.
\7\ For categories of area sources subject to GACT standards,
there is no requirement to address residual risk, but, similar to
the major source categories, the technology review is required.
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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
[[Page 38514]]
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\
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\8\ Congress 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).
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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
[[Page 38515]]
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
SO2 that may be used as a surrogate for acid gas HAP for
those coal-fired EGUs with flue gas desulfurization (FGD) systems and
SO2 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.\9\ Methylmercury 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.
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\9\ U.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).
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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.
[[Page 38516]]
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
[[Page 38517]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.067
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
(SO2, 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
[[Page 38518]]
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\
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\10\ See Document ID No. EPA-HQ-OAR-2018-0794-4565 at https://www.regulations.gov.
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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.
[[Page 38519]]
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.\11\ The EPA's Office of
Enforcement and Compliance Assurance (OECA) also issued the MATS
Enforcement Response policy (Dec. 16, 2011) \12\ which 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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\11\ 77 FR 9406.
\12\ https://www.epa.gov/enforcement/enforcement-response-policy-mercury-and-air-toxics-standard-mats.
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[[Page 38520]]
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
[[Page 38521]]
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.
---------------------------------------------------------------------------
\13\ Technical 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.
---------------------------------------------------------------------------
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
[[Page 38522]]
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.
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\14\ For 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.
---------------------------------------------------------------------------
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,\15\
the 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.
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\15\ Petroleum Refinery Sector Risk and Technology Review and
New Source Performance Standards, 80 FR 75178, 75201 (December 1,
2015).
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In the Iron Ore Processing technology review,\16\ the 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.
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\16\ National Emission Standards for Hazardous Air Pollutants:
Taconite Iron Ore Processing Residual Risk and Technology Review, 85
FR 45476, 45483 (July 28, 2020).
---------------------------------------------------------------------------
In the Integrated Iron and Steel Manufacturing Facilities
technology review,\17\ the 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.
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\17\ National Emission Standards for Hazardous Air Pollutants:
Integrated Iron and Steel Manufacturing Facilities Residual Risk and
Technology Review, 85 FR 42074, 42088 (July 13, 2020).
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In the Portland Cement Manufacturing beyond-the-floor
analysis,\18\ the 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.
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\18\ National 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).
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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
[[Page 38523]]
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 \19\ that 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 PM2.5 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 PM2.5 reduced to be cost-effective for the ferroalloys
production source category \20\ and proposed a limit for secondary lead
smelting sources that cost an inflation-adjusted $114,000 per ton of
fPM reduced.\21\ They 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 PM2.5 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.
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\19\ Assessment 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.
\20\ National Emission Standards for Hazardous Air Pollutants:
Ferroalloys Production, 80 FR 37381 (June 30, 2015).
\21\ National Emission Standards for Hazardous Air Pollutants:
Secondary Lead Smelting, 76 FR 29032 (May 19, 2011).
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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
[[Page 38524]]
a rule cost-effective or not.\22\ The 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.\23\ In
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.
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\22\ See 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.'').
\23\ National Emission Standards for Hazardous Air Pollutants:
Ferroalloys Production, 79 FR 60238, 60273 (October 6, 2014).
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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.\24\ Here 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,\25\ even 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.\26\ Likewise, 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.\27\ Here, the EPA estimates
significantly greater HAP emission reductions, and fPM emission
reductions that are orders of magnitude greater than both prior
rulemakings.\28\
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\24\ Petroleum Refinery Sector Risk and Technology Review and
New Source Performance Standards, 80 FR 75178, 75201 (December 1,
2015).
\25\ 2020 National Emissions Inventory (NEI) Data; https://www.epa.gov/air-emissions-inventories/2020-national-emissions-inventory-nei-data.
\26\ National Emission Standards for Hazardous Air Pollutants:
Integrated Iron and Steel Manufacturing Facilities Residual Risk and
Technology Review, 85 FR 42074, 42088 (July 13, 2020).
\27\ National 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).
\28\ In 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).
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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
[[Page 38525]]
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).\29\
The 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).'' \30\ While the EPA has considered risks as a
factor in some previous technology reviews,\31\ that 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\
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\29\ See, 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).
\30\ National 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).
\31\ See, 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).
\32\ National Emissions Standards for Hazardous Air Pollutants:
Secondary Lead Smelting, 77 FR 556, 564 (January 5, 2012).
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The language and structure of CAA section 112, along with its
legislative history, further underscores the independent nature of
these two provisions.\33\ While 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
[[Page 38526]]
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.
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\33\ See section II.A.2. above for further discussion of the
statutory structure and legislative history of CAA section 112.
---------------------------------------------------------------------------
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 . . . . At 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.\34\ As 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
[[Page 38527]]
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.
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\34\ The 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).
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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,\35\ where the EPA proposed that EGUs that elect to shut down by
January 1, 2032, must maintain their recent historical carbon dioxide
(CO2) 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\
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\35\ 88 FR 33245 (May 23, 2023).
\36\ 88 FR 18824, 18837 (March 29, 2023).
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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 \37\ have 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.
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\37\ In 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.
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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
[[Page 38528]]
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 \38\ provides strong evidence that PM
CEMS can be used effectively to measure low levels of PM emissions.
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\38\ Analysis 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.
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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 SO2 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,\39\ over 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.\40\ The 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
[[Page 38529]]
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,\41\ the 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.
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\39\ Assessment 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.
\40\ See 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.
\41\ See 88 FR 24872.
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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, SeO2). 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.\42\
The 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
[[Page 38530]]
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.
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\42\ As 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.
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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, SeO2).
In conducting this technology review, the EPA found important
developments that informed its proposal. First, from reviewing
historical information contained in WebFIRE,\43\ the 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.\44\ For 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.
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\43\ WebFIRE includes data submitted to the EPA from the
Electronic Reporting Tool (ERT) and is searchable at https://cfpub.epa.gov/webfire/reports/esearch.cfm.
\44\ Analysis 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.
---------------------------------------------------------------------------
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.\45\ As the EPA explained in the
[[Page 38531]]
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.
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\45\ EPA'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 exposure to cause adverse
acute (or short-term) noncancer health effects.
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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.\46\
Indeed, 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.
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\46\ See, 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.'').
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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,\47\ EGUs
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.\48\ As 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].''
---------------------------------------------------------------------------
\47\ See figure 4 of the 2024 Technical Memo.
\48\ See Document CLT-1T Testimony, CLT-11, and CL-12 in Docket
190882 at https://www.utc.wa.gov/documents-and-proceedings/dockets.
\49\ See 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.
\50\ For reference, a dekatherm is equivalent to one million
Btus (MMBtu).
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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\
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\51\ See Document ID No. EPA-HQ-OAR-2018-5984 at https://www.regulations.gov.
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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
[[Page 38532]]
operational in 2028 (see section 3 of the RIA for this final rule).
