[Federal Register Volume 90, Number 247 (Wednesday, December 31, 2025)]
[Rules and Regulations]
[Pages 61328-61355]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2025-24102]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 423
[EPA-HQ-OW-2009-0819; FRL-8794.3-04-OW]
RIN 2040-AG54
Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category--Deadline Extensions
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The U.S. Environmental Protection Agency (the EPA or Agency)
is finalizing a Clean Water Act (CWA) rule to extend deadlines
promulgated in the 2024 ``Supplemental Effluent Limitations Guidelines
and Standards for the Steam Electric Power Generating Point Source
Category'' (2024 rule), update the 2024 rule's transfer provisions to
allow facilities to switch between compliance alternatives, and create
authority for alternative applicability dates and paperwork submission
dates, based on site-specific factors.
DATES: The final rule is effective on March 2, 2026. In accordance with
40 CFR 23.2, this regulation shall be considered issued for purposes of
judicial review at 1 p.m. Eastern time on January 14, 2026. Under
section 509(b)(1) of the CWA, judicial review of this regulation can be
had only by filing a petition for review in the U.S. Court of Appeals
within 120 days after the regulation is considered issued for purposes
of judicial review. Under section 509(b)(2), the requirements in this
regulation may not be challenged later in civil or criminal proceedings
brought by the EPA to enforce these requirements.
ADDRESSES: The EPA has established a docket for this action under
Docket ID
[[Page 61329]]
No. EPA-HQ-OW-2009-0819. All documents in the docket are listed on the
http://www.regulations.gov website. Although listed in the index, some
information is not publicly available, e.g., confidential business
information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the internet and will be publicly available only in hard
copy form. Publicly available docket materials are available
electronically through https://www.regulations.gov.
FOR FURTHER INFORMATION CONTACT: Richard Benware, Engineering and
Science Division, Office of Water (Mail Code 4303T), Environmental
Protection Agency, 1200 Pennsylvania Avenue NW, Washington, DC 20460;
telephone number: 202-566-1369; email address: [email protected].
Information about the Steam Electric Effluent Limitations Guidelines
and Standards (ELGs) is available online at: https://www.epa.gov/eg/steam-electric-power-generating-effluent-guidelines.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Executive Summary
II. Does this action apply to me?
III. What is the EPA's authority for taking this action?
IV. Background
A. Clean Water Act
B. Relevant Effluent Guidelines
1. Best Practicable Control Technology Currently Available
2. Best Available Technology Economically Achievable
3. Pretreatment Standards for Existing Sources
4. Best Professional Judgment
C. 2015 Steam Electric Rule
1. Summary of the 2015 Rule
2. Vacatur of Limitations Applicable to CRL and Legacy
Wastewater
D. 2020 Steam Electric Reconsideration Rule
1. Summary of the 2020 Rule
2. 2020 Rule Litigation
E. 2024 Supplemental Steam Electric Rule
1. Summary of the 2024 Rule
2. 2024 Rule Litigation
3. Administrative Petitions for Reconsideration of the 2024 Rule
4. NOPP Submission Extension Requests
F. Executive Order Summary
V. Information Supporting the Final Action
A. National Energy Crisis
B. Regional Energy Reliability and Resource Adequacy Concerns
C. Increasing Energy Demand From Data Centers, Manufacturing,
and Other Causes
D. Supply-Chain Risks
E. Other Pressures on Retirement
F. Recent Changes in Facilities' Plans To Cease Burning Coal in
Light of Rising Demand
VI. Final Rule
A. NOPP Submission Date Extension
B. Withdrawal of NOPP Companion Direct Final Rule
C. New Transfer Provision
D. Extended BAT Applicability Timing for Zero-Discharge
Limitations
1. Industry-Wide Installation of the 2024 Zero-Discharge
Limitations Cannot Reasonably Be Achieved Nationwide by 2029 Due to
Longer-Than-Expected Timelines and Delays in Procuring Necessary
Components and Completing Installation
2. An Extension of the Latest Compliance Deadlines for the 2024
Rule's Zero-Discharge Limitations Until 2034 Is Warranted Based on
the Adverse Impacts on Customer Rates Resulting From the Cumulative
Costs of Complying With Multiple Rules in Short Succession
3. An Extension of the 2024 Rule's Latest Compliance Deadline
for Zero-Discharge Limitations Is Warranted To Ensure Plants Can
Continue Operating To Support Grid Reliability and in Light of
Legitimate Uncertainties About the Economic and Energy Impacts of
the 2024 Rule
4. The Final Rule Does Not Revise the 2024 Rule's Earliest
Compliance Dates, Which Have Already Passed
E. Tiered PSES
F. Alternative Applicability Timing and NOPP Submission Timing
Flexibility
G. Clarifications to Sections 423.18(a) or 423.19(i)
H. Reliance Interests
I. Economic Achievability
J. Severability
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 14192: Unleashing Prosperity Through
Deregulation
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA)
K. Congressional Review Act (CRA)
I. Executive Summary
The EPA is finalizing regulations that apply to wastewater
discharges from steam electric power plants, particularly coal-fired
power plants. In 2024, the EPA finalized a CWA regulation that revised
the technology-based effluent limitations guidelines and standards
(ELGs) for the steam electric power generating point source category
applicable to flue gas desulfurization (FGD) wastewater, bottom ash
(BA) transport water, and legacy wastewater at existing sources and
combustion residual leachate (CRL) at new and existing sources. 89 FR
40198 (May 9, 2024).
In the last year and a half, the EPA has observed extraordinary
increases in energy demand across the U.S., decreases in energy
reserves, difficulties in transmission across the electricity grid,
increased energy prices, and decreased energy reliability (DCN SE11901,
SE11902). In addition, the EPA has identified additional information
that makes it clear that, due to supply chain logistical challenges as
well as the unique characteristics of each facility's operational
needs, the deadlines to comply with the 2024 rule are infeasible and
impractical on a nationwide basis. This final action revises the
compliance deadlines for existing sources subject to the 2024 rule, as
seen in the following table, at a time of both growing energy crisis as
well as different circumstances than what existed during the 2024
rulemaking process. These compliance deadline extensions also give
utilities and permitting authorities flexibilities needed to ensure
affordable and reliable power (DCN SE11915). Table 1 provides an
overview of each revised regulatory deadline.
Table 1--Summary of Deadline Extensions
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Extendable by 40 CFR
Rule Wastestream/submission Previous deadline New deadline 423.18?
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2020 Rule........... NOPP for the Voluntary October 13, 2021, X................. Yes.
Incentives Plan, June 27, 2023,
Permanent Cessation of December 31, 2025.
Coal Combustion by 2028
Subcategory, and
Transfers.
BA Transport Water December 31, 2025.. X................. Yes.
(Generally Applicable
BAT).
FGD Wastewater
(Generally Applicable
BAT).
[[Page 61330]]
FGD Wastewater (VIP December 31, 2028.. X.................
limitations).
2024 Rule........... NOPP for the Permanent December 31, 2025.. December 31, 2031. X.
Cessation of Coal
Combustion by 2034
Subcategory.
BA Transport Water May 9, 2027........ January 1, 2029 or X.
(Generally Applicable Site-Specific
PSES). Date for BAT (see
below).
FGD Wastewater
(Generally Applicable
PSES).
CRL (Generally
Applicable PSES).
BA Transport Water No later than No later than Yes.
(Generally Applicable December 31, 2029. December 31, 2034.
BAT).
FGD Wastewater
(Generally Applicable
BAT).
CRL (Generally
Applicable BAT).
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The revised deadlines also extend the date for existing steam
electric power plants that seek to achieve permanent cessation of coal
combustion to submit a notice of planned participation (NOPP) to
December 31, 2034, allowing utilities additional time to assess
evolving power demand needed to inform operational planning and
decision-making. In addition to specific extensions to regulatory
deadlines, this final action also revises the existing transfer
provisions at 40 CFR 423.13(o) to allow facilities to switch between
compliance alternatives and creates authority in 40 CFR 423.18 for
alternative applicability dates and paperwork submission dates, based
on site-specific factors. This final rule further establishes tiered
pretreatment standards for existing sources (PSES). In so doing, it
creates a compliance pathway for indirect dischargers that plan to
become direct dischargers and, furthermore, changes the pretreatment
compliance deadlines to provide consistency with the compliance
deadlines for direct dischargers meeting best available technology
economically achievable (BAT) limitations. This final rule does not
change the underlying technology bases for the effluent limitations
based on BAT. Subsequent to this rulemaking, the EPA intends to further
evaluate data submitted during the public comment period and determine
if reconsidering the 2024 BAT requirements is appropriate.
II. Does this action apply to me?
Entities potentially regulated by this action include:
Table 2--Entities Potentially Regulated by This Action
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North American
Industry
Category Example of regulated Classification
entity System (NAICS)
Code
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Industry...................... Electric Power 22111
Generation
Facilities--Electric
Power Generation.
Electric Power 221112
Generation
Facilities--Fossil
Fuel Electric Power
Generation.
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This table is not intended to be exhaustive but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table includes the types of entities that the EPA is now
aware could potentially be regulated by this action. Other types of
entities not included in Table 2 could also be regulated. To determine
whether an entity is regulated by this action, carefully examine the
applicability criteria found in 40 CFR 423.10 (Applicability). For
questions regarding the applicability of this action to a particular
entity, consult the person listed in the FOR FURTHER INFORMATION
CONTACT section.
III. What is the EPA's authority for taking this action?
The authority for this rule is the Federal Water Pollution Control
Act, 33 U.S.C. 1251 et seq., including CWA sections 301, 304(b),
304(g), 307, and 501(a); 33 U.S.C. 1311, 1314(b), 1314(g), 1317, and
1361(a).
Unless otherwise provided by law, an agency may reconsider past
decisions and revise, replace, or repeal a decision so long as the
agency provides a reasoned explanation and considers significant
reliance interests. FCC v. Fox Telev. Stations, Inc., 556 U.S. 502, 515
(2009); Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co.,
463 U.S. 29, 42 (1983); see also Nat'l Ass'n of Home Builders v. EPA,
682 F.3d 1032, 1038 & 1043 (D.C. Cir. 2012) (a revised rulemaking based
``on a reevaluation of which policy would be better in light of the
facts'' is ``well within an agency's discretion,'' and ``[a] change in
administration brought about by the people casting their votes is a
perfectly reasonable basis for an executive agency's reappraisal'' of
its policy choices) (citations omitted).
IV. Background
A. Clean Water Act
Congress passed the Federal Water Pollution Control Act Amendments
of 1972, also known as the Clean Water Act (CWA), to ``restore and
maintain the chemical, physical, and biological integrity of the
Nation's waters.'' 33 U.S.C. 1251(a). The CWA establishes a
comprehensive program for protecting the Nation's waters. Among its
core provisions, the CWA prohibits the direct discharge of pollutants
from a point source to waters of the United States (WOTUS), except as
authorized under the CWA. Under CWA section 402, discharges may be
authorized through a National Pollutant Discharge Elimination System
(NPDES) permit. 33 U.S.C. 1342. The CWA also authorizes the EPA to
establish nationally applicable, technology-based ELGs for discharges
from different categories of point sources, such as industrial,
[[Page 61331]]
commercial, and public sources. 33 U.S.C. 1311, 1314.
Furthermore, the CWA authorizes the EPA to promulgate nationally
applicable pretreatment standards that restrict pollutant discharges
from facilities that discharge wastewater to WOTUS indirectly through
sewers flowing to publicly owned treatment works (POTWs), as outlined
in CWA sections 307(b) and (c). 33 U.S.C. 1317(b)-(c). The EPA
establishes national pretreatment standards for those pollutants in
wastewater from indirect dischargers that may pass through, interfere
with, or are otherwise incompatible with POTW operations. Pretreatment
standards are designed to ensure that wastewaters from indirect
industrial dischargers are subject to similar levels of treatment as
those directly discharged and subject to ELGs. See CWA section 301(b),
33 U.S.C. 1311(b). In addition, the EPA has by regulation required
POTWs to implement local treatment limits applicable to their
industrial indirect dischargers to satisfy any local requirements. See
40 CFR 403.5.
Direct dischargers (i.e., those discharging directly to WOTUS
rather than through POTWs) must comply with effluent limitations in
NPDES permits. Indirect dischargers that discharge through POTWs must
comply with pretreatment standards. Technology-based effluent
limitations (TBELs) in NPDES permits are derived from ELGs (CWA
sections 301 and 304, 33 U.S.C. 1311 and 1314) and new source
performance standards (CWA section 306, 33 U.S.C. 1316) promulgated by
the EPA or based on best professional judgment (BPJ) where the Agency
has not promulgated an applicable effluent guideline or new source
performance standard. CWA section 402(a)(1)(B), 33 U.S.C.
1342(a)(1)(B); 40 CFR 125.3(c). Additional limitations based on water
quality standards are also included in the permit in certain
circumstances. CWA section 301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C); 40
CFR 122.44(d).
The EPA establishes ELGs by regulation for categories of point
source dischargers that are based on the degree of control that can be
achieved using various levels of pollution control technology. The EPA
promulgates national ELGs for major industrial categories for three
classes of pollutants: (1) conventional pollutants (i.e., total
suspended solids or TSS, oil and grease, biochemical oxygen demand or
BOD5, fecal coliform, and pH), as outlined in CWA section
304(a)(4) and 40 CFR 401.16; (2) toxic pollutants (e.g., toxic metals
such as arsenic, mercury, selenium, and chromium; toxic organic
pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene),
as outlined in CWA section 307(a), 40 CFR 401.15 and 40 CFR 423
appendix A; and (3) nonconventional pollutants, which are those
pollutants that are not categorized as conventional or toxic (e.g.,
ammonia-N, phosphorus, and total dissolved solids or TDS).
B. Relevant Effluent Guidelines
The EPA develops effluent guidelines that are technology-based
regulations for a category of dischargers. The EPA bases these
regulations on the performance of control and treatment technologies.
See, e.g., Sw. Elec. Power Co. v. EPA, 920 F.3d 999, 1005 (5th Cir.
2019) (``[T]he Administrator must require industry, regardless of a
discharge's effect on water quality, to employ defined levels of
technology to meet effluent limitations.'') (citations and internal
quotations omitted).
There are several TBELs that may apply to a given discharger under
the CWA: four types of standards applicable to direct dischargers, two
types of standards applicable to indirect dischargers, and a default
site-specific approach. The TBELs relevant to this rulemaking are
described in detail below.
1. Best Practicable Control Technology Currently Available
Traditionally, the EPA defines best practicable control technology
(BPT) effluent limitations based on the average of the best
performances of facilities within the industry, grouped to reflect
various ages, sizes, processes, or other common characteristics. The
EPA may promulgate BPT effluent limitations for conventional, toxic,
and nonconventional pollutants. In specifying BPT, the EPA looks at a
number of factors. The EPA first considers the cost of achieving
effluent reductions in relation to the effluent reduction benefits. The
EPA also considers the age of equipment and facilities, the processes
employed, engineering aspects of the control technologies, any required
process changes, non-water quality environmental impact (including
energy requirements), and such other factors as the Administrator deems
appropriate. See CWA section 304(b)(1)(B), 33 U.S.C. 1314(b)(1)(B). If,
however, existing performance is uniformly inadequate, the EPA may
establish limitations based on higher levels of control than what is
currently in place in an industrial category, when based on an Agency
determination that the technology is available in another category or
subcategory and can be practicably applied.
2. Best Available Technology Economically Achievable
BAT represents the second level of stringency for controlling
direct discharge of toxic and nonconventional pollutants, after BPT.
Courts have referred to this as the CWA's ``gold standard'' for
controlling discharges from existing sources. See, e.g., Sw. Elec.
Power Co., 920 F.3d at 1003. In general, BAT represents the best
available, economically achievable performance of facilities in the
industrial subcategory or category. Consistent with the statutory
language, the EPA considers technological availability and economic
achievability in determining what level of control represents BAT. CWA
section 301(b)(2)(A), 33 U.S.C. 1311(b)(2)(A). Other statutory factors
that the EPA considers in assessing BAT are the cost of achieving BAT
effluent reductions, the age of equipment and facilities involved, the
process employed, potential process changes, non-water quality
environmental impact (including energy requirements), and such other
factors as the Administrator deems appropriate. CWA section
304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B). The EPA retains considerable
discretion in assigning the weight to be accorded each factor.
Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045 (D.C. Cir. 1978). This
is especially true for the EPA's consideration of non-water quality
environmental impact. BP Expl. & Oil, Inc. v. EPA, 66 F.3d 784, 801-02
(6th Cir. 1995). Historically, the EPA has usually determined economic
achievability on the basis of the effect of the cost of compliance with
BAT limitations on overall industry and subcategory financial
conditions. BAT reflects the highest performance in the industry and
may reflect a higher level of performance than is currently being
achieved in the industry. See, e.g., Sw. Elec. Power Co., 920 F.3d at
1006; Am. Paper Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); Am.
Frozen Food Inst. v. Train, 539 F.2d 107, 132 (D.C. Cir. 1976). Under
this approach, BAT may be based upon process changes or internal
controls, even when these technologies are not common industry
practice. See Am. Frozen Food, 539 F.2d at 132, 140; Reynolds Metal Co.
v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); Cal. & Hawaiian Sugar Co. v.
EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977). Courts have previously
endorsed this approach. Kennecott v. EPA, 780 F.2d 445, 448 (4th Cir.
1985); see also Sw. Elec. Power Co., 920 F.3d at 1031.
[[Page 61332]]
3. Pretreatment Standards for Existing Sources
Section 307(b), 33 U.S.C. 1317(b), of the CWA calls for the EPA to
issue pretreatment standards for discharges of pollutants to POTWs
(i.e., indirect discharges). PSES are designed to prevent the discharge
of pollutants that pass through, interfere with, or are otherwise
incompatible with the operation of POTWs. Categorical pretreatment
standards are technology-based and are analogous to BAT ELGs, and thus
the EPA typically considers the same factors in promulgating PSES as it
considers in promulgating BAT. See, e.g., Reynolds Metal Co., 760 F.2d
at 553; Chem. Mfrs. Ass'n v. EPA, 870 F.2d 177, 244 (5th Cir. 1989).
The General Pretreatment Regulations, which set forth the framework for
the implementation of categorical pretreatment standards, are found at
40 CFR part 403. These regulations establish pretreatment standards
that apply to all nondomestic dischargers. See 52 FR 1586 (January 14,
1987).
4. Best Professional Judgment
CWA section 301 and the EPA's implementing regulation at 40 CFR
125.3(a) indicate that technology-based treatment requirements under
section 301(b) represent the minimum level of control that must be
included in an NPDES permit. See 33 U.S.C. 1311. Where EPA-promulgated
effluent guidelines are not applicable to a non-POTW discharge, or
where such EPA-promulgated guidelines have been vacated by a court, the
EPA has provided by regulation that such treatment requirements are
established on a case-by-case basis using the permit writer's BPJ.
Under the EPA's regulations, case-by-case TBELs are developed by permit
writers on the theory that CWA section 402(a)(1) authorizes the EPA
Administrator to issue a permit that will meet either: all applicable
requirements developed under the authority of other sections of the CWA
(e.g., technology-based treatment standards, water quality standards,
ocean discharge criteria) or, before taking the necessary implementing
actions related to those requirements, ``such conditions as the
Administrator determines are necessary to carry out the provisions of
this Act.'' 33 U.S.C. 1342(a)(1). The regulation at 40 CFR 125.3(c)(2)
cites this section of the CWA, stating that technology-based treatment
requirements may be imposed in a permit ``on a case-by-case basis under
section 402(a)(1) of the Act, to the extent that EPA-promulgated
effluent limitations are inapplicable.'' Furthermore, 40 CFR
125.3(c)(3) states that ``[w]here promulgated effluent limitations
guidelines only apply to certain aspects of the discharger's operation,
or to certain pollutants, other aspects or activities are subject to
regulation on a case-by-case basis in order to carry out the provisions
of the Act.'' The factors considered by the permit writer are the same
as those that the EPA considers when establishing effluent guidelines.
