[Federal Register Volume 89, Number 91 (Thursday, May 9, 2024)]
[Rules and Regulations]
[Pages 40198-40306]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-09185]



[[Page 40197]]

Vol. 89

Thursday,

No. 91

May 9, 2024

Part V





Environmental Protection Agency





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40 CFR Part 423





Supplemental Effluent Limitations Guidelines and Standards for the 
Steam Electric Power Generating Point Source Category; Final Rule

  Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules 
and Regulations  

[[Page 40198]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 423

[EPA-HQ-OW-2009-0819; FRL-8794-02-OW]
RIN 2040-AG23


Supplemental Effluent Limitations Guidelines and Standards for 
the Steam Electric Power Generating Point Source Category

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: The Environmental Protection Agency (EPA or the Agency) is 
finalizing a Clean Water Act regulation to revise 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. Last updated in 2015 and 2020, this 
regulation is estimated to cost an additional $536 million to $1.1 
billion dollars annually in social costs and reduce pollutant 
discharges by an additional approximately 660 to 672 million pounds per 
year.

DATES: This final rule is effective on July 8, 2024. In accordance with 
40 CFR part 23, this regulation shall be considered issued for purposes 
of judicial review at 1 p.m. Eastern time on May 23, 2024. Under 
section 509(b)(1) of the Clean Water Act (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 of this regulation may not be challenged later in civil or 
criminal proceedings brought by EPA to enforce these requirements.

ADDRESSES: The EPA has established a docket for this action under 
Docket ID No. EPA-HQ-OW-2009-0819. All documents in the docket are 
listed on the https://www.regulations.gov website. Although listed in 
the index, some information listed in the index 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: For technical information, contact 
Richard Benware, Engineering and Analysis Division, telephone: 202-566-
1369; email: [email protected]. For economic information, contact 
James Covington, Water Economics Center, telephone: 202-566-1034; 
email: [email protected].

SUPPLEMENTARY INFORMATION: 
    Preamble Acronyms and Abbreviations. The EPA uses multiple acronyms 
and terms in this preamble. To ease the reading of this preamble and 
for reference purposes, the EPA defines terms and abbreviations used in 
appendix A (although the list of abbreviations in the appendix is not 
exhaustive).
    Supporting Documentation. The rule is supported by several 
documents, including the following:
     Technical Development Document for the Final Supplemental 
Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category (TDD), Document No. 821R24004. 
This report summarizes the technical and engineering analyses 
supporting the rule. The TDD presents the EPA's updated analyses 
supporting the revisions to FGD wastewater, BA transport water, CRL, 
and legacy wastewater. The TDD includes additional data that has been 
collected since the publication of the 2015 and 2020 rules, updates to 
the industry (e.g., retirements, updates to wastewater handling), cost 
methodologies, pollutant removal estimates, non-water quality 
environmental impacts associated with updated FGD and BA methodologies, 
and calculations for the effluent limitations. In addition to the TDD, 
the Technical Development Document for the Effluent Limitations 
Guidelines and Standards for the Steam Electric Power Generating Point 
Source Category (2015 TDD, Document No. EPA-821-R-15-007) and the 
Supplemental Technical Development Document for Revisions to the 
Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category (2020 Supplemental TDD, Document 
No. EPA-821-R-20-001) provide a more complete summary of the EPA's data 
collection, description of the industry, and underlying analyses 
supporting the 2015 and 2020 rules.
     Environmental Assessment for the Final Supplemental 
Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category (EA), Document No. 821R24005. 
This report summarizes the potential environmental and human health 
impacts estimated to result from implementation of the revisions to the 
2015 and 2020 rules.
     Benefit and Cost Analysis for the Final Supplemental 
Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category (BCA), Document No. 821R24006. 
This report summarizes the societal benefits and costs estimated to 
result from implementation of the revisions to the 2015 and 2020 rules.
     Regulatory Impact Analysis for the Final Supplemental 
Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category (RIA), Document No. 821R24007. 
This report presents a profile of the steam electric power generating 
industry, a summary of estimated costs and impacts associated with the 
revisions to the 2015 and 2020 rules, and an assessment of the 
potential impacts on employment and small businesses.
     Environmental Justice Analysis for the Final Supplemental 
Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category (EJA), Document No. 821R24008. 
This report presents a profile of the communities and populations 
potentially impacted by this rule, an analysis of the distribution of 
impacts in the baseline scenario and with the revisions, and a summary 
of inputs from potentially impacted communities that the EPA met with 
prior to publishing the proposed rulemaking.
     Docket Index for the Supplemental Effluent Limitations 
Guidelines and Standards for the Steam Electric Power Generating Point 
Source Category. This document provides a list of additional memoranda, 
references, and other information the EPA relied on for the final 
revisions to the ELGs.
    Organization of this Document. The information in this preamble is 
organized as follows:

Table of Contents

I. Executive Summary
    A. Purpose of Rule
II. Public Participation
III. General Information
    A. Does this action apply to me?
    B. What action is the EPA taking?
    C. What is EPA's authority for taking this action?
    D. What are the monetized incremental costs and benefits of this 
action?
IV. Background
    A. Clean Water Act
    B. Relevant Effluent Guidelines
    C. 2015 Steam Electric Power Generation Point Source Category 
Rule
    D. 2020 Steam Electric Reconsideration Rule and Recent 
Developments

[[Page 40199]]

    E. Other Ongoing EPA Rules Impacting the Steam Electric Sector
V. Steam Electric Power Generating Industry Description
    A. General Description of Industry
    B. Current Market Conditions and Drivers in the Electricity 
Generation Sector
    C. Control and Treatment Technologies
VI. Data Collection Since the 2020 Rule
    A. Information from the Electric Utility Industry
    B. Notices of Planned Participation
    C. Information from Technology Vendors and Engineering, 
Procurement, and Construction Firms
    D. Other Data Sources
VII. Final Regulation
    A. Description of the Options
    B. Rationale for the Final Rule
    C. Subcategories
    D. Additional Rationale for the Proposed PSES and PSNS
    E. Availability Timing of New Requirements
    F. Economic Achievability
    G. Non-Water Quality Environmental Impacts
    H. Impacts on Residential Electricity Prices and Communities 
with Environmental Justice Concerns
VIII. Costs, Economic Achievability, and Other Economic Impacts
    A. Plant-Specific and Industry Total Costs
    B. Social Costs
    C. Economic Impacts
IX. Pollutant Loadings
    A. FGD Wastewater
    B. BA Transport Water
    C. CRL
    D. Legacy Wastewater
    E. Summary of Incremental Changes of Pollutant Loadings from the 
Final Rule
X. Non-Water Quality Environmental Impacts
    A. Energy Requirements
    B. Air Pollution
    C. Solid Waste Generation and Beneficial Use
    D. Changes in Water Use
XI. Environmental Assessment
    A. Introduction
    B. Updates to the Environmental Assessment Methodology
    C. Outputs from the Environmental Assessment
XII. Benefits Analysis
    A. Categories of Benefits Analyzed
    B. Quantification and Monetization of Benefits
    C. Total Monetized Benefits
    D. Additional Benefits
XIII. Environmental Justice Impacts
    A. Literature Review
    B. Proximity Analysis
    C. Community Outreach
    D. Distribution of Risks
    E. Distribution of Benefits and Costs
XIV. Regulatory Implementation
    A. Continued Implementation of Existing Limitations and 
Standards
    B. Implementation of New Limitations and Standards
    C. Reporting and Recordkeeping Requirements
    D. Site-Specific Water Quality-Based Effluent Limitations
    E. Severability
XV. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 14094: Modernizing Regulatory Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations and Executive Order 14096: Revitalizing Our Nation's 
Commitment to Environmental Justice for All
    K. Congressional Review Act (CRA)
Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations 
Used in This Preamble

I. Executive Summary

A. Purpose of Rule

    The EPA is promulgating this final supplemental rule to update 
requirements that apply to wastewater discharges from steam electric 
power plants, particularly coal-fired power plants. In 2015, the EPA 
set the first Federal limitations on the levels of toxic metals in 
several of the largest sources of wastewater that can be discharged 
from power plants after last updating these regulations in 1982 (80 
Federal Register (FR) 67838; November 3, 2015) (hereinafter the ``2015 
rule''). On an annual basis, the 2015 rule was projected to reduce the 
amount of toxic metals, nutrients, and other pollutants that steam 
electric power plants are allowed to discharge by 1.4 billion pounds 
and reduce water withdrawal by 57 billion gallons. This rule was 
reconsidered in 2020 and modified in part due to changing dynamics in 
the power sector (85 FR 64650; October 13, 2020) (hereinafter the 
``2020 rule''). Steam electric power plants are increasingly aging and 
less competitive sources of electric power in many portions of the 
United States.
    Steam electric power plants, coal-fired power plants in particular, 
are subject to several environmental regulations designed to control 
(and in some cases eliminate) air, water, and land pollution over time. 
This rule, the Steam Electric Power Generating Effluent Limitations 
Guidelines and Standards--or steam electric ELGs--applies to the subset 
of the electric power industry where ``generation of electricity is the 
predominant source of revenue or principal reason for operation, and 
whose generation of electricity results primarily from a process 
utilizing fossil-type fuel (e.g., coal, oil, gas), fuel derived from 
fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear fuel in 
conjunction with a thermal cycle employing the steam-water system as 
the thermodynamic medium'' (40 Code of Federal Regulations (CFR) 
423.10). The 2015 rule addressed discharges from FGD wastewater, fly 
ash (FA) transport water, BA transport water, flue gas mercury control 
(FGMC) wastewater, gasification wastewater, CRL, legacy wastewater, and 
nonchemical metal cleaning wastes. The 2020 rule modified the 2015 
requirements for FGD wastewater and BA transport water for existing 
sources only. The 2015 limitations for CRL from existing sources and 
legacy wastewater were vacated by the United States (U.S.) Court of 
Appeals for the Fifth Circuit in Southwestern Electric Power Co., et 
al. v. EPA, 920 F.3d 999 (5th Cir. 2019).
    In the years since the EPA revised the steam electric ELGs in 2015 
and 2020, new information has become available, which the EPA 
considered in finalizing this supplemental rule. For example, pilot 
testing and full-scale use of various, better performing treatment 
technologies have continued to develop, along with more data and 
information about their performance. The final supplemental rule 
updates requirements for discharges from two wastestreams addressed in 
the 2020 rule: BA transport water and FGD wastewater at existing 
sources. The final supplemental rule also replaces the court-vacated 
limitations for CRL (except for CRL discharges in one subcategory) and 
a subcategory of legacy wastewater. Finally, for the remaining CRL and 
legacy wastewaters, this rule finalizes a site-specific approach to 
developing technology-based limitations based on the permitting 
authorities' best professional judgment (BPJ), an option discussed by 
the Court in Southwestern Electric Power Co. v. EPA.

B. Summary of Final Rule

    For existing sources that discharge directly to surface water, with 
the exception of the subcategories discussed below, the final rule 
establishes the following effluent limitations based on Best Available 
Technology Economically Achievable (BAT):
     A zero-discharge limitation for all pollutants in FGD 
wastewater, BA transport water, and CRL.

[[Page 40200]]

     Numeric (nonzero) discharge limitations for mercury and 
arsenic in unmanaged CRL \1\ and for legacy wastewater discharged from 
surface impoundments during the closure process if those surface 
impoundments have not commenced closure under the Coal Combustion 
Residuals (CCR) regulations as of the effective date of this rule.
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    \1\ As discussed in section VII.C.5 of this document, the EPA is 
defining unmanaged CRL in this rule to mean CRL which either: (1) 
the permitting authority determines are the functional equivalent of 
a direct discharge to waters of the United States (WOTUS) through 
groundwater or (2) CRL that has leached from a waste management unit 
into the subsurface and mixed with groundwater prior to being 
captured and pumped to the surface for discharge directly to a 
WOTUS.
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    The final rule eliminates the separate, 2020 rule's less stringent 
BAT requirements for two subcategories: high-flow facilities and low-
utilization electric generating units (LUEGUs), except to the extent 
they apply to one new permanent cessation of coal combustion 
subcategory. The final rule leaves in place the existing subcategories 
for oil-fired and small (50 megawatts (MW) or less) electric generating 
units (EGUs) established in the 2015 rule. The final rule also leaves 
in place the existing subcategory for EGUs permanently ceasing the 
combustion of coal by 2028, which was established in the 2020 rule and 
amended in a 2023 direct final rule by extending the date for filing a 
Notice of Planned Participation (NOPP). See 88 FR 18440 (March 29, 
2023). Lastly, the final rule creates a new subcategory for EGUs 
permanently ceasing coal combustion by 2034. For both the existing and 
new subcategories referenced immediately above, the EPA is finalizing 
additional reporting and recordkeeping requirements and zero-discharge 
limitations applicable after EGUs cease coal combustion, as well as 
procedural requirements for affected facilities to demonstrate 
permanent cessation of coal combustion or that permanent retirement 
will occur.
    As stated above, the rule eliminates the 2020 rule subcategories 
for high flow and low utilization, except to the extent they apply to 
EGUs in the new permanent cessation of coal combustion by 2034 
subcategory. The elimination of the 2020 rule's subcategories will 
affect the one known high-flow facility (the Tennessee Valley Authority 
(TVA) Cumberland Fossil Plant) that has indicated it is planning to 
close and the two known facilities with LUEGUs (GSP Merrimack LLC and 
Indiana Municipal Power Agency (IMPA) Whitewater Valley Station), one 
of which is also expected to close. For EGUs ceasing coal combustion by 
2034, the final rule retains the 2020 rule requirements for FGD 
wastewater and BA transport water and the pre-2015 BPJ-based BAT 
requirements for CRL rather than requiring the new, more stringent 
zero-discharge requirements for these wastestreams. After the permanent 
cessation of coal combustion, however, EGUs in this subcategory must 
meet limitations on arsenic and mercury based on chemical precipitation 
for CRL.
    Where BAT limitations in this final rule are more stringent than 
previously established Best Practicable Control Technology Currently 
Available (BPT) and BAT limitations, any new limitations for direct 
dischargers do not apply until a date determined by the permitting 
authority that is as soon as possible on or after July 8, 2024, but no 
later than December 31, 2029.
    For indirect discharges (i.e., discharges to publicly owned 
treatment works (POTWs)), the final rule establishes pretreatment 
standards for existing sources that are the same as the BAT limitations 
except where limitations are for total suspended solids (TSS), a 
pollutant that does not pass through POTWs. Pretreatment standards are 
directly enforceable and apply May 9, 2027.
    While the EPA is not aware of any planned new sources that would be 
subject to the requirements of this final supplement rule, this action 
sets new source performance standards and pretreatment standards for 
discharges of CRL from new sources that are equivalent to the new BAT 
limitations--namely, zero discharge.

C. Summary of Costs and Benefits

    The EPA estimates that the final rule will cost $536 million to 
$1.1 billion per year in social costs and result in $3.2 billion per 
year in monetized benefits using a 2 percent discount rate.\2\
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    \2\ The EPA estimated the annualized value of future benefits 
and costs using a discount rate of 2 percent, following current 
Office of Management and Budget (OMB) guidance in Circular A-4 (OMB, 
2023). In appendix B of the BCA, the EPA also provides results of 
analyses performed using 3 percent and 7 percent discount rates to 
allow comparison of the final rule costs and benefits with those 
estimated at proposal, which followed the guidance applicable at the 
time the prior analysis was conducted (OMB, 2003).
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    The EPA's analysis reflects the Agency's understanding of the 
actions steam electric power plants are expected to take to meet the 
limitations and standards in the final rule, including the 
implementation of additional treatment technologies to reduce pollutant 
discharges. The EPA based its analysis on a modeled baseline that 
reflects the full implementation of the 2020 rule, the expected effects 
of announced retirements and fuel conversions, and the anticipated 
impacts of relevant final rules affecting the power sector. Not all 
costs and benefits can be fully quantified and monetized. While some 
health benefits and willingness to pay (WTP) for water quality 
improvements have been quantified and monetized, those estimates may 
not fully capture all important water-quality-related benefits. 
Furthermore, the EPA anticipates the final rule would generate 
important additional benefits that the Agency was only able to analyze 
qualitatively (e.g., improved habitat conditions for plants, 
invertebrates, fish, amphibians, and the wildlife that prey on aquatic 
organisms).
    For additional information on costs and benefits, see sections VIII 
and XII of this preamble, respectively.

II. Public Participation

    During the 60-day public comment period on the 2023 proposed 
supplemental rule (88 FR 18824, March 29, 2023) (from March 29, 2023, 
to May 30, 2023), the EPA received more than 22,000 public comment 
submissions from private citizens, industry representatives, technology 
vendors, government entities, environmental groups, and trade 
associations. The EPA also hosted two online public hearings during the 
public comment period--one on April 20, 2023, and one on April 25, 
2023. These hearings had a combined total of 196 attendees, 46 of whom 
registered to provide comment on the proposed rule. Available documents 
from each public hearing include the presentations given by the EPA and 
two transcripts (document control number (DCN) SE10469, DCN SE10469A1, 
DCN SE10470 and DCN SE10470A1).

III. General Information

A. Does this action apply to me?

    Entities potentially regulated by any final rule following this 
action include the following:

[[Page 40201]]



------------------------------------------------------------------------
                                                          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.
------------------------------------------------------------------------

    This section is not intended to be exhaustive, but rather provides 
a guide regarding entities likely to be regulated by this final rule. 
Other types of entities that do not meet the above criteria could also 
be regulated. To determine whether a specific facility is regulated by 
this final rule, carefully examine the applicability criteria listed in 
40 CFR 423.10 and the definitions in 40 CFR 423.11. If you still have 
questions regarding the applicability of this final rule to a 
particular entity, consult the person listed for technical information 
in the preceding FOR FURTHER INFORMATION CONTACT section.

B. What action is the EPA taking?

    The Agency is revising certain BAT ELGs for existing sources in the 
steam electric power generating point source category that apply to FGD 
wastewater, BA transport water, CRL, and legacy wastewater.

C. What is EPA's authority for taking this action?

    The EPA is finalizing this rule under the authority of sections 
301, 304, 306, 307, 308, 402, and 501 of the CWA, 33 United States Code 
(U.S.C.) 1311, 1314, 1316, 1317, 1318, 1342, and 1361.

D. What are the monetized incremental costs and benefits of this 
action?

    This final rule is estimated to have social costs of $536 million 
to $1.1 billion per year and result in $3.2 billion in benefits using a 
two percent discount rate.\3\
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    \3\ See note 2.
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IV. Background

A. Clean Water Act

    Congress passed the Federal Water Pollution Control Act Amendments 
of 1972, also known as the 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 our 
nation's waters. Among its core provisions, the CWA prohibits the 
discharge of pollutants from a point source to waters of the United 
States (WOTUS), except as authorized under the CWA. Under section 402 
of the CWA, discharges may be authorized through a National Pollutant 
Discharge Elimination System (NPDES) permit. The CWA also authorizes 
the EPA to establish nationally applicable, technology-based ELGs for 
discharges from different categories of point sources, such as 
industrial, commercial, and public sources.
    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 POTWs, as outlined in CWA sections 307(b) and (c), 33 
U.S.C. 1317(b) and (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 direct and indirect industrial dischargers are 
subject to similar levels of treatment. See CWA section 301(b), 33 
U.S.C. 1311(b); Chem. Mfrs. Ass'n v. NRDC, 470 U.S. 116, 119 (1985); 
Envtl. Def. Fund v. Costle, 636 F.2d 1229, 1235 n.15 (D.C. Cir. 1980); 
Reynolds Metals Co. v. EPA, 760 F.2d 549, 553 (4th Cir. 1985); Chem. 
Mfrs. Ass'n v. EPA, 870 F.2d 177, 249 (5th Cir. 1989). In addition, 
POTWs are required to implement local treatment limitations applicable 
to their industrial indirect dischargers to satisfy any local 
requirements. See 40 CFR 403.5.
    Direct dischargers (i.e., those discharging directly from a point 
source to surface waters rather than through POTWs) must comply with 
effluent limitations in NPDES permits. Discharges that flow through 
groundwater before reaching surface waters must also comply with 
effluent limitations in NPDES permits if those discharges are the 
``functional equivalent'' of a direct discharge from a point source to 
a WOTUS. County of Maui v. Hawaii Wildlife Fund, 590 U.S. 165 (2020). 
Indirect dischargers, who discharge through POTWs, must comply with 
pretreatment standards. Technology-based effluent limitations 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 BPJ where the EPA 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 required to be 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, and these ELGs 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., 
TSS, oil and grease, biochemical oxygen demand (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 
section 307(a) of the Act, 40 CFR 401.15 and 40 CFR part 423, appendix 
A; and (3) nonconventional pollutants, which are those pollutants that 
are not categorized as conventional or toxic (e.g., ammonia-N, 
phosphorus, total dissolved solids (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. 
The legislative history of CWA section 304(b), which is the heart of 
the effluent guidelines program, describes the need to press toward 
higher levels of control through research and development of new 
processes, modifications, replacement of obsolete plants and processes, 
and other improvements in technology, while also accounting for the 
cost of controls. Legislative history and case law support that the EPA 
need

[[Page 40202]]

not consider water quality impacts on individual water bodies as the 
guidelines are developed; see Statement of Senator Muskie (October 4, 
1972), reprinted in Legislative History of the Water Pollution Control 
Act Amendments of 1972, at 170. (U.S. Senate, Committee on Public 
Works, Serial No. 93-1, January 1973); see also Southwestern Elec. 
Power Co. v. EPA, 920 F.3d at 1005 (``The 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 many technology-based effluent limitations (TBELs) that 
may apply to a 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. See 
Southwestern Elec. Power Co. v. EPA, 920 F3d at 1025. The EPA may 
promulgate BPT effluent limitations for conventional, toxic, and 
nonconventional pollutants. In specifying BPT, the EPA looks at several 
factors. The EPA considers the cost of achieving effluent reductions in 
relation to the effluent reduction benefits. The Agency 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 impacts (including energy 
requirements), and such other factors as the Administrator deems 
appropriate. 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. Courts have 
referred to this as the CWA's ``gold standard'' for controlling 
discharges from existing sources. Southwestern Elec. Power Co. v. EPA, 
920 F.3d at 1003; see also Kennecott v. EPA, 780 F.2d 445, 448 (4th 
Cir. 1985) (``The BAT standard reflects the intention of Congress to 
use the latest scientific research and technology in setting effluent 
limits, pushing industries toward the goal of zero discharge as quickly 
as possible.''). In general, BAT represents the best available, 
economically achievable performance of facilities in the industrial 
subcategory or category. As the statutory phrase intends, the EPA 
considers the technological availability and the economic achievability 
when 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, and non-water quality 
environmental impacts, 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 Agency retains considerable 
discretion in assigning the weight to be accorded these factors. 
Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045 (D.C. Cir. 1978). The 
EPA usually determines economic achievability based on the effect the 
cost of compliance with BAT limitations has 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 
based on technology transferred from a different subcategory or 
category, bench scale or pilot plant studies, or foreign plants. 
Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1006; Chem. Mfrs. 
Ass'n v. EPA, 870 F.2d at 226; Nat. Res. Def. Council v. EPA, 863 F.2d 
1420, 1426 (9th Cir. 1988); American Paper Inst. v. Train, 543 F.2d 
328, 353 (D.C. Cir. 1976); American Frozen Food Inst. v. Train, 539 
F.2d 107, 132 (D.C. Cir. 1976). BAT may be based upon process changes 
or internal controls, even when these technologies are not common 
industry practice. See American Frozen Foods, 539 F.2d at 132, 140; 
Reynolds Metals Co. v. EPA, 760 F.2d at 562; California & Hawaiian 
Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977). ``In setting 
BAT, EPA uses not the average plant, but the optimally operating plant, 
the pilot plant which acts as a beacon to show what is possible.'' 
Kennecott v. EPA, 780 F.2d at 448 (citing A Legislative History of the 
Water Pollution Control Act Amendments of 1972, 93d Cong., 1st Sess. 
(Comm. Print 1973), at 798). As recently reiterated by the U.S. Court 
of Appeals for the Fifth Circuit, ``Under our precedent, a 
technological process can be deemed available for BAT purposes even if 
it is not in use at all, or if it is used in unrelated industries. Such 
an outcome is consistent with Congress'[s] intent to push pollution 
control technology.'' Southwestern Elec. Power Co. v. EPA, 920 F.3d at 
1031 (citation and internal quotations omitted); see also Am. Petroleum 
Inst. v. EPA, 858 F.2d 261, 265 (5th Cir. 1988).
3. New Source Performance Standards
    New Source Performance Standards (NSPS) reflect effluent reductions 
that are achievable based on the Best Available Demonstrated Control 
Technology (BADCT). Owners of new facilities have the opportunity to 
install the best and most efficient production processes and wastewater 
treatment technologies. As a result, NSPS should represent the most 
stringent controls attainable through the application of the BADCT for 
all pollutants (that is, conventional, nonconventional, and toxic 
pollutants). In establishing NSPS, the EPA is directed to take into 
consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements. CWA 
section 306(b)(1)(B), 33 U.S.C. 1316(b)(1)(B).
4. 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. 
Pretreatment standards for existing sources (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 BPT 
and BAT ELGs; thus, the Agency typically considers the same factors in 
promulgating PSES as it considers in promulgating BAT. 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 non-domestic dischargers. See 52 FR 1586 (January 14, 
1987).

[[Page 40203]]

5. Pretreatment Standards for New Sources
    Section 307(c), 33 U.S.C. 1317(c), of the Act calls for the EPA to 
promulgate Pretreatment Standards for New Sources (PSNS). Such 
pretreatment standards must prevent the discharge of any pollutant into 
a POTW that may interfere with, pass through, or may otherwise be 
incompatible with the POTW. The EPA promulgates PSNS based on BADCT for 
new sources. New indirect dischargers have the opportunity to 
incorporate into their facilities the best available demonstrated 
technologies. The Agency typically considers the same factors in 
promulgating PSNS as it considers in promulgating NSPS.
6. Best Professional Judgment
    CWA section 301 and its implementing regulation at 40 CFR 125.3(a) 
indicate that technology-based treatment requirements under section 
301(b) of the CWA represent the minimum level of control that must be 
imposed in an NPDES permit. 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, such treatment 
requirements are established on a case-by-case basis using the permit 
writer's BPJ. Case-by-case TBELs are developed pursuant to CWA section 
402(a)(1), which 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.'' 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, Sec.  125.3(c)(3) indicates, ``[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 in 
establishing technology-based effluent limitations. See 40 CFR 
125.3(d)(1) through (3).

C. 2015 Steam Electric Power Generation Point Source Category Rule

1. 2015 Rule Requirements
    On November 3, 2015, the EPA promulgated a rule revising the 
regulations for the Steam Electric Power Generating point source 
category, 40 CFR part 423. 80 FR 67838, November 3, 2015. The rule set 
the first Federal limitations on the levels of toxic pollutants (e.g., 
arsenic) and nutrients (e.g., nitrogen) that can be discharged in the 
steam electric power generating industry's largest sources of 
wastewater, based on technology improvements in the steam electric 
power industry over the preceding three decades. Before the 2015 rule, 
regulations for the industry were last updated in 1982 and, for the 
industry's wastestreams with the largest pollutant loadings, contained 
only limitations on TSS and oil and grease.
    Over those 30 years, new technologies for generating electric power 
and the widespread implementation of air pollution controls had altered 
existing wastewater streams or created new wastewater streams at many 
steam electric facilities, particularly coal-fired facilities. 
Discharges of these wastestreams include arsenic, lead, mercury, 
selenium, chromium, and cadmium. Once in the environment, many of these 
toxic pollutants can remain there for years and continue to cause 
adverse impacts.
    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, FGMC wastewater, 
FA transport water, gasification wastewater, and legacy wastewater.\4\ 
The rule required most steam electric facilities to comply with the 
effluent limitations ``as soon as possible'' after November 1, 2018, 
and no later than December 31, 2023. NPDES permitting authorities 
established particular applicability date(s) within that range for each 
facility (except for indirect dischargers) at the time they reissued 
the facility's NPDES permit.
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    \4\ These wastestreams are defined in appendix A to this 
preamble.
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    The 2015 rule was projected to reduce the amount of metals the CWA 
defines as toxic pollutants, nutrients, and other pollutants that steam 
electric facilities are allowed to discharge by 1.4 billion pounds per 
year and reduce water withdrawal by 57 billion gallons. At the time, 
the EPA estimated annual compliance costs for the final rule to be $480 
million (in 2013 dollars, discounted at 3 percent) and estimated annual 
benefits associated with the rule to be $451 to $566 million (in 2013 
dollars, discounted at 3 percent).
2. Vacatur of Limitations Applicable to CRL and Legacy Wastewater
    Seven petitions for review of the 2015 rule were filed in various 
circuit courts by the electric utility industry, environmental groups, 
and drinking water utilities. These petitions were consolidated in the 
U.S. Court of Appeals for the Fifth Circuit, Southwestern Electric 
Power Co. v. EPA, Case No. 15-60821 (5th Cir.). On March 24, 2017, the 
Utility Water Act Group submitted to the EPA an administrative petition 
for reconsideration of the 2015 rule. On April 5, 2017, the Small 
Business Administration (SBA) submitted an administrative petition for 
reconsideration of the 2015 rule.
    On August 11, 2017, then EPA Administrator Scott Pruitt announced 
his decision to conduct a rulemaking to potentially revise the new, 
more stringent BAT effluent limitations and pretreatment standards for 
existing sources 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 Fifth Circuit issued a 
decision on April 12, 2019, vacating those limitations as arbitrary and 
capricious under the Administrative Procedure Act and unlawful under 
the CWA, respectively. Southwestern Elec. Power Co. v. EPA, 920 F.3d 
999. 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 on surface impoundments 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 its plans to address the vacated 
limitations in a later action after the 2020 rule.

[[Page 40204]]

    In September 2017 (82 FR 43494), using notice-and-comment 
procedures, the EPA finalized a rule postponing the earliest compliance 
dates for the more stringent BAT effluent limitations and PSES for FGD 
wastewater and BA transport water in the 2015 rule, from November 1, 
2018, to November 1, 2020 (``postponement rule''). The EPA also 
withdrew a prior action it had taken to stay parts of the 2015 rule 
pursuant to section 705 of the Administrative Procedure Act, 5 U.S.C. 
705. The postponement rule received multiple legal challenges, but the 
courts did not sustain any of them.\5\
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    \5\ See Center for Biological Diversity v. EPA, No. 18-cv-00050 
(D. Ariz. filed January 20, 2018); see also Clean Water Action. v. 
EPA, No. 18-60079 (5th Cir.). On October 29, 2018, the District of 
Arizona case was dismissed upon the EPA's motion to dismiss for lack 
of jurisdiction, and on August 28, 2019, the Fifth Circuit denied 
the petition for review of the postponement rule.
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D. 2020 Steam Electric Reconsideration Rule and Recent Developments

1. 2020 Rule Requirements
    On October 13, 2020, the EPA promulgated the Steam Electric 
Reconsideration Rule (85 FR 64650). The 2020 rule revised requirements 
for FGD wastewater and BA transport water applicable to existing 
sources. 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. This change in the 
technology basis resulted in less stringent selenium limitations but 
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. 
This change in technology resulted in less stringent limitations for 
all pollutants in BA transport water. Second, the 2020 rule revised the 
technology basis for the voluntary incentives program (VIP) for FGD 
wastewater from vapor compression evaporation to chemical precipitation 
plus membrane filtration. This change in the technology basis resulted 
in less stringent limitations for most pollutants but added new 
limitations for bromide and nitrogen. Third, the 2020 rule created 
three new subcategories for high-flow facilities, LUEGUs, and EGUs 
permanently ceasing coal combustion by 2028. These subcategories were 
subject to less stringent limitations: high-flow facilities were 
subject to FGD wastewater limitations based on chemical precipitation; 
LUEGUs were subject to FGD wastewater limitations based on chemical 
precipitation and BA transport water limitations based on surface 
impoundments and a best management practice (BMP) 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, and no later than December 31, 
2025.\6\ 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 reissued 
the facility's NPDES permit.
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    \6\ The 2015 rule's VIP compliance date was revised to December 
31, 2028, in the 2020 rule.
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2. Fourth Circuit Court of Appeals Litigation
    Two petitions for review of the 2020 rule were timely filed by 
environmental group petitioners and consolidated in the U.S. Court of 
Appeals for the Fourth Circuit on November 19, 2020. Appalachian 
Voices, et al. v. EPA, No. 20-2187 (4th Cir.). An industry trade group 
and certain energy companies moved to intervene in the litigation, 
which the Court granted on December 3, 2020. On April 8, 2022, the 
Court granted the EPA's motion and placed the case into abeyance 
pending the completion of the current rulemaking.
3. Executive Order 13990 and Announcement of Supplemental Rule
    On January 20, 2021, President Biden issued Executive Order 13990: 
Protecting Public Health and the Environment and Restoring Science to 
Tackle the Climate Crisis. 86 FR 7037. Executive Order 13990 directed 
Federal agencies to immediately review and, as appropriate and 
consistent with applicable law, take action to address the promulgation 
of Federal regulations and other actions during the previous four years 
that conflict with the national objectives of protecting public health 
and the environment.
    On July 26, 2021, the EPA announced a new rulemaking to strengthen 
certain wastewater pollution discharge limitations for coal-fired power 
plants that use steam to generate electricity (86 FR 41801, August 3, 
2021). The EPA later clarified that, as part of its new rulemaking, it 
would be reconsidering all aspects of the 2020 rule. The EPA undertook 
an evidence-based, science-based review of the 2020 rule under 
Executive Order 13990, finding that there are opportunities to 
strengthen certain wastewater pollution discharge limitations. For 
example, the EPA discussed how treatment systems using membranes have 
advanced since the 2020 rule's promulgation and continue to rapidly 
advance as an effective option for treating a wide variety of 
industrial pollution, including pollution from steam electric power 
plants. In the announcement, the EPA also clarified that, until a new 
rule is promulgated, part 423 will continue to be implemented and 
enforced to achieve needed pollutant reductions.\7\
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    \7\ This includes both the 2020 rule and portions of the 2015 
rule which were not revised or vacated.
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4. Preliminary Effluent Guidelines Plan 15
    In September 2021, the EPA issued Preliminary Effluent Guidelines 
Program Plan 15.\8\ This document discussed the annual review of ELGs, 
rulemakings for new and existing industrial point source categories, 
and any new or existing sources receiving further analyses. Here, in 
the context of the EPA's ongoing steam electric ELG rulemaking, EPA 
noted relevant wastestreams including pointing out that the 2015 rule 
limitations for CRL and legacy wastewater had been vacated and remanded 
to the Agency. For further discussion of the vacatur and remand of the 
2015 limitations applicable to CRL and legacy wastewater, see section 
IV.D of this preamble.
---------------------------------------------------------------------------

    \8\ Available online at: www.epa.gov/system/files/documents/2021-09/ow-prelim-elg-plan-15_508.pdf.
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E. Other Ongoing EPA Rules Impacting the Steam Electric Sector

    The EPA has recently proposed or finalized several other rules to 
protect the nation's air, land, and water from pollution resulting from 
coal-fired power plants. The EPA has primarily considered these other 
rules to support this final rulemaking in two ways. First, when 
appropriate, the EPA has included the impacts of final rules in the 
baseline of its analyses. Second, the EPA has designed this final rule 
to harmonize compliance dates, subcategories, and other aspects of 
these rules to the extent possible and appropriate under different 
statutory schemes. The following sections summarize the solid waste and

[[Page 40205]]

air rules that are most directly relevant to the electric power sector.
1. Coal Combustion Residuals Disposal Rule
    On April 17, 2015, the EPA promulgated the Disposal of Coal 
Combustion Residuals from Electric Utilities final rule (2015 CCR rule) 
(80 FR 21302). This rule finalized national regulations to provide a 
comprehensive set of requirements for the safe disposal of CCR, 
commonly referred to as coal ash, from steam electric power plants. The 
final 2015 CCR rule was the culmination of extensive study on the 
effects of coal ash on the environment and public health. The rule 
established technical requirements for CCR landfills and surface 
impoundments under subtitle D of the Resource Conservation and Recovery 
Act (RCRA), the Nation's primary law for regulating solid waste.
    These regulations established requirements for the management and 
disposal of coal ash, including requirements designed to prevent 
leaking of contaminants into groundwater, blowing of contaminants into 
the air as dust, and the catastrophic failure of coal ash surface 
impoundments. The 2015 CCR rule also set recordkeeping and reporting 
requirements, as well as requirements for each plant to establish and 
post specific information to a publicly accessible website. The rule 
also established requirements to distinguish the beneficial use of CCR 
from disposal.
    As a result of the D.C. Circuit Court decisions in Utility Solid 
Waste Activities Group v. EPA, 901 F.3d 414 (D.C. Cir. 2018) (``USWAG 
decision'' or ``USWAG''), and Waterkeeper Alliance Inc. et al. v. EPA, 
No. 18-1289 (D.C. Cir. filed March 13, 2019), the Administrator signed 
two rules: A Holistic Approach to Closure Part A: Deadline to Initiate 
Closure and Enhancing Public Access to Information (CCR Part A rule) 
(85 FR 53516, August 28, 2020) on July 29, 2020, and A Holistic 
Approach to Closure Part B: Alternate Liner Demonstration (CCR Part B 
rule) (85 FR 72506, December 14, 2020) on October 15, 2020. The EPA 
finalized five amendments to the 2015 CCR rule which are relevant to 
the management of the wastewaters covered by this ELG because these 
wastewaters have historically been co-managed with CCR in the same 
surface impoundments. First, the CCR Part A rule established a new 
deadline of April 11, 2021, for all unlined surface impoundments in 
which CCR are managed (``CCR surface impoundments''), as well as CCR 
surface impoundments that failed the location restriction for placement 
above the uppermost aquifer, to stop receiving waste and begin closure 
or retrofitting. The EPA established this date after evaluating the 
steps that owners and operators need to take for CCR surface 
impoundments to stop receiving waste and begin closure, and the 
timeframes needed for implementation. (This did not affect the ability 
of plants to install new, composite-lined CCR surface impoundments.) 
Second, the Part A rule established procedures for plants to obtain 
approval from the EPA for additional time to develop alternative 
disposal capacity to manage their wastestreams (both CCR and non-CCR) 
before they must stop receiving waste and begin closing their CCR 
surface impoundments. Third, the Part A rule changed the classification 
of compacted-soil-lined and clay-lined surface impoundments from lined 
to unlined. Fourth, the Part B rule finalized procedures potentially 
allowing a limited number of facilities to demonstrate to the EPA that, 
based on groundwater data and the design of a particular surface 
impoundment, the unit ensures there is no reasonable probability of 
adverse effects to human health and the environment. Should the EPA 
approve such a submission, these CCR surface impoundments would be 
allowed to continue to operate.
    As explained in the 2015 and 2020 ELG rules, the ELGs and CCR rules 
may affect the same EGU or activity at a plant. Therefore, when the EPA 
finalized the ELG and CCR rules in 2015, and revisions to both rules in 
2020, the Agency coordinated the ELG and CCR rules to minimize the 
complexity of implementing engineering, financial, and permitting 
activities. Likewise, the EPA considered the interaction of the two 
rules during the development of this final rule. The EPA's analytic 
baseline includes the final requirements of these rules using the most 
recent data provided under the CCR rule reporting and recordkeeping 
requirements. This is further described in Supplemental TDD, section 3. 
For more information on the CCR Part A and Part B rules, including 
information about their ongoing implementation, visit www.epa.gov/coalash/coal-ash-rule.
    Concurrently with the final ELG, in a separate rulemaking, the EPA 
is also finalizing regulatory requirements for inactive CCR surface 
impoundments at inactive utilities (``legacy CCR surface impoundment'' 
or ``legacy impoundment'') (FR 2024-09157 (EPA-HQ-OLEM-2020-0107; FRL-
7814-04-OLEM)). This action is being taken in response to the August 
21, 2018, opinion by the U.S. Court of Appeals for the District of 
Columbia Circuit in the USWAG decision that vacated and remanded the 
provision exempting legacy impoundments from the CCR regulations. This 
action includes adding a definition for legacy CCR surface impoundments 
and other terms relevant to this rulemaking. It also requires that 
legacy CCR surface impoundments comply with certain existing CCR 
regulations with tailored compliance deadlines.
    The EPA is also establishing requirements to address the risks from 
currently exempt solid waste management that involves the direct 
placement of CCR on the land. The EPA is extending a subset of the 
existing requirements in 40 CFR part 257, subpart D, to CCR surface 
impoundments and landfills that closed prior to the effective date of 
the 2015 CCR rule, inactive CCR landfills, and other areas where CCR is 
managed directly on the land. In this action, the EPA refers to these 
as CCR management units, or CCRMU. This rule will apply to all existing 
CCR facilities and all inactive facilities with legacy CCR surface 
impoundments subject to this final rule.
    Finally, the EPA is making a number of technical corrections to the 
existing regulations, such as correcting certain citations and 
harmonizing definitions. For further information on the CCR 
regulations, including information about the CCR Part A and Part B 
rules' ongoing implementation, visit www.epa.gov/coalash/coal-ash-rule.
2. Air Pollution Rules and Implementation
    The EPA is taking several actions to regulate a variety of 
conventional, hazardous, and greenhouse gas (GHG) air pollutants, 
including actions to regulate the same steam electric power plants 
subject to part 423. In light of these ongoing actions, the EPA has 
worked to consider appropriate flexibilities in this ELG rule to 
provide certainty to the regulated community while ensuring the 
statutory objectives of each program are achieved. Furthermore, to the 
extent that these actions have been published before this rule's 
signature and are already impacting steam electric power plant 
operations, the EPA has accounted for these changed operations in its 
Integrated Planning Model (IPM) modeling discussed in section VIII of 
this preamble.

[[Page 40206]]

a. The Revised Cross State Air Pollution Rule Update and the Good 
Neighbor Plan for the 2015 Ozone National Ambient Air Quality Standards
    On June 5, 2023, the EPA promulgated its final Good Neighbor Plan, 
which secures significant reductions in ozone-forming emissions of 
nitrogen oxides (NOX) from power plants and industrial 
facilities. 88 FR 36654. The Good Neighbor Plan ensures that 23 states 
meet the Clean Air Act's (CAA's) ``Good Neighbor'' requirements by 
reducing pollution that significantly contributes to problems attaining 
and maintaining EPA's health-based air quality standard for ground-
level ozone (or ``smog''), known as the 2015 Ozone National Ambient Air 
Quality Standards (NAAQS), in downwind states. Further information on 
this action is available on the EPA's website.\9\
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    \9\ See https://www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqs.
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    As of September 21, 2023, the Good Neighbor Plan's ``Group 3'' 
ozone-season NOX control program for power plants is being 
implemented in: Illinois, Indiana, Maryland, Michigan, New Jersey, New 
York, Ohio, Pennsylvania, Virginia, and Wisconsin. Pursuant to court 
orders staying the Agency's State Implementation Plan disapproval 
action in the following States, the EPA is not currently implementing 
the Good Neighbor Plan ``Group 3'' ozone-season NOX control 
program for power plants in: Alabama, Arkansas, Kentucky, Louisiana, 
Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah, and 
West Virginia.\10\
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    \10\ Further information on EPA's response to the stay orders 
can be found online at: https://www.epa.gov/Cross-State-Air-Pollution/epa-response-judicial-stay-orders.
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    On January 16, 2024, the EPA signed a proposal to partially approve 
and partially disapprove State Implementation Plan submittals 
addressing interstate transport for the 2015 ozone NAAQS from Arizona, 
Iowa, Kansas, New Mexico, and Tennessee and proposed to include these 
States in the Good Neighbor Plan beginning in 2025 (89 FR 12666, 
February 16, 2024).
    On April 30, 2021, the EPA published the final Revised Cross-State 
Air Pollution Rule (CSAPR) Update (86 FR 23054), which resolved 21 
states' good neighbor obligations for the 2008 ozone NAAQS, following 
the remand of the 2016 CSAPR Update (81 FR 74504, October 26, 2016) in 
Wisconsin v. EPA, 938 F.3d 308 (D.C. Cir. 2019). Together, these two 
rules establish the Group 2 and Group 3 market-based emissions trading 
programs for 22 states in the eastern United States for emissions of 
NOX from fossil fuel-fired EGUs during the summer ozone 
season.
b. Clean Air Act section 111 Rule
    Concurrently with the final ELG, the EPA is finalizing the repeal 
of the Affordable Clean Energy Rule, establishing Best System of 
Emissions Reduction (BSER) determinations and emission guidelines for 
existing fossil fuel-fired EGUs, and establishing BSER determinations 
and accompanying standards of performance for GHG emissions from new 
and reconstructed fossil fuel-fired stationary combustion turbines and 
modified fossil fuel-fired EGUs. Specifically, for coal-fired EGUs, the 
EPA is establishing final standards based on carbon capture and 
storage/sequestration with 90 percent capture with a compliance date of 
January 1, 2032 (FR 2024-09233 (EPA-HQ-OAR-2023-0072; FRL-8536-01-
OAR)). For coal-fired EGUs retiring by January 1, 2039, the EPA is 
establishing final standards based on 40 percent natural gas co-firing 
with a compliance date of January 1, 2030.
    While four subcategories for coal-fired EGUs were proposed, the EPA 
is finalizing just the two subcategories for coal-fired EGUs as 
described in the preceding paragraph. Consistent with 40 CFR 60.24a(e) 
and the Agency's explanation in the proposal, states have the ability 
to consider, inter alia, a particular source's remaining useful life 
when applying a standard of performance to that source.\11\
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    \11\ See 88 FR 33240 (May 23, 2023) (invoking RULOF based on a 
particular coal-fired EGU's remaining useful life ``is not 
prohibited under these emission guidelines'').
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    In addition, the EPA is creating an option for states to provide 
for a compliance date extension for existing sources of up to one year 
under certain circumstances for sources that are installing control 
technologies to comply with their standards of performance. States may 
also provide, by inclusion in their state plans, a reliability 
assurance mechanism of up to one year that under limited circumstances 
would allow existing EGUs that had planned to cease operating by a 
certain date to temporarily remain available to support reliability. 
Any extensions exceeding 1-year must be addressed through a state plan 
revision. Further information about the CAA section 111 rule is 
available online at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.
c. Mercury and Air Toxics Standards Rule
    On March 6, 2023 (88 FR 13956), the EPA published a final rule 
which reaffirmed that it remains appropriate and necessary to regulate 
hazardous air pollutants (HAP), including mercury, from power plants 
after considering cost. This action revoked a 2020 finding that it was 
not appropriate and necessary to regulate coal- and oil-fired power 
plants under CAA section 112, which covers toxic air pollutants. The 
EPA reviewed the 2020 finding and considered updated information on 
both the public health burden associated with HAP emissions from coal- 
and oil-fired power plants, as well as the costs associated with 
reducing those emissions under the Mercury and Air Toxics Standards 
(MATS). After weighing the public risks these emissions pose to all 
Americans (and particularly exposed and sensitive populations) against 
the costs of reducing this harmful pollution, the EPA concluded that it 
remains appropriate and necessary to regulate these emissions. This 
action ensures that coal- and oil-fired power plants continue to 
control emissions of hazardous air pollution and that the Agency 
properly interprets the CAA to protect the public from hazardous air 
emissions.
    Concurrently with the final ELG, the EPA is finalizing an update to 
the National Emission Standards for Hazardous Air Pollutants for Coal- 
and Oil-Fired Electric Utility Steam Generating Units (EGUs), commonly 
known as the Mercury and Air Toxics Standards (MATS) for power plants, 
to reflect recent developments in control technologies and the 
performance of these plants (FR 2024-0918 (EPA-HQ-OAR-2018-0794; FRL-
6716.3-02-OAR)). This final rule includes an important set of 
improvements and updates to MATS and also fulfills the EPA's 
responsibility under the Clean Air Act to periodically re-evaluate its 
standards in light of advancements in pollution control technologies to 
determine whether revisions are necessary. The improvements consist of:
     Further limiting the emission of non-mercury HAP metals 
from existing coal-fired power plants by significantly reducing the 
emission standard for filterable particulate matter (fPM), which is 
designed to control non-mercury HAP metals. The EPA is finalizing a 
two-thirds reduction in the fPM standard; \12\
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    \12\ Also, the EPA is finalizing the removal of the low-emitting 
EGU provisions for fPM and non-mercury HAP metals.

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[[Page 40207]]

     Tightening the emission limit for mercury for existing 
lignite-fired power plants by 70 percent; \13\
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    \13\ This level aligns with the mercury standard that other 
coal-fired power plants have been achieving under the current MATS.
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     Strengthening emissions monitoring and compliance by 
requiring coal-and oil-fired EGUs to comply with the fPM standard using 
PM continuous emission monitoring systems (CEMS); \14\
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    \14\ PM CEMS provide regulators, the public, and facility owners 
or operators with cost-effective, accurate, and continuous emission 
measurements. This real-time, quality-assured feedback can lead to 
improved control device and power plant operation, which will reduce 
air pollutant emissions and exposure for local communities.
---------------------------------------------------------------------------

     Revising the startup requirements in MATS to assure better 
emissions performance during startup.
    Additional information on the final MATS is available on the EPA's 
website.\15\
---------------------------------------------------------------------------

    \15\ See https://www.epa.gov/stationary-sources-air-pollution/mercury-and-air-toxics-standards.
---------------------------------------------------------------------------

d. National Ambient Air Quality Standards Rules for Particulate Matter
    On February 7, 2024, the EPA Administrator signed a final rule 
strengthening the National Ambient Air Quality Standards for 
Particulate Matter (PM NAAQS) to protect millions of Americans from 
harmful and costly health impacts, such as heart attacks and premature 
death (89 FR 16202, March 6, 2024). Particle or soot pollution is one 
of the most dangerous forms of air pollution, and an extensive body of 
science links it to a range of serious and in some cases deadly 
illnesses. The EPA set the level of the primary (health-based) annual 
particulate matter (PM2.5) standard at 9.0 micrograms per 
cubic meter to provide increased public health protection, consistent 
with the available health science. The EPA did not change the current 
primary and secondary (welfare-based) 24-hour PM2.5 
standards, the secondary annual PM2.5 standard, and the 
primary and secondary PM10 standards. The EPA also revised 
the Air Quality Index to improve public communications about the risks 
from PM2.5 exposures and made changes to the monitoring 
network to enhance protection of air quality in communities 
overburdened by air pollution. More information about this action is 
available on the EPA's website.\16\
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    \16\ See https://www.epa.gov/pm-pollution/national-ambient-air-quality-standards-naaqs-pm.
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V. Steam Electric Power Generating Industry Description

A. General Description of Industry

    For each previous regulatory action--the 2013 proposed rule (78 FR 
34432, June 7, 2013), the 2015 final rule, the 2019 proposed rule (84 
FR 64620, November 22, 2019), the 2020 final rule, and the 2023 
proposed rule--the EPA provided general descriptions of the steam 
electric power generating industry. The Agency has continued to collect 
information and update this industry profile. The previous descriptions 
reflected the known information about the universe of steam electric 
power plants and incorporated final environmental regulations 
applicable at that time. For this rule, as described in the 
Supplemental TDD, section 3, the EPA has revised its description of the 
steam electric power generating industry (and its supporting analyses) 
to incorporate major changes such as additional retirements, fuel 
conversions, ash handling conversions, wastewater treatment updates, 
and updated information on capacity utilization.\17\ The analyses 
supporting this rule use an updated baseline that incorporates these 
changes in the industry and include the 2015 and 2020 rules' 
limitations for FGD wastewater, BA transport water, CRL, and legacy 
wastewater. The analyses then compare the effect of the new rule's 
requirements to this baseline.
---------------------------------------------------------------------------

    \17\ The data presented in the general description continue to 
reflect some conditions existing in 2009.The 2010 steam electric 
industry survey remains the EPA's best available source of 
information for characterizing operations across the industry in 
cases where the EPA has not received newer information.
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    As described in the Regulatory Impact Analysis, of the 858 steam 
electric power plants in the country identified by the EPA, only those 
coal-fired power plants that discharge FGD wastewater, BA transport 
water, CRL, legacy wastewater and/or unmanaged CRL may incur compliance 
costs under this rule. The EPA estimates that 141 to 170 such plants 
may incur compliance costs under this rule, depending on the scenario 
used to model the occurrence of unmanaged CRL costs. See section 
VII.C.5 of this preamble for more information regarding subcategory for 
discharges of unmanaged CRL. See the EPA's memorandum, Changes to 
Industry Profile for Coal-Fired Generating Units for the Steam Electric 
Effluent Guidelines Final Rule (DCN SE11618), for more information 
about plant retirements, fuel conversions, ash handling conversions, 
wastewater treatment updates, and updated information on capacity 
utilization.

B. Current Market Conditions and Drivers in the Electricity Generation 
Sector

1. Inflation Reduction Act Implementation
    On August 16, 2022, President Biden signed into law the Inflation 
Reduction Act (IRA). The IRA marks the most significant action Congress 
has taken on clean energy and climate change in the nation's history. 
The IRA provides tax credits, financing programs, and other incentives, 
some of which are administered by the EPA, that will accelerate the 
transition to forms of energy that produce little or no GHG emissions 
and other water and air pollutants. As such, it includes many 
provisions that will affect the steam electric power generating 
industry, causing both direct effects through changes in the production 
of electricity and indirect effects on electricity demand and changes 
to fuel markets.
    In September 2023, the EPA published a report on the effect of the 
IRA on the electricity sector and on the economy in general.\18\ The 
report found that the IRA would lead to emission reductions from the 
electric power sector of 49 to 83 percent below 2005 levels in 2030. 
The associated shifts from fossil fuel generation would also lead to 
reductions in water and air pollution from the sector. The study also 
found that the IRA would lower economy-wide CO2 emissions, 
including emissions from electricity generation and use, by 35 to 43 
percent below 2005 levels in 2030. Across the end-use sectors, the 
study found that buildings exhibit the greatest reductions from 2005 
levels of direct plus indirect CO2 emissions from 
electricity, followed by industry and transportation. Though it focuses 
on changes in climate-forcing emissions (in part attributable to the 
models it uses), the study also implies important changes in the 
emissions of other pollutants throughout the economy. The EPA used IPM 
to evaluate the impacts of the final ELG relative to a baseline that 
reflects impacts from other relevant policies and environmental 
regulations that affect the power sector, including the IRA and other 
on-the-books Federal and state rules (see section VIII.C.2 of this 
preamble for more information).
---------------------------------------------------------------------------

    \18\ U.S. EPA (Environmental Protection Agency). 2023. 
Electricity Sector Emissions Impacts of the Inflation Reduction Act: 
Assessment of Projected CO2 Emission Reductions from 
Changes in Electricity Generation and Use. U EPA 430-R-23-004. 
Available online at: https://www.epa.gov/inflation-reduction-act/electric-sector-emissions-impacts-inflation-reduction-act.

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[[Page 40208]]

2. Recent Developments in Ensuring Electric Reliability and Resource 
Adequacy
    The nature and components of the bulk power sector have been 
evolving away from older and less efficient legacy fossil generation 
(mostly coal-fired power plants) towards more decentralized, renewable 
assets and flexible gas-fired generation. Stakeholders have raised 
concerns that centralized, dispatchable power plants are coming offline 
faster than new generation can replace the reliability attributes 
associated with them. However, a combination of technology innovation, 
revised market signals from the Regional Transmission Organizations 
(RTOs) and Independent System Operators (ISOs), and reforms recently 
completed and underway by Federal Energy Regulatory Commission (FERC) 
are collectively poised to address current reliability challenges 
associated with the transition along with expected higher load growth 
and the increasing frequency of extreme weather events. EPA has 
continued to learn and engage on reliability issues, particularly as 
part of the Agency's implementation of the Joint Memorandum on 
Interagency Communication and Consultation on Electric Reliability.\19\ 
As part of this process, EPA has engaged in regular meetings with 
Department of Energy (DOE), North American Electric Reliability 
Corporation (NERC), FERC, and the various ISOs/RTOs.
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    \19\ Available online at: https://www.epa.gov/power-sector/electric-reliability-mou.
---------------------------------------------------------------------------

    FERC, NERC, RTOs, and ISOs are already taking steps to ensure 
reliability during this period of asset evolution. Among FERC's actions 
to help address reliability is Order 2023, or ``Improvements to 
Generator Interconnection Procedures,'' which will help expedite 
interconnections for new assets waiting to connect to the grid. This is 
a very important development to ensure future resource adequacy because 
interconnection wait times for new energy assets entering energy 
markets have increased, which is stifling the ability of replacement 
generation to connect to the grid. FERC's final action on extreme cold 
weather preparedness will support the new peak demand hours, which have 
migrated to winter months. New reliability standards issued for 
inverter-based resources ``will help ensure reliability of the grid by 
accommodating the rapid integration of new power generation 
technologies, known as inverter-based resources (IBRs), that include 
solar photovoltaic, wind, fuel cell and battery storage resources. . . 
.'' \20\ FERC has also undertaken various transmission-related efforts, 
from inter-regional transmission capacity efforts to reconductoring and 
dynamic line rating, that would help bolster reliability by increasing 
the transmission capacity of existing lines and creating incentives for 
new, inter-regional transmission. Increasing transmission capacity can 
enhance reliability by increasing the amount of generation that can 
access the grid to help meet demand.
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    \20\ For further information about FERC actions to address IBRs, 
see https://www.ferc.gov/news-events/news/ferc-moves-protect-grid-transition-clean-energy-resources.
---------------------------------------------------------------------------

    Furthermore, there are new technologies coming online that can also 
help provide reliability attributes. The deployment of many of these 
technologies has been accelerating due to the incentives in the IRA. 
The rapid increase in energy storage deployment across the nation is an 
important part of future grid reliability, particularly as the duration 
of storage assets expands. Examples of existing and emerging storage 
resources include various types of fuel cells, batteries, pumped hydro-
electric reservoirs, and underground hydrogen caverns. Energy storage 
can help buttress reliability by storing renewable energy for dispatch 
when demand is high. Improved management of demand response assets, 
better designed electricity tariff structures, aggregation of 
distributed resources like roof-top solar panels, and integration of 
behind-the-meter battery storage can further support balancing peak 
demand on power grids. For example, programs to manage demand, which 
have shown value well before the recent energy transition, incentivize 
customers to shift their demand during periods when there is ample 
supply, which can help reduce instances when supply is tight.
    Despite these concerns, there are also existing procedures in place 
to ensure electricity system reliability and resource adequacy over 
both the short and long-term. For example, regional planning 
organizations typically have incentive or planning procedures to ensure 
that there is sufficient capacity to meet future demand such as day-
ahead reserve and capacity markets and seasonal reserve margins. 
Furthermore, the EPA understands that before a unit implements a 
retirement decision, the unit's owner will follow the processes put in 
place by the relevant RTO, balancing authority, or state regulator to 
protect electric system reliability. These processes typically include 
analysis of the potential impacts of the proposed EGU retirement on 
electrical system reliability, identification of options for mitigating 
any identified adverse impacts, and, in some cases, temporary provision 
of additional revenues to support the EGU's continued operation until 
longer-term mitigation measures can be put in place.

C. Control and Treatment Technologies

    In general, control and treatment technologies for some 
wastestreams have continued to advance since the 2015 and 2020 rules. 
Often, these advancements provide plants with additional approaches for 
complying with any effluent limitations. In some cases, these 
advancements have also decreased the associated costs of compliance. 
For this rule, the EPA incorporated updated information and evaluated 
several technologies available to control and treat FGD wastewater, BA 
transport water, CRL, and legacy wastewater generated by the steam 
electric power generating industry. See section VIII of this preamble 
for details on updated cost information.
1. FGD Wastewater
    FGD scrubber systems are used to remove sulfur dioxide from flue 
gas so it is not emitted into the air. Dry FGD systems use water in 
their operation but generally do not discharge wastewater because it 
evaporates during operation. Wet FGD systems do produce a wastewater 
stream.
    Steam electric power plants discharging FGD wastewater currently 
employ a variety of wastewater treatment technologies and operating/
management practices to reduce the pollutants associated with FGD 
wastewater discharges. The EPA identified the following types of 
treatment and handling practices for FGD wastewater:
     Chemical precipitation. Chemicals are added as part of the 
treatment system to help remove suspended solids and dissolved solids, 
particularly metals. The precipitated solids are then removed from the 
solution by coagulation/flocculation followed by clarification and/or 
filtration. The 2015 and 2020 rules focused on a specific design that 
employs hydroxide precipitation, sulfide precipitation (organosulfide), 
and iron coprecipitation to remove suspended solids and convert soluble 
metal ions to insoluble metal hydroxides or sulfides. Chemical 
precipitation was part of the BAT technology basis for the effluent 
limitations in the 2015 and 2020 rules.
     High-hydraulic-residence-time biological reduction (HRTR). 
The EPA

[[Page 40209]]

identified three types of biological treatment systems used to treat 
FGD wastewater: anoxic/anaerobic fixed-film bioreactors (which target 
removals of nitrogen compounds and selenium), anoxic/anaerobic 
suspended growth systems (which target removals of selenium and other 
metals), and aerobic/anaerobic sequencing batch reactors (which target 
removals of organics and nutrients). An anoxic/anaerobic fixed-film 
bioreactor designed to remove selenium and nitrogen compounds using 
high hydraulic residence times of approximately 10 to 16 hours was part 
of the BAT technology basis for the effluent limitations in the 2015 
rule.
     Low-hydraulic-residence-time biological reduction (LRTR). 
LRTR is a biological treatment system that targets removal of selenium 
and nitrate/nitrite using fixed-film bioreactors in smaller, more 
compact reaction vessels. This system differs from the HRTR biological 
treatment system evaluated in the 2015 rule, in that the LRTR system is 
designed to operate with a shorter residence time (approximately one to 
four hours, compared to a residence time of 10 to 16 hours for HRTR) 
while still achieving significant removal of selenium and nitrate/
nitrite. LRTR was part of the BAT technology basis for the effluent 
limitations in the 2020 rule.
     Membrane filtration. A membrane filtration system (e.g., 
microfiltration, ultrafiltration, nanofiltration, forward osmosis, 
electrodialysis reversal, or reverse osmosis (RO)) is designed 
specifically for high-TDS and high-TSS wastestreams. These systems are 
designed to minimize fouling and scaling associated with industrial 
wastewater. These systems typically use pretreatment for potential 
scaling agents (e.g., calcium, magnesium, sulfates) combined with one 
or more type of membrane technology to remove a broad array of 
particulate and dissolved pollutants from FGD wastewater. The membrane 
filtration units may also employ advanced techniques, such as vibration 
or creation of vortexes to mitigate fouling or scaling of the membrane 
surfaces. Membrane filtration can achieve zero discharge by 
recirculating permeate from an RO system back into plant operations.
     Spray evaporation. Spray evaporation technologies, which 
include spray dry evaporators (SDEs) and other similar proprietary 
variations, evaporate water by spraying fine misted wastewater into hot 
gases. The hot gases allow the water to evaporate before contacting the 
walls of an evaporation vessel, treating wastewater across a range of 
water quality characteristics such as TDS, TSS, or scale forming 
potential. Spray evaporation technologies use a less complex treatment 
configuration than brine concentrator and crystallizer systems (see the 
description of thermal evaporation systems) to evaporate water using a 
heat source, such as a slipstream of hot flue gas or an external 
natural gas burner. Spray evaporation technologies can be used in 
combination with other volume reduction technologies, such as 
membranes, to maximize the efficiency of each process. Concentrate from 
an RO system can then be processed through the spray evaporation 
technology to achieve zero discharge by recirculating permeate from the 
RO system back into plant operations.
     Thermal evaporation. Thermal evaporation systems use a 
falling-film evaporator (or brine concentrator), following a softening 
pretreatment step, to produce a concentrated wastewater stream and a 
distillate stream to reduce wastewater volume by 80 to 90 percent and 
reduce the discharge of pollutants. The concentrated wastewater is 
usually further processed in a crystallizer that produces a solid 
residue for landfill disposal and additional distillate that can be 
reused within the plant or discharged. These systems are designed to 
remove the broad spectrum of pollutants present in FGD wastewater to 
very low effluent concentrations.
     Some plants operate their wet FGD systems using approaches 
that eliminate the discharge of FGD wastewater. These plants use a 
variety of operating and management practices to achieve this, 
including the following:

--Complete recycle. The FGD wastestream is allowed to recirculate. 
Particulates (e.g., precipitates and other solids) are removed and 
landfilled. Water is supplemented when needed to replace water that 
evaporated or was removed with landfilled solids. This process does not 
produce a saleable product (e.g., wallboard grade gypsum) but it does 
not need a wastewater purge stream to maintain low levels of chlorides.
--Evaporation impoundments. Some plants located in warm, dry climates 
use surface impoundments as holding basins where the FGD wastewater is 
retained until it evaporates. The evaporation rate from these 
impoundments is greater than the flow rate of the FGD wastewater and 
amount of precipitation entering the impoundments; therefore, there is 
no discharge to surface water.\21\ These impoundments must be large 
enough to accommodate extreme precipitation events to prevent 
overtopping and runoff.
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    \21\ Such impoundments must be lined based on the requirements 
in the CCR rule. This lining would significantly reduce the 
potential for a discharge through groundwater that would be the 
functional equivalent of a direct discharge to a WOTUS.
---------------------------------------------------------------------------

--FA conditioning. Many plants that operate dry FA handling systems use 
the water from their FGD system in the FA handling system to suppress 
dust or improve handling and/or compaction characteristics in an on-
site landfill.
--Combination of wet and dry FGD systems. The dry FGD process involves 
atomizing and injecting wet lime slurry, which ranges from 
approximately 18 to 25 percent solids, into a spray dryer. The water 
contained in the slurry evaporates from the heat of the flue gas within 
the system, leaving a dry residue that is removed from the flue gas 
using a fabric filter (i.e., baghouse) or electrostatic precipitator.
--Underground injection. These systems dispose of wastes by injecting 
them into a permitted underground injection well as an alternative to 
discharging wastewater to surface waters.

    The EPA also collected information on other FGD wastewater 
treatment technologies, including direct contact thermal evaporators 
and ion exchange. These treatment technologies have been evaluated, in 
full- or pilot-scale, or are being developed to treat FGD wastewater. 
More information on these technologies is available in section 4.1 of 
the Supplemental TDD.
2. BA Transport Water
    BA (bottom ash) consists of heavier ash particles that are not 
entrained in the flue gas and fall to the bottom of the furnace. In 
most furnaces, the hot BA is quenched in a water-filled hopper.\22\ 
Some plants use water to transport (sluice) the BA from the hopper to 
an impoundment or dewatering bins. The water used to transport the BA 
to the impoundment or dewatering bins is usually discharged to surface 
water as overflow from the systems after the BA has settled to the 
bottom. The industry also uses the following BA handling systems that 
generate BA transport water:
---------------------------------------------------------------------------

    \22\ Consistent with the 2015 and 2020 rule, EGU slag is 
considered BA.
---------------------------------------------------------------------------

     Remote mechanical drag system (MDS). These systems 
transport BA to a remote MDS using the same processes as wet-sluicing 
systems. A drag chain conveyor pulls the BA out of the water bath on an 
incline to dewater the BA. The system can be operated either as a

[[Page 40210]]

closed-loop system (part of the technology basis for the 2015 rule) or 
a high-recycle-rate system (technology basis for the 2020 rule).\23\
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    \23\ In some cases, additional treatment may be necessary to 
maintain a closed-loop system. This additional treatment could 
include polymer addition to enhance removal of suspended solids or 
membrane filtration of a slipstream to remove dissolved solids.
---------------------------------------------------------------------------

     Mobile MDS. This technology is a smaller, mobile version 
of a remote MDS with an additional clarification system. It is not 
intended to be a permanent installation, which allows facilities to 
reduce capital costs. Once in place, the system works like a remote 
MDS--the incoming water is clarified and primary separation occurs. The 
clarified water is taken from the mechanical drag system to a mobile 
clarifier and polished to a level suitable for recirculation. The 
mobile clarifier thickens the collected solids, which are then sent 
back to the mechanical drag system portion and mixed with coarse BA. 
This mixture is sent up an incline, dewatered, and disposed of.
     Dense slurry system. These systems use a dry vacuum or 
pressure system to convey the BA to a silo (as described below for the 
``dry vacuum or pressure system''), but instead of using trucks to 
transport the BA to a landfill, the plant mixes the BA with a lower 
percentage of water compared to a wet-sluicing system and pumps the 
mixture to the landfill.
    As part of the 2020 rule and this rule, the EPA identified the 
following BA handling systems that do not, by definition or practice, 
generate BA transport water.
     MDS. These systems are located directly underneath the 
EGU. The BA is collected in a water quench bath. A drag chain conveyor 
pulls the BA out of the water bath along an incline to dewater the BA.
     Dry mechanical conveyor. These systems are located 
directly underneath the EGU. The system uses ambient air to cool the BA 
in the boiler and then transports the ash out from under the EGU using 
a conveyor. There is no water used in this process.
     Dry vacuum or pressure system. These systems transport BA 
from the EGU to a dry hopper without using any water. Air is percolated 
through the ash to cool it and combust unburned carbon. Cooled ash then 
drops to a crusher and is conveyed via vacuum or pressure to an 
intermediate storage destination.
     Vibratory belt system. These systems deposit BA on a 
vibratory conveyor trough, where the ash is air-cooled and ultimately 
moved through the conveyor deck to an intermediate storage destination 
without using any water.
     Submerged grind conveyor. These systems are located 
directly underneath the EGU and are designed to reuse slag tanks, ash 
gates, clinker grinders, and transfer enclosures from the existing wet 
sluicing systems. The system collects BA from the discharge of each 
clinker grinder. A series of submerged drag chain conveyors transport 
and dewater the BA.
    More information on these technologies is available in section 4.2 
of the Supplemental TDD.
3. CRL
    In promulgating the 2015 rule, the EPA determined that CRL from 
landfills and impoundments includes similar types of constituents as 
FGD wastewater, albeit at potentially lower concentrations and smaller 
volumes. Based on this characterization of the wastewater and knowledge 
of treatment technologies, the EPA determined that certain treatment 
technologies identified for FGD wastewater could also be used to treat 
CRL. These technologies, described in section V.C.1 of this preamble, 
include chemical precipitation, biological treatment (including LRTR), 
membrane filtration, spray evaporation, or other thermal treatment 
options. The EPA also identified other management and reuse strategies 
from responses to the 2010 Questionnaire for the Steam Electric Power 
Generating Effluent Guidelines, or steam electric survey, which 
included using CRL from either an impoundment or landfill for moisture 
conditioning FA, dust control, or truck wash. The EPA also identified 
plants that collect CRL from impoundments and recycle it directly back 
to the impoundment.
4. Legacy Wastewater
    Legacy wastewater can be composed of FGD wastewater, BA transport 
water, FA transport water, CRL, gasification wastewater and/or FGMC 
wastewater generated before the ``as soon as possible'' date that more 
stringent effluent limitations from the 2015 or 2020 rules would apply. 
Discharges of legacy wastewater may occur through an intermediary 
source (e.g., a tank or surface impoundment) or directly into a surface 
waterbody, with the vast majority of legacy wastewater currently 
contained in surface impoundments resulting from treating the 
wastestreams listed above to the previously established BPT 
limitations. The record indicates that the following technologies can 
be applied to treat this type of legacy wastewater: chemical 
precipitation, biological treatment (including LRTR), membrane 
filtration, spray evaporation, and other thermal treatment options. 
These technologies are described in section V.C.1 of this preamble. 
Another option, which may be used in combination with other systems 
such as chemical and physical treatment, is zero valent iron (ZVI).
     ZVI. This technology can be used to target specific 
inorganics, including selenium, arsenic, nitrate, and mercury in this 
type of legacy wastewater. The technology entails mixing influent 
wastewater with ZVI (iron in its elemental form), which reacts with 
oxyanions, metal cations, and some organic molecules in wastewater. ZVI 
causes a reduction reaction in these pollutants, after which the 
pollutants are immobilized through surface adsorption onto iron oxide 
coated on the ZVI or generated from oxidation of elemental iron. The 
coated, or spent, ZVI is separated from the wastewater with a 
clarifier. The quantity of ZVI required and number of reaction vessels 
can vary based on the composition and amount of wastewater being 
treated.
    The EPA recognizes that the characterization of legacy wastewater 
differs within the layers of a CCR impoundment as it is dewatered and 
prepared for closure. Therefore, treatment requirements may change as 
closure continues. Wastewater characteristics may also differ across 
CCR impoundments due to the different types of fuels burned at the 
plant, duration of pond operation, and ash type. Each of the treatment 
technologies identified for legacy wastewater above is applicable to 
all legacy wastewaters; treatment may require a combination of those 
technologies (e.g., chemical precipitation and membrane filtration).
    In addition, solids dewatering is necessary to dredge CCR materials 
from the impoundment. Mobile dewatering systems are typically self-
contained units on a trailer, allowing for the entire system to be 
easily moved on-site and off-site. Legacy wastewater from a holding 
area (e.g., pit, pond, collection tank) is pumped through a filter 
press to generate a filter cake and water stream. A shaker screen can 
be added to the treatment train to remove larger particles prior to the 
filter press. Furthermore, the filter press can be equipped with 
automated plate shifters to allow solids to drop from the end of the 
trailer directly into a loader or truck. The resulting wastestream may 
be further treated to meet any discharge requirements.