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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).\52\ As much of the
[[Page 38533]]
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.
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\52\ See, 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, 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).
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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.\54\ Revenues
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.
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\53\ See Cost TSD for 2022 Proposal at Document ID No. EPA-HQ-
OAR-2018-0794-4620 at https://www.regulations.gov.
\54\ 2019 dollars were used for consistency with the 2023
Proposal.
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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
[[Page 38534]]
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).
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\55\ See note 50, above, for examples of other costs metrics the
EPA has considered in prior CAA section 112 rulemakings.
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The power sector also operates differently than other industries
regulated under CAA section 112.\56\ For 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.
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\56\ This 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.
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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 \57\ and 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.
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\57\ Run 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).
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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
[[Page 38535]]
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,\58\ the
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).
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\58\ The 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.
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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.\59\ PM 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.
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\59\ The 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)].
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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 \60\ is $60,270.\61\
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\60\ Method 5I is one of the EPA's reference test methods for
PM. See 40 CFR part 60, appendix A.
\61\ See Revised Estimated Non-Beta Gauge PM CEMS and Filterable
PM Testing Costs memorandum, available in the docket.
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In choosing a compliance demonstration requirement, the EPA
considers multiple factors, including
[[Page 38536]]
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\
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\62\ See 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.
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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
[[Page 38537]]
than the stack test averages,\64\ which further illustrate real-life
scenarios in which fPM emissions for compliance methods may be
substantially different.
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\63\ The 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.
\64\ See 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.
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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 SO2, CO2, NOX, 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.\65\ The 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).
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\65\ The 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.
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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\
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\66\ As 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.
---------------------------------------------------------------------------
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 (SO3) in the flue gas.
[[Page 38538]]
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.
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\67\ Analysis 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.
---------------------------------------------------------------------------
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,\68\ 13
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.
---------------------------------------------------------------------------
\68\ https://www.eia.gov/electricity/data/eia923/.
---------------------------------------------------------------------------
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.
[[Page 38539]]
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 SO3 in the flue gas stream. The
commenters noted that the presence of SO3 is 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 SO3 on 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 SO3 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 ``SO3 tolerant'' Hg sorbents and other technologies
that are specifically designed for Hg capture in high SO3
flue gas environments. These advanced sorbents allow for capture of Hg
in the presence of SO3 and other challenging flue gas
environments at costs that are consistent with the use of conventional
pre-treated activated carbon sorbents.\69\ The EPA has considered the
additional information regarding the role of flue gas SO3 on
Hg control and the information on the availability of advanced
``SO3 tolerant'' 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.
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\69\ See 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.
---------------------------------------------------------------------------
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
[[Page 38540]]
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.
---------------------------------------------------------------------------
\70\ See 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.
---------------------------------------------------------------------------
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
SO2 control, selective non-catalytic reduction (SNCR) for
control of nitrogen oxides (NOX), 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,\71\ also 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.
---------------------------------------------------------------------------
\71\ Choctaw 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.
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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 SO2/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 SO2
emissions from the Coyote Station EGU (0.89 lb/MMBtu) were
approximately 10 times higher than the SO2 emissions 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.
[[Page 38541]]
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
SO3-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,
[[Page 38542]]
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.\73\ The 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.
---------------------------------------------------------------------------
\72\ Technical Support Document ``1998 ICR Coal Data Analysis
Summary of Findings'' available in the rulemaking docket at EPA-HQ-
OAR-2018-0794.
\73\ In 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/.
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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.
[[Page 38543]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.069
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.
[GRAPHIC] [TIFF OMITTED] TR07MY24.070
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
[[Page 38544]]
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
[GRAPHIC] [TIFF OMITTED] TR07MY24.071
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.
[[Page 38545]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.072
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\0\ vapor in the high-temperature regions of the boiler. Hg\0\ vapor
is difficult to capture because it is typically nonreactive and
insoluble in aqueous solutions. However, under certain conditions, the
Hg\0\ vapor in the flue gas can be oxidized to divalent Hg (Hg\2+\).
The Hg\2+\ can bind to the surface of solid particles (e.g., fly ash,
injected sorbents) in the flue gas stream, often referred to as
``particulate bound Hg'' (Hgp) 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 (HgCl2) at flue gas cleaning temperatures.
However, Hg\0\ 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\, Hg\2+\ compounds, and Hgp.
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 HgCl2, 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\0\ and 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\0\
vapor 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
[[Page 38546]]
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 SO3 on 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 SO3 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
SO2, and only a small portion is further oxidized to
SO3 in the boiler. In response to environmental
requirements, many EGUs have installed SCR systems for NOX
control and FGD systems for SO2 control. One potential
consequence of an SCR retrofit is an increase in the amount of
SO3 in the flue gas downstream of the SCR due to catalytic
oxidation of SO2. Fly ash and condensed SO3 are
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 SO3 levels
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 NOX control.
Several lignite-fired EGUs utilize SNCR systems for NOX
control, which are less effective for NOX control as
compared to SCR systems. Several commenters claimed that SCR is not a
viable NOX 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 SO3, because a common
control strategy for SO3 is the injection of alkaline
sorbents (dry sorbent injection, DSI).
Still, as commenters correctly noted, the presence of
SO3 in 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 SO3.\74\ As noted above, coal-fired
EGUs utilizing bituminous coal--which also experience significant rates
of SO3 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.
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\74\ The 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.
---------------------------------------------------------------------------
The AECOM patented SBS InjectionTM (``sodium-based
solution'') technology has been developed for control of
SO3, 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 SO3 prior to
these devices, many of the adverse effects of SO3 can be
successfully mitigated. AECOM has more recently introduced their
patented HBS InjectionTM technology for effective Hg
oxidation and control.\75\ This new process injects halogen salt
solutions into the flue gas, which react in-situ to form halogen
species that effectively oxidize Hg. The HBS InjectionTM can
be co-injected with the SBS InjectionTM for effective
SO3 control and Hg oxidation/control.
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\75\ https://www.aecom.com/wp-content/uploads/2019/07/10_EUEC_P_PT_Brochure_HBS_InjectionTechnology_20160226_singles.pdf.
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Other vendors also offer technologies to mitigate the impact of
SO3 on 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 SO3.\76\ In testing in a bituminous coal
combustion flue gas stream containing greater than 10 ppm
SO3, 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.
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\76\ https://www.calgoncarbon.com/app/uploads/DS-FLUEST15-EIN-E1.pdf.
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Babcock & Wilcox (B&W) offers dry sorbent injection systems that
remove SO3 before the point of activated carbon sorbent
injection to mitigate the impact of SO3.\77\ Midwest Energy
Emissions Corporation (ME2C) 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. ME2C claims that their Hg control
additives and proprietary sorbent products are ``high-sulfur-tolerant
and SO3-tolerant sorbents.'' \78\
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\77\ https://www.babcock.com/assets/PDF-Downloads/Emissions-Control/E101-3200-Mercury-and-HAPs-Emissions-Control-Brochure-Babcock-Wilcox.pdf.