See 40 CFR 125.3(d)(1) through (3).
C. 2015 Steam Electric Rule
1. Summary of the 2015 Rule
On November 3, 2015, the EPA promulgated a rule revising the
regulations for the steam electric power generating point source
category at 40 CFR 423. 80 FR 67838 (2015 rule). The 2015 rule set the
first Federal limitations on the levels of toxic pollutants (e.g.,
arsenic) and nutrients (e.g., nitrogen) that may be discharged in the
steam electric power generating industry's largest sources of
wastewater, based on technology improvements in the industry over the
preceding three decades. Before the 2015 rule, regulations for the
industry had last been updated in 1982 and, for the industry's
wastestreams with the largest pollutant loadings, contained only
limitations on TSS and oil and grease.
The 2015 rule addressed effluent limitations and standards for
multiple wastestreams generated by new and existing steam electric
facilities: BA transport water, CRL, FGD wastewater, flue gas mercury
control wastewater, fly ash transport water, gasification wastewater,
and legacy wastewater. The 2015 rule required most steam electric
facilities to comply with the effluent limitations ``as soon as
possible'' after November 1, 2018, but no later than December 31, 2023.
Permitting authorities established particular applicability date(s)
within that range for each plant (except for indirect discharges, which
discharge to POTWs) at the time they issued the plant's NPDES permit.
For plants that opted into the 2015 rule's voluntary incentives program
(VIP), which gave plants the certainty of more time to meet more
stringent FGD wastewater limitations, the compliance deadline was
December 31, 2023.
2. Vacatur of Limitations Applicable to CRL and Legacy Wastewater
Electric utilities, environmental groups, and drinking water
utilities filed seven petitions for review of the 2015 rule in various
circuit courts. The petitions were consolidated in the U.S. Court of
Appeals for the Fifth Circuit as Southwestern Electric Power Co. v.
EPA, Case No. 15-60821. In early 2017, the EPA received two
administrative petitions to reconsider the 2015 rule: one from the
Utility Water Act Group (UWAG) and one from the Small Business
Administration.
On August 11, 2017, the EPA announced a rulemaking to potentially
revise the new, more stringent BAT effluent limitations and PSES in the
2015 rule that apply to FGD wastewater and BA transport water. The
Fifth Circuit subsequently granted the EPA's request to sever and hold
in abeyance petitioners' claims related to those limitations and
standards, and those claims are still in abeyance. With respect to the
remaining claims related to limitations applicable to legacy wastewater
and CRL, the court issued a decision in 2019 vacating those limitations
as arbitrary and capricious under the Administrative Procedure Act and
unlawful under the CWA, respectively. Sw. Elec. Power Co., 920 F.3d at
1033. In particular, the court rejected the EPA's BAT limitations for
each wastestream set equal to previously promulgated BPT limitations
based on surface impoundments. In the case of legacy wastewater, the
court held that the EPA's record did not support BAT limitations based
on surface impoundments. Id. at 1015. In the case of CRL, the court
held that the EPA's setting of BAT limitations equal to BPT limitations
was an impermissible conflation of the two standards, which are
supposed to be progressively more stringent, and that the EPA's
rationale was not authorized by the statutory factors for determining
BAT. Id. at 1026. After the court's decision, the EPA announced plans
to address the vacated limitations in a later action.
D. 2020 Steam Electric Reconsideration Rule
1. Summary of the 2020 Rule
On October 13, 2020, the EPA promulgated the Steam Electric
Reconsideration Rule, 85 FR 64650 (2020 rule). The 2020 rule revised
requirements applicable to existing sources for FGD wastewater and BA
transport water. Specifically, the 2020 rule made four changes to the
2015 rule. First, the rule changed the technology basis for control of
FGD wastewater and BA transport water. For FGD wastewater, the
technology basis was changed from chemical precipitation plus high
hydraulic residence time biological reduction to chemical precipitation
plus low hydraulic residence time biological reduction.
[[Page 61333]]
This change in the technology basis resulted in less stringent selenium
limitations and more stringent mercury and nitrogen limitations. For BA
transport water, the technology basis was changed from dry-handling or
closed-loop systems to high-recycle-rate systems, allowing for a site-
specific purge not to exceed 10 percent of the BA transport system's
volume. Second, the 2020 rule revised the technology basis for the VIP
for FGD wastewater from vapor compression evaporation to chemical
precipitation plus membrane filtration. Third, the 2020 rule created
three new subcategories for high-flow facilities, low-utilization
electric generating units (EGUs), and EGUs permanently ceasing coal
combustion by 2028. Facilities or units in these subcategories were
subject to less stringent limitations: high-flow facilities were
subject to FGD wastewater limitations based on chemical precipitation;
low-utilization EGUs were subject to FGD wastewater limitations based
on chemical precipitation and BA transport water limitations based on
surface impoundments and a best management plan; and EGUs permanently
ceasing coal combustion by 2028 were subject to FGD wastewater and BA
transport water limitations based on surface impoundments. Finally, the
2020 rule required most steam electric facilities to comply with the
revised effluent limitations ``as soon as possible'' after October 13,
2021, but no later than December 31, 2025. NPDES permitting authorities
established the particular applicability date(s) of the new limitations
within that range for each facility (except for indirect dischargers)
at the time they issued the facility's NPDES permit. Facilities opting
into the VIP were given until December 31, 2028, to meet the revised
FGD wastewater limitations.
2. 2020 Rule Litigation
Environmental groups filed two petitions for review of the 2020
rule, which were consolidated in the U.S. Court of Appeals for the
Fourth Circuit on November 19, 2020, as Appalachian Voices, et al. v.
EPA, No. 20-2187. An industry trade group and certain energy companies
moved to intervene in the litigation, which the court authorized on
December 3, 2020. On April 8, 2022, the court granted the EPA's motion
to place the case into abeyance as a result of a new rulemaking
announced in July 2021. The case is still in abeyance.
E. 2024 Supplemental Steam Electric Rule
1. Summary of the 2024 Rule
On May 9, 2024, as part of a ``suite of final rules'' imposing new
requirements on the power generation sector, the EPA promulgated the
Steam Electric Supplemental Rule (89 FR 40198) (2024 rule). This
revision of the regulations at 40 CFR part 423 established a zero-
discharge limitation for three wastewaters generated at steam electric
power plants: FGD wastewater, BA transport water, and managed CRL. The
2024 rule also established non-zero numeric discharge limitations on
mercury and arsenic on discharges of CRL that the permitting authority
determines are the functional equivalent of a direct discharge to a
WOTUS through groundwater or discharges of CRL that have leached from a
waste management unit into the subsurface and mixed with groundwater
before being captured and pumped to the surface for discharge directly
to a WOTUS (i.e., ``unmanaged'' CRL). These mercury and arsenic
limitations also apply to a fourth wastestream called legacy
wastewater, which is typically discharged from surface impoundments
during the closure process, where those surface impoundments have not
commenced closure under the EPA's coal combustion residuals regulations
under the Resource Conservation and Recovery Act as of the effective
date of the 2024 rule. The 2024 rule eliminated the 2020 rule's
separate standards applicable to two subcategories of facilities or
units (high-flow facilities and low-utilization EGUs), while retaining
the 2020 rule's subcategory for EGUs permanently ceasing combustion of
coal by 2028. The 2024 rule also established a new subcategory for EGUs
permanently ceasing combustion of coal by December 2034, as well as a
requirement for dischargers to post reporting and recordkeeping
documentation to a publicly available website. For indirect discharges,
the 2024 rule established PSES that are the same as the BAT
limitations. Pretreatment standards are directly enforceable and apply
no later than May 9, 2027.
In this final action, the EPA is not changing the underlying BAT
bases in the 2024 rule, nor is the Agency altering the rule's annual
pollutant loadings and environmental impacts; however, as the Agency
has previously announced, it is considering further rulemaking to
modify the 2024 rule's underlying technology bases and associated
limitations or standards. Due to the postponement of these loadings and
impacts, the EPA has conducted an analysis showing the changes in costs
and benefits due to discounting, but given the limited scope of this
current rulemaking, it has not at this time updated its other primary
analyses from 2024.
2. 2024 Rule Litigation
A number of parties challenged the 2024 rule in various petitions
that were consolidated before the U.S. Court of Appeals for the Eighth
Circuit as Southwestern Electric Power Co. v. EPA, No. 24-2123. On
August 27, 2025, the court granted the EPA's request for an abeyance
and ordered the Agency to file a motion to govern further proceedings
within 30 days after publication in the Federal Register of a final
deadline-extension rule.
3. Administrative Petitions for Reconsideration of the 2024 Rule
The EPA has received two petitions for reconsideration, one from
the Edison Electric Institute (EEI) and one from UWAG.
EEI is a trade association that represents U.S. investor-owned
electric companies. On November 13, 2024, EEI sent a petition to the
EPA that included recommendations primarily related to CRL
applicability (DCN SE11943). This petition was updated with a
supplemental letter of EEI priorities on May 8, 2025, which reiterated
recommendations for CRL, and which also included discussion of
extending the deadlines in the 2020 and 2024 rules (DCN SE11948). With
respect to the 2024 rule's permanent cessation of coal combustion by
2034 subcategory, EEI recommended extending the NOPP deadline from
December 31, 2025, to December 31, 2029, to provide more time to
address load growth challenges. EEI also recommended extending the
zero-discharge compliance dates of the 2024 rule. Finally, EEI
recommended that the EPA extend the generally applicable 2020 rule
deadlines for BA transport water and FGD wastewater to at least
December 2027 to allow units to transfer out of the 2028 cessation of
coal combustion subcategory and, instead, install technologies to meet
the 2020 rule's requirements, and thereby continue to operate and
produce power past 2025.
UWAG is a voluntary nonprofit group composed of individual energy
companies and two national trade associations of energy companies: the
National Rural Electric Cooperative Association (NRECA) and the
American Public Power Association (APPA). NRECA represents nearly 900
local electric cooperatives across the U.S.,
[[Page 61334]]
serving 42 million people and covering 56 percent of the Nation's land
area. APPA is the national service organization that represents not-
for-profit local, state, or other government-owned electric utilities.
On February 21, 2025, UWAG sent the EPA a petition for rulemaking to
reconsider and repeal the 2024 rule, as well as administratively stay
the 2024 rule while it is in litigation (DCN SE11944). The petition
requested several reviews of the determinations underlying the 2024
rule, including the 2024 rule's determination that zero-discharge
technology is available and economically achievable to treat FGD
wastewater and CRL. The UWAG petition correspondingly advocated for
postponement of all compliance dates in the 2024 rule.
In addition to these two petitions, on April 25, 2025, the EPA
received a request from America's Power, a national trade association
representing U.S. steam electric power plants and their supply chains.
The letter noted an estimated 29 coal-fired EGUs have committed to
retire by 2028 and, in light of emerging challenges to grid
reliability, urged the EPA to release these units from their retirement
commitments as quickly as possible (DCN SE11903, SE11903A1). America's
Power also made recommendations for revisions to the 2020 and 2024
rules.
While the EPA was aware of the general subjects raised in these
petitions when finalizing the 2024 rule, as discussed below, load
growth and power demands are much higher than predicted just a year and
a half ago, and reliability and resource adequacy concerns have only
intensified. Forecasts not available at the time of the 2024 rule, and
certainly not available for the 2020 rule, warrant additional
consideration with respect to the various deadlines discussed in
section VII of this preamble. These factors and new information have
been evidenced and recognized through numerous reports from and actions
by the Federal Energy Regulatory Commission (FERC), the North American
Electric Reliability Corporation (NERC), grid operators, grid
reliability experts, the power industry, utility groups, and regulatory
agencies, as described in greater detail in section V of this preamble.
4. NOPP Submission Extension Requests
Stakeholders, including grid operators, grid reliability experts,
trade associations, and utilities, have raised concerns that a
significant number of facilities need more time to understand how their
operations fit within a changing landscape of local and regional demand
that is untethered from rapidly approaching compliance timelines
crafted under different demand assumptions used in the 2024 rule. This
includes, among other decisions, whether to avail themselves of the
compliance pathway for EGUs seeking to retire or convert to alternative
fuel sources by December 31, 2034, by the current NOPP submission
deadline of December 31, 2025.
Under these circumstances, the 2024 rule's December 2025 NOPP
submission deadline conflicts with the Administration's priorities of
ensuring reliable and secure domestic sources of energy to meet demand,
as outlined in the Executive Orders section below.
F. Executive Order Summary
Upon taking office, President Trump issued key executive orders to
unleash America's affordable and reliable energy and natural resources,
including to support the ongoing adoption and development of cutting-
edge technologies. These executive orders took steps to encourage the
increase of coal generation to expand domestic energy and avoid
shutting down steam electric power plants, which could place the
electricity grid at risk, to the extent permitted by law. In accordance
with these orders, the EPA has reviewed the relevant issues and
information referenced previously relating to the burden of existing
compliance deadlines and other issues as part of this rulemaking.
Executive Order 14156, Declaring a National Energy Emergency,
invokes emergency authorities to accelerate domestic fossil fuel
production and infrastructure expansion, citing energy reliability,
affordability, and national security concerns. 90 FR 8433 (January 29,
2025).
Executive Order 14154, Unleashing American Energy, directs Federal
agencies to review and remove, as appropriate and to the extent
permitted by law, regulatory roadblocks to energy development within
the U.S., including by streamlining permitting processes and
reconsidering previous mandates related to climate and renewable
energy. 90 FR 8353 (January 29, 2025). It also directs agencies to
review and revise, as appropriate and to the extent permitted by law,
existing regulations to identify those that impose undue burdens on
development or use of domestic energy resources. Id.
Executive Order 14261, Reinvigorating America's Beautiful Clean
Coal Industry and Amending Executive Order 14241, affirms that clean
coal resources will be critical to meeting the rise in electricity
demand due to the resurgence of domestic manufacturing and the
construction of artificial intelligence (AI) data processing centers,
and encourages the utilization of coal to meet growing domestic energy
demands while ensuring Federal policy does not discriminate against
coal production or coal-fired electricity generation. 90 FR 15517
(April 8, 2025).
Executive Order 14179, Removing Barriers to American Leadership in
Artificial Intelligence, seeks to ensure the rapid pace of U.S.
adoption and development necessary to maintain American dominance and
global leadership in AI. 90 FR 8741 (January 31, 2025).
V. Information Supporting the Final Action
A. National Energy Crisis
The CWA requires the EPA, in developing effluent limitations
guidelines and pretreatment standards, to consider a number of
different factors. 33 U.S.C. 1314(b)(2)(B). The EPA has considerable
discretion in evaluating these relevant factors and determining the
weight given to each in reaching its ultimate BAT determination. Texas
Oil & Gas Ass'n v. EPA, 161 F.3d 923, 928 (5th Cir. 1998). Likewise,
the EPA has significant discretion in weighing the statutory factors to
re-evaluate the policy arguments supporting the 2024 rule. Clean Water
Action v. U.S. EPA, 936 F.3d 308, 315 (5th Cir. 2019) (quoting Nat'l
Ass'n of Home Builders v. EPA, 682 F.3d 1032, 1038, 401 U.S. App. DC
227 (D.C. Cir. 2012)) (stating that ``a reevaluation of which policy
would be better in light of the facts'' is the ``kind of reevaluation
[that] is well within an agency's discretion''). As described in
section IV of this preamble, two factors the EPA considers when setting
limitations based on BAT are non-water quality environmental impact,
which expressly includes ``energy requirements,'' as well as ``such
other factors as the Administrator deems appropriate.'' 33 U.S.C.
1314(b)(2)(B). Most notable with this industry is the impact of
environmental regulations, including the steam electric ELGs, on the
U.S. electricity grid. Since the promulgation of the 2024 rule, Federal
agencies, States, grid operators, and grid reliability experts have
identified an impending energy crisis resulting from increased load and
the premature retirement of critical steam electric and other baseload
power plants. NERC has consistently warned of resource adequacy and
reliability shortfalls that
[[Page 61335]]
could occur if coal-fleet retirements occurred faster than the system
could respond by constructing replacement baseload power (DCN SE11931).
This is consistent with previous testimony that the EPA was aware of as
of the 2024 rule.\1\
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\1\ On May 4, 2023, bipartisan commissioners of FERC testified
before the Senate Energy and Natural Resources Committee about the
very real crisis facing the nation's grid. Commissioners warned of a
``looming reliability crisis in our electricity markets,'' ``a very
catastrophic situation in terms of reliability,'' and
``unprecedented challenges to the reliability of our nation's
electric system'' (DCN SE11932).
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Since the promulgation of the 2024 rule in May of 2024, the EPA has
become aware of new information and data demonstrating the existence of
an energy crisis. Much of the information relied upon by the EPA during
the 2024 rulemaking process proved to underestimate energy supply and
demand projections, while more recent information and data points to an
impending, extraordinary spike in energy demand that cannot currently
be satisfied. For example, on October 16, 2024, FERC held a
Commissioner-led Reliability Technical Conference to discuss policy
issues related to the reliability and security of the North American
bulk power system (BPS). Commissioners and witnesses expressed serious
concerns about the anticipated retirement of existing generating
resources, the addition of significant volumes of variable energy
resources, and rapid anticipated electric load growth (DCN SE11933).
More recently, on June 4 and 5, 2025, FERC held another
Commissioner-led Technical Conference titled ``Meeting the Challenge of
Resource Adequacy in Regional Transmission Organization and Independent
System Operator Regions.'' The technical conference addressed how
resource retirements, load growth, and the changing resource mix have
contributed to resource adequacy challenges across the nation. NERC
testified that ``growth projections of electric demand have reached
heights unseen in decades, disrupting resource adequacy plans across
North America'' (DCN SE11950).
Other Federal agencies have also confirmed, and taken action to
address, the energy crisis. For example, the Department of Energy (DOE)
recently issued an emergency order to delay the closure of Consumers
Energy's 1,560-megawatt (MW) J.H. Campbell steam electric power plant
in West Olive, Michigan, citing urgent reliability concerns for the
Midcontinent Independent System Operator (MISO) grid, as the Midwest
braced for peak summer electricity demand (DCN SE11953). The three-unit
steam electric 1,560 MW J.H. Campbell plant, built between 1962 and
1980, was slated to go ``cold and dark'' by June 2025 as part of
Consumers Energy's transition to renewables. In the October 27 revision
of the 2025 Final E.O. report, the DOE concluded the retirement of firm
power capacity such as coal-fired EGUs is exacerbating the resource
adequacy problem, as this capacity is not being replaced on a one-to-
one basis. One of the key takeaways in the report is, ``The status quo
of more generation retirements and less dependable replacement
generation is neither consistent with winning the AI race and ensuring
affordable energy for all Americans, nor with continued grid
reliability (ensuring `resource adequacy')'' (DCN SE11976). The DOE
also recently issued an emergency order under section 202(c) of the
Federal Power Act directing PJM Interconnection (PJM),\2\ in
coordination with Constellation Energy, to operate specified generation
units at the Eddystone, Pennsylvania, Generation Station past their
planned retirement. The order follows recent statements from PJM
warning that its system faces a ``growing resource adequacy concern''
due to load growth, the retirement of dispatchable resources, and other
factors (DCN SE11922). There are over a dozen such emergency orders
issued by the DOE in the past six months alone (DCN SE11999). In May
2025, FERC also approved a reliability must-run contract between PJM
and Talen Energy to keep the Brandon Shores two-unit, 1,280 MW coal-
fired power plant in Anne Arundel County, Maryland, online past its
anticipated retirement date to ensure reliability (DCN SE11961).
