Document ID: EPA-HQ-OW-2009-0819-8491
Agency: epa
Document Type: Rule
Title: Steam Electric Reconsideration Rule
Posted Date: 2020-10-13T04:00Z

[Federal Register Volume 85, Number 198 (Tuesday, October 13, 2020)]
[Rules and Regulations]
[Pages 64650-64723]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-19542]

[[Page 64649]]

Vol. 85

Tuesday,

No. 198

October 13, 2020

Part III

Environmental Protection Agency

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40 CFR Part 423

Steam Electric Reconsideration Rule; Final Rule

  Federal Register / Vol. 85 , No. 198 / Tuesday, October 13, 2020 / 
Rules and Regulations  

[[Page 64650]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 423

[EPA-HQ-OW-2009-0819; FRL-10014-41-OW]
RIN 2040-AF77

Steam Electric Reconsideration Rule

AGENCY: Environmental Protection Agency.

ACTION: Final rule.

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SUMMARY: The Environmental Protection Agency (EPA or the Agency) is 
finalizing a 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 and bottom ash (BA) transport water. 
This final regulation is estimated to save approximately $140 million 
annually in after tax compliance costs as a result of less costly FGD 
wastewater technologies that could be used with the modification of the 
Steam Electric Power Generating Effluent Guidelines 2015 rule (the 2015 
rule) limitations; less costly BA transport water technologies made 
possible by the revision of the 2015 rule's zero discharge limitations; 
a two-year extension of compliance time frames for meeting FGD 
wastewater and BA transport water limitations, and additional 
subcategories for both FGD wastewater and BA transport water. 
Participation in the voluntary incentive program would contribute to 
the reduction in pollutant discharges by these steam electric power 
plants in FGD wastewater by approximately 26.7 million pounds per year.

DATES: This final rule is effective on December 14, 2020. In accordance 
with 40 CFR part 23, this regulation shall be considered issued for 
purposes of judicial review at 1:00 p.m. Eastern time on October 27, 
2020. Under section 509(b)(1) of the CWA, judicial review of this 
regulation can be had only by filing a petition for review in the U.S. 
Court of Appeals within 120 days after the regulation is considered 
issued for purposes of judicial review. Under section 509(b)(2), the 
requirements in this regulation may not be challenged later in civil or 
criminal proceedings brought by EPA to enforce these requirements.

ADDRESSES: 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 
http://www.regulations.gov website. Although listed in the index, some 
information is not publicly available, e.g., Confidential Business 
Information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the internet and will be publicly available only in hard 
copy form. Publicly available docket materials are available 
electronically through http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT: For technical information, contact 
Richard Benware, Engineering and Analysis Division, Telephone: 202-566-
1369; Email: benware.richard@epa.gov. For economic information, contact 
James Covington, Engineering and Analysis Division, Telephone: 202-566-
1034; Email: covington.james@epa.gov.

SUPPLEMENTARY INFORMATION: 
    Preamble Acronyms and Abbreviations. We use multiple acronyms and 
terms in this preamble. While this list may not be exhaustive, to ease 
the reading of this preamble and for reference purposes, EPA defines 
terms and acronyms in Appendix A.
    Supporting Documentation. Today's final rule is supported by 
numerous documents including:
     Supplemental Technical Development Document for Revisions 
to the Effluent Limitations Guidelines and Standards for the Steam 
Electric Power Generating Point Source Category (Supplemental TDD), 
Document No. EPA-821-R-20-001. The Supplemental TDD summarizes the 
technical and engineering analyses supporting the final rule. It 
presents EPA's updated analyses supporting the revisions to FGD 
wastewater and BA transport water. These updates include additional 
data collected since the signature of the 2015 rule, updates to the 
industry (e.g., retirements, updates to FGD treatment and BA handling), 
cost methodologies, pollutant removal estimates, corresponding non-
water quality environmental impacts associated with updated FGD and BA 
methodologies, and explanations of the calculations of the effluent 
limitations and standards. Except for the updates described in the 
Supplemental 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) is still applicable and provides a more complete summary of EPA's 
data collection, description of the industry, and underlying analyses 
supporting the ELGs established for other wastestreams in the 2015 
rule.
     Supplemental Environmental Assessment for Revisions to the 
Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category (Supplemental EA), Document No. 
EPA-821-R-20-002. The Supplemental EA summarizes the potential 
environmental and human health impacts that are estimated to result 
from implementation of this final rule.
     Benefit and Cost Analysis for Revisions to the Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category (BCA Report), Document No. EPA-821-R-
20-003. The BCA Report summarizes estimates of the societal benefits 
and costs resulting from implementation of this final rule.
     Regulatory Impact Analysis for Revisions to the Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category (RIA), Document No. EPA-821-R-20-004. 
The RIA presents a profile of the steam electric power generating 
industry, a summary of estimated costs and impacts associated with this 
final rule, and an assessment of the potential impacts on employment 
and small businesses.
     Response to Public Comments for Revisions to the Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category. This document provides EPA's 
responses to substantive public comments received on the 2019 proposed 
rule.
     Docket Index for the Revisions to the Steam Electric ELGs. 
This document provides a list of the additional memoranda, references, 
and other information relied upon by EPA for this final rule.
    Organization of this Document. The information in this preamble is 
organized as follows:

I. Executive Summary
II. Public Comments and Online Public Hearing
III. General Information
    A. Does this action apply to me?
    B. What action is 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 (CWA)
    B. Relevant Effluent Guidelines
    1. Best Practicable Control Technology Currently Available (BPT)
    2. Best Available Technology Economically Achievable (BAT)
    3. Pretreatment Standards for Existing Sources (PSES)
    C. 2015 Steam Electric Power Generation Point Source Category 
Rule

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    D. Legal Challenges, Administrative Petitions, Section 705 
Action, Postponement Rule, and Reconsideration of Certain 
Limitations and Standards
    E. Other Ongoing Rules Affecting the Steam Electric Sector
    1. Affordable Clean Energy (ACE) Rule
    2. Coal Combustion Residuals (CCR)
    F. Scope of the Final Rule
V. Steam Electric Power Generating Industry Description
    A. General Description of Industry
    B. Current Market Conditions in the Electricity Generation 
Sector
    C. Control and Treatment Technologies
    1. FGD Wastewater
    2. BA Transport Water
VI. Data Collection Since the 2015 Rule
    A. Information From the Electric Utility Industry
    1. Engineering Site Visits
    2. Data Requests, Responses, and Meetings
    3. Voluntary BA Transport Water Sampling
    4. Electric Power Research Institute (EPRI) Voluntary Submission
    5. Meetings With Trade Associations
    B. Information From the Drinking Water Utility Industry and 
States
    C. Information From Technology Vendors and Engineering, 
Procurement, and Construction (EPC) Firms
    D. Other Data Sources
VII. Final Regulation
    A. Description of the Main BAT/PSES Options
    1. FGD Wastewater
    2. BA Transport Water
    B. Rationale for the Final BAT
    1. FGD Wastewater
    2. BA Transport Water
    3. Voluntary Incentives Program (VIP)
    C. Additional Subcategories
    1. Plants With High FGD Flows
    2. Low Utilization EGUs
    3. EGUs Permanently Ceasing Coal Combustion by 2028
    D. Availability Timing of New Requirements
    E. Additional Rationale for the Final PSES
    F. Economic Achievability
    G. Non-Water Quality Environmental Impacts
    H. Impacts on Residential Electricity Prices and Low-Income and 
Minority Populations
VIII. Costs, Economic Achievability, and Other Economic Impacts
    A. Plant-Specific and Industry Total Costs
    B. Social Costs
    C. Economic Impacts
    1. Screening-Level Assessment
    a. Plant-Level Cost-to-Revenue Analysis
    b. Parent Entity-Level Cost-to-Revenue Analysis
    2. Electricity Market Impacts
    a. Impacts on Existing Steam Electric Power Plants
    b. Impacts on Individual Plants Incurring Costs
IX. Pollutant Loadings
    A. FGD Wastewater
    B. BA Transport Water
    C. Summary of Incremental Changes of Pollutant Loadings From 
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
    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
    1. Changes in Human Health Effects From Surface Water Quality 
Changes
    2. Ecological Condition and Recreational Use Effects From 
Changes in Surface Water Quality
    3. Effects on Threatened and Endangered Species
    4. Changes in Ability To Market Coal Combustion Byproducts
    5. Changes in Dredging Costs
    6. Changes in Air Quality-Related Effects
    7. Changes in Water Withdrawals
    C. Total Monetized Benefits
    D. Unmonetized Benefits
XIII. Development of Effluent Limitations and Standards
    A. FGD Wastewater
    1. Overview of the Limitations and Standards
    2. Criteria Used to Select Data
    3. Data Used to Calculate Limitations and Standards
    4. Long-Term Averages and Effluent Limitations and Standards for 
FGD Wastewater
    B. BA Transport Water Limitations
    1. Maximum 10 Percent 30-Day Rolling Average Purge Rate
    2. Best Management Practices Plan
XIV. Regulatory Implementation
    A. Implementation of the Limitations and Standards
    1. Timing
    3. Implementation for the Low Utilization Subcategory
    4. Transitioning Between Limitations
    5. Addressing Unexpected Changes in Generation
    a. Involuntary Retirement Delays
    b. Emergencies and Major Disasters Under the Stafford Act
    c. Voluntary Retirement Withdrawals and Delays
    B. Reporting and Recordkeeping Requirements
    C. Site-Specific Water Quality-Based Effluent Limitations
XV. Related Acts of Congress, Executive Orders, and Agency 
Initiatives
    A. Executive Orders 12866 (Regulatory Planning and Review) and 
13563 (Improving Regulation and Regulatory Review)
    B. Executive Order 13771 (Reducing Regulation and Controlling 
Regulatory Costs)
    C. Paperwork Reduction Act
    D. Regulatory Flexibility Act
    E. Unfunded Mandates Reform Act
    F. Executive Order 13132: Federalism
    G. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    H. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    I. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    J. National Technology Transfer and Advancement Act
    K. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    L. Congressional Review Act (CRA)
Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations 
Used in This Preamble

I. Executive Summary

A. Purpose of Rule

    Coal-fired plants are affected by several environmental 
regulations. One of these regulations, the Steam Electric Power 
Generating ELGs, was promulgated in 2015 (80 FR 67838; November 3, 
2015) and applies to the subset of the electric power industry in which 
``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, 
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 CFR 423.10). The 
2015 rule addressed discharges from FGD wastewater, fly ash (FA) 
transport water, BA transport water, flue gas mercury control 
wastewater, gasification wastewater, combustion residual leachate, and 
non-chemical metal cleaning wastes.
    Since the Steam Electric Power Generating ELGs were revised in 
2015, steam electric power plants have installed more affordable 
technologies that can remove similar amounts of pollution as those 
operating in 2015. This final rule revises limitations and standards 
for two of the wastestreams addressed in the 2015 rule: BA transport 
water and FGD wastewater. Today's rule does not revise the other 
wastestreams covered by the 2015 rule.

B. Summary of Final Rule

    For existing sources that discharge directly to surface water, with 
the subcategories discussed below excepted, the final rule establishes 
the following effluent limitations based on Best Available Technology 
Economically Achievable (BAT):
     For FGD wastewater, the final rule establishes numeric BAT 
effluent limitations on mercury, arsenic,

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selenium, and nitrate/nitrite as nitrogen.\1\
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    \1\ While the proposed rule described ``two sets'' of BAT 
limitations for both FGD wastewater and BA transport water, this 
rulemaking has been focused on revisions to the 2015 rule 
limitations and standards that were new and more stringent than 
previously established BPT limitations and standards (the ``second 
set'' of limitations). It was not intended to address the TSS BAT 
limitations for these wastestreams promulgated in the 2015 rule (the 
``first set'' of limitations), which have since been vacated by the 
U.S. Court of Appeals for the Fifth Circuit, see Section IV.D, 
below.
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     For BA transport water, the final rules establishes as BAT 
a high recycle rate system with a site-specific volumetric purge 
(defined in the final rule as BA purge water) which cannot exceed 10 
percent of the BA transport water system's volume where the purge 
volume and associated effluent limitations are established by the 
permitting authority.
    The final rule includes separate requirements for the following 
subcategories: High FGD flow plants, electric generating units (EGUs) 
that will permanently cease the combustion of coal by 2028, and low 
utilization EGUs (LUEGUs). The 2015 rule's subcategories for oil-fired 
EGUs and small generating units (50 MW or less) were not reopened in 
this rulemaking and remain in effect. For high FGD flow plants (FGD 
wastewater flows over four million gallons per day, after accounting 
for the plant's ability to recycle the wastewater to the maximum limits 
of the FGD system's materials of construction) and LUEGUs (those with a 
capacity utilization rating (CUR) of less than 10 percent), the final 
rule establishes BAT limitations in the discharged FGD wastewater as 
numeric effluent limitations on mercury and arsenic. For LUEGUs, the 
final rule establishes BAT limitations for BA transport water for total 
suspended solids (TSS) and also includes standards for implementing a 
best management practices (BMP) plan. For EGUs permanently ceasing the 
combustion of coal by 2028, the final rule establishes BAT limitations 
for total suspended solids (TSS) in FGD wastewater and bottom ash 
transport water.
    The final rule establishes a voluntary incentives program that 
provides the certainty of more time (until December 31, 2028) for 
plants to meet new standards and limitations, if they adopt additional 
process changes and controls that achieve more stringent limitations on 
mercury, arsenic, selenium, nitrate/nitrite, bromide, and TSS in FGD 
wastewater. The optional program offers environmental protections 
beyond those achieved by the final BAT limitations, while providing 
plants that opt into the program more flexibility when permeate or 
distillate is used as boiler makeup water, and additional time to meet 
the limitations established for BAT in this final rule.
    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 for TSS, there is no pass through of pollutants at 
POTWs.
    Where BAT limitations in this rule are more stringent than 
previously established BPT limitations applicable to the relevant 
wastestreams, those limitations do not apply until the permitting 
authority determines a date that is as soon as possible on or after 
October 13, 2021, but no later than December 31, 2025.

C. Summary of Costs and Benefits

    EPA estimates that the final rule will save $127 million per year 
in social costs and result in between $-1.7 million and $43 million in 
benefits, using a three percent discount rate, and will save $153 
million per year in social costs and between $6.5 million and $46 
million in benefits, using a seven percent discount. Table XV-1 
summarizes the benefits and social costs for the four regulatory 
options that EPA analyzed at a three percent discount rate. 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. EPA based its analysis on a modeled 
baseline that reflects the expected effects of announced retirements 
and fuel conversions, impacts of relevant final rules such as the Coal 
Combustion Residuals (CCR) Part A final rule that the Agency 
promulgated in August 2020 and the Affordable Clean Energy (ACE) rule 
that the Agency promulgated in 2019, and full implementation of the 
2015 rule. EPA has also provided an assessment of the economic impacts 
of the final revised Steam Electric ELGs relative to an alternative 
baseline including the CCR Part B Rule, which EPA is working on but 
which has not been issued at this time (see DCN SE09360). EPA 
understands that these modeled results have uncertainty and that the 
actual costs for individual plants could be higher or lower than 
estimated. The current estimate reflects the best data and analysis 
available at this time. For additional information, see Sections V and 
VIII.

II. Public Comments and Online Public Hearing

    During the 60-day public comment period for the 2019 proposed rule 
(November 22, 2019 to January 21, 2020), EPA received more than 7,400 
public comment submissions from private citizens, industry members, 
technology vendors, government entities, environmental groups, and 
trade associations. EPA also hosted an online public hearing on 
December 19, 2019 (during the public comment period). The hearing had 
110 attendees, 32 of whom spoke about the proposed rule. Available 
documents from the public hearing include the presentation given by EPA 
and a transcript (DCN SE08497 and DCN SE08498).

III. General Information

A. Does this action apply to me?

    Entities potentially regulated by the final rule include:

------------------------------------------------------------------------
                                                          North American
                                                             industry
            Category               Example of regulated   classification
                                          entity          system (NAICS)
                                                               code
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Industry.......................  Electric Power                    22111
                                  Generation Plants--
                                  Electric Power
                                  Generation.
                                 Electric Power                   221112
                                  Generation Plants--
                                  Fossil Fuel Electric
                                  Power Generation.
------------------------------------------------------------------------

    This section is not intended to be exhaustive, but to provide a 
guide to entities likely to be regulated by the final rule. Other types 
of entities that do not meet the above criteria could also be 
regulated. To determine whether your plant is regulated by the final 
rule, you should carefully examine the applicability criteria listed in 
40 CFR

[[Page 64653]]

423.10 and the definitions in 40 CFR 423.11 of the 2015 rule, as 
amended by this final rule. If you still have questions regarding the 
applicability of the final rule to a particular entity, consult the 
person listed for technical information in the preceding section, 
titled FOR FURTHER INFORMATION CONTACT.

B. What action is EPA taking?

    EPA is revising certain BAT ELGs and pretreatment standards for 
existing sources in the Steam Electric Power Generating point source 
category that apply to FGD wastewater and BA transport water.

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

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

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

    This action is estimated to save $127 million per year in social 
costs and result in between -$1.7 million and $43 million in benefits, 
using a 3 percent discount rate. Using a 7 percent discount rate, the 
estimated savings are $153 million per year and benefits are between 
$6.5 million and $46 million.

IV. Background

A. Clean Water Act (CWA)

    Among its core provisions, the CWA prohibits the discharge of 
pollutants from a point source to waters of the U.S., except as 
authorized under the CWA. Under section 402 of the CWA, 33 U.S.C. 1342, 
discharges may be authorized through a National Pollutant Discharge 
Elimination System (NPDES) permit. The CWA establishes a dual approach 
for these permits: (1) Technology-based controls that establish a floor 
of performance for all dischargers, and (2) water quality-based 
effluent limitations, where the technology-based effluent limitations 
are insufficient to meet applicable water quality standards (WQS). As 
the basis for the technology-based controls, the CWA authorizes EPA to 
establish national technology-based ELGs and new source performance 
standards (NSPS) for discharges into waters of the United States from 
categories of point sources (such as industrial, commercial, and public 
sources).
    The CWA also authorizes EPA to promulgate nationally applicable 
pretreatment standards that control pollutant discharges from sources 
that discharge wastewater indirectly to waters of the U.S., through 
sewers flowing to POTWs, as outlined in sections 307(b) and (c) of the 
CWA, 33 U.S.C. 1317(b) and (c). EPA establishes national pretreatment 
standards for those pollutants in wastewater from indirect dischargers 
that 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). 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 (those discharging to waters of the U.S. rather 
than to a POTW) must comply with effluent limitations in NPDES permits. 
Indirect dischargers, who discharge through POTWs, must comply with 
pretreatment standards. Technology-based effluent limitations and 
standards in NPDES permits are derived from ELGs (CWA sections 301 and 
304, 33 U.S.C. 1311 and 1314) and NSPS (CWA section 306, 33 U.S.C. 
1316) promulgated by EPA, or are based on best professional judgment 
(BPJ) where EPA has not promulgated an applicable ELG or new source 
performance standard (CWA section 402(a)(1)(B), 33 U.S.C. 
1342(a)(1)(B)). Additional limitations are also required in the permit 
where necessary to meet WQS. CWA section 301(b)(1)(C), 33 U.S.C. 
1311(b)(1)(C). The ELGs are established by EPA regulation for 
categories of industrial dischargers and are based on the degree of 
control that can be achieved using various levels of pollution control 
technology, as specified in the CWA (e.g., BPT, BCT, BAT; see below).
    EPA promulgates national ELGs for industrial categories for three 
classes of pollutants: (1) Conventional pollutants (TSS), oil and 
grease, biochemical oxygen demand (BOD5), fecal coliform, and pH), as 
outlined in CWA section 304(a)(4), 33 U.S.C. 1314(a)(4), and 40 CFR 
401.16; (2) toxic pollutants (e.g., toxic metals such as arsenic, 
mercury, selenium, and chromium; toxic organic pollutants such as 
benzene, benzo-a-pyrene, phenol, and naphthalene), as outlined in CWA 
section 307(a), 33 U.S.C. 1317(a); 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, and total dissolved solids (TDS)).

B. Relevant Effluent Guidelines

    EPA establishes ELGs based on the performance of well-designed and 
well-operated control and treatment technologies. The legislative 
history also supports that EPA need not consider water quality impacts 
on individual water bodies as the guidelines are developed; see 
Statement of Senator Muskie (principal author) (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).
    There are various levels of control applicable to direct and 
indirect dischargers, based on the type of pollutant controlled. The 
three standards relevant to this rulemaking are described in detail 
below.
1. Best Practicable Control Technology Currently Available (BPT)
    Traditionally, EPA establishes effluent limitations based on BPT by 
reference to the average of the best performances of facilities within 
the industry, grouped to reflect various ages, sizes, processes, or 
other common characteristics. EPA promulgates BPT effluent limitations 
for conventional, toxic, and nonconventional pollutants. In specifying 
BPT, EPA looks at a number of factors. EPA first 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, EPA may establish limitations 
based on higher levels of control than those 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 
practically applied.
2. Best Available Technology Economically Achievable (BAT)
    BAT represents the second level of control for direct discharges of 
toxic and nonconventional pollutants. As the statutory phrase intends, 
EPA considers the technological availability and the economic 
achievability in determining what level of control represents BAT. CWA 
section 301(b)(2)(A), 33 U.S.C. 1311(b)(2)(A). Other statutory factors

[[Page 64654]]

that EPA must consider in assessing BAT are the cost of achieving BAT 
effluent reductions, the age of equipment and facilities involved, the 
process employed, potential process changes, non-water quality 
environmental 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); Texas Oil and gas Ass'n v. EPA, 
161 F.3d 923, 928 (5th Cir. 1998). The Agency retains considerable 
discretion in assigning the weight to be accorded each of the factors 
it is required to consider. Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 
1045 (D.C. Cir. 1978). Generally, EPA determines economic achievability 
based on the effect of the cost of compliance with BAT limitations on 
overall industry and subcategory (if applicable) financial conditions. 
BAT may reflect the highest performance in the industry, and it 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 studies, or foreign facilities. Am. 
Paper Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); Am. Frozen 
Food Inst. v. Train, 539 F.2d 107, 132 (D.C. Cir. 1976). BAT may be 
based upon process changes or internal controls, even when these 
technologies are not common industry practice. See Am. Frozen Food 
Inst., 539 F.2d at 132, 140; Reynolds Metals Co. v. EPA, 760 F.2d 549, 
562 (4th Cir. 1985); Cal. & Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 
285-88 (2nd Cir. 1977).
    One way that EPA may take into account differences within an 
industry when establishing BAT limitations is through 
subcategorization. The Supreme Court has recognized that the 
substantive test for subcategorizing an industry is whether the plants 
are different with respect to relevant statutory factors. See Chem. 
Mfrs. Ass'n v. EPA, 870 F.2d 177, 214 n.134 (5th Cir. 1989) (citing 
Chem. Mfrs. Ass'n v. NRDC, 470 U.S. 116, 119-22, 129-34 (1985)). Courts 
have stated that there need only be a rough basis for 
subcategorization. See Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 215 n.137 
(summarizing cases).
3. Pretreatment Standards for Existing Sources (PSES)
    Section 307(b) of the CWA, 33 U.S.C. 1317(b), authorizes EPA to 
promulgate pretreatment standards for discharges of pollutants to 
POTWs. 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 effluent limitations guidelines, 
and thus the Agency typically considers the same factors in 
promulgating PSES as it considers in promulgating BPT and BAT. 
Legislative history indicates that Congress intended for the 
combination of pretreatment and treatment by the POTW to achieve the 
level of treatment that would be required if the industrial source were 
discharging to a water of the U.S. Conf. Rep. No. 95-830, at 87 (1977), 
reprinted in U.S. Congress. Senate Committee on Public Works (1978), A 
Legislative History of the CWA of 1977, Serial No. 95-14 at 271 (1978). 
The General Pretreatment Regulations, which set forth the framework for 
the implementation of categorical pretreatment standards, are found at 
40 CFR 403. These regulations establish pretreatment standards that 
apply to all non-domestic dischargers. See 52 FR 1586 (January 14, 
1987).

C. 2015 Steam Electric Power Generation Point Source Category Rule

    EPA, on September 30, 2015, finalized a rule revising the 
regulations for the Steam Electric Power Generating point source 
category (40 CFR part 423) (hereinafter the ``2015 rule''). The rule 
set the first federal limitations on the levels of toxic metals in 
wastewater that can be discharged from steam electric power plants, 
based on technology improvements in the steam electric power industry 
over the preceding three decades. Prior to the 2015 rule, regulations 
for the industry had last been updated in 1982.
    New technologies for generating electric power and the widespread 
implementation of air pollution controls over the last several decades 
have altered wastewater streams or created new wastewater streams at 
many steam electric power plants, particularly coal-fired plants. 
Discharges in these wastestreams include arsenic, lead, mercury, 
selenium, chromium, and cadmium. Many of these toxic pollutants can be 
persistent, meaning once in the environment they can remain there for 
years.
    The 2015 rule addressed effluent limitations and standards for 
multiple wastestreams generated by new and existing steam electric 
facilities: BA transport water, combustion residual leachate, FGD 
wastewater, flue gas mercury control wastewater, FA transport water, 
and gasification wastewater. The rule required most steam electric 
power plants to comply with the effluent limitations ``as soon as 
possible'' after November 1, 2018, and no later than December 31, 2023. 
Within that range, except for indirect dischargers, the NPDES 
permitting authority (typically a state environmental agency) would 
determine the particular compliance date(s) for each plant in the NPDES 
permit.
    On an annual basis, the 2015 rule was projected to reduce the 
amount of metals defined in the Act as toxic pollutants, 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. At the time, EPA estimated annual compliance costs for 
the final rule to be $480 million (in 2013$) and estimated benefits 
associated with the rule to be $451 million to $566 million (in 2013$).

D. Legal Challenges, Administrative Petitions, Section 705 Action, 
Postponement Rule, and Reconsideration of Certain Limitations and 
Standards

    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., et al. v. EPA.\2\ On March 24, 2017, the Utility Water Act 
Group (UWAG) submitted to EPA an administrative petition for 
reconsideration of the 2015 rule. Also, on April 5, 2017, the Small 
Business Administration (SBA) submitted an administrative petition for 
reconsideration of the final rule.
---------------------------------------------------------------------------

    \2\ Case No. 15-60821.
---------------------------------------------------------------------------

    On April 25, 2017, EPA responded to these petitions by publishing a 
postponement of the 2015 rule compliance deadlines that had not yet 
passed, under Section 705 of the Administrative Procedure Act (APA). 
This Section 705 Action drew multiple legal challenges.\3\ The 
Administrator then signed a letter on August 11, 2017, announcing 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 EPA's request 
to sever and hold in abeyance aspects of the litigation related to 
those limitations and standards. With respect to the remaining claims 
related to limitations applicable to legacy wastewater and

[[Page 64655]]

leachate, which are not at issue in this final rule, the Fifth Circuit 
issued a decision on April 12, 2019, vacating those limitations as 
arbitrary and capricious under the APA and unlawful under the CWA, 
respectively. EPA plans to address this vacatur in a subsequent action.
---------------------------------------------------------------------------

    \3\ See Clean Water Action. v. EPA, No. 17-0817 (D.D.C.), appeal 
dismissed, No. 18-5149 (D.C. Cir.); see also Clean Water Action. v. 
EPA, No. 18-60619 (5th Cir.) (case dismissed for lack of 
jurisdiction on October 18, 2018).
---------------------------------------------------------------------------

    In September 2017, EPA finalized a rule, using notice-and-comment 
procedures, postponing the earliest compliance dates for the new, 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. EPA also withdrew its prior action taken pursuant to Section 705 
of the APA. The rule received multiple legal challenges, but the courts 
did not sustain any of them \4\ and EPA prevailed.
---------------------------------------------------------------------------

    \4\ See Center for Biological Diversity v. EPA, No. 18-cv-00050 
(D. Ariz. filed Jan. 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 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.
---------------------------------------------------------------------------

E. Other Ongoing Rules Affecting the Steam Electric Sector

1. Affordable Clean Energy (ACE) Rule
    On June 19, 2019, EPA issued the ACE rule pursuant to Clean Air Act 
(CAA) sections 111(a)(1) and 111(d), providing states with guidelines 
for establishing standards of performance regulating CO2 
emissions at existing coal-fired electric utility generating units 
(EGUs).\5\ This action was finalized in conjunction with two related, 
but separate and distinct rulemakings: (1) The repeal of the Clean 
Power Plan (CPP), and (2) revised implementing regulations for ACE, 
ongoing emission guidelines, and all future emission guidelines for 
existing sources issued under the authority of CAA section 111(d).
---------------------------------------------------------------------------

    \5\ 84 FR 32520.
---------------------------------------------------------------------------

    Under CAA section 111(a)(1) and 111(d), respectively, EPA 
determines the best system of emission reduction (BSER) and states 
submit plans establishing standards of performance based on the BSER. 
The BSER must be applicable to, at, and on the premises of a source 
that is subject to CAA section 111(d). EPA repealed the CPP on the 
basis that it in part improperly premised its BSER on power generation 
that was shifting between EGUs and other, lower-emitting sources. In 
ACE, EPA determined the BSER for coal-fired EGUs as six heat rate 
improvements (HRI) ``candidate technologies,'' as well as additional 
operations and maintenance (O&M) practices, all of which are applicable 
to and at the source.\6\ For each candidate technology, EPA has 
provided the extent of achievable emissions limitations through 
application of the BSER as ranges of expected improvements and costs. 
States are required to submit plans by July 8, 2022 that establish 
standards of performance for their EGUs that are subject to the ACE 
rule. The standards of performance must reflect the degree of emissions 
limitation through application of the BSER, and states may take into 
account remaining useful life and other factors in applying a standard 
to a particular EGU. Multiple legal challenges to this rule were 
consolidated in American Lung Association v. EPA, No. 19-1140, and are 
currently pending in the D.C. Circuit Court of Appeals.
---------------------------------------------------------------------------

    \6\ These six technologies are: (1) Neural network/intelligent 
soot blowers, (2) EGU feed pumps, (3) air heater and duct leakage 
control, (4) variable frequency drives, (5) blade path upgrade 
(steam turbine), and (6) redesign/replace economizer.
---------------------------------------------------------------------------

2. Coal Combustion Residuals (CCR)
    On April 17, 2015, the Agency published the Disposal of Coal 
Combustion Residuals from Electric Utilities final rule (2015 CCR 
rule). This rule finalized national regulations to provide a 
comprehensive set of requirements for the safe disposal of CCR, 
commonly known 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 addressed coal ash disposal, including 
regulations 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. Additionally, 
the 2015 CCR rule set recordkeeping and reporting requirements as well 
as the requirement for each plant to establish and post specific 
information to a publicly accessible website. This final 2015 CCR rule 
also supported the responsible recycling of CCR by distinguishing 
beneficial use from disposal.
    As a result of the D.C. Circuit Court rulings in USWAG v. EPA, No. 
15-1219 (D.C. Cir. 2018) and Waterkeeper Alliance Inc. et al. v. EPA, 
No. 18-1289 (D.C. Cir. 2019), the Administrator signed A Holistic 
Approach to Closure Part A: Deadline to Initiate Closure and Enhancing 
Public Access to Information on July 29 (CCR Part A). In particular, 
four amendments to the CCR rule were finalized which could impact 
plants' decisions under this final ELG rule. First, the CCR Part A rule 
establishes a new deadline of April 11, 2021, for all unlined surface 
impoundments, as well as those surface impoundments that failed the 
location restriction for placement above the uppermost aquifer, to stop 
receiving waste and begin closure or retrofit. EPA determined this date 
after evaluating the steps that owners and operators need to take for 
surface impoundments to stop receiving waste and begin closure, and the 
time frames needed for implementation. Second, the rule establishes 
procedures for plants to obtain additional time to develop alternate 
capacity to manage their wastestreams (both coal ash and non-coal ash) 
before they have to stop receiving waste and begin closing their coal 
ash surface impoundments. Third, the rule changes the classification of 
compacted-soil-lined and clay-lined surface impoundments from lined to 
unlined. Finally, the rule revises the coal ash regulations to specify 
that all unlined surface impoundments are required to retrofit or 
close. This would not affect the ability of plants to install new, 
composite-lined surface impoundments.
    As explained in the 2015 ELG rule and 2019 ELG proposal, the ELGs 
and 2015 CCR rule may affect the same EGU or activity at a plant. 
Therefore, when EPA finalized the ELG and CCR rule in 2015 and proposed 
revisions to both rules in 2019, the Agency coordinated the ELG and CCR 
rules to facilitate and minimize the complexity of implementing 
engineering, financial, and permitting activities. EPA continued to 
coordinate these two rules during the development of the final rule for 
ELG and CCR Part A. EPA's analysis now estimates how the CCR Part A 
rule may affect surface impoundments and the ash handling systems and 
FGD treatment systems that send wastes to those impoundments. This is 
further described in Supplemental TDD, Section 3. For more information 
on the CCR Part A rule and accompanying background documents, visit 
www.regulations.gov Docket EPA-HQ-OLEM-2019-0172 and www.epa.gov/coalash/coal-ash-rule.
    In addition to the final CCR Part A rule, EPA has proposed further 
revisions to the CCR regulations (CCR Part B). Specifically, EPA 
proposed four changes in the CCR Part B rule. First, EPA proposed 
procedures to allow plants to request approval to continue operating 
CCR surface impoundments equipped

[[Page 64656]]

with an alternate liner. Second, EPA proposed two options to allow the 
continued placement of CCR in surface impoundments undergoing forced 
closure. Third, EPA proposed an additional closure option for CCR units 
being closed by removal of CCR. Finally, EPA proposed requirements for 
annual closure progress reports. While the Part B proposal was issued 
after the comment period for the ELG rule had closed and EPA had 
already taken significant steps to respond to public comments on the 
ELG rule and develop the final ELG rule, EPA recognizes that, just as 
with the Part A rule, the first provision of the Part B rule may affect 
the same EGU or activity at a plant that these final ELGs affect. EPA 
is continuing to work on the Part B rule and may finalize this 
provision in the future. Thus, to provide the public with meaningful 
analysis of the potential overlap and impacts of this final rule with 
the CCR Part B rule, EPA has conducted a sensitivity analysis that is 
described further in a memo titled ``Assessment of the economic impacts 
of the final revised Steam Electric ELGs relative to an alternative 
baseline including the CCR Part B Rule'', (DCN SE09360). For more 
information on the CCR Part B rule and accompanying background 
documents, visit www.regulations.gov Docket EPA-HQ-OLEM-2019-0173.

F. Scope of the Final Rule

    The final rule revises the new, more stringent BAT ELGs and 
pretreatment standards for existing sources in the 2015 rule that apply 
to FGD wastewater and BA transport water.

V. Steam Electric Power Generating Industry Description

A. General Description of Industry

    EPA provided a general description of the steam electric power 
generating industry in the 2013 proposed rule, the 2015 rule, the 2019 
proposed rule, and has continued to collect information and update that 
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 the final rule, as described in the Supplemental TDD, Section 3, 
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.\7\ The analyses supporting the final rule use an 
updated baseline that incorporates these changes in the industry. The 
analyses then compare the effect of the final rule's requirements for 
FGD wastewater and BA transport water to the effect on the industry (as 
it exists today) of the 2015 rule's limitations for FGD wastewater and 
BA transport water.
---------------------------------------------------------------------------

    \7\ The data presented in the general description continue to 
reflect some conditions existing in 2009, as the industry survey 
remains EPA's best available source of information for 
characterizing operations across the industry.
---------------------------------------------------------------------------

    As described in the Regulatory Impact Analysis, of the 914 steam 
electric power plants in the country identified by EPA, only those 
coal-fired power plants that discharge bottom ash transport water or 
FGD wastewater may incur compliance costs under this final rule. EPA 
estimates that 108 such plants could have incurred non-zero compliance 
costs under the 2015 rule but that only 75 plants may incur non-zero 
compliance costs under this final rule. As described above, this 
difference is due to plant retirements, fuel conversions, ash handling 
conversions, wastewater treatment updates, and updated information on 
capacity utilization discussed in Changes to Industry Profile for Coal-
Fired Generating Units for the Steam Electric Effluent Guidelines Final 
Rule (DCN SE08688), but does not include additional changes since this 
document was developed.

B. Current Market Conditions in the Electricity Generation Sector

    Market conditions in the electricity generation sector have changed 
significantly and rapidly in the past decade. These changes include 
availability of abundant and relatively inexpensive natural gas, 
emergence of alternative fuel technologies, and continued aging of 
coal-fired steam electric power plants. These changes have resulted in 
coal-fired unit and plant retirements and switching of fuels. The lower 
cost of natural gas and technological advances in solar and wind power 
have had a depressive effect on both coal-fired and nuclear-powered 
generation. (This rule will have no direct effect on the nuclear-
powered sector, except as it might affect relative prices through its 
effects on coal-fired generation.) In the coal-fired sector, the market 
forces manifest as scaling back coal-fired power generation (including 
unit and plant closures) at an accelerated rate. The rate of coal 
capacity retirement is affected by regulations adopted in the last 
decade (e.g., CCR, CPP, and the 2015 Steam Electric ELG), that are 
cited by some power companies when they announce unit or plant 
closures, fuel switching, or other operational changes. Some utilities 
are also trending toward supplementing or replacing traditional 
generation with alternative sources. The electric power infrastructure 
adjusts to these changes and generally trends toward optimal 
infrastructure and operations to deliver the country's power demand. 
Some communities experience negative effects, while for others the 
effects are positive. The negative distributional effects can be 
particularly difficult for communities affected by company decisions to 
scale back or retire a plant. Also see Section 2.3 of the RIA.

C. Control and Treatment Technologies

    In general, control and treatment technologies for some 
wastestreams have continued to advance since the 2015 rule. Often, 
these advancements provide plants with additional ways of meeting 
effluent limitations, sometimes at a lower cost. For this final rule, 
EPA incorporated updated information and evaluated several technologies 
available to control and treat FGD wastewater and BA transport water. 
See Section VIII of this preamble for details on updated cost 
information.
1. FGD Wastewater
    FGD scrubber systems, either dry or wet, remove sulfur dioxide from 
flue gas, preventing sulfur dioxide emissions into the air. Dry FGD 
systems generally do not discharge wastewater, as the water they use 
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 
discharged FGD wastewater. As part of the 2015 rule, EPA identified the 
following types of treatment and handling practices for FGD wastewater:

     Chemical precipitation systems that use tanks to treat 
FGD wastewater. Chemicals are added to help remove suspended solids 
and dissolved solids, particularly metals. The precipitated solids 
are then removed from solution by coagulation/flocculation, followed 
by clarification and/or filtration. The 2015 rule focused on a 
specific design that employs hydroxide precipitation, sulfide 
precipitation (organosulfide), and iron coprecipitation to remove 
suspended solids and to convert soluble metal ions to insoluble 
metal hydroxides or sulfides.
     Biological treatment systems that use microorganisms to 
treat FGD wastewater.

[[Page 64657]]

EPA identified three types of biological treatment systems used to 
treat FGD wastewater: (1) Anoxic/anaerobic fixed-film bioreactors, 
which remove nitrogen compounds and selenium, as well as other 
metals; (2) anoxic/anaerobic suspended growth systems, which remove 
selenium and other metals; and (3) aerobic/anaerobic sequencing 
batch reactors, which remove organics and nutrients. The 2015 rule 
focused on a specific design of anoxic/anaerobic fixed-film 
bioreactors that employs a relatively long residence time for the 
microbial processes. The bioreactor design used as the basis for the 
2015 rule, with a typical hydraulic residence time of approximately 
10 to 16 hours, is referred to in this rulemaking as high residence 
time reduction (HRTR). The BAT technology basis for the 2015 rule 
also included chemical precipitation as a pretreatment stage prior 
to the bioreactor and a sand filter as a polishing step following 
the bioreactor (i.e., CP + HRTR).
     Thermal evaporation systems that use a falling-film 
evaporator (or brine concentrator). Following a softening 
pretreatment step, thermal evaporation systems produce a 
concentrated wastewater stream and a distillate stream to reduce the 
volume of wastewater by 80 to 90 percent and also reduce the 
discharge of pollutants. The concentrated wastewater is usually 
further processed in a crystallizer, which 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.
     Constructed wetland systems using natural biological 
processes. These systems involve wetland vegetation, soils, and 
microbial activity to reduce the concentrations of metals, 
nutrients, and TSS in wastewater. High temperature, chemical oxygen 
demand (COD), nitrates, sulfates, boron, and chlorides in the 
wastewater can adversely affect constructed wetlands' performance. 
To avoid this, plants typically find it necessary to dilute the FGD 
wastewater with service water before it enters the wetland.
     Eliminating discharged FGD wastewater. 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.

--Complete recycle. Plants that operate in this manner do not 
produce a saleable solid product from the FGD system (e.g., 
wallboard-grade gypsum). Because the plants are not selling the FGD 
gypsum, they are able to allow the landfilled material to contain 
elevated levels of chlorides, and as a result do not need a separate 
wastewater purge stream.
--Evaporation impoundments. Some plants in warm, dry climates have 
been able to use surface impoundments as holding basins from which 
the FGD wastewater evaporates. The evaporation rate from the 
impoundments at these plants is greater than or equal to the flow 
rate of the FGD wastewater plus the rate at which precipitation 
enters the impoundments; therefore, there is no discharge to surface 
water.
--FA conditioning. Many plants that operate dry FA handling systems 
will add water to the FA to suppress dust or improve handling and/or 
compaction characteristics in an on-site landfill. EPA is not aware 
of any plants using FGD wastewater to condition ash that will be 
marketed.
--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 
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 by a 
fabric filter (i.e., a baghouse) or electrostatic precipitator 
(ESP).
--Underground injection. These systems dispose of wastes by 
injecting them into an underground well as an alternative to 
discharging wastewater to surface waters.

    As part of the proposed rule, EPA added two additional FGD 
wastewater treatment technologies to the suite of regulatory options 
that were evaluated in the 2015 rule: Low hydraulic residence time 
biological reduction (LRTR) and membrane filtration, which are further 
described below.

     LRTR system. A biological treatment system that targets 
removal of selenium and nitrate/nitrite using fixed-film bioreactors 
in smaller, more compact reaction vessels than those used in the 
biological treatment system evaluated in the 2015 rule (referred to 
in this rule as HRTR--high residence time biological reduction). The 
LRTR system is designed to operate with a shorter residence time 
(approximately 1 to 4 hours, as compared to a residence time of 10 
to 16 hours for HRTR), while still removing significant volumes of 
selenium and nitrate/nitrite. The LRTR technology option selected 
for this final rule includes chemical precipitation as a 
pretreatment stage, followed by the bioreactor, then ultrafiltration 
as a polishing step.
     Membrane filtration. A membrane filtration system 
typically combines pretreatment for potential scaling agents such as 
calcium, magnesium, and sulfates, and one or more types of membrane 
technology (e.g., nanofiltration or reverse osmosis) to remove a 
broad range 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. The membrane filtration 
technology option considered for this final rule includes a 
pretreatment stage.

    EPA also collected new information on other FGD wastewater 
treatment technologies, including spray dryer evaporators, direct 
contact thermal evaporators, zero valent iron treatment, forward 
osmosis, absorption or adsorption media, ion exchange, 
electrocoagulation, and electrodialysis reversal. These treatment 
technologies have been evaluated at full scale or pilot scale, or are 
being developed to treat FGD wastewater. See Section 4.1 of the 
Supplemental TDD for more information on these technologies.
2. BA Transport Water
    BA 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.\8\ Many plants use water 
to transport (sluice) the BA from the hopper to an impoundment system 
or a dewatering bin system. In both the impoundment and dewatering bin 
systems, the BA transport water is usually discharged to surface water 
as overflow from the system, after the BA has settled to the bottom. In 
both the impoundment and dewatering bin systems, the BA transport water 
is usually discharged to surface water as overflow from the system, 
after the BA has settled to the bottom. In addition to wet sluicing to 
an impoundment or dewatering bin system, the industry also uses the 
following BA handling systems that generate BA transport water:
---------------------------------------------------------------------------

    \8\ Consistent with the 2015 rule, boiler slag is considered BA.

     Remote mechanical drag system (remote MDS). These 
systems use the same processes as wet sluicing to an impoundment or 
a dewatering bin system to transport bottom ash to a remote MDS. A 
drag chain conveyor dewaters the bottom ash by pulling it out of the 
water bath on an incline. The system can either be operated as a 
closed loop (evaluated during the 2015 rule) \9\ or a high recycle 
rate system. For the high recycle rate system that serves as the 
basis for BAT in the final rule, plants would be permitted to purge 
a portion of the wastewater from the system to maintain a high 
recycle rate, as described in Section VII of this preamble.
---------------------------------------------------------------------------

    \9\ Additional treatment may be necessary to maintain a true 
closed loop system. This additional treatment could include adding a 
polymer to enhance removal of suspended solids, or membrane 
filtration of a slip stream to remove dissolved solids.
---------------------------------------------------------------------------

     Dense slurry system. These systems use a dry vacuum or 
pressure system to convey the bottom ash to a silo (as described 
below for the dry vacuum or pressure system), but instead of using 
trucks to transport the bottom ash to a landfill, the plant mixes 
the bottom ash with water (a lower percentage of water compared to a 
wet sluicing system) and pumps the mixture to the landfill.
    As part of the 2015 rule and the final rule, EPA identified the 
following BA handling systems that do not generate bottom ash 
transport water.
     Mechanical drag system. These systems operate directly 
underneath the EGU. The bottom ash is collected in a water quench 
bath. A drag chain conveyor dewaters the

[[Page 64658]]

bottom ash by pulling it out of the water bath on an incline.
     Dry mechanical conveyor. These systems operate directly 
underneath the EGU. The system uses ambient air to cool the bottom 
ash in the EGU and then transports the ash out of the EGU on a 
conveyor. No water is used in this process.
     Dry vacuum or pressure system. These systems transport 
bottom ash 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 bottom ash 
into 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.
     Compact submerged conveyor.\10\ 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 bottom ash from 
the discharge of each clinker grinder. A series of submerged drag 
chain conveyors transports and dewaters the bottom ash.
---------------------------------------------------------------------------

    \10\ At proposal, EPA referred exclusively to one specific 
vendor's compact submerged conveyor technology (submerged grinder 
conveyors), but is using the more generic term for the technology 
(compact submerged conveyors) for this final rule because the Agency 
did not intend to limit its consideration to only one vendor's 
technology.

    See Section 4.2 of the Supplemental TDD for more information on 
these technologies.

VI. Data Collection Since the 2015 Rule

A. Information From the Electric Utility Industry

1. Engineering Site Visits
    During October and November 2017, EPA conducted seven site visits 
to plants in five states. EPA selected plants to visit using 
information gathered in support of the 2015 rule, information from 
industry outreach, and publicly available plant-specific information. 
EPA re-visited four plants that were previously visited in support of 
the 2015 rule because they had recently conducted, or were currently 
conducting, FGD wastewater treatment pilot studies. EPA also revisited 
plants that had implemented new FGD wastewater treatment technologies 
or BA handling systems (after the 2015 rule) to learn more about 
implementation timing, start-up and operation, and implementation 
costs. Following the proposal, EPA also conducted five teleconference 
calls in the spring of 2020. One of these plants was selected for a 
conference call because it had installed a compact submerged conveyor 
for management of BA. Two additional plants were selected for a 
conference call due to installed FGD wastewater technologies that EPA 
understood could potentially achieve the limitations in the VIP. The 
final two conference calls were with companies whose plants EPA 
believed were planning or constructing FGD wastewater technologies that 
could potentially achieve the limitations in the VIP, based on 
preliminary information provided by third parties.\11\
---------------------------------------------------------------------------

    \11\ In one case this preliminary information was provided by a 
membrane vendor and in the other the information was provided by a 
state permitting authority.
---------------------------------------------------------------------------

    The specific objectives of these visits and calls were to gather 
general information about each plant's operations, pollution prevention 
and wastewater treatment system operations, ongoing pilot or laboratory 
scale studies of FGD wastewater treatment, and BA handling system 
conversions.
2. Data Requests, Responses, and Meetings
    Under the authority of Section 308 of the Clean Water Act (CWA) (33 
U.S.C. 1318), in January 2018, EPA requested supplemental information 
from nine steam electric power companies that own coal-fired facilities 
generating FGD wastewater:

     FGD wastewater characterization data associated with 
testing and implementation of treatment technologies, in 2013 or 
later.
     Information on halogen usage to reduce flue gas 
emissions, as well as data on halogen concentrations in FGD 
wastewater.
     Projected installations of FGD wastewater treatment 
technologies.
     Cost information for projected or installed FGD 
wastewater treatment systems, from bids received in 2013 or later.

