[Federal Register Volume 88, Number 60 (Wednesday, March 29, 2023)]
[Proposed Rules]
[Pages 18824-18903]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-04984]
[[Page 18823]]
Vol. 88
Wednesday,
No. 60
March 29, 2023
Part IV
Environmental Protection Agency
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40 CFR Part 423
Supplemental Effluent Limitations Guidelines and Standards for the
Steam Electric Power Generating Point Source Category; Proposed Rule
Federal Register / Vol. 88, No. 60 / Wednesday, March 29, 2023 /
Proposed Rules
[[Page 18824]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 423
[EPA-HQ-OW-2009-0819; FRL-8794-01-OW]
RIN 2040-AG23
Supplemental Effluent Limitations Guidelines and Standards for
the Steam Electric Power Generating Point Source Category
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule; notification of public hearing.
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SUMMARY: The Environmental Protection Agency (EPA or the Agency) is
proposing 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, bottom ash (BA) transport water, and
combustion residual leachate (CRL) at existing sources. EPA is also
soliciting comment on ELGs for legacy wastewater. This proposal is
estimated to cost $200 million dollars annually in social costs and
reduce pollutant discharges by approximately 584 million pounds per
year.
DATES:
Comments: Comments on this proposal must be received on or before
May 30, 2023. Comments intended for the associated direct final rule
published elsewhere in this issue of the Federal Register, Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category--Initial Notification Date Extension,
must be received on or before April 28, 2023.
Public hearing: EPA will conduct two online public hearings about
this proposed rule on April 20, 2023, and April 25, 2023. After a brief
presentation by EPA personnel, the Agency will accept oral comments
that will be limited to three (3) minutes per commenter. The hearing
will be recorded and transcribed, and EPA will consider all the oral
comments provided, along with the written public comments submitted via
the docket for this rulemaking. To register for the hearing, please
visit EPA's website at www.epa.gov/eg/steam-electric-power-generating-effluent-guidelines-2023-proposed-rule.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OW-
2009-0819 at www.regulations.gov. Follow the online instructions for
submitting comments. Once submitted, comments cannot be edited or
removed from www.regulations.gov. EPA may publish any comment received
to its public docket. Do not electronically submit any information you
consider to be Confidential Business Information (CBI) or other
information whose disclosure is restricted by statute. Multimedia
submissions (e.g., audio, video) must be accompanied by a written
comment. The written comment is considered the official comment and
should include all points you wish to make. EPA will generally not
consider comments or comment contents located outside of the primary
submission (i.e., on the web, cloud, or other file sharing system). For
additional submission methods, the full EPA public comment policy,
information about CBI and multimedia submissions, and general guidance
on making effective comments, please visit www.epa.gov/dockets/commenting-epa-dockets. All documents in the docket are listed on the
www.regulations.gov website. Although listed in the index, some
information is not publicly available, such as 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. Electronically available
docket materials are available through www.regulations.gov.
FOR FURTHER INFORMATION CONTACT: For technical information, contact
Richard Benware, Engineering and Analysis Division, telephone: 202-566-
1369; email: [email protected]. For economic information, contact
James Covington, Water Economics Center, telephone: 202-566-1034;
email: [email protected].
SUPPLEMENTARY INFORMATION:
Preamble Acronyms and Abbreviations. EPA uses 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 used in Appendix A of this preamble.
Supporting Documentation. The proposed rule is supported by a
number of documents, including:
Technical Development Document for Proposed Supplemental
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (TDD), Document No. 821R23005.
This report summarizes the technical and engineering analyses
supporting the proposed rule. The TDD presents EPA's updated analyses
supporting the proposed revisions to FGD wastewater, BA transport
water, CRL, and legacy wastewater. The TDD includes additional data
that has been collected since the publication of the 2015 and 2020
rules, updates to the industry (e.g., retirements, updates to
wastewater handling), cost methodologies, pollutant removal estimates,
corresponding non-water quality environmental impacts associated with
updated FGD and BA methodologies, and calculation of the proposed
effluent limitations. In addition to the TDD, the Technical Development
Document for the Effluent Limitations Guidelines and Standards for the
Steam Electric Power Generating Point Source Category (2015 TDD,
Document No. EPA-821-R-15-007) and the Supplemental Technical
Development Document for Revisions to the Effluent Limitations
Guidelines and Standards for the Steam Electric Power Generating Point
Source Category (2020 Supplemental TDD, Document No. EPA-821-R-20-001)
provide a more complete summary of EPA's data collection, description
of the industry, and underlying analyses supporting the 2015 and 2020
rules.
Supplemental Environmental Assessment for Proposed
Supplemental Effluent Limitations Guidelines and Standards for the
Steam Electric Power Generating Point Source Category (EA), Document
No. 821R23004. This report summarizes the potential environmental and
human health impacts estimated to result from implementation of the
proposed revisions to the 2015 and 2020 rules.
Benefit and Cost Analysis for Proposed Supplemental
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (BCA Report), Document No.
821R23003. This report summarizes the societal benefits and costs
estimated to result from implementation of the proposed revisions to
the 2015 and 2020 rules.
Regulatory Impact Analysis for Proposed Supplemental
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (RIA), Document No. 821R23002.
This report presents a profile of the steam electric power generating
industry, a summary of estimated costs and impacts associated with the
proposed revisions to the 2015 and 2020 rules, and an assessment of the
potential impacts on employment and small businesses.
Environmental Justice Analysis for Proposed Supplemental
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating
[[Page 18825]]
Point Source Category (EJA), Document No. 821R23001. This report
presents a profile of the communities and populations potentially
impacted by this proposal, analysis of the distribution of impacts in
the baseline and proposed changes, and a summary of inputs from
potentially impacted communities that EPA met with prior to the
proposal.
Docket Index for the Proposed Supplemental Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category. This document provides a list of the
additional memoranda, references, and other information EPA relied on
for the proposed revisions to the ELGs.
Organization of this Document. The information in this preamble is
organized as follows:
I. Executive Summary
A. Purpose of Rule
B. Summary of Proposed Rule
II. Public Participation
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
B. Relevant Effluent Guidelines
1. Best Practicable Control Technology Currently Available
2. Best Available Technology Economically Achievable
3. New Source Performance Standards
4. Pretreatment Standards for Existing Sources
5. Pretreatment Standards for New Sources
6. Best Professional Judgment
C. 2015 Steam Electric Power Generation Point Source Category
Rule
1. Final Rule Requirements
2. Vacatur of Limitations Applicable to CRL and Legacy
Wastewater
D. 2020 Steam Electric Reconsideration Rule and Recent
Developments
1. Final Rule Requirements
2. Fourth Circuit Court of Appeals Litigation
3. Executive Order 13990
4. Announcement of Supplemental Rule and Preliminary Effluent
Guidelines Plan 15
E. Other Ongoing Rules Impacting the Steam Electric Sector
1. Coal Combustion Residuals Disposal Rule
2. Air Pollution Rules and Implementation
V. Steam Electric Power Generating Industry Description
A. General Description of Industry
B. Greenhouse Gas Reduction Targets, the Inflation Reduction
Act, and Potential Impacts on Current Market Conditions
C. Control and Treatment Technologies
1. FGD Wastewater
2. BA Transport Water
3. CRL
4. Legacy Wastewater
VI. Data Collection Since the 2020 Rule
A. Information From the Electric Utility Industry
1. Data Requests and Responses
2. Meetings With Individual Utilities
3. Voluntary CRL Sampling
4. Electric Power Research Institute Voluntary Submission
5. Meetings With Trade Associations
B. Notices of Planned Participation
C. Information From Technology Vendors and Engineering,
Procurement, and Construction Firms
D. Other Data Sources
VII. Proposed Regulation
A. Description of the Options
1. FGD Wastewater
2. BA Transport Water
3. CRL
4. Legacy Wastewater
B. Rationale for the Proposed Rule
1. FGD Wastewater
2. BA Transport Water
3. Combustion Residual Leachate (CRL)
4. Legacy Wastewater
5. Clarification on the Interpretation of 40 CFR 423.10
(Applicability) With Respect to Inactive/Retired Power Plants and
Solicitation of Comments on Potential Clarifying Changes to
Regulatory Text
C. Proposed Changes to Subcategories
1. Plants With High FGD Flows
2. Low Utilization EGUs (LUEGUs)
3. EGUs Permanently Ceasing Coal Combustion by 2028
4. Subcategory for Early Adopters Retiring by 2032
D. Additional Rationale for the Proposed PSES and PSNS
E. Availability Timing of New Requirements
F. Economic Achievability
G. Non-Water Quality Environmental Impacts
H. Impacts on Residential Electricity Prices and 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
2. Electricity Market Impacts
IX. Pollutant Loadings
A. FGD Wastewater
B. BA Transport Water
C. CRL
D. Legacy Wastewater
E. Summary of Incremental Changes of Pollutant Loadings From
Four Regulatory Options
X. Non-Water Quality Environmental Impacts
A. Energy Requirements
B. Air Pollution
C. Solid Waste Generation and Beneficial Use
D. Changes in Water Use
XI. Environmental Assessment
A. Introduction
B. Updates to the Environmental Assessment Methodology
C. Outputs From the Environmental Assessment
XII. Benefits Analysis
A. Categories of Benefits Analyzed
B. Quantification and Monetization of Benefits
1. Human Health Effects From Surface Water Quality Changes
2. Ecological Condition and Recreational Use Effects From
Changes in Surface Water Quality Improvements
3. Changes in Air-Quality-Related Effects
4. Other Quantified and/or Monetized Benefits
C. Total Monetized Benefits
D. Additional Benefits
XIII. Environmental Justice Impacts
A. Literature Review
B. Screening Analysis and Community Outreach
C. Distribution of Risks
1. Air
2. Surface Water
3. Drinking Water
4. Cumulative Risks
D. Distribution of Benefits and Costs
E. Results of the Analysis
F. Solicitations on Environmental Justice Analysis and Community
Outreach
XIV. Development of Effluent Limitations and Standards
A. Criteria Used to Select Data as the Basis for the Limitations
and Standards
B. Data Selection for Each Technology Option
C. CRL
XV. Regulatory Implementation
A. Continued Implementation of Existing Limitations and
Standards
1. Reaffirmation of Expectation That Requirement that FGD and BA
Transport Water BAT Limitations Apply ``As Soon As Possible''
Requires Careful Consideration of the Soonest Date That the
Discharger Can Meet the Limitations
2. Reaffirmation That CRL and Legacy Wastewater BAT Limitations
Require a Site-Specific BPJ Analysis and Careful Consideration of
Technologies Beyond Surface Impoundments
3. Consideration of Late Notice of Planned Participation
B. Implementation of New Limitations and Standards
1. Availability Timing of Proposed Requirements
2. Conforming Changes for Transfers in Sec. Sec. 423.13(o) and
423.19(i)
3. Conforming Changes for Voluntary and Involuntary Delays in
Sec. Sec. 423.18(a) and 423.19(j)
4. Recommended Information to be Submitted With a Permit
Application for a Potential Discharge of CRL Through Groundwater
C. Reporting and Recordkeeping Requirements
1. Summary of Proposed Changes to the Annual Progress Reports
for EGUs Permanently Ceasing Coal Combustion by 2028
2. Summary of the Proposed Reporting and Recordkeeping
Requirements for Early Adopters
3. Summary of Proposed Reporting and Recordkeeping Requirements
for CRL Discharges Through Groundwater
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4. Proposed Deletion of Reporting and Recordkeeping Requirements
for LUEGUs
5. Proposed Requirement To Post Information to a Publicly
Available Website
6. Additional Solicitation on Providing a More Flexible
Transition to Zero Discharge
D. Site-Specific Water Quality-Based Effluent Limitations
XVI. Related Acts of Congress, E.O.s, and Agency Initiatives
A. E.O.s 12866 (Regulatory Planning and Review) and 13563
(Improving Regulation and Regulatory Review)
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. E.O. 13132: Federalism
F. E.O. 13175: Consultation and Coordination With Indian Tribal
Governments
G. E.O. 13045: Protection of Children From Environmental Health
Risks and Safety Risks
H. E.O. 13211: Actions That Significantly Affect Energy Supply,
Distribution, or Use
I. National Technology Transfer and Advancement Act
J. E.O. 12898: Federal Actions To Address Environmental Justice
in Minority Populations and Low-Income Populations
Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations
Used in This Preamble
I. Executive Summary
A. Purpose of Rule
EPA is proposing new regulations that apply to wastewater
discharges from steam electric power plants, particularly coal-fired
power plants. These plants are increasingly aging and uncompetitive
sources of electric power in many portions of the United States and are
subject to several environmental regulations designed to control (and
in some cases eliminate) air, water, and land pollution over time. One
of these regulations, the Steam Electric Power Generating Effluent
Limitations Guidelines--or steam electric ELGs--was promulgated in 2015
(80 FR 67838; November 3, 2015) and revised in 2020 (85 FR 64650;
October 13, 2020). The 2015 and 2020 rules apply to the subset of the
electric power industry where ``generation of electricity is the
predominant source of revenue or principal reason for operation, and
whose generation of electricity results primarily from a process
utilizing fossil-type fuel (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 (FGMC) wastewater,
gasification wastewater, CRL, legacy wastewater, and nonchemical metal
cleaning wastes. The 2020 rule modified the 2015 requirements for FGD
wastewater and BA transport water for existing sources only. The 2015
limitations for CRL from existing sources and legacy wastewater were
vacated by the United States (U.S.) Court of Appeals for the Fifth
Circuit in Southwestern Electric Power Co., et al. v. EPA, 920 F.3d 999
(5th Cir. 2019).
In the years since EPA revised the steam electric ELGs in 2015 and
2020, pilot testing and full-scale use of various, more stringent
compliance technologies have continued to expand. This proposal, if
finalized, would revise requirements for discharges associated with the
two wastestreams addressed in the 2020 rule: BA transport water and FGD
wastewater at existing sources. The proposal would also address the
2015 rule CRL requirements that were vacated. Finally, while EPA is
proposing technology-based limitations determined by permitting
authorities on a site-specific basis using their best professional
judgment (BPJ), an option discussed by the Court in Southwestern
Electric Power Co. v. EPA.
B. Summary of Proposed Rule
For existing sources that discharge directly to surface water, with
the exception of the subcategories discussed below, the proposed rule
would establish the following effluent limitations based on Best
Available Technology Economically Achievable (BAT):
A zero-discharge limitation for all pollutants in FGD
wastewater and BA transport water.
Numeric (non-zero) discharge limitations for mercury and
arsenic in CRL.
The proposed rule would eliminate the separate, less stringent BAT
requirements for two subcategories: high flow facilities and low
utilization electric generating units (LUEGUs). The proposed rule does
not seek to change the existing subcategories for oil-fired EGUs and
small generating units (50 MW or less) established in the 2015 rule.
The proposed rule also does not seek to change the existing subcategory
for electric generating units (EGUs) permanently ceasing the combustion
of coal by 2028, which was established in the 2020 rule (although the
Agency does solicit comment on possible changes to this subcategory).
Finally, the proposed rule would create separate requirements for a new
subcategory of facilities that have already complied with either the
2015 or 2020 rule's requirements (hereafter referred to as ``early
adopters'') where such facilities would retire by 2032. For both the
existing and new subcategory referenced immediately above, EPA proposes
additional requirements for affected facilities to demonstrate
permanent cessation of coal combustion or that permanent retirement
will occur.
For the one known high flow facility (TVA Cumberland Fossil Plant)
and the two known facilities with LUEGUs (GSP Merrimack LLC and Indiana
Municipal Power Agency (IMPA) Whitewater Valley Station), the proposed
rule would eliminate these two subcategories for FGD wastewater and BA
transport water, subjecting those wastestreams to the otherwise
applicable requirements for the rest of the industry. For early
adopters retiring by 2032, the rule would retain the 2020 rule
requirements for FGD wastewater and BA transport water rather than
require the new, more stringent zero-discharge requirements for these
wastestreams.
Where BAT limitations in this proposed rule are more stringent than
previously established BPT and BAT limitations, EPA is proposing that
any new limitations would not apply until a date determined by the
permitting authority that is as soon as possible on or after [Final
Rule Publication Date + 60 days], but no later than December 31, 2029.
For indirect discharges (i.e., discharges to publicly owned
treatment works (POTWs)), the proposed rule would establish
pretreatment standards for existing sources that are the same as the
BAT limitations.
C. Summary of Costs and Benefits
EPA estimates that the proposed rule will cost $200 million per
year in social costs and result in $1,557 million per year in monetized
benefits using a three percent discount rate and will cost $216 million
per year in social costs and result in $1,290 million per year in
monetized benefits using a seven percent discount rate.\1\ Not all
costs and benefits can be fully quantified and monetized, and in
particular EPA anticipates the proposed rule would also generate
important unquantified benefits (e.g., improved habitat conditions for
plants, invertebrates, fish, amphibians, and the wildlife that prey on
aquatic organisms). Furthermore, while some health benefits and
willingness to pay for water quality
[[Page 18827]]
improvements have been quantified and monetized, those estimates may
not fully capture all important water quality-related benefits.
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\1\ As discussed in Section XII of this preamble, not all
benefits could be fully quantified and monetized at this time.
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Table I-1 of this preamble summarizes the monetized benefits and
social costs for the four regulatory options 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 proposed rule. EPA
based its analysis on a modeled baseline that reflects the full
implementation of the 2020 rule, the expected effects of announced
retirements and fuel conversions, and the impacts of relevant final
rules affecting the power sector. Although the baseline does not
reflect anticipated impacts on the industry because of the recently
passed Inflation Reduction Act (IRA), EPA solicits comment on means by
which the Agency could model the impacts of the IRA for the final rule.
Because the primary effect of the IRA in the context of this rule would
be to increase the number of facilities that permanently cease coal
combustion in the baseline, EPA expects that it would proportionally
reduce the benefits and costs estimated in this proposal.\2\ EPA
understands that these modeled results are uncertain and that the
actual costs for individual plants could be higher or lower than
estimated. The current estimate reflects the best data and analysis
currently available. For additional information on costs and benefits,
see Sections VIII and XII of this preamble, respectively.
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\2\ Furthermore, because the cessation of coal combustion would
occur in the baseline, EPA expects that the rule would continue to
be economically achievable even after accounting for the IRA.
Table I-1--Total Monetized Annualized Benefits and Costs of Four Regulatory Options
[Millions of 2021$, three percent discount rate]
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Total Total
Total social monetized monetized net
Regulatory option costs benefits \a\ benefits \a\
\b\ \b\
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Option 1........................................................ $88.4 $696 $608
Option 2........................................................ 167.0 1,336 1,169
Option 3 (Preferred)............................................ 200.3 1,557 1,357
Option 4........................................................ 207.2 1,670 1,463
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\a\ EPA estimated the air-related benefits for Option 3 using the Integrated Planning Model (IPM). EPA did not
analyze Options 1, 2, and 4 using IPM. Instead, EPA extrapolated estimates for Options 1, 2, and 4 air-related
benefits from the estimate for Option 3 in proportion to total social costs.
\b\ Includes benefits of changes in CO2 air emissions monetized using the Interagency Working Group on the
Social Cost of Greenhouse Gases (IWG) SC-CO2 at 3% (average). See Section XII.B.3 of this preamble for
benefits monetized using other SC-CO2 values.
II. Public Participation
Submit your comments, identified by Docket ID No. EPA-HQ-OW-2009-
0819, at www.regulations.gov (our preferred method), or the other
methods identified in the ADDRESSES section. Once submitted, comments
cannot be edited or removed from the docket. EPA may publish any
comment received to its public docket. Do not submit electronically any
information you consider to be CBI or other information whose
disclosure is restricted by statute. Multimedia submissions (e.g.,
audio, video) must be accompanied by a written comment. The written
comment is considered the official comment and should include
discussion of all points you wish to make. EPA will generally not
consider comments or comment contents located outside of the primary
submission (i.e., on the web, cloud, or other file sharing system). For
additional submission methods, the full EPA public comment policy,
information about CBI or multimedia submissions, and general guidance
on making effective comments, please visit www.epa.gov/dockets/commenting-epa-dockets.
III. General Information
A. Does this action apply to me?
Entities potentially regulated by any final rule following this
action include:
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North American
Industry
Category Example of regulated Classification
entity System (NAICS)
Code
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Industry....................... Electric Power 22111
Generation Facilities--
Electric Power
Generation.
Electric Power 221112
Generation Facilities--
Fossil Fuel Electric
Power Generation.
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This section is not intended to be exhaustive, but rather provides
a guide regarding entities likely to be regulated by any final rule
following this action. Other types of entities that do not meet the
above criteria could also be regulated. To determine whether your
facility is regulated by any final rule following this action,
carefully examine the applicability criteria listed in 40 CFR 423.10
and the definitions in 40 CFR 423.11. If you still have questions
regarding the applicability of any final rule following this action to
a particular entity, consult the person listed for technical
information in the preceding FOR FURTHER INFORMATION CONTACT section.
B. What action is EPA taking?
The Agency is proposing to revise, and is soliciting comment on
possible revision to certain BAT effluent limitations guidelines and
pretreatment standards for existing sources in the steam electric power
generating point source category that apply to FGD wastewater, BA
transport water, CRL, and legacy wastewater.
[[Page 18828]]
C. What is EPA's authority for taking this action?
EPA is proposing to promulgate 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 proposed action is estimated to cost $200 million per year in
social costs and result in $1,557 million in benefits using a three
percent discount rate. Using a seven percent discount rate, the
estimated costs are $216 million per year and the benefits are $1,290
million.
IV. Background
A. Clean Water Act
Congress passed the Federal Water Pollution Control Act Amendments
of 1972, also known as the Clean Water Act (CWA), to ``restore and
maintain the chemical, physical, and biological integrity of the
Nation's waters.'' 33 U.S.C. 1251(a). The CWA establishes a
comprehensive program for protecting our nation's waters. Among its
core provisions, the CWA prohibits the discharge of pollutants from a
point source to waters of the United States (WOTUS), except as
authorized under the CWA. Under section 402 of the CWA, discharges may
be authorized through a National Pollutant Discharge Elimination System
(NPDES) permit. The CWA also authorizes EPA to establish nationally
applicable, technology-based ELGs for discharges from different
categories of point sources, such as industrial, commercial, and public
sources.
The CWA authorizes EPA to promulgate nationally applicable
pretreatment standards that restrict pollutant discharges from
facilities that discharge wastewater to WOTUS indirectly through sewers
flowing to Publicly Owned Treatment Works (POTWs), as outlined in CWA
sections 307(b) and (c), 33 U.S.C. 1317(b) and (c). EPA establishes
national pretreatment standards for those pollutants in wastewater from
indirect dischargers that may pass through, interfere with, or are
otherwise incompatible with POTW operations. Pretreatment standards are
designed to ensure that wastewaters from direct and indirect industrial
dischargers are subject to similar levels of treatment. See CWA section
301(b), 33 U.S.C. 1311(b). In addition, POTWs are required to implement
local treatment limits applicable to their industrial indirect
dischargers to satisfy any local requirements. See 40 CFR 403.5.
Direct dischargers (i.e., those discharging directly to surface
waters rather than through POTWs) must comply with effluent limitations
in NPDES permits. Discharges that flow through groundwater before
reaching surface waters must also comply with effluent limitations in
NPDES permits if those discharges are the ``functional equivalent'' of
a direct discharge. County of Maui v. Hawaii Wildlife Fund, 140 S. Ct.
1462 (2020). Indirect dischargers, who discharge through POTWs, must
comply with pretreatment standards. Technology-based effluent
limitations in NPDES permits are derived from effluent limitations
guidelines (CWA sections 301 and 304, 33 U.S.C. 1311 and 1314) and new
source performance standards (CWA section 306, 33 U.S.C. 1316)
promulgated by EPA, or based on best professional judgment (BPJ) where
EPA has not promulgated an applicable effluent guideline or new source
performance standard. CWA section 402(a)(1)(B), 33 U.S.C.
1342(a)(1)(B); 40 CFR 125.3(c). Additional limitations based on water
quality standards are also required to be included in the permit in
certain circumstances. CWA section 301(b)(1)(C), 33 U.S.C.
1311(b)(1)(C); 40 CFR 122.44(d). EPA establishes ELGs by 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.
EPA promulgates national ELGs for major industrial categories for
three classes of pollutants: (1) conventional pollutants (i.e., total
suspended solids (TSS), oil and grease, biochemical oxygen demand
(BOD5), fecal coliform, and pH), as outlined in CWA section
304(a)(4) and 40 CFR 401.16; (2) toxic pollutants (e.g., toxic metals
such as arsenic, mercury, selenium, and chromium; toxic organic
pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene),
as outlined in section 307(a) of the Act, 40 CFR 401.15 and 40 CFR part
423 appendix A; and (3) nonconventional pollutants, which are those
pollutants that are not categorized as conventional or toxic (e.g.,
ammonia-N, phosphorus, and total dissolved solids (TDS)).
B. Relevant Effluent Guidelines
EPA develops effluent guidelines that are technology-based
regulations for a category of dischargers. EPA bases these regulations
on the performance of control and treatment technologies. The
legislative history of CWA section 304(b), which is the heart of the
effluent guidelines program, describes the need to press toward higher
levels of control through research and development of new processes,
modifications, replacement of obsolete plants and processes, and other
improvements in technology, taking into account the cost of controls.
Congress has also stated that EPA need not consider water quality
impacts on individual water bodies as the guidelines are developed; see
Statement of Senator Muskie (October 4, 1972), reprinted in Legislative
History of the Water Pollution Control Act Amendments of 1972, at 170.
(U.S. Senate, Committee on Public Works, Serial No. 93-1, January
1973); see also Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1005
(``The Administrator must require industry, regardless of a discharge's
effect on water quality, to employ defined levels of technology to meet
effluent limitations.'') (citations and internal quotations omitted).
There are many technology-based effluent limitations (TBELs) that
may apply to a discharger under the CWA: four types of standards
applicable to direct dischargers, two types of standards applicable to
indirect dischargers, and a default site-specific approach. The TBELs
relevant to this rulemaking are described in detail below.
1. Best Practicable Control Technology Currently Available
Traditionally, EPA defines Best Practicable Control Technology
(BPT) effluent limitations based on the average of the best
performances of facilities within the industry, grouped to reflect
various ages, sizes, processes, or other common characteristics. EPA
may promulgate 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. See 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 what is
currently in place in an industrial category, when based on an agency
determination that the technology is available in another
[[Page 18829]]
category or subcategory and can be practicably applied.
2. Best Available Technology Economically Achievable
BAT represents the second level of stringency for controlling
direct discharge of toxic and nonconventional pollutants. Courts have
referred to this as the CWA's ``gold standard'' for controlling
discharges from existing sources. Southwestern Elec. Power Co. v. EPA,
920 F.3d at 1003. In general, BAT represents the best available,
economically achievable performance of facilities in the industrial
subcategory or category. 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 that EPA
considers in assessing BAT are the cost of achieving BAT effluent
reductions, the age of equipment and facilities involved, the process
employed, potential process changes, and non-water quality
environmental impacts, including energy requirements, and such other
factors as the Administrator deems appropriate. CWA section
304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B). The agency retains considerable
discretion in assigning the weight to be accorded these factors.
Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045 (D.C. Cir. 1978). EPA
usually determines economic achievability on the basis of the effect of
the cost of compliance with BAT limitations on overall industry and
subcategory financial conditions. BAT reflects the highest performance
in the industry and may reflect a higher level of performance than is
currently being achieved based on technology transferred from a
different subcategory or category, bench scale or pilot plant studies,
or foreign plants. Southwestern Elec. Power Co. v. EPA, 920 F.3d at
1006; American Paper Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir.
1976); American Frozen Food Inst. v. Train, 539 F.2d 107, 132 (D.C.
Cir. 1976). BAT may be based upon process changes or internal controls,
even when these technologies are not common industry practice. See
American Frozen Foods, 539 F.2d at 132, 140; Reynolds Metals Co. v.
EPA, 760 F.2d 549, 562 (4th Cir. 1985); California & Hawaiian Sugar Co.
v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977).
3. New Source Performance Standards
New Source Performance Standards (NSPS) reflect effluent reductions
that are achievable based on the Best Available Demonstrated Control
Technology (BADCT). Owners of new facilities have the opportunity to
install the best and most efficient production processes and wastewater
treatment technologies. As a result, NSPS should represent the most
stringent controls attainable through the application of the BADCT for
all pollutants (that is, conventional, nonconventional, and toxic
pollutants). In establishing NSPS, EPA is directed to take into
consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements. CWA
section 306(b)(1)(B), 33 U.S.C. 1316(b)(1)(B).
4. Pretreatment Standards for Existing Sources
Section 307(b), 33 U.S.C. 1317(b), of the Act calls for EPA to
issue pretreatment standards for discharges of pollutants to POTWs.
Pretreatment standards for existing sources (PSES) are designed to
prevent the discharge of pollutants that pass through, interfere with,
or are otherwise incompatible with the operation of POTWs. Categorical
pretreatment standards are technology-based and are analogous to BPT
and BAT effluent limitations guidelines, and thus the agency typically
considers the same factors in promulgating PSES as it considers in
promulgating BAT. The General Pretreatment Regulations, which set forth
the framework for the implementation of categorical pretreatment
standards, are found at 40 CFR part 403. These regulations establish
pretreatment standards that apply to all non-domestic dischargers. See
52 FR 1586 (January 14, 1987).
5. Pretreatment Standards for New Sources
Section 307(c), 33 U.S.C. 1317(c), of the Act calls for EPA to
promulgate Pretreatment Standards for New Sources (PSNS). Such
pretreatment standards must prevent the discharge of any pollutant into
a POTW that may interfere with, pass through, or may otherwise be
incompatible with the POTW. EPA promulgates PSNS based on best
available demonstrated control technology (BADCT) for new sources. New
indirect dischargers have the opportunity to incorporate into their
facilities the best available demonstrated technologies. The agency
typically considers the same factors in promulgating PSNS as it
considers in promulgating NSPS.
6. Best Professional Judgment
The CWA section 301 and its implementing regulation at 40 CFR
125.3(a) indicate that technology-based treatment requirements under
section 301(b) of the CWA represent the minimum level of control that
must be imposed in an NPDES permit. Where EPA-promulgated effluent
guidelines are not applicable to a non-POTW discharge, or where such
EPA-promulgated guidelines have been vacated by a court, such treatment
requirements are established on a case-by-case basis using the
permitting writer's best professional judgment (BPJ). Case-by-case
TBELs are developed pursuant to CWA section 402(a)(1), which authorizes
EPA Administrator to issue a permit that will meet either: all
applicable requirements developed under the authority of other sections
of the CWA (e.g., technology-based treatment standards, water quality
standards, ocean discharge criteria) or, before taking the necessary
implementing actions related to those requirements, ``such conditions
as the Administrator determines are necessary to carry out the
provisions of this Act.'' The regulation at 40 CFR 125.3(c)(2) cites
this section of the CWA, stating that technology-based treatment
requirements may be imposed in a permit ``on a case-by-case basis under
section 402(a)(1) of the Act, to the extent that EPA-promulgated
effluent limitations are inapplicable.'' Further, section 125.3(c)(3)
indicates, ``[w]here promulgated effluent limitations guidelines only
apply to certain aspects of the discharger's operation, or to certain
pollutants, other aspects or activities are subject to regulation on a
case-by-case basis in order to carry out the provisions of the Act.''
The factors considered by the permit writer are the same. See 40 CFR
125.3(d)(1)-(3).
C. 2015 Steam Electric Power Generation Point Source Category Rule
1. Final Rule Requirements
On September 30, 2015, EPA promulgated 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 that
can be discharged in the steam electric industry's largest sources of
wastewater, based on technology improvements in the steam electric
power industry over the preceding three decades. Before the 2015 rule,
regulations for the industry were last updated in 1982.
Over the last 30 years, new technologies for generating electric
power and the widespread implementation of air pollution controls
[[Page 18830]]
have altered existing wastewater streams or created new wastewater
streams at many steam electric facilities, particularly coal-fired
facilities. Discharges of these wastestreams include arsenic, lead,
mercury, selenium, chromium, and cadmium. Once in the environment, many
of these toxic pollutants can remain there for years and continue to
cause impacts.
The 2015 rule addressed effluent limitations and standards for
multiple wastestreams generated by new and existing steam electric
facilities: BA transport water, CRL, FGD wastewater, FGMC wastewater,
FA transport water, gasification wastewater, and legacy wastewater. The
rule required most steam electric facilities to comply with the
effluent limitations ``as soon as possible'' after November 1, 2018,
and no later than December 31, 2023. NPDES permitting authorities
established particular compliance date(s) within that range for each
facility (except for indirect dischargers) at the time they reissued
the facility's NPDES permit.
The 2015 rule was projected to reduce the amount of metals defined
in the CWA as toxic pollutants, nutrients, and other pollutants that
steam electric facilities are allowed to discharge by 1.4 billion
pounds per year and reduce water withdrawal by 57 billion gallons. At
the time, EPA estimated annual compliance costs for the final rule to
be $480 million (in 2013 dollars) and estimated benefits associated
with the rule to be $451 to $566 million (in 2013 dollars).
2. Vacatur of Limitations Applicable to CRL and Legacy Wastewater
Seven petitions for review of the 2015 rule were filed in various
circuit courts by the electric utility industry, environmental groups,
and drinking water utilities. These petitions were consolidated in the
U.S. Court of Appeals for the Fifth Circuit, Southwestern Electric
Power Co. v. EPA, Case No. 15-60821 (5th Cir.). On March 24, 2017, the
Utility Water Act Group submitted to EPA an administrative petition for
reconsideration of the 2015 rule. On April 5, 2017, the Small Business
Administration (SBA) submitted an administrative petition for
reconsideration of the 2015 rule.
On August 11, 2017, the Administrator announced his decision to
conduct a rulemaking to potentially revise the new, more stringent BAT
effluent limitations and pretreatment standards for existing sources in
the 2015 rule that apply to FGD wastewater and BA transport water. The
Fifth Circuit subsequently granted EPA's request to sever and hold in
abeyance petitioners' claims related to those limitations and
standards, and those claims are still in abeyance. With respect to the
remaining claims related to limitations applicable to legacy wastewater
and CRL, the Fifth Circuit issued a decision on April 12, 2019,
vacating those limitations as arbitrary and capricious under the
Administrative Procedure Act and unlawful under the CWA, respectively.
Southwestern Elec. Power Co. v. EPA, 920 F.3d 999. In particular, the
Court rejected EPA's attempts to set BAT limitations for each
wastestream equal to previously promulgated BPT limitations based on
surface impoundments. In the case of legacy wastewater, the Court held
that EPA's record on surface impoundments did not support BAT
limitations based on surface impoundments. Id. At 1015. In the case of
CRL, the Court held that EPA's setting of BAT limitations equal to BPT
limitations was an impermissible conflation of the two standards, which
are supposed to be progressively more stringent, and that EPA's
rationale was not authorized by the statutory factors for determining
BAT. Id. At 1026. After the Court's decision, EPA announced its plans
to address the vacated limitations in a later action after the 2020
rule.