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\2\ PJM Interconnection is the regional transmission
organization that manages all or parts of Delaware, Illinois,
Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina,
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the
District of Columbia.
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Public utilities at the state level are taking similar actions to
rapidly change planning activities in response to the energy crisis. In
its 2022 integrated resource plan \3\ (IRP) final order, Southern
Company subsidiary Georgia Power had slated Plant Bowen for retirement
by 2027. More recently, Georgia Power announced plans to extend the
life of several existing coal- and natural gas-fired power plants into
the late 2030s, including proposals to extend operations at the 3.2-
gigawatt (GW) Plant Bowen--one of the world's largest coal plants--from
a previously published 2027 retirement date to the end of 2038
according to their January 2025 IRP (DCN SE12076). Between the filing
of Georgia Power's 2025 IRP and its Budget 2026 Load and Energy
Forecast, the total pipeline of large-load projects through the 2030s
has more than doubled, from 22.8 GW to 51.1 GW (EPA-HQ-OW-2009-0819-
10679, pg. 4). Commenters provided additional data to support these
assessments. Prior to 2024, Southern Company reported roughly flat
growth in its electric service territories due to economic conditions
and energy efficiency; more recently, the utility--the second largest
by customer base in the U.S.--now projects average annual retail sales
growth of eight percent through 2029, a significant increase from the
growth forecast of approximately one percent a few years ago (DCN
SE12029) (EPA-HQ-OW-2009-0819-10679, pg. 4).
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\3\ An Integrated Resource Plan is an electric utility's plan to
meet forecasted electricity demand over a specified future period.
Most States require utilities to have IRPs with a 20-year horizon
and commonly require a detailed plan for the first few years of the
forecasted energy demand. An update is typically required every two
or three years with less-detailed interim reports sometimes being
required annually. As discussed in the 2024 rule, utilities plan and
budget for plant closures as part of the normal IRP process.
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According to NERC, regions across the North American BPS are
positioned to meet peak demand under normal summer and winter
conditions, although elevated risks of electricity supply shortfalls
could persist under periods of extreme temperatures, surging demand,
and resource variability as illustrated by the following example. In
June 2025, a severe heat wave impacted the eastern U.S., significantly
increasing energy demand beyond predictions. The National Weather
Service issued extreme heat warnings of triple digit temperatures
ranging from south of St. Louis to north of Boston. To put the strain
on the grid in context, PJM stated that demand reached about 161,000
MWs on June 23, 2025, the highest level recorded since 2011. According
to FERC, PJM had only about 10 GW remaining to spare at the period of
peak load. FERC chairman Mark Christie noted that grid operators'
ability to just narrowly sustain power supplies through the extreme
heat and humidity without blackouts reflects significant and growing
resource adequacy challenges, stating at a June 26, 2025, briefing,
``We're simply not building generation fast enough, and we're not
keeping generation that we need to keep'' (DCN SE11949).
More broadly, this heat wave also resulted in a June 24, 2025,
power outage that left more than 71,000 customers without electricity
in Michigan, Pennsylvania, New York, and
[[Page 61336]]
Massachusetts, according to Poweroutage.us. The heat wave impacted
other regions as well. On June 24, 2025, the DOE issued an emergency
order to Duke Energy Carolina under Section 202(c) of the Federal Power
Act to address potential grid shortfall issues in the Southeast (DCN
SE11962). We Energies in Wisconsin had planned closures of its Oak
Creek Units 5 and 6 in 2024 and Units 7 and 8 in 2025, but it recently
announced postponement of retiring Units 7 and 8, citing tightened
energy supply requirements in the Midwest power market and the need to
maintain reliable service during peak-demand periods, such as those
experienced during the June 2025 heatwave (DCN SE11963). In San
Antonio, ERCOT deployed 400 MW of mobile generation units to help
reduce the risk of energy shortages during heat waves (DCN SE11964).
B. Regional Energy Reliability and Resource Adequacy Concerns
NERC's mission is to ensure the reliability, resiliency, and
security of the North American BPS. The BPS is made up of six regional
entities \4\ that provide NERC with data, narratives, and assessments
to independently evaluate long-term reliability, recognize trends, and
identify emerging issues and potential risks for the upcoming 10-year
period. NERC develops a long-term reliability assessment (LTRA)
annually based on known system changes as of July of the current year.
NERC is subject to oversight by FERC.
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\4\ The six regional entities (REs) overseen by NERC that
monitor and enforce reliability standards for the BPS are: Midwest
Reliability Organization (MRO), Northeast Power Coordinating Council
(NPCC), ReliabilityFirst (RF), SERC Reliability Corporation (SERC),
Texas Reliability Entity (Texas RE), and Western Electricity
Coordinating Council (WECC).
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``Resource adequacy'' refers to the ability of an electricity
system to meet the power demand of customers at all times, even during
peak usage and potential outages. In the December 2024 LTRA, NERC
identified increasing resource adequacy challenges for the upcoming 10
years as demand growth surges and power generators announce retirement
plans (DCN SE11905). NERC also identified a substantial number of the
replacement generation resources as weather dependent and, thus, more
variable and less reliable than the resources they would replace. This
includes ensuring sufficient generation capacity and reserves to
maintain a stable power supply. The MISO recently affirmed the
importance of these resources in its 2024 Reliability Imperative
report, in which it identified significant challenges associated with
new, weather-dependent resources that ``do not provide the same
critical reliability attributes as the conventional dispatchable coal
and natural gas resources that are being retired'' (DCN SE11929).
Furthermore, NERC categorized six areas in the U.S. as ``Elevated-
Risk.'' \5\ Areas categorized as Elevated-Risk meet established
resource adequacy targets or requirements, but probabilistic or
deterministic analysis of conditions that are plausible but more
extreme than normal seasonal peaks are likely to cause shortfall in
area reserves. More extreme conditions can include temperatures that
result in above-normal demand levels, low resource output or
availability, and/or disruption of normal electricity transfers. NERC
further wrote that ``the aggregate of peak electricity demand for
NERC's 23 assessment areas has risen by over 10 GW--more than double
the year-to-year increase that occurred between the summers of 2023 and
2024'' (DCN SE11938). The 2024 LTRA identified PJM as Elevated-Risk due
to resource additions not keeping up with expected generator
retirements and projected demand growth. Here, winter seasons replace
summer as the higher risk periods due to generator performance and fuel
supply issues.
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\5\ The EPA agrees with comments that, at proposal, the Agency
had cited to a previous version of NERC 2024 LTRA that had
erroneously listed MISO as ``High Risk'' due to a data mismatch
error, which has been corrected in the July 11, 2025, update to the
2024 LTRA.
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Since proposal, NERC has also published its seasonal Winter
Reliability Assessment (DCN SE12030). This report found that six NERC
regions or sub-regions have an elevated risk during extreme weather for
the 2025-2026 winter season. Specifically, the report discusses that,
while the share of power that coal provides continues to decrease, the
ability of coal to be stockpiled for extreme winter weather allows coal
to satisfy an increasingly important role that is infeasible or
prohibitively costly for natural gas, a fuel that NERC describes as a
``just-in-time fuel.''
PJM's 2023 study (DCN SE11847) and 2024 study (DCN SE11901)
highlight several trends that increase reliability risks: the growth
rate of electricity demand; retirements at risk of outpacing the
construction of new resources due to a combination of factors including
siting and supply-chain disruptions; and the fact that PJM's
interconnection queue is composed primarily of intermittent and
limited-duration resources, which need multiple MWs to reliably replace
one MW of thermal generation (e.g., coal, natural gas, nuclear). The
2024 PJM report shows increased wholesale power costs of almost five
percent and significant rises in capacity prices, such as 20 percent in
New Jersey. The 2024 report also highlights PJM concern about load
growth, particularly from data centers and electrification, as a
significant driver of increased demand and capacity needs, as well as
the slow pace of new generation coming online to replace retiring
resources, findings further supported in recent public PJM
communications (DCN SE12077).
The National Association of Regulatory Utility Commissioners
(NARUC) also released Grid Reliability and U.S. Coal Fleet Attributes:
Considerations for State Regulators (DCN SE12000). NARUC stresses the
``. . . need for [. . .] regulations that consider grid reliability . .
.'' While noting that the electric grid will continue to undergo
significant changes, with renewables and storage making up the vast
majority of new capacity in coming years, NARUC pointed out that coal
and other conventional generation have advantages in providing
dispatchable power when needed, stating these plants provide
``consistent, reliable power, especially during periods of high demand
or low renewable generation, such as during extreme weather events.''
Thus, the report echoed NERC in finding that the rapid retirement of a
large number of coal plants is a ``concern.''
In deregulated electricity markets, capacity auctions are used to
send signals monetarily that would lead to similar planning as the IRP
process. PJM capacity auctions are typically held three years in
advance of the capacity delivery year and are designed to ensure
sufficient generating capacity to meet electricity demand and grid
reliability at lowest cost. PJM uses capacity market auctions to accept
offers to provide power at lowest cost first, but recent delays in
auctions due to regulatory issues and litigation have led to higher
prices. This can be seen with the results of PJM's recent capacity
auction for the 2026-2027 delivery year. On July 22, 2025, PJM
announced that it had completed its auction and that the clearing price
was the settlement cap of $329.17/MW-day, a 22 percent increase over
the previous year's clearing price, which was already an increase over
the $28.92/MW-day that cleared the auction two years ago. This
clearance price achieved adequate capacity, including reserve margins,
but cleared by only 139 MW, approximately the amount generated by a
single small- to mid-sized EGU. This reflects the tightening margins
between supply and demand in
[[Page 61337]]
the PJM service area, demonstrating that in the short term, the loss of
even a single coal-fired EGU (which can often be several hundred MW
capacity) could lead to resource adequacy issues (DCN SE11965 and DCN
SE11966).
In addition, the 2024 PJM report states, ``The demand in each
scenario reflects growth from end-use electrification, electric
vehicles and data centers. Recent history of this anticipated growth
has proven unprecedented and dynamic. Average growth estimates for
PJM's summer peak, for example, have increased by 375 percent between
the 2022 and 2024 load forecasts, from 0.4 percent per year to 1.6
percent per year. This trend adds to the complexity of ensuring
reliability through the energy transition'' (DCN SE11901). This report
identifies a drastic increase in energy demand, significantly higher
than was anticipated in formulating the 2024 rule.
Finally, another important aspect of the LTRA is the
interconnection queue. The LTRA reports the interconnection queue has a
backlog for the huge variety of replacement sources and storage
projects seeking to connect to the grid, such as the ERCOT example
above. In summary, the 2024 LTRA identified ``critical reliability
challenges facing the industry: satisfying escalating energy growth,
managing generator retirements, and accelerating resource and
transmission development'' (DCN SE11905).
C. Increasing Energy Demand From Data Centers, Manufacturing, and Other
Causes
A data center is a building or group of buildings that holds
computer systems and equipment to power every day digital services.
These facilities provide space, power, cooling, and security for
servers and network hardware. Data centers power almost everything
online, from websites to banking and video streaming. Consumers and
companies worldwide depend on services that run through data centers
every hour. Many industries, such as healthcare, retail, manufacturing,
and government, rely on data centers for secure storage and quick
access to information. The demand for cloud computing, e-commerce,
streaming, AI programming, and social media makes these sites more
important each year. Data centers use a large amount of electricity,
making reliable and affordable power one of the most important factors
to U.S. economic development and national security (DCN SE12002). Data
centers and the massive power they require are critical to national
security because they store and process sensitive government, military,
and intelligence information, support artificial intelligence (AI)
development, and manage critical digital infrastructure (DCN SE12003).
According to the DOE, from 2014 to 2016 the annual energy
consumption of data centers in the U.S. remained stable at
approximately 60 terawatt-hours (TWh). By 2018, this figure had
increased to around 76 TWh, accounting for 1.9 percent of the country's
total electricity consumption. Recent forecasts expect total power
demand for data centers to be between 74 and 132 GW in 2028,
corresponding to 6.7 and 12 percent of total U.S. electricity
consumption. The adoption and growth of AI has been cited as a leading
driver of surging data center demand in the U.S., with the technology
requiring immense computing power, and several utilities are already
adopting additional power resources to meet this demand (DCN SE11906).
For example, Entergy Louisiana will add three highly efficient steam
electric power plants to its system to meet growing power demands due
to data center expansion in the state, including Meta's $10 billion
data center in northeast Louisiana, which will be the largest in Meta's
fleet (EPA-HQ-OW-2009-0819-10667, pg. 8). In February 2025, American
Electric Power's Indiana & Michigan Power Company reached a joint
settlement with the Indiana Office of Utility Customer Counselor,
Amazon Web Services (AWS), Microsoft, Google, and the Data Center
Coalition to establish a process for new, large-scale industrial
customers like data centers to connect to the grid. Previously, AWS
announced a $11 billion investment in a data center campus in New
Carlisle, Indiana, and another $2 billion data center in Fort Wayne,
Indiana, both among the largest economic development projects in the
state (EPA-HQ-OW-2009-0819-10667, pg. 8). Alliant Energy has cited
Google's $576 million data center investment, and Quality Technology
Services' $750 million data center investment, both in Cedar Rapids, as
contributing to the company's projected 30 percent increase in electric
demand in its service area by 2030 (EPA-HQ-OW-2009-0819-10667, pg. 8-
9). The National Renewable Energy Center's ``Data Center Infrastructure
for 2025'' shows transmission network and new data center demand
capacity coinciding geospatially with large cities, highlighting the
challenges demand growth is already placing on the grid (DCN SE11922).
The EPA notes that consultants, investors, and ratings firms such as
S&P and Moody's identify the U.S. technology sector as one that can
initiate, develop, and complete projects relatively quickly, with new
data centers operational in as little as two to three years. Meanwhile,
the energy sector requires longer lead times to schedule and build
infrastructure as a result of extensive planning requirements and
significant capital investment.
These concerns have been confirmed by several commenters who have
expressed a need for more energy load and reliability due to projected
data center buildout, manufacturing growth, and population growth.
South Carolina requires additional capacity due to the State's seven
percent population increase from 2020 to 2024 (DCN SE12036), and $9.22
billion in economic investments announced in 2023, some of which
includes the buildout of data centers (DCN SE12037 and EPA-HQ-OW-2009-
0819-10679, pg. 3). Edison Electric Institute, which represents all
investor-owned electric companies in the U.S., also cited data center
growth as a core reason to continue expanding energy capacity, relying
on a 2024 report by the Electric Power Research Institute finding that
data centers may consume more than nine percent of U.S. electricity
generation annually by 2030, compared to an estimated four percent
today (DCN SE12038 and EPA-HQ-OW-2009-0819-10667, pg. 7). EEI further
cites the rapid buildout of data centers as a reason why ``EEI members
that planned to retire facilities under the 2028 [Permanent Cessation
of Coal Combustion] PCCC Subcategory are finding during analyses of
fleet operability and efficiency that they may need to keep plants
running for additional years to meet customer demand'' (EPA-HQ-OW-2009-
0819-10667, pg. 15). Natural gas and coal are forecast to meet over 40
percent of the electricity demand from data centers until at least 2030
(DCN SE11967).
Moreover, as described in the President's July 2025 strategy titled
``Winning the Arms Race: America's AI Action Plan'' (DCN SE11954), AI
systems may pose novel national security risks in areas such as
cyberattacks and the development of chemical, biological, radiological,
nuclear, or explosive weapons. Ensuring America is at the forefront of
AI development is vital for national defense and homeland security. The
President issued Executive Order 14179, Removing Barriers to American
Leadership in Artificial Intelligence, making it possible for America
to retain global leadership in AI. 90 FR 8741 (January 31, 2025).
Executive Order 14179 will ensure that AI adoption and
[[Page 61338]]
development is progressing at the rapid pace necessary to maintain
American dominance, which would further expand the need for upgrades to
the U.S. electrical grid to support data centers as identified in the
AI Action Plan (DCN SE11954).
D. Supply-Chain Risks
In addition to the documented increase in energy demand, another
issue facing the power sector, in addition to compliance with the 2024
rule's deadlines, is challenges in obtaining equipment to maintain and
upgrade steam electric power plants. This includes the ready supply of
key components of control technologies (e.g., microchips) that are
experiencing increased global demand from other industries and,
consequently, becoming another rate-limiting factor for the
installation of new wastewater treatment technologies necessary to
comply with wastewater limits. For example, Southern Company's public
comment detailed delays from two vendors that might add 16 weeks or
more to its project schedule (EPA-HQ-OW-2009-0819-10705). To support
this comment, Southern Company provided a memorandum from WesTech (EPA-
HQ-OW-2009-0819-10705, Attachment B) detailing a number of long lead
time components for wastewater technologies including the following:
Pumps, compressors, and blowers have lead times of 28 to
40 weeks due to global vendor capacity constraints.
Pressure vessels and heat exchangers have fabrication lead
times that now extend beyond 30 weeks, influenced by material
availability and shop backlogs.
Electrical and control systems require extended delivery
times of 40-plus weeks in some instances due to semiconductor supply
shortages.
Structural steel and specialty alloys are impacted by raw
material and fabrication delays, resulting in delivery windows ranging
from 26 to 32 weeks.
Some specialized valves and actuators are quoted at 28 or
more weeks.
Critical instrumentation, including transmitters and
analyzers, is averaging 30 weeks due to supply chain dependencies in
electronics manufacturing.
The power industry is also experiencing a significant turbine
backlog, primarily for natural gas turbines, leading to a further
reliance on existing steam electric power plants. A combination of
factors, including increasing electricity demand, particularly from
data centers, ongoing natural gas plant development using combustion
turbines, and airline industry manufacturing, has led to a substantial
increase in orders for gas turbines. Three major original equipment
manufacturers--GE Vernova, Siemens Energy, and Mitsubishi Power--have
reported backlogs stretching into 2029 and beyond. The Electric Power
Research Institute reports a five-year-plus wait for new turbine
installations (DCN SE11930).
Critical grid components, like transformers, are also facing longer
lead times, further impacting project timelines (DCN SE11968).
According to the U.S. Department of Commerce, the average U.S.
electricity grid transformer is 38 years old, fast approaching the 40-
year life expectancy of a transformer. The National Renewable Energy
Laboratory notes utilities needing to add or replace transformers are
currently facing high prices and long wait times due to supply-chain
shortages (DCN SE11969). The National Infrastructure Advisory Council
reports Hitachi has a waitlist of two to four years for transformers,
and supply issues and uncertainty continue to affect development with
lead times for transformers averaging 120 weeks and large transformer
lead times averaging 80 to 210 weeks, with at least one other U.S.
company having a backlog of five years (DCN SE11968). The list of U.S.
infrastructure that depends on transformers includes new housing
developments, a growing electric vehicle charging station market, and
renewable energy projects. For instance, in Texas, companies planned to
build 108 new gas-fired power plants and 17 expansions in the next few
years to power AI and other heavy industries. In just one example,
however, the developer Engie withdrew from two projects in Texas in
February 2025 citing ``equipment procurement constraints'' (DCN
SE11951). With the high uncertainty surrounding resource adequacy over
the next decade, the need to maintain baseload capacity from existing
steam electric power plants will remain for the foreseeable future.