    EPA selected these nine companies to provide supplemental 
information because EPA became aware that these companies may be 
testing, piloting or otherwise investigating new wastewater treatment 
technologies and EPA was unable to obtain information about these 
studies on a voluntary basis. After receiving each company's response, 
EPA met with these companies to discuss the FGD-related data they 
submitted, other FGD and BA data outside the scope of the request that 
the company believed to be relevant, and suggestions each company had 
for potential changes to the 2015 rule with respect to FGD wastewater 
and BA transport water. EPA used this information to learn more about 
the performance of new treatment systems, inform the development of FGD 
wastewater limitations, learn more about plant-specific halogen usage 
(such as bromide), and obtain information useful for updating cost 
estimates for installing candidate treatment technologies. As needed, 
EPA conducted follow-up meetings and conference calls with industry 
representatives to discuss and clarify these data.
3. Voluntary BA Transport Water Sampling
    In December 2017, EPA invited seven steam electric power plants to 
participate in a voluntary BA transport water sampling program designed 
to obtain data to supplement the wastewater characterization data set 
for BA transport water included in the record for the 2015 rule. EPA 
asked plants to provide analytical data for ash impoundment effluent 
and untreated BA transport water (i.e., ash impoundment influent). EPA 
selected the plants based on their responses to its 2010 Questionnaire 
for the Steam Electric Power Generating Effluent Guidelines (see 
Section 3.2 of the 2015 TDD). Two plants chose to participate in the 
voluntary BA sampling program. These data were incorporated into the 
analytical data set used to estimate pollutant removals for BA 
transport water.
4. Electric Power Research Institute (EPRI) Voluntary Submission
    EPRI conducts studies--funded by the steam electric power 
generating industry--to evaluate and demonstrate technologies that can 
potentially eliminate wastestreams or remove pollutants from them. 
Following the 2015 rule, and prior to the final rule, EPA reviewed 46 
reports published between 2011 and 2020 that EPRI voluntarily provided 
regarding characteristics of FGD wastewater and BA transport water, FGD 
wastewater treatment pilot studies, BA handling practices, halogen 
addition rates, and the effect of halogen additives on FGD wastewater. 
These EPRI reports include those cited by EPRI in their comments on the 
proposed rule. EPA used information presented in these reports to 
inform the development of numeric effluent limitations for FGD 
wastewater and to update methods for estimating the costs and pollutant 
removals associated with candidate treatment technologies.
5. Meetings With Trade Associations
    In May and June of 2018, EPA met with the Edison Electric Institute 
(EEI), the National Rural Electric Cooperatives Association (NRECA), 
and the American Public Power Association (APPA). These trade 
associations represent investor-owned utilities, electric

[[Page 64659]]

cooperatives, and community-owned utilities, respectively. EPA also met 
with the Utility Water Act Group (UWAG), an association comprising the 
trade associations above as well as individual electric utilities. EPA 
met with each of these trade associations separately and together to 
discuss the technologies and the analyses presented in the 2015 rule 
and receive information related to reconsidering the 2015 rule. EPA 
used information from these meetings to update industry profile data 
(i.e., accounting for retirements, fuel conversions, and updated 
treatment technology installations). EPA also met with UWAG and EEI to 
discuss their comments with them after the close of the 2019 proposed 
rule comment period.

B. Information From the Drinking Water Utility Industry and States

    EPA received additional information from the drinking water utility 
sector and states on the effects of bromide discharges from steam 
electric power plants on drinking water treatment processes. First, EPA 
received letters from, and met with, the American Water Works 
Association (AWWA), the Association of Metropolitan Water Agencies 
(AMWA), the National Association of Water Companies (NAWC), the 
Association of Clean Water Administrators (ACWA), and the Association 
of State Drinking Water Administrators (ASDWA). Second, EPA visited two 
drinking water treatment plants in North Carolina that have modified 
their treatment processes to address an increase in disinfection 
byproduct levels due to bromide discharges from an upstream steam 
electric power plant. Finally, EPA obtained data on surface water 
bromide concentrations and data from drinking water monitoring from the 
two drinking water treatment plants. EPA also obtained existing state 
data from other drinking water treatment plants from the states of 
North Carolina and Virginia.

C. Information From Technology Vendors and Engineering, Procurement, 
and Construction (EPC) Firms

    EPA gathered data on availability and effectiveness from technology 
vendors and EPC firms through presentations, conferences, meetings, and 
email and phone contacts regarding FGD wastewater and BA handling 
technologies used in the industry. The data collected informed the 
development of the technology costs and pollutant removal estimates for 
FGD wastewater and BA transport water. The EPC firms also suggested 
potential changes to the 2015 rule.

D. Other Data Sources

    EPA gathered information on steam electric power plants from the 
Department of Energy's (DOE's) Energy Information Administration (EIA), 
forms EIA-860 (Annual Electric Generator Report) and EIA-923 (Power 
Plant Operations Report). EPA used the 2017 and 2018 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.
    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. EPA also 
used the internet searches to identify or confirm reports of planned 
plant and EGU retirements, and reports of planned unit conversions to 
dry or closed-loop recycle ash handling systems. EPA used this 
information to inform the industry profile and identify process 
modifications occurring in the industry.
    EPA received information from several environmental groups and 
other stakeholders following the 2015 rule. These groups provided 
examples of when, they believed, state permitting authorities had not 
properly implemented the ``as soon as possible date'' for the new, more 
stringent BAT requirements in the 2015 rule when issuing permits. EPA 
also met with these groups after the close of the comment period of the 
2019 proposed rule to discuss those organizations' comments.

VII. Final Regulation

A. Description of the Main BAT/PSES Options

    EPA analyzed four regulatory options at proposal, the details of 
which were discussed in the proposed rule (84 FR 64620). For the final 
rule, EPA evaluated four regulatory options, as shown in Table VII-1. 
Proposed regulatory options 1, 2, 3, and 4 correspond generally to 
regulatory options D, A, B, and C in this final rule, respectively, but 
contain certain differences, as detailed below. Public commenters 
generally supported three of the regulatory options that EPA proposed, 
or variants thereof.\12\ The availability and achievability of 
technologies with better pollutant removals, as well as the general 
lack of public comments supporting proposed regulatory option 1, led 
EPA to focus updates to the Agency's analysis on the remaining three 
regulatory options. EPA did not update the analyses for regulatory 
option D, but rather retained the results of the proposed rule analysis 
for this option.
---------------------------------------------------------------------------

    \12\ Some commenters also supported retaining the 2015 rule.
---------------------------------------------------------------------------

    EPA is finalizing Option A in the final rule. All four options 
include the same technology bases for BA transport water, except Option 
A, which includes a different technology basis for the subcategorized 
low utilization EGUs and surface impoundments for EGUs permanently 
ceasing combustion of coal by 2028. In regards to FGD wastewater, 
Option D is based on chemical precipitation, Options A and B are based 
on a combination of chemical precipitation and low hydraulic residence 
time biological treatment, while Option C is based on membrane 
filtration; the difference between Options A and B is that the former 
includes three subcategories while the latter does not. Table VII-1 
below summarizes the regulatory options considered in this rulemaking. 
The subcategories identified below are described further in Section 
VII.C, below.

[[Page 64660]]

                                                          Table VII-1--Main Regulatory Options
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                 Technology basis for the BAT/PSES regulatory options
            Wastestream                    Subcategory      --------------------------------------------------------------------------------------------
                                                                        D                A (final rule)               B                      C
FGD Wastewater.....................  N/A...................  Chemical precipitation  Chemical               Chemical               Membrane filtration.
                                                                                      precipitation + low    precipitation + low
                                                                                      hydraulic residence    hydraulic residence
                                                                                      time biological        time biological
                                                                                      treatment.             treatment.
                                     High FGD flow plants..  NS....................  Chemical               NS...................  NS.
                                                                                      precipitation.
                                     Low utilization EGUs..  NS....................  Chemical               NS...................  NS.
                                                                                      precipitation.
                                     EGUs permanently        NS....................  Surface impoundments.  NS...................  NS.
                                      ceasing the
                                      combustion of coal by
                                      2028.
------------------------------------------------------------
FGD Wastewater Voluntary Incentives Program (Direct
 Dischargers Only)
-------------------------------------Membrane filtration...- Membrane filtration...  Membrane filtration..  N/A..................
BA Transport Water.................  N/A...................  High recycle rate       High recycle rate      High recycle rate      High recycle rate
                                                              systems.                systems.               systems.               systems.
                                     Low utilization EGUs..  NS....................  Surface impoundments   NS...................  NS.
                                                                                      +BMP plan.
                                     EGUs permanently        NS....................  Surface impoundments.  NS...................  NS.
                                      ceasing the
                                      combustion of coal by
                                      2028.
--------------------------------------------------------------------------------------------------------------------------------------------------------
NS = Not Subcategorized.
Note: The table above does not present subcategories included in the 2015 rule because EPA did not reopen the subcategorization of oil-fired units or
  units with a nameplate capacity of 50 MW or less.

1. FGD Wastewater
    Under Option D, EPA would establish BAT limitations and PSES for 
mercury and arsenic based on chemical precipitation. Under Options A 
and B, EPA would establish BAT limitations and PSES for mercury, 
arsenic, selenium, and nitrate/nitrite based on chemical precipitation 
followed by LRTR and ultrafiltration. Option A contains three 
subcategories. The first subcategory under Option A is for plants with 
high FGD flows (defined as greater than four MGD). For these plants, 
Option A would establish limitations and standards for mercury and 
arsenic based on chemical precipitation. The second subcategory under 
Option A is for low utilization boilers with a capacity utilization 
rating (CUR) of less than 10 percent per year. This is a change from 
the proposed subcategory, which was based on a cutoff of 876,000 MWh 
utilization. For those low utilization EGUs, Option A would require 
mercury and arsenic limitations based on chemical precipitation.\13\ 
The third subcategory under Option A is for EGUs permanently ceasing 
the combustion of coal by December 31, 2028. This is a change from the 
proposed subcategory, which only included EGUs retiring by December 31, 
2028. For this subcategory of EGUs, Option A would establish BAT 
limitations equal to BPT limitations for TSS based on the use of 
surface impoundments with a best management plan for minimizing 
discharges. For Options A, B, and D, EPA would establish voluntary 
incentives program limitations for mercury, arsenic, selenium, nitrate-
nitrite, bromide, and TDS based on membrane filtration preceded by 
pretreatment (i.e., chemical precipitation).\14\ For Option C, EPA 
would establish BAT limitations and PSES for mercury, arsenic, 
selenium, nitrate/nitrite, bromide, and TDS based on membrane 
filtration, which would be applicable to all steam electric power 
plants (except if they qualify for the subcategories contained in the 
2015 rule). For Options B and C, the final rule preamble evaluates 
alternative technology bases for all units to address comments that the 
proposed rule preamble did not evaluate technology alternatives for 
high flow plants, retiring units, or repowering units.
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    \13\ As explained above, EPA did not propose to revise BAT 
limitations or PSES for oil-fired EGUs and/or small EGUs (50 MW or 
smaller).
    \14\ The proposal relied on data from three data sets to 
establish limits for the VIP membrane technology--two using chemical 
precipitation as the pretreatment technology for a portion of the 
pilot and one using chemical precipitation as the pretreatment for 
some portions of the pilot and only microfiltration for other 
portions of the pilot. However, the cost estimates for membrane 
filtration technology at proposal were based on microfiltration (or 
comparable large particle filter) pretreatment technology for plants 
without existing FGD wastewater treatment, which is less costly than 
chemical precipitation. The final rule limits are based entirely on 
those data using chemical precipitation pretreatment, and the final 
rule costs are also based on chemical precipitation as pretreatment. 
See Section XIII for further discussion on the use of data to 
establish limits.
---------------------------------------------------------------------------

2. BA Transport Water
    Under all options described above, the final rule controls the 
discharge of pollutants from BA transport water by establishing daily 
BAT limitations and PSES on the volume of BA transport water that can 
be discharged, based on high recycle rate systems. A high recycle rate 
system is a recirculating, wet ash handling system that periodically 
discharges (purges) a small portion of the process wastewater from its 
system. This is a correction of the proposal, in which the Agency in 
some instances identified ``dry handling or high recycle rate systems'' 
as the proposed technology basis. While plants are free to use dry 
handling technologies to achieve the limitations in the rule, the final 
rule limitations are based on high recycle rate systems (as were the 
proposed limitations).\15\ The only difference between Options A 
through D for BA transport water is that Option A includes two 
subcategories. The first subcategory under Option A is for low 
utilization EGUs with a CUR of less than 10 percent per year. This is a 
change

[[Page 64661]]

from the proposed subcategory which was based on a cutoff at 876,000 
MWh utilization. For these low utilization EGUs, Option A would 
establish BAT limitations for BA transport water equal to the BPT 
limitations based on gravity settling in surface impoundments to remove 
TSS.\16\ Such plants would also be required to develop and implement a 
BMP plan to minimize the discharge of pollutants from BA transport 
water. Because POTWs are designed to treat conventional pollutants such 
as TSS, TSS is not considered to pass through, and EPA would establish 
PSES based on the inclusion of a BMP plan only. For additional 
information on pass through analyses, see Section VII(C) of the 2015 
rule preamble.
---------------------------------------------------------------------------

    \15\ Public comments focused on the appropriateness of high 
recycle rate systems and did not discuss or recommend dry handling 
or other zero discharge systems as the technology basis, which is 
consistent with EPA's intent that the technology basis be high 
recycle rate systems alone, rather than include dry handling or high 
recycle rate systems.
    \16\ Although TSS is a conventional pollutant, regulation of TSS 
in this final rule is intended as regulation of the particulate form 
of toxic metals through the use of an indicator pollutant.
---------------------------------------------------------------------------

    The second subcategory under Option A is for EGUs permanently 
ceasing the combustion of coal by December 31, 2028. This is a change 
from the proposed subcategory, which only included retiring EGUs. For 
this subcategory of EGUs in Option A, EPA would establish BAT 
limitations equal to BPT limitations for TSS, based on gravity settling 
in surface impoundments. For Options B and C, EPA evaluated high 
recycle rate systems for all units to address comments that technology 
options should have considered alternatives for retiring units or 
repowering units. This is a change from the original regulatory options 
presented at proposal.
    Finally, EPA is not finalizing the proposed definitional change to 
exclude water remaining in a tank-based high recycle rate system when 
the plant permanently ceases coal combustion. Instead, facilities with 
high recycle rate systems may properly discharge this water as BA purge 
water subject to the BPJ limits established by the permitting 
authority, as discussed in section XIV(A)(2) of this preamble.

B. Rationale for the Final BAT

    In light of the criteria and factors specified in CWA sections 
304(b)(2)(B) and 301(b)(2)(A) (see Section IV of this preamble), EPA is 
establishing BAT effluent limitations based on the technologies 
described in Option A. EPA's selection of the generally applicable BAT 
(LRTR plus chemical precipitation for FGD wastewater and high recycle 
rate for BA transport water) in Option A is independently supported by 
this rulemaking record and not dependent upon the subcategories that 
are also included in Option A.\17\ EPA's rationale for the final rule's 
limitations are discussed below. EPA is not finalizing the bromide sub-
options proposed in 2019 and, as a result, this section does not 
include discussion of those sub-options. A more complete discussion of 
site-specific water quality-based effluent limitations for bromides 
provided in Section XIV(C) of this preamble.
---------------------------------------------------------------------------

    \17\ If any provisions of this rule are reviewed and vacated by 
a court, it is EPA's intent that as many portions of this rule 
remain in effect as possible.
---------------------------------------------------------------------------

1. FGD Wastewater
    This final rule identifies treatment using chemical precipitation 
followed by a low hydraulic residence time biological treatment, 
including ultrafiltration as the BAT technology basis for control of 
pollutants discharged in FGD wastewater. More specifically, the 
technology basis for BAT includes the same chemical precipitation 
system described in the 2015 rule, which employs equalization, 
hydroxide and organosulfide precipitation, iron coprecipitation, and 
removal of suspended and precipitated solids. This chemical 
precipitation system is followed by a low hydraulic residence time, 
anoxic/anaerobic biological treatment system designed to remove heavy 
metals, selenium, and nitrate-nitrite.\18\ The LRTR bioreactor stage is 
followed by ultrafiltration to remove suspended solids, including 
colloidal particles, exiting the bioreactor.
---------------------------------------------------------------------------

    \18\ Similar to the 2015 rule and consistent with discussions 
with engineering firms and plant staff, EPA assumed that in order to 
meet the limitations and standards, plants would take steps to 
optimize wastewater flows as part of their operating practices (by 
reducing the FGD purge rate or recycling a portion of their FGD 
wastewater back to the FGD system), where the FGD system metallurgy 
can accommodate an increase in chlorides. See Section 5.2.1 of the 
Supplemental TDD.
---------------------------------------------------------------------------

    Both chemical precipitation and biological treatment are well-
demonstrated technologies that are available to steam electric power 
plants for use in treating FGD wastewater. In addition to the 39 plants 
using chemical precipitation that were mentioned in the 2015 rule 
preamble, plants have installed, or have begun installation, of such 
systems, and have taken steps to cease using surface impoundments to 
treat their FGD wastewater. This trend is expected to continue in 
response to the April 11, 2021 cease receipt of waste date in the CCR 
Part A final rule. In addition, thousands of industrial plants 
nationwide have used chemical precipitation for the last several 
decades, as described in the 2015 rule record. Ultrafilters downstream 
of the biological treatment stage are designed to remove suspended 
solids--i.e., any reduced, insoluble selenium, mercury, or other 
particulates--exiting the bioreactor. Ultrafiltration uses a membrane 
with pore size small enough to remove these smaller suspended 
particulates after the biological treatment stage, but still much 
larger than the pore size of the membrane filtration technology (which 
uses nanofiltration or reverse osmosis). Membrane filtration is the 
basis for Option C and the VIP under Options A and B, and is designed 
to remove dissolved metals and inorganics (e.g., nutrients, bromides, 
etc.). Unlike the nanofiltration and reverse osmosis technologies 
included as the technology in Option C and the VIP, ultrafilters do not 
generate a brine that would require encapsulation with FA or other 
disposal techniques. The types and quantities of solids removed by the 
ultrafilter in the CP+LRTR treatment system are similar to the 
particulates captured in other multimedia filters (e.g., sand filters), 
or settled out in HRTR or surface-impoundment-based systems with longer 
residence times. These systems do not result in the same non-water 
quality environmental impacts that are associated with the brine 
generated by the membrane filtration technology.
    After accounting for the changes in the industry described in 
Section V of this preamble, at the time Changes to Industry Profile for 
Coal-Fired Generating Units for the Steam Electric Effluent Guidelines 
Final Rule (DCN SE08688) was developed 15 steam electric power plants 
with wet scrubbers that discharge FGD wastewater are expected to 
already have technologies in place that can meet the final BAT effluent 
limitations for FGD wastewater.\19\ Of these 15 plants, seven are 
currently operating anoxic/anaerobic biological treatment designed to 
substantially reduce nitrogen compounds and selenium in their FGD 
wastewater. These biological treatment

[[Page 64662]]

systems are a mix of low and high hydraulic residence time.\20\ EPA 
identified an eighth plant that previously operated an anoxic/anaerobic 
biological treatment system, but more recently installed a thermal 
system for the treatment of FGD wastewater. See DCN SE08964. A ninth 
plant is also operating an anoxic/anaerobic biological treatment 
system, but is expected to retire all generating units by 2028. Another 
six steam electric power plants are operating thermal treatment systems 
for FGD wastewater; one of these is expected to retire all generating 
units by 2028.
---------------------------------------------------------------------------

    \19\ Two plants will retire or cease burning coal prior to 2028. 
The remaining 13 plants represent 14 percent of steam electric power 
plants with wet scrubbers. EPA notes that 35 percent of all steam 
electric power plants with wet scrubbers use FGD wastewater 
management approaches that eliminate the discharge of FGD wastewater 
altogether. But, although these technologies (described above in 
Section V.C.1) may be available to some plants, none of them are 
available nationwide, and thus do not form the basis for the final 
BAT limitation. For example, evaporation impoundments are only 
practical in certain climates. Similarly, complete recycle FGD 
systems are only available at plants with appropriate FGD 
metallurgy. Facility conditions and availability of these 
technologies have not materially changed since the 2015 rule, and 
EPA thus reaffirms that these technologies are not available 
nationwide and are not a basis for the final BAT limitations.
    \20\ In addition to these seven plants, some plants employ other 
types of biological treatment. Some of these systems are sequencing 
batch reactors (SBR), which treat nitrogen and can be operated to 
remove selenium. The SBR systems currently operating at steam 
electric power plants, however, would likely not be able to meet the 
limitations discussed in the final rule without reconfiguration.
---------------------------------------------------------------------------

    In the 2015 rule, EPA rejected three availability arguments made 
against biological treatment. EPA solicited comment on retaining its 
2015 findings concerning biological treatment, and no new information 
was provided by commenters suggesting that EPA's 2015 analysis was 
incorrect. Instead, EPA has continued to confirm its prior findings 
concerning the availability of biological treatment. First, EPA 
rejected the argument that maintaining a biological system over the 
long run is infeasible. Of the nine full-scale systems mentioned above, 
three plants have used the biological technology for more than a 
decade, with varying operating conditions, climate conditions, and coal 
sources, to treat FGD wastewater. Many pilot tests of the biological 
technology have been conducted at various plants, and data from these 
tests demonstrate that, even in the face of major upsets during 
chemical precipitation, the biological stage continues to reduce 
selenium and nitrogen.
    In the 2015 rule, EPA also rejected the argument that selenium 
removal efficacy is subject to the type of coal burned and coal-
switching. Plants have continued to operate biological treatment 
systems while switching coals and, in those cases, have maintained 
selenium removal. Furthermore, at least three pilot- and one full-scale 
system have now been successfully run or installed to treat FGD 
wastewater at plants burning subbituminous coals or blends of 
bituminous and subbituminous coals, encompassing both HRTR and LRTR 
technologies.
    Finally, in the 2015 rule, EPA rejected arguments that cycling 
plants up and down in production, and even out of service for various 
periods of time, would affect the ability of plants to meet the 
effluent limitations. Industry provided data for two plants showing 
that they successfully operated biological systems while cycling 
operations and undergoing shutdowns in the years since the 2015 rule.
    While the rationale above applies to both CP+HRTR and CP+LRTR 
technologies, EPA is establishing BAT based on the CP+LRTR technologies 
rather than the CP+HRTR technologies. Some commenters pointed out that 
CP+HRTR technologies are still available and economically 
achievable,\21\ and argued that EPA is thus obligated to select 
CP+HRTR. EPA agrees that CP+HRTR continues to be available and 
economically achievable; however, after considering the statutory 
factors in section 304 of the CWA (as EPA is required to do), EPA does 
not find that CP+HRTR is the Best Available Technology Economically 
Achievable. CP+LRTR pollutant reductions are comparable to CP+HRTR 
pollutant reductions,\22\ are less costly, and require significantly 
less process or plant footprint modifications than the CP+HRTR option.
---------------------------------------------------------------------------

    \21\ Without support, some commenters also suggested that 
CP+LRTR and CP+HRTR are the same technologies. A more detailed 
response is provided in Response to Public Comments for Revisions to 
the Effluent Limitations Guidelines and Standards for the Steam 
Electric Power Generating Point Source Category (DCN SE08615).
    \22\ For example, while the effluent from CP+LRTR is more 
variable than from CP+HRTR, both technologies achieve long-term 
average effluent concentrations for selenium lower than 20 mg/L.
---------------------------------------------------------------------------

    As explained in Section XIII of this preamble, the long-term 
averages forming the basis of the selenium limitations for CP+LRTR and 
CP+HRTR are similar, and the higher selenium limitations for the 
CP+LRTR systems are largely driven by increased short-term variability 
around that average, rather than a meaningful difference in long-term 
pollutant removals.\23\ Some commenters argued that CP+LRTR pollutant 
reductions are not comparable to HRTR pollutant reductions. EPA 
disagrees with these commenters and rejects this characterization for 
several reasons. First, these comments appear to be limited to a single 
pollutant: Selenium. When comparing the limitations of all four 
regulated pollutants (mercury, arsenic, selenium, and nitrate/nitrite) 
in the 2015 rule to this final rule, some limitations are more 
stringent, while others are less stringent.\24\ Some commenters 
expected the limitations and long-term averages for all constituents to 
be less stringent with CP+LRTR as compared to CP+HRTR due to the 
shorter residence time. This is not the case. Indeed, some limitations 
become more stringent due, in part, to the different design of CP+LRTR 
systems, which include ultrafiltration in the prefabricated systems 
delivered for pilot studies and full-scale installations to date.\25\ 
Thus, to the extent that commenters relied on the limitations and long-
term averages to make this argument, EPA concludes it is reasonable and 
allowed by the Act to consider removals as a whole, which results in 
comparable removals for the suite of pollutants in FGD wastewater 
discharges.
---------------------------------------------------------------------------

    \23\ Courts have recognized that while section 301 of the CWA 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 [. . 
.]'').
    \24\ While these four indicator pollutants are regulated, the 
record for the 2015 rule and current final rule both indicate 
reductions in many other pollutants.
    \25\ To the extent that limits become more stringent due to the 
use of data from pilot studies with chemical precipitation systems 
designed to meet the 2015 rule limits prior to the biological 
treatment components, CP+HRTR limits would also be expected to 
become more stringent to some extent.
---------------------------------------------------------------------------

    Second, even taking selenium in isolation, EPA disagrees that a 
simple comparison of numeric limitations and long-term averages is the 
only way to identify pollutant removals attainable through the 
application of BAT. It can be misleading to look at the numeric 
limitations in isolation. Instead, EPA has considered pollutant 
concentrations in treated effluent as compared to those in raw FGD 
wastewater. In the 2015 rule TDD, EPA estimated the average selenium 
concentration in untreated FGD wastewater as 3,130 ug/L. Using this for 
comparison demonstrates that both the CP+LRTR and CP+HRTR treatment 
trains remove more than 99 percent of selenium initially present in FGD 
wastewater. Even were EPA to examine incremental removals, when 
compared to the performance of surface impoundments under existing BPT 
regulations, both treatment trains would remove more than 99 percent of 
the selenium remaining after physical settling. EPA also notes that 
both the long-term average and the actual limitations for selenium in 
this final rule are more stringent than they were in the proposed rule. 
In summary, CP+LRTR and CP+HRTR are two very effective selenium removal 
technologies. Between these two, EPA selected as BAT the technology 
that is also less costly and requires significantly less modification 
of a plant's process or footprint.

[[Page 64663]]

    CP+LRTR is less costly than the CP+HRTR technology selected as the 
BAT basis of the 2015 rule. Compared to the baseline of the 2015 rule, 
CP+LRTR is estimated to save approximately $52 million per year in 
after-tax costs to industry \26\ While the CP+HRTR costs are 
economically achievable, EPA finds those costs unreasonable for a 
treatment technology that would result in marginal additional 
reductions in selenium and that would result in marginal increases in 
other pollutants, such as mercury.
---------------------------------------------------------------------------

    \26\ Due to the final rule's changed compliance dates, this 
estimate also includes discounting which may overstate the savings.
---------------------------------------------------------------------------

    CP+LRTR requires fewer process changes than CP+HRTR. Compared to 
HRTR, LRTR installations are less complex and require fewer 
modifications to a plant's footprint. The HRTR systems used as the 
basis for BAT in the 2015 rule were large, concrete tanks, which, along 
with their associated piping and pumping and control equipment, would 
be fabricated on site. By contrast, new LRTR systems have smaller 
footprints, and in many cases come prefabricated as modular components, 
including the ultrafilter polishing stage, and require little more than 
a concrete foundation, electricity supply, and piping connections. For 
further public comments and responses regarding HRTR and LRTR, see DCN 
SE08615.
a. Membrane Filtration
    Except for plants participating in the VIP discussed below, the 
final rule does not establish BAT limitations based on membrane 
filtration (Option C). EPA received many comments arguing both in favor 
and against the use of membrane filtration as BAT for treatment of FGD 
wastewater, including comments on the technology's availability, costs, 
economic achievability, and non-water quality environmental impacts. 
With respect to availability, some commenters argued that the 
technology is available, citing pilot studies, three full-scale foreign 
installations,\27\ use in other industrial sectors, and vendor claims 
of product performance. Other commenters argued that this technology is 
not available due to uncertainties regarding the extent of pretreatment 
required to ensure reliable treatment performance and management of the 
resulting brine. With respect to costs, some commenters argued that 
costs were overestimated due to decreasing EGU use, resulting in 
reduced flow volumes that require treatment; while other commenters 
argued that costs were underestimated due to incomplete pretreatment 
costs (e.g., microfiltration rather than full chemical softening), 
failure to analyze costs using maximum design flows, missing cost 
components, and underestimated ash needs for brine management. With 
respect to economic achievability, some commenters pointed to 
uncertainties about the costs and asserted that membrane filtration 
would not be economically available for some plants. Finally, with 
respect to non-water quality environmental impacts, some commenters 
argued that many plants currently make beneficial use of some or all of 
their FA (a practice that could be hindered if plants use membrane 
filtration); while other commenters argued that beneficial use of FA 
would not be affected by use of membrane filtration and that EPA failed 
to evaluate alternative brine management methods.
---------------------------------------------------------------------------

    \27\ The record at proposal included three full-scale foreign 
installations.
---------------------------------------------------------------------------

    As the summary of comments presented above makes clear, EPA 
received a wide range of comments on membrane filtration technology. 
After carefully considering the statutory factors for BAT and available 
data, EPA is rejecting membrane filtration as BAT. First, based on 
significant information gaps and uncertainties in EPA's record, EPA 
cannot conclude that membrane filtration is technologically available 
nationwide, as required by the CWA. Second, the Agency finds that, on a 
nationwide basis, membrane filtration entails unacceptable non-water 
quality environmental impacts associated with management of the 
membranes' byproduct, brine. Finally, while the factors above are 
sufficient to reject membrane filtration as BAT, EPA also notes that 
membrane filtration would result in higher costs to industry.
    At the time of the 2015 rule, EPA had no record of information 
about membrane filtration technologies. Since that time, EPA collected 
information on several types of membrane filtration technologies. 
Microfiltration and ultrafiltration membranes are used primarily for 
removing suspended solids, including colloids. Nanofiltration, reverse 
osmosis, forward osmosis, and electrodialysis reversal (EDR) membranes 
are used to remove a broad range of dissolved pollutants. Each of these 
membrane filtration technologies generate both a treated effluent and a 
residual wastestream that requires further treatment or disposal. 
Microfiltration and ultrafiltration generate a solid waste residual, 
which is disposed of. Nanofiltration, reverse osmosis, forward osmosis, 
and EDR all produce a concentrated brine residual which must be 
disposed of. At proposal, EPA considered nanofiltration, reverse 
osmosis, forward osmosis, and EDR membranes and proposed effluent 
limitations for the VIP option based specifically on a combination of 
microfiltration and reverse osmosis membrane technologies.
    Other industries use a variety of different types of membrane 
filtration technologies. EPA met with vendors that have installed 
membrane systems in several industries, including textiles,\28\ 
chemical manufacturing,\29\ mining,\30\ and agriculture.\31\ Within the 
steam electric power generation industry, reverse osmosis membranes are 
a technology used for treating EGU makeup water and cooling tower 
blowdown, and EDR membranes are a technology used for treating ash 
impoundment discharges.\32\ Nevertheless, it cannot be assumed that 
membrane filtration technology is transferable, and the information 
presented below demonstrates that, despite its use in other industries, 
there may be technical issues constraining its use for treating FGD 
wastewater.
---------------------------------------------------------------------------

    \28\ ERG. 2020. Final Notes from Call with Dupont. DCN SE08618.
    \29\ ERG. 2020. Final Notes from Call with Dupont. DCN SE08618.
    \30\ ERG. 2019. Final Notes from Meeting with Pall Water. (5 
March). EPA-HQ-OW-2009-0819-7613; Wolkersdorfer, Christian et al. 
2015. Intelligent mine water treatment--recent international 
developments. (21 July). DCN SE08581; U.S. EPA. 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.
    \31\ CH2M Hill. 2010. Review of Available Technologies for the 
Removal of Selenium from Water. (June). DCN SE08583.
    \32\ EPRI (Electric Power Research Institute). 2015. State of 
Knowledge: Power Plant Wastewater Treatment--Membrane Technologies. 
August. 3002002143.
---------------------------------------------------------------------------

    EPA's record demonstrates that no domestic steam electric power 
plants have installed full-scale nanofiltration, reverse osmosis, or 
EDR membrane filtration systems to remove dissolved pollutants in FGD 
wastewater.\33\ A vendor email cited by some commenters erroneously 
asserted that a full-scale installation of such a technology had begun 
at Georgia Power's Plant Scherer. Follow-up discussions with staff 
working on that project revealed that the plant is not installing a 
permanent full-scale membrane technology to treat FGD wastewater, but 
is performing a long-term pilot of both membrane filtration and 
biological treatment systems to

[[Page 64664]]

evaluate possible compliance alternatives under planned future changes 
to the plant (see DCN SE08619). The State of Maryland also informed EPA 
that three GenOn plants planned to install technologies to meet the 
2015 rule VIP effluent limitations. In a teleconference call held to 
learn more about these plans, GenOn staff stated that one of these 
plants (Dickerson) had announced its retirement, but confirmed that the 
other two (Chalk Point and Morgantown) are currently considering 
reverse osmosis systems (see DCN SE08614).\34\ EPA views GenOn's 
consideration of membrane technology similarly to the bids and 
engineering reports for full-scale systems that the agency was aware of 
at proposal. As discussed at proposal, the sources of the bids and 
engineering reports expressed concerns about operating a technology on 
this wastewater that would be the first of its kind in the U.S. While 
bids, engineering reports, and one company considering potential 
membrane installations are important considerations in evaluating the 
availability of a technology, they do not demonstrate that the 
technology is available under the CWA. Because no full-scale membrane 
filtration system for treatment of FGD wastewater is yet operating 
domestically, EPA carefully considered available data from pilots, 
foreign installations, and other industries.
---------------------------------------------------------------------------

    \33\ Ultrafiltration has been installed as part of several FGD 
wastewater treatment systems in the U.S. and is included as a back-
end component of the CP+LRTR BAT established in this final rule; 
however, these membranes are only capable of removing suspended 
solids, not dissolved pollutants.
    \34\ The company indicated that plans for both units will depend 
on the requirements of this final rule, and also, for one of its 
units, changing electricity demand.
---------------------------------------------------------------------------

    With respect to pilots, EPA is aware of at least 19 previous or 
ongoing domestic pilot studies and one foreign pilot study of FGD 
wastewater treatment using four different membrane filtration 
technologies.\35\ All of these technologies first used some form of 
suspended solids removal, such as microfiltration or chemical 
precipitation. This pretreated FGD wastewater was then fed into either 
nanofiltration, reverse osmosis, or EDR membrane filtration systems. 
For several of the pilot studies, the resultant brines were mixed with 
FA and/or lime to test the potential for encapsulation of the 
concentrated brine wastestream.\36\
---------------------------------------------------------------------------

    \35\ Two of these pilot studies were completed in 2014, but 
information about these tests was not provided to EPA prior to the 
2015 rule.
    \36\ The record includes additional encapsulation studies and 
data not explicitly linked to these 19 pilots.
---------------------------------------------------------------------------

    EPA is aware of 12 foreign installations: One in South Korea, one 
in Finland, and 10 in China. EPA's rulemaking record contains very 
limited information about these plants. When EPA contacted Doosan about 
its system in South Korea, the company declined to share plant 
operation, maintenance, or performance information, and indicated that 
it was not interested in the U.S. market. Similarly, EPA contacted 
Lenntech regarding its system in Finland, but has received no 
information about this plant's operation, maintenance, or performance.
    Regarding the plants in China, EPA is generally aware that two of 
the plants employ pretreatment and a combination of reverse osmosis and 
forward osmosis. But EPA was not able to obtain further information 
about the specific configurations, maintenance, or long-term 
performance of these two systems.\37\ EPA also has no information about 
how the resultant brine is being managed or disposed of. Furthermore, 
the company that sold these two systems has since ceased commercial 
operations.\38\ EPA is aware that two other plants operating in China 
employ pretreatment followed by nanofiltration and reverse osmosis. As 
with the systems above, the vendors declined to provide plant 
operation, maintenance, or performance information to EPA. The 
remaining Chinese systems were developed by DuPont, which met with EPA 
after proposal to provide what limited information was available. While 
DuPont has sold six systems to Chinese plants to treat FGD wastewater, 
the company did not have access to operation, maintenance, or 
performance data for these systems.
---------------------------------------------------------------------------

    \37\ This is in contrast to biological treatment systems for 
which EPA has long-term performance data. Although LRTR and HRTR 
systems differ in their configuration (e.g., residence time), the 
underlying performance has been well demonstrated on this 
wastewater.
    \38\ DCN SE08034 contains a story summarizing the forward 
osmosis company Oasys ceasing commercial operations.
---------------------------------------------------------------------------

    Due to travel restrictions in place during the COVID-19 pandemic in 
spring and summer 2020, EPA representatives were unable to travel 
abroad to visit these plants. Because the vendor companies either 
ceased operations or declined to provide EPA with information about the 
operation, maintenance, or performance of their membrane filtration 
products, and EPA's lack of regulatory authority to compel the 
production of information from foreign plants, EPA's record has 
significant information gaps on the operation and performance of 
membranes used to treat FGD wastewater.
    With respect to the use of membrane filtration in other industries 
and in connection with non-FGD power plant wastestreams, given what is 
known about FGD wastewater, EPA focused its evaluation on the more 
challenging wastewaters in other industries. In the mining industry, 
reverse osmosis is employed to treat mine-influenced water. For 
example, since 2006, the Bingham Canyon Water Treatment Plant (BCWTP) 
at the Kennecott South Superfund site treats 3,200 gallons per minute 
of mine-influenced water and has maintained a TDS removal efficiency of 
98.9 percent, given an expected influent TDS of approximately 2,000 mg/
L.\39\ Mining wastewaters demonstrate some similar challenges seen in 
FGD wastewaters, but there are also differences in the two 
wastestreams. For example, both are highly scaling in gypsum,\40\ but 
as the BCWTP example demonstrates, mining influent TDS concentrations 
can be an order of magnitude (or more) lower than the TDS 
concentrations found in some FGD wastewater streams.\41\ In the mining 
industry, brine generated by reverse osmosis is typically disposed of 
through evaporation, deep well injection, or ocean discharge.\42\
---------------------------------------------------------------------------

    \39\ U.S. EPA (Environmental Protection Agency). 2014. Reference 
Guide to Treatment Technologies for Mining-Influenced Water. EPA 
542-R-14-001. Office of Superfund Remediation and Technology 
Innovation. March. Available online at: https://clu-in.org/download/issues/mining/Reference_Guide_to_Treatment_Technologies_for_MIW.pdf 
(DCN SE09084).
    \40\ Patel, S. 2020. Rethinking Wastewater Treatment for Better 
FGD Economics. Power Magazine. May 31. Available online at: https://www.powermag.com/rethinking-wastewater-treatment-for-better-fgd-economics/ (DCN SE09085).
    \41\ The FGD wastewater treatment system pilot tests that were 
highlighted in the petitions for reconsideration of this rule 
illustrate this point. EPRI. 2017. Biological Treatment of Flue Gas 
Desulfurization Wastewater at a Power Plant Burning Powder River 
Basin Coal--Pilot Demonstration with the ABMet Technology. EPA-HW-
OW-2009-0819-6480.2.
    \42\ U.S. EPA (Environmental Protection Agency). 2014. Reference 
Guide to Treatment Technologies for Mining-Influenced Water. EPA 
542-R-14-001. Office of Superfund Remediation and Technology 
Innovation. March. Available online at: https://clu-in.org/download/issues/mining/Reference_Guide_to_Treatment_Technologies_for_MIW.pdf 
(DCN SE09084).
---------------------------------------------------------------------------

    In the oil and gas industry, there are several applications and 
opportunities for membrane filtration, recently summarized by Adham et 
al. (2018).\43\ For example, nanofiltration is used worldwide for 
sulfate removal in offshore oil and gas operations. Reverse osmosis is 
the standard treatment for coal seam gas water in Australia, where 
regulations restrict underground

[[Page 64665]]

injection. Reverse osmosis is also a standard treatment for 
desalination (i.e., TDS removal) in this industry. In contrast to the 
uses for mining wastewaters discussed above, the oil and gas industry's 
use of membranes typically involves wastewaters with TDS concentrations 
at least as high as those found in FGD wastewater, but with different 
scaling potential. Within the oil and gas industry, underground 
injection, evaporation, and ocean discharge are common disposal methods 
for the resulting brine.
---------------------------------------------------------------------------

    \43\ Adham, S., Hussain, A., Minier-Matar, J., Janson, A., 
Sharma, R. 2018. Membrane applications and opportunities for water 
management in the oil and gas industry. Desalination. 440. 2-17. 
Available online at: https://www.sciencedirect.com/science/article/pii/S0011916417321380 (DCN SE09087).
---------------------------------------------------------------------------

    Membrane filtration technologies are also employed for other, non-
FGD wastestreams at steam electric power plants. Reverse osmosis is a 
generally accepted, standard practice for treating EGU makeup water at 
steam electric power plants.\44\ EGU makeup water is often treated 
groundwater or surface water which would, therefore, not have TDS or 
scaling potential similar to FGD wastewater. Reverse osmosis has also 
been used to treat cooling tower blowdown at several coal-fired and 
non-coal-fired steam electric power plants. According to one reverse 
osmosis technology vendor, cooling tower blowdown has similar scaling 
potential to FGD wastewater. EPA does not have information in this 
record to either confirm this statement or to extrapolate this finding 
to the industry more broadly; however, scaling is a known issue for 
cooling tower water, which is ultimately blown down.\45\ The vendor 
that made this statement sold the system, comprising microfiltration 
followed by reverse osmosis, to a plant to treat high TDS cooling tower 
blowdown that was corroding its brine concentrators (thermal systems). 
This membrane filtration system was able to replace the brine 
concentrators, resulting in a reduction of parasitic load in cooling 
tower blowdown and substantial cost savings.\46\ Finally, EDR has also 
been used at a power plant in South Korea to treat ash transport water 
for further use as FGD makeup water.\47\ While ash transport water can 
have high variability, there is no information in the record suggesting 
that ash transport water has scaling potential or TDS concentrations 
similar to FGD wastewater.
---------------------------------------------------------------------------

    \44\ EPRI (Electric Power Research Institute). 2015. State of 
Knowledge: Power Plant Wastewater Treatment--Membrane Technologies. 
August. 3002002143.
    \45\ Daniels, D.G. 2015. Winning the Cooling Tower Trifecta: 
Controlling Corrosion, Scale, and Microbiological Fouling. Power 
Magazine. August 21. Available online at: https://www.powermag.com/winning-the-cooling-tower-trifecta-controlling-corrosion-scale-and-aqmicrobiological-fouling/ (DCN SE09088).
    \46\ Drake, M., Wise, S., Charan, N., and Venkatadri, R. 2012. 
ZLD Treatment of Cooling Tower Blowdown with Membranes. WaterWorld. 
December. Available online at: https://www.watertechonline.com/process-water/article/16211541/zld-treatment-of-cooling-tower-blowdown-with-membranes (DCN SE09089).
    \47\ https://www.ge.com/in/sites/www.ge.com.in/files/GE_solves_ash%20pond_capacity_issue.pdf (DCN SE09090).
---------------------------------------------------------------------------

    After evaluating all available information on membrane filtration, 
EPA has concluded that critical uncertainties remain regarding 
operation of the suite of membrane filtration technologies that the 
Agency evaluated as the basis for Option C. With respect to data from 
the pilot studies, these studies focused on membrane technologies 
intended to remove dissolved pollutants. Several studies of the 
technologies designed to remove dissolved pollutants either did not 
include a second stage of membrane filtration (i.e., a reverse osmosis 
polishing stage, which electric utilities and vendors indicated would 
need to be part of any potential future membrane filtration system that 
they would consider installing to operate with a discharge) or provided 
only summaries of effluent data because of nondisclosure agreements 
between EPRI, treatment technology vendors, and/or the plant operators. 
Both of these limitations prevented EPA from fully analyzing the 
pollutant removal efficacy and effluent variability associated with the 
treatment systems used in those studies. The pilot tests that omitted 
the second stage of membrane filtration do not provide sufficient 
insight into the performance capabilities of the membrane technology 
because the initial membrane filtration step (e.g., a nanofilter unit) 
does not by itself remove the broad range of pollutants as effectively 
as would be achieved by the two-stage configuration. The pilot tests, 
for which EPA has only summary-level data, provide summary statistics, 
such as the observed range of pollutant concentrations, average 
influent and effluent pollutant concentrations, and duration of the 
testing periods. EPA, however, lacks the individual daily sample 
results that are needed to fully evaluate treatment system operation 
and calculate effluent limitations. Complete data sets were only 
available from three pilot plants using a single vendor's reverse 
osmosis technology.\48\ EPA further finds that use of data from 
treatment of non-FGD wastewaters in this and other industries would not 
be appropriate because the other wastewaters that are currently being 
treated by membrane filtration systems at full scale differ in 
variability, scaling potential, TDS, or a combination thereof.
---------------------------------------------------------------------------

    \48\ These three data sets served as the basis of the final VIP 
limitations, described further in Section XIII of this preamble. 
These limited data sets do not provide sufficient information to 
evaluate the performance of nanofiltration and reverse osmosis 
membrane filtration technology as the primary treatment for 
dissolved pollutants in FGD wastewater. Additional pilots, tests, 
and data collection could result in these technologies becoming 
available by the VIP compliance date of 2028; however, the VIP 
compliance date is not based on an assumption that the technology 
will be available by 2028.
---------------------------------------------------------------------------

    Some commenters argue that certain data limitations are not 
sufficient to reject membrane filtration systems as BAT for FGD 
wastewater because such systems can be operated as no discharge 
systems. EPA agrees that membrane filtration systems can be operated as 
no discharge systems; however, due to the significant data gaps in the 
record, EPA cannot conclude that such systems can operate continuously 
as no discharge systems for FGD wastewater, nor that they can operate 
as no-discharge systems on FGD wastewater in all cases, nor that their 
continuous operation would not result in other unacceptable non-water 
quality impacts. Staff working on one current membrane filtration pilot 
indicated that, with additional flexibility to reuse membrane 
filtration permeate as EGU makeup water, the plant may consider a no-
discharge alternative in the future. At present, however, the pilot is 
being conducted to determine the feasibility of operating a membrane 
filtration system with a discharge, including the evaluation of 
pretreatment and post-treatment to comply with the proposed VIP mercury 
limitations. Similarly, while GenOn indicated that it is considering 
installing membrane filtration systems that would recirculate permeate 
as a no discharge system, GenOn acknowledged that at least some 
discharges would eventually be necessary, for example when the EGU is 
not operating or is being retired.
    While the limited information in EPA's record on foreign 
installations may suggest that these systems operate as no-discharge 
systems, EPA does not have information on these systems' long-term 
performance to confirm that they continually operate as no-discharge 
systems, whether there are some periods during which discharges occur, 
or whether their operation may result in other unacceptable non-water 
quality impacts. Furthermore, the information that EPA does possess on 
foreign installations indicates that pretreatment before membrane 
filtration is a challenge due to FGD wastewater

[[Page 64666]]

variability. This is consistent with the public comments received on 
the proposal, as well as the main focus of the long-term pilot at Plant 
Scherer. In contrast to the thermal system that EPA visited in Italy 
before the 2015 rule (and where EPA took samples and discussed the 
system with experienced engineers), EPA does not have access to the 
Chinese plants to resolve some of the critical unanswered questions 
discussed above.
    Supplementing what is known about pilot studies and foreign plants 
with information about the use of membrane filtration on non-FGD 
wastestreams in this and other industries still does not address or 
resolve the uncertainties in EPA's record. Although EPA acknowledges 
that some of the other wastewaters discussed above are subject to 
operational variability, scaling potential, and high levels of TDS, the 
unique combination of these factors present in steam electric FGD 
wastewater favors EPA's conclusion that membrane filtration is not 
available for treatment of FGD wastewater at all plants in the steam 
electric power generating industry.\49\ Nevertheless, like evaporation-
based and thermal treatment technologies, FGD wastewater may be 
amenable to treatment with membrane filtration technologies in at least 
some circumstances. Thus, EPA's conclusion that membranes are not 
available nationwide, as required under the CWA, does not conflict with 
EPA's finding that membrane filtration may be available at specific 
sites for purposes of the VIP.
---------------------------------------------------------------------------