\78\ ME2C 2016 Corporate Brochure, available in the rulemaking
docket at EPA-HQ-OAR-2018-0794.
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Cabot Norit Activated Carbon is the largest producer of powdered
activated carbon worldwide.\79\ Cabot Norit offers different grades of
their DARCO[supreg] 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\0\ from 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 SO3.
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\79\ https://norit.com/application/power-steel-cement/power-plants.
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[[Page 38547]]
Similarly, ADA-ES offers FastPACTM Platinum 80,\80\ an
activated carbon sorbent that was specifically engineered for
SO3 tolerance and for use in applications where
SO3 levels 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 SO3. The
EPA also notes that SO3 is 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.
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\80\ https://www.advancedemissionssolutions.com/ADES-Investors/ada-products-and-services/default.aspx.
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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.
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[[Page 38548]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.073
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To determine the 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
[[Page 38549]]
be acceptable in previous rulemakings for Hg controls.\82\
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\81\ Estimated 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.
\82\ For 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.
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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
SO3 in the flue gas. This SO3 is 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 SO3 is 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 ``SO3 tolerant''
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
\83\ during 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
[[Page 38550]]
in Puerto Rico, which were among the facilities with the highest (but
acceptable) residual risk in the 2020 Residual Risk Review.\84\ The EPA
will continue to monitor the emissions from the dispatch of limited-use
liquid oil-fired EGUs--especially during extreme weather events.
---------------------------------------------------------------------------
\83\ Oil-fired EGUs burning residual fuel oil have generally
higher emission rates of HAP compared to that from the use of other
types of fuel.
\84\ See 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).
---------------------------------------------------------------------------
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 CO2 emission 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.\85\ The 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
[[Page 38551]]
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.
---------------------------------------------------------------------------
\85\ See Document ID No. EPA-HQ-OAR-2018-0794-4565 at https://www.regulations.gov.
---------------------------------------------------------------------------
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
[[Page 38552]]
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 CO2 values 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
[[Page 38553]]
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,\86\ consistent 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.\87\ In 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.
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\86\ As 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.
\87\ 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) (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).
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A. What are the affected facilities?
The EPA estimates that there are 314 coal-fired EGUs \88\ and 58
oil-fired EGUs that will be subject to this final rule by the
compliance date.
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\88\ The 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.
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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
[[Page 38554]]
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,
[[Page 38555]]
chromium, cobalt, lead, manganese, nickel, and selenium.\89\
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\89\ Note that modeled projections include total PM10
and total PM2.5. The EPA estimated non-Hg HAP metals
reductions by multiplying the ratio of non-Hg HAP metals to fPM by
modeled projections of total PM10 reductions 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 PM10 reduced 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.
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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.\90\ Table 9 of this document
presents the estimates of compliance costs for the final rule.
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\90\ Results 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.
[GRAPHIC] [TIFF OMITTED] TR07MY24.075
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,
[[Page 38556]]
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
PM2.5, SO2, NOX and CO2
nationwide. 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.\91\ Methylmercury 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
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\91\ Agency 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.
\92\ U.S. Environmental Protection Agency. Integrated Risk
Information System (IRIS) on Methylmercury. National Center for
Environmental Assessment, Office of Research and Development,
Washington, DC. 2001.
\93\ U.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.
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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
[[Page 38557]]
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
PM2.5, NOX, and SO2 nationally
throughout the year. Because NOX and SO2 are also
precursors to secondary formation of ambient PM2.5, reducing
these emissions would reduce human exposure to ambient PM2.5
throughout the year and would reduce the incidence of PM2.5-
attributable health effects. The rule is also expected to reduce ozone-
season NOX emissions nationally in most years of analysis.
In the presence of sunlight, NOX, and volatile organic
compounds (VOCs) can undergo a chemical reaction in the atmosphere to
form ozone. Reducing NOX emissions in most locations reduces
human exposure to ozone and 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 PM2.5\-\ 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 CO2
emissions. The EPA estimates the climate benefits of CO2
emission reductions expected from the final rule using estimates of the
social cost of carbon (SC-CO2) 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.\94\ The 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).\95\ The 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 \96\ that 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\
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\94\ National Academies of Sciences, Engineering, and Medicine
(National Academies). 2017. Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide. National Academies
Press.
\95\ Regulatory 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.
\96\ Supplemental 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).
\97\ https://www.epa.gov/environmental-economics/scghg-tsd-peer-review.
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Section 4.4 within the RIA for this final rulemaking provides an
overview of the methodological updates incorporated into the SC-
CO2 estimates used in this final RIA.\98\ A 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\
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\98\ Note that the RIA for the proposal of this rulemaking used
the SC-CO2 estimates 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-CO2 estimates 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-CO2 values (IWG 2021) are
presented in Appendix B of the RIA for this final rulemaking for
comparison purposes.
\99\ Supplementary 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.
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The SC-CO2 is the monetary value of the net harm to
society associated with a marginal increase in CO2 emissions
in a given year, or the benefit of avoiding that increase. In
principle, SC-CO2 includes the value of all climate change
impacts both negative and positive, including, but not limited to,
changes in net agricultural productivity, human health effects,
property damage from increased flood risk and natural disasters,
disruption of energy systems, risk of conflict, environmental
migration, and the value of ecosystem services. The SC-CO2,
therefore, reflects the societal value of reducing emissions of
CO2 by one metric ton and is the theoretically appropriate
value to use in conducting benefit-cost analyses of policies that
affect CO2 emissions. In practice, data and modeling
limitations restrain the ability of SC-CO2 estimates 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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This final rule is projected to reduce PM2.5 and 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-CO2 discounted at 2 percent.\100\ Thus,
this final rule would
[[Page 38559]]
generate a PV of monetized benefits of $420 million, with an EAV of $47
million discounted at a 2 percent rate.
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\100\ Monetized climate benefits are discounted using a 2
percent discount rate, consistent with the EPA's updated estimates
of the SC-CO2. 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-CO2
estimates 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 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-CO2.
See Section 4.4 of the RIA for more discussion.
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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-CO2. 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-CO2. 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\
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\101\ See https://www.epa.gov/environmentaljustice/technical-guidance-assessing-environmental-justice-regulatory-analysis.
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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).\102\ In contrast, only the
exposure analyses, which are based on future air quality modeling, can
inform whether there will be potential EJ concerns after implementation
of the regulatory options under consideration (question 2) and whether
potential EJ concerns will be created or mitigated compared to the
baseline (question 3). While the exposure analysis can respond to all
three questions, several caveats should be noted. For example, the air
pollutant exposure metrics are limited to those used in the benefits
assessment. For ozone, that is the maximum daily 8-hour average,
averaged across the April through September warm season (AS-MO3) and
for PM2.5 that is the annual average. This ozone metric
likely smooths potential daily ozone gradients and is not directly
relatable to the National Ambient Air Quality Standards (NAAQS),
whereas the PM2.5 metric is more similar to the long-term
PM2.5 standard. The air quality modeling estimates are also
based on state 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 PM2.5
exposure burden impacts. Note, we discuss HAP and climate EJ impacts of
this action qualitatively (section 6 of the RIA).