[[Page 40211]]

VI. Data Collection Since the 2020 Rule

A. Information from the Electric Utility Industry

1. Data Requests and Responses
    In January 2022, the EPA requested the following pollution 
treatment system performance and cost information for coal-fired power 
plants from three steam electric power companies:
     FGD wastewater installations of the following 
technologies: thermal technology; membrane filtration technology; 
paste, solidification, or encapsulation of FGD wastewater brine; 
electrodialysis; and electrocoagulation.
     Overflow from an MDS, a compact submerged conveyor, or 
remote MDS installations, including purge rate and management from 
remote MDS systems, as well as any pollutant concentration data to 
characterize the overflow or purge.
     CRL treatment from on-site or off-site testing (full-, 
pilot-, or laboratory-scale).
     On-site or off-site testing (full-, pilot-, or laboratory-
scale) and/or implementation of treatment technologies associated with 
surface impoundment dewatering treatment.
     Costs associated with these technologies.
    In addition, after meeting with four additional power companies, 
the EPA sent each company a voluntary request inviting them to provide 
the same data described above.
    In July 2023, the EPA requested any full-, pilot-, or laboratory-
scale data associated with on-site or off-site testing or 
implementation of a recently commissioned spray dryer evaporator for 
FGD wastewater and legacy wastewater at a coal-fired power plant from 
Minnesota Power. The EPA also requested information on pretreatment or 
disposal systems necessary for continued spray dryer evaporator 
operations and any corresponding documentation (e.g., wastestreams 
generated, process flow diagram).
2. Meetings With Individual Utilities
    To gather information to support this supplemental rule, the EPA 
met with representatives from four utilities. Two of these utilities 
reached out to the EPA after the announcement of the supplemental 
rulemaking. The EPA contacted the remaining utilities due to their 
known or potential consideration of membrane filtration. At these 
meetings, the EPA discussed the operation of the utility's coal-fired 
EGUs and the treatment and management of BA transport water, FGD 
wastewater, legacy wastewater, and CRL since the 2020 rule. The EPA 
learned about updates associated with plant operations and studies at 
these plants, which were originally discussed during the 2015 and 2020 
rules.
    The objectives of these meetings were to gather general information 
about coal-fired power plant operations; pollution prevention and 
wastewater treatment system operations; ongoing pilot or laboratory 
scale study information for FGD wastewater treatment; BA system 
performance, characterization, and quantification of the overflow and 
purge from remote MDS installations; and treatment technologies and 
pilot testing associated with CRL and legacy wastewater. The EPA used 
this information to supplement the data collected in support of the 
2015 and 2020 rules.
3. Voluntary CRL Sampling
    In December 2021, the EPA invited eight steam electric power 
companies to participate in a voluntary program designed to obtain data 
to supplement the wastewater characterization data set for CRL. The EPA 
requested these data from facilities believed to have constructed new 
landfills pursuant to the 2015 CCR rule. Six power companies chose to 
participate in this program. The EPA incorporated these data into the 
CRL analytical dataset used to estimate pollutant loadings. More 
information on estimated CRL pollutant loadings is available in section 
6 of the Supplemental TDD.
4. Electric Power Research Institute Voluntary Submission
    The Electric Power Research Institute (EPRI) conducts industry-
funded studies to evaluate and demonstrate technologies that can 
potentially remove pollutants from wastestreams or eliminate 
wastestreams using zero-discharge technologies. Following the 2015 
rule, the EPA reviewed 35 EPRI reports published between 2011 and 2018 
that were voluntarily provided regarding characteristics of FGD 
wastewater, FGD wastewater treatment pilot studies, BA transport water 
characterization, BA handling practices, halogen addition rates, and 
the effect of halogen additives on FGD wastewater. For this 
supplemental rule, EPRI provided an additional 25 reports generated 
since 2018. The EPA used the information in these reports to inform 
treatment technology performance and to update methodologies for 
estimating costs and pollutant removals associated with candidate 
treatment technologies.
5. Meetings With Trade Associations
    In 2021 and 2022, the EPA met with the Edison Electric Institute 
and the American Public Power Association. These trade associations 
represent investor-owned utilities and community-owned utilities, 
respectively. They provided information and perspectives on the status 
of many utilities transitioning away from coal. The EPA also 
participated in meetings with one trade association following the 2023 
proposed rule. This association requested meetings with the EPA to 
discuss the association's public comments.

B. Notices of Planned Participation

    The 2020 rule required facilities to file a Notice of Planned 
Participation (NOPP) with their permitting authority no later than 
October 13, 2021, if the facility wished to participate in the LUEGU 
subcategory, the permanent cessation of coal combustion by 2028 
subcategory, or in the VIP. For the permanent cessation of coal 
combustion by 2028 subcategory, this filing date was extended by a 2023 
direct final rule to June 27, 2023. 88 FR 18440. While the facilities 
were not required to provide copies of the NOPPs to the Agency, the EPA 
nevertheless obtained a number of these filings. Some facilities 
provided the EPA a courtesy copy when filing with the relevant 
permitting authority. The Agency received notice of other filings when 
a state permitting authority sent new draft permits or modifications to 
the EPA for review. The EPA also asked some states for NOPPs after 
those states asked the EPA questions about the process or initiated 
discussions about specific plants. Environmental groups that collected 
some additional information about NOPPs also shared the information 
with EPA prior to the publication of the proposed rule.
    The EPA is currently aware of NOPPs covering 94 EGUs at 38 plants. 
At the time of the proposed rule, four EGUs (at two plants) requested 
participation in the LUEGU subcategory, an additional 12 EGUs (at four 
plants) requested participation in the 2020 rule VIP, and the remaining 
74 EGUs (at 33 plants) requested participation in the permanent 
cessation of coal combustion by 2028 subcategory.\24\ Following the 
2023 direct final rule, the EPA obtained one additional NOPP stating 
that two EGUs (at one plant) requested participation in the permanent 
cessation

[[Page 40212]]

of coal combustion subcategory by 2028 instead of the 2020 rule VIP. 
The EPA notes that these counts are not a comprehensive picture of 
facilities' plans for two reasons. First, the EPA was unable to obtain 
information for all plants and states. Second, even where a facility 
has filed a NOPP, under the transfer provisions of 40 CFR 
423.13(o)(1)(ii), it still retains flexibility to transfer between 
subcategories, or between a subcategory and the 2020 VIP provisions, 
until December 31, 2025.\25\ For example, the EPA made industry profile 
updates to some of the 90 EGUs with corresponding NOPPs based on public 
comments and other power company data (e.g., integrated resource 
planning reports). For further detail, the NOPPs the EPA is aware of 
have been placed in the docket along with a memorandum summarizing the 
information and providing record index numbers for locating each 
facility, entitled Changes to Industry Profile for Coal-Fired 
Generating Units for the Steam Electric Effluent Guidelines Final Rule 
(DCN SE11618).
---------------------------------------------------------------------------

    \24\ Plant Scherer filed a permanent cessation of coal 
combustion by 2028 NOPP for two EGUs and a 2020 rule VIP NOPP for 
the remaining two EGUs; thus, the plant count for the three 
groupings does not equal 38.
    \25\ The ability to transfer into the LUEGU subcategory ended on 
December 31, 2023.
---------------------------------------------------------------------------

C. Information from Technology Vendors and Engineering, Procurement, 
and Construction Firms

    The EPA gathered data on the availability and effectiveness of FGD 
wastewater, BA handling, CRL, and surface impoundment dewatering 
operations and wastewater treatment technologies from technology 
vendors and engineering, procurement, and construction firms through 
presentations, conferences, meetings, and email and phone contacts. 
These collected data informed the development of the technology costs 
and pollutant removal estimates for FGD wastewater, BA transport water, 
CRL, and legacy wastewater.

D. Other Data Sources

    The EPA gathered information on steam electric generating 
facilities from the DOE's Energy Information Administration (EIA) Forms 
EIA-860 (Annual Electric Generator Report) and EIA-923 (Power Plant 
Operations Report). The EPA used the 2019, 2020, and 2021 data to 
update the industry profile, including commissioning dates, energy 
sources, capacity, net generation, operating statuses, planned 
retirement dates, ownership, and pollution controls at the EGUs. The 
EPA also referenced 2022 EIA data to support the analysis of FGD 
halogen (bromide and iodine) loads. Finally, the EPA used a 2024 EIA 
study as the basis for estimating the costs of a new coal-fired steam 
power plant.\26\
---------------------------------------------------------------------------

    \26\ U.S. Energy Information Administration (2024). Capital Cost 
and Performance Characteristics for Utility-Scale Electric Power 
Generating Technologies, available at: https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capital_cost_AEO2025.pdf.
---------------------------------------------------------------------------

    The EPA conducted literature and internet searches to gather 
information on FGD wastewater treatment technologies, including 
information on pilot studies, applications in the steam electric power 
generating industry, and implementation costs and timelines. The EPA 
also used internet searches to identify or confirm reports of planned 
facility plant and EGU retirements and reports of planned unit 
conversions to dry or closed-loop recycle ash handling systems. The EPA 
used this information to inform the industry profile and identify 
process modifications occurring in the industry.

VII. Final Regulation

A. Description of the Options

    The EPA analyzed four main regulatory options at proposal, the 
details of which were discussed in the proposed rule. See 88 FR 18824, 
18837-18838 (Mar. 29, 2023). For the final rule, the EPA evaluated 
three main regulatory options, as shown in table VII-1 of this 
preamble. Option A corresponds to the proposed regulation with 
modifications, while Options B and C would require controls that would 
achieve greater pollutant reductions. All three options include the 
same technology basis for FGD wastewater (zero-discharge systems) and 
BA transport water (dry-handling or closed-loop systems), while 
incrementally increasing controls on CRL and legacy wastewater and 
removing certain subcategories as one moves from Option A to Option C. 
Each successive option from Option A to Option C would achieve a 
greater reduction in wastewater pollutant discharges. Each 
subcategorization is described further in section VII.C of this 
preamble.
1. FGD Wastewater
    Under all three main options, the EPA would require zero discharge 
of FGD wastewater based on zero-discharge technologies and retain the 
2020 FGD wastewater limitations and standards as an interim step toward 
achievement of zero-discharge requirements. Under all three options, 
the EPA would also eliminate the BAT and PSES subcategorizations for 
high-FGD-flow facilities and LUEGUs. Options A and B would also create 
a subcategory for EGUs that will permanently cease coal combustion no 
later than December 31, 2034, and instead of zero discharge would 
require discharges from these facilities to meet the 2020 rule 
limitations as included in their CWA permit. This subcategory modifies 
the proposed early adopters subcategory and is described further in 
section VII.C of this preamble. Under Option C, the EPA would not 
finalize a subcategory for those EGUs planning to cease coal combustion 
by December 31, 2034. Note that, for all three options, the EPA would 
retain the 2020 subcategory for EGUs permanently ceasing coal 
combustion by 2028.
2. BA Transport Water
    Under all three main options, the EPA would require zero discharge 
of BA transport water based on dry-handling or closed-loop systems and 
retain the 2020 BA transport water limitations and standards as an 
interim step toward achievement of zero-discharge requirements. For all 
three options, the EPA would also eliminate the BAT and PSES 
subcategorizations for LUEGUs. Options A and B would also create a 
subcategory for EGUs that will permanently cease coal combustion no 
later than December 31, 2034, and instead would require discharges from 
these facilities to meet the 2020 rule limitations as permitted. Under 
Option C, the EPA would not finalize this subcategory. Note that, for 
all three options, the EPA would retain the 2020 subcategory for EGUs 
permanently ceasing coal combustion by 2028.
3. CRL
    Under Option A, the EPA would establish BAT limitations and PSES 
for mercury and arsenic based on chemical precipitation treatment. 
Under Options B and C, BAT limitations and PSES would be zero discharge 
and the EPA would establish BAT limitations for mercury and arsenic 
based on chemical precipitation for discharges of unmanaged CRL. 
Options A and B would also create a subcategory for EGUs that would 
permanently cease coal combustion no later than December 31, 2034; CRL 
discharges from EGUs in this subcategory would be subject to case-by-
case BPJ decision-making until permanent cessation of coal combustion, 
after which they would be subject to mercury and arsenic limitations 
based on chemical precipitation. Under Option C, the EPA would not 
finalize this subcategory.
4. Legacy Wastewater
    Under Option A, the EPA would not specify a nationwide technology 
basis for BAT/PSES applicable to legacy

[[Page 40213]]

wastewater at this time and such limitations would be derived on a 
site-specific basis by the permitting authorities, using their BPJ. 
Under Options B and C, the EPA would establish a subcategory for 
discharges of legacy wastewater discharged from surface impoundments 
commencing closure after July 8, 2024. For such discharges, the EPA 
would establish mercury and arsenic limitations based on chemical 
precipitation.

[[Page 40214]]

[GRAPHIC] [TIFF OMITTED] TR09MY24.039


[[Page 40215]]


[GRAPHIC] [TIFF OMITTED] TR09MY24.040

B. Rationale for the Final Rule

    After considering the technologies described in this preamble and 
the TDD, as well as public comments, and in light of the factors 
specified in CWA sections 301(b)(2)(A) and 304(b)(2)(B) (see section IV 
of this preamble), the EPA is establishing BAT effluent limitations 
based on the technologies described in Option B.\27\ While the EPA is 
establishing new BAT effluent limitations for FGD wastewater and BA 
transport water based on more stringent technologies than the 2020 
rule, the EPA is retaining the 2020 rule BAT effluent limitations for 
discharges before the applicability dates for new limitations on these 
wastewaters.
---------------------------------------------------------------------------

    \27\ The EPA is including severability language in the final 
rule that makes clear that if any provisions of the final rule are 
reviewed and vacated by a court, it is the EPA's intent that as many 
portions of the rule remain in effect as possible.
---------------------------------------------------------------------------

1. FGD Wastewater
    The EPA is identifying zero-discharge systems as the technology 
basis for establishing BAT limitations to control pollutants discharged 
in FGD wastewater.\28\ More specifically, the technology basis for BAT 
is membrane filtration systems, SDEs, and thermal evaporation systems, 
alone or in any combination, including any necessary pretreatment 
(e.g., chemical precipitation) or post-treatment (e.g., 
crystallization).\29\ Furthermore, where a permeate or distillate is 
generated from the final stage of treatment, the BAT technology basis 
uses a process wherein this water would then be recycled back into the 
plant as either FGD makeup water or EGU makeup water.\30\ After 
considering the factors specified in CWA section 304(b)(2)(B), the 
record shows that this suite of technologies is technologically 
available, is economically achievable, and has acceptable non-water 
quality environmental impacts. It is the EPA's intent that these three 
technologies considered together constitute BAT for FGD wastewater, and 
the EPA concludes that this BAT basis meets the requisite statutory 
factors. The EPA also finds, however, that each of the individual 
technologies within this suite supports a BAT determination on its own.
---------------------------------------------------------------------------

    \28\ As described in section VII.B.5 of this preamble, the EPA 
is also finalizing a definitional change to certain wastewaters, 
including FGD wastewater, that excludes discharges necessary as a 
result of high intensity, infrequent storm events, as well as 
wastewater removed from FGD wastewater treatment equipment within 
the first 120 days of decommissioning the equipment.
    \29\ While three main technologies are listed here and are used 
to evaluate costs and non-water quality environmental impacts, the 
list is not meant to exclude use of other known zero-discharge 
treatment processes, including FA fixation, direct encapsulation, or 
evaporation ponds.
    \30\ The 2020 rule finalized a carve out from the definition of 
FGD wastewater applicable to ``treated FGD wastewater permeate or 
distillate used as boiler makeup water.''
---------------------------------------------------------------------------

    In the following subsections, the EPA discusses its rationale for 
selecting three zero-discharge systems as BAT for the control of FGD 
wastewater, as well as how each individual zero-discharge technology 
supports the BAT technology basis on its own. The EPA also explains why 
it is not selecting a less stringent technology as BAT. For further 
discussion of the changes (now being finalized by the EPA) to the 
definition of FGD wastewater related to infrequent storm events and 
decommissioning wastewater, see section VII.B.5 of this preamble. For 
further discussion of the EPA's retention of the 2020 rule limitations 
as interim limitations, see section VII.C.7 of this preamble.
    a. The EPA selects zero-discharge systems as BAT for FGD 
wastewater.
    Technological availability of zero-discharge systems. At proposal, 
the EPA identified membrane filtration as a potential BAT on which to 
base zero-discharge limitations for FGD wastewater, but also solicited 
comment on several other zero-discharge technologies, such as thermal 
evaporation systems and SDEs, that the EPA thought might serve alone or 
in any combination as the BAT basis for a final rule.
    The EPA received many comments that were specific to individual 
zero-discharge technologies, including both comments supporting and 
opposed to a finding of technological availability for these individual 
technologies as part of the BAT basis. Comments supporting zero-
discharge limitations pointed to the large number of operating zero-
discharge plants and pilot studies as evidence that more than just the 
best performing plant or pilot plants are using zero-discharge systems. 
Comments opposing such a finding primarily focused on membrane 
filtration, the EPA's proposed zero-discharge technology basis under 
the preferred regulatory option. The two concerns raised most commonly 
in opposition to the finding of membrane filtration availability were, 
first, that the EPA did not collect sufficient additional information 
to alter its findings in the 2020 rule regarding this technology's 
availability and, second, that the pilot studies and foreign plants 
cited by the EPA were conducted on small FGD wastewater flows that were 
not representative of domestic industry operations. For both membrane 
filtration systems and thermal evaporation systems, commenters who 
opposed a finding of availability also questioned whether back-end 
management options were available for the associated wastes from zero-
discharge systems. To the extent it received comments suggesting that 
waste management alternatives are not available, the EPA has addressed 
these comments in the subsection discussing non-water quality 
environmental impacts, below.
    After consideration of public comments and as further discussed 
below, the EPA is basing its determination that zero-discharge systems 
are available for control of pollutants found in FGD wastewater on the 
numerous full-scale domestic and foreign installations of zero-
discharge systems to treat FGD wastewater, the large number of 
successful domestic and international pilot tests of zero-discharge 
systems on FGD wastewater, successful use of zero-discharge systems on 
other steam electric wastestreams, and the use of zero-discharge 
systems on wastestreams in many different industries besides the steam 
electric power generating industry. Alternatively, the EPA is basing 
its determination that each of the technologies that make up the suite 
of zero-discharge systems forming the BAT basis, standing alone, is 
available on the several full-scale domestic and/or

[[Page 40216]]

foreign installations of each of these technologies to treat FGD 
wastewater and/or the successful domestic and international pilot tests 
of each of these technologies on FGD wastewater. The availability of 
each technology standing alone is also supported by the successful use 
of each of these technologies on other steam electric wastestreams and/
or the use of each of these technologies on wastestreams in different 
industries besides the steam electric power generating industry. The 
weight of the evidence supports the Agency's conclusion that the suite 
of zero-discharge systems (or each of the individual technologies 
alone) are available in the industry to control FGD wastewater 
discharges, notwithstanding certain uncertainties the EPA described in 
the 2020 rule about one of the technologies that form the zero-
discharge BAT technology basis. Agencies have inherent authority to 
reconsider past decisions and to revise, replace, or repeal a decision 
to the extent permitted by law and supported by a reasoned explanation. 
FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009); Motor 
Vehicle Mfrs. Ass'n v. State Farm Mutual Auto. Ins. Co., 463 U.S. 29, 
42 (1983). A finding that zero-discharge systems are available, or that 
each of the zero-discharge technologies forming the BAT basis is 
available, is also consistent with the technology-forcing nature of BAT 
as described in the legislative history and legal precedents discussing 
this provision (see section IV.B.2 of this preamble).
    Full-scale domestic zero-discharge systems. In the 2020 rule, the 
EPA rejected membrane filtration as a standalone BAT technology basis 
due in part to the lack of a single full-scale domestic installation, 
which is still the case today. In that rule, however, the EPA did not 
evaluate a technology basis that includes the three zero-discharge 
technologies that form this final rule's BAT basis.
    First, the EPA notes that 40 coal-fired power plants in the United 
States currently (as of 2024) operate wet FGD systems and manage their 
wastewater to achieve zero discharge.\31\ These plants achieve zero 
discharge using evaporation ponds, recycling of FGD wastewater, ash 
fixation, thermal evaporation systems (e.g., falling film evaporators), 
or SDEs. About 19 additional plants operated zero-discharge systems for 
FGD wastewater since 2009 but have since retired or converted fuels 
such that the FGD wastewater generation, and associated zero-discharge 
operations, have ceased. In total, more domestic facilities operate, or 
have operated, zero-discharge systems than the biological treatment 
systems used as the 2015 and 2020 rule bases.\32\ Not only are there 
more of these systems, but the systems for which the EPA has 
information have achieved continuous, long-term zero discharge.
---------------------------------------------------------------------------

    \31\ One of these 40 plants, which was already achieving zero 
discharge of its FGD wastewater, is now installing SDE. See https://www.woodplc.com/insights/articles/engineering-solutions-for-wastewater-treatment (DCN SE10284).
    \32\ The EPA accounted for four plants operating biological 
treatment systems in the 2015 rule analyses (DCN SE05832) and nine 
plants in the 2020 rule analyses (DCN SE08629).
---------------------------------------------------------------------------

    With respect specifically to the BAT basis identified in this final 
rule, the EPA finds that there are four U.S. coal-fired power plants 
currently operating full-scale thermal and three U.S. coal-fired power 
plants currently operating full-scale SDE systems.\33\ The full-scale 
domestic application of the technologies identified in the BAT basis 
for this final rule support the EPA's finding that the BAT technology 
basis is available, as that term is used in the CWA. It also supports a 
finding that thermal evaporation systems are technologically available 
on their own and that SDEs are technologically available on their own.
---------------------------------------------------------------------------

    \33\ In the 2020 rule and 2023 proposal, the EPA has continually 
deferred to one company's representations that, contrary to 
representations from the technology vendor, its membrane filtration 
system is a long-term pilot system rather than a full-scale 
installation. This is a distinction without a difference, as the EPA 
can rely on both full-scale installations and pilot plants in 
establishing BAT limitations. Therefore, the EPA addresses this 
system in the section on pilot systems below (even though it could 
arguably be used to treat the facility's entire wastestream in the 
future).
---------------------------------------------------------------------------

    Full-scale, foreign zero-discharge systems and zero-discharge pilot 
plants. While the full-scale, domestic operation of zero-discharge 
systems is sufficient to determine availability of the BAT technology 
basis, the EPA has also identified a number of full-scale, foreign 
zero-discharge systems, as well as domestic and international pilot 
systems; these could additionally or separately support the EPA's 
conclusion that the BAT basis identified in this final rule is 
available.
    In 2020, the EPA declined to find that full-scale, foreign 
installations of membrane filtration demonstrated the availability of 
that technology, in large part because the EPA had not visited these 
systems or obtained long-term performance data on them, and thus stated 
there were uncertainties around these applications that prevented a 
finding of availability. At the time of the 2020 rule, the Agency cited 
12 foreign installations of membrane filtration systems on FGD 
wastewater.\34\ These systems began operating as early as 2015, and all 
of them were designed to operate as zero-discharge systems.\35\ 
Importantly, however, the EPA did not dispute the availability of 
thermal evaporation systems in the 2020 rule. This is consistent with 
the record, as even at the time of the 2015 rule, the EPA visited three 
thermal evaporation systems operating in Italy, obtaining relevant 
performance data on these systems, which it then used to establish BAT 
limitations for a voluntary incentive program based on such technology, 
as well as NSPS for FGD wastewater.\36\
---------------------------------------------------------------------------

    \34\ ERG. 2020. Technologies for the Treatment of Flue Gas 
Desulfurization Wastewater (DCN SE09218); ERG. 2020. Notes from Call 
with DuPont (DCN SE08618); Beijing Jingneng Power. 2017. Beijing 
Jingneng Power Company, Ltd. Announcement on Unit No. 1 of the Hbei 
Shuoshou Jingyuan Thermal Power Co., Ltd. Passing Through the 168-
hours Trial Operation. November 13 (DCN SE08624); Broglio, R. 2019. 
Vendor FGD Wastewater Treatment Details--Doosan. July 15 (DCN 
SE07107); Lenntech. 2020. Lenntech Water Treatment Solutions. Flue 
Gas Desulfurization Treatment (DCN SE08622); Nanostone. 2019. China 
Huadian Jiangsu Power Jurong Power Plant FGD Wastewater Zero Liquid 
Discharge Project was Awarded the Engineering Star Award. June 27 
(DCN SE08623).
    \35\ Technologies for the Treatment of Flue Gas Desulfurization 
Wastewater, Coal Combustion Residual Leachate, and Pond Dewatering 
(DCN SE11695).
    \36\ This information was also used as the basis for the 2015 
rule NSPS for FGD wastewater.
---------------------------------------------------------------------------

    Some commenters on the 2023 proposal reiterated the EPA's 2020 rule 
findings and argued that EPA has not collected sufficient new 
information on foreign installations of membrane filtration to reverse 
its 2020 findings. EPA first notes that, for this final rule, it has 
modified its BAT basis from proposal to consist of three zero-discharge 
systems (each of which was described in the proposal). Since the 2015 
rule, EPA has collected information not just about membrane filtration 
systems abroad, but also about an additional four thermal evaporation 
systems and six SDE systems operating on FGD wastewater outside the 
United States.\37\ The EPA finds that, when combined with the site 
visits and performance data EPA obtained on the three Italian thermal 
evaporation systems as part of the 2015 rulemaking, the current record 
is more than sufficient to determine, based on full-scale, foreign 
installations, that the suite of systems forming the BAT basis in this 
rule is available as that term is used in the CWA.
---------------------------------------------------------------------------

    \37\ Technologies for the Treatment of Flue Gas Desulfurization 
Wastewater, Coal Combustion Residual Leachate, and Pond Dewatering 
(DCN SE11695).

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[[Page 40217]]

    Furthermore, even looking at membrane filtration itself, as the EPA 
noted in the 2023 proposal, the foreign membrane filtration systems 
discussed in the 2020 rule have continued to successfully treat FGD 
wastewater and achieve zero discharge since 2020. Despite commenters 
arguing that this additional information is not important because it 
does not change the overall number of plants known to operate the 
technology or the number of influent and effluent concentration data 
points collected from these plants, the EPA finds that continued 
operations constitute significant new information. This is because the 
longer each zero-discharge system operates, the less probability that 
some yet unknown operational difficulty will appear and the more 
certainty the EPA has that the technology is capable of achieving long-
term zero-discharge treatment of this wastewater. Thus, foreign 
installations of the suite of technologies forming the BAT basis 
support the EPA's conclusion that the BAT basis is available as that 
term is used in the CWA. At the same time, use of thermal evaporation 
systems abroad supports a finding that thermal evaporation systems are 
technologically available on their own, use of SDEs abroad supports a 
finding that SDEs are technologically available on their own, and use 
of membrane filtration systems abroad support a finding that membrane 
filtration is technologically available on its own.
    With respect to pilot studies, the 2020 rule found that pilot 
projects on membrane filtration did not provide sufficient long-term 
concentration data on which to base a finding of availability or 
calculate limitations.\38\ Commenters on the 2023 proposal reiterated 
the EPA's 2020 rule findings and suggested that the EPA had not 
supplemented the record with enough pilot studies to reach a new 
conclusion on availability. The EPA disagrees. The Agency first notes 
that the BAT technology basis in this final rule has been updated to 
consist of three zero-discharge systems. When the 13 thermal pilot 
projects and one SDE pilot project on FGD wastewater in the record are 
combined with the 30 membrane filtration pilots on FGD wastewater 
discussed in the proposed rule (including eight pilot studies conducted 
since the 2020 rule), the EPA has significant evidence of the ability 
of this suite of systems to handle a variety of operating 
conditions.\39\ These domestic and foreign pilots have demonstrated 
success removing pollutants from FGD wastewater under a number of 
pretreatment settings, whether performed without chemical precipitation 
pretreatment, with chemical precipitation pretreatment, or following 
biological treatment.\40\ Furthermore, while some systems will not 
generate a clean permeate or distillate that needs to be handled, those 
that do will recycle this clean water source back into the plant to 
meet the final zero-discharge limitations. Thus, long-term pollutant 
removal information is no longer as relevant as it was in 2020 because 
the EPA is not calculating nonzero limitations in this final rule. 
While this discussion of pilot projects is used to support the 
availability of the BAT technology basis comprised of multiple 
technologies, the large number of successful pilot projects of membrane 
filtration and thermal evaporation systems also supports the EPA's 
finding that these individual technologies are available on their own.
---------------------------------------------------------------------------

    \38\ The EPA nevertheless established limitations based on 
membrane filtration technology in the 2020 VIP.
    \39\ One of the systems is a long-term pilot project at one 
facility, which is a commercial-scale system that may have 
sufficient capacity to treat the full FGD wastestream moving 
forward. Nevertheless, because the company is still making changes 
to the operation of the plant's FGD system, has also pilot tested a 
biological treatment system, and has continued to leave the 
possibility of biological treatment for compliance open, the EPA 
defers to the company's characterization of this system as a pilot, 
rather than a domestic, full-scale installation.
    \40\ In one case, a utility conducted a successful membrane 
pilot even when there were significant failures in the performance 
of upstream pretreatment systems leading to excessive TSS 
passthrough to the membrane system.
---------------------------------------------------------------------------

    In comments, one recurring criticism of the 2023 proposal was that 
conclusions about membrane filtration system availability should not be 
drawn from foreign installations and pilot plants due to their small 
FGD wastewater flow rates. While the EPA acknowledges that foreign 
installations and pilot plants may have had smaller FGD wastewater flow 
rates than some of the plants the Agency expects would use this 
technology to meet the final limitations in this rule, this does not 
weigh against the EPA considering them as evidence of the technology's 
availability because the record shows that membrane filtration systems 
can be readily modified to handle different flow rates. This same 
comment was raised as far back as the 2015 rule with respect to thermal 
evaporation systems. At that time, the EPA responded to comments on the 
scalability of zero-discharge thermal evaporation systems:

    Additionally, even if the flow rates were smaller, the fact that 
the technology can treat the FGD wastewater demonstrates that the 
system is available, and the size of the system does not matter 
because the system design can be scaled and designed to accommodate 
different flow rates.\41\
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    \41\ U.S. EPA (Environmental Protection Agency). 2015. Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category: EPA's Response to Public Comments. 
Part 6 of 10. Page 6-40.

    The EPA has not received information since 2015 that suggests that 
technologies are no longer scalable to higher flows. With respect to 
membrane filtration scalability, in particular, the most common system 
design for operating membrane filtration technologies is to place 
modules of these systems in parallel and simply add more and more 
stacks to treat higher and higher flows. Therefore, the EPA concludes 
that use of zero-discharge systems in smaller flow rate pilots and 
full-scale foreign facilities supports the finding that the BAT 
technology basis is available; these uses also support the EPA's 
finding that each of the individual technologies forming the BAT 
technology basis are available on their own.\42\
---------------------------------------------------------------------------

    \42\ It is also possible that some plants may choose to treat 
only a slipstream of FGD wastewater with a similarly small flow rate 
to keep the system closed loop.
---------------------------------------------------------------------------

    Application to other wastestreams. While the record above is 
sufficient to determine that the BAT basis of several zero-discharge 
systems is available, use of the BAT basis on other wastewaters also 
supports the EPA's finding regarding its availability. In the 2020 
rule, the EPA declined to find that membrane filtration treatment of 
non-FGD wastewaters was sufficient to support a finding of 
availability. In that rule, EPA's conclusions were based on the ways in 
which each non-FGD wastewater appeared different from FGD wastewater. 
The EPA first notes that the BAT basis includes three zero-discharge 
systems, not just membrane filtration. When considering the success 
with which this suite of zero-discharge systems has operated on non-FGD 
wastewater that has similar characteristics to FGD wastewater, the EPA 
views application of these systems to such non-FGD wastewater as 
supporting EPA's conclusion that the suite of zero-discharge 
technologies identified as BAT in this rule is in fact available.
    Examining all three zero-discharge systems that constitute the 
basis for BAT, these systems are used in full-scale applications to 
other wastestreams in the steam electric power sector and other 
industrial sectors. The domestic steam electric power sector applies

[[Page 40218]]

membrane filtration and thermal evaporation systems to EGU makeup 
water,\43\ cooling tower blowdown,\44\ and ash transport water.\45\ 
Other industrial sectors with full-scale applications of membrane 
filtration, thermal evaporation, and SDE systems include the 
textiles,\46\ chemical manufacturing,\47\ mining,\48\ agriculture, \49\ 
oil and gas extraction,\50\ food and beverage,\51\ landfills,\52\ and 
automotive industries.\53\
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    \43\ EPRI (Electric Power Research Institute). 2015. State of 
Knowledge: Power Plant Wastewater Treatment--Membrane Technologies. 
August. 3002002143.
    \44\ See, e.g., Drake, M., Wise, S., Charan, N., Venkatadri, R. 
2012. ZLD Treatment of Cooling Tower Blowdown with Membranes. 
WaterWorld. December 1. Available online at: https://www.watertechonline.com/process-water/article/16211541/zld-treatment-of-cooling-tower-blowdown-with-membranes (DCN SE09089); 
ERG. 2019. Final Notes from Meeting with New Logic Research. July 
22. (DCN SE07231) ERG. 2019. Final Aquatech Meeting Notes. July 26 
(DCN SE07389).
    \45\ See, e.g., https://www.ge.com/in/sites/www.ge.com.in/files/GE_solves_ash%20pond_capacity_issue.pdf (DCN SE09090).
    \46\ ERG. 2020. Final Notes from Call with DuPont (DCN SE08618).
    \47\ ERG. 2020. Final Notes from Call with DuPont (DCN SE08618); 
U.S. EPA (Environmental Protection Agency). 2022. Notes from Vendor 
Call with Vacom on October 27, 2021. November 14 (DCN SE10367).
    \48\ ERG. 2019. Final Notes from Meeting with Pall Water. March 
5. EPA-HQ-OW-2009-0819-7613; Wolkersdorfer, C., et al. 2015. 
Intelligent mine water treatment--recent international developments. 
July 21 (DCN SE08581); U.S. EPA (Environmental Protection Agency). 
2014. Office of Superfund and Remediation and Technology Innovation. 
Reference Guide to Treatment Technologies for Mining-Influenced 
Water. EPA 542-R-14-001. March (DCN SE08582); ERG. 2019. Final 
Aquatech Meeting Notes. July 26 (DCN SE07389); U.S. EPA 
(Environmental Protection Agency). 2022. Notes from Vendor Call with 
Vacom on October 27, 2021. November 14. (DCN SE10367).
    \49\ U.S. EPA (Environmental Protection Agency). 2022. Notes 
from Meeting with BKT--April 9, 2021 (DCN SE10253).
    \50\ ERG. 2018. Final Oasys Meeting Notes. February 16 (DCN 
SE06915); ERG. 2019. Final Aquatech Meeting Notes. July 26 (DCN 
SE07389); ERG. 2019. Final Veolia Meeting Notes. August 30 (DCN 
SE07818); U.S. EPA (Environmental Protection Agency). 2022. Notes 
from Vendor Call with Purestream on October 26, 2021. November 14 
(DCN SE10366); U.S. EPA (Environmental Protection Agency). 2022. 
Notes from Vendor Call with Vacom on October 27, 2021. November 14 
(DCN SE10367).
    \51\ U.S. EPA (Environmental Protection Agency). 2022. Notes 
from Meeting with BKT--April 9, 2021 (DCN SE10253).
    \52\ ERG. 2019. Sanitized_Saltworks Vendor Meeting Notes--Final 
(DCN SE07089); U.S. EPA (Environmental Protection Agency). 2022. 
Notes from Vendor Call with Heartland on October 19, 2021. September 
26 (DCN SE10291).
    \53\ U.S. EPA (Environmental Protection Agency). 2022. Notes 
from Meeting with ProChem--April 9, 2021 (DCN SE10254).
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    Information in the record indicates that there are many 
similarities between the FGD and the non-FGD wastestreams where zero-
discharge systems have been used. In the 2020 rule record, the EPA 
discussed that cooling tower blowdown at steam electric power plants 
and desalination in oil and gas extraction were examples of where 
membrane filtration has been used in full-scale applications for 
treating high-TDS wastewaters (high-TDS being a characteristic of FGD 
wastewater); 85 FR 64664-64665. The 2020 rule record also established 
that mining wastewaters, which are high in gypsum scaling potential 
(another characteristic of FGD wastewater), have been successfully 
treated with membrane filtration applications. Finally, the 2020 rule 
record established that, despite the high variability in ash transport 
water (a third characteristic of FGD wastewater), it has been 
successfully treated with membrane filtration. This information 
indicates that membrane filtration can operate effectively on 
wastestreams that contain several characteristics of FGD wastewater, 
including high TDS, high gypsum scaling potential, and high 
variability.\54\ The similarities of other wastewaters to FGD 
wastewater are also relevant when considering the successful treatment 
by thermal evaporation systems. Thermal evaporation systems have been 
used to treat mining wastewaters, oil and gas wastewaters, and landfill 
leachate. SDE systems have been used to treat landfill leachate. Thus, 
based on the information, the use of zero-discharge systems on other 
wastestreams supports the Agency's conclusion that the BAT basis of 
zero-discharge systems is available for FGD wastewater discharges. 
These uses also support the Agency's conclusion that membrane 
filtration, thermal evaporation systems, or SDE systems are each 
available on their own.
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    \54\ Use of membrane filtration has since expanded into 
additional applications, treating wastewaters and industries beyond 
those where it was used at the time of the 2020 rule (e.g., the food 
and beverage and automotive industries).
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    For all the foregoing reasons, the EPA finds that the BAT basis of 
zero-discharge systems is technologically available for the control of 
discharges in FGD wastewater. Steam electric power plants have used 
membrane filtration systems to achieve zero discharge of FGD wastewater 
internationally for years, and they have used traditional thermal 
evaporation systems \55\ and SDEs \56\ to achieve zero discharge of FGD 
wastewater domestically and internationally for years, as even recent 
electric utility reports acknowledge.57 58 59 60 The 
widespread use across a variety of configurations of zero-discharge 
systems, when supplemented with the successful domestic and 
international pilot tests and use of such systems on other wastewaters 
in many industries (including the steam electric power generating 
industry itself and including wastewaters with characteristics that are 
similar to the FGD wastestream), further supports EPA's conclusion that 
the suite of zero-discharge technologies identified as the BAT basis in 
this rule is available. While this is not necessary to support its 
prior availability determination, the EPA further finds that any one of 
the technologies making up the BAT basis for FGD wastewater is 
available as that term is used in the Act. For membrane filtration, 
availability is demonstrated through full-scale use of membrane 
filtration abroad and in pilot projects both domestically and abroad, 
as well as its application to other wastestreams. For thermal 
evaporation, availability is demonstrated through use of full-scale 
thermal evaporation systems domestically and abroad and pilot projects 
both domestic and abroad, as well as their application to other 
wastestreams. For SDE systems, availability is demonstrated through use 
of full-scale SDE systems domestically and abroad, as well as their use 
in at least one known pilot project and application to a non-FGD 
wastestream.
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    \55\ The Italian thermal evaporation systems discussed first in 
the 2013 proposed rule have been in operation for over a decade.
    \56\ Spray dry absorbers, effectively the same technology as the 
SDE, have been in use for decades to capture the same pollutants 
present in FGD wastewater.
    \57\ ``Proven technology (considered BAT for new sources by 
EPA). 3+ U.S. installations and 6+ European installations by 
Aquatech'' (DCN SE07206).
    \58\ DCN SE10234.
    \59\ DCN SE09998.
    \60\ EPRI (Electric Power Research Institute). 2017. Thermal 
Evaporation Technologies for Treating Power Plant Wastewater: A 
Review of Six Technologies. 000000003002011665 (DCN SE06971).
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    Reliance interests in connection with 2020 BAT technologies. 
Several commenters on the 2023 proposal criticized EPA for continuing 
to support implementation of the 2020 rule while simultaneously 
revising that rule with potentially more stringent limitations. These 
commenters stated that utilities relied upon materials announcing the 
Agency's decision to reconsider the 2020 rule and statements in the 
2023 proposal which both confirmed that utilities should continue to 
implement the 2020 rule. Thus, in reliance, utilities claimed that they 
have continued to install compliant technologies and that such reliance 
should lead the EPA to a decision not to finalize more stringent BAT 
for these wastewaters. In the

[[Page 40219]]

alternative, some commenters recommended that such facilities reliance 
on, and compliance with, the 2020 rule should lead the EPA to build in 
additional flexibility for any more stringent BAT. Suggested 
flexibilities focused on subcategorization or longer timeframes for 
cost recovery before installation of more stringent technologies.
    The EPA agrees that such reliance interests should be 
considered.\61\ The EPA disagrees, however, with commenters who 
suggested these interests mean the Agency must retain only the 2020 
limitations in all cases. First, no NPDES permittee has certainty of 
its limitations beyond its five-year NPDES permit term, as reissued 
permits must incorporate any newly promulgated technology-based 
limitations as well as potentially more stringent limitations necessary 
to achieve water quality standards. See 40 CFR 122.44(a) and (d). The 
statute is designed for both technology-based and water quality-based 
effluent limitations to be revisited in each permit and, when 
necessary, revised consistent with these provisions and in light of the 
goal of ultimately eliminating pollutant discharges from point sources 
into WOTUS. See CWA section 101, 33 U.S.C. 1251.
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    \61\ The Supreme Court has held that, while an agency may change 
policies based upon a reasoned explanation, where a prior policy has 
engendered serious reliance interests, those interests must be taken 
into account. FCC v. Fox Television Stations, Inc., 556 U.S. at 515 
(citation omitted).
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    Moreover, the EPA has included enough time for facilities to build 
in any reasonable reliance interest. As discussed in section VII.E of 
this preamble, the Agency is finalizing a ``no later than'' date for 
the new FGD wastewater BAT limitations of December 31, 2029. Having a 
``no later than'' date approximately five-and-a-half years following 
promulgation allows facilities to rely on permitted limitations for the 
remainder of any permit existing as of the effective date of this final 
rule.
    Third, the EPA has considered the arguments that facilities have 
unrecoverable costs, particularly for biological treatment systems that 
the final rule may render obsolete, by evaluating both the existing 
costs of the 2020 rule and the costs of this final rule together in the 
IPM analysis. As discussed in sections VII.F and VIII.C, the EPA uses 
IPM to analyze electric sector impacts.\62\ IPM shows small impacts 
across the industry and leads the EPA to the conclusion that even the 
cumulative cost of the two technologies is economically achievable 
(this concept is explained in section VII.F of this preamble). Where 
more stringent technologies are available, are economically achievable, 
and have acceptable non-water quality environmental impacts as zero-
discharge systems do here, the fact that facilities may have to spend 
more to supplement or replace existing treatment systems, even 
relatively new ones, is not a sufficient reason on its own to reject 
selection of the technology.
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    \62\ While this modeling illustrates how the sector may comply 
with the rule, the EPA notes that the rule does not require any 
facilities to close.
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    Lastly, to the extent that the facilities claiming to be most 
impacted by having to add treatment are those that will be permanently 
ceasing coal combustion by 2034, the EPA has created a new subcategory 
for these facilities that would allow them to continue to meet only the 
2020 BAT limitations and thereby avoid recovering the costs of two 
treatment systems (i.e., biological treatment and a zero-discharge 
system), each one designed to meet the requirements of the 2020 or 2024 
rules, over the facility's short remaining useful life. EPA anticipates 
that approximately nine EGUs may be able to avail themselves of this 
subcategory with respect to FGD wastewater.\63\
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    \63\ Additional EGUs are projected to participate in this 
subcategory for BA transport water and CRL as discussed in the 
sections below.
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    Economic achievability of zero-discharge systems. The EPA finds 
that the costs of zero-discharge systems for control of FGD wastewater 
are economically achievable. The 2020 rule cited the increased cost of 
membrane filtration as compared to the selected technology basis as a 
reason for rejecting membrane filtration \64\ but did not find that the 
costs of membrane filtration were not economically achievable at that 
time. The EPA also declined in the 2020 rule to establish BAT based on 
thermal evaporation systems, which the Agency stated were 2.4 times the 
costs of the 2020 BAT technology basis of chemical precipitation plus 
low-residence-time-reduction biological treatment and 1.04 times the 
cost of membrane filtration. The Agency said that these costs were 
unreasonably high, and it cited this finding, together with the costs 
that the industry was facing due to other EPA rules, to reject thermal 
technologies as not economically achievable.
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    \64\ While the relative costs of technologies differ from plant 
to plant, the 2020 rule acknowledged, and additional information 
obtained during the 2022 information collection confirms, that, in 
some cases, technologies such as membrane filtration may be less 
costly than biological treatment at individual plants even where, on 
average, they would be more expensive to the industry as a whole.
---------------------------------------------------------------------------

    After updating the cost analysis and IPM modeling for the final 
rule, the EPA finds that the costs of the BAT basis of zero-discharge 
systems for FGD wastewater are economically achievable for the 
industry, as discussed further below and in sections VII.F and VIII. 
Furthermore, the EPA notes that the estimates in IPM are conservative 
with respect to FGD wastewater. To the extent that costs would have 
been lower at six plants had the EPA used certain CBI costs for thermal 
evaporation systems in its primary cost analysis, the economic impacts 
modeled in IPM at these plants are overestimated.\65\
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    \65\ To the extent that cost estimates for individual 
technologies are roughly of the same magnitude as indicated in the 
primary cost analysis, these costs would not be expected to alter 
the findings on economic achievability, even if the Agency were to 
rely on any one of the zero-discharge technologies as a standalone 
BAT basis.
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    Non-water quality environmental impacts of zero-discharge systems. 
The EPA finds that the non-water quality environmental impacts of zero-
discharge systems are acceptable.
    The EPA proposed to find that the non-water quality environmental 
impacts of membrane filtration are acceptable. Specifically, the EPA 
proposed to reverse findings from the 2020 rule regarding FA use to 
encapsulate the brine generated by membrane filtration. The EPA also 
solicited comment on the non-water quality environmental impacts of 
other zero-discharge systems that might be used as a BAT technology 
basis.
    Some commenters raised concerns relating to the non-water quality 
environmental impacts of zero-discharge systems. Specifically, 
commenters expressed concerns that the EPA had incorrectly evaluated FA 
availability because it did not use the most recent EIA data (which 
demonstrates that there is not enough FA available for brine 
encapsulation), did not use proper brine generation and encapsulation 
blending rates, and did not account for the costs of lost FA sales. 
Other commenters questioned the technological availability of one 
method of handling the solid waste generated from zero-discharge 
technologies--brine encapsulation--claiming that it has not been 
demonstrated to adequately retain pollutants in a landfill and, 
furthermore, that a particular form of brine encapsulation (paste 
encapsulation) has not been demonstrated and may not satisfy current 
disposal requirements. Finally, commenters claimed that pollutants in 
encapsulated brines and unencapsulated salt crystals could be

[[Page 40220]]

remobilized in a landfill setting or could damage the landfill-liner 
system. While some comments argued these disposal issues spoke to 
availability of the zero-discharge technology, the EPA views this 
rather as a non-water quality environmental impact (solid waste 
disposal issue) that it must consider. After considering these comments 
and the record, the EPA finds that the non-water quality environmental 
impacts of zero-discharge systems are acceptable.
    With respect to comments on FA availability, the EPA agrees with 
commenters that it should evaluate the most recent EIA data, brine 
generation data, and data on encapsulation blends. Therefore, the EPA 
has updated its analysis to consider the most recent information in 
2024 Steam Electric Supplemental Final Rule: Fly Ash Analysis (DCN 
SE11692). As noted in that document, FA sold for beneficial use 
fluctuates from year-to-year, but over the last five years the amount 
sold would still be less than the amount available for sale even after 
assuming that every plant uses FA to encapsulate brine from an FGD 
wastewater and/or CRL treatment system. Thus, the EPA does not expect 
that under worst-case scenarios the use of FA to encapsulate brine 
would hamper the fly ash sales market, let alone constitute an 
unacceptable non-water quality environmental impact.
    Furthermore, the assumption that all facilities use membrane 
filtration and generate a brine for encapsulation represents a 
conservative estimate on FA usage. The EPA has updated its cost 
estimates as discussed in section VIII and section 5 of the TDD. These 
revised cost estimates consist of least-cost analysis across the 
various zero-discharge systems. Part of this update also included 
adjustments to better account for the amount of FA available for 
encapsulation, brine generation rates, and brine encapsulation blends, 
all to respond to commenters and improve the accuracy of the Agency's 
analysis. The EPA finds that the now higher costs of membrane 
filtration lead thermal and SDE systems to be a less costly option at 
many plants. This finding is consistent with cost information received 
from some companies showing that membrane filtration would not be the 
least-cost technology. As a result of this analysis selecting non-
membrane systems at a number of plants, the assumptions of FA usage 
presented above can be seen as a likely worst-case scenario. To the 
extent that FA sales would be even less hampered than the scenario 
already found to be acceptable above, it would only further support the 
Agency's conclusion that FA use in brine encapsulation has acceptable 
non-water quality environmental impacts. For a further discussion of 
EPA's revised cost estimates, see section 5 of the TDD.
    With respect to comments about potential remobilization of 
pollutants from brine encapsulation and demonstration of paste 
encapsulation; as far back as the 2015 rule, the EPA pointed to 
multiple waste-handling alternatives that were being employed by 
facilities with zero-discharge systems. Some facilities at that time 
used the brine generated by thermal systems to condition ash for 
disposal. In the 2020 rule record, the EPA discussed facilities that 
directly engage in FA fixation of the FGD wastewater for this purpose, 
skipping the volume reduction step that a membrane or thermal system 
would offer (see section 4.1.5 of the 2020 TDD, DCN SE08650). When 
commenters express concern that contaminants from encapsulated brines 
could be remobilized, these comments assume less processing than EPA 
contemplates. The commenters reference situations where FGD wastewater 
or brine are merely used to condition ash without employing the further 
pozzolanic reactions that the EPA expects to occur in the full 
encapsulation process and that EPA included in its cost estimates of 
zero discharge. Encapsulation studies demonstrate that concentrations 
of leachate pass leachate toxicity tests and are of lower concentration 
than raw FGD wastewater. Encapsulation would also result in far less 
remobilization than exiting ash conditioning practices. Furthermore, to 
the extent that the EPA considered and discussed paste encapsulation, 
it was as a potentially cost-saving alternative to these conditioning 
and encapsulation techniques that are already well-demonstrated. Thus, 
to the extent that it is a less costly solid waste management 
alternative, it only provides the promise of cost savings compared to 
the EPA's estimates, but the EPA does not rely on this particular form 
of brine encapsulation in determining that solid waste disposal issues 
as a whole have acceptable non-water quality environmental impacts.
    Even if brine encapsulation had not been adequately demonstrated as 
a solid waste handling practice, other solid waste handling 
alternatives are available. For example, facilities in the 2015 and 
2020 rule records took the brine generated from a thermal system all 
the way down to a salt crystal using a crystallizer (DCN SE11695). The 
EPA evaluated these costs in the FGD Wastewater, CRL, and Legacy 
Wastewater Zero Discharge Treatment Technologies Costs, Loadings, and 
Non-Water Quality Environmental Impacts file (DCN SE11709) as an 
alternative and found it would increase annualized costs by three 
percent. These slightly higher overall costs would still be 
economically achievable.\66\
---------------------------------------------------------------------------

    \66\ Facilities could also consider deep-well injection of their 
brine. The EPA found that these costs on a nationwide basis would be 
three times the costs of encapsulation, and so are unlikely to be 
pursued by most facilities, though this too would constitute an 
alternative disposal practice available for the management of brine.
---------------------------------------------------------------------------

    With respect to comments about remobilization of pollutants, the 
EPA agrees with commenters that pollutants in a landfill can be 
remobilized through percolation of rainwater through the disposed solid 
wastes. These solid wastes would include not only any encapsulated 
brines but also certain solids and salt crystals that would be disposed 
of following use of some thermal and SDE alternatives where no brine is 
generated. Here, absent the pozzolanic reactions from either ash 
conditioning or encapsulation, remobilization of pollution is more 
possible as rainfall percolates through these disposed solids. 
Nevertheless, proper landfill management is designed to reduce 
infiltration of water through a landfill and to capture leachate that 
makes it to the liner at the bottom of a landfill. The EPA received no 
comments that the facilities already generating these solids and salts 
have failed to properly operate their landfills such that contaminants 
were remobilized into the environment. Even where remobilization can 
reduce the overall effectiveness of the pollution treatment systems, as 
discussed in section VII.B.3 of this preamble, the EPA is also 
finalizing zero-discharge limitations for CRL during the life of the 
plant, unless they are discharges of unmanaged CRL.\67\ This is 
designed to further ensure that these pollutants are kept in the 
landfill to the maximum extent possible rather than remobilized and 
released into the environment.
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    \67\ Note that the EPA is finalizing zero-discharge limitations 
for CRL, except as specified in the subcategories discussed in 
sections VII.C.4 and C.5. Where lined WMUs collect and treat CRL to 
zero-discharge standards during a facility's operation, permeate and 
distillate can be used to condition CCR for disposal in these WMUs.
---------------------------------------------------------------------------

    Many of the facilities presented in the record as having zero-
discharge systems have also successfully disposed of conditioned ash or 
FGD solids in landfills for years. The record supports that a properly 
designed, installed, and maintained landfill can operate as intended. 
As the EPA learned during implementation of the CCR rule, many

[[Page 40221]]

historical CCR landfills may suffer from the lack of an adequate liner 
system. However, the Agency has no evidence that, where liners are 
properly designed, installed, and maintained, they are incompatible 
with the additional pollutants in FGD wastewater that zero-discharge 
systems would capture.\68\
---------------------------------------------------------------------------

    \68\ In contrast, FGD gypsum is already removed from FGD 
wastewater before discharge and is known to loosen clay soils which 
sometimes form the base of older landfills designed without 
composite liners.
---------------------------------------------------------------------------

    Finally, the EPA finds that, even to the extent that there are any 
negative non-water quality environmental impacts, the positive non-
water quality environmental impacts outweigh the negative ones. In 
particular, the EPA estimates that there are significant decreases in 
air pollution and water withdrawals \69\ as a result of this rule. 
While the rule is not being promulgated to reduce these impacts, these 
resulting non-water quality environmental impacts further support the 
Agency's conclusion that zero-discharge systems for FGD wastewater are 
BAT.
---------------------------------------------------------------------------

    \69\ Reduced water withdrawals could also lead to reduced 
impingement and entrainment.
---------------------------------------------------------------------------

    b. The EPA rejects less stringent technologies than zero-discharge 
systems as BAT for FGD wastewater.
    Except for the new permanent cessation of coal combustion by 2034 
subcategory discussed in section VII.C.4 of this preamble, and for 
discharges before the applicability dates of the new zero discharge-
requirements in this final rule, the EPA is not selecting chemical 
precipitation followed by a low hydraulic residence time biological 
treatment including ultrafiltration, as the BAT technology basis. BAT 
is the ``gold standard'' for controlling water pollution from existing 
sources, and the Supreme Court has explained that BAT must achieve 
``reasonable further progress'' toward the CWA's goal of eliminating 
pollution. See Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1003, 
1006 (citing Nat'l Crushed Stone v. EPA, 449 U.S. 64, 75 (1980)). The 
record shows that the 2020 rule industrywide BAT technology basis for 
FGD wastewater removes fewer pollutants than the zero-discharge BAT 
technology basis identified in this final rule that has been found to 
be technologically available, be economically achievable and have 
acceptable non-water quality environmental impacts.\70\ Similarly, 
except for the permanent cessation of coal combustion by 2028 
subcategory discussed in section VII.C.3 of this preamble, the EPA is 
not identifying the less stringent (and previously rejected in the 2015 
and 2020 rules) technologies of surface impoundments or chemical 
precipitation, as these technologies too will remove fewer pollutants 
than the BAT technology basis in this rule.
---------------------------------------------------------------------------

    \70\ In contrast, nothing in the record or public comments 
indicates that chemical precipitation plus low hydraulic residence 
time biological reduction has ceased to be available, be 
economically achievable, and have acceptable non-water quality 
environmental impacts for discharges before the applicability dates 
of the new, more stringent limitations of this rule.
---------------------------------------------------------------------------

2. BA Transport Water
    The EPA is identifying the zero-discharge systems of dry-handling 
or closed-loop systems as the technology basis for establishing BAT 
limitations to control pollutants discharged in BA transport water.\71\ 
Specifically, dry-handling systems include both waterless air-cooled 
conveyor systems and pneumatic systems, as well as under-boiler 
mechanical drag systems (e.g., submerged chain conveyors) and submerged 
grind conveyors (e.g., compact submerged conveyors), which use quench 
water to cool the ash but immediately remove the ash without generating 
BA transport water. Closed-loop systems consist of remote mechanical 
drag systems that actively sluice the ash (i.e., transport the ash with 
water) and are paired with any necessary storage tanks, chemical 
addition systems, and/or RO treatment necessary to fully recycle BA 
transport water except during high intensity, infrequent storm events 
as discussed below.\72\ The EPA finds that these technologies are 
technologically available, are economically achievable, and have 
acceptable non-water quality environmental impacts after evaluating the 
factors specified in CWA section 304(b)(2)(B).
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    \71\ As described in section VII.B.5 of this preamble, the EPA 
is also finalizing a definitional change to certain wastewaters, 
including BA transport water, that excludes discharges necessary as 
a result of high intensity, infrequent storm events, as well as 
wastewater removed from ash handling equipment within the first 120 
days of decommissioning the equipment.
    \72\ In addition to remote MDSs, non-BAT technologies include 
many dewatering bins (also known as hydrobins), and surface 
impoundments may also have the flexibility to operate as closed-loop 
systems. Like remote MDSs, the latter systems may need to install 
chemical addition systems (acid, caustic, and/or flocculants), RO 
systems, and/or additional storage tanks to operate as fully closed 
loop.
---------------------------------------------------------------------------

    In the 2020 rule, the EPA rejected dry-handling or closed-loop 
systems as the BAT technology basis in favor of high-recycle-rate 
systems with a site-specific purge allowance of up to 10 percent of the 
BA transport water system's volume to address four potential purge 
needs.\73\ The EPA justified this change in BAT due to process changes 
plants were making to comply with the CCR regulations, as well as the 
additional costs of dry-handling or closed-loop systems. In the 2023 
proposal, the EPA reevaluated the four asserted purge needs relied upon 
in establishing the 2020 purge, and for each asserted purge need, the 
Agency explained why the record no longer supported that these purges 
should be part of the BAT technology basis. As a result, the EPA 
proposed returning to the dry-handling or closed-loop systems that 
served as the BAT technology basis in the 2015 rule.
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    \73\ The four asserted purge needs related to precipitation, 
maintenance, water chemistry, and water balance.
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    The EPA received comments both supporting and criticizing the 
proposed return to the BAT basis of dry-handling or closed-loop systems 
selected in the 2015 rule. Comments supporting the EPA's proposal to 
return to the 2015 BAT technology basis for BA transport water focused 
on the lack of evidence in the record of facilities with a demonstrated 
need to purge BA transport water. These comments also focused on the 
legal standard that BAT represents the best performing plant, arguing 
further that the EPA has never disputed that the best performing plant 
can achieve zero discharge. Comments opposing the return to the 2015 
rule standard reiterated the four potential purge needs discussed in 
the 2020 rule. In the alternative, these commenters asked the EPA to 
formulate flexibilities for purges that in practice might be more or 
less flexible than the site-specific 10 percent volumetric purge 
allowance arrived at in the 2020 rule.
    Commenters also responded to the EPA's solicitation about the 
potential disparity between the purges from closed-loop systems and the 
purges from under-boiler ``dry'' handling systems that still use quench 
water. These comments asked EPA not to further regulate quench water 
from under-boiler systems because the water is not used to transport 
ash and these facilities had relied on the quench water from dry-
handling systems being treated as a ``low volume waste source'' rather 
than BA transport water.
    After considering all public comments and the EPA's extensive 
record in light of the statutory factors, and as explained below, the 
EPA finds that dry-handling or closed-loop systems are available and 
economically achievable, and that they have acceptable non-water 
quality environmental impacts. Therefore, the

[[Page 40222]]

EPA is selecting dry-handling or closed-loop systems as the BAT 
technology basis for BA transport water but is retaining the 2020 rule 
limitations for discharges before the applicability dates of the new 
zero-discharge requirement.
    In the first subsection immediately below, the EPA discusses its 
rationale for selecting dry-handling or closed-loop systems as the BAT 
technology basis for BA transport water. In the following subsection, 
the EPA explains why it is not selecting less stringent technologies 
than dry-handling or closed-loop systems as the BAT technology basis 
for BA transport water. In the final subsection, the EPA discusses the 
definition of BA transport water and why, in light of the record, it 
declines to change how under-boiler ``dry'' systems with a discharge 
are regulated. For further discussion of the definitional changes to BA 
transport water that are being finalized with respect to high 
intensity, infrequent storm events, as well as decommissioning 
wastewater, see section VII.B.5 of this preamble. For further 
discussion of the EPA's retention of the 2020 rule limitations as 
interim limitations, see section VII.C.7 of this preamble.
    a. The EPA selects dry-handling or closed-loop systems as BAT for 
BA transport water.
    Technological availability of dry-handling or closed-loop systems. 
Based on the record, the EPA finds that dry-handling or closed-loop 
systems are technologically available. At the time of the 2020 rule, 
the EPA estimated that more than 75 percent of plants already employed 
dry-handling systems or wet-sluicing systems in a closed-loop manner, 
or they had announced plans to switch to such systems soon. Some of 
these systems have been in use since the 1970s, and today, most 
facilities have installed one or more such systems.\74\ The high 
percentage of plants employing these systems indicates that they are 
technologically available.
---------------------------------------------------------------------------

    \74\ One vendor estimates that only seven ash conversions remain 
in the entire industry.
---------------------------------------------------------------------------

    In the 2015 and 2020 rule preambles, the EPA discussed the 
widespread use of dry-handling systems for control of BA transport 
water servicing about 200 EGUs at over 100 plants. In the 2020 rule, 
the EPA also discussed advances in dry BA handling systems. 
Specifically, the Agency discussed a newer technology called submerged 
grind conveyors (one example of which is called a compact submerged 
conveyor). At the time, compact submerged conveyors were known to be 
installed and in operation at two plants. The EPA has since learned 
that an additional plant has installed compact submerged 
conveyors.75 76 In addition to the increased use of compact 
submerged conveyors, a higher number and broader array of dry-handling 
systems are currently in place than the EPA originally forecasted. For 
example, as indicated in the 2020 rule record, one utility commented 
that it had space constraints at a facility that would preclude the 
installation of a compact submerged conveyor, and the EPA thus 
projected that this facility would employ a high recycle rate system 
under the 2020 rule. After the 2020 rule, however, that utility 
ultimately installed a different dry-handling system--which highlights 
the broad array of dry-handling options available for coal-fired power 
plants, regardless of their configuration. Even where space constraints 
may prohibit certain dry systems, a plant could use a pneumatic system, 
albeit at a somewhat greater cost. The 2020 rule record included 
information on 50 pneumatic installations from as early as 1992. Given 
that BAT is to reflect the best performing plant in the field, 
Kennecott v. EPA, 780 F.2d at 447, and that the facts in the record 
support the use of dry-handling technology to achieve zero discharge of 
BA transport water, it is likely the EPA could have selected dry-
handling systems as the sole technology basis for control of BA 
transport water. Nonetheless, as it did in the 2015 rule, the EPA is 
also identifying closed-loop systems as a BAT technology basis for 
controlling discharges of BA transport water, given that a limited 
number of plants may find that option to be more attractive due to 
space constraints and lower costs when compared to a pneumatic system.
---------------------------------------------------------------------------

    \75\ Some utilities have even suggested that the discussion of 
compact submerged conveyors in the final 2020 rule preamble and 
additional compliance timeframes have led them to consider these 
newer dry systems rather than a previously contemplated high-
recycle-rate/closed-loop system.
    \76\ Final Burns & McDonnell Meeting Notes (DCN SE10248).
---------------------------------------------------------------------------

    After the 2015 rule and during the 2020 rulemaking, certain 
industry representatives argued that there are challenges to operating 
a closed-loop BA handling system in a truly zero-discharge manner. They 
argued that closed-loop systems, including remote MDS and dewatering 
bins, cannot maintain fully closed-loop operations due to chemistry 
issues or water imbalances in the system, such as those that might 
occur from unexpected maintenance or large precipitation events. Even 
accounting for these issues, however, the 2020 rule did not find that 
closed-loop systems are not technologically available. Information in 
the EPA's 2020 rule record indicated that plants can operate their 
closed-loop systems to achieve zero discharge, although this could 
require some process changes and their resulting costs. Instead, the 
Agency rejected this technology as a basis for BAT based process 
changes happening at plants to comply with the CCR regulations 
(addressed further below), while also noting the additional costs over 
the 2015 rule's estimates. As explained below, the record indicates 
that closed-loop BAT handling systems are economically achievable. See 
section VIII of this preamble for a further discussion of costs 
associated with the closed-loop system technology basis.
    In the 2020 rule, the EPA discussed four potential challenges with 
maintaining closed-loop systems: (1) managing non-BA transport water 
inflows, (2) managing precipitation-related inflows, (3) managing 
unexpected maintenance events, and (4) maintaining water system 
chemistry. The 2023 proposal discussed these issues at length, 
including why EPA did not view them as a basis for rejecting zero-
discharge requirements. As explained in the proposal and further 
discussed below, based on the current record, the EPA continues to view 
none of these previously discussed challenges as providing a basis for 
rejecting closed-loop systems as not technologically available, 
although these issues may in certain circumstances require a plant to 
incur additional costs (which are found to be economically achievable) 
or to have an infrequent precipitation-related discharge (which would 
be addressed by the definitional changes the EPA is finalizing in this 
rule).
    First, in 2020, the EPA stated that managing non-BA transport water 
inflows had the potential to result in water imbalances within a 
closed-loop system. In the 2023 proposal, the EPA found that closed-
loop systems can be sized to handle additional wastestreams. The EPA 
received comments reiterating the 2020 rule findings; however, none of 
these comments provided specific data or information demonstrating that 
even one system cannot handle non-BA transport water inflows. Thus, EPA 
is maintaining its finding from proposal that a purge in response to 
water imbalance due to management of other wastestreams is not 
necessary.
    Second, in 2020, EPA stated that managing precipitation-related 
inflows had the potential to result in water imbalances in the BA 
handling system. At proposal, EPA found that precipitation-related 
inflows can be

[[Page 40223]]

adequately managed with design improvements, including the use of 
roofing where appropriate. The 2015 BAT technology basis and 2020 rule 
remote MDS technology designs included covers to avoid collecting 
precipitation, and the costs for covers were included in the associated 
cost analysis. The EPA received comments on the 2023 proposal 
reiterating the 2020 rule findings; however, none of these comments 
provided specific data or information demonstrating that even one 
system cannot handle common precipitation-related inflows.\77\ To the 
extent that a plant experiences precipitation-related inflows as a 
result of a 10-year storm event of 24-hour or longer duration (e.g., a 
10-year, 30-day storm event), the EPA is finalizing a definitional 
change discussed in section VII.B.5 of this preamble.
---------------------------------------------------------------------------

    \77\ In one comment, a utility suggested that it could not 
employ roofing at its plant without jeopardizing the necessary 
cooling of the BA, but this plant did not provide any data showing 
that it could not manage this heat transfer with standard heating, 
ventilation, and air conditioning (HVAC) equipment.
---------------------------------------------------------------------------

    The 2020 rule mentioned a third previously discussed challenge to 
operating a remote MDS as a closed-loop system: the possibility of 
infrequent maintenance events that might fall outside the 2015 rule 
exclusion of ``minor maintenance'' and ``leaks'' from the definition of 
BA transport water. EPRI 78 79 listed several such 
maintenance events; most were expected to occur less than annually. 
EPRI provided information about the estimated frequency and volume of 
water associated with each maintenance event; however, EPRI did not 
provide information about a specific remote MDS unable to manage these 
maintenance events with existing maintenance tanks. In the 2023 
proposal, the EPA found that maintenance could be managed within a 
closed-loop system. Furthermore, even where maintenance wastewater 
volumes are too large to be managed in existing maintenance tanks, 
utilities can, at additional cost, lease storage tanks for short-term 
maintenance where these infrequent maintenance events are foreseeable. 
Commenters did not provide any information on maintenance activities 
that would require a purge if facilities properly planned and executed 
regular operation and maintenance (O&M). Thus, the EPA is maintaining 
its finding from proposal that a purge of BA transport water for 
maintenance is not necessary.
---------------------------------------------------------------------------

    \78\ EPRI, 2018. Closed-Loop Bottom Ash Transport Water: Costs 
and Benefits to Managing Purges (DCN SE06920).
    \79\ EPRI, 2016. Guidance Document for Management of Closed-Loop 
Bottom Ash Handling Water in Compliance with the 2015 Effluent 
Limitations Guidelines (DCN SE06963).
---------------------------------------------------------------------------

    The final engineering challenge discussed in the 2020 rule record 
with respect to closed-loop systems was the need to maintain water 
system chemistry. The 2020 rule discussed potentially problematic 
system chemistries, such as extreme acidic conditions, high scaling 
potential, and the buildup of fine particulates that could clog pumps 
and other equipment. The 2015 closed-loop system BAT design basis 
included a chemical addition system to manage these system chemistries, 
as does the BAT basis in this final rule. In particular, corrosivity 
can be managed through pH adjustment, scaling can be managed with acid 
and/or antiscalants, and fines can be further settled out with polymers 
and other coagulants. EPRI has documented that some systems have gone 
slightly further, pairing the chemical addition systems with changes in 
operations, such as higher flow rates or longer contact time. Some 
commenters on the 2023 proposal suggested that systems would not be 
able to manage these chemistry problems but did not provide information 
supporting this assertion. In the absence of information, the EPA finds 
that, even assuming that the previously mentioned strategies would not 
apply at a given plant, the same slipstream of purge allowed under the 
2020 rule could be treated with RO and recycled back in as clean makeup 
water. The EPA has considered these additional costs as discussed in 
sections VII.F and VIII, and outside the additional cost (which is 
found to be economically achievable), there is no record evidence that 
this chemistry-related challenge cannot be overcome with reasonable 
steps. Therefore, this concern does not provide a basis for rejecting 
closed-loop systems as BAT.
    For all the foregoing reasons, the EPA finds that the record 
indicates that dry-handling or closed-loop systems are technologically 
available for control of discharges in BA transport water.
    Economic achievability of dry-handling or closed-loop systems. The 
EPA finds that the costs of dry-handling or closed-loop systems are 
economically achievable. In the 2020 rule, the EPA cited the costs of 
closed-loop systems as an additional basis for selecting high recycle 
rate systems. In the 2020 rule, the EPA noted that it had 
``conservatively'' estimated costs of $63 million per year based on all 
facilities using a remote MDS needing a 10 percent purge to be treated 
with RO in order to achieve complete recycle (i.e., zero discharge 
operations). The EPA never found, however, that the additional costs to 
achieve zero discharge were not economically achievable.
    The EPA's updated cost estimates demonstrate that, after including 
the costs of treating all wastestreams--including achieving zero 
discharge for BA transport water--the final rule would result in 
minimal economic impacts. (For further information, see sections VII.F 
and VIII.) After considering these results, the EPA finds that these 
additional costs are economically achievable as that term is used in 
the CWA.
    Non-water quality environmental impacts of dry-handling or closed-
loop systems. The EPA finds that the non-water quality environmental 
impacts associated with dry-handling or closed-loop systems for 
controlling BA transport water discharges are acceptable. See sections 
VII.G and X below for more details.
    Process changes associated with dry-handling or closed-loop 
systems. In the 2020 rule, the EPA also rejected dry handling or 
closed-loop systems due to process changes happening at steam electric 
facilities as they moved toward compliance with the CCR regulations. 
The EPA stated that, as plants close their surface impoundments under 
the CCR regulations, they may choose to send certain non-CCR 
wastewaters to their BA handling system. This was said to potentially 
complicate their efforts to fully close their BA handling systems due 
to increased scaling, corrosivity, or plugging of equipment. 
Alternatively, a closed-loop requirement might incentivize plants to 
discharge their non-CCR wastes rather than send them to their BA 
handling systems for control, in which case they would be subject to 
less stringent requirements governing low volume waste sources. The EPA 
also suggested that requiring limitations based on closed-loop systems 
could result in plants using their surface impoundments longer, 
assuming plants cannot build alternative storage capacity and need to 
continue to send their non-CCR wastes to unlined impoundments.
    The rationale in the 2020 rule is no longer persuasive as a reason 
to select high recycle rate systems rather than dry-handling or closed-
loop systems because the changes happening at plants under the CCR 
regulations are expected to be complete by the time the final BAT 
limitations apply to any given plant. In particular, the final rule BA 
transport water requirements will be included in NPDES permits with an 
applicability date of no later than December 31, 2029. This is over a 
decade after the

[[Page 40224]]

promulgation of the 2015 CCR rule and eight years after even the 
revised CCR surface impoundment deadline of April 11, 2021, by which 
facilities were required to cease receipt of all wastes into their 
unlined CCR surface impoundment.\80\ As of the publication of this 
rule, most facilities have already completed conversions of their 
leaking, unlined CCR surface impoundments under the CCR regulations, 
which means that they no longer rely on these unlined surface 
impoundments as part of their BA handling systems, but rather have 
installed systems to handle their BA transport water that do not rely 
on unlined CCR surface impoundments.\81\
---------------------------------------------------------------------------

    \80\ 40 CFR 257.101(a)(1).
    \81\ See, e.g., https://www.epa.gov/coalash/coal-combustion-residuals-ccr-part-implementation.
---------------------------------------------------------------------------

    Of the remaining unlined CCR surface impoundments that might exist 
following promulgation of this rule, those operating under the CCR Part 
A rule flexibility found in Sec.  257.103(f)(2) must permanently cease 
coal combustion, and as discussed below, the EPA is retaining the 
subcategory for EGUs permanently ceasing coal combustion by 2028, which 
does not require zero discharge of BA transport water. For those 
unlined CCR surface impoundments that are not permanently ceasing coal 
combustion and are required to close for cause but where alternative 
capacity is technically infeasible, there is some flexibility under the 
CCR Part A rule allowing for a maximum timeframe of October 15, 2023, 
or October 15, 2024, for the surface impoundment to cease receipt of 
waste.\82\ The 2023 and 2024 extended timeframes require EPA 
approval.\83\ Even with these extensions, the majority of facilities 
will have ceased receipt of waste in its non-compliant surface 
impoundment and completed its conversion to a CCR regulation-compliant 
BA handling method (necessary to remain in operation) within a few 
months of the effective date of this rule. Since there are no looming 
deadlines and tight timeframes under the CCR regulations that would 
justify continued flexibility, facilities with high recycle rate 
systems are free to focus on transitioning those high recycle rate 
systems to closed-loop operations.\84\ Because ash handling changes 
will no longer be compelled by the CCR regulations by the time this 
final rule is effective, the EPA concludes that there are no ``process 
change'' or non-water quality environmental impact reasons related to 
the CCR regulations that weigh against the EPA's decision to select 
dry-handling or closed-loop systems as the BAT basis for control of BA 
transport water discharges.
---------------------------------------------------------------------------

    \82\ 40 CFR 257.103(f)(1)(vi).
    \83\ Further information on the implementation of these Part A 
applications is available on EPA's website at: https://www.epa.gov/coalash/coal-combustion-residuals-ccr-part-implementation.
    \84\ Although the EPA estimates that fully closing the loop 
would be less expensive than converting to a dry-handling system, 
nothing would preclude a facility with a high recycle rate system 
from installing one of the technologically available and 
economically achievable dry-handling systems.
---------------------------------------------------------------------------

    b. The EPA rejects less stringent technologies than dry-handling or 
closed-loop systems as BAT for BA transport water.
    Except for the new subcategory for EGUs permanently ceasing coal 
combustion by December 31, 2034, and for discharges before the 
applicability dates for the new zero-discharge requirement of this 
rule, the EPA is not establishing BAT limitations based on high recycle 
rate systems. In the 2020 rule, the EPA reversed its decision from the 
2015 rule and determined that dry-handling or closed-loop systems were 
not BAT. As a result, the EPA established a volumetric purge allowance 
(with a maximum of 10 percent of the system volume) to be determined on 
a case-by-case basis by the permitting authority, which required a 
permitting authority's BPJ analysis to determine any appropriate 
further control. As discussed above, the technological issues 
identified in the 2020 rule can be resolved, albeit at potentially 
additional costs, which the EPA finds are economically achievable. 
Furthermore, a dewatering bin or remote MDS with a purge removes fewer 
pollutants than the BAT basis of dry-handling or closed-loop systems, 
which the Agency finds is technologically available, economically 
achievable, and has acceptable non-water quality environmental 
impacts.\85\ BAT is the ``gold standard'' for controlling water 
pollution from existing sources, and the Supreme Court has explained 
that BAT must achieve ``reasonable further progress'' toward the Act's 
goal of eliminating pollution. See Southwestern Elec. Power Co. v. EPA, 
920 F.3d at 1003, 1006 (citing Nat'l Crushed Stone v. EPA, 449 U.S. at 
75). For these reasons, the EPA is not selecting high-rate-recycle 
systems as BAT.
---------------------------------------------------------------------------

    \85\ In contrast, nothing in the record or public comments 
indicates that high-recycle-rate systems ceased to be available, be 
economically achievable, and have acceptable non-water quality 
environmental impacts for discharges before the applicability dates 
of the new, more stringent limitations of this rule.
---------------------------------------------------------------------------

    Except for the subcategory for EGUs permanently ceasing coal 
combustion by December 31, 2028, the EPA is also not identifying the 
less stringent (and previously rejected in the 2015 and 2020 rules) 
technology of surface impoundments as the technology basis for BAT, as 
this technology would also remove fewer pollutants than the BAT basis 
of dry-handling or closed-loop systems, which the EPA finds is 
technologically available, is economically achievable, and has 
acceptable non-water quality environmental impacts.
    c. The EPA continues to regulate discharges from some dry-handling 
BA systems as a low volume waste source.
    As previously discussed, the final BAT technology basis for BA 
transport water is dry-handling or closed-loop systems. This technology 
basis incorporates systems that operate so as to not generate BA 
transport water at all (so-called ``dry'' systems), as well as systems 
that do generate BA transport water but recycle that transport water in 
a closed-loop manner so as to achieve no discharge (so-called ``wet'' 
systems). At proposal, EPA solicited comment on the issue of whether 
the final rule could create unintended consequences if discharges from 
a ``dry'' BA handling system are regulated differently than discharges 
from a ``wet'' BA handling system. Historically, discharges from a dry 
bottom ash handling system have not been considered transport water or 
BA purge water, but rather have been considered a ``low volume waste 
source,'' and therefore subject to their own limitations. These 
limitations include BPT limitations on TSS and oil and grease, as well 
as any more stringent BAT limitations that the permitting authority 
determines appropriate on a case-by-case basis using its BPJ.
    In the proposal, the EPA pointed to one instance of a reported 
purge at an under-boiler dry-handling system that uses quench water to 
cool the BA but did not transport the ash with water and thus did not 
generate BA transport water. After soliciting comment on a number of 
potential modifications the Agency could make to address potential 
disparities between allowable purges from a wet BA handling system and 
a dry BA handling system, the EPA received only one comment that 
provided meaningful data relevant to the solicitations. Santee Cooper 
provided findings of a third-party analysis of the Cross facility's 
under-boiler dry BA handling system. Over the two years of 2021 and 
2022, the BA system at Cross was fully drained 10 times and partially 
drained 29 times for maintenance. Historically, BA contact water such 
as that discharged at Cross has been treated as a low volume waste 
source.