    \49\ While one membrane vendor commented that FGD wastewater is 
no different than any other industrial wastewater, it did not 
provide any data or analysis to support this statement.
---------------------------------------------------------------------------

    EPA also rejects membranes as the technology basis for BAT for all 
existing plants because it could discourage more valuable forms of 
beneficial reuse of FA (such as replacing Portland cement in concrete), 
causing more FA to be disposed of as waste.\50\ While EPA agrees with 
comments that there may be several alternative ways to treat or dispose 
of the brine generated by membrane filtration, as discussed further 
below, plants are most likely to encapsulate the brine with FA and lime 
and dispose of the resulting solid in a landfill.
---------------------------------------------------------------------------

    \50\ While EPA considers FA use for waste solidification and 
stabilization as beneficial use, the CCR waste being solidified or 
stabilized must still be disposed of in accordance with 40 CFR 257.
---------------------------------------------------------------------------

    In concluding that the selection of membranes as BAT would result 
in unacceptable non-water quality environmental impacts, EPA evaluated 
brine management alternatives that were discussed with domestic plants 
employing thermal systems, foreign plants employing membrane filtration 
systems, and domestic plants in other industries employing membrane 
filtration systems.\51\ EPA also evaluated whether FA is being disposed 
of or is being sold and productively reused. After careful review of 
the information in the record for this rulemaking, EPA projects that, 
in the United States, the least cost option if membrane filtration were 
selected would be encapsulation with FA and lime and disposal of the 
resulting solid in a landfill. The following paragraphs summarize the 
evaluations which led to EPA's conclusion that there is an unacceptable 
non-water quality environmental impact in selecting membrane filtration 
systems as BAT.
---------------------------------------------------------------------------

    \51\ EPA did not evaluate alternatives which would not be 
available to the industry (e.g., unlike offshore oil and gas 
facilities, ocean discharge would not be available to inland power 
plants).
---------------------------------------------------------------------------

    There are no domestic plants operating membrane filtration systems 
for EPA to contact. EPA therefore contacted two domestic plants 
operating thermal FGD systems and examined information submitted to 
EPA's Region 1 regarding a third thermal FGD system. Thermal and 
membrane filtration systems generate similar brines, as both increase 
the concentration of TDS in FGD wastewater by removal of ``clean'' 
water. For the three domestic thermal systems treating FGD wastewater, 
the resultant brine is either used to condition (i.e., wet) ash for 
disposal without encapsulation\52\ or is crystallized and sent to a 
landfill. Thus, encapsulation of the brine using FA at these three 
plants is unnecessary. When asked about the availability of FA for 
sale, one of the three plants indicated that its particular market for 
FA is flush, and that plant was no longer able to maintain contracts 
for the sale of its FA, which would make it available for the plant to 
use to encapsulate the thermal system brine. In contrast, two of the 
plants with which EPA discussed possible future installations of 
membrane filtration systems stated that they sell 100 percent of the FA 
generated for beneficial reuse. Although some commenters suggested that 
there is more than sufficient FA available for reuse, the EPA's 
rulemaking record contains information to the contrary. According to 
2017 and 2018 EIA data, the median percentage of FA that was sold for 
beneficial use by plants with wet FGD systems was approximately 14 
percent, with some plants selling all of their fly ash and some plants 
selling none. Furthermore, these EIA estimates may be low, as one 
plant's staff represented that they were beneficially using 100 percent 
of their FA rather than the amount reported in the EIA data.\53\ A 
quantitative comparison of EIA data for plants with FGD wastewater 
indicates that if plants currently disposing of their FA installed 
membrane filtration, they may have enough FA to encapsulate the 
quantities of brine produced by membrane filtration. Two assumptions 
underly EPA's comparison of EIA FA beneficial use and disposal data to 
FGD brine encapsulation. First, EPA assumes that the fraction of brine 
generated from all FGD wastewaters is the same at all plants that would 
install a membrane system. Second, it assumes that all plants that 
would install a membrane system would be able to make use of similar 
encapsulation blends as the bids and pilots which EPA reviewed. In 
practice, EPA expects the percent of brine generated by membrane 
systems to differ from plant to plant, based on FGD wastewater 
characteristics. EPA also expects the encapsulation blend to differ 
from plant to plant based on both the brine characteristics and the fly 
ash characteristics. This is consistent with public comments EPA 
received on the proposal. Thus, while EPA's assumption of a typical 
blend is reasonable for a nationwide assessment, the Agency anticipates 
that there will be sites where non-water quality environmental impacts 
are particularly unacceptable.\54\
---------------------------------------------------------------------------

    \52\ Ash conditioning with water or surfactants is a standard 
industry practice to control fugitive dust emissions, and also a 
standard component of fugitive dust plans required under the CCR 
rule.
    \53\ EPA was unable to resolve the conflicting company-stated 
beneficial use rates at this plant with the plant-specific EIA data.
    \54\ While there may be some sites where these non-water quality 
environmental impacts are acceptable, the Agency has not identified 
either information or a consistent basis upon which to subcategorize 
these plants. In any case, such a subcategorization approach may 
still not address the availability concerns raised in the discussion 
above.
---------------------------------------------------------------------------

    But, while these assumptions are appropriate for nationwide cost 
estimates which are needed to demonstrate economic achievability for 
the industry as a whole, this does not necessarily mean that these 
assumptions should be used for analyzing the non-water quality 
environmental impacts associated with the resultant brine from membrane 
use, and in particular, estimating what plants are likely to do with 
this by-product in relation to available FA. Whether sufficient FA is 
present on site or available in the local market is a site-specific 
question. Should plants generate more brine than EPA estimated in its 
analysis, or should plants not have the quality of FA (e.g., class C, 
class F) necessary for the

[[Page 64667]]

assumed blend, those plants would need to reduce the quantity of ash 
beneficially reused or acquire a substitute to encapsulate the brine 
byproduct of an installed membrane system.
    Based on the limited available information, EPA understands that at 
least two foreign plants operating full-scale membrane systems send the 
resulting brine to a crystallizer to generate and sell a 95 percent 
high-purity industrial salt. However, there are too many uncertainties 
for EPA to estimate with confidence how many plants in the United 
States might be able do the same. EPA understands that these foreign 
plants engaged in negotiations with end-users prior to commissioning 
their membrane systems. At one example system, the plant generates and 
sells approximately 10,000 tons of industrial-grade salt per year. 
While a crystallizer would be a more expensive option than ash 
conditioning practiced at no-discharge plants in the U.S., the sale of 
industrial salt could generate additional revenue to offset those 
additional costs. Without salt revenue data from China, it is not 
possible to compare these specific scenarios either in terms of costs 
or non-water quality environmental impacts and any conclusions would be 
speculative and lack factual support in this rulemaking record. 
Furthermore, EPA cannot evaluate the practicality of such sales in the 
U.S. because the Agency does not know which industries are purchasing 
these salts, if these industries operate in the U.S., if they would be 
willing to purchase salts from the U.S., or what the specifications are 
for the salt product.
    Finally, EPA examined brine management in other industries. In both 
the mining industry and in oil and gas, brine is managed through 
evaporation (including evaporation impoundments), deep well injection, 
and ocean discharge. Most steam electric power plants are not near 
enough to an ocean for ocean discharge to be a feasible alternative. 
Evaporation is more consistent with disposal methods at the domestic 
thermal and foreign membrane filtration plants discussed above. The use 
of evaporation impoundments is generally dependent upon climate and 
plant space, so not all steam electric power plants may be able to 
employ evaporation impoundments as is done at some mining and oil and 
gas establishments. However, crystallization is an evaporation means 
that is employed at some domestic and foreign plants to manage FGD 
wastewater brine. Finally, deep well injection is not known to be used 
at any steam electric power plants to manage FGD wastewater brine.
    After consideration of the information above, EPA evaluated 
membrane filtration with three representative brine management 
alternatives to determine which could most likely represent future 
brine management. First, as it did for the proposed rule, EPA evaluated 
brine encapsulation with FA and lime, in a blend representative of the 
information in EPA's record.\55\ Second, EPA conducted a sensitivity 
analysis which examined crystallization and disposal of the resultant 
salt.\56\ Finally, EPA conducted a sensitivity analysis which examined 
deep well injection. While EPA received comments that the brine might 
be sold to oil and gas companies, commenters did not provide any 
examples where this is currently occurring, nor is the Agency aware of 
any. Thus, as it did for ocean discharge (see above), EPA concluded 
that direct sale of brine to oil and gas companies would not be 
representative of potential brine management in the steam electric 
power generating industry.
---------------------------------------------------------------------------

    \55\ This scenario is representative not only of that blend, but 
also of blends that would use more or less fly ash and/or lime, as 
well as less expensive ash conditioning, in which ash is wetted just 
with the brine (in lieu of other water or surfactants) prior to 
disposal.
    \56\ This scenario could also be representative of 
crystallization with sale of the resultant salt; however, EPA's 
rulemaking record lacks information with which to analyze potential 
sales.
---------------------------------------------------------------------------

    After conducting these three representative brine management 
analyses, EPA concludes that the method most likely to be employed by 
steam electric power plants using membrane filtration to treat FGD 
wastewater would be encapsulation with FA and lime for disposal of the 
resulting solid in a landfill. This brine management alternative was 
the least cost solution in the bids and engineering documents examined, 
was the least cost solution in EPA's own cost estimates, and is the 
disposal approach discussed by both Georgia Power \57\ and GenOn \58\ 
as their most likely procedure if theyose ultimately choose to 
participate in the VIP and install membrane filtration systems by the 
2028 compliance date.
---------------------------------------------------------------------------

    \57\ In discussions about the potential for Plant Scherer to 
install a membrane filtration technology under the proposed VIP, 
Georgia Power staff indicated that should such an installation 
occur, it would make use of a paste landfill where encapsulation of 
brine would occur.
    \58\ GenOn indicated that plans for Chalk Point and Morgantown 
included off-site disposal without FA from those plants because so 
much of that FA is already beneficially used.
---------------------------------------------------------------------------

    As described in the proposal, landfilling an encapsulated material 
raises challenges. For instance, comingling encapsulated material with 
other landfill refuse could result in a leachate blowout. The King 
County Landfill in Virginia experienced a leachate blowout when compact 
CCR materials with a low infiltration rate were layered with normal 
municipal solid waste having a higher infiltration rate. Similarly, in 
the case of encapsulated brine paste, the paste would set and 
thereafter achieve a very low infiltration rate. When comingled with 
CCR having a higher infiltration rate, this would lead to layers with 
disparate infiltration rates akin to those experienced in the King 
County scenario. Thus, segregation of low infiltration rate 
encapsulated brine in a landfill cell separate from other, higher 
infiltration wastes could be necessary to prevent this layering and a 
potential leachate blowout. Such dedicated landfill cells do not exist 
today and would require time to permit and construct.\59\
---------------------------------------------------------------------------

    \59\ EPA also estimates that the volume of waste requiring 
disposal if membrane filtration was selected is 10 times the volume 
of waste estimated under the selected LRTR technology.
---------------------------------------------------------------------------

    Moreover, instead of disposing of their FA, plants can sell it for 
beneficial use. As stated in the 2015 CCR rule:

    The beneficial use of CCR is a primary alternative to current 
disposal methods. And as EPA has repeatedly concluded, it is a 
method that, when performed correctly, can offer significant 
environmental benefits, including greenhouse gas (GHG) reduction, 
energy conservation, reduction in land disposal (along with the 
corresponding avoidance of potential CCR disposal impacts), and 
reduction in the need to mine and process virgin materials and the 
associated environmental impacts.\60\
---------------------------------------------------------------------------

    \60\ 80 FR 21329 (April 17, 2015).

    Specifically, the Agency estimated (U.S. EPA 2011) that each ton of 
FA used as a substitute for Portland cement would avoid the use of 
5,400 megajoules of nonrenewable energy, 690 liters of water use, 
1,000,000 grams (g) of CO2 emissions, 840 g of methane 
emissions, 1,400 g of CO emissions, 2,700 g of NOX 
emissions, 2,500 g of SOX emissions, 2,400 g of PM, 0.08 g 
of Hg, 490 g of TSS discharge, 23 g of BOD discharge, and 46 g of COD 
discharge.\61\ After considering these cross-program environmental 
impacts, EPA finds that discouraging this beneficial use of FA on a 
nationwide basis would result in unacceptable non-water-quality

[[Page 64668]]

environmental impacts.\62\ As discussed below in connection with the 
VIP, however, EPA finds that, based on site-specific circumstances, the 
non-water quality environmental impacts identified on a nationwide 
basis could exist to a lesser extent (thereby not resulting in 
unacceptable non-water quality environmental impacts).\63\
---------------------------------------------------------------------------

    \61\ U.S. EPA (Environmental Protection Agency). 2011. Waste and 
Materials--Flow Benchmark Sector Report: Beneficial Use of Secondary 
Materials--Coal Combustion Products. Office of Solid Waste and 
Emergency Response. Washington, DC 20460. April.
    \62\ Although EPA evaluated FA and lime encapsulation as the 
least-cost nationally available brine disposal alternative, other 
alternatives with higher costs may also have adverse non-water 
quality environmental impacts. For example, if a plant chose to 
crystallize the resulting brine to continue selling its FA, this 
thermal crystallization process could have a higher cost and 
parasitic energy load.
    \63\ The same would be true for other VIP-compliant technologies 
(e.g., thermal) that might be installed.
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    While EPA views the foregoing reasoning as sufficient to find that 
membrane filtration is not BAT for existing sources, EPA notes that 
membrane filtration is projected to cost industry 26 percent more than 
estimated at proposal. As identified by commenters, the data used to 
establish limitations for membrane filtration for the proposed rule 
included pilots that preceded membrane filtration with chemical 
precipitation, while the cost estimates were based only on 
microfiltration as pretreatment. EPA agrees. Where EPA has information 
on pretreatment at foreign plants, none of those plants relies on 
microfiltration alone. To correct this inconsistency, in the final 
rule, EPA included the cost of chemical precipitation as the 
pretreatment method for the membrane filtration cost estimates and 
adjusted the set of data used to establish effluent limitations. For 
the final rule, both effluent limitations and cost estimates reflect 
data for systems using chemical precipitation as pretreatment before 
membrane filtration. EPA disagrees with comments that suggested the 
costs were not estimated correctly due to the use of incorrect flows 
and FA consumption rates. For a more detailed discussion of the 
membrane filtration public comments and responses, see DCN SE08615.
    In addition to the estimated pretreatment costs, plants will also 
incur costs to dispose of the resulting brine. Some plants that may 
otherwise sell their FA may choose to use their FA to encapsulate the 
brine, thereby foregoing revenue from FA sales. Other plants that 
choose to continue to sell their FA will need to dispose of the brine 
using another disposal alternative, such as crystallization, at an 
additional cost. Costs are a separate statutory factor that EPA 
considers in selecting BAT (see, for example, BP Exploration & Oil, 
Inc. v. EPA, 66 F.3d 784, 796 (6th Cir. 1996)). Here, while these costs 
do not make the membrane filtration option economically unachievable 
across the point source category as a whole,\64\ these estimated 
increased costs do weigh against selecting membranes as BAT.
---------------------------------------------------------------------------

    \64\ See, e.g., Texas Oil and Gas Ass'n et al. v. EPA, 161 F.3d 
923, 927 (5th Cir. 1998).
---------------------------------------------------------------------------

b. Other Technologies Evaluated for BAT Limitations
    As described further below, EPA is also not establishing BAT 
limitations based on other technologies evaluated in the 2019 proposed 
rule and 2015 rule.
    First, except for the permanent cessation of coal combustion and 
low-utilization subcategories discussed below, EPA is not establishing 
BAT limitations based on surface impoundments. One commenter suggested 
that EPA should adopt a high recycle rate system for FGD wastewater if 
the purge from such a system would receive BAT limitations equal to BPT 
limitations. The commenter relied on EPA's proposed BAT for BA 
transport water for this suggestion. Even for the purged wastewater 
from a high recycle rate BA transport water system, however, the final 
rule does not establish BAT limitations equal to BPT limitations. 
Instead, EPA leaves the BAT limitations to be determined by the 
permitting authority on a case-by-case basis, subject to BPJ. Such a 
case-by-case determination is not warranted for FGD wastewater because 
EPA has determined that CP+LRTR is available and economically 
achievable for treatment of FGD wastewater. Furthermore, EPA confirms 
its previous findings that surface impoundments are not as effective at 
controlling pollutants (such as dissolved metals and nutrients) as 
available and achievable technologies like CP+LRTR; however, as 
described in Section X below, other statutory factors and EPA's 
rulemaking record support the use of surface impoundments for two 
subcategories.
    Second, except for the low utilization EGU subcategory discussed 
below, the final rule does not establish BAT limitations or PSES based 
on chemical precipitation alone. As EPA noted during the development of 
the 2015 rule, chemical precipitation is effective at removing mercury, 
arsenic, and certain other heavy metals. This technology alone does not 
remove nitrogen, nor does it remove the majority of selenium. 
Furthermore, the data in EPA's rulemaking record demonstrate that both 
LRTR and HRTR remove approximately 90 percent of the mercury remaining 
in the effluent from chemical precipitation treatment.\65\ Because the 
combination of chemical precipitation with LRTR provides substantial 
further reductions in the discharge of pollutants industry-wide, EPA 
has established BAT based on CP+LRTR.
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    \65\ Recall that the FGD mercury and arsenic limitations in the 
2015 rule were based on chemical precipitation data alone because 
the plants operating biological systems were not using all of the 
chemical precipitation additives in the technology basis.
---------------------------------------------------------------------------

    Third, the final rule does not establish BAT limitations based on 
thermal technologies, such as chemical precipitation (including 
softening) followed by a falling film evaporator, based on the 
statutory factors of total costs to industry and non-water quality 
environmental impacts. EPA received comments stating that thermal 
technologies are available, are unavailable, are economically 
achievable, and are not economically achievable. EPA agrees that these 
technologies are available but disagrees that these technologies are 
economically achievable. Although commenters arguing against 
availability raise a number of arguments, these arguments were 
considered and rejected in the 2015 rule, and no new information has 
been provided that warrants revisiting those findings. Since the 2015 
rule, EPA has collected additional information on full-scale 
installations and pilots of thermal technologies to treat FGD 
wastewater. EPA's rulemaking record includes information about nine 
pilot studies conducted in the United States, providing performance 
data for five different thermal technologies. In addition, full-scale 
installations are operating at six domestic plants,\66\ and a seventh 
purchased thermal equipment, but elected not to install it.\67\ EPA is 
also now aware of seven foreign installations in Italy and China, five 
more foreign installations than at the time of the 2015 rule.
---------------------------------------------------------------------------

    \66\ One of these plants successfully ran three different 
thermal systems to treat its wastewater, transitioning from a 
falling film evaporator to a direct-contact evaporator, which mixes 
hot gases in a high turbulence evaporation chamber, and finally to a 
spray dryer evaporator.
    \67\ This plant purchased a falling film evaporator for the 
purpose of meeting water quality-based effluent limitations for 
boron, but then elected to instead pay approximately $1 million per 
year to send its wastewater to a local POTW.
---------------------------------------------------------------------------

    With respect to economic achievability, in the 2015 rule EPA 
rejected thermal technology as a basis for BAT limitations due to high 
costs to industry. New thermal technologies have been pilot tested and 
used at full scale since the 2015 rule, and related

[[Page 64669]]

cost information demonstrates that thermal technologies are now less 
costly than when estimated for the 2015 rule. Nevertheless, the thermal 
costs evaluated in EPA's memorandum FGD Thermal Evaporation Cost 
Methodology (DCN SE08631) are still 2.4 times higher than the CP+LRTR 
technology selected as BAT, and 1.04 times higher than the membrane 
filtration costs in Option C. As authorized by section 304(b) of the 
CWA, which requires EPA to consider costs, as well as the discretion 
that the statute gives EPA to weigh the statutory factors, the Agency 
finds that, for this final rule, thermal technologies are not BAT due 
to the unreasonably high costs to industry.\68\ Given the high costs 
associated with thermal technology, and the fact that the steam 
electric power generating industry continues to face costs associated 
with several other rules, in addition to this rule, EPA is not 
establishing BAT limitations for FGD wastewater based on thermal 
technologies.
---------------------------------------------------------------------------

    \68\ Some industry comments asserted that EPA underestimated the 
cost for thermal technologies and that more accurate costs would 
make these technologies economically unachievable. However, as 
described above, EPA need not adjust its cost assumptions because 
the Agency's own cost estimates result in unreasonably high costs.
---------------------------------------------------------------------------

    In addition to the unreasonably high costs, thermal technologies 
have unacceptable non-water quality environmental impacts associated 
with management of the resultant brine. Thermal technologies generate a 
brine similar to membrane filtration technologies. For this reason, 
portions of the discussion of membrane filtration brine above are based 
on brine management at plants with thermal systems. EPA also concludes 
that thermal technologies have unacceptable non-water quality 
environmental impacts. The reasoning is the same as for membrane 
filtration--unacceptable non-water quality environmental impacts would 
occur as a result of discouraging the beneficial use of FA, and 
additional disposal requirements would result from the production of a 
brine byproduct.
    Furthermore, since the membrane filtration technologies evaluated 
in Option C appear to achieve similar pollutant removals at lower costs 
than thermal, as discussed later in this section, EPA is revising the 
basis for the VIP limitations adopted in the 2015 rule to membrane 
filtration, instead of thermal technologies.\69\
---------------------------------------------------------------------------

    \69\ EPA notes that thermal technologies could continue to be 
used to meet the voluntary incentives program limitations based on 
membrane filtration.
---------------------------------------------------------------------------

    Finally, EPA is declining to establish BAT limitations for FGD 
wastewater as a case-by-case determination to be made by the permitting 
authority using BPJ. EPA explained in the 2015 rule why BPJ 
determinations would not be appropriate for FGD wastewater, 
particularly given the availability of several other technologies, and 
nothing in EPA's record would alter the Agency's previous conclusion.
2. BA Transport Water
    Under the final rule, EPA has selected high recycle rate systems as 
the technology basis for establishing the BAT requirements to control 
pollutants discharged in BA transport water. EPA determines that this 
technology is available and economically achievable after evaluating 
the factors specified in CWA section 304(b)(2)(B). In the 2015 rule, 
EPA selected dry BA handling or closed-loop wet ash handling systems as 
the technology basis for the no-discharge BAT requirements for BA 
transport water. EPA established no discharge effluent limitations 
based on these technologies, while also creating a limited allowance 
for pollutant discharges associated with leaks and certain maintenance 
activities.\70\
---------------------------------------------------------------------------

    \70\ See 40 CFR 423.11(p).
---------------------------------------------------------------------------

    At the time of the 2015 rule, EPA estimated that more than 50 
percent of plants already employed dry handling systems or wet sluicing 
systems designed to operate closed-loop, or had announced plans to 
switch to such systems in the near future. Based on new information 
collected since the 2015 rule, EPA now estimates that number to be over 
75 percent of the industry. However, since the 2015 rule, EPA's 
understanding has changed regarding the types of available dry systems, 
and the ability of wet systems to operate a true closed-loop system (or 
to achieve complete recycle) has changed.
    EPA is aware of advances in dry BA handling systems since the 2015 
rule.\71\ For example, in addition to under-EGU mechanical drag chain 
systems (described in the 2015 rule), pneumatic systems and compact 
submerged conveyors (CSCs, which are referred to in the proposed rule 
and in many public comments as submerged grinder conveyors, the 
appellation of the most commonly sold system) are now in use at some 
plants. EPA received comments that it failed to consider whether plants 
could retrofit their operation using CSC systems, and that EPA should 
retain the zero discharge limitations established in the 2015 rule. EPA 
also received comments that CSCs could be more costly than other 
technologies and that CSCs are not available. These included comments 
that CSCs are not demonstrated, that CSCs cannot handle the high ash 
loading rates of larger EGUs, and that retrofit with CSCs are not 
feasible for EGUs below grade or with space constraints leaving the 
EGU.
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    \71\ The term ``dry handling'' is used to refer to ash handling 
systems that do not use water as the transport medium for conveying 
ash away from the EGU. Such systems include pneumatic and mechanical 
processes (some mechanical processes use water to cool the BA or 
create a water seal between the EGU and ash hoppers, but the water 
does not act as the transport medium).
---------------------------------------------------------------------------

    EPA disagrees with commenters who asserted that it failed to 
consider zero discharge requirements for BA transport water. While the 
Agency acknowledges that it did not identify technologies that could 
achieve zero discharge of BA transport water among its ``main'' 
regulatory options at proposal, the 2015 rule required zero discharge, 
and EPA described the technologies forming the basis for the 2015 rule 
and considered them and others, including CSCs, in this rulemaking.
    With respect to costs, since the proposal, EPA has conducted 
conference calls with two plants, one of which operates a vacuum system 
and one that operates a CSC. The Agency acknowledges that, at proposal, 
it did not estimate costs of installing pneumatic systems (which 
include both dry vacuum or pressure systems) or CSCs. In the case of 
pneumatic systems, these systems tend to be more expensive than 
alternatives, and third party EPCs have indicated that the decision to 
install such systems is often driven by a combination of space 
constraints and limitations on water withdrawals. EPA continues to view 
pneumatic systems as more expensive than alternatives. With respect to 
CSCs, the Agency did not have cost data at proposal to conduct a cost 
analysis; however, since proposal the Agency has obtained CSC cost 
information from one plant, which demonstrates that for that plant it 
was the least-cost technology alternative. The costs for this plant are 
comparable to other technologies that EPA evaluated, and this finding 
is consistent with the representations of electric utilities, vendors, 
and third-party EPC firms, which have found that, on a plant-specific 
basis, CSCs may be the least costly bottom ash conversion option. 
However, because CSCs serve only an individual EGU, the more EGUs a 
plant has, the less economical this technology becomes. One vendor 
suggested that plants with three or more EGUs would generally find 
remote MDSs to be a least-cost alternative.
    With respect to availability, commenters disputed that CSCs are 
demonstrated, but did not make the

[[Page 64670]]

same claim for pneumatic systems. Two full-scale CSCs became 
operational in 2019,\72\ while 50 plants employing pneumatic systems 
are currently operating, with retrofits dating back to 1992. EPA is 
aware of only two CSCs in operation domestically today; however, the 
Agency has identified three additional CSCs currently being installed. 
Furthermore, in a conference call with one plant, it appears that, 
while there were some challenges, especially during installation, this 
particular system has operated successfully since its commissioning. 
However, this plant did not experience the same space constraints 
discussed below. Similarly, commenters raised issues with the ability 
of CSCs to handle high ash loading rates. While staff at one plant 
indicated that they successfully ramped up the speed of their CSC to 
handle more tons of ash per hour, and constructed a 100 percent 
redundant system, AEP submitted comments that the installation of CSCs 
at a larger lignite EGU with high ash loading rates would be considered 
high ``application risk.'' \73\ Specifically, the lignite coal burned 
in this EGU has a much higher ash content, and its bottom ash tends to 
be more abrasive, relative to the typical bituminous coals burned and 
bottom ash produced at other AEP EGUs. As a result, 100 percent 
redundant systems would be required, which would eliminate the cost 
savings potential of the CSC system.\74\ In contrast, no commenters 
claimed that pneumatic systems had loading rate constraints. Finally, 
industry engineers, third-party EPC firms, and vendors have indicated 
that pneumatic systems and CSCs can be installed at plants that are 
constrained from retrofitting the larger under-EGU MDS due to 
insufficient vertical space under the EGU. EPA has identified five EGUs 
at three plants where MDS installation is precluded due to insufficient 
vertical space. Commenters stated that CSCs, while smaller, could not 
be installed at these space-constrained plants where MDS installation 
is precluded without dismantling and excavating beneath the EGU, and 
EPA finds that, at a minimum, these five EGUs could face such 
limitations. AEP additionally described EGUs where space constraints 
would not preclude installation of a single CSC, but would preclude the 
installation of AEP's required 100 percent redundant design basis.\75\ 
Commenters did not argue that space constraints would preclude 
pneumatic systems.
---------------------------------------------------------------------------

    \72\ EPA only had a conference call with one of these two plants 
because the second plant did not respond to EPA outreach.
    \73\ AEP indicated that the vendor had found this application to 
be high risk as well.
    \74\ See DCNs SE08695 and SE08695A1.
    \75\ See DCNs SE08695 and SE08695A1.
---------------------------------------------------------------------------

    With respect to wet BA handling systems, in their petitions for 
reconsideration and in recent meetings with EPA, utilities and trade 
associations informed EPA that many existing remote wet systems are, in 
reality, ``partially closed'' rather than fully closed-loop, as assumed 
by EPA in the 2015 rule. Utilities and trade associations informed EPA 
that these systems operate partially closed, rather than closed, due to 
small discharges associated with: (1) Additional maintenance and repair 
activities not accounted for in the 2015 maintenance allowances; \76\ 
(2) water imbalances within the system, such as those associated with 
stormwater; \77\ and (3) water chemistry imbalances, including acidity 
and corrosiveness, scaling, and fines buildup. While some plants have 
controlled or eliminated these challenges with relatively 
straightforward steps (See DCNs SE08179 and SE06963), others require 
more extensive process changes and associated increased costs or find 
them difficult to resolve (See DCNs SE08188, SE08180, and SE06920).
---------------------------------------------------------------------------

    \76\ The 2015 rule maintenance discharges were characterized as 
not a significant portion of the system volume, compared to, for 
example, potential discharges resulting from maintenance of the 
remote MDS tank or the conveyor itself. Such maintenance could 
require draining the entire system, which would not be permissible 
under the 2015 rule maintenance discharge allowance.
    \77\ The 2015 rule provided no exemption or allowance for 
discharges due to precipitation events. While systems are often 
engineered with extra capacity to handle rainfall and runoff from a 
certain size precipitation event, these events may occur back-to-
back, or plants may receive events with higher rates of accumulation 
beyond what the plant was designed to handle.
---------------------------------------------------------------------------

    EPA agrees that the new information indicates that some plants with 
wet ash removal systems can operate as zero discharge systems, but in 
many cases must operate as high recycle rate systems. While some plants 
currently handle the challenges discussed above by discharging some 
portion of their BA transport water, the record demonstrates that 
plants can likely eliminate such discharges with additional process 
changes and expenditures. For the 2015 rule, EPA estimated costs of 
chemical additions to manage scaling. Now, companies could be adding 
additional treatment chemicals (caustic) to manage acidity or other 
chemicals to control alkalinity, using reverse osmosis filters to 
remove dissolved solids from a slipstream of the recycled water, adding 
polymer to enhance settling and removal of fine particulates 
(``fines''), and building storage tanks to hold water during infrequent 
maintenance or precipitation events. Industry-wide, EPA conservatively 
estimates the costs of the additional measures needed to achieve and 
maintain a truly closed-loop system to be $63 million per year in 
after-tax costs, beyond the costs of the systems 
themselves.78 79 These additional costs and process changes 
were not accounted for in the 2015 rule; however, as discussed in 
Section 5.3.3 of the Supplemental TDD, EPA has accounted for these 
costs in estimating the baseline costs of the BA limitations in the 
2015 rule. Some commenters argued that EPA's costs were too 
conservative and asserted that these costs would not be necessary at 
most sites. While EPA agrees that it is not likely that all plants 
would incur these additional costs, EPA had no means to predict which 
plants would ultimately incur these additional costs, and thus the 
Agency reasonably assumed, for purposes of its economic achievability 
analysis, that each plant would incur these costs--in order to ensure 
that the costs upon which economic achievability are based are not 
underestimated. However, to the extent that necessary purges are 
smaller than this upper bound, EPA evaluated an alternate scenario in a 
Bottom Ash Alternate Purge Sensitivity Analysis (DCN SE09073). These 
lower costs were considered in addition to the costs presented above 
and would not change EPA's conclusion that high recycle rate systems, 
rather than closed-loop systems, are BAT. For further discussion of 
public comments and responses about closed loop and high recycle rate 
systems, see DCN SE08615.
---------------------------------------------------------------------------

    \78\ Due to the final rule's changed compliance dates this 
estimate also includes discounting, which may overstate the savings.
    \79\ Utilities and EPC firms have discussed the availability of 
new dry systems, such as the CSC or pressure systems, which at some 
plants would have costs similar to recirculating wet systems (which 
would require a purge). Because EPA did not have cost information to 
determine the subset of plants for which new dry systems might be 
least costly, some portion of the costs estimated for this rule may 
be based on selecting recirculating wet systems at plants that could 
ultimately choose to install dry handling technologies. Thus, EPA 
may overestimate costs or underestimate pollutant removals at the 
subset of plants where such a dry system would be selected.
---------------------------------------------------------------------------

    EPA also recognizes the need for plants to consider their ability 
to comply with multiple environmental regulations simultaneously. As 
discussed in Section IV above, EPA has recently finalized the CCR Part 
A rule, requiring plants to cease receipt of waste in unlined surface 
impoundments by April 11, 2021 (with certain

[[Page 64671]]

exceptions).\80\ The challenges of operating a truly closed-loop 
system, discussed above, are compounded by the requirements of the CCR 
rule. Plants often send various CCR and non-CCR wastestreams, such as 
coal mill rejects, economizer ash, etc., with BA transport water into 
their surface impoundments. According to reports provided to EPA and 
conversations with electric utilities, several plants have already 
begun (or even completed) the transition away from impoundments and use 
the BA treatment system for some of their non-CCR (i.e., non-FA, BA, or 
FGD) wastewaters.\81\ This can be beneficial where it reduces the 
discharge of the non-CCR wastewaters, which might otherwise be 
discharged subject only to the TSS limitations applicable to low volume 
wastewater. At the same time, however, doing so can lead to or 
exacerbate scaling, corrosion, or plugging of equipment, all of which 
require process changes and additional expense to address, thereby 
complicating establishment of a closed-loop system. These problems 
could be avoided by purging the system from time to time, as necessary. 
Fewer than 25 percent of plants have not yet installed a BA transport 
water technology beyond surface impoundments and could potentially 
employ a dry system. However, due to the fast approaching cease-
receipt-of-waste date under the CCR rule, it is probable that the 
majority of these plants have already begun their conversions to wet 
ash handling systems, which makes switching to a wholly different BA 
handling technology infeasible so late into the process.\82\ For EPA to 
not allow a purge may encourage more of the non-CCR wastewaters 
mentioned above to be discharged as low volume waste. In order to 
accommodate both compliance with this rule and the CCR Part A rule, EPA 
finds it necessary for the permitting authority to allow for a high 
recycle rate system with some purge rather than a truly closed-loop 
system.
---------------------------------------------------------------------------

    \80\ As mentioned in Section IV of this preamble, further 
information about this proposal is available at http://www.regulations.gov, Docket EPA-HQ-OLEM-2019-0172.
    \81\ In some cases, the treatment system predated even the 
proposed CCR rule.
    \82\ The CCR Part A rule acknowledges that a subset of plants 
which were lined or met the groundwater monitoring requirements and 
location restrictions may not yet have taken steps to convert their 
systems.
---------------------------------------------------------------------------

    Furthermore, to the extent that plants had not designed, planned, 
procured, or commissioned segregated non-CCR wastewater treatment 
systems yet, requiring a plant to close the loop where closed loop 
operation would require wastewater segregation may force those plants 
to continue to send the non-CCR wastewater to their existing surface 
impoundments, thus extending their surface impoundment operations until 
new non-CCR wastewater systems can be commissioned. Some comments point 
to CCR rule requirements and Duke Energy's installation of lined 
retention basins in an attempt to demonstrate that non-CCR wastewaters 
can be managed separately within the 2015 rule time frames. EPA 
disagrees in both instances. While it might be possible for the 
retention basins being installed by Duke Energy to handle redirection 
of all of these non-CCR wastewaters, Duke Energy itself did not design 
for this, and instead designed and currently operates at least some of 
its high recycle rate systems to handle non-CCR wastewaters.\83\ The 
CCR Part A rule generally requires plants to cease receiving waste in 
unlined surface impoundments no later than April 2021. Nevertheless, in 
cases where alternative capacity is not available, plants may request a 
site-specific alternative closure extension to operate that surface 
impoundment until 2023 or 2024. Thus, if the final rule were to require 
complete recycling of BA transport water, and this could only be 
accomplished by segregating wastewaters, at least some plants that 
might currently be able to meet the CCR Part A rule's April 2021 cease-
receipt-of-waste date would instead be forced to request a site-
specific alternative closure extension and continue operating the 
existing, unlined surface impoundment while they developed alternative 
disposal capacity to manage these newly segregated wastestreams.
---------------------------------------------------------------------------

    \83\ For example, Duke Energy's Belews Creek plant manages its 
coal mill rejects wastestream in its recently commissioned remote 
mechanical drag system.
---------------------------------------------------------------------------

    In light of the foregoing process changes and associated 
engineering challenges facing plants needing to implement a true zero 
discharge BA transport water limitation in combination with the CCR 
rule, and to give plants flexibilities that will facilitate orderly 
compliance with the fast-approaching CCR rule deadlines, EPA determines 
that the basis of the BA transport water BAT limitations is the use of 
high recycle rate systems rather than dry handling or closed-loop 
systems, which were the technologies on which the zero discharge BAT 
limitation (adopted in the 2015 rule) were based. EPA's conclusion is 
based on its discretion to give particular weight to the CWA Section 
304(b) statutory factor of ``process changes.'' Process changes to 
existing high recycle rate, non-closed loop systems made to comply with 
this rule in conjunction with the CCR rule, as discussed above, could 
be more challenging without a further discharge allowance, and in some 
plants could also prolong use of unlined surface impoundments.
    EPA concludes that the factors discussed above are sufficient to 
support the Agency's decision not to select dry handling or closed-loop 
systems as BAT for BA transport water. EPA also notes that cost is a 
statutory factor that it must consider when establishing BAT, and that 
closed-loop systems cost more than high recycle rate systems for 
treatment of BA transport water. Some commenters stated that high 
recycle rate systems cannot be selected solely on the basis of higher 
costs when those costs are economically achievable. While EPA does not 
find the estimated additional cost to industry would result in plant 
closures, cost is a statutory factor that EPA must consider under 
section 304(b) of the CWA, and EPA has discretion in weighing the 
statutory factors, see, e.g., BP Exploration & Oil Inc. v. EPA, 66 F.3d 
784, 799-800 (6th Cir. 1995) (citation omitted)). EPA views the higher 
cost of fully closed-loop systems as an additional factor supporting 
EPA's decision to reject closed-loop systems as BAT for treating BA 
transport water.
    Some commenters argued that the proposed BAT based on high recycle 
rate systems is not warranted because that technology basis does not 
represent what is achieved by the single best performing plant, and 
even went so far as to say that this standard reflected the worst 
performing plant. EPA disagrees with these commenters. Some companies 
began proactive fleetwide conversions either before the effective dates 
of the 2015 rule or in some cases before the 2015 rule was signed. Many 
of these fleetwide conversions were to the remote MDS, a specific type 
of high recycle rate system that formed the ``closed-loop'' part of the 
2015 rule BA transport water BAT technology basis. As discussed above, 
these systems do not all operate 100 percent closed-loop, as EPA 
assumed they did when finalizing the 2015 rule. Based on actual, 
measured purge rates in EPRI (2016), however, the Agency estimates that 
actual purge rates necessary on a day-to-day basis may be less than one 
percent of the system's volume, with higher purges necessary at less 
frequent intervals due to precipitation and maintenance. Furthermore, 
while surface impoundments can cover dozens of acres and contain 
volumes in the billions of gallons, typical high

[[Page 64672]]

recycle rate systems have volumes closer to one-half million gallons 
(\1/2\ million). Thus, even assuming the proposed maximum allowable 
purge of 10 percent is necessary for a unit, the average gallons per 
day released by high recycle rate systems will be two percent of the 
average gallons per day released by surface impoundments, and therefore 
will also be 1.5 percent of the pollutant releases expected from 
surface impoundments. Industry-wide, EPA estimates this combination of 
reduced volume and increased recycling reduces discharges by 366 
million pounds of pollutants per year, and thus makes reasonable 
further progress toward the CWA goal to eliminate the discharge of 
pollutants. See 33 U.S.C. 1251(a), 1311(b)(2)(A). Therefore, it is the 
combination of the reduced system volume and high capacity to recycle 
BA transport water that supports EPA's basis for high recycle rate 
systems as BAT.
    The Agency also received comments that a generic 10 percent purge 
was not justified and that tighter limitations could be applied in some 
cases. One state commenter argued that it should be permissible for a 
permitting authority to continue to set zero discharge requirements. 
EPA has considered these comments and made modifications to improve the 
final rule. EPA is finalizing the site-specific alternative for which 
it solicited comment. Under the final rule, EPA establishes that the 
NPDES permitting authority will determine on a case-by-case basis the 
purge allowance (not to exceed 10 percent) necessary at a particular 
plant with a wet transport system.\84\
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    \84\ While this could include a purge of zero percent, EPA 
believes that such a determination could only occur in those cases 
where the system is designed to function, and is demonstrated to 
successfully perform, as a zero discharge system.
---------------------------------------------------------------------------

    As with the proposal, this site-specific purge could in no case 
exceed 10 percent of the system volume per day on a 30-day rolling 
average. EPA concludes that the maximum purge volume would more than 
account for the challenges identified above, including infrequent large 
precipitation and maintenance events. EPA defines the term ``30-day 
rolling average'' to mean the series of averages using the measured 
values of the preceding 30 days for each average in the series. The 
purge volume is more appropriately determined on a case-by-case basis 
because these plants vary so much with regard to what purge is needed 
to maintain the wastewater treatment system versus the tradeoffs at 
each site regarding what options are available for the non-CCR 
wastewater, Thus, this option is designed to provide flexibility if and 
when needed to address site-specific challenges of operating the 
recirculating ash system (for more on implementation, see Section XIV 
of this preamble).\85\
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    \85\ EPA's pollutant loading analyses provided in Section IX.B 
of this preamble and described in detail in the BCA Report and 
Supplemental TDD, were based on an assumed 10 percent purge at each 
affected plant, and therefore overestimates pollutant discharges 
associated with the BAT for BA transport water.
---------------------------------------------------------------------------

    Some commenters suggested that EPA establish a BMP plan rather than 
a 10 percent purge. Commenters seemed to misunderstand the 10 percent 
purge in relation to BAT. When EPA establishes BAT, it selects a 
technology that is available nationally and economically achievable 
industry-wide. EPA then calculates the effluent limitations expected 
from the performance of the selected technology. Only after 
establishing those limitations might EPA impose an additional BMP plan 
under section 304(e) of the CWA. Here, BAT is high recycle rate 
systems, and based on the available data, EPA has established 
limitations that such systems can achieve.
    Under the final rule's site-specific requirement for determining 
discharge allowances there may be wastewater from whatever is purged by 
the high recycle rate system, and plants may wish to discharge this 
wastewater. At proposal, EPA solicited comment on whether specific 
technologies should be selected as BAT for the purged wastewater. Some 
commenters suggested that surface impoundments should be selected 
because the high recycle rate systems already make reasonable forward 
progress. While EPA agrees that high recycle rate systems make 
reasonable forward progress in accordance with the CWA, the Agency must 
still consider any available treatment alternatives for the purged 
wastewater. Two considerations make determining a nationwide BAT for 
these discharges challenging and site-specific. First, in the case of 
precipitation or maintenance-related purges, such purges could be large 
volumes at infrequent intervals.\86\ Each plant necessarily has 
different climates and maintenance needs that make selecting a uniform 
treatment system more difficult. Second, utilities have stated that 
discharges of wastewater associated with high recycle rate systems are 
sent to low volume wastewater treatment systems, which are typically 
dewatering basins or surface impoundments. Many of these systems are in 
transition as a result of the CCR rule. New wastewater treatment 
systems installed for low volume wastewater and other wastestreams 
(which could be used to treat the wastewater purged from a high recycle 
rate system), as well as the types of wastestreams combined in such 
systems, are likely to vary across plants. For further purge-related 
public comments and responses see DCN SE08615.
---------------------------------------------------------------------------

    \86\ For example, rainfall exceeding a 10 year, 24-hour event 
would only be expected to occur twice during the 20-year lifetime of 
the equipment.
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    In light of the information discussed above, and EPA's authority 
under section 304(b) to consider both the process employed (for 
maintenance needs) and process changes (for new treatment systems 
installed to comply with the CCR rule), EPA concluded that BAT 
limitations for any wastewater that is purged from a high recycle rate 
system and then discharged, should be established by the NPDES 
permitting authority on a case-by-case basis using BPJ. EPA concludes 
that permitting authorities are in a better position than EPA to 
examine site-specific climate and maintenance factors, especially since 
the permitting authority will already be determining the allowable 
volume of purge, up to a maximum of 10 percent of the system's volume. 
Permitting authorities will also be in a better position than EPA to 
account for site-specific treatment technologies and their 
configurations already installed or being installed to comp0ly with the 
CCR rule and other regulations which could accommodate the volumes of, 
and successfully treat, any discharges of wastewater from a high 
recycle rate system associated with the proposed allowance.
    EPA is not identifying surface impoundments as BAT for BA transport 
water because surface impoundments are not as effective at removing 
dissolved metals as available and achievable technologies, such as high 
recycle rate systems. Furthermore, the record since the 2015 rule shows 
that plants have continued to convert away from surface impoundments to 
the types of technologies described above, either voluntarily or due to 
the CCR rule, and in 2018, the U.S. Court of Appeals for the District 
of Columbia vacated that portion of the 2015 CCR rule that allowed both 
unlined and clay-lined surface impoundments to continue operating. 
USWAG v. EPA, No. 15-1219 (D.C. Cir. 2018). Since very few CCR surface 
impoundments are composite-lined, the practical effect of this ruling 
is that many plants with operating impoundments likely will cease 
sluicing waste to these impoundments in the near future. In the 2015 
CCR rule, EPA estimated that it would be less costly for plants to 
install under-EGU or remote

[[Page 64673]]

drag chain systems and send BA to landfills rather than continue to wet 
sluice BA and replace unlined impoundments with composite lined 
impoundments. This supports the suggestion that surface impoundments 
are not BAT for all plants; however, EPA is identifying surface 
impoundments as BAT for two subcategories, as discussed later in this 
section. In addition, EPA is defining a new wastestream, BA purge 
water, which is a more accurate term than the proposed ``maintenance 
purge water.'' BA purge water consists of the water permissibly purged 
from a high recycle rate system. This wastestream is no longer defined 
as BA transport water; therefore EPA is making conforming changes to 
the BPT regulations to make clear that the BPT limitations based on 
surface impoundments for TSS and oil and grease, which are applicable 
to BA transport water, also continue to be applicable to BA purge 
water. Effluent limitations for BA purge water are to be established by 
the permitting authority based on BPJ.
3. Voluntary Incentives Program (VIP)
    The final rule includes a VIP that provides the certainty of more 
time (until December 31, 2028, instead of a date determined by the 
permitting authority that is as soon as possible beginning October 13, 
2021) for plants to implement new BAT limitations if they adopt 
additional process changes and controls that achieve limitations on 
mercury, arsenic, selenium, nitrate-nitrite, bromide, and TDS in FGD 
wastewater, based on membrane plus pretreatment technology. The 2015 
rule included a similar VIP that was based on thermal evaporation 
technology and that would extend the compliance deadline for VIP 
participants by five years. See Section VIII(C)(13) of the 2015 rule 
preamble for a more complete description of the selection of the 
thermal technology basis, chemical precipitation (with softening) 
followed by a falling film evaporator. As in the 2015 rule, EPA expects 
the additional time to achieve compliance, combined with other factors 
(such as the possibility that a plant's NPDES permit may need more 
stringent limitations to meet applicable water quality standards), may 
lead some plants to choose this option for future implementation by 
incorporating the VIP limitations into their permit when applying.
    Some commenters argued that EPA lacks authority under the CWA to 
establish a VIP with compliance deadlines beyond three years from the 
date of promulgation of the final rule. EPA disagrees. The VIP program 
established in the 2015 rule was not challenged in court (and also not 
challenged by these particular commenters who challenged other aspects 
of the 2015 rule). The statute is silent with respect to BAT effluent 
limitations established after 1989. As the U.S. Court of Appeals for 
the Fifth Circuit recently held, the CWA's requirement in 33 U.S.C. 
1311(b)(2)(C), (D), and (F) that effluent limitations be met no later 
than three years after promulgation plainly applies only to initial BAT 
limitations, not revisions of such effluent limitations. Clean Water 
Action v. Pruitt, 936 F.3d 308, 316 (5th Cir. 2018). The compliance 
deadlines in Sections 301(b)(2)(C), (D), and (F) of the CWA only apply 
to effluent limitation guidelines that were established prior to the 
outside dates specified in those provisions. They do not apply to 
effluent limitations guidelines established in 2020. For further 
discussion, see DCN SE08615.
    New information in several utilities' internal analyses and 
contractor reports provided to EPA since the 2015 rule, as well as 
information EPA gathered in meetings with utilities, EPC firms, and 
vendors, indicates that plant decisions to install the more expensive 
thermal systems both prior to and following the 2015 rule were driven 
by water-quality-based effluent limitations imposed by the NPDES 
permitting authority. These documents and meetings also revealed that 
several plants considered installing membrane filtration technologies 
under the 2015 rule VIP as well, and EPA is aware of one company, 
GenOn, that has plants that opted into the 2015 VIP with plans to use 
membrane filtration technologies to meet the VIP limitations. Despite 
membrane filters not being available nationwide and not being 
appropriate for all facilities, due to electric utilities' continued 
interest in this technology, EPA evaluated membrane filtration as an 
alternative basis for the VIP limitations.
    Under the final rule, EPA establishes VIP limitations based on 
membrane filtration, replacing the 2015 rule VIP limitations based on 
thermal technology, because EPA estimates that membrane filtration 
systems are less costly than thermal systems and have comparable 
pollutant removal performance. Membrane filtration achieves pollutant 
removals comparable to thermal systems in situations where the thermal 
system would discharge, which the VIP in the 2015 authorized. Due to 
the significantly higher costs of thermal systems compared to chemical 
precipitation followed by LRTR, EPA does not expect that many plants 
would install a new thermal system under a VIP program as the least 
cost technology, though some might install it to comply with water 
quality-based effluent limitations established by their permitting 
authority.\87\ As authorized by section 304(b) of the CWA, which allows 
EPA to consider costs, EPA is selecting membrane filtration as the 
technology basis for the VIP limitations, with limitations for mercury, 
arsenic, selenium, nitrate-nitrite, bromide, and TDS.\88\
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    \87\ See, e.g., https://www.powermag.com/how-low-temperature-evaporation-treats-fgd-wastewater/ (DCN SE09091).
    \88\ Note that the 2015 rule VIP did not include limitations for 
nitrate/nitrite or bromide.
---------------------------------------------------------------------------