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\102\ The baseline for proximity analyses is current population
information, whereas the baseline for ozone exposure analyses are
the future years in which the regulatory options will be implemented
(e.g., 2023 and 2026).
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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 PM2.5 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,
[[Page 38560]]
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 PM2.5
concentration 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 NO2 and SO2 emitted 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., SO2) 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
PM2.5, NOX, and SO2 nationally
throughout the year. Because NOX and SO2 are also
precursors to secondary formation of ambient PM2.5 and
because NOX is a precursor to ozone formation, reducing
these emissions would impact human exposure. Quantitative ozone and
PM2.5 exposure analyses can provide insight into all three
EJ questions, so they are performed to evaluate potential
disproportionate impacts of this rulemaking. Even though both the
proximity and exposure analyses can potentially improve understanding
of baseline EJ concerns (question 1), the two should not be directly
compared. This is because the demographic proximity analysis does not
include air quality information and is based on current, not future,
population information.
The baseline analysis of ozone and PM2.5 concentration
burden responds to question 1 from 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
PM2.5 and 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
PM2.5 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 PM2.5 concentrations than the
reference group. Therefore, also in response to question 1, there
likely are potential EJ concerns associated with ozone and
PM2.5 exposures affected by the regulatory action for
population groups of concern in the baseline. However, these baseline
exposure results have not been fully explored and additional analyses
are likely needed to understand potential implications. Due to the
small magnitude of the exposure changes across population demographics
associated with the rulemaking relative to the magnitude of the
baseline disparities, we infer that post-policy EJ ozone and
PM2.5 concentration burdens are likely to remain after
implementation of the regulatory action or alternative under
consideration (question 2).
Question 3 asks whether potential EJ concerns will be created or
mitigated as compared to the baseline. Due to the very small magnitude
of differences across demographic population post-policy ozone and
PM2.5 exposure impacts, we do not find evidence that
potential EJ concerns related to ozone and PM2.5
concentrations will be created or mitigated as compared to the
baseline.\103\
---------------------------------------------------------------------------
\103\ Please note that results for ozone and PM2.5
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.
---------------------------------------------------------------------------
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 PM2.5 and ozone concentration. The projected
monetized benefits also include climate benefits due to reductions in
CO2 emissions. The projected health benefits are associated
with several point estimates and are presented at real discount rates
of 2, 3, and 7 percent. The projected climate
[[Page 38561]]
benefits in this table are based on estimates of the SC-CO2
at 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
[GRAPHIC] [TIFF OMITTED] TR07MY24.077
BILLING CODE 6560-50-C
As shown in table 11 of this document, this rule is projected to
reduce PM2.5 and 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 CO2,
producing
[[Page 38562]]
a projected PV of monetized climate benefits of about $130 million,
with an EAV of about $14 million using the SC-CO2 discounted
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\
---------------------------------------------------------------------------
\104\ Each facility is a respondent and some facilities have
multiple EGUs.
---------------------------------------------------------------------------
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
[[Page 38563]]
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
PM2.5 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
PM2.5 in 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
PM2.5 and 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 PM2.5
and 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
PM2.5 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. Hispanics, Blacks, those below
the poverty line, and uninsured populations may also experience
disproportionately higher PM2.5 concentrations 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 PM2.5 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 PM2.5 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
PM2.5 exposure 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
[[Page 38564]]
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
0
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart A--General Provisions
0
2. In Sec. 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
0
3. Section 63.9991 is amended by revising paragraph (a)(2) to read as
follows:
Sec. 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.
* * * * *
0
4. Amend Sec. 63.10000 by:
0
a. Revising paragraph (c)(1)(i) and paragraph (c)(1)(i)(A);
0
b. Redesignating paragraph (c)(1)(i)(C) as paragraph (c)(1)(i)(D);
0
c. Adding new paragraph (c)(1)(i)(C);
0
d. Revising paragraph (c)(1)(iv);
0
e. Adding new paragraphs (c)(1)(iv)(A) through (C);
0
f. Revising paragraphs (c)(2)(i) and (ii);
0
g. Revising paragraph (d)(5)(i); and
0
h. Revising paragraph (m) introductory text.
The revisions and additions read as follows:
Sec. 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
Sec. 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 Sec. 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 Sec. 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 Sec.
63.10010(h).
* * * * *
(m) Should you choose to rely on paragraph (2) of the definition of
``startup'' in Sec. 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 Sec.
63.10020(e). On and after January 2, 2025 you will no longer be able to
choose paragraph (2) of the ``startup'' definition in Sec. 63.10042.
* * * * *
[[Page 38565]]
0
5. Amend Sec. 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:
Sec. 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 Sec. 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 Sec. 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:
* * * * *
0
6. Amend Sec. 63.10006 by revising paragraph (a) to read as follows:
Sec. 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 Sec. 63.10000(c), you must conduct all applicable
performance tests according to Table 5 to this subpart and Sec.
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.
* * * * *
0
7. Amend Sec. 63.1007 by revising paragraphs (a)(3) and (c) to read as
follows:
Sec. 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 Sec. 63.10000(c), you must also establish an
operating limit according to Sec. 63.10011(b), Sec. 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 Sec. 63.7(f).
* * * * *
0
8. Amend Sec. 63.10010 by revising paragraphs (a) introductory text,
(h) introductory text, (i) introductory text, (j), and (l) introductory
text to read as follows:
Sec. 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
[[Page 38566]]
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 Sec. 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 Sec. 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 Sec. 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
Sec. 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 Sec. 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 Sec. 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 Sec. 63.10020(e). On and after January 2, 2025 you will no
longer be able to choose paragraph (2) of the ``startup'' definition in
Sec. 63.10042 for your EGU.
* * * * *
0
9. Amend Sec. 63.10011 by revising paragraphs (b), (g)(3), and (4)
introductory text to read as follows:
Sec. 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 Sec. 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) * * *
[[Page 38567]]
(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 Sec. 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 Sec. 63.10042 or you
may submit a request to use an alternative non-opacity emissions
standard, as described below.
* * * * *
0
10. Section 63.10020 is amended by revising paragraphs (e) introductory
text and (e)(3)(i) introductory text to read as follows:
Sec. 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 Sec. 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:
* * * * *
0
11. Section 63.10021 is amended by revising paragraphs (c) introductory
text and (i) to read as follows:
Sec. 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.
[GRAPHIC] [TIFF OMITTED] TR07MY24.079
Where:
Hpvi is 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.