In September 2017, using notice-and-comment procedures, EPA
finalized a rule (``postponement rule'') postponing the earliest
compliance dates for the more stringent BAT effluent limitations and
PSES for FGD wastewater and BA transport water in the 2015 rule, from
November 1, 2018, to November 1, 2020. EPA also withdrew a prior action
it had taken to stay parts of the 2015 rule pursuant to Section 705 of
the Administrative Procedure Act, 5 U.S.C. 705. The postponement rule
received multiple legal challenges, but EPA prevailed, and the courts
did not sustain any of them.\3\
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\3\ See Center for Biological Diversity v. EPA, No. 18-cv-00050
(D. Ariz. filed January 20, 2018); see also Clean Water Action. v.
EPA, No. 18-60079 (5th Cir.). On October 29, 2018, the District of
Arizona case was dismissed upon EPA's motion to dismiss for lack of
jurisdiction, and on August 28, 2019, the Fifth Circuit denied the
petition for review of the postponement rule.
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D. 2020 Steam Electric Reconsideration Rule and Recent Developments
1. Final Rule Requirements
On August 31, 2020, EPA promulgated the Steam Electric
Reconsideration Rule (hereinafter the ``2020 rule''). The 2020 rule
revised requirements for FGD wastewater and BA transport water
applicable to existing sources. Specifically, the 2020 rule made four
changes to the 2015 rule. First, the rule changed the technology basis
for control of FGD wastewater and BA transport water. For FGD
wastewater, the technology basis was changed from chemical
precipitation plus high hydraulic residence time biological reduction
to chemical precipitation plus low hydraulic residence time biological
reduction. This change in the technology basis resulted in less
stringent selenium limitations but more stringent mercury and nitrogen
limitations. For BA transport water, the technology basis was changed
from dry handling or closed-loop systems to high recycle rate systems,
allowing for a site-specific purge not to exceed 10 percent of the
system volume. This change in technology resulted in less stringent
limitations for all pollutants in BA transport water. Second, the 2020
rule revised the technology basis for the voluntary incentives program
(VIP) for FGD wastewater from vapor compression evaporation to chemical
precipitation plus membrane filtration. This change in the technology
basis resulted in less stringent limitations for most pollutants but
added new limitations for bromide and nitrogen. Third, the 2020 rule
created three new subcategories for high-flow facilities, LUEGUs, and
EGUs permanently ceasing coal combustion by 2028. These subcategories
were subject to less stringent limitations. Finally, the 2020 rule
required most steam electric facilities to comply with the revised
effluent limitations ``as soon as possible'' after October 13, 2021,
and no later than December 31, 2025.\4\ NPDES permitting authorities
established the particular compliance date(s) within that range for
each facility (except for indirect dischargers) at the time they
reissued the facility's NPDES permit.
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\4\ The 2015 rule's VIP compliance date was revised to December
31, 2028, in the 2020 rule.
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2. Fourth Circuit Court of Appeals Litigation
Two petitions for review of the 2020 rule were timely filed by
environmental group petitioners and consolidated in the U.S. Court of
Appeals for the Fourth Circuit on November 19, 2020. Appalachian
Voices, et al. v. EPA, No. 20-2187 (4th Cir.). An industry trade group
and certain energy companies moved to intervene in the litigation,
which the Court granted on December 3, 2020.
3. Executive Order 13990
On January 20, 2021, President Biden issued Executive Order (E.O.)
13990:
[[Page 18831]]
Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis (86 FR 7037). E.O. 13990 directed Federal
agencies to immediately review and, if necessary, take action to
address the promulgation of Federal regulations and other actions
during the previous four years that conflict with the national
objectives of protecting public health and the environment. A list of
regulations to be reviewed, including the 2020 rule, was released in
conjunction with this E.O.
4. Announcement of Supplemental Rule and Preliminary Effluent
Guidelines Plan 15
On July 26, 2021, EPA announced the new rulemaking to strengthen
certain wastewater pollution discharge limitations for coal-fired power
plants that use steam to generate electricity. EPA later clarified
that, as part of its new rulemaking, it would be reconsidering all
aspects of the 2020 rule.\5\ EPA undertook an evidence-based, science-
based review of the 2020 Steam Electric Reconsideration Rule under E.O.
13990, finding that there are opportunities to strengthen certain
wastewater pollution discharge limitations. For example, EPA discussed
how treatment systems using membranes have advanced since the 2020
rule's promulgation and continue to rapidly advance as an effective
option for treating a wide variety of industrial pollution, including
pollution from steam electric power plants. In the announcement, EPA
also confirmed that until a new rule is promulgated, the 2015 and 2020
regulations will continue to be implemented and enforced to achieve
needed pollutant reductions.
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\5\ On April 8, 2022, the U.S. Court of Appeals for the Fourth
Circuit granted EPA's motion for a long-term abeyance of the
litigation challenging the 2020 rule, pending this rulemaking.
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In September 2021, EPA issued Preliminary Effluent Guidelines
Program Plan 15.\6\ This document discussed the annual review of
effluent limitations guidelines and pretreatment standards, rulemakings
for new and existing industrial point source categories, and any new or
existing sources receiving further analyses. Here, EPA not only
discussed the wastestreams affected by the 2020 rule (FGD wastewater
and BA transport water), but also the wastestreams from the 2015 rule
which had limitations vacated and remanded to the Agency (i.e., CRL and
legacy wastewater). This was the first time EPA had publicly presented
information that the supplemental rulemaking could cover these
wastestreams as well. For further discussion of the vacatur and remand
of the 2015 limitations applicable to CRL and legacy wastewater, see
Section IV.D of this preamble.
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\6\ Available online at: www.epa.gov/system/files/documents/2021-09/ow-prelim-elg-plan-15_508.pdf.
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E. Other Ongoing Rules Impacting the Steam Electric Sector
1. Coal Combustion Residuals Disposal Rule
On April 17, 2015, EPA promulgated 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 coal combustion residuals (CCR),
commonly referred to as coal ash, from steam electric power plants. The
final 2015 CCR rule was the culmination of extensive study on the
effects of coal ash on the environment and public health. The rule
established technical requirements for CCR landfills and surface
impoundments under subtitle D of the Resource Conservation and Recovery
Act (RCRA), the nation's primary law for regulating solid waste.
These regulations established requirements for the management and
disposal of coal ash, including requirements designed to prevent
leaking of contaminants into groundwater, blowing of contaminants into
the air as dust, and the catastrophic failure of coal ash surface
impoundments. The 2015 CCR rule also set recordkeeping and reporting
requirements, as well as requirements for each plant to establish and
post specific information to a publicly accessible website. The rule
also established requirements to distinguish between the beneficial use
of CCR from disposal.
As a result of the D.C. Circuit Court decisions in Utility Solid
Waste Activities Group v. EPA, 901 F.3d 414 (D.C. Cir. 2018), and
Waterkeeper Alliance Inc. et al. v. EPA, No. 18-1289 (D.C. Cir. filed
March 13, 2019), the Administrator signed two rules: A Holistic
Approach to Closure Part A: Deadline to Initiate Closure and Enhancing
Public Access to Information (CCR Part A rule) on July 29, 2020, and A
Holistic Approach to Closure Part B: Alternate Liner Demonstration (CCR
Part B rule) on October 15, 2020. EPA finalized five amendments to the
2015 CCR rule which continue to impact the wastewaters covered by this
ELG. First, the CCR Part A rule established 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
retrofitting. EPA established 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 timeframes needed for
implementation. (This would not affect the ability of plants to install
new, composite-lined surface impoundments.) Second, the Part A rule
established procedures for plants to obtain approval from EPA for
additional time to develop alternative disposal capacity to manage
their wastestreams (both coal ash and noncoal ash) before they must
stop receiving waste and begin closing their coal ash surface
impoundments. Third, the Part A rule changed the classification of
compacted-soil-lined and clay-lined surface impoundments from lined to
unlined. Fourth, the Part B rule finalized procedures potentially
allowing a limited number of facilities to demonstrate to EPA that,
based on groundwater data and the design of a particular surface
impoundment, the unit ensures there is no reasonable probability of
adverse effects to human health and the environment. Should such a
submission be approved, these CCR surface impoundments would be allowed
to continue to operate.
As explained in the 2015 and 2020 ELG rules, the ELGs and CCR rules
may affect the same EGU or activity at a plant. Therefore, when EPA
finalized the ELG and CCR rules in 2015, and revisions to both rules in
2020, the Agency coordinated the ELG and CCR rules to minimize the
complexity of implementing engineering, financial, and permitting
activities. EPA considered the interaction of these two rules during
the development of this proposal. EPA's analysis builds in the final
requirements of these rules in the baseline accounting for the most
recent data provided under the CCR rule reporting and recordkeeping
requirements. This is further described in Supplemental TDD, Section 3.
For more information on the CCR Part A and Part B rules, including
information about their ongoing implementation, visit www.epa.gov/coalash/coal-ash-rule.
2. Air Pollution Rules and Implementation
EPA is taking several actions to regulate a variety of
conventional, hazardous, and greenhouse gas (GHG) air pollutants,
including actions to regulate the same steam electric plants subject to
Part 423. Other actions impact steam electric plants indirectly when
implemented by states. In light of these
[[Page 18832]]
ongoing actions, EPA has worked to consider appropriate flexibilities
in this proposed ELG rule to provide certainty to the regulated
community while ensuring the statutory objectives of each program are
achieved. Furthermore, to the extent that these actions are finalized
and already impacting steam electric plant operations, EPA has
accounted for these changed operations in its IPM modeling discussed in
Section VIII of this preamble.
a. The Revised Cross State Air Pollution Rule (CSAPR) Update and the
Proposed Good Neighbor Plan for the 2015 Ozone National Ambient Air
Quality Standards (NAAQS)
EPA recently completed a rulemaking to address ``good neighbor''
obligations for the 2008 ozone national ambient air quality standards
(NAAQS) and proposed a rulemaking in 2022 with respect to the same
statutory obligations for the 2015 ozone NAAQS. These actions implement
the Clean Air Act's (CAA's) prohibition on emissions that significantly
contribute to nonattainment or interfere with maintenance of the NAAQS
in other states.
On April 30, 2021, EPA published the final Revised Cross-State Air
Pollution Rule (CSAPR) Update, 86 FR 23054, which resolved 21 states'
good neighbor obligations for the 2008 ozone NAAQS, following the
remand of the 2016 CSAPR Update (81 FR 74504, October 26, 2016) in
Wisconsin v. EPA, 938 F.3d 308 (D.C. Cir. 2019). Between them, these
two rules establish the Group 2 and Group 3 market-based emissions
trading programs for 22 states in the eastern United States for
emissions of oxides of nitrogen (NOX) from fossil fuel-fired
EGUs during the summer ozone season.
On February 28, 2022, the Administrator signed a proposed rule,
Federal Implementation Plan Addressing Regional Ozone Transport for the
2015 Ozone National Ambient Air Quality Standards, 87 FR 20036 (April
6, 2022) (also called the Good Neighbor Plan). This proposed rule
includes further ozone-season NOX pollution reduction
requirements for fossil fuel-fired EGUs to address 25 states' good
neighbor obligations for the 2015 ozone NAAQS. The proposed rule would
establish an enhanced Group 3 market-based emissions trading program
with NOX budgets for EGUs in those 25 states, beginning in
2023. Further information about this proposal is available on EPA's
website.\7\
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\7\ See www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqs.
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b. Clean Air Act Section 111 Rule
On October 23, 2015, EPA finalized NSPSs for emissions from new,
modified, and reconstructed fossil fuel-fired EGUs under CAA section
111(b). Specifically, the 2015 NSPS established separate standards for
emissions of CO2 from newly constructed, modified, and
reconstructed fossil fuel-fired electric utility steam generating units
(i.e., utility EGUs and integrated gasification combined cycle units)
and from newly constructed and reconstructed fossil fuel-fired
stationary combustion turbines. The standards set in the 2015 NSPS
reflected the degree of emission limitation achievable through
application of the best system of emission reduction that EPA
determined to have been adequately demonstrated for each type of unit
and was codified in 40 CFR part 60, subpart TTTT. EPA is currently
reviewing the 2015 NSPS--including new technologies to mitigate GHG
emissions from new, modified, and reconstructed stationary combustion
turbines--and will, if warranted, propose to revise the NSPSs in an
upcoming rulemaking.
On August 3, 2015, under CAA section 111(d), EPA promulgated its
first emission guidelines regulating emissions from existing fossil
fuel-fired EGUs in the Clean Power Plan (CPP) (40 CFR part 60, subpart
UUUU). The CPP was subsequently stayed by the U.S. Supreme Court. On
June 19, 2019, EPA promulgated new emission guidelines, known as the
Affordable Clean Energy (ACE) Rule (40 CFR part 60, subpart UUUUa), and
issued a repeal of the CPP. On January 19, 2021, the U.S. Court of
Appeals for the D.C. Circuit vacated the ACE Rule and remanded the rule
to EPA for further consideration consistent with its decision. The
Supreme Court then overturned portions of the D.C. Circuit Court's
decision in West Virginia v. EPA, No. 20-1530, in June 2022. EPA is now
considering the implications of the Supreme Court's decision and is
undertaking a new rulemaking to establish new emission guidelines under
CAA section 111(d) to limit emissions from existing fossil fuel-fired
EGUs.
c. Mercury and Air Toxics Standards Rule
After considering costs, EPA recently proposed to reaffirm the
determination that it is appropriate and necessary to regulate
hazardous air pollutants (HAPs), including mercury, from coal- and oil-
fired steam generating power plants. These regulations are known as the
Mercury and Air Toxics Standards (MATS) for power plants. The proposed
MATS action would revoke a 2020 finding that it is not appropriate and
necessary to regulate coal- and oil-fired power plants under CAA
section 112, but which did not disturb the underlying MATS regulations.
The MATS proposal would ensure that coal- and oil-fired power plants
continue to control emissions of toxic air pollution, including
mercury.
d. National Ambient Air Quality Standards Rules for Particulate Matter
EPA is currently reconsidering a December 7, 2020, decision to
retain the primary (health-based) and secondary (welfare-based) NAAQS
for particulate matter (PM).\8\ EPA is reconsidering the December 2020
decision because available scientific evidence and technical
information indicate that the current standards may not be adequate to
protect public health and welfare, as required by the CAA.
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\8\ See www.epa.gov/newsreleases/epa-reexamine-health-standards-harmful-soot-previous-administration-left-unchanged.
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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 final rule, the
2019 proposed rule, and the 2020 final 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 this proposal, 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.\9\ The analyses
supporting the proposed rule use an updated baseline that incorporates
these changes in the industry. The analyses then compare the effect of
the proposed rule's requirements for FGD wastewater, BA transport
water, CRL, and legacy wastewater to the effect on the industry (as it
exists today) of the 2015 and 2020 rules' limitations for FGD
wastewater,
[[Page 18833]]
BA transport water, CRL, and legacy wastewater.
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\9\ The data presented in the general description continue to
reflect some conditions existing in 2009, as the 2010 steam electric
industry survey remains EPA's best available source of information
for characterizing operations across the industry.
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As described in the Regulatory Impact Analysis, of the 871 steam
electric power plants in the country identified by EPA, only those
coal-fired power plants that discharge FGD wastewater, BA transport
water, CRL, and/or legacy wastewater may incur compliance costs under
this proposal. EPA estimates that 69 to 93 such plants may incur
compliance costs under the regulatory options in this proposal. For
further information about plant retirements, fuel conversions, ash
handling conversions, wastewater treatment updates, and updated
information on capacity utilization, see Changes to Industry Profile
for Coal-Fired Generating Units for the Steam Electric Effluent
Guidelines Proposed Rule (DCN SE10241).
B. Greenhouse Gas Reduction Targets, the Inflation Reduction Act, and
Potential Impacts on Current Market Conditions
While this proposal was motivated by the CWA and by the need to
address water pollution, EPA acknowledges that there are also large
changes happening in the industry, in part due to a series of actions
targeted toward GHG reductions. First, in April 22, 2021, President
Biden announced new 2030 GHG reduction targets for the United
States.\10\ As part of reaching net zero emissions by 2050, the
nationally determined contribution submitted to the United Nations
Framework Convention on Climate Change includes a 50-52 percent
reduction from 2005 levels by 2030. These reduction targets were
developed by the National Climate Task Force and support the United
States' commitments under the Paris Agreement.
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\10\ See www.whitehouse.gov/ceq/news-updates/2021/12/13/icymi-president-biden-signs-executive-order-catalyzing-americas-clean-energy-economy-through-federal-sustainability/.
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The steam electric sector is one of the largest contributors of
U.S. GHG emissions. Figure IV-1 of this preamble below is reproduced
from EPA's website.\11\ As shown in the figure, EPA estimates that 25
percent of 2020 GHG emissions in the United States came from
electricity generation (largely comprised of emissions from steam
electric power plants). Although this fraction continues to decline,
several models looking at plausible pathways to meet the announced 2030
goal have estimated that substantial additional GHG reductions from
coal combustion will be necessary.\12\
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\11\ See www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
\12\ Bistline, J., Abhyankar, N., Blanford, G., Clarke, L.,
Fakhry, R., Mcjeon, H., Reilly, J., Roney, C., Wilson, T., Yuan, M.,
and Zhao, A. 2022. Actions for reducing US emissions at least 50% by
2030. Policies must help decarbonize power and transport sectors.
Science. Vol 376, Issue 6596. Pg 922-924. May 26. Available online
at: www.science.org/doi/10.1126/science.abn0661.
\13\ Total emissions in 2020 = 5,981 million metric tons of
CO2 equivalent. Percentages may not add up to 100 percent
due to independent rounding.
\14\ Land use, land-use change, and forestry in the United
States is a net sink and removes approximately 13 percent of these
GHG emissions. This net sink is not shown in the above diagram. All
emission estimates are from the Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2020. Available online at: www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks.
[GRAPHIC] [TIFF OMITTED] TP29MR23.059
The GHG reduction targets did not directly impose incentives on
steam electric plants; however, on August 16, 2022, President Biden
signed the IRA into law. The IRA includes many provisions that will
affect the steam electric power generating industry. The IRA provides
tax credits, financing programs, and other incentives that will
accelerate the transition to forms of energy that produce little or no
GHG emissions. An analysis conducted by the Department of Energy (DOE)
shows that tax incentives included in the IRA will increase the growth
of wind and
[[Page 18834]]
solar electricity generation while supporting the maintenance of the
country's existing nuclear power fleet.\15\ Thus, the DOE analysis
suggests the IRA may reduce the number of coal burning power plants in
operation.
---------------------------------------------------------------------------
\15\ See www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf.
---------------------------------------------------------------------------
Based on these DOE analytic results EPA would expect reduced
baseline emissions of air and water pollution, lower total incremental
costs, and lower total incremental benefits of this rule. Lower costs
and benefits would alter the regulatory impact analysis under E.O.
12866 and E.O. 13563. While the impacts of the IRA are not reflected in
the detailed analyses included with this proposal (because the analyses
were completed prior to the passage of the IRA), EPA is evaluating how
the IRA can be incorporated into the baseline of the final rule
(including IPM) and will update the analyses to reflect the IRA for any
final rule. EPA solicits comment on the incorporation of the IRA into
its analyses, including any specific recommendations or data supporting
a particular approach.
EPA does not expect the IRA to affect the current findings of
economic achievability of the rule. To evaluate economic achievability,
EPA considers the costs of the technologies that form the basis for BAT
and uses IPM to assess changes in the power sector, including closures.
As discussed in Section VIII of this preamble, EPA expects the costs of
the technologies discussed here to result in a single coal-fired power
plant closure; thus, the rule would be economically achievable.
C. Control and Treatment Technologies
In general, control and treatment technologies for some
wastestreams have continued to advance since the 2015 and 2020 rules.
Often, these advancements provide plants with additional approaches for
complying with any effluent limitations. In some cases, these
advancements have also decreased the associated costs of compliance.
For this proposal, EPA incorporated updated information and evaluated
several technologies available to control and treat FGD wastewater, BA
transport water, CRL, and legacy wastewater generated by the steam
electric industry. See Section VIII of this preamble for details on
updated cost information.
1. FGD Wastewater
FGD scrubber systems are used to remove sulfur dioxide from flue
gas so it is not emitted into the air. Dry FGD systems use water in
their operation but generally do not discharge wastewater as it is
evaporated during operation, while wet FGD systems produce a wastewater
stream.
Steam electric power plants discharging FGD wastewater currently
employ a variety of wastewater treatment technologies and operating/
management practices to reduce the pollutants associated with FGD
wastewater discharges. EPA identified the following types of treatment
and handling practices for FGD wastewater as part of the 2015 and 2020
rules:
Chemical precipitation. Chemicals are added as part of the
treatment system to help remove suspended solids and dissolved solids,
particularly metals. The precipitated solids are then removed from
solution by coagulation/flocculation followed by clarification and/or
filtration. The 2015 and 2020 rules focused on a specific design that
employs hydroxide precipitation, sulfide precipitation (organosulfide),
and iron coprecipitation to remove suspended solids and to convert
soluble metal ions to insoluble metal hydroxides or sulfides. Chemical
precipitation was part of the BAT technology basis for the effluent
limitations in the 2015 and 2020 rule.
High hydraulic residence time biological reduction (HRTR).
EPA identified three types of biological treatment systems used to
treat FGD wastewater: anoxic/anaerobic fixed-film bioreactors (which
target removals of nitrogen compounds and selenium), anoxic/anaerobic
suspended growth systems (which target removals of selenium and other
metals), and aerobic/anaerobic sequencing batch reactors (which target
removals of organics and nutrients). An anoxic/anaerobic fixed-film
bioreactor designed to remove selenium and nitrogen compounds using
high hydraulic residence times of approximately 10 to 16 hours was the
BAT technology basis for the effluent limitations in the 2015 rule.
Low hydraulic residence time biological reduction (LRTR).
A biological treatment system that targets removal of selenium and
nitrate/nitrite using fixed-film bioreactors in smaller, more compact
reaction vessels. This system differs from the HRTR biological
treatment system evaluated in the 2015 rule, in that the LRTR system is
designed to operate with a shorter residence time (approximately one to
four hours, compared to a residence time of 10 to 16 hours for HRTR),
while still achieving significant removal of selenium and nitrate/
nitrite. LRTR was the BAT technology basis for the effluent limitations
in the 2020 rule.
Membrane filtration. A membrane filtration system (e.g.,
microfiltration, ultrafiltration, nanofiltration, forward osmosis (FO),
electrodialysis reversal (EDR), or reverse osmosis (RO)) designed
specifically for high TDS and TSS wastestreams. These systems are
designed to minimize fouling and scaling associated with industrial
wastewater. These systems typically use pretreatment for potential
scaling agents (e.g., calcium, magnesium, sulfates) combined with one
or more type of membrane technology to remove a broad array of
particulate and dissolved pollutants from FGD wastewater. The membrane
filtration units may also employ advanced techniques, such as vibration
or creation of vortexes to mitigate fouling or scaling of the membrane
surfaces. Membrane filtration can achieve zero discharge by
recirculating permeate from the RO system back into plant operations.
Spray evaporation. Spray evaporation technologies, which
include spray dry evaporators (SDEs) and other similar proprietary
variations, evaporate water by spraying fine misted wastewater into hot
gasses. The hot gasses allow the water to evaporate before contacting
the walls of an evaporation vessel, treating wastewater across a range
of water quality characteristics such as TDS, TSS, or scale forming
potential. Spray evaporation technologies use a less complex treatment
configuration than brine concentrator and crystallizer systems (see the
description of thermal evaporation systems) to evaporate water by a
heat source, such as a slipstream of hot flue gas or an external
natural gas burner. Spray evaporation technologies can be used in
combination with other volume reduction technologies, such as
membranes, to maximize the efficiency of each process. Concentrate from
the RO system can then be processed through the spray evaporation
technology to achieve zero discharge by recirculating permeate from the
RO system back into plant operations.
Thermal evaporation. Thermal evaporation systems that use
a falling-film evaporator (or brine concentrator), following a
softening pretreatment step, to produce a concentrated wastewater
stream and a distillate stream to reduce wastewater volume by 80 to 90
percent and reduce the discharge of pollutants. The concentrated
wastewater is usually further processed in a crystallizer that produces
a solid residue for landfill disposal and additional distillate that
can be reused within the plant or discharged. These systems are
designed
[[Page 18835]]
to remove the broad spectrum of pollutants present in FGD wastewater to
very low effluent concentrations.
Some plants operate their wet FGD systems using approaches
that eliminate the discharge of FGD wastewater. These plants use a
variety of operating and management practices to achieve this,
including the following:
--Complete recycle. The FGD Wastestream is allowed to recirculate.
Particulates (e.g., precipitates and other solids) are removed and
landfilled. Water is supplemented when needed to replace that
evaporated or removed with landfilled solids. This process does not
produce a saleable product (e.g., wallboard grade gypsum) but it does
not need a wastewater purge stream to maintain low levels of chloride.
--Evaporation impoundments. Some plants located in warm, dry climates
have been able to use surface impoundments as holding basins where the
FGD wastewater is retained until it evaporates. The evaporation rate
from the impoundments at these plants is greater than the flow rate of
the FGD wastewater and amount of precipitation entering the
impoundments; therefore, there is no discharge to surface water.\16\
These impoundments must be large enough to accommodate extreme
precipitation events to prevent overtopping and runoff.
---------------------------------------------------------------------------
\16\ Such impoundments must be lined based on the requirements
in the CCR rule. This would significantly reduce the potential of a
discharge to groundwater.
---------------------------------------------------------------------------
--FA conditioning. Many plants that operate dry FA handling systems
will utilize the water from their FGD system in the FA handling system
to suppress dust or improve handling and/or compaction characteristics
in an on-site landfill.
--Combination of wet and dry FGD systems. The dry FGD process involves
atomizing and injecting wet lime slurry, which ranges from
approximately 18 to 25 percent solids, into a spray dryer. The water
contained in the slurry evaporates from the heat of the flue gas within
the system, leaving a dry residue that is removed from the flue gas by
a fabric filter (i.e., baghouse) or electrostatic precipitator.
--Underground injection. These systems dispose of wastes by injecting
them into a permitted underground injection well as an alternative to
discharging wastewater to surface waters.
EPA also collected new information on other FGD wastewater
treatment technologies, including direct contact thermal evaporators
and ion exchange. These treatment technologies have been evaluated, in
full- or pilot-scale, or are being developed to treat FGD wastewater.
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.\17\ Some plants use water
to transport (sluice) the BA from the hopper to an impoundment or
dewatering bins. The water used to transport the BA to the impoundment
or dewatering bins is usually discharged to surface water as overflow
from the systems after the BA has settled to the bottom. The industry
also uses the following BA handling systems that generate BA transport
water:
---------------------------------------------------------------------------
\17\ Consistent with the 2015 and 2020 rule, boiler slag is
considered BA.
---------------------------------------------------------------------------
Remote mechanical drag system (MDS). These systems
transport BA to a remote MDS using the same processes as wet-sluicing
systems. A drag chain conveyor pulls the BA out of the water bath on an
incline to dewater the BA. The system can either be operated as a
closed-loop system (technology basis for the 2015 rule) or a high
recycle rate system (technology basis for the 2020 rule).\18\
---------------------------------------------------------------------------
\18\ In some cases, additional treatment may be necessary to
maintain a closed-loop system. This additional treatment could
include polymer addition to enhance removal of suspended solids or
membrane filtration of a slip stream to remove dissolved solids.
---------------------------------------------------------------------------
Mobile MDS. This technology is a smaller, mobile version
of a remote MDS with an additional clarification system. It is not
intended to be a permanent installation, allowing for the reduction of
capital costs as facility needs allow. Once in place, the system works
like a remote MDS--the incoming water is clarified and primary
separation occurs. The clarified water is taken from the mechanical
drag system to a mobile clarifier and polished to a level suitable for
recirculation. The mobile clarifier thickens the collected solids,
which are then sent back to the mechanical drag system portion and
mixed with coarse BA. This mixture is sent up an incline, dewatered,
and disposed of.
Dense slurry system. These systems use a dry vacuum or
pressure system to convey the BA to a silo (as described below for the
``Dry Vacuum or Pressure System''), but instead of using trucks to
transport the BA to a landfill, the plant mixes the BA with a lower
percentage of water compared to a wet-sluicing system and pumps the
mixture to the landfill.
As part of the 2020 rule and this proposed rule, EPA identified the
following BA handling systems that do not, by definition or practice,
generate BA transport water.
MDS. These systems are located directly underneath the
boiler. The BA is collected in a water quench bath. A drag chain
conveyor pulls the BA out of the water bath along an incline to dewater
the BA.
Dry mechanical conveyor. These systems are located
directly underneath the boiler. The system uses ambient air to cool the
BA in the boiler and then transports the ash out from under the boiler
using a conveyor. There is no water used in this process.
Dry vacuum or pressure system. These systems transport BA
from the boiler to a dry hopper without using any water. Air is
percolated through the ash to cool it and combust unburned carbon.
Cooled ash then drops to a crusher and is conveyed via vacuum or
pressure to an intermediate storage destination.
Vibratory belt system. These systems deposit BA on a
vibratory conveyor trough, where the ash is air-cooled and ultimately
moved through the conveyor deck to an intermediate storage destination
without using any water.
Submerged grind conveyor. These systems are located
directly underneath the boiler and are designed to reuse slag tanks,
ash gates, clinker grinders, and transfer enclosures from the existing
wet sluicing systems. The system collects BA from the discharge of each
clinker grinder. A series of submerged drag chain conveyors transport
and dewater the BA.
See Section 4.2 of the Supplemental TDD for more information on
these technologies.
3. CRL
In promulgating the 2015 rule, EPA determined that combustion
residual leachate from landfills and impoundments includes similar
types of constituents as FGD wastewater, albeit at potentially lower
concentrations and smaller volumes. Based on this characterization of
the wastewater and knowledge of treatment technologies, EPA determined
that certain treatment technologies identified for FGD wastewater could
also be used to treat leachate from landfills and impoundments
containing combustion residuals. These technologies, described in
Section V.C.1, of this preamble include chemical precipitation,
[[Page 18836]]
biological treatment (including LRTR), membrane filtration, spray
evaporation, or other thermal treatment options. EPA also identified
other management and reuse strategies from responses to the 2010
Questionnaire for the Steam Electric Power Generating Effluent
Guidelines, or steam electric survey, that included using CRL from
either an impoundment or landfill for moisture conditioning FA, dust
control, or truck wash. EPA also identified plants that collect CRL
from impoundments and recycle it directly back to the impoundment.
4. Legacy Wastewater
Legacy wastewater can be comprised of FGD wastewater, BA transport
water, FA transport water, CRL, gasification wastewater and/or FGMC
wastewater generated before the ``as soon as possible'' date that more
stringent effluent limitations from the 2015 or 2020 rules would apply.
Discharges of legacy wastewater may occur through an intermediary
source (e.g., a tank or surface impoundment) or directly into a surface
waterbody (see Section VII.B.4 of this preamble). The record indicates
that the following technologies can be applied to treat this type of
legacy wastewater: chemical precipitation, biological treatment
(including LRTR), membrane filtration, spray evaporation, or other
thermal treatment options. These technologies are described in Section
V.C.1 of this preamble. Another option, which may be used in
combination with other systems such as chemical and physical treatment,
is zero valent iron (ZVI).
ZVI. This technology can be used to target specific
inorganics, including selenium, arsenic, nitrate, and mercury in this
type of legacy wastewater. The technology entails mixing influent
wastewater with ZVI (iron in its elemental form), which reacts with
oxyanions, metal cations, and some organic molecules in wastewater. ZVI
causes a reduction reaction of these pollutants, after which the
pollutants are immobilized through surface adsorption onto iron oxide
coated on the ZVI or generated from oxidation of elemental iron. The
coated, or spent, ZVI is separated from the wastewater with a
clarifier. The quantity of ZVI required and number of reaction vessels
can vary based on the composition and amount of wastewater being
treated.
EPA recognizes that the characterization of legacy wastewater
differs within the layers of a CCR impoundment as it is dewatered and
prepared for closure. Therefore, treatment requirements may change as
closure continues. Wastewater characteristics also differ across CCR
impoundments due to different types of fuels burned at the plant,
duration of pond operation, and ash type. The list of treatment
technologies identified for legacy wastewater above are all applicable
to all legacy wastewaters; however, treatment may require a combination
of those technologies (e.g., chemical precipitation and membrane
filtration).
In addition, solids dewatering is necessary to dredge CCR materials
from the impoundment. Mobile dewatering systems are typically self-
contained units on a trailer, allowing for the entire system to be
easily moved on-site and off-site. Legacy wastewater from a holding
area (e.g., pit, pond, collection tank) is pumped through a filter
press to generate a filter cake and water stream. A shaker screen can
be added to the treatment train to remove larger particles prior to the
filter press. Furthermore, the filter press can be equipped with
automated plate shifters to allow solids to drop from the end of the
trailer directly into a loader or truck. The resulting wastestream may
be further treated to meet any discharge requirements.
VI. Data Collection Since the 2020 Rule
A. Information From the Electric Utility Industry
1. Data Requests and Responses
In January 2022, EPA requested the following pollution treatment
system performance and cost information for coal-fired power plants
from three steam electric power companies:
FGD wastewater installations of the following
technologies: thermal technology; membrane filtration technology;
paste, solidification, or encapsulation of FGD wastewater brine;
electrodialysis; and electrocoagulation.
Overflow from an MDS, a compact submerged conveyor (CSC),
or remote MDS installations, including purge rate and management from
remote MDS systems, as well as any pollutant concentration data to
characterize the overflow or purge.
CRL treatment from on-site or off-site testing (full-,
pilot-, or laboratory-scale).
On-site or off-site testing (full-, pilot-, or laboratory-
scale) and/or implementation of treatment technologies associated with
surface impoundment decanting or dewatering treatment.
Costs associated with these technologies.
In addition, EPA sent four additional power companies a voluntary
request inviting them to provide the same data described above after
EPA had met with these companies.
2. Meetings With Individual Utilities
To gather information to support this supplemental proposed rule,
EPA met with representatives from four utilities. Two of these
utilities reached out to EPA after the announcement of the supplemental
rule. EPA contacted the remaining utilities due to their known or
potential consideration of membrane filtration. At these meetings, EPA
discussed the operation of the utility's coal-fired generating units
and the treatment and management of BA transport water, FGD wastewater,
legacy wastewater, and CRL since the 2020 rule. EPA learned about
updates associated with plant operations and studies that were
originally discussed during the 2015 and 2020 rules.
The specific objectives of these meetings were to gather general
information about coal-fired power plant operations; pollution
prevention and wastewater treatment system operations; ongoing pilot or
laboratory scale study information for FGD wastewater treatment; BA
system performance, characterization, and quantification of the
overflow and purge from remote MDS installations; and treatment
technologies and pilot testing associated with CRL and legacy
wastewater. EPA used this information to supplement the data collected
in support of the 2015 and 2020 rules.
3. Voluntary CRL Sampling
In December 2021, EPA invited eight steam electric power companies
to participate in a voluntary program designed to obtain data to
supplement the wastewater characterization data set for CRL. EPA
requested these data from facilities believed to have constructed new
landfills pursuant to the 2015 CCR rule. Six power companies chose to
participate in this program.