[[Page 40225]]

    Based on public comments and a consideration of the record, the EPA 
is not modifying the regulations to address discharges that the EPA has 
historically not considered BA transport water. EPA did not receive any 
information to call into question its previous conclusions about the 
different characteristics of BA contact water and BA transport water, 
including the Agency's findings in 2015 and 2020 that BA contact water 
has lower pollutant concentrations than BA transport water. Moreover, 
no commenters provided information supporting a finding that the zero-
discharge requirements in this rule could have the unintended effect of 
leading to more discharges of low volume waste from dry BA handling 
systems than would otherwise occur. Based on the limited information 
provided in comments, EPA concludes no changes to the regulatory 
treatment of purges from a dry BA handling systems are warranted, and 
they will continue to be regulated as low-volume wastes.\86\
---------------------------------------------------------------------------

    \86\ Furthermore, the EPA notes that the resulting average 
annual discharge of about 600,000 gallons per year of BA contact 
water at Cross results in small pollutant loadings in both relative 
and absolute terms. Contrast this to the three million gallons per 
day of BA transport water and the relative reduction in water 
volumes alone, not accounting for the lower pollutant concentrations 
of BA contact water, mean that the pollutant discharges are reduced 
by over 99.9 percent.
---------------------------------------------------------------------------

    Aside from the under-boiler BA handling systems (``dry-handling'' 
systems) that the EPA solicited comment on, some commenters also 
responded to EPA's solicitations by suggesting that purges from remote 
BA handling systems (``closed-loop'' systems) should continue to be 
allowed to avoid creating disparities between dry-handling and closed-
loop systems.\87\ Comments in this vein tended to be very generalized 
and did not provide any meaningful reason for EPA to change direction 
from its proposal, with the exception of the EPA's definitional change 
described in section VII.B.5 of this preamble.
---------------------------------------------------------------------------

    \87\ For context, the requested purges from remote systems 
operating as high-recycle-rate rather than closed-loop systems are 
often in the range of 50,000 to 100,000 gallons per day, an amount 
far greater than the amounts of BA contact water (a low-volume waste 
source with fewer pollutants) discharged in the one dry-handling 
facility for which the EPA has information on purges.
---------------------------------------------------------------------------

3. CRL
    Except for the subcategory for discharges of unmanaged CRL, the EPA 
is identifying zero-discharge systems as the technology basis for 
establishing BAT limitations to control pollutants discharged in 
CRL.\88\ More specifically, as with FGD wastewater, the technology 
basis for CRL is membrane filtration systems, SDEs, and thermal 
evaporation systems alone, or in any combination, including any 
necessary pretreatment e.g., chemical precipitation) or post-treatment 
(e.g., crystallization).\89\ Furthermore, where a permeate or 
distillate is generated from the final stage of treatment, the 
technology basis is a process wherein this water would then be recycled 
back into the plant as either FGD makeup water or EGU makeup water.\90\ 
After evaluating the factors specified in CWA section 304(b)(2)(B), the 
record shows that these technologies are available, are economically 
achievable, and have acceptable non-water quality environmental 
impacts. For discussion of the subcategory for discharges of unmanaged 
CRL, see section VII.C.5.
---------------------------------------------------------------------------

    \88\ As described in section VII.B.5 of this preamble, the EPA 
is also finalizing a definitional change to certain wastewaters, 
including CRL, that excludes discharges necessary as a result of 
high intensity, infrequent storm events.
    \89\ While three main technologies are listed here and are used 
to evaluate costs and non-water quality environmental impacts, the 
list is not meant to exclude use of FA fixation, direct 
encapsulation, evaporation ponds, or other zero-discharge treatment 
options where a facility uses these technologies to meet the zero-
discharge standard established in this rule.
    \90\ The 2020 rule finalized a carve out from the definition of 
FGD wastewater applicable to ``treated FGD wastewater permeate or 
distillate used as boiler makeup water.'' The EPA is making the 
equivalent change to the definition of CRL for the same reasons the 
change was made to the definition FGD wastewater and to support 
consistency across these two zero-discharge wastewater streams. See 
85 FR 64675. No corresponding change is necessary for use to 
condition CCR destined for disposal where the disposal would be 
subject to the same zero-discharge limitations.
---------------------------------------------------------------------------

    Based on the BAT technology basis identified, the EPA is 
establishing zero-discharge limitations for CRL, as it does for FGD 
wastewater. However, because CRL is different from FGD wastewater in 
that it is expected to continue to be generated and discharged 
following even the retirement of the plant, the EPA is also using the 
BAT technology basis identified to establish nonzero numeric 
limitations following a plant's eventual retirement--limitations based 
on membrane filtration for CRL permeate and limitations based on 
thermal evaporation for CRL distillate.
    In the subsection immediately below, the EPA discusses its 
rationale for establishing zero-discharge systems as BAT for control of 
CRL. In the following subsection, the EPA explains why it rejected less 
stringent technologies as BAT. In the final subsection, the EPA 
explains the rationale for establishing zero-discharge systems as NSPS 
for control of CRL. For further discussion of the new subcategories for 
permanent cessation of coal combustion by 2034 and discharges of 
unmanaged CRL, see section VII.C of this preamble. For further 
discussion of the definitional change to CRL that is being finalized 
with respect to high intensity, infrequent storm events, see section 
VII.B.5 of this preamble.
    a. The EPA selects zero-discharge systems as BAT for CRL.
    Technological availability of zero-discharge systems. Although the 
EPA's preferred option at proposal was to identify BAT based on 
chemical precipitation, it solicited comment on a zero-discharge 
requirement based on other technologies as well, including the same 
technologies identified as the BAT basis for control of FGD wastewater 
in this rule. 88 FR 18849. The EPA received comments both for and 
against the availability of zero-discharge systems. Commenters favoring 
zero discharge of CRL pointed to the EPA's record, which shows that one 
facility already employs a zero-discharge thermal evaporation system to 
co-treat its CRL and FGD wastewater, many non-CCR landfills use zero-
discharge systems to treat their leachate, and zero-discharge systems 
have been used to treat other wastewaters similar to CRL, including FGD 
wastewater. In contrast, commenters opposed to zero-discharge systems 
claimed that the EPA did not sufficiently evaluate such systems at 
proposal and further disputed EPA's findings that pollutants in CRL are 
similar to those in FGD wastewater.
    After consideration of the comments received and evaluation of the 
extensive record, the EPA finds that zero-discharge systems are 
technologically available for control of CRL discharges. BAT is 
supposed to reflect the highest performance in the industry and may 
reflect a higher level of performance than is currently being achieved 
based on technology transferred from a different subcategory or 
category, bench scale or pilot plant studies, or foreign plants. See 
Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1006; Am. Paper Inst. 
v. Train, 543 F.2d at 353; Am. Frozen Food Inst. v. Train, 539 F.2d at 
132. The EPA disagrees with commenters who suggested the Agency had not 
sufficiently evaluated zero-discharge options at proposal and instead 
agrees with commenters that the best-performing plant treating CRL 
domestically in this industry is achieving zero discharge. At proposal, 
the EPA discussed a thermal evaporation system that has achieved zero 
discharge of CRL and FGD

[[Page 40226]]

wastewater since 2015.91 92 The record also includes two 
domestic pilot studies on CRL: one using membrane filtration and 
another using membrane filtration with SDE. Furthermore, the proposed 
rule record included information on treatment of non-CCR landfill 
leachate, including one thermal technology vendor with full-scale 
installations, one thermal technology vendor with a pilot study, and 
two installations of membrane filtration with SDE.\93\ The successful 
use of these systems at non-CCR landfills is relevant to CRL because 
CRL contains the same pollutants as found in these landfills (e.g., 
mercury, arsenic, selenium, nitrates), and indeed non-CCR landfills 
have potentially even more challenging characteristics that these 
systems are able to handle. In particular, these systems have proven 
able to successfully treat the same pollutants found in CRL, in 
addition to treating potentially more challenging organic pollutants 
and managing more challenging biological fouling agents found in non-
CCR landfill leachate that are either absent from, or present in lower 
concentrations in, CRL. Since the absence of these pollutants and 
fouling agents make treatment simpler, these differences support the 
EPA's finding of technological availability.
---------------------------------------------------------------------------

    \91\ ERG. 2020. Final Notes from Site Call with Duke Energy's 
Mayo Steam Station. June 15 (DCN SE08964).
    \92\ The EPA notes that, while the utility employing this system 
filed comments on the proposed rule, it did not dispute in its 
comments that its system effectively operates zero discharge for 
CRL, nor did it dispute that zero discharge is technologically 
available for CRL.
    \93\ An additional three membrane filtration technology vendors 
successfully treat non-CCR landfill leachate, but the operators of 
these installations have so far chosen to discharge the clean 
permeate instead of operating with zero discharge.
---------------------------------------------------------------------------

    Finally, since the record indicates that CRL is similar to FGD 
wastewater--which the record demonstrates can be effectively treated 
using zero-discharge systems--the EPA also independently relies on the 
record evidence discussed in section VII.B.1 of this preamble above and 
technology transfer from FGD wastewater to support its conclusion that 
zero-discharge systems are available for controlling CRL discharges. 
The EPA may rely on technology transfer to establish technology-based 
limitations such as those in this rule. Am. Iron & Steel Inst. v. EPA, 
526 F.2d 1027, 1058, 1061, 1064 (3d Cir. 1975); Weyerhaeuser Co. v. 
Costle, 590 F.2d at 1054 n.70; Reynolds Metals Co. v. EPA, 760 F.2d at 
562; California & Hawaiian Sugar Co. v. EPA, 553 F.2d at 287. In the 
2015 rule record, EPA found that the pollutants of concern in CRL are 
the same pollutants that are present in, and in many cases are also 
pollutants of concern for, FGD wastewater, FA transport wastewater, BA 
transport water, and other CCR solids. This finding led the Agency to 
select chemical precipitation as the technology basis for the 2015 
rule's NSPS and PSNS for CRL, based on technology transfer from the use 
of chemical precipitation on FGD wastewater.\94\ This finding was never 
challenged. The EPA is basing the final rule CRL limitations on the 
same zero-discharge systems selected as BAT for treating FGD wastewater 
in this final rule. In contrast to comments that pollutants found in 
CRL are fundamentally different than those found in FGD wastewater, the 
EPA confirms its findings from the 2015 rule that CRL is 
characteristically like FGD wastewater. Even after accounting for 
additional data from 12 landfills gathered prior to the 2023 proposal, 
the EPA's analysis in the CRL Analytical Data Evaluation--2024 Final 
Rule (DCN SE11715) memorandum shows that CRL continues to have the same 
pollutants of concern in similar concentrations as other wastewaters, 
including FGD wastewater. Zero-discharge systems are available to treat 
this type of wastewater, and the limitations based on this technology 
would eliminate all arsenic, mercury, and other toxic pollutants from 
CRL discharges by the steam electric power generating industry. 
Moreover, just as the use of each individual technology within the BAT 
technology basis for FGD wastewater discussed in section VII.B.1 of 
this preamble supports the availability of each individual technology 
as BAT for that wastestream, based on technology transfer from FGD 
wastewater, the use of each individual technology is sufficient on its 
own to support the availability of a zero-discharge limitation for CRL.
---------------------------------------------------------------------------

    \94\ In establishing chemical precipitation as the basis for 
NSPS, the Agency stated that for combustion residual leachate, 
chemical precipitation is a well-demonstrated technology for 
removing metals and other pollutants from a variety of industrial 
wastewaters, including leachate from landfills not located at power 
plants. Chemical precipitation is also well demonstrated at steam 
electric power plants for treatment of FGD wastewater that contains 
the pollutants in combustion residual leachate (80 FR 67859).
---------------------------------------------------------------------------

    At proposal, the EPA solicited comment on zero discharge 
limitations for CRL as well as transferring the 2015 NSPS or 2020 VIP 
nonzero numeric limitations for FGD wastewater. Some commenters claimed 
the need to discharge from a zero-discharge system after retirement. 
While EPA is requiring zero discharge of pollutants from CRL during 
active operations, this is based, in part, on the ability of active 
EGUs to use clean permeate or distillate resulting from CRL treatment 
either in an FGD absorber or as boiler makeup water. After the last EGU 
at a facility retires, it may become necessary for a facility to 
discharge the permeate or distillate from its zero-discharge treatment 
system. Thus, the EPA is transferring the BAT limitations from the 2020 
VIP and 2015 NSPS to provide more flexibility to a plant post-
retirement. Plants may discharge CRL permeate after retirement subject 
to the 2020 rule VIP limitations designed for permeate from a membrane 
filtration system. Alternatively, plants may discharge CRL distillate 
after retirement subject to the 2015 rule NSPS limitations designed for 
distillate from a thermal treatment system.\95\
---------------------------------------------------------------------------

    \95\ SDEs and thermal systems that do not generate a distillate 
would not require this flexibility.
---------------------------------------------------------------------------

    Economic achievability of zero-discharge systems. The EPA finds 
that the costs of zero-discharge systems for control of CRL discharges 
are economically achievable. For further discussion of the economic 
analysis, see sections VII.F and VIII, below.
    Non-water quality environmental impacts of zero-discharge systems. 
The EPA finds that the non-water quality environmental impacts 
associated with zero-discharge systems to control CRL discharges are 
acceptable. See discussion below in section VII.G and section X of this 
preamble.
    b. The EPA rejects less stringent technologies than zero-discharge 
systems as BAT for CRL.
    Except for the new subcategories for permanent cessation of coal 
combustion by 2034 and discharges of unmanaged CRL, discussed in 
sections VII.C.4 and VII.C.5 of this preamble, EPA is not selecting 
less stringent technologies than the zero-discharge systems discussed 
above. BAT is the ``gold standard'' for controlling water pollution 
from existing sources, and the Supreme Court has explained that BAT 
must achieve ``reasonable further progress'' toward the CWA's goal of 
eliminating pollution. See Southwestern Elec. Power Co. v. EPA, 920 
F.3d at 1003, 1006 (citing Nat'l Crushed Stone v. EPA, 449 U.S. at 75). 
The record shows that zero-discharge systems are available, are 
economically achievable, and have acceptable non-water quality 
environmental impacts. Therefore, with the exception of the new 
subcategory for permanent cessation of coal combustion by 2034, the EPA 
is not leaving BAT for determination on a case-by-case BPJ basis by the 
permitting authority. Similarly, except for the new subcategory for 
discharges of

[[Page 40227]]

unmanaged CRL, the EPA is not identifying as BAT the less stringent 
technology of chemical precipitation, as this technology would remove 
fewer pollutants than the BAT basis in this final rule, which the EPA 
has found is available, is achievable, and has acceptable non-water 
quality environmental impacts. Finally, the EPA is also rejecting the 
less stringent technologies of surface impoundments and chemical 
precipitation followed by a low hydraulic residence time biological 
treatment, as these systems would also remove fewer pollutants than the 
BAT basis in this final rule, which the EPA has found meets the 
requisite statutory requirements.
    c. The EPA selects zero-discharge systems as NSPS for CRL.
    At proposal, the EPA solicited comments on the propriety of 
revising NSPS for CRL based on decisions made with respect to BAT for 
CRL.\96\ The EPA did not receive any comments on its solicitation for 
updating NSPS for CRL. After considering all of the technologies 
described in this preamble and TDD section 7, and in light of the 
factors specified in CWA section 306, the EPA concludes that zero-
discharge systems represent BADCT for CRL at steam electric power 
plants, and the final rule promulgates NSPS based on these systems. 
More specifically, the BADCT technology basis for CRL is membrane 
filtration systems, SDEs, and thermal evaporation systems alone, or in 
any combination, including any necessary pretreatment (e.g., chemical 
precipitation) or post-treatment (e.g., crystallization).\97\ 
Furthermore, where a permeate or distillate is generated from the final 
stage of treatment, the technology basis is a process wherein this 
water would then be recycled back into the plant as either FGD makeup 
water or EGU makeup water.\98\ The record indicates that the zero-
discharge systems that serve as the basis for the final NSPS are well 
demonstrated. This is fully supported by the discussion of the 
availability of zero-discharge systems for identifying BAT, both as a 
whole and as stand-alone technologies, as described above in section 
VII.B.3 of this preamble. As discussed in the preceding BAT discussion, 
because CRL is expected to continue to be generated and discharged even 
after the retirement of the plant, the EPA is also using the BAT 
technology basis identified to establish nonzero numeric limitations 
following a plant's eventual retirement--limitations based on membrane 
filtration for CRL permeate and limitations based on thermal 
evaporation for CRL distillate.
---------------------------------------------------------------------------

    \96\ The EPA did not solicit comment on revising any other NSPS 
because the proposed BAT technology bases for FGD wastewater and BA 
transport water would be similar to the 2015 BADCT technology bases 
for these wastestreams. The final rule is consistent with the 
proposal in that way.
    \97\ While three main technologies are listed here and are used 
to evaluate costs and non-water quality environmental impacts, the 
list is not meant to exclude use of FA fixation, direct 
encapsulation, evaporation ponds, or other zero-discharge treatment 
options where a facility uses these technologies to meet the zero-
discharge standard established in this rule.
    \98\ The 2020 rule finalized a carve out from the definition of 
FGD wastewater applicable to ``treated FGD wastewater permeate or 
distillate used as boiler makeup water.'' The EPA is making the 
equivalent change to the definition of CRL for the same reasons the 
change was made to the definition FGD wastewater and to support 
consistency across these two zero-discharge wastewater streams. See 
85 FR 64675.
---------------------------------------------------------------------------

    The NSPS in the final rule poses no barrier to entry. This is due, 
first, to the fact that no new coal-fired power plants are expected to 
be built. As the EPA's Power Sector Trends Technical Support Document 
states:

    It is unlikely that new conventional coal-fired EGUs will come 
online in the US. The last year in which a new coal-fired EGU 
(greater than 25 MW) was completed was in 2014. There are no new 
announced plans to build new coal-fired EGUs.\99\
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    \99\ Available online at: https://www.epa.gov/system/files/documents/2023-05/Power%20Sector%20Trends%20TSD.pdf.

    This is consistent with EIA data \100\ and is due to the 
uncompetitive financial realities of coal-fired power. Existing coal is 
almost universally estimated to be more expensive than replacement 
capacity moving forward.\101\ Since no new coal-fired power plants are 
expected, updating NSPS to the same zero-discharge systems as BAT is 
more of a safeguard to ensure a consistent regulation of CRL, even if 
it likely will never apply.
---------------------------------------------------------------------------

    \100\ Available online at: https://www.eia.gov/todayinenergy/detail.php?id=54559#.
    \101\ Energy Innovation Policy & Technology LLC[supreg]. 2023. 
Coal Cost Crossover 3.0: Local Renewables Plus Storage Create New 
Opportunities for Customer Savings and Community Reinvestment. 
January. Available online at: https://energyinnovation.org/wp-content/uploads/2023/01/Coal-Cost-Crossover-3.0.pdf.
---------------------------------------------------------------------------

    Second, the final NSPS poses no barrier to entry based on the EPA's 
assessment of the possible impacts of the final NSPS on new sources 
using a comparison of the incremental costs of the final rule to the 
costs of hypothetical new generating units. The EPA developed NSPS 
compliance costs for new sources using a methodology similar to the one 
used to develop compliance costs for existing sources. The EPA's 
estimates for compliance costs for new sources are based on the net 
difference in costs between (1) wastewater treatment system 
technologies that would likely have been implemented at new sources 
under the previously established regulatory requirements and (2) those 
that would likely be implemented under the final rule. The EPA 
estimated that the incremental compliance costs for a new generating 
unit (capital and O&M) represent about one percent of the annualized 
cost of building and operating a new 650 MW coal-fired plant,\102\ with 
capital costs representing approximately one percent of the overnight 
construction costs, and annual O&M costs also representing one percent 
of the fuel and other O&M cost of operating a new plant.
---------------------------------------------------------------------------

    \102\ Energy Information Administration. 2024. Capital Cost and 
Performance Characteristics for Utility-Scale Electric Power 
Generating Technologies, January 2024. Available online at https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capital_cost_AEO2025.pdf.
---------------------------------------------------------------------------

    Finally, the EPA analyzed the non-water quality environmental 
impacts and energy requirements associated with the final BAT 
limitations for CRL. Since there is nothing inherently different 
between an existing and new source, the EPA drew on the analyses for 
existing sources and determined that NSPS based on the final rule BAT 
technologies have acceptable non-water quality environmental impacts 
and energy requirements. For further discussion of the non-water 
quality environmental impacts evaluated for BAT, see sections VII.G and 
X.
    The EPA did not retain chemical precipitation as the basis for NSPS 
for CRL because, under CWA section 306, NSPS reflect ``the greatest 
degree of effluent reduction . . . achievable.'' Zero-discharge systems 
are capable of eliminating all discharges associated with CRL, and they 
form the BAT technology basis used to establish limitations for 
existing sources of CRL discharges in this rule. Moreover, establishing 
NSPS for CRL based on zero-discharge systems does not add to the 
overall estimated cost of the rule because the EPA does not predict any 
new coal-fired generating units will be installed in the timeframe of 
the EPA's analyses.
4. Legacy Wastewater
    Except for the subcategory for legacy wastewater discharged from 
surface impoundments commencing closure after July 8, 2024, the EPA is 
reserving BAT basis for legacy wastewater at this time and instead is 
continuing to reserve BAT limitations for case-by case determination by 
the permitting authority, using its BPJ. This potential case-by-case 
outcome was explicitly

[[Page 40228]]

identified by the Fifth Circuit Court of Appeals as an alternative the 
EPA should have considered in the 2015 rule. Southwestern Elec. Power 
Company v. EPA, 920 F.3d at 1021 (``[E]ven assuming a lack of data 
prevented the EPA from determining BAT for legacy wastewater, nothing 
required the agency simply to set impoundments as BAT. Instead, the EPA 
could have declined to set nationwide effluent guidelines for legacy 
wastewater and allowed BAT determinations to be made by each facility's 
permitting authority through the NPDES permitting process on a site-
specific basis.'') (citations omitted).
    In the 2015 rulemaking and subsequent litigation, petitioners 
argued that the EPA lacks authority to establish differentiated 
limitations for legacy wastewater, as compared to newly generated 
wastewater, because the text of the CWA does not contain specific 
distinctions based on when wastewater is produced. As explained in the 
2015 rule and in briefs before the Fifth Circuit Court of Appeals, 
however, nothing in the statute requires the EPA to establish the same 
technology basis for each wastestream within a point source category 
when establishing limitations.\103\ The CWA directs the EPA to take 
into account a variety of factors in establishing the best available 
technology economically achievable, including,'' ``process changes,'' 
``non-water quality environmental impacts,'' and ``such other factors 
ats the Administrator deems appropriate.'' 33 U.S.C. 1314(b)(2)(B). As 
discussed further below, the rule's differentiated BAT limitations for 
legacy wastewater are based on the changes happening at plants under 
the CCR regulations in relation specifically to legacy wastewater, 
which by and large is contained in surface impoundments. The EPA's 
conclusion that it is appropriate to set different BAT limits for 
legacy wastewater based on the different way this wastewater is handled 
in response to the CCR regulations is within the Agency's broad 
discretion under the statute. See Texas Oil & Gas Ass'n v. EPA, 161 
F.3d 923, 934 (5th Cir. 1998) (``EPA has significant discretion in 
deciding how much weight to accord each statutory factor under the 
CWA.'').
---------------------------------------------------------------------------

    \103\ This was a question the Fifth Circuit never reached 
because it vacated and remanded the 2015 legacy wastewater 
limitations on other grounds. Southwestern Elec. Power Co. v. EPA, 
920 F.3d at 1015.
---------------------------------------------------------------------------

    In contrast to the environmental group petitioners' arguments 
discussed above that legacy wastewater should be subject to the same 
limitations and standards as newly generated wastewater, some 
commenters on the 2023 proposed rule argued that the EPA lacks 
authority to establish BAT limitations on legacy wastewater at all 
since it was previously generated and ``treated'' under the prior ELGs. 
The CWA regulates discharges of pollutants, 33 U.S.C. 1311(a), and 
nothing in the CWA prohibits the EPA from applying discharge 
limitations to previously generated (and even ``treated'') wastewater. 
The Commenters' view would lead to results under the statute that 
Congress could not have intended. Under commenters' reading, if 
wastewater was treated to meet BPT regulations, it could not be treated 
any further to meet more stringent BAT regulations. This would be 
contrary to the CWA's technology-forcing scheme. In this case, the 
treatment referred to by the commenter is treatment using a surface 
impoundment. The Fifth Circuit has strongly suggested that, in light of 
the EPA's 2015 finding that surface impoundments are ``largely 
ineffective'' at removing dissolved metals, to achieve the BAT 
standard, something more than limitations based on surface impoundments 
should be required of legacy wastewater discharges. Southwestern Elec. 
Power Co. v. EPA, 920 F.3d at 1015, 1017.
    While commenters claim that it is not fair for plants to be subject 
to new limitations for wastewater generated when the plant was making 
operational decisions under a prior ELG, as further discussed below, 
the EPA finds that it is economically achievable for certain plants to 
meet additional limitations on their legacy wastewater, as required for 
Best Available Technology Economically Achievable under the CWA. 
Moreover, the EPA has considered the unique situation in which some 
plants may have already closed and, therefore, lack an active revenue 
stream to pay for additional pollution controls. For the case-by-case 
legacy wastewater limitations discussed below, permitting authorities 
can consider the site-specific economic achievability of particular 
requirements when identifying BAT. For the legacy wastewater 
subcategory described in section VII.C.6 of this preamble, the BAT 
limitations are based on chemical precipitation. The EPA rejected more 
stringent limitations than those based on chemical precipitation, 
alone, in part because of the higher costs of more advanced treatment-
based limitations, given that many legacy discharges may occur after a 
plant ceases operating.
    The EPA also disagrees with commenters that plants could not have 
known they might be subject to more stringent limits for wastewater 
already generated. The CWA has always regulated discharges, and plants 
should have known that their discharges would potentially be subject to 
more stringent requirements, given that the CWA envisions progressively 
more stringent limits to meet progressively more stringent standards. 
See Texas Oil & Gass Ass'n v. EPA, 161 F.3d at 927; Southwestern Elec. 
Power Co. v. EPA, 920 F.3d at 1006-07. Plants should have known that 
the limitations to which their discharges are subject might changes, as 
ELGs are established or revised, including to account for technological 
advancements. See CWA sections 301(d) and 304(b), 33 U.S.C. 1311(d) and 
1314(b). Indeed, water quality concerns might require water quality-
based effluent limitations that change over time as well.
    In the first subsection immediately below, the EPA discusses its 
rationale for reserving BAT limitations to be derived on a BPJ-basis to 
control legacy wastewater. In the second subsection, EPA discusses why 
it is not selecting surface impoundments as BAT for legacy wastewater. 
In the final subsection, the EPA discusses why it is not selecting more 
stringent technologies as BAT for legacy wastewater, except for a 
subcategory of legacy wastewater discussed in section VII.C.6 of this 
preamble. For further discussion of the subcategory for legacy 
wastewater discharged from surface impoundments commencing closure 
after July 8, 2024, see section VII.C.6 of this preamble.
a. BPJ-based BAT Limitations Will Continue To Apply to Legacy 
Wastewater
    The EPA is finalizing the approach proposed for this rule for 
legacy wastewater: permitting authorities will continue to develop BAT 
limitations on a case-by-case basis, using their BPJ. The EPA received 
comments supporting and opposed to the case-by-case approach. 
Commenters opposing this approach came from two perspectives. Some 
industry commenters believed that only BPT and water quality-based 
effluent limitations currently apply to legacy wastewater and that the 
EPA should finalize this approach. In contrast, other commenters viewed 
the proposed BPJ approach as impermissibly allowing permitting 
authorities to select surface impoundments as BAT. In the alternative, 
these commenters recommended that the EPA formally constrain the 
permitting authorities' discretion when determining BAT with a BPJ 
analysis. Commenters that supported the EPA's proposed approach

[[Page 40229]]

opposed selecting more stringent technologies as BAT in large part 
because of the timelines for completing closure under the CCR 
regulations. Some commenters also stated that most or all legacy 
wastewater will have been discharged prior to the effective date of any 
final rule. Finally, commenters from multiple perspectives universally 
opposed certain definitional changes that the EPA solicited comment on 
at proposal, involving establishment of two new classes of legacy 
wastewaters called surface impoundment decant wastewater and surface 
impoundment dewatering wastewater. Their comments opposed the changes 
because of the unclear delineation between the two types of legacy 
wastewater and the view that all legacy wastewater should be regulated 
the same.
    After considering the comments received and evaluating the record 
in light of the factors specified in CWA section 304(b)(2)(B), the EPA 
finds that no single technology is technologically available and 
economically achievable for control of pollutants in legacy wastewater, 
except for legacy wastewater from a subcategory of EGUs as discussed in 
section VII.C.6 of this preamble. Because of process changes happening 
at plants in the form of ongoing and soon-to-be-completed surface 
impoundment closures under the CCR regulations, the EPA finds that it 
is infeasible to finalize a nationwide BAT limitation for legacy 
wastewater mid-closure. The statute requires BAT to reflect what is 
technologically available, is economically achievable, and has 
acceptable non-water quality environmental impacts based on 
consideration of several factors, including ``process changes,'' ``non-
water quality environmental impacts,'' and ``such other factors'' as 
the Administrator deems appropriate. Because many facilities with 
surface impoundments are in the process of closing their surface 
impoundments under the CCR regulations (regulations that create 
safeguards around the disposal of solid waste, as explained in section 
IV.E of this preamble), the technology that represents BAT for legacy 
wastewater treatment is likely to vary from site to site depending on 
several factors. These factors include, but are not limited to, the 
types of wastes and wastewaters present, the characteristics of the 
legacy wastewater in each layer of a surface impoundment, the amount of 
legacy wastewater remaining to be treated in a surface impoundment, the 
treatment already available on site, the treatment option costs, the 
extent to which CWA requirements could interfere with closure 
timeframes required under the CCR regulations, the potential for 
increased groundwater contamination, and the potential for increased 
discharges through groundwater that are determined to be the functional 
equivalent of direct discharges (FEDDs) to a WOTUS.
    The effect of the EPA declining to identify a nationally applicable 
BAT for this wastewater is that permitting authorities will continue to 
establish site-specific technology-based effluent limitations using 
their BPJ.\104\ Because the limitations under this rule are required to 
be derived on a site-specific basis, taking into account the requisite 
BAT statutory factors and applying them to the circumstances of a given 
plant, these case-by-case limitations would by definition be 
technologically available and economically achievable and have 
acceptable non-water quality environmental impacts, where the 
permitting record reflects that such is the case. While the dynamic and 
changing nature of this wastestream at this time means there is no 
typical site, given the CCR regulations' closure requirements, the EPA 
agrees with commenters that, were permitting authorities to choose 
surface impoundments as the BAT technology for a particular site using 
the same rationale that the EPA put forth in 2015, this would run afoul 
of the Fifth Circuit's decision that found selecting surface 
impoundments as BAT was arbitrary, capricious, and inconsistent with 
the ``technology-forcing mandate of the CWA.'' Southwestern Elec. Power 
Company v. EPA, 920 F.3d at 1017.
---------------------------------------------------------------------------

    \104\ Because some commenters took issue with the EPA's 
statements in the proposed rule that, under the prior regulations in 
effect, BAT limitations based on a permitting authority's BPJ are 
appropriate for legacy wastewater, the Agency is explicitly 
reserving BAT limitations for legacy wastewaters in the regulatory 
provisions setting forth BAT requirements for FGD wastewater, BA 
transport water, FA transport water, and flue gas mercury control 
wastewater to avoid any ambiguity regarding whether BPJ applies.
---------------------------------------------------------------------------

    Factors the permitting authority must consider when establishing 
BPJ-based BAT effluent limitations for legacy wastewater are specified 
in section 304(b) of the CWA, 33 U.S.C. 1314(b), and 40 CFR 125.3(d). 
The EPA solicited comment on whether it should explicitly promulgate, 
in regulatory text, specific elements related to these factors for this 
steam electric wastewater. While some commenters advocated for further 
restrictions to deter or even prohibit permitting authorities from 
selecting surface impoundments as BAT through a BPJ analysis, the CWA 
and EPA regulations already require the permitting authority to 
evaluate whether more stringent technologies are available, are 
economically achievable, and have acceptable non-water quality 
environmental impacts. Moreover, given existing case law and 
information known about more advanced technologies, the EPA believes 
that a permitting authority which chooses to select surface 
impoundments as BAT would face substantial legal risk unless it could 
justify its decision based on the BAT statutory factors. See 
Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1018 n.20 (``EPA may 
have been uncertain about what the precise BAT for legacy wastewater 
should be, but the record fails to explain why impoundments are BAT, if 
that term is to have any meaning.'').
    The EPA agrees with commenters that differentiating legacy 
wastewaters into two distinct classes in the manner the EPA solicited 
comment on at proposal (i.e., decant and dewatering wastewaters) is 
unnecessary and not useful; therefore, the EPA is not finalizing new 
definitions to distinguish classes of legacy wastewater. The proposal 
would have potentially doubled the number of BPJ analyses performed by 
permitting authorities--as there would have been two classes of legacy 
wastewater that each required BPJ determinations--without likely 
changing the ultimate outcome of treatment of the legacy wastewater as 
a whole. Moreover, it is doubtful that creating two new definitions of 
legacy would be useful given that, where a surface impoundment is 
already closing under the CCR regulations, both types of wastewater 
would likely be discharged before a new CWA permit incorporating the 
limitations in this final rule would take effect. Lastly, given the 
confusion commenters expressed over how to interpret the definitions, 
the EPA is concerned that finalizing these definitions would complicate 
implementation.
    The EPA also agrees with commenters that the vast majority of 
legacy wastewater likely has been, or will be, discharged pursuant to 
BPJ determinations under existing permits. Rapid closure of many of 
these surface impoundments is ongoing under the CCR regulations. The 
EPA notes that most surface impoundments had to cease receipt of waste 
by April 11, 2021, and commenced closure soon after. These surface 
impoundments were either unlined, in violation of location 
restrictions, or both. The EPA estimates that 398 of 507 such surface 
impoundments are less than 40 acres and thus must close within seven 
years of commencing closure (five years plus

[[Page 40230]]

a possible two-year extension).\105\ The remaining 109 are over 40 
acres and thus can receive additional two-year extensions. Even with 
the possibility of extensions, dewatering is one of the first steps of 
closure and, therefore, most of the 507 surface impoundments which have 
already begun the closure process will have completed dewatering before 
permitting authorities issue NPDES permits implementing this final ELG 
rule.
---------------------------------------------------------------------------

    \105\ See 40 CFR 257.102(f).
---------------------------------------------------------------------------

    Moreover, as is the case for all promulgated effluent limitations 
guidelines, the requirements for direct dischargers \106\ in this rule 
do not become applicable to a given discharger until they are contained 
in revised NPDES permits. NPDES permits are typically issued for the 
maximum allowed five-year permit term. Most permits are not immediately 
revised after the EPA issues a new ELG rule, rather permitting 
authorities incorporate the new ELG rule limitations at the time the 
next five-year permit is up for reissuance. In addition, it is not 
uncommon for permits to be administratively continued beyond the five-
year permit term if a permittee submits a timely permit renewal 
application, in which case the existing permit stays in effect until a 
new permit is effective. See 40 CFR 122.6. Thus, even if these new ELG 
requirements were implemented into NPDES permits in a timely manner 
following their effective date on July 8, 2024, the vast majority of 
legacy wastewater would have been discharged or will be discharged 
pursuant to BPJ determinations in existing permits rather than pursuant 
to any regulations the EPA might promulgate. Much, if not all, of the 
remaining legacy wastewater is included in the 19 surface impoundments 
expected to be covered by the subcategory for legacy wastewater 
discharged from surface impoundments commencing closure after July 8, 
2024. This subcategory is further described in section VII.C.6 of this 
preamble.
---------------------------------------------------------------------------

    \106\ Indirect dischargers (those who discharge to POTWs) are 
subject to pretreatment standards that are directly implemented and 
enforceable. See CWA section 307, 33 U.S.C. 1317; 40 CFR part 403.
---------------------------------------------------------------------------

    Reserving BAT limitations for this legacy wastewater to be 
developed by the permitting authority on a BPJ-basis would allow 
permitting authorities, on a case-by-case basis, to impose more 
stringent limitations (including potentially zero-discharge 
limitations) based on technologies that remove more pollutants than the 
previously promulgated BPT limitations based on surface impoundments, 
depending on what is technologically available and economically 
achievable for individual facilities. In this way, the final rule does 
not ``freeze impoundments in place as BAT for legacy wastewater,'' a 
criticism of the 2015 rule's legacy wastewater limitations by the Fifth 
Circuit, which acknowledged that BAT has in inbuilt `reasonable further 
progress' standard and that `BPT serves as the prior standard with 
respect to BAT.' Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1017 
(citation omitted). Moreover, this final rule record includes 
information about technologies beyond surface impoundments and their 
application to legacy wastewater that could be useful to permitting 
authorities in making their determinations.
    b. The EPA rejects surface impoundments as BAT for legacy 
wastewater.
    The EPA is not selecting surface impoundments as the BAT basis for 
controlling discharges of legacy wastewater because there are more 
effective technologies for controlling discharges that some plants 
could use. Several plants described in the record employ technologies 
ranging from chemical precipitation to zero-discharge systems for 
legacy wastewaters. The previously promulgated BPT limitations are 
based on surface impoundments. As the Fifth Circuit has acknowledged, 
BPT is merely the first step toward the CWA's pollution reduction goals 
and provides the ``prior standard'' against which the stricter BAT is 
to be measured. Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1006 
(citing Nat'l Crushed Stone, 449 U.S. at 69, 77 & n.14). Therefore, the 
EPA is retaining the current case-by-case BAT approach rather than 
selecting surface impoundments.
    c. The EPA rejects specific, across-the-board technologies more 
stringent than surface impoundments as BAT for legacy wastewater.
    The EPA is not selecting more stringent, one-size-fits-all 
technologies, such as chemical precipitation, biological treatment, 
membrane filtration, thermal evaporation, and/or spray dryer 
evaporation as the BAT basis for controlling discharges of legacy 
wastewater, except for the legacy wastewater described in section 
VII.C.6 of this preamble. As explained previously, many plants with 
legacy wastewater have already begun closure of their surface 
impoundments under the CCR regulations. These plants are in different 
stages of the dewatering process, as they are trying to meet their 
closure deadlines under the CCR regulations. Requiring limitations 
based on a more stringent BAT technology basis at all plants that are 
in the process of dewatering when their permit is renewed but before 
closure is complete would jeopardize their ability to meet their 
closure deadlines under the CCR regulations. This is because having to 
consider and add one or more treatment components would slow the 
dewatering process, at some plants more than others. If plants could 
not meet their closure deadlines under the CCR regulations, this would 
be an unacceptable non-water quality environmental impact.
    Furthermore, some zero-discharge technologies are not available to 
plants after they cease coal combustion, even if the discharge of 
legacy wastewater will occur after that date. For example, while 
Boswell Energy Center has installed and is operating an SDE for 
treating several wastewaters including legacy wastewater, this SDE 
would not be available to a facility that no longer produces power 
because it is designed and operated using a slipstream of the hot flue 
gas to evaporate the wastewater, a heat source no longer available 
after retirement.
    Although the EPA cannot determine that a particular technology is 
available within the meaning of CWA section 304(b) to treat the legacy 
wastewater described in this section, the Agency could expect the 
permitting authority to select more stringent technologies than surface 
impoundments on a site-specific basis. In some cases, the stage of 
closure and realities on site may point to use of a more stringent 
technology. For example, a facility in early closure stages may be able 
to lease commercial, off-the-shelf equipment to treat its legacy 
wastewater. Alternatively, permitting authorities could assess the 
technologies a plant already uses for treatment of other wastewaters 
and determine that the legacy wastewater could be readily directed to 
an existing treatment system.
5. Definitional Changes
    The EPA is finalizing two definitional changes. The first 
definitional change applies to high intensity, infrequent storm events 
as described in subsection (a), below. The second definitional change 
applies to decommissioning wastewater from FGD wastewater treatment 
equipment and ash handling equipment as discussed in subsection (b), 
below.
a. Definitional Change for High-Intensity, Infrequent Storm Events
    The EPA is finalizing a definitional change for all the wastewaters 
for which the Agency is establishing zero-

[[Page 40231]]

discharge limitations in this final rule: FGD wastewater, BA transport 
water, and CRL. Specifically, the EPA is excluding from the definitions 
of these wastewaters any discharges which are necessary (i.e., cannot 
be managed with existing systems or practices) as the result of high-
intensity, infrequent storm events exceeding a 10-year storm event of 
24-hour or longer duration (e.g., a 10-year, 30-day storm event). The 
EPA is specifically selecting this duration storm event as this is a 
consistent duration storm event to the storm event described in 40 CFR 
part 423 with respect to regulation of coal pile runoff.\107\ Due to 
these definitional exclusions, such discharges would not be subject to 
the zero-discharge requirements that otherwise apply to FGD wastewater, 
BA transport water, and CRL under this final rule. Instead, these 
discharges would be considered a ``low volume waste source'' and the 
TSS and oil and grease BPT limitations for such waste would apply, as 
well as any BAT limitations for the low volume waste source developed 
by a permitting authority using its BPJ. As discussed in section 
XIV.C.4 of this preamble, the EPA is also finalizing reporting and 
recordkeeping requirements that facilities must comply with when they 
discharge during these high intensity, infrequent storm events, which 
are intended to demonstrate that the discharge is necessary and to 
provide information about the time, place, and volume of the necessary 
discharge. Each of the wastestreams subject to this definitional change 
is discussed in turn below.
---------------------------------------------------------------------------

    \107\ 40 CFR 423.12(b)(10) (BPT limitations) and 423.15(a)(12) 
and (b)(12) (NSPS) provide, ``Any untreated overflow from facilities 
designed, constructed, and operated to treat the volume of coal pile 
runoff which is associated with a 10, year, 24 hour rainfall event 
shall not be subject to'' the TSS limitations or standards that 
otherwise apply to discharges of coal pile runoff.
---------------------------------------------------------------------------

    At the outset, the EPA notes that stormwater is not FGD wastewater, 
BA transport water, or CRL, though it may mix with these wastewaters. 
Instead, the EPA describes stormwater on its website as follows:

    Stormwater runoff is generated from rain and snowmelt events 
that flow over land or impervious surfaces, such as paved streets, 
parking lots, and building rooftops, and does not soak into the 
ground. The runoff picks up pollutants like trash, chemicals, oils, 
and dirt/sediment that can harm our rivers, streams, lakes, and 
coastal waters. To protect these resources, communities, 
construction companies, industries, and others, use stormwater 
controls, known as best management practices (BMPs). These BMPs 
filter out pollutants and/or prevent pollution by controlling it at 
its source.\108\
---------------------------------------------------------------------------

    \108\ Available online at: https://www.epa.gov/npdes/npdes-stormwater-program.

    Since stormwater picks up different pollutants, for example dirt, 
it has inherently different characteristics from the wastewaters 
regulated in this final rule. Furthermore, larger storm events result 
in a higher fraction of stormwater and stormwater pollutants as 
compared to the pollutants in FGD wastewater, BA transport water, and 
CRL. Taken together, this means that during these high intensity, 
infrequent storm events, a requirement to treat to zero discharge would 
essentially be requiring higher and higher amounts of stormwater 
treatment, rather than treatment of the pollutants of concern in these 
three wastewaters.
    Based on the CWA statutory factors of ``process employed,'' 
``engineering aspects'' of control techniques, and non-water quality 
environmental impacts, the EPA concludes that a zero-discharge 
requirement for discharges of CRL, FGD wastewater, and BA transport 
water that cannot be managed with existing systems or practices during 
a high-intensity, infrequent storm event is not warranted. The CWA 
statutory factor of ``cost'' provides additional support for EPA's 
decision. Regarding CRL, the EPA solicited comment on the potential to 
exclude discharges from the definition of CRL to account for specific 
storm events. Several commenters expressed concerns that CRL collection 
systems in general, or at specific facilities, collected both CRL and 
stormwater. In such cases, segregation of the CRL and stormwater may 
not be possible for treatment. One specific design of concern to these 
commenters, although not the only problematic one, employs a chimney 
system to channel stormwater vertically through a landfill in order to 
minimize contact with the ash, and thus minimize the generation of CRL 
in the first place. In some cases, this design is used voluntarily as a 
BMP to reduce the potential for groundwater contamination; in other 
cases, commenters pointed out that such a design is required by state 
law. The EPA agrees that minimizing the formation of CRL promotes the 
goals of both RCRA and the CWA by reducing the pollutants mobilized 
into CRL that can potentially migrate into groundwater, be discharged 
into surface water, or both. It would be impracticable (and in some 
cases may also violate state law) for a facility with such a landfill 
design to rip out these chimney structures in order to segregate CRL 
from stormwater, but more importantly it would result in the 
mobilization of more pollutants into CRL (because more water would 
percolate through the CCR), not less.
    Alternatively, it may be possible to design larger treatment 
systems that can handle even the additional flows resulting from the 
high intensity, infrequent storm events specified in the definitional 
change described above. However, here too the record does not support 
zero-discharge systems as BAT to control necessary discharges of CRL 
during the storm events described. First, the rainfall that reached the 
collection system via the chimneys would either be pristine rainfall or 
rainfall contaminated by runoff sediment, and thus would not be CRL. 
Second, CRL generated by the rainfall that does percolate through the 
landfill would not reach the leachate collection system at the same 
time as the rainfall that passes immediately through the chimneys. 
Depending on the infiltration rate and depth of the CCR, it may take 
hours, days, weeks, or longer for the additional CRL generated by the 
rainfall to ultimately pass through the layers of CCR and into the 
leachate collection system below. Until the leachate from the storm 
event migrates to the leachate collection system, the treatment system 
could be treating mostly or entirely non-CRL stormwater.
    The EPA concludes that the considerations discussed above are 
sufficient to support its decision to exclude necessary discharges of 
CRL during high intensity, infrequent storm events from the definition 
of CRL and, thus, from the zero-discharge requirement that would 
otherwise apply to CRL. The EPA also notes that cost is a statutory 
factor that it must consider when establishing BAT, and that treatment 
of the higher flows comprised of primarily non-CRL during such high 
intensity, infrequent storm events would be more costly. EPA examined 
the data in the National Oceanic and Atmospheric Administration's 
Precipitation Frequency Data Server.\109\ The amount of precipitation 
for a storm event in the 10-year to 25-year storm event range will be 
approximately double that of a 1-year storm event. It approximately 
doubles yet again for something even more extreme such as a 1,000-year 
storm event. Thus, were the EPA not to finalize a definitional change 
related to high-intensity, infrequent storm events, a facility would be 
forced to construct a system at least double the size, but potentially 
much larger, in order to manage volumes from these low-probability of 
occurrence

[[Page 40232]]

precipitation events. As a result, costs could at least double.\110\ 
The doubling of costs to have a system available to manage volumes from 
these low-probability events occurring once every 25 or 200 years would 
be a wholly disproportionate costs per day in use when compared to the 
costs actually considered in the EPA's cost estimates, costs that 
already treat the average annual flows of CRL under the more common 
storm events to zero discharge approximately nine years and 364 days 
out of every 10 years.\111\ The EPA views the high cost of treating CRL 
discharges that cannot be managed by an existing zero-discharge system 
or practices during a high intensity, infrequent storm event as an 
additional factor supporting the EPA's decision to exclude such 
discharges from the definition of CRL.
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    \109\ Available online at: https://hdsc.nws.noaa.gov/pfds/.
    \110\ Volume is one of the primary inputs to the EPA's cost 
models of zero-discharge systems. The relationships are not linear, 
but costs do increase at a similar enough rate for purposes of the 
illustrative argument above. For more information on the specific 
cost estimates the EPA used, see section 5 of the TDD.
    \111\ Furthermore, doubling the costs of these systems would not 
be justified as the CRL, and thus the pollutants in CRL, would not 
reach the leachate collection system until much later. Instead, this 
larger system would be underutilized for years or decades at a time, 
only to treat a wastestream composed of mostly non-CRL wastewater on 
the infrequent occasion that it was ultimately called upon just for 
the sake of saying that the system eliminated all CRL discharges. 
Courts have recognized that while CWA section 301 is intended to 
help achieve the national goal of eliminating the discharge of all 
pollutants, at some point the technology-based approach has its 
limitations. See Am. Petroleum Inst. v. EPA, 787 F.2d 965, 972 (5th 
Cir. 1986) (``EPA would disserve its mandate were it to tilt at 
windmills by imposing BAT limitations which removed de minimis 
amounts of polluting agents from our nation's waters . . . .'').
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    The definitional change discussed for CRL is also appropriate for 
FGD wastewater. The EPA solicited comment on a zero-discharge 
requirement for discharges of FGD wastewater, including the 
availability of zero-discharge systems and ability of plants to meet 
zero-discharge limitations. The EPA received one comment suggesting 
that a zero-discharge requirement for FGD wastewater could force an 
offline plant to operate its coal-fired boilers for the sole purpose of 
recycling the excess water generated in its FGD treatment system during 
a storm event. The EPA acknowledges that some FGD treatment systems 
include open-air tanks and a few include lined surface impoundment 
pretreatment to increase physical settling. In these scenarios, it is 
possible that stormwater will increase the need to recycle the clean 
permeate or distillate from a zero-discharge system at a time when the 
plant is offline.\112\ This scenario does raise concerns that there 
might be limited instances in which a discharge is necessary or 
otherwise might result in a plant running when it is not needed. This 
could result in unnecessary air emissions, a non-water quality 
environmental impact that the EPA is required to consider.
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    \112\ Recall that recycling of the permeate or distillate into 
the FGD system or the boiler is part of the zero-discharge system 
technology basis.
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    The EPA also notes that several facilities already co-treat FGD 
wastewater and CRL.\113\ Nothing in this final rule would prohibit 
facilities from achieving zero discharge of these two wastewaters with 
a single system. Therefore, the EPA expects that, where there are 
economies of scale, facilities may elect to co-treat these wastewaters. 
While nothing in the final rule would prohibit such co-treatment, not 
finalizing a stormwater flexibility for FGD wastewater where such 
flexibility exists for CRL, and a discharge is necessary for the co-
treated CRL, could make such co-treatment impracticable. Furthermore, 
just as with CRL, discharges during high intensity, infrequent storm 
events would consist primarily of rainfall and runoff rather than of 
FGD wastewater. For the reasons above, the EPA finds that zero-
discharge systems are not BAT for discharges of FGD wastewater that 
cannot be managed with existing systems or practices during these high 
intensity, infrequent storm events.
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    \113\ Other commenters that do not yet have co-treatment also 
suggested that co-treatment be allowed.
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    Finally, the definitional change discussed above for CRL and FGD 
wastewater is appropriate for BA transport water as well. The EPA 
solicited comment on the potential need for purges from a closed-loop 
BA handling system, including purges related to precipitation events, 
which were a basis for including a purge allowance in the 2020 rule. 
The EPA's record shows that remote MDS systems can install roofing to 
mitigate the need to discharge during storm events, and this feature is 
included in the Agency's cost estimate. One commenter provided 
information about the necessary cooling received from its open air 
remote MDS and suggested that it may need to install expensive heat 
exchangers to make up for the lost cooling once a roof is installed. 
The EPA agrees that cooling BA (a waste so hot that is sometimes 
generated in molten form) is one of the primary functions of a BA 
handling system. While this comment did not provide data showing that 
cooling would fall enough to jeopardize the ability to recycle 
wastewater, to the extent that roofing could affect the ability of a 
remote MDS to return water cool enough to quench BA,\114\ the EPA would 
agree that this could jeopardize the ability of that system to attain 
zero discharge during high intensity, infrequent storm events.
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    \114\ The commenter stated that its facility needed water below 
140 degrees Fahrenheit in order to sufficiently cool its BA.
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    The EPA also acknowledges that some BA handling systems must 
recycle some BA into their FGD wastewater treatment systems either by 
design or to manage the volume of water or chemistry of water in the 
closed-loop system. For the reasons stated above finding that a 
definitional change is warranted for FGD wastewater, it would also make 
sense to have a definitional change for BA transport water, especially 
to the extent that the BA transport water in closed-loop systems is 
used as FGD makeup water to comply with the zero discharge-
requirements. For the reasons above, the EPA finds that zero-discharge 
systems are not BAT for BA transport water discharges that cannot be 
managed with existing systems or practices during high intensity, 
infrequent storm events.
    While the previous considerations are sufficient to support the 
Agency's decision to exclude necessary discharges of BA transport water 
during high intensity, infrequent storm events from the definition of 
BA transport water and, thus, from the zero-discharge requirement that 
would otherwise apply to BA transport water, the EPA notes that the 
statutory factor of cost also supports the EPA's decision. Remote MDS 
systems are not the only systems that the EPA estimates will operate as 
closed-loop systems. At some facilities, larger settling systems such 
as concrete basins have already been constructed. In contrast to MDS 
systems, the EPA acknowledges that its cost estimates assume that some 
non-MDS wet systems (e.g., dewatering bins, lined surface impoundments, 
basins) would make low-cost changes to recirculate BA transport water 
rather than install a new BA handing system. A roof or other cover over 
surface impoundments or basins that could be acres in size would be 
cost prohibitive at such sites.
    In summary, after considering public comments and the facts and 
analyses in the record, and in light of the requirements for the EPA to 
consider several statutory factors (including the process employed at 
the facility, the engineering aspects of the application of various 
types of control techniques, and

[[Page 40233]]

non-water quality environmental impacts) the EPA rejects zero-discharge 
systems as BAT to control necessary discharges of FGD wastewater, BA 
transport water and CRL mixed with stormwater during high intensity, 
infrequent storm events exceeding a 10-year storm event of 24-hour or 
longer duration (e.g., a 30-day storm event). The EPA's decision is 
further supported after considering the associated costs. While the EPA 
is excluding necessary discharges resulting from such storm events from 
the definitions of CRL, FGD wastewater, and BA transport water, this 
does not mean that no limitations apply to these discharges. As low 
volume waste sources (which are defined in 40 CFR part 423 as 
wastewater from all sources except those for which specific limitations 
or standards are otherwise established in this part), these discharges 
are subject to the BPT limitations for low volume waste sources as well 
as any BAT limitations developed by the permitting authority on a BPJ 
basis.
    Furthermore, the EPA notes that facilities would still be required 
to follow any stormwater requirements. High-intensity, infrequent storm 
events are currently addressed in the 2021 Multi-Sector General Permit 
(MSGP), the most recent to address industrial stormwater, including 
stormwater at steam electric power plants.\115\ The MSGP requires a 
Stormwater Pollution Prevention Plan (SPPP), which is developed at each 
individual facility and is therefore tailored to the types and 
frequencies of storms experienced at each facility. This makes sense as 
a site prone to hurricanes may take different stormwater precautions 
than a site located in an arid climate.\116\ As a result of site-
specific permit requirements or voluntary efforts, some steam electric 
facilities already exceed the performance of a 10-year, 24-hour design 
standard and would have even less frequent stormwater-related discharge 
needs than envisioned by the definitional change in this final rule. 
For example, in a recent BA transport water purge request for the Four 
Corners Power Plant, the utility demonstrated the ability to fully 
recycle under a 10-year storm event, and only showed the need for 
discharge during a 100-year storm event.
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    \115\ Available online at: https://www.epa.gov/npdes/stormwater-discharges-industrial-activities-epas-2021-msgp.
    \116\ While climate change may be driving more extreme storm 
events in some areas, it is possible that, given this design and the 
age of the facility, the facility will never experience a situation 
where a stormwater-related discharge under this rule would be 
required before its retirement from service.
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    For the final rule, in addition to requiring facilities to meet 
limitations applicable to low volume waste sources, to ensure 
facilities are not backing away from more protective management 
practices, the EPA is requiring that any necessary discharges of CRL, 
FGD wastewater, or BA transport water resulting from such a high-
intensity, infrequent storm event be accompanied by an official 
certification statement that includes information that these discharges 
were necessary (i.e., could not be managed with existing systems or 
practices). Importantly, nothing in this definitional change or the 
associated reporting and recordkeeping requirement changes a facility's 
obligations for stormwater management under its current permit or 
general permit. For further discussion of this reporting and 
recordkeeping requirement, see section XIV.C.4 of this preamble.
b. Definitional Change for Decommissioning Wastewater
    When the EPA finalized non-zero limitations for FGD wastewater and 
BA transport water in the 2020 rule, facilities could discharge these 
wastewaters when decommissioning equipment after retirement. The EPA 
proposed zero-discharge limitations and at proposal did not 
specifically address the scenario in which plants may be 
decommissioning their zero-discharge treatment equipment. One commenter 
said that wastewater must be discharged from such equipment at the time 
of decommissioning and recommended that the Agency either retain the 
2020 rule purge allowance or finalize an end-of-life flexibility that 
the EPA proposed in 2019 for ``wastewater present in equipment when a 
facility is retired from service.'' Another commenter, in the context 
of the permanent cessation of coal combustion subcategory, suggested 
that the Agency allow facilities to discharge wastewaters for 120 days 
after permanently ceasing coal combustion.
    The EPA agrees with the commenter that, given the zero-discharge 
limitations being finalized for FGD wastewater and BA transport water 
in this rule, an end-of-life flexibility for certain discharges is 
warranted. More specifically, the EPA finds a limited definitional 
change, appliable to all EGUs, to allow one-time discharges associated 
with decommissioning an FGD wastewater treatment system or BA handling 
system after retirement is appropriate. Part of the basis for the zero-
discharge limitations in this rule is tied to the ability of an active 
plant to recycle the wastewaters back into the plant (e.g., as FGD 
makeup water). This is no longer the case when a facility retires. 
Furthermore, as discussed in the subsequent sections VII.C.3 and 
VII.C.4, the Agency is finalizing a tiered set of zero-discharge 
limitations for FGD wastewater and BA transport water at EGUs 
permanently ceasing coal combustion, but it is including time that 
allows for discharges of these wastewaters up to 120 days after the EGU 
ceases coal combustion, due to the technical constraints of achieving 
zero-discharge when active operations have ceased. Because there is no 
material difference in residual discharges from a decommissioned system 
at a plant retiring before the December 31, 2028, or December 31, 2034, 
dates in the permanent cessation of coal combustion subcategories, as 
compared to a plant retiring after those dates, it is consistent to 
treat facilities retiring before and after those dates the same. Thus, 
the EPA is excluding wastewater removed from wastewater treatment or 
ash handling equipment within the first 120 days of decommissioning the 
equipment from the definitions of FGD wastewater and transport water.
    While the EPA is excluding this narrow class of wastewaters from 
the definitions of FGD wastewater and transport water, this does not 
mean that no limitations apply to discharges of such wastewater. As low 
volume waste sources (which are defined as wastewater from all sources 
except those for which specific limitations or standards are otherwise 
established in part 423), these discharges are subject to the BPT 
limitations for low volume waste sources, as well as any BAT 
limitations developed by the permitting authority on a BPJ basis. The 
EPA expects permitting authorities to consider any treatment 
technologies available at the plant in devising appropriate, case-by-
case BAT limitations.
6. Clarification on the Interpretation of 40 CFR 423.10 (Applicability)
    The EPA clarified at proposal that part 423 applies to discharges 
of legacy wastewater at inactive/retired power plants because the 
discharge of these wastewaters ``result[s] from the operation of a 
generating unit.'' \117\ This

[[Page 40234]]

interpretation is consistent with the EPA's longstanding view on the 
applicability of 40 CFR part 423 to inactive/retired plants, as well as 
with implementation by state permitting authorities. For example, in 
2016, the South Carolina Department of Health and Environmental Control 
reissued a permit to the South Carolina Electricity & Gas Company's 
Canadys Station Site (SC0002020) which stated, ``Because electricity is 
not being generated, 40 CFR part 423-Steam Electric Power Generating 
Point-Source Category will only apply to the discharge of legacy 
wastewaters.'' \118\ This is also consistent with the EPA's position 
provided in response to comments on the 2015 rule, in which the Agency 
stated:
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    \117\ 40 CFR 423.10. The provisions of the part apply to 
discharges resulting from the operation of a generating unit by an 
establishment whose generation of electricity is the predominant 
source of revenue or principal reason for operation, and whose 
generation of electricity results primarily from a process utilizing 
fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel 
(e.g., petroleum coke, synthesis gas), or nuclear fuel in 
conjunction with a thermal cycle employing the steam water system as 
the thermodynamic medium. This part applies to discharges associated 
with both the combustion turbine and steam turbine portions of a 
combined cycle generating unit.
    \118\ DHEC (Department of Health and Environmental Control). 
2016. FACT SHEET AND PERMIT RATIONALE: South Carolina Electric & Gas 
Company, Canadys Station Site. NPDES Permit No. SC0002020. May 16.

    EPA disagrees with the commenter that the `effluent limits would 
not apply' to discharges associated with retired units. For example, 
combustion residual leachate from landfills or surface impoundments 
containing combustion residuals from the time a generating unit was 
operating may occur and continue to be subject to the effluent 
limitations and standards requirements long after a generating unit 
is retired. Similarly, if an impoundment containing wastewater 
created while the generating unit was in operation (e.g., FGD 
wastewater, fly ash or bottom ash transport water) were to 
discharge, it would certainly be discharging wastewater `resulting 
from the operation of a generating unit.' In these instances, even 
though the generating unit may no longer be in operation, the 
wastewater is the result of its previous operation. Therefore, to 
the extent that steam electric power plants discharge wastestreams 
like this resulting from the operation of a generating unit, the 
ELGs do apply.\119\
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    \119\ U.S. EPA (Environmental Protection Agency). 2015. Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category: EPA's Response to Public Comments. 
September (SE05958A2) Page 3-563.

    Due to the proposed expansion of the RCRA CCR closure requirements 
to inactive surface impoundments at inactive (i.e., retired) plants, 
some of these surface impoundments are expected to dewater and 
therefore discharge legacy wastewater. At proposal, the EPA sought to 
clarify the applicability of part 423 to these legacy wastewaters since 
the Agency was soliciting comment on establishing nationally applicable 
BAT limitations rather than reserving BAT limitations to be developed 
on a case-by-case basis using a permitting authority's BPJ. As 
described in section VII.B.4 of this preamble, the EPA is instead 
declining to establish a nationwide BAT for discharges of legacy 
wastewaters, except for those discharges of legacy wastewater described 
in section VII.C.6 of this preamble (which would not occur at 
previously retired facilities), and it is thus continuing to reserve 
these BAT limitations for case-by-case decision-making using the 
permitting authorities' BPJ. As a result, the applicability of part 423 
to legacy wastewater discharges at inactive/retired plants would not 
impact the technology-based effluent limitations that apply to such 
discharges. In other words, the EPA's interpretation makes no 
difference to the ultimate disposition of legacy wastewater because, 
while the EPA interprets the rule to apply to legacy wastewater at 
inactive/retired steam electric power plants, the same BPJ approach 
called for in this rule would apply even if inactive/retired plants 
were not subject to part 423, given that BAT limitations must be 
developed on a BPJ basis where nationally applicable limitations do not 
apply. See CWA section 402(a)(1), 33 U.S.C. 1342(a)(1); 40 CFR 122.44, 
125.3. For further discussion of these additional legacy surface 
impoundments, see Legacy Wastewater at CCR Surface Impoundments--
Estimated Volumes, Treatment Costs, and Pollutant Loadings (DCN 
SE11503).
    At proposal, the EPA also solicited comment on whether there are 
other wastewaters that may continue to be discharged after the 
retirement of a facility and the generation of electricity is the ``but 
for'' cause of the discharge. Some commenters suggested that the Agency 
should clarify its interpretation to include additional wastewaters 
such as CRL, while others disagreed that this would be a permissible 
reading of the regulation. Commenters opposed to an expansive reading 
stated that other wastewaters such as CRL generated after closure were 
not generated as a result of operating a generating unit, but as the 
result of precipitation percolating through a waste management unit. 
Commenters opposed to an expansive reading also pointed to the history 
of 40 CFR part 423, suggesting that the EPA never intended to cover CRL 
from retired power plants as it never evaluated these facilities.
    The EPA agrees with commenters stating that discharges of CRL, even 
after retirement, result from the operation of a steam EGU. Were it not 
for operation of the unit, there could be no CRL discharges, regardless 
of whether there are other conditions that also exist to facilitate the 
discharge. Moreover, the EPA disagrees with commenters that the Agency 
never intended to cover CRL from retired power plants. As can be seen 
from the response to comment excerpt above, in 2015, the EPA expected 
that CRL discharges would continue to be subject to 40 CFR part 423 
after a facility retired. This is an important clarification that makes 
it clear that the limitations being finalized, including those for 
subcategories, would continue to apply after the facility retires. At 
the same time, two other statements from the 2015 rule record 
demonstrate that the Agency only intended the regulations to cover 
leachate prospectively from the 2015 rule. First, also in the 2015 
response to comments is the EPA's statement that:

    Retired landfills with or without leachate collection systems 
are not subject to the combustion residual leachate limitations and 
standards. EPA's methodology does not include costs or pollutant 
loadings removals from closed or retired landfills in its 
analyses.\120\
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    \120\ U.S. EPA (Environmental Protection Agency). 2015. Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category: EPA's Response to Public Comments. 
September (DCN SE05958A6) Page 7-82.