    Also, as authorized by section 304(b) of the CWA, which allows EPA 
to consider process changes and non-water quality environmental 
impacts, EPA is revising the compliance date for the VIP limitations to 
December 31, 2028. That is the date EPA has determined that the 
membrane filtration technology will likely be available for full-scale 
implementation at those plants that choose to adopt it. EPA proposed to 
conclude that membrane technology would be nationally available in 
2028. Some commenters asserted that it is inappropriate for EPA to 
predict a date in the future when a technology will become nationally 
available for CWA purposes. EPA agrees with these commenters and in the 
final rule concludes only that membrane technology will likely be 
available by 2028 on a site-specific basis. Although EPA will continue 
investigating the availability and economic achievability of this 
technology, EPA cannot predict with certainty that the technology will 
be nationally available in 2028.
    The 2028 time frame is based on the time necessary to pilot, 
design, procure, and install both the membrane filtration systems and 
the brine management systems, including disposal capacity. Additional 
time is also often necessary to complete the permitting process. This 
time frame should also be adequate for alternative VIP-compliant 
technologies, such as thermal systems. Because EPA establishes BAT 
effluent limitations based on a specific technology's performance, but 
does not require a specific technology for compliance, thermal systems 
would still be allowable under the final rule VIP program, as would 
alternative non-membrane technologies that meet the limitations.
    Some commenters argued that the 2028 deadline for the VIP is too 
long, citing shorter construction time frames and an email from one 
electric utility

[[Page 64674]]

suggesting a VIP deadline of 2026 would be feasible.\89\ While EPA 
agrees that some plants opting into the VIP may be able to install the 
technology sooner, part of the incentive for the program, which is 
expected to result in substantial additional pollutant removals from 
plants opting in, is the extra time provided to achieve compliance. 
Finally, EPA notes that this time frame is also similar to the eight-
year period between promulgation of the 2015 rule and the 2023 deadline 
for the 2015 rule's VIP. For a further discussion of VIP timing in 
public comments and responses, see DCN SE08615.
---------------------------------------------------------------------------

    \89\ This company appears to be retiring its coal-fired EGUs 
from service, and therefore EPA does not project that it would use 
the VIP whether the deadline is 2026 or 2028.
---------------------------------------------------------------------------

    EPA finds that using membrane filtration as the technology basis 
for the VIP does not result in the same non-water quality environmental 
impacts that informed the Agency's decision not to select membranes as 
BAT for the entire industry. First, participation in the VIP is 
voluntary and EPA would expect it to be selected only by plants for 
which it presents the least cost option, accounting for particular FA 
production, use, disposal and market availability. Where plants have 
limited FA markets and already dispose of their ash, they could dispose 
of the brine using encapsulation or ash conditioning without reducing 
beneficial use of FA. EPA understands that this is the case at Duke's 
Mayo Plant. Other plants may have sufficient external sources of FA and 
landfill space to dispose of an encapsulated material. EPA understands 
that this is the case at GenOn's two remaining Maryland plants. Of 
course, brine disposal options are not the only considerations for 
plants deciding whether to participate in the VIP. As noted above, 
GenOn indicated that final plans for treatment technology for both 
units will depend on the standards of this final rule, and for one of 
its units, changing electricity demand.
    Finally, forthcoming changes in membrane filtration brine disposal 
options may reduce the non-water quality environmental impacts 
associated with encapsulation, as discussed in Section VII(b)(i) above. 
Through discussions with several utilities and EPRI, EPA learned that a 
developing ``paste'' technology may allow plants to mix the brine with 
lower quantities of FA and lime and pump the resulting paste via pipes 
to an onsite landfill where the paste would self-level prior to setting 
as an encapsulated material. According to these discussions, such a 
process may be less costly than current brine disposal alternatives. 
This process could also reduce non-water quality environmental impacts 
by reducing the amount of FA used, decreasing air emissions and fuel 
use associated with trucking and spreading, and, where FA is already 
being disposed of, reduce the volumes and pollutant concentrations in 
leachate.90 91 EPA is aware that part of Plant Scherer's 
current, long-term pilot study is intended to evaluate this very 
process.
---------------------------------------------------------------------------

    \90\ Sniderman, Debbie. 2017. From Power Plant to Landfill: 
Encapsulation. Innovative Technology Offers Elegant Solution for 
Disposing of Multiple Types of Waste. EPRI Journal. September 19. 
Available online at: http://eprijournal.com/from-power-plant-to-landfill-encapsulation/ (DCN SE09092).
    \91\ Although EPA is not establishing BAT for leachate in the 
current rulemaking, the vacatur and remand of BAT for leachate in 
Southwestern Electric Power Co., et al. v. EPA means that decreasing 
volumes of leachate and the concentration of pollutants in that 
leachate might make more technologies available in a future BAT 
rulemaking.
---------------------------------------------------------------------------

    Two additional challenges were identified for the membrane 
filtration technology or the paste technology described above. The 
first challenge regarding the paste alternative is developing 
approaches to manage wastes (e.g., flush water) from periodic cleaning 
of the paste transportation piping, where such piping is used.\92\ 
Consistent with the proposal, and as authorized by section 304(b) of 
the CWA, which allows EPA to consider the process employed, EPA is 
finalizing a modification of the definition of FGD wastewater and ash 
transport water to explicitly exclude water used to clean FGD paste 
piping. This enables plants using paste piping for brine encapsulation 
and disposal in an on-site landfill to clean residual paste from pipes 
and other equipment more easily.
---------------------------------------------------------------------------

    \92\ Utilities described this process as water pushing a ball 
through the paste piping when not in use, based on cleaning done of 
concrete pipes at construction sites. While the ball would clean out 
the majority of the paste, water would still contact incidental 
amounts of ash and FGD materials, thus potentially subjecting it to 
regulations for those wastewaters.
---------------------------------------------------------------------------

    The second challenge is that some plants that might want to re-use 
the first stage, membrane-treated FGD wastewater without a polishing RO 
stage as EGU makeup water could be discouraged from doing so. As 
discussed in Section VII(B)(1) above, RO is the standard treatment for 
source water (e.g., groundwater and surface water) used in the EGU to 
generate steam. These existing systems must ensure sufficiently low 
levels of pollutants (such as TDS) to prevent corrosion, fouling, 
foaming, scale deposits, and loss of heat transfer efficiency within 
the EGU. This extremely clean water is turned into steam at the EGU and 
is used to turn the blades of the turbine to generate electricity 
before being condensed back into water at the cooling towers and 
returned to the EGU. Some plants that participate in the VIP and 
install a membrane filtration system to treat their FGD wastewater by 
the 2028 compliance date might find it advantageous to direct their 
partially treated FGD wastewater through their EGU makeup water RO 
system, instead of employing a second stage RO treatment to meet the 
membrane filtration-based limitations in this rule. In these cases, it 
is unlikely that the FGD wastewater treated using the first stage of 
the membrane filtration treatment system alone would meet the final 
membrane-based limitations (i.e., an internal limitation could not be 
met), and after mixing with other source water (e.g., river water or 
groundwater) at the EGU makeup water RO treatment system, it could be 
infeasible to demonstrate compliance based on existing methods.\93\ 
Small amounts of EGU water are handled as EGU blowdown, which is sent 
to flash tanks where most will turn to steam. While some of the rest 
can be recycled, at times it is necessary to discharge this water, 
subject to existing limitations for low volume waste (as the existing 
regulatory definition of low volume wastes includes EGU blowdown). This 
could occur where the EGU is emptied for maintenance (e.g., to repair 
tube leaks) or shut down (e.g., during outages). Reduced water 
withdrawals are a non-water quality environmental impact that not only 
saves plants money to withdraw and treat significant volumes of water, 
but would also reduce impingement and entrainment. EPA projects that 
the final rule VIP will result in 292,000 gallons per day of reduced 
water withdrawals at eight plants. While some of these reduced water 
withdrawals may be due to increased recycling within the FGD system, at 
least a portion of these reduced withdrawals would be expected where a 
plant used the permeate as EGU makeup water. Therefore, to encourage 
this practice where EGU makeup water is ultimately discharged as EGU 
blowdown, the EPA is making a change from proposal by clarifying that 
membrane permeate and thermal

[[Page 64675]]

distillate used as EGU makeup water is not considered FGD wastewater, 
and is thus removing them from the definition of FGD wastewater at 
423.11(n).
---------------------------------------------------------------------------

    \93\ As discussed in Section XIII of this preamble, the data 
points used for developing limitations of three constituents in the 
VIP included too many non-detect values to develop a monthly limit, 
and these data points did not include dilution water, as would be 
the case here.
---------------------------------------------------------------------------

    A compliance date of December 31, 2028 for the VIP allows time for 
further development of this paste technology, increasing its 
availability to plants, and giving plants more time to acquire any 
necessary permits for landfill cells for brine encapsulated with FA and 
lime if needed; allowing plants time to conduct pilot testing, 
demonstrations, and further analyses to identify and implement process 
changes associated with membrane filtration; and assessing the long-
term performance of the technology for treatment of FGD wastewaster.
    Taken together, EPA's final VIP gives plants greater flexibility 
when choosing a technology to achieve the established VIP pollutant 
limitations, resulting in pollutant reductions beyond the BAT 
limitations that are generally applicable to the industry. Under the 
proposal, EPA estimated that 18 plants may opt into the VIP program. 
Based on public comments and cost estimate revisions, under the final 
rule, EPA now estimates that eight plants (13 percent of plants 
estimated to incur FGD compliance costs) may opt into the VIP program.
    EPA is not finalizing the VIP for PSES for several reasons. First, 
the CWA dictates that plants subject to PSES comply within three years 
after the limitations are promulgated. Thus, the statute does not allow 
for additional time to implement VIP limitations. Second, there are 
only two plants with indirect discharges of FGD wastewater. One of 
these plants has announced its retirement, and EPA expects that plant 
to participate in the subcategory for EGUs permanently ceasing the 
combustion of coal. The other plant has a water quality-based effluent 
limitation that would already call for the use of a technology that 
could meet the VIP limitations. Since a PSES VIP would not grant any 
additional time or flexibility, EPA determines that such a provision is 
not justified.

C. Additional Subcategories

    In the 2015 rule, EPA established subcategories for small EGUs 
(less than or equal to 50 MW nameplate capacity) and oil-fired units. 
EPA subcategorized small EGUs due to disproportionate costs when 
compared to the rest of the industry and subcategorized oil-fired units 
both because they generated substantially fewer pollutants and are 
generally older \94\ (and more susceptible to early retirement). In the 
2015 rule, EPA stated:
---------------------------------------------------------------------------

    \94\ Age is a statutory factor for BAT. CWA section 304(b), 33 
U.S.C. 1304(b).

    ``If these units shut down, EPA is concerned about resulting 
reductions in the flexibility that grid operators have during peak 
demand due to less reserve generating capacity to draw upon. But, 
more importantly, maintaining a diverse fleet of generating units 
that includes a variety of fuel sources is important to the nation's 
energy security. Because the supply/delivery network for oil is 
different from other fuel sources, maintaining the existence of oil-
fired generating units helps ensure reliable electric power 
generation, as commenters confirmed.'' \95\
---------------------------------------------------------------------------

    \95\ 80 FR 67856 (November 3, 2015).

    For these subcategorized units in the 2015 rule, EPA established 
differentiated limitations based on surface impoundments (i.e., setting 
BAT limitations equal to BPT limitations on TSS).
    EPA did not propose, and is not changing in this final rule, the 
2015 rule subcategorization of small EGUs and oil-fired units. The 
final rule does, however, incorporate and expand on EPA's previous 
analysis of characteristics and differences within the industry. EPA 
has authority in a national rulemaking to establish different limits 
for different plants after considering the statutory factors listed in 
section 304(b). See Texas Oil & Gas Ass'n v. EPA, 161 F.3d 923, 938 
(5th Cir. 1998) (``We find nothing in the text of the CWA indicating 
that Congress intended to prohibit the promulgation of different 
effluent limits within a single subcategory of point sources . . . . 
The fact that EPA must promulgate rules for classes of polluters rather 
than individual polluters does not mean that EPA is required to treat 
all polluters within each class identically. The phrases `for 
categories and classes' and `within such categories or classes' simply 
do not, by their terms, exclude a rule allowing less than perfect 
uniformity within a category or subcategory.). The final rule includes 
subcategories applicable to FGD wastewater and BA transport water for 
EGUs with low utilization and EGUs permanently ceasing the combustion 
of coal. In addition, the final rule includes a subcategory applicable 
to FGD wastewater for power plants with high FGD flows. These 
subcategories are discussed below.
1. Plants With High FGD Flows
    Consistent with the proposal, EPA is finalizing a subcategory for 
plants with high FGD flows based on the statutory factor of cost. 
Specifically, this subcategory faces a disproportionately higher 
capital cost than other plants in the industry. The 2015 rule discussed 
the ability of high flow plants to recycle FGD wastewater back into the 
air pollution control system to decrease FGD wastewater flows and 
treatment costs. After the 2015 rule, the Tennessee Valley Authority 
(TVA) submitted a request seeking a fundamentally different factors 
(FDF) variance for its Cumberland power plant.\96\ This variance 
request relied primarily on two facts. First, TVA stated that 
Cumberland's FGD wastewater flow volumes are several million gallons 
per day,\97\ approximately an order of magnitude higher than many other 
plants with comparable generation capacity, and millions of gallons per 
day higher than the next highest flow rate in the entire industry.\98\ 
TVA further stated that the FGD system at Cumberland is constructed of 
a steel alloy that is susceptible to chloride corrosion. Based on the 
typical chloride concentrations in the FGD scrubber, the plant would be 
able to recycle little, if any, of the wastewater back to the scrubber 
as a means for reducing the flow volume sent to a treatment system.\99\ 
Second, as a result of the inability to recycle these high FGD flows, 
TVA stated that the cost of a biological treatment system would be 
high.
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    \96\ Tennessee Valley Authority (TVA)--Cumberland Fossil Plant--
NPDES Permit No. TN0005789--TVA Request for Alternative Effluent 
Limitations for Wet FGD System Discharges Based on Fundamentally 
Different Factors Pursuant to 33 U.S.C. 1311(n). April 28, 2016.
    \97\ In the FDF variance, TVA cites to a hypothetical maximum 
flow of 9 MGD; however, based on survey responses and discussions 
with TVA staff, the company has never approached this flow rate and 
does not expect to.
    \98\ Cumberland accounts for approximately one-seventh to one-
sixth of all industry FGD wastewater flows.
    \99\ Reducing the volume purged from the FGD system or recycling 
FGD wastewater back to the FGD system can be used to reduce the 
volume of wastewater requiring treatment, and thus reduce the cost 
of treating the wastes. However, reducing the flow sent to treatment 
also has the effect of increasing the concentration of chlorides in 
the wastewater, and FGD system metallurgy can impose constraints on 
the degree of recycle that is possible.
---------------------------------------------------------------------------

    The final rule subcategorizes plants with FGD purge flows of 
greater than four million gallons per day, after accounting for that 
plant's ability to recycle the wastewater to the maximum limitations 
for the FGD system materials of construction, to avoid placing a 
disproportionate cost on such plants. Such a flow reflects the 
reasonably predictable flow associated with actual and expected FGD 
operations.
    According to TVA's analysis, chemical precipitation plus biological 
treatment at that high flow plant would result in a capital cost of 
$171 million,

[[Page 64676]]

and an O&M cost of approximately $20 million per year.\100\ EPA's cost 
estimates are higher than TVA's, a $235 million dollar capital cost 
plus $21 million per year in O&M. EPA proposed to find that these costs 
are disproportionate, and thus proposed to subcategorize the Cumberland 
plant and any other plant with similarly high flows.
---------------------------------------------------------------------------

    \100\ Email to Anna Wildeman. November 13, 2018.
---------------------------------------------------------------------------

    Some commenters argued that EPA cannot legally create a subcategory 
of one plant. These commenters suggest that EPA must issue a 
fundamentally different factors (FDF) variance rather than create a 
subcategory. Other commenters argued that EPA cannot create a 
subcategory based on costs alone and that EPA had overestimated costs. 
Finally, commenters claimed that EPA reversed previous findings about 
the ability to recycle within the Cumberland FGD system without 
sufficient explanation.
    With respect to subcategory size, EPA does not agree that the CWA 
prohibits the creation of the subcategory for plants with high flows, 
and EPA discussed its CWA authority earlier in this section. Here, EPA 
has determined that plants that have particularly high FGD flows are 
different from other plants in the industry with respect to the 
compliance costs they would incur if they were expected to achieve the 
otherwise applicable limits based on CP+LRTR. While EPA is currently 
aware of only one plant that operates with flows at this high level, 
any plant in the industry that operates with these flow levels would 
qualify for the different limitations established in this subcategory.
    With respect to FDF variances, EPA does not agree that CWA section 
301(n) somehow restricts EPA's authority to establish subcategories. 
Rather, section 301(n) provides an ``acceptable alternative to 
subcategorizing an industry to account for plant-specific 
characteristics.'' Chem. Mfrs. Ass'n v. EPA, 870 F.2d 177, 221 (5th 
Cir. 1989) (citation omitted). While EPA is ``not required to establish 
separate subcategories for single plants,'' Chem. Mfrs. Ass'n v. EPA, 
870 F.2d at 239, it is not prohibited from doing so. Furthermore, FDFs 
are different from subcategories in important ways because they 
typically are based on information that EPA did not have a chance to 
consider in the national rulemaking. See 40 CFR 125.31(a)(2) (a request 
for establishment of effluent limitations based on fundamentally 
different factors shall be approved only if the factors are 
``fundamentally different from those considered by EPA in establishing 
the national limitations'').
    With respect to establishing a subcategory based on costs, EPA is 
required to consider ``cost'' under the statute, and that includes 
consideration of costs for a subcategory. See Chem. Mfrs. Ass'n v. EPA, 
870 F.2d 177, 239 (5th Cir. 1989). EPA has broad discretion in deciding 
how to account for the consideration factors and the weight to be 
accorded to each factor. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 
1045 (D.C. Cir. 1978); Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 214; Texas 
Oil & Gas Ass'n v. EPA, 161 F.3d 923, 928 (5th Cir. 1998). Here, EPA 
has determined that total capital costs are a reasonable way to 
consider cost in this scenario because they demonstrate the significant 
up-front disparity created just to install the system. EPA acknowledges 
that the capital cost estimates developed by the Agency at proposal 
were, and continue to be for the final rule, higher than TVA's 
estimates, but notes that the O&M costs are nearly identical. EPA's 
estimated capital costs for Cumberland amount to one quarter of the 
total capital costs to the entire industry for treating FGD wastewater 
with CP+LRTR, but they would still amount to approximately one fifth if 
TVA's estimated capital costs were used. Both instances represent 
disproportionately high costs, as compared to the rest of the industry. 
Furthermore, while the baseline IPM run discussed below used costs of 
the 2015 rule (i.e., CP+HRTR), which are somewhat higher than those for 
this final rule, these costs were projected to result in reduction of 
Cumberland's operations by 96 percent and partial retirement of the 
plant in order to meet the 2015 rule requirements.
    With respect to recycling within the FGD scrubber system, EPA has 
not reversed any previous findings. At proposal, EPA found that, based 
on the maximum chlorides concentrations allowable in ``once through'' 
FGD systems, many of these systems could still employ some recycling of 
FGD water within the scrubber. For plants like Cumberland, this was 
true in 2015 and is true today. The amount of recycling EPA estimated 
for Cumberland, however, is small relative to its flows. This recycling 
is explicitly accounted for in the 2019 proposal, and now in the final 
rule analysis of O&M costs. For further public comments and responses 
on the propriety of this subcategory, see DCN SE08615.
    As authorized by section 304(b) of the CWA, which allows EPA to 
consider costs, EPA is finalizing a new subcategory for FGD wastewater 
based on these unacceptable disparate costs. EPA finds that chemical 
precipitation does not impose the same unacceptable disparate costs. 
Therefore, the subcategory BAT is based on chemical precipitation, with 
effluent limitations for mercury and arsenic.
2. Low Utilization EGUs
    EPA is establishing a new subcategory for EGUs with low utilization 
(i.e., peaking EGUs) based on the statutory factors of cost, non-water 
quality environmental impacts (including energy requirements), and 
other factors the Administrator deems appropriate (i.e., harmonization 
with Clean Air Act and CWA regulations which apply to electric 
utilities). Low natural gas prices and other factors have led to a 
decline in capacity utilization for the majority of coal-fired EGUs. 
According to EIA 923 data,\101\ overall coal-fired production for 2017-
2018 was approximately one-third lower than in 2009, with the majority 
of EGUs decreasing utilization, some of them significantly. While the 
majority of EGUs were base load in 2009, coal-fired EGUs today often 
operate as cycling or peaking EGUs, responding to changes in load 
demand.\102\
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    \101\ https://www.eia.gov/electricity/data/eia923/
    \102\ In meetings and conference calls with electric utilities 
and trade organizations, several examples were provided of former 
base load plants that have since modified operations to be load-
following, or that no longer produce at all except for peak days in 
summer or winter. These discussions tracked closely with changes in 
production reported in the EIA 923 data.
---------------------------------------------------------------------------

    In light of these industry changes, EPA examined the costs of the 
2019 proposed BAT limitations and pretreatment standards for FGD 
wastewater and BA transport water on the basis of MWh produced, rather 
than the nameplate capacity (which was used to subcategorize EGUs with 
50 MW capacity or less in the 2015 rule). Specifically, the Agency 
proposed a subcategorization for plants producing less than 876,000 MWh 
per year on a rolling two-year basis. EPA received many comments on 
this subcategory, including some that suggested different MWh 
utilization thresholds or tiering with different limitations for 
different thresholds. Some commenters argued that the proposed cutoff 
was not based on utilization at all, and that it could apply to very 
high utilization EGUs that just happened to have a smaller nameplate 
capacity, or recommended that EPA consider other utilization measures 
such as the eight percent CUR threshold used in the 2012 Mercury and 
Air Toxics Standards rule (77 FR 9304, February 16, 2012). EPA agrees 
with the latter comments and has made changes

[[Page 64677]]

in the final rule to ensure that this subcategory is focused on low 
utilization EGUs and better reflect the intent of this subcategory, 
which its name makes apparent. Specifically, EPA has changed how it 
determines low utilization from a method which was based on MWh/yr (a 
production metric) to one based on utilization as measured by CUR.
    Similar to EPA's finding regarding small units in the 2015 rule, 
the record indicates that disparate costs to meet the proposed FGD 
wastewater and BA transport water BAT limitations and pretreatment 
standards are imposed on EGUs with low capacity utilization. 
Specifically, EPA focused its analysis on annualized capital costs as 
opposed to O&M costs because O&M costs are often tied to CUR, a measure 
of how frequently and to what extent an EGU is generating electricity: 
The more an EGU runs, the higher the CUR, and the more residuals it 
generates and must pay to dispose of.\103\ In contrast to O&M costs 
which correlate to how much an EGU is operating, capital costs do not 
vary with generation as they correspond to the original design of a 
system that can handle the maximum FGD scrubber purge flow and ash 
generation rate such that the system can handle a high-end/peaking 
power demand scenario (typically the EGU's nameplate capacity which 
would result in a CUR of 100%) and still meet the limitations. Thus, as 
utilization decreases, O&M costs are expected to decrease 
proportionally, while capital costs are not.
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    \103\ Unlike residuals, wastewater volumes need not always vary 
directly with utilization due to flexibility in how the system is 
operated and timing of the generation of wastewater.
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    Of the EGUs which EPA estimates have production lower than the 
proposed rule's 876,000 MWh/yr threshold, nearly two-thirds have a CUR 
over 25 percent. This confirms that the subcategory as proposed was 
more indicative of low production rather than low utilization. Thus, to 
properly evaluate low utilization, EPA compared costs on a CUR basis. 
Figure VIII-1 below presents annualized capital costs per MWh produced 
versus CUR. These are the costs of Option B (i.e., no 
subcategorization) as measured against the status quo, rather than 
against the 2015 rule baseline. This figure shows that four to six EGUs 
with a CUR between 0 percent and 16 percent have disparately higher 
capital costs per MWh produced than facilities with a higher CUR.
[GRAPHIC] [TIFF OMITTED] TR13OC20.002

    Some commenters argued that the CWA does not allow 
subcategorization based on costs. Some commenters also argued that 
costs should properly be compared on a plant basis, and that costs are 
not disparate on a plant basis. EPA disagrees with these comments. See 
the discussion in the introduction of this subcategorization section. 
EPA also notes that it subcategorized units with a 50 MW nameplate 
capacity or less based on disparate costs alone in the 2015 rule, and 
that provision of the 2015 rule was not challenged. With respect to 
commenters' arguments that the relevant metric is plant costs rather 
than unit costs, EPA finds that many decisions to retire, repower, or 
upgrade treatment are made at the EGU level, and many other EPA 
regulations are tied to EGUs, as discussed below. Thus, an EGU-level 
comparison is appropriate when examining disparate costs of this rule.
    In addition to disparate costs, EPA considered non-water quality 
environmental impacts (including energy requirements). Because CUR is a 
reflection of the frequency and extent of an EGU's generation, LUEGUs 
necessarily operate much less frequently, delivering electricity only 
during peak loading. For example, EGUs operating for approximately one 
month out of the year would have a CUR just over eight percent, but 
their continued operation is useful, if not necessary, for ensuring 
electricity reliability in the near term. Some commenters disagreed 
that electricity reliability is a concern, and they pointed to excess 
reserve margins in some regions of the country. EPA acknowledges that 
electricity reliability may not be a concern everywhere in the U.S., 
nor will it be a concern in all seasons. For instance, the most recent 
NERC winter reliability assessment states, ``Anticipated

[[Page 64678]]

resources in all assessment areas meet or exceed their respective 
Reference Margin Levels for the upcoming winter period.'' \104\ In 
contrast, Figure VIII-2 below presents the most recent (summer 2019) 
anticipated reserve margins as well as the reference margin designed to 
ensure electric reliability. As seen in that figure, the most recent 
summer assessment showed one region (ERCOT) that was not anticipated to 
meet its reference margin, and another (MISO) which was anticipated to 
be very close to its reference margin (19 percent vs.17 percent).
---------------------------------------------------------------------------

    \104\ NERC (North America Electric Reliability Corporation). 
2019. 2019-2020 Winter Reliability Assessment. November. Available 
online at: https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC%20WRA%202019_2020.pdf (DCN 
SE09093).
[GRAPHIC] [TIFF OMITTED] TR13OC20.003

    The figure above also does not present NERC sub-regions or local 
distribution, which may present additional reliability challenges. For 
example, one trade association commenter provided an example in 
Southeast Michigan where a natural gas distribution system caught fire 
during the winter of 2019. The temporary shortage caused by the fire 
and cold temperatures caused local auto and semiconductor manufacturers 
to shut down or cut production and put Michigan residents at risk of 
service interruptions.\105\ To the extent that LUEGUs are able to 
remain in service, they would be available to help alleviate these 
types of short-term localized shortages and outages.
---------------------------------------------------------------------------

    \105\ U.S. News. 2019. Bitter Cold and Natural Gas Shortages 
Shutter Auto Plants. DCN SE08655A081.
---------------------------------------------------------------------------

    Finally, EPA considered an ``other factor[ ]'' the Administrator 
deems appropriate,\106\ which is the harmonization of regulations. DOE/
EIA does not define what a peaking unit is, nor do the CAA or CWA. 
Nevertheless, EPA has grappled with this issue in previous regulations 
under these two statutes. A discussion of these regulatory examples is 
provided in Steam Electric Effluent Guidelines Reconsideration--
Evaluation of Final Rule Subcategories (DCN SE09071). These regulations 
have in some cases specified a 10 percent CUR, an eight percent CUR, or 
have allowed for consideration of CUR in site-specific decisions. This 
provides some flexibility in implementing these rules, including 
reduced monitoring, different recordkeeping, and alternative compliance 
technologies for units meeting the relevant CUR threshold. As is clear 
in these examples, EPA has long considered certain low CUR EGUs as 
important to local reliability and resiliency of the power grid. 
Various definitions of low CUR have been used by EPA programs to 
identify where regulatory requirements should be different. While in 
all of these example regulations EPA concluded that additional 
flexibility was warranted for EGUs based on CUR, EPA did not define 
peaking EGUs, nor is the Agency defining peaking EGUs in this final 
ELG.
---------------------------------------------------------------------------

    \106\ 33 U.S.C. 1314(b)(1)(B).
---------------------------------------------------------------------------

    EPA has consistently given more flexibility to EGUs operating at 
the margins of the electric grid. While EPA has not consistently 
implemented the same CUR for all of its regulations, in practice the 
difference between eight percent and 10 percent CUR is minor, 
approximately one week of operations. Furthermore, while the 
subcategory is not limited to EGUs that already operate at these 
levels, EPA estimates that only one EGU that will incur costs under 
this final rule falls between eight and 10 percent CUR, based on EIA 
data from 2017-2018. In light of the range of CURs over which there 
appear to be disparate costs, the potential to contribute to reserve 
margins or provide local flexibility in case of unexpected capacity 
disruption, and the desire to harmonize with the range of CURs that 
have been provided additional flexibilities in other EPA rules, the 
final rule establishes a subcategory for LUEGUs with an average annual 
CUR of less than 10 percent per year averaged over 24 months. For 
further public comments and responses on the propriety of this 
subcategory, see DCN SE08615.
    Consistent with the proposal, for this low utilization subcategory, 
EPA selected chemical precipitation as the technology basis for BAT 
limitations and PSES for FGD wastewater, with effluent limitations for 
mercury and arsenic. Also, for this subcategory EPA selected composite 
lined surface impoundments as the BAT technology basis for BA transport 
water and established limitations for TSS based on surface impoundments 
in combination with a BMP plan under section 304(e) of the CWA. For 
example, surface impoundments that meet the

[[Page 64679]]

engineering and design requirements in 40 CFR 257.71 would comply with 
this requirement. While EPA projects that some plants in this 
subcategory with unlined surface impoundments are likely to meet these 
TSS limitations using technologies other than surface impoundments once 
they have closed any unlined surface impoundments under the CCR rule, 
EPA projects that two plants will continue to operate lined surface 
impoundments.\107\
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    \107\ Furthermore, EPA notes that plants may choose to retrofit 
a surface impoundment or construct a new lined surface impoundment 
under the CCR rule.
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    As authorized by section 304(b) of the CWA, which allows EPA to 
consider costs, non-water quality environmental impacts (including 
energy requirements), and other factors the Administrator deems 
appropriate, EPA explicitly finds that additional technologies are not 
BAT for this subcategory. Some commenters argued that the technologies 
identified for this subcategory do not represent the single best plant 
within the subcategory. To an extent, commenters were correct in 
identifying more advanced technologies (e.g., biological treatment) in 
use within the LUEGU subcategory as it was proposed. However, those 
technologies were typically installed when the EGU had been operated at 
a much higher utilization rate. Thus, it is not appropriate to draw 
conclusions about what BAT for LUEGUs is today based on what might have 
been available and economically achievable when these EGUs operated at 
greater capacity utilization rates (and would therefore not have 
qualified as LUEGUs). In addition, the LUEGU subcategory in the final 
rule is narrower than the subcategory EPA proposed, with fewer plants 
eligible and fewer plants with advanced technologies in place.
    Other commenters took a different view, suggesting that, for 
LUEGUs, BAT should be set equal to BPT. EPA disagrees with these 
commenters and declines to set BAT equal to BPT. In this final rule, 
EPA finds that chemical precipitation for treatment of FGD wastewater, 
by itself, does not impose on LUEGUs the same disproportionate costs as 
CP + LRTR and that chemical precipitation is technologically available 
and economically achievable. Similarly, the requirement of a BMP plan 
to recycle what water can be recycled in a BA transport water system 
does not impose on LUEGUs the same disproportionate costs as 
installation of a high recycle rate system and is technologically 
available and economically achievable. Plants that can achieve some 
level of recycle, but not 90 percent, are required to do just that. 
While this may still be significant due to changes occurring under the 
CCR rule, the fact that significant reductions might occur at little 
cost does not make the BMP requirement so burdensome as to warrant 
defaulting to BPT.
    In light of the foregoing discussion, EPA finds that chemical 
precipitation for FGD wastewater and surface impoundments for BA 
transport water, along with a requirement to prepare and implement a 
BMP plan under section 304(e) of the Act to reduce pollutant discharges 
from BA transport water, are the only technologies that would not 
impose disproportionate costs or cause unacceptable non-water quality 
environmental impacts for this subcategory. While the Fifth Circuit in 
Southwestern Electric Power Company v. EPA, 920 F.3d 999, 1018 n.20 
(5th Cir. 2019), found EPA's use of surface impoundments as the 
technology basis for effluent limitations on legacy wastewater to be 
arbitrary and capricious, the Court left open the possibility that 
surface impoundments could be used as the basis for BAT effluent 
limitations so long as the Agency identifies a statutory factor, such 
as cost, in its rationale for selecting surface impoundments.
    Finally, EPA rejects setting BAT limitations for BA transport water 
in this subcategory on a case-by-case basis using BPJ because the 
technologies a permitting authority would necessarily consider are the 
same dry handling and high recycle rate systems that result in 
unacceptable disproportionate costs per MWh and unacceptable non-water 
quality environmental impacts, according to EPA's analysis above. For 
further public comments and responses on the appropriate BAT for this 
subcategory, see DCN SE08615.
3. EGUs Permanently Ceasing Coal Combustion by 2028
    Under the final rule, EPA establishes a subcategory for EGUs 
permanently ceasing the combustion of coal by 2028, based on the 
statutory factors of cost, the age of the equipment and plants 
involved, non-water quality environmental impacts (including energy 
requirements), and other factors as the Administrator deems appropriate 
(harmonization with the CCR rule alternative closure provisions).
    Some commenters argued that EPA does not have authority to 
establish a subcategory for EGUs that are projected to retire because 
the CWA does not give it authority to establish a subcategory to 
``avoid premature closures'' of plants. EPA disagrees that it lacks 
authority to establish the subcategory for EGUs that will cease 
combustion of coal by 2028. While it may be true, as commenters 
suggested, that Congress contemplated that marginal plants may close 
under a BAT standard, it required that EPA consider specific factors in 
devising a nationally applicable ELG rule: ``Factors relating to the 
assessment of best available technology shall take into account the age 
of equipment and facilities involved, the process employed, the 
engineering aspects of the application of various types of control 
techniques, process changes, the cost of achieving such effluent 
reduction, non-water quality environmental impact (including energy 
requirements), and such other factors as the Administrator deems 
appropriate.'' 33 U.S.C. 1314(b)(2)(B)). And, as stated previously in 
this preamble, EPA has considerable discretion in deciding how to 
account for the statutory factors and the weight to be accorded to each 
factor. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045 (D.C. Cir. 
1978); Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 214; Texas Oil & Gas Ass'n 
v. EPA, 161 F.3d 923, 928 (5th Cir. 1998). Based on the consideration 
of the statutory factors presented below, EPA is within its statutory 
authority to establish different limitations for such plants to help 
avoid unacceptable impacts.\108\
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    \108\ It is of no moment that, in 2015, EPA declined to 
establish different limits for plants that might soon retire. EPA is 
free to change its mind as a matter of policy, so long as it 
explains its decision. 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). That one EPA Administrator 
may weigh the statutory consideration factors differently from a 
previous one does not make the decision arbitrary, particularly 
where courts have long held that the Administrator has considerable 
discretion in weighing the factors. See also Nat'l Ass'n of Home 
Builders v. EPA, 682 F.3d 1032, 1038 & 1043 (D.C. Cir. 2012) (a 
revised rulemaking based ``on a reevaluation of which policy would 
be better in light of the facts'' is ``well within an agency's 
discretion,'' and `` `[a] change in administration brought about by 
the people casting their votes is a perfectly reasonable basis for 
an executive agency's reappraisal' '' of its policy choices) 
(citations omitted).
---------------------------------------------------------------------------

    EPA proposed to include only retiring EGUs in this subcategory but 
solicited comment on the inclusion of repowering EGUs. Electric utility 
commenters across the board suggested that EPA include all EGUs that 
would cease the combustion of coal, and thus the generation of the 
wastewaters regulated under this final rule. EPA agrees with these 
comments. EGUs that are repowering cease generation of BA transport 
water and FGD wastewater, just as retiring EGUs do. Furthermore, 
inclusion of repowering EGUs will enhance harmonization of the rules

[[Page 64680]]

applicable to this industry and give greater clarity to the regulated 
community. As discussed in the CCR Part A final rule, the alternative 
closure provisions for surface impoundments where there is ``permanent 
cessation of the coal fired boiler'' in Section 257.103(f)(2) includes 
surface impoundments at EGUs that convert to natural gas or other 
fuels. The final subcategory in this ELG final rule adopts nearly 
identical terminology as the language in Section 257.103(f)(2) of CCR 
Part A. EPA believes the phrase used in Sec.  423.11(w) of this rule 
``permanent cessation of coal combustion'' will avoid confusion over 
the intent to include repowering EGUs, and is intended to parallel the 
EGUs that would be able to satisfy Section 257.103 of the CCR rule. 
Thus, adopting the same approach for these ELGs will create consistency 
and certainty for the regulated community. Furthermore, not treating 
repowering as equivalent to closure could create an unfavorable 
incentive for a plant that desires to continue operating to, instead of 
repowering, retire and construct a new EGU on a greenfield, rather than 
use existing infrastructure. It would be better environmentally for the 
plant to use existing transmission and distribution infrastructure 
where possible to limit potential new impacts from greenfield project 
development. Therefore, as described below, this subcategory includes 
repowering EGUs.
    EPA has continued to gather information about plant and EGU 
retirements, deactivations, and fuel conversions since the 2015 rule 
from company announcements, industry public comments, and government 
databases as discussed in Changes to Industry Profile for Coal-Fired 
Generating Units for the Steam Electric Effluent Guidelines Final Rule 
memorandum (DCN SE08688). In the 2019 proposed rule, EPA identified 107 
plants which had announced, commenced or completed such actions since 
the development of the 2015 rule record, the most frequently stated 
reason in these public statements or filings being market forces, such 
as the continued low price of natural gas (49 plants).\109\ This was 
followed by other reasons (46),110 111 environmental 
regulations (33),\112\ and consent decrees (10). The fact that 
environmental regulations were listed in these public statements or 
filings by nearly one-third of these plants and that ELGs were 
specifically listed by some respondents suggests that additional 
flexibility may help to avoid premature closures of some plants and/or 
EGUs. As presented in Figure VIII-2 and section VII.C.2 of the preamble 
above, the most recent summer assessment showed one region (ERCOT) that 
was not anticipated to meet its reference margin, and another (MISO) 
which was anticipated to be very close to its reference margin (19 
percent vs.17 percent). Thus, EPA concludes that premature closure of 
some plants and/or EGUs is an unacceptable non-water quality 
environmental impact because it could impact reliability. Therefore the 
avoidance of these premature closures weighs in favor of 
subcategorization.
---------------------------------------------------------------------------

    \109\ This is consistent with recent analyses of the costs of 
coal-fired electric power generation versus other sources. Examples 
include: (1) https://www.bloomberg.com/news/articles/2018-03-26/half-of-all-u-s-coal-plants-would-lose-money-without-regulation; 
(DCN SE09094). (2) https://insideclimatenews.org/news/25032019/coal-energy-costs-analysis-wind-solar-power-cheaper-ohio-valley-southeast-colorado (DCN SE09095).
    \110\ Announcements for some power plants cited several 
rationales, hence the numbers do not add to 107.
    \111\ ``Other'' includes age, reliability of the plant, emission 
reduction goals, decreased local electricity demand, plant site 
limitations, and company goals to invest in clean/renewable energy.
    \112\ Approximately 31 percent of the facilities identified 
specific environmental regulations affecting their decision-making. 
Specific environmental regulations, when mentioned, included CPP, 
MATS, ELGs, CCR Rule, and Regional Haze Rules.
---------------------------------------------------------------------------

    Some commenters took issue with EPA's analysis of a hypothetical 
plant (see 84 FR 64640, November 22, 2019) and suggested that EPA 
should have evaluated the costs and pollutant loadings of EGUs that 
fall into this subcategory. EPA agrees with the latter suggestion, and 
the final rule thus includes in the baseline all EGUs retiring and 
repowering after 2023 (the latest compliance deadlines in the 2015 
rule). For those EGUs that would be subcategorized as permanently 
ceasing coal combustion by 2028, EPA evaluated the changes in costs and 
pollutant loads under regulatory Option A.
    As noted above, EPA gathered readily available information from 
publicly available sources, company announcements, industry public 
comments, and government databases to identify EGUs. A list of EGUs EPA 
believes to be retiring or repowering between 2024 and 2028 is 
presented in Changes to Industry Profile for Coal-Fired Generating 
Units for the Steam Electric Effluent Guidelines Final Rule memorandum 
(DCN SE08688). Twenty-three EGUs at 12 plants may incur costs under the 
final rule absent a subcategory for units ceasing coal combustion by 
2028.\113\ Under Option B, these EGUs combined have estimated capital 
costs of $209 million and estimated O&M costs of $21 million per year, 
leading to combined annualized costs as high as $63 million per 
year.\114\ When compared to the costs per MWh for EGUs not ceasing coal 
combustion by 2028, the shorter amortization periods for these LUEGUs 
lead to much higher costs per MWh in some cases. For example, while 
Winyah Unit 2 and Will County Unit 4 have approximate costs of $6/MWh 
under a normal 20-year amortization period, over the shortened 
amortization period these costs jump to over $10/MWh. These costs would 
both be among the highest, if not the highest, costs absent a 
subcategory for units ceasing coal combustion by 2028.
---------------------------------------------------------------------------

    \113\ Three EGUs at two plants are expected to retire or cease 
burning coal between permit renewal and the no later than compliance 
date.
    \114\ This upper bound assumes costs are all incurred between 
2021 and the announced year of closure or conversion to a different 
fuel source.
---------------------------------------------------------------------------

    EPA received comments that the compliance deadline for this 
subcategory should be different. Commenters suggesting a longer time 
frame proposed site-specific extensions past 2028, or later dates for 
LUEGUs. Some commenters also suggested that this time frame was too 
long for a variety of reasons. With respect to comments that the time 
frame should be shortened, EPA received comments presenting the time 
frame for building replacement capacity. One example provided by 
Southern Company demonstrated a real-world case where the construction 
of the natural gas replacement EGUs took eight years from the initial 
coal EGU retirement decision.\115\ Furthermore, as presented above, EPA 
has demonstrated that costs are disparate over these shorter time 
frames. Even if commenters disagree with EPA's characterization of 
these time frames as short, compressing cost recovery into these 
smaller amortization periods does result in disproportionate costs. 
Responding to comments that the time frame should be lengthened, EPA 
further examined the 24 EGUs that have announced retirement or fuel 
conversion after 2028 presented in Steam Electric Effluent Guidelines 
Reconsideration--Evaluation of Final Rule Subcategories (DCN SE09071). 
Of these 24 EGUs, only four EGUs at two plants are projected to incur 
costs under a final ELG rule. These EGUs will continue burning coal 
until 2033 and 2035, meaning that they will be able to

[[Page 64681]]

amortize their costs over a time frame closer to the estimated 20-year 
amortization period used for the industry as a whole. Unlike the EGUs 
ceasing coal combustion by 2028, the costs per MWh of these four EGUs 
do not increase significantly when evaluated with a shortened 
amortization period, and appear to fall in the range of the rest of the 
industry. Thus, changes to the latest year for permanent cessation of 
coal combustion is not justified based on disparate costs.\116\ 
Finally, with respect to both sets of comments suggesting longer and 
shorter time frames, changing the time frames would eliminate 
harmonization with the CCR rule. The CCR Part A rule finalized 
alternative closure provisions under 257.103(f) for coal-fired EGUs 
that permanently cease by 2028. For EPA to have requirements with that 
date under the CCR rule and a different date (earlier or later) for 
requirements under the ELGs would introduce unnecessary confusion and 
potentially limit the flexibilities deliberately afforded to the 
regulated community under one or both regulations. In meetings with 
EPA, utilities expressed two other concerns related to retiring or 
repowering units which would support this subcategory and the 
associated time frames. First, several utilities discussed the 
possibility that public utility commissions (PUC) would not allow cost 
recovery for equipment purchased near the end of a plant's useful life, 
resulting in stranded assets. Although the utilities indicated that 
PUCs have historically allowed for cost recovery even after the 
retirement of an EGU, they provided recent examples of PUCs rejecting 
cost recovery, which makes the prospect of continued recovery after 
retirement less certain. Second, utilities expressed the need for 
sufficient time to plan, construct, and obtain necessary permits and 
approvals for replacement generating capacity. In discussions of 
example Integrated Resource Plans (IRPs) and the associated process, 
utilities suggested timelines that would extend for five to eight years 
or longer.\117\
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    \115\ While replacement capacity may not be necessary in all 
cases, the Agency believes that it should not tie the hands of 
electric utilities by foreclosing the possibility.
    \116\ While it is possible additional plants might choose to 
retire or repower soon after 2028 and have not yet announced their 
intent to do so, it is not possible to predict such possibilities.
    \117\ Utilities also shared instances of very quick turnaround 
in some cases.
---------------------------------------------------------------------------

    Finally, the North American Electric Reliability Corporation (NERC) 
recently conducted an aggressive stress test scenario identifying the 
reliability risks if large baseload coal and nuclear plants were to 
bring their projected retirement dates forward.\118\ That report found 
that if retirements happen faster than the system can respond (by 
constructing new base load, e.g.), significant reliability problems 
could occur. NERC cautions that, though this stress test is not a 
predictive forecast,\119\ the findings are consistent with the concern 
that electric utilities conveyed to EPA, viz., that the well-planned 
construction of new generation capacity and orderly retirement of older 
plants are vital to ensuring electricity reliability. While EPA 
received comments that the scenarios that EPA evaluated at proposal did 
not result in the same level of retirements as the NERC stress test, 
any retirements caused by EPA, including under this regulation, could 
contribute to such a scenario. Furthermore, as presented in the 
discussion of LUEGUs above, inadequate reserve margins in some regions 
and commenter-provided examples of electricity upsets support EPA's 
view that marginal plants should not be forced into retirement while 
they still have a useful role to play in ensuring electric reliability.
---------------------------------------------------------------------------

    \118\ North American Electric Reliability Corporation (NERC). 
2018. Special Reliability Assessment: Generation Retirement 
Scenario. Atlanta, GA 30326. December 18. Available online at: 
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Retirements_Report_2018_Final.pdf. (DCN SE09096)
    \119\ ``NERC's stress-test scenario is not a prediction of 
future generation retirements nor does it evaluate how states, 
provinces, or market operators are managing this transition. 
Instead, the scenario constitutes an extreme stress-test to allow 
for the analysis and understanding of potential future reliability 
risks that could arise from an unmanaged or poorly managed 
transition.''
---------------------------------------------------------------------------