Demand for all major fuels and energy-related technologies jumped
in 2024 worldwide, and coal remains a crucial fuel source in addressing
potential demand spikes in several countries besides the U.S., notably
in China, in India, and across much of Southeast Asia. A May 2025
International Energy Agency report stated that peak demand is slated to
grow even faster than overall power demand, and potentially 80 percent
faster in emerging markets and developing economies by 2035 (DCN
SE11915). These findings highlight that supply-chain issues are
increasing globally (DCN SE11977) and will likely continue to increase
as the demand and the competition for components escalates across the
world.
E. Other Pressures on Retirement
The EPA notes that there are additional legal pressures leading to
generator retirements that are not within the considerations above and
are outside the Agency's CWA authority, but that are relevant to the
extent they inform conditions facing the steam electric generating
industry. These include State or regional laws that may either provide
incentives toward retiring steam electric power generation or
specifically provide timelines for retirements. An example of the
former is the Regional Greenhouse Gas Initiative, which 10 States have
joined to cap and reduce carbon emissions. An example of the latter is
that, in 2021, Illinois passed the Climate and Equitable Jobs Act,
which, with certain exceptions, required the phase-out of coal-fired
power plants by 2030 and natural gas-fired power plants by 2045 (DCN
SE11970).
Some steam electric power plants have also entered into settlements
with States, the Federal Government, and/or local community groups to
retire a plant or EGUs. For example, in 2015, American Electric Power
(AEP) announced a settlement with the Sierra Club and other parties to
cease coal combustion at Cardinal Unit 1 by 2030 (DCN SE11971). More
recently, in 2024, the EPA and two environmental groups entered into a
settlement that results in the closure of the Merrimack Station (DCN
SE11972). These are just some examples of the settlements that continue
to influence steam electric power plants' operations.
F. Recent Changes in Facilities' Plans To Cease Burning Coal in Light
of Rising Demand
Several commenters provided their own examples of how projected
energy demand increases have impacted facility retirement dates and
additional data to suggest that unprecedented demand is driving policy
changes that support the extension of the 2024 rule's deadlines. Talen,
for example, has determined that a 2028 planned retirement of two of
its facilities--Keystone Generating Station and Conemaugh Generating
Station, both in Pennsylvania--is no longer feasible (EPA-HQ-OW-2009-
0819-10695, pg. 7).
In early 2025, Santee Cooper, a public power utility in South
Carolina, reassessed its 2024 IRP adopted in May
[[Page 61339]]
2024 and updated it. This update reflects ``significant uncertainties
on whether Santee Cooper will be able to retire its Winyah Generating
Station by its targeted retirement date of 2033.'' The confluence of a
number of factors \6\ has made it ``impossible'' for Santee Cooper to
``establish a firm retirement date for the four Winyah units, which
would be reflected in a federally enforceable commitment through the
NOPP election by the end of [2025]'' (EPA-HQ-OW-2009-0819-10683, pg.
4).
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\6\ Specific factors cited as challenges to establishing
retirement dates included: unanticipated increases in electricity
demand due to the explosive growth of energy-intensive manufacturing
and data centers, electrification of the transportation sector, and
substantial challenges and timing uncertainties in the development
of new replacement generation and other related energy
infrastructure, including the permitting and buildout of new natural
gas combustion turbines, natural gas pipelines, transmission lines,
and large transformers.
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Buckeye Power's Cardinal Plant submitted a NOPP intending to retire
its unit 3, which was consistent with demand forecasts when the NOPP
was submitted in 2021; however, recent PJM capacity market results
resulted in discussions between Buckeye Power and PJM to continue
operating this unit under a reliability must-run (RMR) order through
May 2029 or longer. Ultimately, Cardinal was able to continue operating
this unit in light of projected increases without an RMR (DCN SE12008,
pg. 125). Similar discussions were had between PJM and KeyCon's
Conemaugh Plant, which had filed a NOPP to retire by 2028, but in light
of recent auctions and clearing prices soaring to their highest level
in decades, KeyCon was able to procure treatment technologies to meet
limitations and remain in compliance for coming years (DCN SE12008, pg.
125-26).
Southwestern Electric Power (SWEPCO) originally submitted a NOPP
for its Welsh Plant to cease coal combustion by 2028. However, as
demand has evolved, to be compliant with its minimum Southwest Power
Pool (SPP) capacity obligations, Welsh would need to convert to an
alternative fuel source or add new generation before ceasing coal
combustion in 2028. If SWEPCO did not meet its capacity obligations,
SPP could issue deficiency charges (EPA-HQ-OW-2009-0819-10671, p. 16).
Southern Company submitted NOPPs for 2028 retirement for 12 units.
While two units retired, two were denied by the public service
commission for retirement, others have repowered or plan to repower,
and the rest of the units transferred applicability to continue
operating in response to load growth (EPA-HQ-OW-2009-0819-10705, p.
26). The Georgia Public Service Commission initially postponed a
decision on the retirement of Plant Bowen in 2022, and in 2025 supports
continued operation to the mid-2030s due to increasing load growth in
Georgia (EPA-HQ-OW-2009-0819-10705, p. 23).
In addition, several power companies (e.g., Mill Creek Generating
Station, E.W. Brown Generating Station, CPS Energy's Spruce Unit 1,
PacifiCorp's David Johnston Plant, KeyCon's Keystone Generating
Station) expressed concern regarding EGU retirements in light of
increasing power demand. Some suggested an extension would allow them
to delay these retirements, in part, to meet surging energy demand. PPL
Corporation and its two subsidiaries, Louisville Gas and Electric and
Kentucky Utilities Company, provided comments indicating that the 2024
rule would likely ``compel premature retirement of a significant number
of our coal generating fleet'' despite the company's projected ``very
high levels of increased demand in the near term.'' Furthermore, PPL
projected that annual energy requirements will climb sharply from
32,808 GWh in 2025 to 48,129 GWh in 2032--an increase of almost 47
percent. Peak summer and winter demand increases of about 1,800 MW for
the same period are also projected (EPA-HQ-OW-2009-0819-10674, pg. 5).
The EEI noted in their comments that several members that had planned
to retire units before the 2028 cessation deadline may need to keep
these units online for additional years to meet customer demand (EPA-
HQ-OW-2009-0819-10667, p.15).
VI. Final Rule
The EPA is extending seven deadlines in the 2024 rule, updating the
2024 rule's transfer provisions to allow facilities to switch between
compliance alternatives, and creating authority for limited additional
timing flexibility for both the 2020 and 2024 rule deadlines, based on
site-specific factors. First, the EPA is extending the date for
existing steam electric power plants to submit a NOPP for the permanent
cessation of coal combustion by 2034 subcategory. In addition to this
deadline extension, the EPA is expanding the transfer flexibilities in
40 CFR 423.13(o) by including a new transfer provision for facilities
wishing to switch between requirements for zero discharge and
requirements applicable to the permanent cessation of coal combustion
by 2034 subcategory. Second, the EPA is extending the latest compliance
dates for zero-discharge limitations applicable to discharges of FGD
wastewater, BA transport water, and CRL. The third set of deadline
extensions apply to standards for the same wastewaters from indirect
dischargers. Specifically, the EPA is promulgating a set of tiered
standards for indirect dischargers that would provide flexibility to
achieve zero discharge on the same timelines as direct dischargers.
Fourth, the EPA is providing authority for additional site-specific
extensions of paperwork submission dates and deadlines in the 2020 or
2024 rules when necessary to address unexpected circumstances.
The EPA's proposed rule solicited comment on each of the provisions
described above, including comments on alternatives and comments
providing information and data supporting the proposed deadline
extensions and related provisions (90 FR 47703 to 47707). Following the
thorough engagement process, which included public webinars, tribal
consultations, and a careful consideration of all comments and
information submitted, the EPA has determined that the final extensions
and related modifications are supported by the full record before the
Agency. As discussed further below in this section, the EPA finds that
none of the alternatives presented by commenters were supported by new
information or otherwise warranted modification to the date extensions
or other provisions outlined in the proposal. The EPA also finds that
suggestions not to move forward with finalizing any of the deadline
extensions or related modifications were not warranted in light of the
record and statutory factors, as discussed more fully in later parts of
this section. As such, and for the reasons described herein, the EPA is
finalizing the proposed extensions and modifications. This rule will,
in part, provide flexibility to a critical industry in advance of
imminent deadlines, which could otherwise force utilities to make
premature and irrevocable decisions to begin the process of
decommissioning without full consideration of rapidly evolving regional
resource adequacy needs.
As part of the proposal, the EPA also requested data to better
understand whether and the extent to which it would be appropriate for
the EPA to undertake more comprehensive reconsideration of the 2024
rule, in part, to ensure grid reliability beyond this rule's most
immediate extensions and related modifications. The decisions described
below reflect the EPA's commitment to maintaining a balanced
[[Page 61340]]
approach that supports both environmental goals and operational
feasibility for an industry on which Americans rely. See the EPA's
response to comments document (DCN SE12008) for a more detailed
discussion of the Agency's finding with regards to public input on the
proposed regulation.
A. NOPP Submission Date Extension
Following publication of the 2024 rule, stakeholders, including
trade associations and utilities, have raised concerns that certain
facilities need more time to decide whether to avail themselves of the
2024 rule's compliance pathway for EGUs seeking to retire or convert to
alternative fuel sources by December 31, 2034. Based on recent
forecasts projecting a surge in energy demand, the EPA finds that the
2024 rule's December 2025 deadline may unreasonably force facilities to
decide to retire when they could still be needed to meet local or
regional resource adequacy and grid reliability needs. Such premature
retirements could result in unforeseen impacts on the ability of the
U.S. to ensure that energy remains abundant, affordable, and reliable
for Americans. This would be inconsistent with the Administration's
prioritization of ensuring a reliable and secure domestic source of
energy to meet those demands. The EPA is committed to ensuring these
steam electric power plants have the option to remain in operation to
increase the Nation's energy supply, meet surging demand (e.g., from
data centers), support regional grid reliability, and grow domestic
manufacturing, jobs, and wages, while simultaneously fulfilling its
statutory duties and advancing the Clean Water Act's goal of
eliminating discharges to the Nation's waters.
Since promulgation of the 2024 rule, the EPA has continued to
discuss electric reliability issues with the DOE, NERC, and other
stakeholders under the framework established in the Joint Memorandum on
Interagency Communication and Consultation on Electric Reliability
(EPA-DOE MOU) (DCN SE11904). At a recent EPA-DOE MOU meeting, NERC
presented findings from its LTRA (DCN SE11905). In the 2024 LTRA, NERC
found that electric reliability will face unanticipated challenges in
the coming decade due to ``surging demand growth'' at the same time
many generators are anticipating retiring, decisions that are being
forced, in part, by the adoption of a regulatory regime that was
informed by significantly lower demand forecasts. One key aspect
identified in the 2024 LTRA is the surging demand growth needs of data
centers. In its 2024 U.S. Data Center Energy Usage Report, the DOE
found that ``U.S. data center energy use has continued to grow at an
increasing rate . . .'' (DCN SE11906). The EPA has also received
additional reports indicating that surging demand will introduce
resource adequacy issues to a greater extent than the Agency
anticipated during the 2024 rule proceedings (see section V).
As previously explained, in the 2024 rule, the EPA established a
subcategory for EGUs permanently ceasing coal combustion by December
31, 2034. For these EGUs, less stringent limitations and standards
apply to discharges of pollutants. These less stringent limitations and
standards are the same as the limitations and standards previously
applicable under the 2020 rule. As there were no nationally applicable
limitations and standards for CRL prior to 2024, the subcategory left
in place the requirement for permitting authorities to develop case-by-
case TBELs using their BPJ, and it established mercury and arsenic
limitations based on chemical precipitation after the retirement of the
plant. In order to participate in this subcategory, facilities had to
submit a NOPP to their permitting authority or control authority by
December 31, 2025, and subsequently submit annual progress reports on
the steps taken to achieve permanent cessation of coal combustion. The
NOPP notifies the permitting authority or control authority of the
plant's intent to opt into the 2024 rule's subcategory for sources that
anticipate closure or repowering.
At the time of the 2024 rule, the EPA estimated there were ``around
50'' EGUs whose retirement dates had been announced between 2030 and
2034. While the flexibilities in the new permanent cessation of coal
combustion subcategory were also applicable to retirements prior to
2030 (especially with regard to CRL), these post-2030 retirements would
have been subject to the full suite of zero-discharge limitations but
for the subcategory. Utilities and trade associations have extensively
communicated to the EPA that facilities need additional time to decide
about ceasing coal combustion in light of surging electricity demand,
especially in areas where data centers and manufacturing facilities may
be constructed in the near future. Several public comments further
confirmed this understanding. For example, Santee Cooper discussed
changes in its South Carolina service area that left the utility
uncertain as to whether it could retire its Winyah facility by 2033
(EPA-HQ-OW-2009-0819-10683).
The EPA received many comments in support of, and in opposition to,
the extension of the NOPP submission date extension. Comments in
support of the extension pointed to many of the same considerations
discussed by the EPA in the proposal. Comments opposing the NOPP
extension pointed to many of the same concerns certain commenters had
with the deadline extensions as a whole (i.e., that the EPA did not
sufficiently justify how concerns with energy reliability or
affordability, as well as supply-chain issues, warrant any regulatory
changes).
The EPA disagrees with comments arguing that the record does not
support a NOPP submission date extension and agrees with those
commenters supporting the proposed NOPP submission date extension to
December 31, 2031. Providing for NOPP submission as late as 2031 allows
utilities to evaluate their most recent IRP or three-year capacity
market auction result before committing to this pathway, and the new
submission deadline does not reflect when all facilities will actually
submit their NOPP to receive subcategorized limitations in their
permit.
In addition, the EPA disagrees with comments characterizing the
NOPP submission date as a substantive regulatory provision in and of
itself, whether those comments supported or opposed the extension of
that date. The primary function of the NOPP is to inform the permitting
authority that the discharger will seek the less stringent
subcategorized limitations applicable to EGUs planning to permanently
cease coal combustion. In this way, it can help the permitting
authority to better understand and prepare the resources needed for
permitting these particular facilities. However, beyond conveying this
intent to the permitting authority, the NOPP serves no other purpose
for regulated utilities or permitting authorities. Regardless of the
timing of the NOPP submission, and even if the EPA were to eliminate
the requirement to file a NOPP altogether, the limitations of the
subcategory and corresponding substantive deadlines would still apply
as they did prior to this final deadline-extension rule.
With respect to the suggestion that issuing a DFR extending the
NOPP date demonstrates that the EPA pre-judged the outcome of this
rulemaking, the Agency disagrees. As the EPA stated above and in the
proposal, allowing for NOPP submission as late as 2031 lets utilities
evaluate their most recent IRP or three-year capacity market auction
result before committing to this compliance pathway. While the EPA
[[Page 61341]]
could have issued a DFR with an earlier submission date that did not
exceed the zero-discharge compliance dates, this would have resulted in
the Agency needing to take a second action, shortly after the first, to
extend the NOPP submission date once again, even after the DFR went
into effect.
The rationale for the subcategory for the permanent cessation of
coal combustion by 2034 was set forth in the 2024 rule and, as
described in that rule, is based on the statutory factors in CWA
sections 301 and 304. The NOPP provides the mechanism for facilities to
make use of that subcategory, and thus the date for the NOPP submission
is authorized under CWA section 501(a), which allows the Administrator
to prescribe such regulations as are necessary to carry out his
functions, including establishment of ELGs, pursuant to sections 301
and 304 of the CWA. As such, the EPA is extending the NOPP date in 40
CFR 423.19(h) from December 31, 2025, to December 31, 2031. The new
December 31, 2031, NOPP submission date is three years prior to the
permanent cessation of coal combustion date and, thus, would allow for
the most accurate three-year capacity auctions in deregulated regions
(e.g., PJM) or the more typical two- to three-year IRP cycle to
conclude prior to a plant opting into the subcategory with a NOPP. See
the response to comments document (DCN SE12008) for further discussion
of EPA findings related to the NOPP extension.
B. Withdrawal of NOPP Companion Direct Final Rule
Contemporaneously with the notice of proposed rulemaking, the EPA
published a direct final rule extending the date (from December 31,
2025, to December 31, 2031) for existing steam electric power plants to
submit a NOPP in the 2024 rule's subcategory for EGUs permanently
ceasing coal combustion by December 31, 2034.
The EPA received adverse comments on the direct final rule and
thus, as the Agency indicated it would in such event, subsequently
withdrew that rule (90 FR 54588, November 28, 2025). The deadline
extension for NOPP submission is instead addressed by this final
action.
C. New Transfer Provision
The EPA is establishing a set of new transfer provisions in 40 CFR
423.13(o) to enhance flexibility to choose among compliance
alternatives. As described in the 2020 rule, even where facilities have
provided a NOPP and publicly announced retirement or repowering plans,
actually ceasing coal combustion may ``require local or state
regulatory approval prior to reducing its utilization or planning to
retire . . .'' 85 FR at 64709. Such procedural steps continue to exist,
and in light of energy demand concerns and commitments, they may not be
ultimately fulfilled. Thus, a plant fully intending to retire steam
electric power generation under a previous announcement could be
subject to unanticipated demand growth or other circumstances that lead
a regulatory authority to reject the retirement decision. In such
cases, it is reasonable and consistent with the statutory and
regulatory framework to permit a plant to transfer back into a
compliance pathway that applies the generally applicable zero-discharge
limitations. Similarly, it is possible that a plant intending to remain
in operation may not clear a capacity auction or may be required by a
State regulatory body to retire. In such cases, it would contradict the
intent of the subcategory to treat these facilities differently from
those that were carrying out earlier planned retirements.
The EPA did not receive adverse comments on the proposed transfer
provision distinct from comments relating to the proposed compliance
deadline extensions. Several commenters provided suggested edits,
largely based on specific needs of a utility or a utility group.
However, the EPA did not find the suggested revisions were accompanied
with a sufficient underlying rationale to warrant modifying the
proposal for this final rule. As such, the EPA is finalizing these
provisions as proposed--allowing transfers into and out of the
subcategory for EGUs permanently ceasing combustion of coal by 2034 up
until the December 31, 2034, deadline--to ensure that facilities facing
unexpected changes in operations are not unfairly penalized as compared
to the rest of the industrial sector. See the response to comments
document (DCN SE12008) for a more detailed discussion on this topic.
D. Extended BAT Applicability Timing for Zero-Discharge Limitations
As originally promulgated, the 2024 rule's zero-discharge
limitations must be met as soon as possible, but ``no later than''
December 31, 2029. As part of its rationale for establishing this
latest date, the EPA stated that this date created ``a level playing
field'' for facilities regardless of where they were in their five-year
permit cycle. 89 FR at 40256. After considering the comments, and for
the reasons discussed below, the EPA is extending the ``no later than''
dates for zero-discharge limitations in the 2024 rule (applicable to
discharges of FGD wastewater, BA transport water, and CRL) to December
31, 2034 (i.e., one additional permit cycle).
The EPA finds that postponing the ``no later than'' dates is
warranted for several reasons, supported by the statutory factors,
found in sections 301 and 304 of the CWA, of availability,
achievability, cost, non-water quality environmental impact (including
energy requirements), and such other factors as the Administrator deems
appropriate. Three reasons, in particular, led to the EPA's finding.