    Second, in the 2015 TDD, the EPA stated that ``combustion residual 
leachate from retired units is not regulated in the final rule.'' These 
two statements, together with the earlier response to comments 
discussed above, reflect the actual approach finalized in the 2015 
rule; namely, that only CRL generated and discharged at EGUs operating 
after the effective date of the 2015 rule was covered.\121\ The 
approach taken in this final rule is consistent with that of the 2015 
rule. That is, discharges of CRL (including unmanaged CRL) are covered 
prospectively by the final rule, but they will continue to be covered 
even after that facility and any waste management units generating CRL 
have retired. To the extent that a retired facility or closed waste 
management unit (WMU) is subject to 40 CFR part 423 but its discharges 
of CRL (including unmanaged CRL) are not subject to this rule, 
permitting authorities will instead continue to establish technology-
based effluent limitations that reflect BAT using their BPJ. Thus, 
these facilities will have to meet BAT limitations for their discharges 
of CRL that are available, are economically achievable,

[[Page 40235]]

and have acceptable non-water quality environmental impacts.\122\
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    \121\ This is the case even though the Fifth Circuit Court of 
Appeals vacated and remanded the BAT limitations for CRL finalized 
in 2015.
    \122\ The EPA conservatively included closed WMUs in its cost 
analyses when they were located at active facilities. CRL flows at 
composite-lined landfills could be comingled with the flows from 
adjacent, active landfill cells. Furthermore, unmanaged CRL flows 
could be caught up in site-wide pump-and-treat operations where both 
active and closed WMUs are present. Thus, while this is a 
conservative assumption, it is a reasonable estimate that helps 
ensure the costs of the rule are not underestimated and are 
economically achievable.
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C. Subcategories

    The EPA has authority in a national rulemaking to establish 
different limitations for different plants after considering the 
statutory factors listed in CWA section 304(b). See Texas Oil & Gas 
Ass'n v. EPA, 161 F.3d at 938 (stating that the CWA does not ``exclude 
a rule allowing less than perfect uniformity within a category or 
subcategory.'').
    In the 2015 rule, the EPA established subcategories for small EGUs 
(less than or equal to 50 MW nameplate capacity) and oil-fired EGUs. In 
this rulemaking, the EPA did not propose to revise or eliminate these 
subcategories and did not receive any comments on removing such 
subcategories; therefore, this final rule keeps the 2015 subcategories 
intact.
    In the 2020 rule, the EPA established additional subcategories for 
high FGD flow facilities (EGUs with FGD purge flows of greater than 4 
million gallons per day), LUEGUs (EGUs with a capacity utilization 
rating of less than 10 percent per year), and EGUs permanently ceasing 
coal combustion by 2028. For these subcategorized units, the EPA 
established different limitations using different technology bases as 
compared to the limitations applicable to the rest of the steam 
electric point source category. In 2023, the EPA proposed to eliminate 
the 2020 rule's high FGD flow subcategory and LUEGU subcategory, but 
also proposed to retain the permanent cessation of coal combustion by 
2028 subcategory.
    Based on public comment, in this final rule, the EPA is eliminating 
the 2020 rule's high FGD flow subcategory, as well as the LUEGU 
subcategory, but is retaining the permanent cessation of coal 
combustion by 2028 subcategory. These three subcategories are addressed 
in subsections 1-3 below.
    In addition, the final rule creates three new subcategories based 
on the proposal, as described further in subsections 4-6 below. These 
subcategories are for (1) EGUs permanently ceasing coal combustion by 
2034, (2) discharges of unmanaged CRL, and (3) discharges of legacy 
wastewater from surface impoundments that will commence closure under 
the CCR regulations after the effective date of this final rule. For 
these subcategorized units, the EPA is establishing different 
limitations (using different technology bases) than the ones applicable 
to the rest of the steam electric point source category.
1. Plants With High FGD Flows
    Except as discussed in section VII.C.4 of this preamble, as 
proposed, the EPA is eliminating the high FGD flow subcategory 
promulgated in the 2020 rule. The EPA finds that, after evaluating 
public comments, along with the record and factors specified in CWA 
section 304(b)(2)(B), the subcategory is no longer warranted.
    At the time of the 2020 rule, the EPA's understanding was that this 
subcategory would apply to only one facility, TVA Cumberland, which 
operated with FGD purge flows of over 400 million gallons per day. The 
EPA based the creation of the subcategory on the supposedly disparately 
high costs that would result from high FGD flows at this facility and 
thus the need to install a larger, more costly treatment system than at 
other EGUs.
    Several commenters on the 2019 and 2023 proposals claimed that this 
subcategory of one facility was inconsistent with the CWA, and further 
argued that the costs estimated for TVA were overestimated and not 
disparately high as compared to other facilities.\123\ The EPA 
acknowledges that its cost estimates were higher than TVA's own 
estimates for installing biological treatment, and thus costs may not 
be as disparately high as indicated in the 2020 rule.
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    \123\ The EPA notes that these commenters were also petitioners 
in the consolidated Appalachian Voices case discussed in section IV 
of this preamble.
---------------------------------------------------------------------------

    Since the 2020 rule, TVA has announced a notice in the Federal 
Register of plans to retire the facility, which are further detailed in 
a draft Environmental Impact Statement (EIS). See 86 FR 25933 (May 11, 
2021). This draft EIS solicits comment on three alternatives, all of 
which include retirement but with different electricity replacement 
scenarios. While TVA's comments on the 2023 proposed rule still appear 
to support retaining this subcategory, its comments also confirm that 
TVA plans to retire the Cumberland plant.
    Due to TVA's retirement plans, the EPA finds that this subcategory 
is no longer warranted based on the rationale provided in the 2020 
rule. As appears in its Federal Register document, all the alternatives 
TVA is considering (including its preferred alternative) would result 
in the plant's retirement. To the extent that the plant is able to 
participate in the permanent cessation of coal combustion by 2028 
subcategory, the plant's limitations would be based on surface 
impoundments.\124\ To the extent that the plant operates beyond 2028, 
it would be able to participate in the permanent cessation of coal 
combustion by 2034 subcategory (discussed below in section VII.C.4 of 
this preamble) and have limitations based on chemical precipitation 
(the same 2020 rule limitations applicable to plants in the high FGD 
flow subcategory). Thus, there would be no costs to TVA Cumberland 
associated with the more stringent, zero-discharge limitations in this 
final rule, and thus no disparate costs. Disparate costs were the sole 
rationale for the high FGD flow subcategory, and neither the EPA nor 
commenters have identified alternative bases that could serve to 
support this subcategory. Furthermore, after the retirement of TVA 
Cumberland, because this plant was the only one qualifying as a high 
flow facility, this subcategory becomes a null set; therefore, the EPA 
is eliminating the subcategory.
---------------------------------------------------------------------------

    \124\ TVA submitted a NOPP for the permanent cessation of coal 
combustion subcategory to the Tennessee Department of Environment 
and Conservation on October 6, 2021. To date, the EPA is not aware 
of any actions taken at the facility to meet the limitations in the 
high flow subcategory no later than December 31, 2023, as required 
to participate in this subcategory.
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2. LUEGUs
    Except as discussed in section VII.C.4 of this preamble for the new 
permanent cessation of coal combustion subcategory, as proposed, the 
EPA is eliminating the LUEGU subcategory after evaluating public 
comments received and the record as it informs the factors specified in 
CWA section 304(b)(2)(B). The EPA finds that the subcategory is no 
longer warranted. The EPA established the subcategory for LUEGUs in the 
2020 rule based on cost (disparate capital costs), non-water quality 
environmental impacts (energy reliability), and other factors the 
Administrator deemed appropriate (i.e., harmonization with CAA and RCRA 
regulations that apply to electric utilities).
    The EPA received comments on the proposal both in support of and 
opposition to eliminating this subcategory. Commenters supporting 
elimination of the subcategory agreed with the statements and findings 
included in the EPA's proposal that the

[[Page 40236]]

2020 LUEGU subcategory is no longer warranted based on the factors 
originally cited. Commenters opposed to elimination of this subcategory 
faulted the EPA for several reasons. First, they contended that the EPA 
could not evaluate the subcategory without better understanding how 
many plants intend to make use of it. In particular, they claimed that 
the EPA's understanding of the universe of plants intending to make use 
of the subcategory is not based on a comprehensive accounting of NOPPs 
and facilities with LUEGU limitations included via the transfer 
provisions of the 2020 rule, contained in Sec.  423.13(o), which allow 
facilities to transfer into the LUEGU subcategory automatically without 
requesting a permit modification. Second, these commenters reiterated 
the findings in the 2020 rule and claimed they supported creation of 
the subcategory. Finally, the commenters disputed the proposal's 
characterization of GSP Merrimack Station, the only plant currently 
seeking to participate in this subcategory.
    Under the 2020 rule, a facility wishing to avail itself of the 
limitations available in the subcategories for low utilization or 
permanent cessation of coal combustion, or any facility wishing to 
participate in the VIP, was required to file a NOPP by October 13, 
2021. The EPA acknowledges that facilities and permitting authorities 
were not required to provide NOPPs to the EPA as part of the 2020 rule. 
Instead, the EPA obtained NOPP submissions through normal permit 
reviews, as courtesy copies, in providing technical support to state 
permitting authorities, and via the sharing of a set of NOPPs that 
environmental groups had already collected. In total, these NOPPs cover 
94 EGUs at 38 plants--about 34 percent of all facilities predicted to 
incur costs under the 2020 rule.\125\ Furthermore, the EPA did not 
receive comments from any facilities stating that they had filed NOPPs 
of which the EPA was not aware. Most of these NOPPs are from plants 
wishing to avail themselves of flexibilities in the 2020 rule other 
than the LUEGU subcategory. Only one facility indicated it would like 
to avail itself of the BAT limitations in the subcategory for LUEGUs: 
the GSP Merrimack Station in Bow, New Hampshire.
---------------------------------------------------------------------------

    \125\ Four units at two plants are represented twice. NOPPs for 
two units were initially filed by one plant for the VIP, and NOPPs 
for two separate units were initially filed by another plant for the 
LUEGU subcategory. Both plants then filed new NOPPs for their two 
units to permanently cease coal combustion by 2028.
---------------------------------------------------------------------------

    On March 27, 2024, GSP issued a press release announcing a 
settlement with the EPA whereby GSP has committed to permanently 
ceasing coal combustion at Merrimack Station no later than June 1, 
2028. This dates is memorialized in a Settlement Agreement that arose 
out of an Alternative Dispute Resolution process conducted in 
connection with an administrative appeal of an NPDES permit 
modification for Schiller Station.\126\ As a result of the only known 
facility with LUEGUs retiring and no comments revealing the existence 
of any other LUEGU, the EPA is eliminating the LUEGU subcategory in 
this final rule, except to the extent it supports entry into the new 
permanent cessation of coal by 2034 subcategory discussed below.
---------------------------------------------------------------------------

    \126\ See, e.g., https://indepthnh.org/2024/03/27/last-coal-plants-in-new-england-to-voluntarily-close-transitioning-to-renewable-energy-parks/.
---------------------------------------------------------------------------

3. EGUs Permanently Ceasing Coal Combustion by 2028
    The EPA is retaining the subcategory for EGUs permanently ceasing 
coal combustion by 2028 after evaluating public comments and the record 
in light of the factors specified in CWA section 304(b)(2)(B) and 
finding that the subcategory continues to be warranted. For EGUs in 
this subcategory, the EPA is also retaining the 2020 rule BAT 
limitations based on surface impoundments.
    The EPA proposed to retain the subcategory for EGUs permanently 
ceasing coal combustion by 2028 and simultaneously extended the NOPP 
filing date through a companion direct final rulemaking. See 88 FR 
18440 (March 20, 2023). No commenter argued for the elimination of this 
subcategory, though commenters disagreed about any potential changes. 
Some commenters suggested extending the latest date to permanently 
cease coal combustion beyond December 31, 2028, while other commenters 
opposed any extension of this date. Similarly, some commenters sought 
additional transparency and enforceability of the criteria to 
permanently cease coal combustion while other commenters opposed such 
modifications. In the subsections below, the EPA discusses why this 
subcategory continues to be warranted and why it is retaining the BAT 
technology bases for this subcategory. The EPA also discusses the zero-
discharge limitations that apply after ceasing coal combustion, as well 
as reporting and recordkeeping requirements in the final rule.
    a. The subcategory continues to be warranted based on several 
statutory factors.
    The EPA established this subcategory in the 2020 rule based on the 
statutory factors of cost, the age of the equipment and plants 
involved, non-water quality environmental impacts (including energy 
requirements), and such other factors as the Administrator deems 
appropriate (harmonization with the CCR regulations' alternative 
closure provisions). The EPA notes the unanimous agreement that this 
subcategory should be retained, and it agrees with commenters, although 
the EPA is no longer relying on cost as a primary basis for this 
subcategory, as discussed below.
    In particular, the EPA recognizes that, based on the creation of 
this subcategory, which was part of the 2020 rule, many plants have 
begun moving forward with plans to retire or repower in the then-eight-
year time frame afforded under that rule. In the 2020 rule, EPA 
described how recent NERC reliability assessments showed one region 
that was not anticipated to meet its reference margin \127\ and another 
region that was anticipated to be very close to its reference margin 
(and these assessments are consistent with NERC's 2023 Long-Term 
Reliability Assessment). Therefore, for the 2020 rule, the EPA found 
that premature closure of some plants and/or EGUs as a result of the 
general, industry-wide limitations would be an unacceptable non-water 
quality environmental impact because it could impact reliability. 
Utilities with a limited remaining useful life have planned and 
budgeted for replacement capacity under timelines approved by public 
utility commissions (PUCs) and public service commissions (PSCs) as 
part of the normal integrated resource planning process. These 
submissions were made since the 2020 rule, as part of the 2020 rule's 
eight-year window to permanently cease coal combustion. The EPA does 
not think that it should disrupt these ongoing plans by changing the 
date halfway through the period that plants have moved forward with 
those plans. Maintaining the same timeframe allowed by the prior rule 
supports efforts planned for the orderly transition of generating 
capacity as a result of the 2020 rule in a way that helps ensure

[[Page 40237]]

grid reliability and weighs in favor of retaining the same date in this 
rule.
---------------------------------------------------------------------------

    \127\ ``Reference margins, which differ by region, are reserve 
margin targets based on each area's load, generation capacity, and 
transmission characteristics. In some cases, the reference margin 
level is a requirement implemented by states, provinces, independent 
system operators, or other regulatory bodies. Reliability entities 
in each region aim to have their anticipated reserve margins surpass 
their reference margins, which are generally set near 15% in most 
regions.'' Available online at: https://www.eia.gov/todayinenergy/detail.php?id=31492.
---------------------------------------------------------------------------

    With respect to air pollution, a non-water quality environmental 
impact, the EPA notes that several utilities have decided to make use 
of this subcategory where they may not have previously had plans to 
retire by 2028. For example, the DTE Energy Company filed a NOPP for 
this subcategory for its Belle River Power Plant and is now planning to 
retire in 2028 rather than 2030. Replacing coal-fired capacity with 
natural gas, renewables, and other sources leads to decreased emissions 
of several air pollutants. The subcategory allows utilities seeking to 
retire by 2028 to do so and achieve the associated air pollution and 
solid waste reductions, which further supports the finding that the 
subcategory continues to be warranted.
    In addition, the EPA still wishes to harmonize this rule with the 
CCR alternative closure provisions as described in the proposal, and 
those provisions have not changed. Twenty-five plants are seeking to 
use the alternative closure provisions under the CCR regulations, which 
allow for closure of the unlined impoundment(s) and the power plant no 
later than 2023 (for surface impoundments under 40 acres) or 2028 
(surface impoundments over 40 acres).\128\ Elimination of the permanent 
cessation of coal combustion subcategory from this ELG could interfere 
with the plans of utilities with surface impoundments in the 2028 
category, complicating their compliance with the CCR regulations. 
Furthermore, the EPA has also finalized additional flexibility under 
the Good Neighbor Plan, discussed in section IV.E.2.a of this 
preamble.\129\ Harmonization between regulations on air, water, and 
land pollution gives industry certainty to plan and implement these 
requirements in an orderly, efficient manner.
---------------------------------------------------------------------------

    \128\ Further information is available online at: https://www.epa.gov/coalash/coal-combustion-residuals-ccr-part-implementation.
    \129\ To facilitate a potentially economic and environmentally 
superior unit-level compliance response across the programs that 
nonetheless maintains the NOX reductions required by the 
state budgets from 2026 forward in the proposal, the EPA requested 
comment on potentially deferring the application of the backstop 
daily rate for large coal EGUs that submit written attestation to 
the EPA that they make an enforceable commitment to retire by no 
later than the end of calendar year 2028. 87 FR 20036, 20122 (April. 
6, 2022).
---------------------------------------------------------------------------

    Although the EPA concludes that the previous factors are sufficient 
to justify the retention of this subcategory, the EPA also notes that, 
with respect to cost, the 2020 rule record included an analysis showing 
that amortization of capital costs for less than the typical 20-year 
life of pollution control equipment leads to greater annualized costs 
per MWh as compared to costs at EGUs that are not retiring or 
repowering. Many plants made decisions at the time of the 2020 rule to 
opt for the alternative retirement compliance pathway, and they are now 
several years into meeting the milestones for that path. In this case, 
a change in the rule requiring these facilities to install new 
treatment technologies would result in even shorter timeframes and even 
greater costs per MWh. Thus, the EPA finds that cost provides an 
additional basis for the subcategory.
    After considering all the information above, the EPA finds that the 
record and statutory factors discussed above continue to support this 
2020 subcategory and associated limitations. Each of these bases, 
discussed above and supported by a statutory factor, provide a separate 
and independent basis for subcategorization, save for the cost basis 
which serves as additional support. Thus, the EPA is retaining this 
subcategory in its current form. This includes retaining the BAT 
technology basis for limitations applicable to EGUs in this 
subcategory, surface impoundments. Surface impoundments are 
technologically available, are economically achievable, and have 
acceptable non-water quality environmental impacts as applied to this 
subcategory. They represent BAT for this subcategory because they 
support the ability of plants with a limited remaining useful life to 
continue with their ongoing plans for orderly retirement or repowering. 
The EPA also notes that they would not lead to higher costs for 
facilities based on the remaining useful life of their EGUs. The EPA 
did not select any other technology for this subcategory because it 
would disrupt plants' already approved, ongoing plans for ceasing coal 
combustion by 2028. The EPA also notes that imposing more stringent BAT 
limitations on EGUs in this subcategory would subject them to greater 
costs per MWh, as compared to EGUs in the general industry, given that 
these EGUs have a limited remaining useful life.
    b. The final rule includes post-coal combustion cessation zero-
discharge limitations for EGUs in this subcategory to avoid 
circumvention.
    The EPA proposed to include zero-discharge limitations applicable 
after the permanent cessation of coal combustion date, December 31, 
2028, for all discharges in this subcategory. The goal of these 
limitations was to ensure that a facility does not manipulate the 
flexibilities in 40 CFR part 423 to avoid meeting industry-wide zero-
discharge limitations and then simply keep discharging without relevant 
permit limitations being applicable to them. The EPA received several 
comments on these limitations that would apply after the permanent 
cessation of coal combustion date. Some commenters expressed a 
preference for them and sought an even stronger requirement that the 
zero-discharge limitations be retroactive. Other commenters suggested 
that these limitations are not necessary, are unduly burdensome, and 
are not cost-free, even where a facility successfully permanently 
ceases coal combustion by the specified date. One commenter in the 
latter category suggested a 120-day flexibility for facilities that 
permanently ceased coal combustion to allow for some residual 
discharges of these wastewaters as necessary, subject to requirements 
no more stringent than BPT limitations.
    After considering these comments, the EPA is finalizing zero-
discharge limitations that would apply after the permanent cessation of 
coal combustion date, December 31, 2028, with modifications from the 
proposal, in order to ensure that the eligibility for participation in 
this subcategory designed for EGUs that permanently cease coal 
combustion is not circumvented. The modifications the EPA made to these 
limitations following proposal are based on legitimate concern raised 
in public comments concerning the potential need to discharge for a 
relatively short period of about fourth months following the permanent 
cessation of coal combustion. For example, a facility retiring on 
December 31, 2028, may still need to discharge the wastewater remaining 
in existing tanks from the final hours and days of lawful operations. 
The EPA does not wish to interfere with owner/operator plans for the 
permanent cessation of coal combustion or discourage the use of this 
subcategory by unfairly preventing any residual discharges that are 
necessary after coal combustion has permanently ceased.
    The final rule reflects that the EPA continues to view zero-
discharge limitations that apply following the permanent cessation of 
coal combustion date as an appropriate tool to avoid circumvention, as 
well as some flexibility to account for legitimate concern regarding 
the need to discharge following the permanent cessation of coal 
combustion date. The final rule thus contains a tiered set of zero-
discharge limitations applicable following December 31, 2028:

[[Page 40238]]

     The first tier of these limitations is composed of zero-
discharge limitations for FGD wastewater and BA transport water after 
April 30, 2029. These limitations would apply if the EGU had in fact 
permanently ceased coal combustion by December 31, 2028, as the plant 
represented it would. As suggested in the comments, this date is 120 
days after the latest permanent cessation of coal combustion date, 
allowing for facilities to complete any necessary residual 
decommissioning discharges.\130\
---------------------------------------------------------------------------

    \130\ The EPA notes that these do not include discharges of 
legacy wastewaters from surface impoundments closing under the CCR 
rule, which are covered by different regulatory provisions.
---------------------------------------------------------------------------

     The second tier is composed of zero-discharge limitations 
for these same wastewaters after December 31, 2028. If a plant fails to 
cease combustion of coal by 2028, as it represented it would, for any 
reason other than those specified in section 423.18, these zero-
discharge limitations would automatically apply.
    Dischargers to which the second tier applies, the EPA notes, would 
be subject not only to this rule's requirements, but also to 
enforcement for false statements in their filings under Sec.  423.19--
for example, statements made in the NOPP, in the annual progress 
reports, in the notice of material delay, and for failure to file a 
notice of material delay in a timely fashion. Any reporting and 
recordkeeping violations would also be subject to enforcement. The EPA 
finds that, together, the zero-discharge limitations and reporting and 
recordkeeping requirements, as modified below, are sufficient to ensure 
that facilities do not unfairly benefit by continuing to discharge 
after the subcategory's permanent cessation of coal combustion date.
    c. The final rule includes additional reporting and recordkeeping 
requirements for EGUs in this subcategory.
    For a discussion of additional reporting and recordkeeping 
requirements, see section XIV.C.1 of this preamble.
4. EGUs Permanently Ceasing Coal Combustion by 2034
    The EPA proposed a new ``early adopter'' subcategory for EGUs 
permanently ceasing coal combustion by December 31, 2032, with certain 
eligibility criteria targeted toward those plants that had already 
installed the FGD and BA technology bases on which the 2020 rule rested 
by the date of the 2023 proposed rule. The EPA solicited comment on 
whether the permanent cessation of coal combustion date should be 
earlier or later than 2032, as well as the propriety of the proposed 
criteria based on technology adoption for the subcategory. Based on 
public comments, the EPA is finalizing the new subcategory, except that 
the date for permanently ceasing coal combustion is December 31, 2034, 
rather than 2032. In addition, the EPA is not establishing strict 
eligibility criteria that would have narrowed the universe of plants to 
which this subcategory might apply. Through public comments, the EPA 
learned that, while many plants have continued to move toward 
compliance with the 2020 rule limitations, including by making various 
expenditures toward that goal (e.g., securing contracts, conducting 
pilots, etc.), relatively few had actually installed the technologies 
on which the 2020 rule limitations were based by the time the 2023 
proposed rule was published. In some cases, this was due to the timing 
of when a plant's NPDES permit was expected to be renewed. As a result, 
the cutoff that the EPA proposed--in terms of both the date for 
adoption and what steps constituted adoption--as well as other cutoffs 
that the EPA considered, would not necessarily capture the universe of 
plants that the EPA intended to capture. Moreover, the bases for this 
subcategory in terms of the statutory factors, as discussed further 
below, support this subcategory even without the proposed requirement 
for installation of the 2020 rule BAT technologies by the 2023 proposed 
rule date.
    For EGUs that permanently cease coal combustion by December 31, 
2034, the EPA is establishing limitations for FGD wastewater and BA 
transport water that are the same as those in place following the 
effective date of the 2020 rule. These limitations differed for some 
EGUs if they participated in a subcategory promulgated by the 2020 
rule, but for the general industrial category consisted of limitations 
based on chemical precipitation followed by low residence time 
biological reduction treatment for FGD wastewater and limitations based 
on high recycle rate systems for BA transport water.
    The final rule also covers discharges of CRL from EGUs in the new 
permanent cessation of coal combustion subcategory. The EPA notes that 
facilities discharge CRL either alone or in combination with FGD 
wastewater and BA transport water. The EPA solicited comment at 
proposal on the treatment of CRL at EGUs that will soon permanently 
cease coal combustion and close their CCR landfills. In response to 
this solicitation, several commenters recommended either including CRL 
in any new permanent cessation of coal combustion subcategory or 
creating a separate subcategory for CRL generated at landfills nearing 
closure. Several commenters recommended that CRL discharged from 
retired EGUs or EGUs that were about to retire should be subcategorized 
to avoid imposing disparate costs. One commenter pointed to the 
Agency's findings that the volume of CRL generated after closure of a 
landfill was approximately an order of magnitude lower than the volume 
of CRL generated during that landfill's operation.
    The EPA agrees with many of these comments and is including CRL as 
one of the wastestreams covered by the new permanent cessation of coal 
combustion by 2034 subcategory. While an EGU is still combusting coal, 
that combustion generates CCR, which in turn generates CRL. As well as 
being tied to ongoing operations during a facility's remaining useful 
life (as are FGD wastewater and BA transport water), CRL can be 
comanaged with FGD wastewater (as is currently done at some 
facilities). Furthermore, including CRL in this subcategory promotes 
ease of administration, avoiding the creation of a separate subcategory 
for CRL designed to accomplish the same fundamental goals.
    For CRL discharged at EGUs in this subcategory, the EPA is 
reserving BAT limitations to be developed on a BPJ basis by the 
permitting authority until the permanent cessation of coal combustion, 
after which the EPA is establishing mercury and arsenic limitations 
based on chemical precipitation, which are the same limitations that 
EPA proposed for all discharges of CRL.
    The EPA received a number of comments on the overall propriety of 
the proposed subcategory. Though commenters were split, many supported 
a new subcategory for additional flexibility but disagreed with the 
contours of what the EPA proposed. After considering the comments and 
evaluating the record in light of the factors specified in CWA section 
304(b)(2)(B), the EPA finds that a new permanent cessation of coal 
combustion subcategory is warranted. The statutory bases for this 
subcategory are discussed in the subsection below. The rationale for 
the selected BAT technology bases appears thereafter, as well as the 
rationale for rejecting other technologies. Importantly, this 
subcategory is in addition to the 2020 rule's permanent cessation of 
coal combustion by 2028 subcategory, which is carried forward in this 
rule. While the

[[Page 40239]]

two subcategories are similar in that they apply to EGUs that plan to 
permanently cease combustion of coal, they differ as discussed below.
    a. This subcategory is justified based on several statutory 
factors.
    This subcategory is supported by consideration of three CWA section 
304(b) statutory factors: age of equipment and facilities involved, 
non-water quality environmental impacts, and cost. The EPA notes that 
the cost factor supports subcategorization, but it is not relying on 
that factor as a primary basis for the subcategory. Each of the bases 
discussed below and supported by a statutory factor provide a separate 
and independent basis for subcategorization, except for cost, which 
simply provides additional support.
    Age of the equipment and facilities involved. The EPA recognizes 
that this 2024 rule establishes new, more stringent limitations over 
the limitations promulgated in 2020. For some plants, that means that 
they may no longer be able to rely on parts of the wastewater treatment 
systems they installed to meet the 2020 limitations to meet the new 
2024 limitations. Under the Act's technology-forcing regime, imposing 
limitations requiring facilities to shift installation to new pollution 
control technologies is warranted as more effective technologies are 
available and economically achievable. In the particular circumstances 
here, however, the ``age of equipment and facilities involved'' 
supports allowing plants with EGUs permanently ceasing combustion of 
coal by December 31, 2034, to continue to meet limitations under the 
2020 rule. Such facilities either have recently or are in the process 
of installing technologies to meet the 2020 rule limitations and, 
rather than require these facilities to also install technologies to 
meet limitations under the 2024 rule as well, given the short remaining 
useful life of certain plants, the EPA views it as reasonable to 
provide flexibility in this rule for plants with EGUs permanently 
ceasing combustion of coal by December 31, 2034.
    There are many coal-fired EGUs that have announced a retirement or 
fuel conversion that would occur after December 31, 2028, which is the 
date used to establish the 2020 subcategory applicable to EGUs 
permanently ceasing coal combustion. In table VII-2 below, the EPA 
presents all of the announcements at EGUs estimated to potentially make 
new investments under this final ELG rule.

[[Page 40240]]

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[[Page 40241]]


[GRAPHIC] [TIFF OMITTED] TR09MY24.042


[[Page 40242]]


[GRAPHIC] [TIFF OMITTED] TR09MY24.043

    As seen in the table above, there have been 120 announcements that 
cover the years from 2029 to 2066. Of these, the EPA assumes that the 
nine EGUs retiring in 2029 would already be able to retire without 
making new investments under this rule, as these facilities could 
obtain a ``no later than'' date for the final limitations in this rule

[[Page 40243]]

from their permitting authority as late as December 31, 2029. In 
particular, the EPA notes that there is a cluster of announced 
retirements that tails off around 2034, with relatively few additional 
retirements in subsequent years until the 2039/2040 timeframe. These 
retirements have already been announced, planned for, and in some cases 
already approved by state and regional utility commissions or grid 
operators.
    Some commenters expressed the view that the EPA had not considered 
reliance interests created by the 2020 rule and the EPA's decision to 
continue to implement that rule. The EPA disagrees. As discussed in 
previous sections, a facility cannot reasonably rely on the limitations 
established in a permit beyond the life of the permit itself, which is 
typically issued for five-year term, and the technology-forcing nature 
of the statute contemplates establishment and revision of limitations 
based on the best available technology reflecting currently available 
information. Nevertheless, as noted above, there are around 50 EGUs 
planning to permanently cease coal combustion between 2030 and 2034. 
The plants where these EGUs are located are in the process of 
installing or have recently installed new technologies under the 2020 
rule, as the latest date for compliance in that rule is December 31, 
2025. Without establishment of this subcategory, these plants could now 
be expected, under this rule, to potentially abandon parts of their 
2020 treatment systems and install different treatment systems to 
comply with this 2024 rule, which has a compliance date of December 31, 
2029, at the latest. These plants, in particular, have adopted certain 
strategies for an orderly transition to retirement or an alternate fuel 
source. The owners and operators of these plants have planned this 
transition taking into consideration effects on the broader grid and 
the reasonable useful life of recently installed or soon-to-be 
installed water pollution treatment equipment under the 2020 rule. 
Under these circumstances, the EPA does not view it as reasonable, in 
view of all the relevant considerations, to expect this group of plants 
to abandon prior installations under the 2020 rule and make additional 
upgrades under this 2024 rule, given the relatively short remaining 
useful life of the EGUs and treatment systems. The EPA notes, moreover, 
that plants installing and operating technologies to meet the 2020 
limitations will achieve reductions of pollutants of concern in their 
wastewaters.
    For CRL, it is also relevant to consider the remaining useful life 
of the WMU. As discussed earlier in this section, commenters 
recommended providing flexibility for landfills which were nearing 
retirement, as these landfills would be closed and generate a much 
smaller volume of CRL after retirement. Thus, instead of installing an 
oversized system to operate for potentially only a couple of years, a 
more tailored system could be installed to treat the smaller, post-
closure flow.
    Non-water quality environmental impacts (including energy 
requirements). The already planned retirements and fuel conversions of 
coal-fired EGUs discussed above would not only reduce or eliminate the 
water pollution associated with the continued operation of coal-fired 
EGUs, but it would also reduce or eliminate air pollution and solid 
waste generation. Electric utilities have an interest in continuing the 
planned, orderly transition of this cluster of EGUs in a way that 
achieves an adequate amortization period for the water pollution 
treatment technologies. Without subcategorization, this cluster of 
facilities may choose to extend the life of these EGUs in order to 
better amortize the costs of both the existing technologies as well as 
the new technologies that would otherwise be required by this final 
rule. If that were to happen, the reductions in air pollution and solid 
waste generation associated with the planned retirement or repowering 
of the EGU would be forgone, and the EPA finds these non-water quality 
environmental impacts weigh in favor of this subcategory.
    In addition, ``energy requirements'' are an express non-water 
quality environmental impact that EPA must consider under the statute, 
and several commenters raised concerns regarding electric reliability. 
These commenters suggested that a subcategory was necessary to maintain 
reliability. As discussed above, the retirements of EGUs in this 
subcategory have already been announced, planned for, and in some cases 
already approved by state and regional utility commissions or grid 
operators. The Agency finds that the creation of this subcategory 
provides flexibility for the orderly retirement or fuel conversion of 
coal-fired EGUs in a way that helps ensure grid reliability, as it 
allows plants to continue as planned while meeting the 2020 
limitations. This provides additional support for this subcategory.
    Cost. The EPA also notes that ``cost' is a factor that EPA must 
consider under CWA section 304(b), and, while not a primary basis, this 
factor provides additional support for this subcategory. Looking at the 
EGUs permanently ceasing coal combustion by December 31, 2034, absent 
the new subcategory, these EGUs would have additional capital costs of 
$708M and additional O&M costs of $93.0M. Given the short remaining 
useful life of the EGUs and associated wastewater treatment equipment, 
facilities with these EGUs would have fewer years of remaining life 
over which to amortize these costs, and thus the costs would be higher 
per MWh than the costs per MWh for EGUs not permanently ceasing coal 
combustion by 2034. This is especially true of plants that might not 
install the 2024 technologies until the latest compliance date of 
December 31, 2029. The EPA analyzed these costs in the 2020 rule with 
respect to the permanent cessation of coal by 2028 subcategory and 
similarly found unreasonably higher costs for that subcategory.
    Selection of 2034 date. While the EPA proposed a permanent 
cessation of coal combustion date of December 31, 2032, several 
commenters advocated for different dates as early as 2030 and as late 
as 2040. The record discussed above does not provide a clear 
delineation for where such a cutoff should be placed; however, after 
careful consideration of the information in the record, the EPA finds 
that selecting a permanent cessation of coal combustion date of 
December 31, 2034, to be a reasonable way to account for the interests 
described above while still furthering the CWA's goals. First, as 
discussed above, there is a cluster of retirements occurring from 2030 
to 2034. Relatively few additional EGUs would qualify for the 
subcategory if the date were placed a year or two further into the 
future, but many EGUs would be excluded if the date were kept at 2032 
or moved even earlier as some commenters suggested. Furthermore, cost 
per MWh becomes greater as the amortization period of new equipment is 
shortened. An effective date for the final rule in 2024 and a ``no 
later than'' date of December 31, 2029, means that plants with 
retirements or fuel conversions in the 2030 to 2034 cluster would 
amortize costs over a period of several months to at most, 10 years. 
Finally, the use of December 31, 2034, would create parity for 
facilities regardless of where they were in their permit cycle. Since 
the 5-year permit cycle after the effective date of this rule would go 
from 2024 to 2029, one more 5-year permit cycle after that ends in 
2034.
    Finally, the EPA has considered how the requirements in this rule 
interact

[[Page 40244]]

with the requirements in the CAA section 111 rule. One of the frequent 
comments received during the public comment period on the proposed ELG 
was that this rule and the CAA section 111 rule should be harmonized. 
Commenters argued that harmonization may consist of several aspects, 
including aligning compliance dates, aligning subcategories and other 
flexibilities, and aligning reporting and recordkeeping requirements. 
In the context of a subcategory for the permanent cessation of coal 
combustion, the EPA finds that the subcategory discussed here creates 
sufficient space for the flexibilities under the CAA section 111 rule 
to be utilized as appropriate.
    As described in section IV.E.2 of this preamble, the final CAA 
section 111 rule consists of only two coal-fired EGU subcategories, and 
no longer has subcategories for EGUs retiring by 2032 or 2034 as were 
in the proposed CAA section 111 rule. Instead, the final CAA section 
111 rule includes site-specific flexibilities to ensure reliability. 
While it is not always possible or necessary to harmonize the CAA and 
CWA requirements due to the different means by which flexibilities are 
implemented under the two statutes, EPA has provided flexibility under 
the ELG which would reasonably allow for the use of the site-specific 
flexibilities of the CAA section 111 rule. Specifically, since the two 
coal-fired EGU subcategories in the CAA section 111 final rule have 
compliance dates of January 1, 2030, and January 1, 2032, the use of 
the site-specific flexibilities tied to reliability would necessarily 
mean that some EGUs could retire after those dates with less stringent 
or delayed standards. Thus, the additional time provided by a 2034 
permanent cessation of coal combustion date in the final ELG allows 
time for the corresponding site-specific flexibilities in the CAA 111 
rule to be utilized.
    While harmonization with the CAA section 111 rule supports the 
finding that this subcategory is appropriate, it is the EPA's intent 
that this new permanent cessation of coal combustion subcategory be 
retained even if the final CAA section 111 rule is not in effect. The 
EPA finds that, even in the absence of the CAA 111 rule, the other 
statutory factors of age, non-water quality environmental impacts, and 
cost are sufficient, either alone (save for cost) or together, to 
support the subcategory for EGUs permanently ceasing coal combustion by 
2034.
    b. The EPA is establishing BAT limitations for EGUs in this 
subcategory based on the currently applicable BAT technology bases for 
FGD wastewater, BA transport water, and CRL during the continued 
combustion of coal.
    The EPA finds that the 2020 rule BAT technologies that formed the 
bases for the generally applicable limitations for FGD wastewater and 
BA transport water, as well as the BAT technologies that formed the 
bases for limitations in the high FGD flow subcategory and in the LUEGU 
subcategory, are available, are economically achievable, and have 
acceptable non-water quality environmental impacts, as explained in the 
2020 rule and further confirmed by analyses in this rule. EPA is, 
therefore, identifying them as the BAT technology bases for FGD 
wastewater and BA transport water for EGUs in this subcategory.\131\ 
The EPA is also declining to establish BAT limitations on CRL prior to 
permanently ceasing combustion of coal. The effect of EPA declining to 
establish BAT limitations for CRL discharged from EGUs in this 
subcategory prior to permanently ceasing coal combustion is that 
permitting authorities will continue to establish technology-based 
effluent limitations using their BPJ. Because the limitations are 
required to be derived on a case-by-case basis, taking into account the 
requisite statutory factors and applying them to the circumstances of a 
given plant, these limitations would by definition be technologically 
available and economically achievable and have acceptable non-water 
quality environmental impacts where the permitting authority supports 
in the record of the permit that such is the case.
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    \131\ In identifying the BAT technology bases of the 2020 rule 
as BAT for the new permanent cessation of coal combustion by 2034 
subcategory, the EPA is excluding the technology bases for EGUs 
permanently ceasing coal combustion by 2028. These EGUs can already 
seek an ``as soon as possible'' date for the new 2024 limitations 
later than the December 31, 2028, date for the permanent cessation 
of coal combustion.
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    The EPA rejects more stringent technologies, such as zero-discharge 
systems, for FGD wastewater, BA transport water, or CRL in this 
subcategory before the permanent cessation of coal combustion. Zero-
discharge requirements for this subcategory may not allow electric 
utilities with a limited remaining useful life to continue their 
ongoing, approved plans for an organized phasing out of EGUs that are 
no longer economical, in favor of more efficient, newly constructed 
generating stations. This concern is reduced by maintaining the 
currently applicable BAT limitations for this subcategory.
    While the previous basis is sufficient to reject technologies that 
would result in more stringent limitations, the EPA notes that 
limitations based on such technologies as zero-discharge systems would 
impose greater costs per MWh on this subcategory of EGUs, given their 
limited remaining useful life. This provides additional support for 
rejecting more stringent limitations. Retaining the currently 
applicable BAT for this subcategory alleviates the choice for these 
plants to either pass on the greater capital costs per MWh of zero-
discharge systems over a shorter remaining useful life or risk the 
possibility that post-retirement rate recovery would be denied for the 
significant capital and operating costs associated with the final rule. 
In addition, with respect to CRL, requiring across-the-board BAT 
limitations before permanent cessation of coal combustion could lead to 
individual facilities experiencing disparate costs not only because of 
the short remaining useful life of the facility, but also because of 
the short remaining useful life of the waste management unit. The 
record indicates that the volumes of CRL generated by a retired 
landfill are approximately an order of magnitude lower than the volumes 
of CRL generated by an operating landfill. One of the primary inputs to 
EPA's cost model is the volume treated. Here, if the EPA mandated 
categorical limitations based on a treatment technology prior to 
ceasing combustion of coal, a facility would need to size that 
technology to treat the flows of a fully operating landfill. However, 
about 90 percent of that system would go idle only a few years later 
and remain idle into perpetuity. Thus, these capital investments would 
result in greater costs per MWh sold compared to the costs described to 
treat CRL discharges at plants continuing operations (see section 
VII.B.3 of this preamble). CRL costs for a post-retirement-sized system 
would be lower in absolute terms, but also lower in light of these 
costs being incurred later. This finding does not conflict with the 
EPA's finding that case-by-case BAT limitations developed using a 
permitting authority's BPJ are available, are economically achievable, 
and have acceptable non-water quality environmental impacts because a 
permitting authority can consider site-specific information, such as 
the availability of other existing wastewater treatment systems at the 
plant to accommodate the volumes of CRL generated.\132\
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    \132\ For example, if an FGD wastewater treatment system already 
in place at a facility was under-utilized, the permitting authority 
might find that treatment with that system is available, 
economically achievable, and has acceptable non-water quality 
environmental impacts for that facility.

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[[Page 40245]]

    The EPA also rejects surface impoundments as BAT for FGD 
wastewater, BA transport water or CRL in this subcategory before the 
permanent cessation of coal combustion. Some commenters encouraged the 
EPA to finalize either a new or an extended permanent cessation of coal 
subcategory with surface impoundments as BAT. While EPA has today 
reaffirmed its 2020 rule findings that surface impoundments are BAT for 
the subcategory of EGUs permanently ceasing coal combustion by 2028 in 
the section above, part of those 2020 rule findings included the 
finding that more stringent technologies were BAT for EGUs operating 
beyond December 31, 2028, because those technologies are available, are 
economically achievable, and have acceptable non-water quality 
environmental impacts. The EPA received several comments in the record 
from utilities that have done as the EPA indicated at proposal: they 
have continued to move forward with implementation of the 2020 rule. 
These utilities discussed the significant costs associated with interim 
steps toward implementation such as engineering design, bidding, 
contracting for systems, and commencing construction. EPA acknowledges 
these expenditures. To the extent that costs have already been 
incurred, these are sunk costs that cannot be recovered, and thus the 
marginal impact of the rule would not interfere with power plants' 
already approved, ongoing plans to transition to retirement or 
repowering or impose disparate costs. While EPA expects that most costs 
will already have been incurred, the 2020 rule limitations have a ``no 
later than'' date of December 31, 2025, rather than this rule's ``no 
later than'' date of December 31, 2029, for the new, more stringent BAT 
limitations. Thus, even in the rare case that a facility has failed to 
diligently pursue treatment that would meet the 2020 rule limitations, 
such a facility will have an additional four years to amortize any 
remaining capital costs of their treatment systems before ceasing coal 
combustion in 2034 as compared to the amount of time they would have to 
amortize the capital costs of treatments systems to meet this final 
rule's more stringent BAT limitations. Therefore, it is less likely 
that the investments made to comply with the 2020 rule would interfere 
with the orderly transition of generating capacity for those EGUs in 
this subcategory.
    Moreover, the EPA finds that the costs to EGUs in this subcategory 
for meeting the currently applicable FGD wastewater and BA transport 
water limitations as compared to EGUs that are not permanently ceasing 
coal combustion by 2034 do not justify rejecting the 2020 rule 
limitations in favor of BAT limitations based on surface impoundments, 
especially where there are more stringent technologies capable of 
greater pollutant discharge reduction as described above that are 
available, are achievable, and have acceptable non-water quality 
environmental impacts. This finding is further confirmed in the EPA's 
evaluation of the 2020 rule costs in the baseline and policy runs of 
IPM, both of which demonstrate that the 2020 rule limitations continue 
to be economically achievable. The EPA's decision to continue to 
require permitting authorities to develop limitations on CRL discharges 
is also consistent with the Fifth Circuit's decision in Southwestern 
Electric Power Co. v. EPA. There, the Court vacated BAT limitations for 
CRL based on surface impoundments, citing the EPA's statements in the 
record that surface impoundments do not adequately control dissolved 
metals and the fact that there are more stringent technologies than 
surface impoundments that are available to control discharges of CRL. 
Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1029-1030. Reserving 
BAT limitations for CRL discharged before an EGU permanently ceases 
coal combustion in this subcategory allows for the permitting authority 
to impose more stringent technologies as appropriate.
    c. For EGUs in this subcategory, BAT limitations for CRL after the 
EGU permanently ceases combustion of coal are based on chemical 
precipitation.
    The EPA expects that, unlike FGD wastewater and BA transport water, 
CRL will continue to be discharged even after a plant permanently 
ceases coal combustion. For EGUs in this subcategory, the EPA is 
establishing nationwide limitations for CRL on mercury and arsenic 
based on chemical precipitation after permanently ceasing combustion of 
coal. Specifically, the BAT technology basis after permanently ceasing 
coal combustion is a chemical precipitation system that employs 
hydroxide precipitation, sulfide precipitation (organosulfide), and 
iron coprecipitation.
    With respect to BAT limitations after permanent cessation of coal 
combustion, the rule record is extensive in support of the EPA's 
finding that chemical precipitation is technologically available for 
the treatment of arsenic and mercury in CRL. As far back as the 2015 
rule, the EPA found that four plants operated chemical precipitation 
systems on their CRL and, in fact, established NSPS for CRL based on 
chemical precipitation systems.\133\ The EPA also found that chemical 
precipitation was in use on FGD wastewater (which EPA found was 
characteristically similar to CRL), metal products and machinery 
plants, iron and steel manufacturers, metal finishers, and mining 
operations (including coal mines).\134\ All of these uses have 
demonstrated the ability of chemical precipitation technology to remove 
arsenic and mercury.\135\
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    \133\ U.S. EPA (Environmental Protection Agency). 2015. 
Technical Development Document for the Effluent Limitations 
Guidelines and Standards for the Steam Electric Power Generating 
Point Source Category. September. Washington, DC 20460. EPA-821-R-
15-007. Available online at: https://www.epa.gov/sites/default/files/2015-10/documents/steam-electric-tdd_10-21-15.pdf.
    \134\ Id.
    \135\ Id.
---------------------------------------------------------------------------

    One commenter suggested that chemical precipitation does not treat 
dissolved arsenic concentrations. This comment contradicts what is 
known about chemical precipitation. In the 2015 rule record, the EPA 
explained that chemical precipitation systems typically use pH 
adjustment to make soluble forms of pollutants insoluble. The EPA found 
that most systems operate with three chemicals that are added in one 
tank or in separate tanks, depending on the pH at which individual 
metals will settle out.\136\ Thus, while plants may need to adjust 
systems until it is optimized for the specific CRL and target pollutant 
removals, the EPA sees nothing to indicate that dissolved arsenic 
concentrations are not treatable just because they are dissolved. The 
pre- and post-treatment dissolved arsenic data the commenter refers to 
are a subset of total arsenic (not just dissolved arsenic) that the EPA 
noted in 2015 was very low (near or below the limit of quantification). 
The fact that some data points are above the limit of quantitation does 
not change the fact that these are still very low dissolved arsenic 
numbers that demonstrate the ability of the technology to meet the 
established limitations. The fact that the technology did not continue 
to remove arsenic below the treatment levels that the EPA established 
in 2015 does not negate the fact that this same data

[[Page 40246]]

demonstrates the technology does remove arsenic down to that limit.
---------------------------------------------------------------------------

    \136\ Id.
---------------------------------------------------------------------------

    Another commenter referenced 2010 survey data as showing elevated 
levels of iron, aluminum, and manganese in CRL from landfills where 
coal-handling byproducts were also disposed, which this commenter 
suggested would make treatment more complex. The commenter did not 
claim that these elevated influent concentrations make the waste 
untreatable through chemical precipitation, only that there may be 
additional solid wastes or a need for multiple treatment vessels. 
Without more information, the EPA has no reason to conclude that 
chemical precipitation would not work as intended in these 
scenarios.\137\
---------------------------------------------------------------------------

    \137\ The EPA also notes that, should a facility with such a 
landfill generate CRL that is sufficiently different from the CRL 
evaluated in the record, the facility may be able to apply for a 
Fundamentally Different Factors variance.
---------------------------------------------------------------------------

    The EPA finds that BAT limitations based on chemical precipitation 
for EGUs discharging CRL after permanently ceasing coal combustion in 
this subcategory are economically achievable based on the results of 
IPM modeling, as explained in sections VII.F and VIII.
    The EPA finds that BAT limitations based on chemical precipitation 
for EGUs discharging CRL after permanently ceasing coal combustion in 
this subcategory have acceptable non-water quality environmental 
impacts as discussed in sections VII.G and X.
    For a further discussion of the availability timing of these 
limitations, see section VII.E of this preamble.
    d. The EPA rejects surface impoundments as BAT for CRL after 
permanent cessation of coal combustion in this subcategory.
    The EPA finds that surface impoundments are not BAT for CRL after 
permanent cessation of coal combustion for EGUs in this subcategory. 
The record shows that chemical precipitation is available, is 
economically achievable, and has acceptable non-water quality 
environmental impacts for treatment of CRL discharges after the 
permanent cessation of coal combustion. Moreover, chemical 
precipitation removes more pollutants than surface impoundments, which 
better achieves the BAT requirement of making reasonable further 
progress toward the CWA's goals. See Southwestern Elec. Power Co. v. 
EPA, 920 F.3d at 1003, 1006 (citing Nat'l Crushed Stone v. EPA, 449 
U.S. at 75).
    e. The EPA rejects more stringent technologies as BAT for CRL after 
permanent cessation of coal combustion in this subcategory.
    The EPA finds that more stringent technologies are not BAT for CRL 
after permanent cessation of coal combustion for EGUs in this 
subcategory based on the statutory factors of age and cost, as well as 
given certain information gaps in the record. Specifically, the EPA 
finds that more stringent technologies are not commensurate with the 
age of the facility being in a retired status, which would lead to 
unacceptably higher capital costs that can no longer be spread over 
electricity sales.
    Concerning CRL generated after retirement, the EPA notes that CRL 
will continue to be generated into perpetuity without any associated 
revenue stream tied to ongoing coal combustion, as several commenters 
pointed out.\138\ This differs substantially from scenarios involved in 
a typical ELG, for which the EPA conducts a screening economic analysis 
that compares costs to revenues at the facility level in addition to 
the owner level.\139\ The EPA notes that this results not in a standard 
disparate cost, but rather an overall disparate circumstance. Since 
this unique scenario does not often play out in ELGs, the EPA does not 
have examples to draw from in evaluating economic achievability.
---------------------------------------------------------------------------

    \138\ The EPA acknowledges that this subcategory also applies to 
fuel conversions. The EPA considered the fact that this subset of 
EGUs within this subcategory would have a future revenue stream, 
unlike EGUs that permanently retire. However, were the EPA to 
require more stringent treatment at this subset of EGUs, the result 
could be for a facility converting to natural gas (for example) to 
instead construct its replacement gas-fired capacity on an 
immediately adjacent greenfield to avoid the additional costs of 
treatment. This is a perverse incentive because it could implicate 
the development of additional land, perhaps even a greenfield, and 
construction of new transmission lines. These are adverse non-water 
quality environmental impacts that the EPA finds unacceptable, and 
it is thus declining to treat this subset differently from retiring 
EGUs. The EPA further notes that this outcome would result in 
additional costs of replacement capacity without achieving any 
additional pollutant discharge reductions.
    \139\ While The EPA has performed that comparison here using the 
operating revenues prior to the cessation of coal combustion, the 
Agency has already found that subcategorization is warranted for a 
number of reasons and justified retaining the current requirement 
that case-by-case BPJ determinations be made by the permitting 
authority in controlling CRL discharges.
---------------------------------------------------------------------------

    Given this unique aspect of this ELG, the EPA notes that any 
treatment system built to operate only after the permanent cessation of 
coal combustion will necessarily experience costs in a differing 
circumstance when compared to the costs recovered via ongoing 
electricity sales by EGUs not in this subcategory. For CRL that is not 
otherwise subcategorized in this rule, the EPA is requiring limitations 
based on zero-discharge systems during operations to continue to apply 
even after retirement. These EGUs will continue to combust coal beyond 
2034, so systems will already be partially or fully paid for with rate 
recovery from electricity sales during the active phase of the EGU. 
Thus, the marginal cost of continuing to use such an existing treatment 
system are limited to O&M costs, and thus would not result in capital 
costs being incurred under the disparate circumstance of retired coal-
fired EGUs.
    As this discussion demonstrates, the selected BAT basis, chemical 
precipitation, already imposes costs in a disparate circumstance 
compared to EGUs not in this subcategory. Compared to chemical 
precipitation systems, however, biological and zero-discharge systems 
worsen already existing situational revenue disparities based on the 
already passed retirement age for these EGUs when compared to the rest 
of the industrial category. Both chemical precipitation plus biological 
treatment systems and zero-discharge systems typically have capital 
costs about double the capital costs of chemical precipitation systems 
alone.\140\ The EPA finds that the increased costs of these more 
stringent technologies renders them unacceptable in light of the post-
retirement age of the EGUs to which they would apply. The EPA intends 
the age, cost, and economic achievability rationale discussed here is 
unique to the small number of industry-wide discharges at retired 
facilities with no revenue such as the landfill industrial point source 
category: it thus will not form a precedent for evaluating costs and 
economic achievability at the vast majority of facilities which 
continue to operate and have active revenue streams.
---------------------------------------------------------------------------

    \140\ For biological treatment cost comparisons, the EPA is 
using the 2020 rule record with respect to FGD wastewater.
---------------------------------------------------------------------------

    The EPA also considered the availability of biological treatment 
systems for CRL at closed landfills. Some commenters raised concerns 
that biological treatment systems could not handle low or fluctuating 
flows associated with CRL. The EPA agrees, in part, with these 
comments. Biological treatment systems require a minimum amount of feed 
source for the microorganisms to survive. While facilities have 
demonstrated the ability to supplement these nutrients in the FGD 
wastewater context, CRL generated after a landfill is closed is 
precipitation-dependent and may not be as easy to

[[Page 40247]]

forecast as FGD wastewater flows. Thus, even if facilities provided a 
supplemental feed source, it would be possible to develop either too 
large or too small a bacterial colony. The EPA's record demonstrates 
that hydrogen sulfide formation can result from biological treatment 
when oxidation reduction potential (ORP) is too low. Sulfide produced 
in the system readily forms metal complexes with other metals and 
precipitate out of the FGD wastewater. During backwashing events, the 
system releases any trapped gasses generated in the process, including 
hydrogen sulfide (DCN SE02955). The EPA notes that large concentrations 
of sulfides are only a problem if the ORP goes too low for a long 
time.\141\ The EPA's record lacks evidence of a biological treatment 
system operating on a retired landfill; therefore, no information is 
available on whether other issues related to biological treatment of 
CRL from retired landfills affect ORP or hydrogen sulfide production. 
In the absence of any record evidence of a biological treatment system 
operating on a retired landfill, the EPA concludes that these concerns, 
together with the age of the EGUs being in a retired status and the 
cost considerations regarding biological treatment discussed above, 
justify rejecting this technology as BAT for CRL post-cessation of coal 
combustion.
---------------------------------------------------------------------------

    \141\ For FGD wastewater, EPA recommends ORP monitors to avoid 
these scenarios.
---------------------------------------------------------------------------

    Zero-discharge systems can adapt to changes in flow rates more 
easily than biological treatment. Nevertheless, as with biological 
treatment, the record does not contain any information on zero-
discharge systems operating on CRL or non-CCR landfill leachate after a 
facility has retired. The examples EPA has demonstrating availability 
consist of co-treatment with FGD wastewater or treatment of non-CCR 
landfill leachate during operations. During the development of this 
rule, the EPA sought information on treatment of CRL or non-CCR 
landfill leachate through vendors of applicable systems, but there were 
no known installations on retired landfills were indicated. While it 
may be possible for the EPA to establish zero-discharge systems even in 
record absence of operations post-cessation of coal combustion, when 
this information gap is combined with the age and cost considerations 
discussed above, it leads the EPA to conclude that zero-discharge 
systems do not represent BAT for post-cessation of coal combustion 
discharges of CRL in this subcategory.
    f. The EPA is not including legacy wastewater in the permanent 
cessation of coal combustion subcategory.
    The EPA received some comments suggesting that any new permanent 
cessation of coal combustion subcategory should cover discharges of 
legacy wastewater from EGUs in the subcategory. These comments did not 
provide information demonstrating that legacy wastewater discharges are 
tied to the marginal operating costs of steam EGUs. Rather, the record 
demonstrates that legacy wastewater discharges will primarily continue 
to occur through the dewatering of surface impoundments closing under 
the CCR regulations. Since treatment of legacy wastewater will occur 
whether an EGU continues to burn coal or not, investments made under 
this rule do not have the potential to interfere with the orderly 
transition of generating capacity, as they would be incurred even if 
the EGU had ceased operations years ago. Moreover, because the costs 
must be incurred whether or not the EGU closes, these costs do not 
differ based on the remaining useful life of the EGUs. Since the EPA 
does not find that the statutory factors discussed above as the bases 
to establish this subcategory would apply to legacy wastewater, the EPA 
is not subcategorizing legacy wastewater based on the permanent 
cessation of coal combustion. Instead, the case-by-case limitations 
described in section VII.B.4 of this preamble will continue to apply.
    g. The EPA is finalizing post-coal combustion cessation zero-
discharge limitations for EGUs in this subcategory to avoid 
circumvention.
    As with the permanent cessation of coal combustion by 2028 
subcategory, the EPA proposed to include zero-discharge limitations 
applicable after the permanent cessation of coal combustion date for 
this subcategory, December 31, 2034. The EPA received comments that 
opposed the finalization of this subcategory, but in the alternative 
these commenters advocated for post-coal combustion cessation 
limitations to help ensure that the cease combustion of coal criterion 
for the subcategory is met. EPA also received more general comments as 
described in section VII.C.3 of this preamble.
    After considering these comments, and for the same reasons set 
forth in section VII.C.3 of this preamble, the EPA is finalizing a 
tiered set of zero-discharge BAT limitations that apply following the 
cease combustion of coal by 2034 date, as follows:
     The first tier of these limitations is composed of zero-
discharge limitations for FGD wastewater and BA transport water after 
April 30, 2035.\142\ These limitations would apply if the EGU has in 
fact permanently ceased coal combustion as it represented it would. As 
suggested in the comments, this is 120 days after the latest permanent 
cessation of coal combustion date, allowing for facilities to complete 
any necessary residual decommissioning discharges.\143\
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    \142\ The EPA is also finalizing requirements that the BAT 
limitations for CRL in this subcategory be met no later than April 
30, 2035, to align with the dates in this backstop provision. For 
further discussion, see section VII.E of this preamble.
    \143\ The EPA notes that these do not include discharges of 
legacy wastewaters from surface impoundments closing under the CCR 
rule, which are covered by different regulatory provisions.
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     The second tier is composed of zero-discharge limitations 
for the same wastewaters, as well as CRL, after December 31, 2034. If a 
plant fails to cease combustion of coal by 2034 (as it represented it 
would) for any reason other than those specified in Sec.  423.18, these 
zero-discharge limitations would automatically apply.
    As explained in section VII.C.3 of this preamble, the EPA finds 
that together, the zero-discharge limitations and reporting and 
recordkeeping requirements are sufficient to ensure that facilities do 
not unfairly benefit by continuing to discharge after the subcategory's 
permanent cessation of coal combustion date.
5. Discharges of Unmanaged CRL
    The EPA is establishing a new subcategory for discharges of 
unmanaged CRL, which EPA is defining in this rule to mean the 
following: (1) discharges of CRL that the permitting authority 
determines are the FEDD to a WOTUS through groundwater or (2) 
discharges of CRL that has 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.\144\ After 
evaluating public comments, and in light of the factors specified in 
CWA section 304(b)(2)(B), the EPA finds that the record demonstrates 
such a subcategory is warranted based on the unacceptably high costs to 
the plants in this subcategory associated with zero-discharge 
requirements, which would

[[Page 40248]]

otherwise apply to CRL discharges under this rule (see discussion 
below). For units with discharges in this subcategory, The EPA is 
finalizing the proposed mercury and arsenic limitations, based on 
chemical precipitation, which the record shows are available, are 
economically achievable, and have acceptable non-water quality 
environmental impacts. A discussion of the selected technology basis, 
as well as rejected technology bases, appears below, following two 
subsections that address several overarching comments the EPA received 
about discharges in this subcategory.
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    \144\ The latter type of unmanaged CRL is no different than the 
former except that it is already being collected for treatment and 
discharge as of the effective date of the final rule. Since 
migration from the waste management unit and mixing with groundwater 
occurs in both cases, the characteristics and volumes of these two 
types of unmanaged CRL are expected to be consistent and, therefore, 
have been modeled consistently for the cost analysis discussed in 
section VIII.A of this preamble.
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    The EPA solicited comment on an option to subcategorize EGUs with 
discharges through groundwater. Leachate is typically managed through 
the use of a liner and leachate collection system. In the context of 
municipal solid waste landfills and hazardous waste landfills, a 
leachate collection system is designed to maintain less than a 30-
centimeter depth over the liner.145 146 As stated in Solid 
Waste Disposal Facility Criteria Technical Manual:
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    \145\ 40 CFR 258.40(a)(2).
    \146\ 40 CFR 264.251(a)(2).

    The primary function of the leachate collection system is to 
collect and convey leachate out of the landfill unit and to control 
the depth of the leachate above the liner. The leachate collection 
system (LCS) should be designed to meet the regulatory performance 
standard of maintaining less than 30 cm (12 inches) depth of 
leachate, or ``head,'' above the liner. The 30-cm head allowance is 
a design standard and the Agency recognizes that this design 
standard may be exceeded for relatively short periods of time during 
the active life of the unit. Flow of leachate through imperfections 
in the liner system increases with an increase in leachate head 
above the liner. Maintaining a low leachate level above the liner 
helps to improve the performance of the composite liner.\147\
---------------------------------------------------------------------------

    \147\ U.S. EPA (Environmental Protection Agency). 1993. Solid 
Waste Disposal Facility Criteria Technical Manual. November. EPA530-
R-93-017.

    In contrast, many CCR landfills and surface impoundments have 
unmanaged CRL, which is allowed to percolate out of the WMU and into 
the subsurface and this subcategory applies to such unmanaged CRL. 
Specifically, the final subcategory covers such discharges of CRL that 
are determined, on a case-by-case, site-specific basis by the 
permitting authority to constitute the FEDD to a WOTUS. The EPA is also 
including certain direct discharges of CRL in this subcategory--in 
particular, discharges of CRL that has leached from a waste management 
unit into the subsurface and mixed with groundwater before being 
captured and pumped to the surface--because the EPA is aware that some 
plants could independently choose to pump and treat groundwater as a 
result of the CCR regulations, sometimes before wastewater from the 
impoundments traveling through groundwater has reached a WOTUS and 
become the FEDD to a WOTUS. This subcategory applies to any direct 
discharges of such CRL to a WOTUS. Both types of unmanaged CRL could 
occur at a plant with an unlined WMU, and both present the same basic 
issues in terms of costs for treatment, given the volumes of wastewater 
that would need to be treated to meet BAT limitations for unmanaged 
CRL.
    a. The EPA has CWA authority to regulate certain discharges through 
groundwater from landfills and surface impoundments.
    The EPA proposed that CRL limitations would apply not only to 
traditional end-of-pipe discharges, but also to discharges of CRL 
through groundwater, which a permitting authority deems to be the FEDD 
from a point source to a WOTUS. EPA received many comments related to 
the discharge of CRL through groundwater. Comments expressed varying 
views as to whether CRL discharged through groundwater from landfills 
and surface impoundments would be the FEDD.
    As a threshold matter, as it explained in the proposed rule, the 
EPA is not determining that all discharges through groundwater from 
landfills and surface impoundments are the FEDD from a point source to 
a WOTUS. Rather, in this rule, the EPA is establishing limitations that 
apply to any discharge of this kind that a permitting authority or 
facility owner or operator determines to be the FEDD from a point 
source to a WOTUS, and thus requires an NPDES permit. The threshold 
standard for the ``functional equivalence'' determination is outside 
the scope of this rule.
    Some comments argue that the EPA lacks the legal authority to 
regulate any leachate that reaches navigable waters through groundwater 
from landfills or surface impoundments because landfills and surface 
impoundments are not point sources. These comments cite two cases in 
support of this position. See Sierra Club v. Va. Elec. & Power Co., 903 
F.3d 403 (4th Cir. 2018); Ky. Waterways All. V. Ky, Utils. Co., 905 
F.3d 925 (6th Cir. 2018). Related comments suggest that, in County of 
Maui, there were unique facts regarding the existence of a point source 
that are not applicable in the CRL context.
    In response to these comments, the EPA reaffirms its longstanding 
position, which is consistent with the Maui decision: a point source 
determination is case-specific, and some landfills and surface 
impoundments may likely meet the definition of point sources under the 
CWA. ``The term `point source' means any discernible, confined and 
discrete conveyance, including but not limited to any pipe, ditch, 
channel, tunnel, conduit, well, discrete fissure, container, rolling 
stock, concentrated animal feeding operation, or vessel or other 
floating craft, from which pollutants are or may be discharged.'' 33 
U.S.C. 1362(14). At least some of the landfills and surface 
impoundments at steam electric facilities may fit this definition, in 
that they are ``discernible, confined, and discrete conveyances.'' A 
permitting authority may also deem surface impoundments at these 
facilities to be analogous to ``wells'' or ``containers'' some of the 
illustrative examples in the definition. As the Fifth Circuit noted in 
Southwestern Elec. Power Co. v. EPA, where leachate occurs at a steam 
electric power plant, it is typically collected and transported to an 
impoundment, and ``[u]nlined landfills or impoundments simply `allow 
the leachate to potentially migrate to nearby ground waters, drinking 
water wells, or surface waters.' '' 920 F.3d at 1011 (citing the 2015 
rule preamble); id. at 1029 (noting that the EPA's environmental 
assessment document reports that ``[c]ombustion residual leachate can 
migrate from the site in the ground water at concentrations that could 
contaminate public or private drinking water wells and surface waters, 
even years following disposal of combustion residuals'') (citation 
omitted). And the Fifth Circuit had earlier addressed the question of 
whether sump pits into which miners channeled contaminated runoff and 
which sometimes overflowed to ``waters of the United States'' were 
point sources, holding on these facts that ``[g]ravity flow, resulting 
in a discharge of a pollutant into a navigable water, may be a point 
source discharge if the miner at least initially collected or channeled 
the water and other materials.'' Sierra Club v. Abston Construction 
Co., Inc., 620 F.2d 41, 45 (5th Cir. 1980). Under this rule, permitting 
authorities will continue to determine whether a particular landfill or 
surface impoundment meets the definition of point source, and then they 
will determine whether or not that point source has a discharge of 
pollutants subject to the CWA.
    To the extent that the Fourth Circuit's decision in Sierra Club v. 
Va. Elec. & Power Co. held that an impoundment can never be a ``point 
source'' under the CWA, the Supreme Court's decision in

[[Page 40249]]

Maui calls that holding into question.\148\ While commenters correctly 
point out that the parties in Maui conceded that there was a point 
source, so the issue was not directly before the Court, the injection 
wells at issue in Maui are factually very similar to some EGU surface 
impoundments. The Supreme Court in Maui described the facts of the case 
as a wastewater reclamation facility that ``collects sewage from the 
surrounding area, partially treats it, and pumps the treated water 
through four wells hundreds of feet underground. This effluent, 
amounting to about 4 million gallons each day, then travels a further 
half mile or so, through groundwater, to the ocean.'' County of Maui, 
590 U.S. at 171. Furthermore, the Supreme Court rejected EPA's argument 
that ``all releases of pollutants to groundwater'' are excluded from 
the scope of the permitting program, ``even where pollutants are 
conveyed to jurisdictional surface waters via groundwater,'' in part 
because of the definition of ``point source,'' concluding:
---------------------------------------------------------------------------

    \148\ The decision in Ky. Waterways All. v. Ky, Utils. Co., 905 
F.3d 925, cited by some commenters did not address the question of 
whether an impoundment is a point source but rather held that ``The 
CWA does not impose liability on surface water pollution that comes 
by way of groundwater.'' The decision has been abrogated by Maui.

    It is difficult to reconcile EPA's interpretation with the 
statute's inclusion of ``wells'' in the definition of ``point 
source,'' for wells most ordinarily would discharge pollutants 
through groundwater. And it is difficult to reconcile EPA's 
interpretation with the statutory provisions that allow EPA to 
delegate its permitting authority to a State only if the State 
(among other things) provides ``adequate authority'' to ``control 
the disposal of pollutants into wells.'' Sec.  402(b), 86 Stat. 881. 
What need would there be for such a proviso if the Federal 
permitting program the State replaces did not include such 
---------------------------------------------------------------------------
discharges (from wells through groundwater) in the first place?

County of Maui, 590 U.S. at 181.
    Similarly, some EGU impoundments, like wells, may discharge through 
groundwater to a WOTUS in a manner that is the FEDD. For example, 
suppose leachate from a coal-fired power plant is collected and 
contained in a waterfront surface impoundment dug below the groundwater 
table, and the leachate flows through the groundwater into the nearby 
``water of the United States.'' Excluding such a discharge from CWA 
permitting requirements would create a loophole in the Act's coverage 
similar to the one that concerned the Supreme Court in Maui: ``We do 
not see how Congress could have intended to create such a large and 
obvious loophole in one of the key regulatory innovations of the Clean 
Water Act.'' County of Maui, 590 U.S. at 178-79. Cf. California ex rel. 
State Water Resources Control Bd., 426 U.S., at 202-204 (basic purpose 
of Clean Water Act is to regulate pollution at its source); The Emily, 
9 Wheat. 381, 390 (1824) (rejecting an interpretation that would 
facilitate ``evasion of the law'').
    Thus, to the extent that landfills, surface impoundments, or other 
features that could be considered point sources and from which FEDDs of 
CRL occur to a WOTUS, this rule informs the permitting authority of the 
appropriate technology-based effluent limitations that would apply. At 
this time, the EPA cannot agree with commenters who presume to know the 
extent of such potential discharges. The EPA need not speculate as to 
the myriad of possible scenarios. Determining which impoundments and 
landfills meet the definition of ``point source'' is a task for 
permitting authorities and outside the scope of this rulemaking. 
Instead, the EPA points out that, based on current law and facts as 
they appear in the record, the CRL limitations the EPA is promulgating 
will apply to some discharges from some impoundments and landfills--
i.e., those that a permitting authority determines to be the FEDD from 
a point source to a WOTUS.
    b. Potential interactions with RCRA and the CCR regulations do not 
justify rejection of a nationwide BAT for certain CRL discharges 
through groundwater.
    With respect to RCRA and the CCR regulations, some commenters 
stated that regulation of CRL discharged through groundwater would 
``nullify'' the CCR regulations in violation of RCRA's industrial 
wastewater exclusion or anti-duplication provision. Other commenters 
argued that imposing any CWA requirements on FEDDs of CRL could not be 
harmonized with RCRA requirements found in the CCR regulations and 
recommended that the EPA leave such discharges to be managed by the CCR 
program and states. Each of these comments is addressed in a separate 
discussion below.
    RCRA industrial wastewater exclusion. The EPA disagrees with 
commenters stating that establishing BAT limitations for certain CRL 
discharges through groundwater would ``nullify'' the CCR regulations 
due to RCRA's industrial wastewater exclusion. At the outset, as 
explained above, this rule does not address the scope of the CWA, as it 
does not address which discharges may require an NPDES permit, but 
rather it establishes appropriate technology-based limitations to 
include in such a permit. Since this rule does not expand CWA 
jurisdiction over any discharges--in particular, it does not require 
CWA regulation of discharges, such as certain CRL discharges through 
groundwater, that would not already be regulated by the CWA--it does 
not alter the existing RCRA framework that accounts for the CWA.
    The EPA also disagrees with commenters that regulation of certain 
CRL discharges through groundwater would block regulation by the CCR 
regulations. RCRA excludes from the definition of ``solid waste'' any 
``industrial discharges which are point sources subject to permits'' 
under the CWA. 42 U.S.C. 6903(27). As the EPA has explained before, 
this RCRA exclusion applies to discharges to jurisdictional waters 
under the CWA, and not to any activity, including groundwater releases 
or contaminant migration, that occurs prior to that point. The EPA 
explained this in more detail in a ``Question and Answer'' on the EPA's 
website:

    Does the issuance of an NPDES permit covering discharges from a 
CCR unit exempt the owner/operator from any requirements under the 
CCR rule?
    No, discharges covered by an NPDES permit are not a ``solid 
waste'' pursuant to RCRA section 1004(27). The RCRA exclusion only 
applies to ``industrial discharges that are point sources subject to 
permits,'' i.e., to the discharges to jurisdictional waters, and not 
to any activity, including groundwater releases or contaminant 
migration, that occurs prior to that point. See title 40 of the Code 
of Federal Regulations (CFR) 261.4(a)(2) (``This exclusion applies 
only to the actual point source discharge. It does not exclude 
industrial wastewaters while they are being collected, stored or 
treated before discharge.''). For purposes of the RCRA exclusion, 
EPA considers the ``actual point source discharge'' to be the point 
at which a discharge reaches the jurisdictional waters, and not in 
the groundwater or otherwise prior to the jurisdictional water. 
Thus, the issuance of an NPDES permit for discharges from a 
facility's CCR surface impoundment would not exempt the owner/
operator from any requirements under the CCR rule applicable to the 
disposal unit, such as the requirements to ensure the structural 
stability of the unit, to clean up all releases to the aquifer, and 
to meet all closure standards.\149\
---------------------------------------------------------------------------

    \149\ Available online at: https://www.epa.gov/coalash/relationship-between-resource-conservation-and-recovery-acts-coal-combustion-residuals-rule.

Compare RCRA's ``solid waste'' definition, 42 U.S.C. 6903(27), with the 
CWA's definition of the ``discharge of pollutants,'' 33 U.S.C. 1362(12) 
(``any addition of any pollutant to navigable waters from any point 
source''). Until the point at which the discharge reaches

[[Page 40250]]

``navigable waters,'' any collection, storage, treatment, or even 
groundwater contamination is still subject to RCRA and the requirements 
of the CCR regulations.
    RCRA anti-duplication provision. The EPA also disagrees with 
commenters who asserted that regulation of certain CRL discharges 
through groundwater would be inconsistent with or duplicative of 
regulation by the CCR regulations due to RCRA's anti-duplication 
provision. RCRA, by its terms, requires administration and enforcement 
that is ``not inconsistent'' with, among other Federal statutes, the 
CWA. 42 U.S.C. 6905(a). It further requires both integration and non-
duplication with the CWA ``to the maximum extent practicable.'' 42 
U.S.C. 6905(b) (emphasis added). The requirements do not mean there can 
be no overlap to accomplish the purposes of each statute.
    Circuit courts have found several similar instances of RCRA and the 
CWA operating in tandem.\150\ For example, in Goldfarb v. Mayor and 
City Council of Baltimore, 791 F.3d 500 (4th Cir. 2005), construction 
activities allegedly spread/worsened existing soil, water, and 
groundwater contamination. The defendants maintained their NPDES permit 
shielded them from RCRA liability because of RCRA's anti-duplication 
provision. The court rejected this contention, explaining:
---------------------------------------------------------------------------

    \150\ In contrast, the EPA acknowledges that the Ky. Waterways 
All. case found that RCRA's anti-duplication provision barred CWA 
authority, a finding which is not only not supported by the text of 
the CWA but is also to the EPA's knowledge not found in the case law 
of any other circuit.

    To be ``inconsistent'' for purposes of [RCRA's] Sec.  6905(a), 
then, the CWA must require something fundamentally at odds with what 
RCRA would otherwise require . . . RCRA mandates which are just 
different, or even greater, than what the CWA requires, are not 
necessarily the equivalent of being ``inconsistent'' with the CWA. . 
. . It is not enough that the activity or substance is already 
regulated under the CWA; it must also be ``incompatible, 
incongruous, and inharmonious.'' . . . The district court's 
conclusion is thus built on the faulty premise that the CWA and RCRA 
---------------------------------------------------------------------------
cannot regulate the same activity under any circumstance.