    In light of the information discussed above, and EPA's authority 
under section 304(b) to consider cost, the age of equipment and plants 
involved, non-water quality environmental impacts (including energy 
requirements), and other factors that the Administrator deems 
appropriate, EPA is establishing a new subcategory for EGUs that plan 
to permanently cease combustion of coal no later than December 31, 
2028, subject to a certification requirement (described in Section 
XIV). For this subcategory, EPA is establishing BAT limitations for TSS 
for both FGD wastewater and BA transport water based on surface 
impoundments as the selected technology basis.\120\ Some commenters 
disputed EPA's selected technology basis for EGUs in this subcategory. 
Comments argued that EPA cannot legally select surface impoundments for 
this subcategory, failed to base BAT on the best performing plant in 
the subcategory, and failed to consider that units in this subcategory 
could lease rather than purchase equipment to help meet the final 
limitations. As mentioned above, the Fifth Circuit's decision in 
Southwestern Electric Power Company v. EPA left open the possibility 
that surface impoundments could be used as the basis for BAT effluent 
limitations, so long as the Agency identifies a statutory factor, such 
as cost, in its rationale for selecting surface impoundments. For 
further public comments and responses on this subcategory, see DCN 
SE08615.
---------------------------------------------------------------------------

    \120\ EPA is not specifying that the BAT technology basis is 
composite lined impoundments here, as it did for the low utilization 
subcategory, because under the CCR rule, plants must cease receiving 
waste in their unlined surface impoundments by April 11, 2020, but 
plants that need additional time to develop alternate capacity to 
manage their wastestreams may continue to use their unlined surface 
impoundments under the alternative closure provisions of 40 
CFR257.103(f)(1) or (2). Units falling within the alternative 
closure provision of (f)(2) must both complete closure of their 
unlined surface impoundments and permanently cease combustion of 
coal by 2023 or 2028 (depending on size of the impoundment). Thus, 
use of unlined surface impoundments under the ELG up to that date 
would be compatible with the CCR rule, and nothing in this final ELG 
would authorize the use of an unlined surface impoundment outside of 
these CCR Part A rule flexibilities.
---------------------------------------------------------------------------

    Next EPA examined the treatment technologies employed at plants 
that have units that qualify for this subcategory. Four of the 12 
plants retiring or repowering between 2024 and 2028 are projected to 
incur FGD wastewater costs. Of these, two have chemical precipitation, 
one has chemical precipitation plus biological treatment, and the 
remaining plant has physical settling via surface impoundments. The one 
plant with biological treatment is Duke Energy's Allen Steam Station, 
which installed an HRTR system more than 10 years ago. Thus, unlike 
other plants with no current treatment, this plant has had sufficient 
time to amortize its costs. The fact that a plant could absorb the 
costs of an advanced wastewater treatment technology a decade ago when 
it operated at a much higher utilization does not demonstrate that, 
moving forward, plants already planning to retire could absorb such 
costs. For BA transport water, nine of the 12 plants will incur BA 
transport water costs under this final rule. Four of these plants 
already operate high recycle rate systems, while the remaining five 
plants only have wet sluice of their ash to surface impoundments. 
Again, the fact that a plant could easily absorb the costs of such 
systems previously, does not indicate that such systems are BAT moving 
forward.
    Finally, although EPA agrees with commenters that a wide variety of

[[Page 64682]]

wastewater treatment systems are available to lease, availability alone 
does not eliminate the issues already identified. Commenters provided 
information that systems were available for lease but did not provide 
information that leasing a treatment system would be less costly than 
the alternative. In contrast, during one of the conference calls 
identified above, EPA learned that one utility had conducted an 
evaluation of leasing equipment for one of its plants. At that plant, 
the leasing option was not less costly than purchasing and installing 
the same equipment. Data in the record regarding costs of leasing FGD 
wastewater treatment systems is limited. EPA had meetings or conference 
calls with several vendors and plants regarding leasing treatment 
equipment, but only obtained specific cost data for a single plant. EPA 
used the information provided about this plant to evaluate leasing in 
Cost to Lease Flue Gas Desulfurization Wastewater Treatment memorandum 
(DCN SE08633). For further public comments and responses on the issue 
of costs associated with leasing FGD wastewater treatment systems, see 
DCN SE08615.
    After considering the information above, EPA finds that additional 
technologies such as chemical precipitation, CP+LRTR, CP+HRTR, membrane 
filtration, or thermal technologies for FGD wastewater, and the dry 
handling/closed-loop technologies or high recycle rate BA transport 
water technologies are not BAT for this subcategory due to the 
unacceptable disproportionate costs they would impose; the potential of 
such costs to accelerate retirements of EGUs at this age of their 
useful life; the resulting increase in the risk of electricity 
reliability problems due to those accelerated retirements; and the 
harmonization with the CCR rule. EPA finds that surface impoundments 
are the only technology that would not impose such disproportionate 
costs on this subcategory of EGUs. Establishing surface impoundments as 
BAT for this subcategory alleviates the choice for these plants to 
either pass on disparately high capital costs over a shorter 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. This subcategory also allows electric utilities to 
continue the organized phasing out of EGUs that are no longer 
economical, in favor of more efficient, newly constructed generating 
stations, and helps prevent the scenario described in the NERC stress 
test. Additionally, it ensures that plants could make better use of the 
CCR rule's alternative closure provision, by which an unlined surface 
impoundment could continue to receive waste and complete closure by 
2028.\121\ EPA notes that, in order to complete closure by 2028, plants 
may have to cease receiving waste well in advance of that date; 
however, a 2028 date ensures that the final rule does not restrict the 
use of this alternative closure provision regardless of when a plant 
ultimately ceases receipt of waste. Furthermore, EPA rejects setting 
BAT limitations for either FGD wastewater or BA transport water in this 
subcategory on a case-by-case basis, using BPJ because the technologies 
an NPDES permitting authority would necessarily consider are the same 
systems that result in unacceptable disproportionate costs and 
unacceptable non-water quality environmental impacts according to EPA's 
analysis (described above). Because these EGUs are already nearing the 
end of their useful lives as coal-fired units, and are susceptible to 
early retirement or fuel conversion, losing the use of surface 
impoundments for wastewater before currently planned closure dates 
would undermine the flexibility of the CCR alternative closure 
provisions. This could hasten the retirement of units in a manner more 
closely resembling the reliability stress test discussed above, which 
is an unacceptable non-water quality environmental impact (including 
energy requirements) of compromised electric reliability. For further 
public comments and responses on the issue of the appropriate BAT 
technology for this subcategory, see DCN SE08615.
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    \121\ 40 CFR 257.103(b).
---------------------------------------------------------------------------

D. Availability Timing of New Requirements

    Where BAT limitations in the 2015 rule are more stringent than 
previously established BPT limitations for FGD wastewater and BA 
transport water, those BAT limitations, under the compliance dates as 
amended by the 2017 postponement rule, do not apply until a date 
determined by the permitting authority that is ``as soon as possible'' 
beginning November 1, 2020.\122\ The 2015 rule also specifies the 
factors that the permitting authority must consider in determining the 
``as soon as possible'' date.\123\ In addition, the 2017 postponement 
rule did not revise the 2015 rule's ``no later than'' date of December 
31, 2023, for implementation because, as public commenters pointed out, 
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. Like the 2015 rule, as part of the consideration of the 
technological availability and economic achievability of the BAT 
limitations in this proposal, EPA considered the magnitude and 
complexity of process changes and new equipment installations that 
would be required at plants to meet the final rule's limitations and 
standards. Where such limitations and standards justified a different 
``no later than'' date, EPA has changed this date, as detailed below. 
However, where EPA continued to project that technologies would be 
available by the existing ``no later than'' deadlines, those deadlines 
have been considered appropriate and retained.
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    \122\ 40 CFR 423.11(t).
    \123\ These factors are: (a) Time to expeditiously plan 
(including to raise capital), design, procure, and install equipment 
to comply with the requirements of the final rule; (b) changes being 
made or planned at the plant in response to greenhouse gas 
regulations for new or existing fossil fuel-fired power plants under 
the Clean Air Act, as well as regulations for the disposal of coal 
combustion residuals under subtitle D of the Resource Conservation 
and Recovery Act; (c) for FGD wastewater requirements only, an 
initial commissioning period to optimize the installed equipment; 
and (d) other factors as appropriate. 40 CFR 423.11(t)
---------------------------------------------------------------------------

    In the 2015 rule, and as amended by the 2017 postponement rule, EPA 
selected the time frames described above to enable many plants to raise 
needed capital, plan and design systems, procure equipment, and then 
construct and test systems. The time frames also allow for 
consideration of plant changes being made in response to other Agency 
rules affecting the steam electric power generating industry (e.g., the 
CCR rule). EPA understands that some plants may have already installed, 
or are now installing, technologies that could comply with the final 
limitations. While these plants could therefore potentially meet the 
standards of the final rule by the earliest date on which the 
limitations may become applicable, EPA received comments asking that 
EPA not select November 1, 2020 for the ``as soon as possible'' date, 
and further pointed out that this November 1, 2020 date was chosen to 
allow for sufficient time to conduct this rulemaking rather than with 
respect to when plants could meet the final limitations in this rule. 
As the Agency explained in the 2017 postponement rule, the November 1, 
2020 date was selected based on the time frame for finalizing a new 
rule (i.e., this final rule).
    For this final rule, EPA concluded that the earliest date the 
industry can achieve compliance with these new,

[[Page 64683]]

more stringent limitations is October 13, 2021. EPA notes that, while 
the limitations being finalized today are in some cases more flexible 
than those of the 2015 rule, in other cases they are more stringent. 
For instance, mercury limitations for FGD wastewater in the final rule 
are several times more stringent than those in the 2015 rule. Even a 
plant that might have a fully installed and operational biological 
treatment system to meet the 2015 rule might have to modify its 
physical/chemical pretreatment system or install post-treatment to 
ensure meeting these lower mercury limitations. Thus, even plants with 
treatment systems may need additional time to evaluate those systems 
against the new limitations, make modifications, and optimize 
performance. These changes might be minor in some cases; in other cases 
they could require procurement and installation of additional 
equipment. For example, Duke Energy has recently procured ultrafilters 
for its HRTR systems.
    At the same time as these plants may have to procure and install 
additional equipment, the global pandemic related to COVID-19 has 
disrupted normal supply chains and forced companies to rethink how 
construction is conducted, in many cases putting in place additional 
protocols such as distancing. In conversations since the proposal with 
staff at Platte River Power Authority, Duke Energy, Georgia Power, and 
GenOn, each company indicated that it had made changes to construction 
projects or experienced delays. For example, GenOn had on-site 
contractors mobilized at some plants in February, but due to 
restrictions imposed in March, those contractors left the sites and 
GenOn was forced to seek out an alternate vendor. This led to a six-
month delay on that project.\124\ Several companies also indicated that 
they have had to postpone outages. Since these outages are necessary to 
perform final hookups to newly installed wastewater treatment systems, 
delays will directly impact the time frames over which plants could 
meet any limitations. Furthermore, any additional time short of one 
year from the publication date of this rule would be insufficient for 
plants in many areas of the country because the construction season 
would already be over. Instead, EPA finds that setting the earliest 
applicability dates for both bottom ash transport water and FGD 
wastewater as October 13, 2021, which also happens to be toward the end 
of the 2021 construction season, would allow companies time to analyze 
the final rule, make plans, and construct any necessary treatment 
system upgrades under COVID-19 construction protocols. In addition to 
the considerations above, allowing a full year after publication will 
allow plants time to adjust to changed electricity demand due to the 
pandemic and the subsequent phases of reopening; \125\ build in 
evaluations with the most recent utilization rates; and evaluate 
whether participation in either the LUEGU or permanent cessation of 
coal combustion subcategories would be appropriate for any EGUs.
---------------------------------------------------------------------------

    \124\ DCN SE08621.
    \125\ Peer reviewed research from Imperial College in March 2020 
suggested that some form of mitigation measures (e.g., social 
distancing) might be required for 18 months or longer which would 
correspond to September 2021. Available online at: 
www.imperial.ac.uk/media/imperial-college/medicine/sph/ide/gida-fellowships/Imperial-College-COVID19-NPI-modelling-16-03-2020.pdf. 
(DCN SE09097)
---------------------------------------------------------------------------

    With respect to the latest compliance dates, EPA collected updated 
information regarding the technical availability of the proposed FGD 
and BA BAT technology bases and the VIP alternative. Based on the 
engineering dependency charts, bids, and other analytical documents in 
the current record, individual plants may need two to three years from 
the effective date of any rule to install and begin operating a 
treatment system to achieve the BAT limitations for FGD wastewater. 
Information in EPA's rulemaking record indicates a typical time frame 
of 26 to 34 months to raise capital, plan and design systems (including 
any necessary pilot testing), procure equipment, and construct and then 
test systems (including a commissioning period for FGD wastewater 
treatment systems).\126\ For BA transport water, the record at proposal 
indicated a typical time frame of 15 to 23 months to raise capital, 
plan and design systems, procure equipment, and construct a dry 
handling or closed loop or high recycle rate BA system. Nothing in the 
comments received by EPA leads the Agency to a different conclusion.
---------------------------------------------------------------------------

    \126\ Many plants have already completed initial steps of this 
process, having evaluated water balances and conducted pilot testing 
to prepare for implementing the 2015 rule.
---------------------------------------------------------------------------

    EPA received comments that the record did not support longer 
compliance time frames for FGD wastewater, based on the typical 
installation time frames. EPA disagrees with these comments. While the 
time frames above may be appropriate for an individual plant, several 
utilities and EPC firms pointed out difficulties in retrofitting 
biological treatment systems on a company-wide or industry-wide basis. 
Moreover, the same engineers, vendors, and construction companies are 
often used across plants. These same issues do not arise for chemical 
precipitation systems, which are substantially more prevalent in the 
industry, and in many cases would likely be installed to meet the 
cease-receipt-of-waste deadlines in the CCR Part A rule. That CCR rule 
finalized April 11, 2021 as the cease-receipt-of-waste date, with a 
site-specific alternative closure extension provision in 257.103(f) 
that allows a plant to get extensions up to as late as 2023 or 2024, 
depending on whether the plant was already required to close prior to 
the USWAG mandate. To stop receiving waste in an unlined surface 
impoundment, a plant would need to construct a treatment system to meet 
applicable ELGs, such as a tank-based system that meets the BPT 
limitations. However, biological treatment is not necessary to remove 
TSS, and therefore more time for implementation of the final BAT 
limitations will help to accommodate the process changes necessitated 
by combining chemical precipitation and LRTR and alleviate competition 
for resources. Considering all the factors described above, EPA is 
extending the ``no later than'' date for meeting FGD wastewater BAT 
limitations based on CP+LRTR to December 31, 2025. Thus, for FGD 
wastewater, BAT limitations based on CP+LRTR do not apply until a date 
determined by the permitting authority that is as soon as possible 
beginning October 13, 2021, but no later than December 31, 2025.
    With respect to BA transport water, commenters expressed several 
concerns, including: A concern that 2023 was not a sufficient time to 
plan for and meet new limitations, nor a sufficient time to conduct a 
BPJ analysis for the BA purge water and install any appropriate 
technology; a concern that these dates should be harmonized with the 
final CCR Part A rule, and that these dates were not harmonized with 
the time frames proposed for FGD wastewater (including the FGD makeup 
water exemption).\127\ EPA agrees with some comments, disagrees with 
others, and concludes that extension of the 2023 date as proposed is 
warranted, for the reasons discussed below.
---------------------------------------------------------------------------

    \127\ Commenters also stated that these time frames would be 
insufficient for installation of dry CSC systems. While dry handling 
is no longer considered part of the technology basis, EPA 
acknowledges that dry handling would be an alternative means for 
meeting the final limits, and agrees that based on information 
provided in the Rawhide conference call as well as the CCR rule 
docket, CSC systems may require a longer time frame for 
installation.

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[[Page 64684]]

    EPA disagrees that specific facts asserted by commenters warrant 
extending the time beyond 2023. First, EPA concludes that many plants 
could meet the 2023 date as proposed. As described at proposal, the 
industry continues to shift away from the use of surface impoundments 
for handling BA due to the CCR rule which has requirements to cease 
receipt of waste by a date certain. The CCR Part A final rule 
establishes a cease receipt of waste date of April 11, 2021 for many of 
these impoundments; however, other provisions of the 2015 CCR rule have 
cease receipt of waste dates which have already passed. With respect to 
the concerns related to BPJ analysis timing and FGD wastewater 
exemption, EPA responds that these timing issues can be addressed with 
flexibilities for the respective provisions, rather than extending the 
``no later than'' dates. For BPJ, plants can work with their permitting 
authority to develop reasonable compliance time frames to meet whatever 
BPJ is selected for BA purge water. EPA has clarified in the regulatory 
text that BA transport water sent to the FGD system for use as FGD 
makeup water becomes FGD wastewater. Thus, whatever limitations apply 
to FGD wastewater at the time, also apply to the BA transport water 
used in the FGD systems as FGD makeup water. Where the compliance date 
for FGD wastewater limitations occurs after the compliance date for BA 
transport water limitations, plants would continue to meet the BPT 
limitations for the BA transport water used in the FGD system as FGD 
makeup water until the former compliance date.
    However, EPA agrees that other facts presented by commenters and in 
EPA's rulemaking record do warrant extending the latest compliance 
dates for BA transport water beyond 2023. First, the CCR Part A rule 
alternate closure provision in 257.103(f)(1) now allows a subset of 
surface impoundments to receive waste as late as 2024. Harmonizing 
compliance time frames to at least 2024 would allow plants to make use 
of the CCR Part A rule's additional flexibility. Second, EPA 
acknowledges that deadlines were harmonized across wastestreams in the 
2015 rule, providing plants an opportunity to plan for any upgrades in 
a more integrated fashion. Harmonization of FGD wastewater and BA 
transport water ``no later than'' dates would be consistent with that 
approach.
    Considering all the factors described above, EPA is extending the 
``no later than'' date for compliance with the generally applicable BA 
transport water BAT limitations to December 31, 2025. While 
harmonization with other wastestreams' compliance dates could support 
either a 2023 or 2025 ``no later than'' date for the BA transport water 
limitations in this rule, the 2023 date would frustrate the 
flexibilities provided for impoundments until 2024 to close under the 
final CCR Part A rule and lead to disjointed plant planning across the 
two wastestreams. The more holistic approach is to select the 2025 
date, thereby harmonizing the dates applicable to the two wastestreams 
being finalized in this rule. Thus, for BA transport water, BAT 
limitations based on high recycle rate systems do not apply until a 
date determined by the NPDES permitting authority that is as soon as 
possible beginning October 13, 2021, but no later than December 31, 
2025.
    Importantly, for both FGD and BA, EPA distinguishes the ``no later 
than'' date from the ``as soon as possible'' date, determined by the 
permitting authority in accordance with the factors in 40 CFR 
423.11(t). While EPA is postponing the ``no later than'' dates in this 
final rule, where plants can comply with these final limitations 
sooner, NPDES permitting authorities are already required to 
incorporate those earlier permit dates, as specified in 423.11(t). 
Thus, this change to the ``no later than'' dates to December 31, 2025 
will not change the dates included in every NPDES permit.
    In addition, as discussed earlier, EPA is giving plants that opt 
into the VIP until December 31, 2028, to meet the VIP FGD wastewater 
limitations, which are based on membrane filtration technology. That is 
the date on which EPA finds that the membrane filtration technologies 
may be available, on a site-specific basis, to plants that might choose 
to participate in the VIP and be bound by those limitations. The final 
rule gives plants sufficient time to work out operational issues 
related to being the first plants in the U.S. to treat FGD wastewater 
using membrane filtration at full scale, as well as to conduct 
engineering studies on the encapsulation mix appropriate at that site 
for the disposal of the resulting brine. As previously explained, both 
of these issues contributed to EPA's decision that membrane filtration 
is not appropriate as a nationwide BAT. EPA also believes that a 
compliance deadline of December 2028 is an effective incentive for 
plants to opt into a program that can achieve significant pollutant 
reductions.

E. Additional Rationale for the Final PSES

    EPA is continuing to rely on the pass-through analysis as the basis 
of the limitations and standards in the 2015 rule. With respect to FGD 
wastewater, as discussed above, the long-term averages for LRTR 
biological treatment are comparable to those achieved with HRTR 
biological systems. On this basis, EPA concludes that mercury, arsenic, 
selenium, and nitrate/nitrite pass-through POTWs, as it concluded in 
the 2015 rule.
    With respect to BA transport water, EPA projects that plants 
converting to dry handling or recycling all of their BA transport water 
would continue to perform as the zero discharge systems EPA used in its 
2015 rule pass-through analysis. As explained in Section VII.b.ii, for 
those plants using high recycle rate systems, the final rule allows the 
NPDES permitting authority to establish, on a case-by-case basis, the 
volume of discharge (with a maximum of 10 percent of the system volume 
per day, on a 30-day rolling average) and to determine the BAT 
limitations for that discharge based on BPJ. For indirect dischargers, 
control authorities can establish local limitations on a BPJ basis.
    Thus, like BAT, the final rule establishes PSES based on Option A: 
PSES for FGD wastewater based on CP+LRTR, and PSES for BA transport 
water based on high recycle rate systems. EPA is establishing these 
technologies as the bases for PSES for the same reasons that the final 
rule selects these technologies as the bases for BAT. Moreover, the 
final rule establishes the same subcategories for PSES as it does for 
BAT limitations, for the same reasons described earlier.\128\
---------------------------------------------------------------------------

    \128\ Where the final rule establishes any subcategory that 
identifies BAT based on surface impoundments, with a restriction on 
TSS, there is no such parallel restriction for the analogous PSES 
subcategory because POTWs effectively treat TSS.
---------------------------------------------------------------------------

    As with the final BAT effluent limitations, in considering the 
availability and achievability of the final PSES, EPA concluded that 
existing indirect dischargers need some time to achieve the final 
standards, in part to avoid forced outages (see Section VIII.C.7). 
However, in contrast to CWA section 301(b), which does not specify a 
compliance date for BAT limitations promulgated after 1989, CWA section 
307(b)(1) requires that pretreatment standards shall specify a time for 
compliance not to exceed three years from the date of promulgation. 
Therefore, the PSES compliance dates established by this rule are three 
years

[[Page 64685]]

from promulgation of this rule. Unlike limitations on direct 
discharges, limitations on indirect discharges are not implemented 
through an NPDES permit and are directly enforceable. EPA has 
determined that all existing indirect dischargers can meet the 
standards within three years of the effective date of this final rule.

F. Summary of Economic Achievability

    As EPA did for the 2015 rule, the Agency performed cost and 
economic impact assessments using the Integrated Planning Model (IPM) 
to determine the effect of the proposed ELGs, using a baseline that 
incorporates impacts from other relevant environmental regulations (see 
Chapter 5 in the RIA). At the time of the 2015 rule, the IPM model 
showed a total incremental closure of 843 MW of coal-fired electric 
power generation as a result of the ELGs, corresponding to a net effect 
of two EGU closures.\129\ However, since then, natural gas prices have 
remained low, additional coal plants have retired or refueled, and 
changes that have been proposed to several environmental regulations 
have been included in those model runs. Owing to these changes, EPA ran 
an updated version of IPM (see Section VIII.C.2 for additional 
discussion of these updates).
---------------------------------------------------------------------------

    \129\ In meetings with EPA since the 2015 rule, electric 
utilities have expressed concerns that IPM underpredicts closures by 
not accounting for the ability of plants in regulated states to cost 
recover even if they would otherwise lose money or are not 
economical to operate.
---------------------------------------------------------------------------

    EPA also ran IPM to analyze the effect of the final rule. As of run 
year 2030, IPM estimates a total net increase of 1.3 GW in coal-fired 
electric generating capacity compared to the baseline IPM run 
(compliance with the 2015 rule), reflecting full compliance by all 
plants with the final rule. This change represents a net increase in 
capacity; however, due to increased capacity utilization of several 
plants in one region, IPM results show a net increase of one additional 
early closure. These IPM results indicate that the final rule is 
economically achievable for the steam electric power generating 
industry as a whole, as required by CWA section 301(b)(2)(A).
    EPA's economic achievability analysis for this and other options is 
described in Section VIII, below.

G. Summary of Non-Water Quality Environmental Impacts

    For the 2015 rule, EPA performed an assessment of non-water quality 
environmental impacts, including energy requirements, air impacts, 
solid waste impacts, and changes in water use and found them to be 
acceptable. Some commenters stated that consideration of air pollution 
changes suggest a more stringent option is warranted. EPA reevaluated 
these impacts in light of the changed industry profile, as well as the 
requirements of the final rule. Based on the results of these analyses 
EPA determines that the final rule has acceptable non-water quality 
impacts, including those air pollution impacts raised by commenters. 
See additional information in Section 7 of the Supplemental TDD, as 
well as Section X of this preamble.

H. Summary of Impacts on Residential Electricity Prices and Low-Income 
and Minority Populations

    As EPA did for the 2015 rule, the Agency examined the effects of 
the final rule on consumers as an additional factor that might be 
appropriate when considering what level of control represents BAT. If 
all annualized compliance cost savings were passed on to residential 
consumers of electricity, instead of being borne by the operators and 
owners of plants, the average per houshold cost savings under the final 
rule is $0.49 per year, as compared to the 2015 rule.
    EPA similarly evaluated the effect of the final rule on minority 
and low-income populations. As explained in Section XII, EPA used 
demographic data for populations potentially impacted by steam electric 
power plant discharges due to their proximity (i.e., within 50 miles) 
to one or more plants. For those populations, EPA evaluated both 
recreational and subsistence fisher populations. The analysis described 
in Section XII indicates that absolute changes in human health impacts 
are smaller than the overall impacts resulting from the 2015 rule. 
However, low-income and minority populations are potentially affected 
to a greater degree than the general population by discharges from 
steam electric power plants and are expected to accrue the benefits or 
drawbacks of the final rule to a greater degree than the general 
population.

VIII. Costs, Economic Achievability, and Other Economic Impacts

    EPA evaluated the costs and associated impacts of the final rule on 
EGUs at steam electric power plants. These costs were analyzed within 
the context of compounding regulations and industry trends that have 
affected steam electric power plants' profitability and power 
generation. These include the effects of current environmental 
regulations (e.g., final ACE rule, and final CCR Part A rule), as well 
as other market conditions, described in Section V.B. This section 
provides an overview of the methodology EPA used to assess the costs 
and the economic impacts and summarizes the results of these analyses. 
See the RIA in the docket for additional details, including results for 
other regulatory options EPA considered.
    Neither the cost estimates, nor the pollutant loading estimates 
(see section IX of the preamble), prepared by EPA for the purpose of 
evaluating various regulatory options, are designed to reflect changes 
to an industry with exact precision. See BP Exploration & Oil, Inc. v. 
EPA, 66 F.3d 784, 800 (6th Cir. 1995) (`` `The CWA does not require a 
precise calculation of BAT and NSPS costs.' '') (quoting NRDC, Inc. v. 
EPA, 863 F.2d 1420, 1426 (9th Cir. 1988)); Chem. Mfrs. Ass'n v. EPA, 
870 F.2d 177, 237-38 (5th Cir. 1989) (``The Act requires the EPA to 
`take into account' the costs of BAT; it does not require a precise 
calculation. The EPA `need make only a reasonable cost estimate in 
setting BAT'; it is sufficient if the EPA develops `a rough idea of the 
costs the industry would incur.' '') (internal quotations and citations 
omitted); see also Texas Oil & Gas Ass'n v. EPA, 161 F.3d 923, 936 (5th 
Cir. 1998) (EPA's effluent reduction estimates were performed ``only to 
satisfy the CWA's unrelated requirement that the EPA `identify' in its 
regulations the degree of effluent reduction attainable through the 
application of BAT . . . As such, even serious flaws in the effluent 
reduction estimates could not provide grounds for remanding the zero 
discharge limit.'') (citing 33 U.S.C. 1314(b)(2)(A)).
    In developing ELGs, and as required by CWA section 301(b)(2)(A), 
EPA evaluates economic achievability to assess the impacts of applying 
the limitations and standards on 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, 
the final rule is expected to provide cost savings when compared to the 
baseline. Like the prior analysis of the 2015 rule and the analysis of 
the 2019 proposal, the cost and economic impact analysis for the final 
rule focuses on understanding the magnitude and distribution of 
compliance cost savings across the industry, and the broader market 
impacts.
    EPA used specific indicators to assess the impacts of the 
regulatory options on the steam electric power generating industry as a 
whole. These indicators are consistent with those used to assess the 
economic achievability of the 2015 rule (80 FR 67838, November 3, 
2015);

[[Page 64686]]

however, for the final rule, EPA compared the values to a baseline that 
reflects implementation of existing environmental regulations (as of 
this action), including the 2015 rule. In the 2015 rule analysis, the 
costs of achieving the 2015 rule requirements were reflected in the 
policy cases analyzed rather than the baseline. Here, the baseline 
appropriately includes costs for achieving the 2015 rule limitations 
and standards, and the policy cases show the impacts of changes to 
those 2015 limitations and standards. More specifically, EPA compared 
the estimated baseline costs to the total cost to industry, and the 
change in the numbers and capacities of specific EGUs and plants 
expected to close under the regulatory options (including the final 
rule, Option A). As a screening tool, EPA also analyzed the ratio of 
compliance costs to revenue to see how the regulatory options change 
the number of plants (and their owning entities) that exceed thresholds 
indicative of financial strain.
    In addition to the analyses supporting the economic achievability 
of the final rule, EPA conducted other analyses to: (1) Characterize 
other estimated effects of the final rule (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

    EPA estimated plant-specific costs to control FGD wastewater and BA 
transport water discharged at existing EGUs at steam electric power 
plants to which the ELGs apply.\130\ EPA assessed the operations and 
treatment system components currently in place at a given unit (or 
expected to be in place as a result of other existing environmental 
regulations), identified equipment and process changes that plants 
would likely make to meet the 2015 rule (for baseline) and the final 
rule, and estimated the cost to implement those changes. As explained 
in the Supplemental TDD, the baseline also accounts for announced unit 
retirements, conversions, and other relevant operational changes that 
have occurred since EPA promulgated the 2015 rule. EPA thus derived 
plant-level capital and O&M costs for controlling FGD wastewater and BA 
transport water using the technologies that form the bases of the 2015 
rule, and for the final rule. See Section 5 of the Supplemental TDD for 
a more detailed description of the methodology EPA used to estimate 
plant-level costs.
---------------------------------------------------------------------------

    \130\ EPA did not estimate costs for other wastestreams not 
affected by this final rule.
---------------------------------------------------------------------------

    Following the same methodology used for the 2015 rule analysis and 
2019 proposal, and consistent with OMB guidance, EPA used a discount 
rate of seven percent to annualize one-time costs and costs recurring 
on other than an annual basis over a specific useful life, 
implementation period, and/or event recurrence period. For capital 
costs and initial one-time costs, EPA used 20 years. For O&M costs 
incurred at intervals longer than one year, EPA used the interval as 
the annualization period (3 years, 5 years, 6 years, 10 years). EPA 
added annualized capital costs, initial one-time costs, and the non-
annual portion of O&M costs to annual O&M costs to derive total 
annualized plant costs. EPA then calculated total industry costs by 
summing plant-specific annualized costs. To assess industry costs, EPA 
considered both pre-tax and after-tax costs. 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. EPA 
uses pre- and/or after-tax costs in different analyses, depending on 
the concept appropriate to each analysis (e.g., social costs are 
calculated using pre-tax costs whereas cost-to-revenue screening-level 
analyses are conducted using after-tax costs).
    EPA estimated that the final rule will provide cost savings 
(negative incremental costs) as compared to the costs that the industry 
would incur under the 2015 rule of $175 million on a pre-tax basis, and 
$140 million on an after-tax basis. The savings are attributable to 
less expensive high recycle rate BA systems, lower cost FGD wastewater 
treatment systems (chemical precipitation and LRTR), and the 
subcategorization of LUEGUs, high-FGD flow plants, and EGUs permanently 
ceasing the combustion of coal by December 31, 2028. Additional cost 
savings are due to the changes in compliance time frames discussed 
above in Section VII.D.

B. Social Costs

    Social costs are the costs of the final rule from the viewpoint of 
society as a whole, rather than the viewpoint of regulated plants 
(which are private costs). In calculating social costs, EPA tabulated 
the pre-tax costs in the year when they are estimated to be incurred. 
As described in Section VII.D of this preamble, the compliance 
deadlines and therefore the expected technology implementation years 
vary across plants. EPA performed the social cost analysis over a 27-
year period (2021-2047), which combines the length of the period during 
which plants are anticipated to install the control technologies (which 
could be as late as 2028) and the useful life of the longest-lived 
technology installed at any plant (20 years). EPA calculated the social 
cost of the final rule using both a three percent discount rate and an 
alternative discount rate of seven percent. For plants that have EGUs 
permanently ceasing coal combustion during the period of analysis, EPA 
zeroed out O&M costs in the years following the cessation of coal 
combustion.
    Social costs include costs incurred by both private entities and 
the government (e.g., in implementing the regulation). As described 
further in Chapter 10 of the RIA, EPA did not quantify the incremental 
increase in the cost to state governments to evaluate and incorporate 
BPJ into NPDES permits.\131\ 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 for 
the seven percent discount rate differ from comparable pre-tax industry 
compliance costs. The pre-tax industry compliance costs represent the 
annualized costs of the final rule if they were incurred today (i.e., 
in 2020), and thus these costs are discounted into social costs which 
are estimated based on the stream of future costs starting in the year 
that individual plants are projected to actually comply with the 
requirements of the final rule under the availability timing proposed 
in Section VII.D, and as described above, account for changes to costs 
to reflect EGUs permanently ceasing the combustion of coal during the 
period of analysis.
---------------------------------------------------------------------------

    \131\ The sensitivity analysis presented in Response to Public 
Comments for Revisions to the Effluent Limitations Guidelines and 
Standards for the Steam Electric Power Generating Point Source 
Category (DCN SE08615) estimated that BPJ could increase costs by up 
to $0.5 million per year.
---------------------------------------------------------------------------

    EPA estimated that the final rule will provide total annualized 
social cost savings (as opposed to industry cost savings, as presented 
above), of $153 million using a seven percent discount rate, and $127 
million using a three percent discount rate.

C. Economic Impacts

    EPA assessed the economic impacts of the final rule in two ways: 
(1) A screening-level assessment of the cost impacts on existing EGUs 
at steam

[[Page 64687]]

electric power plants and the entities that own those plants, based on 
comparison of costs to revenue; and (2) an assessment of the impact of 
the final rule 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, including results for other regulatory options EPA 
considered.
    The first set of cost and economic impact analyses--at both the 
plant and parent company levels--provide screening-level indicators of 
the impacts of costs for FGD wastewater and BA transport water 
controls, relative to historical operating characteristics of steam 
electric power plants incurring those costs (i.e., level of electricity 
generation and revenue). EPA conducted these analyses for the baseline 
and the final rule, and then compared these effects to understand the 
incremental effects of the final rule. The second set of analyses look 
at broader electricity market impacts, considering the interconnection 
of regional and national electricity markets. It 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 electricity market as a whole, 
including changes in generation 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 2015 rule and other existing 
regulations. EPA used results from the screening analysis of plant- and 
entity-level impacts, together with changes in projected capacity 
closure from the market model, to understand the impacts of the final 
rule relative to the baseline.
1. Screening-Level Assessment
    EPA conducted a screening-level analysis of the final rule's 
estimated impact to existing EGUs at steam electric power plants and 
parent entities based on cost-to-revenue ratios. Although this is a 
cost savings rule, for analytic convenience and as a worst-case 
scenario, the Agency assumed that all of the compliance costs in the 
baseline, and lower compliance costs in the final rule, would be 
absorbed by the steam electric power plants and their parent entities 
(and none passed on to consumers). This assumption may overstate the 
impacts of compliance expenditures in the baseline to the extent that 
steam electric power plants operating in a regulated market may in fact 
be able to pass on increases in production costs to consumers through 
changes in electricity prices. It is, however, an appropriate 
assumption for a screening-level estimate of the potential cost and 
savings impacts.
a. Plant-Level Cost-to-Revenue Analysis
    EPA developed revenue estimates for this analysis using EIA data, 
then calculated the change in the annualized after-tax costs of the 
final rule as a percent of baseline annual revenues. See Chapter 4 of 
the RIA for a more detailed discussion of the methodology used for the 
plant-level cost-to-revenue analysis, as well as results for other 
regulatory options EPA considered.
    Cost-to-revenue ratios are used to describe impacts to entities 
because they provide screening-level indicators of potential economic 
impacts. Just as for the plants owned by small entities under guidance 
in U.S. EPA (2006),\132\ the full range of plants incurring costs below 
one percent of revenue are unlikely to face economic impacts, while 
plants with costs between one percent and three percent of revenue have 
a higher chance of facing economic impacts, and plants incurring costs 
above three percent of revenue have a still higher probability of 
facing economic impacts.
---------------------------------------------------------------------------

    \132\ U.S. EPA (Environmental Protection Agency). 2006. EPA's 
Action Development Process: Final Guidance for EPA Rulewriters: 
Regulatory Flexibility Act as amended by the Small Business 
Regulatory Enforcement Fairness Act. November 2006. Available online 
at: https://www.epa.gov/reg-flex/epas-action-development-process-final-guidance-epa-rulewriters-regulatory-flexibility-act. (DCN 
SE09098)
---------------------------------------------------------------------------

    Under the baseline scenario, which includes the 2015 rule, EPA 
estimated that 12 plants would incur costs greater than or equal to one 
percent of revenue, including four plants that would have costs greater 
than or equal to three percent of revenue, and an additional 96 plants 
would incur costs that are less than one percent of revenue. For the 
final rule, EPA estimated that nine plants incur costs greater than or 
equal to one percent of revenue, including three plants that have costs 
greater than or equal to three percent of revenue; an additional 100 
plants incur costs that are less than one percent of revenue.
b. Parent Entity-Level Cost-to-Revenue Analysis
    EPA also assessed the economic impact of the final rule on parent 
entities. The screening-level cost-to-revenue analysis at the parent 
entity level provides insight on the impact on those entities that own 
existing electric generating units at steam electric power plants. In 
this analysis, the domestic parent entity associated with a given plant 
is defined as that entity with the largest ownership share in the 
plant. For each parent entity, EPA compared the incremental change in 
the total annualized after-tax costs and the total revenue for the 
entity under the final rule compared with the baseline (see Chapter 4 
of the RIA for details). Following the methodology employed in the 
analyses for the 2015 rule and 2019 proposal (80 FR 67838, 84 FR 
64620), EPA developed a range of estimates for the number of entities 
currently owning an EGU at a steam electric power plant, accounting for 
partial information available for steam electric power plants that are 
not expected to incur compliance costs to meet the final rule BAT 
limitations and pretreatment standards.
    Similar to the plant-level analysis above, cost-to-revenue ratios 
provide screening-level indicators of potential economic impacts to the 
owning entities; higher ratios suggest a higher probability of economic 
impacts. EPA estimated that the number of entities currently owning 
EGUs at steam electric power plants ranges from 231 to 459, depending 
on the assumed ownership structure of plants not incurring costs under 
the final rule and not explicitly analyzed. EPA estimates that, in the 
baseline, 225 to 452 parent entities, respectively, would either incur 
no costs or incur costs that are less than one percent of their 
revenues (annualized) to meet the 2015 rule BAT limitations and 
pretreatment standards. Six entities would have costs exceeding 1 
percent of revenue, and none of the entities would have costs exceeding 
three percent of revenue.
    Compared to the baseline, the final rule reduces the impacts on the 
small number of entities incurring costs. Specifically, there are two 
fewer entities in the one to three percent of revenue category under 
the final rule that were not in this category at proposal.
2. Electricity Market Impacts
    In analyzing the impacts of regulatory actions affecting the 
electric power sector, EPA used 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

[[Page 64688]]

impact of any power plant regulation because of the interdependence of 
electric EGUs in supplying 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 
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 others), or 
avoided closures, based on a more detailed analysis of market factors 
than in the screening-level analyses above. The results further inform 
EPA's understanding of the potential impacts of the final rule. For the 
current analyses, EPA used version 6 (v6) of IPM to analyze the impacts 
of the final rule. IPM v6 is based on an inventory of U.S. utility- and 
non-utility-owned EGUs and generators that provide power to the 
integrated electric transmission grid, including plants to which the 
ELGs apply. IPM v6 embeds an energy demand forecast that is derived 
from DOE's ``Annual Energy Outlook 2018'' (AEO 2018). IPM v6 also 
incorporates the expected compliance response to current regulatory 
requirements affecting the power sector (e.g., Cross-State Air 
Pollution Rule (CSAPR) and CSAPR Update Rule, Mercury and Air Toxics 
Rule (MATS), the 2014 CWA section 316(b) Cooling Water Intake Structure 
(CWIS) rule, and 2015 CCR and 2020 CCR Part A rules, the final ACE 
rule, as well as the 2015 ELG rule).
    In contrast to the screening-level analyses, which do not account 
for interdependence of electric EGUs in supplying power to the 
transmission grid, IPM v6 accounts for potential changes in the 
generation profile of steam electric and other EGUs and consequent 
changes in market-level generation costs, as the electric power market 
responds to changes in generation costs due to the final rule. 
Additionally, in contrast to the screening-level analyses, in which EPA 
assumed no cost pass through of ELG compliance costs, IPM v6 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 in those markets.
    In analyzing the final rule, EPA estimated changes in the fixed and 
variable costs for the steam electric power plants and EGUs already 
incurring costs in the baseline to instead incur costs (or avoid 
incurring costs) to comply with the final rule. 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, EPA estimated these costs exogenously for each 
EGU and input these costs into the IPM model as fixed and variable O&M 
cost adders. In other words, since the IPM code does not include 
wastewater treatment cost minimization equations, wastewater treatment 
costs must be calculated outside the model and input separately to be 
considered during the model run. EPA then ran IPM v6 including these 
new cost estimates to determine the dispatch of electric EGUs that 
would meet projected demand at the lowest cost, subject to the same 
constraints as in the baseline analysis. The estimated changes in 
plant- and EGU-specific production levels and costs--and, in turn, 
changes in total electric power sector costs and production profile--
are key data elements in evaluating the expected national and regional 
effects of the final rule, including closures or avoided closures of 
steam electric EGUs and plants.
    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 non-steam electric 
power plants); (2) impact on steam electric power plants as a group, 
and (3) impact on individual steam electric power plants incurring 
costs. Chapter 5 of the RIA discusses the first analysis; the sections 
below summarize the last two, which are also further described in 
Chapter 5 of the RIA. All results presented below are representative of 
post-compliance modeled market conditions in the years 2028-2033.
a. Impacts on Existing Steam Electric Power Plants
    EPA used IPM v6 results for 2030 \133\ to assess the potential 
impact of the final rule on current 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 power plants. Table 
VIII-3 reports estimated results for current EGUs at steam electric 
power plants, as a group. EPA looked at the following metrics: (1) 
Incremental (and avoided) 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) change in 
electricity generation from plants regulated by 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). Note that 
changes in electricity generation presented in Table VIII-3 are 
attributable both to changes in retirements, as well as to changes in 
capacity utilization at EGUs and plants whose retirement status does 
not change.
---------------------------------------------------------------------------

    \133\ IPM model year 2030 represents years 2028-2033.

   Table VIII-3--Estimated Impact of the Final Rule on Steam Electric Power Plants as a Group at the Year 2030
                                              Compared to Baseline
----------------------------------------------------------------------------------------------------------------
                                                                                   Change in value from baseline
                                                                                  attributable to the final rule
                             Metric                               Baseline value -------------------------------
                                                                                       Value          Percent
----------------------------------------------------------------------------------------------------------------
Total capacity (MW).............................................         314,952             800            0.3%
Early retirements or closures \a\ (MW)..........................          68,959            -800           -1.2%
Early retirements or closures \a\ (number of plants)............              62               1            1.6%
Total generation (GWh)..........................................       1,475,819           4,160            0.3%
Variable production cost (2018$/MWh)............................          $25.92           $0.03            0.1%

[[Page 64689]]

 
Annual costs (million 2018$)....................................         $57,620            $109            0.2%
----------------------------------------------------------------------------------------------------------------
\a\ Baseline values for early retirements or closures reflect changes from current operations considering the
  effects of all current regulations and market trends, not solely the 2015 rule. Values for incremental early
  retirements or closures represent change relative to the baseline, and thus reflect only changes resulting
  from the cost savings of this final rule. IPM may show partial (unit) or full plant early retirements
  (closures). It may also show avoided closures (negative closure values) in which an EGU or plant that is
  projected to close in the baseline is estimated to continue operating in the policy case.

    Under the final rule, generation at steam electric power plants is 
projected to increase by 4,160 GWh (0.3 percent) nationally, when 
compared to the baseline. IPM v6 projects a net increase in total steam 
electric capacity by 800 MW or approximately 0.3 percent of total 
baseline capacity, and one net plant retirement, which results from 
increased steam electric generation at several other coal-fired power 
plants in one region (an overall net increase in steam electric 
generation). 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 the steam electric power plants as a 
group. For further discussion of closures and related distributional 
impacts, see Chapter 5 of the RIA.
b. Impacts on Individual Plants Incurring Costs
    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 [capacity (MW) times 8,760 
hours]) (2) electricity generation, and (3) variable production costs 
per MWh, defined as variable O&M costs plus fuel cost divided by net 
generation. The analysis of changes in individual plants is detailed in 
Chapter 5 of the RIA.
    The results generally show no change, or less than a one percent 
reduction or one percent increase for steam electric power plants 
projected to incur compliance costs under the final rule. Consistent 
with lower estimated compliance costs under the final rule than the 
costs the plants would incur under the 2015 rule, a greater number of 
plants see improving operating conditions under the final rule (i.e., 
higher capacity utilization or generation, lower variable production 
costs) than deteriorating conditions when compared to the baseline. 
Thus, the results for the subset of plants incurring compliance costs 
further support the conclusion that the effects of the final rule on 
the steam electric power generating industry will be less than those of 
the 2015 rule.

IX. Pollutant Loadings

    In developing ELGs, EPA typically evaluates the pollutant loading 
reductions of regulatory options under CWA section 304(b)(1)(A)(BPT), 
304(b)(2)(A)(BAT) and 304 (b)(4)(A)(BCT). In estimating pollutant 
reductions associated with the final rule, EPA took the same approach 
as described above for plant-specific costs. That is, EPA compared the 
values to a baseline that reflects implementation of current 
environmental regulations, including the 2015 rule. In the 2015 rule, 
the baseline did not reflect pollutant loading reductions for meeting 
the 2015 rule requirements, as that effluent reduction is what EPA 
analyzed to support the 2015 rule. Here, the baseline appropriately 
includes pollutant loading reductions for achieving the 2015 rule 
requirements as EPA is analyzing the impact resulting from any changes 
to those requirements. More specifically, EPA considered the change in 
the pollutant loading reductions associated with the final rule to 
those projected under the baseline.
    The general methodology that EPA used to calculate pollutant 
loadings is the same as that described in the 2015 rule. EPA used data 
collected for the 2015 rule, as well as the data described in Section 
VI, to characterize pollutant concentrations for FGD wastewater and BA 
transport water. EPA evaluated these data sources to identify 
analytical data that meet EPA's acceptance criteria for inclusion in 
analyses for characterizing discharges of FGD wastewater and BA 
transport water.\134\ For each plant discharging FGD wastewater or BA 
transport water, EPA used data from the 2009 survey and/or industry-
submitted data to determine the discharge flow rates of those 
wastewaters. To determine the pollutant loadings of the baseline, EPA 
adjusted the discharge flow rates used in the pollutant loadings 
estimates to account for retirements, fuel conversions, and other 
changes in operations scheduled to occur by December 31, 2023, 
described in Section 6 of the Supplemental TDD, that will eliminate or 
alter the discharge of an applicable wastestream. Finally, the Agency 
adjusted the discharge flow rates to account for changes in plant 
operations to optimize FGD wastewater flows and to comply with the 2015 
CCR rule and 2020 CCR Part A rule. For further discussion of these 
adjustments, see Sections 6.2.2 and 6.3.2 of the Supplemental TDD, 
respectively.
---------------------------------------------------------------------------

    \134\ Acceptance criteria are presented in Section 6.1 of the 
Supplemental TDD.
---------------------------------------------------------------------------

    EPA first estimated--on an annual, per plant basis--the pollutant 
discharge load for FGD wastewater and BA transport water associated 
with the technology basis evaluated for plants to comply with the 2015 
rule requirements relative to the conditions currently present or 
planned at each plant. EPA similarly estimated plant-specific post-
compliance pollutant loadings associated with the technology basis for 
plants to meet the effluent limitations of the final rule. 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 those plants that discharge indirectly to POTWs, EPA adjusted 
the baseline loadings and the loadings associated with the final rule 
to account for pollutant removals expected from POTWs. These adjusted 
pollutant loadings for indirect dischargers therefore approximate the 
resulting discharges to receiving waters. For additional details on the 
methodology EPA used to calculate pollutant loading reductions, 
including for the other regulatory options, see Section 6 of the 
Supplemental TDD.