First, the December 31, 2029, date for meeting the limitations no
longer is ``available'' for all facilities under the current
circumstances due to constraints in the ability to procure and install
the control technologies or their component parts, including as a
result of supply-chain disruptions, as well as competition for skilled
labor. Second, delaying the ``no later than'' date is critical in
allowing facilities that recently invested in technologies to meet the
2020 rule a longer period to amortize the costs of those technologies,
which is expected to improve their ability to undertake additional
investments towards compliance with the 2024 rule, in addition to
having less impact on customer rates. Finally, postponing the ``no
later than'' date until December 31, 2034, gives facilities the ability
to transfer out of the permanent cessation of coal combustion by 2034
subcategory and still meet the applicable BAT limitations by their
deadline, thereby allowing them to continue to generate electricity
using coal resources as necessitated by local or regional resource
adequacy and reliability needs and to mitigate an impending national
energy emergency. This postponement also provides the EPA time to
consider a subsequent rulemaking where it can further review new
comments and data received on the costs, economic achievability, and
energy impacts of the zero-discharge requirements that are subject to
extended compliance deadlines in this final rule.
The EPA received a number of comments in support of, and in
opposition to, the deadline extensions. One group of commenters argued
that the proposed rule's legal and factual bases for the extensions
were improper and fully opposed them. These commenters further insisted
that the record does not support the reasons the EPA provided as
justification. Specifically, these commenters disputed that there were
any documented supply-chain delays demonstrating the deadline of 2029
is not achievable. These commenters stated that the EPA only provided
anecdotal evidence of supply-
[[Page 61342]]
chain issues impacting industry compliance or that evidence presented
was not ``new.'' Commenters also argued that the compliance date of
2029 was still technologically available using the EPA's own analysis
and findings. Finally, these commenters disputed the EPA's proposed
findings that there was a national energy crisis leading to resource
adequacy and reliability concerns or that demand from data centers and
manufacturing growth was as much as claimed. Therefore, these
commenters asserted that planning timeframes did not support the need
for flexibility until as late as 2034.
A second group of commenters argued that the deadline extensions
would not cure the underlying legal and factual deficiencies in the
2024 rule. These comments typically also included tacit support for the
extensions as a temporary fix while the EPA reconsidered the underlying
regulatory provisions.
A third group of commenters supported the deadline extensions and,
in some cases, recommended changes. These comments supported both the
legal and factual bases for the extensions or suggested additional
rationales. These comments also supported extending all the zero-
discharge limitations, citing the fact that many facilities choose to
develop co-treatment of wastewaters. Many of these commenters agreed
that there were supply-chain issues affecting the feasibility of a 2029
compliance deadline. One commenter cited a recent six-month delay in a
necessary component and overall schedule for a membrane and thermal
system designed to meet the VIP limitations for FGD wastewater. Several
other comments represented that these systems were not available by
2029 either due to supply-chain issues or other reasons. One of these
comments provided an engineering dependency chart demonstrating that a
plant in South Carolina would need until December of 2031 to complete
installation of a zero-discharge system. Some commenters further
suggested that competition over skilled labor meant that, while the
2029 deadlines might be achievable by some facilities, they may not be
feasible industrywide.
Several commenters also agreed with the EPA that cost recovery is
often spread over longer timeframes than the four years between the
2020 rule deadlines (no later than 2025) and 2024 rule deadlines (no
later than 2029). In particular, some commenters pointed to examples of
a 20-year bonding program that was approved by one state public utility
commission. These commenters also agreed with the EPA that allowing
until 2034 would provide the greatest latitude to facilities to
transfer between the compliance alternatives of the 2024 rule and avoid
rushed decision-making and premature retirements that could impact
resource adequacy and reliability. Some commenters suggested that the
EPA is warranted in extending compliance deadlines so that facilities
would have sufficient time to see the results of any subsequent
rulemaking before committing further resources to compliance. Some of
these comments pointed to the 2017 postponement rule (82 FR 43494,
September 18, 2017) as a precedent for the EPA to take this action. In
light of the comments received and EPA's careful review of the record,
the EPA is finalizing the zero-discharge compliance deadline extensions
as proposed. The following paragraphs further explain the reasons for
the EPA's decision.
1. Industry-Wide Installation of the 2024 Zero-Discharge Limitations
Cannot Reasonably Be Achieved Nationwide by 2029 Due to Longer-Than-
Expected Timelines and Delays in Procuring Necessary Components and
Completing Installation
The first basis supporting the EPA's decision to postpone the
latest compliance deadlines for the zero-discharge limitations is the
longer-than-expected timelines and delays in procuring necessary
components and completing installation of the relevant wastewater
control technologies. With respect to the first basis for the
postponement, supported by the statutory factors of technological
availability and ``other factors'' (here, supply-chain risks), the EPA
concludes that the record clearly demonstrates that at least some
extension is warranted, as discussed further in this section. And the
EPA also concludes that the record supports an extension until 2034 for
the latest deadline, for the reasons also discussed below.
In feedback on the proposed rule, electric utilities and trade
associations provided information calling into question the ability of
plants to meet the 2024 rule zero-discharge requirements on the
timeframes set forth in that rule. In particular, some commenters
offered new information with timeframes for specific steps in the
implementation of zero-discharge technologies that could result in
exceedance of the ``no later than'' December 31, 2029, compliance dates
(e.g., see Southern Company Comments--EPA-HQ-OW-2009-0819-10705), and
Santee Cooper submitted a detailed engineering dependency chart
demonstrating that it cannot comply with the 2024 rule's requirements
for FGD wastewater prior to December 2031 (EPA-HQ-OW-2009-0819-10769).
After considering this new information, it is apparent that at least
some facilities will need longer timeframes than until 2029 to
comply.\7\
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\7\ While environmental groups correctly note that, in some
circumstances, facilities may be able to request a variance, this
does not eliminate the EPA's duty to establish reasonable timeframes
for a national regulation, pursuant to the statutory factors
prescribed by the CWA.
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This assumption is bolstered by the fact that the vendor that sold
the zero-discharge system employed at one plant (the NRG Parish plant)
submitted comments on the proposed rule that support the EPA's finding
that delayed implementation is warranted, in part, to avoid
overwhelming qualified contractors.\8\ This vendor is not the only
commenter to have raised such concerns. Other commenters noted that
competition for skilled labor and supplies means that, while individual
facilities may still be able to comply by 2029, industrywide conversion
may take longer, a consideration that similarly factored into the EPA's
choice of applicability timing in the 2020 rule (85 FR 64683).
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\8\ While the vendor supported an extension, the vendor also
suggested a staggered variant of the deadline extension wherein some
facilities comply sooner and information from those facilities is
shared with ``higher risk'' facilities to create a larger base of
``operational know-how.'' The EPA did not finalize this alternative
approach.
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In addition to the information that longer timeframes may be needed
for at least some plants, supply-chain disruptions risk further delays
in these timelines, which were already problematic for compliance.
While the EPA agrees in part with comments that supply-chain issues are
not wholly ``new'' concerns, the Agency has identified disruption in
supply chains as an issue ever since the 2020 rule (85 FR 64683). The
fact that supply-chain issues continue to linger, and that these issues
continue to result in delays in the ultimate timeframes to commission
wastewater treatment systems, are important aspects of the problem that
the EPA should consider. Motor Vehicle Mfrs. Ass'n v. State Farm Mut.
Auto. Ins. Co., 463 U.S. 29, 43 (1983). The EPA also agrees with
comments stating that the Agency has authority to consider supply-chain
risks as an ``other factor'' that the Administrator deems appropriate,
under CWA section 304(b), when determining BAT applicability, and it
has done so here.
Furthermore, the nature of supply-chain risks is not static, but
continues to evolve. In 2020, the EPA was primarily concerned about
supply-chain
[[Page 61343]]
disruptions from the COVID-19 pandemic and how it impacted the timing
of the technologies required to comply with the 2020 rule's generally
applicable limitations (e.g., biological treatment). At that time, the
EPA did not consider supply-chain risks a concern for meeting BAT
limitations in the VIP, as the rule gave utilities over eight years to
install the relevant technologies to meet such limitations.
Stakeholders have recently identified delays in obtaining critical
components for these same technologies (which can be used to achieve
the 2024 rule's zero-discharge limitations), and these newly identified
delays have the potential to delay existing coal-fired EGUs from
complying with the 2024 rule's limitations on the timelines envisioned
in that rule, as the following example shows.
Georgia Power Company's Plant Scherer has experienced delays in
receiving equipment for its membrane and brine crystallization system
that may delay the project timeline by up to 16 weeks. While this 16-
week project delay is not expected to singlehandedly cause the facility
to miss the 2028 deadline for achieving the 2020 rule's BAT limitations
in the VIP, that deadline was over eight years from publication of the
2020 rule and over seven years from the facility submitting a NOPP
requesting VIP limitations in its permit. In contrast, the latest zero-
discharge deadlines in the 2024 rule were approximately five and a half
years from publication and a mere four years from the December 31, 2025
deadline to submit a NOPP, should a facility have opted into the
subcategory for the permanent cessation of coal combustion by 2034.\9\
When considering FGD wastewater and CRL,\10\ these deadlines also apply
to a much larger group of facilities than the handful of facilities
that opted into the 2020 rule VIP as of the October 2021 deadline.
Thus, while facilities in the 2020 rule's VIP may be able to
accommodate a 16-week delay due to the longer timeframe of that
compliance pathway, the shorter timeframe and larger number of
facilities needing to comply with the 2024 rule's zero-discharge
limitations substantially raises the likelihood that at least some
facilities will face delays impacting compliance.
---------------------------------------------------------------------------
\9\ The EPA only notes the NOPP filing deadline to the extent
that facilities may not have been certain of their compliance
pathway prior to this date.
\10\ BAT for BA transport water is not based on the same
technologies as FGD wastewater and CRL.
---------------------------------------------------------------------------
Plant Scherer is also not the sole example provided by commenters.
Others stated that similar supply-chain issues have impacted
installation schedules for at least two other plants in the VIP while
waiting for critical component parts, such as specialty alloys and
rotating equipment (EPA-HQ-OW-2009-0819-10667-A1 Comment Excerpt 11;
EPA-HQ-OW-2009-0819-10694-A1, Comment Excerpt 16). Another comment adds
that the wait time for membrane delivery can be over two years (e.g.,
28-month lead time), which would follow the sometimes equally lengthy
process of designing the new wastewater treatment system for a given
plant (EPA-HQ-OW-2009-0819-10679, pg. 39).\11\ These specific examples
demonstrate that supply-chain delay concerns are more than just
hypothetical, as some commenters have suggested.
---------------------------------------------------------------------------
\11\ This comment also states that lead times for SDEs are 13
months.
---------------------------------------------------------------------------
The challenge in weighing supply-chain risks is further supported
by comments from technology vendors themselves. While one treatment
technology vendor submitted a comment reaffirming its ability to
deliver treatment technologies within the original 2029 compliance
deadlines, this vendor relied in part on its previous experience and
staffing converting BA systems to 2024 rule-compliant systems across
the coal fleet. However, the technologies for FGD wastewater and CRL
are not the same as those for BA conversions, and even if that
experience is directly translatable, BA conversions occurred over a 10-
year period from the publication of the 2015 rule to 2025, whereas the
timeframe under the 2024 rule is only five and a half years.
Two other zero-discharge technology vendors submitted comments on
the proposal expressly supporting the need for additional time. One
vendor agreed with the EPA's proposed extension, while the other vendor
recommended a staged compliance timeline rather than the ``no later
than'' dates specified in the rule to avoid what they referred to as a
``compliance cliff'' (EPA-HQ-OW-2009-0819-10666-A1, Comment Excerpt
Number 3). While the EPA agrees that it could be counterproductive to
just push off compliance by five years for all facilities, this is not
how section 423.11(t) operates. That provision requires permitting
authorities to establish a date that is ``as soon as possible'' subject
to the consideration of four factors but ``no later than'' the dates
that the EPA is postponing in this action. Thus, if properly applied,
this will result in some gradual adoption of zero-discharge
technologies rather than a rush for all facilities to convert in 2034.
Furthermore, a number of facilities are proceeding with these
technologies under the VIP or are in the process of transferring out of
the permanent cessation subcategory into the VIP, and thus they will
still be installing these same technologies by 2028.
Some commenters argued that the compliance date extensions are not
warranted because the 2024 rule record demonstrated that membrane,
thermal, and SDE technologies could be installed in timeframes shorter
than 2029 and because at least one plant (the NRG Parish plant)
subsequently did just that in under two years. While the EPA
acknowledges that parts of the 2024 rule record appear to support the
2024 rule's original timeframes, the Agency disagrees that the
compliance deadline extensions are not warranted. The information
pointed out by these commenters must be considered along with other
record evidence, particularly newer information, showing longer
timeframes are needed, as described above.
After carefully considering the information before it, the EPA has
determined that the weight of the evidence shows that the 2024 rule BAT
technologies are no longer available nationwide on the timeframes
provided for in that rule and, therefore, expecting compliance by 2029
is no longer reasonable. Courts have recognized that the EPA must
select a ``reasonable'' time by which BAT limitations are available.
See Am. Frozen Food Inst., 539 F.2d at 132 (endorsing the view that,
although the best available standard does not mean that the technology
must be in actual routine use somewhere, it does mean that the
technology ``must be available at a cost and at a time which the
Administrator determines to be reasonable'') (citation omitted); see
also CPC Int'l, Inc. v. Train, 515 F.2d 1032, 1048 (8th Cir. 1975)
(same). Thus, the EPA's next task was to determine the precise length
of the extension. The EPA has decided that an extension until 2034 is
reasonable because it addresses the on-the-ground realities and
concerns discussed above, and extending the latest compliance deadlines
one additional permit cycle will create parity wherever a plant is in
its particular permit cycle. Selecting compliance dates that account
for the fact that the CWA envisions issuance of NPDES permits on a 5-
year schedule, 33 U.S.C. 1342(b)(1)(B), is consistent with how the EPA
structured its compliance period in the 2015, 2020, and 2024 rules. The
EPA further notes that it did not extend these deadlines past 2034 as
[[Page 61344]]
some comments suggested.\12\ Instead, any unforeseen circumstances that
may be out of a facility's control and would hinder a facility's
ability to comply by 2034 could, where appropriate, be sufficiently
addressed by the site-specific timeline flexibilities established at 40
CFR 423.18(d), as discussed below.
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\12\ As was done in the 2015, 2020, and 2024 rules, the EPA will
also evaluate availability timing as part of any subsequent
reconsideration.
---------------------------------------------------------------------------
2. An Extension of the Latest Compliance Deadlines for the 2024 Rule's
Zero-Discharge Limitations Until 2034 Is Warranted Based on the Adverse
Impacts on Customer Rates Resulting From the Cumulative Costs of
Complying With Multiple Rules in Short Succession
The second basis supporting the EPA's decision to postpone the
latest compliance deadlines for the zero-discharge limitations is the
adverse impacts on customer rates, which have seen soaring increases,
including the cumulative costs to utilities of complying with both the
2020 and 2024 rules in short succession. This second basis is supported
by the statutory factors of ``cost'' and ``other factors as the
Administrator deems appropriate,'' which in this case is electricity
price impacts to residential households. The EPA disagrees with the
commenter that suggests that finalizing the deadline extensions would
increase residential electric customer bills in either the short run or
the long run. Electricity bills are climbing rapidly and, while not all
service areas have experienced the same 20 percent electricity price
increase seen in New Jersey (DCN SE11952 and SE11973), many states have
seen prices rise over recent years (DCN SE12031). Electricity prices
had already been a problem for many Americans. In 2021, many moratoria
on utility shut-offs ended with tens of billions of dollars in bills
coming due ``as high as $1,500 to $2,000'' for some customers (DCN
SE12032), and yet a recent article documented that U.S. Census Bureau
data show an increase from 20 percent to 24 percent of households
unable to pay their energy bills between 2021 and 2024 (DCN SE12031).
These challenges would continue to mount for utilities forced to
comply with the 2024 rule under that rule's deadlines. One municipal
commenter explained that, if their utility had to rush to install zero-
discharge systems for BA transport water and CRL under the timeframes
of the 2024 rule, their customers would face a price increase of up to
15 percent (EPA-HQ-OW-2009-0819-10691). Instead, this commenter
supported the proposed deadline extensions being finalized because, in
part, it would allow the municipality to ``orient their budget cycles
to the compliance schedule'' (EPA-HQ-OW-2009-0819-10691). The EPA
agrees with this commenter that longer implementation timeframes can
moderate impacts to electricity consumers. Specifically, two
municipalities that recently procured zero-discharge technologies to
treat CRL were able to avoid price increases to existing tipping fees,
in part because they were provided ample time to plan and save for
these expenditures (DCN SE12033, DCN SE12034).
This consideration is more pronounced for facilities with FGD
wastewater. The EPA agrees with comments stating that typical
amortization periods for wastewater treatment technologies are 20
years. One comment providing a specific state approval of a 20-year
cost-recovery program bears this timeframe out as normal and
appropriate (EPA-HQ-OW-2009-0819-10665). The 2020 and 2024 rules
discussed how facilities incur greater capital costs when amortized
over fewer and fewer years. Specifically, the record demonstrated that
annualized capital costs approximately double when amortization shrinks
from the typical 20-year period to eight years. 84 FR 64640. In some
cases, under the 2024 rule, facilities completing installation of a
biological treatment system by the end of 2025 would be required to
turn around and install zero-discharge systems by 2029.
In the 2024 rule, the EPA's analysis showed that these cumulative
costs were economically achievable within the previously projected
electricity market supply and demand; however, these supply and demand
assumptions have proven inaccurate, as discussed previously.\13\ In
addition to the requirement under section 304(b) of the CWA to consider
``cost,'' the effects of cumulative impacts are an important
consideration that agencies regularly consider,\14\ and back-to-back
amortization of costs incurred by some of the larger plants to meet the
2020 and 2024 rules could mean steep rises in costs to utilities. These
costs are often passed on, leading to similarly steep rises in
residential electricity prices, at a time where there are significant
concerns related to the grid demand and reliability.\15\ While the CWA
does contemplate technological advancement, in addition to the
requirement to consider the ``cost'' of achieving effluent reduction,
as mentioned, the Act also requires consideration of ``such other
factors as the Administrator deems appropriate.'' 33 U.S.C.
1314(b)(2)(B). The EPA has historically examined potential impacts on
residential electricity prices in previous iterations of the Steam
Electric ELG as an ``additional factor that might be appropriate when
considering what level of control represents BAT'' (80 FR 67856, 85 FR
64685). Providing facilities more time to amortize the costs of the
previous 2020 rule helps reduce short-term price pressures on American
families, as well as domestic manufacturers, and adds additional
support for this action's extension of the latest deadlines for the
2024 rule's zero-discharge limitations.
---------------------------------------------------------------------------
\13\ The EPA expects to update any relevant portions of its cost
and achievability analyses, as appropriate, in any subsequent action
considering revisions to the underlying technology bases for the
2024 rule.
\14\ See, e.g., Executive Order 13563--Improving Regulation and
Regulatory Review.
\15\ Again, while the EPA's 2024 rule record analyzed these
electric price increases, the EPA expects to update any relevant
portions of this analysis in a future rulemaking to reflect more
current conditions, as appropriate.