    Goldfarb v. Mayor and City Council of Baltimore, 791 F.3d at 505-
06, 510. Similarly, Ecological Rights Foundation v. Pacific Gas & 
Electric Co., 874 F.3d 1083 (9th Cir. 2017), involved an action against 
owners of mining activities that allegedly leached toxic substances 
into navigable waters. The court held that so long as RCRA's 
application is not ``inconsistent'' with the CWA, the anti-duplication 
provision is no bar to a RCRA action. Id. at 1089, 1095-97 (collecting 
cases and a Department of Justice Office of Legal Counsel opinion). It 
further held that the term ``inconsistent'' must be ``mutually 
repugnant or contradictory'' such that ``one implies abrogation or 
abandonment of the other.'' Id. at 1095 (citations omitted). The case 
expressly recognized that there can be overlap between these regulatory 
schemes. Since case law generally supports the operation of the CWA in 
tandem, not in lieu of RCRA, the EPA disagrees with commenters. See 
also Chemical Waste Management v. EPA, 976 F.2d 2, 23, 25 (D.C. Cir. 
1992).
    Practical interaction of the CCR and ELG rules. The EPA also 
disagrees with commenters who stated that imposing any CWA requirements 
on FEDDs of CRL could otherwise not be harmonized with RCRA 
requirements found in the CCR regulations. The RCRA CCR regulations, 
which post-date the CWA, were written with integration in mind. That 
is, 40 CFR 257.52(b) provides: ``Any CCR landfill, surface impoundment, 
or lateral expansion of a CCR unit continues to be subject to the 
requirements in Sec. Sec.  257.3-1, 3-2, and 3-3.'' And 40 CFR 257.3-
3(a) provides: ``For purposes of section 4004(a) of the [Resource 
Conservation and Recovery] Act, a facility shall not cause a discharge 
of pollutants into waters of the United States that is in violation of 
the requirements of the National Pollutant Discharge Elimination System 
(NPDES) under section 402 of the Clean Water Act, as amended.'' 
Critically, nothing in Sec.  257.3-3(a) or other sections establish a 
RCRA permitting scheme for discharges to navigable waters, nor in any 
other ways contradicts the CWA's NPDES permit program. The CCR 
regulations generally, and Sec.  257.3-3(a) specifically, leave the 
regulation of point source discharges to navigable waters to the CWA. 
The CCR regulations regulate the management of CCR to protect human 
health and the environment, including groundwater, from contamination 
associated with the mismanagement of these wastes. See, e.g., 40 CFR 
257.91 through 257.98. They do so because, among other important 
reasons, CCR is a potential source of contamination in wells used for 
drinking water.
    Given the above, the EPA does not agree with commenters that 
establishing limitations for functionally equivalent CRL discharges 
through groundwater would conflict with the CCR regulations. Instead, 
the CCR regulations require CRL-contaminated groundwater to meet 
specific levels or to be cleaned up to those levels through corrective 
action. The EPA expects that in many cases this would require pump-and-
treat operations.\151\ To the extent that a facility elects to pump 
CRL-contaminated groundwater to the surface and discharge it directly, 
this final subcategory and corresponding limitations would apply to the 
end of that pipe. While groundwater monitoring may be appropriate to 
ensure that CRL is not evading the pump-and-treat operations and 
resulting in an unpermitted discharge to a WOTUS, the groundwater 
concentrations would not be subject to this final rule.
---------------------------------------------------------------------------

    \151\ The EPA acknowledges that, at present, many facilities 
have instead selected monitored natural attenuation as a remedy even 
though this remedy would, by definition, patently fail to meet the 
cleanup standards established in Sec.  257.97(b).
---------------------------------------------------------------------------

    To further elaborate the point that the limitations established in 
this final rule are for surface water discharges, consider the 
alternatives to pump-and-treat operations. Facilities are not required 
to employ the specific technology of chemical precipitation established 
as BAT today. Some commenters specifically requested that the EPA 
consider the flexibility for facilities to clean close their surface 
impoundments or to perform in situ treatment or impermeable barriers. 
But this flexibility already exists. If a facility were to install an 
impermeable barrier that prevented groundwater contamination from 
discharging to a WOTUS, or a semi-permeable barrier that treated the 
discharge to remove toxic pollutants, it could satisfy the specific 
mercury and arsenic limitations that the EPA is finalizing. It also 
might be possible for facilities to avoid the need for an NPDES permit 
by clean closing and eliminating any point source itself. In these 
cases, there very well may continue to be CRL-contaminated groundwater, 
but this is outside the purview of the CWA because the CRL would not be 
reaching WOTUS, as discussed in the sections above. Thus, the EPA does 
not find any conflict between the CCR regulations' protection of 
groundwater and the establishment of BAT limitations for CRL discharged 
through that groundwater that is found to be the FEDD; nor does it find 
any way in which the two sets of requirements cannot be harmonized.
    c. The EPA selects chemical precipitation as BAT for discharges of 
CRL in this subcategory.
    For this subcategory, the EPA is establishing BAT limitations for 
mercury and arsenic based on chemical precipitation. Specifically, the 
technology basis for BAT is a chemical

[[Page 40251]]

precipitation system that employs hydroxide precipitation, sulfide 
precipitation (organosulfide), and iron coprecipitation.
    As described in section VII.C.4 of this preamble, the rule record 
is extensive in support of the EPA's finding that chemical 
precipitation is technologically available for the treatment of arsenic 
and mercury in CRL. As far back as the 2015 rule, the EPA found that 
four plants operated chemical precipitation systems on their CRL.\152\ 
EPA also found that chemical precipitation was in use on FGD wastewater 
(which the EPA found was characteristically similar to CRL), metal 
products and machinery plants, iron and steel manufacturers, metal 
finishers, and mining operations (including coal mines).\153\ All of 
these uses have demonstrated the use of chemical precipitation 
technology to remove arsenic and mercury.\154\
---------------------------------------------------------------------------

    \152\ U.S. EPA (Environmental Protection Agency). 2015. 
Technical Development Document for the Effluent Limitations 
Guidelines and Standards for the Steam Electric Power Generating 
Point Source Category. September. EPA-821-R-15-007. Available online 
at: https://www.epa.gov/sites/default/files/2015-10/documents/steam-electric-tdd_10-21-15.pdf.
    \153\ Id.
    \154\ Id.
---------------------------------------------------------------------------

    At proposal, the EPA's preferred regulatory option would have 
established chemical precipitation as BAT for all types of CRL 
discharges. Several commenters took issue with the EPA's proposed 
findings and BAT selection for FEDDs of CRL. These commenters stated 
that EPA failed to evaluate how CRL changes in groundwater. Commenters 
stated that differences from end-of-pipe CRL suggest that the EPA 
should decline to set national limitations and retain case-by-case BPJ 
determinations for, or alternatively require only monitoring of, FEDD 
of CRL at this time.
    With respect to the interaction of CRL with groundwater, while the 
EPA received general comments about the possibility of interactions in 
groundwater, commenters did not provide data to demonstrate that CRL in 
groundwater changes to the extent that pollutant concentrations would 
no longer fall within the range of concentrations evaluated by the EPA 
for CRL. Nor did commenters provide data that CRL becomes untreatable 
via chemical precipitation from any such changes. Instead, comments 
describe ``attenuation'' such as through adsorption. However, to the 
extent that adsorption and other attenuation processes would remove 
pollutants, this would only make it easier for chemical precipitation 
to meet the established limitations.
    In addition to being technologically available, chemical 
precipitation for this subcategory is economically achievable. At 
proposal, EPA could not prospectively determine how many or which 
instances of CRL discharged through groundwater would ultimately be 
found to require CWA permits. As described above, to be a covered 
discharge, there must be a discharge (or FEDD) of pollutants from a 
point source into a WOTUS. Since this determination is outside the 
scope of the rule, EPA examined this cost via a sensitivity analysis 
entitled Evaluation of Unmanaged CRL (DCN SE11501). The fact that EPA 
estimated these costs (and pollutant loadings) in a separate document 
from the more traditional end-of-pipe discharges does not mean that the 
EPA concluded that none would be subject to CWA permitting, as some 
commenters claimed. Neither did the EPA's assumption for the purposes 
of a worst-case costing analysis suggest that the EPA was concluding 
that all of these potential discharges would be subject to CWA 
permitting, as other commenters claimed. Instead, when total costs (and 
pollutant loadings) are viewed in conjunction with this separate 
analysis, they provide the range within actual costs (and pollutant 
loadings) are expected to fall. The EPA acknowledges that a best 
estimate would be helpful, but in the absence of permitting 
determinations on which discharges are subject to CWA permitting, the 
EPA declines to speculate as to the ultimate coverage. This position is 
consistent with the position outlined above. All that the EPA is 
required to do for this rulemaking is make a reasonable estimation of 
costs, which EPA has does done. See Chem. Mfrs. Ass'n v. EPA, 870 F.2d 
at 237-38.
    For the final rule, EPA has updated these CRL costs in Evaluation 
of Unmanaged CRL (DCN SE11501). These engineering costs were then used 
to develop an upper bound and lower bound that more accurately reflects 
the range of costs of treating unmanaged CRL as described in section 
VIII.A of this preamble. Using these costs, the EPA then conducted a 
screening-level analysis of economic impacts, which helped inform EPA's 
determination that the final rule's unmanaged CRL limitations are 
economically achievable. For further discussion of the screening-level 
analysis and economic achievability, see sections VII.F and VIII.C.1 of 
this preamble.
    The EPA notes that some commenters suggested that state permitting 
authorities would face an incredible regulatory burden if the rule were 
finalized as proposed.\155\ The EPA disagrees that it is creating any 
additional burden to permitting authorities in finalizing this 
subcategory. Permitting authorities are already required to determine 
whether a discharge is subject to CWA permitting and to act on 
applications for CWA permits or certain modification requests for such 
permits. Furthermore, FEDDs are already subject to the CWA under Maui. 
Thus, to the extent that permitting authorities are already required to 
evaluate and develop technology-based and water quality-based effluent 
limitations for FEDDs, this existing burden will not change, regardless 
of the EPA's selection of BAT. If burden is changing at all, it is 
decreasing, because EPA is selecting chemical precipitation as BAT, as 
discussed in the section below. Since this replaces BPJ determinations, 
it means that permitting authorities can avoid BPJ analyses that they 
otherwise would have performed for FEDDs of CRL.
---------------------------------------------------------------------------

    \155\ Some comments also pointed to the state amicus brief filed 
in Maui, where states made this very argument in a broader context 
(an argument ultimately rejected by the Maui Court itself).
---------------------------------------------------------------------------

    d. The EPA rejects surface impoundments as BAT for discharges of 
CRL in this subcategory.
    The EPA is not selecting surface impoundments as BAT for FEDDs of 
CRL. BAT must achieve ``reasonable further progress'' toward the CWA's 
goal of eliminating pollution. See Southwestern Elec. Power Co. v. EPA, 
920 F.3d at 1003, 1006 (citing Nat'l Crushed Stone v. EPA, 449 U.S. at 
75). The record shows that chemical precipitation removes more 
pollutants than surface impoundments and that chemical precipitation is 
technologically available, is economically achievable, and has 
acceptable non-water quality environmental impacts.
    With respect to comments suggesting the EPA finalize only a 
monitoring requirement, the EPA does not view monitoring alone as 
satisfying the statutory obligation to identify BAT to control all 
discharges, particularly where there is a technology that can be 
applied to control discharges of CRL, chemical precipitation, that is 
technologically available, is economically achievable and has 
acceptable non-water quality environmental impacts. As described in 
section XIV.C.3 of this preamble below, however, the EPA is finalizing 
additional monitoring requirements to

[[Page 40252]]

support the implementation of the limitations in this subcategory.
    e. The EPA rejects more stringent technologies as BAT for 
discharges of CRL in this subcategory.
    EPA rejects zero-discharge systems as BAT for this subcategory. The 
EPA finds that the potential zero discharge costs for CRL discharges in 
this subcategory are unacceptably high. EPA's CRL costs as reflected in 
Evaluation of Unmanaged CRL (DCN SE11501) show that the capital costs 
of zero-discharge treatment could range as high as $17.4 billion while 
O&M costs could range as high as $2.04 billion per year. The annualized 
total costs of zero discharge could be as high as $3.69 billion. These 
costs are nearly an order of magnitude higher than total costs to the 
industry for all of the remaining end-of-pipe discharges from every 
wastestream combined (including costs associated with discharges of CRL 
that is not covered by this subcategory). The EPA finds that these 
additional zero discharge costs are unreasonable. Costs are one of the 
statutory factors that the EPA must consider, and courts have found 
that the EPA can properly rely on costs in rejecting potential BAT 
technologies. See e.g., BP Exploration & Oil Inc. v. EPA, 66 F.3d 784, 
799-800 (6th Cir. 1995).\156\ For further discussion of costs and 
economic achievability, see sections VII.F and VIII.
---------------------------------------------------------------------------

    \156\ The high costs in this case were estimated to be about $3 
billion in capital costs, or $6.7 billion after adjusting for 
inflation to 2023 dollars. The EPA notes that the $17.4 billion in 
capital costs for zero discharge here, even if only half of such 
discharges are covered, would still be higher (about 2.5 times).
---------------------------------------------------------------------------

    The EPA also rejects chemical precipitation plus low hydraulic 
residence time biological reduction as BAT for this subcategory. While 
no commenter recommended that the EPA select chemical precipitation 
plus low-hydraulic-residence-time biological reduction as BAT for 
discharges of CRL in this subcategory, the record does contain two 
plants treating traditional, end-of-pipe CRL with biological treatment. 
The EPA does not have sufficient data from these plants on which to 
base possible limitations. Therefore, the EPA declines to identify 
chemical precipitation plus biological treatment as BAT.\157\
---------------------------------------------------------------------------

    \157\ Although the EPA did not conduct a sensitivity analysis on 
costs of this technology as it did for chemical precipitation or 
zero discharge, the EPA notes that this cost would be between these 
two costs based on the cost estimation results of the previous 
rulemakings. Since these costs would be higher than chemical 
precipitation alone, they may also be unacceptably high, as are the 
costs for zero discharge.
---------------------------------------------------------------------------

6. Legacy Wastewater Discharged From Surface Impoundments Commencing 
Closure After July 8, 2024
    The EPA is establishing a new subcategory for legacy wastewater 
discharged from surface impoundments which commence closure under the 
CCR regulations after July 8, 2024. For units in this subcategory, the 
EPA is establishing mercury and arsenic limitations based on chemical 
precipitation. More specifically, the technology basis for BAT includes 
the same chemical precipitation system described in the 2015 rule, 
which employs hydroxide precipitation, sulfide precipitation 
(organosulfide), and iron coprecipitation.
    At proposal, the EPA solicited comment on a legacy wastewater 
subcategory for composite-lined surface impoundments that meet the 
location restrictions of the CCR regulations. In contrast to most 
surface impoundments, the EPA identified 22 surface impoundments at 17 
facilities in Legacy Wastewater at CCR Surface Impoundments (DCN 
SE10252) that the record indicated met these criteria. The EPA 
solicited comment on this subcategory because its view was that these 
surface impoundments can continue to operate and thus would likely not 
begin closure and dewatering until after the effective date of any 
final ELG. Since these surface impoundments would not already be in the 
midst of dewatering under the tight closure timeframes of the CCR 
regulations, these facilities would have time to develop a CCR closure 
plan that included wastewater treatment during the dewatering phase of 
closure. Many commenters were opposed to the establishment of such a 
subcategory based on liner type. The EPA also received comments, 
however, recommending that, in order to address the issue that it had 
raised at proposal about potentially differentiated limitations for 
certain impoundments that have not already begun to dewater, a legacy 
wastewater subcategory should be created that is defined based on a 
deadline under the CCR regulations.
    After considering the comments received and evaluating the record 
in light of the factors specified in CWA section 304(b)(2)(B), the EPA 
concludes that a subcategory is warranted for certain legacy wastewater 
discharges based on process changes at these plants happening under the 
CCR regulations. First, the EPA agrees with commenters that a liner-
based subcategory would be inappropriate. On the one hand, some 
composite-lined surface impoundments may have already commenced closure 
under the CCR regulations. Thus, a subcategory that included these 
units would still include surface impoundments in the midst of closure 
under the tight deadlines of the CCR regulations, the very scenario 
described in section VII.B.4 of this preamble, for which the EPA found 
it is inappropriate to establish nationwide BAT limitations. On the 
other hand, the CCR regulations include flexibilities that allow a 
facility needed for reliability to continue to receive waste in an 
unlined surface impoundment or to make an alternate liner demonstration 
to continue to receive waste in an unlined surface impoundment. In both 
cases, the unlined surface impoundment could continue operation and not 
commence closure until after the ELG effective date. Thus, similar to 
the lined units discussed at proposal, these facilities would be able 
to build wastewater treatment into their closure plans. As is apparent 
from this discussion, a subcategory based on liner type is potentially 
both overinclusive and underinclusive, which was not the EPA's intent.
    The EPA does, however, agree with comments suggesting an 
alternative subcategory designation more appropriately aligned with the 
EPA's intent and tied to the regulatory triggers in the CCR rule. It 
was suggested that the EPA consider using the CCR regulations' cease 
receipt of waste date; however, after a more thorough examination of 40 
CFR part 257, the EPA finds that the ``commence closure'' date of Sec.  
257.102(e) is the appropriate regulatory trigger. This provision 
applies to surface impoundments that are not closed for cause (i.e., 
unlined or failing location restrictions), but rather because the 
surface impoundment will no longer be used.\158\ This subcategorization 
solves the dual problem described for the proposed liner-based 
subcategorization above. If a lined surface impoundment has already 
commenced closure under Sec.  257.102(e), then it would not be subject 
to this subcategory, and if an unlined surface impoundment is 
continuing to operate under one of the CCR rule flexibilities, then it 
will not yet have commenced closure pursuant to this provision. Thus, 
the final rule subcategory captures only surface impoundments that are 
not in the midst of closure, as the proposed rule intended. While the

[[Page 40253]]

EPA declined to establish nationwide BAT limitations for legacy 
wastewater in section VII.B.4 of this preamble based on process 
changes, specifically the ongoing closure of these units under the CCR 
rule, the EPA finds that this factor is inapplicable to the legacy 
wastewater that will be discharged in the future at these 
subcategorized surface impoundments.
---------------------------------------------------------------------------

    \158\ Commencing closure is triggered when a unit ceases receipt 
of waste or ceases extraction of materials for beneficial use, 
though facilities are also permitted to postpone this commence 
closure date if they make a filing that the facility intends to 
restart the receipt of waste or extraction of materials for 
beneficial use at a specific future date.
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    a. The EPA selects chemical precipitation as BAT for legacy 
wastewater in this subcategory.
    Since nationwide limitations are appropriate for this subcategory, 
the EPA next evaluates the final rule technology basis of chemical 
precipitation. For this subcategory of legacy wastewater discharges, 
EPA is establishing chemical precipitation-based limitations, as they 
are available, are economically achievable, and have acceptable non-
water quality environmental impacts, as described below.
    The EPA finds that chemical precipitation is available to treat 
legacy wastewater in this subcategory. At the time of the 2015 rule, 
the Agency acknowledged that chemical precipitation was being used on 
legacy wastewater discharges comprised of ash transport water. 80 FR 
67855. Since that time, the EPA has learned of additional use on legacy 
wastewater of chemical precipitation at two Duke facilities and an SDE 
system at Boswell Energy Center. In addition to the use of chemical 
precipitation at a number of legacy wastewaters domestically, the EPA 
notes that, in the 2015 record, it did not discuss potential technology 
transfer of chemical precipitation-based limitations to legacy 
wastewater based on its performance in treating other wastestreams that 
comprise legacy wastewater. The Agency has consistently found, however, 
that two of the other three wastewaters regulated in this final rule 
(FGD wastewater and CRL) have the same pollutants and are amenable to 
treatment with the same treatment systems. As a result of this finding, 
the 2015 rule established NSPS for CRL based on chemical precipitation. 
Furthermore, in 2015, also found that CRL has the same pollutants as BA 
transport water, a wastewater that some facilities treated with 
chemical precipitation at the time of that final rule. See EPA-HQ-OW-
2009-0819-6230. In short, the three wastewaters being regulated in this 
final rule for which the EPA is amending the legacy wastewater 
limitations have all been successfully treated with chemical 
precipitation systems. Based on what is known about the properties of 
these treatment systems, the characteristics of the various 
wastestreams at issue, and the demonstrated ability of chemical 
precipitation to treat such wastestreams, the EPA is transferring 
mercury and arsenic limitations from FGD wastewater and CRL to the 
subcategory of legacy wastewater described in this section for the 
final rule. As previously explained, EPA may rely on technology 
transfer to establish technology-based limitations such as those in 
this rule. See Am. Iron & Steel Inst. v. EPA, 526 F.2d at 1058, 1061, 
1064; Weyerhaeuser Co. v. Costle, 590 F.2d at 1054 n.70; Reynolds 
Metals Co. v. EPA, 760 F.2d at 562; California & Hawaiian Sugar Co. v. 
EPA, 553 F.2d at 287.
    The EPA also finds that the costs of chemical precipitation systems 
are economically achievable for the subcategory. At proposal, the EPA 
evaluated the costs for legacy wastewater in a sensitivity analysis. 
For this final rule, EPA has included these costs in its primary cost 
estimates and economic screening analysis. IPM, which projects 
decisions on dispatch of EGUs, is not affected by these costs, which 
occur irrespective of generation. Thus, the costs are not included in 
the IPM analysis. However, the cost analysis demonstrates that costs 
for treating this wastestream are low, a finding that is bolstered by 
the relatively low impacts as a percent of revenues as seen in the 
economic screening analysis of the final rule. (For further 
information, see sections VII.F and VIII.) Because the EPA is required 
to consider whether the cost of BAT can be reasonably borne by the 
industry and confers on the EPA discretion in consideration of the BAT 
factors, see, e.g., Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 262; 
Weyerhaeuser v. Costle, 590 F.2d at 1045, EPA finds that these 
additional costs are economically achievable as that term is used in 
the CWA.
    Finally, the EPA finds that the non-water quality environmental 
impacts associated with chemical precipitation systems for controlling 
legacy wastewater discharges in this subcategory are acceptable. See 
sections VII.G and X below for more details.
    b. The EPA rejects less stringent technologies as BAT for legacy 
wastewater in this subcategory.
    The EPA did not select surface impoundments as BAT for legacy 
wastewater in this subcategory, as surface impoundments would remove 
fewer pollutants than the BAT technology selected above, which is 
available, is achievable, and has acceptable non-water quality 
environmental impacts, and which will better achieve the BAT 
requirement of making reasonable further progress toward the CWA's 
goals. See Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1003, 1006 
(citing Nat'l Crushed Stone v. EPA, 449 U.S. at 75).
    c. The EPA rejects more stringent technologies as BAT for legacy 
wastewater in this subcategory.
    The EPA is not selecting chemical precipitation plus biological 
treatment as BAT for legacy wastewater in this subcategory. Biological 
treatment requires a period of optimization for concentration and 
composition of the microorganisms to reach a steady state in which the 
reduction-oxidation activity of the microorganisms can reduce 
pollutants of concern without creating excessive levels of hydrogen 
sulfide gas. Unlike FGD wastewater, however, which is a relatively 
consistent wastewater that can be equalized in tanks to moderate 
differences before treatment, legacy wastewater being drained from a 
surface impoundment is known to quickly change pollutant concentrations 
as the surficial water is drained and dewatering progresses down 
through one or more layers of CCR. Due to the relatively short 
timelines for dewatering when compared to the equalization timeframes 
for the bacteria, biological reduction would not be able to 
consistently meet the biological treatment-based limitations 
established for FGD wastewater in the 2015 or 2020 rules.
    The EPA is also not selecting chemical precipitation plus ZVI 
systems as BAT. The EPA acknowledges that it learned of a plant using 
this technology to treat its legacy wastewater. The EPA does not, 
however, have any information in the record on the influent or effluent 
data from this system to establish limitations, nor has the EPA 
developed ZVI-based limitations for any other wastestream that it can 
transfer. Commenters did not advocate for establishment of limitations 
based on ZVI systems, nor submit any information related to the 
performance of these systems, including data that would allow the 
Agency to develop numerical limitations; therefore, the EPA cannot, at 
this time, establish limitations based on chemical precipitation plus 
ZVI systems.
    The EPA finds that zero-discharge systems are not BAT for legacy 
wastewater in this subcategory based on the statutory factor of age and 
cost, as well as given certain information gaps in the record. 
Specifically, the EPA finds that more stringent zero-discharge 
technologies are not commensurate with the age of the facility being in 
a retired status, which would lead to unacceptably higher capital costs 
that

[[Page 40254]]

can no longer be spread over electricity sales.
    As described in section VII.C.4 of this preamble with respect to 
CRL generated and discharged after a plant retires, surface impoundment 
dewatering at EGUs in this subcategory is also likely to take place 
when a facility would no longer be generating revenue, as several 
commenters pointed out. Thus, any treatment system, including the 
selected BAT basis of chemical precipitation, built to operate only 
after retirement will necessarily have to incur capital costs in a 
disparate circumstance of a post-retirement age when compared to costs 
to EGUs that dewater their impoundments while still generating revenue. 
Compared to chemical precipitation systems, however, zero-discharge 
systems worsen the disparate circumstance of EGUs facing costs while in 
a retired status. Zero-discharge systems typically have capital costs 
approximately double the capital costs of chemical precipitation 
systems alone. The EPA finds that the increased cost of these more 
stringent technologies renders them unacceptable in light of the unique 
position of the EGUs to which they would apply. The EPA intends that 
the cost and economic achievability rationale discussed here is unique 
to the small number of industry-wide discharges at retired facilities 
with no revenue, and thus will not form a precedent for evaluating 
costs and economic achievability at the vast majority of facilities 
which continue to operate and have active revenue streams.
    The EPA also notes that there are data gaps in the record for zero-
discharge technologies. The current record reflects only a single 
facility employing a zero-discharge SDE system to treat legacy 
wastewater, and unlike Boswell Energy Center, many facilities in this 
subcategory will dewater and close their ash impoundments after the 
facility ceases generating electricity. Without electricity production, 
there is no slipstream of flue gas with which to operate the same type 
of SDE system that is achieving zero discharge at Boswell. The EPA is 
not aware of any other facility that is employing a zero-discharge 
technology, such as membrane filtration or thermal evaporation, to 
treat its legacy wastewater. While it is possible that the EPA could 
transfer non-zero numerical limitations from treatment of other 
wastestreams using these technologies, given the information gap and 
the additional costs in the context of these EGUs unique position 
discussed above, the EPA declines to select zero-discharge systems as 
BAT for legacy wastewater in this subcategory.
7. Interim Limitations Applicable to FGD Wastewater and BA Transport 
Water
    The EPA is retaining the final 2020 rule BAT technology bases and 
limitations for FGD wastewater and BA transport water as interim 
limitations until the applicability dates of the new zero-discharge 
limitations (see section VII.E of this preamble for availability timing 
of the new requirements). Specifically, the 2020 rule established BAT 
limitations for FGD wastewater based on chemical precipitation plus low 
hydraulic residence time biological reduction or, in the case of the 
high FGD flow and LUEGU subcategories, based on chemical precipitation 
only. BAT limitations for BA transport water were based on high recycle 
rate systems with up to a 10 percent volumetric purge or, in the case 
of the LUEGU subcategory, based on surface impoundments with a BMP 
plan. The EPA finds that the 2020 BAT technology bases continue to be 
available, economically achievable, and have acceptable non-water 
quality environmental impacts for all of the reasons stated in the 2020 
rulemaking and as supplemented by the new IPM analyses updating the 
Agency's economic achievability determination and further discussed 
below.
    Although it proposed more stringent zero-discharge limitations in 
2023, the Agency always intended that the 2020 rule limitations would 
continue to apply. For example, when EPA explained its reasoning as to 
why it did not postpone the requirements in the 2020 rule, it stated, 
``There is no basis in the record indicating that the limitations 
finalized in 2020 are not available or economically achievable, and 
thus there is no reason for the EPA to postpone their implementation. 
EPA is focused on progress toward eliminating discharges, consistent 
with CWA section 301(b)(2)(A).'' 88 FR 18886. Similarly, the EPA's 
earlier announcement of this supplemental rulemaking stated (and the 
proposal reiterated) that ``the pollutant reductions accomplished by 
the existing rules will occur while the Agency engages in rulemaking to 
consider more stringent requirements.'' 86 FR 41802.
    The EPA received many comments from electric utilities arguing that 
this approach was not appropriate. Some commenters claimed that the EPA 
should have halted implementation while it considered rule revisions. 
Some commenters stated that costs of the 2020 rule technologies would 
not be fully recovered over the timeframe before new, more stringent 
limitations would come into effect. Others described these costs as 
high, or potentially drawing investment away from the transition to 
cleaner energy sources. One commenter claimed that the EPA violated its 
own policy of only revisiting ELGs for seven years after a final 
regulation is issued. Finally, the EPA received comments that the 2020 
rule limitations were well founded.
    After considering public comments, including those mentioned above, 
the EPA is retaining the 2020 rule limitations applicable to FGD 
wastewater and BA wastewater as interim limitations before the 
applicability dates of the zero-discharge limitations finalized. The 
EPA disagrees that it should have halted implementation of the 2020 
rule. The EPA found the 2020 rule technologies to be available, 
economically achievable, and to have acceptable non-water quality 
environmental impacts. While the EPA agrees that cost recovery periods 
for the 2020 rule technologies will be curtailed, and that it is 
possible that this would divert investment dollars from clean energy 
projects, the record shows that the total costs of implementing the 
technologies of both rules under the corresponding timeframes are 
economically achievable according to the Agency's IPM modeling, 
discussed further in section VII.F of this preamble. Furthermore, the 
EPA disagrees with comments suggesting it cannot revisit an ELG for 
seven years. The EPA has revisited many final ELG rules within this 
time frame, either as the result of a court's vacatur or remand, or as 
the result of an administrative petition. In fact, the same commenter 
arguing against the EPA's supplemental rulemaking here submitted 
administrative petitions for the EPA to reconsider the 2015 rule, and 
at that time found no procedural problem with the EPA revising a rule 
before seven years had elapsed.
    The EPA views the retention of the 2020 BAT limitations for FGD 
wastewater and BA wastewater in the interim as in keeping with the 
technology-forcing nature of the CWA and essential for meeting the 
statutory requirement that BAT result in reasonable further progress 
toward the CWA's goal of zero discharge of pollutants. See Nat. Res. 
Def. Council v. EPA, 808 F.3d 556, 563-64 (2d Cir. 2015) (``Congress 
designed this standard to be technology-forcing, meaning it should 
force agencies and permit applicants to adopt technologies that achieve 
the greatest reductions in pollution.'') (citation omitted). Without 
these interim limitations, which have a

[[Page 40255]]

latest applicability date of December 31, 2025, plants could 
potentially have up to December 31, 2029 (the latest applicability for 
the zero-discharge requirements in this final rule), before they are 
required to meet limitations beyond the 1982 limitations based on 
surface impoundments. The EPA never intended that, as part of this 
rulemaking to explore additional pollutant discharge reductions that 
this industry could achieve, plants could thereby avoid taking 
available and achievable steps toward discharge control in the interim. 
See Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1003-1004 
(describing the 1982-era regulations as from a ``by-gone era'' in which 
limitations were based on the ``archaic'' technology of surface 
impoundments, ``which are essentially pits where wastewater sits, 
solids (sometimes) settle out, and toxins leach into groundwater.''). 
More information on implementation of the 2020 rule limitations as an 
interim step toward achievement of the new zero-discharge FGD 
wastewater limitations is available in section XIV.A of this preamble.

D. Additional Rationale for the Proposed PSES and PSNS

    Before establishing PSES/PSNS for a pollutant, the EPA examines 
whether the pollutant ``passes through'' a POTW to WOTUS or interferes 
with the POTW operation or sludge disposal practices. In determining 
whether a pollutant passes through POTWs for these purposes, the EPA 
typically compares the percentage of a pollutant removed by well-
operated POTWs performing secondary treatment to the percentage removed 
by the BAT/NSPS technology basis. A pollutant is determined to pass 
through POTWs when the median percentage removed nationwide by well-
operated POTWs is less than the median percentage removed by the BAT/
NSPS technology basis. The EPA establishes pretreatment standards for 
those pollutants regulated under BAT/NSPS that pass through POTWs.
    The EPA received comments that it should update this analysis to 
include more recent POTW pollutant removal data. Specifically, one 
commenter pointed to more recent analyses that POTWs remove 45 percent 
of arsenic and 60 percent of mercury. This comment also faulted the EPA 
for summarily finding that pollutants treated by a zero-discharge 
system would pass through a POTW since the POTW does not achieve 100 
percent removals of these pollutants.
    After considering these comments, the EPA finds that the 2015 rule 
pass-through analyses of these same technologies is still 
representative of current pollutant behavior. Specifically, the EPA is 
continuing to rely on the pass-through analyses as the basis of the 
limitations and standards in the 2015 rule as the Agency did in the 
2020 rule. This analysis found that POTWs do not significantly remove 
mercury and arsenic in several wastewaters. Contrary to commenters' 
assertions that new data show some significantly improving removals of 
these pollutants, the EPA notes that table 10-1 of the 2015 TDD shows 
median arsenic removals of 65.8 percent and median mercury removals of 
90.2 percent, higher removals than the new removal data cited by the 
commenters. Thus, because the EPA considered pass-through using higher 
pollutant removals, the EPA's findings would not change substituting 
the new pollutant removal data. With respect to zero discharge, the EPA 
is establishing zero-discharge limitations for three wastestreams in 
this rule. As in the 2015 rule, the EPA did not conduct its traditional 
pass-through analysis for wastestreams with zero-discharge limitations 
or standards. Zero-discharge limitations and standards achieve 100 
percent removal of pollutants, including salts like boron and bromide 
which are not treated at all by the typical POTW treatment system.\159\ 
Therefore, the EPA concludes that all pollutants in those wastestreams 
treated by the zero-discharge technologies would otherwise pass through 
the POTW absent application of the zero discharge technologies that 
form the BAT bases for FGD wastewater, BA transport water, and CRL.
---------------------------------------------------------------------------

    \159\ The commenter has, in fact, historically sent its FGD 
wastewater to a POTW, thereby diluting the wastewater to the extent 
that it can meet a water quality-based effluent limitation for 
boron.
---------------------------------------------------------------------------

    PSES. After considering public comments and the record in light of 
the relevant CWA statutory factors, the EPA is establishing PSES for 
indirect discharges based on the technologies described in Option B. 
EPA is establishing Option B technologies as the bases for PSES for the 
same reasons that it is finalizing the Option B technologies as the 
bases for BAT for direct dischargers. The EPA's analysis shows that, 
for both direct and indirect dischargers, the final rule technologies 
are available and economically achievable, and they have acceptable 
non-water quality environmental impacts, including energy requirements 
(see sections VIII and X). For the final rule, the EPA is not selecting 
other technology bases for PSES for the same reasons that it is not 
finalizing other technology bases for BAT.
    Furthermore, the EPA reaches the same conclusions for the same 
reasons discussed in section VII.C of this preamble with respect to 
several subcategories. EPA finds that retention of differentiated PSES 
for EGUs permanently ceasing coal combustion by 2028 are warranted. The 
EPA also finds establishing two new subcategories with differentiated 
PSES for EGUs permanently ceasing coal combustion by 2034 and legacy 
wastewater discharged from surface impoundments commencing closure 
after July 8, 2024, is warranted. In contrast, the EPA is not 
establishing a subcategory with differentiated PSES for discharges of 
unmanaged CRL because that subcategory is only intended to address CRL 
discharges that are found by a permitting authority to be the 
functional equivalent of a direct discharge to WOTUS or that are direct 
discharges of CRL to a WOTUS that result from the capture and pumping 
to the surface of CRL that has leached from a waste management unit 
into the subsurface and mixed with groundwater. Given the high volumes 
associated with operations that might capture and pump to the surface 
CRL that has leached from a waste management unit into the subsurface, 
the EPA does not expect facilities to find it a cost-feasible 
alternative to send such volumes to a POTW.
    With respect to the low utilization subcategory, the EPA is 
eliminating the PSES subcategory for LUEGUs, as it does for direct 
dischargers, after further considering specific facts about the 
universe of plants that would potentially qualify for this subcategory. 
The EPA is only aware of one indirect discharger that has filed a NOPP 
to potentially avail itself of this subcategory, the Whitewater Valley 
Station; the EPA received no further comments indicating other indirect 
dischargers that planned to make use of the 2020 LUEGU subcategory. 
Whitewater Valley Station consists of two EGUs (Coal Boiler #1 and Coal 
Boiler #2). Coal Boiler #1 has a nameplate capacity of 35 MW, and it 
had 2019 and 2020 CURs of 5 percent and 3.67 percent, respectively. 
Coal Boiler #2 has a nameplate capacity of 65 MW, and it had 2019 and 
2020 CURs of 5.5 percent and 5.1 percent, respectively. On its website, 
IMPA states that the station ``has been utilized by IMPA during peak 
load periods during the hot summer months and cold winter months.'' 
\160\ This utilization

[[Page 40256]]

profile was confirmed by IMPA's comments on the 2023 proposed rule. At 
proposal, the EPA noted that Coal Boiler #1 is small enough to avail 
itself of the 2015 rule subcategory for small EGUs (i.e., less than or 
equal to 50 MW nameplate capacity). While IMPA agreed, it also conveyed 
in its comments that it may not be able to increase the utilization of 
this small EGU without changes to its permits, and furthermore that 
this would not make up for any loss of operation of Coal Boiler #2 
since both EGUs perform winter and summer peaking operations in tandem.
---------------------------------------------------------------------------

    \160\ See www.impa.com/about-impa/generation-resources/giant-tcr.
---------------------------------------------------------------------------

    IMPA also clarified in its comments that the ash handling system it 
employs to comply with the CCR rule has not resulted in the elimination 
of its BA transport water discharges. The system includes dewatering 
bins followed by the addition of flocculant and coagulant to facilitate 
particulate removals in geotubes. Remaining wastewater is then sent to 
four polishing surface impoundments that are not designed to hold an 
accumulation of CCR, and thus not subject to the CCR rule, before the 
wastewater is sent to the POTW. While IMPA also provided concentration 
data from its BA transport water, none of this information demonstrated 
removals of pollutants to a degree that would change the results of the 
pass-through analysis from the 2015 rule.
    Finally, IMPA provided comments describing the costs of potential 
BA transport water modifications, the impacts to the local community, 
and the potential for the facility to continue to support 
reliability.\161\ In the comments regarding reliability, IMPA appeared 
to suggest that the facility would be operating until 2032. IMPA and 
the EPA had a follow-up conversation to discuss these comments and the 
EPA confirmed that, in the absence of outside factors, the facility is 
expecting to cease operations in 2032.
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    \161\ While the EPA received comments from other parties about 
the elimination of this PSES subcategory, only IMPA provided site-
specific information that was potentially relevant to the EPA's 
discussion here. For further discussion of comments, see Response to 
Public Comments for Supplemental Effluent Limitations Guidelines and 
Standards for the Steam Electric Power Generating Point Source 
Category, April 2024 (SE11794).
---------------------------------------------------------------------------

    After considering the comments and information in the record, the 
EPA is eliminating the LUEGU subcategory for indirect dischargers as 
unnecessary and not supported by the factors relied on in 2020. With 
respect to FGD wastewater under the LUEGU subcategory, no NOPPs were 
filed from indirect dischargers requesting this subcategory for this 
wastestream. Thus, continued existence of this subcategory is 
unnecessary. With respect to BA transport water, EPA notes that, under 
the final rule's subcategory for EGUs permanently ceasing coal 
combustion by 2034, the one facility with indirect discharges to a POTW 
known to be interested in using the 2020 LUEGU subcategory would be 
able to continue to operate under the BA transport water PSES of the 
2020 rule and retire in 2032 as planned without incurring any 
additional treatment costs and without creating an energy reliability 
concern. Thus, the LUEGU subcategory is no longer supported by the 
factors the EPA cited in the 2020 rule, nor any other factors.
    PSNS. The EPA selects zero-discharge systems as the bases for the 
CRL PSNS for the same reasons that EPA selects these systems as the 
bases for the CRL NSPS (see section VII.B.3 of this preamble). The 
EPA's record demonstrates that zero-discharge systems are available and 
demonstrated, do not pose a barrier to entry, and have acceptable non-
water quality environmental impacts, including energy requirements (see 
sections VII.G and X of this preamble). The EPA rejected other options 
for CRL PSNS for the same reasons that it rejected other options for 
CRL NSPS. And, as with the final CRL PSES, the EPA concludes that the 
final CRL PSNS prevent pass through of pollutants from POTWs into 
receiving streams and help control contamination of POTW sludge.

E. Availability Timing of New Requirements

    Where BAT limitations in the 2015 and 2020 rules are more stringent 
than previously established BPT limitations, those BAT limitations do 
not apply until a date determined by the permitting authority that is 
``as soon as possible'' after considering four factors. Depending on 
the particular wastewater, the 2015 and 2020 rules also established a 
``no later than'' date of December 31, 2023, or December 31, 2025, for 
reasons discussed in the record of those rules, including that, without 
such a date, implementation could be substantially delayed, and a firm 
``no later than'' date creates a more level playing field across the 
industry.
    As part of the consideration of the technological availability and 
economic achievability of the new BAT limitations in this regulation, 
the EPA considered the magnitude and complexity of process changes and 
new equipment installations that would be required for plants to meet 
the final rule's new, more stringent limitations and standards. 
Specifically, the EPA considered timeframes that enable many plants to 
raise needed capital, plan and design systems, procure equipment, and 
construct and test systems. The EPA also considered the timeframes 
needed for appropriate consideration of any plant changes being made in 
response to other Agency rules affecting the steam electric power 
generating industry. The EPA understands that some plants may have 
already installed, or are now installing, technologies that could 
comply with the rule's limitations. Therefore, EPA finds that the 
earliest date some plants can achieve compliance with these new 
limitations would be July 8, 2024. Where this is not the case, nothing 
in this rule would preclude a permitting authority from establishing a 
later date, up to the ``no later than'' date, after considering the 
four specific factors in 40 CFR 423.11(t).\162\
---------------------------------------------------------------------------

    \162\ These factors are: (1) time to expeditiously plan 
(including to raise capital), design, procure, and install equipment 
to comply with the requirements of the final rule; (2) changes being 
made or planned at the plant in response to GHG regulations for new 
or existing fossil fuel-fired power plants under the CAA, as well as 
regulations for the disposal of coal combustion residuals under 
subtitle D of RCRA; (3) for FGD wastewater requirements only, an 
initial commissioning period to optimize the installed equipment; 
and (4) other factors as appropriate. See 40 CFR 423.11(t).
---------------------------------------------------------------------------

    With respect to the latest compliance dates, the EPA collected 
updated information on the technical availability of the BAT technology 
bases. Information in EPA's rulemaking record indicates that a typical 
timeframe to raise capital, plan and design systems (including any 
necessary pilot testing), procure equipment, and construct and test 
systems falls well within the existing five-year permit cycle.\163\ 
Furthermore, the chemical precipitation and zero-discharge BAT 
technologies here do not implicate the same industrywide competition 
over a small number of biological treatment vendors that the 2020 rule 
implicated. The EPA notes that while plants may not need about five 
years to comply with the final limitations, the ``no later than'' date 
creates an outer boundary beyond which no discharger may seek 
additional time and creates a level playing field regarding the latest 
date. Therefore, the EPA is finalizing the requirement that the new 
limitations for FGD wastewater, BA transport water, and CRL be achieved 
``no later than'' December 31, 2029.
---------------------------------------------------------------------------

    \163\ See FGD and Bottom Ash Implementation Timing (DCN 
SE08480).
---------------------------------------------------------------------------

    The EPA received comments that these ``no later than'' dates should 
be shortened or lengthened. Comments suggesting shortening these 
timeframes focused on record information

[[Page 40257]]

describing that individual facilities can install certain technologies 
in timeframes shorter than out to 2029. EPA declines to establish ``no 
later than'' dates shorter than one permit cycle from the final rule. 
Some permits may not be renewed and able to incorporate the new 
limitations until 2029, and this later date creates an even playing 
field for the industrial category. In contrast, commenters suggesting 
lengthening these timeframes did not provide specific data that 
demonstrate a legitimate need for a longer timeframe. In the absence of 
data demonstrating different timelines are necessary or appropriate 
(e.g., engineering dependency charts), the EPA cannot justify 
timeframes longer than those in the Agency's current record.
    For the new subcategory for EGUs permanently ceasing coal 
combustion by 2034, the EPA is finalizing different availability timing 
for the BAT limitations applicable to CRL discharged after cessation of 
coal combustion. Since CRL was not covered by the 2020 permanent 
cessation of coal subcategory, plants with EGUs retiring both before 
and after 2028 may wish to avail themselves of the CRL limitations 
applicable to the subcategory for EGUs permanently ceasing coal 
combustion by 2034. Furthermore, as discussed in section VII.C.4 of 
this preamble, the new subcategory for EGUs permanently ceasing coal 
combustion by 2034 takes into account the changes expected to occur in 
CRL flow after closure of the WMU, the timing of which depends on, but 
is not the same as, the date the EGU will cease coal combustion. To 
facilitate administration, the EPA is adopting the same ``as soon as 
possible'' applicability timing framework as used for other limitations 
in this rule. Thus, the BAT limitations for mercury and arsenic in CRL 
discharges from this subcategory must be met as soon as possible 
beginning 120 days after permanent cessation of coal combustion. Since 
the subcategory allows for permanent cessation of coal combustion by 
December 31, 2034, with an additional 120 days allowed for the 
discharge of FGD wastewater, the Agency is adopting an April 30, 2035 
``no later than'' date for meeting BAT limitations for discharges of 
CRL from this subcategory.\164\ Thus, while a permitting authority must 
establish availability timing that is ``as soon as possible,'' nothing 
in this rule would preclude a permitting authority from establishing a 
later date, up to the ``no later than'' date, after considering the 
four specific factors in 40 CFR 423.11(t). For PSES in this subcategory 
the statute does not allow for flexible availability timing and so 
here, to provide the same flexibility, the Agency is adopting tiered 
limitations with the second tier applying no later than April 30, 2035.
---------------------------------------------------------------------------

    \164\ Where EGUs are ceasing coal combustion near the end of 
this timeframe, or where closure of a WMU is lengthy such that it 
extends past this latest date, it is possible that a facility may 
not be able to fully take advantage of this flexibility for all of 
its WMUs.
---------------------------------------------------------------------------

    For the discharge of legacy wastewater, the EPA is not establishing 
the same ``no later than'' date framework as the other wastewaters. 
Instead, the limitations for legacy wastewater are simply effective on 
July 8, 2024. For legacy wastewater generally, this makes sense because 
the BAT limitations are based on a permitting authority's BPJ, and 
permitting authorities may consider the availability timing of 
technologies to a particular plant as part of its BAT determination. 
For legacy wastewater in the new subcategory described in section 
VII.C.6 of this preamble, this will have no impact because, as of the 
effective date of this rule, these surface impoundments will not have 
triggered the requirements under the CCR regulations to cease receipt 
of waste and commence closure. Furthermore, allowing for up to five 
years before the limitations' ``no later than'' date could provide time 
for circumvention of these limitations where a plant quickly drains its 
surface impoundment under the existing case-by-case approach.
    As with the new BAT effluent limitations, in considering the 
availability and achievability of the new PSES, the EPA concluded that 
existing indirect dischargers need some time to achieve the final 
standards, in part to avoid forced outages. While the BAT limitations 
apply on a date determined by the permitting authority that is as soon 
as possible beginning on the effective date of the final rule, but no 
later than December 31, 2029, under CWA section 307(b)(1), pretreatment 
standards shall specify a time for compliance not to exceed three years 
from the date of promulgation, so the EPA cannot establish a longer 
implementation period. Moreover, unlike requirements on direct 
discharges, requirements on indirect discharges are not implemented 
through NPDES permits. Nevertheless, the EPA finds that all existing 
indirect dischargers can meet the standards within three years of 
promulgation as discussed below.
    At proposal, the EPA projected that there would be no remaining 
indirect dischargers of FGD wastewater. In response to this finding, 
City Water, Light and Power (CWLP) filed comments indicating that it 
retains the option of either sending its treated FGD wastewater to the 
local POTW, or directly discharging. The EPA takes CWLP at its word 
that it will continue to be an indirect discharger at least some of the 
time. Nevertheless, the EPA estimates that it would take a single plant 
18 to 28 months to achieve zero discharge for both FGD wastewater and 
CRL. Similarly, with respect to BA transport water, the EPA estimates 
that a closed-loop system can achieve zero discharge within 35 months, 
and substantially sooner if a high recycle rate system is already 
operating.\165\ Finally, with respect to legacy wastewater and CRL 
generated after permanent cessation of coal combustion, the EPA 
estimates the chemical precipitation systems can achieve the mercury 
and arsenic limitations within 22 months.\166\ Thus, the final PSES are 
available 3 years after publication of the final rule. Further 
discussion of availability timing can be found in section XIVB.1 of 
this preamble.
---------------------------------------------------------------------------

    \165\ DCN SE08480.
    \166\ The EPA expects this timing to be similar to a chemical 
precipitation installation for FGD wastewater, DCN SE10289.
---------------------------------------------------------------------------

F. Economic Achievability

    Under the CWA, BAT limitations must be economically achievable. 
Courts have interpreted the economic achievability requirement as a 
test of whether the regulations can be ``reasonably borne'' by the 
industry as a whole. Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 262; BP 
Exploration & Oil v. EPA, 66 F.3d at 799-800; see also Southwestern 
Elec. Power Co. v. EPA, 920 F.3d at 1006; Nat'l Wildlife Fed'n v. EPA, 
286 F.3d 554, 570 (D.C. Cir. 2002); CPC Int'l Inc. v. Train, 540 F.2d 
1329, 1341-42 (8th Cir. 1976), cert. denied, 430 U.S. 966 (1977). 
``Congress clearly understood that achieving the CWA's goal of 
eliminating all discharges would cause `some disruption in our 
economy,' including plant closures and job losses.'' Chem. Mfrs. Ass'n 
v. EPA, 870 F.2d at 252 (citations omitted).
    At proposal, the EPA found that the rule was economically 
achievable, but solicited comment on whether and how to include the 
impacts of the IRA for the final rule analysis. The EPA received 
comments recommending modifications to its use of IPM. Specifically, 
some commenters recommended including the impacts of the IRA in the 
baseline, while other comments disagreed that the EPA should include 
the IRA impacts, with the latter commenters suggesting that any results 
with the IRA

[[Page 40258]]

included would be speculative and uncertain. The EPA also received 
comments that its findings should consider the joint impact of multiple 
regulations on this industry.
    The EPA acknowledges these comments. The EPA used IPM to perform 
cost and economic impact assessments, using a baseline that reflects 
impacts from the IRA and final environmental regulations that were 
published before this rule was signed (see RIA).\167\ As explained in 
detail in section VIII of this preamble, the IPM baseline used for this 
analysis includes the impacts of the IRA and several other final power 
sector regulations published before this rule. This is consistent with 
OMB Circular A-4 and EPA's Guidelines for Preparing Economic 
Analysis.\168\ The EPA did not, however, include all the regulations 
some comments suggested. For example, two CAA rules, the MATS and 
section 111 rules, are being issued contemporaneously with this ELG and 
none of these rules includes the others in the baseline of the primary 
IPM analysis. This too is consistent with OMB guidelines and 
established EPA practice.
---------------------------------------------------------------------------

    \167\ IPM is a comprehensive electricity market optimization 
model that can evaluate such impacts within the context of regional 
and national electricity markets. See section VIII of this preamble 
for additional discussion.
    \168\ Available online at: https://www.epa.gov/environmental-economics/guidelines-preparing-economic-analyses-2016.
---------------------------------------------------------------------------

    EPA's analysis for the final BAT limitations and PSES demonstrates 
that they are economically achievable for the steam electric industry, 
as required by CWA section 301(b)(2)(A). For the final rule, the model 
projected very small additional effects on the electricity market, on 
both a national and regional sub-market basis. Based on the results of 
these analyses, the EPA estimated that the final rule requirements 
would result in a net reduction of 5,782 MW in steam electric 
generating capacity as of the model year 2035, reflecting full 
compliance by all plants. This capacity reduction corresponds to a net 
effect of approximately five early plant retirements.\169\ These IPM 
results support the EPA's conclusion that the final rule is 
economically achievable.
---------------------------------------------------------------------------

    \169\ Given the design of IPM, unit-level and thereby plant-
level projections are presented as an indicator of overall 
regulatory impact rather than a precise prediction of future unit-
level or plant-specific compliance actions. The projected net plant 
closure occurs at a plant whose only steam electric EGU had a 
capacity utilization of only six percent in the baseline.
---------------------------------------------------------------------------

    Furthermore, before the IPM analysis, the EPA also performed a 
cost-to-revenue screening analysis which included costs to wastestreams 
not tied to ongoing electric generation (i.e., costs which would not 
change operational decisions in IPM). Specifically, this analysis 
included the upper bound and lower bound costs for treating unmanaged 
CRL as well as the costs of treating legacy wastewater discharged from 
surface impoundments commencing closure after July 8, 2024. For further 
discussion of these costs, see section VIII.A of this preamble. The 
screening-level assessment of economic impacts showed a greater 
potential for impacts with 13 to 17 parent entities incurring 
annualized costs representing one percent or more of their revenues, 
including 6 to 9 parent entities that would incur costs representing 
more than three percent of revenue. Since the EPA estimates that there 
are between 220 and 391 parent entities, this means that between three 
and eight percent of parent entities would incur costs representing one 
percent or more of their revenues and a subset of between two and four 
percent of parent entities would incur costs representing more than 
three percent of revenue. However, as noted in the RIA, these results 
are based on the conservative assumption that zero costs are passed on 
to consumers and represent a worst-case scenario from the plant owners' 
perspective. The combination of the screening analysis (including 
unmanaged CRL costs) and the IPM market-level results (excluding 
unmanaged CRL costs) supports the EPA's conclusion that the final rule 
is economically achievable.
    Other considerations also support the EPA's findings on economic 
achievability. While EPA properly excluded from its main analysis 
regulations that are being issued contemporaneously with this rule and 
that were not published before this rule was signed, the Agency 
conducted a supplemental analysis to evaluate the cumulative effect of 
multiple rules affecting the electric power sector. This multi-rule 
modeling includes this final rule, CAA sections 111(d) and 111(b) EGU 
rules, and MATS as a combined policy scenario, and includes the EPA 
vehicle rules (LDV, MDV and HDV) in the baseline (i.e., relevant EPA 
rules). As such, the results of this modeling cannot be used to show 
the individual effect of this final rule and are not a substitute for 
the rule-specific modeling EPA conducted to determine economic 
achievability of the final rule. However, the multi-rule modeling does 
clearly illustrate that the cumulative effect of these rules in terms 
of reduction in steam electric generating capacity is less than the sum 
of each of these rules individually. This means that, considering the 
rules together, the affected universe of EGUs with significant 
mitigation responsibilities under the EPA rules that make up the policy 
case is overlapping, not purely additive, as it largely reflects the 
same segment of the grid's generation portfolio. In other words, if the 
same EGU at baseline that has new regulatory requirements for both its 
air and water wastestreams chooses to retire rather than adopting 
control technologies, it would not do so twice, and so the generation 
lost from that EGU would only need to be replaced once. Hence, simply 
adding the independently modeled costs of each of the rules, which 
include effects associated with coal-fired EGU retirements attributable 
to each rule, would be inappropriate, as these effects are not 
additive. The sensitivity analysis bears this out over the time periods 
of relevance to the ELG.\170\
---------------------------------------------------------------------------

    \170\ See IPM Sensitivity Runs Memo (SE11829) for further 
details.
---------------------------------------------------------------------------

    In terms of reductions in coal-fired generating capacity and coal 
plant closures, affected EGUs are expected to undertake investment 
decisions to comply with multiple rules simultaneously, as seen in the 
sensitivity analysis for the combined policy scenario. For example, 
EGUs that decide to invest in CCS in relevant years may also decide to 
invest in a dry-handling system, depending on the operational need of 
the unit. In this case, the costs of CCS and a dry-handling system may 
be summed. However, if an EGU decides to retire, then the costs 
associated with the retirement decision would occur only once. For the 
reasons discussed above, had the Agency done an IPM analysis of ELG 
impacts in which the other relevant EPA rules were in the baseline, EPA 
expects that the results of such an analysis would likely show 
comparable or fewer impacts attributable to the ELG than projected in 
EPA's main analysis.\171\ Thus, nothing in the multi-rule modeling 
suggests EPA's conclusion that the final ELG rule is economically 
achievable would be meaningfully different, particularly where courts 
have upheld EPA's BAT regulations as economically achievable even under 
circumstances of much greater industry-wide economic impact than 
projected here. See Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 252 n.337

[[Page 40259]]

(reviewing cases in which courts have upheld EPA's regulations that 
projected up to 50 percent closure rates).
---------------------------------------------------------------------------

    \171\ The multi-rule run also confirms that resource adequacy is 
maintained, even taking into account the collective impact of the 
various EPA rules discussed here. See Resource Adequacy Analysis: 
Vehicle Rules, 111 EGU rule, ELG, and MATS Technical MEMO (SE11830).
---------------------------------------------------------------------------

    Finally, the EPA notes that coal-fired power plants with the 
wastestreams subject to this final rule are only a fraction of all 
coal-fired power plants, which are only a fraction of all steam 
electric power plants subject to part 423. The combination of the 
screening analysis (including unmanaged CRL and legacy wastewater 
costs), the IPM market-level results (excluding unmanaged CRL and 
legacy wastewater costs), and the other considerations in this 
paragraph support the EPA's conclusion that the rule is economically 
achievable.

G. Non-Water Quality Environmental Impacts

    For the 2023 proposed rule, the EPA assessed non-water quality 
environmental impacts, including energy requirements, air impacts, 
solid waste impacts, and changes in water use and found them to be 
acceptable. The EPA reevaluated these impacts in light of the changed 
industry profile and public comments, as well as the requirements of 
the final rule. Based on the results of these analyses, the EPA 
determines that the final rule has acceptable non-water quality 
environmental impacts. See additional information in section 7 of the 
Supplemental TDD, as well as section X of this preamble.

H. Impacts on Residential Electricity Prices and Communities With 
Environmental Justice Concerns

    The EPA presents the effects of the final rule on consumers as part 
of the RIA. While the CWA section 304(b)'s ``consideration'' factors do 
not require these details, the EPA presents them for informational 
purposes. If all annualized compliance costs were passed on to 
residential consumers of electricity instead of being borne by the 
operators and owners of power plants (a conservative assumption), the 
average yearly electricity bill increase for a typical household would 
be $1.61 to $3.14 under the final rule, or a change of less than 0.1 
percent relative to the baseline. For further information see section 7 
of the RIA.
    The EPA also presents the effect of the final rule on communities 
with environmental justice concerns under Executive Order 14096. As 
explained in sections XIII and XV.J, using demographic data on who 
resides closest to steam electric power plant discharges, who fishes in 
downstream waterbodies, and who consumes drinking water from downstream 
drinking water treatment plants, the EPA concludes that, although 
benefits are likely to accrue to all members of the affected public, 
communities with environmental justice concerns will experience health 
and environmental benefits more than the general population from the 
reductions in discharges associated with the final rule due to their 
disproportionate exposure.

VIII. Costs, Economic Achievability, and Other Economic Impacts

    The EPA evaluated the costs and associated impacts of the three 
main final regulatory options on existing EGUs at steam electric power 
plants. The Agency analyzed these costs within the context of existing 
environmental regulations, market conditions, and other trends that 
have affected steam electric power plant profitability and generation, 
as described in section V.B of this preamble. This section provides an 
overview of the methodology the EPA used to assess the costs and the 
economic impacts and summarizes the results of these analyses. The 
methodology is largely the same as for the proposed rule analysis, but 
with updates to reflect more recent data and comments the EPA received 
on the proposal. See the RIA in the docket for additional detail.
    In developing ELGs, and as required by CWA section 301(b)(2)(A), 
the EPA evaluates the economic achievability of regulatory options to 
assess the impacts of applying the limitations and standards to the 
industry as a whole, which typically includes an assessment of 
incremental plant closures attributable to a regulatory option. As 
described in more detail below, this supplemental ELG is expected to 
result in incremental costs when compared to baseline. Like the prior 
analysis of the 2015 and 2020 rules and the 2023 proposal, the cost and 
economic impact analysis for this final rule focuses on understanding 
the magnitude and distribution of compliance costs across the industry 
and the broader market impacts. The EPA used indicators to assess the 
impacts of the three regulatory options on the whole steam electric 
power generating industry. These indicators are consistent with those 
used to assess the economic achievability of the 2015 and 2020 rules 
and the 2023 proposal. As was done at proposal, the EPA compared the 
values to a baseline that reflects implementation of existing 
environmental regulations (as of this final rule), including the 2020 
rule and the effects of the IRA of 2022, but does not include the 
effects of regulations discussed in section IV.E of this preamble that 
had not been published at the time of signature of this final rule. As 
such, the baseline appropriately includes the costs of achieving the 
2020 rule limitations and standards, and the policy cases show the 
impacts resulting from potential changes to the existing 2020 
limitations and standards. More specifically, the EPA considered the 
total cost to the industry and the change in the number and capacity of 
specific EGUs and plants expected to close under the final rule (Option 
B) compared to the baseline. The EPA also analyzed the ratio of 
compliance costs to revenue to see how the three main regulatory 
options affect how many plants (and their owning entities) exceed 
thresholds indicating potential financial strain. In addition to the 
analyses supporting the economic achievability of the regulatory 
options, the EPA conducted other analyses to (1) characterize other 
potential impacts of the regulatory options (e.g., on electricity 
rates) and (2) meet the requirements of Executive Orders or other 
statutes (e.g., Executive Order 12866, Regulatory Flexibility Act, 
Unfunded Mandates Reform Act).

A. Plant-Specific and Industry Total Costs

    The EPA estimated plant-specific costs to control FGD wastewater, 
BA transport water, CRL, and legacy wastewater discharges at existing 
EGUs at steam electric power plants to which the ELGs apply.
    The EPA assessed the operations and treatment system components 
currently in place at each unit (or expected to be in place because of 
other existing regulations, including the 2020 ELG rule), identified 
equipment and process changes that plants would likely make under each 
of the three regulatory options presented in table VII-1 of this 
preamble, considering the subcategory applicable to each EGU, and 
estimated the capital and O&M costs to implement those changes. As 
explained in the TDD, the baseline also accounts for additional 
announced unit retirements, conversions, and relevant operational 
changes that have occurred since the EPA promulgated the 2020 rule. 
Following the same methodology used for the 2015 and 2020 rules and the 
2023 proposal analyses, when estimating the annualized industry 
compliance costs, the EPA used a private rate of capital to annualize 
one-time costs and costs recurring a nonannual basis. For this 
analysis, this rate is 3.76 percent and represents estimated weighted 
average cost of capital for the industry. For capital costs and initial 
one-time costs, the EPA used

[[Page 40260]]

a 20-year amortization period. For O&M costs incurred at intervals 
greater than one year, the EPA used the interval as the annualization 
period (e.g., five years, 10 years). The EPA added annualized capital, 
initial one-time costs, and the nonannual portion of O&M costs to 
annual O&M costs to derive total annualized plant costs. The EPA 
estimated after-tax costs based on the type of entity owning each 
plant. The EPA then calculated total industry costs by summing plant-
specific annualized costs.
    The EPA proposed that membrane filtration was BAT for FGD 
wastewater; therefore the Agency continued to rely primarily on the 
costs of membrane filtration to evaluate economic achievability at 
proposal while analyzing costs of SDEs and thermal evaporation systems 
using sensitivity analyses. Comments supportive of zero discharge 
suggested that sometimes thermal evaporation systems were less costly 
than membrane filtration systems and that these systems can achieve 
zero discharge alone or in combination. Other commenters suggested that 
the EPA's cost estimates were too low. Specifically, commenters 
suggested that the EPA did not properly reflect the costs of FA 
diversion to a landfill as part of the proposal's membrane filtration 
costs.
    The EPA has updated its cost estimates to more accurately reflect 
the costs of FA used for brine encapsulation. As a result of these 
updates, the EPA estimates that membrane filtration is no longer the 
least costly FGD treatment technology nationwide.
    Furthermore, because the final rule identifies the BAT technology 
basis for FGD wastewater as membrane filtration, SDEs, and thermal 
evaporation systems alone or in combination, the EPA performed a least-
cost analysis to determine which technology each plant would select. 
While the EPA costed all three technologies, the cost estimates for 
thermal technologies contain CBI and cannot be released publicly.\172\ 
To increase transparency of this final rule, the EPA ran an alternative 
set of costs selecting the least-cost technology between only membrane 
filtration and SDEs. The EPA found that only six plants would select 
thermal evaporation systems as the lowest cost option when considering 
all three technologies. Moreover, when comparing the least-cost 
analysis among the three technologies to the least-cost analysis with 
only membrane filtration and SDEs, the EPA found that the overall costs 
associated with the latter exceed the former by only five percent. 
Since the non-CBI costs do not substantially differ from the CBI costs, 
the EPA ran these non-CBI costs through IPM so that model's inputs and 
outputs could also be made public.
---------------------------------------------------------------------------

    \172\ Standard thermal evaporation system costs are analyzed in 
DCN SE11694 but not included in this least cost analysis because 
portions of those costs are being treated as CBI pursuant to claims 
made by vendors under the EPA's CBI regulations.
---------------------------------------------------------------------------

    With respect to BA transport water, the 2020 rule record never 
demonstrated that a full 10 percent purge at all facilities was a 
realistic costing assumption. The primary basis for the 2020 rule purge 
allowance was a 2016 report from EPRI that involved continuous purges, 
the majority of which were well under one percent. Thus, in the 2020 
rule record, the EPA presented a sensitivity analysis with costs for a 
two percent purge treatment, which better reflect the handful of 
facilities for which the EPA has record evidence of a purge.
    At proposal, the EPA retained this dual costing approach. Based on 
IPM modeling results, including the 10 percent purge treatment cost 
estimates, the EPA proposed to find that dry-handling or closed-loop 
systems are economically achievable. The EPA received comments 
suggesting that a 10 percent purge is not realistic of the potential 
purge needs of facilities. EPA agrees that the record reflects very few 
facilities with demonstrated purge needs, and that these were all two 
percent or less. Thus, the Agency has now adopted the more realistic 
two percent purge treatment cost estimate as its primary analysis but 
has retained the 10 percent purge treatment costs as a sensitivity 
analysis.\173\
---------------------------------------------------------------------------

    \173\ This primary use of the two percent numbers is also more 
reasonable when considering the definitional change whereby 
necessary discharges from storm events are not considered BA 
transport water, and thus would not require any additional purge or 
purge treatment.
---------------------------------------------------------------------------

    With respect to CRL, the EPA proposed to establish limitations 
based on chemical precipitation systems but estimated the costs of 
alternative zero-discharge systems for treating CRL in a separate 
memorandum. Some commenters asked the EPA to repropose CRL limitations 
since these analyses were not presented as part of the main regulatory 
options. Commenters also presented various reasons why they believed 
that the EPA's cost estimates were too low. Specifically, commenters 
suggested that the EPA did not properly reflect the costs of fly ash 
diversion to a landfill as part of the proposal's membrane filtration 
costs.
    The EPA disagrees with commenters that it should repropose CRL 
limitations because costs and pollutant loadings of additional 
technologies were estimated in a separate document. The Agency provided 
commenters with a fair opportunity to present their views on the 
contents of the final rule, which is all that is required to satisfy 
notice and comment requirements. BASF Wyandotte Corp. v. Costle, 598 
F.2d 637, 641-644 (1st Cir. 1979) (rejecting notice and comment 
objections to a final ELG rule based on changes from proposal). The EPA 
has also updated its cost estimates to reflect more accurate costs of 
using FA for brine encapsulation as was done for FGD wastewater in 
section VII.B.1 of this preamble.
    With respect to unmanaged CRL, the proposed rule included a 
bounding sensitivity analysis with costs for every facility and every 
unlined landfill and surface impoundment (WMU) to treat their unmanaged 
CRL either with chemical precipitation or SDEs. These bounding analyses 
were presented as a conservative estimate to demonstrate the potential 
universe of discharges of unmanaged CRL and potential costs. Some 
commenters stated their view that the EPA had not sufficiently 
evaluated unmanaged CRL and argued that the EPA should re-propose CRL 
limits after conducting a more accurate costing analysis. The EPA also 
received comments disagreeing with two misunderstandings of the 
Agency's proposed application of the rule to unmanaged CRL, with 
commenters believing either all or none of the facilities in the 
Agency's analyses were covered. One commenter further suggested that 
the EPA should include additional WMUs under the new CCR proposed rule 
(88 FR 31982).
    The EPA disagrees with commenters that it did not sufficiently 
evaluate unmanaged CRL and that CRL limits should be re-proposed. The 
proposed rule gave commenters notice of the basic engineering cost and 
economic screening approaches that the Agency applied in evaluating 
discharges of unmanaged CRL for the final rule, as those approaches 
have not changed. Furthermore, at proposal, the EPA analysis included 
the broadest set of potential facilities and WMUs estimated to be 
potentially subject to these limitations to ensure that the public was 
given fair notice of how the final rule could apply, even in cases 
where such an application might be highly unlikely. The EPA disagrees 
with commenters that making this assumption for the purposes of a 
bounding analysis had any implications as to whether a permitting 
authority would ultimately find the existence of a point source with

[[Page 40261]]

a functional equivalent direct discharge to a WOTUS at any given WMU.
    For the final rule, to better reflect on-the-ground reality, and in 
response to public comment, the EPA has refined the bounding analyses 
from proposal to remove the WMUs least likely to incur costs under this 
final rule. The EPA began by compiling groundwater monitoring 
information from unlined WMUs reported under the CCR regulations. This 
information consisted of detection monitoring data, assessment 
monitoring data, statistical analyses, and other narrative discussion 
in the groundwater monitoring reports. WMUs which are still in 
detection monitoring, and where there is either no statistically 
significant increase (SSI) of specified parameters \174\ above the 
groundwater background, or an increase that is not attributable to the 
WMU, are the least likely to be sources of pollutants and therefore 
also the least likely to potentially incur treatment costs under the 
rule. Thus, the EPA excluded these units from its revised bounding 
analysis.
---------------------------------------------------------------------------

    \174\ Appendix III to Part 257--Constituents for Detection 
Monitoring includes TDS.
---------------------------------------------------------------------------

    In addition to the updated bounding analysis, for the final rule, 
also in response to public comments, the EPA now presents a range of 
more likely costs consisting of a revised upper bound and revised lower 
bound analysis. These lower and upper bounds provide a likely more 
accurate range of cost estimates and other impacts for treating 
unmanaged CRL. The revised upper bound estimate probabilistically 
considers three separate scenarios, described in the next paragraph. 
The revised lower bound estimate probabilistically considers an 
additional four scenarios, also described below. Together, the 
resulting range represents a reasonable range of nationwide costs of 
treatment for unmanaged CRL, but as discussed in the following 
paragraphs, it could overestimate costs at some facilities and 
underestimate costs at others.
    The revised upper bound cost estimate uses proxies for the factors 
that make unmanaged CRL more likely to be subject to the limitations in 
the final rule, and therefore more likely to incur costs. The first 
scenario the EPA modeled was one in which unmanaged CRL treatment costs 
are assigned only to each plant's WMU closest to a surface waterbody. 
The Supreme Court in County of Maui recognized the importance of 
distance in determining whether a discharge might fall within the CWA's 
jurisdiction. County of Maui v. Hawaii Wildlife Fund, 590 U.S. at 184. 
For any given facility, for purposes of this cost estimate, the EPA 
assumes that the unlined WMU that is most likely to have unmanaged CRL 
subject to this rule's limitations is the unlined WMU nearest a surface 
waterbody. In selecting the nearest such WMU for the purposes of 
analysis, the EPA is not making any findings that these unmanaged CRL 
discharges would be subject to the final rule requirements or that 
discharges from other WMUs would not be. In reality, WMUs further from 
a surface waterbody could be found to be point sources with FEDDs of 
CRL to a WOTUS which are subject to CWA permitting. In addition, any of 
the closest WMUs modeled here may be found not to be point sources with 
FEDDs of CRL and thus subject to CWA permitting. Nevertheless, the EPA 
finds that it is reasonable to assume that the closest WMUs are more 
likely to incur costs under this final rule.
    The other two scenarios the EPA modeled focused not on distance, 
but on which WMUs are more likely to be a source of pollutants. For 
these WMUs, the Agency estimated costs of chemical precipitation 
treatment at both the WMU level and at the facility level. As discussed 
in the preceding paragraphs, the EPA's updated bounding analysis 
already removed those WMUs with less probability of incurring costs for 
unmanaged CRL treatment due to the absence of a WMU-caused SSI in 
detection monitoring pollutants (e.g., TDS). Just because a facility 
finds an SSI for a detection monitoring parameter does not indicate 
that it will incur costs under this final rule. This final rule imposes 
mercury and arsenic limitations based on chemical precipitation, a 
treatment system that does not treat all pollutants which might be 
found in TDS and other detection monitoring parameters. Instead, the 
EPA notes that nearly all of the assessment monitoring pollutants in 
appendix IV to part 257 are pollutants treated by chemical 
precipitation. The EPA finds that WMUs that are the source for an SSI 
of one or more appendix IV pollutants, and thus trigger corrective 
action under the CCR regulations, are the most likely to incur chemical 
precipitation-related costs under this final rule. This is so for two 
reasons.
    First, there is the possibility that these facilities could, in the 
future, select a pump-and-treat remedy under the corrective action 
requirements of the CCR regulation, which will be discharged. Any 
resulting direct discharge would need to comply with the limits in this 
rule. Second, where a pump-and-treat remedy is not selected, the EPA 
examined treatment of arsenic. Arsenic has historically been one of the 
most prevalent pollutants in CCR damage cases and under this final rule 
is also one of the two indicator pollutants monitored to demonstrate 
compliance with the BAT limitations for discharges of unmanaged CRL. 
While this regulation establishes technology-based limitations, the 
daily and monthly arsenic limitations being finalized are very close 
to, and bracket, the health-based arsenic standard in the CCR 
regulations.\175\ Thus, for purposes of determining the facilities and 
WMUs most likely to incur costs with respect to unmanaged CRL, the EPA 
finds that focusing on arsenic is reasonable.
---------------------------------------------------------------------------

    \175\ The daily and monthly BAT limitations being established 
are 11 ug/L and 8 ug/L, respectively as compared to the maximum 
contaminant level of 10 ug/L, which is the trigger for corrective 
action under the CCR regulations.
---------------------------------------------------------------------------

    While the EPA believes that using WMUs that have triggered 
corrective action is a reasonable proxy for estimating WMUs most likely 
to incur costs associated with unmanaged CRL under this rule, EPA notes 
that here too, just because a facility is in corrective action for its 
groundwater contamination does not mean that the WMU at issue would 
necessarily be found to be a point source with a FEDD of CRL to a 
WOTUS. Thus, in some cases, these costs will be overestimated for 
specific facilities. At the same time, it may be possible that 
unmanaged CRL is subject to CWA permitting but does not trigger 
corrective action under the CCR regulations.
    Due to the uncertainties surrounding future permitting authority 
findings regarding unmanaged CRL, the EPA probabilistically combined 
the three cost scenarios discussed above with equal weights: those 
involving (1) each plant's closest WMU, (2) cases of corrective action 
at the WMU level, and (3) cases of corrective action where surface 
impoundment flows are combined at the facility level. These modeling 
assumptions should not be interpreted as a finding that any specific 
site is subject to the unmanaged CRL limitations in the final rule. 
Rather, these assumptions should be considered as assisting in a 
reasonable estimation of costs nationwide, with actual site-specific 
costs under- or overestimated.

[[Page 40262]]

    The revised lower bound cost estimate uses proxies for the factors 
that make unmanaged CRL most likely to be subject to the limitations in 
the final rule, and therefore most likely to incur costs. Specifically, 
as of January 22, 2022, the EPA was aware of 67 WMUs at 38 facilities 
which had selected corrective action remedies that includes pumping and 
treating of groundwater now or in the future.\176\ These data are 
summarized in table VIII-1 below.
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    \176\ EPA presents this dataset in DCN SE11501.
    [GRAPHIC] [TIFF OMITTED] TR09MY24.044
    
    While the statistics are based on a 2022 subset of the facilities 
that have selected corrective action remedies thus far or will select 
corrective action remedies in the future, this empirical data provides 
the best available information on which to base the fraction of WMUs or 
facilities that may ultimately select a remedy that generates a CRL 
wastestream that could potentially be discharged, and thus potentially 
incur treatment costs under the final rule. While some of these 
facilities selected a remedy that explicitly included pump-and-treat 
operations, others included other categories of groundwater extraction 
or collection that may or may not ultimately result in a discharge. The 
EPA probabilistically used four scenarios to account for the 
uncertainty in the likelihood of a discharge that would incur ELG 
compliance costs.
    Two scenarios relied on the fraction of WMUs where such discharges 
were possible based on the remedy selected. Due to the number of WMUs 
at different facilities being unequal, the EPA also evaluated two 
scenarios that instead relied on the fraction of facilities with 
landfills and the fraction of facilities with surface impoundments 
where such discharges were possible. For each of these, a pair of 
estimates was generated assuming the fraction that would ultimately 
discharge subject to the ELG would include either only the pump-and-
treat operations or, alternatively, both pump-and-treat operations and 
other remedies with groundwater collection or extraction that could 
potentially discharge in the future. For the two scenarios using the 
facility-based extrapolation, the EPA used the costs for facility-wide 
corrective action described as one scenario in the revised upper bound 
scenario in the preceding paragraphs. Finally, by treating each of 
these scenarios with an equal likelihood to occur, the revised lower 
bound estimate avoids attaching too much certainty to any individual 
estimate based on this data set.
    The EPA notes that the revised upper bound analysis still 
represents a conservative estimate of the costs for unmanaged CRL. As 
facilities continue to implement the CCR regulations, landfills and 
surface impoundments continue to close and conduct corrective action. 
In some cases, closure may eliminate the continued source of pollutants 
(e.g., WMUs which are clean closed) or may reduce the concentrations of 
pollutants, making treatment costs under this final ELG less likely. 
Furthermore, where corrective action is taken pursuant to the CCR 
regulations, it is possible that the corrective action selected would 
reduce the probability that the facility would incur costs under the 
final rule. This could be the result of installing impermeable or semi-
permeable barriers, conducting in-situ treatment, or undergoing pump-
and-treat operations where the water is returned to the ground rather 
than discharged. Even where unmanaged CRL in groundwater is pumped to 
the surface, some of that water may be reused within the plant or 
treated and returned to the ground. When considered against this 
backdrop, the revised upper bound costs estimated for unmanaged CRL can 
be considered a reasonable, conservative estimate for purposes of 
ensuring that these costs are considered and found to be economically 
achievable.
    Similarly, the revised lower bound analysis still represents a 
likely underestimate of the costs of unmanaged CRL. Once regulations 
establishing a Federal CCR permit program are finalized, the EPA or 
state agencies may find that some previously selected corrective action 
remedies may not satisfy the corrective action requirements under the 
CCR regulations and, thus, a new remedy which does result in a 
discharge could be required. Furthermore, it may be possible that some 
unmanaged CRL satisfying the health-based requirements of the CCR 
regulations could still result in a FEDD of CRL into a WOTUS and, 
therefore, incur costs for complying with the ELG. For these reasons, 
the EPA believes the ultimate costs and economic impacts associated 
with unmanaged CRL are most likely to fall between the revised upper 
bound and revised lower bound estimates evaluated in the Agency's cost 
and economic analyses.
    With respect to legacy wastewater, the EPA proposed to retain the 
existing case-by-case limitations but estimated the costs of 
alternative treatment systems for treating legacy wastewater in a 
separate memorandum at proposal. Some commenters asked the EPA to 
repropose legacy wastewater limitations since these analyses were not 
presented as part of the main regulatory options. The EPA disagrees 
with commenters for the same reasons presented in the CRL discussion 
immediately above. For the subcategory of surface impoundments 
continuing to operate after the effective

[[Page 40263]]

date of the rule, the EPA expects that many plants may only close and 
dewater their ponds after 2049, which is outside of the period of 
analysis (and thus, for the purposes of this analysis, would be zero). 
The Agency has also evaluated a worst-case scenario where all plants 
close and dewater their ponds soon after the final rule is effective 
(see RIA appendix C). These costing scenarios bound the potential costs 
of the final subcategory; however, the likely costs fall somewhere in 
between. While the EPA cannot know with certainty when a surface 
impoundment may be closed in the future, the Agency compiled data in 
the 2015 CCR rule record which revealed a median operating life of 40 
years for a surface impoundment \177\ and this 40-year life was used 
for estimating costs, benefits, and other impacts in Regulatory Impact 
Analysis for EPA's 2015 Coal Combustion Residuals Final Rule. To ensure 
that the costs of the final legacy wastewater subcategory were included 
in the Agency's main cost analyses, the Agency assumed that these costs 
would be incurred in 2044. This corresponds to 20 years after the 
effective date of the final rule (i.e., half of a useful operating 
life).\178\
---------------------------------------------------------------------------

    \177\ See section 4.3.1 of Human and Ecological Risk Assessment 
of Coal Combustion Residuals.
    \178\ Assuming the same 40-year surface impoundment operating 
life used in the 2015 CCR rule record and acknowledging that these 
impoundments could be anywhere in that 40-year lifespan, the Agency 
uses the midpoint of 20-years as a reasonable approximation for 
purposes of ensuring that these costs are included in the main cost 
analyses of the final rule. To the extent that costs could be 
incurred before this date at some facilities and after this date at 
other facilities, these nationwide costs may either over- or 
underestimate the site-specific costs at any particular facility.
---------------------------------------------------------------------------

    Pre-tax annualized costs provide insight on the total expenditure 
as incurred, while after-tax annualized costs are a more meaningful 
measure of impact on privately owned for-profit entities and 
incorporate approximate capital depreciation and other relevant tax 
treatments in the analysis. The EPA uses pre- and/or after-tax costs in 
different analyses, depending on the concept appropriate to each 
analysis (i.e., social costs are calculated using pre-tax costs whereas 
cost-to-revenue screening-level analyses are conducted using after-tax 
costs).
    The after-tax annualized costs of the final rule range between $479 
million and $956 million for the lower and upper bound cost scenarios, 
respectively, whereas the pre-tax annualized costs range between $596 
million and $1,164 million.