4. Electric Power Research Institute Voluntary Submission
The Electric Power Research Institute (EPRI) conducts industry-
funded studies to evaluate and demonstrate technologies that can
potentially remove pollutants from wastestreams or eliminate
wastestreams using zero discharge technologies. Following the 2015
rule, EPA reviewed 35 reports published between 2011 and 2018 that EPRI
voluntarily provided regarding characteristics of FGD wastewater, FGD
wastewater treatment pilot studies, BA transport water
characterization, BA handling practices, halogen addition rates, and
the effect of halogen additives on FGD wastewater. For this
[[Page 18837]]
supplemental proposed rule, EPRI provided an additional 25 reports
generated in the intervening years. EPA used information presented in
these reports to inform the development of numeric effluent limitations
for FGD wastewater and to update methodologies for estimating costs and
pollutant removals associated with candidate treatment technologies.
5. Meetings With Trade Associations
In 2021 and 2022, EPA met with the Edison Electric Institute and
the American Public Power Association. These trade associations
represent investor-owned utilities and community-owned utilities,
respectively. They provided information and perspectives on the current
status of many utilities transitioning away from coal.
B. Notices of Planned Participation
The 2020 rule required facilities to file a notice of planned
participation (NOPP) with their permitting authority no later than
October 13, 2021, if the facility wished to participate in the LUEGU
subcategory, the permanent cessation of coal combustion subcategory, or
in the VIP (see 40 CFR 423.19(e), (f), and (h), respectively). While
EPA did not require that a copy be provided to the Agency, EPA
nevertheless obtained a number of these filings. Some facilities
provided EPA a courtesy copy when filing with the relevant permitting
authority. The Agency received notice of other filings as part of its
standard permit review process when a state permitting authority sent
new draft permits or modifications to EPA for review. EPA also asked
some states for NOPPs after those states asked EPA questions about the
process or initiated discussions about specific plants. Environmental
groups who had been tracking NOPPs at specific plants and states also
shared with EPA the information they had collected.
EPA is currently aware of NOPPs covering 90 EGUs at 38 plants. Of
these, four EGUs (at two plants) have requested participation in the
LUEGU subcategory, an additional 12 EGUs (at four plants) have
requested participation in the 2020 rule VIP, and the remaining 74 EGUs
(at 33 plants) have requested participation in the permanent cessation
of coal combustion subcategory.\19\ EPA cautions that these counts are
not a comprehensive picture of what facilities' plans are for two
reasons. First, EPA was unable to obtain information for all plants and
states, and thus solicits comment on whether the public is aware of
additional NOPPs that are not yet known to the Agency. Second, even
where a facility has filed a NOPP, it still retains the flexibility
under the transfer provisions of 40 CFR 423.13(o) to transfer between
subcategories, or between a subcategory and the 2020 VIP provisions
until 2023 or 2025 (depending on the transfer desired). EPA therefore
solicits comment on additional information that would inform the
Agency's understanding of facilities' plans under the 2020 rule. For
further detail, the NOPPs EPA is aware of have been placed in the
docket along with a memo summarizing the information and providing
record index numbers for locating each facility, entitled Changes to
Industry Profile for Coal-Fired Generating Units for the Steam Electric
Effluent Guidelines Proposed Rule (SE10241).
---------------------------------------------------------------------------
\19\ Plant Scherer filed a permanent cessation of coal
combustion NOPP for two EGUs and a 2020 rule VIP NOPP for the
remaining two EGUs; thus, the plant count for the three groupings
does not equal 38.
---------------------------------------------------------------------------
C. Information From Technology Vendors and Engineering, Procurement,
and Construction Firms
EPA gathered data on the availability and effectiveness of FGD
wastewater, BA handling, CRL, and pond dewatering operations and
wastewater treatment technologies in the industry from technology
vendors and Engineering, Procurement, and Construction firms through
presentations, conferences, meetings, and email and phone contacts.
These collected data informed the development of the technology costs
and pollutant removal estimates for FGD wastewater, BA transport water,
CRL, and legacy wastewater.
D. Other Data Sources
EPA gathered information on steam electric generating facilities
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 2019 and 2020
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 internet searches to identify or confirm reports of planned
facility plant and EGU retirements and reports of planned unit
conversions to dry or closed-loop recycle ash handling systems. EPA
used this information to inform the industry profile and identify
process modifications occurring in the industry.
VII. Proposed Regulation
A. Description of the Options
This proposal evaluates four regulatory options and identifies one
preferred option (Option 3), as shown in Table VII-1 of this preamble.
All options include the same technology basis for CRL (chemical
precipitation) and legacy wastewater (best professional judgment) while
incrementally increasing controls on FGD wastewater, BA transport
water, or both. Each successive option from Option 1 to 4 would achieve
a greater reduction in wastewater pollutant discharges. Each
subcategorization is described further in Section VII.C of this
preamble. In addition to some specific requests for comment included
throughout this proposal, EPA solicits comment on all aspects of this
proposal, including the information, data, and assumptions EPA relied
upon to develop the four regulatory options, as well as the proposed
BAT, effluent limitations, and alternate approaches included in this
proposal.
1. FGD Wastewater
Under Option 1, EPA proposes to eliminate the BAT and PSES
subcategorizations for high FGD flow facilities and LUEGUs. Option 1
would establish the same mercury, arsenic, selenium, and nitrogen
limitations applicable to the industrial category based on chemical
precipitation, followed by low hydraulic residence time biological
treatment and ultrafiltration. Under Options 2 and 3, EPA proposes to
eliminate the BAT and PSES subcategorizations for high FGD flow
facilities and LUEGUs and further proposes to require zero discharge of
FGD wastewater based on chemical precipitation followed by membrane
filtration with 100 percent recycle of the permeate. These proposed
options would also create a subcategory for early adopters that have
already installed compliant biological treatment systems and would
retire no later than December 31, 2032. Under Option 4, EPA proposes to
establish an industrywide zero-discharge requirement without
establishing an early adopter subcategory. Note that for all four
options EPA proposes to retain the subcategory for EGUs permanently
ceasing coal combustion by 2028.
[[Page 18838]]
2. BA Transport Water
Under Options 1 and 2, EPA proposes to eliminate the BAT and PSES
subcategorization for LUEGUs. Options 1 and 2 would establish the same
volumetric purge limitation applicable to the industrial category based
on high recycle rate systems. Under Option 3, EPA proposes zero
discharge based on dry handling or closed-loop systems. This proposed
option would also create a subcategory for early adopters that have
already installed a compliant high recycle rate system and would retire
no later than December 31, 2032. Under Option 4, EPA proposes to
establish an industrywide zero-discharge requirement without
establishing an early adopter subcategory. For all four options, EPA
proposes to retain the subcategory for EGUs permanently ceasing coal
combustion by 2028.
3. CRL
Under all four options, EPA proposes to establish BAT limitations
and PSES for mercury and arsenic based on chemical precipitation
treatment.
4. Legacy Wastewater
Under all four options, EPA proposes not to specify a nationwide
technology basis for BAT/PSES applicable to legacy wastewater at this
time, but rather proposes that such limitations are to be derived on a
site-specific basis by the permitting authorities, using their BPJ. EPA
does solicit comment on other options, as discussed below.
Table VII-1--Main Regulatory Proposed Options
--------------------------------------------------------------------------------------------------------------------------------------------------------
Technology Basis for the BAT/PSES Regulatory Options
Wastestream Subcategory --------------------------------------------------------------------------------------------
1 2 3 (Preferred) 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
FGD wastewater..................... N/A................... Chemical precipitation Chemical Chemical Chemical
+ biological precipitation + precipitation + precipitation +
treatment + membrane filtration. membrane filtration. membrane filtration.
ultrafiltration.
High FGD flow NS.................... NS................... NS................... NS.
facilities/LUEGUs.
EGUs permanently Surface impoundments.. Surface impoundments. Surface impoundments. Surface impoundments.
ceasing coal
combustion by 2028.
Early adopters NS.................... Chemical Chemical NS.
permanently ceasing precipitation + precipitation +
coal combustion by biological treatment biological treatment
2032. + ultrafiltration. + ultrafiltration.
BA transport water................. N/A................... High recycle rate High recycle rate Dry handling or Dry handling or
systems. systems. closed-loop systems. closed-loop systems.
LUEGUs................ NS.................... NS................... NS................... NS.
EGUs permanently Surface impoundments.. Surface impoundments. Surface impoundments. Surface impoundments.
ceasing coal
combustion by 2028.
Early adopters NS.................... NS................... High recycle rate NS.
permanently ceasing systems.
coal combustion by
2032.
CRL................................ N/A................... Chemical precipitation Chemical Chemical Chemical
precipitation. precipitation. precipitation.
Legacy wastewater.................. N/A................... Best professional Best professional Best professional Best professional
judgment. judgment. judgment. judgment.
--------------------------------------------------------------------------------------------------------------------------------------------------------
N/A = Not applicable.
NS = Not subcategorized.
Note: The table above does not present existing subcategories included in the 2015 rule or the 2020 VIP for FGD wastewater. EPA is not proposing any
changes to the existing 2015 rule subcategorization of oil-fired units, units with a nameplate capacity of 50 MW or less, or the 2020 VIP.
B. Rationale for the Proposed Rule
In light of the criteria and factors specified in CWA sections
301(b)(2)(A) and 304(b)(2)(B) (see Section IV of this preamble, above),
EPA proposes to establish BAT effluent limitations based on the
technologies described in Option 3.\20\
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\20\ EPA proposes to include language in the final rule that
makes clear that if any provisions of the final rule are reviewed
and vacated by a court, it is EPA's intent that as many portions of
the rule remain in effect as possible.
---------------------------------------------------------------------------
1. FGD Wastewater
EPA is proposing chemical precipitation, followed by membrane
filtration, as the technology basis for establishing BAT limitations to
control pollutants discharged in FGD wastewater. After considering the
factors specified in CWA section 304(b)(2)(B), EPA proposes to find
that this technology is technologically available, economically
achievable, and has acceptable non-water quality environmental impacts.
More specifically, the technology basis for BAT would include chemical
precipitation to remove suspended solids and scaling compounds prior to
treatment with one or more stages of nanofiltration, electrodialysis
reversal (EDR), RO, and/or forward osmosis. The permeate from the final
stage of treatment would then be recycled back into the plant either as
FGD makeup water or boiler makeup water.\21\
---------------------------------------------------------------------------
\21\ The 2020 rule finalized an exemption from the definition of
FGD wastewater applicable to ``treated FGD wastewater permeate or
distillate used as boiler makeup water.''
---------------------------------------------------------------------------
In the subsection immediately below, EPA discusses its rationale
for proposing membrane filtration as BAT for the control of FGD
wastewater. In the following subsection, EPA discusses why it is not
proposing as its main option other zero discharge technologies as BAT
but is taking comment on such technologies. In the final subsection,
EPA discusses why it is not proposing a less stringent technology as
BAT.
[[Page 18839]]
a. Membrane Filtration
Availability of membrane filtration. EPA is proposing to determine
that membrane filtration is available for use by the steam electric
industry to control discharges of FGD wastewater. Such a finding is
consistent with the technology forcing nature of BAT as described in
the legislative history and legal precedents discussing this provision.
``In setting BAT, EPA uses not the average plant, but the optimally
operating plant, the pilot plant which acts as a beacon to show what is
possible.'' (Kennecott v. EPA, 780 F.2d 445, 448 (4th Cir. 1985)
(citing A Legislative History of the Water Pollution Control Act
Amendments of 1972, 93d Cong., 1st Sess. (Comm. Print 1973), at 798).
BAT is supposed to reflect the highest performance in the industry and
may reflect a higher level of performance than is currently being
achieved based on technology transferred from a different subcategory
or category, bench scale or pilot plant studies, or foreign plants.
Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1006; Am. Paper Inst.
v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); Am. Frozen Food Inst. v.
Train, 539 F.2d 107, 132 (D.C. Cir. 1976). BAT may be based upon
process changes or internal controls, even when these technologies are
not common industry practice. See Am. Frozen Foods, 539 F.2d at 132,
140; Reynolds Metals Co. v. EPA, 760 F.2d 549, 562 (4th Cir. 1985);
California & Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir.
1977). As recently reiterated by the U.S. Court of Appeals for the
Fifth Circuit, ``Under our precedent, a technological process can be
deemed available for BAT purposes even if it is not in use at all, or
if it is used in unrelated industries. Such an outcome is consistent
with Congress'[s] intent to push pollution control technology.''
Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1031 (citation and
internal quotations omitted).
As further discussed below, EPA is proposing to base its
determination that membrane filtration is available for control of
pollutants found in FGD wastewater on the numerous full-scale foreign
installations of membrane filtration to treat FGD wastewater, the large
number of successful domestic and international pilot tests of membrane
filtration on FGD wastewater, successful use of membrane filtration on
other steam electric wastestreams, and the use of membrane filtration
on wastestreams in a many different industries besides the steam
electric industry.
In the 2020 rule, EPA determined that membrane filtration was not
available to control FGD wastewater industrywide, primarily due to the
lack of a full-scale membrane filtration system in use to control FGD
wastewater discharges at a U.S. facility. There was also discussion of
possible uncertainties or data gaps in the record regarding foreign
plants, pilot tests, or use of membrane filtration on other
wastestreams. When EPA promulgated the 2020 rule, however, the Agency
was aware of membrane filtration being successfully used on FGD
wastewater at 12 foreign plants, on FGD wastewater in 20 domestic
pilots, and on several wastestreams with characteristics similar to
those of FGD wastewater both within the steam electric sector and in
other industries. The language and intent of the CWA, repeatedly
confirmed by Federal appellate courts, demonstrates that Congress
intended that BAT reflect the best performing plant (see, e.g.,
Kennecott v. EPA, 780 F.2d. at 447; Southwestern Elec. Power Co. v.
EPA, 920 F.3d at 1018). Accordingly, some might argue that the amount
of information in the 2020 record was sufficient to support a finding
of membrane filtration as BAT for control of FGD wastewater discharges.
Based on EPA's current record, which contains additional information
regarding the application of membrane filtration to FGD wastewater and
other wastestreams inside and outside the steam electric industry,\22\
the weight of the evidence supports the Agency's proposed conclusion
that membrane filtration is available in the industry to control FGD
wastewater discharges, notwithstanding the uncertainties raised in the
2020 rule. Agencies have inherent authority to reconsider past
decisions and to revise, replace, or repeal a decision to the extent
permitted by law and supported by a reasoned explanation. FCC v. Fox
Television Stations, Inc., 556 U.S. 502, 515 (2009); Motor Vehicle
Mfrs. Ass'n v. State Farm Mutual Auto. Ins. Co., 463 U.S. 29, 42
(1983). Thus, for the following reasons, EPA proposes coming to a
different conclusion regarding the availability of membrane filtration
than in it did in the 2020 rule.\23\
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\22\ Caselaw supports that EPA may base BAT on technologies used
in other industries. See, e.g., Kennecott v. EPA, 780 F.2d at 453
(``Congress envisioned the scanning of broader horizons and asked
EPA to survey related industries and current research to find
technologies which might be used to decrease the discharge of
pollutants.'').
\23\ EPA also recognizes that, while it may change policies
based upon a reasoned explanation, where a prior policy has
engendered serious reliance interests, those interests must be taken
into account. FCC v. Fox Television Stations, Inc., 556 U.S. at 515
(citation omitted). EPA has taken reliance interests into account in
this rulemaking, as is clear from EPA's proposal in Section VII.C.4
of this preamble, below, to create a new subcategory for early
adopters who relied on certain of EPA's past determinations. EPA
also notes that no NPDES permittee has certainty of its limitations
beyond its 5-year NPDES permit term, as reissued permits must
incorporate any newly promulgated technology-based limitations as
well as potentially more stringent limitations necessary to achieve
water quality standards. See 40 CFR 122.44(a) & (d).
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International installations. At the time of the 2020 rule, the
Agency cited 12 foreign installations of membrane filtration on FGD
wastewater.\24\ These systems began operating as early as 2015, and all
of the systems were designed to operate as zero discharge systems.\25\
Since the 2020 rule, EPA has become aware of additional information
about these international installations that supports its proposed
determination that membrane filtration is available for control of FGD
wastewater discharges. In particular, the Agency has learned that
certain Chinese facilities with membrane installations have
successfully achieved zero discharge of FGD wastewater, in part by
adjusting the ratios and dosages of the specific chemicals used in
their chemical precipitation pretreatment systems.\26\ EPA also has
learned that certain Chinese plants with later installations did not
need to pilot membrane filtration systems before successfully
installing and operating them at full scale. The operating information
from the previous installations was sufficient to successfully install
a full-scale membrane system without the need for an intermediate
pilot.\27\
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\24\ ERG, 2020. Technologies for the Treatment of Flue Gas
Desulfurization Wastewater. DCN SE09218.; ERG, 2020. Notes from Call
with DuPont. DCN SE08618.; Beijing Jingneng Power. 20177. Beijing
Jingneng Power Company, Ltd. Announcement on Unit No. 1 of the Hbei
Shuoshou Jingyuan Thermal Power Co., Ltd. Passing Through the 168-
hours Trial Operation. (13 November). DCN SE08624.; Broglio, Robert.
2019. Doosan. Vendor FGD Wastewater Treatment Details--Doosan. (15
July). DCN SE07107.; Lenntech. 2020. Lenntech Water Treatment
Solutions. Flue Gas Desulfurization Treatment. DCN SE08622.;
Nanostone. 2019. China Huadian Jiangsu Power Jurong Power Plant FGD
Wastewater Zero Liquid Discharge Project was Awarded the Engineering
Star Award. (27 June). DCN SE08628.
\25\ Technologies for the Treatment of Flue Gas Desulfurization
Wastewater, Coal Combustion Residual Leachate, and Pond Dewatering
(SE10281).
\26\ SE06915.
\27\ SE08618.
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In the 2020 rule, EPA stated that there were too many unknowns
about the foreign installations to support a finding of availability,
including not knowing enough about their configurations, operations,
performance, or long-term maintenance. These American-made systems have
continued to operate since the 2020 rule, with the oldest now
[[Page 18840]]
operating for seven years. This continued operation suggests that EPA's
concerns in 2020 may have been overstated. Additional data on foreign
system configurations and operations have also enhanced the Agency's
understanding of these systems.\28\ Particularly, EPA was able to learn
more about the issues with pretreatment identified at the pilot stage
for one of the first Chinese installations. These issues were a result
of the FGD wastewater's high suspended solids and high hardness. While
these issues were identified at the outset of pilot testing, they were
sufficiently resolved through adjustment of the chemical precipitation
pretreatment process, leading the facility to install the system at
full scale. For later installations at different sites, this Chinese
utility ceased conducting pilot tests since appropriate pretreatment
steps had already been identified.
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\28\ SE10245.
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In the 2020 rule, EPA also stated that there was not enough
information to know if the foreign installations could continually
operate as zero discharge systems or whether there would be some
periods during which discharges occur. EPA notes that two additional
years of zero discharge operation for these foreign plants have
occurred since the 2020 rule, which supports a finding that continuous
zero discharge operations are achievable. As discussed in Section XIV
of this preamble, while EPA proposes zero discharge of pollutants in
FGD wastewater, the Agency solicits comment on alternative membrane
filtration-based BAT limitations if comments demonstrate that a regular
or intermittent discharge is necessary for some plants. For the reasons
discussed above, the installation and operation of membrane filtration
to treat FGD wastewater abroad supports the proposed BAT basis of
membrane filtration for FGD wastewater discharges.
Pilot applications. Although EPA has sufficient information to
propose that membrane filtration is available based on foreign
installations alone, pilot applications also support the availability
of membrane filtration for control of FGD wastewater discharges. In the
2020 rule record, the Agency cited 20 pilot applications of membrane
filtration on FGD wastewater (19 domestic and one international).\29\
While EPA stated that there were data gaps associated with the pilot
studies that prevented a finding that membrane filtration is available,
these gaps primarily related to the development of numeric limitations,
and EPA nevertheless established limitations based on membrane
filtration technology in the VIP. Furthermore, the record showed that
membrane filtration pilots in the United States have demonstrated
success removing pollutants from FGD wastewater under a number of
pretreatment settings, whether performed without chemical precipitation
pretreatment, with chemical precipitation pretreatment, or following
biological treatment.\30\ While specifics of these reports are claimed
as CBI, EPA notes that the authors of several pilot test reports gave
glowing reviews of the technology and detailed a number of advantages
that membrane filtration offered versus biological treatment.
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\29\ One of the systems EPA was aware of for the 2020 rule was a
long-term pilot project at one facility, which is a commercial-scale
system that may have sufficient capacity to treat the full FGD
wastestream moving forward. Nevertheless, because the company is
still making changes to the operation of the plant's FGD system, has
also pilot tested a biological treatment system, and has continued
to leave the possibility of biological treatment for compliance
open, EPA defers to the company's characterization of this system as
a pilot. Thus, it is not considered a domestic, full-scale
installation.
\30\ In one case, a utility conducted a successful membrane
pilot even when there were significant failures in the performance
of upstream pretreatment systems leading to excessive TSS
passthrough to the membrane system.
---------------------------------------------------------------------------
One of these reports, Performance Evaluation of a Vibratory Shear
Enhanced Processing Membrane System for FGD Wastewater Treatment, which
was published in 2014 but recently made publicly available, found that
the piloted membrane filtration technology reliably removed the vast
majority of pollutants in FGD wastewater. This pilot of the Vibratory
Shear Enhanced Processing/Spiral Reverse Osmosis (VSEP/RO) system from
New Logic Research, Inc. was performed at the Water Research Center at
Georgia Power's Plant Bowen. The pilot included operations in both
single pass mode (i.e., continuous operations) and batch mode (focused
on maximizing water recovery) on moderate TDS FGD wastewater and high
TDS VSEP/RO concentrate. As explained in the report, ``The first stage,
VSEP pilot unit, removed approximately 94% TDS, while the second stage,
Spiral RO pilot unit, removed an additional 5.8% TDS, yielding an
overall TDS removal efficiency of 99.8%.'' Furthermore, the system
successfully removed pollutants even when the pollutant concentrations
were increased from an average of approximately 15,000 mg/L TDS to an
average of approximately 54,000 mg/L TDS, demonstrating the versatility
of the system across a range of concentrations. Finally, the system
continued operation without decreased performance due to scaling/
fouling. ``In both modes of operation (single-pass and batch
concentration), no irreversible membrane fouling, no irregular
transmembrane pressure (TMP) increase was observed throughout the
project.'' This appeared to result from a combination of the acid/base
cleanings and the VSEP membrane vibration design/mechanism. This pilot
supports that membrane filtration systems can successfully remove
pollutants under a variety of TDS concentrations and scaling potentials
found in FGD wastewater.
Since the 2020 rule, EPA has also become aware of new information
on three additional domestic pilot applications of membrane filtration
on FGD wastewater. Each of these pilots was performed with a different
technology and demonstrated successful removal of pollutants in FGD
wastewater and recovery of usable permeate. In particular, the first-
of-its-kind domestic pilot of an EDR pilot plant for FGD wastewater
indicates that treatment with membrane filtration has continued to
advance and become more available. This pilot is detailed in EPRI
(2020), which found that ``The Flex EDR Selective pilot plant reliably
operated for 61 days, 24/7, including weekends and unattended
overnights.'' Other key findings included an average 93 percent water
recovery, 98 percent uptime of continuous operations (more than 1440
hours), selective removal of chloride, the elimination of the need for
soda ash softening, ``demonstrated versatility to treat wastewater of
different concentrations and water chemistries with the same treatment
plant,'' and the potential for cost savings when compared to comparable
treatment systems. Thus, the weight of evidence available from a
growing number of pilot studies supports the Agency's proposed
conclusion that membrane filtration is BAT for FGD wastewater
discharges.
Application to other wastestreams. As EPA explained in the 2020
rule, membrane filtration is used in full-scale applications to other
wastestreams in the steam electric power sector and other industrial
sectors. The domestic steam electric power sector regularly uses
membrane filtration for boiler makeup water,\31\ cooling tower
[[Page 18841]]
blowdown,\32\ and ash transport water.\33\ Other industrial sectors
with full-scale membrane filtration applications include the
textiles,\34\ chemical manufacturing,\35\ mining,\36\ agriculture, oil
and gas extraction,\37\ food and beverage,\38\ microelectronics/
semiconductors,\39\ landfills,\40\ and automotive industries.\41\
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\31\ EPRI (Electric Power Research Institute). 2015. State of
Knowledge: Power Plant Wastewater Treatment--Membrane Technologies.
August. 3002002143.
\32\ See, e.g., 5 Daniels, D.G. 2015. Winning the Cooling Tower
Trifecta: Controlling Corrosion, Scale, and Microbiological Fouling.
Power Magazine. August 21. Available online at: www.powermag.com/winning-the-cooling-towertrifecta-controlling-corrosion-scale-andaqmicrobiological-fouling/ (DCN SE09088).
\33\ See, e.g., www.ge.com/in/sites/www.ge.com.in/files/GE_solves_ash%20pond_capacity_issue.pdf (DCN SE09090).
\34\ ERG. 2020 Final Notes from Call with DuPont. DCN SE08618.
\35\ ERG. 2020. Final Notes from Call with DuPont. DCN SE08618.
\36\ 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.
\37\ CH2M Hill. 2010. Review of Available Technologies for the
Removal of Selenium from Water. (June). DCN SE08583.
\38\ U.S. EPA. 2022. Notes from Meeting with BKT--April 9, 2021.
DCN SE010253.
\39\ U.S. EPA. 2022. Notes from Meeting with BKT--April 9, 2021.
DCN SE010253.
\40\ ERG. 2019. Sanitized_Saltworks Vendor Meeting Notes--Final.
DCN SE07089.
\41\ U.S. EPA. 2022. Notes from Meeting with ProChem--April 9,
2021. DCN SE10254.
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In the 2020 rule, EPA stated that some of these other applications
did not show that membrane filtration was available for use on FGD
wastewater by focusing on the differences between specific
characteristics of these individual wastewaters and FGD wastewater.
Information in the 2020 record and the current record, however,
indicates that there are many similarities between FGD and the non-FGD
wastestreams where membranes have been utilized. In the 2020 rule
record, EPA discussed that cooling tower blowdown at steam electric
plants and desalination in oil and gas extraction were examples where
membrane filtration was used in full-scale applications for treating
high TDS wastewaters, a characteristic of FGD wastewater (85 FR at
64664-64665, October 13, 2020). The 2020 rule record also established
that mining wastewaters, which are high in gypsum scaling potential
(another characteristic of FGD wastewater), have been successfully
treated with membrane filtration applications. Finally, the 2020 rule
record established that despite the high variability in ash transport
water (a third characteristic of FGD wastewater), it was successfully
treated with membrane filtration. This information indicates that
membrane filtration can operate effectively on wastestreams that
contain several characteristics of FGD wastewater, including high TDS,
high gypsum scaling potential, and high variability.\42\ Thus, based on
the information gathered in both EPA's prior and current records, the
utilization of membrane technology on other wastestreams supports the
Agency's proposed conclusion that membrane filtration technology is BAT
for FGD wastewater discharges.
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\42\ Use of membrane filtration has since expanded into
additional applications, treating wastewaters and industries beyond
those where it was used at the time of the 2020 rule (e.g., the food
and beverage, microelectronics/semiconductors, landfills, and
automotive industries).
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For all the foregoing reasons, EPA proposes to find that membrane
filtration is technologically available for the control of discharges
in FGD wastewater. Moreover, membrane filtration would make reasonable
further progress toward the Act's goal of eliminating the discharge of
all pollutants because it would result in zero discharge of FGD
wastewater from steam electric power plants.
Economic achievability of membrane filtration. EPA proposes to find
that the costs of membrane filtration for control of FGD wastewater
discharges are economically achievable. Under the CWA, BAT limitations
must be economically achievable. Courts have interpreted that
requirement as a test of whether the regulations can be ``reasonably
borne'' by the industry as a whole. Chem. Mfrs. Ass'n v. EPA, 870 F.2d
177, 262 (5th Cir. 1989); BP Exploration & Oil v. EPA, 66 F.3d 784,
799-800 (6th Cir. 1996); see also Nat'l Wildlife Fed'n v. EPA, 286 F.3d
554, 570 (D.C. Cir. 2002); CPC Int'l Inc. v. Train, 540 F.2d 1329,
1341-42 (8th Cir. 1976), cert. denied, 430 U.S. 966 (1977). ``Congress
clearly understood that achieving the CWA's goal of eliminating all
discharges would cause `some disruption in our economy,' including
plant closures and job losses.'' Chem. Mfrs. Ass'n v. EPA, 870 F.2d at
252 (citations omitted); see also id. at 252 n.337 (reviewing cases in
which courts have upheld EPA's regulations that projected up to 50
percent closure rates). Although the 2020 rule cited the increased cost
of membrane filtration as compared to the selected technology basis as
a reason for rejecting membrane filtration,\43\ the Agency did not go
so far as to find that the costs of membrane filtration were not
economically achievable at that time. EPA proposes to find that the
costs of membrane filtration for FGD wastewater are economically
achievable for the industry as a whole, as discussed further below and
in Sections VII.F and VIII of this preamble.
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\43\ While the relative costs of technologies differ from plant
to plant, new information obtained during the 2022 information
collection confirms what was shown in the 2020 record: that, in some
cases, technologies such as membrane filtration may be less costly
than biological treatment at individual plants even where, on
average, they would be more expensive to the industry as a whole.
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Non-water quality environmental impacts of membrane filtration. EPA
proposes to find that the non-water quality environmental impacts of
membrane filtration are acceptable. For further discussion of these
impacts, see Sections VII.G and X of this preamble. There was one non-
water quality environmental impact that the 2020 rule found was
unacceptable. In that rule, EPA expressed concern that use of membrane
filtration would unacceptably limit the beneficial use of FA. The 2020
rule record and the current record demonstrate that the beneficial use
of FA as an admixture or to replace Portland cement in concrete
provides a substantial environmental benefit. As such, the potential
that using FA to help dispose of brine from membrane filtration would
limit this beneficial use continues to be potentially the most
substantial non-water quality environmental impact when considering
whether membrane filtration is BAT. Nevertheless, in light of the facts
and analyses described in the following paragraphs, EPA proposes to
find that these non-water quality environmental impacts are acceptable,
most importantly because EPA's record indicates that there is
sufficient FA to accommodate both FGD brine encapsulation needs
following membrane filtration of FGD wastewater and the beneficial use
market.
At the outset, EPA notes that the 2020 rule record discusses two
uses of FA: FA fixation and brine encapsulation. FA fixation occurs
when a facility conditions its dry FA with FGD wastewater rather than
fresh makeup water.\44\ The use of FA fixation prior to the 2020 rule
is partly due to the very low costs of FA conditioning compared to
other wastewater treatment technologies for FGD wastewater, as well as
the potential to eliminate the discharge of FGD wastewater. The 2020
rule record also included discussion of brine encapsulation. Brine
encapsulation is the process of mixing raw FGD wastewater or
concentrated
[[Page 18842]]
FGD wastewater brine with FA and lime, which results in pozzolanic
reactions that bind additional pollutants into the final solid matrix.
Since the 2020 rule, additional facilities have evaluated FA fixation
with FGD wastewater and/or encapsulation of FGD wastewater using FA and
lime. In at least one instance, fixation/encapsulation was less costly
than biological treatment. Thus, even without a new regulation
establishing BAT limitations based on membrane filtration, the record
demonstrates that implementation of the baseline 2020 rule has resulted
in the use of some FA for fixation or encapsulation.
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\44\ Conditioning is required to avoid air dispersion of the
fine FA particulates.
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While FA fixation still may be an option for brine management, EPA
evaluated the option most discussed in the record: brine encapsulation.
Since the question in evaluating the impact of brine encapsulation is
not whether the FA needed for these processes will be disposed of, but
to what extent additional disposal curtails the FA available for
beneficial use, EPA conducted an analysis of FA availability entitled
2021 Steam Electric Supplemental Proposed Rule: Fly Ash Availability
(SE10242). This analysis shows that the amount of FA needed to dispose
of membrane filtration's byproduct would not have an unacceptable
impact on the amount of FA that is used for beneficial purposes. In
this analysis, consistent with EPA's costing methodology, the Agency
conservatively assumed that all facilities generate brine from a single
pass of a membrane filtration system, which is then encapsulated with
FA and lime.\45\ In other words, EPA conservatively assumed no further
brine concentration (e.g., additional membrane filtration, or thermal
evaporation) would be performed that would further decrease the amount
of FA needed for encapsulation.
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\45\ While EPA's costs assume a polishing stage RO, the brine
from that system in returned to the first stage system.
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The results of EPA's conservative FA availability analysis support
the finding that there is sufficient FA for the majority of the 22
plants that would be expected to make treatment upgrades to meet the
proposed limitations. Based on EPA's analysis of 2019 and 2020 EIA
data, 20 of these 22 power plants that would be expected to install
membrane filtration under proposed Option 3 have enough FA for
encapsulation before accounting for reported FA sales. For the two
remaining plants, EPA estimates there would be a combined annual FA
deficiency of approximately 240,000 tons. After accounting for reported
FA sales, and assuming these sales continue, EPA estimates that an
additional four power plants may not have enough FA available for
encapsulation--a total of six plants with a combined annual FA
deficiency of approximately 750,000 tons (or approximately one percent
of all fly ash generated). In light of the relatively small on-site FA
deficiency estimated using conservative assumptions and, as discussed
more fully below, the potential for plants to use off-site FA or
additional lime for their brine encapsulation needs or available brine
management alternatives that do not rely on FA or use less FA, EPA
proposes that its estimate of on-site FA that may no longer be
available for beneficial use after implementation of this rule does not
rise to the level of an unacceptable non-water quality environmental
impact.
The 750,000 ton per year shortfall of FA described above is likely
an overestimate for several reasons. First, based on the 2020 EIA data,
coal-fired power plants reported more than 30 million tons of FA
generated annually. While there are increasing FA sales reported each
year, EPA identified more than 100 coal-fired power plants generating
over 9.6 million tons of unsold FA that could be redirected from
disposal towards either encapsulation or other beneficial uses.\46\
Thus, EPA estimates that there is enough FA to accommodate both FGD
brine encapsulation needs and the beneficial use market with millions
of tons still requiring disposal. In the 2020 rule record, GenOn's
plans to install membrane filtration at certain facilities did not
include use of FA from those facilities. Instead, GenOn had plans to
send the brine offsite to be mixed with other FA and lime for disposal
and continued to seek options for beneficial use of the brine.\47\ The
concepts of use of off-site FA or beneficial use of brine are not
unique to GenOn. With respect to alternate FA, the 2022 World of Coal
Ash conference included 10 sessions with abstracts discussing the
harvesting and beneficiation of previously disposed ash.\48\ This
further supports that, after accounting for FA availability across the
entire industry, the non-water quality environmental impacts of
potential FA disposal associated with membrane filtration are
acceptable.
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\46\ EPA also notes that the 2020 rule record failed to
acknowledge that both the American Coal Ash Association and EPA have
historically considered waste stabilization and solidification as a
category of beneficial use. See, e.g., www.acaa-usa.org/wp-content/uploads/coal-combustion-products-use/ACAA-Brochure-Web.pdf.
\47\ Notes from Call with GenOn (SE08614).
\48\ Session abstracts are available online at:
www.woca2022.conferencespot.org/event-data/activity.