---------------------------------------------------------------------------
3. An Extension of the 2024 Rule's Latest Compliance Deadline for Zero-
Discharge Limitations Is Warranted To Ensure Plants Can Continue
Operating To Support Grid Reliability and in Light of Legitimate
Uncertainties About the Economic and Energy Impacts of the 2024 Rule
The third basis supporting the EPA's decision to postpone the
latest compliance deadlines for the zero-discharge limitations is the
need to ensure plants can continue operating to support grid
reliability and in light of legitimate uncertainties about the economic
and energy impacts of the 2024 rule. With respect to the third basis
for the postponement, based on the statutory factors of economic
achievability, as well as non-water quality environmental impact
(including energy requirements) or ``other factors'' (resource adequacy
and grid reliability), the EPA agrees with comments stating that there
is a national energy crisis impacting resource adequacy and grid
reliability. The EPA has continued to identify information supporting
this conclusion, including NARUC (2025), NERC 2025-2026 Winter
Reliability Assessment, and information provided in various public
comments. The EPA also agrees that increasing demand from data centers,
manufacturing, and other causes could exacerbate these issues in the
short run. The EPA received several comments detailing population
growth, manufacturing growth, and data center
[[Page 61345]]
projects that are leading to demand increases in several service areas.
As a result of this information, the EPA disagrees with comments that
appear to cherry pick information to the contrary and present that
information as a justification for retaining the 2024 rule's 2029
compliance deadlines.
While these commenters list a litany of supposed errors in the
EPA's rationale, their complaints sometimes contradict each other. For
example, some commenters state that the EPA does not have the expertise
to make judgments about reliability and resource adequacy or that the
Agency should defer to states, which are given the primary oversight of
reliability-related issues, whereas other commenters accuse the Agency
of not conducting sufficient analysis on those issues. Some commenters
even go so far as to suggest that the EPA second-guess the DOE's
lawfully issued Federal Power Act section 202(c) orders.
The EPA disagrees with the premise of these comments, as they
illustrate a misunderstanding that the Agency is trying to regulate the
electric grid or make primary findings regarding the operations
thereof. To the contrary, the EPA is merely pointing to what competent
state, national, and North American electric reliability authorities
have already concluded as the Agency decides how best to implement its
statutory directive to establish technology-based regulations governing
point source discharges under the CWA. Even taking these commenters'
information as true, the EPA finds that, at most, it demonstrates that
there is uncertainty as to future demand growth, resource adequacy
needs, and reliability concerns. To the extent that these commenters
point to information that calls out these uncertainties, the EPA agrees
that the future on these difficult issues is uncertain, but that is no
reason to continue with the status quo. In fact, uncertainty is
commonly accounted for by reliability authorities through probabilistic
assessments. For example, NERC states that it conducts its analysis of
electricity shortfall risks by considering ``probability-based risk
assessments'' (DCN SE12030).
The EPA notes that there is also uncertainty in the extent to which
the 2024 rule is driving closures in the near term. Closures matter in
determining the economic achievability of the rule, as well as impacts
on grid reliability, which the EPA may consider as an ``energy
requirement'' or, alternatively, an appropriate ``other factor'' in its
BAT decision-making. The EPA disagrees with comments stating that the
2024 rule analyses demonstrate that the costs of the rule are still
economically achievable and that the impacts on coal-fired plants are
small. In response to the EPA's request for data to support any
subsequent rulemaking, commenters have raised concerns that the
Agency's data may be stale, the Agency may have underestimated costs,
and these underestimated costs may have led to underestimated market
impacts.\16\ Furthermore, some commenters have provided cost estimates
of systems that are significantly more expensive than the EPA's
estimates in 2024. Compounding these purported analytical inaccuracies,
underlying inputs for electric market modeling (e.g., demand
projections) have also changed significantly in just one year. These
factors all result in the impacts of the 2024 rule being uncertain,
despite the relatively short time that has elapsed since the 2024 rule
analyses were performed.
---------------------------------------------------------------------------
\16\ Even if the impacts were accurately estimated, costs and
impacts that the EPA found to be achievable in 2024 may no longer
be, in light of the Agency's findings regarding resource adequacy
and reliability.
---------------------------------------------------------------------------
However, it is also not reasonable for some commenters to request
that the EPA update all the Agency's data and analyses prior to
finalizing this deadline-extension rule, and such an update is not
legally required. The EPA has always been clear that it would conduct
any reconsideration in multiple phases (DCN SE12039), and in the
proposed deadline-extension rule the Agency explicitly stated that it
would use information received from its data request to ``define the
scope of this subsequent rulemaking to potentially revise the
underlying technology bases for certain limitations and standards in
the 2024 rule'' (90 FR 47708). This is consistent with the approach
taken in the 2017 postponement rule. That rule was finalized relatively
quickly, and without revising the EPA's major analyses, which were only
updated during the subsequent 2020 reconsideration rule (85 FR 64650),
a substantial effort that took three years. The U.S. Court of Appeals
for the Fifth Circuit upheld the EPA's 2017 postponement rule as a
lawful follow-on rulemaking to the 2015 rule. Clean Water Action v.
EPA, 936 F.3d 308, 315-16 (5th Cir. 2019). Assuming a three-year re-
analysis here, the EPA would not be able to meaningfully evaluate the
very data it asked for and finalize a rule until 2028. It would make no
sense for the EPA to finalize a deadline-extension rule one year before
the 2024 rule's latest compliances deadlines for zero-discharge
limitations, as most of the costs for the rule would have been incurred
and most of the construction completed. Instead, the EPA is proceeding
exactly as it said it would by completing this relatively narrow and
tailored first rule and then, after determining the scope of a
subsequent reconsideration rulemaking, commencing the difficult work of
updating all its analyses and conclusions, as appropriate. This
approach is entirely consistent with case law finding that an agency
``need not solve every problem before it in the same proceeding.''
Mobil Oil Expl. & Producing Se. v. United Distrib. Cos., 498 U.S. 211
(1991) (citing Vt. Yankee Nuclear Power Corp. v. NRDC, Inc., 435 U.S.
519, 543-544 (1978) (agencies are free to engage in multiple rulemaking
``absent constitutional constraints or extremely compelling
circumstances'').
The EPA also notes that coal-fired power plants serve a unique
niche in the electric grid. As discussed in NARUC (2025) and NERC 2025-
2026 Winter Reliability Assessment, these plants, unlike natural gas
plants, have fuel stockpiles and can reliably provide dispatchable
power during extreme weather (DCN SE12000 and DCN SE12030). These
findings are consistent with the operations of the Keystone and
Conemaugh plants, which total 3,400 MW of nameplate capacity and were
dispatched during Winter Storm Elliot, allowing PJM to avoid a load
shedding event (DCN SE12042). This illustrates the importance of
maintaining a diverse fleet of generating units that includes a variety
of fuel sources, a fact that the EPA cited in subcategorizing oil-fired
units in the 2015 rule (80 FR 67856).
Based on the foregoing considerations, the EPA has concluded that
an approach that meets the statutory directives and environmental goals
of the CWA while respecting the needs for resource adequacy and
reliability is warranted in the short term. In particular, by extending
the latest compliance deadlines for the zero-discharge requirements in
the 2024 rule to December 31, 2034, the EPA can help ensure that plants
that might be planning for retirement or repowering by 2034 can more
readily stay online past that date to meet the Nation's energy
requirements and still be on track to meet the otherwise applicable
effluent limitations. Furthermore, while the commenters paint a picture
in which costs and impacts of the 2024 rule are small, interconnection
queue backlogs are resolved, and new generation and storage projects
are able to quickly address resource adequacy concerns, this scenario
falls on one end of a spectrum of probabilistic outcomes.
[[Page 61346]]
Other probabilistic outcomes include those with significantly higher
costs and impacts, high demand growth, delays with commissioning new
generation, and impactful extreme weather events. Instead of
definitively resolving these uncertainties, it is appropriate for the
EPA to fulfill its statutory duties while exercising its discretion to
ensure maintenance of a diverse fleet and protection against any number
of worst-case scenarios, especially while it considers further actions
it may take to revise the 2024 rule.
4. The Final Rule Does Not Revise the 2024 Rule's Earliest Compliance
Dates, Which Have Already Passed
The EPA disagrees with public comments suggesting that these
extensions would result in widespread delays in compliance. The EPA is
not postponing the earliest compliance date for the 2024 rule, which
has since passed and, as a result, facilities without some of the
limitations described above have already begun submitting NOPPs (DCN
SE12001) and installing technology to comply with zero-discharge
limitations (EPA-HQ-OW-2009-0819-10666). These extensions are not
intended to simply provide this industrial sector with a blanket
deferral of compliance, but instead to appropriately acknowledge the
rapidly changing demand on this industry and provide permitting
authorities greater flexibility to react in real time to the evolving
challenges on the power sector. Of note is the fact that a permitting
authority is required to evaluate the same criteria in section
423.11(t) as was required in the 2024 rule when considering the ``as
soon as possible'' date. The factors at section 423.11(t) include
consideration of ``Time to expeditiously plan (including to raise
capital), design, procure, and install equipment to comply with the
requirements of the final rule'' and ``Other factors as appropriate.''
For these reasons, the EPA disagrees with comments suggesting that it
is necessary to postpone the earliest compliance dates. Therefore, the
EPA is not postponing the ``as soon as possible'' date. See
Implementation of the Steam Electric ELGs Deadline Extension Final Rule
(DCN SE12026) for detail on how these changes impact the ongoing
permitting of facilities. For a more thorough discussion of the EPA's
response to the public comments on the extensions of the zero-discharge
limitations, see the response to comments document (DCN SE12008).
E. Tiered PSES
While the majority of steam electric power plants directly
discharge the three wastestreams for which the EPA established zero-
discharge limitations in the 2024 rule, there are still one or more
indirect dischargers of each of these wastewaters. The EPA finds that
the considerations discussed above in this preamble that warrant longer
applicability timing for zero-discharge requirements on direct
dischargers are equally applicable to indirect dischargers. Thus, the
EPA is finalizing a new tiered standard for indirect dischargers that
conforms with the Act and allows an indirectly discharging plant to
choose to be subject to the same limitations, and on the same
timeframes, as apply to existing direct dischargers.
Section 307(b)(1) of the CWA requires that pretreatment standards
``shall specify a time for compliance not to exceed three years from
the date of promulgation.'' 33 U.S.C. 1317(b)(1). This three-year
period is similar to the three years stated in sections 301(b)(2)(C),
(D), and (F), which apply to BAT limitations. 33 U.S.C. 1311(b)(2)(C),
(D), and (F). Section 301(b)(2)(C) states that ``there shall be
achieved . . . compliance with [BAT] effluent limitations . . . as
expeditiously as practicable but in no case later than three years
after the date such limitations are promulgated . . . and in no case
later than March 31, 1989.'' \17\ 33 U.S.C. 1311(b)(2)(C). The EPA
reads those provisions as requiring that the Agency's original BAT
limitations be met no later than three years after the date that ELGs
are promulgated, with a back-end deadline of March 31, 1989.
Furthermore, the Act is silent as to any required timeframe for
compliance with revised effluent limitations after March 31, 1989. See
Clean Water Action v. EPA, 936 F.3d 308, 316-17 (5th Cir. 2019)
(``EPA's reading of the text accords the language its natural meaning:
the initial BAT effluent limitations were to be complied with as
expeditiously as practicable, but in no case later than three years
after promulgation, with a final compliance date of March 31, 1989--
whichever came first. This reading is supported by section 1311(d),
which requires the EPA periodically to review BAT limitations,
including after 1989, but contains no such compliance deadline.'')
(citation omitted).
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\17\ CWA section 301(b)(2)(D) and section 301(F) contain similar
language. 33 U.S.C. 1311(b)(2)(D) and (F).
---------------------------------------------------------------------------
Given that BAT limitations and PSES are intended to be analogous,
as previously described, it would make sense that the three-year
requirement in CWA section 307 also applies only to the EPA's initial
pretreatment standards for an industry. This is supported by CWA
section 307(b)(2), which includes language stating that the
Administrator shall ``from time to time'' revise its pretreatment
standards and does not include language directing compliance with
revised standards under that paragraph by any particular date. In other
words, it would be illogical to read into the statute a deadline for
compliance with revised standards if it remains within the EPA's
discretion as to when to initiate revisions to such standards.
Nonetheless, even assuming that the three-year requirement applies to
revisions of those standards, the EPA's pretreatment standards meet
that requirement because they represent a phased-in standard that
increases in stringency after three years from promulgation, in order
to reflect when more stringent technologies are available, achievable,
and have acceptable non-water quality environmental impact, as required
by the Act.
In the first tier of the standard, indirect dischargers are
required, by January 1, 2029, to meet pre-2024 rule standards for FGD
wastewater, BA transport water, and CRL. These standards (which are
based, respectively, on biological treatment plus chemical
precipitation, high-recycle-rate systems, and the permitting
authority's BPJ) are available and achievable, as supported by the
record in the EPA's prior rules. In the second tier of the standard,
facilities opting to file a permit application with their permitting
authority to directly discharge these wastewaters are allowed to
continue indirectly discharging until the compliance date determined by
the permitting authority, but no later than December 31, 2034, provided
they certify that they will complete the conversion to direct
discharge. In the second tier of the standard for facilities that do
not opt to become direct dischargers, the tiered standard changes to
zero discharge by January 1, 2029. In either case, this pretreatment
standard is one standard that tightens over time, and so it conforms to
the requirement of the Act that pretreatment standards specify a time
for compliance not to exceed three years from the date of
promulgation.\18\ The EPA expects that
[[Page 61347]]
this approach provides equity across a range of permitted facilities
regardless of their discharge circumstance--i.e., direct or indirect.
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\18\ As explained more fully in its response to comments
document (DCN SE12008), the EPA also does not agree with commenters
that BAT limitations such as the ones promulgated in the 2024 rule
and addressed in this action are subject to a requirement that they
apply no later than three years after the date of promulgation.
---------------------------------------------------------------------------
The EPA received a number of comments in support of, and in
opposition to, the tiered standard for indirect dischargers. Comments
against the tiered standard included general opposition to the delay in
compliance with the 2024 standard, claims that the EPA lacks a record
supporting the delay, and questions regarding the Agency's legal
authority to delay the 2024 pretreatment standards. The EPA disagrees
with commenters that argue there is no record support for the
extension, as detailed in the paragraphs above supporting the
compliance date extension for the zero-discharge BAT limitations. The
Agency also disagrees that the PSES compliance deadlines cannot
lawfully be extended beyond three years from promulgation of the 2024
rule, for the reasons discussing EPA's statutory authority under
Section 307 of the CWA, explained above.
The EPA agrees with commenters that support the tiered standard for
PSES because the approach provides consistency in the compliance
deadlines between requirements for indirect and direct dischargers. The
tiered standard gives facilities that have infrastructure that conveys
wastewater to a publicly owned treatment works adequate time to design,
procure, and install new, zero-discharge technology to comply with the
2024 limitations. This approach will provide equitable regulatory
treatment across permitted facilities regardless of their discharge
circumstance (i.e., direct or indirect). The tiered PSES standard is
appropriate because, as a general matter, the same factors that warrant
longer applicability timing for zero-discharge limitations for direct
dischargers (e.g., equipment delays due to supply-chain disruptions,
changing energy demand forecasts) apply equally to indirect
dischargers. There is no difference as a general matter between a
direct discharger and indirect discharger as far as being able to
procure and install the relevant zero-discharge technologies, nor is
there a difference in terms of the importance of these plants to
meeting regional energy demands. See the discussion above and EPA's
response to comments document (DCN SE12008) regarding the rationale for
the extension of the latest compliance dates for the 2024 rule BAT
limitations. The tiered requirement is also consistent with the
extended deadline to submit a NOPP for cessation of coal combustion by
2034. The tiered PSES gives facilities the flexibility to consider
retirement decisions, especially in light of increased energy demand
and resource adequacy concerns, before the deadlines for requirements
based on installation of zero-discharge technology, rather than
potentially forcing premature retirement.
Finally, the EPA received comments opposing the zero-discharge
PSES, suggesting that indirect dischargers should continue to be able
to discharge to POTWs. The EPA also received comments from utilities
and industry trade associations that the zero-discharge technologies
used to establish PSES and BAT limitations in the 2024 rule are not
available or economically achievable and are a primary cause of coal-
fired power plant retirements. As previously explained, the EPA is
considering future action to revise the zero-discharge BAT limitations
and PSES for the relevant wastestreams.
F. Alternative Applicability Timing and NOPP Submission Timing
Flexibility
The EPA is finalizing a site-specific timing flexibility to be
incorporated in the permit conditions set forth in 40 CFR 423.18(d),
based on the statutory factors of ``availability,'' as well as ``non-
water quality environmental impact (including energy requirements)''
or, alternatively, ``other factors'' the Administrator deems
appropriate (i.e., sudden changes in resource adequacy needs for a
particular service area or supply-chain issues). See 33 U.S.C.
1311(b)(2)(A), 1314(b)(2)(B). As discussed further below, this
flexibility is primarily intended to address challenges previously
described in this final rule that may result in a plant, or even a
single EGU at a plant, pivoting too quickly or too late into an
alternative compliance pathway to ensure compliance with the applicable
requirements. Unlike the compliance deadline extensions for the 2024
rule's zero-discharge limitations discussed above, this site-specific
timing flexibility could potentially apply to the 2020 rule
limitations.
While the EPA is aware that several utilities have already pushed
back plans to retire coal units by 2028 in order to support regional
resource adequacy, trade associations and regional transmission
organizations have discussed further scenarios with the Agency that
could lead to impractical timeframes for the installation of
technologies needed to meet applicable limitations. In one scenario,
such as that experienced at Buckeye Power's Cardinal Plant (DCN
SE12043), a utility may have announced that one or more EGUs at a plant
would retire by 2028 (making it eligible for the 2020 rule's
subcategory for the permanent cessation of coal combustion by 2028),
while the remainder would continue generation. If the IRP process or
capacity auctions indicate that future needs may not be met, these EGUs
may need to back out of previous retirement decisions. However, the
plant may have combined wastewaters, such as combined FGD wastewaters
from a joint FGD unit that treats flue gas from the entire plant. In
the case that the plant was properly developing a treatment system that
could treat wastewater from the EGUs it had intended to continue
operating, the continued operation of one or more additional EGU(s)
could lead to more wastewater than the system can treat. In such
circumstances, the plant would be forced to choose between
noncompliance or retiring an EGU needed for local resource adequacy.
The EPA agrees that a plant in such a situation should be given the
time to build out treatment systems and comply with the 2020 rule given
the rapidly evolving resource needs for this critical industry.
In another scenario, such as that experienced at KeyCon's Conemaugh
plant (DCN SE12042), a plant that had submitted a NOPP for permanent
cessation of coal combustion by 2028 may learn through the IRP process
or capacity auctions that its continued operation is necessary to
support local resource adequacy. Such facilities can still use the
transfer flexibilities in 40 CFR 423.13(o) to transfer to the VIP
limitations for FGD wastewater and the generally applicable limitations
for BA transport water by December 31, 2025. However, if a plant had
not taken significant steps to design, bid, and procure these
technologies prior to the transfer deadline, it would not be
practicable for the plant to do so by the deadlines in the 2020 rule,
particularly where the generally applicable BA transport water
limitations have the same deadline as the transfer itself. In such
circumstances, a plant could be forced into deciding whether to risk
noncompliance or retire despite being needed for local resource
adequacy. Furthermore, requirements to first notify or gain approval
from a state public utility commission might make formally submitting a
transfer notice by December 31, 2025, impracticable.\19\ As with the
previous example, the EPA
[[Page 61348]]
agrees that, in such circumstances, the plant should be given time to
both get approvals needed to submit a transfer notice and build out
treatment systems to comply with the 2020 rule.
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\19\ Some utilities may also be required to conduct
environmental reviews of such decisions under state or Federal law,
further delaying the date by which a notice to transfer could be
filed.