B. Social Costs

    Social costs are the costs of the supplemental ELG from the 
viewpoint of society as a whole, rather than the viewpoint of regulated 
plants and owning entities (which are private costs). They include 
costs incurred by both private entities (e.g., in complying with the 
regulation) and by the government (e.g., in implementing the 
regulation). To calculate social costs, the EPA tabulated the pre-tax 
costs in the year they are estimated to be incurred, which varies 
across plants based on the estimated compliance year. The EPA performed 
the social cost analysis over a 25-year period of 2025 to 2049, which 
combines the length of the period during which plants are anticipated 
to install the control technologies (which could be as late as 2029) 
and the useful life of the longest-lived technology installed at any 
plant (20 years). The EPA calculated the social cost of the final rule 
using a two percent discount rate, following current OMB guidance in 
Circular A-4.\179\
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    \179\ OMB (2023). Circular A-4: Regulatory Analysis. Washington 
DC. Available at https://www.whitehouse.gov/wp-content/uploads/2023/11/CircularA-4.pdf.
---------------------------------------------------------------------------

    As described further in section 10 of the RIA, there are no 
incremental increases in the cost to state governments to revise NPDES 
permits. Consequently, the only category of costs used to calculate 
social costs are those pre-tax costs estimated for steam electric power 
plants. Note that the annualized social costs differ from pre-tax 
industry compliance costs discussed in section VIII.A of this preamble 
due to differences in both the discount rate used (2 percent) and the 
year-explicit accounting of the costs. Whereas the costs in section 
VIII.A of this preamble represent the annualized costs of each option 
if they were incurred in 2024, the annualized social costs are 
estimated based on the stream of future costs starting in the year that 
individual plants are projected to comply with the requirements of the 
final rule. The final rule has estimated annualized incremental social 
costs of $536 million to $1,064 million.

C. Economic Impacts

    The EPA assessed the economic impacts of this final rule in two 
ways: (1) a screening-level assessment of the cost impacts on existing 
EGUs at steam electric power plants and the entities that own those 
plants, based on a comparison of costs to revenue and (2) an assessment 
of the impacts within the context of the broader electricity market, 
which includes an assessment of changes in predicted plant closures 
attributable to the final rule. The following sections summarize the 
results of these analyses. The RIA discusses the methods and results in 
greater detail.
    The first set of cost and economic impact analyses--at both the 
plant and parent company level--provides screening-level indicators of 
the impacts of costs for FGD wastewater, BA transport water, and CRL 
controls relative to historical operating characteristics of steam 
electric power plants incurring those costs (i.e., level of electricity 
generation and revenue).\180\ The EPA conducted these analyses for 
baseline and for the three regulatory options presented in table VII-1 
of this preamble, then compared these impacts to understand the 
incremental effects of the regulatory options, including the final rule 
(Option B).
---------------------------------------------------------------------------

    \180\ As discussed in section VIII.A of this preamble, in 
analyzing the costs and benefits of the final rule, the EPA 
estimated that the costs to meet future legacy wastewater 
limitations would occur outside the period of analysis and therefore 
focused on the FGD wastewater, BA transport water and CRL 
wastestreams for this analysis.
---------------------------------------------------------------------------

    The second set of analyses looks at broader electricity market 
impacts, considering the interconnection of regional and national 
electricity markets. This analysis also looks at the distribution of 
impacts at the plant and EGU level. This second set of analyses 
provides insight on the impacts of the final rule on steam electric 
power plants, as well as the entire electricity market, including 
changes in capacity, generation, and wholesale electricity prices. The 
market analysis compares model predictions for the final rule to a base 
case that includes the predicted and observed economic and market 
effects of the 2020 rule and other environmental regulations.
1. Screening-Level Assessment
    The EPA conducted a screening-level analysis of each regulatory 
option's potential impact on existing EGUs at steam electric power 
plants and parent entities based on cost-to-revenue ratios. For each of 
the two levels of analysis (plant and parent entity), the Agency 
assumed, for analytic convenience and as a worst-case scenario, that 
none of the compliance costs would be passed on to consumers through 
electricity rate increases and would instead be absorbed by the steam 
electric power plants and their parent entities. This assumption 
overstates the impacts of compliance expenditures since steam electric 
power plants that operate in a regulated market may be able to pass on 
changes in production costs to

[[Page 40264]]

consumers through changes in electricity prices. It is, however, an 
appropriate assumption for a screening-level estimate of the potential 
cost impacts.
a. Plant-Level Cost-to-Revenue Analysis
    The EPA developed revenue estimates for this analysis using EIA 
data. The EPA then calculated the change in the annualized after-tax 
costs of the three regulatory options presented in table VII-1 of this 
preamble as a percentage of baseline annual revenues. See section 4 of 
the RIA for a more detailed discussion of the methodology used for the 
plant-level cost-to-revenue analysis.
    Cost-to-revenue ratios are screening-level indicators of potential 
economic impacts. For this analysis, the EPA assessed plants incurring 
costs below one percent of revenue as unlikely to face economic 
impacts, plants with costs between one percent and three percent of 
revenue as having a higher chance of facing economic impacts, and 
plants incurring costs above three percent of revenue as having a still 
higher probability of economic impact.
    Under the final rule (Option B), the EPA estimates that 50 to 72 
plants would incur incremental costs greater than or equal to one 
percent of revenue under the lower and upper bound cost scenarios 
respectively, including 18 to 31 plants that have costs greater than or 
equal to three percent of revenue. An additional 91 to 98 plants would 
incur costs that are less than one percent of revenue. section 4.2 in 
the RIA provides results for the other regulatory options the EPA 
analyzed.
b. Parent Entity-Level Cost-to-Revenue Analysis
    The EPA also assessed the economic impact of the regulatory options 
presented in table VII-1 of this preamble at the level of the firm that 
own steam electric power plants to analyze the potential impacts on 
these firms, referred to as ``parent entities.'' In this analysis, the 
domestic parent entity associated with a given plant is defined as the 
entity with the largest ownership share in the plant. For each parent 
entity, the EPA compared the incremental change in the total annualized 
after-tax costs and the total revenue for the entity to the baseline 
(see section 4 of the RIA for details). Following the methodology 
employed in the analyses for the 2015 and 2020 rules, the EPA 
considered a range of estimates for the number of entities owning an 
existing EGU at a steam electric power plant to account for partial 
information available for steam electric power plants that are not 
expected to incur ELG compliance costs.
    Like the plant-level analysis above, cost-to-revenue ratios provide 
screening-level indicators of potential economic impacts, this time to 
the owning entities; higher ratios suggest a higher probability of 
economic impacts. The EPA estimates that the number of entities owning 
existing EGUs at steam electric plants ranges from 220 (lower-bound 
estimate) to 391 (upper-bound estimate), depending on the assumed 
ownership structure of plants not incurring ELG costs and not 
explicitly analyzed. The EPA estimates that under the final rule 
(Option B) and for the lower and upper bound cost scenarios, 13 to 17 
parent entities would incur annualized costs representing one percent 
or more of their revenues, including 6 to 9 parent entity that would 
incur costs representing more than three percent of its revenue.
2. Electricity Market Impacts
    To analyze the impacts of regulatory actions on the electric power 
sector, the EPA commonly uses IPM, a comprehensive electricity market 
optimization model that can evaluate such impacts within the context of 
regional and national electricity markets. The model is designed to 
evaluate the effects of changes in EGU-level electric generation costs 
on the total cost of electricity supply, subject to specified demand 
and emissions constraints. Use of a comprehensive market analysis 
system is important in assessing the potential impact of any power 
plant regulation because of the interdependence of EGUs that supply 
power to the electric transmission grid. Changes in electricity 
production costs at some EGUs can have a range of broader market 
impacts affecting other EGUs, including the average likelihood that 
various units are dispatched. The analysis also provides important 
insight on steam electric capacity closures (e.g., retirements of EGUs 
that become uneconomical relative to other EGUs), based on a more 
detailed analysis of market factors than in the screening-level 
analyses above.
    In contrast to the screening-level analyses, which are static and 
do not account for the interdependence of EGUs supplying power to the 
electric transmission grid, IPM accounts for potential changes in the 
generation profile of steam electric and other EGUs, as well as the 
consequent changes in market-level generation costs as the electric 
power market responds to changes in generation costs for steam electric 
EGUs due to the regulatory options. Additionally, in contrast to the 
screening-level analyses, in which the EPA assumed no cost pass-through 
of ELG compliance costs, IPM depicts production activity in wholesale 
electricity markets where the specific increases in electricity prices 
for individual markets would result in some recovery of compliance 
costs for plants. IPM is based on an inventory of U.S. utility- and 
nonutility-owned EGUs and generators that provide power to the 
integrated electric transmission grid, including plants to which the 
ELGs apply.
    The EPA analyzed the final rule (Option B) using IPM to further 
inform the Agency's understanding of the potential impacts of the ELGs. 
The base case used for this analysis, which the EPA was developed using 
IPM Version 6, embeds an energy demand forecast that is derived from 
DOE's ``Annual Energy Outlook 2023.'' \181\ The base case also includes 
the effects of the IRA provisions reflecting supply-side impacts, final 
Federal rules (e.g., 2020 ELG rule, CSAPR and CSAPR Update, 2012 MATS 
rule, the 2014 CWA section 316(b) rule, and 2015 CCR rule and CCR Part 
A rule), and state rules and programs such as the Regional Greenhouse 
Gas Initiative, California's Global Warming Solutions Act, and state-
level Renewable Portfolio Standards policies.
---------------------------------------------------------------------------

    \181\ U.S. Energy Information Administration (2023b). Annual 
Energy Outlook 2023. Available at https://www.eia.gov/outlooks/aeo/.
---------------------------------------------------------------------------

    In analyzing the final rule, the EPA estimated incremental fixed 
and variable costs for the steam electric power plants and EGUs to 
comply with Option B. Because IPM is not designed to endogenously model 
the selection of wastewater treatment technologies as a function of 
electricity generation, effluent flows, and pollutant discharge, the 
EPA estimated these costs exogenously for each steam EGU and input 
these costs into the IPM model as fixed and variable O&M cost adders in 
addition to the costs already reflected in the base case, which 
included compliance with the 2020 ELG rule (the baseline analysis) and 
other applicable regulations. The EPA then ran IPM with these new cost 
estimates to determine the dispatch of EGUs that would meet projected 
demand at the lowest costs, subject to the same constraints as those in 
the baseline analysis. The estimated changes in plant- and EGU-specific 
production levels and costs--and, in turn, changes in the electric 
power sector's total costs and production profile--are key data 
elements in evaluating the expected national and regional effects of 
the final rule,

[[Page 40265]]

including closures or avoided closures of EGUs and plants.
    The EPA considered impact metrics of interest at three levels of 
aggregation: (1) impact on national and regional electricity markets 
(all electric power generation, including steam and nonsteam electric 
power plants); (2) impact on steam electric power plants as a group, 
and (3) impact on individual steam electric power plants incurring 
costs. section 5 of the RIA discusses the first analysis; the sections 
below summarize the last two, which are further described in section 5 
of the RIA. All results presented below are representative of modeled 
market conditions in the model year 2035, when the plants will have 
implemented changes to meet the revised ELGs.
a. Impacts on Existing Steam Electric Power Plants
    The EPA used IPM results for 2035 to assess the potential impact of 
the final rule on existing EGUs at steam electric power plants. The 
purpose of this analysis is to assess any fleetwide changes from 
baseline impacts on EGUs at steam electric plants. Table VIII-2 of this 
preamble reports estimated results for existing EGUs at steam electric 
power plants, as a group. EPA looked at the following metrics: (1) 
incremental early retirements and capacity closures, calculated as the 
difference between capacity under the regulatory option and capacity 
under the baseline; (2) incremental capacity closures as a percentage 
of baseline capacity; (3) changes in electricity generation from plants 
subject to the ELGs; (4) changes in variable production costs per MWh, 
calculated as the sum of total fuel and variable O&M costs divided by 
net generation; and (5) changes in annual costs (fuel, variable O&M, 
fixed O&M, and capital). Items (1) and (2) provide important insight 
for determining the economic achievability of the ELG rule. Note that 
changes in electricity generation at steam electric power plants 
presented in table VIII-2 are attributable both to changes in 
retirements and changes in capacity utilization at operating EGUs and 
plants.
[GRAPHIC] [TIFF OMITTED] TR09MY24.045

    Under the final rule, generation at steam electric power plants is 
projected to decrease by 23,579 GWh (3.0 percent) nationally when 
compared to baseline. IPM projects a net decline in total steam 
electric capacity by 5,782 MW (approximately 2.6 percent of total 
baseline steam electric capacity) due to early retirement attributable 
to this final rule. Five additional plants are projected to retire 
early under the final rule when compared to baseline. These incremental 
early retirements represent a 6.4 percent increase relative to 
projected baseline plant retirements, but only represent 0.7 percent of 
the total 688 steam electric power plants modeled in IPM. See section 
5.2.2.2 in the RIA for details.
    These findings suggest that the final rule can be expected to have 
small economic consequences for steam electric power plants as a group. 
Option B would affect the operating status of very few steam electric 
power plants, with five projected additional plant closures (including 
one plant that was not estimated to incur costs under Option B).
b. Impacts on Individual Plants Incurring Costs
    To assess potential plant-level effects, the EPA also analyzed 
plant-specific changes attributable to the final rule for the following 
metrics: (1) capacity utilization (defined as annual generation (in 
MWh) divided by the product of capacity (MW) and 8,760 hours), (2) 
electricity generation, and (3) variable production costs per MWh, 
defined as variable O&M cost plus fuel cost divided by net generation. 
The analysis of changes in individual plants is detailed in section 5 
of the RIA. The results indicate that most plants would experience only 
slight effects--i.e., no change or a reduction/increase of less than 
one percent. Across the full set of steam electric power plants 
modeled, 36 plants would incur a reduction in generation of at least 
one percent; 17 of these plants are also estimated to incur a reduction 
in capacity utilization of at least one percent. At the same time, 21 
plants would increase generation by at least one percent, and 10 plants 
see their capacity utilization increase by at least one percent. Of the 
subset of 35

[[Page 40266]]

steam electric power plants that were estimated to incur costs under 
the final rule (Option B), four plants would incur a decrease in 
generation, whereas four plants would see either no change or an 
increase in generation. Moreover, 13 plants for which the EPA estimated 
costs are projected to close in the baseline scenario, and four 
additional plants are projected to close under the final rule (Option 
B).

IX. Pollutant Loadings

    In developing ELGs, the EPA typically evaluates the pollutant 
loading reductions of the final rule to assess the impacts of the 
compliance requirements on discharges from the whole industry. The EPA 
took the same approach to the one described above for plant-specific 
costs for estimating pollutant reductions associated with this rule. 
That is, the EPA compared the values to a baseline that reflects 
implementation of existing environmental regulations, including the 
2020 rule for FGD wastewater and BA transport water.
    The general methodology that the EPA used to calculate pollutant 
loadings is the same as that described in the 2020 rule. The EPA first 
estimated--on an annual, per plant basis--the pollutant discharge load 
associated with the technology bases evaluated for plants to comply 
with the 2020 rule requirements for FGD wastewater and BA transport 
water, accounting for the current or planned conditions at each plant. 
For CRL and legacy wastewater, the EPA estimated the pollutant 
discharge load associated with current discharges. For all 
wastestreams, the EPA similarly estimated plant-specific post-
compliance pollutant loadings as the load associated with the 
technology bases for plants to comply with the effluent limitations in 
this rule. The EPA then calculated the changes in pollutant loadings at 
a particular plant as the sum of the differences between the estimated 
baseline and post-compliance discharge loadings for each applicable 
wastestream.
    For plants that discharge indirectly to POTWs, the EPA adjusted the 
baseline and option loadings to account for pollutant removals expected 
from POTWs. These adjusted pollutant loadings for indirect dischargers 
therefore reflect the resulting discharges to receiving waters. For 
details on the methodology the EPA used to calculate pollutant loading 
reductions, see section 6 of the TDD.

A. FGD Wastewater

    For FGD wastewater, the EPA continued to use the average pollutant 
effluent concentration with plant-specific discharge flow rates to 
estimate the mass pollutant discharge per plant for the baseline and 
the final rule. EPA used data compiled for the 2015 and 2020 rules as 
the initial basis for estimating discharge flow rates and updated the 
data to reflect retirements or other relevant changes in operation. As 
in the 2020 rule, the EPA also accounted for increased rates of recycle 
through the scrubber that would affect the discharge flow.
    The EPA assigned pollutant concentrations for each analyte based on 
the operation of a treatment system designed to comply with baseline or 
the final rule. The EPA used data compiled for the 2020 rule to 
characterize FGD chemical precipitation plus LRTR effluent and chemical 
precipitation plus membrane filtration effluent. In addition, the EPA 
used data provided by industry and other stakeholders during the 2020 
rule and 2023 proposed rule, as described in section IV of this 
preamble, to quantify bromide in FGD wastewater under baseline 
conditions and the final rule.

B. BA Transport Water

    The EPA estimated baseline and post-compliance loadings for the 
final rule using pollutant concentrations for BA transport water and 
plant-specific flow rates. The EPA used data compiled for the 2020 rule 
as the basis for estimating BA transport water discharge flows and 
updated the data set to reflect retirements and other relevant changes 
in operation (e.g., ash handling conversions, fuel conversions) that 
have occurred since collecting the 2020 rule data. Under the baseline, 
which reflects the 2020 rule requirement for the high recycle rate 
technology option (or BMP plan in the case of Merrimack Station), the 
EPA estimated discharge flows associated with the purge from remote MDS 
operation, based on the generating unit capacity and the volume of the 
remote MDS. Under the zero-discharge option, the EPA estimated a flow 
rate of zero.

C. CRL

    For CRL, the EPA used the average pollutant effluent concentration 
with plant-specific discharge flow rates to estimate the mass pollutant 
discharge per plant for baseline and the final rule. The EPA used data 
compiled for the 2015 rule as the initial basis for estimating 
discharge flow rates and updated the data to reflect retirements. The 
EPA also used utilities' ``CCR Rule Compliance Data and Information'' 
websites to identify new landfills constructed since 2015 and waste 
management units that may discharge unmanaged CRL. For new landfills, 
the EPA used the 2015 methodology to estimate leachate flow 
proportionate to landfill size, if available, or as the median leachate 
volume (in gallons per day) calculated from the 2010 steam electric 
survey. For plants with EGUs no longer burning coal by 2034 (e.g., 
retired, converted EGUs to natural gas), the EPA adjusted CRL discharge 
flow rates to account for an expected decrease in CRL volume following 
the closure of the waste management unit. For discharges of unmanaged 
CRL, the EPA estimated the volume of leachate-laden groundwater 
captured from pumping systems that draw down the groundwater elevation 
along the hydraulically downgradient cross-sectional width of the CCR 
management unit.
    The EPA assigned pollutant concentrations for each analyte based on 
current operating conditions or treatment in place for the baseline and 
the operation of a treatment system designed to comply with the final 
rule. The EPA used data compiled for the 2015 rule, in addition to data 
gathered as part of this rulemaking (see section VI.A.3 of this 
preamble), to characterize untreated CRL. Consistent with its 
methodology for the 2015 rule, the EPA evaluated the new CRL data for 
use in the untreated CRL analytical dataset and incorporated the data 
acceptable for the loadings analyses (see section 6.4 of the TDD for 
more information). The EPA transferred the average FGD effluent 
concentrations for chemical precipitation, as it did in the 2015 rule.

D. Legacy Wastewater

    The EPA estimated baseline and post-compliance loadings for the 
final rule using pollutant concentrations for legacy wastewater and 
plant-specific flow rates. The EPA used utilities' ``CCR Rule 
Compliance Data and Information'' websites to estimate the volume and 
type of CCR and water stored in impoundments. The EPA estimated the 
volume of impounded water (i.e., decant wastewater) and dewatering 
wastewater for each impoundment primarily using information from the 
annual inspection reports. To estimate the flow rate, the EPA divided 
the total volume of legacy wastewater by the closure duration, 
specified in utilities' closure plans or estimated based on permit 
cycles. For surface impoundments where the total wastewater volume was 
unknown, the EPA used the median total estimated volume of wastewater 
from the impoundments in its analysis and a closure duration of seven 
years.
    The EPA used 2015 rule surface impoundment effluent concentration

[[Page 40267]]

data sets to estimate baseline loadings as each impoundment in the 
population varies in the CCR material it contains, including FA, BA, 
combined ash, and FGD wastewater. The EPA transferred the average FGD 
effluent concentrations for chemical precipitation, as it did with CRL.

E. Summary of Incremental Changes of Pollutant Loadings from the Final 
Rule

    Compared to the 2020 rule (baseline), the final rule results in a 
reduction of 656 million pounds of pollutants to surface waters 
annually. The EPA estimates pollutant removals associated with 
discharges of unmanaged CRL could amount to between 3.62 and 16.4 
million pounds annually. See section VII.C.5 of this preamble for more 
information regarding the subcategory for discharges of unmanaged CRL.

X. Non-Water Quality Environmental Impacts

    The elimination or reduction of one form of pollution may create or 
aggravate other environmental problems. Therefore, sections 304(b) and 
306 of the CWA require the EPA to consider non-water quality 
environmental impacts (including energy requirements) associated with 
ELGs. Accordingly, the EPA has considered the potential impacts of this 
rule on air emissions, solid waste generation, and energy consumption. 
In general, to conduct this analysis, the EPA used the same methodology 
(with updated data as applicable) as it did for the analyses supporting 
the 2015 and 2020 rules. The following sections summarize the 
methodology and results. See section 7 of the supplemental TDD for 
additional details.

A. Energy Requirements

    Steam electric power plants use energy when transporting ash and 
other solids on or off site, operating wastewater treatment systems 
(e.g., chemical precipitation, membrane filtration, SDEs), or operating 
ash handling systems. For this final rule, the EPA considered whether 
there would be an associated change in the incremental energy 
requirements compared to the baseline. The EPA estimated the increase 
in energy usage in MWh for equipment added to the plant systems or in 
gallons of fuel consumed for transportation/operating equipment and 
summed the facility-specific estimates to calculate the net change in 
energy requirements from the baseline for the final rule.
    The EPA estimated the amount of energy needed to operate wastewater 
treatment systems and ash handling systems based on the horsepower 
ratings of the pumps and other equipment. The EPA also estimated any 
changes in the fuel consumption associated with transporting solid 
waste and combustion residuals (e.g., ash) from steam electric power 
plants to landfills (on- or off-site). The frequency and distance of 
transport depends on a plant's operation and configuration; specific 
factors include the volume of waste generated and the availability of 
either an on-site or off-site nonhazardous landfill and its distance 
from the plant. Table X-1 of this preamble shows the net change in 
annual electrical energy usage associated with the final rule compared 
to the baseline, as well as the net change in annual fuel consumption 
requirements associated with the final rule compared to the baseline.
[GRAPHIC] [TIFF OMITTED] TR09MY24.046

    The EPA estimates that energy use associated with discharges of 
unmanaged CRL could amount to as much as 280,000 MWh and 442 thousand 
gallons of fuel annually. See section VII.C.5 of this preamble for more 
information regarding the subcategory for discharges of unmanaged CRL.

B. Air Pollution

    The final rule is expected to affect air pollution through three 
main mechanisms: (1) changes in auxiliary electricity use by steam 
electric power plants due to the need to operate wastewater treatment, 
ash handling, and other systems for compliance with regulatory 
requirements; (2) changes in transportation-related emissions due to 
the trucking of CCR waste to landfills; and (3) the change in the 
profile of electricity generation due to regulatory requirements. This 
section discusses air emission changes associated with the first two 
mechanisms and presents the corresponding estimated net changes in air 
emissions. See section XII.B.3 of this preamble for additional 
discussion of the third mechanism.
    Steam electric power plants generate air emissions from operating 
transport vehicles, such as dump trucks, which release criteria air 
pollutants and GHGs. A decrease in energy use or vehicle operation 
would result in decreased air pollution.
    The final rule is projected to result in changes in electrical 
energy compared to the baseline. To estimate the net air emissions 
associated with these changes, the EPA combined the energy usage 
estimates with air emission factors associated with electricity 
production to calculate air emissions associated with the incremental 
energy requirements. The EPA estimated NOX, sulfur dioxide 
(SO2), and CO2 emissions using plant- or NERC-
specific emission factors (tons/MWh) obtained from IPM for run year 
2035.
    To estimate net air emissions changes in the operation of transport 
vehicles, the EPA used the MOVES4.0 model to identify air emission 
factors (tons/mile) for the air pollutants of interest. The EPA 
estimated the annual number of miles that dump trucks moving ash or 
wastewater treatment solids to on- or off-site landfills would travel 
for the final rule. The EPA used these estimates to calculate the net 
change in air emissions for the final rule. Table X-2 of this preamble 
presents the estimated net change in air emissions associated with 
auxiliary electricity and transportation for the final rule.

[[Page 40268]]

[GRAPHIC] [TIFF OMITTED] TR09MY24.047

    The EPA estimates that air emissions associated with discharges of 
unmanaged CRL could amount to as much as 0.048 million tons of 
CO2, 0.022 thousand tons of NOX, and 0.014 
thousand tons of SO2 annually. See section VII.C.5 of this 
preamble for more information regarding the subcategory for discharges 
of unmanaged CRL.
    The modeled output from IPM predicts that compliance costs 
attributable to the final rule will result in changes in electricity 
generation compared to the baseline. These changes in electricity 
generation are, in turn, predicted to affect the amount of 
NOX, SO2, and CO2 emissions from steam 
electric power plants.\182\ Table X-3 of this preamble shows a summary 
of the net change in annual air emissions associated with the final 
rule for all three mechanisms for the IPM run year 2035. As with costs, 
the IPM run from the final rule reflects the range of non-water quality 
environmental impacts associated with the final rule. To provide some 
perspective on the estimated changes, the EPA compared the estimated 
change in air emissions to the net amount of air emissions generated in 
a year by all electric power plants throughout the United States. For a 
detailed breakout of each of the three sources of air emission changes, 
see section 7 of the TDD.
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    \182\ The EPA also considered changes in particulate matter (see 
section XII.B.3 of this preamble). As explained in the BCA section 
8.1: ``IPM outputs include estimated CO2, NOX, 
and SO2 emissions to air from EGUs. The EPA also used IPM 
outputs to estimate EGU emissions of primary PM2.5 based 
on emission factors described in U.S. EPA (2020c). Specifically, the 
EPA estimated primary PM2.5 emissions by multiplying the 
generation predicted for each IPM plant type (ultrasupercritical 
coal without carbon capture and storage, combined cycle, combustion 
turbine, etc.) by a type-specific empirical emission factor derived 
from the 2016 National Emissions Inventory and other data sources. 
The emission factors reflect the fuel type (including coal rank), 
FGD controls, and state emission limits for each plant type, where 
applicable.''
[GRAPHIC] [TIFF OMITTED] TR09MY24.048

C. Solid Waste Generation and Beneficial Use

    Steam electric power plants generate solid waste associated with 
sludge from wastewater treatment systems (e.g., chemical 
precipitation). The EPA estimates the change in the amount of solids 
generated under the final rule compared to the baseline as 1.74 million 
tons per year. The EPA estimates that solid waste generation associated 
with the treatment of discharges of unmanaged CRL could amount to as 
much as 4.2 million tons per year.
    The EPA also evaluated the potential impacts of diverting FA from 
current beneficial uses toward encapsulation of membrane filtration 
brine for disposal in a landfill. According to the latest American Coal 
Ash Association survey,\183\ more than half of the FA generated by 
coal-fired power plants is being sold for beneficial uses rather than 
disposed of, and the majority of this beneficially used FA is replacing 
Portland cement in concrete. This also holds true for the specific 
facilities currently discharging FGD wastewater and expected to achieve 
zero discharge under the final rule, as seen by sales of FA in Schedule 
8A of the 2021 EIA-923.\184\ Summary statistics of the FA beneficial 
use percentage for these facilities is displayed in table X-4.
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    \183\ Available online at: https://acaa-usa.org/wp-content/uploads/2022/12/2021-Production-and-Use-Survey-Results-FINAL.pdf.
    \184\ Available online at: https://www.eia.gov/electricity/data/eia923/.

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[[Page 40269]]

[GRAPHIC] [TIFF OMITTED] TR09MY24.049

    The EPA also evaluated FA sales at facilities with CRL discharges 
that achieve zero discharge under the final rule in Schedule 8A of the 
2021 EIA-923.\185\ Summary statistics of the FA beneficial use 
percentage for these facilities are displayed in table X-5.
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    \185\ Available online at: https://www.eia.gov/electricity/data/eia923/.
[GRAPHIC] [TIFF OMITTED] TR09MY24.050

    In the CCR rule,\186\ the EPA noted that FA replacing Portland 
cement in concrete would result in significant avoided environmental 
impacts to energy use, water use, GHG emissions, air emissions, and 
waterborne wastes.
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    \186\ Available online at: https://www.regulations.gov. Docket 
ID: EPA-HQ-RCRA-2009-0640.
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    For the final rule, the EPA is identifying zero-discharge systems 
as the technology basis for establishing BAT limitations to control 
pollutants discharged in FGD wastewater and CRL. More specifically, the 
technology basis for BAT is membrane filtration systems, SDEs, and 
thermal evaporation systems (see section VII.B of this preamble for 
more details). For the final rule, the EPA made several updates to its 
FA analysis, including the following: revising estimates of the amount 
of FA required for brine encapsulation, revising estimates of the 
amount of FA available at each plant for brine encapsulation, adding 
costs for steam electric power plants that would need to purchase 
additional FA for brine encapsulation, adding costs for disposal of the 
additional FA, and revising compliance costs by selecting the least 
costly zero-discharge technology for FGD and/or CRL. See section 5 of 
the TDD and the EPA's 2024 Steam Electric Supplemental Final Rule: Fly 
Ash Analysis memorandum (DCN SE11692) for more details. The EPA found 
that 17 of the 26 steam electric power plants with FGD wastewater 
discharges produce enough FA for the EPA's estimated brine 
encapsulation if they do not sell any FA. Two plants with a FA deficit 
are expected to retire or undergo fuel conversion prior to December 31, 
2034, and will not need to meet zero-discharge requirements under the 
final rule. The EPA expects that the other seven plants with a FA 
deficit will install SDEs (or another technology at a lower cost) that 
will not require the use of FA for encapsulation to meet the final rule 
requirements. In addition, plants may be able to manage the FA deficit 
through FGD scrubber purge management and using a different brine 
encapsulation recipe (e.g., include additional lime).
    The EPA also found 61 of the 90 steam electric power plants with 
CRL discharges produce enough FA for the EPA's estimated brine 
encapsulation, even after accounting for encapsulation for FGD 
wastewater treatment. Thirteen of the 29 plants with a FA deficit will 
retire or undergo fuel conversion prior to December 31, 2034, and will 
not need to meet zero discharge requirements under the final rule. The 
EPA expects that the other 16 plants with a FA deficit will either 
purchase FA (accounted for in the EPA's cost estimates), manage the 
deficit using approaches described above for FGD wastewater, or install 
SDEs (or another technology at a lower cost) which will

[[Page 40270]]

not require the use of FA for encapsulation to meet the final rule 
requirements. See additional discussion in section VII.B.1.a of this 
preamble.

D. Changes in Water Use

    Steam electric power plants typically use water for handling solid 
waste, including ash, and for operating wet FGD scrubbers. The 
technology basis for FGD wastewater in the 2020 rule, chemical 
precipitation plus LRTR, was not expected to reduce or increase the 
volume of water used. Under this final rule, plants that install a 
membrane filtration or thermal evaporation system for FGD wastewater 
treatment are assumed to decrease their water use compared to the 
baseline by recycling all permeate back into the FGD system, which 
would avoid the costs of pumping or treating new makeup water. 
Therefore, the EPA estimated the reduction in water use resulting from 
membrane filtration or thermal evaporation treatment as equal to the 
estimated volume of the permeate stream from the membrane filtration 
system.
    The BA transport technologies associated with the baseline and the 
final rule for BA transport water eliminate or reduce the volume of 
water used by wet sluicing BA operating systems. The 2020 rule 
established limitations based on plants operating a high recycle rate 
system, allowing up to a 10 percent purge of the total system volume. 
As part of this rule, the EPA is establishing zero-discharge 
requirements for BA handling. Thus, for the final rule, the EPA expects 
to see a decrease in water use for BA handling operations because 
plants that operate zero discharge BA handling systems are assumed to 
decrease their water use compared to baseline by recycling all 
transport water back to the BA handling system, which would avoid the 
costs of pumping or treating new makeup water. The EPA estimated the 
reduction in water use resulting from complete recycle as equal to the 
estimated volume of the percent purge (estimated to be 2 percent).
    The EPA does not expect a change in water use associated with the 
treatment technology considered for the treatment of CRL or legacy 
wastewater as part of this final rule.
    Overall, the EPA estimates that plants would decrease their water 
use by 5.52 million gallons per day (MGD) compared to the baseline 
under the final rule.

XI. Environmental Assessment

A. Introduction

    The EPA conducted an environmental assessment for this final rule. 
The Agency reviewed available literature on the documented 
environmental and human health effects of the pollutants discharged in 
steam electric power plant FGD wastewater, BA transport water, CRL, and 
legacy wastewater. The EPA conducted modeling to determine the impacts 
of pollutant discharges from the plants that are regulated by this 
final rule. For the reasons described in section VIII of this preamble, 
the baseline for these analyses appropriately consists of the 
environmental and human health results of achieving the 2020 rule 
requirements (the same baseline the EPA used to evaluate costs, 
benefits, and pollutant loadings). Under this assessment, the EPA 
compared the change in impacts associated with the final rule to those 
projected under the baseline.
    The EA presents information from the EPA's review of the scientific 
literature and documented cases of impacts of pollutants discharged in 
steam electric power plant wastewater on human health and the 
environment, as well as a description of EPA's modeling methodology and 
results. The EA contains information on literature that the EPA has 
reviewed since the 2020 rule, updates to the environmental assessment 
analyses, and modeling results for the final rule. The 2015 EA (EPA-
821-R-15-006) and 2020 EA (EPA 821-R-20-002) provide information from 
the EPA's earlier review of the scientific literature and of documented 
cases of the impacts on human health and the environment associated 
with the wider range of steam electric power plant wastewater 
discharges addressed in the 2015 rule, as well as a full description of 
the EPA's modeling methodology.
    Current scientific literature indicates that untreated steam 
electric power plant wastewaters, such as FGD wastewater, BA transport 
water, CRL, and legacy wastewater, contain large amounts of a wide 
range of pollutants, some of which are toxic and bioaccumulative and 
cause detrimental environmental and human health impacts. For 
additional information, see section 2 of the EA. The EPA also 
considered environmental and human health effects associated with 
changes in air emissions, solid waste generation, and water 
withdrawals. sections X and XII of this preamble discuss these effects.

B. Updates to the Environmental Assessment Methodology

    For this rule, the EPA used the steady-state, national-scale 
immediate receiving water (IRW) model to evaluate the direct and 
indirect discharges from steam electric power plants. This model was 
also used for the 2015 and 2020 ELG rules and 2015 CCR rule. The model 
focused on impacts within the immediate surface waters where discharges 
occurred (defined as the closest segments of approximately 0.25 miles 
to five miles long). The EPA also modeled receiving water 
concentrations downstream from steam electric power plant discharges 
using a downstream fate and transport model (see section XII). For this 
final rule, the Agency updated pollutant-specific benchmarks based on 
revised guidance and standards. The environmental assessment also 
incorporates changes to the industry profile outlined in section V of 
this preamble.

C. Outputs From the Environmental Assessment

    Based on comparisons to the baseline, the EPA estimated 
environmental and ecological changes associated with the changes in 
pollutant loadings expected under the final rule. These environmental 
and ecological changes include changes in impacts to wildlife and 
humans. More specifically, the environmental assessment evaluated 
changes in: (1) surface water quality, (2) impacts to wildlife, (3) 
number of receiving waters with potential human health cancer risks, 
(4) number of receiving waters with potential to cause noncancer human 
health effects, and (5) metal and nutrient discharges to sensitive 
waters (e.g., CWA section 303(d) impaired waters).\187\ The EPA also 
evaluated other unqantified environmental changes (e.g., ground water 
quality and attractive nuisances), as well as further impacts as 
described in section XII.
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    \187\ For the proposed rule, the EPA evaluated potential 
cumulative impacts (joint toxic action) based on interaction 
profiles (Supplemental Environmental Assessment for the Proposed 
Revisions to the Effluent Limitations Guidelines and Standards for 
the Steam Electric Power Generating Point Source Category (EPA-821-
R-23-004). DCN SE10328). EPA did not receive any comment on the 
analysis and provides a qualitative summary in the EA for the final 
rule based on the previous analysis.
---------------------------------------------------------------------------

    As described in the EA, the EPA focused its quantitative analyses 
on the changes in environmental and human health impacts associated 
with exposure to toxic, bioaccumulative pollutants via the surface 
water pathway. The EPA modeled changes levels of toxic, bioaccumulative 
pollutants in

[[Page 40271]]

discharges of FGD wastewater, BA transport water, CRL, and legacy 
wastewater into rivers, streams, and lakes, including reservoirs. The 
EPA also addressed environmental impacts from nutrients in the EA, as 
well as in a separate analysis in section XII of this preamble.
    The environmental assessment concentrates on impacts to aquatic 
life based on changes in surface water quality; impacts to aquatic life 
based on changes in sediment quality in surface waters; impacts to 
wildlife from consumption of contaminated aquatic organisms; and 
impacts to human health from consumption of contaminated fish and 
water. The EA discusses, with quantified results, the estimated 
environmental improvements within the immediate receiving waters due to 
the pollutant loading reductions associated with the final rule 
compared to the 2020 rule.

XII. Benefits Analysis

    This section summarizes the national environmental benefits due to 
changes in steam electric power plant discharges. The BCA report 
provides additional details on the benefits methodologies and analyses. 
The analysis methodology for quantified benefits is generally the same 
that EPA used for the 2015 and 2020 rules, but with revised inputs and 
assumptions that reflect updated data and regulatory options. 
Consistent with the analysis of social costs, the EPA analyzed benefits 
of changes occurring in 2025 through 2049. The rule benefits are 
projected to begin accruing when each plant implements the control 
technologies needed to comply with any applicable BAT effluent 
limitations or pretreatment standards. As discussed in the BCA, for the 
purpose of the economic impact and benefit analysis, EPA generally 
estimates that plants will implement control technologies to meet the 
applicable rule limitations and standards as their permits are renewed, 
and no later than December 31, 2029. This schedule recognizes that 
control technology implementation is likely to be staggered over time 
across the universe of steam electric power plants. The period of 
analysis extends to 2049 to capture the estimated life of the 
compliance technology at any steam electric power plant (20 or more 
years), starting from the year of technology implementation, which can 
be as late as 2029. Benefits are annualized over 25 years.

A. Categories of Benefits Analyzed

    Table XII-1 of this preamble summarizes benefit categories 
associated with the final rule. Analyzed benefits fall into four broad 
categories: (1) human health benefits from surface water quality 
improvements, (2) ecological conditions and recreational use effects 
from surface water quality changes, (3) market and productivity 
benefits, and (4) air-related effects.\188\ Within these broad 
categories, the EPA was able to assess the benefits of the final rule 
with varying degrees of completeness and rigor. Where possible, the EPA 
quantified the expected changes in effects and estimated monetary 
values. However, data limitations, modeling limitations, and gaps in 
the understanding of how society values certain environmental changes 
prevented the EPA from quantifying and/or monetizing some benefit 
categories.
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    \188\ Consistent with Office of Management and Budget Circular 
A-4 (2023), EPA appropriately considers additional benefits of this 
action (e.g., air benefits). Circular A-4 (2023) states:
    Your analysis should look beyond the obvious benefits and costs 
of your regulation and consider any important additional benefits or 
costs, when feasible. . . . These sorts of effects sometimes are 
referred to by other names: for example, indirect or ancillary 
benefits and costs, co-benefits, or countervailing risks.
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    The following section summarizes the EPA's analysis of the benefit 
categories the Agency was able to partially quantify and/or monetize to 
various degrees (identified in the columns of table XII-1 of this 
preamble). The EPA reviewed comments received in response to the 
proposed rule on the extent to which partially quantified benefits 
(e.g., some health endpoints) or unquantified benefits (e.g., cost 
savings to drinking water systems) could be more fully quantified and/
or monetized. In the final rule analysis, the Agency revised its 
approach to quantify and monetize additional benefits, including those 
associated with avoided cardiovascular disease premature mortality from 
reduced lead exposure and those associated with avoided drinking water 
treatment costs. The final rule also affects additional benefit 
categories that the Agency was not able to quantify or monetize at all. 
The BCA further describes some of these important nonmonetized 
benefits. The EPA notes that all human health and environmental 
improvements discussed in the EA also represent benefits of the final 
rule (whether quantified or unquantified).

[[Page 40272]]

[GRAPHIC] [TIFF OMITTED] TR09MY24.051


[[Page 40273]]



B. Quantification and Monetization of Benefits

1. Human Health Effects From Surface Water Quality Changes
    Changes in pollutant discharges from steam electric power plants 
affect human health in multiple ways. Exposure to pollutants in steam 
electric power plant discharges via consumption of fish from affected 
waters can cause a wide variety of adverse health effects, including 
cancer, kidney damage, nervous system damage, fatigue, irritability, 
liver damage, circulatory system damage, vomiting, diarrhea, and IQ 
loss. Exposure to drinking water containing brominated disinfection 
byproducts can cause adverse health effects such as bladder cancer and 
reproductive and fetal development issues. Because the final rule will 
reduce discharges of steam electric pollutants into waterbodies that 
directly receive or are downstream from these discharges, it may reduce 
the incidence of associated illnesses, even if by relatively small 
amounts.
    Due to data limitations and uncertainties, the EPA can only 
monetize a subset of the health benefits associated with changes in 
pollutant discharges from steam electric power plants resulting from 
the final rule. The EPA estimated changes in the number of individuals 
experiencing adverse human health effects in the populations exposed to 
steam electric discharges and/or altered exposure levels and valued 
these changes using different monetization methods for different 
benefit endpoints.
    The EPA estimated changes in health risks from the consumption of 
contaminated fish from waterbodies within 50 miles of households. The 
EPA used Census block group population data and region-specific average 
fishing rates to estimate the exposed population. The EPA used cohort-
specific fish consumption rates and waterbody-specific fish tissue 
concentration estimates to calculate potential exposure to steam 
electric pollutants in recreational fishers' households. Cohorts were 
defined by age, sex, race/ethnicity, and fishing mode (recreational or 
subsistence). EPA used these data to quantify and monetize changes in 
three categories of human health effects, which are further detailed in 
the BCA Report: (1) reduction in IQ loss from lead exposure via fish 
consumption in children aged zero to seven, (2) reduction in 
cardiovascular disease premature mortality from lead exposure via fish 
consumption and (3) reduction in in utero mercury exposure via maternal 
fish consumption and associated IQ loss. The EPA also analyzed the 
reduction in the incidence of skin cancer from arsenic exposure via 
fish consumption but found negligible changes and therefore did not 
monetize the associated benefits.
    EPA estimated the annualized human health benefits of surface water 
quality changes of the final rule and the resultant reduction in 
pollutant exposure from consuming self-caught fish to range between 
$2.18 million and $2.45 million using a two percent discount rate. Most 
of these monetized benefits are associated with the changes in mercury 
exposure. section 5 of the BCA provides additional detail on the 
methodology.
    The EPA also estimated changes in bladder cancer incidence from the 
use and consumption of drinking water with lower levels of total 
trihalomethanes (TTHMs) resulting from reductions in bromide discharges 
under the final rule. The EPA estimated changes in cancer risks within 
populations served by drinking water treatment plants with intakes on 
surface waters affected by bromide discharges from steam electric power 
plants. The EPA used the service area of each public water system to 
estimate and characterize the exposed population. The EPA modeled 
changes in waterbody-specific bromide concentrations and changes in 
facility-specific TTHM concentrations at drinking water treatment 
facilities to calculate potential reductions in TTHM exposure and 
associated health benefits. To value changes in the economic burden 
associated with cancer morbidity, the EPA used base WTP estimates from 
Bosworth, Cameron, and DeShazo (2009) for colon/bladder cancer. To 
value changes in excess mortality from bladder cancer, the EPA used the 
estimated value of a statistical life (VSL) for each year in the period 
of analysis (from $13.54 million per death in 2025 to $16.36 million 
per death in 2049).
    The final rule is estimated to result in a total of 98 avoided 
cancer cases and 28 avoided premature excess deaths by reducing TTHM 
exposure during the period 2025-2049. The associated annualized 
benefits are $13.4 million using a two percent discount rate.
    The formation of TTHM in a particular water treatment system is a 
function of several site-specific factors, including chlorine, bromine, 
and organic carbon concentrations; and temperature and pH of the water; 
and the system residence time. The EPA did not collect site-specific 
information on these factors at each potentially affected drinking 
water treatment facility. Instead, the EPA's analysis only addresses 
the estimated site-specific changes in bromides. The EPA used the 
national relationship between changes in TTHM exposure and changes in 
incidence of bladder cancer modeled by Regli et al. (2015) \189\ and 
Weisman et al. (2022).\190\ Thus, while the national changes in TTHM 
exposure and bladder cancer incidence are the EPA's best estimate given 
estimated changes in bromide, the EPA cautions that estimates for any 
specific drinking water treatment facility could be over- or 
underestimated. Additional details on this analysis are provided in 
section 4 of the BCA.
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    \189\ Regli, S., Chen, J., Messner, M., Elovitz, M.S., 
Letkiewicz, F.J., Pegram, R.A., . . . Wright, J.M. (2015). 
Estimating Potential Increased Bladder Cancer Risk Due to Increased 
Bromide Concentrations in Sources of Disinfected Drinking Waters. 
Environmental Science & Technology, 49(22), 13094-13102. Available 
online at: https://doi.org/10.1021/acs.est.5b03547.
    \190\ Weisman, R., Heinrich, A., Letkiewicz, F., Messner, M., 
Studer, K., Wang, L., . . . Regli, S. (2022). Estimating National 
Exposures and Potential Bladder Cancer Cases Associated with 
Chlorination DBPs in U.S. Drinking Water. Environmental Health 
Perspectives, 130:8, 087002-1-087002-10. Available online at: 
https://ehp.niehs.nih.gov/doi/full/10.1289/EHP9985.
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2. Ecological Condition and Recreational Use Effects from Changes in 
Surface Water Quality Improvements
    The EPA evaluated whether the final rule would alter aquatic 
habitats and human welfare by reducing concentrations of harmful 
pollutants such as arsenic, cadmium, chromium, copper, lead, mercury, 
nickel, selenium, zinc, nitrogen, phosphorus, and suspended sediment 
relative to baseline. These changes may affect the usability of some 
recreational waters relative to baseline, thereby affecting 
recreational users. Changes in pollutant loadings can also change the 
attractiveness of recreational waters by making recreational trips more 
or less enjoyable. The final rule may also change nonuse values 
stemming from bequest, altruism, and existence motivations. Individuals 
may value water quality maintenance, ecosystem protection, and healthy 
species populations independent of any use of those attributes.
    The EPA uses a water quality index (WQI) to translate water quality 
measurements, gathered for multiple parameters that indicate various 
aspects of water quality, into a single numerical indicator. The 
indicator reflects achievement of quality consistent with the 
suitability for certain uses. The WQI includes seven parameters: 
dissolved oxygen, biochemical oxygen demand, fecal coliform, total 
nitrogen, total phosphorus, TSS, and one aggregate

[[Page 40274]]

subindex for toxics. The EPA modeled changes in four of these 
parameters and held the remaining parameters (dissolved oxygen, 
biochemical oxygen demand, and fecal coliform) constant for the 
purposes of this analysis.
    The EPA estimated the change in monetized benefit values using an 
updated version of the meta-regressions of surface water valuation 
studies used in the benefit analyses of the 2015 and 2020 rules. The 
meta-regressions quantify average household WTP for incremental 
improvements in surface water quality. section 6 of the BCA provides 
additional detail on the valuation methodology.
    An estimated 58.9 million households reside in Census block groups 
that are within 100 miles of reaches that are affected by the final 
rule.\191\ The central tendency estimate of the total WTP for water 
quality changes associated with reductions in metal pollutants 
(arsenic, cadmium, chromium, copper, lead, mercury, zinc, and nickel), 
nonmetal pollutants (selenium), nutrient pollutants (phosphorus and 
nitrogen under the final rule is $1.24 million using a two percent 
discount rate. The average WTP per household is $0.02 per year.
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    \191\ A reach is a section of a stream or river along which 
similar hydrologic conditions exist, such as discharge, depth, area, 
and slope.
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3. Changes in Air-Quality-Related Effects
    The EPA expects the final rule to affect air pollution through 
three main mechanisms: (1) changes in auxiliary electricity use by 
steam electric facilities due to the need to operate wastewater 
treatment, ash handling, and other systems for compliance with the 
final rule; (2) changes in transportation-related air emissions due to 
changes in the trucking of CCR waste to landfills; and (3) changes in 
the electricity generation profile due to increases in wastewater 
treatment costs compared to baseline and the resulting changes in EGU 
relative operating costs.
    Changes in the electricity generation profile can increase or 
decrease air pollutant emissions because emission factors vary for 
different types of EGUs. For this analysis, the changes in air 
emissions are based on the change in dispatch of EGUs as projected by 
IPM after overlaying the costs of complying with the final rule onto 
EGUs' production costs. As discussed in section VIII of this preamble, 
the IPM analysis accounts for the effects of other regulations on the 
electric power sector, as well as provisions of the IRA.
    The EPA evaluated potential effects resulting from net changes in 
air emissions of five pollutants: CO2, CH4, 
NOX, SO2, and primary PM2.5. 
CO2 and CH4 are key GHGs linked to a wide range 
of climate-related effects. CO2 is also the main GHG emitted 
from coal power plants. NOX and SO2 are 
precursors to PM2.5, which are also emitted directly, and 
NOX is an ozone precursor. These air pollutants cause a 
variety of adverse health effects including premature mortality, 
nonfatal heart attacks, hospital admissions, emergency department 
visits, upper and lower respiratory symptoms, acute bronchitis, 
aggravated asthma, lost work and school days, and acute respiratory 
symptoms.
    Table XII-2 of this preamble shows the changes in emissions of 
CO2, CH4, NOX, SO2, and 
primary PM2.5 under the final rule relative to the baseline 
for selected IPM run years. The final rule will result in a net 
reduction in air emissions of four pollutants, and a small increase in 
CH4 emissions due to the increased trucking of CCR waste to 
landfills. This effect is driven mostly by the estimated changes in the 
profile of electricity generation, as emission reductions due to shifts 
in modeled EGU dispatch and energy sources offset relatively small 
increases in air emissions from increased electricity use and trucking 
by steam electric power plants.
[GRAPHIC] [TIFF OMITTED] TR09MY24.052

    The EPA estimated the monetized value of human health benefits 
among populations exposed to changes in PM2.5 and ozone. The 
final rule is expected to alter the emissions of primary 
PM2.5, SO2 and NOX, which will in turn 
affect the level of PM2.5 and ozone in the atmosphere. Using 
photochemical modeling, the EPA predicted the change in the annual 
average PM2.5 and summer season ozone across the United 
States. The EPA next quantified the human health impacts and economic 
value of these changes in air quality using the environmental Benefits 
Mapping and Analysis Program--Community Edition.
    To estimate the climate benefits associated with changes in 
CO2 and CH4 emissions, the EPA used social cost 
of greenhouse gas (SC-GHG) estimates specifically, estimates of the 
social cost of carbon (SC-CO2) and social cost of methane 
(SC-CH4). The SC-GHG is an estimate of the monetary value of 
the net harm to society associated with emitting a metric ton of the 
GHG in question into the atmosphere in a given

[[Page 40275]]

year, or the benefit of avoiding those emissions.\192\
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    \192\ In principle, the SC-GHG includes the value of all climate 
change impacts, including (but not limited to) changes in net 
agricultural productivity, human health effects, property damage 
from increased flood risk and natural disasters, disruption of 
energy systems, risk of conflict, environmental migration, and the 
value of ecosystem services. The SC-GHG therefore, reflects the 
societal value of reducing emissions of by one metric ton. The EPA 
and other Federal agencies began regularly incorporating estimates 
of SC-CO2 in their benefit-cost analyses conducted under 
Executive Order 12866 since 2008, following a Ninth Circuit Court of 
Appeals remand of a rule for failing to monetize the benefits of 
reducing CO2 emissions in a rulemaking process.
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    To estimate the net climate benefits of CO2 emission 
reductions expected from the final rule and disbenefits of increases in 
CH4 emissions, the EPA used the SC-GHG estimates presented 
in the 2023 final rule Standards of Performance for New, Reconstructed, 
and Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review (U.S. EPA, 2023). These estimates 
reflect recent advances in the scientific literature on climate change 
and its economic impacts and incorporate recommendations made by the 
National Academies (National Academies, 2017). See section 8 of the BCA 
for more discussion of the SC-GHG values.
    Table XII-3 of this preamble shows the annualized climate change, 
PM2.5, and ozone-related human health benefits for the final 
rule. Climate change benefits are presented for the three near-term 
Ramsey discount rates used in developing the SC-GHG values, whereas the 
PM2.5 and ozone-related human health benefits are based on 
long-term ozone exposure mortality risk estimates and with a two 
percent discount rate. See section 8 of the BCA for benefits based on 
pooled short-term ozone exposure mortality risk estimates.
[GRAPHIC] [TIFF OMITTED] TR09MY24.053

    The estimates of monetized benefits shown here do not include 
several important benefit categories, such as direct exposure to 
SO2, NOX, and HAPs, including mercury and 
hydrogen chloride. Although the EPA does not have sufficient 
information or modeling available to provide monetized estimates of 
changes in exposure to these pollutants for the final rule, the EPA 
includes a discussion of these unquantified benefits in the BCA. For 
more information on the benefits analysis, see section 8 of the BCA.
4. Other Quantified and/or Monetized Benefits
a. Changes in Drinking Water Treatment Costs
    The final rule will decrease discharges of pollutants that affect 
the costs of treating drinking water. TSS affects turbidity of source 
water, which drinking water systems treat by adding chemical coagulants 
to bond to the sediment particles. Drinking water systems thus accrue 
incremental costs related to purchases of coagulants as well as costs 
from disposal of coagulant sediment sludge. In addition, drinking water 
systems address taste and odor issues linked to excess nutrients (such 
as nitrogen) and associated eutrophication in source water. The EPA 
identified drinking water systems whose source waters are likely to see 
reductions in TSS and total nitrogen under the final rule, then 
estimated changes in source water concentrations of the pollutants for 
those systems. The EPA then estimated treatment cost savings associated 
with reductions in TSS and total nitrogen using a treatment cost 
elasticity approach (see Price and Heberling (2018) for a review of the 
literature on drinking water treatment cost elasticities). The EPA 
estimated cost changes relating to treatment O&M costs alone, assuming 
no net savings from any capital improvements drinking water systems 
already made. The EPA did not quantify avoided drinking water treatment 
costs associated with reductions in pollutants such as phosphorus, 
halogens, and metals due to uncertainties in the elasticity between 
source water concentrations of these parameters and drinking water 
treatment costs, lack of information on baseline concentrations of 
these pollutants at source water intakes, and the possibility of 
double-counting treatment cost savings for particular pollutants. The 
EPA expects that the final rule will provide relatively small 
annualized benefits from reductions in nitrogen and total suspended 
solids in the form of drinking water treatment cost savings of $460,000 
to $552,000 per year, calculated using a 2 percent discount rate.
b. Changes in Dredging Costs
    The final rule affects discharge loadings of various categories of 
pollutants, including TSS. As a result, the final rule is expected to 
change the rate of sediment deposition in affected waterbodies, 
including navigable waterways and reservoirs that require dredging for 
maintenance. The EPA estimated very small benefits from changes in 
sedimentation and associated maintenance dredging costs in reaches and 
reservoirs affected by steam electric power plant discharges. section 9 
of the BCA provides additional detail on the methodology.
c. Benefits to Threatened and Endangered Species
    To assess the potential for the final rule to benefit threatened 
and endangered species (both aquatic and terrestrial) relative to the 
2020 ELG baseline, the EPA analyzed the overlap between waters expected 
to see reductions in wildlife water quality criteria exceedance status 
under the final rule and the known critical habitat

[[Page 40276]]

locations of high-vulnerability threatened and endangered species. The 
EPA examined the life history traits of potentially affected threatened 
and endangered species and categorized the species by potential for 
population impacts due to surface water quality changes. Section 7 of 
the BCA provides additional detail on the methodology. The EPA's 
analysis showed that, of the species categorized as having higher 
vulnerability to water pollution, 30 have known critical habitats 
overlap with surface waters affected by steam electric power plant 
discharges. Improvements under the final rule between 2025 and 2029 are 
estimated to potentially benefit 10 of these species, whereas 
improvements projected after 2030 are estimated to benefit 12 species. 
Principal sources of uncertainty include the specifics of how changes 
under the final rule will impact threatened and endangered species, 
exact spatial distribution of the species, and additional species of 
concern not considered.

C. Total Monetized Benefits

    Using the analysis approach described above, the EPA estimated 
annualized benefits of the final rule for all monetized categories. The 
final rule has monetized benefits estimated at $3,217 million using a 
two percent discount rate, as shown in table XII-4.
[GRAPHIC] [TIFF OMITTED] TR09MY24.054

D. Additional Benefits

    The monetary value of the final rule's effects on social welfare 
does not account for all effects of the rule because, as described 
above, the EPA is currently unable to quantify and/or monetize some 
categories. The EPA anticipates that the final rule will also generate 
important unquantified benefits, including but not limited to:
     health benefits to over 30 million people who, due to 
reductions in PWS-level arsenic, lead, and thallium concentrations, 
will experience reductions in unmonetized cancer and non-cancer effects 
from exposure to toxic pollutants from consumption of fish or drinking 
water;
     unquantified and unmonetized averted IQ losses and 
educational effects from childhood lead exposure and in-utero mercury 
exposure from fish consumption by households that do not engage in 
recreational or subsistence fishing;
     improved habitat conditions for plants, invertebrates, 
fish, amphibians, and the wildlife that prey on aquatic organisms;
     enhanced ecosystem productivity and health, including 
reduced toxic discharges into habitats of over 100 high-vulnerability 
threatened and endangered species;

[[Page 40277]]

     additional changes to water treatment costs for drinking 
water, irrigation, and agricultural uses;
     changes in fisheries yield and harvest quality from 
aquatic habitat changes;
     changes in health hazards from recreational exposures; and
     groundwater quality impacts.
    While some health benefits and WTP for water quality improvements 
have been partially quantified and/or monetized, those estimates may 
not fully capture all important water quality-related benefits. 
Although the following quantifications cannot necessarily be combined 
with other monetized effects, another way to characterize the benefits 
is that the final rule is expected to result in a 53 percent reduction 
in chronic exceedances and a 33 percent reduction in acute exceedances 
of the national recommended water quality criteria. It is also expected 
to result in a reduction of up to a 63 percent in the number of 
immediate receiving water reaches with ambient concentrations exceeding 
human health criteria for at least one pollutant.
    The BCA discusses changes in these potentially important effects 
qualitatively, indicating their potential magnitude where possible.

XIII. Environmental Justice Impacts

    Consistent with the EPA's commitment to advancing environmental 
justice (EJ) in the Agency's actions, the Agency has analyzed the 
impacts of this action on communities with EJ concerns and sought input 
and feedback from stakeholders representing these communities. The EPA 
has prepared this analysis to implement the recommendations of the 
Agency's EJ Technical Guidance.\193\ For ELG rulemakings, an analysis 
of EJ impacts is typically conducted as part of the BCA alongside other 
non-statutorily required analyses such as monetized benefits. However, 
for this action, the analysis was placed in a standalone EJA document 
to provide the public with a more detailed discussion of the potential 
EJ impacts of this action and the initial outreach to communities with 
potential EJ impacts. The analysis does not form a basis or rationale 
for any of the actions the EPA is taking in this rulemaking.
---------------------------------------------------------------------------

    \193\ U.S. EPA (Environmental Protection Agency). 2016. 
Technical Guidance for Assessing Environmental Justice in Regulatory 
Analysis. June. Available online at: https://www.epa.gov/environmentaljustice/technical-guidance-assessing-environmental-justice-regulatory-analysis.
---------------------------------------------------------------------------

    Overall, EPA's EJ analysis showed the final rule will reduce 
differential baseline exposures to pollutants in wastewater and 
resulting human impacts for population groups of concern when 
considering potential EJ implications of this regulatory action. E.O. 
12898 identifies a number of population groups of concern including 
minority populations, low-income populations, and Indigenous peoples in 
the United States and its territories and possessions. In this 
particular analysis, improvements to water quality, wildlife, and human 
health resulting from reductions in pollutants in surface water will be 
distributed more among low-income populations and some people of color 
under some or all of the regulatory options for this final rule.
    Reductions in TTHM concentrations in drinking water and resulting 
reductions in bladder cancer cases and excess bladder cancer deaths 
will also be distributed more among communities with EJ concerns under 
the final rule. Remaining exposures, impacts, and benefits analyzed are 
small enough that EPA could not conclude whether changes in baseline 
disproportionate impacts would occur, such as reductions in avoided IQ 
point losses among children exposed to lead from fish consumption which 
were estimated to be a total of one avoided IQ point loss across 
approximately 1.5 million children.
    Although the changes in GHGs attributable to the final rule are 
small compared to worldwide emissions, findings from peer-reviewed 
evaluations demonstrate that actions that reduce GHG emissions are also 
likely to reduce climate-related impacts on communities with EJ 
concerns.
    At the national level, upper bound average compliance costs per 
residential households under the final rule are $3.14 per year. Costs 
of the final rule in terms of electricity price increases among 
residential households may impact low-income households and households 
of color more relative to all households as low-income households and 
households of color tend to spend a greater proportion of their income 
on energy expenditures. Despite this, the potential price increases 
under the upper bound cost scenario represent between less than 0.1 
percent and 0.2 percent of energy expenditures for all income, race 
groups, and income quintiles, and therefore the EPA does not expect 
costs to have a substantial impact on low-income households and 
households of color. The methodology and findings of the EJA are 
described in further detail below.

A. Literature Review

    The EPA conducted a literature review to identify academic research 
and articles on EJ concerns related to coal-fired power plants. The EPA 
identified eight papers that focused on coal-fired power plants in the 
United States that were directly relevant to this final rule. The 
findings of these papers suggest that coal-fired power plants tend to 
be in poor communities, Indigenous communities, and communities of 
color. Toomey (2013) reported that 78 percent of African Americans in 
the United States live within a 30-mile radius of a coal-fired power 
plant.\194\ Impacts discussed in the reports included adverse health 
impacts resulting from air pollutants (e.g., SO2, 
NOX, PM2.5) for those living in proximity to 
coal-fired power plants, climate justice issues resulting from GHG 
emissions, and risk of impoundment failures for populations living in 
proximity to coal waste surface impoundments where coal is 
mined.195 196 197 All these impacts were found in one or 
more papers to differentially impact poor communities, Indigenous 
communities, and communities of color. For further discussion of the 
literature review, see section 2 of the EJA.
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    \194\ Toomey, D. 2013. Coal Pollution and the Fight for 
Environmental Justice. Yale Environment 360. June 19. Available 
online at: https://www.e360.yale.edu/features/naacp_jacqueline_patterson_coal_pollution_and_fight_for_environmental_justice.
    \195\ Li[eacute]vanos, R.S., Greenberg, P., Wishart, R. 2018. In 
the Shadow of Production: Coal Waste Accumulation and Environmental 
Inequality Formation in Eastern Kentucky. Social Science Research, 
Vol. 71: pp. 37-55.
    \196\ Israel, B. 2012. Coal Plants Smother Communities of Color. 
Scientific American. Available online at: https://
www.scientificamerican.com/article/coal-plants-smother-communities-
of-color/
#:~:text=People%20living%20near%20coal%20plants,percent%20are%20peopl
e%20of%20color.
    \197\ NAACP (National Association for the Advancement of Colored 
People). 2012. Coal Blooded: Putting Profits Before People. 
Available online at: https://www.naacp.org/resources/coal-blooded-putting-profits-people.
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B. Proximity Analysis

    The EPA performed proximity analyses to identify and characterize 
the communities that are expected to be impacted by discharges from 
steam electric plants via relevant exposure pathways. First, the EPA 
used geographic information system (GIS) software to map out 1- and 3-
mile buffers around each facility. A buffer is a zone that extends a 
specified distance in every direction from a point on a map. The EPA 
then assessed potential air impacts within those zones. The 1- and 3-
mile distances were chosen to be consistent with the buffer distances

[[Page 40278]]

used by the Office of Air and Radiation when performing screening 
analyses for communities surrounding industrial sources that are 
expected to be exposed to air emissions (U.S. EPA, 2021a).\198\ These 
are the distances at which air pollution concentrations will be highest 
before the plume disperses, and an analysis of air impacts with these 
zones may capture other localized impacts such as air emissions from 
truck traffic due to changes in activities at steam electric power 
plants.
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    \198\ U.S. EPA. 2021a. Regulatory Impact Analysis for Phasing 
Down Production and Consumption of Hydrofluorocarbons (HFCs) 
(September). EPA-HQ-OAR-2021-0044-0046.
---------------------------------------------------------------------------

    Second, the EPA assessed potential impacts in downstream surface 
waterbodies using 1-, 3-, 50-, and 100-mile buffer distances around 
each waterbody segment downstream of the initial common identifiers 
(COMIDs) identified for each effluent discharge. These buffers 
distances were used to capture impacts to local populations as well as 
impacts to those traveling to fish or recreate in downstream 
waterbodies (Sohngen et al, 2015; Sea Grant--Illinois-Indiana, 2018; 
Viscusi et al., 2008).199 200
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    \199\ For this analysis, a downstream waterbody is defined as a 
segment of water 300 kilometers (~187 miles) downstream of a point 
of discharge from a steam electric power plant.
    \200\ Sohngen, B., Zhang, W., Bruskotter, J., & Sheldon, B. 
(2015). Results from a 2014 survey of Lake Erie anglers. Columbus, 
OH: The Ohio State University, Department of Agricultural, 
Environmental and Development Economics and School of Environment & 
Natural Resources; Sea Grant--Illinois-Indiana (2018). Lake Michigan 
anglers boost local Illinois and Indiana economies; Viscusi, W.K., 
Huber, J., & Bell, J. (2008). The economic value of water quality. 
Environmental and resource economics, 41(2), 169-187.
---------------------------------------------------------------------------

    Finally, the EPA assessed potential drinking water impacts using 
information about the service area of PWSs with surface intakes 
downstream from steam electric power plants.
    Overall, the EPA found that 90,000 people live within 1 mile of at 
least one of the 112 steam electric power plants expected to be 
affected by the final rule and modeled for the benefits analysis, and 
about 790,000 people live within 3 miles. When comparing the 
demographic characteristics of these populations to national 
demographic characteristics, small exceedances of the national average 
are observed. Of the population living within 3 miles of a steam 
electric power plant, the percentage of people identified as low-income 
is 0.1 percent greater than the national average, and the percent of 
the population identified as American Indian/Alaska Native and Other 
living within one and three miles of a steam electric power plant is 
one percent greater than the national average. The results show 
relatively greater proportions of people who identify as Asian (non-
Hispanic), people who identify as American Indian or Alaska Native 
(non-Hispanic), and people who identify as Hispanic or Latino.

C. Community Outreach

    During the public comment period, the EPA received a comment 
requesting that the Agency conduct additional outreach with the nine 
communities identified for outreach during the 2023 proposal. 
Commenters urged the EPA to not extend the written public comment 
period and to move forward expeditiously to finalize the proposed rule. 
Given the time required to plan and conduct the community outreach for 
the proposed rule (meetings with five of the nine communities were held 
between May and September 2022, with planning starting in February 
2022), the EPA determined that it could not hold additional outreach 
meetings with all nine communities and also finalize the proposed rule 
expeditiously, as requested by the commenters. Therefore, the EPA did 
not hold additional outreach meetings for the final rule. The EPA 
presents the feedback received from the community outreach meetings 
conducted for the proposed rule in section 7.5 of the 2023 EJA,\201\ 
which the EPA took into consideration for the final rule.
---------------------------------------------------------------------------

    \201\ U.S. Environmental Protection Agency (2023b). 
Environmental Justice Analysis for Proposed Supplemental Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category.
---------------------------------------------------------------------------

    For the proposed rule, the EPA conducted initial outreach in all 
nine communities to local environmental and community development 
organizations, local government agencies, and individual community 
members involved in community organizing. Between May and September of 
2022, EPA was able to meet with community members in five of the 
identified communities either virtually or in a hybrid format with some 
in-person participation. The EPA was not able to hold a virtual or 
hybrid meeting with the remaining four communities. For detailed 
information of the EPA's community selection methodology, the 
communities selected, and the structure of the community meetings, see 
section 7.4 of the 2023 EJA.\202\
---------------------------------------------------------------------------

    \202\ Ibid.
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    The EPA received a broad range of input from individuals in these 
communities on regulatory preferences, environmental concerns, human 
health and safety concerns, economic impacts, cultural/spiritual 
impacts, and ongoing communication/public outreach. Community members 
also expressed interest in other EPA actions. Two broad themes were 
conveyed consistently across communities. First, community members 
identified several perceived harmful impacts from steam electric power 
plants and conveyed their desire for more stringent regulations to 
reduce these harmful impacts. Second, community members expressed that 
more transparency and communication is needed to overcome their 
decreasing trust in the regulated steam electric power plants and state 
regulatory agencies and their feelings of skepticism that their 
communities will be protected from these harmful impacts. In addition 
to these broad themes, commenters also raised concerns unique to each 
community. For example, members of the Navajo Nation discussed with the 
EPA the spiritual and cultural impacts to the community from pollution 
related to steam electric power plants. In Jacksonville, Florida, 
community members raised concerns about tidal flows that carry 
pollution upstream and about storm surges that occur during extreme 
weather events, causing additional challenges in their community. More 
detailed summaries of these meetings are presented in section X of the 
EJA.
    The EPA considered all feedback received in these outreach 
meetings, including feedback on the stringency of potential new 
regulations and negative impacts experienced as a result of steam 
electric discharges. The final rule will result in more stringent 
limitations that will further reduce negative impacts associated with 
steam electric discharges. The EPA also considered feedback expressing 
the desire for increased transparency and communication. As discussed 
in section XIV.C.6, the EPA requiring posting of required reports to a 
publicly available website to improve transparency. In addition, the 
EPA recently added a new feature called ECHO Notify to the Enforcement 
and Compliance History Online (ECHO) website. ECHO Notify provides 
weekly email notifications of changes to enforcement and compliance 
data in ECHO. Notifications are tailored to the geographic locations, 
facility IDs, and notification options that users select. The EPA 
encourages interested community members to sign up for these alerts. 
Further information is available at https://www.echo.epa.gov/tools/echo-notify. The EPA also encourages individual facilities to work with 
local communities to foster trust and communication, for example, 
through text alert systems.