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Second, the Agency notes that multiple alternatives exist for
handling the resulting brine that do not involve FA and thus would have
no impact on the beneficial use of FA in other settings. EPA evaluated
alternative scenarios including disposal of brine in a deep injection
well and crystallization to a salt for disposal. With respect to
disposal in a deep injection well, EPA has been encouraging efforts for
water reuse rather than deep well injection, particularly in arid
western climates. Most of the facilities in question here, however, are
located in the Midwest and Southern U.S., places where water reuse may
still be important when feasible, but not to the level that EPA would
find injection to be unacceptable. With respect to crystallization and
disposal of the resultant salt, none of the facilities that currently
generates brine as part of a zero discharge system elects to
encapsulate and dispose of that brine.\49\ Rather, these facilities
send the concentrated brine to a crystallizer, and these resulting salt
crystals can then be disposed of without the use of FA. The costs and
non-water quality environmental impacts of these alternatives are
presented in Alternative Brine Management Methodology (SE10243). The
2015 rule record found crystallization to have acceptable non-water
quality environmental impacts. Based on this most current analysis
along with the 2015 record, EPA proposes to find that these alternative
brine management strategies have acceptable non-water quality
environmental impacts and that, while these costs are higher, they
would be economically achievable.
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\49\ While these systems are thermal systems rather than
membrane systems, the brine generated would not differ substantially
in its ultimate characteristics.
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Third, EPA also notes that the six plants with potentially
insufficient FA may still be able to sell their FA if the brine
encapsulation were performed with additional lime use. EPA notes that
extraction, processing, and transportation associated with additional
lime use would result in some additional air emissions, but that these
emissions would be less than those associated with Portland cement, the
material that FA replaces in its most environmentally beneficial use.
Fourth, EPA's estimates regarding non-water quality environmental
impacts associated with membrane filtration's byproduct are likely
conservative (an overestimate) because, even where encapsulation will
be the
[[Page 18843]]
ultimate brine management scenario, further concentration of the brine
is not only possible, but probable for at least some facilities. For
example, one utility evaluating 2020 rule VIP-compliant systems for a
specific facility discussed how it would send the membrane reject brine
to a thermal system to further reduce the volume of FGD brine to be
encapsulated. This process would result in less demand for FA due to
the decreased volume of brine.
Finally, the 2020 record indicated that the management of FGD brine
could actually lead to new beneficial uses. At least one Chinese plant
was taking its brine down to salts and then selling its salts for an
industrial use.\50\ Where companies are ultimately able to beneficially
use some of the brine in lieu of disposal, this would be a positive
non-water quality environmental impact. Thus, both ongoing evaluation
and historical practice indicate EPA's assumptions regarding FA use to
encapsulate FGD brine is likely a conservative estimate of the amount
of ash that will be diverted from beneficial use to disposal. All of
the above information supports EPA's proposed finding that the non-
water quality environmental impacts of membrane filtration are
acceptable.
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\50\ Final DuPont Meeting Notes (SE08618), Notes from Vendor
Call with DuPont October 29 and December 8, 2021 (SE10245).
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b. Other Zero Discharge Technologies
For this proposal, EPA evaluated other zero discharge technologies
that could also eliminate the discharge of FGD wastewater. However, EPA
is not relying upon them as a basis for proposed BAT limitations
because they achieve the same pollutant reductions as the proposed BAT
technology basis (membrane filtration) but at a higher cost.
Nevertheless, EPA solicits comment on whether the Agency should
determine in a final rule that any one or more of these technologies
constitutes an additional BAT technology basis for controlling
pollutants discharged in FGD wastewater in addition to membrane
technology, or alternatively, in place of membrane technology.
Currently, 36 coal-fired power plants in the United States operate
wet FGD systems and manage their wastewater to achieve zero
discharge.\51\ These plants achieve zero discharge using evaporation
ponds, recycling of FGD wastewater, ash fixation, thermal systems
(e.g., falling film evaporators), or SDEs. Since 2009, approximately 15
additional plants that also operated wet FGD systems and achieved zero
discharge of FGD wastewater have retired or refueled such that the FGD
wastewater has been eliminated. While some of these systems
(evaporation ponds, fixation, and recycling) may not be available at
every single site,\52\ the number of thermal and SDE systems both
domestically and internationally in use on FGD wastewater demonstrates
that they are commercially available, and thus potentially
technologically available, as technologies for treating FGD wastewater
to meet zero-discharge limitations.\53\ Specifically, at least some
steam electric power plants have used the traditional thermal systems
\54\ and SDEs \55\ to achieve zero discharge of FGD wastewater
domestically and internationally for years, and several recent electric
utility reports acknowledge this fact.56 57 58 59 EPA has
separately evaluated the costs of thermal and SDE systems. Costs per
facility have decreased over time, and due to retirements and fuel
conversions, total costs have decreased substantially. Although EPA has
not estimated potential closures associated with these technologies
using the same model it has for supporting the economic achievability
of Option 3, as discussed more in Section VIII of this preamble below,
EPA does not expect the costs associated with these technologies to
have a significant impact on industry closures. In that case, the costs
of these technologies, although higher than the costs estimated for
industrywide membrane filtration,\60\ would be reasonable for the
category as whole, and thus economically achievable.61 62
Furthermore, consistent with the findings of the 2015 rule, EPA
proposes to find no unacceptable non-water quality environmental
impacts from operation of thermal systems and proposes that SDEs have
similarly acceptable non-water quality environmental impacts.\63\
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\51\ A 37th project that will result in zero discharge may have
also been completed: www.woodplc.com/insights/articles/engineering-solutions-for-wastewater-treatment.
\52\ EPA acknowledged as much in both the 2015 and 2020 rules.
\53\ See, e.g., APEC (Asia-Pacific Economic Cooperation) Energy
Working Group. 2015. Water Energy Nexus: Coal-Based Power Generation
and Conversion--Saving Water. EWG 08/2014 A. December. Available
online at: www.apec.org/docs/default-source/Publications/2017/2/
Water-Energy-Nexus-Coal-Based-Power-Generation-and-Conversion__-
Saving-Water/217_EWG_APEC-Energy-Water-Nexus-Report-20161230-
_CPAU_010217.pdf.
\54\ The Italian thermal systems discussed first in the 2013
proposed rule have been in operation for over a decade.
\55\ Spray dry absorbers, effectively the same technology as the
SDE, have been in use for decades to capture the same pollutants
present in FGD wastewater.
\56\ ``Proven technology (considered BAT for new sources by
EPA). 3+ U.S. installations and 6+ European installations by
Aquatech'' (SE07206).
\57\ SE10234.
\58\ SE09998.
\59\ EPRI (Electric Power Research Institute). 2017. Thermal
Evaporation Technologies for Treating Power Plant Wastewater: A
Review of Six Technologies. 000000003002011665. (SE06971).
\60\ The record indicates that individual utilities have found
thermal and/or SDE systems to be less expensive than membrane (and
even biological) systems in some cases.
\61\ Thermal Evaporation Cost Methodology (SE10246).
\62\ Spray Dryer Evaporator Cost Methodology (SE10247).
\63\ EPA evaluated the non-water quality environmental impacts
of these technologies in Alternative Brine Management Methodology
(SE10243). EPA performed this evaluation in the context of brine
management technologies for membrane filtration, and the types of
impacts and findings would remain the same even if used as
standalone technologies.
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EPA solicits comment on whether the Agency should identify, in any
final rule, one or more of the technologies of evaporation ponds,
recycling of FGD wastewater, ash fixation, thermal systems (e.g.,
falling film evaporators), or SDEs as a BAT technology basis for
control of FGD wastewater discharges, in addition to membrane
filtration technology. EPA solicits comment on whether such additional
BAT basis or bases would be technologically available and economically
achievable, and whether they would have acceptable non-water quality
environmental impacts. EPA also solicits comment on whether any one or
more of these alternative zero discharge technologies should be the BAT
technology basis for control of FGD wastewater discharges in lieu of
chemical precipitation plus membrane filtration.
c. EPA Proposes To Reject as BAT Less Stringent Technologies Than
Membrane Filtration
Except for the early adopter subcategory discussed in Section
VII.C.4 of this preamble, EPA is not proposing to base BAT on chemical
precipitation followed by a low hydraulic residence time biological
treatment including ultrafiltration, the technology which EPA
determined to be BAT in the 2020 rule. Under CWA section 301(b)(2)(A),
BAT is supposed to result in ``reasonable further progress toward the
national goal of eliminating the discharge of all pollutants'' and
``shall require the elimination of discharges of all pollutants if the
Administrator finds . . . that such elimination is technologically and
economically achievable'' as determined in accordance with CWA section
304(b)(2)(B). The record shows that the 2020 rule industrywide BAT
technology
[[Page 18844]]
basis for FGD wastewater removes fewer pollutants than the BAT basis of
chemical precipitation plus membrane filtration identified in this
proposal. Similarly, except for the permanent cessation of coal
combustion subcategory discussed in Section VII.C.3 of this preamble,
EPA is not identifying the less stringent (and previously rejected)
technologies of surface impoundments or chemical precipitation, as
these technologies too will remove fewer pollutants than the BAT in
this proposal.
2. BA Transport Water
EPA is proposing dry handling or closed-loop systems as the
technology basis for establishing BAT limitations to control pollutants
discharged in BA transport water. EPA proposes to find that these
technologies are technologically available, are economically
achievable, and have acceptable non-water quality environmental impacts
after evaluating the factors specified in CWA section 304(b)(2)(B).
Specifically, dry handling systems include mechanical drag systems
(e.g., submerged chain conveyors), submerged grind conveyors (e.g.,
compact submerged conveyors), air-cooled conveyor systems, and
pneumatic systems. Closed-loop systems consist of remote mechanical
drag systems paired with any necessary storage tanks, chemical addition
systems, and/or RO treatment necessary to fully recycle BA transport
water.\64\
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\64\ In addition to remote MDSs, non-BAT technologies include
many dewatering bins (also known as hydrobins), and surface
impoundments may also have the flexibility to operate as closed-loop
systems. Like remote MDSs, the latter systems may need to install
chemical addition systems (acid, caustic, and/or flocculants), RO
systems, and/or additional storage tanks to operate as fully closed
loop.
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In the 2020 rule, EPA rejected dry handling or closed-loop systems
as the BAT technology basis in favor of high recycle rate systems due
to process changes plants made to comply with the CCR rule (i.e., re-
routing non-CCR wastes to their wet BA handling systems to avoid
sending them to their unlined surface impoundments, as the CCR rule's
cease-receipt-of-waste date approached), as well as the additional
costs of dry handling or closed-loop systems. EPA also stated in 2020
that many plants may not, as a technical matter, be able to fully close
their BA handling systems to operate without discharge. Upon further
careful consideration of the record and the CCR rule, EPA does not
think that plants need a purge allowance to comply with the CCR rule.
While in some cases plants may incur additional costs to achieve zero
discharge by making process changes, the widespread use of dry handling
or closed-loop systems supports the view that these technologies are
available. As explained below, EPA proposes to find that the
technologies are available and economically achievable, and they have
acceptable non-water quality environmental impacts. Thus, EPA is
proposing dry handling or closed-loop systems as the BAT technology
basis for BA transport water.
In the first subsection immediately below, EPA discusses its
rationale for proposing dry handling or closed-loop systems as BAT for
BA transport water. In the following subsection, EPA discusses why it
is not proposing less stringent technologies than dry handling or
closed-loop systems. In the final subsection, EPA solicits comment on
issues associated with a BA transport water purge allowance and bottom
ash contact water.
a. Dry Handling or Closed-Loop Systems
Availability of dry handling or closed-loop systems. Based on the
record, EPA proposes to find that dry handling or closed-loop systems
are technologically available. At the time of the 2020 rule, EPA
estimated that more than 75 percent of plants already employed dry
handling systems or wet sluicing systems in a closed-loop manner, or
had announced plans to switch to such systems in the near future. The
high percentage of plants already employing these systems indicates
that they are technologically available. Some of these systems have
been in use since the 1970s, and today, most facilities have installed
one or more such systems.\65\
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\65\ One vendor estimates that only seven ash conversions remain
in the entire industry.
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In the 2015 and 2020 rule preambles, EPA discussed the widespread
use of dry handling systems for control of BA transport water servicing
approximately 200 EGUs at over 100 plants. In the 2020 rule, EPA also
discussed advances in dry BA handling systems. Specifically, the Agency
discussed a newer technology called submerged grind conveyors (one
example of which is called a compact submerged conveyor). At the time,
compact submerged conveyors were known to be installed and in operation
at two plants. EPA has since learned that about 12 compact submerged
conveyors have been installed.66 67 Partly due to the
increased use of compact submerged conveyors, more dry handling systems
are currently in place than EPA originally forecasted. For example, as
indicated in the 2020 rule record, one utility commented that it had
space constraints at a facility that would preclude the installation of
a compact submerged conveyor, and EPA thus projected that this facility
would employ a high recycle rate system under the 2020 rule. Since the
2020 rule, however, that utility ultimately proceeded to install a
different dry handling system, which highlights the broad array of dry
handling options available for coal-fired power plants, regardless of
their configuration. Even where space constraints may prohibit certain
dry systems, a plant could use a pneumatic system, albeit at a somewhat
greater cost. The 2020 rule record included information on 50 pneumatic
installations from as early as 1992. Given that BAT is to reflect the
best performing plant in the field Kennecott v. EPA, 780 F.2d at 447,
and the facts in the record support the use of dry handling technology
to achieve zero discharge of BA transport water, EPA could propose to
identify dry handling as the sole technology basis for control of BA
transport water. Nonetheless, as it did in the 2015 rule, EPA is
proposing to also identify closed-loop systems as a BAT technology
basis for controlling discharges of BA transport water, given that a
limited number of plants may find that option to be more attractive due
to space constraints and lower costs when compared to a pneumatic
system.
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\66\ Some utilities have even suggested that the discussion of
compact submerged conveyors in the final 2020 rule preamble and
additional compliance timeframes have led them to consider these
newer dry systems rather than a previously contemplated high recycle
rate/closed-loop system.
\67\ Final Burns & McDonnell Meeting Notes (SE10248).
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After the 2015 rule and throughout the 2020 rulemaking, certain
industry representatives argued that there are challenges to operating
a closed-loop BA handling system in a truly zero discharge manner. They
argued that closed-loop systems, including remote MDS and dewatering
bins, cannot maintain fully closed-loop operations due to chemistry
issues or water imbalances in the system, such as those that might
occur from unexpected maintenance or large precipitation events.
However, even accounting for these issues, the 2020 rule did not find
that closed-loop systems are not technologically available. Information
in EPA's 2020 rule record indicated that plants can operate their
closed-loop systems to achieve zero discharge, although this could
require some process changes and their resulting costs. The 2020 record
found that industry could achieve complete recycle
[[Page 18845]]
at an additional cost of $63 million per year in after-tax costs
(beyond the costs of the systems themselves) over the 2015 rule's
estimates. Moreover, EPA's cost estimates at the time were admittedly
conservative, as the Agency assumed the need to treat 10 percent of the
BA handling system's volume using RO for every facility with a closed-
loop system. See Section VIII of this preamble for a further discussion
of costs associated with the proposed closed-loop system technology
basis.
In the 2020 rule record, EPA discussed four potential challenges
with maintaining closed-loop systems: (1) managing non-BA transport
water inflows, (2) managing precipitation-related inflows, (3) managing
unexpected maintenance events, and (4) maintaining water system
chemistry. As further discussed below, based on the current record,
none of these previously discussed challenges provide a reasoned basis
for finding closed-loop systems not to be technologically available,
although these issues may in certain circumstances require a plant to
incur additional costs.
First, in 2020, EPA stated that managing non-BA transport water
inflows had the potential to result in water imbalances within a
closed-loop system. With respect to the inflow of other wastestreams
into the BA handling system, EPA's record in the 2015 and 2020 rules
indicates that closed-loop systems (i.e., remote MDSs) can be sized to
handle these additional wastestreams.\68\ To ensure effective
operations when designing and procuring closed-loop systems, facilities
should seek to size these systems for all wastestreams the system would
handle. Moreover, there is no evidence in the record that unanticipated
inflows cannot be addressed with reasonable steps.\69\ EPA solicits
comment on whether the best performing remote MDSs have documented non-
BA transport water inflows regularly exceeding the ability of the
systems to reuse their wastewater. EPA solicits comment providing data
from any remote MDS that would suggest whether a purge allowance is or
is not appropriate due to the technological availability of the system.
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\68\ For example, the Belews Creek remote MDS discussed during
the 2020 rulemaking also accepts economizer ash and pyrites
(SE07137).
\69\ Even including dewatering bins, which are not the basis for
either the 2015 BAT for BA transport water or this proposed BAT, the
2020 record included only a single facility where the water inflows
to its dewatering bin system were too great to be recycled due to
the presence of other wastewaters.
---------------------------------------------------------------------------
Second, in 2020, EPA stated that managing precipitation-related
inflows had the potential to result in water imbalances in the BA
handling system. However, EPA's record shows that precipitation-related
inflows can be adequately managed with design improvements, including
the use of roofing where appropriate. The 2015 BAT technology basis and
2020 rule remote MDS technology designs included and costed for covers
to avoid collecting precipitation.\70\ There is no record evidence that
this previously discussed precipitation-related challenge cannot be
overcome with reasonable steps and, therefore, this concern does not
provide a basis for rejecting closed-loop systems as BAT. EPA solicits
comment on whether the best performing remote MDSs have documented
precipitation inflows that have exceeded the ability of the systems to
reuse or store their wastewater, or whether the technology issue can be
addressed by undertaking measures at a reasonable additional cost. EPA
solicits comment providing data from such systems that would suggest
whether a purge allowance is or is not warranted. EPA solicits comment
on allowing for unlimited one-time purges due to large precipitation
events exceeding a 10-year storm event of 24-hour or longer duration
(e.g., a 30-day storm event) where drains or other precipitation-
collection components may not be amenable to roofs or other covers,
including any necessary reporting or recordkeeping requirements. Due to
the increasing storm severity associated with climate change, EPA also
solicits comment on whether a different type of storm event would be
more appropriate. Should EPA allow such discharges, the Agency solicits
comment on whether to require facilities to submit information when
they discharge, such as why the discharge was necessary, how much was
discharged, or any other specific information (e.g., meteorological
information) that would be helpful to the permitting authority or
public at large.
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\70\ 2020 Supplemental TDD (EPA-821-R-20-001).
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A third previously discussed challenge mentioned in the 2020 rule
to operating a remote MDS as a closed-loop system is the possibility of
infrequent maintenance events that might fall outside the 2015 rule
exemption of ``minor maintenance'' and ``leaks'' from the definition of
BA transport water. EPRI (2018) listed several such maintenance events;
most were expected to occur less than annually. EPRI provided
information about the estimated frequency and volume of water
associated with each maintenance event; however, EPRI did not provide
information about a specific remote MDS unable to manage these
maintenance events with existing maintenance tanks. Furthermore, even
where maintenance wastewater volumes are too large to be managed in
existing maintenance tanks, utilities can, at additional cost, lease
storage tanks for short-term maintenance where these infrequent
maintenance events are foreseeable.\71\ There is no record evidence
that infrequent maintenance events cannot be overcome with reasonable
steps and, therefore, this concern does not provide a basis for
rejecting closed-loop systems as BAT. EPA solicits comment on whether
data from such systems would suggest a purge allowance is or is not
warranted, as well as on the underlying data. EPA also solicits comment
on whether the Agency should expand the existing ``minor maintenance
event'' exemption from the definition of BA transport water in Sec.
423.11(p). One example of such a potential expansion could include
changing the current language that excludes ``minor maintenance events
(e.g., replacement of valves or pipe section)'' to instead state
``minor maintenance (e.g., replacement of valves or pipe sections) or
infrequent (i.e., occurring less than annually) maintenance events.''
Another example would be to delete the term ``minor'' and associated
parenthetical and merely say ``maintenance events.'' To the extent that
EPA expands this exemption in 40 CFR 423.11(p), the Agency also
solicits comment on any appropriate reporting or recordkeeping
requirements. For example, EPA is interested in commenters' views on
whether, when a facility discharges due to a maintenance event,
facilities should submit information about why it was necessary to
discharge, how much was discharged, or any other specific information
that would be helpful to the permitting authority or broader public.
Furthermore, EPA solicits comment on whether implementation of such a
change to the definition of BA transport water should require, for
example, a demonstration that the maintenance water could not be
managed within the system.
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\71\ In contrast, if the maintenance discharge is caused by an
unforeseeable upset condition, the plant would have an affirmative
defense to an enforcement action if the requirements of 40 CFR
122.41(n) are met.
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The final engineering challenge discussed in the 2020 rule record
as a reason for selecting high recycle rate systems rather than closed-
loop systems was the need to maintain water system chemistry. The 2020
rule discussed
[[Page 18846]]
potentially problematic system chemistries, such as extreme acidic
conditions, high scaling potential, and the buildup of fine
particulates that could clog pumps and other equipment. The 2015
closed-loop system BAT design basis included a chemical addition system
to manage these system chemistries. In particular, corrosivity could be
managed through pH adjustment, scaling could be managed with acid and/
or antiscalants, and fines could be further settled out with polymers
and other coagulants. EPRI \72\ documented that some systems went
slightly further, pairing the chemical addition systems with changes in
operations such as higher flow rates or longer contact time. Even where
all else fails, the same slipstream of purge allowed under the 2020
rule could be treated with RO and recycled back in as clean makeup
water. While it is possible that addressing these issues could entail
additional costs, there is no record evidence that this chemistry-
related challenge cannot be overcome with reasonable steps and,
therefore, this concern does not provide a basis for rejecting closed-
loop systems as BAT. EPA solicits comment on the extent to which any
plant using a remote MDS has tried all the processes described above
and still failed to adequately control system chemistry. EPA solicits
comment on whether data from such systems would suggest a purge is or
is not warranted, as well as on the underlying data.
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\72\ SE08927.
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For all the foregoing reasons, EPA proposes to find that the record
indicates that dry handling or closed-loop systems are technologically
available for control of discharges in BA transport water. Moreover,
dry handling or closed-loop systems would result in reasonable further
progress toward the Act's goal of eliminating the discharge of all
pollutants, as the limitations based on this technology would require
zero discharge of BA transport water from the steam electric industry.
Economic achievability of dry handling or closed-loop systems. EPA
proposes to find that the costs of dry handling or closed-loop systems
are economically achievable for the industry as a whole. In the 2020
rule, EPA cited the additional costs of closed-loop systems as part of
its basis for selecting high recycle rate systems. In the 2020 rule
record, EPA noted that it had ``conservatively'' estimated costs of $63
million per year based on all facilities using a remote MDS needing a
10 percent purge to be treated with RO in order to achieve complete
recycle (i.e., zero discharge operations). However, EPA never found
that the additional costs to achieve zero discharge were not
economically achievable. Moreover, the 2020 rule record never
demonstrated that a full 10 percent purge at all facilities was a
realistic costing assumption. The primary basis for the 2020 rule purge
allowance was a 2016 report from EPRI that involved continuous purges,
the majority of which were well under one percent. Thus, in the 2020
rule record, EPA presented a sensitivity analysis with costs for a two
percent purge treatment, which may better reflect actual operations.
Even using the more conservative cost estimates in the baseline IPM
analysis for the 2020 rule (i.e., full implementation of the 2015
rule),\73\ the record demonstrated minimal changes in coal combustion
and in steam electric power plant retirements. After updating these
conservative cost estimates to $45 million per year pre-tax in proposed
Option 3, the IPM analysis performed for this proposed rule continues
to demonstrate that, after including the costs of treating all
wastestreams--including achieving zero discharge for BA transport
water--the proposed rule would result in minimal economic impacts. (For
further information, see Sections VII.F and VIII of this preamble).
Because EPA is required to consider whether the cost of BAT can be
reasonably borne by the industry and confers on EPA discretion in
consideration of the BAT factors, see, e.g., Chem. Mfrs. Ass'n v. EPA,
870 F.2d at 262; Weyerhaeuser v. Costle, 590 F.2d at 1045, EPA proposes
to find that these additional costs are economically achievable as that
term is used in the CWA.
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\73\ The 2020 rule analysis had a baseline of zero discharge
under the 2015 rule.
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Non-water quality environmental impacts of dry handling or closed-
loop systems. EPA proposes to find that the non-water quality
environmental impacts associated with dry handling or closed-loop
systems for controlling BA transport water discharges are acceptable.
See Sections VII.G and X of this preamble below for more details.
Process changes associated with dry handling or closed-loop
systems. EPA also rejected closed-loop systems in the 2020 rule due to
process changes happening at steam electric facilities as they move
toward compliance with the CCR rule. EPA stated that as plants close
their surface impoundments under the CCR rule, they may choose to send
certain non-CCR wastewaters to their BA handling system. This could
complicate their efforts to fully close their BA handling systems due
to increased scaling, corrosivity, or plugging of equipment.
Alternatively, EPA mentioned that a closed-loop requirement might
incentivize plants to discharge their non-CCR wastes rather than send
them to their BA handling systems for control, in which case they would
be subject to less stringent requirements governing low-volume wastes.
EPA also suggested that requiring limitations based on closed-loop
systems could result in plants using their surface impoundments longer,
assuming plants cannot build alternative storage capacity and need to
continue to send their non-CCR wastes to unlined impoundments.
The rationale in the 2020 rule is not persuasive under the
timeframe of any final ELG rule because by the time any BA transport
water requirement would be implemented in NPDES permits, the CCR rule
ash pond cease receipt of waste dates will have long since passed, or
this rule's proposed subcategories could address any remaining CCR
coordination issue. The CCR Part A rule required plants to cease
receipt of waste in unlined surface impoundments by April 11, 2021.\74\
This date has already passed, with most facilities having completed
conversions from leaking, unlined surface impoundment BA handling
systems to a CCR rule-compliant BA handling system (i.e., systems that
do not rely on unlined CCR surface impoundments). Of the remaining
unlined surface impoundments, those operating under CCR Part A
flexibility found in Sec. 257.103(f)(2) are permanently ceasing coal
combustion, and EPA proposes to continue to treat them differently
under the subcategory for EGUs permanently ceasing coal combustion by
2028. This leaves only the unlined surface impoundments where
alternative capacity is technically infeasible, a CCR Part A
flexibility with maximum timeframes of October 15, 2023, and October
15, 2024, to cease receipt of waste.\75\ These later dates require EPA
approval.\76\ Even with extensions, nearly every facility will have
completed its conversion to a CCR rule-compliant BA handling method by
2024, the year in which EPA intends to promulgate any final ELG
following this proposal. Since EPA expects that all facilities would
comply with the CCR
[[Page 18847]]
rule cease-receipt-of-waste provisions and have alternative BA handling
systems or compliant surface impoundments by then, there are no looming
deadlines and tight timeframes that would justify continued
flexibility. Instead, with the work to meet these CCR deadlines
completed, facilities with high recycle rate systems would be free to
focus on transitioning those high recycle rate systems to closed-loop
operations.\77\ Thus, EPA proposes that there are no ``process change''
reasons related to the CCR rule that undermine EPA's proposed BAT basis
of dry handling or closed-loop systems for control of BA transport
water discharges.
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\74\ 40 CFR 257.101(a)(1).
\75\ 40 CFR 257.103(f)(1)(vi).
\76\ Further information on the implementation of these Part A
applications is available on EPA's website at: www.epa.gov/coalash/coal-combustion-residuals-ccr-part-implementation.
\77\ Although EPA estimates that fully closing the loop would be
less expensive than converting to dry handling, nothing would
preclude a facility with a high recycle rate system from installing
one of the technologically available and economically achievable dry
handling systems.
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b. EPA Proposes To Reject as BAT Less Stringent Technologies Than Dry
Handling or Closed-Loop Systems
Except for the early adopter subcategory, EPA is not proposing to
base BAT on high recycle rate systems. In the 2020 rule, EPA reversed
its decision from the 2015 rule and determined that closed-loop systems
were not BAT. As a result, EPA established a volumetric purge allowance
(with a maximum of 10 percent of the system volume) to be determined on
a case-by-case basis by the permitting authority, which required a
permitting authority's BPJ analysis to determine whether that purge
required further control. As discussed above, the technological issues
can be resolved, albeit at potentially additional costs, which EPA now
proposes are economically achievable. Furthermore, a dewatering bin or
remote MDS with a purge removes fewer pollutants than the proposed BAT
basis of dry handling or closed-loop systems, which the Agency proposes
to find are technologically available, are economically achievable, and
have acceptable non-water quality environmental impacts. Under CWA
section 301(b)(2)(A), BAT is supposed to result in ``reasonable further
progress toward the national goal of eliminating the discharge of all
pollutants'' and ``shall require the elimination of discharges of all
pollutants if the Administrator finds . . . that such elimination is
technologically and economically achievable'' as determined in
accordance with CWA section 304(b)(2)(B). Because high rate recycle
systems achieve fewer pollutant removals than the dry handling or
closed-loop systems EPA has proposed as BAT, such less stringent
technologies would not result in reasonable further progress toward the
CWA's goal of eliminating the discharge of pollutants.
Except for the permanent cessation of coal combustion subcategory,
EPA is also not identifying the less stringent (and previously
rejected) technology of surface impoundments as the technology basis
for BAT, as this technology would also remove fewer pollutants than the
proposed BAT basis of dry handling or closed-loop systems, which EPA
proposes are technologically available, are economically achievable,
and have acceptable non-water quality environmental impacts.
c. Solicitation of Comment on Additional BPJ-Based Permitting
Constraints and Issues Related to BA Contact Water
Despite the preceding discussion, if EPA were to maintain the 2020
rule's purge allowance, the Agency solicits comment on whether it
should establish constraints and additional requirements on where and
how a purge may be allowed on a case-by-case basis. All the instances
EPA is aware of involving requests by plants to purge BA transport
water under the 2020 rule have included a request for a full 10 percent
purge. The limitation EPA established in the 2020 rule was, however, a
site-specific purge allowance with a maximum 10 percent threshold. In
practice, this flexibility has resulted in a situation where BA
handling systems either achieve zero discharge or purge the maximum 10
percent. EPA notes that all the chemistry-related purges discussed in
EPRI (2016) were one percent or less of system volume, and it solicits
comment on whether, if a final rule were to include allowance for any
purge, the Agency should constrain the purge allowance to reflect the
smaller continuous purge volumes in EPRI (2016). EPA also solicits
comment on whether, in the event of allowance of any purge, the
permittee should provide further analysis and justification to the
permitting authority or if EPA should place further constraints on the
permitting authority in allowing purges. For example, EPA solicits
comment on whether permittees should be required to complete an
engineering study, starting with closed-loop operations and slowly
increasing purge as necessary after demonstrating that the system
cannot be operated with the existing level of purge (e.g., by using
chemical addition systems, changing flows, or residence time).
Moreover, if EPA elects to retain a high recycle rate system as BAT
for BA transport water, the Agency is interested in whether there
should be any additional constraints on the purge allowance to ensure
that the pollutant reductions achieved are consistent with the
reductions expected from the BAT technology basis. In particular, EPA
has become aware of system operations that recycle a high percent of
water, but in practice may not achieve pollutant removals as high as
those of the remote mechanical drag chain and dewatering bin systems
described in the 2020 rule preamble, which were the bases for the
following findings:
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
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 lb/year of pollutants, 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.
(Emphasis added.)
As an example of such a system, following the 2020 rule, EPA became
aware of one plant that intentionally constructed a concrete basin
system intended to recycle only 90 percent of BA transport water (Smith
et al., 2022).\78\ Due to the size of this system, the 10 percent purge
generated results in a much greater volume of discharged wastewater
than the 2020 rule contemplated. This facility is not unique in its use
of large, concrete basins. The APS Four Corners power
[[Page 18848]]
plant recently submitted a request for a 10 percent purge of BA
transport water \79\ where the claimed system volume of over 4.5
million gallons would result in a BA transport water purge of nearly
one-half MGD, a volume greater than the entirety of the purges claimed
for the Duke Energy coal fleet.\80\ While the facility employs
dewatering bins as the primary BA handling mechanism, part of this high
volume discharge request appears to stem from the large concrete
basins, or ``tanks,'' that APS has installed. EPA solicits comment on
other facilities that have installed concrete basin systems or tanks
and any facts describing the size, flows, and other operational
parameters of such systems. Furthermore, should EPA ultimately elect to
retain a purge allowance for BA transport water, the Agency solicits
comment on whether the total volume (not just the percent) of purge
should also be limited to ensure that the system achieves the pollutant
removals of a true high recycle rate system (i.e., a remote MDS).
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\78\ See www.woca2022.conferencespot.org/event-data/pdf/catalyst_activity_28074/catalyst_activity_paper_20220329020324138_a6f09dfc_ad86_4183_9ecb_a71e88b48245.
\79\ An updated submission made to EPA has since reduced this
request to between two and 2.5 percent of system volume and is
currently being evaluated by the Agency.
\80\ In contrast, the purge requests from Duke Energy estimated
a 10 percent purge of between approximately 50,000 and 100,000
gallons per day at each of the company's five plants with such
systems.
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While EPA is concerned that the site-specific purge in the 2020
rule may be unnecessary or not adequately justified, the Agency also
notes that ``dry handling'' systems often are not completely dry. EPRI
(2014) included information about an MDS with purge of 270 gpm from an
under-boiler ``dry handling'' system. EPA has received additional flow
diagrams in the most recent information collection that show purges
from additional MDS systems.\81\ Thus, while many facilities have
installed pneumatic and air-cooled drag chain systems, many EGUs with
``dry handling'' due to under-boiler MDS or compact submerged conveyor
systems still rely on wet hoppers that catch and cool hot (in some
cases molten) BA in quench water. EPA has not considered this BA
contact water to be transport water (instead considering it within the
catch-all category of low volume wastewater), because, as explained in
the 2015 rule, the water is not used to transport the BA, resulting in
decreased contact times (and thus decreased pollutant concentrations)
from the BA. While overall pollutant concentrations may be lower,
leaching data in the 2015 CCR rule record indicate that some
constituents wash out due to their high solubility.\82\ For these
pollutants, there may be little difference in concentration between
transport water and contact water. In the absence of data from actual
under-boiler purges, EPA solicits comment providing data and purge
examples from existing dry handling systems. EPA solicits comment on
whether limiting or removing the ability to purge from a high recycle
rate system but not from a ``dry'' under-boiler system may result in
unwarranted disparate treatment or perverse incentives. EPA solicits
comment on whether there is a potential unwarranted disparity and how
the Agency might address this disparity to avoid potentially
encouraging larger discharges. For example, EPA solicits comment on
whether it should continue to allow (or alternatively not allow,
through a zero-discharge requirement) a purge for both contact water
and transport water. Since contact water is not covered by the
definition of transport water in 40 CFR 423.11(p), EPA solicits comment
on whether the purge of such water should nevertheless be included as
``bottom ash purge water'' under Sec. 423.11(cc) and thus subject to a
BPJ analysis by the permitting authority.
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\81\ These flow diagrams did not include flow rates or pollutant
concentrations. (SE09754 and SE09724.)
\82\ U.S. EPA (Environmental Protection Agency). 2014. Human
Health and Ecological Risk Assessment of Coal Combustion Residuals.
2050-AE81. December. Available online at www.regulations.gov.
Document ID#: EPA-HQ-OLEM-2019-0173-0008.