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Finally, stakeholders have expressed concerns with supply chains,
as discussed in sections V and VI. As also discussed, the rapid growth
of data centers, in some cases, takes materials and components that
might otherwise have been used in an ELG compliance technology. Thus,
it is possible that facilities may have to wait on parts that are
available on the market, but that are not available on the timelines
originally believed or agreed to in a contract. In such cases, it is
reasonable and consistent with the statutory and regulatory scheme that
a plant should have sufficient time to obtain and install its
compliance technologies and should not be penalized for factors outside
of its control. While the EPA cited supply-chain concerns as part of
the reason for the compliance deadline extensions for the 2024 rule's
zero-discharge limitations from 2029 to 2034 discussed above, here,
supply-chain concerns serve as an independent basis for the additional
site-specific flexibilities because these flexibilities would also
apply to 2020 rule deadlines and are limited to unexpected
circumstances that might arise in a site-specific context affecting a
project schedule, which is not as likely to be an issue for deadlines
farther out into the future, such as the 2034 deadlines. Moreover,
while the more general compliance deadline extensions until 2034 are
intended to address systemic issues experienced at the industry-level,
this site-specific flexibility is intended to address unforeseen issues
at particular facilities. See the response to comments document (DCN
SE12008) for further discussion on EPA's decision to finalize these
site-specific flexibilities.
The EPA is requiring that a plant submit an initial request letter
and regular progress reports to their permitting authority. The initial
request letter must include the circumstance under which it is
requesting alternative applicability timing. The letter must also
include detailed engineering dependency charts that would allow the
permitting authority to establish an alternative applicability date
and, where appropriate, an associated schedule of milestones in the
permit, as well as determine the frequency of regular progress reports.
For instance, if a plant needed only an extra six months to install
relevant technologies, then monthly progress reports might be
warranted; however, if the same plant needed an extra six years to
install relevant technologies, then annual or biannual progress reports
might be sufficient.\20\ Furthermore, the plant's engineering
dependency charts should identify contingencies, especially for
uncertain or critical path steps, so that any associated schedule can
be sufficiently flexible to avoid the potential for permit
modifications upon a predictable delay. Finally, the letter must be
accompanied by any missing NOPPs or progress reports. While the EPA
intends that this flexibility be used only when necessary, the Agency
is finalizing it in a way that provides sufficient flexibility in terms
of time and need. Facilities and permitting authorities should continue
to plan for compliance through normal pathways to the extent possible.
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\20\ Note that nothing in this requirement prevents a permitting
authority from requesting additional information or information at
additional times, consistent with applicable law.
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The EPA received comments both in support of, and in opposition to,
these provisions. Commenters opposed to the flexibilities argued that
they are arbitrary and unlawfully fail to include sufficient
safeguards. These commenters more specifically took issue with the EPA
presenting no new data to indicate that facilities require additional
time for compliance. Commenters argued that the EPA has not explained
why the 2024 rule and its deadlines do not already account for
reliability, capacity needs, or supply-chain issues. Commenters also
suggested that the CWA already allows the EPA and state authorities to
adjust national requirements for unique site-specific circumstances
through statutory variances, such as fundamentally different factors
(FDF) variances. Some commenters suggested that the EPA should, while
others suggested the Agency should not, explicitly describe the
circumstances which warrant or qualify for flexibility.
Commenters in favor of the flexibilities also asked that these
flexibilities be automatically applied via a fixed extension. Some
commenters also requested some specific changes to the language in 40
CFR 423.18(d). Commenters asked that language be revised or added to
call out facilities or EGUs that move within a permanent cessation of
coal combustion subcategory. One commenter provided an example of an
EGU changing from retiring to continuing operation but changing fuel
sources. Commenters also requested that the EPA clarify whether 40 CFR
423.18(d) provisions apply to requirements for zero discharge only or
also apply to advanced biological treatment systems. Another commenter
requested that the EPA establish national guidance and an interim
implementation framework. Finally, the EPA received feedback on
specific language changes for the provisions.
In general, the EPA disagrees that the establishment of the new
site-specific applicability date provision in section 423.18(d) is
arbitrary, unnecessary, or otherwise insufficiently supported. However,
the EPA acknowledges that, as part of the proposal, it did rely on
relatively generic scenarios rather than provide specific examples to
demonstrate the need for these provisions. The EPA has also added a new
memoranda to the record, Implementation of the Steam Electric ELGs
Deadline Extension Final Rule, providing further examples on how these
provisions could be implemented in facilities' individual permits (DCN
SE12026).
The EPA also disagrees with comments that the Agency should
explicitly list additional circumstances in the new section 423.18(d)
and agrees with those instead recommending the same or similar approach
to the proposal. These provisions are meant for extraordinary measures
beyond what was foreseen in the ELG analysis or even in a facility's
initial planning. The EPA expects that facilities should and will plan
to meet the compliance dates as specified in the ELG; however, should
market conditions change too late for a facility to feasibly come into
compliance, then 40 CFR 423.18(d) may be invoked. The EPA views these
flexibilities as extraordinary measures. Thus, the EPA recommends that
utilities and their permitting authorities turn to these flexibilities
only as a last resort and only for the reasons and issues described in
423.18(d)(3).
Given the emergency nature that the provisions are intended to
address, despite some comments requesting more prescriptive language in
the regulation, the EPA is declining to explicitly list conditions or
qualifiers which must be met prior to being granted these
flexibilities. Likewise, the EPA also disagrees with the commenter
suggesting that the flexibility be finalized as an automatic extension.
Such an extension would be overbroad for some facilities while
potentially being too short for others. The EPA finds that the
decisions surrounding when and how to administer these flexibilities
should be left to the permitting authority, who will be best positioned
to consider all the relevant factors at that time and establish
alternative applicability dates that are appropriate in light of each
facility's specific circumstances.
[[Page 61349]]
The EPA also disagrees with some commenters stating that the
flexibilities do not include safeguards. The EPA has crafted a set of
circumstances that require very detailed showings. For example, section
423.18(d)(3)(iii) is only available when supply-chain issues result in
a delay of ``a necessary component (not merely a preferred component
where there are reasonable substitutes) at a key stage of fabrication
or installation . . .'' Furthermore, while the EPA does not explicitly
include backstops as requested by these commenters, the 2020 rule
implementation is complete on December 31, 2028. Thus, as of January 1,
2029, a facility would have to be in compliance, have permanently
ceased coal combustion, or have begun some formal transfer with today's
new extensions. A facility failing to complete one of these actions
would already be in noncompliance. Third, these site-specific
flexibilities are not automatic like the transfers of section
423.13(o). Instead, a facility would be required to undergo a permit
renewal or permit modification to incorporate any alternative
applicability timing.
Finally, the EPA has included a number of reporting and
recordkeeping requirements, including requirements for some of the very
information commenters suggest is needed, and a requirement to post
this documentation to the facility's public-facing ELG Compliance Data
and Information website. For further discussion of implementation, see
the implementation memo (DCN SE12026).
After considering the feedback received from the public on this
topic and the full record before it, the EPA is finalizing a
requirement for permitting authorities to extend the NOPP submission
dates or applicability timing for any compliance date in the 2020 or
2024 rules (including the VIP limitations for FGD wastewater) due to
these or any other unexpected and uncontrollable circumstances. These
flexibilities, as determined appropriate by a permitting authority,
would be included as a new permit condition via 40 CFR 423.18(d). This
would allow an alternative applicability date and, where appropriate,
associated schedule of milestones, to be included in a permit,
notwithstanding the existing applicability timing in the regulatory
text. See the EPA's response to comments document (DCN SE12008) for
further discussion of the public comments received on this provision,
as well as additional detail supporting the Agency's findings.
G. Clarifications to Sections 423.18(a) or 423.19(i)
In the 2020 rule, the EPA discussed how changed circumstances in a
plant's operations could affect compliance with the ELG. This
discussion distinguished voluntary versus involuntary changes in
operations. As examples of involuntary changes, the EPA noted that
electric utilities are regulated by a variety of agencies that can
legally require continued generation at a plant (e.g., section 202(c)
of the Federal Power Act). For these types of reliability-related
issues, the EPA established permit conditions that would ensure non-
interference with resource adequacy and reliability when such orders
were issued.\21\ After this provision was established, stakeholders
raised questions as to the applicability of the section to energy
emergency alerts (EEAs). In response to these stakeholder concerns,
when finalizing the 2024 rule, the EPA reinforced its commitment to not
interfering with the provision of reliable power by amending 40 CFR
423.18(a) to expressly include EEAs as a valid trigger for the
protections therein.
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\21\ In contrast, the EPA noted that a plant voluntarily
changing operations needed to ``carefully plan its implementation.''
85 FR 64650, 64709 (October 13, 2020).
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Since the 2024 rule, stakeholders have questioned whether 40 CFR
423.18(a) can be read to include other types of actions not explicitly
listed. Specifically, four scenarios were raised for which stakeholders
wish further clarification from the EPA. These include the following:
Whether 40 CFR 423.18(a)(2) is interpreted to include
FERC's acceptance of a reliability must-run agreement as being a
reliability must-run agreement issued by a public utility commission as
contemplated within this subsection;
Whether 40 CFR 423.18(a)(3) is interpreted to include the
following as a qualifying event: where an EGU(s) has certified it would
cease combustion of coal, and an appropriate balancing authority
projects, pursuant to its authority, that doing so would cause a
resource adequacy shortfall for an upcoming delivery year;
Whether 40 CFR 423.19(i)(1)(ii) is interpreted to include
the 30-day submission applicability to any findings made pursuant to 40
CFR 423.18(a)(3); and
Whether 40 CFR 423.19(i)(3) is interpreted such that the
termination of need statement submission is also triggered 30 days from
when the source is no longer subject to extended production (which is
increased production) resulting from the qualifying event.
With respect to the first issue, the EPA intended for any
reliability must-run agreement or similar order to be covered. The EPA
believes that, between 40 CFR 423.18(a)(2) and 423.18(a)(3), there is
sufficient flexibility that either provision or both could apply to
such orders depending on the entity making or receiving the filing.
With respect to the second issue, the EPA received a similar
question from the Tennessee Valley Authority (TVA) at the time of the
2023 proposal. There, the EPA pointed out that TVA was certified by
NERC as the reliability coordinator for itself and several other
utilities. Therefore, the record supported that TVA had the authority
to issue operating instructions and emergency operating instructions
with which any utilities (including itself) must comply, making TVA a
competent electricity regulator. Since 40 CFR 423.18 refers broadly to
``a competent electricity regulator (e.g., an independent system
operator),'' the EPA concluded that this broad definition allowed for
load balancing authorities to be included and thus made no textual
changes.
With respect to the third issue, the EPA notes that 40 CFR
423.19(i)(2)(ii) refers back to (i)(2)(i), which in turn refers back to
any qualifying event in 40 CFR 423.18(a). Since the reference does not
limit qualifying events to any subparagraph in 40 CFR 423.18(a), the
EPA agrees that any event under (a)(3) would trigger the reporting and
recordkeeping requirement.
With respect to the final issue, the EPA again agrees that extended
production is increased production.
The EPA received comments supporting these clarifications. One
commenter requested further clarification as to whether a reliability
must-run directive may emanate from NERC-certified reliability
coordinator that oversees the balancing area. Finally, one commenter
asked the EPA to codify these clarifications.
With respect to directives from a NERC-certified reliability
coordinator, the EPA agrees that such an order could qualify under
section 423.18(a)(3) as ``any other reliability-related order [. . .]
by a competent electricity regulator . . .''
Finally, the EPA disagrees with the single comment suggesting
codification of these clarifications. Unlike the codification of
``energy emergency alert'' in the 2024 rule, where that type of action
was not clearly in line with the other enumerated actions in section
[[Page 61350]]
423.18(a)(3), here a reliability must-run order fits squarely within
the types of orders and agreements covered by existing regulatory text.
H. Reliance Interests
As set forth in section III, explaining the EPA's authority for
taking this action, unless otherwise provided by law, agencies may
reconsider past decisions and revise them, so long as they provide a
reasoned explanation and consider significant reliance interests. FCC
v. Fox Telev. Stations, Inc., 556 U.S. at 515; Motor Vehicle Mfrs.
Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. at 42; see also Nat'l
Ass'n of Home Builders v. EPA, 682 F.3d at 1038 & 1043. In addition to
the reasoned explanation for the decisions in this rule described in
this section above, the Agency has also considered whether there are
significant reliance interests affected by the rule. Despite requesting
feedback on possible reliance interests impacted by this rule, the
Agency received very few comments on the subject, and the comments that
it did receive are either not material to this final action or lacking
in sufficient specificity. Some commenters raised concerns about
reliance interests related to the underlying technology bases for
previous rules (e.g., biological treatment) or on various subcategories
(e.g., the permanent cessation of coal combustion subcategories in the
2020 or 2024 rules). These concerns are not germane to this final rule,
which deals only with deadline extensions and related provisions and
does not address the underlying technology bases or subcategories of
prior rules. One commenter argued that certain ``engineering,
procurement, and construction firms, consultants and/or vendors'' have
reliance interests that are adversely affected by this rule. It stated
that ``these entities and their supply-chain partners will lose or have
delayed market opportunities. These entities may have made investments
that will be stranded or they will see a considerable delay in
recouping sunk costs.'' The Agency notes that this commenter is not
itself an engineering, procurement, or construction firm, nor is it a
consultant or vendor of any treatment or related technology. In fact,
no such entity submitted comments with similar concerns, including any
that are small businesses, which the commenter urged the EPA to
especially consider. Even in light of this final rule, there may be
other reasons why a utility would move forward with installation of
zero-discharge technologies on the timeline envisioned by the 2024
rule. Moreover, this comment fails to recognize that, in light of the
supply-chain issues identified in this action, some vendors may be
helped by the delay in compliance deadlines. Finally, the commenter
offers no specific evidence regarding delayed market opportunities,
stranded investments, or sunk costs. Without more, the EPA cannot
quantify any potential impacts. Finally, one commenter claimed that
there may be reliance interests on the part of States, Tribes, local
communities, and environmental groups adversely affected by this rule
because ``[t]hose stakeholders set up permits, health protections, and
restoration projects based on the original schedule.'' This commenter,
however, did not provide any specific information to support these
reliance interest claims. Again, without more, these claims appear
speculative, and the EPA cannot quantify any potential impact.
Moreover, as noted in its response to comments document, the Agency
disagrees with some commenters that previously estimated pollutant
reductions will no longer occur simply as a result of this deadline
extensions rule; based on this rule's analysis, the EPA expects the
full range of benefits (i.e., water, air, non-water quality, human
health) will still occur, but on a different timeline than stated in
the 2024 rule. In light of comments received, the EPA has determined
that it is appropriate to finalize the rule, including to the extent
the rule revises decisions made previously, for the reasons discussed
above in section VI.
I. Economic Achievability
In the 2024 rule, the EPA estimated that the cost to industry of
zero discharge of FGD wastewater would be $179 million per year, the
cost to industry of zero discharge of BA transport water would be $19
million per year, and the cost to industry of zero discharge and
chemical precipitation of CRL would be $218 million per year in
annualized costs at a 3.76 percent discount rate. Combined, this led to
a total compliance cost estimate of $416 million per year at a 3.76
percent discount rate. At that time, the EPA determined that these
costs were economically achievable to the industry. The deadline
extensions and flexibilities finalized in today's action are designed
to lessen the burden to comply with the existing Steam Electric ELGs,
in part due to the dramatic increase in energy demand described above,
and the EPA anticipates that these flexibilities will allow utilities
to better make compliance decisions that impose minimum economic impact
across the industry and to their customers.
As discussed in today's preamble, there have been significant
changes in market conditions and state and federal legislation
affecting the power sector since the EPA conducted the 2024 Rule
analysis; therefore, there is a high degree of uncertainty regarding
the costs and benefits presented based on the 2024 analysis, given
recent changes affecting the electricity sector.
The final rule extends by five years the ``no later than'' deadline
for complying with zero-discharge limitations for BA transport water,
FGD wastewater, and managed CRL. As the rule specifies that the
limitations are to be met ``as soon as possible . . . but no later
than,'' it is possible that plants will comply sooner and according to
a schedule that is similar to that for the baseline. To model the
effects of the final rule, the EPA conservatively assumed that each
affected plant would implement technologies five years later than
assumed in the analysis of the 2024 rule, i.e., implementation starting
in 2030 under this final rule and being completed by 2034, so as to not
underestimate potential impacts. At a three percent discount rate, the
EPA estimates that this rule would save utilities approximately $61
million annualized; and at a seven percent discount rate, the EPA
estimates that this rule would save utilities approximately $112
million annualized. As such, the EPA finds that, with these cost
savings, this final action is economically achievable.
The EPA also received several adverse comments stating that the
underlying cost and economic impact analysis for the 2024 rule used old
data, particularly in light of the incredible increase in energy demand
across the U.S. in the last year and current projections. Subsequent to
this rulemaking effort, the EPA intends to undertake a further
reconsideration of certain aspects of the existing regulations. Should
the EPA decide in a future action to reopen the BAT basis for the
underlying 2024 rule more broadly, it will make a decision at that time
(based on the current conditions of the industry) as to the need for
updating both the underlying data and/or the Agency's modeled costs and
economic impacts.
J. Severability
The purpose of this section is to clarify the EPA's intent with
respect to the severability of provisions of this final rule. In the
event of a stay or invalidation of part of this rule, the Agency's
intent is to preserve the remaining portions of the rule to the
[[Page 61351]]
fullest extent possible. The EPA notes the following existing
regulatory text at 40 CFR 423.10(b) that is not altered by this final
rule: ``The provisions of this part are separate and severable from one
another. If any provision is stayed or determined to be invalid, the
remaining provisions shall continue in effect.'' Moreover, to dispel
any doubt regarding the EPA's intent and to inform how any final
regulation would operate if severed, the Agency is adopting each
portion of this rule independent of the other portions. As explained
below, the EPA carefully crafted this rule so that each provision or
element of the rule can operate independently. Moreover, the EPA has
organized the rule so that if any provision or element of this final
rule is determined by judicial review or operation of law to be
invalid, that partial invalidation would not render the remainder of
the rule invalid.
This final rule extends the NOPP submission deadline for the
subcategory for permanent cessation of coal combustion by 2034. It is
the EPA's position that this extension is justified and supported by
the record independently of the compliance date extensions. Although
the invalidation of compliance date extensions would result in a NOPP
submission date in 2031 that is two years after the latest compliance
dates for the generally applicable limitations, the EPA finds that this
would still be appropriate as the practicalities of permitting would
result in facilities submitting NOPPs prior to the latest compliance
dates to avoid receiving permits with zero-discharge limitations.
This final rule extends certain compliance dates associated with
zero-discharge limitations and standards for discharges of pollutants
found in three steam electric wastestreams. The final rule provides
extended dates for limitations and standards associated with each
wastestream in separate sections that do not rely on one another.
Although the decision to extend deadlines applicable to each
wastestream rests on overlapping facts, the decision to extend the
compliance dates for limitations for each wastestream was made
independently of the decisions to extend the other compliance dates.
In addition, the rule creates a site-specific flexibility for
additional time to comply with the limitations in the 2020 and 2024
rules under four separate sets of circumstances. The EPA finds that
there is support and authority for this site-specific flexibility
independent of the support and authority for the general compliance
deadline extension for zero-discharge limitations. Thus, the EPA would
have promulgated this flexibility even if it did not simultaneously
promulgate the more general compliance deadline extension until 2034.
Furthermore, the EPA finds that there is support and authority for each
circumstance provided for in this site-specific flexibility, which is
independent of the support and authority for the other circumstances.