0
12. Section 63.10022 is amended by revising paragraphs (a)(2) and (3)
to read as follows:
Sec. 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.
* * * * *
0
13. Section 63.10023 is amended by adding introductory text to the
section to read as follows:
Sec. 63.10023 How do I establish my PM CPMS operating limit and
determine compliance with it?
The provisions of this section Sec. 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.
* * * * *
0
14. Section 63.10030 is amended by revising paragraphs (e)(3), (8)
introductory text, and (8)(i) introductory text to read as follows:
[[Page 38568]]
Sec. 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 Sec. 63.10042. On or after
January 2, 2025 you may not use paragraph (2) of the definition of
startup in Sec. 63.10042.
(i) Before January 2, 2025 should you choose to rely on paragraph
(2) of the definition of ``startup'' in Sec. 63.10042 for your EGU,
you shall include a report that identifies:
* * * * *
0
15. Section 63.10031 is amended by revising paragraphs (a)(4), (c)(5)
introductory text, (f)(2), (i), and (k) to read as follows:
Sec. 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 Sec. 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 SO2,
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.
0
16. Section 63.10032 is amended by revising paragraphs (a) introductory
text and (f)(2) introductory text to read as follows:
Sec. 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 Sec. 63.10042 for your EGU (on or after January 2, 2025
you may not use paragraph (2) of the definition of startup in Sec.
63.10042), you must keep records of:
* * * * *
0
17. Section 63.10042 is amended by revising the definition ``Startup''
to read as follows:
Sec. 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
[[Page 38569]]
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.
* * * * *
0
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 Sec. 63.9991, you must comply with the following
applicable emission limits:
----------------------------------------------------------------------------------------------------------------
Using these requirements, as
You must meet the appropriate (e.g., specified
If your EGU is in this For the following following emission sampling volume or test run
subcategory . . . pollutants . . . limits and work duration) and limitations with the
practice standards test methods in Table 5 to this
. . . Subpart . . .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank a. Filterable 9.0E-2 lb/MWh \1\.. Collect a minimum catch of 6.0
virgin coal. particulate matter milligrams or a minimum sample
(PM). volume of 4 dscm per run.
OR OR
Total non-Hg HAP 6.0E-2 lb/GWh...... Collect a minimum of 4 dscm per
metals. run.
OR OR
Individual HAP ................... Collect a minimum of 3 dscm per
metals:. 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 chloride 1.0E-2 lb/MWh...... For Method 26A at appendix A-8 to
(HCl). part 60 of this chapter, collect
a minimum of 3 dscm per run. For
ASTM D6348-03(Reapproved 2010)
\2\ or Method 320 at appendix A
to part 63 of this chapter,
sample for a minimum of 1 hour.
OR
Sulfur dioxide (SO2) 1.0 lb/MWh......... SO2 CEMS.
\3\.
c. Mercury (Hg)..... 3.0E-3 lb/GWh...... Hg CEMS or sorbent trap monitoring
system only.
2. Coal-fired units low rank a. Filterable 9.0E-2 lb/MWh \1\.. Collect a minimum catch of 6.0
virgin coal. particulate matter milligrams or a minimum sample
(PM). volume of 4 dscm per run.
OR OR
Total non-Hg HAP 6.0E-2 lb/GWh...... Collect a minimum of 4 dscm per
metals. run.
OR OR
Individual HAP ................... Collect a minimum of 3 dscm per
metals:. 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 chloride 1.0E-2 lb/MWh...... For Method 26A, collect a minimum
(HCl). of 3 dscm per run For ASTM D6348-
03(Reapproved 2010) \2\ or Method
320, sample for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 1.0 lb/MWh......... SO2 CEMS.
\3\.
[[Page 38570]]
c. Mercury (Hg)..... Before July 8, Hg CEMS or sorbent trap monitoring
2024: 4.0E-2 lb/ system only.
GWh; On or after
July 8, 2024: 1.3E-
2 lb/GWh.
3. IGCC unit..................... a. Filterable 7.0E-2 lb/MWh \4\ Collect a minimum catch of 3.0
particulate matter 9.0E-2 lb/MWh \5\. milligrams or a minimum sample
(PM). volume of 2 dscm per run.
OR OR
Total non-Hg HAP 4.0E-1 lb/GWh...... Collect a minimum of 1 dscm per
metals. run.
OR OR
Individual HAP ................... Collect a minimum of 2 dscm per
metals:. 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 chloride 2.0E-3 lb/MWh...... For Method 26A, collect a minimum
(HCl). 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)
\2\ or Method 320, sample for a
minimum of 1 hour.
OR
Sulfur dioxide (SO2) 4.0E-1 lb/MWh...... SO2 CEMS.
\3\.
c. Mercury (Hg)..... 3.0E-3 lb/GWh...... Hg CEMS or sorbent trap monitoring
system only.
4. Liquid oil-fired unit-- a. Filterable 3.0E-1 lb/MWh \1\.. Collect a minimum of 1 dscm per
continental (excluding limited- particulate matter run.
use liquid oil-fired subcategory (PM).
units).
OR OR
Total HAP metals.... 2.0E-4 lb/MWh...... Collect a minimum of 2 dscm per
run.
OR OR
Individual HAP ................... Collect a minimum of 2 dscm per
metals:. 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 chapter sample
volume determination (Section
8.2.4), the estimated Hg
concentration should nominally be
<\1/2\ the standard.
b. Hydrogen chloride 4.0E-4 lb/MWh...... For Method 26A, collect a minimum
(HCl). of 3 dscm per run. For ASTM D6348-
03(Reapproved 2010) \2\ or Method
320, sample for a minimum of 1
hour.
c. Hydrogen fluoride 4.0E-4 lb/MWh...... For Method 26A, collect a minimum
(HF). of 3 dscm per run. For ASTM D6348-
03 (Reapproved 2010) \2\ or
Method 320, sample for a minimum
of 1 hour.
5. Liquid oil-fired unit--non- a. Filterable 2.0E-1 lb/MWh \1\.. Collect a minimum of 1 dscm per
continental (excluding limited- particulate matter run.
use liquid oil-fired subcategory (PM).
units).
OR OR
Total HAP metals.... 7.0E-3 lb/MWh...... Collect a minimum of 1 dscm per
run.
OR OR
Individual HAP ................... Collect a minimum of 3 dscm per
metals:. run.
Antimony (Sb)....... 8.0E-3 lb/GWh......
[[Page 38571]]
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 <\1/2\ the
standard.
b. Hydrogen chloride 2.0E-3 lb/MWh...... For Method 26A, collect a minimum
(HCl). of 1 dscm per run; for Method 26,
collect a minimum of 120 liters
per run. For ASTM D6348-03
(Reapproved 2010) \2\ or Method
320, sample for a minimum of 1
hour.
c. Hydrogen fluoride 5.0E-4 lb/MWh...... For Method 26A, collect a minimum
(HF). of 3 dscm per run. For ASTM D6348-
03 (Reapproved 2010) \2\ or
Method 320, sample for a minimum
of 1 hour.