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3. Combustion Residual Leachate (CRL)
EPA is proposing chemical precipitation as the technology basis for
establishing BAT limitations to control pollutants discharged in CRL.
After evaluating the factors specified in CWA section 304(b)(2)(B), EPA
proposes that this technology is available, is economically achievable,
and has acceptable non-water quality environmental impacts.
Specifically, the proposed BAT basis consists of chemical
precipitation/coprecipitation employing the combination of hydroxide
precipitation, iron coprecipitation, and sulfide precipitation.
In the subsection immediately below, EPA discusses its rationale
for proposing chemical precipitation as BAT for control of leachate. In
the following subsection, EPA solicits comment on whether it should
base BAT for CRL on more stringent technologies, such as chemical
precipitation plus biological treatment, chemical precipitation plus
membrane filtration, or chemical precipitation plus thermal treatment,
and whether these technologies are technologically available, are
economically achievable, and have acceptable non-water quality
environmental impacts, as discussed below. In the third subsection, EPA
discusses why it is not proposing to establish BAT for control of
pollutants in CRL based on surface impoundments. In the fourth
subsection below, EPA solicits comment on additional options related to
co-treatment of FGD and CRL wastewater, a potential grandfathering
provision, co-treatment of CRL and stormwater, and potential
differences in leachate associated with pre- and post-close of
landfills. Finally, in the last subsection below, EPA solicits comment
on EPA's estimates of potential costs and loads of pollutant discharges
through groundwater, treatment differences, and potential
subcategorization related to discharges through groundwater.
a. Chemical Precipitation
Technological availability of chemical precipitation. EPA proposes
to find that chemical precipitation is technologically available for
control of CRL discharges. In the 2015 rule record, EPA found that
chemical precipitation systems are technologically available for
treating CRL, capable of achieving low effluent concentrations of
various metals, and effective at removing many of the pollutants of
concern present in CRL discharges to surface waters. The Agency also
found that the pollutants of concern in CRL are the same pollutants
that are present in, and in many cases are also pollutants of concern
for, FGD wastewater, FA transport wastewater, BA transport water, and
other CCR solids. This proposed finding is consistent with the findings
of this technology as the basis for the 2015 rule's NSPS and PSNS for
CRL.\83\
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\83\ In establishing chemical precipitation as the basis for
NSPS, the Agency stated that chemical precipitation is a well-
demonstrated technology for removing metals and other pollutants
from a variety of industrial wastewaters. 80 FR 67859.
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EPA is basing the proposed effluent limitations on the chemical
precipitation system for treating FGD wastewater as described in the
2015 rule record because the record indicates that CRL wastewater is
similar to FGD wastewater, which the record demonstrates can be
effectively treated using chemical precipitation. Specifically, the
system serving as the BAT technology basis employs equalization,
hydroxide and organosulfide precipitation, iron coprecipitation, and
removal of suspended and precipitated solids. As discussed in Section
VI of this preamble above, EPA asked eight utilities to
[[Page 18849]]
voluntarily perform CRL sampling at CCR landfills the Agency believed
were new CCR rule-compliant landfills and/or expansions. EPA ultimately
received supplemental CRL sampling data covering 25 landfills. EPA
analyzed these data in the CRL Analytical Data Evaluation (SE10249) and
found that CRL has a similar wastewater characterization to FGD
wastewater. Chemical precipitation would make reasonable further
progress toward the Act's goal of eliminating the discharge of all
pollutants, as the limitations based on this technology would eliminate
substantial amounts of arsenic, mercury, and other toxic pollutants
from CRL discharges by the steam electric industry.
Economic achievability of chemical precipitation. EPA proposes to
find that the costs of chemical precipitation for control of CRL
discharges are economically achievable. This proposal includes IPM
modeling of the preferred option (Option 3) which includes chemical
precipitation costs for CRL. The results of the analysis show small
changes in coal utilization and only one incremental retirement of a
facility out of 871 steam electric power plants in the steam electric
power generation industrial category. Furthermore, that plant already
operates at a low capacity utilization rating. This is well within the
economic impact estimated for other BAT rules and has been upheld by
courts. Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 252. As a result of this
analysis, EPA proposes to find that chemical precipitation is
economically achievable.\84\ For further discussion of the economic
analysis, see Sections VII.F and VIII of this preamble below.
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\84\ EPA notes that the 2015 rule record indicated that the
costs of treating CRL based on chemical precipitation were only
marginally higher than the total costs in the selected option, which
was found to result in minimal economic impacts. Furthermore, the
cost screening in 2015 found that only a small portion of the plants
and parent entities would experience costs greater than one percent
or three percent of revenue, even with chemical precipitation
treatment of CRL. While these thresholds do not necessarily equate
to what is economically achievable, they may serve as a screening
analysis to find that the costs do not raise economic achievability
concerns.
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Non-water quality environmental impacts of chemical precipitation.
EPA proposes to find that the non-water quality environmental impacts
associated with chemical precipitation to control CRL discharges are
acceptable. See discussion below in Section VII.G and Section X of this
preamble.
b. More Stringent Technologies Than Chemical Precipitation
EPA solicits comment on whether the technology basis for BAT
limitations to control discharges of pollutants in CRL should be based
on more stringent technology, such as biological treatment, spray dry
evaporation, thermal systems, or membrane filtration. The record
includes plants that have successfully treated a combination of CRL and
FGD wastewater with chemical precipitation as pretreatment for
biological or thermal systems. This successful treatment history may
further support the availability of chemical precipitation either alone
or as pretreatment for more advanced systems. EPA solicits comment and
additional data about these systems treating CRL beyond chemical
precipitation and further solicits comment on whether and to what
extent it should instead, or in addition, base BAT limitations
applicable to CRL on these technologies.
With respect to biological treatment, EPA solicits comment on
whether it should base BAT limitations applicable to CRL on chemical
precipitation plus biological treatment. In the 2015 rule record, EPA
found that chemical precipitation plus biological treatment was
technologically available and in use domestically to treat a mix of FGD
wastewater and CRL. Given the data cited above showing the similarity
of FGD and CRL wastewater, EPA solicits comment on transferring the FGD
wastewater technology basis and BAT limitations from the 2020 rule as
the technology basis and BAT limitations for CRL as well.
With respect to thermal treatment, the 2020 rule record included a
facility that co-treated its FGD wastewater and CRL with a thermal
system to achieve zero discharge. At least four vendors have conducted
thermal system pilots on CRL, and there has been one full-scale thermal
system installation for the treatment of CRL. EPA has identified four
vendors that have conducted successful thermal system pilots, and each
of these vendors has installed multiple full-scale thermal systems at
non-power plant landfills. Thus, EPA solicits comment on finalizing a
zero-discharge requirement for CRL based on chemical precipitation plus
thermal treatment systems and/or SDE treatment systems, or
alternatively on transferring the chemical precipitation plus thermal
treatment-based BAT limitations established for the FGD wastewater NSPS
in the 2015 rule.
With respect to membrane treatment, as discussed above under FGD
wastewater, the record is also replete with the use of membrane
filtration for a variety of wastestreams with characteristics like high
TDS, high scaling potential, and high variability, both within the
steam electric sector and in other industries. Furthermore, one
midwestern facility conducted a successful pilot of a membrane
filtration system on CRL.\85\ EPA solicits comment on establishing zero
discharge BAT limitations for CRL based on chemical precipitation plus
membrane filtration, or alternatively on transferring the membrane
filtration limitations established in the VIP for FGD wastewater in the
2020 rule.
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\85\ This utility declined to provide the pilot in response to a
voluntary request from EPA.
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EPA also solicits comment on establishing limitations based on any
combination of chemical precipitation plus membrane filtration,
chemical precipitation plus thermal, and/or SDE treatment. To
facilitate comments on a zero discharge option, EPA has provided memos
to the record evaluating the costs of achieving zero discharge of CRL
and the associated pollutant reductions.\86\ Should EPA finalize BAT
limitations based on more stringent technologies than chemical
precipitation, EPA also solicits comment on the appropriateness of
revising NSPS and PSNS for CRL based on a more stringent technology
than the NSPS basis selected in the 2015 rule (chemical precipitation).
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\86\ Evaluation of Zero Discharge Options for CRL (SE10257).
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c. Less Stringent Technologies Than Chemical Precipitation
EPA is not proposing to base BAT limitations for control of CRL on
surface impoundments because there are other technologies (like
chemical precipitation) that achieve greater reductions in pollutant
discharges, which EPA proposes are available and economically
achievable, with acceptable non-water quality environmental impacts.
Surface impoundments would not make reasonable further progress toward
the national goal of eliminating the discharge of pollutants.
d. Solicitation of Comment on Additional Options Related to Co-
Treatment of FGD and CRL Wastewater, Potential Grandfathering
Provision, Co-Treatment of CRL and Stormwater, and Potential
Differences in Discharges Associated With Pre- and Post-Closure of
Landfills
EPA also solicits comment on whether EPA should create a
[[Page 18850]]
subcategory allowing facilities that co-treat their FGD and CRL
wastewater to meet BAT limitations based on a different technology
basis than the one used by facilities treating CRL alone. EPA solicits
comment on whether there are engineering obstacles to such co-treatment
based on proximity of the landfill or other factors. EPA also solicits
comment on whether it would be appropriate to establish either a
grandfathering provision that would allow such facilities a limited
payback period to recover costs on the CRL treatment investments
already made before having to comply with any new limitations or
another provision that would account for the potentially unique
circumstances of these facilities, in light of the factors specified
under CWA section 304(b).
In developing the current record, EPA received information about
systems that collect leachate and stormwater in the same system. For
example, one type of system involves the use of chimneys that route
stormwater straight through a landfill into the leachate collection
system to minimize percolation through the CCR solids. Thus, EPA also
solicits comment on flexibilities that might be warranted for such
systems. For example, EPA solicits comment on whether such systems
should be subcategorized, or whether either the definition of CRL or
the applicability of the CRL limitations should exclude discharges when
stormwater exceeds specific storm events, such as events used as the
basis of the BA transport water purge allowance in the 2020 rule.
EPA also discussed the differences between pre- and post-closure
landfill operations with several stakeholders. For example, post-
closure, the CCR rule requires landfills and surface impoundments
closing with waste in place to have a cap that is graded to minimize
infiltration into the CCR solids. This will result in volumes of CRL
decreasing significantly post-closure. EPA solicits comment on specific
information that would suggest whether different limitations should
apply to the same landfill or surface impoundment pre- and post-
closure. The change in flows also means the amount of capital
expenditure on treatment systems (larger flows lead to larger treatment
systems) might be disparate for landfills and surface impoundments
nearing closure when compared to those with many operating years
remaining or to those that have already closed under the CCR rule.
Thus, EPA solicits comment on whether there should be flexibility for
landfills and surface impoundments nearing closure such that
limitations could be postponed until after closure to avoid
construction of a larger, more expensive system that would operate for
only a relatively short period of time. EPA also solicits comment on
whether CRL generated by already closed landfills and surface
impoundments should be subcategorized, as well as information
demonstrating whether subcategorization is warranted.
e. Solicitation of Comment on EPA Estimates of Potential Costs and
Loads of Pollutant Discharges Through Groundwater, Treatment
Differences, and Potential Subcategorization
EPA also notes that unlined landfills and surface impoundments
potentially discharge CRL through groundwater before entering surface
water.\87\ EPA, through this action, is not addressing the definition
of any terms in the CWA (such as ``point source'' or ``discharge of a
pollutant'') that govern when a discharge is subject to NPDES
permitting requirements or when a discharge to WOTUS through
groundwater is a functional equivalent of a discharge and thus subject
to the Act's NPDES permitting requirement. See County of Maui v. Hawaii
Wildlife Fund, 140 S. Ct. 1462 (2020). Those issues are outside the
scope of this rulemaking. EPA proposes that any discharge through
groundwater that is the functional equivalent of a direct discharge
under the Maui decision would be subject to the same BAT limitations as
discharges that occur at the end of pipe. To evaluate the potential
costs and loads of such discharges, EPA conducted Evaluation of
Potential CRL in Groundwater (SE10250). EPA solicits comment on the
appropriateness of the Agency's proposed BAT findings and their
application to any discharges of CRL via groundwater that permitting
authorities ultimately determine are subject to NPDES permitting. EPA
also solicits comment on the extent to which CRL discharges through
groundwater might be different than other discharges potentially
subject to any final rule, including specific facts demonstrating that
the chemical makeup, treatment effectiveness, or other factors differ
from end-of-pipe discharges of CRL. EPA solicits comment on whether
such discharges of CRL through groundwater should be defined as a
separate wastestream or subcategorized and how, including whether these
discharges should be subject to BAT limitations on a case-by-case, BPJ
basis. Should EPA reserve these limitations such that permitting
authorities' BPJ would apply, section 304(b) of the CWA, 33 U.S.C.
1314(b), and 40 CFR 125.3 specify factors the permitting authority
would consider when establishing BPJ-based effluent limitations for
CRL. Furthermore, EPA solicits comment on whether the Agency should
explicitly set BAT equal to BPJ in the regulation and include
additional constraints (e.g., one or more presumptive standards) that
are specific to this wastestream in this industry.
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\87\ Three panels in the 2022 World of Coal Ash conference
included discharges through groundwater as a topic in their
abstracts, and one abstract stated that surface impoundments are
located so close to surface waters that the groundwater underlying
the surface impoundment ``is often in hydraulic communication with
surface water.'' DeJournett et al., 2022. Available online at:
www.woca2022.conferencespot.org/event-data/pdf/catalyst_activity_28060/catalyst_activity_paper_20220124235416545_8aa3636e_85c7_4a17_bcca_a3119e01a5f9.
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4. Legacy Wastewater
EPA proposes not to establish a nationwide BAT basis for legacy
wastewater at this time and instead to continue to reserve these
limitations for determination by the permitting authority, using its
BPJ for what is technologically available, economically achievable, and
has acceptable non-water quality environmental impacts. This potential
case-by-case outcome was explicitly identified by the Court in
Southwestern Elec. Power Company v. EPA, 920 F.3d at 1021, as an
alternative EPA should have considered.
In the first subsection immediately below, EPA discusses its
rationale for BPJ-based BAT limitations to control legacy wastewater.
In the second subsection, EPA discusses why it is not proposing less
stringent technologies as BAT for legacy wastewater. In the last
subsection, EPA discusses why it is not selecting more stringent
technologies as BAT for legacy wastewater and is soliciting comment on
potentially different limitations for a subset of legacy wastewater.
a. BPJ-Based BAT Limitations
After evaluating the factors specified in CWA section 304(b)(2)(B),
EPA is proposing to find that no single technology is technologically
available and economically achievable on a nationwide basis for control
of pollutants in legacy wastewater. Because of process changes
happening at plants in the form of ongoing and soon-to-be-completed
rapid surface impoundment closures under the CCR rule, EPA proposes
that a nationwide BAT limitation for legacy wastewater that would be
finalized mid-closure could be infeasible. The statute requires BAT to
reflect what is technologically available, is economically achievable,
[[Page 18851]]
and has acceptable non-water quality environmental impacts based on
consideration of several factors, including ``process changes'' and
``such other factors'' as the Administrator deems appropriate. Because
many facilities with surface impoundments are or will be in the process
of closing their surface impoundments under the CCR rule, the
technology that represents BAT for legacy wastewater treatment is
likely to vary at any given site depending on several factors. These
factors include, but are not limited to, the types of wastes and
wastewaters present, the characteristics of the legacy wastewater in
each layer of a surface impoundment, the amount of legacy wastewater
remaining to be treated in a surface impoundment, the treatment option
costs, the extent to which CWA requirements could interfere with
closure timeframes required under the CCR rule, and the potential for
increased discharges through groundwater. While there is no typical
site given the dynamic and changing nature of this wastestream at this
time, given the CCR rule's closure requirements, permitting authorities
should seriously consider treatment beyond that afforded by surface
impoundments, which the Fifth Circuit found to be arbitrary,
capricious, and inconsistent with the ``technology-forcing mandate of
the CWA.'' Southwestern Elec. Power Company v. EPA, 920 F.3d at 1017.
The effect of finalizing this proposal would be for permitting
authorities to continue to establish site-specific technology-based
effluent limitations using their BPJ. Because the limitations would be
derived on a site-specific basis, taking into account the requisite
statutory factors and applying them to the circumstances of a given
plant, EPA proposes that these case-by-case limitations would be
technologically available and economically achievable and have
acceptable non-water quality environmental impacts.
As part of this proposal, EPA is proposing to segregate legacy
wastewater into two main categories of separately regulated discharges,
which would each be subject to separate case-by-case technology-based
effluent limitations established by the permitting authority (after
considering the statutory factors). Legacy wastewater was defined in
the 2015 rule preamble as:
``. . . FGD wastewater, fly ash transport water, bottom ash
transport water, FGMC wastewater, or gasification wastewater
generated prior to the date determined by the permitting authority
that is as soon as possible . . .'' \88\
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\88\ 80 FR 67854. CRL does not appear in this list because, in
2015, EPA did not establish more stringent limitations for this
wastewater than the previously applicable BPT limitations.
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In practice, there are two distinct categories of legacy
wastewater: (1) wastewater that is continuously or intermittently
generated and discharged to a pond after the issuance of the first
permit implementing the 2015 or 2020 rule but before the compliance
date specified in the permit (the ``as soon as possible'' date required
by the rule), and (2) wastewater that was discharged to the pond
previously and will be discharged when the pond is dewatered for
closure.
By segregating wastewaters continuously or intermittently generated
and discharged after permit issuance from those already accumulated in
closing surface impoundments, permitting authorities could justify more
stringent BAT requirements on a BPJ basis for one or both categories of
legacy wastewater. The first category is continuously or intermittently
generated and discharged and may be able to be more easily transmitted
to other treatment systems at the facility. The second type is
typically treated with modular, leased systems for a shorter period,
making treatment more affordable.
For example, regarding FGD wastewater generated after permit
issuance but before the ``as soon as possible'' date determined by the
permitting authority, a facility installing the 2020 BAT technology
basis of chemical precipitation plus biological treatment and
ultrafiltration may be able to operate the chemical precipitation
module before the date the permitting authority determines is the
soonest date that the more stringent limitations apply pursuant to
Sec. 423.11(t). In such a scenario, it would be reasonable for a
permitting authority to establish BAT limitations for legacy FGD
wastewater using a BPJ approach that would transfer mercury and arsenic
limitations with a date corresponding to the operability of that
chemical precipitation module. Since permitting authorities already
determine the ``as soon as possible'' date, it is reasonable that the
same information could be used for a BPJ analysis.
The state of Pennsylvania recently implemented a similar approach
in an NPDES permit issued to Homer City. In the Homer City NPDES Permit
Fact Sheet Addendum 3,\89\ the state found the plant had ``voluntarily
committed'' to a more stringent technology than BAT. The state further
found that the plant needed time ``to plan, design, procure, and
install equipment'' that would ``bring about a result that is more
desirable under the Clean Water Act than a treated discharge--the
elimination of a discharge.'' While the permit limits for this legacy
wastewater were not as stringent as the 2020 rule FGD wastewater BAT
limitations, the state permit required the discharger to meet interim
effluent limits based on a chemical precipitation and aerobic
biological treatment system that was available to this facility but may
not be to other facilities, as the facility already had this technology
in place before the completion of upgrades to achieve zero discharge.
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\89\ Available online at: www.files.dep.state.pa.us/water/wastewater%20management/EDMRPortalFiles/Permits/PA0005037_FACT_SHEET_20210819_DRAFT_V2.pdf.
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The second category of legacy wastewater is wastewater accumulated
over years in a surface impoundment that is later drained during the
closure of that surface impoundment. Such wastewater consists of:
surficial water located above the CCR solids (hereafter
referred to as ``surface impoundment (SI) decant wastewater''); and
pore water in the saturated CCR layer at levels beyond
that needed for conditioning (hereafter referred to as ``surface
impoundment (SI) dewatering wastewater'')
EPA also notes that there would necessarily be an interstitial zone
where there may be some disturbed CCR solids. In this case, the water
may not necessarily be pore water from CCR solids but would
sufficiently mix with the CCR solids such that it presents similarly
elevated pollutant concentrations. Hence, while it is not pore water
per se, this interstitial zone water should be similarly situated with
the pore water layer from a regulatory perspective. For this reason,
EPA is proposing, and soliciting comment on, the following set of
definitions and proposing to require a separate BAT/BPJ analysis for
this category of legacy wastewater:
The term ``surface impoundment'' means a natural
topographic depression, man-made excavation, or diked area that is
designed to hold an accumulation of coal combustion residuals and
liquids, and the unit treats, stores, or disposes of coal combustion
residuals.\90\
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\90\ EPA has always sought to harmonize the CCR rule and this
ELG. Therefore, this definition, and terms therein (e.g., unit), was
taken from 40 CFR 257.53 to match the definition under the CCR rule.
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The term ``surface impoundment decant wastewater'' means
the layer of
[[Page 18852]]
a closing surface impoundment's wastewater that is located from the
water surface down to the level sufficiently above any coal combustion
residuals that, when drained, does not resuspend the coal combustion
residuals.
The term ``surface impoundment dewatering wastewater''
means the layer of a closing surface impoundment's wastewater that is
located below surface impoundment decant water due to its contact with
either stationary or resuspended coal combustion residuals.
EPA also proposes a clarifying change to the definition of ``tank''
to ensure that there would be no structure that would qualify as both a
tank and a surface impoundment. By separating these legacy wastewaters
as distinct wastestreams from the legacy wastewater definition
discussed above, EPA is proposing that the treatment of SI decant and
dewatering wastewaters can, and in many cases should, be subject to
different limitations from the first category of continuously or
intermittently generated and discharged legacy wastewater. For example,
a permitting authority conducting a BPJ analysis for a plant with the
first type of legacy wastewater discussed above (e.g., a continuously
or intermittently discharged FGD wastewater) may determine that BAT
limitations based on chemical precipitation are appropriate for the
plant's legacy FGD wastewater discharged before its ``as soon as
possible'' date, and that BAT limitations based on chemical
precipitation plus biological treatment are appropriate thereafter. At
the same time, the same plant may have the second type of legacy
wastewater--SI decant and/or dewatering wastewater. For example, the
plant may be dewatering one or more surface impoundments with
historically generated FA and BA transport water, which the permitting
authority could determine should be subject to different BAT effluent
limitations after performing a BPJ analysis. These limitations could be
more or less stringent than the FGD-specific chemical precipitation
limitations derived for discharges before the ``as soon as possible''
date.
Factors the permitting authority must consider when establishing
BPJ-based BAT effluent limitations for these two types of legacy
wastewater are specified in section 304(b) of the CWA, 33 U.S.C.
1314(b), and 40 CFR 125.3(d). EPA solicits comment on whether the
Agency should explicitly promulgate specific elements related to these
factors, which are particular to this wastewater in this industry, in
regulatory text. For example, such specific elements could include: (1)
technologies available at the site, (2) the characteristics of the
legacy wastewater, (3) amount of remaining legacy wastewater, (4) the
treatment option costs, (5) the extent to which CWA requirements would
interfere with surface impoundment closure required under the CCR rule,
(6) the completed stage of closure for each surface impoundment, or (7)
the closure deadline under the CCR rule.
EPA notes that some permitting authorities have actively sought to
regulate these SI decant and dewatering wastewaters (typically through
water quality-based effluent limitations). For example, the state of
North Carolina considered SI decant and dewatering wastewaters in
issuing several permits to Duke Energy. These permits generally limited
SI decant wastewater to a maximum elevation change (e.g., one foot per
day), applied controls to stop decanting if TSS or dissolved pollutants
exceeded some fraction of the discharge limitations (e.g., 50 percent
of TSS, 85 percent of arsenic), and would not drop the water level
below some threshold (e.g., three feet above the CCRs).\91\ These
performance restrictions were also paired with monitoring and reporting
requirements. EPA discussed these permits with North Carolina
regulators who found that this set of restrictions in the uppermost
layer (i.e., SI decant water) have been sufficient to protect receiving
water quality.\92\ EPA also notes that this approach is consistent with
the approach EPRI presents in section 4 of Coal Combustion Residuals
Pond Closure: Guidance for Dewatering and Capping.93 These
same North Carolina permits place water quality-based effluent
limitations on several pollutants that apply once the lower water
levels (i.e., SI dewatering wastewater) are reached. These pollutants
differ for each permit, but generally have led to the inclusion of
physical settling, chemical precipitation, and (for at least one
facility) ZVI treatment \94\ to remove TSS, metals, and selenium/
nutrients, respectively. This makes these systems a potential basis for
BAT for the newly defined SI decant and dewatering wastewaters. In
response to a voluntary information request from EPA, Duke Energy
declined to provide additional data on these systems.\95\ EPA solicits
comment on the costs and performance of all the systems discussed above
and whether any of these systems could be used as a basis for a
nationwide BAT limitations for SI decant and dewatering wastewaters.
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\91\ Requirements differ by permit. Permits are available online
at: www.deq.nc.gov/about/divisions/water-resources/duke-energy-npdes-wastewater-permitting.
\92\ Notes from Meeting with NC DEQ--December 13, 2021
(SE10258).
\93\ EPRI (Electric Power Research Institute). 2014. Coal
Combustion Residuals Pond Closure: Guidance for Dewatering and
Capping. Palo Alto, CA. 3002001117. March.
\94\ Duke Energy Site Visit Notes--November 2021 (SE10259).
\95\ Although Duke declined to provide this information on claim
that it was proprietary information of the vendors, EPA has already
discussed some of these systems with the vendors and notes that the
Agency can protect proprietary information as CBI.
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EPA also learned that Minnesota Power has commissioned an SDE for
its Boswell Energy Center.\96\ On October 4, 2020, the plant also
provided a notice of intent to close its unit 4 surface impoundment
under the CCR rule.\97\ EPA has learned that the SDE is currently used
to evaporate SI decant and dewatering wastewater as part of its closure
process. Once this impoundment is drained, the SDE will treat FGD
blowdown and other plant wastewater such as bottom ash blowdown, pond
water, and cooling tower blowdown. EPA solicits comment on this
system's use, as well as cost and performance data related to this
system. EPA solicits comment on whether an SDE might serve as a
technology basis for BAT for SI decant and dewatering wastewaters.
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\96\ SE10376.
\97\ This filing is available online at: www.mp-ccr.azurewebsites.net/Content/Facilities/Boswell/Closure_And_Post_Closure/BEC%20Pond%204%20Notice%20of%20Intent%20to%20Close.pdf.
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While there may be technologies in use to treat these wastewaters,
EPA notes that the vast majority of SI decant and dewatering wastewater
is likely to have already been discharged pursuant to BPJ
determinations under existing permits rather than in any new permits
implementing any finalized ELG revisions. Rapid closure of many of
these surface impoundments is ongoing under the CCR rule. EPA notes
that the vast majority of surface impoundments had to cease receipt of
waste by April 11, 2021, and commence closure soon after. These surface
impoundments were either unlined and leaking, in violation of location
restrictions, or both. Thus, the vast majority of surface impoundments
have already begun the closure process, of which dewatering is one of
the first steps. Since closure must be completed within five years,
subject to limited extensions,\98\ most surface impoundments
potentially discharging SI decant and dewatering wastewater to comply
with the CCR rule will no longer
[[Page 18853]]
be discharging by 2026. As is the case for all promulgated effluent
limitations guidelines, the requirements for direct dischargers \99\ do
not become applicable to a given discharger until they are contained in
revised NPDES permits. NPDES permits are typically issued for the
maximum allowed five-year permit term. Most permits are not immediately
revised after EPA issues a new ELG rule. Moreover, it is not uncommon
for permits to be administratively continued beyond the five-year
permit term if a permittee submits a timely permit renewal application,
in which case the existing permit stays in effect until a new permit is
effective. EPA expects to issue the final rule in 2024. Thus, even if
these new ELG requirements were implemented into NPDES permits in a
timely manner, the vast majority of SI decant and dewatering wastewater
would have been discharged pursuant to BPJ determinations in existing
permits rather than pursuant to any regulations EPA might promulgate.
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\98\ See 40 CFR 257.102(f).
\99\ Indirect dischargers (those who discharge to POTWs) are
subject to pretreatment standards that are directly implemented and
enforceable. CWA section 307; 40 CFR part 403.
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EPA proposes that a BPJ approach for permitting legacy wastewater
would result in reasonable further progress toward the CWA's goal of
eliminating the discharge of all pollutants because it would allow
permitting authorities to impose more stringent limitations (including
potentially zero-discharge limitations) based on technologies that
remove more pollutants than surface impoundments on a case-by-case
basis, depending on what is technologically available and economically
achievable for individual facilities.
EPA solicits comment on the proposed approach of continuing the
current practice of case-by-case BPJ for determining BAT for legacy
wastewater. EPA also solicits comment on explicitly establishing BAT
equal to BPJ in the text of the regulations in a manner consistent with
CWA section 304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B) and 40 CFR 125.3(d).
b. B. Less Stringent Technologies Than BPJ
EPA is not proposing surface impoundments as the BAT basis for
control of legacy wastewater discharges because there are technologies
more stringent than surface impoundments that could be used at some
plants. Thus, to make reasonable further progress as required by the
CWA, EPA is proposing a case-by-case BAT approach rather than
defaulting to the BPT technology basis for the wastestreams implicated
here. This is in keeping with the Fifth Circuit's order vacating the
2015 legacy wastewater BAT limitations, which were set equal to
previously established BPT limitations based on surface impoundments,
in Southwestern Elec. Power Co. v. EPA, 920 F.3d at 1018.
c. C. More Stringent Technologies and Solicitation of Comments on
Potentially Different Limitations for a Subset of Legacy Wastewater
EPA is not proposing more stringent technologies, such as chemical
precipitation, biological treatment, membrane filtration, thermal
evaporation, and/or spray dryer evaporation as the BAT basis for
controlling discharges of legacy wastewater. EPA is not certain that
these systems can be used nationwide on the vast array of legacy
wastewaters that exist at steam electric plants without disrupting some
plants' already commenced (and contracted for) closure process, thereby
possibly jeopardizing the ability of those plants to meet their closure
deadlines under the CCR rule. However, EPA is soliciting comment on
limitations based on chemical precipitation, biological treatment,
membrane filtration, thermal evaporation, and/or spray dryer
evaporation or any other more stringent technologies that plants may be
using to dewater their surface impoundments. EPA is especially
interested in information related to the technological availability,
economic achievability, and non-water quality environmental impacts of
such technologies. Since these wastewaters are the same wastewaters as
those regulated elsewhere in Part 423, EPA solicits comment on whether
the Agency could transfer limitations, specifically any of the 2015 or
2020 limitations for FGD wastewater (including subcategories or VIP) or
the proposed zero-discharge limitations.
Finally, EPA solicits comment on whether any presumptive standard
or other appropriate constraint should be placed on any BPJ analysis
should the Agency finalize a case-by-case BPJ approach. Even if EPA's
final rule adopts a BPJ standard for deriving BAT limitations for
legacy wastewater, recognizing that the wastewater contained in surface
impoundments can vary across sites in the country, EPA could expect
permitting authorities to thoroughly assess the technologies a plant
already uses (including for treatment of other wastewaters) to
determine whether the legacy wastewater could be directed to those
systems for treatment. This would presumably represent an acceptable
application of BPJ at the plant. For example, if a facility has
installed and already uses an SDE to treat its FGD wastewater, then it
would be reasonable for the permitting authority to find such
technology to be technologically available and economically achievable
to treat legacy wastewater that exists in a surface impoundment
designed to store legacy FGD wastewater.
In contrast to most surface impoundments, EPA has identified 22
surface impoundments at 17 facilities that the record indicates are
composite lined and meet the location restrictions of the CCR rule. A
further discussion of these surface impoundments can be found in Legacy
Wastewater at CCR Surface Impoundments (SE10252). Since these surface
impoundments continue to operate, they would likely not begin closure
and dewatering until after the effective date of any final rule. Thus,
these surface impoundments do not present the same issue as the surface
impoundments which have commenced, or imminently will commence,
closure. A further discussion of these surface impoundments and the
corresponding costs and pollutant loadings associated with candidate
technologies for a potential BAT basis can be found in Legacy
Wastewater at CCR Surface Impoundments (SE10252). EPA solicits comment
on whether the Agency should establish a subcategory or different
limitations applicable to discharges of these wastewaters. EPA solicits
comment on what the subcategory could look like, including what cutoff
could be used to establish this subcategory, as well as whether the
subcategory should apply to surface impoundments that have not
triggered the cease receipt of waste and/or closure requirements of the
CCR rule, to surface impoundments that have not yet begun the
dewatering process, and to just the SI dewatering water where decanting
has already begun or completed. Finally, EPA is currently developing a
proposed CCR rule for legacy surface impoundments at inactive or
retired power plants. EPA solicits comment on the universe of potential
legacy surface impoundments under that rule that may become subject to
any limitations established under a final ELG.
5. Clarification on the Interpretation of 40 CFR 423.10 (Applicability)
With Respect to Inactive/Retired Power Plants and Solicitation of
Comments on Potential Clarifying Changes to Regulatory Text
EPA is clarifying that part 423 applies to discharges of the
proposed SI decant
[[Page 18854]]
and dewatering wastewaters at inactive/retired power plants because the
discharge of these wastewaters ``result[s] from the operation of a
generating unit.'' \100\ Due to the potential expansion of the CCR rule
closure requirements to cover inactive surface impoundments at inactive
(i.e., retired) plants, these surface impoundments will likely need to
dewater and discharge legacy wastewater, specifically SI decant and
dewatering wastewaters. Thus, EPA wishes to clarify the applicability
of these proposed regulations at inactive/retired power plants.
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\100\ 40 CFR 423.10 Applicability. The provisions of this part
apply to discharges resulting from the operation of a generating
unit by an establishment whose generation of electricity is the
predominant source of revenue or principal reason for operation, and
whose generation of electricity results primarily from a process
utilizing fossil-type fuel (coal, oil, or gas), fuel derived from
fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear fuel
in conjunction with a thermal cycle employing the steam water system
as the thermodynamic medium. This part applies to discharges
associated with both the combustion turbine and steam turbine
portions of a combined cycle generating unit.
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On August 21, 2018, the U.S. Court of Appeals for the District of
Columbia issued a decision in Utility Solid Waste Activities Group, et
al. v. EPA, which vacated and remanded the CCR rule provision that
exempted inactive impoundments at inactive facilities from the CCR rule
requirements. As a first step to respond to the Court's order, EPA
sought comments and data on inactive surface impoundments at inactive
facilities in an advanced notice of proposed rulemaking (ANPRM) to help
develop future regulations for these CCR units (85 FR 65015, October
14, 2020). This ANPRM also discussed the related research conducted to
date, described EPA's preliminary analysis of that research, and sought
additional data and public input on issues that may inform a future
proposed rule.
As a result of the ANPRM, EPA's understanding of the potential
universe of legacy surface impoundments has grown. Specifically,
comments by Earthjustice et al. identified an estimated 170 surface
impoundments and 47 landfills at 72 retired power plants in Potential
CCR Legacy Units (2021).101 EPA is currently evaluating this
information, as well as comments submitted by states, local
governments, environmental groups, tribes, and industry, as part of
Hazardous and Solid Waste Management System: Disposal of Coal
Combustion Residuals From Electric Utilities; Legacy Surface
Impoundments (RIN: 2050-AH14).\102\ EPA notes that many of these 72
facilities were still operating for some or all of the period during
which EPA performed its detailed study for the steam electric power
generating industry, 2013 proposal, and 2015 final rule. The record
includes no information that these wastewaters have changed during
closure such that there is any difference between the types of wastes
and wastewaters in these units as compared to units at active power
plants.