For example, if a court were to find that the site-specific flexibility
for one circumstance (e.g., supply-chain risks) was not justified, the
EPA would maintain that the site-specific flexibility should still be
retained for the remaining three circumstances.
This final rule also provides flexibility for steam electric
facilities to opt into different compliance pathways that exist in the
rule, for example, due to changed circumstances. This flexibility to
transfer to a different compliance pathway is unrelated to other
provisions in the final rule, and the EPA's decision to allow for such
transfers is unrelated to other aspects of the rule.
Finally, this final rule creates authority for alternative
applicability dates for limitations promulgated in the 2020 or 2024
rules, based on site-specific factors. This authority is independent
from other changes being finalized, and the EPA's decision to provide
for such authority is unrelated to other aspects of this final rule.
For example, in the event of a stay or invalidation of any extended
compliances dates for the zero-discharge limitations or standards, the
EPA finds there is continued authority for alternative applicability
dates, as discussed in this paragraph, and such authority could
continue to be implemented.
These examples are illustrative, rather than exhaustive, and the
EPA intends for each portion of this final rule to be independent and
severable. Furthermore, if application of any portion of this final
rule to a particular circumstance is determined to be invalid, the EPA
intends that this rule remain applicable to all other circumstances.
VII. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is an economically significant regulatory action as
defined under section 3(f)(1) of Executive Order 12866. Accordingly, it
was submitted to the Office of Management and Budget (OMB) for review.
Any changes made in response to E.O. 12866 interagency review have been
documented in the docket. From a 2024 rule baseline, the EPA estimated
that this action would result in annualized cost savings of $61 million
at a three percent discount rate, and $112 million at a seven percent
discount rate.
The Agency also prepared monetized benefits, attempting to
incorporate some of the current uncertainty in the industry changes,
and as such are presenting a range of monetized benefits. EPA estimates
this action would result in forgone benefits ranging between $3.3
million at the low end and $95 million to $232 million at the high end
at a three percent discount rate; and between $3.3 million at the low
end and $112 million to $271 million at the high end at a seven percent
discount rate. See memorandum entitled ``Overview of Costs and Benefits
of Steam Electric ELG 2025 Deadline Extensions Final Rule'' for more
details on the Agency's economic analysis supporting this action (DCN
SE12028).
B. Executive Order 14192: Unleashing Prosperity Through Deregulation
This action is considered an Executive Order 14192 deregulatory
action. This final rule provides burden reduction by allowing
additional time for the regulated community associated with their
decision-making.
C. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the PRA. The Information Collection Request (ICR) document that
the EPA prepared has been assigned EPA ICR number 7814.02 (OMB Control
Number 2040-0313) and is included in the docket for this rule. The ICR
is briefly summarized here. The information collection requirements are
not enforceable until OMB approves them.
The EPA is promulgating several new reporting and recordkeeping
requirements or changes as part of the final rule. First, to implement
this rule's expanded transfer flexibilities, under CWA sections 304(i)
and 308, this rule includes expanded reporting and
[[Page 61352]]
recordkeeping requirements in 40 CFR 423.19(l). Second, to implement
this final rule's new tiered PSES for facilities that wish to receive
applicability dates as direct dischargers from a permitting authority,
the rule includes a new reporting and recordkeeping requirement in 40
CFR 423.19(p). Third, to implement the final rule's new flexibility for
alternative applicability dates, the rule includes two new reporting
and recordkeeping requirements in 40 CFR 423.19(q). Specifically, the
rule includes requirements for an initial request letter and regular
progress reports. Finally, to implement the final rule, permitting
authorities need time to read and analyze additional submissions. The
EPA also notes that with these additional reporting and recordkeeping
requirements, the rule also expands the filings required to be posted
to each plant's public-facing website.
Respondents/affected entities: steam electric facilities.
Respondent's obligation to respond: Mandatory (40 CFR 423.19).
Estimated number of respondents: 90.
Frequency of response: Annually.
Total estimated burden: 3,225 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $335,343 (per year), includes $0 annualized
capital or 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 9. When OMB approves
this ICR, the EPA will announce that approval in the Federal Register
and publish a technical amendment to 40 CFR 9 to display the OMB
control number for the approved information collection activities
contained in this final rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the EPA concludes that the impact of concern
for this rule is any significant adverse economic impact on small
entities and that the Agency is certifying that this rule will not have
a significant economic impact on a substantial number of small entities
because the rule relieves regulatory burden on the small entities
subject to the rule. This action consists of a compliance date
extension for the steam electric power generating industry, including
small entities, which will allow for greater flexibility for
compliance. The EPA has therefore concluded that this action will
relieve regulatory burden for all directly regulated small entities. In
addition, the EPA previously certified that the 2024 rule, which had a
higher cost burden than is anticipated for this action, will not have a
significant economic impact on a substantial number of small entities
under the RFA (89 FR 40198).
As small entities were estimated to incur an estimated 21 percent
of the annualized compliance costs for meeting BA, FGD, and managed CRL
limitations in the 2024 rule analysis, the EPA expects that they may
see a corresponding share of the estimated cost savings from the
compliance date extension (i.e., total savings of $12.7 million at a 3
percent discount rate).
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate as described in
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect
small governments. The action imposes no enforceable duty on any State,
local, or Tribal governments or the private sector.
F. 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.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications as specified in
Executive Order 13175. It does not have substantial direct effects on
Tribal governments, on the relationship between the Federal Government
and the Indian Tribes, or the distribution of power and
responsibilities between the Federal Government and Indian Tribes as
specified in Executive Order 13175. The EPA's analyses show that no
plant subject to the final ELGs is owned by Tribal governments. Thus,
Executive Order 13175 does not apply to this action.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that the Agency has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order.
Therefore, this action is not subject to Executive Order 13045
because it does not concern an environmental health risk or safety
risk. Since this action does not concern human health, the EPA's Policy
on Children's Health also does not apply.
I. 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. The compliance date extensions would
allow EGUs to continue operations with additional time for decision-
making and will beneficially, rather than adversely, impact supply,
distribution, or use.
J. National Technology Transfer and Advancement Act (NTTAA)
This rulemaking does not involve technical standards.
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 423
Environmental protection, Electric power generation, Power
facilities, Waste treatment and disposal, Water pollution control.
Lee Zeldin,
Administrator.
For the reasons stated in the preamble, the Environmental
Protection Agency amends 40 CFR part 423 as follows:
PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY
0
1. The authority citation for part 423 continues to read as follows:
Authority: 33 U.S.C. 1251 et seq.; 1311; 1314(b), (c), (e), (g),
and (i)(A) and (B); 1316; 1317; 1318 and 1361.
0
2. Amend Sec. 423.13 by:
0
a. Revising paragraphs (g)(4)(i)(A), (k)(4)(i), and (l)(1)(i)(A); and
0
b. Adding paragraph (o)(1)(iii).
The revisions and addition read as follows:
[[Page 61353]]
Sec. 423.13 Effluent limitations guidelines representing the degree
of effluent reduction attainable by the application of the best
available technology economically achievable (BAT).
* * * * *
(g) * * *
(4) * * *
(i) * * *
(A) Dischargers must meet the effluent limitations for FGD
wastewater in this paragraph (g)(4)(i) by a date determined by the
permitting authority that is as soon as possible beginning July 8,
2024, but no later than December 31, 2034. These effluent limitations
apply to the discharge of FGD wastewater generated on and after the
date determined by the permitting authority for meeting the effluent
limitations, as specified in this paragraph (g)(4)(i).
* * * * *
(k) * * *
(4) * * *
(i) Except for those discharges to which paragraphs (k)(4)(ii)
through (iv) of this section applies, or when the bottom ash transport
water is used in the FGD scrubber, there shall be no discharge of
pollutants in bottom ash transport water. Dischargers must meet the
discharge limitation in this paragraph (k)(4)(i) by a date determined
by the permitting authority that is as soon as possible beginning July
8, 2024, but no later than December 31, 2034. The limitation in this
paragraph (k)(4)(i) applies to the discharge of bottom ash transport
water generated on and after the date determined by the permitting
authority for meeting the discharge limitation, as specified in this
paragraph (k)(4)(i).
* * * * *
(l) * * *
(1) * * *
(i) * * *
(A) Dischargers must meet the effluent limitations for combustion
residual leachate in this paragraph (l)(1)(i) by a date determined by
the permitting authority that is as soon as possible beginning July 8,
2024, but no later than December 31, 2034. The effluent limitations in
this paragraph (l)(1)(i) apply to the discharge of combustion residual
leachate generated on and after the date determined by the permitting
authority for meeting the effluent limitations, as specified in this
paragraph (l)(1)(i).
* * * * *
(o) * * *
(1) * * *
(iii) On or before December 31, 2034, a facility may convert:
(A) From the generally applicable zero discharge limitations under
paragraphs (g)(4)(i), (k)(4)(i), or (l)(1)(i) of this section to
limitations for electric generating units permanently ceasing coal
combustion under paragraphs (g)(4)(iii), (k)(4)(iii), or (l)(2)(i) of
this section; or
(B) From limitations for electric generating units permanently
ceasing coal combustion under paragraphs (g)(4)(iii), (k)(4)(iii), or
(l)(2)(i) of this section to the generally applicable zero discharge
limitations under paragraphs (g)(4)(i), (k)(4)(i), or (l)(1)(i) of this
section.
0
3. Amend Sec. 423.16 by revising paragraphs (e)(3), (g)(3), and (j)(1)
to read as follows:
Sec. 423.16 Pretreatment standards for existing sources (PSES).
* * * * *
(e) * * *
(3) 2024 PSES. Except as provided for in paragraph (e)(4) of this
section, for any electric generating unit with a total nameplate
generating capacity of more than 50 megawatts and that is not an oil-
fired unit:
(i) Dischargers must meet the standards in paragraph (e)(1) of this
section by January 1, 2028. The standards in paragraph (e)(1) of this
section apply to the discharge of FGD wastewater generated on and after
January 1, 2028.
(ii) By the dates in paragraph (e)(3)(ii)(A) or (B) of this section
there shall be no discharge of pollutants in FGD wastewater:
(A) January 2, 2028; or
(B) Where a certification statement has been submitted pursuant to
Sec. 423.19(p), December 31, 2034.
* * * * *
(g) * * *
(3) 2024 PSES. Except as provided for in paragraph (g)(4) of this
section, for any electric generating unit with a total nameplate
generating capacity of more than 50 megawatts and that is not an oil-
fired unit:
(i) Dischargers must meet the standards in paragraph (g)(1) of this
section by January 1, 2028. The standards in paragraph (g)(1) of this
section apply to the discharge of bottom ash transport water generated
on and after January 1, 2028.
(ii) By the dates in paragraph (g)(3)(ii)(A) or (B) of this
section, there shall be no discharge of pollutants in bottom ash
transport water:
(A) January 2, 2028; or
(B) Where a certification statement has been submitted pursuant to
Sec. 423.19(p), December 31, 2034.
* * * * *
(j) * * *
(1) 2024 PSES. Until and including the dates specified in
paragraphs (j)(1)(i) and(ii), or paragraph (j)(2) of this section, the
EPA is declining to establish PSES for combustion residual leachate and
is reserving such standards to be established by the control authority
on a case-by-case.
(i) Except for those discharges to which paragraph (j)(1)(ii) of
this section applies, by the dates in paragraph (j)(1)(i)(A) or (B) of
this section, there shall be no discharge of pollutants in combustion
residual leachate:
(A) January 2, 2028; or
(B) Where a certification statement has been submitted pursuant to
Sec. 423.19(p), December 31, 2034.
(ii) After the retirement of all units at a facility, the quantity
of pollutants in CRL shall not exceed the quantity determined by
multiplying the flow of CRL permeate times the concentrations listed in
the table 7 to Sec. 423.13(g)(3)(i) or the flow of CRL distillate
times the concentrations listed in the table in Sec. 423.15(b)(13).
0
4. Amend Sec. 423.18 by adding paragraph (d) to read as follows:
Sec. 423.18 Permit conditions.
* * * * *
(d)(1) Notwithstanding the dates associated with any limitations in
Sec. 423.13(g), (k), or (l), a permitting authority shall establish,
in a facility's permit, an alternative applicability date and, where
appropriate, an associated schedule of milestones, for achieving the
required limitations when the facility meets one of the circumstances
in paragraph (d)(3) of this section, provided that the facility submits
an initial request letter pursuant to Sec. 423.19(q) and the
permitting authority finds that request factually supported in the
letter and attachments provided.
(2) Notwithstanding the dates associated with any notice of planned
participation required to be submitted under Sec. 423.19(g), (j), or
(l), a permitting authority may accept a late notice of planned
participation provided that the facility meets one of the circumstances
in paragraph (d)(3) of this section, submits an initial request letter
pursuant to Sec. 423.19(q), and the permitting authority finds that
request factually supported in the letter and attachments provided.
Transfers pursuant to Sec. 423.13(o)(1)(ii) but receiving alternative
Sec. 423.19(l) submission dates in this paragraph (d)(2) shall be
deemed timely. In no case may a late notice of planned participation be
accepted pursuant to this paragraph (d)(2) after December 31, 2028.
[[Page 61354]]
(3) Circumstances which a permitting authority shall find warrant
an alternative applicability date or later notice of planned
participation submission date based on factual support under paragraph
(d)(1) or (2) of this section include:
(i) Where a facility needs an alternative applicability date upon
making a permissible transfer between limitations prior to the
deadlines in Sec. 423.13(o) due to:
(A) An unexpected change in regional capacity market prices; or
(B) An unexpected change in local demand which materially exceeds
projections made in the most recent iterations of integrated resource
plans or other planning documents;
(ii) Where a facility has one or more electric generating units
using a wastewater treatment system treating combined wastewater (e.g.,
wastewater from a single flue gas desulfurization system servicing
different units) and needs an alternative applicability date after
making a decision to back out of a commitment to permanently cease coal
combustion at one or more different electric generating units at the
same plant due to:
(A) An unexpected change in regional capacity market prices; or
(B) An unexpected change in local demand which materially exceeds
projections made in the most recent iterations of integrated resource
plans or other planning documents;
(iii) Where a facility needs an alternative applicability date
because it faces an unexpected supply chain issue that delays a
necessary component (not merely a preferred component where there are
reasonable substitutes) at a key stage of fabrication or installation
such that the timeline for reaching steady-state treatment is delayed;
or
(iv) Where a facility faces any other circumstance that requires
additional time and is wholly outside both the facility's control and
the facility's ability to plan for.
(4) A facility availing itself of this paragraph (d) may consider
the alternative applicability dates or alternative notice of planned
participation submission dates when evaluating compliance for purposes
of Sec. 423.13(o)(2).
0
5. Amend Sec. 423.19 by:
0
a. Revising paragraphs (c)(1), (h)(1), (l) paragraph heading, and
(l)(1); and
0
b. Adding paragraphs (p) and (q).
The revisions and additions read as follows:
Sec. 423.19 Reporting and recordkeeping requirements.
* * * * *
(c) * * *
(1) Except as provided in paragraph (c)(2) of this section, each
facility subject to one or more of the reporting requirements in
paragraphs (d) through (q) of this section must maintain a publicly
accessible internet site (ELG website) containing the information
specified in paragraphs (d) through (q) of this section, if applicable.
This website shall be titled ``ELG Rule Compliance Data and
Information.'' The facility must ensure that all information required
to be posted is immediately available to anyone visiting the site,
without requiring any prerequisite, such as registration or a
requirement to submit a document request. All required information must
be clearly identifiable and must be able to be immediately downloaded
by anyone accessing the site in a format that enables additional
analysis (e.g., comma-separated values text file format). When the
facility initially creates, or later changes, the web address (i.e.,
Uniform Resource Locator (URL)) at any point, they must notify the EPA
via the ``contact us'' form on EPA's Effluent Guidelines website and
the permitting authority or control authority within 14 days of
creating the website or making the change. The facility's ELG website
must also have a ``contact us'' form or a specific email address posted
on the website for the public to use to submit questions and issues
relating to the availability of information on the website.
* * * * *
(h) * * *
(1) Notice of Planned Participation. For sources seeking to qualify
as an electric generating unit that will achieve permanent cessation of
coal combustion by December 31, 2034, under this part, a Notice of
Planned Participation shall be made to the permitting authority, or to
the control authority in the case of an indirect discharger, no later
than December 31, 2031.
* * * * *
(l) Requirements for facilities seeking protections under this
part--(1) Notice of Planned Participation. For sources which intend to
make changes that would qualify them for a different set of
requirements under Sec. 423.13(o), a Notice of Planned Participation
shall be made to the permitting authority, or to the control authority
in the case of an indirect discharger, no later than the dates stated
in Sec. 423.13(o)(1).
* * * * *
(p) Requirements for facilities subject to zero discharge
pretreatment standards for existing sources by 2034. For sources
seeking to be subject to the second tier of the tiered standards in
Sec. 423.16(e)(3)(ii)(B), (g)(3)(ii)(B), or (j)(2)(i)(B), a
certification statement shall be submitted to the control authority by
January 1, 2028 stating that the facility has submitted a permit
application, permit renewal application, or permit modification request
to its permitting authority seeking an as soon as possible date for
achieving the corresponding generally applicable zero discharge
limitations in Sec. 423.13(g)(4)(i), (k)(4)(i), or (l)(1)(i), subject
to the considerations in Sec. 423.11(t). Furthermore, the
certification statement will include an affirmative statement that the
facility will also cease its indirect discharge by the as soon as
possible date determined in this permitting action.
(q) Requirements for facilities seeking an alternative
applicability date under this part--(1) Initial request letter. A
facility may submit a letter to its permitting authority requesting
that it receive an alternative applicability date pursuant to Sec.
423.18(d).
(2) Contents and timing. The initial request letter must detail the
significant unexpected circumstance in Sec. 423.18(d)(2) and a
compelling narrative that explains why these unexpected circumstances
warrant an alternative applicability date by the permitting authority
in light of the facility's plans and execution of those plans. The
letter must also contain a proposed schedule of compliance to be
incorporated into the permit, supported by detailed engineering
dependency chart that clearly shows the milestones leading to
compliance as soon as possible given the unexpected circumstances
described in the letter, including contingencies for critical path
steps. In the case of a missed notice of planned participation, annual
progress report, or other reporting or recordkeeping requirement that
should have been submitted prior to March 2, 2026, the letter must also
attach such reporting requirements. Such submissions shall be deemed
timely by the permitting authority. The facility shall submit an
initial request letter within 60 days of the significant unexpected
circumstance detailed in the letter or by March 2, 2026, whichever is
later.
(3) Progress reports. A facility that submits an initial request
letter pursuant to paragraph (q)(1) of this section must submit regular
progress reports with its permitting authority at a frequency
determined in paragraph (q)(4) of this section.
(4) Contents and timing. Progress reports must include a
description of tasks and sub-tasks completed towards each of the
milestones listed in the initial request letter, any changes to the
[[Page 61355]]
expected dates of milestones, and any contingencies from the initial
request letter which have been effectuated. The permitting authority
shall establish the timing of regular progress reports based on the
following considerations:
(i) The estimated duration of the alternative applicability timing;
(ii) The timeframes of various milestones, tasks, and sub-tasks;
(iii) The number and magnitude of contingencies; and
(iv) Any other appropriate and relevant factor.
(5) Request letter. A facility may submit a single initial request
letter under this paragraph (q)(5) to provide factual support for
circumstances specified in Sec. 423.18(d)(3) that would support of one
or more requests for alternative dates in Sec. 423.18(d)(1) or (2).
[FR Doc. 2025-24102 Filed 12-30-25; 8:45 am]
BILLING CODE 6560-50-P