6. Solid oil-derived fuel-fired a. Filterable 3.0E-2 lb/MWh \1\.. Collect a minimum of 1 dscm per
unit. particulate matter run.
(PM).
OR OR
Total non-Hg HAP 6.0E-1 lb/GWh...... Collect a minimum of 1 dscm per
metals. run.
OR OR
Individual HAP ................... Collect a minimum of 3 dscm per
metals:. 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 chloride 4.0E-4 lb/MWh...... For Method 26A, collect a minimum
(HCl). of 3 dscm per run. For ASTM D6348-
03 (Reapproved 2010) \2\ or
Method 320, sample for a minimum
of 1 hour.
OR
Sulfur dioxide (SO2) 1.0 lb/MWh......... SO2 CEMS.
\3\.
c. Mercury (Hg)..... 2.0E-3 lb/GWh...... Hg CEMS or Sorbent trap monitoring
system only.
----------------------------------------------------------------------------------------------------------------
\1\ Gross output.
\2\ Incorporated by reference, see Sec. 63.14.
\3\ You may not use the alternate SO2 limit 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 SO2 CEMS installed.
\4\ Duct burners on syngas; gross output.
\5\ Duct burners on natural gas; gross output.
0
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 Sec. 63.9991, you must comply with the following
applicable emission limits: \1\
----------------------------------------------------------------------------------------------------------------
Using these requirements, as
You must meet the appropriate (e.g., specified
If your EGU is in this For the following following emission sampling volume or test run
subcategory . . . pollutants . . . limits and work duration) and limitations with the
practice standards test methods in Table 5 to this
. . . Subpart . . .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank a. Filterable Before July 6, Before July 6, 2027: Collect a
virgin coal. particulate matter 2027: 3.0E-2 lb/ minimum of 1 dscm per run.
(PM). MMBtu or 3.0E-1 lb/
MWh \2\.
[[Page 38572]]
On or after July 6, On or after July 6, 2027: Collect
2027: 1.0E-2 lb/ a minimum catch of 6.0 milligrams
MMBtu or 1.0E-1 lb/ or a minimum sample volume of 4
MWh \2\. dscm per run.
OR OR On or after July 6, 2027 you may
only demonstrate compliance 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 Before July 6, Collect a minimum of 1 dscm per
metals. 2027: 5.0E-5 lb/ run.
MMBtu or 5.0E-1 lb/
GWh.
On or after July 6,
2027: 1.7E-5 lb/
MMBtu or 1.7E-1 lb/
GWh.
OR OR On or after July 6, 2027 you may
only demonstrate compliance with
the following individual HAP
metals emissions 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 ................... Collect a minimum of 3 dscm per
metals:. 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.
[[Page 38573]]
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 chloride 2.0E-3 lb/MMBtu or For Method 26A at appendix A-8 to
(HCl). 2.0E-2 lb/MWh. part 60 of this chapter, collect
a minimum of 0.75 dscm per run;
for Method 26, collect a minimum
of 120 liters per run. For ASTM
D6348-03 (Reapproved 2010) \3\ or
Method 320 at appendix A to part
63 of this chapter, sample for a
minimum of 1 hour.
OR
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 1.5E0 lb/MWh.
c. Mercury (Hg)..... 1.2E0 lb/TBtu or LEE Testing for 30 days with a
1.3E-2 lb/GWh. 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 LEE Testing for 90 days with a
1.1E-2 lb/GWh. 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 a. Filterable Before July 6, Before July 6, 2027: Collect a
virgin coal. particulate matter 2027: 3.0E-2 lb/ minimum of 1 dscm per run.
(PM). MMBtu or 3.0E-1 lb/ On or after July 6, 2027: Collect
MWh \2\. a minimum catch of 6.0 milligrams
On or after July 6, or a minimum sample volume of 4
2027: 1.0E-2 lb/ dscm per run.
MMBtu or 1.0E-1 lb/
MWh \2\.
[[Page 38574]]
OR OR On or after July 6, 2027 you may
only demonstrate compliance 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 Before July 6, Collect a minimum of 1 dscm per
metals. 2027: 5.0E-5 lb/ run.
MMBtu or 5.0E-1 lb/
GWh.
On or after July 6,
2027: 1.7E-5 lb/
MMBtu or 1.7E-1 lb/
GWh.
OR OR On or after July 6, 2027 you may
only demonstrate compliance with
the following individual HAP
metals emissions 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 ................... Collect a minimum of 3 dscm per
metals:. 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.
[[Page 38575]]
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 chloride 2.0E-3 lb/MMBtu or For Method 26A, collect a minimum
(HCl). 2.0E-2 lb/MWh. of 0.75 dscm per run; for Method
26 at appendix A-8 to part 60 of
this chapter, collect a minimum
of 120 liters per run. For ASTM
D6348-03 (Reapproved 2010) \3\ or
Method 320, sample for a minimum
of 1 hour.
OR OR
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 1.5E0 lb/MWh.
c. Mercury (Hg)..... Before July 6, LEE Testing for 30 days with a
2027: 4.0E0 lb/ sampling period consistent with
TBtu or 4.0E-2 lb/ that given in section 5.2.1 of
GWh. appendix A to this subpart per
On or after July 6, Method 30B run or Hg CEMS or
2027: 1.2E0 lb/ sorbent trap monitoring system
TBtu or 1.3E-2 lb/ only.
GWh.
3. IGCC unit..................... a. Filterable 4.0E-2 lb/MMBtu or Before July 6, 2027: Collect a
particulate matter 4.0E-1 lb/MWh \2\. minimum of 1 dscm per run.
(PM). 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 6.0E-5 lb/MMBtu or Collect a minimum of 1 dscm per
metals. 5.0E-1 lb/GWh. run.
OR OR
Individual HAP ................... Collect a minimum of 2 dscm per
metals:. 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.
[[Page 38576]]
Cobalt (Co)......... 1.2E0 lb/TBtu or
2.0E-2 lb/GWh.
Lead (Pb)........... 1.9E+2 lb/TBtu or
1.8E0 lb/GWh.
Manganese (Mn)...... 2.5E0 lb/TBtu or
3.0E-2 lb/GWh.
Nickel (Ni)......... 6.5E0 lb/TBtu or
7.0E-2 lb/GWh.