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\101\ Available online at: www.regulations.gov/comment/EPA-HQ-OLEM-2020-0107-0073.
\102\ EPA is currently evaluating potential legacy surface
impoundments and intends to include a more refined estimate in its
upcoming proposal.
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EPA wishes to clarify the applicability of 40 CFR part 423 to
inactive/retired plants because some may question whether the existing
effluent guidelines apply to discharges from surface impoundments at
inactive/retired plants. Because the existing requirements under the
ELGs for legacy wastewater were based on the pollutant removals
achieved by surface impoundments (i.e., gravity settling), whether the
rule applied or not did not make a practical difference in terms of the
technology-based limitations for this wastewater. Should EPA finalize
limitations for SI decant and dewatering wastewater at inactive/retired
plants that are more stringent than those based on the treatment
achieved by surface impoundments, it is important that permittees with
the estimated 170 legacy surface impoundments at inactive/retired power
plants understand EPA's interpretation of the rule's applicability.
EPA notes that the current applicability text in Sec. 423.10
conditions applicability on whether a discharge is ``resulting from the
operation of a generating unit.'' Generally, when a plant ceases
electricity production and retires, it either turns off, removes, or
demolishes wastewater equipment such as intakes, cooling towers, pumps,
and other equipment related to power generation. Thus, EPA expects that
most wastewaters would no longer be generated and, therefore, no longer
discharged. In contrast, some wastewaters, such as stormwater, will
clearly continue to be generated and discharged after retirement, but
cannot be said to result from the operation of an EGU. Between these
two groupings of wastewaters lay wastewaters that, but for the
operation of the generating unit, would not have been generated and
discharged. Specifically, the proposed SI decant and dewatering
wastewaters (legacy wastewaters) can be generated years in advance and
retained in surface impoundments, either at the surface of the unit or
in its pore water.
The interpretation above is consistent with EPA's long-time view on
the applicability of part 423 to inactive/retired plants and consistent
with implementation by state permitting authorities. For example, in
2016, South Carolina DHEC reissued a permit to the South Carolina
Electricity & Gas Company's Canadys Station Site (SC0002020) which
stated, ``Because electricity is not being generated, 40 CFR part 423--
Steam Electric Power Generating Point-Source Category will only apply
to the discharge of legacy wastewaters.'' \103\
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\103\ DHEC (Department of Health and Environmental Control).
2016. FACT SHEET AND PERMIT RATIONALE: South Carolina Electric & Gas
Company, Canadys Station Site. NPDES Permit No. SC0002020. May 16.
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In summary, EPA interprets the rule to apply to legacy wastewater
at inactive/retired steam electric power plants. EPA solicits comment
on whether Sec. 423.10 should be amended to further support such a
clarification with respect to legacy wastewater or whether the existing
regulatory text already sufficiently supports this interpretation. In
particular, the current applicability provision means that discharges
of legacy wastewater that occur after the unit has ceased generating
still ``result from'' the operation of the generating unit because but
for the operation of the generating unit, there would be no subsequent
discharge.
EPA solicits comment on whether there are other wastewaters that
may continue to be discharged after the retirement of a facility and
the generation of electricity is the ``but for'' cause of the
discharge. EPA solicits comment on whether the Agency should clarify
its interpretation for any such wastewaters or modify the text of
section 423.10 to further clarify applicability to these wastewaters.
For example, EPA solicits comment on whether CRL generated after
retirement should continue to remain subject to 40 CFR part 423.
Finally, EPA solicits comment on whether there are wastewaters at
retired power plants that the Agency should clarify are explicitly
excluded from the applicability of 40 CFR part 423.
C. Proposed Changes to Subcategories
In the 2015 rule, EPA established subcategories for small EGUs
(less than or equal to 50 MW nameplate capacity) and oil-fired EGUs. In
the 2020 rule, EPA established additional subcategories for high FGD
flow facilities, LUEGUs, and EGUs permanently ceasing coal combustion
[[Page 18855]]
by 2028. For these subcategorized units, EPA established differentiated
limitations with different technology bases from the remaining steam
electric point source category. EPA has authority in a national
rulemaking to establish different limitations 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)
(stating that the CWA does not ``exclude a rule allowing less than
perfect uniformity within a category or subcategory.'').
EPA is not proposing to eliminate the 2015 rule subcategorization
of small EGUs or oil-fired EGUs. Furthermore, while the Agency is
soliciting comment on the permanent cessation of coal combustion
subcategory, it is also not proposing to eliminate this 2020 rule
subcategorization. However, EPA is proposing to remove both the high
FGD flow and low utilization 2020 rule subcategories. EPA is also
proposing a new subcategory for early adopters which permanently cease
coal combustion by December 31, 2032. These subcategories are discussed
below.
1. Plants With High FGD Flows
EPA is proposing to eliminate the high FGD flow subcategory. EPA
proposes that, after evaluating the factors specified in CWA section
304(b)(2)(B), the subcategory is no longer warranted. In the 2020 rule,
EPA evaluated one facility, TVA Cumberland, when it established the
high FGD flow subcategory. At the time, this facility was found to have
the highest costs due to its high FGD flows. Several commenters on the
2019 proposal claimed that this subcategory of one facility was
inconsistent with the CWA, and further contested that the costs
estimated for TVA were overestimated and not disparate.\104\ EPA
acknowledges that its cost estimates were higher than TVA's own
estimates for installing biological treatment, and thus costs may not
be as disparate as indicated in the 2020 rule. Nevertheless, EPA need
not reach a determination on these costs as TVA has since issued a
Federal Register notice for plans to retire the facility, which are
further detailed in a draft Environmental Impact Statement (EIS) (86 FR
25933. May 11, 2021). This draft EIS solicits comment on three
alternatives, all of which include retirement but with different
electricity replacement scenarios.
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\104\ EPA notes that these commenters were also petitioners in
the consolidated Appalachian Voices case discussed in Section IV of
this preamble above.
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EPA bases this proposal principally on TVA's primary decision to
permanently cease coal combustion at the Cumberland plant. Because all
the alternatives TVA is considering (including its preferred
alternative) would result in the plant's retirement, EPA proposes to
eliminate the 2020 rule high FGD flow subcategory as unnecessary. EPA
solicits comment on the 2020 basis of disparate costs used to
subcategorize this facility in the first place. Since this subcategory
consists of only mercury and arsenic limitations based on chemical
precipitation, EPA also solicits comment on whether, should TVA step
back from its retirement plans, elimination of the subcategory would
still be warranted.
2. Low Utilization EGUs (LUEGUs)
EPA proposes to eliminate the low utilization subcategory after
evaluating the factors specified in CWA section 304(b)(2)(B) and based
on EPA's proposed finding that the subcategory is no longer warranted.
EPA proposes that the low utilization subcategory is no longer
warranted given that only one plant has expressed an interest in
availing itself of the BAT limitations in the subcategory, and the
concerns EPA originally sought to address by creating the subcategory
are not present for that plant. EPA established the subcategory for
LUEGUs in the 2020 rule based on cost (disparate capital costs), non-
water quality environmental impacts (including energy requirements),
and other factors the Administrator deemed appropriate (i.e.,
harmonization with CAA and RCRA regulations that apply to electric
utilities). Any facility seeking subcategorization of one or more EGUs
as an LUEGU was required to submit a NOPP to the permitting authority
by October 13, 2021. While EPA did not perform a comprehensive search
for NOPPs, EPA's large collection of NOPPs across several states
(described above in Section VI.B of this preamble) only included one
submission for participation in the LUEGU subcategory from a direct
discharger. This submission was for EGUs at the GSP Merrimack Station
in Bow, New Hampshire. This plant is discussed below.
Merrimack Station has two EGUs (MK1 and MK2). Although these units
were once baseload generating units, over approximately the last 10
years, these units have transitioned to only operating intermittently
when needed, primarily during winter and (even less frequently) summer
months when natural gas supplies are constrained. As provided in
Merrimack Station's 2021 NOPP, MK1 has a nameplate capacity of 113.6 MW
and in 2019 and 2020 had capacity utilization factors (CUFs) of 6.6
percent and 3.6 percent, respectively. MK2 has a nameplate capacity of
345.6 MW and had 2019 and 2020 CUFs of 7.8 percent and three percent,
respectively.
Following Merrimack Station's request for permit modification to
incorporate the 2020 steam electric ELGs for both its BA transport
water and FGD wastewater, the facility submitted a timely NOPP. In its
NOPP, the facility requested coverage under the low utilization
subcategory for both wastestreams, as well as the ability to transition
to the 2020 rule subcategory for permanent cessation of coal combustion
by 2028 or the 2020 rule VIP for its FGD wastewater, pursuant to 40 CFR
423.13(o). EPA acknowledges the facility's request to participate in
the low utilization subcategory but to have the flexibility to
potentially shift to operate under another subcategory or the VIP, as
allowed by the 2020 rule.
However, EPA does not think the subcategory is warranted for this
plant because the facility has already installed an advanced FGD
wastewater treatment system capable of meeting the limitations in this
proposed rule, and thus is not expected to incur any capital costs, let
alone disparate costs, to meet the proposed FGD wastewater limitations.
Moreover, the facility operates in a capacity futures market that helps
offset the financial challenges potentially faced by a facility that
operates at a reduced capacity. Because the cost/financial concerns EPA
discussed in the 2020 rule are not present for this facility, EPA also
proposes to find that there are no grid reliability concerns with
eliminating this subcategory.
After an initial startup period,\105\ Merrimack Station has
operated since 2012 with zero discharges of its FGD wastewater. To
operate with zero discharge, the plant has both a primary and secondary
wastewater treatment system. The primary system consists of
equalization tanks, reaction tanks, a softener, gravity filters, an
enhanced mercury and arsenic removal system, and a holding tank. The
secondary wastewater treatment system, referred to by the facility as
the vapor compression evaporation system, generally consists of a brine
concentrator, two crystallizers, and a belt filter press. Although the
plant has operated with
[[Page 18856]]
zero discharge, in its most recent permit application, the plant at one
point requested authorization to discharge FGD wastewater, but later
withdrew the request. While technically the anti-backsliding provisions
of 40 CFR 122.44(l) do not apply to Merrimack's FGD wastewater (since
it has never had a limitation in its permit), the current permit does
not allow FGD wastewater discharges and thus the permit would
effectively become less stringent through the application of the low
utilization subcategory, which would allow such discharges. Where a
technology has already been in use at a facility for a decade and has
been shown to be available and economically achievable for that
facility, with acceptable non-water quality environmental impacts,
relaxing a permit so use of that technology can be discontinued is
inconsistent with the statute's BAT provisions intended to make
reasonable further progress toward eliminating discharges into U.S.
waters.\106\
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\105\ The wet scrubbers became operational on September 28,
2011. For approximately two years, while the treatment system was
being adjusted and optimized, wastewater was periodically hauled
off-site to local POTWs for disposal.
\106\ This plant is arguably one of the best performing plants
in the industry with respect to its FGD wastewater, further
supporting that subcategorization is not appropriate.
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Furthermore, Merrimack Station receives a production-independent
revenue stream in the form of payments from the Independent System
Operator (ISO) New England region's capacity futures markets. These
competitive markets were designed to ensure sufficient capacity and
reliability for the New England grid as described by ISO New England:
The Forward Capacity Market (FCM) ensures that the New England
power system will have sufficient resources to meet the future
demand for electricity. Forward Capacity Auctions (FCAs) are held
annually, three years in advance of the operating period. Resources
compete in the auctions to obtain a commitment to supply capacity in
exchange for a market-priced capacity payment. These payments help
support the development of new resources. Capacity payments also
help retain existing resources. For example, they incentivize
investment in technology or practices that help ensure strong
performance. They also serve as a stable revenue stream for
resources that help meet peak demand but don't run often the rest of
the year.\107\
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\107\ See www.iso-ne.com/markets-operations/markets/forward-capacity-market/.
In 2019, an independent estimate suggested that, between 2018 and
2023, Merrimack Station would receive approximately $189 million in
these capacity market payments.\108\ Thus, the plant is in a different
financial situation than the other plants discussed in the 2020 rule
record, which EPA was concerned would be forced to prematurely retire
due to costs associated with the rule and reduced utilization and
which, as a result, would potentially impact grid reliability.
Furthermore, the fact that several of the plants that EPA estimated
would participate in the low utilization subcategory in the 2020 rule
record have since retired despite the flexibility of the subcategory
and without causing grid reliability problems suggests that EPA may
have overestimated both the financial viability of these plants and the
threat of reliability issues. Since Merrimack Station also requested
the ability to transfer to limitations for the permanent cessation of
coal combustion subcategory for its discharges of both FGD wastewater
and BA transport water, it is also possible that regardless of any
flexibilities EPA affords, the plant is headed toward retirement. EPA
notes that the ISO New England's last two Forward Capacity Auctions
show a downward trend of reduced capacity commitments for Merrimack
Station.
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\108\ See www.concordmonitor.com/merrimack-station-bow-nh-28840181.
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With respect to BA transport water, Merrimack Station does not have
a dry handling or high recycle rate system. The plant has an unlined
boiler slag pond that is also used to accept other wastestreams from
around the plant. The utility represented to EPA Region 1 permitting
staff that this surface impoundment was not subject to the CCR rule.
EPA plans to further evaluate this issue, but for purposes of
estimating costs for this rule, EPA is currently relying on the
facility's representation and has included costs of BA conversion in
its analysis. Working with EPA Region 1 permitting staff, Merrimack
Station previously represented that it could achieve zero discharge
through construction of a new remote MDS system by 2022.\109\
Furthermore, this system was estimated to cost $14.9 million at
most.\110\ Given the timing of this proposal, Merrimack Station's
representations about what date it could achieve zero discharge and
cost of the relevant BA system are no longer accurate. EPA now
conservatively estimates the raw capital costs of a closed-loop system
to be over $26 million. Of this, approximately $22 million would be for
the installation of a remote MDS and associated equipment, while
approximately $4 million would be capital costs to achieve complete
recycle. As discussed in Section VII.B.2 of this preamble, the over $4
million in capital costs to close the loop may be unnecessary or
overstated, and EPA has incorporated these cost estimates into its
consideration of cost and economic achievability for BA transport water
BAT limitations.
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\109\ See January 30 email from Linda Landis, available online
at: www3.epa.gov/region1/npdes/merrimackstation/pdfs/ar/AR-1513.pdf.
After EPA announced its reconsideration of the 2015 steam electric
rule in 2017, the facility announced it would halt any efforts
toward achieving zero discharge of its BA transport water pending
revision of the rule. See April 20 letter from Linda Landis,
available at: www3.epa.gov/region1/npdes/merrimackstation/pdfs/ar/AR-1362.pdf. Ultimately, EPA issued a renewed NPDES permit for
Merrimack Station in 2020 with a zero discharge BA transport water
limitation to be achieved by December 31, 2023.
\110\ See www3.epa.gov/region1/npdes/merrimackstation/pdfs/final/merrimack-final-rtc-ch-5.pdf.
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After considering the record discussed above, EPA proposes to
remove the 2020 rule low utilization subcategory. The record now
indicates that there has been only one facility seeking to avail itself
of low utilization discharge limitations for FGD wastewater, and that
single facility already has zero discharge treatment equipment in
place. Thus, it is not appropriate to continue the subcategory for this
wastewater, as there are no disparate capital costs, no unacceptable
non-water quality environmental impacts (including potential grid
reliability impacts), and no need to allow this facility to otherwise
discontinue use of its very efficient pollution treatment equipment to
``harmonize'' with other regulations. EPA solicits comment on whether
any additional facilities with FGD wastewater have submitted NOPPs for
the low utilization subcategory of which the Agency is not aware.
Finally, EPA does not think that Merrimack Station's costs (e.g.,
in installing and operating a technology to meet the proposed BA
transport water limitations), even if higher, warrant a special
subcategory, given that this facility receives a production-independent
revenue stream in the form of payments from New England's capacity
futures markets. EPA is continuing to examine whether the plant's
unlined slag settling pond is ``a natural topographic depression, man-
made excavation, or diked area, which is designed to hold an
accumulation of CCR and liquids, and the unit treats, stores, or
disposes of CCR.'' \111\ Should the slag settling pond meet this
definition, the unlined status of this pond would mean the facility is
obligated under the CCR rule to cease receipt of waste in the surface
impoundment and construct an alternative BA handling system,
eliminating any potentially disparate
[[Page 18857]]
capital costs associated with meeting potentially more stringent BA
transport water limitations. Even if the pond is not subject to the CCR
rule, EPA questions whether there would be disparate costs for treating
BA transport water at Merrimack Station, which receives capacity market
payments designed specifically to allow the plant to stay in operation
for reliability purposes, even though its operating costs may not
otherwise be recouped by the plant's low sales without those payments.
EPA further notes that, while courts have upheld subcategorization
based on consideration of statutory factors, courts have also upheld
BAT based on consideration of the point source category as a whole. See
Texas Oil & Gas Ass'n et al. v. EPA, 161 F.3d 923, 928 (5th Cir. 1998)
(``[I]n promulgating ELGs, EPA must set discharge limits reflecting
best available technology that EPA determines to be economically
feasible across the category or subcategory as a whole.'').
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\111\ 40 CFR 257.53.
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Finally, EPA solicits comment on the level of recycling that this
plant's BA transport water system could employ, with or without
additional modifications to the plant. For example, in the 2020 rule
record, NRG Energy suggested that it would be able to recycle all its
BA transport water from an existing surface impoundment system by
merely changing the flow of existing sumps. Should comments demonstrate
that Merrimack Station's two EGUs are necessary for reliability, that
the slag settling pond is not a CCR surface impoundment, and that the
costs for upgrading BA transport water systems are too great to bear in
light of the unique circumstances above, EPA also solicits comment on
whether the LUEGU subcategory should be retained only for BA transport
water and/or for plants with a lower capacity utilization rate
(CUR).\112\ Finally, EPA solicits comment on whether future LUEGUs
should be subcategorized such that they must only achieve the 2020 rule
BAT limitations for FGD wastewater, which would still be less costly
than the zero-discharge limitations of the current proposal.
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\112\ For example, in comments provided during state and local
government consultations, IMPA suggested a seven percent CUR.
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3. EGUs Permanently Ceasing Coal Combustion by 2028
After evaluating the record, and to help establish certainty for
the regulated community, EPA proposes to: maintain the subcategory for
EGUs permanently ceasing coal combustion by 2028 for the reasons
discussed below, modify reporting and recordkeeping requirements,
clarify how limitations should be written into permits, and extend the
period to file the initial notice of planned participation.
a. The Subcategory Continues To Be Warranted
EPA proposes that, after evaluating the factors specified in CWA
section 304(b)(2)(B), the subcategory continues to be warranted. EPA
established this subcategory in the 2020 rule based on the statutory
factors of cost (the cost burden on these facilities is greater because
they have less time to recoup investments); the age of the equipment
and plants involved (the remaining useful life of the plants and their
pollutant control equipment is shorter than for typical plants);
potential non-water quality environmental impacts, including energy
requirements (early retirement of these plants could affect energy
supply); and harmonization with the CCR rule alternative closure
provisions. EPA continues to find that these factors weigh in favor of
the subcategory but solicits comment on several issues, as detailed
below.
With respect to cost and age, the 2020 rule record included an
analysis showing that amortization of capital costs for less than the
typical 20-year life of pollution control equipment leads to disparate
annualized costs until after about eight years, which at the time was
2028. Many plants made decisions at the time of the 2020 rule to opt
for the alternative retirement compliance pathway, and they are now
several years into meeting the milestones for that path.
Similarly, with respect to non-water quality environmental impacts,
including energy requirements, a review of new information continues to
support this subcategory in some instances. First, utilities have
planned and budgeted for replacement capacity under timelines approved
by public utility commissions (PUCs) and public service commissions
(PSCs) as part of the normal integrated resource planning process.
These submissions were made since the 2020 rule, as part of the 2020
rule's eight-year window to permanently cease coal combustion. EPA does
not think it should disrupt these ongoing plans by changing the date.
There will continue to be some plants for which replacement capacity is
not an issue due to excess reserve margins, and others where
replacement capacity is still necessary but changes in the power sector
(including the Inflation Reduction Act) may allow for replacement
capacity to be constructed more quickly. That said, EPA thinks that
maintaining the same timeframe allowed by the prior rule supports
efforts planned as a result of the 2020 rule and weighs in favor of
retaining the same date in a revised rule.
Second, with respect to air pollution, EPA notes that several
utilities have accelerated their retirement of coal-fired power plants
and construction of replacement capacity. For example, the DTE filed a
NOPP for this subcategory for its Belle River Power Plant and is
accelerating the plant's retirement from 2030 to 2028. Replacing coal-
fired capacity with natural gas, renewables, and other sources leads to
decreased emissions of several air pollutants. The subcategory allows
utilities already seeking to accelerate retirements to do so and
achieve the associated air pollution reductions (a non-water quality
environmental impact), which further supports the proposed finding that
the subcategory continues to be warranted.
In addition, EPA still wishes to harmonize this rule with the CCR
rule alternative closure provisions, which have not changed. Twenty-
five plants are seeking to use the CCR rule's alternative closure
provisions, which allow for closure of the unlined impoundment(s) and
the power plant no later than 2023 (for surface impoundments under 40
acres) or 2028 (surface impoundments over 40 acres).\113\ Elimination
of the permanent cessation of coal combustion subcategory from this ELG
could potentially interfere with the plans of utilities with surface
impoundments in the 2028 category, complicating their compliance with
the CCR rule. Furthermore, EPA has also solicited comment on a
corresponding flexibility under the proposed Good Neighbor Plan,
discussed in Section IV.E.2.a of this preamble, above.\114\
Harmonization between regulations on air, water, and land pollution
gives industry certainty to plan and implement these requirements in an
orderly, efficient manner.
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\113\ Further information is available online at: www.epa.gov/coalash/coal-combustion-residuals-ccr-part-implementation.
\114\ ``To facilitate a potentially economic and environmentally
superior unit-level compliance response across these programs that
nonetheless maintains the NOX reductions required by the
state budgets from 2026 forward in this proposal, EPA is requesting
comment on potentially deferring the application of the backstop
daily rate for large coal EGUs that submit written attestation to
EPA that they make an enforceable commitment to retire by no later
than the end of calendar year 2028.'' 87 FR 20036, 20122 (April 6,
2022).
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Finally, EPA notes that even if the permanent cessation of coal
combustion subcategory were eliminated in a final
[[Page 18858]]
rule, it is unlikely to result in more stringent limitations in time to
affect these plants. As discussed elsewhere in this proposal, EPA
intends to issue a final rule in 2024, and the rule's requirements
would not be implemented for direct dischargers until permitting
authorities issue new permits incorporating those limitations. Since
permits are typically not immediately reissued upon promulgation of a
new rule, and the rule would likely allow some time to accomplish the
new more stringent requirements as soon as possible, but not later than
approximately five years after promulgation (i.e., no later than
December 31, 2029), it is likely that the 2028 permanent cessation of
coal combustion date would have passed before a new ``no later than''
date under a new permit implementing the rule. Furthermore, in many
cases, retirements and fuel conversions are planned to be completed
well before 2028, with some already having occurred. After considering
all the information above, EPA proposes that the consideration of the
factors that led to the creation of this subcategory in the 2020 rule
not only continues to weigh in favor of subcategorization but may be
stronger than at the time of the 2020 rule. Thus, EPA proposes to
retain this subcategory in its current form.
EPA solicits comment on the proposal to retain the subcategory. EPA
also solicits comment on additional information that would suggest
eliminating the subcategory, selecting a more stringent BAT for the
subcategory, or specifying that BAT should be determined by the
permitting authority on a case-by-case, BPJ basis. EPA explicitly
solicits comment on a constrained BPJ approach whereby the permitting
authority could require more stringent limitations where a facility has
previously installed technologies that were designed to achieve
pollutant removals beyond those achievable with surface impoundments,
or alternatively, limitations based specifically on the more advanced
technologies that a facility has previously installed. EPA is
interested in whether these alternate approaches might better achieve
the goals of the CWA, which requires reasonable further progress toward
the elimination of discharges.
b. Clarification of Existing Limitations
As a clarification of how existing limitations should be written
into permits, EPA also proposes to explicitly require permitting
authorities to include in these sources' permits limitations requiring
zero discharge of FGD wastewater and BA transport water after December
31, 2028, to ensure that permit requirements accurately reflect that no
discharges of these wastewaters are allowed after the cessation of coal
combustion date applicable to the subcategory. If the plant fails to
cease combustion of coal by 2028 for any reason other than those
specified in section 423.18, the zero-discharge limitations would
automatically apply. These provisions are costless, and merely clarify
the intent that plants which get the benefit of this subcategory do so
because they will no longer discharge after 2028. To help ensure that
facilities benefitting from less stringent requirements between the
effective date of any final rule and the closure date are truly going
to meet the deadline for participation in the subcategory, EPA is
proposing to add this requirement.
Proposal to Extend NOPP Filing Deadline Should EPA Receive Adverse
Comment and Withdraw Related Direct Final Rule. Utilities have
continued to assess and consider plans for plants and EGUs as part of
their normal integrated resource planning process. ``Representatives
from Utilities and trade associations suggested that these continued
evaluations have led additional facilities to seek accelerated
retirement or fuel conversion of coal-fired power plants beyond those
for which NOPPs were filed by the 2020 rule's October 13, 2021,
deadline. Having not filed a NOPP by the 2021 deadline, such facilities
would be forced to incur capital expenditures to install technologies
to meet the 2020 rule limitations, thus receiving disparate treatment
from those who filed a NOPP by October 13, 2021. EPA is proposing to
change the NOPP filing date to 60 days after publication of a final
rule. However, the Agency notes that following the public comment
period and time to consider any comments on this issue, EPA would
likely be unable to finalize a rule earlier than summer 2023, which
would leave industry without certainty that plants that had not
previously filed NOPPs might still be able to avail themselves of the
2020 subcategory for plants ceasing coal combustion by 2028. Given the
lead times necessary to procure and install 2020 rule-compliant
technologies (e.g., biological treatment), the regulated community
would benefit from certainty that such a provision will be finalized
much sooner than summer 2023 to guarantee that unnecessary costs can
still be avoided.\115\ Thus, separately from this proposed rule, EPA is
publishing a related direct final rule that changes the date of the
NOPP filing to June 27, 2023, which will take effect on May 30, 2023
assuming EPA does not receive any adverse comments on the direct final
rule. As described in the direct final rule, any adverse comment on the
direct final rule must be received by April 28, 2023 if the commenter
wishes to keep the direct final rule from taking effect.
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\115\ EPA notes that, given the timeframes for procurement and
installation of 2020 rule-compliant technologies presented in the
2020 rule record, utilities would have to start incurring expenses
around the end of the comment period of this proposal to avoid the
risk of noncompliance with the 2020 rule.
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While EPA is promulgating a direct final rule to extend the NOPP
deadline to June 27, 2023, EPA is through this proposal also proposing
to extend the NOPP deadline to 60 days after publication of a final
rule. Thus, if EPA receives adverse comment on the direct final rule
within 30 days of publication and subsequently withdraws that rule, the
Agency still has the option of finalizing its proposal to extend the
NOPP filing deadline. It is possible that EPA could take final action
on this aspect of the rule prior to the rest of the proposed rule. If
EPA does not receive adverse comment on the direct final rule and it
takes effect, then the Agency would not plan to finalize this aspect of
the proposal. In connection with the proposal to extend the NOPP filing
deadline to 60 days after publication of a final rule, EPA solicits
comment on briefly extending the NOPP filing deadline to allow for
these additional retirements and fuel conversions to qualify for
treatment under this subcategory. EPA solicits comment on specific
information suggesting that specific plants or EGUs not the subject of
a previously filed NOPP would consider permanently ceasing coal
combustion by December 31, 2028. This could include new integrated
resource plans, new retirement announcements, or other similar
information. EPA solicits comment on whether a different NOPP filing
deadline is appropriate and information demonstrating why. Any comments
on this aspect of this proposal should clearly state that they are
being made in response to the proposed extension of the NOPP filing
deadline rather than on the direct final rule being published elsewhere
in this issue of the Federal Register.
c. Additional Reporting and Recordkeeping Requirements
For a discussion of additional reporting and recordkeeping
requirements, see Section XV.C.1 of this preamble.
[[Page 18859]]
4. Subcategory for Early Adopters Retiring by 2032
EPA is proposing a new subcategory for plants that have achieved
compliance either with the 2015 or 2020 rule limitations on FGD
wastewater and BA transport water by publication of this proposed rule,
and which elect to retire no later than December 31, 2032. EPA further
proposes to explicitly require, as a condition for being eligible for
this subcategory, that permitting authorities include the BAT
limitations (proposed here as zero discharge of FGD wastewater and BA
transport water) in these sources' permits after December 31, 2032.
This will ensure that permits accurately reflect that no discharges of
these wastewaters are allowed after the cessation of coal combustion
date applicable to the subcategory. If a plant fails to cease
combustion of coal by 2032 for any reason other than those specified in
section 423.18, the zero-discharge limitations would automatically
apply. After evaluating the factors specified in CWA section
304(b)(2)(B), EPA proposes that such a subcategory is warranted on the
basis of cost (disparate costs to facilities with these units), age
(both the age of the new pollution treatment technology and the
remaining useful life of the plant), non-water quality environmental
impacts (air pollution), and other factors the Administrator deems
appropriate (impacts to early adopters who relied on the identification
of biological treatment as BAT for FGD wastewater in the 2015 and 2020
rules). For units in this subcategory, EPA proposes limitations based
on the same technology bases for control of FGD wastewater and BA
transport water in the 2020 rule, which EPA proposes are available, are
economically achievable, and have acceptable non-water quality
environmental impacts.
As discussed in Section IV of this preamble above, discharges from
steam electric plants have been the subject of proposed and final
regulations for the past decade, an unsurprising fact given this
industry's long tenure among the top industrial point source
discharges.\116\ Some utilities and states pushed forward pursuant to
the 2015 and 2020 rules with biological treatment and dry or closed-
loop BA handling systems (even where these systems turned out to have a
purge), and have achieved compliance with the limitations in those
rules by the date of publication of this proposed rule. This proposal
refers to those facilities as ``early adopters.'' In contrast, other
utilities have avoided incurring any cost for as long as possible, and
as a result may be better poised to adjust to today's more stringent
proposal. Thus, EPA considered how the statutory factors may justify a
balancing of these equities.
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\116\ See, e.g., Effluent Guidelines Plan 14/Preliminary
Effluent Guidelines Plan 15, available online at: www.epa.gov/eg/effluent-guidelines-plan.
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EPA gathered as much information as possible to consider when early
adopter units might plan to close in order to qualify for this
subcategory. With respect to disparate costs and age (remaining life of
the EGU), EPA continued to gather information from publicly available
sources, company announcements, industry public comments, and
government databases to identify EGUs that may have already installed
2020 rule-compliant technologies. Many of these EGUs have already
announced retirement by 2032 or soon thereafter.\117\ EPA presents a
list of such EGUs in Table VII-1 of this preamble below. As shown in
the table, the record includes 15 EGUs at five plants that have already
adopted technologies to comply with the 2015 or 2020 rules that may
incur costs under the proposal without a subcategory for early
adopters. Under Option 3, these EGUs combined have estimated capital
costs of $51 million and estimated operations and maintenance (O&M)
costs of $4 million per year. Under Option 4, these EGUs combined have
estimated capital costs of $110 million and estimated O&M costs of $11
million per year. Thus, the costs for the rule more than double without
subcategorization of these units. Furthermore, accounting for the
remaining useful life of these EGUs, costs in many cases would be
amortized over periods shorter than the assumed 20-year life of the
equipment. As discussed in the 2020 rule record and above in the
discussion for the subcategory for EGUs permanently ceasing coal
combustion by 2028, amortization periods shorter than eight years may
lead to disparate costs.
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\117\ Even the one EGU with a retirement date of 2040
(Mountaineer Unit 1) recently contemplated retirement by 2028 when
both Virginia and Kentucky rejected rate recovery for ELG-compliant
upgrades to AEP's coal-fired power plants.
Table VII-1--Early Adopters
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3 costs Option 4 costs
---------------------------------------------------------------
Plant name SE Unit ID Retire year Capacity (MW) Capital Capital
(2021$) O&M (2021$) (2021$) O&M (2021$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Plant James H Miller Jr........... SE Unit-1........... N/A 706 $0 $0 $4,700,000 $130,000
Plant James H Miller Jr........... SE Unit-2........... N/A 706 0 0 4,700,000 130,000
Plant James H Miller Jr........... SE Unit-3........... N/A 706 0 0 4,700,000 130,000
Plant James H Miller Jr........... SE Unit-4........... N/A 706 0 0 4,700,000 130,000
Marshall Steam Station............ SE Unit-1........... 2028 380 2,800,000 210,000 4,900,000 540,000
Marshall Steam Station............ SE Unit-2........... 2028 380 2,800,000 210,000 4,900,000 540,000
Marshall Steam Station............ SE Unit-3........... 2032 658 4,900,000 370,000 9,200,000 1,100,000
Marshall Steam Station............ SE Unit-4........... 2032 660 4,900,000 370,000 7,300,000 750,000
Mountaineer Plant................. SE Unit-1........... 2040 1,300 7,300,000 780,000 17,000,000 2,200,000
Gallatin.......................... SE Unit-1........... 2035 300 2,300,000 110,000 3,700,000 250,000
Gallatin.......................... SE Unit-2........... 2035 300 2,300,000 110,000 3,700,000 250,000
Gallatin.......................... SE Unit-3........... 2035 328 2,500,000 120,000 4,000,000 270,000
Gallatin.......................... SE Unit-4........... 2035 328 2,500,000 120,000 4,000,000 270,000
Belews Creek Steam Station........ SE Unit-1........... 2035 1,110 9,700,000 790,000 18,000,000 2,100,000
Belews Creek Steam Station........ SE Unit-2........... 2035 1,110 9,700,000 790,000 19,000,000 2,300,000
-----------------------------------------------------------------------------------------------
Total......................... .................... .............. 9,675 51,000,000 4,000,000 110,000,000 11,000,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Totals may not add due to rounding.
With respect to non-water quality environmental impacts, including
energy requirements, a review of new information supports the creation
of this subcategory. Replacement of coal-fired capacity with natural
gas, renewables,
[[Page 18860]]
and other sources leads to decreased emissions of several air
pollutants, including GHGs. Thus, to the extent that the subcategory
allows utilities already seeking to accelerate retirements in response
to the Inflation Reduction Act and other factors the ability to do so
and achieve the associated air pollution reductions (a non-water
quality environmental impact), it further supports the proposed finding
that the subcategory is warranted.