A. FGD Wastewater

    For FGD wastewater, EPA used the average pollutant effluent 
concentration

[[Page 64690]]

and plant-specific discharge flow rates to estimate the mass pollutant 
discharge per plant for baseline and for the final rule. EPA used data 
compiled for the 2015 rule as the initial basis for estimating 
discharge flow rates and updated the data to reflect retirements or 
other relevant changes in operation. For example, EPA reviewed state 
and EIA data to identify flow rates for new scrubbers that have come 
online since the 2015 rule. EPA also accounted for increased scrubber 
recycle rates, which would affect the discharge flow.
    EPA assigned pollutant concentrations for each analyte based on the 
operation of a treatment system designed to comply with the baseline or 
the final rule. EPA used data compiled for the 2015 rule to 
characterize untreated FGD purge, chemical precipitation effluent, and 
CP+HRTR effluent. EPA used data provided by industry to characterize 
effluent quality for CP+LRTR and membrane filtration effluent under the 
VIP. In addition, EPA used data provided by industry and other 
stakeholders, as described in Section VI of this preamble, to quantify 
bromide in FGD wastewater under baseline conditions and for the final 
rule.
    EPA received comments on potential errors in the bromide loadings 
calculations used for the 2019 proposal. EPA agrees with comments 
identifying conversion errors, as well as comments suggesting updated 
bromide addition rates and has, therefore, updated its bromide loadings 
estimates to reflect these changes. Some commenters also expressed 
preferences for addressing or not addressing iodine as presented in 
Section XIV(C) below. EPA's rulemaking record contains very limited 
information about iodine, and publicly available data is more limited 
and uncertain than data on bromide. However, in response to comments, 
EPA conducted a mass balance to estimate iodine loadings based on the 
limited available data. For a more complete discussion of these 
changes, see Section 6 of the Supplemental TDD.

B. BA Transport Water

    EPA estimated baseline and post-compliance loadings for the final 
rule in Table VII-1 using pollutant concentrations for BA transport 
water and plant-specific flow rates. EPA used data compiled for the 
2015 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 occurred after the 2015 rule data were collected. For 
the high recycle rate technology option, EPA also estimated discharge 
flows associated with the purge from remote MDS operation, based on the 
EGU capacity and the volume of the remote MDS. Under the baseline, 
which reflects the 2015 rule limitation of zero discharge, EPA 
estimated a flow rate of zero.
    For the final rule, in response to the administrative petitions 
discussed in Section IV of this preamble, EPA used a revised set of the 
2015 rule analytical data to characterize BA transport water effluent 
from steam electric power plants. As an example, EPA re-evaluated and 
revised, as appropriate, its data sets in light of questions 
petitioners raised about the inclusion and validity of certain data 
due, in part, to what the petitioners assert are flaws in data 
acceptance criteria, obsolete analytical methods, and the treatment of 
non-detect analytical results, which petitioners believed resulted in 
an overestimation of pollutant loadings resulting from current 
practices for BA transport water, in turn resulting in an 
overestimation of pollutant removals under the 2015 rule. EPA also 
updated the data set and incorporated BA transport water sampling data 
submitted by industry during the final months of the 2015 rulemaking 
and as part of a voluntary sampling program described in Section VI of 
this preamble. For a detailed discussion, including for other 
regulatory options, see Section 6 of the Supplemental TDD.

C. Summary of Incremental Changes of Pollutant Loadings From Final Rule

    Compared to the 2015 rule, the final rule is estimated to result in 
further reductions of approximately 972,000 pounds of pollutants per 
year. Reductions under the final rule would be realized to the extent 
that plants choose to meet the limitations based on membrane filtration 
under the VIP for FGD wastewater. The EPA estimated that, under the 
final rule, eight plants (13 percent of plants estimated to incur FGD 
compliance costs) would opt into the VIP program.

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 Act require EPA to consider non-water quality environmental 
impacts (including energy impacts) associated with ELGs. Accordingly, 
EPA has considered the potential impact of the final rule on air 
emissions, solid waste generation, and energy consumption. For the 
reasons described in Section IX of this preamble, the baseline for 
these analyses appropriately includes non-water quality environmental 
impacts associated with meeting the 2015 rule requirements, and EPA has 
analyzed the incremental impacts resulting from the final rule compared 
to those projected under the 2015 Rule baseline. In general, EPA used 
the same methodology to conduct the current analysis (with updated data 
as applicable) as it did for the analysis supporting the 2015 rule and 
the 2019 proposal. The following summarizes the methodology and 
results. See Section 7 of the Supplemental TDD for additional details, 
including analysis of the other regulatory options that EPA considered.

A. Energy Requirements

    Steam electric power plants use energy when transporting ash and 
other solids on or off site, transporting brine off site, operating 
wastewater treatment systems (e.g., chemical precipitation, biological 
treatment), or operating ash handling systems. For the final rule, EPA 
considered whether there would be an associated change in the 
incremental energy requirements compared to baseline. Therefore, as 
applicable, EPA estimated the increase in energy usage in megawatt 
hours (MWh) for equipment added to the plant systems or in consumed 
fuel (gallons) for transportation/operating equipment for the baseline 
and final rule. EPA summed the plant-specific estimates to calculate 
the net overall difference in energy requirements between baseline and 
the final rule. This section discusses plant-specific energy 
requirements and does not address electricity reliability of the 
electric grid. See Section VII.C for discussion of electricity 
reliability with respect to LUEGUs and EGUs permanently ceasing coal 
combustion.
    EPA estimated the amount of energy needed to operate wastewater 
treatment systems and ash handling systems based on the horsepower 
rating of the pumps and other equipment. EPA also estimated the fuel 
consumption associated with the changes in transportation needed to 
landfill solid waste and combustion residuals (e.g., ash) of steam 
electric power plants (on site or off site) and send concentrated brine 
off site to a centralized waste treatment (CWT) plant. The frequency 
and distance of transport depend on a plant's location, operation, and 
configuration; specifically, the volume of waste generated and the 
availability of either an on-site or off-site non-hazardous landfill 
and its distance from the plant. Table X-1 shows the net

[[Page 64691]]

change in annual electrical energy usage associated with the final rule 
compared to 2015 rule baseline, as well as the net change in annual 
fuel consumption requirements associated with the final rule compared 
to baseline.

     Table X-1--Estimated Incremental Change in Energy Requirements
      Associated With the Final Rule Compared to 2015 Rule Baseline
------------------------------------------------------------------------
                Non-water quality impact                  Energy use \a\
------------------------------------------------------------------------
Electrical Energy Used (MWh)............................         -37,200
Fuel Used (Thousand Gallons Per Year)...................      -1,062,000
------------------------------------------------------------------------
\a\ Negative values represent a decrease in energy use under the final
  rule compared to baseline.

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 to operate wastewater treatment, ash handling, 
and other systems needed to meet regulatory standards; (2) changes to 
transportation-related emissions due to the trucking of CCR waste to 
landfills; and (3) the change in the profile of electricity generation 
due to any regulatory requirements. This section discusses air emission 
changes associated with the first two mechanisms and presents the 
corresponding estimated net change in air emissions. See Section XII of 
this preamble for additional discussion of the third mechanism.
    Steam electric power plants generate air emissions by operating 
transport vehicles, such as dump trucks, which release criteria air 
pollutants and greenhouse gases. A decrease in energy use or vehicle 
operation would result in decreased air pollution from those sources.
    To estimate the net air emissions associated with changes in 
electrical energy use projected under the final rule compared to the 
2015 rule baseline, EPA combined the energy usage estimates with air 
emission factors associated with electricity production to calculate 
air emissions associated with the incremental energy requirements. EPA 
used emission factors projected by IPM v6 (ton/MWh) for nitrogen 
oxides, sulfur dioxide, and carbon dioxide to generate estimates of the 
changes in air emissions associated with changes in energy production 
for the final rule compared to baseline.
    To estimate net air emissions associated with the change in 
operation of transport vehicles, EPA used the MOVES2014b model to 
identify air emission factors (grams per mile) for the relevant air 
pollutants. EPA estimated the annual number of miles that dump trucks 
moving ash or wastewater treatment solids to on- or off-site landfills 
would travel under the regulatory options. EPA used these estimates to 
calculate the net change in air emissions for the final rule compared 
to the 2015 rule baseline. Table X-2 presents EPA's estimated net 
change in air emissions associated with auxiliary electricity and 
transportation.

     Table X-2--Estimated Net Change in Industry-Level Air Emissions
 Associated With Auxiliary Electricity and Transportation for the Final
                Rule Compared to the 2015 Rule Baseline a
------------------------------------------------------------------------
                                                             Change in
                Non-water quality impact                     emissions
                                                            (tons/year)
------------------------------------------------------------------------
NOX.....................................................           -21.9
SO2.....................................................           -16.8
CO2.....................................................         -33,300
------------------------------------------------------------------------
\a\ Negative values represent a decrease in energy use compared to 2015
  Rule baseline.

    The modeled output from IPM v6 predicts changes in electricity 
generation due to compliance costs attributable to the final rule 
compared to the 2015 rule 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. A summary of the net change in annual air 
emissions under the final rule for all three mechanisms is shown in 
Table X-3. To provide some perspective on the estimated changes in 
annual air emissions, EPA compared the estimated change in air 
emissions to the net amount of air emissions generated in a year by all 
steam electric power plants throughout the United States. For more 
details on the sources of air emission changes, see Section 7 of the 
Supplemental TDD.

     Table X-3--Estimated Net Change in Industry-Level Air Emissions
  Associated With Changes in Electricity Generation for the Final Rule
                   Compared to the 2015 Rule Baseline
------------------------------------------------------------------------
                                                          2018 emissions
                                                            by electric
                                             Change in         power
        Non-water quality impact             emissions      generating
                                          (million tons)     industry
                                                          (million tons)
------------------------------------------------------------------------
NOX.....................................         0.00067            1.29
SO2.....................................          0.0016            1.41
CO2.....................................            2.67           1,970
------------------------------------------------------------------------

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, 
biological treatment). EPA estimated the change in the amount of solids 
generated under the final rule in comparison to the 2015 Rule baseline. 
For FGD wastewater treatment, the final rule results in an increase in 
the amount of solid waste generated compared to baseline due to 
projected implementation of the VIP at eight plants. While BA solids 
are also generated at steam electric power plants, all of the BA solids 
accounted for in the waste volumes disposed of in the 2015 rule 
analysis were suspended solids from combustion, and, therefore, the 
final rule does not alter the amount of BA or other combustion 
residuals generated. EPA estimates that plants impacted by the final 
rule would generate 30,800 more tons of waste per year than plants in 
the baseline scenario. However, EPA finds that these additional non-
water quality environmental impacts are acceptable, as these volumes 
represent much less than a one percent increase in total waste 
generation by these plants.
    EPA also evaluated the potential impacts of diverting FA from 
current beneficial uses to encapsulate brine (from membrane filtration) 
for disposal

[[Page 64692]]

in landfills. According to the latest American Coal Ash Association 
(ACAA) survey,\135\ most beneficially used FA is replacing Portland 
cement used to make concrete. As seen by FA sales data in the 2018 EIA-
923 Schedule 8A, plants currently discharging FGD wastewater on average 
sell 34 percent of their FA for beneficial use.\136\ Summary statistics 
of the FA beneficial use percentage for these plants are displayed in 
Table X-5 below.
---------------------------------------------------------------------------

    \135\ Available online at: https://www.acaa-usa.org/Portals/9/Files/PDFs/2018-Survey-Results.pdf (DCN SE09099).
    \136\ Available online at: https://www.eia.gov/electricity/data/eia923/.

 Table X-5--Percent of FA Sold for Beneficial Use by Plants Discharging
                             FGD Wastewater
------------------------------------------------------------------------
                                                           Percent of FA
                        Statistic                            sold for
                                                          beneficial use
------------------------------------------------------------------------
Min.....................................................              0%
25th percentile.........................................               0
Median..................................................              13
Mean....................................................              34
75th percentile.........................................              79
Max.....................................................             100
------------------------------------------------------------------------

    In EPA's CCR disposal rule,\137\ EPA noted that FA replacing 
Portland cement in concrete would result in significant avoided 
environmental impacts to energy use, water use, greenhouse gas 
emissions, air emissions, and waterborne wastes. Although EPA cannot, 
with available data, tie specific plants selling their FA to this 
specific beneficial use, the ACAA data indicate that more than half of 
the FA beneficially used currently replaces Portland cement in 
concrete. Therefore, where sale for this particular beneficial use 
occurs by plants that may otherwise use their FA to encapsulate 
membrane filtration brine under Option C, EPA finds that would result 
in unacceptable air and other non-water quality environmental impacts, 
as detailed in Section VII(B)(1).
---------------------------------------------------------------------------

    \137\ Available online at: http://www.regulations.gov Docket ID: 
EPA-HQ-RCRA-2009-0640.
---------------------------------------------------------------------------

D. Changes in Water Use

    Steam electric power plants generally use water for handling solid 
waste, including ash, and for operating wet FGD scrubbers. The BA 
transport technologies associated with baseline and the final rule for 
BA transport water eliminate or reduce the volume of water used by wet 
sluicing BA operating systems. The 2015 rule baseline required zero 
discharge of pollutants in BA transport water, and because the use of 
other wastewater could significantly increase the necessary purge flow 
to maintain water chemistry, EPA estimated the increase in water use 
for BA handling associated with the final rule compared to baseline as 
equal to the BA purge flow.
    The technology basis for FGD wastewater in the final rule, CP+LRTR, 
is not expected to reduce or increase the volume of water used. Plants 
that install a membrane filtration system for FGD wastewater treatment 
as part of the VIP option are assumed to decrease their water use 
compared to baseline by recycling all permeate back into the FGD 
system, which would avoid costs of pumping or treating new makeup 
water. Therefore, EPA estimated the reduction in water use resulting 
from membrane filtration treatment as equal to the estimated volume of 
the permeate stream from the membrane filtration system. EPA estimates 
that plants impacted by the final rule will increase their water use by 
3.94 million gallons per day compared to baseline. EPA finds this 
impact to be acceptable because it represents less than a one percent 
increase in water use at these plants.

XI. Environmental Assessment

A. Introduction

    EPA conducted an environmental assessment for the 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 and BA transport water. EPA conducted 
modeling to determine the impacts of pollution from the universe of 
plants to which the final rule applies. 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 2015 rule requirements (the same baseline EPA used to 
evaluate costs). This assessment compares the potential environmental 
impacts of the 2015 rule with those of the final rule.
    Information from EPA's review of the scientific literature and 
documented cases of impacts of pollutants discharged in steam electric 
power plant FGD wastewater and BA transport water on human health and 
the environment, as well as a description of EPA's modeling methodology 
and results, are provided in the Supplemental Environmental Assessment 
(Supplemental EA). The Supplemental EA contains information on 
literature that EPA has reviewed since the 2015 rule, updates to the 
modeling methodology and modeling results supporting the analysis for 
the final rule. The 2015 EA provides information from EPA's earlier 
review of the scientific literature and documented cases of the full 
spectrum of impacts associated with the wider range of steam electric 
power plant wastewater discharges addressed in the 2015 rule on human 
health and the environment, as well as a full description of EPA's 
modeling methodology.
    Current scientific literature indicates that untreated steam 
electric power plant wastewaters, such as FGD wastewater and BA 
transport water, 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 Supplemental EA. 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

    The environmental assessment modeling for this final rule consisted 
of the steady-state, national-scale immediate receiving water (IRW) 
model that EPA used to evaluate the direct and indirect discharges from 
steam electric power plants for the 2019 proposal, the 2015 rule and 
2015 CCR rule.\138\ The model focused on impacts within the immediate 
surface waters where the discharges occurred (the closest segments of 
approximately 0.25 miles to 5 miles long). EPA also modeled receiving 
water concentrations downstream from steam electric power plant 
discharges using a downstream fate and transport model (see Section XII 
of this preamble).
---------------------------------------------------------------------------

    \138\ These rules modeled the same waterbodies for which the 
model was peer reviewed in 2008.
---------------------------------------------------------------------------

    The environmental assessment also incorporates changes to the 
industry profile outlined in Section V of this preamble. Additionally, 
EPA retained the updates and improvements to several input parameters 
for the IRW model from the 2019 proposal, including receiving water 
boundaries and volumetric flow data from the National Hydrography 
Dataset Plus (NHDPlus) Version 2, updated national recommended water 
quality criteria (NRWQC) for cadmium and selenium, updated benchmarks 
for ecological impacts in benthic sediment, and an updated 
bioconcentration factor for cadmium.

[[Page 64693]]

C. Outputs From the Environmental Assessment

    EPA estimates small environmental and ecological changes associated 
with changes in pollutant loadings for the final rule as compared to 
the baseline, including small changes in impacts to wildlife and 
humans. More specifically, in addition to other unquantified 
environmental changes, 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 non-cancer human health 
effects, and (5) nutrient impacts.
    As described in the Supplemental EA, 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. EPA modeled changes in discharged toxic, 
bioaccumulative pollutants from both FGD wastewater and BA transport 
water into rivers and streams and lakes, including reservoirs. EPA also 
addressed environmental impacts from nutrients in the Supplemental EA, 
as well as in a separate analysis discussed 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 within surface waters; impacts to 
wildlife from consumption of contaminated aquatic organisms; and 
impacts to human health from consumption of contaminated fish and 
water. The Supplemental EA discusses, with quantified results, the 
estimated environmental changes projected within the immediate 
receiving waters due to the estimated pollutant loading changes 
associated with today's final rule compared to the 2015 rule. All of 
the modeled changes relative to the baseline are small.

XII. Benefits Analysis

    This section summarizes EPA's national estimates of the changes in 
social benefits expected to result from estimated changes in steam 
electric power plant wastewater discharges described in Section IX of 
this preamble and the resultant environmental effects summarized in 
Section XI of this preamble. The Benefit Cost Analysis (BCA) report 
provides additional details on the benefits, methodologies, and 
analyses, including uncertainties and limitations. The analysis 
methodology for quantified benefits is generally the same as that used 
by EPA for the 2015 rule and the 2019 proposal, but with revised inputs 
and assumptions that reflect updated data. For the final rule, EPA used 
the same methodology developed for the Affordable Clean Energy (ACE) 
rule (84 FR 32520, July 8, 2019) to estimate human health effects due 
to changes in pollutant air emissions relative to the baseline.

A. Categories of Benefits Analyzed

    Table XII-1 summarizes benefit categories associated with the final 
rule and notes which categories EPA was able to quantify and monetize. 
Analyzed benefits fall into five broad categories: Human health 
benefits from surface water quality improvements; ecological conditions 
and effects on recreational use from surface water quality changes; 
market and productivity benefits, air-related effects, and changes in 
water withdrawal. Within these broad categories, EPA was able to assess 
changes in the benefits projected for today's final rule with varying 
degrees of completeness and rigor. Where possible, 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 prevent EPA from 
quantifying and/or monetizing some benefit categories. In the following 
discussion, positive benefit values represent improvements in 
environmental conditions and negative values represent forgone benefits 
of the final rule relative to the baseline.

                     Table XII-1--Summary of Benefits Categories Associated With Final Rule
----------------------------------------------------------------------------------------------------------------
                                                                                    Quantified,       Neither
                        Benefit category                          Quantified and      but not     quantified nor
                                                                     monetized       monetized       monetized
----------------------------------------------------------------------------------------------------------------
                             Human Health Effects From Surface Water Quality Changes
----------------------------------------------------------------------------------------------------------------
Changes in halogen levels in drinking water treatment plant       ..............         [check]  ..............
 source waters..................................................
Changes in human health effects (e.g., bladder cancer)            ..............  ..............         [check]
 associated with halogenated disinfection byproduct exposure via
 drinking water.................................................
Changes in incidence of cancer from arsenic exposure via fish            [check]  ..............  ..............
 consumption....................................................
Changes in incidence of cardiovascular disease from lead          ..............  ..............         [check]
 exposure via fish consumption..................................
Changes in incidence of other cancer and non-cancer adverse       ..............  ..............         [check]
 health effects (e.g., reproductive, immunological,
 neurological, circulatory, or respiratory) due to exposure to
 arsenic, lead, cadmium, and other toxics via fish consumption
 or drinking water..............................................
Changes in IQ loss in children from lead exposure via fish               [check]  ..............  ..............
 consumption....................................................
Changes in need for specialized education for children from lead         [check]  ..............  ..............
 exposure via fish consumption..................................
Changes in in utero mercury exposure via maternal fish                   [check]  ..............  ..............
 consumption....................................................
Changes in health hazards from exposure to pollutants in waters   ..............  ..............         [check]
 used recreationally (e.g., swimming)...........................
----------------------------------------------------------------------------------------------------------------
              Ecological Condition and Recreational Use Effects From Surface Water Quality Changes
----------------------------------------------------------------------------------------------------------------
Benefits from changes in surface water quality, including:               [check]  ..............  ..............
 Aquatic and wildlife habitat; water-based recreation, including
 fishing, swimming, boating, and nearwater activities; aesthetic
 benefits, such as enhancement of adjoining site amenities
 (e.g., residing, working, traveling, and owning property near
 water; \a\ and non-use value (existence, option, and bequest
 value from improved ecosystem health).\a\......................
Changes in protection of threatened and endangered species......  ..............         [check]  ..............
Changes in sediment contamination...............................  ..............  ..............         [check]
----------------------------------------------------------------------------------------------------------------

[[Page 64694]]

 
                                         Market and Productivity Effects
----------------------------------------------------------------------------------------------------------------
Changes in water treatment costs for municipal drinking water,    ..............  ..............         [check]
 irrigation water, and industrial process water.................
Changes in commercial fisheries yields..........................  ..............  ..............         [check]
Changes in tourism and participation in water-based recreation..  ..............  ..............         [check]
Changes in property values from water quality changes...........  ..............  ..............         [check]
Changes in ability to market coal combustion byproducts.........  ..............  ..............         [check]
Changes in maintenance dredging of navigational waterways and            [check]  ..............  ..............
 reservoirs due to changes in sediment discharges...............
----------------------------------------------------------------------------------------------------------------
                                           Air Quality-Related Effects
----------------------------------------------------------------------------------------------------------------
Changes in human morbidity and mortality from changes in                 [check]  ..............  ..............
 exposure to NOX, SO2, O3, and particulate matter (PM2.5).......
Changes in ecosystem effects; visibility impairment; and human    ..............  ..............         [check]
 health effects from direct exposure to NO2, SO2, and HAP.......
Changes in climate change impacts from CO2 emissions............         [check]  ..............  ..............
----------------------------------------------------------------------------------------------------------------
                                           Changes in Water Withdrawal
----------------------------------------------------------------------------------------------------------------
Changes in the availability of groundwater resources............         [check]  ..............  ..............
Changes in the availability of surface water resources..........  ..............  ..............         [check]
Changes in impingement and entrainment of aquatic organisms.....  ..............  ..............         [check]
----------------------------------------------------------------------------------------------------------------
\a\ These values are implicit in the total willingness-to-pay (WTP) for water quality improvements.

    The following section summarizes EPA's analysis of the benefit 
categories that the Agency was able to quantify and/or monetize 
(identified in the first and second columns of Table XII-1). Benefits 
are a function of the changes in pollutant loadings under the final 
rule and the timing of the rule's implementation. The final rule would 
also affect additional benefit categories that the Agency was not able 
to quantify or monetize. The BCA report further describes additional 
qualitative and nonmonetized benefits.

B. Quantification and Monetization of Benefits

1. Changes in 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, liver damage, circulatory 
damage, vomiting, diarrhea, brain damage, IQ loss, fatigue, 
irritability, and many others. Exposure to drinking water containing 
halogenated disinfection byproducts could cause adverse health effects 
such as cancer and reproductive and fetal development issues. Because 
the final rule is expected to change discharges of steam electric 
pollutants into surface waters, it may alter incidence of associated 
health effects, even if by small amounts. EPA's analyses of human 
health effects, detailed in Chapters 4 and 5 of the BCA report, find 
that the incremental changes in exposure between the baseline and the 
final rule are minimal compared to the estimates of absolute changes in 
exposure for those same pollutants under the 2015 rule.
    Due to data limitations and uncertainties, EPA is able to monetize 
only a subset of the changes in health effects associated with changes 
in pollutant discharges under the final rule relative to the baseline. 
EPA's analysis first estimated the changes in the expected number of 
individuals experiencing adverse health effects in the populations 
affected by exposure to discharged pollutants under the final rule 
relative to the baseline. EPA then estimated the value of these changes 
by using different monetization methods for different health benefit 
endpoints.
    EPA estimated changes in health risks from the consumption of 
contaminated fish from waterbodies within 50 miles of households. EPA 
used Census Block Group population data and state-specific average 
fishing participation rates to estimate the exposed population. EPA 
used population cohort-specific fish consumption rates and waterbody-
specific fish tissue concentration estimates to calculate potential 
exposure to pollutants from steam electric power plants. Cohorts were 
defined by age, gender, race/ethnicity, and fishing mode (recreational 
or subsistence). EPA used these data to quantify and monetize changes 
in the following four categories of human health effects, which are 
further detailed in the BCA report:
     Changes in IQ loss in children aged zero to seven from 
lead exposure via fish consumption.
     Changes in need for specialized education for children 
from lead exposure via fish consumption.
     Changes in in utero mercury exposure via maternal fish 
consumption and associated IQ loss.
     Changes in incidence of cancer from arsenic exposure via 
fish consumption.
    Table XII-2 summarizes the monetary value of changes in quantified 
and monetized health outcomes associated with consumption of 
contaminated fish tissue under the final rule relative to the baseline. 
In addition, EPA estimates no changes in cancer incidence due to 
arsenic exposure via fish consumption under the final rule relative to 
the baseline. Accordingly, EPA estimates no change in social benefits 
for this health endpoint. Chapter 5 of the BCA report provides 
additional detail on EPA's methodologies.

[[Page 64695]]

    Table XII-2--Estimated Monetary Values of Changes in Human Health
            Effects Under the Final Rule Compared to Baseline
                    [Millions of 2018$, annualized]a
------------------------------------------------------------------------
                                            3% Discount     7% Discount
          Human health benefits                rate            rate
------------------------------------------------------------------------
Reduced Lead Exposure for Children......          -$0.02      \b\ <$0.00
Reduced Mercury Exposure for Children...          -$0.32          -$0.11
                                         -------------------------------
    Total Monetized Benefits............          -$0.34          -$0.11
------------------------------------------------------------------------
\a\ Negative values represent forgone benefits.
\b\ ``<$0.00'' indicates that monetary values are greater than -$0.01
  million but less than $0.00 million.

    There is evidence of linkages between adverse human health effects, 
including bladder cancer, and exposure to halogenated disinfection 
byproducts in drinking water. Reductions in halogen levels in source 
waters for drinking water treatment plants can contribute to reductions 
in halogenated disinfection byproduct levels in drinking water. EPA 
analyzed the populations served by drinking water treatment plants with 
intakes on surface waters to which steam electric power plants 
discharge. EPA used Safe Drinking Water Information System (SDWIS) and 
U.S. Census data to estimate the exposed population. EPA estimated 
reductions in source water halogen concentrations under this final rule 
relative to the baseline. EPA estimates that following implementation 
of wastewater treatment upgrades to meet the revised ELGs (i.e., 
starting in 2029), 323 drinking water treatment plants serving a total 
population of 7.3 million people will experience a reduction in source 
water halogen concentrations under the final rule relative to baseline. 
These halogen reduction benefits derive from projected plant 
participation in the VIP.\139\ Additional details on this analysis, 
including a discussion of uncertainties, are provided in Chapter 4 of 
the BCA report.
---------------------------------------------------------------------------

    \139\ Estimated halogen concentrations increase relative to 
baseline for some drinking water treatment plants due to BA 
requirements under this final rule, but the magnitude of these 
increases is generally much smaller than the magnitude of decreases 
at plants experiencing reductions.
---------------------------------------------------------------------------

2. Ecological Condition and Recreational Use Effects From Changes in 
Surface Water Quality

    EPA evaluated whether the final rule would alter aquatic habitats 
and human welfare by changing concentrations of harmful pollutants such 
as arsenic, cadmium, chromium, copper, lead, mercury, nickel, selenium, 
zinc, nitrogen, phosphorus, and suspended sediment relative to the 
baseline. As a result, the usability of some of the waters for 
recreation relative to baseline conditions could change under the final 
rule, thereby affecting recreational users. Changes in pollutant 
loadings can also change the attractiveness of waters usable for 
recreation 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.
    EPA uses a water quality index (WQI) to translate water quality 
measurements, gathered for multiple parameters that are indicative of 
various aspects of water quality, into a single numerical indicator 
that reflects water quality suitable for certain uses. The WQI includes 
seven parameters: Dissolved oxygen, biochemical oxygen demand, fecal 
coliform, total nitrogen, total phosphorus, suspended solids, and an 
aggregate subindex for toxics. For the purposes of this analysis, EPA 
modeled changes in four of these parameters, and held the remaining 
parameters (dissolved oxygen, biochemical oxygen demand, and fecal 
coliform) constant. Relative to baseline, EPA estimates that the final 
rule will result in small reductions in water quality during the period 
being analyzed. During the 2021 though 2028 time period, the change in 
WQI is uniformly negative or zero, with surface water segment-level 
changes ranging from -5.8 to 0.0 (median change is -
3.8x10-4). From 2029 through 2047, the change in WQI is 
positive in some segments, and segment level WQI changes overall range 
from -0.7 to 1.5 (median change is -8.1x10-5). The positive 
changes in WQI in some reaches derive from projected plant 
participation in the VIP.
    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 analysis for the 2015 rule and 2019 
proposal. The meta-regressions quantify average household willingness 
to pay (WTP) for incremental improvements in surface water quality. 
This WTP is the maximum amount of money a person is willing to give up 
for a given improvement in water quality. Chapter 6 of the BCA report 
provides additional detail on the valuation methodology. Overall, the 
final rule is estimated to result in small reductions in water quality 
relative to baseline, which is reflected in negative average annual 
household WTP values ranging from -$0.40 to -$0.20 (central estimate -
$0.31).
    Table XII-3 presents annualized total WTP values for water quality 
changes associated with modified toxic pollutant (arsenic, cadmium, 
chromium, copper, lead, mercury, selenium, zinc, and nickel), nutrient 
pollutant (phosphorus and nitrogen), and sediment pollutant discharges 
to approximately 10,610 reach miles affected by the final rule. An 
estimated 82.4 million households reside in census block groups within 
100 miles of affected reaches. The central tendency estimates of the 
total annualized benefits of water quality changes for the final rule 
range from -$12.5 million (7 percent discount rate) to -$11.8 million 
(3 percent discount rate).

[[Page 64696]]

   Table XII-3--Estimated Total Willingness-to-Pay for Water Quality Changes Under the Final Rule Compared to
                                                   Baseline a
                                         [Millions of 2018$; annualized]
----------------------------------------------------------------------------------------------------------------
                                        Total willingness-to-pay for water quality changes
    Number of    -----------------------------------------------------------------------------------------------
    affected                     3% discount rate                                7% discount rate
   households    -----------------------------------------------------------------------------------------------
   (millions)           Low           Central          High             Low           Central          High
----------------------------------------------------------------------------------------------------------------
82.4                      -$15.3          -$11.8           -$7.4          -$16.4          -$12.5           -$8.0
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent forgone benefits.

3. Effects on Threatened and Endangered Species
    EPA assessed the potential for impacts on threatened and endangered 
(T&E) species, both aquatic and terrestrial, relative to the baseline, 
by analyzing the overlap between waters expected to change their 
wildlife national recommended water quality criteria (NRWQC) exceedance 
status under the final rule and the known habitat ranges of T&E species 
listed under the Endangered Species Act. EPA examined the life history 
traits of potentially affected T&E species and categorized them by 
potential for population impacts due to surface water quality changes. 
EPA estimated that there are 194 species whose known habitat range 
overlaps with surface waters that receive discharges from steam 
electric power plants. Five of the 194 T&E species have habitat ranges 
that intersect with waters that EPA estimates have changes in NRWQC 
exceedances under the final rule relative to the baseline, four of 
which correspond to estimated increases in NRWQC exceedances during the 
2021-2028 period, and one of which corresponds to an estimated 
reduction in NRWQC exceedances starting in 2029 following 
implementation of wastewater treatment technologies to achieve the 
revised limitations. Principal sources of uncertainty in this analysis 
include the specifics of how the final rule could impact T&E species 
(e.g., exposure levels, species reactions to exposure levels), exact 
species spatial distributions, and additional species that were not 
considered. Chapter 7 of the BCA report provides additional details on 
EPA's methodology.
4. Changes in Ability to Market Coal Combustion Byproducts
    The final rule could affect the ability of steam electric power 
plants to market coal combustion byproducts for beneficial use by 
converting from wet to dry handling of BA. In particular, EPA evaluated 
the potential effects of changes in marketability of BA as a substitute 
for sand and gravel in fill applications. EPA estimates that the final 
rule will affect the quantity of BA handled wet relative to the 
baseline. The estimated increase in BA handled wet is small (total of 
246,871 tons per year at five plants). Given the small magnitude of 
these changes and the uncertainty associated with projecting plant-
specific changes in marketed ash, EPA did not to monetize this benefit 
category in the final rule analysis. See Chapter 2 in the BCA report 
for additional details.
5. Changes in Dredging Costs
    The final rule would affect discharge of multiple pollutants, 
including sediment, thereby changing the rate of sediment deposition in 
affected waterbodies, including navigable waterways and reservoirs that 
require dredging for maintenance.
    Navigable waterways, including rivers, lakes, bays, shipping 
channels and harbors, are an integral part of the United States 
transportation network. They are liable to reduced functionality due to 
sediment buildup, which can reduce the navigable depth and width of the 
waterway. In many cases, costly periodic dredging is necessary to keep 
them passable. Reservoirs serve many functions, including storage of 
drinking and irrigation water, flood control, hydropower supply, and 
recreation. Streams and rivers can carry sediment into reservoirs, 
where it can settle and cause buildup of sediment layers. Sedimentation 
reduces reservoir capacity and useful life unless measures such as 
dredging are taken to reclaim capacity. Chapter 10 of the BCA report 
provides additional details on EPA's methodology for this benefit 
category.
    EPA estimates that sediment deposition in navigable waterways and 
reservoirs will increase under the final rule relative to baseline, 
increasing maintenance dredging costs by less than $0.01 million (3 or 
7 percent discount rates).
6. Changes in Air Quality-Related Effects
    EPA expects the final rule will affect air pollution through three 
main mechanisms: (1) Changes in auxiliary electricity use by steam 
electric power plants to operate wastewater treatment, ash handling, 
and other systems that EPA predicts plants would use under the final 
rule; (2) changes in transportation-related air emissions due to 
changes in trucking of CCR waste to landfills; and (3) changes in the 
profile of electricity generation due to changes in costs to generate 
electricity at steam electric power plants affected by the final rule.
    Changes in the electricity generation profile can increase or 
decrease air pollutant emissions because emission factors vary for 
different types of electric EGUs. For this analysis, the changes in air 
emissions relative to the baseline are based on the change in dispatch 
of generation units as projected by IPM v6 given the overlaying of 
costs for complying with the final rule onto steam electric EGUs' 
production costs. As discussed in Section VIII of this preamble, the 
IPM v6 analysis accounts for the effects of other regulations on the 
electric power sector.
    EPA evaluated potential effects resulting from net changes in air 
emissions of three pollutants: NOX, SO2, primary 
PM2.5, and CO2. NOX and SOX 
are precursors to fine particles sized 2.5 microns and smaller 
(PM2.5) and NOX is an ozone precursor. These air 
pollutants cause a variety of adverse health effects including 
premature death, non-fatal 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.\140\ CO2 is a key greenhouse

[[Page 64697]]

gas linked to a wide range of domestic effects. Other than mercury (Hg) 
and hydrogen chloride (HCl) emissions, EPA did not estimate changes in 
any other air pollutants (e.g., carbon monoxide) emissions that may 
occur as a result of the final rule due to methodology and resource 
limitations.
---------------------------------------------------------------------------

    \140\ U.S. EPA. Integrated Science Assessment (ISA) for 
Particulate Matter (Final Report, 2009). U.S. Environmental 
Protection Agency, Washington, DC, EPA/600/R-08/139F, 2009; U.S. 
EPA. Integrated Science Assessment for Particulate Matter (Final 
Report, 2019), U.S. Environmental Protection Agency, Washington, DC, 
EPA/600/R-19/188; U.S. EPA. Integrated Science Assessment for Ozone 
and Related Photochemical Oxidants (Final Report, 2013). U.S. 
Environmental Protection Agency, Washington, DC, EPA/600/R-10/076F; 
and U.S. EPA. Integrated Science Assessment for Ozone and Related 
Photochemical Oxidants (Final Report, 2020) U.S. Environmental 
Protection Agency, Washington, DC, EPA/600/R-20/012.
---------------------------------------------------------------------------

    Table XII-4 shows the changes in emissions of CO2, 
NOX, SO2, and primary PM2.5 based on 
the estimated changes in the profile of electricity generation, 
including increased generation from coal-fired EGUs (see Table VIII-3) 
under the final rule relative to baseline.
    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, EPA predicted the change in the annual average 
PM2.5 and summer season ozone across the U.S. 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 (BenMAP-CE). EPA quantified effects using 
concentration-response parameters which are consistent with those 
employed by the Agency in the PM NAAQS, Ozone NAAQS, and ACE RIAs (U.S. 
EPA, 2012; 2015; 2019).
    To estimate the climate benefits associated with changes in 
CO2 emissions, EPA applied a measure of the domestic social 
cost of carbon (SC-CO2). The SC-CO2 is a metric 
that estimates the monetary value of impacts associated with marginal 
changes in CO2 emissions in a given year. The SC-
CO2 estimates used in the analysis for this final rule focus 
on the direct impacts of climate change that are anticipated to occur 
within U.S. borders.
    Table XII-5 shows the total annualized monetary values associated 
with changes in emissions of primary PM2.5, SO2 
and NOX under the final rule. To give readers insight to the 
distribution of estimated benefits displayed in Table XII-5, EPA also 
reports the PM benefits according to alternative concentration cut-
points and concentration-response parameters. EPA uses two long-term 
epidemiological studies to estimate risk, Krewski et al. (2009) \141\ 
and Lepeule et al. (2012).\142\ Small shares of avoided 
PM2.5-related premature deaths occur above the annual mean 
PM2.5 NAAQS of 12 mg/m\3\, with percentages depending on the 
year and epidemiological studies. The shares range from less than 1 
percent to up to 2 percent based on Lepeule et al. (2012) and from less 
than 1 percent to 3 percent based on Krewski et al. (2009).
---------------------------------------------------------------------------

    \141\ Krewski, D., Jerrett, M., Burnett, R.T., Ma, R., Hughes, 
E., Shi, Y., Turner, M.C., Pope, C.A., Thurston, G., Calle, E.E., 
Thun, M.J., Beckerman, B., DeLuca, P., Finkelstein, N., Ito, K., 
Moore, D.K., Newbold, K.B., Ramsay, T., Ross, Z., Shin, H., 
Tempalski, B., 2009. Extended follow-up and spatial analysis of the 
American Cancer Society study linking particulate air pollution and 
mortality. Res. Rep. Health. Eff. Inst. 5-114-36.
    \142\ Lepeule, J., Laden, F., Dockery, D., Schwartz, J., 2012. 
Chronic exposure to fine particles and mortality: An extended 
follow-up of the Harvard Six Cities study from 1974 to 2009. 
Environ. Health Perspect. https://doi.org/10.1289/ehp.1104660.
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    Table XII-6 reports the combined human health benefits and domestic 
climate benefits attributable to changes in SO2, 
NOX, primary PM2.5, and CO2 emissions 
estimated with 3 percent and 7 percent discount rates. This table 
reports the air pollution effects calculated using PM2.5 
log-linear no threshold concentration-response functions that quantify 
risk associated with the full range of PM2.5 exposures 
experienced by the population (U.S. EPA, 2009; \143\ U.S. EPA, 2011; 
\144\ NRC, 2002).\145\
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    \143\ U.S. EPA, 2009. Integrated Science Assessment for 
Particulate Matter. U.S. Environmental Protection Agency, National 
Center for Environmental Assessment, Research Triangle Park, NC.
    \144\ U.S. EPA, 2011. Policy Assessment for the Review of the 
Particulate Matter National Ambient Air Quality Standards. Research 
Triangle Park, NC.
    \145\ NRC, 2002. Estimating the Public Health Benefits of 
Proposed Air Pollution Regulations. National Research Council. 
Washington, DC.
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    In general, EPA is more confident in the size of the risks 
estimated from simulated PM2.5 concentrations that coincide 
with the bulk of the observed PM concentrations in the epidemiological 
studies that are used to estimate the benefits. Likewise, EPA is less 
confident in the risk EPA estimates from simulated PM2.5 
concentrations that fall below the bulk of the observed data in these 
studies.\146\ Furthermore, when setting the 2012 PM NAAQS, the former 
EPA Administrator also acknowledged greater uncertainty in specifying 
the ``magnitude and significance'' of PM-related health risks at PM 
concentrations below the NAAQS. As noted in the preamble to the 2012 PM 
NAAQS final rule, ``EPA concludes that it is not appropriate to place 
as much confidence in the magnitude and significance of the 
associations over the lower percentiles of the distribution in each 
study as at and around the long-term mean concentration.'' \147\
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    \146\ The Federal Register notice for the 2012 PM NAAQS states, 
``In considering this additional population level information, the 
Administrator recognizes that, in general, the confidence in the 
magnitude and significance of an association identified in a study 
is strongest at and around the long-term mean concentration for the 
air quality distribution, as this represents the part of the 
distribution in which the data in any given study are generally most 
concentrated. She also recognizes that the degree of confidence 
decreases as one moves towards the lower part of the distribution.'' 
See 78 FR 3159 (Jan. 15, 2013).
    \147\ See 78 FR 3154, January 15, 2013.
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    Estimates of monetized co-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 EPA does not have sufficient information or modeling 
available to provide monetized estimates of changes in exposure to 
these pollutants for the final rule, EPA includes a discussion of these 
unquantified benefits in the BCA. For more information on the benefits 
analysis, see Chapter 8 of the BCA Report.

 Table XII-4--Estimated Changes in Air Pollutant Emissions From Changes in Electricity Generation Profile Under
                                      the Final Rule Compared to Baseline a
----------------------------------------------------------------------------------------------------------------
                                                                                                   Primary PM2.5
                                                   CO2 (million    NOX (thousand   SO2 (thousand     (thousand
                      Year                          short tons/     short tons/     short tons/     short tons/
                                                       year)           year)           year)           year)
 
----------------------------------------------------------------------------------------------------------------
2021                                                      -0.079           -0.25            -1.4          -0.028
2023                                                         2.9             3.0            -2.6            0.45
2025                                                         2.2             1.6           -0.70            0.91
2030                                                         2.7            0.69             1.7            0.48
2035                                                        0.88           -0.57             1.8            0.81

[[Page 64698]]

 
2040                                                         1.0            -1.6            -2.9           -0.22
2045                                                         2.8            0.15            0.92            0.44
----------------------------------------------------------------------------------------------------------------
\a\ All values in this table are rounded to two significant figures. Negative values represent emission
  reductions and positive values represent emission increases.

BILLING CODE 6560-50-P

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[GRAPHIC] [TIFF OMITTED] TR13OC20.004

BILLING CODE 6560-50-C

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 Table XII-6--Estimated Monetized Benefits From Changes in Air Emissions for the Final Rule Compared to Baseline
                                                        a
                                          [Millions 2018$; annualized]
----------------------------------------------------------------------------------------------------------------
                                                         3% Discount rate                7% Discount rate
                                                 ---------------------------------------------------------------
                Benefit category                    Lower bound     Upper bound     Lower bound     Upper bound
                                                        \b\             \c\             \b\             \c\
----------------------------------------------------------------------------------------------------------------
Climate change..................................               -$14
                                                               -2.3
                                                 ---------------------------------------------------------------
Human health....................................             $28             $65             $25             $56
                                                 ---------------------------------------------------------------
    Total.......................................              14              51              23              54
----------------------------------------------------------------------------------------------------------------
\a\ All values in this table are rounded to two significant figures. Negative values represent forgone benefits
  and positive values represent realized benefits. Climate benefits reflect the value of domestic impacts from
  CO2 emissions changes. The human health benefits reflect the sum of the PM2.5 and ozone benefits and reflect
  the range based on adult mortality functions. The health co-benefits do not account for direct exposure to
  NO2, SO2, and HAP; ecosystem effects; or visibility impairment.
\b\ Lower bound is based on human health benefit point estimates using Krewski et al. (2009) for PM2.5 and Smith
  et al (2009) for ozone.
\c\ Upper bound is based on human health benefit point estimates using Lepeule et al. (2012) for PM2.5 and
  Jerrett et al. (2009) for ozone.

7. Changes in Water Withdrawals
    Steam electric power plants use water for handling BA and operating 
wet FGD scrubbers. By changing the use of water in sluicing operations 
or prompting the recycling of water in FGD wastewater treatment 
systems, the final rule may affect the amount of water withdrawn from 
surface waters or aquifers. Using the same methodology used for the 
2015 rule, EPA estimated the monetary value of increased groundwater 
withdrawals based on increased costs of groundwater supply. The final 
rule is expected to increase water withdrawal from aquifers relative to 
baseline. EPA multiplied the increase in groundwater withdrawal (in 
gallons per year) by water costs of approximately $1,347 per acre-foot 
(326,000 gallons; 2018$). Chapter 9 of the BCA report provides the 
details of this analysis. EPA estimates the changes in annualized 
benefits of increased groundwater withdrawals are -$0.01 million (3 
percent and 7 percent discount rates). Due to data limitations, EPA was 
not able to estimate the monetary value of changes in surface water 
withdrawals. Chapter 9 of the BCA report and Section 7 of the 
Supplemental TDD provide additional details on the estimated changes in 
surface water withdrawals.

C. Total Monetized Benefits

    Using the analysis approach described above, EPA estimated the 
total monetary value of annualized benefits of the final rule for all 
monetized categories. Table XII-7 summarizes the total annualized 
monetary value of social welfare effects using 3 percent and 7 percent 
discount rates. The total monetary value of benefits under the final 
rule range from -$1.7 million to $43.3 million using a 3 percent 
discount rate and from $6.5 million to $45.9 million using a 7 percent 
discount rate.

   Table XII-7--Summary of Total Annualized Benefits of the Final Rule
                    [Millions of 2018$; annualized] a
------------------------------------------------------------------------
                                            3% Discount     7% Discount
            Benefit category                   rate            rate
------------------------------------------------------------------------
Human Health............................           -$0.3           -$0.1
    Changes in IQ losses in children               <$0.0           <$0.0
     from exposure to lead \b\..........
    Changes in IQ losses in children               -$0.3           -$0.1
     from exposure to mercury...........
Ecological Conditions and Recreational       -$15.3 to -     -$16.4 to -
 Uses Changes...........................            $7.4            $8.0
    Use and nonuse values for water          -$15.3 to -     -$16.4 to -
     quality changes \c\................            $7.4            $8.0
Market and Productivity.................           <$0.0           <$0.0
    Changes in dredging costs \b\.......           <$0.0           <$0.0
    Changes in water withdrawals \b\....           <$0.0           <$0.0
Air Quality-related effects.............      $14 to $51      $23 to $54
    Domestic climate benefits \d\.......            -$14           -$2.3
    Health benefits d e.................      $28 to $65      $25 to $56
                                         -------------------------------
        Total Monetized Benefits \f\....  -$1.7 to $43.3   $6.5 to $45.9
------------------------------------------------------------------------
\a\ Negative values represent forgone benefits and positive values
  represent realized benefits.
\b\ ``<$0.0'' indicates that monetary values are greater than -$0.1
  million but less than $0.00 million.
\c\ The range reflects the lower and upper bound willingness-to-pay
  estimates.
\d\ Values for air-quality related effects are rounded to two
  significant figures.
\e\ The range reflects the lower and upper bound estimates of human
  health effects from changes in PM2.5 and ozone levels.
\f\ Values for individual benefit categories may not sum to the totals
  due to independent rounding.