Selenium (Se)....... 2.2E+1 lb/TBtu or
3.0E-1 lb/GWh.
b. Hydrogen chloride 5.0E-4 lb/MMBtu or For Method 26A, collect a minimum
(HCl). 5.0E-3 lb/MWh. of 1 dscm per run; for Method 26,
collect a minimum of 120 liters
per run. For ASTM D6348-03
(Reapproved 2010) \3\ or Method
320, sample for a minimum of 1
hour.
c. Mercury (Hg)..... 2.5E0 lb/TBtu or LEE Testing for 30 days with a
3.0E-2 lb/GWh. 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-- a. Filterable 3.0E-2 lb/MMBtu or Collect a minimum of 1 dscm per
continental (excluding limited- particulate matter 3.0E-1 lb/MWh \2\. run.
use liquid oil-fired subcategory (PM).
units).
OR OR On or after July 6, 2027 you may
only demonstrate compliance 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 Collect a minimum of 1 dscm per
8.0E-3 lb/MWh. run.
OR OR On or after July 6, 2027 you may
only demonstrate compliance with
the following individual HAP
metals emissions 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 ................... Collect a minimum of 1 dscm per
metals:. 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 For Method 30B sample volume
2.0E-3 lb/GWh. determination (Section 8.2.4),
the estimated Hg concentration
should nominally be <\1/2\ the
standard.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or For Method 26A, collect a minimum
(HCl). 1.0E-2 lb/MWh. of 1 dscm per run; for Method 26,
collect a minimum of 120 liters
per run. For ASTM D6348-03
(Reapproved 2010) \3\ or Method
320, sample for a minimum of 1
hour.
c. Hydrogen fluoride 4.0E-4 lb/MMBtu or For Method 26A, collect a minimum
(HF). 4.0E-3 lb/MWh. of 1 dscm per run; for Method 26,
collect a minimum of 120 liters
per run. For ASTM D6348-03
(Reapproved 2010) \3\ or Method
320, sample for a minimum of 1
hour.
5. Liquid oil-fired unit--non- a. Filterable 3.0E-2 lb/MMBtu or Collect a minimum of 1 dscm per
continental (excluding limited- particulate matter 3.0E-1 lb/MWh \2\. run.
use liquid oil-fired subcategory (PM).
units).
[[Page 38577]]
OR OR On or after July 6, 2027 you may
only demonstrate compliance 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 Collect a minimum of 1 dscm per
7.0E-3 lb/MWh. run.
OR OR On or after July 6, 2027 you may
only demonstrate compliance with
the following individual HAP
metals emissions 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 ................... Collect a minimum of 2 dscm per
metals:. 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 For Method 30B sample volume
4.0E-4 lb/GWh. determination (Section 8.2.4),
the estimated Hg concentration
should nominally be <\1/2\ the
standard.
b. Hydrogen chloride 2.0E-4 lb/MMBtu or For Method 26A, collect a minimum
(HCl). 2.0E-3 lb/MWh. of 1 dscm per run; for Method 26,
collect a minimum of 120 liters
per run. For ASTM D6348-03
(Reapproved 2010) \3\ or Method
320, sample for a minimum of 2
hours.
c. Hydrogen fluoride 6.0E-5 lb/MMBtu or For Method 26A, collect a minimum
(HF). 5.0E-4 lb/MWh. of 3 dscm per run. For ASTM D6348-
03 (Reapproved 2010) \3\ or
Method 320, sample for a minimum
of 2 hours.
6. Solid oil-derived fuel-fired a. Filterable 8.0E-3 lb/MMBtu or Before July 6, 2027: Collect a
unit. particulate matter 9.0E-2 lb/MWh \2\. minimum of 1 dscm per run.
(PM). 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 compliance 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 4.0E-5 lb/MMBtu or Collect a minimum of 1 dscm per
metals. 6.0E-1 lb/GWh. run.
OR OR On or after July 6, 2027 you may
only demonstrate compliance with
the following individual HAP
metals emissions 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 ................... Collect a minimum of 3 dscm per
metals:. 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.
[[Page 38578]]
Beryllium (Be)...... 6.0E-2 lb/TBtu or
5.0E-4 lb/GWh.
Cadmium (Cd)........ 3.0E-1 lb/TBtu or
4.0E-3 lb/GWh.
Chromium (Cr)....... 8.0E-1 lb/TBtu or
2.0E-2 lb/GWh.
Cobalt (Co)......... 1.1E0 lb/TBtu or
2.0E-2 lb/GWh.
Lead (Pb)........... 8.0E-1 lb/TBtu or
2.0E-2 lb/GWh.
Manganese (Mn)...... 2.3E0 lb/TBtu or
4.0E-2 lb/GWh.
Nickel (Ni)......... 9.0E0 lb/TBtu or
2.0E-1 lb/GWh.
Selenium (Se)....... 1.2E0 lb/TBtu or
2.0E-2 lb/GWh.
b. Hydrogen chloride 5.0E-3 lb/MMBtu or For Method 26A, collect a minimum
(HCl). 8.0E-2 lb/MWh. of 0.75 dscm per run; for Method
26, collect a minimum of 120
liters per run. For ASTM D6348-03
(Reapproved 2010) \3\ or Method
320, sample for a minimum of 1
hour.
OR OR
Sulfur dioxide (SO2) 3.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 2.0E0 lb/MWh.
c. Mercury (Hg)..... 2.0E-1 lb/TBtu or LEE Testing for 30 days with a
2.0E-3 lb/GWh. 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 a. Filterable Before July 6, Before July 6, 2027: Collect a
(EBCR)-fired unit. particulate matter 2027: 3.0E-2 lb/ minimum of 1 dscm per run.
(PM). MMBtu or 3.0E-1 lb/ On or after July 6, 2027: Collect
MWh \2\. a minimum catch of 6.0 milligrams
On or after July 6, or a minimum sample volume of 4
2027: 1.0E-2 lb/ dscm per run.
MMBtu or 1.0E-1 lb/
MWh \2\.
OR OR On or after July 6, 2027 you may
only demonstrate compliance 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 Before July 6, Collect a minimum of 1 dscm per
metals. 2027: 5.0E-5 lb/ run.
MMBtu or 5.0E-1 lb/
GWh.
On or after July 6,
2027: 1.7E-5 lb/
MMBtu or 1.7E-1 lb/
GWh.
OR OR On or after July 6, 2027 you may
only demonstrate compliance with
the following individual HAP
metals emissions 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 ................... Collect a minimum of 3 dscm per
metals:. 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.
[[Page 38579]]
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.
[[Page 38580]]
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 chloride 4.0E-2 lb/MMBtu or For Method 26A at appendix A-8 to
(HCl). 4.0E-1 lb/MWh. part 60 of this chapter, collect
a minimum of 0.75 dscm per run;
for Method 26, collect a minimum
of 120 liters per run. For ASTM
D6348-03 (Reapproved 2010) \3\ or
Method 320 at appendix A to part
63 of this chapter, sample for a
minimum of 1 hour.
OR
Sulfur dioxide (SO2) 6E-1 lb/MMBtu or SO2 CEMS.
\4\. 9E0 lb/MWh.
c. Mercury (Hg)..... 1.2E0 lb/TBtu or LEE Testing for 30 days with a
1.3E-2 lb/GWh. 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 LEE Testing for 90 days with a
1.1E-2 lb/GWh. 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.