With respect to age (of pollution treatment equipment) and ``other
factors'' the Administrator deems appropriate, EPA considered the
impacts of expecting early adopters to meet new limitations based on
technologies different than those identified as the technology bases in
the 2015 and 2020 rules. As stated above, the ELGs for direct
discharges are implemented in permits. Some facilities have diligently
applied for and obtained permits implementing the 2015 or 2020 rules'
limitations for FGD wastewater and BA transport water and installed
technologies that meet those limitations. Several utilities have
biological treatment that could meet the 2020 rule limitations. For
example, Duke Energy made a fleetwide conversion to chemical
precipitation plus biological treatment and ultrafiltration for its FGD
wastewater, despite EPA's reconsideration of the 2015 rule. In part,
continued investments in FGD wastewater treatment technologies by Duke
and others were driven by permit limitations.\118\ However, at least
some of these plants relied upon EPA's continued determinations in the
2019 proposal and 2020 final rule that some form of biological
treatment was still BAT for FGD wastewater. It is also worth noting
that some of these utilities may not have been able to select more
stringent technologies, even under the 2020 VIP, in part because PUCs/
PSCs would not agree to this higher cost unless the more stringent
limitations were legally required. Thus, several companies installed a
technology unable to achieve the same zero-discharge limitations that
the BAT basis proposed in Option 3 (chemical precipitation plus
membrane filtration) can achieve. While some of these systems were
installed over a decade ago and may have already achieved some payback,
in other cases these systems are new and far from the end of their
useful life. For this reason, it is appropriate for EPA to consider the
additional cost associated with these early adopters having to meet a
new set of limitations.
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\118\ See, e.g., water quality-based effluent limitations at
Plant Miller (SE08188).
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EPA notes that these same plants that have already incurred costs
for FGD wastewater treatment technologies have also moved forward with
converting previous surface impoundment-based BA transport water
systems. These conversions often occurred due to a combination of the
CCR and ELG rules. Nevertheless, in instances where a plant incurred
capital costs to install a remote MDS, the plant may similarly face the
task of adjusting this system to operate zero discharge for additional
costs in conjunction with the costs of installing additional FGD
wastewater treatment technologies. EPA notes that the costs to upgrade
the BA handling system are typically relatively small, with EPA's
conservative estimates of capital and O&M costs averaging approximately
$4 million up front and $370,000 per year for each EGU. For this
reason, EPA does not propose extending this subcategory to facilities
with high recycle rate BA transport systems that have not also
installed biological treatment or comparable systems for FGD
wastewater.\119\
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\119\ Note that many facilities also meet existing 2020 FGD
wastewater BAT limitations because they either do not generate or do
not discharge FGD wastewater. This subcategory would not apply to
such facilities.
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EPA solicits comment on several issues regarding this subcategory,
including whether the subcategory is warranted based on the record.
Many of the solicitations below are in direct response to suggestions
from utilities and trade associations that were similar to, but
contained differences from, the proposed subcategory. For example, EPA
solicits comment on whether costs are disparate in light of the
relatively higher utilization of some of these EGUs and the ability of
utilities to lease the additional treatment stages necessary to meet
any new limitations. EPA solicits comment on alternate cutoff dates the
Agency could use for early adoption. For example, EPA could make the
cutoff date earlier than publication of the proposed rule (e.g., full
compliance by the announcement of this rulemaking in 2021) or later
(e.g., any facility that had already entered into a binding contract by
the signature date of the proposal).\120\ EPA also solicits comment on
whether early adoption should be required at all, or whether the Agency
should merely include a new subcategory for retirement by 2032 rather
than 2028, as discussed above. In the case of such a change, EPA
solicits comment on the appropriate BAT limitations until that time.
EPA also solicits comment on whether the early adopter subcategory
should require a different date for the permanent cessation of coal
combustion. EPA is undertaking rulemakings related to EGUs under the
CAA and solicits comment on whether the permanent cessation of coal
combustion date proposed here should be harmonized with any CAA rule
that is ultimately promulgated. EPA solicits comment on whether the
Agency should finalize an early adopter subcategory that would be
available to early adopters of the 2015/2020 rule technology bases (or
similar bases), whether they plan to retire by a certain date or not.
Whether or not the subcategory is tied to retirement, EPA also solicits
comment on whether the early adopter subcategory should be limited such
that less stringent limitations based on 2015/2020 rule technologies
would only be available to a plant until the capital investment of the
previous technologies has been paid back. EPA solicits comment on
whether, after a full payback period has passed, an early adopter
should immediately be subject to any new, more stringent limitations.
EPA also solicits comment on whether the Agency should allow
participation in this subcategory if the plant is not retiring, but
instead converting to other fuels (e.g., natural gas), as was done in
the 2020 rule for the EGUs permanently ceasing coal combustion by 2028
subcategory.
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\120\ For an example of the latter approach, see 40 CFR
122.29(b)(4)(ii) as it relates to defining new sources.
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EPA solicits comment on whether this subcategory should be extended
to facilities other than those that installed biological treatment or
ZVI treatment for FGD wastewater. ZVI is an equivalent technology to
biological treatment that several plants had identified could meet the
limitations during the 2020 rulemaking but couldn't achieve zero
discharge. Although EPA isn't aware of any completed installations of
ZVI, the Agency does not wish to close the door on any facilities that
had similar reliance interests but installed the competitor technology.
EPA solicits comment on whether an early adopter subcategory should
include facilities that have already met both the FGD wastewater and BA
transport water limitations for the LUEGU or high FGD flow subcategory
by any means, not by a specified treatment technology. EPA also
solicits comment on whether the subcategory should include facilities
that have only met the limitations for BA transport water because they
have no FGD wastewater. If so, EPA solicits comment on whether it
should require that early adopters for BA transport
[[Page 18861]]
water actually incurred capital costs to install a remote MDS system
rather than merely recycling wastewater through existing systems (e.g.,
through surface impoundments). EPA also solicits comment on whether BA
transport water should be included in the subcategory at all, or
alternatively whether the subcategory should apply only to early
adopters of FGD wastewater technologies.
D. Additional Rationale for the Proposed PSES and PSNS
Before establishing PSES/PSNS for a pollutant, EPA examines whether
the pollutant ``passes through'' a POTW to WOTUS or interferes with the
POTW operation or sludge disposal practices. In determining whether a
pollutant passes through POTWs for these purposes, EPA typically
compares the percentage of a pollutant removed by well-operated POTWs
performing secondary treatment to the percentage removed by the BAT/
NSPS technology basis. A pollutant is determined to pass through POTWs
when the median percentage removed nationwide by well-operated POTWs is
less than the median percentage removed by the BAT/NSPS technology
basis. EPA establishes pretreatment standards for those pollutants
regulated under BAT/NSPS that pass through POTWs.
EPA is continuing to rely on the pass-through analysis as the basis
of the limitations and standards in the 2015 rule, which found that
mercury and arsenic in CRL are not significantly removed by POTWs. As
in the 2015 rule, EPA also did not conduct its traditional pass-through
analysis for wastestreams with proposed zero-discharge limitations or
standards. Zero-discharge limitations and standards achieve 100 percent
removal of pollutants; therefore, all pollutants in those wastestreams
treated by the proposed zero discharge technologies would otherwise
pass through the POTW absent application of those technologies.
After considering all the relevant factors and technology options
presented in this preamble and in the TDD, EPA is proposing to
establish PSES for indirect dischargers based on the technologies
described in Option 3. EPA is proposing the Option 3 technologies as
the bases for PSES for the same reasons that the Agency is proposing
the Option 3 technologies as the bases for BAT for direct
dischargers.\121\ EPA's analysis shows that, for both direct and
indirect dischargers, the Option 3 technologies are available and
economically achievable, and Option 3 has acceptable non-water quality
environmental impacts, including energy requirements (see Sections VIII
and X of this preamble). For the preferred option (Option 3), EPA is
not proposing other technology bases for PSES for the same reasons that
the Agency is not proposing other technology bases for BAT.
Furthermore, for the same reasons that apply to EPA's proposed
retention of differentiated BAT limitations for EGUs permanently
ceasing coal combustion by 2028 and creation of differentiated
limitations for early adopters, EPA proposes the same flexibilities in
PSES under Option 3.
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\121\ Since Dallman has converted to a direct discharger
(SE10256), EPA projects that the proposed PSES for FGD wastewater
would not apply to any plants.
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With respect to the low utilization subcategory, EPA proposes to
eliminate the PSES subcategory for LUEGUs, as it does for direct
dischargers, after considering specific facts for the lone indirect
discharge from a LUEGU. EPA is only aware of one indirect discharger
that has filed a NOPP to avail itself of this subcategory, the
Whitewater Valley Station. Whitewater Valley Station consists of two
EGUs (Coal Boiler #1 and Coal Boiler #2). Coal Boiler #1 has a
nameplate capacity of 35 MW and a 2019 and 2020 CUR of five percent and
3.67 percent, respectively. Coal Boiler #2 has a nameplate capacity of
65 MW and a 2019 and 2020 CUR of 5.5 percent and 5.1 percent,
respectively. On the IMPA website, the Agency states that the station
``has been utilized by IMPA during peak load periods during the hot
summer months and cold winter months.'' \122\ EPA notes that Coal
Boiler #1 need not have been included in this facility's NOPP filing as
this EGU is small enough to avail itself of the 2015 rule subcategory
for small EGUs (i.e., less than or equal to 50 MW nameplate capacity).
---------------------------------------------------------------------------
\122\ See www.impa.com/about-impa/generation-resources/giant-tcr.
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Whitewater Valley Station does not generate or discharge FGD
wastewater but does generate BA transport, water which it has
historically discharged indirectly through a POTW. According to
comments filed during consultations with state and local government
entities and associations, IMPA described a treatment chain it might
utilize for this subcategory:
``Under the existing system, LUEGUs will be able to use gravity
settling in surface impoundments to remove Total Suspended Solids
(TSS). Low utilization subcategory EGUs then must develop and
implement a best management practice (BMP) plan to minimize the
discharge of pollutants from BA transport water. As an example, an
IMPA facility that plans to apply the low utilization subcategory
transports its BA transport water through a settlement and
filtration system that removes TSS and other contaminants before
discharging to the relevant POTW for treatment.'' \123\
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\123\ Available online at: www.regulations.gov, Document ID:
EPA-HQ-OW-2009-0819-9020.
EPA estimated this facility would need to employ two under-boiler
MDS systems because of the CCR requirement to cease receipt of waste in
the facility's unlined surface impoundments. However, the comment
excerpted above (received after EPA had completed its analysis)
suggests that has already taken, and possibly finalized, an alternative
treatment system that is not zero discharge, given the CCR rule's April
2021 cease receipt of waste deadline.
Nevertheless, EPA proposes to eliminate the LUEGU subcategory for
indirect dischargers. With respect to FGD wastewater under the LUEGU
subcategory, no NOPPs were filed from indirect dischargers requesting
this subcategory for this wastestream. Thus, continued existence of
this subcategory is unnecessary. With respect to BA transport water,
EPA has not evaluated costs for Whitewater Valley Station's Coal Boiler
#2 for the reasons discussed above, but again notes that no costs would
be imposed for Coal Boiler #1 as it could continue to discharge under
the less stringent limitations in the 2015 subcategory for small units.
Given the very low utilization of the two EGUs, EPA solicits comment on
whether the peaking function of Whitewater Valley Station could
continue by utilizing only Coal Boiler #1 after 2028 if the facility
transitioned Coal Boiler #2 into the permanent cessation of coal
combustion subcategory.\124\ EPA also solicits comment on the specific
pollution controls in place at the Whitewater Valley Station, as well
as the levels of pollution reduction that system achieves both alone
and in combination with the downstream POTW via which the facility
discharges its BA transport water. For PSES, EPA also solicits comment
on the same issues discussed in Section VII.C.2 of this preamble for
direct dischargers. Finally, EPA solicits comment on whether the LUEGU
subcategory should be retained for BA transport water for indirect
dischargers only.
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\124\ Note that small EGUs are not limited to a 10 percent CUR.
---------------------------------------------------------------------------
For purposes of the proposed PSES, EPA also proposes the same
definitional changes for legacy wastewater that were
[[Page 18862]]
proposed for BAT in Section VII.B.4 of this preamble. For the same
reasons as the proposed BAT determination, EPA proposes to decline
establishing a nationally applicable PSES for wastewater generated
before the ``as soon as possible'' date, SI decant wastewater, and SI
dewatering wastewater. The effect of not finalizing PSES for this set
of wastewaters would mean that any pretreatment standards in addition
to those set forth in 40 CFR part 403 would need to be established as
local limits by the control authority.
E. Availability Timing of New Requirements
Where BAT limitations in the 2015 and 2020 rules are more stringent
than previously established BPT limitations, those BAT limitations do
not apply until a date determined by the permitting authority that is
``as soon as possible'' after considering four factors.\125\ Depending
on the particular wastewater, the 2015 and 2020 rules also established
a ``no later than'' date of December 31, 2023, and/or December 31,
2025, for reasons discussed in the record of those rules, including
that without such a date, implementation could be substantially
delayed, and a firm ``no later than'' date creates a more level playing
field across the industry.
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\125\ These factors are: (1) Time to expeditiously plan
(including to raise capital), design, procure, and install equipment
to comply with the requirements of the final rule; (2) changes being
made or planned at the plant in response to GHG regulations for new
or existing fossil fuel-fired power plants under the Clean Air Act,
as well as regulations for the disposal of coal combustion residuals
under subtitle D of the Resource Conservation and Recovery Act; (3)
for FGD wastewater requirements only, an initial commissioning
period to optimize the installed equipment; and (4) other factors as
appropriate. 40 CFR 423.11(t).
---------------------------------------------------------------------------
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 for plants to meet the
proposed rule's limitations and standards. Specifically, EPA selected
the timeframes described above to enable many plants to raise needed
capital, plan and design systems, procure equipment, and construct and
test systems. EPA also considered the timeframes needed for appropriate
consideration of any plant changes being made in response to other
Agency rules affecting the steam electric power generating industry.
EPA understands that some plants may have already installed, or are now
installing, technologies that could comply with the proposed
limitations. Therefore, EPA proposes that the earliest date some plants
can achieve compliance with these new limitations would be the
effective date of any final rule. Where this is not the case, nothing
in this proposal would preclude a permitting authority from
establishing a later date, up to the ``no later than'' date, after
considering the four specific factors in 40 CFR 423.11(t).
With respect to the latest compliance dates, EPA collected updated
information regarding the technical availability of the proposed
technology bases. Information in EPA's rulemaking record indicates that
a typical timeframe to raise capital, plan and design systems
(including any necessary pilot testing), procure equipment, and
construct and test systems falls well within the existing five-year
permit cycle.\126\ Furthermore, the chemical precipitation and zero
discharge technologies proposed here do not implicate the same
industrywide competition over a small number of biological treatment
vendors that the 2020 rule implicated. EPA notes that while plants may
not need approximately five years to comply with the proposed
limitations, the ``no later than'' date creates an outer boundary
beyond which no discharger may seek additional time and creates a level
playing field regarding the latest date. Therefore, EPA proposes that
any final limitations be achieved ``no later than'' December 31, 2029.
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\126\ See FGD and Bottom Ash Implementation Timing (SE08480).
---------------------------------------------------------------------------
As with the proposed BAT effluent limitations, in considering the
availability and achievability of the proposed PSES, EPA concluded that
existing indirect dischargers need some time to achieve the final
standards, in part to avoid forced outages. While the BAT limitations
apply on a date determined by the permitting authority that is as soon
as possible beginning on the effective date of any final rule (but no
later than December 31, 2029), under CWA section 307(b)(1),
pretreatment standards shall specify a time for compliance not to
exceed three years from the date of promulgation, so EPA cannot
establish a longer implementation period. Moreover, unlike requirements
on direct discharges, requirements on indirect discharges are not
implemented through NPDES permits. Nevertheless, EPA proposes to find
that all existing indirect dischargers can meet the standards within
three years of promulgation. There will be no remaining indirect
dischargers of FGD wastewater by the time any final rule is
promulgated. With respect to BA transport water, EPA estimates that a
closed-loop system can achieve zero discharge within 35 months, and
substantially sooner if a high recycle rate system is already
operating.\127\ Finally, with respect to CRL, EPA estimates the
chemical precipitation systems can achieve the mercury and arsenic
limitations within 22 months.\128\ Thus, the proposed PSES technologies
are available in the proposed timeframe. Further discussion of
availability timing can be found in Section XV of this preamble.
---------------------------------------------------------------------------
\127\ SE08480.
\128\ SE10289.
---------------------------------------------------------------------------
F. Economic Achievability
As explained in detail in Section VIII of this preamble, below,
EPA's analysis for the proposed BAT limitations and PSES demonstrates
that they are economically achievable for the steam electric industry
as a whole, as required by CWA section 301(b)(2)(A). EPA used IPM to
perform cost and economic impact assessments, using a baseline that
reflects impacts from other relevant environmental regulations (see
RIA).\129\ For the proposed rule, the model showed very small
additional effects on the electricity market, on both a national and
regional sub-market basis. Based on the results of these analyses, EPA
estimated that the proposed rule requirements would result in a net
reduction of 249 MW in steam electric generating capacity as of the
model year 2030, reflecting full compliance by all plants. This
capacity reduction corresponds to a net effect of approximately one EGU
closure or, when aggregating to the level of steam electric generating
plants, one early plant closure.\130\ These IPM results support EPA's
conclusion that the proposed rule is economically achievable.
---------------------------------------------------------------------------
\129\ IPM is a comprehensive electricity market optimization
model that can evaluate such impacts within the context of regional
and national electricity markets. See Section VIII of this preamble
for additional discussion.
\130\ Given the design of IPM, unit-level and thereby plant-
level projections are presented as an indicator of overall
regulatory impact rather than a precise prediction of future unit-
level or plant-specific compliance actions. The projected net plant
closure occurs at a plant whose only steam electric EGU had a
capacity utilization of only six percent in the baseline.
---------------------------------------------------------------------------
G. Non-Water Quality Environmental Impacts
The proposed BAT limitations and PSES have acceptable non-water
quality environmental impacts, including energy requirements. Section X
of this preamble describes EPA's analysis of
[[Page 18863]]
non-water quality environmental impacts and energy requirements in more
detail. EPA estimates that by 2029, under the proposed rule and
reflecting full compliance, energy consumption would increase by less
than 0.003 percent of the total electricity generated by power plants.
EPA also estimates that the amount of fuel consumed by increased
operation of motor vehicles (e.g., for transporting waste) would
increase by approximately 0.0005 percent of total fuel consumption by
all motor vehicles.
EPA also evaluated the effect of the BAT effluent limitations on
air emissions generated by all electric power plants (NOX,
SOX, and CO2), solid waste generation, and water
usage. Under the proposed rule, depending on the year, CO2
emissions are projected to decrease by 0.1 to 1.1 percent,
NOX emissions are projected to decrease by 0.6 to 2.4
percent, and SO2 emissions are projected to decrease by 0.2
to 3.9 percent due to changes in the mix of electricity generation
(e.g., less electricity from coal-fired steam EGUs and more electricity
from natural gas-fired steam EGUs). Moreover, solid waste generation is
projected to increase by less than one percent of total solid waste
generated by all electric power plants. Finally, EPA estimates that the
proposed rule will have a positive impact on water withdrawal, with
steam electric power plants reducing the amount of water they withdraw
by 4.33 billion gallons per year (11.8 MGD).
H. Impacts on Residential Electricity Prices and Low-Income and
Minority Populations
EPA examined the effects of the proposed rule on consumers as an
additional factor that might be appropriate when considering what level
of control represents BAT. If all annualized compliance costs were
passed on to residential consumers of electricity instead of being
borne by the operators and owners of power plants (a conservative
assumption), the average yearly electricity bill increase for a typical
household would be no more than $0.63 under the proposed rule. For
further information see Chapter 7 of the RIA.
EPA also considered the effect of the proposed rule on minority and
low-income populations. As explained in Section XVI of this preamble,
using demographic data regarding who resides closest to steam electric
power plant discharges, who fishes in downstream waterbodies, and who
consumes drinking water from downstream drinking water treatment
plants, EPA concluded that low-income and minority populations benefit
to an even greater degree than the general population from the
reductions in discharges associated with the proposed rule.
VIII. Costs, Economic Achievability, and Other Economic Impacts
EPA evaluated the costs and associated impacts of the four
regulatory options on existing EGUs at steam electric plants. These
costs are analyzed within the context of existing environmental
regulations, market conditions, and other trends that have affected
steam electric plant profitability and generation, as described in
Section V.B of this preamble. 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 detail.
In developing ELGs, and as required by CWA section 301(b)(2)(A),
EPA evaluates the economic achievability of regulatory options to
assess the impacts of applying the limitations and standards to the
industry as a whole, which typically includes an assessment of
incremental plant closures attributable to a regulatory option. As
described in more detail below, this proposed ELG is expected to result
in incremental costs when compared to baseline. Like the prior analysis
of the 2015 and 2020 rules, the cost and economic impact analysis for
this proposed rulemaking focuses on understanding the magnitude and
distribution of compliance costs across the industry and the broader
market impacts. EPA used indicators to assess the impacts of the four
regulatory options on the whole steam electric power generating
industry. These indicators are consistent with those used to assess the
economic achievability of the 2015 rule and 2020 rule. For this
proposal, EPA compared the values to a baseline that reflects
implementation of existing environmental regulations (as of this
proposal), including the 2020 rule. As such, the baseline appropriately
includes the costs of achieving the 2020 rule limitations and
standards, and the policy cases show the impacts resulting from
potential changes to the existing 2020 limitations and standards. More
specifically, EPA considered the total cost to industry and change in
the number and capacity of specific EGUs and plants expected to close
under the proposed rule (Option 3) compared to baseline. EPA also
analyzed the ratio of compliance costs to revenue to see how the four
main regulatory options change the number of plants and their owning
entities that exceed thresholds indicating potential financial strain.
In addition to the analyses supporting the economic achievability of
the regulatory options, EPA conducted other analyses to (1)
characterize other potential impacts of the regulatory options (e.g.,
on electricity rates) and (2) to meet the requirements of E.O.s or
other statutes (e.g., E.O. 12866, Regulatory Flexibility Act, Unfunded
Mandates Reform Act).
A. Plant-Specific and Industry Total Costs
EPA estimated plant-specific costs to control FGD wastewater, BA
transport water, and CRL discharges at existing EGUs at steam electric
plants to which the ELGs apply. EPA assessed the operations and
treatment system components currently in place at a given unit (or
expected to be in place because of other existing regulations,
including the 2020 ELG rule), identified equipment and process changes
that plants would likely make under each of the four regulatory options
presented in Table VII-1 of this preamble, and estimated the capital
and O&M costs to implement those changes. As explained in the TDD, the
baseline also accounts for additional announced unit retirements,
conversions, and relevant operational changes that have occurred since
EPA promulgated the 2020 rule. Following the same methodology used for
the 2015 and 2020 rule analyses, EPA used a rate of seven percent to
annualize one-time costs and costs recurring on other than an annual
basis. For capital costs and initial one-time costs, EPA used a 20-year
amortization period. For O&M costs incurred at intervals greater than
one year, EPA used the interval as the annualization period (e.g., five
years, 10 years). EPA added annualized capital, initial one-time costs,
and the nonannual portion of O&M costs to annual O&M costs to derive
total annualized plant costs. EPA then calculated total industry costs
by summing plant-specific annualized costs. For the assessment of
industry costs, EPA considered costs on both a pre-tax and after-tax
basis.
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
[[Page 18864]]
analyses are conducted using after-tax costs).
Table VIII-1 of this preamble summarizes estimates of incremental
pre- and post-tax industry costs for the four regulatory options
presented in Table VII-1 of this preamble as compared to baseline. The
after-tax annualized costs of the proposed rule (Option 3) are $181
million.
Table VIII-1--Estimated Total Annualized Industry Costs
[Millions of 2021$, seven percent discount rate]
------------------------------------------------------------------------
Regulatory option Pre-tax After-tax
------------------------------------------------------------------------
Option 1................................ $102.4 $81.1
Option 2................................ 189.0 149.0
Option 3................................ 230.5 181.2
Option 4................................ 241.3 189.6
------------------------------------------------------------------------
B. Social Costs
Social costs are the costs of the proposed rule from the viewpoint
of society as a whole, rather than the viewpoint of regulated plants
and owning entities (which are private costs). In calculating social
costs, EPA tabulated the pre-tax costs in the year they are estimated
to be incurred, which varies across plants based on the estimated
compliance year. EPA performed the social cost analysis over a 25-year
period of 2025 to 2049, which combines the length of the period during
which plants are anticipated to install the control technologies (which
could be as late as 2029) and the useful life of the longest-lived
technology installed at any plant (20 years). EPA calculated the social
cost of the proposed rule using both a primary three percent discount
rate and an alternative seven percent discount rate. 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, there were no
incremental increases in the cost to state governments to revise NPDES
permits. Consequently, the only category of costs used to calculate
social costs are those pre-tax costs estimated for steam electric
plants. Note that the annualized social costs presented in Table VIII-2
of this preamble for the seven percent discount rate differ from
comparable pre-tax industry compliance costs shown in Table VIII-1 of
this preamble. The costs in Table VIII-1 of this preamble represent the
annualized costs of each option if they were incurred in 2024, whereas
the annualized costs in Table VIII-2 of this preamble are estimated
based on the stream of future costs starting in the year that
individual plants are projected to comply with the requirements of the
proposed options.
Table VIII-2 of this preamble presents the total annualized social
costs of the four regulatory options, compared to baseline and
calculated using three percent and seven percent discount rates. The
proposed rule (Option 3) has estimated incremental social costs of $200
million using a three percent discount rate and $216 million using a
seven percent discount rate.
Table VIII-2--Estimated Total Annualized Social Costs
[Millions of 2021$, three and seven percent discount rate]
------------------------------------------------------------------------
3% Discount 7% Discount
Regulatory option rate rate
------------------------------------------------------------------------
Option 1................................ $88.4 $96.6
Option 2................................ 167.0 180.4
Option 3................................ 200.3 216.5
Option 4................................ 207.2 224.1
------------------------------------------------------------------------
C. Economic Impacts
EPA assessed the economic impacts of this proposed rule in two
ways: (1) a screening-level assessment of the cost impacts on existing
EGUs at steam electric plants and the entities that own those plants,
based on comparison of costs to revenue and (2) an assessment of the
impacts within the context of the broader electricity market, which
includes an assessment of changes in predicted plant closures
attributable to the proposed rule. The following sections summarize the
results of these analyses. The RIA discusses the methods and results in
greater detail.
The first set of cost and economic impact analyses--at both the
plant and parent company level--provides screening-level indicators of
the impacts of costs for FGD wastewater, BA transport water, and CRL
controls relative to historical operating characteristics of steam
electric plants incurring those costs (i.e., level of electricity
generation and revenue). EPA conducted these analyses for baseline and
for the four regulatory options presented in Table VII-1 of this
preamble, then compared these impacts to understand the incremental
effects of the regulatory options in this proposal.
The second set of analyses looks at broader electricity market
impacts, considering the interconnection of regional and national
electricity markets. This analysis also looks at the distribution of
impacts at the plant and EGU level. This second set of analyses
provides insight on the impacts of the proposed rule on steam electric
plants, as well as the entire electricity market, including changes in
capacity, generation, and wholesale electricity prices. The market
analysis compares model predictions for the proposed rule to a base
case that includes the predicted and observed economic and market
effects of the 2020 rule and other environmental regulations.
1. Screening-Level Assessment
EPA conducted a screening-level analysis of each regulatory
option's potential impact on existing EGUs at steam electric plants and
parent entities based on cost-to-revenue ratios. For each of the two
levels of analysis (plant and parent entity), the Agency assumed, for
analytic convenience and as a worst-case scenario, that none of the
compliance costs would be passed on to consumers through electricity
rate increases and would instead be absorbed by the steam electric
plants and their parent entities. This assumption overstates the
impacts of compliance expenditures since steam electric plants that
operate in a regulated market may be able to pass on changes 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 impacts.
a. Plant-Level Cost-to-Revenue Analysis
EPA developed revenue estimates for this analysis using EIA data.
EPA then calculated the change in the annualized after-tax costs of the
four regulatory options presented in Table VII-1 of this preamble 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.
Cost-to-revenue ratios are screening-level indicators of potential
economic impacts. EPA guidance describes certain cost-to-revenue ratios
for evaluating small entity impacts under the RFA (U.S. EPA 2006).\131\
As described in the Guidance, 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 economic
impact.
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\131\ U.S. Environmental Protection Agency. (2006). Final
Guidance for EPA Rulewriters: Regulatory Flexibility Act as Amended
by the Small Business Regulatory Enforcement Fairness Act.
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Under the proposed rule (Option 3), EPA estimated that 19 plants
would incur incremental costs greater than or equal to one percent of
revenue,
[[Page 18865]]
including three plants that have costs greater than or equal to three
percent of revenue, and an additional 73 plants would incur costs that
are less than one percent of revenue. Section 4.2 in the RIA provides
results for the other regulatory options EPA analyzed.
b. Parent Entity-Level Cost-to-Revenue Analysis
EPA also assessed the economic impact of the regulatory options
presented in Table VII-1 of this preamble at the parent entity level.
The screening-level cost-to-revenue analysis at the parent entity level
provides insight on the impact on those entities that own existing EGUs
at steam electric plants. In this analysis, the domestic parent entity
associated with a given plant is defined as the entity with the largest
ownership share in the plant. For each parent entity, EPA compared the
incremental change in the total annualized after-tax costs and the
total revenue for the entity to baseline (see Chapter 4 of the RIA for
details). Following the methodology employed in the analyses for the
2015 and 2020 rules, EPA considered a range of estimates for the number
of entities owning an existing EGU at a steam electric plant to account
for partial information available for steam electric plants that are
not expected to incur ELG compliance costs.
Like the plant-level analysis above, cost-to-revenue ratios provide
screening-level indicators of potential economic impacts, this time to
the owning entities; higher ratios suggest a higher probability of
economic impacts. EPA estimated that the number of entities owning
existing EGUs at steam electric plants ranges from 229 (lower-bound
estimate) to 427 (upper-bound estimate), depending on the assumed
ownership structure of plants not incurring ELG costs and not
explicitly analyzed. EPA estimates that under the proposed rule (Option
3), four parent entities would incur annualized costs representing one
percent or more of their revenues, including one parent entity that
would incur costs representing more than three percent of revenue.
2. Electricity Market Impacts
To analyze the impacts of regulatory actions affecting the electric
power sector, EPA commonly uses IPM, a comprehensive electricity market
optimization model that can evaluate such impacts within the context of
regional and national electricity markets. The model is designed to
evaluate the effects of changes in EGU-level electric generation costs
on the total cost of electricity supply, subject to specified demand
and emissions constraints. Use of a comprehensive market analysis
system is important in assessing the potential impact of any power
plant regulation because of the interdependence of EGUs 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 average likelihood that
various units are dispatched. The analysis also provides important
insight on steam electric capacity closures (e.g., retirements of EGUs
that become uneconomical relative to other EGUs), based on a more
detailed analysis of market factors than in the screening-level
analyses above.
In contrast to the screening-level analyses, which are static
analyses and do not account for interdependence of EGUs in supplying
power to the electricity transmission grid, IPM 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 for steam electric
EGUs due to the regulatory options. Additionally, in contrast to the
screening-level analyses, in which EPA assumed no cost pass-through of
ELG compliance costs, IPM depicts production activity in wholesale
electricity markets where the specific increases in electricity prices
for individual markets would result in some recovery of compliance
costs for plants. IPM is based on an inventory of U.S. utility- and
nonutility-owned EGUs and generators that provide power to the
integrated electric transmission grid, including plants to which the
ELGs apply.
EPA analyzed proposed Option 3 using IPM. The results of this
analysis further inform EPA's understanding of the potential impacts of
the proposed rule (Option 3). The version of IPM used for this
analysis, IPM V6, embeds an energy demand forecast that is derived from
DOE's ``Annual Energy Outlook 2021'' (AEO 2021). IPM also incorporates
the expected compliance response into existing regulatory requirements
for regulations affecting the power sector, including the 2020 ELG
rule, CSAPR and CSAPR Update, MATS rule, the final 2014 CWA section
316(b) rule, and the final 2015 CCR rule and CCR Part A rule. The
reference case also includes the effects of the Regional Greenhouse Gas
Initiative; California's Global Warming Solutions Act; Renewable
Portfolio Standards state-level policies, including recent Clean Energy
Standards in Illinois, Oregon, Delaware, North Carolina, and
Massachusetts; and the 45Q tax credit for CO2 sequestration.
In analyzing the proposed option, EPA estimated incremental fixed
and variable costs for the steam electric plants and EGUs to comply
with Option 3. 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 steam EGU and input these
costs into the IPM model as fixed and variable O&M cost adders in
addition to the costs already reflected in the Base Case, which
included compliance with the 2020 ELG rule (the baseline analysis). EPA
then ran IPM with these new cost estimates to determine the dispatch of
EGUs that would meet projected demand at the lowest costs, subject to
the same constraints as those in the baseline analysis. The estimated
changes in plant- and EGU-specific production levels and costs--and, in
turn, changes in the electric power sector's total costs and production
profile--are key data elements in evaluating the expected national and
regional effects of the regulatory options in this proposal, including
closures or avoided closures of 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 nonsteam electric
plants); (2) impact on steam electric plants as a group, and (3) impact
on individual steam electric plants incurring costs. Chapter 5 of the
RIA discusses the first analysis; the sections below summarize the last
two, which are further described in Chapter 5 of the RIA. All results
presented below are representative of modeled market conditions in the
model year 2030, when the plants will have implemented changes to meet
the proposed ELGs.
a. Impacts on Existing Steam Electric Power Plants
EPA used IPM results for 2030 to assess the potential impact of the
proposed rule on existing EGUs at steam electric plants. The purpose of
this analysis is to assess any fleetwide changes from baseline impacts
on EGUs at steam electric plants. Table VIII-3 of this preamble reports
estimated results for existing EGUs at steam electric plants, as a
group. EPA looked at the following metrics: (1) incremental early
retirements and capacity closures, calculated as the difference between
capacity under the regulatory option
[[Page 18866]]
and capacity under baseline; (2) incremental capacity closures as a
percentage of baseline capacity; (3) change in electricity generation
from plants subject to the ELGs; (4) changes in variable production
costs per MWh, calculated as the sum of total fuel and variable O&M
costs divided by net generation; and (5) changes in annual costs (fuel,
variable O&M, fixed O&M, and capital). Note that changes in electricity
generation at steam electric plants presented in Table VIII-3 of this
preamble are attributable both to changes in retirements and changes in
capacity utilization at operating EGUs and plants.
Table VIII-3--Estimated Impact of the Proposed Rule (Option 3) on Steam Electric Plants as a Group at the Year
2030
----------------------------------------------------------------------------------------------------------------
Change attributable to the
proposed rule as compared to
Metric Baseline value baseline
-------------------------------
Value Percent
----------------------------------------------------------------------------------------------------------------
Total capacity (MW)............................................. 274,256 -249 -0.1
Early retirement or closure (MW)................................ 56,422 249 0.4
Early retirement or closure (number of plants).................. 28 1 3.6
Total generation (GWh).......................................... 1,226,067 -5,703 -0.5
Average variable production cost (2021$/MWh).................... $21.63 $0.02 0.1
Annual cost (million 2021$)..................................... $44,427 $2 0.0
----------------------------------------------------------------------------------------------------------------
MW = megawatt; MWh = megawatt-hour; GWh = gigawatt-hour = 1,000 MWh.