D. Unmonetized Benefits

    The monetary value of the final rule's effects on social welfare 
does not account for all anticipated effects of the final rule because, 
as described above, EPA is unable to monetize certain benefit 
categories. Examples of effects not reflected in the monetary estimates 
include changes in bladder cancer

[[Page 64701]]

incidence and other human health effects associated with changes in 
drinking water disinfection byproduct levels; changes in ecosystem, 
visibility, and human health effects due to direct exposure to 
NOX, HAP, and SO2 air emissions; changes in 
certain non-cancer human health risks (e.g., effects of cadmium on 
kidney functions and bone density); impacts of pollutant discharge 
changes on threatened and endangered species; and ash marketability 
changes. The BCA report discusses changes in these effects 
qualitatively and indicates their potential magnitude where possible.

XIII. Development of Effluent Limitations and Standards

A. FGD Wastewater

    Consistent with the proposal, EPA is finalizing several sets of 
new, concentration-based, numeric effluent limitations and pretreatment 
standards that apply to discharged FGD wastewater from existing 
sources.\148\ The specific limitations that apply to any particular 
plant are determined by whether it qualifies for one of the rule's 
subcategories or whether it chooses to participate in the VIP. EPA 
developed the numeric effluent limitations and pretreatment standards 
in this rule using long-term average effluent values and variability 
factors that account for variations in performance at well-operated 
plants that employ the technologies that constitute the bases for 
control. EPA's methodology for derivation of limitations in ELGs is 
longstanding and has been upheld in court. See, e.g., Chem. Mfrs. Ass'n 
v. EPA, 870 F.2d 177 (5th Cir. 1989); Nat'l Wildlife Fed'n v. EPA, 286 
F.3d 554 (D.C. Cir. 2002). EPA establishes the final effluent 
limitations and standards as ``daily maximums'' and ``maximums for 
monthly averages.'' Definitions provided in 40 CFR 122.2 state that the 
daily maximum limitation is the ``highest allowable `daily discharge' 
'' and the maximum for monthly average limitation is the ``highest 
allowable average of `daily discharges' over a calendar month, 
calculated as the sum of all `daily discharges' measured during a 
calendar month divided by the number of `daily discharges' measured 
during that month.'' Daily discharges are defined as the `` `discharge 
of a pollutant' measured during a calendar day or any 24-hour period 
that reasonably represents the calendar day for purposes of sampling.''
---------------------------------------------------------------------------

    \148\ Effluent limitations for EGUs with nameplate capacity of 
50 MW or smaller and for EGUs that will retire by December 31, 2028, 
are not discussed in this section. The proposed limitations for 
these generating units are based on the previously established BPT 
limitations on TSS.
---------------------------------------------------------------------------

1. Overview of the Limitations and Standards
    EPA's objective in establishing daily maximum limitations is to 
restrict the discharges on a daily basis at a level that is achievable 
for a plant that designs and operates its treatment to achieve the 
long-term average performance that EPA's statistical analyses show the 
BAT/PSES technology can attain (i.e., the mean of the underlying 
statistical distribution of daily effluent values). EPA recognizes that 
variability around the long-term average occurs during normal 
operations. This variability means that plants occasionally may 
discharge at a level that is higher than the long-term average, and at 
other times will discharge at a level that is lower than the long-term 
average. To allow for these possibly higher daily discharges and 
provide an upper bound for the allowable concentration of pollutants 
that may be discharged, while still targeting achievement of the long-
term average, EPA has established the daily maximum limitation. A plant 
consistently discharging at a level near the daily maximum limitation 
would be symptomatic of a plant that is not operating its treatment to 
achieve the long-term average. Targeting treatment to achieve the daily 
limitation, rather than the long-term average, is not consistent with 
the capability of the BAT/PSES technology basis and may result in 
values that periodically exceed the limitations due to routine 
variability in treated effluent.
    EPA's objective in establishing monthly average limitations is to 
provide an additional restriction to help ensure that plants target 
their average discharges to achieve the long-term average. The monthly 
average limitation requires dischargers to provide ongoing control that 
supplements controls imposed by the daily maximum limitation. In order 
to meet the monthly average limitation, a plant must counterbalance a 
value near the daily maximum limitation with one or more values well 
below the daily maximum limitation.
2. Criteria Used to Select Data
    In developing effluent limitations guidelines and standards for any 
industry, EPA qualitatively reviews all the data related to effluent 
treatment to identify data that represent proper operation of the 
technology that forms the basis for the limitations. EPA typically uses 
four criteria to assess the data. The first criterion requires that the 
plants have the model treatment technology identified as the basis for 
effluent limitations (e.g., CP + LRTR) and demonstrate consistently 
diligent and optimal operation. Application of this criterion typically 
eliminates any plant with treatment other than the model technology. 
EPA generally determines whether a plant meets this criterion based on 
site visits, discussions with plant management, and/or comparison to 
the characteristics, operation, and performance of treatment systems at 
other plants. EPA reviews available information to determine whether 
data submitted were representative of normal operating conditions for 
the plant and equipment. As a result of this review, EPA typically 
excludes the data from plants that have not optimized the performance 
of their treatment systems.
    A second criterion generally requires that the influents and 
effluents from the treatment components represent typical wastewater 
from the industry, without incompatible wastewater from other sources. 
Application of this criterion results in EPA selecting those plants 
where the commingled wastewaters did not result in substantial 
dilution, unequalized slug loads resulting in frequent upsets and/or 
overloads, more concentrated wastewaters, or wastewaters with different 
types of pollutants than those generated by the wastestream for which 
EPA is establishing effluent limitations and pretreatment standards.
    A third criterion typically ensures that the pollutants are present 
in the influent at sufficient concentrations to evaluate treatment 
effectiveness. If a data set for a pollutant shows that the pollutant 
was not present at a treatable concentration at sufficient frequency 
(e.g., the pollutant was below the level of detection in all influent 
samples), EPA excludes the data for that pollutant at that plant when 
calculating the limitations.
    A fourth criterion typically requires that the data are valid and 
appropriate for their intended use (e.g., the data must be analyzed 
with a sufficiently sensitive analytical method). Also, EPA does not 
use data associated with periods of treatment upsets because these data 
would not reflect the performance from well-designed and well-operated 
treatment systems. In applying the fourth criterion, EPA may evaluate 
the pollutant concentrations, analytical methods and the associated 
quality control/quality assurance data, flow values, mass loading, 
plant logs, test reports, and other available information. As part of 
this evaluation, EPA reviews the process or treatment conditions that 
may have resulted in

[[Page 64702]]

extreme values (high and low). As a consequence of this review, EPA may 
exclude data associated with certain time periods or other data 
outliers that reflect poor performance or analytical anomalies by an 
otherwise well-operated site.
    The fourth criterion also is applied in EPA's review of data from 
the initial commissioning period of treatment systems and startup 
periods of pilot test equipment. Most industries incur commissioning 
periods during which adjustments must be made to newly installed 
treatment systems. During this acclimation and optimization process, 
the effluent concentration values tend to be highly variable, with 
occasional extreme values (high and low). This occurs because the 
treatment system typically requires some ``tuning'' by the plant staff 
and equipment and chemical vendors. They work together to determine the 
optimum chemical addition locations and dosages, vessel hydraulic 
residence times, internal treatment system recycle flows (e.g., filter 
backwash frequency, duration and flow rate, return flows between 
treatment system components), and other operational conditions, such as 
clarifier sludge wasting protocols. It may also take time for treatment 
system operators to gain expertise in operating the new treatment 
system, which also contributes to treatment system variability during 
the commissioning period. After this initial adjustment period, the 
systems should operate at steady state with relatively low variability 
around a long-term average over many years. Because commissioning 
periods typically reflect one-time operating conditions unique to the 
first time the treatment system begins operation, EPA generally 
excludes such data in developing the limitations.\149\
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    \149\ Examples of conditions that are typically unique to the 
initial commissioning period include operator unfamiliarity or 
inexperience with the system and how to optimize its performance; 
wastewater flow rates that vary widely from engineering design, 
altering hydraulic residence times, chemical contact times, and/or 
clarifier overflow rates, and potentially causing large changes in 
planned chemical dosage rates or the need to substitute alternative 
chemical additives; equipment malfunctions; fluctuating wastewater 
flow rates or other dynamic conditions (i.e., not steady state 
operation); and initial purging of contaminants associated with 
installation of the treatment system, such as initial leaching from 
coatings, adhesives, and susceptible metal components. These 
conditions differ from those associated with the restart of an 
already-commissioned treatment system, such as may occur from a 
treatment system that has undergone either short or extended 
duration shutdown.
---------------------------------------------------------------------------

3. Data Used To Calculate Limitations and Standards
    The Supplemental TDD provides a description of the data and 
methodology used to develop long-term averages, variability factors, 
and limitations and standards for this rule. The effluent limitations 
and pretreatment standards for the low utilization subcategory and high 
FGD flow subcategory are based on chemical precipitation. The 
derivation of the limitations for these subcategories and the data used 
are described in section 13 of the 2015 TDD. The new limitations and 
pretreatment standards for plants not in those subcategories, and for 
the VIP, were derived from a statistical analysis of effluent data 
collected by plants during extended testing of the LRTR technology and 
membrane filtration technology, respectively. The duration of the test 
programs at these plants varied from approximately one month for 
membranes to more than a year for LRTR, enabling EPA to evaluate long-
term performance of these technologies under conditions that can 
contribute to influent variability, including varying power demand, 
changes in coal suppliers, and changes in operation of the air 
pollution control system. The tests occurred over different seasons of 
the year and demonstrate that the technologies operate effectively 
under different climate conditions.
    During the development of the final limitations and pretreatment 
standards, EPA identified certain data that warranted exclusion 
because: (1) The samples were analyzed using a method that is not 
sensitive enough to reliably quantify the pollutants present (e.g., use 
of EPA Method 245.1 to measure the concentration of mercury in effluent 
samples); (2) the analytical results were identified as questionable 
due to quality control issues associated with the laboratory analysis 
or sample collection, or were analytical anomalies; (3) the samples 
were collected prior to steady-state operating conditions and do not 
represent BAT/PSES level of performance; (4) the samples were collected 
during a period where influent composition did not reflect the FGD 
wastewater (e.g., untreated FGD wastewater was mixed with large volumes 
of non-FGD wastewater prior to entering the treatment system); (5) the 
treatment system was operating in a manner that does not represent BAT/
PSES level of performance; or (6) the samples were collected from a 
location that is not representative of treated effluent.
4. Long-Term Averages and Effluent Limitations and Standards for FGD 
Wastewater
    EPA received numerous comments on the development of the CP+LRTR 
limitations. First, the Agency received comments arguing that the 
limitations calculations should have included or excluded individual 
data points or data sets, for a number of reasons. For example, one 
commenter asserted that plant 2027's mercury data set used an improper 
method under EPA's criteria, another asserted that plant 2066 had 
unrepresentative influent pollutant concentrations, and another 
asserted that excluded data points from plant 2019 were actually 
representative of potential operating conditions. EPA also received 
comments that limitations should be developed with data from full-scale 
systems and that nitrate/nitrite limitations are unnecessary for a 
well-operated biological treatment system. Finally, EPA was aware of an 
additional data set which it discussed at proposal, and had requested, 
but which the Agency did not receive until after the comment period 
closed.
    EPA agrees with comments that the mercury data set for Plant 2027 
did not use an EPA-approved method and that the method used had an 
improper mercury detection limitation (not sufficiently sensitive). 
Accordingly, the Agency has excluded those mercury data from its 
calculation of the final mercury limitations. With respect to plant 
2066, EPA compared this plant's data to other plants and found that it 
neither had the lowest influent concentrations nor met the test for 
statistical outliers.\150\ In the absence of a valid statistical 
rationale for excluding these data, which meet all of the criteria 
detailed above, EPA used these data in its calculations of the final 
limitations. With respect to plant 2019, the data in question were 
excluded by the Agency because that data was collected during periods 
where the pilot study operators attempted to test the operating 
limitations of (i.e., ``break'') the biological treatment system by 
spiking the influent with large quantities of constituents and/or 
drastically altering the flow. Contrary to the assertions by commenters 
that there could be operating conditions like these in the future, 
these pilot conditions were intentionally designed not to be 
representative of the BAT/PSES level of performance, and thus do not 
satisfy the selection criteria (specifically, criterion

[[Page 64703]]

5) above.\151\ Remaining comments suggesting inclusion of individual 
data points were reasonable and adhered to sound engineering 
principles. Since EPA agrees with commenters that these are valid, 
representative data, EPA included them in the final limitations 
calculations.
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    \150\ For example, this plant's data are well within the range 
of the Interquartile Range Rule. See Section 8 of the Supplemental 
TDD for more discussion.
    \151\ However, to the extent such artificial conditions could be 
representative of an upset, the Agency still finds that these data 
may be useful for plants to consider when designing their systems.
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    The Agency agrees with commenters that full-scale system data is 
typically preferable to pilot study data. Nevertheless, EPA weighed the 
potential benefit of waiting for full-scale LRTR system data (which due 
to the recency of LRTR installations is only just being collected) 
versus the potential harm of delaying a final rule where the 2015 rule 
compliance dates are this year, and determined such a course of action 
is not warranted. The Agency has always maintained, and courts have 
upheld, its ability to establish limitations based on pilot data. See 
Am. Iron & Steel Institute v. EPA, 526 F.2d 1027, 1063 (3d Cir. 1975); 
Weyerhaeuser v. Costle, 590 F.2d 1011, 1054 n.70 (D.C. Cir. 1978). 
Furthermore, the Agency does not need to wait for better information 
when the information available is sufficient. See Texas Oil and gas 
Ass'n v. EPA, 161 F.3d 923, 935 (5th Cir. 1998) (``An agency's choice 
to proceed on the basis of `imperfect information' is not arbitrary and 
capricious unless `there is simply no rational relationship' between 
the means used to account for any imperfections and the situations to 
which those means are applied.'') (citation omitted). Here the Agency 
determined that the pilot data are sufficiently representative, and 
therefore the marginal adjustments in limitations that might result 
from full-scale system performance data do not warrant the delayed 
pollutant reductions of these limitations going into effect.
    EPA also disagrees that nitrate/nitrite limitations are 
unnecessary. While commenters are correct that a properly operated and 
maintained biological treatment system will necessarily remove nitrate/
nitrite prior to reduction of selenium, it is the nitrate/nitrite 
limitations themselves that in part ensure that the BAT technology or 
other comparable technology is used. In the absence of a nitrate/
nitrite limit, two electric utilities described how the use of chemical 
precipitation-based systems might be used to treat selenium in the 
selenite form if the limitation is raised from the 2015 rule 
limit.\152\ Another pilot of a ZVI system showed high selenium removal 
efficiency but did not consistently remove nitrogen (DCN SE05619). 
Neither the chemical-precipitation-based systems or ZVI systems would 
consistently treat nitrate/nitrite and thus, while they may be a more 
advanced technology than chemical precipitation alone and meet the 
limitations for mercury, arsenic, and selenium included in this final 
rule, neither would achieve full compliance.
---------------------------------------------------------------------------

    \152\ TVA suggested that a sulfide analyzer would allow it to 
monitor ORP in the FGD to produce a higher fraction of selenite (a 
form of dissolved selenium which, with optimization, can be 
precipitated to a high degree, even without a biological treatment 
stage).
---------------------------------------------------------------------------

    Finally, EPA received an additional LRTR pilot data set conducted 
at the Kingston power plant. EPA had mentioned this pilot at proposal, 
but the full study and analysis of data were only completed in January 
2020. While commenters did not have an ability to comment on the data 
per se, EPA continues to rely on the same criteria for selecting and 
including representative data, and the same methodology for analyzing 
those data in development of the long-term averages and limitations, 
and other data, all of which were subject to public comment. The data 
meet the criteria specified above, and EPA has determined these are 
valid, representative data. Therefore, EPA has supplemented the LRTR 
data used for development of the final limitations with the Kingston 
data set. See BASF Wyandotte Corp. v. Costle, 598 F.2d 637, 644-46 (1st 
Cir. 1979) (holding that EPA's use of new data in a final rule did not 
deprive the public of a fair opportunity to comment on the data). The 
outcome of the changes described above was generally to lower long-term 
averages but increase daily variability factors. This results in, for 
example, higher daily arsenic limitations while monthly arsenic 
limitations were lower.
    EPA also received comments on the VIP limitations. As with the 
CP+LRTR limitations comments, commenters argued that EPA should not 
have excluded certain data points, and that such exclusions had made 
the limitations too stringent. Commenters also argued that EPA had 
relied too heavily on non-detects.
    Commenters suggested that EPA include certain individual data 
points because the data were reasonable and adhered to sound 
engineering principles. EPA agrees with commenters that these are 
valid, representative data. EPA has included these data in the final 
VIP limitations calculations. The situation with non-detect data was 
more complicated. The same commenters who suggested that the monthly 
data sets relied too heavily on non-detect data also made very 
compelling arguments that EPA should have evaluated membrane filtration 
with pretreatment using chemical precipitation, as discussed with 
respect to updated costs in Section VIII above. In light of these 
compelling comments, and for consistency, EPA re-evaluated the data 
used to develop the proposed VIP limitations. The record indicates that 
one pilot plant incorporated microfiltration rather than chemical 
precipitation for a portion of its pilot data set, and therefore EPA 
decided that the microfiltration-only subset of data should be excluded 
as it is not representative of the BAT technology basis for the final 
rule (see Section VII(B)(1) above). As a result, EPA agrees that some 
of the monthly data sets relied heavily on non-detect data, and due to 
the inability to calculate monthly variability factors with the reduced 
data set, has not finalized a monthly limitation for selenium or 
bromide.\153\ This also resulted in daily limitations for selenium and 
bromide that are just one-half and one-third of those proposed, 
respectively. In contrast, EPA found that monthly limitations for 
mercury, nitrate/nitrite, and TDS were still appropriately calculated 
from detected concentrations. Importantly, the Agency has not 
eliminated the daily maximum limitations for these constituents, and it 
finds that the very low monthly average TDS limitations ensure that VIP 
systems are obtaining sufficient pollutant removals at plants that do 
not eliminate their discharges completely (e.g., by recycling permeate 
or distillate).
---------------------------------------------------------------------------

    \153\ Monthly average limits for arsenic were not calculated for 
the proposal, and thus this is not a change.
---------------------------------------------------------------------------

    Table XIV-1 presents the final effluent limitations and standards 
for FGD wastewater. For comparison, the table also presents the long-
term average treatment performance calculated for each parameter. Due 
to routine variability in treated effluent, a power plant that targets 
discharging its wastewater at a level near the values of the daily 
maximum limitation or the monthly average limitation may periodically 
experience values exceeding the limitations. For this reason, EPA 
recommends that plants design and operate their treatment system to 
achieve the long-term average for the model technology. A system that 
is designed and operated to achieve the long-term average BAT/PSES 
level of control would meet the limitations.
    EPA expects that plants will be able to meet their effluent 
limitations or

[[Page 64704]]

standards at all times. If an exceedance is caused by an upset 
condition, the plant would have an affirmative defense to an 
enforcement action if the requirements of 40 CFR 122.41(n) are met. 
Exceedances caused by a design or operational deficiency, however, are 
indications that the plant's performance does not represent the 
appropriate level of control. For the final limitations and 
pretreatment standards, EPA finds that such exceedances can be 
controlled by diligent operational practices for the process and 
wastewater treatment system, such as regular monitoring of influent and 
effluent wastewater characteristics and adjusting dosage rates for 
chemical additives to target effluent performance for regulated 
pollutants at the long-term average concentration for the BAT/PSES 
technology. Additionally, some plants may need to upgrade or replace 
existing treatment systems to ensure that the treatment system is 
designed to achieve performance that targets the effluent 
concentrations at the long-term average. This is consistent with EPA's 
costing approach and its engineering judgment, developed over years of 
evaluating wastewater treatment processes for steam electric power 
plants and other industrial sectors. EPA recognizes that some 
dischargers, including those that are currently operating technologies 
representing the technology basis for the final rule and VIP, may need 
to improve their treatment systems, process controls, and/or treatment 
system operations in order to consistently meet the final effluent 
limitations and pretreatment standards. This is consistent with the 
CWA, which requires that BAT/PSES discharge limitations and standards 
reflect the best available technology economically achievable.
    See Section 8 of the Supplemental TDD for more information about 
the calculation of the limitations and pretreatment standards presented 
in the tables below.

         Table XIV-1--Long-Term Averages and Effluent Limitations and Pretreatment Standards for FGD Wastewater for Existing Sources (BAT/PSES)a
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                             Long-Term     Daily maximum
                Subcategory                                   Pollutant                       average       limitation      Monthly average limitation
--------------------------------------------------------------------------------------------------------------------------------------------------------
Requirements for all plants not in the VIP   Arsenic ([micro]g/L........................            4.98              18  8
 or subcategories specified below (BAT &
 PSES).
                                             Mercury (ng/L).............................           13.48             103  34
                                             Nitrate/nitrite as N (mg/L)................            2.14               4  3
                                             Selenium ([micro]g/L)......................           15.87              70  29
Voluntary Incentives Program for FGD         Arsenic ([micro]g/L).......................         \b\ 5.0               5  NA
 Wastewater (existing direct dischargers).
                                             Mercury (ng/L).............................            5.44              23  10
                                             Nitrate/nitrite as N (mg/L)................            0.89             2.0  1.2
                                             Selenium ([micro]g/L)......................            7.35              10  NA
                                             Bromide (mg/L).............................           0.200             0.2  NA
                                             TDS (mg/L).................................           86.06             306  149
Low utilization subcategory-AND-High FGD     Arsenic ([micro]g/L).......................            5.98              11  8
 flow subcategory (BAT & PSES).
                                             Mercury (ng/L).............................             159             788  356
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ BAT effluent limitations for EGUs that will permanently cease the combustion of coal by December 31, 2028, are based on the previously established
  BPT limitations on TSS and are not shown in this table. The BAT effluent limitations for TSS for these EGUs are: Daily maximum of 100 mg/L; and
  monthly average of 30 mg/L.
\b\ Long-term average is the arithmetic mean of the quantitation limitations because all observations were not detected.
\c\ Limitation is set equal to the quantitation limit for the data evaluated.
\d\ Monthly average limitation is not established when the daily maximum limitation is based on the quantitation limit.

    EPA notes that some limitations are higher than corresponding 
limitations in the 2015 rule (or even the 2019 proposal), and in other 
cases limitations of additional pollutants or lower limitations for 
pollutants regulated in the 2015 rule have also been calculated.

B. BA Transport Water Limitations

1. Maximum 10 Percent 30-Day Rolling Average Purge Rate
    In contrast to the concentration-based, numeric limitations 
estimated for specific pollutants above, EPA is finalizing a pollutant 
discharge allowance in the form of a site-specific percentage purge 
rate for BA transport water with a maximum cap. To develop this 
requirement, EPA first collected data on the discharge needs of the 
model treatment technology (high recycle rate systems) to maintain 
water chemistry or water balance.\154\ EPRI (2016) presents discharge 
data from seven currently operating wet BA transport water systems at 
six plants. These plants were able to recycle most or all BA transport 
water from these seven systems, resulting in discharges of between zero 
and two percent of the system volume. EPA's goal in establishing the 
purge rate was to provide a requirement based on process needs, as 
reflected in the EPRI (2016) data, as well as infrequent precipitation 
and maintenance events. While EPRI (2016) noted that infrequent 
discharges happened at some plants, it did not include such events in 
its discharge calculations. As a result, EPA looked to EPRI (2018), 
which presents hypothetical maximum discharge volumes and the estimated 
frequencies of such infrequent events for currently operating wet BA 
systems.\155\ For purposes of calculating the maximum allowance 
percentage associated with such infrequent events, EPA divided the 
discharge associated with an estimated maintenance and precipitation 
event by the volume of the system, and then

[[Page 64705]]

averaged the resulting percent over 30 days.
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    \154\ Although the technology basis includes dry handling, the 
limitation is based on the necessary purge volumes of a wet, high 
recycle rate BA system.
    \155\ Although presented in EPRI (2018), EPA did not consider 
events such as pipe leaks, as these would not be reflective of 
proper system operation (see DCN SE06920).
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    Finally, EPA added each reported regular discharge percent from 
EPRI (2016) to the averaged infrequent discharge percent under four 
scenarios: (1) With no infrequent discharge event; (2) with only a 
precipitation-related discharge event; (3) with only a maintenance-
related discharge event; and (4) with both a precipitation-related and 
maintenance-related discharge event. These potential discharge needs 
are reported in Table XIV-2 below. Consistent with the statistical 
approach used to develop effluent limitations and pretreatment 
standards for individual pollutants, EPA selected a 95th percentile of 
total system volume as representative of a 30-day rolling average, 
which results in a limitation of 10 percent of total system 
volume.\156\
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    \156\ While there were further decimal points for the actual 
calculated 95th percentile, EPA notes that 10 percent is two 
significant digits, consistent with the limitations for FGD 
wastewater pollutants. Furthermore, a 10 percent volumetric limit 
will be easier for implementation by the permitting authority as it 
results in a simple decimal point movement for calculations.

                                  Table XIV-2--30-Day Rolling Average Discharge Volume as a Percent of System Volume a
--------------------------------------------------------------------------------------------------------------------------------------------------------
         Infrequent discharge needs as estimated in EPRI (2018)            Regular discharge needs to maintain water chemistry and/or water balance as
------------------------------------------------------------------------                           characterized in EPRI (2016)
                                                               30-day   --------------------------------------------------------------------------------
            Type of infrequent discharge event                rolling                                                             Plant F-     Plant F-
                                                              average     Plant A    Plant B    Plant C    Plant D    Plant E     system 1     system 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              0.1%       0.0%       1.0%       0.0%       0.8%         2.0%         2.0%
Neither Event.............................................         0.0%       0.1%       0.0%       1.0%       0.0%       0.8%         2.0%         2.0%
Precipitation Only........................................         5.4%       5.5%       5.4%       6.4%       5.4%       6.2%         7.4%         7.4%
Maintenance Only..........................................         3.3%       3.4%       3.3%       4.3%       3.3%       4.1%         5.3%         5.3%
Both Events...............................................         8.7%       8.8%       8.7%       9.7%       8.7%       9.5%        10.7%        10.7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ These estimates sum actual, reported, plant-specific regular discharge needs with varying combinations of hypothetically estimated, infrequent
  discharge needs.

    EPA received a significant range of comments on the calculation of 
this 10 percent purge. Many comments concerned the treatment of 
infrequent purges, especially those relating to precipitation. The 
range of comments demonstrates, among other things, that a nationwide 
limitation for precipitation-related purges can be too stringent in 
some geographic areas and not stringent enough in others. EPA, 
therefore, made modifications in the final rule that require the NPDES 
permitting authority to develop a site-specific purge percentage that 
is capped at 10 percent.\157\ EPA recognizes that some plants may need 
to improve their equipment, process controls, and/or operations to 
consistently meet the limitations included in this final rule; however, 
this is consistent with the CWA, which requires that BAT/PSES discharge 
limitations and standards reflect the best available technology 
economically achievable.
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    \157\ As discussed in Section VIII(b)(2) above, to the extent 
that a precipitation event such as a hurricane were to occur and 
result in a plant needing to discharge in excess of the established 
purge percent, upset provisions provide a potentially appropriate 
affirmative defense.
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    The remainder of comments on the 10 percent purge calculation 
recommended additional circumstances in which EPA should allow a purge 
beyond 10 percent. EPA disagrees with these comments because the 10 
percent purge cap that EPA estimated is reflective of properly operated 
and maintained high recycle rate systems, the technology that EPA 
selected as BAT. In the rare cases when precipitation-related events 
result in a purge of greater than 10 percent--100-year/24 hour storms, 
multiple large storms, etc.--EPA notes that the NPDES regulations 
contain flexibilities for upset and bypass. See 40 CFR 122.41(m) and 
(n).
2. Best Management Practices Plan
    As described in Section VII of this preamble, the final rule 
requires a subcategory of plants discharging BA transport water and 
having a low CUR to develop and implement a BMP plan to recirculate BA 
transport water back to the BA handling system (see Section VII of this 
preamble for more details).
    The final BMP provisions require subject plants to develop a plan 
to minimize the discharge of pollutants by recycling as much BA 
transport water as feasible back to the BA handling system.\158\ After 
determining the amount of BA transport water that could be feasibly 
recycled and developing and implementing a plant-specific BMP plan, 
plants are required to review the plan annually and revise it as 
necessary.
---------------------------------------------------------------------------

    \158\ Since the BMP plan requirements include periodic updates, 
a change in treatment technology (for instance due to the CCR rule) 
would be reflected automatically in the BMP plan.
---------------------------------------------------------------------------

XIV. Regulatory Implementation

A. Implementation of the Limitations and Standards

    The limitations and standards in this rule apply to discharges from 
steam electric power plants through incorporation into NPDES permits 
issued by EPA or by authorized states under Section 402 of the CWA, and 
through local pretreatment programs under Section 307 of the CWA. NPDES 
permits or control mechanisms issued after this rule's effective date 
must incorporate the ELGs, as applicable. Where permits with the 2015 
rule limitations have already been issued, EPA expects that the final 
rule requirements will be incorporated through permit modifications in 
most cases. 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 this rule. Finally, in addition to requiring 
application of the technology-based ELGs in this 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.
1. Timing
    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 floor or a minimum level of control. The final rule provides the 
plant's permitting authority with certain discretion to determine the 
date when the new effluent limitations for FGD wastewater and BA 
transport water will apply to a given discharger. The rule specifies 
that the earliest date these new limitations can apply to a discharger 
is

[[Page 64706]]

October 13, 2021. Except for the limitations in certain subcategories, 
for any final effluent limitation that is specified to become 
applicable after October 13, 2021, the specified date must be as soon 
as possible after that date, but in no case later than December 31, 
2025. Consistent with the proposal, for dischargers choosing to meet 
the VIP effluent limitations for FGD wastewater, the date for meeting 
those limitations is December 31, 2028.
    For FGD wastewater and BA transport water from EGUs permanently 
ceasing the combustion of coal by 2028, the final BAT limitations for 
this subcategory apply on the date that an NPDES permit is issued to a 
discharger. The final rule does not build in an implementation period 
for meeting these limitations, as the BAT limitation on TSS is equal to 
the previously promulgated BPT limitation on TSS.
    Consistent with the proposal, for FGD wastewater and BA transport 
water from low utilization EGUs and FGD wastewater from high FGD flow 
plants, the final BAT limitations for these subcategories would apply 
on or after October 13, 2021. The specified date must be as soon as 
possible after that date, but in no case later than December 31, 2023. 
EPA considered earlier and later dates than December 31, 2023. With 
respect to later dates, the limitations in these subcategories are less 
stringent than the limitations in the 2015 rule, which the Agency found 
were achievable by 2023. Nothing in the Agency's record since then 
would suggest otherwise. Thus, the Agency did not select a later date. 
With respect to earlier dates, EPA acknowledges that some of the 
limitations might be implemented sooner at some plants. Nevertheless, 
the Agency is retaining the December 31, 2023 date. For LUEGUs, the 
Agency is allowing demonstration of the required CUR by December 31, 
2023, in response to comments, as discussed in Section XIV(A)(3) below. 
Since it would be inconsistent to require compliance with these 
limitations prior to demonstration that the LUEGU CUR requirements are 
met, setting a ``no later than date'' earlier than December 31, 2023, 
would not adequately support this modified requirement of the final 
rule. For high FGD flow plants, EPA is also retaining the outside 
compliance date of December 31, 2023. In an FDF variance request filed 
for the single known high flow plant, that plant indicated that it did 
not have chemical precipitation, and preliminary estimates were that 
chemical precipitation would take until 2023 to construct, commission, 
and optimize. The EPA does not have any information to suggest that a 
chemical precipitation system at a high flow plant could be installed 
any more quickly; however, to the extent that an earlier date is 
feasible at a high FGD flow plant, the permitting authority can already 
account for this under current 40 CFR 423.11(t).
    Pretreatment standards, unlike effluent limitations, are directly 
enforceable and must be met three years after the effective date of any 
final rule. CWA section 307(b)(1). Under EPA's General Pretreatment 
Regulations for Existing and New Sources, POTWs with flows in excess of 
5 Mgd must develop pretreatment programs meeting prescribed conditions, 
including the legal authority to require compliance with applicable 
general and categorical pretreatment standards and control the 
introduction of pollutants to the POTW through permits, orders or 
similar means, to ensure the contribution to the POTW by each 
industrial user is in compliance with applicable pretreatment standards 
and requirements. 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 discharge limitations for the POTW's industrial users. Because 
pollutant discharge limitations in categorical pretreatment standards 
may be expressed either as concentrations or mass limitations, the 
control authority, in many cases, must convert the pretreatment 
standards to limitations applicable to a specific industrial user and 
then include these in POTW permits or another control instrument.
    Regardless of when a plant's NPDES permit is ready for renewal, EPA 
recommends that each plant immediately begin evaluating how it intends 
to comply with the requirements of any final rule. In cases where 
significant changes in operation are appropriate, 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 a 
final rule is issued, even prior to the permit renewal process.
    In cases where a plant's final NPDES permit was issued before these 
ELGs were finalized and includes limitations for BA transport water 
and/or FGD wastewater from the 2015 rule, the permitting authority may 
modify the permit based on promulgation of this rule pursuant to 40 CFR 
122.62(a)(3). EPA recommends that the plant and permitting authority 
determine whether such a permit should be modified in light of this 
rule, and if so, that it be modified as soon as practicable and 
consistent with any new rule provisions.\159\
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    \159\ In some circumstances, if a permit cross-references or 
incorporates the regulation by reference, if state law allows, it is 
possible that the changes finalized today might be automatically 
incorporated. However, this is unlikely to be the case in many 
permits, and plants should carefully review their permits before 
drawing this conclusion.
---------------------------------------------------------------------------

    The ``as soon as possible'' date is October 13, 2021, unless the 
NPDES permitting authority determines another date after receiving 
relevant information submitted by the discharger.\160\ The final rule 
does not revise the specified factors that the NPDES permitting 
authority must consider in determining the as soon as possible date 
under the 2015 rule. Assuming that the NPDES permitting authority 
receives relevant information from each discharger, in order to 
determine what date is ``as soon as possible'' within the 
implementation period, the factors established in the 2015 rule are:
---------------------------------------------------------------------------

    \160\ Information in the record indicates that most facilities 
should be able to complete all steps to implement changes needed to 
comply with proposed BA transport water requirements within 15-23 
months, and the FGD wastewater requirements within 26 to 34 months.
---------------------------------------------------------------------------

    (a) Time to expeditiously plan (including to raise capital), 
design, procure, and install equipment to comply with the requirements 
of the final rule.\161\
---------------------------------------------------------------------------

    \161\ Cooperatives and municipalities presented information to 
EPA suggesting that obtaining financing for these projects can be 
more challenging than for investor-owned utilities. Under this 
factor, permitting authorities may consider whether the type and 
size of owner and difficulty in obtaining the expected financing 
might warrant additional flexibility up to the ``no later than'' 
date.
---------------------------------------------------------------------------

    (b) Changes being made or planned at the plant in response to 
greenhouse gas 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 the Resource Conservation and 
Recovery Act.
    (c) For FGD wastewater requirements only, an initial commissioning 
period to optimize the installed equipment.
    (d) Other factors as appropriate.
    EPA proposed to clarify that the discharger must provide relevant, 
site-specific information for consideration of these factors by the 
permitting authority. However, commenters stated that in many cases, 
information developed to inform these decisions may reflect fleet-wide 
or company-wide operations, maintenance or financial information and 
may not be ``site-specific'' to a single plant or EGU. Thus, the key is 
that the information be demonstrated to be relevant to the plant in 
question, but need not be based on

[[Page 64707]]

site-specific operations, maintenance or financial information. The 
Agency agrees with these comments, and thus the final rule does not 
include a requirement for unique, site-specific information.
    As specified in factor (b), the permitting authority must also 
consider scheduling for installation of equipment, which includes a 
consideration of plant changes planned or being made to comply with 
certain other key rules that affect the steam electric power generating 
industry. As specified in factor (c), for the FGD wastewater 
requirements only, the permitting authority must consider whether it is 
appropriate to allow more time for implementation in order to ensure 
that the plant has appropriate time to optimize any relevant 
technologies.
    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 October 13, 2021, the justification would 
explain why allowing additional time to meet the final limitations is 
appropriate, and why the discharger cannot meet the effluent 
limitations as of October 13, 2021. In cases where the plant is already 
operating the BAT technology basis for a specific wastestream (e.g., 
high recycle rate system for BA transport water), operates the majority 
of the proposed BAT technology basis (e.g., FGD chemical precipitation 
and biological treatment, without sulfide addition), or expects that 
relevant treatment and process changes would be in place prior to 
October 13, 2021 (for example due to the CCR rule), it would not 
usually be appropriate to allow additional time beyond that date to 
comply with the final rule limitations and standards. Regardless, in 
all cases, the permitting authority would make clear in the permit by 
what date the plant must meet the final limitations, and that date is 
no later than December 31, 2025.\162\
---------------------------------------------------------------------------

    \162\ For BA purge water, permitting authorities may determine 
the appropriate timeframe for any limitations imposed as a result of 
a BPJ analysis on this wastestream; however, EPA strongly encourages 
state and tribal permitting authorities to invest the time and 
resources necessary to establish BPJ limits for BA purge water and 
issue permits timely to allow facilities to install the necessary 
equipment within the compliance deadlines in the final rule.
---------------------------------------------------------------------------

    Where a discharger chooses to participate in the VIP and be subject 
to effluent limitations for FGD wastewater based on membranes, the 
NPDES permitting authority must allow the plant up to December 31, 
2028, to meet those limitations, consistent with the documentation 
received from the plant. Again, the permit must make clear that the 
plant must meet the limitations by December 31, 2028.
2. Determining the Site-Specific Bottom Ash Purge Water Volume and 
Treatment
    While EPA is establishing a maximum 10 percent volumetric cap on 
bottom ash purge water, the NPDES permitting authority is to determine 
the site-specific volumes and technology-based BAT effluent limitations 
using BPJ.\163\ To assist the NPDES permitting authority in making 
these determinations, EPA is requiring information on the types of 
discharges and available treatment technologies in the reporting and 
recordkeeping requirements discussed below. However, having reviewed 
the information available in the record, EPA has distilled certain 
basic principles that may be useful for a permitting authority to 
consider.
---------------------------------------------------------------------------

    \163\ BPJ limits established by the permitting authority only 
apply to discharges from high recycle rare systems and do not apply 
to BA transport water discharges from LUEGUs or EGUs permanently 
ceasing coal combustion, as plants eligible for those subcategories 
are subject to the TSS limitations established in this final rule.
---------------------------------------------------------------------------

    Information in EPA's record indicates that purges can be classified 
into two distinct classes. The first class comprises purges that must 
be made on a regular or continuous basis. These purges are typically 
related to system water chemistry or water balance and are permissible 
under 40 CFR 423.13(k)(2)(i)(A)(2) and (3). Based on EPA's record, once 
a plant has taken steps to manage such purges, these purges should 
typically comprise a small portion of system volume, and in some cases 
may have volumes close to zero. The second class of purges are those 
that are made less frequently. Based on information in EPA's record, 
discharges from storm events larger than a 10-year, 24-hour or longer 
duration event, or maintenance events not included in 40 CFR 
423.13(k)(2)(i)(A)(1) through (A)(3)--such as those associated with EGU 
outages or decommissioning of the high recycle rate system--are 
expected in many cases to occur at most once per year and are 
permissible under 40 CFR 423.13(k)(2)(i)(A)(1) and (4).
    EPA notes that the storm events included in (A)(1) are: Different 
from those included at proposal in two ways. First, commenters 
suggested that EPA use a 10-year storm event rather than a 25-year 
storm event. EPA agrees that such a change makes the requirements 
consistent with those for coal pile runoff.\164\ Second, commenters 
pointed to a 30-day rainfall event in Tennessee in which individual 24-
hour precipitation events may not have exceeded a 10-year storm event, 
but multiple 24-hour periods of precipitation taken together did exceed 
a 10-year, 30-day storm event. At proposal EPA had used the phrase 
``multiple consecutive events'' to capture such a possibility; however, 
the more precise characterization of the event in the Tennessee example 
would be a 10-year, 30-day storm event. Therefore, the Agency now uses 
the phrase ``or longer duration'' to denote all 10-year events of a 
duration longer than 24-hours.\165\
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    \164\ 40 CFR 423.12(b)(10).
    \165\ NOAA ATLAS 14 POINT PRECIPITATION FREQUENCY ESTIMATES 
include the following 10-year events in this range: 24-hour, 2-day, 
3-day, 4-day, 7-day, 10-day, 20-day, 30-day, 45-day, and 60-day 
storm events. Available online at: https://hdsc.nws.noaa.gov/hdsc/pfds/pfds_map_cont.html (DCN SE09100).
---------------------------------------------------------------------------

    Permitting authorities may initially determine which of these two 
classes of purge are necessary at any given site. Where necessary 
purges fall into the first class, and result in relatively consistent 
volumes and water quality, such a discharge may be more amenable to 
treatment technologies beyond physical settling. Necessary purges fall 
into the second class, and result in infrequent and potentially very 
large volumes; such a discharge may make treatment beyond physical 
settling challenging. In both of these cases, where only a single class 
of purge is expected, the permitting authority's job will be more 
straightforward.
    A more challenging scenario occurs when the NPDES permitting 
authority determines that both classes of purge will be present. In 
such cases a permitting authority could consider whether tiered or 
differentiated purges or purge treatment might be warranted. For 
example, during periods where no large precipitation or maintenance 
events occur, continuous purges may be properly limited to a smaller 
volume, with more advanced treatment with a second limitation 
permitting larger volumes and less advanced treatment during periods 
where the plant records a qualifying event. There is no across-the-
board formula for determining appropriate purge limitations, as long as 
the bottom ash purge volume does not exceed 10 percent of the primary 
active wetted bottom ash system volume on a 30-day rolling average 
basis.

[[Page 64708]]

3. Implementation for the Low Utilization Subcategory
    The final rule establishes a subcategory for LUEGUs with a two-year 
average capacity utilization rate (CUR) of less than 10 percent per 
year. CUR is calculated as the total MWh of production divided by the 
hours per year times the nameplate capacity. Unlike other 
subcategories, which often require that a plant possess some static 
characteristic (e.g., less than 50 MW nameplate capacity), the low 
utilization subcategory is based on the fluctuating CUR. Thus, EPA is 
clarifying how permitting authorities can determine whether a plant 
qualifies for this subcategory.
    If a plant seeks to have the limitations from this subcategory 
applied to discharges from one or more EGUs, the plant needs to provide 
the permitting authority its calculation of the average of the most 
recent two calendar years of CUR for the subject EGU(s). EPA received 
some comments that plants should be allowed to certify to future low 
utilization operations, even where current operations are not low 
utilization. Other comments stated that additional reporting and 
recordkeeping should be required to prevent abuse. EPA agrees with both 
comments. It was not the Agency's intent for plants on a downward 
utilization trajectory to be barred from the LUEGU subcategory, where 
current operations exceed the required less than 10 percent CUR 
threshold. Thus, the NPDES permitting authority should refrain from 
establishing a ``no later than date'' that would restrict a plant from 
demonstrating two years of reduced CUR. However, NPDES permitting 
authorities also need to know when to provide flexibility and when to 
dutifully set a compliance date which is ``as soon as possible.'' Thus, 
EPA is requiring in the rule that a plant seeking to qualify for this 
subcategory must file a Notice of Planned Participation (NOPP) by 
October 13, 2021, even if it would not yet qualify, and must operate 
below this threshold before the latest compliance dates of December 31, 
2023. Upon receipt of a NOPP, the NPDES permitting authority can 
properly consider that NOPP in the ``other factors'' of 40 CFR 
423.11(t)(4).
    Once a plant reaches the ``as soon as possible'' date determined by 
the permitting authority, it must thereafter provide annual 
certifications of its 24-month average CUR. This average should 
primarily be calculated using data developed for reporting to the EIA, 
since MWh production information already collected for the EIA will 
both eliminate the potentially unnecessary paperwork burden of a 
separate calculations and information gathering and allow the NPDES 
permitting authority to verify the accuracy of the reported values more 
easily. The use of a two-year average will ensure that a low 
utilization EGU responding to a single extreme demand event in one year 
(e.g., unexpectedly high peak demand in summer or winter) can still 
qualify for this subcategory if its average CUR over the two years 
remains below 10 percent. Furthermore, the plant must annually provide 
the permitting authority an updated two-year average CUR for each 
subcategorized EGU within 60 days of submitting production information 
to the EIA to ensure that it remains an LUEGUs.
4. Transitioning Between Limitations
    EPA received a significant number of comments that it should 
harmonize the CCR and ELG rules to the extent practicable. As discussed 
above, EPA agrees that such harmonization is important. One major set 
of features EPA attempted to harmonize this final rule with are the 
alternative closure provisions of Paragraphs 257.103(f)(1) and (f)(2) 
of the CCR rule. In response to comments on the CCR Part A Proposed 
Rule (one of which, the USWAG comment, was incorporated by reference 
into a public comment submitted for this ELG rule), EPA added a 
provision to the final CCR Part A Rule that provides for transfer 
between these paragraphs. A plant that had applied for a site-specific 
alternative closure extension to extend its cease receipt of waste date 
under paragraph 257.103(f)(1) could, for example, now transfer into the 
provision that requires permanent cessation of a coal-fired EGU under 
paragraph 257.103(f)(2). Similarly, EPA has discussed transfer between 
ELG subcategories with electric utilities. Thus, to align with the 
flexibilities of the CCR Part A final rule and make implementation of 
this rule easier, EPA is finalizing provisions allowing for a plant 
with a permit to transfer between two subcategories, or between a 
subcategory and the VIP, without undergoing a permit modification.\166\
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    \166\ Categorical pretreatment standards are directly 
enforceable and are not implemented through NPDES permits issued to 
indirect dischargers. Indirect dischargers, however, may be subject 
to enforceable individual local permits or equivalent individual 
control mechanisms issued to individual indirect dischargers by a 
POTW with an approved pretreatment program or the appropriate 
control authority. Because indirect dischargers do not have NPDES 
permits, the NPDES provisions for transferring between limits in a 
permit do not apply to indirect dischargers. Indirect dischargers 
subject to categorical pretreatment standards under EPA's 
pretreatment regulations must comply with these standards. What 
pretreatment standards will apply depends on whether an indirect 
discharger is subject to a particular subcategory as provided in the 
regulation. As such, in the event the pretreatment standards change, 
the indirect dischargers will be subject to the modified standards.
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    The EPA is also establishing deadlines by which such transfers must 
occur. Transfers into the LUEGU subcategory must occur no later than 
December 31, 2023, the latest date by which compliance dates for this 
subcategory would fall. For all other transfers, the EPA is selecting 
December 31, 2025 as the latest date for three reasons. First, the 
ability to transfer under Section 257.103 of the CCR Rule will 
terminate before this date, giving plants certainty as to their CCR 
compliance strategies. Thus, it is consistent with the CCR rule. 
Second, the first five-year permitting cycle will have ended, and EPA 
expects that plants subject to NPDES permitting under this rule will 
have determined their compliance path by then. Lastly, some of the 
provisions that can be transferred to in this rule include compliance 
dates for the generally applicable limitations of no later than 
December 31, 2025. In such cases, allowing transfer to such provisions 
at a later date could create disparities for compliance with these 
genearlly applicable limitations within the industry. Thus, a final 
transfer date of December 31, 2025, creates a consistent time frame for 
all plants to make decisions and achieve compliance with the generally 
applicable limitations, whether they initially start in another 
subcategory or not.
    Consistent with the CCR Part A final rule requirements, a plant 
seeking to transfer between the ELG rule provisions must demonstrate 
compliance with all requirements of both the provision transferred from 
and the provision transferred to, and continue to meet requirements 
that were applicable if that applicability date has passed. This 
ensures that a plant does not miss or circumvent otherwise applicable 
deadlines or cease operating equipment already installed, operated, and 
maintained to comply with deadlines that have passed.
    The first objective addresses, for example, a plant converting from 
the permanent cessation of coal combustion subcategory with deadlines 
of 2028, to the LUEGU subcategory, with deadlines no later than 2023. 
EPA does not want a plant to miss or circumvent the lastest LUEGU 
compliance dates of December 31, 2023, because the plant initially

[[Page 64709]]

intends to meet the 2028 requirements and later changes its mind. Such 
a scenario could, for example, result in the plant failing to meet the 
2023 LUEGU requirements for five years between 2023 and 2028.
    The second objective would mean that, for example, where a plant is 
already implementing a BMP plan for BA transport water under the LUEGU 
subcategory and then decided to convert to the subcategory for 
permanent cessation of coal combustion, the plant would continue to 
implement the BMP plan until such cessation occurs. This ensures that 
technology-based requirements that were applicable would continue to be 
met, furthering the goals of eliminating discharges to the extent 
technologically available and achievable under section 301(b) of the 
CWA.
    This new set of provisions is also appropriate as a practical 
matter to implement the subcategories as finalized. While EPA proposed 
for plants to certify to a subcategory immediately, based on public 
comments. EPA has finalized provisions allowing plants to file an 
initial notice of planned participation such that the plant could 
certify differently within the compliance time frame. In many cases, a 
plant may require local or state regulatory approval prior to reducing 
its utilization or planning to retire. These changes in the final rule 
allow plants to notify their permitting authority of their intent to 
particpiate in a subcategory, but also allows time to obtain local or 
state approval, if necessary, before the compliance deadline. By 
allowing automatic transfer between alternatives, the final rule also 
avoids unecessarily burdensome permit modifications that can further 
extend timelines to make plant changes, including equipment upgrades.
    Finally, the Agency notes that with later dates for certification 
and the ability to transfer between alternative limitations for a 
period of time, there is no longer a need for tiered limitations in the 
LUEGU subcategory. Thus, the proposed tiering of limitations are not 
being finalized.
5. Addressing Unexpected Changes in Generation
    Since the 2015 rule, EPA has learned of several instances when 
plants have withdrawn or delayed retirement announcements for coal-
fired EGUs and plants. These instances can be grouped into two 
categories. First, some delays were involuntary, resulting from orders 
issued by the Department of Energy (DOE) or Public Utility Commissions 
(PUCs). The remaining announcements were withdrawn or delayed 
voluntarily due to changed circumstances. While both the voluntary and 
involuntary changes to announced retirements were infrequent, EPA 
acknowledges that such changes will necessarily impact a plant's status 
with regard to some of the subcategories in the final rule. These 
situations are discussed below. For further information on announced 
retirements, see DCN SE07207.
a. Involuntary Retirement Delays
    At least five plants with announced retirement dates had those 
dates involuntarily delayed as a result of the DOE issuing orders under 
Section 202(c) of the Federal Power Act, or a PUC issuing a reliability 
must-run agreement. Such involuntary operations have raised questions 
about the conflict between legal obligations to produce electricity and 
legal obligations under environmental statutes.\167\ Today's final rule 
would subcategorize LUEGUs and EGUs permanently ceasing coal combustion 
by 2028, subjecting those subcategories to less stringent limitations. 
However, both utilization and decisions to permanently cease coal 
combustion could be impacted by involuntary orders and agreements. 
Thus, EPA is establishing in this final rule an NPDES permit condition 
that would be included in all permits where a plant seeks limitations 
under one of these two subcategories. Such a provision protects a plant 
that involuntarily fails to qualify for the subcategory for low 
utilization EGUs or EGUs permanently ceasing coal combustion by 2028, 
and it allows that plant to prove that, but for the order or agreement, 
it would have qualified for the subcategory. EPA received comments that 
the enumerated orders in the proposal were too narrow, and that 
alternative regulatory bodies (e.g., Independent System Operators) 
might also issue these types of orders. EPA agrees with these 
commenters, and thus, has modified the language in section 423.18(a) of 
the final rule.
---------------------------------------------------------------------------

    \167\ Moeller, James. 2013. Clean air vs. electric reliability: 
The case of the Potomac River Generating Station. September. 
Available online at: https://scholarlycommons.law.wlu.edu/cgi/viewcontent.cgi?referer=https://www.google.com/&httpsredir=1&article=1077&context=jece. (DCN SE09101)
---------------------------------------------------------------------------

b. Emergencies and Major Disasters Under the Stafford Act
    The final rule also includes in the section 423.18(a) provision 
``Emergency'' \168\ and ``Major Disaster'' \169\ events as defined by 
the Stafford Act.\170\ These events encompass scenarios such as the 
current Covid-19 pandemic, floods, hurricanes, and other scenarios that 
may not be predictable, but may impact the need for, and availability 
of, electricity. The benefit of adding these terms to the emergency 
orders and must run agreements already detailed in section 423.18(a) is 
that it would prevent an EGU from being noncompliant if operations 
during such an emergency or major disaster would have otherwise caused 
it to exceed the rule's capacity utilization threshold. Stafford Act 
declarations of major disaster or emergency are made by the President 
at the request of the Governor or Chief Executive of an Indian Tribe. 
See 42 U.S.C. 5170 and 5191. For emergency declarations involving 
primary federal responsibility, the President does not need a request 
from the Governor, but may make an emergency determination (42 U.S.C. 
5191(b)). Furthermore, these events are limited in geographic scope and 
in duration. Thus, while they would advance the protection for future 
LUEGUs to operate in emergency situations above the required capacity, 
they would be relatively rare, thus maintaining the majority of 
pollutant removals expected under this final rule in the long run.
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    \168\ 42 U.S.C. 5122(1).
    \169\ 42 U.S.C. 5122(2).
    \170\ 42 U.S.C. 5121 et seq.
---------------------------------------------------------------------------

c. Voluntary Retirement Withdrawals and Delays
    Units at five plants with announced retirement dates had those 
dates voluntarily withdrawn or delayed due to changed situations, 
including market conditions, unavailability of natural gas pipelines, 
changes in environmental regulations, and sale of the plant. Like the 
involuntary retirement delays discussed in the section above, these 
situations could impact a plant's qualification for the subcategories 
for LUEGUs and EGUs ceasing combustion of coal by 2028. Unlike the 
involuntary retirement delays, these voluntary delays and withdrawals 
can be accounted for through normal integrated resource planning. Thus, 
the final rule does not include a similar protection provision for such 
units. Instead, a plant should carefully plan its implementation of the 
ELGs.