----------------------------------------------------------------------------------------------------------------
\1\ For 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 filterable 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 Sec. 63.7(f).
\2\ Gross output.
\3\ Incorporated by reference, see Sec. 63.14.
\4\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
installed.
0
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 Sec. 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 Sec. 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 Sec. 63.10021(e).
3. A coal-fired, liquid oil- a. Before January 2, 2025 you have the
fired (excluding limited-use option of complying using either of the
liquid oil-fired subcategory following work practice standards in
units), or solid oil-derived paragraphs (1) and (2). On or after
fuel-fired EGU during January 2, 2025 you may not choose to
startup. use paragraph (2) of the definition of
startup in Sec. 63.10042 and the
following associated work practice
standards in paragraph (2).
[[Page 38581]]
(1) If you choose to comply using
paragraph (1) of the definition of
``startup'' in Sec. 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 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). For startup of a unit, you
must use clean fuels as defined in Sec.
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 applicable 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 concerning activities
and startup periods, as specified in
Sec. 63.10011(g) and Sec.
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 Sec. 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 Sec. 63.10042 to the
maximum extent possible, taking into
account considerations such as boiler 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
practice requirements as identified in
Sec. 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 firing 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 applicable 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
periods.
d. You must collect monitoring data
during startup periods, as specified in
Sec. 63.10020(a) and (e). You must
keep records during startup periods, as
provided in Sec. Sec. 63.10021(h) and
63.10032. You must provide reports
concerning activities and startup
periods, as specified in Sec. Sec.
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 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). On or after January 2,
2025 you may not use paragraph (2) of
the definition of startup in Sec.
63.10042.
4. A coal-fired, liquid oil- You must operate all CMS during shutdown.
fired (excluding limited-use You must also collect appropriate data,
liquid oil-fired subcategory and you must calculate the pollutant
units), or solid oil-derived emission rate for each hour of shutdown
fuel-fired EGU during for those pollutants for which a CMS is
shutdown. used.
While firing coal, residual oil, or solid
oil-derived fuel during shutdown, you
must vent emissions 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 support the shutdown
process, that additional fuel must be
one or a combination of the clean fuels
defined in Sec. 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.
[[Page 38582]]
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 Sec. 63.10020(a). You
must keep records during shutdown
periods, as provided in Sec. Sec.
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 Sec. Sec. 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, according to 40
CFR 63.10031(i). On or after January 2,
2025 you may not use paragraph (2) of
the definition of startup in Sec.
63.10042.
------------------------------------------------------------------------
0
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 Sec. 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 compliance You must meet these operating limits . .
using . . . .
------------------------------------------------------------------------
PM CPMS...................... Maintain the 30-boiler operating day
rolling average PM CPMS output
determined in accordance with the
requirements of Sec. 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).
------------------------------------------------------------------------
0
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 Sec. 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
[[Page 38583]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.101
[[Page 38584]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.102
[[Page 38585]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.103
[[Page 38586]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.104
[[Page 38587]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.105
[[Page 38588]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.106
[[Page 38589]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.107
[[Page 38590]]
[GRAPHIC] [TIFF OMITTED] TR07MY24.108
BILLING CODE 6560-50-C
\1\ Regarding emissions data collected during periods of startup
or shutdown, see Sec. Sec. 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 Sec.
63.7(f).
\2\ See tables 1 and 2 to this subpart for required sample
volumes and/or sampling run times.
\3\ Incorporated by reference, see Sec. 63.14.
0
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 Sec. 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.
----------------------------------------------------------------------------------------------------------------
And you choose to
establish PM CPMS According to the
If you have an applicable operating limits, And . . . Using . . . following procedures .
emission limit for . . . you must . . . . .
----------------------------------------------------------------------------------------------------------------
Filterable Particulate matter Install, certify, Establish a site- Data from the PM 1. Collect PM CPMS
(PM), total non-mercury HAP maintain, and specific CPMS and the PM output data during
metals, individual non-mercury operate a PM operating limit or HAP metals the entire period of
HAP metals, total HAP metals, CPMS for in units of PM performance the performance
or individual HAP metals for monitoring CPMS output tests. tests.
an EGU. emissions signal (e.g., 2. Record the average
discharged to milliamps, mg/ hourly PM CPMS output
the atmosphere acm, or other for each test run in
according to raw signal). the performance test.
Sec. 3. Determine the PM
63.10010(h)(1). CPMS operating limit
in accordance with
the requirements of
Sec. 63.10023(b)(2)
from data obtained
during the
performance test
demonstrating
compliance with the
filterable PM or HAP
metals emissions
limitations.
----------------------------------------------------------------------------------------------------------------
[[Page 38591]]
0
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 Sec. 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, operating You demonstrate continuous
limits, or work practice standards . . compliance by . . .
.
------------------------------------------------------------------------
1. CEMS to measure filterable PM, SO2, Calculating the 30- (or 90-)
HCl, HF, or Hg emissions, or using a boiler operating day rolling
sorbent trap monitoring system to arithmetic average emissions
measure Hg. 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 Calculating the 30- (or 90-)
parametric operating limit. (On or boiler operating day rolling
after July 6, 2027 you may not use PM arithmetic average of all of
CPMS for compliance demonstrations, the quality assured hourly
unless it is for an IGCC unit.). 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 If applicable, by conducting
for liquid oil-fired EGUs for HCl and the monitoring in accordance
HF emission limit monitoring. with an approved site-specific
monitoring plan.
4. Quarterly performance testing for Calculating the results of the
coal-fired, solid oil derived fired, testing in units of the
or liquid oil-fired EGUs to measure applicable emissions standard.
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 demonstrations, unless it
is for an IGCC unit.).
5. Conducting periodic performance tune- Conducting periodic performance
ups of your EGU(s). tune-ups of your EGU(s), as
specified in Sec.
63.10021(e).
6. Work practice standards for coal- Operating in accordance with
fired, liquid oil-fired, or solid oil- Table 3.
derived fuel-fired EGUs during startup.
7. Work practice standards for coal- Operating in accordance with
fired, liquid oil-fired, or solid oil- Table 3.
derived fuel-fired EGUs during
shutdown.
------------------------------------------------------------------------
0
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
completion 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
operating 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 SO2 emissions.
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 SO2 monitoring
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 SO2 or 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.
[[Page 38592]]
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), according 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 SO2 CEMS (or 90-boiler operating day rolling averages
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 definition 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
reports 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 ECMPS
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.
------------------------------------------------------------------------
0
26. In appendix C to subpart UUUUU:
0
a. Revise sections 1.2, 1.3, 4.1, and 4.1.1.
0
b. Add sections 4.1.1.1 and 4.2.3.
0
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
[[Page 38593]]
(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
* * * * *
0
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