[[Page 40279]]

D. Distribution of Risks

    The EPA evaluated the distribution of pollutant loadings, estimated 
human health, and estimated environmental impacts resulting from 
polluted air, surface water, and drinking water. The EPA examined these 
distributions under both baseline and the regulatory options to 
identify where current conditions and future improvements may have a 
differential impact on communities with EJ concerns. The following 
sections discuss the EPA's methodology and findings.
1. Air
    The EPA evaluated air quality impacts in terms of changes in warm 
season maximum daily average 8-hour (MDA8) ozone and average annual 
PM2.5 concentrations, as described in the BCA. The EPA used 
the results of the analysis to further evaluate the distribution of 
air--quality impacts in the EJA to determine whether communities with 
EJ concerns experience disproportionately high exposures to MDA8 ozone 
and average annual PM2.5 under the baseline and Option B.
    The results of the EPA's distributional analysis of air quality 
impacts indicates that, under the baseline, average annual 
PM2.5 and MDA8 ozone exposures are higher among certain 
communities with EJ concerns. The EPA found higher exposures for some 
populations, such as American Indian and Alaska Native (non-Hispanic), 
Asian (non-Hispanic), and Hispanic populations, relative to their 
relevant comparison groups. While the regulatory analysis estimating 
changes in average annual PM2.5 and MDA8 ozone exposures 
shows increases and decreases in pollutant emissions across regions of 
the United States under the final rule, these changes overall are small 
and do not change the distribution of air-quality impacts observed 
under the baseline. Therefore, the EPA concludes that the air-quality 
changes resulting from the final rule are not expected to mitigate or 
exacerbate distributional disparities present under the baseline. See 
section 4.2 of the EJA for more information.
2. Surface Water
    Using results from the EA and BCA, the EPA evaluated the 
distribution of pollutant loadings and the environmental and human 
health effects of wastewater discharges from steam electric power 
plants into surface waters into immediate receiving waters. The 
following sections provide an overview of the EPA's methodology and the 
results of the EPA's distributional analysis.
a. Immediate Receiving Waters
    Using results from the EA, the EPA evaluated the distribution of 
pollutant loadings and the environmental and human health effects of 
wastewater discharges from steam electric power plants into immediate 
receiving waters across communities with EJ concerns. To evaluate the 
distribution of water quality impacts, the EPA used the IRW model to 
evaluate water quality impacts by calculating annual average total and 
dissolved pollutant concentrations in the water column and sediment of 
immediate receiving waters. It then compares these concentrations to 
specific water quality criteria values--National Recommended Water 
Quality Criteria (NRWQC) and Maximum Contaminant Levels (MCLs)--to 
assess potential impacts to wildlife and human health. To evaluate 
potential impacts to wildlife, the EPA used the IRW model to estimate 
bioaccumulation of pollutants in fish tissue of trophic level 3 (T3) 
and trophic level 4 (T4) fish using the annual average pollutant 
concentrations in the immediate receiving water. Those results were 
then compared to benchmark values--threshold effect concentration (TEC) 
and no effect hazard concentration (NEHC)--to evaluate potential 
impacts on exposed sediment biota and piscivorous wildlife that consume 
T3 and T4 fish, respectively. The EPA also used estimated fish tissue 
concentrations to assess human health impacts--non-cancer and cancer 
risks--to human populations from consuming fish that are caught in 
contaminated receiving waters. For a more detailed discussion of the 
IRW Model see the EA. Information on the socioeconomic characteristics 
of affected communities was gather from the 2017-2021 ACS dataset and 
was included with the results from the model to evaluate the 
distribution of impacts (relative to the baseline) under the final 
rule.
b. Water Quality, Wildlife, and Human Health Impacts
    Based on the results of the distributional analyses of water 
quality, wildlife, and human health impacts, the EPA determined that 
under the baseline there were distributional disparities among 
communities with EJ concerns. Disparities were most often observed 
among populations such as African American (non-Hispanic) or American 
Indian or Alaska Native (non-Hispanic) populations when comparing the 
percent of the population affected in communities with immediate 
receiving waters benchmark exceedances to the national average and to 
communities with immediate receiving waters without benchmark 
exceedances. This, along with distributional disparities observed under 
the baseline for other populations, indicates the presence of potential 
EJ concerns under the baseline across the three analyses. Analyzing the 
impacts of final rule across the analyses, the EPA found that the final 
rule reduced the amount of immediate receiving waters with benchmark 
exceedances and the population affected by these exceedances. However, 
in each of the analyses the EPA found that while the final rule 
mitigated distributional disparities identified under the baseline for 
communities with EJ concerns, remaining immediate receiving waters with 
exceedances under the final rule were more concentrated in other 
communities with EJ concerns. EPA found particular concentration for 
American Indian or Alaska Native populations relative to the baseline. 
See section 4.2 of the EJA for more information.
c. Downstream Waters
    Using the results from the downstream analysis performed in the 
BCA, the EPA further evaluated the downstream surface water impacts in 
the EJA to determine whether communities with EJ concerns experience a 
differential share of noncancer health effects from exposure mercury 
through consuming fish in contaminated downstream surface waters.
    The results of the EPA's analysis showed potential EJ concerns in 
the baseline in terms of differential and adverse impacts in 
communities with EJ concerns. Differential and adverse impacts were 
concentrated among infants of color (e.g., Hispanic, Asian [non-
Hispanic], and Other [non-Hispanic]) and infants below the poverty 
level of mothers consuming fish at recreational and subsistence rates 
relative to White children and children not below the poverty line, 
respectively. For both cohorts, under the final rule, increases in 
avoided IQ point losses were estimated relative to the baseline across 
all racial or ethnic groups and income groups. These estimated 
increases were too small to substantially change the distribution of IQ 
points relative to the baseline among infants of color and among 
infants below the poverty level. See section 4.3 of the EJA for more 
information.
    The EPA also evaluated human health endpoints related to lead and 
arsenic exposures from fish consumption. As shown in the BCA, avoided 
IQ point losses in children and avoided cardiovascular deaths (CVD) in 
adults

[[Page 40280]]

from reductions in fish tissue concentrations of lead, as well as 
reductions in annual skin cancer cases in adults from reductions in 
fish tissue concentrations of arsenic estimated under the final rule 
were negligible (e.g., a total avoided IQ point loss of one point 
across 1,555,558 exposed children). Therefore, the EPA determined that 
reporting fractional distributional changes by racial or ethnic groups 
and income groups for the affected population would not be informative. 
See section 4.3 of the EJA for more information.
3. Drinking Water
    Using the results from the drinking water analysis performed in the 
BCA, the EPA further evaluated downstream drinking water impacts in the 
EJA to determine whether communities with EJ concerns served by 
potentially affected drinking water systems experience a differential 
share of bladder cancer cases from exposure to TTHM. In the BCA, the 
EPA modeled baseline incremental TTHM concentrations and bladder cancer 
cases attributable to steam electric discharges.\203\ Since the EPA 
evaluated only the changes in TTHM concentrations and avoided bladder 
cancer cases and deaths attributable to steam electric discharges in 
the BCA, in this analysis, the EPA only evaluated whether the 
distribution of exposures and health effects indicated potential EJ 
concerns under the incremental changes resulting from the regulatory 
options.
---------------------------------------------------------------------------

    \203\ Background TTHM concentrations and bladder cancer cases 
attributable to sources other than steam electric discharges were 
not modeled under the baseline but would not impact the analysis of 
incremental changes as discussed in the BCA.
---------------------------------------------------------------------------

    The results of the EPA's analysis of changes in TTHM concentrations 
and resulting changes in bladder cancer cases and deaths from consuming 
drinking water with TTHM shows that the final rule reduces TTHM 
concentrations and reduces the incidence of bladder cancer cases and 
excess bladder cancer deaths in states with affected drinking water 
systems. Across the analyses, under the final rule, the majority of 
states with affected systems serve communities with at least one 
demographic group (i.e., low-income or person of color) above the 
national average, with the largest proportion of these states having 
two demographic groups above the national average. Analyzing the 
distribution of changes across the analyses and regulatory options, the 
EPA finds that states with affected systems serving communities with 
one demographic group above the national average experience the largest 
median changes in TTHM concentrations and avoided bladder cancer cases 
and excess bladder cancer deaths than states serving communities with 
two and three or more demographic groups above the national average, 
respectively. While the magnitude of the median change observed across 
the analyses decreases in communities with one, two, or three or more 
demographic groups above the national average, the EPA finds that this 
is not due to there being smaller reductions in TTHM concentrations and 
avoided bladder cancer cases and excess bladder cancer deaths, but 
rather that these states generally have more systems experiencing 
smaller changes. See section 4.4. of the EJA for more information.

E. Distribution of Benefits and Costs

    The EPA examined the estimated benefits and costs of the final rule 
for potential differences in how they are distributed across affected 
communities, in addition to evaluating the distribution of exposures 
and health impacts discussed above. Office of Management and Budget 
(OMB) Circular A-4, which implements E.O. 12866, states that regulatory 
analyses should analyze distributional effects which Circular A-4 
defines as ``how the benefits and the costs of a regulatory action are 
ultimately experienced across the population and economy, divided up in 
various ways (e.g., income groups, race or ethnicity, gender, sexual 
orientation, disability, occupation, or geography; . . .).'' As 
discussed below, EPA research demonstrates that climate change impacts 
associated with GHG reductions that are modeled to occur under this 
rule are likely to accrue to communities with EJ concerns but other 
benefits and costs under the final rule may not have substantial 
impacts.
    The EPA began its evaluation of benefits with a screening of the 
benefits categories. For Option B, at both three percent and seven 
percent discount rates, approximately 99 percent of monetized benefits 
accrued from reductions in air pollution due to estimated shifts in 
electric generation resulting from the incremental costs of the final 
rule. Furthermore, these air benefits were always comprised of 
approximately a 3-to-1 ratio of conventional air pollutant health 
benefits to GHG benefits (see section 8 of the BCA for more information 
on air emissions and benefits).\204\ Thus, while the EPA evaluated a 
number of exposures and endpoints for disproportionate baseline 
impacts, the Agency screened these two benefit categories through this 
initial comparison for further evaluation.
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    \204\ EPA scaled the air benefits to other regulatory options 
based on total costs.
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    With respect to GHG benefits, scientific assessments and Agency 
reports produced over the past decade by the U.S. Global Change 
Research Program,\205\ the Intergovernmental Panel on Climate 
Change,206 207 208 209 210 and the National Academies of 
Science, Engineering, and Medicine 211 212 provide evidence 
that the impacts of climate change raise potential EJ concerns. These 
reports conclude that poorer communities or communities of color can be 
especially vulnerable to climate change impacts because they tend to 
have limited adaptive capacities, are more dependent on climate-
sensitive resources such as local water and food supplies or have less 
access to social and information resources. Some communities of color, 
specifically populations defined jointly by ethnic/

[[Page 40281]]

racial characteristics and geographic location, may be uniquely 
vulnerable to climate change health impacts in the United States.
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    \205\ USGCRP. 2016. The Impacts of Climate Change on Human 
Health in the United States: A Scientific Assessment. Crimmins, 
Balbus, A., Gamble, J., Beard, C., Bell, J., Dodgen, D., Eisen, R., 
Fann, N., Hawkins, M., Herring, S., Jantarasami, L., Mills, D., 
Saha, S., Sarofim, M., Trtanj, J., Ziska, L. Eds. U.S. Global Change 
Research Program, Washington, DC, 312 pp. Available online at: 
https://www.dx.doi.org/10.7930/J0R49NQX.
    \206\ USGCRP. 2018. Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment. U.S. Global Change 
Research Program. Available online at: https://pp.doi.org/10.7930/NCA4.2018.
    \207\ Porter, J, Xie, L., Challinor, A., Cochrane, K., Howden, 
S., Iqbal, M., Lobell, D., Travasso, M. 2014. Food security and food 
production systems. In: Climate Change 2014: Impacts, Adaptation, 
and Vulnerability. Part A: Global and Sectoral Aspects. Contribution 
of Working Group II to the Fifth Assessment Report of the 
Intergovernmental Panel on Climate Change pp. 485-533.
    \208\ Oppenheimer, M., Campos, M., Warren, R., Birkmann, J., 
Luber, G., O'Neill, B., Takahashi, K. 2014. Emergent risks and key 
vulnerabilities. Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part A: Global and Sectoral Aspects. pp. 1039-1099.
    \209\ Smith, K, Woodward, A., Campbell-Lendrum, D., Chadee, D., 
Honda, Y., Liu, Q., Olwoch, J., Revich, B., Sauerborn, R. 2014. 
Human health: impacts, adaptation, and co-benefits. Climate Change 
2014. Impacts, Adaptation, and Vulnerability. Part A: Global and 
Sectoral Aspects. Contribution of Working Group II to the Fifth 
Assessment Report of the Intergovernmental Panel on Climate Change 
pp. 709-754.
    \210\ IPCC (Intergovernmental Panel on Climate Change), 2018. 
Global Warming of 1.5[deg]C, An IPCC Special Report on the impacts 
of global warming of 1.5[deg]C above pre-industrial levels and 
related global greenhouse gas emission pathways, in the context of 
strengthening the global response to the threat of climate change, 
sustainable development, and efforts to eradicate poverty.
    \211\ National Research Council. 2011. America's Climate 
Choices. Available online at: https://www.doi.org/10.17226/12781.
    \212\ NASEM. 2017. Communities in Action: Pathways to Health 
Equity. Available online at: https://www./doi.org/10.17226/24624.
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    The EPA recently conducted a peer-reviewed analysis of the 
distribution of climate change impacts. EPA (2021) \213\ evaluated the 
disproportionate risks to communities with EJ concerns. The EPA looked 
at factors including age, income, education, race, and ethnicity 
associated with six impact categories: air quality and health, extreme 
temperature and health, extreme temperature and labor, coastal flooding 
and traffic, coastal flooding and property, and inland flooding and 
property. The EPA calculated risks for each demographic group relative 
to its ``reference population'' (all individuals outside of each group) 
for scenarios with 2[deg]C of global warming or 50 centimeters of sea 
level rise. The estimated risks were based on current demographic 
distributions in the contiguous United States. EPA (2021) includes 
findings that the following groups are more likely than their reference 
population to currently live in areas with:
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    \213\ U.S. EPA (Environmental Protection Agency). 2021. Climate 
Change and Social Vulnerability in the United States: A Focus on Six 
Impacts. EPA 430-R-21-003.
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     The highest increases in childhood asthma diagnoses from 
climate-driven changes in PM2.5 (low-income, Black and 
African American, Hispanic and Latino, and Asian populations);
     The highest percentage of land lost to inundation (low-
income and American Indian and Alaska Native populations);
     The highest increases in mortality rates due to climate-
driven changes in extreme temperatures (low-income and Black and 
African American populations);
     The highest rates of labor hour losses for weather-exposed 
workers due to extreme temperatures (low-income, Black and African 
American, American Indian and Alaska Native, Hispanic and Latino, and 
Pacific Islander populations);
     The highest increases in traffic delays associated with 
high-tide flooding (low-income, Hispanic and Latino, Asian, and Pacific 
Islander populations); and
     The highest damages from inland flooding (Pacific Islander 
populations).
    For further discussion of the impacts analyzed in U.S. EPA (2021) 
and other peer-reviewed evaluations, see section 5.1 of the EJA.
    The EPA notes that the changes in GHG emissions attributable to the 
final rule are relatively small compared to worldwide emissions. 
Nevertheless, the findings of peer-reviewed evaluations demonstrate 
that actions that reduce GHG emissions are likely to reduce climate 
impacts on communities with EJ concerns. Findings demonstrate 
particular reductions in climate impacts for communities of color and 
low-income communities.
    With respect to conventional air pollutant health benefits, the 
current EPA modeling methodology results in benefits that are 
proportional to exposures. In other words, the distributional findings 
of air pollutant exposures discussed above are the same findings the 
EPA has for this benefit category: exposure and health benefit 
improvements and degradations attributable to this final rule will be 
proportionately experienced by all communities evaluated. However, 
there are several important nuances and caveats to this conclusion 
owing to differences in vulnerability and health outcomes across 
demographic groups. For example, there is some information suggesting 
that the same PM2.5 exposure reduction will reduce the 
hazard of mortality more so in Black populations than in White 
populations.214 215 In addition, demographic-stratified 
information relating PM2.5 and ozone to other health effects 
and valuation estimates is currently lacking.
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    \214\ U.S. EPA (Environmental Protection Agency). 2019. 
Integrated Science Assessment (ISA) for Particulate Matter (Final 
Report). December. EPA/600/R-19/188. Available at: https://www.epa.gov/naaqs/particulate-matter-pm-standards-integrated-science-assessments-current-review.
    \215\ U.S. EPA (Environmental Protection Agency). 2022. 
Supplement to the 2019 Integrated Science Assessment for Particulate 
Matter (Final Report). May. EPA/600/R-22/028. Available at: https://www.epa.gov/isa/integrated-science-assessment-isa-particulate-matter.
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    With respect to costs, the EPA notes that the impacts on ratepayers 
will depend on the degree to which compliance costs are passed through 
to electricity consumers via higher electricity rates. In general, 
lower-income households spend less, in the absolute, on energy than 
higher-income households, but energy expenditures represent a larger 
share of their income. Therefore, electricity price increases tend to 
have a relatively larger effect on lower-income households. Further 
discussion of these disparities is provided in section 5.2 of the EJA. 
The EPA estimated the potential impacts of incremental ELG compliance 
costs on households' utility bills based on average electricity 
consumption and assuming a worst-case scenario where all costs are 
passed through to consumers. The EPA estimated that the final rule 
(Option B) corresponds to an average increase of $3.14 per household 
per year, with a range of $0.19 to $5.44 per year across NERC regions. 
These cost increases are too small \216\ to indicate the potential for 
significant direct impacts to household electricity consumers.\217\
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    \216\ While the incremental burden relative to income is not 
distributionally neutral, i.e., any increase would affect lower-
income households to a greater extent than higher-income households, 
the final rule is expected to have a very small impact in the 
absolute across all regions analyzed which is also small relatively 
as the potential price increase is between less than 0.1 percent and 
0.2 percent of energy expenditures for all income and race groups, 
and between less than 0.1 percent and 0.5 percent of just 
electricity expenditures for all but the bottom quintile income 
group in the most impacted NERC region.
    \217\ EPA notes that other electricity consumers (e.g., 
industrial consumers) could also face increased electricity prices.
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XIV. Regulatory Implementation

A. Continued Implementation of Existing Limitations and Standards

    The EPA has continually stressed, since the announcement of this 
supplemental rulemaking, that the existing 40 CFR part 423 limitations 
and standards in effect continue to apply.\218\ In the sections below, 
the EPA discusses considerations for permitting authorities and 
regulated entities as they continue to implement existing regulations 
and look ahead to the regulations finalized.
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    \218\ 86 FR 41801 (August 3, 2021).
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1. Facilities Must Still Continue To Be Permitted for, and Meet, the 
2020 Rule Limitations
    The EPA reaffirms that permitting authorities must continue to 
write permits that include existing 2015 and 2020 rule BAT limitations 
as applicable, whether as part of permit renewals or as part of permit 
modifications. Similarly, permittees must meet applicable permit 
limitations as soon as possible. The Agency has not issued a 
postponement rule for the 2020 rule FGD wastewater and BA transport 
water BAT limitations as it did in 2017 for the 2015 rule. And as 
discussed in section VII of this preamble, the EPA is retaining the 
2020 FGD wastewater and BA transport water limitations and affirms that 
the technologies on which they are based are available and achievable, 
as an interim step toward meeting the final zero-discharge requirements 
in this rule.
    Since the EPA did not postpone the earliest compliance dates in the 
2020 rule,\219\ which have since passed, permitting authorities should 
not establish an ``as soon as possible'' date that is anything other 
than as soon as

[[Page 40282]]

possible to comply with the 2020 limitations. In some cases, although 
unlikely at the time of this publication, a facility may still not have 
a permit incorporating the 2015 or 2020 rule BAT requirements. In such 
circumstances, a permitting authority must still include these 
limitations with the appropriate ``as soon as possible'' date. For 
example, suppose a permit applicant's permit still has the 1982 
limitations; the applicant submits a permit modification request prior 
to this final rule effective date, but the permitting authority has not 
yet issued a modified permit. Here, the permitting authority may not 
simply issue the facility a permit incorporating this final zero-
discharge limitations with a ``no later than'' date of 2029. Instead, 
the permittee is still obligated to meet the 2020 rule limitations no 
later than December 31, 2025. Note that, without the 2020 rule 
limitations in a permit, a facility may not participate in the 
permanent cessation of coal combustion by 2034 subcategory.
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    \219\ Compliance dates for FGD wastewater and BA transport water 
in the 2020 rule were as soon as possible beginning October 13, 
2021.
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2. Permitting Site-Specific Technology-Based Effluent Limitations 
Through BPJ Analysis
    At proposal, the EPA reaffirmed that BAT limitations were currently 
required to be developed on a BPJ basis by permitting authorities for 
discharges of both CRL and legacy wastewater. Some commenters contended 
that this outcome is improper because it does not constrain the 
permitting authority from selecting surface impoundments as BAT. The 
EPA disagrees. In Southwestern Electric Power Co. v. EPA, the Fifth 
Circuit stopped short of prohibiting any future selection of surface 
impoundments as the commenters stated. Instead, the Court held that the 
Agency's actions in selecting surface impoundments as BAT for legacy 
wastewater and CRL was arbitrary and capricious or inconsistent with 
the statute based on EPA's stated rationale. In particular, the Court 
faulted the EPA for not offering any rationale as to why surface 
impoundments were BAT, using the statutory factors. See Southwestern 
Elec. Power Co. v. EPA, 920 F.3d at 1018 n.20 (``[T]he record fails to 
explain why impoundments are BAT, if that term is to have any meaning. 
Furthermore, if chemical precipitation or biological treatment are 
technically feasible but simply too costly for treating legacy 
wastewater, the EPA could have said so.''); id. at 1025 (``The rule 
pegs BAT for leachate to the decades-old BPT standard, without offering 
any explanation for why that prior standard is now BAT. That is flatly 
inconsistent with the Act's careful distinction between the two 
standards.''). Permitting authorities performing a BPJ analysis are 
required to consider the statutory factors and determine what 
technologies are available, are economically achievable, and have 
acceptable non-water quality environmental impacts. Thus, permitting 
authorities would also be prohibited from defaulting to surface 
impoundments without explaining why surface impoundments represent BAT, 
as that term is used in the CWA. Instead, they must perform a thorough 
BPJ analysis that considers technologies beyond surface impoundments 
(including, presumably, the technologies described in this record) to 
identify the technology that represents BAT. The EPA does not rule out 
the possibility that circumstances at a facility will lead the 
permitting authority to select surface impoundments as BAT. However, 
this would only occur where a permitting authority can demonstrate that 
surface impoundments meet the BAT statutory factors, a tough hurdle for 
a treatment technology that has been found not to remove dissolved 
pollutants. Id. at 1026 (``To be sure, we do not say that EPA is 
precluded by the Act from ever setting BAT equivalent to a prior BPT 
standard. But given the plain distinction between the two standards 
market out in the Act, the agency would at least have to offer some 
explanation for its decision that speaks to the statutory differences 
between BAT and BPT.'').
    Furthermore, the EPA received comments that certain state laws 
prohibit permitting authorities in those states from imposing BAT 
limitations more stringent than any national regulations. EPA disagrees 
that this poses an implementation challenge. The EPA has not 
established BAT based on surface impoundments, but rather, in some 
cases, reserved BAT limitations to be developed by permitting 
authorities using their BPJ. And the requirement for BPJ is to perform 
a thorough analysis to select the technology that represents BAT at a 
particular site. Thus, to the extent that a permitting authority 
determines a more stringent technology represents BAT at a particular 
site, this would not be inconsistent with the state laws cited.
3. Reopening Permits for CRL and Legacy Wastewater
    At proposal, the EPA recommended, but did not require, that any 
permit issued or modified between the proposal and the final rule 
contain a reopener clause in accordance with 40 CFR 122.62(a)(7) and 
124.5. Permitting authorities that included this provision should 
consider reopening these portions of existing permits as soon as 
practicable after July 8, 2024.

B. Implementation of New Limitations and Standards

    The limitations and standards in this final rule apply to 
discharges from steam electric power plants through incorporation into 
NPDES permits issued by the EPA and authorized states under CWA section 
402, and through pretreatment programs under CWA section 307. NPDES 
permits and pretreatment control mechanisms issued after July 8, 2024, 
must incorporate the ELGs, as applicable. Also, under CWA section 510, 
states can require effluent limitations under state law as long as they 
are no less stringent than the requirements of any final rule. Finally, 
as well as requiring application of the technology-based ELGs in any 
final rule, CWA section 301(b)(1)(C) requires the permitting authority 
to impose more stringent effluent limitations, as necessary, to meet 
applicable water quality standards. Relevant water quality-based 
considerations are discussed in section XIV.D.
1. Availability Timing of Final Rule Requirements
    The direct discharge limitations in this rule apply only when 
implemented in an NPDES permit issued to a discharger. Under the CWA, 
the permitting authority must incorporate these ELGs into NPDES permits 
as a minimum level of control. The final rule provides the plant's 
permitting authority with discretion to determine the date when the new 
effluent limitations for FGD wastewater, BA transport water, and CRL 
would apply to a given discharger. For zero discharge requirements for 
FGD wastewater, BA transport water, and CRL, as well as the chemical 
precipitation-based requirements for unmanaged CRL, the limitations in 
this final rule become applicable by a date that is as soon as possible 
after July 8, 2024, but in no case later than December 31, 2029.
    For dischargers subject to less stringent FGD wastewater and BA 
transport water limitations based on certifications that they qualify 
for a subcategory based on permanent cessation of coal combustion, the 
EPA is requiring permitting authorities to put in tiered limitations 
after the permanent cessation of coal combustion. For the permanent 
cessation of coal combustion by 2028 subcategory, the final rule 
contains a tiered set of limitations applicable following December 31, 
2028:
     The first tier of these limitations is composed of zero-
discharge limitations

[[Page 40283]]

for FGD wastewater and BA transport water after April 30, 2029. These 
limitations would apply if the EGU had in fact permanently ceased coal 
combustion by December 31, 2028, as the plant represented it would. As 
suggested in public comments, this date is 120 days after the permanent 
cessation of coal combustion date, allowing for facilities to complete 
any necessary residual discharges.\220\
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    \220\ The EPA notes that these do not include discharges of 
legacy wastewaters from surface impoundments closing under the CCR 
rule, which are covered by different regulatory provisions.
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     The second tier is composed of zero-discharge limitations 
for these same wastewaters after December 31, 2028. If a plant fails to 
cease combustion of coal by 2028, as it represented it would, for any 
reason other than those specified in Sec.  423.18, these zero-discharge 
limitations would automatically apply.
    For the permanent cessation of coal combustion by 2034 subcategory, 
the final rule contains a tiered set of limitations applicable 
following December 31, 2034:
     The first tier of these limitations is composed of zero-
discharge limitations for FGD wastewater and BA transport water after 
April 30, 2035. These limitations would apply if the EGU had in fact 
permanently ceased coal combustion as it represented it would.
     The second tier is composed of zero-discharge limitations 
for the same wastewaters, as well as CRL, after December 31, 2034. If a 
plant fails to cease combustion of coal by 2034, as it represented it 
would, for any reason other than those specified in Sec.  423.18, these 
zero-discharge limitations would automatically apply.
    This final rule does not affect dischargers choosing to meet the 
2020 VIP effluent limitations for FGD wastewater; the date for meeting 
those limitations is December 31, 2028. Similarly, where a facility has 
elected to participate in the subcategory for permanent cessation of 
coal combustion by December 31, 2028, the final rule allows for the 
zero-discharge limitations for FGD wastewater and BA transport water to 
be met as late as December 31, 2029, and is not designed to impose 
these zero-discharge limitations prior to the tiered zero-discharge 
limitations established for that subcategory.\221\
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    \221\ In contrast, the subcategory for EGUs permanently ceasing 
coal combustion by December 31, 2028, does not cover discharges of 
CRL, and thus discharges of CRL would be permitted in accordance 
with limitations in the subcategory for EGUs permanently ceasing 
coal combustion by December 31, 2034.
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    Pretreatment standards, unlike effluent limitations, are directly 
enforceable and must specify a time for compliance not to exceed three 
years from the date of promulgation under CWA section 307(b)(1). Under 
the EPA's General Pretreatment Regulations for Existing and New 
Sources, POTWs with flows in excess of five MGD must develop 
pretreatment programs meeting prescribed conditions.\222\ These POTWs 
have the legal authority to require compliance with applicable 
pretreatment standards and control the introduction of pollutants to 
the POTW through permits, orders, or similar means. POTWs with approved 
pretreatment programs act as the control authorities for their 
industrial users. Among the responsibilities of the control authority 
are the development of the specific indirect discharge limitations for 
the POTW's industrial users. Because pollutant discharge limitations in 
categorical pretreatment standards may be expressed as concentrations 
or mass limitations, in many cases, the control authority must convert 
the concentration- or mass-based limitations applicable to a specific 
industrial user and then include these in POTW permits or another 
control instrument.
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    \222\ See, e.g., 40 CFR 403.8(a).
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    Regardless of when a plant's NPDES permit is ready for renewal, the 
EPA recommends that each plant immediately begin evaluating how it 
intends to comply with the requirements of the final rule. In cases 
where significant changes in operation are appropriate, the EPA 
recommends that the plant discuss such changes with its permitting 
authority and evaluate appropriate steps and a timeline for the changes 
as soon as possible, even before the permit renewal process begins.
    The ``as soon as possible'' date is the effective date of any final 
rule, unless the permitting authority determines another date after 
receiving relevant information submitted by the discharger.\223\ The 
final rule does not revise the specified factors permitting authorities 
must consider in determining the as soon as possible date under the 
2015 and 2020 rules. Based on receiving relevant information from the 
discharger, the NPDES permitting authority may determine a different 
date is ``as soon as possible'' within the implementation period, using 
the factors below:
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    \223\ Information in the record indicates that most facilities 
should be able to complete all steps to implement changes needed to 
comply with the BA transport water requirements within 32 to 35 
months, the FGD wastewater requirements within 28 months, and the 
CRL requirements within 22 months (DCN SE08480, SE10289).
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     Time to expeditiously plan (including to raise capital), 
design, procure, and install equipment to comply with the requirements 
of the final rule.
     Changes being made or planned at the plant in response to 
GHG regulations for new or existing fossil fuel-fired plants under the 
CAA, as well as regulations for the disposal of coal combustion 
residuals under subtitle D of RCRA.
     For FGD wastewater requirements only, an initial 
commissioning period to optimize the installed equipment.
     Other factors as appropriate.
    The ``as soon as possible'' date determined by the permitting 
authority may or may not be different for each wastestream. The NPDES 
permitting authority should provide a well-documented justification of 
how it determined the ``as soon as possible'' date in the fact sheet or 
administrative record for the permit. If the permitting authority 
determines a date later than the effective date of the final rule, the 
justification should explain why allowing more time to meet any final 
limitations is appropriate, and why the discharger cannot meet the 
effluent limitations as of the effective date.
2. Conducting BPJ Analyses for Discharges of CRL and Legacy Wastewater
    For some CRL and legacy wastewaters, the EPA is reserving BAT 
limitations to be determined on a case-by-case basis using the 
permitting authority's BPJ. The factors considered by the permit writer 
in a BPJ analysis are the same as those that EPA considers in 
establishing technology-based effluent limitations. See 40 CFR 
125.3(d)(1) through (3). Thus, a permitting authority may not default 
to any technology (for example, surface impoundments) in selecting BAT, 
nor may a permitting authority fail to develop technology-based 
effluent limitations and instead simply calculate water quality-based 
effluent limitations. Instead, a permitting authority is required to 
determine limitations based on the BAT.\224\
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    \224\ In doing so, permitting authorities may consider relevant 
information such pollution treatment technologies already in 
operation at the facility and the information contained in this 
record on the performance and costs of various technologies.
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    Consideration of Leasing. Leasing is an option offered by 
commercial vendors. In some cases, it may be possible to lease various 
pollution treatment technologies for a timeframe shorter than the 
timeframes considered in this rule's primary evaluation. In

[[Page 40284]]

some cases, shorter duration leases might be more costly; however, 
where the record precluded the EPA from establishing a nationwide BAT, 
it is possible that site-specific considerations may make leased 
equipment economically achievable for a given facility, and thus a 
relevant consideration in a BPJ analysis.
    Consideration of Closure Deadlines Pursuant to the CCR Rule. For 
certain legacy wastewater, the EPA declined to establish a nationwide 
BAT, in part, due to the tight closure timeframes for CCR surface 
impoundments under the CCR rule. The EPA cannot evaluate the precise 
stage of closure each CCR surface impoundment would be in at the time 
of its permit issuance or renewal and whether continuation with that 
stage of closure would be compatible with the operation of any specific 
technology. In contrast, permitting authorities can do this through the 
BPJ process after gathering relevant information through the permit 
application or permit modification. This may require examination of the 
site-specific closure plan required under the CCR rule and any 
additional details regarding the ongoing closure process that are not 
contained in the closure plan itself.
3. Conforming Changes to Sec.  423.18
    The EPA is making two changes to Sec.  423.18. First, the EPA is 
including the new permanent cessation of coal combustion by 2034 
subcategory in the permit conditions of Sec.  423.18. When an EGU 
proceeds towards permanent cessation of coal combustion under the new 
subcategory, if that EGU is involuntarily forced to burn coal beyond 
December 31, 2034, it may qualify for the same protections as an EGU in 
the permanent cessation of coal combustion by 2028 subcategory.
    Second, the EPA is clarifying that an Energy Emergency Alert (EEA) 
is a valid order under Sec.  423.18(a)(3) to qualify for this 
provision. The purpose of an EEA is to provide real-time indication of 
potential and actual energy emergencies within an interconnection.\225\ 
The EPA received comment about these alerts specifically in the context 
of the CAA section 111 proposed rule. These are short-duration 
reliability events similar to the types explicitly listed in Sec.  
423.18, and this clarification is not meant to limit the use of Sec.  
423.18, but rather to ensure that it operates as intended: to allow an 
EGU to operate for reliability purposes without violating its CWA 
permit.
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    \225\ An EEA-Level 1 occurs when the ISO/RTO has enough power to 
meet demand but not enough backup resources. An EEA-Level 2 occurs 
when the ISO/RTO anticipates interruption of service and takes steps 
to avoid power outages by requesting outside help to meet 
requirements including consumers being asked to conserve energy. An 
EEA-Level 3 occurs when an ISO/RTO is energy deficient and operating 
with reserves below the required minimum. At level 3, utilities 
curtail energy use through controlled service interruptions.
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4. Information To Assist in Permitting Discharges of Unmanaged CRL
    At proposal, the EPA provided a recommended list of information 
that could be provided to a permitting authority to determine whether a 
discharge of CRL through groundwater constituted the FEDD from a point 
source into a WOTUS. The EPA also solicited comment on including 
provision of this information as a regulatory requirement or otherwise 
obtaining the data (e.g., through a CWA section 308 request). The EPA 
received a wide range of comment on this solicitation, but on November 
20, 2023, the Agency published a draft guidance titled Applying the 
Supreme Court's County of Maui v. Hawaii Wildlife Fund Decision in the 
Clean Water Act section 402 National Pollutant Discharge Elimination 
System Permit Program to Discharges through Groundwater. The draft 
guidance describes the Maui decision's functional equivalent analysis 
and explains the types of information that may be relevant to 
determining which discharges through groundwater require coverage under 
an NPDES permit. This guidance will assist permitting authorities, the 
regulated community, and other stakeholders in appropriately applying 
the ``functional equivalent'' standard in the NPDES permits program and 
is a more appropriate instrument for addressing this particular 
implementation issue. The EPA intends to issue revised guidance on this 
topic soon. For further information visit: https://www.epa.gov/npdes/releases-point-source-groundwater.

C. Reporting and Recordkeeping Requirements

    The EPA is finalizing several new or modified reporting and 
recordkeeping requirements in Sec.  423.19, pursuant to authority under 
CWA sections 304(i) and 308. First, the EPA is including additional 
provisions for the annual progress reports required for EGUs 
permanently ceasing coal combustion by 2028. Second, the EPA is 
including reporting and recordkeeping requirements for the new 
subcategory of EGUs permanently ceasing coal combustion by 2034. Third, 
the EPA is including reporting and recordkeeping requirements for the 
subcategory for EGUs with certain discharges of unmanaged CRL. Fourth, 
the EPA is including reporting and recordkeeping requirements for 
facilities making use of the definitional changes with respect to 
necessary discharges of FGD wastewater, BA transport water or CRL 
during high intensity, infrequent storm events. Fifth, the EPA is 
including a one-year flexibility for EGUs that have installed zero-
discharge systems to support their transition to zero discharge by 
allowing necessary discharges of permeate or distillate subject to 
reporting and recordkeeping requirements. Finally, the EPA is requiring 
this and all other reporting to be posted to a publicly available 
website.
1. Summary of Changes to the Annual Progress Reports for EGUs 
Permanently Ceasing Coal Combustion by 2028
    The EPA is modifying the annual progress reports for the 
subcategory of EGUs permanently ceasing coal combustion by 2028, as it 
proposed it would. Specifically, the EPA is adding a requirement that 
the annual progress reports include either the official filing to the 
facility's reliability authority or a certification providing an 
estimate of when such a filing will be made. Furthermore, the EPA is 
requiring that the final annual progress report prior to permanent 
cessation of coal combustion must include the official filing. While 
facilities may already include these filings in the NOPP or annual 
progress reports, these filings were not explicitly required in the 
2020 rule and provide the strongest assurance that a facility will not 
voluntarily change its plans and continue discharging beyond 2028.
2. Summary of the Reporting and Recordkeeping Requirements for EGUs 
Permanently Ceasing Coal Combustion by 2034
    The EPA is including new reporting and recordkeeping requirements 
for EGUs permanently ceasing coal combustion by 2034, including an 
initial NOPP and annual progress reports, as it proposed it would. 
Consistent with the requirements for EGUs permanently ceasing coal 
combustion by 2028, the EPA is requiring that the initial NOPP contain 
several items. A NOPP shall include the expected date that each EGU is 
projected to achieve permanent cessation of coal combustion, whether 
each date represents a retirement or a fuel conversion, whether each 
retirement or fuel conversion has been approved by a regulatory body, 
and what the relevant regulatory body is. In addition, the NOPP shall 
include the most recent integrated resource plan for

[[Page 40285]]

which the applicable state agency approved the retirement or repowering 
of the unit subject to the ELGs, or other documentation supporting that 
the electric generating unit will permanently cease the combustion of 
coal by December 31, 2034. The NOPP shall also include, for each such 
EGU, a timeline to achieve the permanent cessation of coal combustion. 
Each timeline shall include interim milestones and the projected dates 
of completion. Finally, the NOPP shall include, for each such EGU, a 
certification statement that the facility is in compliance with the FGD 
wastewater and BA transport water limitations of the 2020 rule. Because 
the NOPP requires a certification statement that the facility is in 
compliance with the FGD wastewater and BA transport water limitations 
of the 2020 rule, which could have applicability dates as late as 
December 31, 2025, EPA has finalized that date as the date for 
submitting the NOPP.
    The EPA is also requiring an annual progress report for facilities 
in this subcategory. An annual progress report shall detail the 
completion of any interim milestones listed in the NOPP since the 
previous progress report, provide a narrative discussion of any 
completed, missed, or delayed milestones, and provide updated 
milestones. An annual progress report shall also include one of the 
following:
     A copy of the official suspension filing (or equivalent 
filing) made to the facility's reliability authority detailing the 
conversion to a fuel source other than coal;
     A copy of the official retirement filing (or equivalent 
filing) made to the facility's reliability authority which must include 
a waiver of recission rights; or
     An initial certification, or recertification for 
subsequent annual progress reports, containing a statement that the 
facility will make one of the other filings.
    The certification or recertification must include the estimated 
date that such a filing will be made. Furthermore, the EPA is requiring 
that the final annual progress report must include the actual filing to 
the reliability authority. Thus, the final annual progress report 
cannot include a certification statement.
3. Summary of Reporting and Recordkeeping Requirements for Certain 
Discharges of Unmanaged CRL
    As discussed in section VII of this preamble, CRL can be discharged 
not only through end-of-pipe discharges, but also through groundwater, 
and the EPA is establishing BAT limitations for a subcategory of EGUs 
that includes EGUs with discharges of CRL that a permitting authority 
determines are the FEDD of CRL to a WOTUS. The EPA is including annual 
reporting and recordkeeping requirements to facilitate the permitting 
authorities' review of such discharges. These requirements also 
facilitate compliance monitoring and make compliance information 
available to the public.
    As it proposed it would, the EPA is requiring that facilities with 
discharges of CRL that a permitting authority determines are the FEDD 
of CRL to a WOTUS file an annual combustion residual leachate 
monitoring report with the permitting authority. This annual reporting 
requirement would be implemented via NPDES permits that cover one or 
more FEDD of CRL to a WOTUS through groundwater. The EPA is requiring 
that this report provide a comprehensive set of monitoring data. The 
EPA is including this requirement to facilitate permitting authorities' 
ability to determine compliance with CRL limitations and to increase 
transparency to local communities. Thus, in addition to the data 
provided under 40 CFR part 127, where an EGU is determined to have a 
FEDD of CRL, the EPA is requiring groundwater monitoring data on the 
CRL leaving each landfill or surface impoundment and where it enters 
surface waterbodies. The EPA is also requiring the report to include 
monitoring data on all the pollutants treated by chemical 
precipitation, not just mercury and arsenic, the two indicator 
pollutants.
4. Certification for Necessary Discharges of FGD Wastewater, BA 
Transport Water, or CRL During High Intensity, Infrequent Storm Events
    At proposal, the EPA solicited comment on a number of topics 
concerning stormwater mixed with regulated process wastewaters, as well 
as comment on any necessary, related reporting and recordkeeping 
requirements. As discussed in section VII.B.5 of this preamble, the EPA 
is finalizing a definitional change for wastewater resulting from 
certain high intensity, infrequent storm events. As part of this 
change, the EPA is requiring a certification that includes several 
pieces of information that will assure the permitting authority and the 
public that the discharge is necessary and does not violate any other 
permit requirements. First, the certification shall include a statement 
that the facility experienced a storm event exceeding a 10-year, 24-
hour or longer duration, including specifics of the actual storm event 
that are sufficient for a third party to verify the accuracy of the 
statement. Second, the certification shall include a statement that the 
discharge of low volume wastewater that would otherwise meet the 
definition of FGD wastewater, BA transport water, or CRL was necessary, 
including a list of the best management practices at the site and a 
narrative discussion of the ability of on-site equipment and practices 
to manage the wastewater. Third, the certification statement shall 
include the duration and volume of any such discharge. Finally, the 
certification statement shall include a statement that the discharge 
does not otherwise violate any other limitation or permit condition.
5. One-Year Flexibility for Any Necessary Discharges of Permeate or 
Distillate From Newly Operational FGD Wastewater or CRL Treatment 
Systems
    The EPA anticipates that some plants seeking to meet the final 
zero-discharge limitations for FGD wastewater or CRL may install one or 
more technologies that produce a distillate or permeate following 
treatment. The EPA's technology basis incorporates a process by which 
the plant will recycle such distillate or permeate within the plant to 
achieve zero discharge. At proposal, however, the EPA solicited comment 
on the propriety of a limited flexibility that would allow some time 
for a plant to optimize its zero-discharge system to fully achieve zero 
discharge, subject to a reporting requirement. Importantly, for plants 
seeking this flexibility, a permitting authority would not include this 
optimization period in the calculation of the plant's ``as soon as 
possible'' date for meeting the FGD wastewater or CRL limitations. A 
plant given this flexibility would monitor and report any necessary 
discharges of permeate or distillate over the first year of attempted 
zero discharge, while the system was being optimized, and these 
discharges would not be a violation of the otherwise applicable zero-
discharge requirements. For subsequent years, the flexibility would be 
discontinued.
    The EPA received few comments on this solicitation, but those that 
were received favored the additional flexibility. On the timeframe, the 
EPA received comments suggesting that one or two years might be 
appropriate for such a flexibility. One commenter specifically 
discussed steps for optimizing an initial stage chemical precipitation 
system that could take up to two years.
    The EPA agrees with commenters that the flexibility is warranted, 
but disagrees that two years is appropriate. In discussions with 
technology vendors,

[[Page 40286]]

the EPA learned that new pollution control technology operators at a 
facility are most likely to seek vendor support during the first year 
of operations. Even the comment suggesting a two-year timeframe 
conceded, ``Commercially proven technology designs generally take a 
full year to optimize.'' During this optimization process, even with 
the flexibility to discharge permeate or distillate when necessary, the 
zero-discharge treatment technology will still result in significant 
additional pollutant removals which will only be improved upon once the 
optimization is complete and the permeate or distillate may no longer 
be discharged. The NSPS limitations established in the 2015 rule and 
the BAT limitations in the 2020 rule's VIP (which were developed using 
data from thermal evaporation systems' distillate and membrane 
filtration systems' permeate, respectively) result in more pollutant 
removals than either chemical precipitation alone or chemical 
precipitation plus biological treatment. By expressly allowing plants a 
period for optimization, and removing this optimization consideration 
that would otherwise allow for delayed availability timing under Sec.  
423.11(t)(3), this flexibility will also facilitate the transition to 
zero discharge by reducing the amount of time it would take for plants 
to begin full-scale use of their pollutant treatment systems. 
Therefore, the EPA is finalizing a flexibility in Sec.  423.18 to allow 
discharges of distillate or permeate from a newly operational FGD 
wastewater or CRL treatment system, where necessary, in the first year 
of operations.
    The necessary discharges included in this flexibility are subject 
to additional reporting and recordkeeping requirements. Specifically, 
the facility shall include a letter requesting this flexibility from 
the permitting authority. This initial request letter will detail the 
expected type, frequency, and duration of discharge. The letter will 
also include a certification that the facility has not considered the 
zero-discharge system optimization period in its availability timing 
request under Sec.  423.11(t). After including flexibility for 
necessary discharges of the permeate or distillate in the permit, the 
permitting authority shall also extend any existing monitoring and 
reporting requirements to ensure that any necessary discharges of the 
distillate or permeate do not violate other applicable conditions of 
the permit such as water quality-based effluent limitations.
6. Requirement to Post Information to a Publicly Available Website
    The reporting and recordkeeping requirements of the CCR rule 
included a novel approach for posting information to a publicly 
available website. This was done because, at the time the CCR rule was 
signed, the EPA did not have enforcement authority over the CCR rule. 
Thus, given the self-implementing nature of the regulations, EPA sought 
to make information more readily available to states, as well as 
members of the public, who could enforce the CCR rule through citizen 
suits.\226\
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    \226\ While the Water Infrastructure Improvements for the Nation 
Act later provided the EPA with permitting and oversight authority, 
the CCR rule continues to require posting to publicly available 
websites.
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    In contrast to the CCR rule, ELGs are implemented largely through 
authorized state permitting programs with EPA oversight. Nevertheless, 
one message that EPA received in initial outreach to communities was 
that there is a lack of trust of utilities (and in some cases, the 
states that regulate them). Another message was that there is an 
interest in more accessible information. At proposal, the EPA included 
a website posting requirement for all documentation included in Sec.  
423.19.
    The EPA received comments both supporting and opposing the 
inclusion of a website requirement. Comments supporting the requirement 
desired additional transparency and suggested the EPA expand the 
requirement to all permitting documentation. Comments opposing the 
requirement expressed the opinion that these requirements would be a 
duplicative and unnecessary burden. One comment also pointed out that 
there was no provision for using a combined CCR rule/ELG rule website 
where a facility became subject to requirements after the effective 
date of the rule.
    At the outset, the EPA agrees with commenters supporting a website 
reporting requirement. Given the success CCR rule websites have 
achieved in disseminating information to a variety of stakeholders, the 
EPA is finalizing a comparable posting requirement for the ELG rule. 
These websites will ensure transparency and ease of access to 
information. The EPA disagrees with these commenters that more is 
necessary. The existing reporting and recordkeeping requirements for 
general permitting provisions (e.g., documentation during the permit 
application and permit modification processes, effluent reporting, 
etc.) are outside the scope of this rulemaking. Furthermore, even if 
the EPA were to consider broader changes to the reporting and 
recordkeeping requirements for all industrial categories, the Agency 
would do so through a rulemaking not specific to the steam electric 
power generating industry. Thus, the EPA is finalizing a website 
posting requirement only with respect to information contained in Sec.  
423.19.
    Specifically, the EPA is requiring that all reporting and 
recordkeeping information not only be retained by the regulated entity 
and provided to the permitting authority, but that it also be posted to 
a public website for 10 years, or the length of the permit plus five 
years, whichever is longer. This posting requirement includes NOPPs and 
other filings that have occurred since the 2020 rule. The EPA is also 
allowing facilities to post on existing CCR rule compliance websites to 
reduce paperwork burden and make it easier for communities to access. 
One commenter correctly pointed out that, where facilities were not 
immediately subject to the reporting and recordkeeping requirements of 
Sec.  423.19, it would have not been able to make the proper 
notification of combined CCR rule/ELG rule website usage within the 
proposed 60-day timeframe. Therefore, the EPA is finalizing a date for 
notification of this combined website that is July 8, 2024, or the date 
which the facility becomes subject to Sec.  423.19 reporting 
requirements, whichever is later.

D. Site-Specific Water Quality-Based Effluent Limitations

    The EPA regulations at 40 CFR 122.44(d)(1), implementing section 
301(b)(1)(C) of the CWA, require each NPDES permit to include any 
requirements, in addition to or more stringent than ELGs or standards 
promulgated pursuant to sections 301, 304, 306, 307, 318, and 405 of 
the CWA, necessary to achieve water quality standards established under 
section 303 of the CWA, including state narrative criteria for water 
quality. Those same regulations require that limitations must control 
all pollutants or pollutant parameters (either conventional, 
nonconventional, or toxic pollutants) that the Director determines are 
or may be discharged at a level that will cause, have the reasonable 
potential to cause, or contribute to an excursion above any state water 
quality standard, including state narrative criteria for water quality. 
40 CFR 122.44(d)(1)(i). In the sections below, the EPA describes the 
potential need to develop monitoring requirements and or limitations 
relating

[[Page 40287]]

to bromide, per- and polyfluoroalkyl substances (PFAS), and Tribal 
rights.
1. Bromide
    The preamble to the 2015 rule discussed bromide as a parameter for 
which water quality-based effluent limitations may be appropriate. The 
EPA stated its recommendation that permitting authorities carefully 
consider whether water quality-based effluent limitations for bromide 
or TDS would be appropriate for FGD wastewater discharged from steam 
electric power plants upstream of drinking water intakes. The EPA also 
stated its recommendation that the permitting authority notify any 
downstream drinking water treatment plants of the discharge of bromide.
    The final rule requires zero discharge of FGD wastewater, BA 
transport water, and CRL. Nevertheless, the EPA is finalizing 
subcategories for these wastewaters that will allow some discharge of 
these wastewaters, and all three have been shown to have measurable 
levels of bromide.\227\ Therefore, the records for the 2015 rule, the 
2020 rule, and this action continue to suggest that permitting 
authorities should consider establishing water quality-based effluent 
limitations where necessary to meet applicable water quality standards 
to protect of populations served by downstream drinking water treatment 
plants.
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    \227\ The record also includes iodide in these discharges, 
another pollutant which should be considered alongside bromide for 
water quality-based effluent limitations.
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    In consultations conducted with state and local government 
entities, the EPA received comments from the American Water Works 
Association (AWWA) and the Association of Metropolitan Water Agencies. 
These comments requested that the EPA consider technologies that could 
treat upstream pollutants at the point of discharge, but also suggested 
that the EPA empower states to address the issue as well. The latter 
discussion referenced the approaches discussed in Methods to Assess 
Anthropogenic Bromide Loads from Coal-Fired Power Plants and Their 
Potential Effect on Downstream Drinking Water Utilities.\228\ This 
document, provided in comments during the 2020 rulemaking and again 
during consultations on the current rulemaking, describes 
methodologies, data sources, and considerations for constructing an 
approach to bromide issues on a site-specific basis. This document 
presents additional data sources that NPDES permitting authorities 
could use to establish site-specific, water quality-based effluent 
limitations (see, e.g., Figure 29 in AWWA's document). The document 
also provides examples of where states have already taken similar 
action. For example, AWWA cites California's 0.05 mg/L standard for in-
river bromide to protect public health for specific waterways and 
drinking water treatment systems.
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    \228\ Available online at: https://www.awwa.org/Portals/0/AWWA/ETS/Resources/17861ManagingBromideREPORT.pdf?ver=2020-01-09-151706-107.
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2. PFAS
    In addition to considering water quality-based effluent limitations 
for parameters present in these wastestreams, the EPA also calls 
attention to the need to address potential for PFAS discharges. In the 
EPA's PFAS Strategic Roadmap,\229\ the Agency laid out actions that 
would prevent PFAS from entering the environment. Specifically, the EPA 
stated it would ``proactively use existing NPDES authorities to reduce 
discharges of PFAS at the source and obtain more comprehensive 
information through monitoring on the sources of PFAS and quantity of 
PFAS discharged by these sources.'' The EPA's Office of Water issued a 
memorandum in 2022, covering facilities where the EPA is the permitting 
authority,\230\ as well as guidance to state permitting authorities to 
address PFAS in NPDES permits.\231\ While the steam electric power 
sector was not identified as one of the top PFAS dischargers, the EPA 
notes that PFAS may nevertheless be present in steam electric 
discharges. For example, the Wisconsin Department of Natural Resources 
has found PFAS at eight power plants.\232\ In addition, firefighting 
foam used in exercises or actual fires at steam electric power plants 
could contain PFAS. Therefore, permitting or control authorities may 
appropriately consider whether PFAS monitoring and any further 
restrictions (e.g., BMPs) would be appropriate at a given facility.
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    \229\ U.S. EPA (Environmental Protection Agency). 2021. PFAS 
Strategic Roadmap: EPA's Commitments to Action 2021-2024. October 
18. Available online at: https://www.epa.gov/system/files/documents/2021-10/pfas-roadmap_final-508.pdf.
    \230\ Fox, R. 2022. Addressing PFAS Discharges in EPA-Issued 
NPDES Permits and Expectations Where EPA is the Pretreatment Control 
Authority. April 28. Available online at: https://www.epa.gov/system/files/documents/2022-04/npdes_pfas-memo.pdf.
    \231\ Fox, R. 2022. Addressing PFAS Discharges in NPDES Permits 
and Through the Pretreatment Program and Monitoring Programs. 
December 5. Available online at: https://www.epa.gov/system/files/documents/2022-12/NPDES_PFAS_State%20Memo_December_2022.pdf.
    \232\ The maximum sampled concentrations in discharge from eight 
steam electric power plants were 28 ng/L for perfluorooctane 
sulfonic acid (PFOS) and 35 ng/L for perfluorooctanoic acid (PFOA), 
which the Wisconsin Department of Natural Resources theorized was 
due to concentration in cooling tower effluent.
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3. Tribal Reserved Rights
    A third water-quality based consideration for steam electric power 
plants is Tribal reserved rights. Many Tribes hold reserved rights to 
resources on lands and waters where states establish water quality 
standards, through treaties, statutes, or other sources of Federal law. 
The U.S. Constitution defines treaties as the supreme law of the land. 
On December 5, 2022, the EPA proposed revisions to the Federal water 
quality standards (WQS) regulation at 40 CFR part 131. See 87 FR 74361 
(Dec. 5, 2022) (``Tribal Reserved Rights proposed rule''). The proposed 
revisions, if finalized, would create a regulatory framework that would 
be applied case-specifically to protect aquatic and aquatic-dependent 
resources--such as fish--reserved to Tribes through treaties, statutes, 
and executive orders, in WOTUS. The Tribal Reserved Rights proposed 
rule aims to improve protection of resources reserved to Tribes and the 
health of Tribal members exercising their reserved rights, as well as 
transparency and predictability for Tribes, states, regulated 
community, and the public. The EPA is working to expeditiously finalize 
the proposed rule, taking into account public comments. During Tribal 
outreach on the Steam Electric ELG rulemaking, Tribes raised concerns 
about potential impacts to their Tribal reserved rights. For further 
discussion of EPA's outreach to Tribes, see section XV.F.

E. Severability

    The purpose of this section is to clarify the Agency's intent with 
respect to the severability of provisions of this rule in the event of 
litigation. In the event of a stay or invalidation of any part of this 
rule, the Agency's intent is to preserve the remaining portions of the 
rule to the fullest possible extent. To dispel any doubt regarding the 
EPA's intent and to inform how the regulation would operate if severed, 
the EPA has added the following regulatory text at Sec.  423.10(b): 
``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.'' This rule serves in 
many respects to further the goals of the CWA, and the Agency would 
have adopted each portion of this rule independent of the other 
portions. As explained below, the Agency carefully crafted this rule so 
that each provision or element of the rule

[[Page 40288]]

can operate independently. Moreover, the Agency has organized the rule 
so that if any provision or element of this rule is determined by 
judicial review or operation of law to be invalid, that partial 
invalidation will not render the remainder of this rule invalid.
    This rule primarily regulates discharges associated with four steam 
electric wastestreams. The rule provides limitations and standards 
associated with each wastestream in separate sections that do not rely 
on one another. The decision to regulate each wastestream was made 
independently of the decisions to regulate the other wastestreams. This 
is because the EPA applied the BAT statutory factors in its decision 
for each wastestream. This is consistent with the Fifth Circuit's 
decision in Southwestern Elec. Power Co. v. EPA, in which the Court 
held that the EPA must apply the BAT factors with respect to each 
wastestream, in that case CRL. Southwestern Elec. Power Co. v. EPA, 920 
F.3d at 1027. Indeed, the Court ultimately vacated only those portions 
of the 2015 rule regulating legacy wastewater and CRL, without 
disturbing any further aspects of the rule. Id. at 1033.
    This rule also contains several subcategories. The rule provides 
limitations and standards associated with each subcategory in separate 
sections, which are not relied on by other aspects of the rule. The 
decision to subcategorize particular discharges, for example, certain 
discharges of unmanaged CRL or certain discharges of legacy wastewater, 
had no bearing on the BAT decisions made with respect to the rest of 
the industry, for which the EPA finds the rule is technologically 
available and economically achievable after a consideration of the CWA 
section 304(b) factors. And each subcategory is supported by its own, 
independent BAT determination. Moreover, the rest of the industry's 
requirements are not tied in the regulatory text to the requirements of 
the subcategories. Similarly, the decision to subcategorize certain 
discharges from EGUs expected to cease combustion of coal had no 
bearing on the EPA's BAT decisions made with respect to the rest of the 
industry, for which the EPA finds the rule is technologically available 
and economically achievable after a consideration of the CWA section 
304(b) factors. And the cease combustion of coal subcategories are 
supported by their own, independent BAT determinations. Moreover, the 
rest of the industry's requirements are not tied in the regulatory text 
to the requirements of the subcategories. Were the EPA to receive an 
adverse decision on any of the subcategories established in this rule, 
the EPA would expect to potentially address any remand and/or vacatur 
of the limitations applicable to the subcategory by considering the 
Court's opinion and the requisite statutory factors in re-promulgating 
any appropriate limitations for such subcategory. The EPA would, for 
example, have to demonstrate that any new limitations for the 
subcategory are technologically available and economically achievable 
for the subcategory, after a consideration of the CWA section 304(b) 
factors. These examples are illustrative, rather than exhaustive, and 
the EPA intends each portion of the rule to be independent and 
severable. Furthermore, if the application of any portion of this rule 
to a particular circumstance is determined to be invalid, the Agency 
intends that the rule remain applicable to all other circumstances.

XV. Statutory and Executive Order Reviews

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

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 14094: Modernizing Regulatory Review

    This action is a ``significant regulatory action,'' as defined 
under section 3(f)(1) of Executive Order 12866, as amended by Executive 
Order 14094. Accordingly, the EPA submitted this action to the Office 
of Management and Budget (OMB) for Executive Order 12866 review. The 
EPA has included redline strikeout versions showing changes made in 
response to the Executive Order 12866 review available in the docket. 
The EPA prepared an analysis of the estimated costs and benefits 
associated with this action. This analysis is contained in section 12 
of the BCA and is also available in the docket.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this rule have been 
submitted for approval to the OMB under the PRA. The Information 
Collection Request (ICR) document that the EPA prepared has been 
assigned EPA ICR number 2752.02 and OMB Control Number 2040-0310. You 
can find a copy of the ICR in the docket for this rule, and it is 
briefly summarized here. The information collection requirements are 
not enforceable until OMB approves them.
    As described in section XIV.C, the EPA is finalizing several 
changes to the individual reporting and recordkeeping requirements of 
Sec.  423.19 for specific subcategories of plants and/or plants that 
have certain types of discharges. The EPA is adding reporting and 
recordkeeping requirements for plants in the permanent cessation of 
coal combustion by 2034 subcategory and for plants that discharge 
unmanaged CRL. EPA is also removing reporting and recordkeeping 
requirements for LUEGUs and finalizing a new requirement for plants to 
post reports to a publicly available website.
    Respondents/affected entities: The respondents affected by this ICR 
are steam electric power plants. The North American Industry 
Classification System (NAICS) identification number applicable to 
respondents is 221112: Electric Power Generation Plants--Fossil Fuel 
Electric Power Generation. The U.S. Census Bureau describes this U.S. 
industry as establishments primarily engaged in operating fossil-fuel-
powered electric power generation facilities. These facilities use 
fossil fuels, such as coal, oil, or gas, in an internal combustion or a 
combustion turbine conventional steam process to produce electric 
energy. The electric energy produced in these establishments is 
provided to electric power transmission systems or to electric power 
distribution systems.
    Respondent's obligation to respond: Mandatory (40 CFR parts 423 and 
122).
    Estimated number of respondents: The EPA estimates that 236 steam 
electric facilities would be subject to this final rule.
    Frequency of response: The EPA made the following assumptions for 
estimating frequency:
     NOPPs, notices, and the Combustion Residual Leachate 
Monitoring Report (CRLMR) would be submitted one time (in the first 
year of the requirements).
     Progress reports and the annual CRLMR would be submitted 
once a year following the submittal of the official NOPP (i.e., twice 
over a three-year period).
     Progress reports associated with EPA's VIP program or 
NOPPs that have already been submitted would be submitted once a year 
following the publication of the final rule.
    Total estimated burden: For facilities, the estimated facility 
universe for any reporting, for the purpose of this estimate is 236 
facilities. The EPA estimates the total one-time labor hours associated 
with this ICR to facilities is 6,520 and total annual labor hours of 
22,000 hours for a total annual average of 24,300 hours. Similarly, the 
EPA estimates the total one-time labor costs

[[Page 40289]]

to facilities to be $650,000 and total annual labor costs of about 
$2,300,000 for a total annual average of $2,540,000. For permitting/
control authorities, the estimated universe is 41. The EPA estimates 
the total one-time labor hours associated with this ICR to permitting/
control authorities is 416 and total annual labor hours ranging from 
3,050 to 3,160 for a total annual average of 3,230 hours. Similarly, 
the EPA estimates the total one-time labor costs to permitting/control 
authorities to be $33,300 and total annual labor costs range from 
$256,000 to $265,000 for a total annual average of $273,000.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. The 
small entities subject to the requirements of this action include small 
businesses and small governmental jurisdictions that own steam electric 
plants. The EPA has determined that 220 to 391 entities own steam 
electric power plants subject to the ELGs, of which 117 to 202 entities 
are small. These small entities own a total of 267 steam electric power 
plants (out of the total of 858 plants), including 33 to 39 plants 
estimated to incur costs under the final rule under the lower and upper 
cost scenarios, respectively. The EPA considered the impacts of the 
final rule on small businesses using a cost-to-revenue test. The 
analysis compares the cost of implementing wastewater controls under 
the final rule to those under baseline (which reflects the 2020 rule, 
as explained in section V of this preamble). Small entities estimated 
to incur compliance costs exceeding one or more of the one percent and 
three percent impact thresholds were identified as potentially 
incurring a significant impact. For the final rule under the lower 
bound cost scenario, the EPA's analysis shows 10 small entities (4 non-
utilities, 3 cooperatives, and 3 municipalities) expected to incur 
incremental costs equal to or greater than one percent of revenue. For 
5 of these small entities (2 non-utilities, 2 cooperatives, and 1 
municipality), the incremental cost of the final rule exceeds three 
percent of revenue. For the upper bound cost scenario, an additional 2 
small entities (both non-utilities) have costs equal to or greater than 
one percent of revenue for a total of 12 entities. For 2 non-utilities, 
3 cooperatives, and 2 municipalities, these costs exceed three percent 
of revenue. Details of this analysis are presented in section 8 of the 
RIA, included in the docket.
    These results support the EPA's finding of no significant impact on 
a substantial number of small entities.

D. Unfunded Mandates Reform Act (UMRA)

    This action contains a Federal mandate under the UMRA, 2 U.S.C. 
1531-1538 that may result in expenditures of $100 million (adjusted 
annually for inflation) or more for state, local, and Tribal 
governments, in the aggregate, or the private sector in any one year 
($198 million in 2023 dollars). Accordingly, the EPA has prepared a 
written statement required under section 202 of UMRA. The statement is 
included in the docket for this action (see section 9 in the RIA) and 
briefly summarized below.
    Consistent with the intergovernmental consultation provisions of 
section 204 of the UMRA, the EPA consulted with government entities 
potentially affected by this rule. The EPA described the government-to-
government dialogue leading to the proposed rule in its preamble to the 
proposed rulemaking. The EPA received comments from state and local 
government representatives in response to the proposed rule and 
considered this input in developing the final rule.
    Consistent with section 205, the EPA has identified and considered 
a reasonable number of regulatory alternatives to develop BAT. The main 
regulatory options are described in section VII of this preamble. These 
options included a range of technology-based approaches. As discussed 
in detail in section VII.B of this preamble, the EPA is selecting 
Option B as the BAT after considering the factors required under CWA 
section 304(b)(2)(B). The technologies are available, are economically 
achievable, and have acceptable non-water quality environmental 
impacts.
    This final rule is not subject to the requirements of section 203 
of UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. To assess the 
impact of compliance requirements on small governments (i.e., 
governments with a population of less than 50,000), the EPA compared 
total costs and costs per plant estimated to be incurred by small 
governments with the costs estimated to be incurred by large 
governments. The EPA also compared costs for small government-owned 
plants with those of non-government-owned facilities. The Agency 
evaluated both the average and maximum annualized costs per plant under 
both the lower and upper bound cost scenarios. section 9 of the RIA 
provides details of these analyses. In all these comparisons, both for 
the cost totals and, in particular, for the average and maximum cost 
per plant, the costs for small government-owned facilities were less 
than those for small non-government-owned facilities. This was true for 
both the lower and upper bound cost scenarios. The maximum cost per 
plant was also smaller for the small government-owned plants vs. the 
large government-owned plants under the lower bound cost scenario. The 
average annualized costs per plant were larger for small government-
owned plants vs. large government-owned plants under the upper bound 
cost scenario, but not markedly so. On this basis, the EPA concludes 
that the compliance cost requirements of the steam electric ELGs would 
not significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism

    The EPA has concluded that this action has federalism implications 
because it imposes direct compliance costs on state or local 
governments, and the Federal Government will not provide the funds 
necessary to pay those costs.
    As discussed in section XV.B, the EPA anticipates that this final 
rule does not impose incremental administrative burden on states from 
issuing, reviewing, and overseeing compliance with discharge 
requirements. The EPA has identified 148 steam electric power plants 
owned by 63 state or local government entities. Under the final rule, 
the EPA projects that 15 government-owned plants would incur compliance 
costs. The EPA estimates the maximum compliance cost in any one year to 
governments (excluding the Federal Government) for the final rule range 
from $155 million and $220 million, whereas the annualized costs range 
between $40 million and $67 million (see section 9 of the RIA for 
details).
    The EPA provides the following federalism summary impact statement.
    The EPA consulted with state and local officials early in the 
process of developing the rule to permit them to

[[Page 40290]]

have meaningful and timely input into its development. The preamble to 
the proposed rule described these consultations, which included a 
meeting held on January 27, 2022, attended by representatives from 15 
state and local government organizations and outreach with several 
intergovernmental associations representing elected officials and 
encouraged their members to participate in the meeting, including the 
National Governors Association, the National Conference of State 
Legislatures, the Council of State Governments, the National 
Association of Counties, the National League of Cities, the U.S. 
Conference of Mayors, the County Executives of America, and the 
National Associations of Towns and Townships.
    The EPA received five sets of unique written comments after the 
meeting and considered these comments in the development of the 
proposed rule. For further information regarding the consultation 
process and supplemental materials provided to state and local 
government representatives, please go to the steam electric power 
generating effluent guidelines website at: https://www.epa.gov/eg/2021-supplemental-steam-electric-rulemaking.
    The EPA received comment on the proposed ELGs from three state and 
local officials or their representatives. Some state and local 
officials expressed concerns the EPA had underestimated the costs and 
overstated the pollutant removals of the technology options. Commenters 
stated that the ELGs would impose significant costs on small entities 
and would result in electricity rate increases that are unaffordable 
for households. Commenters also expressed concern about coordination of 
the various rules affecting the power sector. The EPA considered these 
comments in developing the final rule.
    A list of the state and local government commenters has been 
provided to OMB and has been placed in the docket for this rulemaking. 
In addition, the detailed response to comments from these entities is 
contained in the EPA's response to comments document on this final 
rulemaking, which has also been placed in the docket for this 
rulemaking.
    As explained in section VII of this preamble, the EPA is 
establishing more stringent limitations on several wastestreams that 
would alleviate concerns raised by the public water systems. At the 
same time, the EPA's final rule includes subcategories for units 
certifying to the permanent cessation of coal combustion. The EPA 
believes these differentiated requirements alleviate some of the 
concerns raised by publicly owned utilities. Further, as explained in 
section VIII of this preamble, the EPA's analysis demonstrates that the 
final requirements are economically achievable for the steam electric 
power generating industry as a whole and for plants owned by state or 
local government entities.

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

    This action has Tribal implications; however, it will neither 
impose substantial direct compliance costs on federally recognized 
Tribal governments, nor preempt Tribal law, as specified in Executive 
Order 13175. See 65 FR 67249 (November 9, 2000). 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 facility subject to the final ELGs is owned 
by Tribal governments. Thus, Executive Order 13175 does not apply to 
this action. The EPA acknowledges this action has Tribal implications, 
not prescribed in Executive Order 13175, because during Tribal 
Consultation, the EPA received written comments from 3 Tribal nations 
that conveyed the importance of historical Tribal waters and rights 
(e.g., fishing, trapping), recommended more stringent technological 
controls to protect those rights, or encouraged retirement or fuel 
conversion of old coal-fired EGUs.
    Although Executive Order 13175 does not apply to this action, the 
EPA consulted with Tribal officials early in the process of developing 
this rule to enable them to have meaningful and timely input into its 
development. The EPA initiated consultation and coordination with 
federally recognized Tribal governments in January 2022, sharing 
information about the steam electric effluent guidelines rulemaking 
with the National Tribal Caucus, the National Tribal Water Council, and 
several individual Tribes. The EPA continued this government-to-
government dialogue and, on February 1 and February 9, 2022, invited 
Tribal representatives to participate in further discussions about the 
rulemaking process and objectives, with a focus on identifying specific 
ways the rulemaking may affect Tribes.\233\ The consultation process 
ended on March 29, 2022. The EPA is including in the docket for this 
action a memorandum that provides a response to the comments it 
received through this consultation and the consultations described in 
sections XVI.D and XVI.E of this preamble. For further information 
regarding the consultation process and supplemental materials provided 
to Tribal representatives, please go to the steam electric power 
generating effluent guidelines website at: https://www.epa.gov/eg/2021-supplemental-steam-electric-rulemaking.
---------------------------------------------------------------------------

    \233\ As discussed in sections XIII and XVI.J, the EPA also did 
targeted outreach to communities in the top tier of its EJ screening 
analysis which included two tribal communities.
---------------------------------------------------------------------------

    Representatives from several Tribes provided input to the rule. The 
EPA considered input from Tribal representatives in developing this 
final rule.

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

    Executive Order 13045 directs Federal agencies to include an 
evaluation of the health and safety effects of the planned regulation 
on children in Federal health and safety standards and explain why the 
regulation is preferable to potentially effective and reasonably 
feasible alternatives. This action is not subject to Executive Order 
13045 because the EPA does not believe the environmental health risks 
or safety risks addressed by this action present a disproportionate 
risk to children. This action's health and risk assessments are 
discussed in sections 4 and 5 of the BCA and are summarized below.
    The EPA identified several ways in which the final rule will 
benefit children, including by potentially reducing health risks from 
exposure to pollutants present in steam electric power plant 
discharges, or through impacts of the discharges on the quality of 
source water used by public water systems. This reduction arises from 
more stringent pollutant limitations as compared to baseline. The EPA 
quantified the changes in IQ losses from lead exposure among preschool 
children and from mercury exposure in utero resulting from maternal 
fish consumption under the final rule as compared to baseline. The EPA 
also estimated changes in the lifetime risk of developing bladder 
cancer due to exposure to TTHM in drinking water, or of cardiovascular 
premature mortality from exposure to lead. For these analyses, the EPA 
did not estimate children-specific risks because these adverse health 
effects normally follow

[[Page 40291]]

long-term exposure. Finally, the EPA estimated changes in air-related 
adverse health effects resulting from changes in the profile of 
electricity generation under the final rule as compared to baseline. 
The analysis found that the resulting reductions in PM2.5 
and ozone will benefit children by reducing asthma onset and symptoms, 
allergy symptoms, emergency room visits and hospital visits for 
respiratory conditions, and school absences.
    However, the EPA's Policy on Children's Health applies to this 
action. Information on how the Policy was applied is available under 
``Children's Environmental Health'' in this SUPPLEMENTARY INFORMATION 
section.

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

    This final 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 EPA analyzed the potential energy 
effects of the final rule relative to baseline and found minimal or no 
impacts on electricity generation, generating capacity, cost of energy 
production, or dependence on a foreign supply of energy. Specifically, 
the Agency's analysis found that the final rule would not reduce 
electricity production by more than 1 billion kWhs per year or by 500 
MW of installed capacity, nor would the final rule increase U.S. 
dependence on foreign energy supplies. For more detail on the potential 
energy effects of this action, see section 10.7 in the RIA, available 
in the docket.

I. National Technology Transfer and Advancement Act

    This rulemaking does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations and 
Executive Order 14096: Revitalizing Our Nation's Commitment to 
Environmental Justice for All

    The EPA believes that the human health or environmental conditions 
existing prior to this action result in or have the potential to result 
in disproportionate and adverse human health or environmental effects 
on communities with EJ concerns. Current research suggests that coal-
fired power plants tend to be in low-income communities, Indigenous 
communities, and communities of color. Toomey (2013) reported that 78 
percent of African Americans in the United States live within a 30-mile 
radius of a coal-fired power plant.\234\ Impacts discussed in the 
reports included adverse health impacts resulting from air pollutants 
(e.g., SO2, NOX, PM2.5) for those 
living in proximity to coal-fired power plants, climate justice issues 
resulting from GHG emissions, and risk of impoundment failures for 
populations living in proximity to coal waste surface impoundments 
where coal is mined.235 236 237 All these impacts were found 
in one or more papers to disproportionately impact low-income, 
minority, and Indigenous communities. The EPA also conducted a 
proximity analysis to characterize the demographics of communities 
potentially exposed to pollution from steam electric power plant 
wastewater discharges through proximity to plants, proximity to 
downstream surface waters receiving, or being served by a PWS using 
impacted downstream receiving waters as source water for drinking 
water. The results of the EPA's analysis showed that these communities 
have higher proportions of low-income individuals and people of color 
compared to the national average, national rural average, and 
respective state averages suggesting potential EJ concerns under the 
baseline in terms of disproportionate exposures. The EPA believes that 
this action is likely to reduce existing disproportionate and adverse 
effects on communities with EJ concerns. The EPA's EJ analysis showed 
the final rule will reduce differential baseline exposures for low-
income communities and communities of color to pollutants in wastewater 
and resulting human impacts. Improvements to water quality, wildlife, 
and human health resulting from reductions in pollutants in surface 
water will be distributed more among communities with EJ concerns under 
some or all of the regulatory options due to their disproportionate 
exposures under the baseline. Drinking water improvements will also be 
distributed more among communities with EJ concerns under the final 
rule due to their disproportionate exposures under the baseline. 
Remaining exposures, impacts, and benefits analyzed are small enough 
that EPA could not conclude whether changes in disproportionate impacts 
under the baseline would occur. While the changes in GHGs attributable 
to the final rule are small compared to worldwide emissions, findings 
from peer-reviewed evaluations demonstrate that actions that reduce GHG 
emissions are also likely to reduce climate-related impacts on 
vulnerable communities, including communities with EJ concerns. Costs 
of the final rule in terms of electricity price increases among 
residential households may impact low-income households and households 
of color more relative to all households as low-income households and 
households of color tend to spend a greater proportion of their income 
on energy expenditures. Despite this, the potential price increases 
under the upper bound cost scenario represent between less than 0.1 
percent and 0.2 percent of energy expenditures for all income, race 
groups, and income quintiles, and therefore the EPA does not expect 
costs to have a substantial impact on low-income households and 
households of color.
---------------------------------------------------------------------------

    \234\ Toomey, D. 2013. Coal Pollution and the Fight for 
Environmental Justice. Yale Environment 360. June 19. Available 
online at: https://www.e360.yale.edu/features/naacp_jacqueline_patterson_coal_pollution_and_fight_for_environmental_justice.
    \235\ Li[eacute]vanos, R., Greenberg, P., Wishart, P. 2018. In 
the Shadow of Production: Coal Waste Accumulation and Environmental 
Inequality Formation in Eastern Kentucky, pp. 37-55.
    \236\ Israel, B. 2012. Coal Plants Smother Communities of Color. 
https://www.scientificamerican.com/article/coal-plants-smother-
communities-of-color/
#:~:text=People%20living%20near%20coal%20plants,percent%20are%20peopl
e%20of%20color.
    \237\ NAACP (National Association for the Advancement of Colored 
People). 2012. Coal Blooded: Putting Profits Before People. 
www.naacp.org/resources/coal-blooded-putting-profits-people.
---------------------------------------------------------------------------

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).

Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations 
Used in This Preamble

    The following acronyms, abbreviations, and terms are used in 
this preamble. These terms are provided the reader's for 
convenience; they are not regulatory definitions with the force or 
effect of law, nor are they to be used as guidance for 
implementation of this rule.
    Administrator. The Administrator of the U.S. Environmental 
Protection Agency.
    Agency. U.S. Environmental Protection Agency.
    BAT. Best available technology economically achievable, as 
defined by CWA sections 301(b)(2)(A) and 304(b)(2)(B).
    BA transport water. Wastewater that is used to convey bottom ash 
from the ash collection or storage equipment, or boiler, and has 
direct contact with the ash.
    BCA. Abbreviation used for the Benefit and Cost Analysis for the 
Final Supplemental Effluent Limitations Guidelines and Standards for 
the Steam Electric Power Generating Point Source Category report.

[[Page 40292]]

    Bioaccumulation. A general term describing a process by which 
chemicals are taken up by an organism either directly from exposure 
to a contaminated medium or by consumption of food containing the 
chemicals, resulting in a net accumulation of the chemical over time 
by the organism.
    BMP. Best management practice.
    BA. Bottom ash. The ash, including EGU slag, that settles in a 
furnace or is dislodged from furnace walls. Economizer ash is 
included when it is collected with BA.
    BA purge water. The water discharged from a wet BA handling 
system that recycles some, but not all, of its BA transport water.
    BPT. The best practicable control technology currently 
available, as defined by CWA sections 301(b)(1) and 304(b)(1).
    CBI. Confidential business information.
    CCR. Coal combustion residuals.
    CWA. Clean Water Act; the Federal Water Pollution Control Act 
Amendments of 1972 (33 U.S.C. 1251 et seq.), as amended, e.g., by 
the Clean Water Act of 1977 (Pub. L. 95-217) and the Water Quality 
Act of 1987 (Pub. L. 100-4).
    Combustion residuals. Solid wastes associated with combustion-
related steam electric power plant processes, including fly ash and 
BA from coal-, petroleum coke-, or oil-fired units; FGD solids; FGMC 
wastes; and other wastewater treatment solids associated with steam 
electric power plant wastewater. In addition to the residuals 
associated with coal combustion, this also includes residuals 
associated with the combustion of other fossil fuels.
    CRL. Combustion residual leachate. Leachate from landfills or 
surface impoundments that contains combustion residuals. Leachate is 
composed of liquid, including any suspended or dissolved 
constituents in the liquid, that has percolated through waste or 
other materials emplaced in a landfill, or that passes through the 
surface impoundment's containment structure (e.g., bottom, dikes, 
berms). Combustion residual leachate includes seepage and/or leakage 
from a combustion residual landfill or impoundment unit. It also 
includes wastewater from landfills and surface impoundments located 
on non-adjoining property when under the operational control of the 
permitted facility.
    CWA. Clean Water Act.
    Direct discharge. (1) Any addition of any ``pollutant'' or 
combination of pollutants to ``waters of the United States'' from 
any ``point source'' or (2) any addition of any pollutant or 
combination of pollutant to waters of the ``contiguous zone'' or the 
ocean from any point source other than a vessel or other floating 
craft that is being used as a means of transportation. This 
definition includes additions of pollutants into waters of the 
United States from surface runoff that is collected or channeled by 
man; discharges through pipes, sewers, or other conveyances owned by 
a state, municipality, or other person that do not lead to a 
treatment works; and discharges through pipes, sewers, or other 
conveyances that lead into privately owned treatment works. This 
term does not include addition of pollutants by any ``indirect 
discharger.''
    Direct discharger. A plant that discharges treated or untreated 
wastewaters into waters of the United States.
    DOE. Department of Energy.
    Dry BA handling system. A system that does not use water as the 
transport medium to convey BA away from the EGU. Dry-handling 
systems include systems that collect and convey the BA without using 
any water, as well as systems in which BA is quenched in a water 
bath and then mechanically or pneumatically conveyed away from the 
EGU. Dry BA handling systems do not include wet sluicing systems 
(such as remote MDS or complete recycle systems).
    Effluent limitation. Under CWA section 502(11), any restriction, 
including schedules of compliance, established by a state or the 
Administrator on quantities, rates, and concentrations of chemical, 
physical, biological, and other constituents that are discharged 
from point sources into navigable waters, the waters of the 
contiguous zone, or the ocean.
    EGU. Electric generating unit.
    EIA. Energy Information Administration.
    EJA. Abbreviation used for the Environmental Justice Analysis 
for the Final Supplemental Effluent Limitations Guidelines and 
Standards for the Steam Electric Power Generating Point Source 
Category report.
    ELGs. Effluent limitations guidelines and standards.
    E.O. Executive order.
    EPA. U.S. Environmental Protection Agency.
    FA. Fly ash. The ash that is carried out of the furnace by a gas 
stream and collected by a capture device such as a mechanical 
precipitator, electrostatic precipitator, and/or fabric filter. 
Economizer ash is included in this definition when it is collected 
with FA. Ash is not included in this definition when it is collected 
in wet scrubber air pollution control systems whose primary purpose 
is particulate removal.
    Facility. Any NPDES ``point source'' or any other facility or 
activity (including land or appurtenances thereto) that is subject 
to regulation under the NPDES program.
    FA transport water. Wastewater that is used to convey fly ash 
from the ash collection or storage equipment, or boiler, and has 
direct contact with the ash.
    FGD. Flue gas desulfurization.
    FGMC. Flue gas mercury control.
    FGD wastewater. Wastewater generated specifically from the wet 
FGD scrubber system that contacts the flue gas or the FGD solids, 
including, but not limited to, the blowdown or purge from the FGD 
scrubber system, overflow or underflow from the solids separation 
process, FGD solids wash water, and the filtrate from the solids 
dewatering process. Wastewater generated from cleaning the FGD 
scrubber, cleaning FGD solids separation equipment, cleaning FGD 
solids dewatering equipment, or that is collected in floor drains in 
the FGD process area is not considered FGD wastewater.
    FGMC wastewater. Any wastewater generated from an air pollution 
control system installed or operated for the purpose of removing 
mercury from flue gas. This includes wastewater from fly ash 
collection systems when the particulate control system follows 
sorbent injection or other controls to remove mercury from flue gas. 
FGD wastewater generated at plants using oxidizing agents to remove 
mercury in the FGD system and not in a separate FGMC system is not 
considered FGMC wastewater.
    Gasification wastewater. Any wastewater generated at an 
integrated gasification combined cycle operation from the gasifier 
or the syngas cleaning, combustion, and cooling processes. 
Gasification wastewater includes, but is not limited to, the 
following: sour/grey water; CO2/steam stripper 
wastewater; sulfur recovery unit blowdown; and wastewater resulting 
from slag handling or fly ash handling, particulate removal, halogen 
removal, or trace organic removal. Air separation unit blowdown, 
noncontact cooling water, and runoff from fuel and/or byproduct 
piles are not considered gasification wastewater. Wastewater that is 
collected intermittently in floor drains in the gasification process 
area from leaks, spills, and cleaning occurring during normal 
operation of the gasification operation is not considered 
gasification wastewater.
    Groundwater. Water that is found in the saturated part of the 
ground underneath the land surface.
    Indirect discharge. Wastewater discharged or otherwise 
introduced to a POTW.
    IPM. Integrated Planning Model.
    Landfill. A disposal facility or part of a facility or plant 
where solid waste, sludges, or other process residuals are placed in 
or on any natural or manmade formation in the earth for disposal and 
which is not a storage pile, a land treatment facility, a surface 
impoundment, an underground injection well, a salt dome or salt bed 
formation, an underground mine, a cave, or a corrective action 
management unit.
    Legacy wastewater. FGD wastewater, BA transport water, FA 
transport water, CRL, gasification wastewater and/or FGMC wastewater 
generated before the ``as soon as possible'' date that more 
stringent effluent limitations from the 2015 or 2020 rules would 
apply.
    MDS. Mechanical drag system.BA handling system that collects BA 
from the bottom of an EGU in a water-filled trough. The water bath 
in the trough quenches the hot BA as it falls from the EGU and seals 
the EGU gases. A drag chain operates in a continuous loop to drag BA 
from the water trough up an incline, which dewaters the BA by 
gravity, draining the water back to the trough as the BA moves 
upward. The dewatered BA is often conveyed to a nearby collection 
area, such as a small bunker outside the EGU building, from which it 
is loaded onto trucks and either sold or transported to a landfill. 
The MDS is considered a dry BA handling system because the ash 
transport mechanism is mechanical removal by the drag chain, not the 
water.
    Mortality. Death rate or proportion of deaths in a population.
    NAICS. North American Industry Classification System.
    NPDES. National Pollutant Discharge Elimination System.
    NSPS. New Source Performance Standards.

[[Page 40293]]

    ORP. Oxidation-reduction potential.
    Paste. A substance containing solids in a fluid which behaves as 
a solid until a force is applied that causes it to behave like a 
fluid.
    Paste landfill. A landfill that receives any paste designed to 
set into a solid after the passage of a reasonable amount of time.
    Point source. Any discernible, confined, and discrete 
conveyance, including but not limited to any pipe, ditch, channel, 
tunnel, conduit, well, discrete fissure, container, rolling stock, 
concentrated animal feeding operation, vessel, or other floating 
craft from which pollutants are or may be discharged. The term does 
not include agricultural stormwater discharges or return flows from 
irrigated agriculture. See CWA section 502(14), 33 U.S.C. 1362(14); 
40 CFR 122.2.
    POTW. Publicly owned treatment works. See CWA section 212, 33 
U.S.C. 1292; 40 CFR 122.2, 403.3.
    PSES. Pretreatment Standards for Existing Sources.
    PSC. Public service commission.
    PUC. Public utility commission.
    RCRA. The Resource Conservation and Recovery Act of 1976, 42 
U.S.C. 6901 et seq.
    Remote MDS. BA handling system that collects BA at the bottom of 
the EGU, then uses transport water to sluice the ash to a remote MDS 
that dewaters BA using a configuration similar to MDS. The remote 
MDS is considered a wet BA handling system because the ash transport 
mechanism is water.
    RO. Reverse osmosis.
    RFA. Regulatory Flexibility Act.
    SBA. Small Business Administration.
    Sediment. Particulate matter lying below water.
    Surface water. All waters of the United States, including 
rivers, streams, lakes, reservoirs, and seas.
    TDD. Abbreviation used for the Technical Development Document 
for the Final Supplemental Effluent Limitations Guidelines and 
Standards for the Steam Electric Power Generating Point Source 
Category report.
    Toxic pollutants. As identified under the CWA, 65 pollutants and 
classes of pollutants, of which 126 specific substances have been 
designated priority toxic pollutants. See appendix A to 40 CFR part 
423.
    Transport water. Wastewater that is used to convey FA, BA, or 
economizer ash from the ash collection or storage equipment or EGU 
and that has direct contact with the ash. Transport water does not 
include low-volume, short-duration discharges of wastewater from 
minor leaks (e.g., leaks from valve packing, pipe flanges, or 
piping) or minor maintenance events (e.g., replacement of valves or 
pipe sections).
    UMRA. Unfunded Mandates Reform Act.
    Wet BA handling system. A system in which BA is conveyed away 
from the EGU using water as a transport medium. Wet BA systems 
typically send the ash slurry to dewatering bins or a surface 
impoundment. Wet BA handling systems include systems that operate in 
conjunction with a traditional wet sluicing system to recycle all BA 
transport water (e.g., remote MDS or complete recycle systems).
    Wet FGD system. Wet FGD systems capture sulfur dioxide from the 
flue gas using a sorbent that has mixed with water to form a wet 
slurry, and that generates a water stream that exits the FGD 
scrubber absorber.

List of Subjects in 40 CFR Part 423

    Environmental protection, Electric power generation, Power 
facilities, Waste treatment and disposal, Water pollution control.

Michael S. Regan,
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 is revised 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. Revise Sec.  423.10 to read as follows:


Sec.  423.10  Applicability and severability.

    (a) Applicability. The provisions of this part apply to discharges 
resulting from the operation of a generating unit by an establishment 
whose generation of electricity is the predominant source of revenue or 
principal reason for operation, and whose generation of electricity 
results primarily from a process utilizing fossil-type fuel (coal, oil, 
or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis 
gas), or nuclear fuel in conjunction with a thermal cycle employing the 
steam water system as the thermodynamic medium. This part applies to 
discharges associated with both the combustion turbine and steam 
turbine portions of a combined cycle generating unit.
    (b) Severability. 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.


0
3. Amend Sec.  423.11 by revising paragraphs (n), (p), (r), (w), (z), 
and (bb) and adding paragraphs (ee) and (ff) to read as follows:


Sec.  423.11  Specialized definitions.

* * * * *
    (n) The term flue gas desulfurization (FGD) wastewater means any 
wastewater generated specifically from the wet flue gas desulfurization 
scrubber system that comes into contact with the flue gas or the FGD 
solids, including but not limited to, the blowdown from the FGD 
scrubber system, overflow or underflow from the solids separation 
process, FGD solids wash water, and the filtrate from the solids 
dewatering process. Wastewater generated from cleaning the FGD 
scrubber, cleaning FGD solids separation equipment, cleaning FGD solids 
dewatering equipment; FGD paste equipment cleaning water; treated FGD 
wastewater permeate or distillate used as boiler makeup water; water 
that is collected in floor drains in the FGD process area; wastewater 
removed from FGD wastewater treatment equipment within the first 120 
days of decommissioning the equipment, or wastewater generated by a 10-
year, 24-hour or longer duration storm event when meeting the 
certification requirements in Sec.  423.19(o) is not considered FGD 
wastewater.
* * * * *
    (p) The term transport water means any wastewater that is used to 
convey fly ash, bottom ash, or economizer ash from the ash collection 
or storage equipment, or boiler, and has direct contact with the ash. 
Transport water does not include low volume, short duration discharges 
of wastewater from minor leaks (e.g., leaks from valve packing, pipe 
flanges, or piping), minor maintenance events (e.g., replacement of 
valves or pipe sections), FGD paste equipment cleaning water, bottom 
ash purge water, wastewater removed from ash handling equipment within 
the first 120 days of decommissioning the equipment, or wastewater 
generated by a 10-year, 24-hour or longer duration storm event when 
meeting the certification requirements in Sec.  423.19(o).
* * * * *
    (r) The term combustion residual leachate means leachate from 
landfills or surface impoundments containing combustion residuals. 
Leachate is composed of liquid, including any suspended or dissolved 
constituents in the liquid, that has percolated through waste or other 
materials emplaced in a landfill, or that passes through the surface 
impoundment's containment structure (e.g., bottom, dikes, berms). 
Combustion residual leachate includes seepage and/or leakage from a 
combustion residual landfill or impoundment unit. Combustion residual 
leachate includes wastewater from landfills and surface impoundments 
located on non-adjoining property when under the operational control of 
the permitted facility. Combustion residual leachate does not include 
wastewater generated by a 10-year, 24-hour or longer duration storm 
event when meeting the certification requirements in Sec.  423.19(o).
* * * * *

[[Page 40294]]

    (w) The term permanent cessation of coal combustion means the owner 
or operator certifies under Sec.  423.19(g) or (h) that an electric 
generating unit will cease combustion of coal no later than December 
31, 2028, or December 31, 2034.
* * * * *
    (z) The term low utilization electric generating unit means any 
electric generating unit for which the facility owner certifies, and 
annually recertifies, under Sec.  423.19(f) that the two-year average 
annual capacity utilization rating is less than 10 percent.
* * * * *
    (bb) The term tank means a stationary device, designed to contain 
an accumulation of wastewater which is constructed primarily of non-
earthen materials (e.g., wood, concrete, steel, plastic) which provide 
structural support and which is not a coal combustion residual surface 
impoundment.
* * * * *
    (ee) The term coal combustion residual surface impoundment means a 
natural topographic depression, man-made excavation, or diked area, 
which is designed to hold an accumulation of coal combustion residuals 
and liquids, and the unit treats, stores, or disposes of coal 
combustion residuals.
    (ff) The term unmanaged combustion residual leachate means 
combustion residual leachate which either:
    (1) Is determined by the permitting authority to be the functional 
equivalent of a direct discharge to waters of the United States (WOTUS) 
through groundwater; or
    (2) Has leached from a waste management unit into the subsurface 
and mixed with groundwater prior to being captured and pumped to the 
surface for discharge directly to WOTUS.


0
4. Amend Sec.  423.13 by:
0
a. Revising paragraph (g);
0
b. Adding a heading for paragraph (h);
0
c. Revising paragraph (h)(1)(ii);
0
d. Adding a heading for paragraph (i);
0
e. Revising paragraph (i)(1)(ii); and
0
f. Revising paragraphs (k), (l), and (o).
    The revisions and additions read as follows:


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) FGD wastewater--(1) 2020 BAT. (i) Except for those discharges 
to which paragraph (g)(2) or (3) of this section applies, the quantity 
of pollutants in FGD wastewater shall not exceed the quantity 
determined by multiplying the flow of FGD wastewater times the 
concentration listed in table 5 to this paragraph (g)(1)(i). 
Dischargers must meet the effluent limitations for FGD wastewater in 
this paragraph (g)(1)(i) by a date determined by the permitting 
authority that is as soon as possible beginning October 13, 2021, but 
no later than December 31, 2025. The effluent limitations in this 
paragraph (g)(1)(i) 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)(1)(i), until the date determined by the permitting authority for 
meeting the effluent limitations in paragraph (g)(4) of this section.

                     Table 5 to Paragraph (g)(1)(i)
------------------------------------------------------------------------
                                             BAT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              18               8
Mercury, total (ng/L)...................             103              34
Selenium, total ([micro]g/L)............              70              29
Nitrate/nitrite as N (mg/L).............               4               3
------------------------------------------------------------------------

    (ii) For FGD wastewater generated before the date determined by the 
permitting authority, as specified in paragraph (g)(1)(i) of this 
section, the EPA is declining to establish BAT limitations and is 
reserving such limitations to be established by the permitting 
authority on a case-by-case basis using the permitting authority's best 
professional judgment.
    (2) 2020 BAT subcategories. (i) For any electric generating unit 
with a total nameplate capacity of less than or equal to 50 megawatts, 
that is an oil-fired unit, or for which the owner has submitted a 
certification pursuant to Sec.  423.19(g), the quantity of pollutants 
discharged in FGD wastewater shall not exceed the quantity determined 
by multiplying the flow of FGD wastewater times the concentration 
listed for total suspended solids (TSS) in Sec.  423.12(b)(11).
    (A) For any electric generating unit for which the owner has 
submitted a certification pursuant to Sec.  423.19(g), where such unit 
has permanently ceased coal combustion by December 31, 2028, there 
shall be no discharge of pollutants in FGD wastewater after April 30, 
2029.
    (B) For any electric generating unit for which the owner has 
submitted a certification pursuant to Sec.  423.19(g), where such unit 
has failed to permanently cease coal combustion by December 31, 2028, 
there shall be no discharge of pollutants in FGD wastewater after 
December 31, 2028.
    (ii) For FGD wastewater discharges from a high FGD flow facility, 
the quantity of pollutants in FGD wastewater shall not exceed the 
quantity determined by multiplying the flow of FGD wastewater times the 
concentration listed in table 6 to this paragraph (g)(2)(ii). 
Dischargers must meet the effluent limitations for FGD wastewater in 
this paragraph (g)(2)(ii) by a date determined by the permitting 
authority that is as soon as possible beginning October 13, 2021, but 
no later than December 31, 2023. The effluent limitations in this 
paragraph (g)(2)(ii) 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)(2)(ii), until the date determined by the permitting authority for 
meeting the effluent limitations in paragraph (g)(4) of this section.

[[Page 40295]]



                     Table 6 to Paragraph (g)(2)(ii)
------------------------------------------------------------------------
                                             BAT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

    (iii) For FGD wastewater discharges from a low utilization electric 
generating unit, the quantity of pollutants in FGD wastewater shall not 
exceed the quantity determined by multiplying the flow of FGD 
wastewater times the concentration listed in table 6 to paragraph 
(g)(2)(ii) of this section. Dischargers must meet the effluent 
limitations for FGD wastewater in this paragraph (g)(2)(iii) by a date 
determined by the permitting authority that is as soon as possible 
beginning October 13, 2021, but no later than December 31, 2023. 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)(2)(iii), until the date determined by the permitting authority for 
meeting the effluent limitations in paragraph (g)(4) of this section.
    (3) Voluntary incentives plan. (i) For dischargers who voluntarily 
choose to meet the effluent limitations for FGD wastewater in this 
paragraph (g)(3)(i), the quantity of pollutants in FGD wastewater shall 
not exceed the quantity determined by multiplying the flow of FGD 
wastewater times the concentration listed in table 7 to this paragraph 
(g)(3)(i). Dischargers who choose to meet the effluent limitations for 
FGD wastewater in this paragraph (g)(3)(i) must meet such limitations 
by December 31, 2028. The effluent limitations in this paragraph 
(g)(3)(i) apply to the discharge of FGD wastewater generated on and 
after December 31, 2028.

                     Table 7 to Paragraph (g)(3)(i)
------------------------------------------------------------------------
                                             BAT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...................               5              NA
Mercury, total (ng/L)...................              23              10
Selenium, total (ug/L)..................              10              NA
Nitrate/Nitrite (mg/L)..................             2.0             1.2
Bromide (mg/L)..........................             0.2              NA
TDS (mg/L)..............................             306             149
------------------------------------------------------------------------

    (ii) For discharges of FGD wastewater generated before December 31, 
2023, the quantity of pollutants discharged in FGD wastewater shall not 
exceed the quantity determined by multiplying the flow of FGD 
wastewater times the concentration listed for TSS in Sec.  
423.12(b)(11).
    (4) 2024 BAT. (i) Except for those discharges to which paragraphs 
(g)(3) and (g)(4)(ii) through (iv) of this section applies, there shall 
be no discharge of pollutants in FGD wastewater.
    (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, 2029. 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).
    (B) A facility which submits a request under Sec.  423.19(n) may 
discharge permeate or distillate from an FGD wastewater treatment 
system designed to achieve the limitations in this paragraph (g)(4)(i) 
for an additional period of up to one year from the date determined in 
paragraph (g)(4)(i)(A) of this section.
    (ii) For any electric generating unit with a total nameplate 
capacity of less than or equal to 50 megawatts or that is an oil-fired 
unit, the quantity of pollutants discharged in FGD wastewater shall not 
exceed the quantity determined by multiplying the flow of FGD 
wastewater times the concentration listed for TSS in Sec.  
423.12(b)(11).
    (iii) For any electric generating unit for which the owner has 
submitted a certification pursuant to Sec.  423.19(h), the quantity of 
pollutants discharged in FGD wastewater shall continue to be subject to 
limitations specified in paragraph (g)(1) or (g)(2)(ii) or (iii) of 
this section as incorporated into the existing permit.
    (A) Where such unit has permanently ceased coal combustion by 
December 31, 2034, there shall be no discharge of pollutants in FGD 
wastewater after April 30, 2035.
    (B) Where such unit has failed to permanently cease coal combustion 
by December 31, 2034, there shall be no discharge of pollutants in FGD 
wastewater after December 31, 2034.
    (iv) For FGD wastewater discharged from any coal combustion 
residual surface impoundment which commences closure pursuant to 40 CFR 
257.102(e) after July 8, 2024, the quantity of pollutants in FGD

[[Page 40296]]

wastewater shall not exceed the quantity determined by multiplying the 
flow of FGD wastewater times the concentration listed in table 8 to 
this paragraph (g)(4)(iv).

                     Table 8 to Paragraph (g)(4)(iv)
------------------------------------------------------------------------
                                             BAT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

    (h) Fly ash transport water. (1) * * *
    (ii) Legacy fly ash transport water. For fly ash transport water 
generated before the date determined by the permitting authority, as 
specified in paragraph (h)(1)(i) of this section, the EPA is declining 
to establish BAT limitations and is reserving such limitations to be 
established by the permitting authority on a case-by-case basis using 
the permitting authority's best professional judgment.
* * * * *
    (i) Flue gas mercury control wastewater. (1) * * *
    (ii) Legacy flue gas mercury control wastewater. For flue gas 
mercury control wastewater generated before the date determined by the 
permitting authority, as specified in paragraph (i)(1)(i) of this 
section, the EPA is declining to establish BAT limitations and is 
reserving such limitations to be established by the permitting 
authority on a case-by-case basis using the permitting authority's best 
professional judgment.
* * * * *
    (k) Bottom ash transport water--(1) 2020 BAT. (i) Except for those 
discharges to which paragraph (k)(2) 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)(1)(i) by a date determined by the permitting authority that is as 
soon as possible beginning October 13, 2021, but no later than December 
31, 2025. The limitation in this paragraph (k)(1)(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)(1)(i), until the date 
determined by the permitting authority for meeting the effluent 
limitations in paragraph (k)(4) of this section. Except for those 
discharges to which paragraph (k)(2) of this section applies, whenever 
bottom ash transport water is used in any other plant process or is 
sent to a treatment system at the plant (except when it is used in the 
FGD scrubber), the resulting effluent must comply with the discharge 
limitation in this paragraph (k)(1)(i). When the bottom ash transport 
water is used in the FGD scrubber, it ceases to be bottom ash transport 
water, and instead is FGD wastewater, which must meet the requirements 
in paragraph (g) of this section.
    (ii) For bottom ash transport water generated before the date 
determined by the permitting authority, as specified in paragraph 
(k)(1)(i) of this section, the EPA is declining to establish BAT 
limitations and is reserving such limitations to be established by the 
permitting authority on a case-by-case basis using the permitting 
authority's best professional judgment.
    (2) 2020 BAT subcategories. (i)(A) The discharge of pollutants in 
bottom ash transport water from a properly installed, operated, and 
maintained bottom ash system is authorized under the following 
conditions:
    (1) To maintain system water balance when precipitation-related 
inflows are generated from storm events exceeding a 10-year storm event 
of 24-hour or longer duration (e.g., 30-day storm event) and cannot be 
managed by installed spares, redundancies, maintenance tanks, and other 
secondary bottom ash system equipment; or
    (2) To maintain system water balance when regular inflows from 
wastestreams other than bottom ash transport water exceed the ability 
of the bottom ash system to accept recycled water and segregating these 
other wastestreams is not feasible; or
    (3) To maintain system water chemistry where installed equipment at 
the facility is unable to manage pH, corrosive substances, substances 
or conditions causing scaling, or fine particulates to below levels 
which impact system operation or maintenance; or
    (4) To conduct maintenance not otherwise included in paragraph 
(k)(2)(i)(A)(1), (2), or (3) of this section and not exempted from the 
definition of transport water in Sec.  423.11(p), and when water 
volumes cannot be managed by installed spares, redundancies, 
maintenance tanks, and other secondary bottom ash system equipment.
    (B) The total volume that may be discharged for the activities in 
paragraph (k)(2)(i)(A) of this section shall be reduced or eliminated 
to the extent achievable using control measures (including best 
management practices) that are technologically available and 
economically achievable in light of best industry practice. The total 
volume of the discharge authorized in this paragraph (k)(2)(i)(B) shall 
be determined on a case-by-case basis by the permitting authority and 
in no event shall such discharge exceed a 30-day rolling average of ten 
percent of the primary active wetted bottom ash system volume. The 
volume of daily discharges used to calculate the 30-day rolling average 
shall be calculated using measurements from flow monitors.
    (ii) For any electric generating unit with a total nameplate 
generating capacity of less than or equal to 50 megawatts, that is an 
oil-fired unit, or for which the owner has certified to the permitting 
authority that it will cease combustion of coal pursuant to Sec.  
423.19(g), the quantity of pollutants discharged in bottom ash 
transport water shall not exceed the quantity determined by multiplying 
the flow of the applicable wastewater times the concentration for TSS 
listed in Sec.  423.12(b)(4).
    (A) Where a unit has certified that it will cease combustion of 
coal pursuant to Sec.  423.19(g) and such unit has permanently ceased 
coal combustion by December 31, 2028, there shall be no

[[Page 40297]]

discharge of pollutants in bottom ash transport water after April 30, 
2029.
    (B) Where a unit has certified that it will cease combustion of 
coal pursuant to Sec.  423.19(g) and such unit has failed to 
permanently cease coal combustion by December 31, 2028, there shall be 
no discharge of pollutants in bottom ash transport water after December 
31, 2028.
    (iii) For bottom ash transport water generated by a low utilization 
electric generating unit, the quantity of pollutants discharged in 
bottom ash transport water shall not exceed the quantity determined by 
multiplying the flow of the applicable wastewater times the 
concentration for TSS listed in Sec.  423.12(b)(4), until the date 
determined by the permitting authority for meeting the effluent 
limitations in paragraph (k)(4) of this section, and shall incorporate 
the elements of a best management practices plan as described in 
paragraph (k)(3) of this section.
    (3) Best management practices plan. Where required in paragraph 
(k)(2)(iii) of this section, the discharger shall prepare, implement, 
review, and update a best management practices plan for the recycle of 
bottom ash transport water, and must include:
    (i) Identification of the low utilization coal-fired generating 
units that contribute bottom ash to the bottom ash transport system.
    (ii) A description of the existing bottom ash handling system and a 
list of system components (e.g., remote mechanical drag system, tanks, 
impoundments, chemical addition). Where multiple generating units share 
a bottom ash transport system, the plan shall specify which components 
are associated with low utilization generating units.
    (iii) A detailed water balance, based on measurements, or estimates 
where measurements are not feasible, specifying the volume and 
frequency of water additions and removals from the bottom ash transport 
system, including:
    (A) Water removed from the BA transport system:
    (1) To the discharge outfall;
    (2) To the FGD scrubber system;
    (3) Through evaporation;
    (4) Entrained with any removed ash; and
    (5) To any other mechanisms not specified paragraphs 
(k)(3)(iii)(A)(1) through (4) of this section.
    (B) Water entering or recycled to the BA transport system:
    (1) Makeup water added to the BA transport water system.
    (2) Bottom ash transport water recycled back to the system in lieu 
of makeup water.
    (3) Any other mechanisms not specified in paragraphs 
(k)(3)(iii)(B)(1) and (2) of this section.
    (iv) Measures to be employed by all facilities:
    (A) Implementation of a comprehensive preventive maintenance 
program to identify, repair and replace equipment prior to failures 
that result in the release of bottom ash transport water.
    (B) Daily or more frequent inspections of the entire bottom ash 
transport water system, including valves, pipe flanges and piping, to 
identify leaks, spills and other unintended bottom ash transport water 
escaping from the system, and timely repair of such conditions.
    (C) Documentation of preventive and corrective maintenance 
performed.
    (v) Evaluation of options and feasibility, accounting for the 
associated costs, for eliminating or minimizing discharges of bottom 
ash transport water, including:
    (A) Segregation of bottom ash transport water from other process 
water.
    (B) Minimization of the introduction of stormwater by diverting 
(e.g., curbing, using covers) storm water to a segregated collection 
system.
    (C) Recycling bottom ash transport water back to the bottom ash 
transport water system.
    (D) Recycling bottom ash transport water for use in the FGD 
scrubber.
    (E) Optimization of existing equipment (e.g., pumps, pipes, tanks) 
and installing new equipment where practicable to achieve the maximum 
amount of recycle.
    (F) Utilization of ``in-line'' treatment of transport water (e.g., 
pH control, fines removal) where needed to facilitate recycle.
    (vi) Description of the bottom ash recycle system, including all 
technologies, measures, and practices that will be used to minimize 
discharge.
    (vii) A schedule showing the sequence of implementing any changes 
necessary to achieve the minimized discharge of bottom ash transport 
water, including the following:
    (A) The anticipated initiation and completion dates of construction 
and installation associated with the technology components or process 
modifications specified in the plan.
    (B) The anticipated dates that the discharger expects the 
technologies and process modifications to be fully implemented on a 
full-scale basis, which in no case shall be later than December 31, 
2023.
    (C) The anticipated change in discharge volume and effluent quality 
associated with implementation of the plan.
    (viii) Description establishing a method for documenting and 
demonstrating to the permitting/control authority that the recycle 
system is well operated and maintained.
    (ix) Performance of weekly flow monitoring for the following:
    (A) Make up water to the bottom ash transport water system.
    (B) Bottom ash transport water sluice flow rate (e.g., to the 
surface impoundment(s), dewatering bins(s), tank(s), remote mechanical 
drag system).
    (C) Bottom ash transport water discharge to surface water or 
publicly owned treatment works (POTW).
    (D) Bottom ash transport water recycle back to the bottom ash 
system or FGD scrubber.
    (4) 2024 BAT. (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, 2029. 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).
    (ii) For any electric generating unit with a total nameplate 
generating capacity of less than or equal to 50 megawatts or that is an 
oil-fired unit, the quantity of pollutants discharged in bottom ash 
transport water shall not exceed the quantity determined by multiplying 
the flow of the applicable wastewater times the concentration for TSS 
listed in Sec.  423.12(b)(4).
    (iii) For any electric generating unit for which the owner has 
submitted a certification pursuant to Sec.  423.19(h), the quantity of 
pollutants discharged in bottom ash transport water shall continue to 
be subject to limitations specified in paragraph (k)(1) or (k)(2)(i) or 
(iii) of this section as incorporated into the existing permit.
    (A) Where such unit has permanently ceased coal combustion by 
December 31, 2034, there shall be no discharge of pollutants in bottom 
ash transport water after April 30, 2035.
    (B) Where such unit has failed to permanently cease coal combustion 
by December 31, 2034, there shall be no discharge of pollutants in 
bottom ash transport water after December 31, 2034.

[[Page 40298]]

    (iv) For bottom ash transport water discharged from any coal 
combustion residual surface impoundment which commences closure 
pursuant to 40 CFR 257.102(e) after July 8, 2024, the quantity of 
pollutants in bottom ash transport water shall not exceed the quantity 
determined by multiplying the flow of bottom ash transport water times 
the concentration listed in table 10 to this paragraph (k)(4)(iv).

                    Table 10 to Paragraph (k)(4)(iv)
------------------------------------------------------------------------
                                             BAT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

    (l) Combustion residual leachate--(1) 2024 BAT. (i) Except for 
those discharges to which paragraph (l)(1)(i)(B) or (C) or (1)(2) of 
this section applies, there shall be no discharge of pollutants in 
combustion residual leachate.
    (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, 2029. 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).
    (B) A facility which submits a request under Sec.  423.19(n) may 
discharge permeate or distillate from a combustion residual leachate 
treatment system designed to achieve the limitations in this paragraph 
(l)(1)(i) for an additional period of up to one year from the date 
determined in paragraph (l)(1)(i)(A) of this section.
    (C) After the retirement of all units at a facility, the quantity 
of pollutants in combustion residual leachate (CRL) shall not exceed 
the quantity determined by multiplying the flow of CRL permeate times 
the concentrations listed in the table 7 to paragraph (g)(3)(i) of this 
section or the flow of CRL distillate times the concentrations listed 
in the table following Sec.  423.15(b)(13).
    (ii) For combustion residual leachate generated before the date 
determined by the permitting authority, as specified in paragraph 
(l)(1)(i) of this section, the EPA is declining to establish BAT 
limitations and is reserving such limitations to be established by the 
permitting authority on a case-by-case basis using the permitting 
authority's best professional judgment.
    (2) 2024 BAT subcategories. (i) Discharges of combustion residual 
leachate for which the owner has submitted a certification pursuant to 
Sec.  423.19(h).
    (A) Where such unit has permanently ceased coal combustion by 
December 31, 2034, the quantity of pollutants in combustion residual 
leachate shall not exceed the quantity determined by multiplying the 
flow of combustion residual leachate times the concentration listed in 
table 11 to this paragraph (l)(2)(i)(A) by a date determined by the 
permitting authority that is as soon as possible beginning 120 days 
after the facility permanently ceases coal combustion, but no later 
than April 30, 2035.

                   Table 11 to paragraph (l)(2)(i)(A)
------------------------------------------------------------------------
                                             BAT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

    (B) Where such unit has failed to permanently cease coal combustion 
by December 31, 2034, there shall be no discharge of pollutants in 
combustion residual leachate after December 31, 2034.
    (ii) For discharges of unmanaged combustion residual leachate, the 
quantity of pollutants in unmanaged combustion residual leachate shall 
not exceed the quantity determined by multiplying the flow of unmanaged 
combustion residual leachate times the concentration listed in the 
table 11 to paragraph (l)(2)(i)(A) of this section.
    (A) Dischargers must meet the effluent limitations for unmanaged 
combustion residual leachate in this paragraph (l)(2)(ii) by a date 
determined by the permitting authority that is as soon as possible 
beginning July 8, 2024, but no later than December 31, 2029. The 
effluent limitations in this paragraph (l)(2)(ii) apply to the 
discharge of unmanaged 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)(2)(ii).
    (B) Discharges of unmanaged combustion residual leachate before the 
date determined in paragraph (l)(2)(ii)(A) of this section.
    (iii) For combustion residual leachate discharged from any coal 
combustion residual surface impoundment which commences closure 
pursuant to 40 CFR

[[Page 40299]]

257.102(e) after July 8, 2024, the quantity of pollutants in combustion 
residual leachate shall not exceed the quantity determined by 
multiplying the flow of combustion residual leachate times the 
concentration listed in table 12 to this paragraph (l)(2)(iii).

                    Table 12 to Paragraph (l)(2)(iii)
------------------------------------------------------------------------
                                             BAT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

* * * * *
    (o) Transfers. (1) Transfer between applicable limitations in a 
permit. Where, in the permit, the permitting authority has included 
alternative limits subject to eligibility requirements, upon timely 
notification to the permitting authority under Sec.  423.19(l), a 
facility can become subject to the alternative limits under the 
following circumstances:
    (i) On or before December 31, 2023, a facility may convert:
    (A) From limitations for electric generating units permanently 
ceasing coal combustion under paragraph (g)(2)(i) or (k)(2)(ii) of this 
section to limitations for low utilization electric generating units 
under paragraph (g)(2)(iii) or (k)(2)(iii) of this section; or
    (B) From voluntary incentives program limitations under paragraph 
(g)(3)(i) of this section or generally applicable limitations under 
paragraph (k)(1)(i) of this section to limitations for low utilization 
electric generating units under paragraph (g)(2)(iii) or (k)(2)(iii) of 
this section.
    (ii) On or before December 31, 2025, a facility may convert:
    (A) From voluntary incentives program limitations under paragraph 
(g)(3)(i) of this section to limitations for electric generating units 
permanently ceasing coal combustion under paragraph (g)(2)(i) of this 
section; or
    (B) From limitations for electric generating units permanently 
ceasing coal combustion under paragraph (g)(2)(i) or (k)(2)(ii) of this 
section to voluntary incentives program limitations under paragraph 
(g)(3)(i) of this section or generally applicable limitations under 
(k)(1)(i) of this section; or
    (C) From limitations for low utilization electric generating units 
under paragraph (g)(2)(iii) or (k)(2)(iii) of this section to generally 
applicable limitations under paragraph (g)(1)(i) or (k)(1)(i) of this 
section; or
    (D) From limitations for low utilization electric generating units 
under paragraph (g)(2)(iii) or (k)(2)(iii) of this section to voluntary 
incentives program limitations under paragraph (g)(3)(i) of this 
section or generally applicable limitations under paragraph (k)(1)(i) 
of this section; or
    (E) From limitations for low utilization electric generating units 
under paragraph (g)(2)(iii) or (k)(2)(iii) of this section to 
limitations for electric generating units permanently ceasing coal 
combustion under paragraph (g)(2)(i) and (k)(2)(ii) of this section.
    (2) A facility must be in compliance with all of its currently 
applicable requirements to be eligible to file a notice under Sec.  
423.19(l) and to become subject to a different set of applicable 
requirements under paragraph (o)(1) of this section.
    (3) Where a facility seeking a transfer under paragraph (o)(1)(ii) 
of this section is currently subject to more stringent limitations than 
the limitations being sought, the facility must continue to meet those 
more stringent limitations.
* * * * *

0
5. Amend Sec.  423.15 by adding paragraph (c) to read as follows:


Sec.  423.15  New source performance standards (NSPS).

* * * * *
    (c) 2024 NSPS for combustion residual leachate. (1) Except as 
provided in paragraph (c)(2) of this section, there shall be no 
discharge of pollutants in combustion residual leachate (CRL). Whenever 
CRL is used in any other plant process or is sent to a treatment system 
at the plant, the resulting effluent must comply with the discharge 
standard in this paragraph (c).
    (2) 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 
table 7 to Sec.  423.13(g)(3)(i) or the flow of CRL distillate times 
the concentrations listed in the table in paragraph (b)(13) of this 
section.
* * * * *

0
6. Amend Sec.  423.16 by revising paragraphs (e) and (g) and adding 
paragraph (j) to read as follows:


Sec.  423.16  Pretreatment standards for existing sources (PSES).

* * * * *
    (e) FGD wastewater--(1) 2020 PSES. Except as provided for in 
paragraph (e)(2) of this section, for any electric generating unit with 
a total nameplate generating capacity of more than 50 megawatts, that 
is not an oil-fired unit, and that the owner has not certified that it 
will cease coal combustion pursuant to Sec.  423.19(g), the quantity of 
pollutants in FGD wastewater shall not exceed the quantity determined 
by multiplying the flow of FGD wastewater times the concentration 
listed in table 3 to this paragraph (e)(1). Dischargers must meet the 
standards in this paragraph (e)(1) by October 13, 2023, except as 
provided for in paragraph (e)(2) of this section. The standards in this 
paragraph (e)(1) apply to the discharge of FGD wastewater generated on 
and after October 13, 2023.

[[Page 40300]]



                       Table 3 to Paragraph (e)(1)
------------------------------------------------------------------------
                                                       PSES
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              18               8
Mercury, total (ng/L)...................             103              34
Selenium, total ([micro]g/L)............              70              29
Nitrate/nitrite as N (mg/L).............               4               3
------------------------------------------------------------------------

    (2) 2020 PSES subcategories. (i) For FGD wastewater discharges from 
a low utilization electric generating unit, the quantity of pollutants 
in FGD wastewater shall not exceed the quantity determined by 
multiplying the flow of FGD wastewater times the concentration listed 
in the table 4 to paragraph (e)(2)(ii) of this section. Dischargers 
must meet the standards in this paragraph (e)(2)(i) by October 13, 
2023.
    (ii) If any low utilization electric generating unit fails to 
timely recertify that the two year average capacity utilization rating 
of such an electric generating unit is below 10 percent per year as 
specified in Sec.  423.19(f), regardless of the reason, within two 
years from the date such a recertification was required, the quantity 
of pollutants in FGD wastewater shall not exceed the quantity 
determined by multiplying the flow of FGD wastewater times the 
concentration listed in the table 3 to paragraph (e)(1) of this 
section.

                     Table 4 to Paragraph (e)(2)(ii)
------------------------------------------------------------------------
                                                       PSES
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

    (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, there shall be no discharge of pollutants in FGD 
wastewater. Dischargers must meet the standards in this paragraph 
(e)(3) by May 9, 2027, except as provided for in paragraph (e)(4) of 
this section. The standards in this paragraph (e)(3) apply to the 
discharge of FGD wastewater generated on and after May 9, 2027.
    (4) 2024 PSES subcategories. (i) For any electric generating unit 
for which the owner has submitted a certification pursuant to Sec.  
423.19(h), the quantity of pollutants discharged in FGD wastewater 
shall continue to be subject to standards specified in paragraph (e)(1) 
or (2) of this section as incorporated into the existing control 
mechanism.
    (A) Where such unit has permanently ceased coal combustion by 
December 31, 2034, there shall be no discharge of pollutants in FGD 
wastewater after April 30, 2035.
    (B) Where such unit has failed to permanently cease coal combustion 
by December 31, 2034, there shall be no discharge of pollutants in FGD 
wastewater after December 31, 2034.
    (ii) For FGD wastewater discharged from any coal combustion 
residual surface impoundment which commences closure pursuant to 40 CFR 
257.102(e) after July 8, 2024, the quantity of pollutants in FGD 
wastewater shall not exceed the quantity determined by multiplying the 
flow of FGD wastewater times the concentration listed in the table 5 to 
this paragraph (e)(4)(ii).

                     Table 5 to Paragraph (e)(4)(ii)
------------------------------------------------------------------------
                                                       PSES
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------


[[Page 40301]]

* * * * *
    (g) Bottom ash transport water--(1) 2020 PSES. Except for those 
discharges to which paragraph (g)(2) of this section applies, or when 
the bottom ash transport water is used in the FGD scrubber, for any 
electric generating unit with a total nameplate generating capacity of 
more than 50 megawatts, that is not an oil-fired unit, that is not a 
low utilization electric generating unit, and that the owner has not 
certified that the electric generating unit will cease coal combustion 
pursuant to Sec.  423.19(g), there shall be no discharge of pollutants 
in bottom ash transport water. The standard in this paragraph (g)(1) 
applies to the discharge of bottom ash transport water generated on and 
after October 13, 2023. Except for those discharges to which paragraph 
(g)(2) of this section applies, whenever bottom ash transport water is 
used in any other plant process or is sent to a treatment system at the 
plant (except when it is used in the FGD scrubber), the resulting 
effluent must comply with the discharge standard in this paragraph 
(g)(1). When the bottom ash transport water is used in the FGD 
scrubber, the quantity of pollutants in bottom ash transport water 
shall not exceed the quantity determined by multiplying the flow of 
bottom ash transport water times the concentration listed in table 3 to 
paragraph (e)(1) of this section.
    (2) 2020 PSES subcategories. (i) The discharge of pollutants in 
bottom ash transport water from a properly installed, operated, and 
maintained bottom ash system is authorized under the following 
conditions:
    (A) To maintain system water balance when precipitation-related 
inflows are generated from a 10-year storm event of 24-hour or longer 
duration (e.g., 30-day storm event) and cannot be managed by installed 
spares, redundancies, maintenance tanks, and other secondary bottom ash 
system equipment; or
    (B) To maintain system water balance when regular inflows from 
wastestreams other than bottom ash transport water exceed the ability 
of the bottom ash system to accept recycled water and segregating these 
other wastestreams is feasible; or
    (C) To maintain system water chemistry where current operations at 
the facility are unable to currently manage pH, corrosive substances, 
substances or conditions causing scaling, or fine particulates to below 
levels which impact system operation or maintenance; or
    (D) To conduct maintenance not otherwise included in paragraphs 
(g)(2)(i)(A), (B), or (C) of this section and not exempted from the 
definition of transport water in Sec.  423.11(p), and when water 
volumes cannot be managed by installed spares, redundancies, 
maintenance tanks, and other secondary bottom ash system equipment.
    (ii) The total volume that may be discharged to a POTW for the 
activities in paragraphs (g)(2)(i)(A) through (D) of this section shall 
be reduced or eliminated to the extent achievable as determined by the 
control authority. The control authority may also include control 
measures (including best management practices) that are technologically 
available and economically achievable in light of best industry 
practice. In no event shall the total volume of the discharge exceed a 
30-day rolling average of ten percent of the primary active wetted 
bottom ash system volume. The volume of daily discharges used to 
calculate the 30-day rolling average shall be calculated using 
measurements from flow monitors.
    (iii) For bottom ash transport water generated by a low utilization 
electric generating unit, the quantity of pollutants discharged in 
bottom ash transport water shall incorporate the elements of a best 
management practices plan as described in Sec.  423.13(k)(3).
    (3) 2024 PSES. Except for those discharges to which paragraph 
(g)(4) of this section applies, for any electric generating unit with a 
total nameplate generating capacity of more than 50 megawatts, that is 
not an oil-fired unit, there shall be no discharge of pollutants in 
bottom ash transport water. The standard in this paragraph (g)(3) 
applies to the discharge of bottom ash transport water generated on and 
after May 9, 2027. Except for those discharges to which paragraph 
(g)(4) of this section applies, whenever bottom ash transport water is 
used in any other plant process or is sent to a treatment system at the 
plant, the resulting effluent must comply with the discharge standard 
in this paragraph (g)(3).
    (4) 2024 PSES subcategories. (i) For any electric generating unit 
for which the owner has submitted a certification pursuant to Sec.  
423.19(h), the quantity of pollutants discharged in bottom ash 
transport water shall continue to be subject to standards specified in 
paragraph (g)(1) or (2) as incorporated into the existing control 
mechanism.
    (A) Where such unit has permanently ceased coal combustion by 
December 31, 2034, there shall be no discharge of pollutants in bottom 
ash transport water after April 30, 2035.
    (B) Where such unit has failed to permanently cease coal combustion 
by December 31, 2034, there shall be no discharge of pollutants in 
bottom ash transport water after December 31, 2034.
    (ii) For bottom ash transport water discharged from any coal 
combustion residual surface impoundment which commences closure 
pursuant to 40 CFR 257.102(e) after July 8, 2024, the quantity of 
pollutants in bottom ash transport water shall not exceed the quantity 
determined by multiplying the flow of bottom ash transport water times 
the concentration listed in table 6 to this paragraph (g)(4)(ii).

                     Table 6 to Paragraph (g)(4)(ii)
------------------------------------------------------------------------
                                                       PSES
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

* * * * *
    (j) Combustion residual leachate--(1) 2024 PSES. (i) Except for 
those discharges to which paragraph (j)(2) or (j)(1)(ii) of this 
section applies, there shall be no discharge of pollutants in 
combustion residual leachate. The standard in this paragraph (j)(1)(i) 
applies to the discharge of combustion residual leachate generated on 
and after May 9, 2027. Except for those discharges to which paragraph 
(j)(2) of this section

[[Page 40302]]

applies, whenever combustion residual leachate is used in any other 
plant process or is sent to a treatment system at the plant, the 
resulting effluent must comply with the discharge standard in this 
paragraph (j)(1)(i).
    (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).
    (2) 2024 PSES subcategories. (i) Except as described in paragraph 
(j)(2)(i)(A) of this section, the EPA is declining to establish PSES 
for electric generating units for which the owner has submitted a 
certification pursuant to Sec.  423.19(h) and is reserving such 
standards to be established by the control authority on a case-by-case.
    (A) Where such unit has permanently ceased coal combustion by 
December 31, 2034, the quantity of pollutants in combustion residual 
leachate shall not exceed the quantity determined by multiplying the 
flow of combustion residual leachate times the concentration listed in 
the table 7 to this paragraph (j)(2)(i)(A) no later than April 30, 
2035.

                    Table 7 to paragraph (j)(2)(i)(A)
------------------------------------------------------------------------
                                                       PSES
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

    (B) Where such unit has failed to permanently cease coal combustion 
by December 31, 2034, there shall be no discharge of pollutants in FGD 
wastewater after December 31, 2034.
    (ii) For combustion residual leachate discharged from any coal 
combustion residual surface impoundment which commences closure 
pursuant to 40 CFR 257.102(e) after July 8, 2024, the quantity of 
pollutants in combustion residual leachate shall not exceed the 
quantity determined by multiplying the flow of combustion residual 
leachate times the concentration listed in table 8 to this paragraph 
(j)(2)(ii).

                     Table 8 to Paragraph (j)(2)(ii)
------------------------------------------------------------------------
                                                       PSES
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                             any 1 day      consecutive
                                                          days shall not
                                                              exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L).............              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------


0
7. Amend Sec.  423.17 by adding paragraph (c) to read as follows:


Sec.  423.17  Pretreatment standards for new sources (PSNS).

* * * * *
    (c) 2024 PSNS for combustion residual leachate. (1) Except as 
provided in paragraph (c)(2) of this section, there shall be no 
discharge of pollutants in combustion residual leachate (CRL). Whenever 
CRL is used in any other plant process or is sent to a treatment system 
at the plant, the resulting effluent must comply with the discharge 
standard in this paragraph (c)(1).
    (2) 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 
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
8. Revise Sec.  423.18 to read as follows:


Sec.  423.18  Permit conditions.

    All permits subject to this part shall include the following permit 
conditions:
    (a) An electric generating unit shall qualify as a low utilization 
electric generating unit, permanently ceasing the combustion of coal by 
December 31, 2028, or permanently ceasing the combustion of coal by 
December 31, 2034, if such qualification would have been demonstrated 
absent the following qualifying event:
    (1) An emergency order issued by the Department of Energy under 
section 202(c) of the Federal Power Act;
    (2) A reliability must run agreement issued by a Public Utility 
Commission; or
    (3) Any other reliability-related order, energy emergency alert, or 
agreement issued by a competent electricity regulator (e.g., an 
independent system operator) which results in that electric generating 
unit operating in a way not contemplated when the certification was 
made; or
    (4) The operation of the electric generating unit was necessary for 
load balancing in an area subject to a declaration under 42 U.S.C. 5121 
et seq., that there exists:
    (i) An ``Emergency''; or
    (ii) A ``Major Disaster''; and
    (iii) That load balancing was due to the event that caused the 
``Emergency'' or ``Major Disaster'' in paragraphs

[[Page 40303]]

(a)(4)(i) and (ii) of this section to be declared.
    (b) Any facility providing the required documentation pursuant to 
Sec.  423.19(i) may avail itself of the protections of the permit 
condition in paragraph (a) of this section.
    (c) A facility discharging permeate or distillate from an FGD 
wastewater or combustion residual leachate treatment system and 
satisfying Sec.  423.19(n) shall be deemed to meet the following 
requirements:
    (1) The FGD wastewater requirements of Sec.  423.13(g)(4) for up to 
one year after the date determined pursuant to Sec.  423.11(t); and
    (2) The combustion residual leachate requirements of Sec.  
423.13(l)(1) for up to one year after the date determined pursuant to 
Sec.  423.11(t).

0
9. Revise and republish Sec.  423.19 to read as follows:


Sec.  423.19  Reporting and recordkeeping requirements.

    (a) In general. Discharges subject to this part must comply with 
the reporting requirements in this section.
    (b) Signature and certification. Unless otherwise provided in this 
section, all certifications and recertifications required in this part 
must be signed and certified pursuant to 40 CFR 122.22 for direct 
dischargers or 40 CFR 403.12(l) for indirect dischargers.
    (c) Publicly accessible internet site requirements. (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 (o) 
of this section must maintain a publicly accessible internet site (ELG 
website) containing the information specified in paragraphs (d) through 
(o), 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 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.
    (2)(i) When an owner or operator subject to this section already 
maintains a ``CCR Rule Compliance Data and Information'' website 
pursuant to 40 CFR 257.107, the postings required under this section 
may be made to the existing ``CCR Rule Compliance Data and 
Information'' website and shall be delineated under a separate heading 
that shall state ``ELG Rule Compliance Data and Information.'' When 
electing to use an existing website pursuant to this paragraph (c)(2), 
the facility shall notify EPA via the ``contact us'' form on EPA's 
Effluent Guidelines website and the permitting authority or control 
authority no later than July 8, 2024, or upon first becoming subject to 
paragraphs (d) through (o) of this section, whichever is later.
    (ii) When the same owner or operator is subject to the provisions 
of this part for multiple facilities, the owner or operator may comply 
with the requirements of this section by using the same internet site 
for multiple facilities provided the ELG website clearly delineates 
information by the name of each facility.
    (3) Unless otherwise required in this section, the information 
required to be posted to the ELG website must be made available to the 
public for at least 10 years following the date on which the 
information was first posted to the ELG website, or the length of the 
permit plus five years, whichever is longer. 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).
    (4) Unless otherwise required in this section, the information must 
be posted to the ELG website:
    (i) Within 30 days of submitting the information to the permitting 
authority or control authority; or
    (ii) Where information was submitted to the permitting authority or 
control authority prior to July 8, 2024, by July 8, 2024.
    (d) Requirements for facilities discharging bottom ash transport 
water under this part--(1) Certification statement. For sources seeking 
to discharge bottom ash transport water pursuant to Sec.  
423.13(k)(2)(i) or (g)(2)(i), an initial certification shall be 
submitted to the permitting authority by the as soon as possible date 
determined under Sec.  423.11(t), or the control authority by October 
13, 2023, in the case of an indirect discharger.
    (2) Signature and certification. The certification statement must 
be signed and certified by a professional engineer.
    (3) Contents. An initial certification shall include the following:
    (i) A statement that the professional engineer is a licensed 
professional engineer.
    (ii) A statement that the professional engineer is familiar with 
the requirements in this part.
    (iii) A statement that the professional engineer is familiar with 
the facility.
    (iv) The primary active wetted bottom ash system volume in Sec.  
423.11(aa).
    (v) Material assumptions, information, and calculations used by the 
certifying professional engineer to determine the primary active wetted 
bottom ash system volume.
    (vi) A list of all potential discharges under Sec.  
423.13(k)(2)(i)(A)(1) through (4) or Sec.  423.16(g)(2)(i)(A) through 
(D), the expected volume of each discharge, and the expected frequency 
of each discharge.
    (vii) Material assumptions, information, and calculations used by 
the certifying professional engineer to determine the expected volume 
and frequency of each discharge including a narrative discussion of why 
such water cannot be managed within the system and must be discharged.
    (viii) A list of all wastewater treatment systems at the facility 
currently, or otherwise required by a date certain under this section.
    (ix) A narrative discussion of each treatment system including the 
system type, design capacity, and current or expected operation.
    (e) Requirements for a bottom ash best management practices plan--
(1) Initial and annual certification statement. For sources required to 
develop and implement a best management practices plan pursuant to 
Sec.  423.13(k)(3), an initial certification shall be made to the 
permitting authority with a permit application or within two years of 
October 13, 2021, whichever is later, or to the control authority no 
later than October 13, 2023, in the case of an indirect discharger, and 
an annual recertification shall be made to the permitting authority, or 
control authority in the case of an indirect discharger, within 60 days 
of the anniversary of the original plan.
    (2) Signature and certification. The certification statement must 
be signed and certified by a professional engineer.
    (3) Contents for initial certification. An initial certification 
shall include the following:

[[Page 40304]]

    (i) A statement that the professional engineer is a licensed 
professional engineer.
    (ii) A statement that the professional engineer is familiar with 
the requirements in this part.
    (iii) A statement that the professional engineer is familiar with 
the facility.
    (iv) The best management practices plan.
    (v) A statement that the best management practices plan is being 
implemented.
    (4) Additional contents for annual certification. In addition to 
the required contents of the initial certification in paragraph (e)(3) 
of this section an annual certification shall include the following:
    (i) Any updates to the best management practices plan.
    (ii) An attachment of weekly flow measurements from the previous 
year.
    (iii) The average amount of recycled bottom ash transport water in 
gallons per day.
    (iv) Copies of inspection reports and a summary of preventative 
maintenance performed on the system.
    (v) A statement that the plan and corresponding flow records are 
being maintained at the office of the plant.
    (f) Requirements for low utilization electric generating units--(1) 
Notice of Planned Participation. For sources seeking to qualify as a 
low utilization electric generating units, a Notice of Planned 
Participation shall be submitted to the permitting authority or control 
authority no later than October 13, 2021.
    (2) Contents. A Notice of Planned Participation shall identify the 
potential low utilization electric generating unit. The notice shall 
also include a statement of at least two years' capacity utilization 
rating data for the most recent two years of operation of each low 
utilization electric generating unit and a statement that the facility 
has a good faith belief that each low utilization electric generating 
unit will continue to operate at the required capacity utilization 
rating. Where the most recent capacity utilization rating does not meet 
the low utilization electric generating unit requirement, a discussion 
of the projected future utilization shall be provided, including 
material data and assumptions used to make that projection.
    (3) Initial and annual certification statement. For sources seeking 
to qualify as a low utilization electric generating unit under this 
part, an initial certification shall be made to the permitting 
authority, or to the control authority in the case of an indirect 
discharger, no later than December 31, 2023, and an annual 
recertification shall be made to the permitting authority, or control 
authority in the case of an indirect discharger, within 60 days of 
submitting annual electricity production data to the Energy Information 
Administration.
    (4) Contents. A certification or annual recertification shall be 
based on the information submitted to the Energy Information 
Administration and shall include copies of the underlying forms 
submitted to the Energy Information Administration, as well as any 
supplemental information and calculations used to determine the two 
year average annual capacity utilization rating.
    (g) Requirements for units that will achieve permanent cessation of 
coal combustion by December 31, 2028--(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, 2028, 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 June 27, 2023.
    (2) Contents. A Notice of Planned Participation shall identify the 
electric generating units intended to achieve the permanent cessation 
of coal combustion. A Notice of Planned Participation shall include the 
expected date that each electric generating unit is projected to 
achieve permanent cessation of coal combustion, whether each date 
represents a retirement or a fuel conversion, whether each retirement 
or fuel conversion has been approved by a regulatory body, and what the 
relevant regulatory body is. The Notice of Planned Participation shall 
also include a copy of the most recent integrated resource plan for 
which the applicable state agency approved the retirement or repowering 
of the unit subject to the ELGs, certification of electric generating 
unit cessation under 40 CFR 257.103(b), or other documentation 
supporting that the electric generating unit will permanently cease the 
combustion of coal by December 31, 2028. The Notice of Planned 
Participation shall also include, for each such electric generating 
unit, a timeline to achieve the permanent cessation of coal combustion. 
Each timeline shall include interim milestones and the projected dates 
of completion.
    (3) Annual progress report. Annually after submission of the Notice 
of Planned Participation in paragraph (g)(1) of this section, a 
progress report shall be filed with the permitting authority, or 
control authority in the case of an indirect discharger.
    (4) Contents. An annual progress report shall detail the completion 
of any interim milestones listed in the Notice of Planned Participation 
since the previous progress report, provide a narrative discussion of 
any completed, missed, or delayed milestones, and provide updated 
milestones. An annual progress report shall also include one of the 
following:
    (i) A copy of the official suspension filing (or equivalent filing) 
made to the facility's reliability authority detailing the conversion 
to a fuel source other than coal;
    (ii) A copy of the official retirement filing (or equivalent 
filing) made to the facility's reliability authority which must include 
a waiver of recission rights; or
    (iii) An initial certification, or recertification for subsequent 
annual progress reports, containing either a statement that the 
facility will make the filing required in paragraph (g)(4)(i) of this 
section or a statement that the facility will make the filing required 
in paragraph (g)(4)(ii) of this section. The certification or 
recertification must include the estimated date that such a filing will 
be made.
    (iv) A facility shall not include a certification or 
recertification under paragraph (g)(4)(iii) of this section in the 
final annual progress report submitted prior to permanent cessation of 
coal combustion. Rather, this final annual progress report must include 
the filing under paragraph (g)(4)(i) or (ii) of this section.
    (h) Requirements for units that will achieve permanent cessation of 
coal combustion by December 31, 2034--(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, 2025.
    (2) Contents. A Notice of Planned Participation shall identify the 
electric generating units intended to achieve the permanent cessation 
of coal combustion. A Notice of Planned Participation shall include the 
expected date that each electric generating unit is projected to 
achieve permanent cessation of coal combustion, whether each date 
represents a retirement or a fuel conversion, whether each retirement 
or fuel conversion has been approved by a regulatory body, and what the 
relevant regulatory body is.

[[Page 40305]]

The Notice of Planned Participation shall also include a copy of the 
most recent integrated resource plan for which the applicable state 
agency approved the retirement or repowering of the unit subject to the 
ELGs, or other documentation supporting that the electric generating 
unit will permanently cease the combustion of coal by December 31, 
2034. The Notice of Planned Participation shall also include, for each 
such electric generating unit, a timeline to achieve the permanent 
cessation of coal combustion. Each timeline shall include interim 
milestones and the projected dates of completion. Finally, the Notice 
of Planned Participation shall also include, for each such electric 
generating unit, a certification statement that the facility is in 
compliance with the following limitations or standards:
    (i) The applicable limitations or standards for FGD wastewater in 
Sec.  423.13(g)(1) or (g)(2)(ii) or (iii) or Sec.  423.16(e)(1) or (2); 
and
    (ii) The applicable limitations or standards for bottom ash 
transport water in Sec.  423.13(k)(1) or (k)(2)(i) or (iii) or Sec.  
423.16(g)(1) or (2).
    (3) Annual progress report. Annually after submission of the Notice 
of Planned Participation in paragraph (h)(1) of this section, a 
progress report shall be filed with the permitting authority, or 
control authority in the case of an indirect discharger.
    (4) Contents. An annual progress report shall detail the completion 
of any interim milestones listed in the Notice of Planned Participation 
since the previous progress report, provide a narrative discussion of 
any completed, missed, or delayed milestones, and provide updated 
milestones. An annual progress report shall also include one of the 
following:
    (i) A copy of the official suspension filing (or equivalent filing) 
made to the facility's reliability authority detailing the conversion 
to a fuel source other than coal;
    (ii) A copy of the official retirement filing (or equivalent 
filing) made to the facility's reliability authority which must include 
a waiver of recission rights; or
    (iii) An initial certification, or recertification for subsequent 
annual progress reports, containing either a statement that the 
facility will make the filing required in paragraph (h)(4)(i) of this 
section or a statement that the facility will make the filing required 
in paragraph (h)(4)(ii) of this section. The certification or 
recertification must include the estimated date that such a filing will 
be made.
    (iv) A facility shall not include a certification or 
recertification under paragraph (h)(4)(iii) of this section in the 
final annual progress report submitted prior to permanent cessation of 
coal combustion. Rather, this final annual progress report must include 
the filing under paragraph (h)(4)(i) or (ii) of this section.
    (i) Requirements for facilities seeking protections under this 
part--(1) Certification statement. For sources seeking to apply the 
protections of the permit conditions in Sec.  423.18(a), and for each 
instance that Sec.  423.18(a) is applied, a one-time certification 
shall be submitted to the permitting authority, or control authority in 
the case of an indirect discharger, no later than:
    (i) In the case of an order or agreement under Sec.  423.18(a)(1), 
30 days from receipt of the order or agreement attached pursuant to 
paragraph (i)(2)(ii) of this section; or
    (ii) In the case of an ``Emergency'' or ``Major Disaster'' under 
Sec.  423.18(a)(2), 30 days from the date that a load balancing need 
arose.
    (2) Contents. A certification statement must include the following:
    (i) The qualifying event from the list in Sec.  423.18(a), the 
individual or entity that issued or triggered the event, and the date 
that such an event was issued or triggered.
    (ii) A copy of any documentation of the qualifying event from the 
individual or entity listed under paragraph (i)(2)(i) of this section, 
or, where such documentation does not exist, other documentation with 
indicia of reliability for the permitting authority to confirm the 
qualifying event.
    (iii) An analysis and accompanying narrative discussion which 
demonstrates that an electric generating unit would have qualified for 
the subcategory at issue absent the event detailed in paragraph 
(i)(2)(i) of this section, including the material data, assumptions, 
and methods used.
    (3) Termination of need statement. For sources filing a 
certification statement under paragraph (i)(1) of this section, and for 
each such certification statement, a one-time termination of need 
statement shall be submitted to the permitting authority, or control 
authority in the case of an indirect discharger, no later than 30 days 
from when the source is no longer subject to increased production from 
the qualifying event.
    (4) Contents. A termination of need statement must include a 
narrative discussion including the date the qualifying event 
terminated, or if it has not terminated, why the source believes the 
capacity utilization will no longer be elevated to a level requiring 
the protection of Sec.  423.18.
    (j) Requirements for facilities voluntarily meeting limits in this 
part--(1) Notice of Planned Participation. For sources opting to comply 
with the Voluntary Incentives Program requirements of Sec.  
423.13(g)(3)(i) by December 31, 2028, a Notice of Planned Participation 
shall be made to the permitting authority no later than October 13, 
2021.
    (2) Contents. A Notice of Planned Participation shall identify the 
facility opting to comply with the Voluntary Incentives Program 
requirements of Sec.  423.13(g)(3)(i), specify what technology or 
technologies are projected to be used to comply with those 
requirements, and provide a detailed engineering dependency chart and 
accompanying narrative demonstrating when and how the system(s) and any 
accompanying disposal requirements will be achieved by December 31, 
2028.
    (3) Annual progress report. After submission of the Notice of 
Planned Participation in paragraph (j)(1) of this section, a progress 
report shall be filed with the permitting authority, or control 
authority in the case of an indirect discharger.
    (4) Contents. An annual progress report shall detail the completion 
of interim milestones presented in the engineering dependency chart 
from the Notice of Planned Participation since the previous progress 
report, provide a narrative discussion of completed, missed, or delayed 
milestones, and provide updated milestones.
    (5) Rollover certification. Where, prior to October 13, 2020, a 
discharger has already provided a notice to the permitting authority of 
opting to comply with the Voluntary Incentives Program requirements of 
Sec.  423.13(g)(3)(i), such notice will satisfy paragraph (j)(1) of 
this section. However, where details required by paragraph (j)(2) of 
this section were missing from the previously provided notice, those 
details must be provided in the first annual progress report, no later 
than October 13, 2021.
    (k) Requirements for facilities with discharges of unmanaged 
combustion residual leachate--(1) Annual combustion residual leachate 
monitoring report. In addition to reporting pursuant to 40 CFR part 
127, each facility with discharges of unmanaged combustion residual 
leachate meeting the definition in Sec.  423.11(ff)(1) shall file an 
annual combustion residual leachate monitoring report each calendar 
year to the permitting authority.

[[Page 40306]]

    (2) Contents. The annual combustion residual leachate monitoring 
report shall provide the following monitoring data for each pollutant 
listed in table 1 to paragraph (k)(2)(v) of this section. For 
paragraphs (k)(2)(ii) and (iii) of this section the report shall also 
describe the location of monitoring wells, screening depth, and 
frequency of sampling. The report shall include summary statistics 
including monthly minimum, maximum, and average concentrations for each 
pollutant. The report shall be supported by an appendix of all samples.
    (i) A list of coal combustion residual landfills and surface 
impoundments which the permitting authority has determined are point 
sources with functional equivalent direct discharges.
    (ii) Groundwater monitoring data as the combustion residual 
leachate leaves each of the landfills or surface impoundment listed in 
paragraph (k)(2)(i) of this section.
    (iii) Groundwater monitoring at the point the combustion residual 
leachate enters a surface waterbody.
    (iv) Effluent monitoring data reported pursuant to 40 CFR part 127.
    (v) Summary statistics for the data described in paragraphs 
(k)(2)(ii) through (iv) of this section including the monthly average 
and daily maximum of each pollutant in the table 1 to this paragraph 
(k)(2)(v) and a comparison to any limitation in Sec.  423.13(l)(2)(ii).

                     Table 1 to Paragraph (k)(2)(v)
------------------------------------------------------------------------
 
------------------------------------------------------------------------
         BAT Treated Pollutants in Combustion Residual Leachate
------------------------------------------------------------------------
Antimony                             Magnesium
Arsenic                              Manganese
Barium                               Mercury
Beryllium                            Molybdenum
Cadmium                              Nickel
Chromium                             Thallium
Cobalt                               Titanium
Copper                               Vanadium
Lead                                 Zinc
------------------------------------------------------------------------

    (l) Requirements for facilities seeking to transfer between 
applicable limitations in a permit under this part--(1) Notice of 
Planned Participation. For sources which have filed a Notice of Planned 
Participation under paragraph (f)(1), (g)(1), or (j)(1) of this section 
and 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).
    (2) Contents. A Notice of Planned Participation shall include a 
list of the electric generating units for which the source intends to 
change compliance alternatives. For each such electric generating unit, 
the notice shall list the specific provision under which this transfer 
will occur, the reason such a transfer is warranted, and a narrative 
discussion demonstrating that each electric generating unit will be 
able to maintain compliance with the relevant provisions.
    (m) Notice of material delay--(1) Notice. Within 30 days of 
experiencing a material delay in the milestones set forth in paragraph 
(g)(2), (h)(2), or (j)(2) of this section and where such a delay may 
preclude permanent cessation of coal combustion or compliance with the 
voluntary incentives program limitations by December 31, 2028, a 
facility shall file a notice of material delay with the permitting 
authority, or control authority in the case of an indirect discharger.
    (2) Contents. The contents of such a notice shall include the 
reason for the delay, the projected length of the delay, and a proposed 
resolution to maintain compliance.
    (n) Requirements for facilities seeking a one-year flexibility to 
discharge permeate or distillate from an FGD wastewater or combustion 
residual leachate treatment system designed to achieve limitations in 
this part--(1) Initial request letter. When filing a permit application 
or permit modification request, a facility seeking to discharge 
permeate or distillate during the first year of operations after the 
date determined in Sec.  423.13(g)(4)(i)(A) or (l)(1)(i)(A) shall 
include a letter requesting this flexibility from the permitting 
authority. The initial request letter shall detail the expected type, 
frequency, duration, and necessity of discharge. The initial request 
letter shall also state that this period of discharge was not included 
for consideration in establishing the applicability timing under Sec.  
423.11(t)(3).
    (2) Discharge monitoring and reporting. Upon inclusion in the 
permit of the flexibility to discharge the permeate or distillate as 
requested in paragraph (n)(1) of this section, the permitting authority 
shall also extend any existing monitoring and reporting requirements 
(e.g., arsenic monitoring).
    (o) Certification for wastewater generated by a 10-year, 24-hour or 
longer duration storm event--(1) Storm Event Discharge Certification 
Statement. For sources seeking to discharge low volume wastewater which 
would otherwise be considered FGD wastewater, bottom ash transport 
water, or combustion residual leachate but for a storm event exceeding 
a 10-year, 24-hour or longer duration storm event, a Storm Event 
Discharge Certification Statement shall be submitted to the permitting 
authority, or control authority in the case of an indirect discharger, 
no later than five business days from the last discharge.
    (2) Signature and certification. The certification statement must 
be signed and certified by a professional engineer.
    (3) Contents. A Storm Event Discharge Certification shall include 
the following:
    (i) A statement that the professional engineer is a licensed 
professional engineer.
    (ii) A statement that the professional engineer is familiar with 
the requirements in this part.
    (iii) A statement that the professional engineer is familiar with 
the facility.
    (iv) A statement that the facility experienced a storm event 
exceeding a 10-year, 24-hour or longer duration, including specifics of 
the actual storm event that are sufficient for a third party to verify 
the accuracy of the statement.
    (v) A statement that a discharge of low volume wastewater that 
would otherwise meet the definition of FGD wastewater, bottom ash 
transport water, or combustion residual leachate was necessary, 
including a list of the best management practices at the site and a 
narrative discussion of the ability of on-site equipment and practices 
to manage the wastewater.
    (vi) The duration and volume of any such discharge.
    (vii) A statement that the discharge does not otherwise violate any 
other limitation or permit condition.

[FR Doc. 2024-09185 Filed 5-8-24; 8:45 am]
BILLING CODE 6560-50-P