B. Reporting and Recordkeeping Requirements

    To implement the rule's provisions providing for subcategories and 
a site-specific determination of controls on BA purge water, this final 
rule includes eight reporting and recordkeeping requirements. There 
were two

[[Page 64710]]

overarching goals of these requirements. The first goal was to balance 
the additional flexibilities for certifying to subcategories or VIP 
limitations at a later date with additional reporting and recordkeeping 
to provide extra certainty that the plant still intends to avail itself 
of those provisions. A second goal was to adopt provisions consistent 
with those of the CCR rule where an initial notice is provided to EPA, 
followed by regular progress reports to avoid last-minute surprises 
that might result in unexpected noncompliance.\171\
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    \171\ While the initial notice in the CCR rule is termed a 
``notice of intent'' because that is a CWA term of art related to 
NPDES permitting that has a different meaning than intended here, 
this final rule provides a ``notice of planned participation.'' The 
intended result is the same for both rules, to give the permitting 
authority advanced notice that a plant intends to avail itself of 
provisions other than those generally applicable to the industry.
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    First, EPA is finalizing a reporting and recordkeeping requirement 
for plants operating high recycle rate BA systems. EPA is requiring 
that such plants submit the calculation of the primary active wetted BA 
system volume, which means the maximum volumetric capacity of bottom 
ash transport water in all non-redundant piping (including 
recirculation piping) and primary tanks (e.g., bins, troughs, 
clarifiers, and hoppers) of a wet bottom ash system, excluding the 
volumes of surface impoundments, secondary bottom ash system equipment 
(e.g., installed spares, redundancies, and maintenance tanks), and non-
bottom ash transport systems that may direct process water to the 
bottom ash system. This ensures that the permitting authority can 
verify the volume of discharge allowed for a high recycle rate system.
    Because the NPDES permitting authority is basing the site-specific 
purge percentage and limitations on BPJ, EPA is also requiring the 
following:
    (1) A list of all potential discharges, the expected volume of each 
discharge, and the expected frequency of each discharge.
    (2) Material assumptions, information, and calculations used by the 
certifying professional engineer to determine the expected volume and 
frequency of each discharge.
    (3) A list of all wastewater treatment systems currently at the 
plant, or otherwise required by a date certain under this section.
    (4) A narrative discussion of each treatment system, including the 
system type, design capacity, and current operation.
    Second, EPA is finalizing a reporting and recordkeeping requirement 
for plants seeking to qualify as an LUEGU. EPA is requiring that the 
plant submit a NOPP to certify one or more LUEGUs. Once any limitations 
of this subcategory are applicable, the final rule requires that such a 
plant annually recertify that the EGU continues to meet the 
requirements of this subcategory, along with an updated two-year 
average CUR calculation and information for each applicable EGU. If an 
EGU exceeds the CUR requirements of this subcategory, no further 
recordkeeping or reporting would be required for this subcategory, as 
the EGU would leave the subcategory permanently.
    Third, as described in Section VII.C.2, plants with EGUs that 
qualify for the low-utilization subcategory and that discharge BA 
transport water, are required to develop and implement a BMP plan to 
minimize the discharge of pollutants by recycling as much BA transport 
water as feasible back to the BA handling system.\172\ As part of any 
NPDES permit renewal or any re-opening, such plants need to submit 
their plant-specific plan, certified that it meets the proposed 
requirements of 40 CFR 423.13(k)(3)) along with certification that the 
plan is being implemented. For each NPDES permit renewal, the plan and 
professional engineer certification needs to be updated and provided to 
the permitting authority.
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    \172\ EPA is finalizing the same requirements for determining 
feasibility that were included in the proposal: Segregation of 
bottom ash transport water from other process water, minimization of 
the introduction of stormwater by diverting (e.g., curbing, using 
covers) stormwater to a segregated collection system, recycling 
bottom ash transport water back to the bottom ash transport water 
system, recycling bottom ash transport water for use in the FGD 
scrubber, optimization of existing equipment (e.g., pumps, pipes, 
tanks) and installing new equipment where practicable to achieve the 
maximum amount of recycle, and utilization of ``in-line'' treatment 
of transport water (e.g., pH control, fines removal) where needed to 
facilitate recycle.
---------------------------------------------------------------------------

    Fourth, EPA is finalizing reporting and recordkeeping requirements 
for plants seeking subcategorization for an EGU(s) achieving permanent 
cessation of coal combustion by December 31, 2028. EPA is requiring 
that a plant file a NOPP to certify one or more such EGUs, including 
whether the retirement or fuel conversion has already been approved by 
the regulatory authority. EPA received comments suggesting that 
additional information should be required regularly from such EGUs. EPA 
agrees that, given the time frame for retiring or repowering some EGUs, 
a lack of reporting combined with missed deadlines could lead to 
situations where a plant fails to permanently cease coal combustion as 
scheduled and immediately falls into noncompliance without the 
permitting authority being aware of the situation. Thus, EPA is also 
requiring in the rule annual progress reports to confirm that the EGU 
is on track to complete its retirement or fuel conversion on time. This 
requirement is meant to provide the NPDES permitting authority further 
evidence that an EGU will, in fact, cease the combustion of coal by 
December 31, 2028.
    Fifth, EPA is finalizing reporting and recordkeeping requirements 
for plants invoking the protective NPDES permit conditions described 
above, which allow a plant to continue to be subject to limitations for 
low utilization EGUs or those ceasing combustion of coal by 2028 in the 
event of an emergency order, must-run agreement, national emergency, or 
major disaster. EPA is requiring in the rule that such plants must 
demonstrate that an EGU would have qualified for the subcategory at 
issue, if not for the emergency order, must-run agreement, national 
emergency, or major disaster as described above. Furthermore, EPA is 
requiring in the rule that the plant submit to the NPDES permitting 
authority a copy of such order or agreement as an attachment to the 
submission.
    Sixth, EPA is finalizing reporting and recordkeeping requirements 
for plants participating in the VIP. As with the retirement 
subcategory, given the long time frames, a lack of reporting combined 
with missed deadlines could lead to situations in which a plant fails 
to complete the installation of a VIP technology as scheduled and 
immediately falls into noncompliance without the permitting authority 
being aware. Thus, EPA is requiring in the rule annual progress reports 
to confirm that the plant is on track to complete its VIP technology 
installation. This requirement is meant to provide the NPDES permitting 
authority further evidence that an EGU will, in fact, be able to meet 
the VIP limitations by December 31, 2028.
    Seventh, the final rule includes reporting and recordkeeping 
requirements for plants transitioning between compliance alternatives. 
For example, a plant may initially file a NOPP for participation in the 
permanent cessation of coal combustion subcategory, but then several 
years later it may determine that it is profitable to remain in 
operation, and instead comply with the VIP. Under such scenarios, where 
the permitting authority has included alternative limitations subject 
to eligibility requirements, EPA is requiring in the rule that the 
plant provide a notice to the NPDES permitting authority of what 
transition the plant will make.

[[Page 64711]]

    Finally, the final rule includes a requirement that a plant provide 
notice of any material delays, meaning a delay that could result in 
non-compliance (with the compliance date set forth in the permit) 
within 30 days of experiencing such a delay.\173\ For instance, if such 
a delay might preclude permanent cessation of coal combustion by 
December 31, 2028, a plant shall file a notice of material delay with 
the permitting authority (or the control authority in the case of an 
indirect discharger) to facilitate resolution before the compliance 
date. The notice requirement does not change the 2028 date in this rule 
but provides the permitting authority adequate notice to seek a 
resolution. 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.
---------------------------------------------------------------------------

    \173\ Note: It is unlikely that a delay would be material after 
2028, as all requirements of the rule will have been implemented 
industry-wide.
---------------------------------------------------------------------------

C. Site-Specific Water Quality-Based Effluent Limitations

    EPA regulations at 40 CFR 122.44(d)(1), implementing section 
301(b)(1)(C) of the CWA, require that each NPDES permit shall include 
any requirements, in addition to or more stringent than effluent 
limitations guidelines 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) 
which the Director determines are or may be discharged at a level which 
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.
    Bromide was discussed in the preamble to the 2015 rule as a 
parameter for which water quality-based effluent limitations may be 
appropriate. 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. EPA 
also stated its recommendation that the permitting authority notify any 
downstream drinking water treatment plants of the discharge of bromide.
    In addition to the comments regarding EPA's analysis of bromide-
related pollutant loadings, DBP formation, and health benefits 
(discussed in Section XII above), EPA also received many comments on 
the bromide-focused sub-options discussed in the 2019 proposal. Some 
commenters supported implementation of one or more of the proposed 
options, while other comments did not support the proposed options. 
Electric utility commenters were split. Some electric utility comments 
disagreed that these sub-options were warranted, with one trade 
association stating that these sub-options were not sufficiently 
described to allow meaningful comment. Other electric utility comments 
supported a monitoring-only approach. One commenter also provided an 
example of a site-specific approach on the Broad River, which is 
discussed further below. Environmental group commenters also disagreed 
with the proposed bromide sub-options; they argued that membrane 
filtration should be BAT, and thus these sub-options should either not 
be implemented or should be implemented on top of more stringent 
limitations. Drinking water utilities, though supporting the selection 
of membrane filtration over these sub-options, also recommended that in 
the absence of selecting more stringent limitations for discharges of 
FGD wastewater, EPA should finalize requirements for monitoring and a 
bromide minimization plan.
    The final rule does not include limitations on bromide for FGD 
wastewater beyond the removals that would be required of plants 
choosing to meet the VIP limitations. EPA agrees with the wide variety 
of commenters that the selection of BAT based on the statutory factors, 
combined with the imposition of water quality-based effluent 
limitations where appropriate, rather than these sub-options, is the 
proper way to address impacts from bromides at this time.
    The records for the 2015 rule, the 2019 proposal, and this final 
rule continue to suggest that permitting authorities should consider 
establishing water quality-based effluent limitations that are 
protective of populations served by downstream drinking water treatment 
plants. As described in Section XII, the analysis of changes in 
downstream bromide concentrations associated with changes in bromide 
discharges are concentrated at a small number of sites. This supports 
EPA's determination that potential discharges are best addressed using 
site-specific, water quality-based effluent limitations established by 
NPDES permitting authorities for the small number of steam electric 
power plants that may impact downstream drinking water treatment 
plants. Such an approach allows the permitting authority to tailor any 
monitoring or other requirement to the watershed and plants at issue, 
avoiding many of the individual concerns raised about specific 
monitoring programs. While EPA is not finalizing monitoring or other 
requirements, EPA believes that some information provided in comments 
discussed below may be particularly helpful for NPDES permitting 
authorities in devising a water quality-based approach.
    Duke Energy provided an example of a successful site-specific 
bromide approach instituted on the Broad River in South Carolina.\174\ 
As detailed in the settlement agreement attached to Duke Energy's 
public comment (EPA-HQ-OW-2009-0819-8320), this approach relied upon 
the establishment of an in-river bromide concentration of 0.6 ppm, 
below which there was ``. . . no significant impact upon the Downstream 
Plants' ability to meet the MCL for TTHMs.'' As part of this approach, 
the plant discharging bromide had to establish a collection point where 
the process water could be transferred off-site for treatment or 
disposal, and USGS data were used to determine the average flow of the 
river each week. Using the river flow from the previous week and the 
concentrations in the process water, the discharging plant had to 
determine the volume of process water to divert to the collection 
point. The discharging plant had to take 24-hour composite samples of 
its effluent one or more times per week and use those data to estimate 
in-river bromide concentrations, taking additional steps should those 
estimates exceed 0.6 ppm. EPA notes that this approach could be 
modified and applied at any particular watershed by determining the in-
river bromide concentrations that affect the ability of drinking water 
treatment plants to meet the MCL for TTHMs, whether the bromide level 
is set higher or lower than the 0.6 ppm level established for the Broad 
River.
---------------------------------------------------------------------------

    \174\ See Attachment E of Document ID: EPA-HQ-OW-2009-0819-8320, 
available online at www.regulations.gov.
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    In December 2019, AWWA also finalized Methods to Assess 
Anthropogenic Bromide Loads from Coal-fired Power Plants and Their 
Potential Effect on Downstream

[[Page 64712]]

Drinking Water Utilities.\175\ This document 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 could be used by NPDES permitting 
authorities 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, the 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.
---------------------------------------------------------------------------

    \175\ Availabile online at www.awwa.org/Portals/0/AWWA/ETS/Resources/17861ManagingBromideREPORT.pdf?ver=2020-01-09-151706-107 
(DCN SE08643).
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    EPA also received a variety of comments on iodides. For a 
discussion of iodides, including data limitations and EPA's response to 
these comments, see Section 6 of the Supplemental TDD and EPA's 
response to comments document.

XV. Related Acts of Congress, Executive Orders, and Agency Initiatives

    Additional information about these statutes and Executive Orders 
can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Orders 12866 (Regulatory Planning and Review) and 13563 
(Improving Regulation and Regulatory Review)

    This final rule is an economically significant regulatory action 
that was submitted to the Office of Management and Budget (OMB) for 
review. Any changes made in response to OMB recommendations have been 
documented in the docket. EPA prepared an analysis of the estimated 
social costs and benefits associated with this action. This analysis is 
presented in Chapter 13 of the BCA, available in the docket. The 
analysis in the BCA builds on compliance costs and certain other 
assumptions regarding compliance years discussed in the RIA to analyze 
and update estimated incremental social costs and benefits of the final 
rule and revisions relative to the baseline.
    Table XV-1 presents the annualized value of the social costs and 
benefits of the final rule. These costs and benefits are annualized 
over 27 years and discounted using three and seven percent discount 
rates. In the table, negative costs indicate avoided costs (i.e., cost 
savings) and negative benefits indicate forgone benefits (positive 
benefits values represent realized benefits).

 Table XV-1--Total Monetized Annualized Benefits and Costs of the Final
        Rule at 3% and 7% Discount Rates as Compared to Baseline
                   [Millions of 2018$; annualized] \a\
------------------------------------------------------------------------
                                                               Total
              Discount rate                Total social      monetized
                                             costs \b\    benefits \c d\
------------------------------------------------------------------------
3%......................................         -$127.1  -$1.7 to $43.3
7%......................................         -$153.4   $6.5 to $45.9
------------------------------------------------------------------------
\a\ All social costs and benefits were annualized over 27 years using 3%
  and 7% discount rates. Negative costs indicate avoided costs and
  negative benefits indicate forgone benefits.
\b\ Total social costs are compliance costs to plants accounting for
  when those costs are incurred.
\c\ Total monetized benefits exclude other benefits discussed
  qualitatively.
\d\ The range reflects the lower and upper bound willingness-to-pay
  estimates and air quality-related effects.

B. Executive Order 13771 (Reducing Regulation and Controlling 
Regulatory Costs)

    The final rule is an Executive Order 13771 deregulatory action. 
Details on the estimated cost savings of the final rule are in the RIA, 
and in Table XV-1 above.

C. Paperwork Reduction Act

    OMB has previously approved the information collection requirements 
contained in the current regulations 40 CFR part 423 under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and 
has assigned OMB control number 2040-0004. The OMB control numbers for 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    EPA estimated small changes in monitoring costs at steam electric 
power plants under the final rule relative to the baseline. These 
changes apply to plants to which the subcategories are applicable. In 
some cases, in lieu of these monitoring requirements, plants will have 
additional paperwork burden such as that associated with certifications 
and applicable BMP plans. See Section VII of this preamble. However, 
some plants will also realize savings relative to the baseline by no 
longer monitoring pollutants discharged by some subcategories of EGUs 
and because their applicable limitations and standards are based on 
less costly technologies. EPA projects that the burden associated with 
the new paperwork requirements will be largely offset by the reduced 
burden associated with less monitoring; therefore, the Agency projects 
that the final rule will have no net effect on the burden of the 
approved information collection requirements. With respect to 
permitting authorities, based on the information in its record, EPA 
also does not expect the final rule to increase or decrease their 
burden. The final rule will not change permit application requirements 
or the associated review; the final rule will not affect the number of 
permits issued to steam electric power plants; nor will the final rule 
materially change the efforts involved in developing or reviewing such 
permits. Accordingly, EPA estimated no net change (i.e., no increase or 
decrease) in the cost burden to federal or state governments or 
dischargers associated with the final rule. EPA does not believe that 
any updates are needed to that ICR so it has not submitted it to OMB 
for review under the PRA.

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice-and-comment rulemaking requirements under the Administrative 
Procedure Act or any other statute, unless the agency certifies that 
the rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    The Agency certifies that this action will not have a significant 
economic impact on a substantial number of small entities under the 
RFA. The basis for this finding is summarized below. For

[[Page 64713]]

further details, including analysis of other regulatory options 
considered, see Chapter 8 of the RIA.
    EPA estimates that 231 to 459 entities, of which 76 to 127 are 
small, own steam electric power plants to which the final rule applies. 
These small entities own a total of 138 steam electric power plants. 
EPA considered the impacts of the final rule on small businesses using 
a cost-to-revenue test. The analysis compares the cost of implementing 
controls for BA and FGD wastewater under the final rule to those costs 
under the baseline (which reflects the 2015 rule, as explained in 
Section V of this preamble). EPA used cost-to-revenue ratios of three 
percent and one percent as indicative of potentially significant 
impact. EPA's analysis shows that no small entities exceed the three 
percent impact threshold. Three small entities (one cooperative and two 
municipalities) are expected to incur costs equal to or greater than 
one percent (but less than three percent) of revenue to meet the 2015 
rule. Cost savings provided under the final rule reduce to two the 
number of small entities incurring costs equal to or greater than one 
percent of revenue. The number of small entities exceeding the one 
percent impact threshold in the baseline is small in the absolute and 
represents a small percentage of the total estimated number of small 
entities; the cost savings provided by the final rule further support 
EPA's finding of no significant impact on a substantial number of small 
entities (No SISNOSE).

E. Unfunded Mandates Reform Act

    EPA finds that this action is not subject to the requirements of 
UMRA section 203 because the expenditures are less than $160 million or 
more in any one year. As detailed in Chapter 9 of the RIA, for its 
assessment of the impact of changes in compliance requirements on small 
governments (governments with jurisdiction over populations of less 
than 50,000), EPA estimated the changes in costs for compliance with 
the final rule relative to the baseline for different categories of 
entities. The final rule results in lower compliance costs (cost 
savings) when compared to the baseline. Compared to $113.5 million in 
the baseline, the Agency estimates that the final rule will reduce the 
maximum cost in any one year to state, local, or tribal governments by 
-$74.1 million. Compared to $1,313 million in baseline, the incremental 
cost in any given year to the private sector under the final rule is -
$914 million. From these incremental cost values, EPA determines that 
the final rule does not constitute a federal mandate that may result in 
expenditures of $160 million (in 2018 dollars) or more for state, 
local, and tribal governments in the aggregate, or the private sector 
in any one year. Chapter 9 of the RIA report provides details of these 
analyses.
    This action is also not subject to the requirements of UMRA section 
203 because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. To assess whether 
the final rule would affect small governments in a way that is 
disproportionately burdensome in comparison to the effect on large 
governments, EPA compared total incremental costs and incremental costs 
per plant for small governments and large governments. EPA also 
compared the changes in per plant costs incurred for small-government-
owned plants with those incurred by non-government-owned plants. The 
Agency evaluated both average and maximum annualized incremental costs 
per plant. These analyses find that small governments will not be 
significantly or uniquely affected by the final rule. For further 
discussion, including results for other regulatory options, see Chapter 
9 of the RIA.

F. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government. Under 
Executive Order (E.O.) 13132, EPA may not issue an action that has 
federalism implications, that imposes substantial direct compliance 
costs, and that is not required by statute, unless the federal 
government provides the funds necessary to pay the direct compliance 
costs incurred by state and local governments, or EPA consults with 
state and local officials early in development of the action.
    EPA anticipates that the final rule will not impose incremental 
administrative burden on states due to issuing, reviewing, and 
overseeing compliance with discharge limitations and standards.
    As detailed in Chapter 9 of the RIA in the docket for this action, 
EPA has identified 157 steam electric plants owned by state or local 
governments, of which 13 plants are estimated to incur costs to comply 
with the BA transport water and FGD limitations in the 2015 rule. 
However, the final rule provides estimated cost savings as compared to 
the baseline. The difference in the maximum annualized costs per plant 
under the final rule as compared to the baseline is -$1.2 million. 
Based on this information, EPA concludes that this action will not 
impose substantial direct compliance costs on state or local 
governments.

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

    This action does not have tribal implications, as specified in E.O. 
13175 (65 FR 67249, November 9, 2000). It will not have substantial 
direct effects on tribal governments, on the relationship between the 
federal government and the Indian tribes, or on the distribution of 
power and responsibilities between the federal government and Indian 
tribes, as specified in E.O. 13175.
    EPA assessed potential tribal implications for the final rule 
arising from three main changes: (1) Direct compliance costs incurred 
by plants; (2) impacts on drinking water systems downstream from steam 
electric power plants; and (3) administrative burden on governments 
that implement the NPDES program.
    Regarding direct compliance costs, EPA's analyses show that no 
steam electric power plants with BA transport water or FGD discharges 
are owned by tribal governments. Regarding impacts on drinking water 
systems, EPA identified 14 public water systems operated by tribal 
governments that may have waters that receive halogen discharges from 
steam electric power plants. These systems serve a total of 
approximately 28,000 people. EPA estimated changes in source water 
halogen concentrations for these systems under the final rule relative 
to the baseline. This analysis, which is described in Chapter 4 of the 
BCA report, finds very small changes in source water halogen 
concentrations between the baseline and the final rule. Finally, 
regarding administrative burden, no tribal governments are currently 
authorized pursuant to section 402(b) of the CWA to implement the NPDES 
program. Based on this information, EPA concludes that the final rule 
will not have substantial direct effects on tribal governments.

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

    This action is not subject to E.O. 13045 (62 FR 19885, April 23, 
1997) because EPA does not expect that the environmental health risks 
or safety risks associated with steam electric power plant discharges 
addressed by this action present a disproportionate risk to children. 
This action's health risk

[[Page 64714]]

assessments are described in Chapters 4 and 5 of the BCA report and are 
summarized below.
    EPA identified several ways in which this final rule could affect 
children, including potentially increasing health risks due to an 
increase in exposure to pollutants present in steam electric power 
plant FGD wastewater and BA transport water discharged, and through 
those pollutants' potential impacts on public water systems' source 
water quality. This increase arises from less stringent pollutant 
limitations and later deadlines for meeting effluent limitations under 
the final rule relative to the baseline. In particular, EPA quantified 
the changes in IQ losses from lead exposure among pre-school children 
and from mercury exposure in utero deriving from maternal fish 
consumption under the final rule relative to the baseline. EPA also 
estimated changes in the number of children with very high blood lead 
concentrations. Finally, EPA estimated changes in concentrations of 
halogens in source waters for drinking water treatment plants. Under 
certain circumstances, halogens can contribute to the formation of 
halogenated disinfection byproducts in drinking water, for which there 
is evidence of a linkage to bladder cancer incidence. EPA did not 
estimate children-specific exposure to changes in halogen 
concentrations because these adverse health effects normally follow 
long-term exposure. These analyses show that today's final rule will 
have a small, and not disproportionate, impact on children.

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

    This action is not a ``significant energy action,'' as defined by 
E.O. 13211 (66 FR 28355, May 22, 2001) because it is not likely to have 
a significant adverse effect on the supply, distribution, or use of 
energy.
    The Agency analyzed the potential energy effects of the final rule 
relative to the 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 will not reduce electricity 
production by more than 1 billion kilowatt hours per year or by 500 
megawatts of installed capacity, nor will the final rule increase U.S. 
dependence on foreign supplies of energy. For details on the potential 
energy effects of the other regulatory options considered, see Section 
10.7 in the RIA, available in the docket.

J. National Technology Transfer and Advancement Act

    The final rule does not involve technical standards.

K. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes that this action may have disproportionate effects 
on minority populations, low-income populations and/or indigenous 
peoples, as specified in Executive Order 12898 (59 FR 7629, February 
16, 1994). EPA conducted two main analyses, described in Chapter 14 of 
the BCA, to evaluate the environmental justice (EJ) considerations for 
the final rule: (1) Summarizing the demographic characteristics of the 
households living in proximity to steam electric power plants, plant 
air emissions and surface water discharges, and to the downstream 
reaches affected by plant discharges; and (2) Analyzing the 
distribution of estimated human health impacts among minority and/or 
low-income populations from estimated changes in exposure to pollutants 
in drinking water, self-caught fish, and the air.
    The first analysis provides insight on the distribution of 
estimated regulatory option effects (e.g., estimated effects on water 
quality and air pollutant emissions) on communities in proximity to 
steam electric power plants. The second analysis seeks to provide more 
specific insight on the distribution of estimated changes in adverse 
health effects and benefits and to assess whether minority and/or low-
income populations incur disproportionately high environmental impacts 
and/or will be disproportionately excluded from realizing benefits 
under the regulatory options.
    Overall, the various analyses show that estimated environmental 
changes under the regulatory options analyzed, including the final 
rule, may affect minority and/or low income populations to different 
degrees across environmental media, exposure pathways, and over time, 
but the estimated effects (positive or negative) of the changes will be 
small.
    Communities living near steam electric power plants (i.e., up to 50 
miles) tend to have a lower proportion of low-income households and 
minority population than the national average, when considered in the 
aggregate, but there may be localized EJ considerations for some 
communities near individual plants (up to 50 miles) that have higher 
proportions of low-income or minority populations than the national 
and/or state average.
    EPA's analysis considered the distribution of estimated effects on 
populations near both immediate and downstream reaches, in downstream 
PWS service areas, and in adjacent airsheds to assess whether low-
income and/or minority populations may be disproportionately affected 
by changes under the final rule. The analysis shows that the EJ 
population subgroups are not excluded from the benefits of the final 
rule. For example, projected air quality changes under the final rule 
may disproportionately benefit minority and low-income populations 
based on the socioeconomic characteristics of populations of counties 
with changes in PM2.5 and ozone levels during the period of 
analysis. Additionally, estimated foregone benefits related to water 
quality changes may disproportionately affect minority and subsistence 
fisher populations. However, the magnitude of the changes (positive and 
negative) and associated benefits (including foregone benefits) is 
small, relative to the baseline, both overall across the exposed 
population, and across socioeconomic and fisher subgroups..

L. Congressional Review Act (CRA)

    This action is subject to the CRA, and EPA will submit a rule 
report to each House of Congress and to the Comptroller General of the 
United States. This action is a ``major rule'' as defined by 5 U.S.C. 
804(2).

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

    The following acronyms and abbreviations are used in this 
preamble. These terms are provided for convenience to the reader and 
they are not regulatory definitions with the force or effect of law, 
nor are they to be used as guidance for implementation of this final 
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).
    Bioaccumulation. 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 
chemical, resulting in a net accumulation of the chemical by the 
organism.
    BMP. Best management practice.
    BA. The ash, including EGU slag, which settles in the furnace or 
is dislodged from furnace walls. Economizer ash is included when it 
is collected with BA.

[[Page 64715]]

    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 sections 301(b)(1) and 304(b)(1) of the CWA.
    CBI. Confidential Business Information.
    CCR. Coal Combustion Residuals.
    CSC. Compact Submerged Conveyor.
    Clean Water Act (CWA). 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 power plant processes, including fly and BA from coal-, 
petroleum coke-, or oil-fired units; FGD solids; FGMC wastes; and 
other wastewater treatment solids associated with combustion 
wastewater. In addition to the residuals that are associated with 
coal combustion, this also includes residuals associated with the 
combustion of other fossil fuels.
    Direct discharge. (a) Any addition of any ``pollutant'' or 
combination of pollutants to ``waters of the United States'' from 
any ``point source,'' or (b) 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 which 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 U.S.
    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. It includes systems 
that collect and convey the bottom ash 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, including schedules of compliance.
    EIA. Energy Information Administration.
    ELGs. Effluent limitations guidelines and standards.
    E.O. Executive Order.
    EPA. U.S. Environmental Protection Agency.
    FA. Fly Ash.
    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.
    FGD. Flue Gas Desulfurization.
    FGD Wastewater. Wastewater generated specifically from the wet 
FGD scrubber system that comes into contact with 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.
    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.
    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.
    MDS. Mechanical drag system.
    Mechanical drag system. BA handling system that collects BA from 
the bottom of the 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.
    ORCR. Office of Resource Conservation and Recovery.
    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.
    Publicly Owned Treatment Works. Any device or system owned by a 
state or municipality that is used in the treatment (including 
recycling and reclamation) of municipal sewage or industrial wastes 
of a liquid nature. This includes sewers, pipes, or other 
conveyances only if they convey wastewater to a POTW providing 
treatment. CWA section 212, 33 U.S.C. 1292; 40 CFR 122.2 and 403.3.
    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 similar configuration as the MDS. The 
remote MDS is considered a wet BA handling system because the ash 
transport mechanism is water.
    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.
    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 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 (remote MDS or complete recycle system).
    Wet FGD system. Wet FGD systems capture sulfur dioxide from the 
flue gas using a

[[Page 64716]]

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.

Andrew Wheeler,
Administrator.

    For the reasons stated in the preamble, the Environmental 
Protection Agency amends 40 CFR part 423 as follows:

PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY

0
1. The authority citation for part 423 continues to read as follows:

    Authority:  Secs. 101; 301; 304(b), (c), (e), and (g); 306; 307; 
308 and 501, Clean Water Act (Federal Water Pollution Control Act 
Amendments of 1972, as amended; 33 U.S.C. 1251; 1311; 1314(b), (c), 
(e), and (g); 1316; 1317; 1318 and 1361).

0
2. Amend Sec.  423.11 by revising paragraphs (n), (p), and (t) and 
adding paragraphs (u), (v), (w), (x), (y), (z), (aa), (bb), (cc), and 
(dd) 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, or water 
that is collected in floor drains in the FGD process area 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, or bottom 
ash purge water
* * * * *
    (t) The phrase ``as soon as possible'' means November 1, 2018 
(except for purposes of Sec.  423.13(g)(1)(i) and (k)(1)(i), in which 
case it means October 13, 2021), unless the permitting authority 
establishes a later date, after receiving site-relevant information 
from the discharger, which reflects a consideration of the following 
factors:
    (1) Time to expeditiously plan (including to raise capital), 
design, procure, and install equipment to comply with the requirements 
of this part.
    (2) Changes being made or planned at the plant in response to:
    (i) New source performance standards for greenhouse gases from new 
fossil fuel-fired electric generating units, under sections 111, 301, 
302, and 307(d)(1)(C) of the Clean Air Act, as amended, 42 U.S.C. 7411, 
7601, 7602, 7607(d)(1)(C);
    (ii) Emission guidelines for greenhouse gases from existing fossil 
fuel-fired electric generating units, under sections 111, 301, 302, and 
307(d) of the Clean Air Act, as amended, 42 U.S.C. 7411, 7601, 7602, 
7607(d); or
    (iii) Regulations that address the disposal of coal combustion 
residuals as solid waste, under sections 1006(b), 1008(a), 2002(a), 
3001, 4004, and 4005(a) of the Solid Waste Disposal Act of 1970, as 
amended by the Resource Conservation and Recovery Act of 1976, as 
amended by the Hazardous and Solid Waste Amendments of 1984, 42 U.S.C. 
6906(b), 6907(a), 6912(a), 6944, and 6945(a).
    (3) For FGD wastewater requirements only, an initial commissioning 
period for the treatment system to optimize the installed equipment.
    (4) Other factors as appropriate.
    (u) The term ``FGD paste'' means any combination of FGD wastewater 
treated with fly ash, lime, Portland cement, and/or other pozzolanic 
material prior to being landfilled, and which is engineered to form a 
solid through pozzolanic reactions.
    (v) The term ``FGD paste equipment cleaning water'' means any 
wastewater generated from the cleaning of pugmills, piping, or other 
equipment used to make, process, or transport FGD paste from its point 
of generation to a landfill.
    (w) The term ``permanent cessation of coal combustion'' means the 
owner or operator certifies under Sec.  423.19(f) that an electric 
generating unit will cease combustion of coal no later than December 
31, 2028.
    (x) The term ``high FGD flow'' means the maximum daily volume of 
FGD wastewater that could be discharged by a facility is above 4 
million gallons per day after accounting for that facility's ability to 
recycle the wastewater to the maximum limits for the FGD system 
materials of construction.
    (y) The term ``capacity utilization rating'' means the total MWh 
production of an electric generating unit over a calendar year divided 
by the product of the number of hours in that year times the nameplate 
capacity.
    (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(e) that the two-year average 
annual capacity utilization rating is less than 10 percent.
    (aa) The term ``primary active wetted bottom ash system volume'' 
means the maximum volumetric capacity of bottom ash transport water in 
all non-redundant piping (including recirculation piping) and primary 
bottom ash collection and recirculation loop tanks (e.g., bins, 
troughs, clarifiers, and hoppers) of a wet bottom ash system, excluding 
the volumes of surface impoundments, secondary bottom ash system 
equipment (e.g., installed spares, redundancies, and maintenance 
tanks), and non-bottom ash transport systems that may direct process 
water to the bottom ash.
    (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.
    (cc) The term ``bottom ash purge water'' means any water being 
discharged subject to Sec.  423.13(k)(2)(i) or 423.16(g)(2)(i).
    (dd) The term ``30-day rolling average'' means the series of 
averages using the measured values of the preceding 30 days for each 
average in the series.

0
3. Amend Sec.  423.12 by revising paragraph (b)(11) to read as follows.

Sec.  423.12  Effluent limitations guidelines representing the degree 
of effluent reduction attainable by the application of the best 
practicable control technology currently available (BPT).

* * * * *
    (b)(11) The quantity of pollutants discharged in FGD wastewater, 
flue gas mercury control wastewater, combustion residual leachate, 
gasification wastewater, or bottom ash purge water shall not exceed the 
quantity determined by multiplying the

[[Page 64717]]

flow of the applicable wastewater times the concentration listed in the 
table 7:

                      Table 7 to Paragraph (b)(11)
------------------------------------------------------------------------
                                             BPT effluent limitations
                                         -------------------------------
                                                            Average of
                                                           daily values
     Pollutant or pollutant property        Maximum for       for 30
                                          any 1 day (mg/    consecutive
                                                L)        days shall not
                                                           exceed (mg/L)
------------------------------------------------------------------------
TSS.....................................           100.0            30.0
Oil and grease..........................            20.0            15.0
------------------------------------------------------------------------

* * * * *

0
4. Amend Sec.  423.13 by:
0
a. Revising paragraphs (g)(1)(i); (g)(2) and (g)(3)(i);
0
b. Revising paragraphs (k)(1)(i) and (k)(2);
0
c. Adding paragraphs (k)(3), and (o).
    The additions and revisions 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) * * *
    (1) * * *
    (i) FGD wastewater. Except for those discharges to which paragraph 
(g)(2) or (g)(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 the table 
1 following this paragraph (g)(1)(i). Dischargers must meet the 
effluent limitations for FGD wastewater in this paragraph 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. 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.

                     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 (ug/L)...................              18               8
Mercury, total (ng/L)...................             103              34
Selenium, total (ug/L)..................              70              29
Nitrate/nitrite as N (mg/L).............               4               3
------------------------------------------------------------------------

* * * * *
    (2)(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(f), 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).
    (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 the table following this paragraph (g)(2)(ii). 
Dischargers must meet the effluent limitations for FGD wastewater in 
this paragraph 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.

[[Page 64718]]

                     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 (ug/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 the table following 
paragraph (g)(2)(ii). Dischargers must meet the effluent limitations 
for FGD wastewater in this paragraph 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.
    (3)(i) For dischargers who voluntarily choose to meet the effluent 
limitations for FGD wastewater in this paragraph, 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 following this paragraph (g)(3)(i). Dischargers who 
choose to meet the effluent limitations for FGD wastewater in this 
paragraph must meet such limitations by December 31, 2028. These 
effluent limitations apply to the discharge of FGD wastewater generated 
on and after December 31, 2028.

                     Table 7 of 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
------------------------------------------------------------------------

* * * * *
    (k)(1)(i) Bottom ash transport water. 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 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. This limitation 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. 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. 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.
* * * * *
    (2)(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 paragraphs 
(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.

[[Page 64719]]

    (B) The total volume that may be discharged for the above 
activities 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 
subsection 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(f), 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 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), and shall 
incorporate the elements of a best management practices plan as 
described in (k)(3) of this section.
    (3) 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
    (5) To any other mechanisms not specified above.
    (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 above.
    (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 POTW.
    (D) Bottom ash transport water recycle back to the bottom ash 
system or FGD scrubber.
* * * * *
    (o)(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(i), 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 paragraphs (g)(2)(i) or (k)(2)(ii) of 
this section to limitations for low utilization electric generating 
units under paragraphs (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 paragraphs (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

[[Page 64720]]

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 paragraphs (g)(2)(i) or (k)(2)(ii) of 
this section to voluntary incentives program limitations under 
paragraphs (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 paragraphs (g)(2)(iii) or (k)(2)(iii) of this section to 
generally applicable limitations under paragraphs (g)(1)(i) or 
(k)(1)(i) of this section; or
    (D) From limitations for low utilization electric generating units 
under paragraphs (g)(2)(iii) or (k)(2)(iii) of this section to 
voluntary incentives program limitations under paragraphs (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 paragraphs (g)(2)(iii) or (k)(2)(iii) of this section to 
limitations for electric generating units permanently ceasing coal 
combustion under paragraphs (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(i) 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.
    2. Amend Sec.  423.16 by revising paragraphs (e) and (g) to read as 
follows:

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

* * * * *
    (e)(1) FGD wastewater. 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 to the permitting 
authority that it will cease the coal combustion pursuant to Sec.  
423.19(f), 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 by 
October 13, 2023 except as provided for in paragraph (e)(2) of this 
section. These standards apply to the discharge of FGD wastewater 
generated on and after October 13, 2023.

                       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 (ug/L)...................              18               8
Mercury, total (ng/L)...................             103              34
Selenium, total (ug/L)..................              70              29
Nitrate/nitrite as N (mg/L).............               4               3
------------------------------------------------------------------------

    (2)(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). Dischargers must meet the standards in this paragraph 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 a electric generating unit is below 10 percent per year as 
specified in Sec.  423.19(e), 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).

                     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 (ug/L)...................              11               8
Mercury, total (ng/L)...................             788             356
------------------------------------------------------------------------

* * * * *
    (g)(1) Except for those discharges to which paragraph (g)(2) 
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 to the permitting authority that the 
electric generating unit will cease the cessation of coal combustion 
pursuant to Sec.  423.19(f), there shall be no discharge of pollutants 
in bottom ash

[[Page 64721]]

transport water. This standard 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. 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 the table in paragraph (e) of this section.
    (2)(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)(1), (2), or (3) of this section and not exempted from the 
definition of transport water inSec.  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 
above activities 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).

0
5. Add 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 or permanently ceasing the combustion of coal 
by December 31, 2028, 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 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 paragraph (a)(4) of this section 
to be declared,
    (b) Any facility providing the required documentation pursuant to 
Sec.  423.19(g) may avail itself of the protections of this permit 
condition.

0
6. Add Sec.  423.19 to read as follows.

Sec.  423.19  Reporting and recordkeeping requirements.

    (a) Discharges subject to this part must comply with the following 
additional reporting requirements.
    (b) Signature and certification. Unless otherwise provided below, 
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) Requirements for facilities discharging bottom ash transport 
water pursuant to Sec.  423.13(k)(2)(i) or 423.16(g)(2)(i).
    (1) Initial Certification Statement. For sources seeking to 
discharge bottom ash transport water pursuant to Sec.  423.13(k)(2)(i) 
or 423.16(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:
    (A) A statement that the professional engineer is a licensed 
professional engineer.
    (B) A statement that the professional engineer is familiar with the 
regulation requirements.
    (C) A statement that the professional engineer is familiar with the 
facility.
    (D) The primary active wetted bottom ash system volume in Sec.  
423.11(aa).
    (E) Material assumptions, information, and calculations used by the 
certifying professional engineer to determine the primary active wetted 
bottom ash system volume.
    (F) 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.
    (G) 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.
    (H) A list of all wastewater treatment systems at the facility 
currently, or otherwise required by a date certain under this section.
    (I) A narrative discussion of each treatment system including the 
system type, design capacity, and current or expected operation.
    (d) 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

[[Page 64722]]

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:
    (A) A statement that the professional engineer is a licensed 
professional engineer.
    (B) A statement that the professional engineer is familiar with the 
regulation requirements.
    (C) A statement that the professional engineer is familiar with the 
facility.
    (D) The best management practices plan.
    (E) 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 (c)(3) 
of this section an annual certification shall include the following:
    (A) Any updates to the best management practices plan.
    (B) An attachment of weekly flow measurements from the previous 
year.
    (C) The average amount of recycled bottom ash transport water in 
gallons per day.
    (D) Copies of inspection reports and a summary of preventative 
maintenance performed on the system.
    (E) A statement that the plan and corresponding flow records are 
being maintained at the office of the plant.
    (e) 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.
    (f) 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 October 13, 2021.
    (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 (f)(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.
    (g) Requirements for facilities seeking the protections of Sec.  
423.18.
    (1) Certification statement. For sources seeking to apply the 
protections of the permit conditions in paragraph Sec.  423.18, and for 
each instance that Sec.  423.18 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:
    (A) 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 (g)(2)(B) of this section; or
    (B) 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:
    (A) 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.
    (B) A copy of any documentation of the qualifying event from the 
individual or entity listed under paragraph (g)(2)(A) 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.
    (C) An analysis and accompanying narrative discussion which 
demonstrates that a electric generating unit would have qualified for 
the subcategory at issue absent the event detailed in paragraph 
(g)(2)(A), including the material data, assumptions, and methods used.
    (3) Termination of need statement. For sources filing a 
certification statement under paragraph (g)(1) above, 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

[[Page 64723]]

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.
    (h) Requirements for facilities voluntarily meeting the limits in 
423.13(g)(3)(i).
    (1) Notice of Planned Participation. For sources opting to comply 
with the Voluntary Incentives Program requirements of section 
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 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 (h)(1), 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 the effective date, 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)(i), such notice will satisfy paragraph (h)(1) of this 
section. However, where details required by (h)(2) of this sectionwere 
missing from the previously provided notice, those details must be 
provided in the first Annual Progress Report, no later than October 13, 
2021.
    (i) Requirements for facilities seeking to transfer between 
applicable limitations in a permit under Sec.  423.13(o).
    (1) Notice of Planned Participation. For sources which have filed a 
Notice of Planned Participation under paragraphs (e)(1), (f)(1), or 
(h)(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.
    (j) Notice of material delay. (1) Notice. Within 30 days of 
experiencing a material delay in the milestones set forth in paragraphs 
(f)(2) or (h)(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.

[FR Doc. 2020-19542 Filed 10-9-20; 8:45 am]
 BILLING CODE 6560-50-P