Under the proposed rule, generation at steam electric plants is
projected to decrease by 5,703 GWh (0.5 percent) nationally when
compared to baseline. IPM projects a net decline in total steam
electric capacity by 249 MW (approximately 0.1 percent of total
baseline capacity) due to early retirement attributable to this
proposal. One additional plant is projected to retire early under the
proposed rule when compared to baseline. See section 5.2.2.2 in the RIA
for details.
These findings suggest that the proposed rule can be expected to
have small economic consequences for steam electric plants as a group.
Option 3 would affect the operating status of very few steam electric
plants, with only one additional plant closure (a plant with very low
capacity utilization of less than six percent in baseline).
b. Impacts on Individual Plants Incurring Costs
To assess potential plant-level effects, EPA also analyzed plant-
specific changes attributable to the proposed 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 cost plus fuel cost divided by net generation. The
analysis of changes in individual plants is detailed in Chapter 5 of
the RIA. The results indicate that most plants would experience only
slight effects--i.e., no change or less than a one percent reduction or
one percent increase. Across the full set of steam electric plants
modeled, 30 plants would incur a reduction in generation of at least
one percent; 18 of these plants are also estimated to incur a reduction
in capacity utilization of at least one percent. Of the subset of 46
steam electric plants that would incur costs under Option 3, 19 plants
incur a decrease in generation, whereas 16 plants see no change, 10
plants close in baseline, and one additional plant closes under Option
3.
IX. Pollutant Loadings
In developing ELGs, EPA typically evaluates the pollutant loading
reductions of regulatory options to assess the impacts of the
compliance requirements on discharges from the whole industry. EPA took
the same approach to the one described above for plant-specific costs
for estimating pollutant reductions associated with this proposal. That
is, EPA compared the values to a baseline that reflects implementation
of existing environmental regulations, including the 2020 rule for FGD
wastewater and BA transport water.
The general methodology that EPA used to calculate pollutant
loadings is the same as that described in the 2020 rule. EPA first
estimated--on an annual, per plant basis--the pollutant discharge load
associated with the technology bases evaluated for plants to comply
with the 2020 rule requirements for FGD wastewater and BA transport
water, accounting for the current or planned conditions at each plant.
For CRL, EPA estimated the pollutant discharge load associated with
current discharges. For all wastestreams, EPA similarly estimated
plant-specific post-compliance pollutant loadings as the load
associated with the technology bases for plants to comply with effluent
limitations based on each regulatory option in this proposal. For each
regulatory option, 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 loads for each
applicable wastestream.
For plants that discharge indirectly to POTWs, EPA adjusted the
baseline and option loads to account for pollutant removals expected
from POTWs. These adjusted pollutant loadings for indirect dischargers
therefore reflect the resulting discharges to receiving waters. For
additional details on the methodology EPA used to calculate pollutant
loading reductions, see section 6 of the TDD.
A. FGD Wastewater
For FGD wastewater, EPA continued to use the average pollutant
effluent concentration with plant-specific discharge flow rates to
estimate the mass pollutant discharge per plant for baseline and each
proposed regulatory option in Table VII-1 of this preamble. EPA used
data compiled for the 2015 and 2020 rules as the initial basis for
estimating discharge flow rates and updated the data to reflect
retirements or other relevant changes in operation. As in the 2020
rule, EPA also accounted for increased rates of recycle through the
scrubber that would affect the discharge flow.
EPA assigned pollutant concentrations for each analyte based on the
operation of a treatment system designed to comply with baseline or the
regulatory options. EPA used data compiled for the 2020 rule to
characterize FGD chemical precipitation plus LRTR effluent and chemical
[[Page 18867]]
precipitation plus membrane filtration effluent. In addition, EPA used
data provided by industry and other stakeholders during the 2020 rule,
as described in Section IV of this preamble, to quantify bromide in FGD
wastewater under baseline conditions and for the four regulatory
options.
B. BA Transport Water
EPA estimated baseline and post-compliance loadings for each
regulatory option in Table VII-1 of this preamble using pollutant
concentrations for BA transport water and plant-specific flow rates.
EPA used data compiled for the 2020 rule as the basis for estimating BA
transport water discharge flows and updated the data set to reflect
retirements and other relevant changes in operation (e.g., ash handling
conversions, fuel conversions) that have occurred since collecting the
2020 rule data. Under the baseline, which reflects the 2020 rule
requirement for the high recycle rate technology option (or BMP plan in
the case of Merrimack Station), EPA estimated discharge flows
associated with the purge from remote MDS operation, based on the
generating unit capacity and the volume of the remote MDS. Under the
zero discharge option, EPA estimated a flow rate of zero.
C. CRL
For CRL, EPA used the average pollutant effluent concentration with
plant-specific discharge flow rates to estimate the mass pollutant
discharge per plant for baseline and chemical precipitation (proposed
in each regulatory option) in Table VII-1 of this preamble. EPA used
data compiled for the 2015 rule as the initial basis for estimating
discharge flow rates and updated the data to reflect retirements. EPA
also used utilities' ``CCR Rule Compliance Data and Information''
websites to identify new landfills constructed since 2015. For new
landfills, EPA used the 2015 methodology to estimate leachate flow
proportionate to landfill size, if available, or as the median leachate
volume (in gallons per day (GPD)) calculated from the 2010 steam
electric survey.
EPA assigned pollutant concentrations for each analyte based on
current operating conditions or treatment in place for baseline and the
operation of a treatment system designed to comply with the four
regulatory options. EPA used data compiled for the 2015 rule to
characterize untreated CRL and, as in the 2015 rule, transferred the
average FGD effluent concentrations for chemical precipitation.
D. Legacy Wastewater
EPA is not proposing nationally applicable BAT limitations or PSES
for legacy wastewater and, therefore, did not estimate changes in
loadings under the regulatory options. EPA has nevertheless evaluated
the scope of pond dewatering and decant wastewaters and associated
baseline pollutant discharges in Legacy Wastewater at CCR Surface
Impoundments (SE10252). As discussed in Section VII.B.4 of this
preamble, EPA is soliciting comment on various technologies that could
potentially serve as a technology basis for BAT for these two specific
legacy wastewaters. EPA has evaluated the potential costs and pollutant
removals of these technologies as part of its Legacy Wastewater at CCR
Surface Impoundments (SE10252).
E. Summary of Incremental Changes of Pollutant Loadings From Four
Regulatory Options
Table IX-1 of this preamble summarizes the net reduction to annual
pollutant loadings, compared to baseline, associated with each
regulatory option in Table VII-1 of this preamble. Compared to the 2020
rule (baseline), all regulatory options result in decreased pollutant
loadings to surface waters.
Table IX-1--Estimated Incremental Reductions in Annual Pollutant Loading
for Regulatory Options 1, 2, 3, and 4 [in Pounds/Year] Compared to
Baseline
------------------------------------------------------------------------
Reductions in
annual
Regulatory option pollutant
loadings
------------------------------------------------------------------------
1....................................................... 18,100,000
2....................................................... 575,000,000
3....................................................... 584,000,000
4....................................................... 639,000,000
------------------------------------------------------------------------
Note: Reductions in pollutant loadings are rounded to three significant
figures.
X. Non-Water Quality Environmental Impacts
The elimination or reduction of one form of pollution may create or
aggravate other environmental problems. Therefore, sections 304(b) and
306 of the CWA require EPA to consider non-water quality environmental
impacts (including energy requirements) associated with ELGs.
Accordingly, EPA has considered the potential impact of the regulatory
options in this proposal on air emissions, solid waste generation, and
energy consumption. In general, EPA used the same methodology (with
updated data as applicable) as it did for the analyses supporting the
2015 and 2020 rules to conduct this analysis. The following sections
summarize the methodology and results. See section 7 of the
supplemental TDD for additional details.
A. Energy Requirements
Steam electric power plants use energy when transporting ash and
other solids on or off site, operating wastewater treatment systems
(e.g., chemical precipitation, membrane filtration), or operating ash
handling systems. For this proposal, EPA considered whether there would
be an associated change in the incremental energy requirements compared
to baseline. Energy requirements vary depending on the regulatory
option evaluated and the current operations of the facility. 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 all four
regulatory options. EPA summed the facility-specific estimates to
calculate the net change in energy requirements from baseline for the
regulatory options.
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 any changes
in the fuel consumption associated with transporting solid waste and
combustion residuals (e.g., ash) from steam electric power plants to
landfills (on- or off-site). The frequency and distance of transport
depends on a plant's operation and configuration; specifically, the
volume of waste generated and the availability of either an on-site or
off-site nonhazardous landfill and its distance from the plant. Table
X-1 of this preamble shows the net change in annual electrical energy
usage associated with the regulatory options compared to baseline, as
well as the net change in annual fuel consumption requirements
associated with the four regulatory options compared to baseline.
[[Page 18868]]
Table X-1--Estimated Incremental Change in Energy Requirements Associated With Regulatory Options Compared to
Baseline
----------------------------------------------------------------------------------------------------------------
Energy use associated with regulatory options
Non-water quality environmental impact ---------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Electrical energy usage (MWh)................... 38,000 126,000 139,000 151,000
Fuel (thousand gallons)......................... 53.0 122 622 639
----------------------------------------------------------------------------------------------------------------
B. Air Pollution
The four proposed regulatory options are expected to affect air
pollution through three main mechanisms: (1) changes in auxiliary
electricity use by steam electric plants to operate wastewater
treatment, ash handling, and other systems needed to comply with
regulatory requirements; (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 regulatory
requirements. This section discusses air emission changes associated
with the first two mechanisms and presents the corresponding estimated
net changes in air emissions. See Section XII.B.3 of this preamble for
additional discussion of the third mechanism.
Steam electric power plants generate air emissions from operating
transport vehicles, such as dump trucks, which release criteria air
pollutants and GHGs. Similarly, a decrease in energy use or vehicle
operation would result in decreased air pollution.
To estimate the net air emissions associated with changes in
electrical energy use projected as a result of the regulatory options
in this proposal compared to 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 estimated NOX, SO2, and
CO2 emissions using plant- or North American Electric
Reliability Corporation (NERC)-specific emission factors (ton/MWh)
obtained from IPM for run year 2035.\132\
---------------------------------------------------------------------------
\132\ While EPA only ran IPM for the proposed rule (Option 3),
EPA extrapolated the benefits estimated using these IPM outputs to
options 1, 2, and 4 to provide insight on the potential air quality-
related effects of the other regulatory options. See Section 8 of
the BCA for details.
---------------------------------------------------------------------------
To estimate net air emissions associated with the change in
operation of transport vehicles, EPA used the MOVES2021b model to
identify air emission factors (gram per mile) for the air pollutants of
interest. EPA estimated the annual number of miles that dump trucks
moving ash or wastewater treatment solids to on- or off-site landfills
would travel for the regulatory options. EPA used these estimates to
calculate the net change in air emissions for the four regulatory
options. Table X-2 of this preamble presents EPA's estimated net change
in air emissions associated with auxiliary electricity and
transportation for the proposed options.
Table X-2--Estimated Net Change in Industry-Level Air Emissions Associated With Auxiliary Electricity and
Transportation for Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
Non-water quality environmental impact Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
CO2 (million tons/year)......................... 0.03 0.12 0.13 0.14
NOX (thousand tons/year)........................ 0.02 0.065 0.081 0.085
SO2 (thousand tons/year)........................ 0.022 0.06 0.07 0.072
----------------------------------------------------------------------------------------------------------------
The modeled output from IPM predicts changes in electricity
generation due to compliance costs attributable to the proposed options
compared to 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.\133\ A
summary of the net change in annual air emissions associated with
Option 3 for all three mechanisms are shown in Table X-3 of this
preamble. As with costs, the IPM run from this option reflects the
range of non-water quality environmental impacts associated with all
four regulatory options. To provide some perspective on the estimated
changes, EPA compared the estimated change in air emissions to the net
amount of air emissions generated in a year by all electric power
plants throughout the United States. For a detailed breakout of each of
the three sources of air emission changes, see section 7 of the TDD.
---------------------------------------------------------------------------
\133\ EPA also considered changes in particulate matter (see
Section XII.B.3 of this preamble). As explained in the BCA Chapter
8.1: ``IPM outputs include estimated CO2, NOX, and
SO2 emissions to air from EGUs. EPA also used IPM outputs
to estimate EGU emissions of primary PM2.5 based on
emission factors described in U.S. EPA (2020c). Specifically, EPA
estimated primary PM2.5 emissions by multiplying the
generation predicted for each IPM plant type (ultrasupercritical
coal without carbon capture and storage, combined cycle, combustion
turbine, etc.) by a type-specific empirical emission factor derived
from the 2016 National Emissions Inventory (NEI) and other data
sources. The emission factors reflect the fuel type (including coal
rank), FGD controls, and state emission limits for each plant type,
where applicable.''
[[Page 18869]]
Table X-3--Estimated Net Change in Industry-Level Air Emissions
Associated With Changes in Auxiliary Electricity, Transportation, and
Electricity Generation for Proposed Option 3 Compared to Baseline
------------------------------------------------------------------------
2020 emissions
Change in by electric
Non-Water quality environmental impact emissions-- power
option 3 generating
industry
------------------------------------------------------------------------
CO2 (million tons/year)................. -11 1,650
NOX (thousand tons/year)................ -5.1 1,020
SO2 (thousand tons/year)................ -5.8 954
------------------------------------------------------------------------
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). EPA estimated the change in the amount of solids
generated under each regulatory option for each plant compared to
baseline. Table X-4 of this preamble shows the net change in annual
solid waste generation, compared to baseline, associated with the four
regulatory options.
Table X-4--Estimated Incremental Changes to Solid Waste Generation Associated With Regulatory Options Compared
to Baseline
----------------------------------------------------------------------------------------------------------------
Solid waste generation associated with regulatory options
Non-Water quality environmental impact -------------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Solids generated (tons/year)................ 236,000 1,220,000 1,240,000 1,330,000
----------------------------------------------------------------------------------------------------------------
EPA also evaluated the potential impacts of diverting FA from
current beneficial uses toward encapsulation of membrane filtration
brine for disposal in a landfill. According to the latest American Coal
Ash Association survey,\134\ more than half of the FA generated by
coal-fired power plants is being sold for beneficial uses rather than
disposed, and the majority of this beneficially used FA is replacing
Portland cement in concrete. This also holds true for the specific
facilities currently discharging FGD wastewater and expected to install
membranes under proposed Option 3, as seen by sales of FA in the 2020
EIA-923 Schedule 8A.\135\ Summary statistics of the FA beneficial use
percentage for these facilities is displayed in Table X-5 below.
---------------------------------------------------------------------------
\134\ Available online at: www.acaa-usa.org/wp-content/uploads/coal-combustion-products-use/2016-Survey-Results.pdf.
\135\ Available online at: www.eia.gov/electricity/data/eia923/.
Table X-5--Percent of FA Sold for Beneficial Use at Facilities
Discharging FGD Wastewater
------------------------------------------------------------------------
FA percent
sold for
Statistic beneficial use
(percent)
------------------------------------------------------------------------
Min..................................................... 0
10th.................................................... 0
25th.................................................... <1
Median.................................................. 39
Mean.................................................... 46
75th.................................................... 86
90th.................................................... 99
Max..................................................... 100
------------------------------------------------------------------------
In the CCR rule,\136\ EPA noted that FA replacing Portland cement
in concrete would result in significant avoided environmental impacts
to energy use, water use, GHG emissions, air emissions, and waterborne
wastes.
---------------------------------------------------------------------------
\136\ Available online at: www.regulations.gov. Docket ID: EPA-
HQ-RCRA-2009-0640.
---------------------------------------------------------------------------
Based on EPA's analysis of 2019 and 2020 EIA data, most of the
power plants that would be expected to install membrane filtration
under proposed Option 3 have enough FA for encapsulation before
accounting for reported FA sales, leaving only two plants without
enough FA needed for the estimated encapsulation recipe (by
approximately 240,000 tons of FA). After accounting for reported FA
sales, EPA estimates that six power plants may not have enough FA
available for encapsulation (by approximately 750,000 tons of FA).
These facilities would thus have to reduce sales of their FA, use
additional lime, find a beneficial use of the brine, dispose of the
brine through deep well injection, or reduce the volume of brine with
thermal technologies including potential crystallization. EPA expects
that the amount of FA required for encapsulation will vary based on the
amount of FGD wastewater generated and treated in a given operating
year, in addition to the variability in FA markets. Based on the 2020
EIA data, coal-fired power plants reported more than 30 million tons of
FA sold, and while there are increasing FA sales reported, EPA
identified more than 100 coal-fired power plants (9.6 million tons of
FA) that do not report any FA sales. EPA estimates that there is enough
FA to accommodate both FGD brine encapsulation needs and the beneficial
use market and proposes to find that this non-water quality
environmental impact is acceptable. See also discussion in Section
VII.B.1.a of this preamble.
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
technology basis for FGD wastewater in the 2020 rule, chemical
precipitation plus LRTR, was not expected to reduce or increase the
volume of water used. Under this proposed rule, plants that install a
[[Page 18870]]
membrane filtration system for FGD wastewater treatment are assumed to
decrease their water use compared to baseline by recycling all permeate
back into the FGD system, which would avoid the 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.
The BA transport technologies associated with the baseline and the
proposed rule for BA transport water eliminate or reduce the volume of
water used by wet sluicing BA operating systems. The 2020 rule
established limitations based on plants operating a high recycle rate
system, allowing up to a 10 percent purge of the total system volume.
As part of this rule, EPA is proposing options that include zero-
discharge requirements for BA handling, which may result in a decrease
in water use for BA handling by eliminating the purge. For proposed
Options 1 and 2, EPA generally expects no change in water use
associated with BA handling. For proposed Options 3 and 4, EPA expects
to see a decrease in water use for BA handling operations. Under this
proposed rule, plants that operate zero discharge BA handling systems
are assumed to decrease their water use compared to baseline by
recycling all transport water back to the BA handling system, which
would avoid the costs of pumping or treating new makeup water.
Therefore, EPA estimated the reduction in water use resulting from
complete recycle as equal to the estimated volume of the 10 percent
purge.
EPA does not estimate a change in water use associated with the
treatment technology considered for the treatment of CRL as part of
this proposed rule.
Overall, EPA estimates that plants impacted by the proposed rule
would decrease their water use by 11.8 MGD compared to baseline for
preferred regulatory Option 3. Table X-6 of this preamble sums the
changes for FGD wastewater and BA transport water and shows the net
decrease in water use, compared to baseline, for the four regulatory
options.
Table X-6--Estimated Incremental Decreases in Water Use Associated With Regulatory Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
Decreases in water use associated with regulatory options
Non-Water quality environmental impact -------------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Decreases in water use (MGD)................ 4.47 9.79 11.8 12.4
----------------------------------------------------------------------------------------------------------------
XI. Environmental Assessment
A. Introduction
EPA conducted an environmental assessment for this proposed rule.
The Agency reviewed available literature on the documented
environmental and human health effects of the pollutants discharged in
steam electric power plant FGD wastewater, BA transport water, CRL, and
legacy wastewater. EPA conducted modeling to determine the impacts of
pollutant discharges from the plants to which the proposed rule
applies. For the reasons described in Section VIII of this preamble of
this preamble, the baseline for these analyses appropriately consists
of the environmental and human health results of achieving the 2020
rule requirements (the same baseline EPA used to evaluate costs,
benefits, and pollutant loads). Under this assessment, EPA compared the
change in impacts associated with the four regulatory options presented
in Table VII-1 of this preamble to those projected under baseline.
Information from EPA's review of the scientific literature and
documented cases of impacts of pollutants discharged in steam electric
power plant wastewater on human health and the environment, as well as
a description of EPA's modeling methodology and results, are provided
in the Environmental Assessment for Proposed Supplemental ELGs (EA
Report). The EA Report contains information on literature that EPA has
reviewed since the 2020 rule, updates to the environmental assessment
analyses, and modeling results for each of the regulatory options in
this proposal. The 2015 EA (EPA-821-R-15-006) and 2020 EA (EPA 821-R-
20-002) provide information from EPA's earlier review of the scientific
literature and documented cases of the 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, BA transport
water, CRL, and legacy wastewater, contain large amounts of a wide
range of pollutants, some of which are toxic and bioaccumulative and
cause detrimental environmental and human health impacts. For
additional information, see section 2 of the EA Report. 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 proposed 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 2020 ELG rule, 2015
ELG rule, and 2015 CCR rule. The model focused on impacts within the
immediate surface waters where discharges occurred (the closest
segments of approximately 0.25 miles to five 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). For this proposed rule, the Agency
expanded its environmental assessment to evaluate cumulative impacts by
assessing human health impacts from the joint toxic action of multiple
pollutants in steam electric power plant discharges. The environmental
assessment also incorporates changes to the industry profile outlined
in Section V of this preamble.
C. Outputs From the Environmental Assessment
Compared to baseline, EPA estimated environmental and ecological
changes associated with changes in pollutant loadings for the four
regulatory options presented in Table VII-1 of this preamble. These
include changes in impacts to wildlife and humans. More specifically,
in addition to other unquantified environmental changes (e.g.,
groundwater quality and attractive nuisances), the environmental
[[Page 18871]]
assessment evaluated changes in: (1) surface water quality, (2) impacts
to wildlife, (3) number of receiving waters with potential human health
cancer risks, (4) number of receiving waters with potential to cause
noncancer human health effects, (5) metal and nutrient discharges to
sensitive waters (e.g., CWA Section 303(d) impaired waters impaired
waters), and (6) number of receiving waters with potential joint toxic
action of multiple pollutants. EPA also evaluates further impacts in
Section XII of this preamble.
As described in the EA Report, 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 FGD wastewater, BA transport water, and
CRL into rivers, streams, and lakes, including reservoirs. EPA also
addressed environmental impacts from nutrients in the EA Report, as
well as in a separate analysis in Section XII of this preamble.
The environmental assessment concentrates on impacts to aquatic
life based on changes in surface water quality; impacts to aquatic life
based on changes in sediment quality in surface waters; impacts to
wildlife from consumption of contaminated aquatic organisms; and
impacts to human health from consumption of contaminated fish and
water. The EA Report discusses, with quantified results, the estimated
environmental improvements projected within the immediate receiving
waters due to the estimated pollutant loading reductions associated
with the regulatory options in this proposal compared to the 2020 rule.
XII. Benefits Analysis
This section summarizes EPA's estimates of the changes in national
environmental benefits expected to result from changes in steam
electric plant 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. The analysis
methodology for quantified benefits is generally the same that EPA used
for the 2015 and 2020 rules, but with revised inputs and assumptions
that reflect updated data and regulatory options.
A. Categories of Benefits Analyzed
Table XII-1 of this preamble summarizes benefit categories
associated with the four regulatory options and notes which categories
EPA was able to quantify and monetize. Analyzed benefits fall into four
broad categories: (1) human health benefits from surface water quality
improvements, (2) ecological conditions and effects on recreational use
from surface water quality changes, (3) market and productivity
benefits, and (4) air-related effects.\137\ Within these broad
categories, EPA was able to assess the benefits associated with the
regulatory options in this proposal 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. EPA notes that
all human health and environmental improvements discussed in the EA
Report also represent benefits of the proposal (whether quantified or
unquantified), and the Agency will continue to enhance its benefits
analysis methods where appropriate as it finalizes the rule.
---------------------------------------------------------------------------
\137\ Consistent with Office of Management and Budget Circular
A-4, EPA appropriately considers ancillary benefits of this proposal
(e.g., air benefits). Circular A-4 states:
Your analysis should look beyond the direct benefits and direct
costs of your rulemaking and consider any important ancillary
benefits and countervailing risks. An ancillary benefit is a
favorable impact of the rule that is typically unrelated or
secondary to the statutory purpose of the rulemaking . . .
---------------------------------------------------------------------------
The following section summarizes EPA's analysis of the benefit
categories the Agency was able to partially quantify and/or monetize to
various degrees (identified in the columns of Table XII-1 of this
preamble, respectively). EPA solicits comment on the extent to which
unquantified benefits (e.g., some health endpoints without defined
dose-response relationship) or partially quantified benefits (e.g., the
social cost of GHG metrics which omit many significant categories of
climate damages) could be more fully quantified and/or monetized for
any final rule. The regulatory options would also affect additional
benefit categories that the Agency was not able to quantify or monetize
at all. The BCA Report further describes some of these important
nonmonetized benefits, and the Agency solicits comment on the extent to
which these benefits could be quantified and/or monetized for any final
rule.
Table XII-1--Summary of Estimated Benefits Categories
----------------------------------------------------------------------------------------------------------------
Neither
Benefit category Quantified and Quantified, but quantified nor
monetized not monetized monetized
----------------------------------------------------------------------------------------------------------------
Human Health Benefits From Surface Water Quality Improvements
----------------------------------------------------------------------------------------------------------------
Changes in incidence of bladder cancer from exposure to total [ballot] ............... ...............
trihalomethanes (TTHM) in drinking water....................
Changes in incidence of cancer from arsenic exposure via ............... [ballot] ...............
consumption of self-caught fish.............................
Changes in incidence of cardiovascular disease from lead ............... ............... [ballot]
exposure via consumption of self-caught fish................
Changes in incidence of other cancer and noncancer adverse ............... [ballot] [ballot]
health effects (e.g., reproductive, immunological,
neurological, circulatory, or respiratory toxicity) due to
exposure to arsenic, lead, cadmium, and other toxics from
consumption of self-caught fish or drinking water...........
Changes in IQ loss in children from lead exposure via [ballot] ............... ...............
consumption of self-caught fish.............................
Changes in specialized education needs for children from lead ............... [ballot] ...............
exposure via fish consumption of self-caught fish...........
Changes in in utero mercury exposure via maternal fish [ballot] ............... ...............
consumption of self-caught fish.............................
[[Page 18872]]
Changes in health hazards from exposure to pollutants in ............... ............... [ballot]
waters used recreationally (e.g., swimming).................
----------------------------------------------------------------------------------------------------------------
Ecological Condition and Recreational Use Effects From Surface Water Quality Changes
----------------------------------------------------------------------------------------------------------------
Benefits from changes in surface water quality, including: [ballot] ............... ...............
aquatic and wildlife habitat; water-based recreation,
including fishing, swimming, boating, and near-water
activities; aesthetic benefits, such as enhancement of
adjoining site amenities (e.g., residing, working,
traveling, and owning property near the water); \a\ and
nonuse value (existence, option, and bequest value from
improved ecosystem health) \a\..............................
Benefits from protection of threatened and endangered species ............... [ballot] ...............
Changes in sediment contamination............................ ............... ............... [ballot]
----------------------------------------------------------------------------------------------------------------
Market and Productivity Benefits
----------------------------------------------------------------------------------------------------------------
Changes in water treatment costs for municipal drinking ............... ............... [ballot]
water, irrigation water, and industrial process.............
Changes in commercial fisheries yields....................... ............... ............... [ballot]
Changes in tourism and participation in water-based ............... ............... [ballot]
recreation..................................................
Changes in property values from water quality changes........ ............... ............... [ballot]
Changes in maintenance dredging of navigational waterways and [ballot] ............... ...............
reservoirs due to changes in sediment discharges............
----------------------------------------------------------------------------------------------------------------
Air-Related Effects
----------------------------------------------------------------------------------------------------------------
Human health benefits from changes in morbidity and mortality [ballot] ............... ...............
from exposure to NOX, SO2, and particulate matter (PM2.5)...
Avoided climate change impacts from CO2 emissions............ [ballot] ............... ...............
----------------------------------------------------------------------------------------------------------------
\a\ Some, although not necessarily all, of these values are implicit in the total willingness to pay (WTP) for
water quality improvements.
B. Quantification and Monetization of Benefits
1. Human Health Effects From Surface Water Quality Changes
Changes in pollutant discharges from steam electric plants affect
human health in multiple ways. Exposure to pollutants in steam electric
power plant discharges via consumption of fish from affected waters can
cause a wide variety of adverse health effects, including cancer,
kidney damage, nervous system damage, fatigue, irritability, liver
damage, circulatory damage, vomiting, diarrhea, brain damage, and IQ
loss. Exposure to drinking water containing brominated disinfection
byproducts can cause adverse health effects such as cancer and
reproductive and fetal development issues. Because the regulatory
options in this proposal would change discharges of steam electric
pollutants into waterbodies that directly receive or are downstream
from these discharges, they may alter incidence of associated
illnesses, even if by relatively small amounts.
Due to data limitations and uncertainties, EPA can only monetize a
subset of the health benefits associated with changes in pollutant
discharges from steam electric plants resulting from the regulatory
options in this proposal as compared to baseline. EPA estimated the
change in the number of individuals experiencing adverse human health
effects in the populations exposed to steam electric discharges and/or
altered exposure levels and valued these changes using different
monetization methods for different benefit endpoints.
EPA estimated changes in health risks from the consumption of
contaminated fish from waterbodies within 50 miles of households. EPA
used Census block population data and region-specific average fishing
rates to estimate the exposed population. EPA used cohort-specific fish
consumption rates and waterbody-specific fish tissue concentration
estimates to calculate potential exposure to steam electric pollutants
in recreational fishers' households. Cohorts were defined by age, sex,
race/ethnicity, and fishing mode (recreational or subsistence). EPA
used these data to quantify and monetize changes in two categories of
human health effects, which are further detailed in the BCA Report: (1)
changes in IQ loss in children aged zero to seven from lead exposure
via fish consumption and (2) changes in in utero mercury exposure via
maternal fish consumption and associated IQ loss. EPA also analyzed the
changes in the incidence of skin cancer from arsenic exposure via fish
consumption but found negligible changes and therefore did not monetize
the associated benefits.
Table XII-2 of this preamble summarizes the monetary value of
changes in estimated health outcomes associated with consumption of
contaminated fish for the ELG options compared to baseline. EPA
estimated the annualized benefits of the proposed rule at $3.1 million
using a three percent discount rate ($0.6 million using a seven percent
discount rate). Chapter 5 of the BCA provides additional detail on the
methodology. EPA solicits comment on the assumptions and uncertainties
included in this analysis.
[[Page 18873]]
Table XII-2--Annualized Estimated Benefits of Changes in Human Health Outcomes Associated With Fish Consumption
(Millions of 2021$) for Proposed ELG Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
Reduced
Reduced lead mercury
Discount rate Regulatory option exposure for exposure for Total
children children
----------------------------------------------------------------------------------------------------------------
3%.................................... Option 1................ $0.00 $2.94 $2.94
Option 2................ 0.00 2.99 2.99
Option 3................ 0.00 3.11 3.11
Option 4................ 0.01 3.11 3.12
7%.................................... Option 1................ 0.00 0.54 0.54
Option 2................ 0.00 0.55 0.55
Option 3................ 0.00 0.58 0.58
Option 4................ 0.00 0.58 0.58
----------------------------------------------------------------------------------------------------------------
EPA also estimated changes in bladder cancer incidence from the use
and consumption of drinking water with changing levels of total
trihalomethanes (TTHMs) resulting from reductions in bromide loadings
associated with the four regulatory options relative to baseline. EPA
estimated changes in cancer risks within populations served by drinking
water treatment plants with intakes on surface waters affected by
bromide discharges from steam electric plants. EPA used Safe Drinking
Water Information System and U.S. Census data to estimate and
characterize the exposed population. EPA modeled changes in waterbody-
specific bromide concentrations and changes in drinking water treatment
facility-specific TTHM concentrations to calculate potential changes in
TTHM exposure and associated adverse health outcomes.
Table XII-3 of this preamble summarizes the estimated monetary
value of estimated changes in bromide-related human health outcomes
from modeled surface water quality improvements under the four
regulatory options. The proposed rule (Option 3) is estimated to result
in 112 avoided cancer cases and to have associated annualized benefits
of $9.6 million using a three percent discount rate ($6.2 million using
a seven percent discount rate).
Table XII-3--Estimated Annualized Human Health Benefits of Changing Bromide Discharges (Millions of 2021$) Under
the Proposed ELG Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
Benefits from Benefits from
Discount rate Regulatory option avoided avoided Total benefits
mortality morbidity
----------------------------------------------------------------------------------------------------------------
3%.................................... Option 1................ $0.45 $0.00 $0.45
Option 2................ 9.29 0.08 9.37
Option 3................ 9.53 0.08 9.61
Option 4................ 12.60 0.10 12.70
7%.................................... Option 1................ 0.13 0.00 0.28
Option 2................ 6.04 0.05 6.09
Option 3................ 6.19 0.05 6.24
Option 4................ 8.19 0.07 8.26
----------------------------------------------------------------------------------------------------------------
The formation of TTHM in a particular water treatment system is a
function of several site-specific factors, including chlorine, bromine,
organic carbon, temperature, pH, and the system residence time. EPA did
not collect site-specific information on these factors at each
potentially affected drinking water treatment facility. Instead, EPA's
analysis only addresses the estimated site-specific changes in
bromides. EPA used the national relationship between changes in TTHM
exposure and changes in incidence of bladder cancer modeled by Regli et
al. (2015) \138\ and Weisman et al. (2022).\139\ Thus, while the
national changes in TTHM and bladder cancer incidence given estimated
changes in bromide are EPA's best estimate, EPA cautions that estimates
for any specific drinking water treatment facility could be over- or
underestimated. Additional details on this analysis are provided in
Chapter 4 of the BCA Report. EPA solicits comment on all aspects of the
approach to assessing bladder cancer risk as well as the uncertainty
surrounding site-specific estimated benefits, as well as data that
would help EPA evaluate this uncertainty.
---------------------------------------------------------------------------
\138\ Regli, S., Chen, J., Messner, M., Elovitz, M.S.,
Letkiewicz, F.J., Pegram, R.A., . . . Wright, J.M. (2015).
Estimating Potential Increased Bladder Cancer Risk Due to Increased
Bromide Concentrations in Sources of Disinfected Drinking Waters.
Environmental Science & Technology, 49(22), 13094-13102. doi.org/10.1021/acs.est.5b03547.
\139\ Weisman, R., Heinrich, A., Letkiewicz, F., Messner, M.,
Studer, K., Wang, L., . . . Regli, S. (2022). Estimating National
Exposures and Potential Bladder Cancer Cases Associated with
Chlorination DBPs in U.S. Drinking Water. Environmental Health
Perspectives, 130:8, 087002-1-087002-10. ehp.niehs.nih.gov/doi/full/10.1289/EHP9985.
---------------------------------------------------------------------------
2. Ecological Condition and Recreational Use Effects From Changes in
Surface Water Quality Improvements
EPA evaluated whether the regulatory options in this proposal 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 baseline. As a result, the usability of some
recreational waters relative to baseline discharge conditions could
change under each option, thereby affecting recreational users. Changes
in pollutant loadings can also change the attractiveness of
recreational waters by making recreational trips more or less
enjoyable. The regulatory options may also change nonuse values
stemming from bequest, altruism, and
[[Page 18874]]
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 achievement of quality consistent with the suitability
for certain uses. The WQI includes seven parameters: dissolved oxygen,
biochemical oxygen demand, fecal coliform, total nitrogen, total
phosphorus, TSS, and one aggregate subindex for toxics. EPA modeled
changes in four of these parameters and held the remaining parameters
(dissolved oxygen, biochemical oxygen demand, and fecal coliform)
constant for the purposes of this analysis.
EPA estimated the change in monetized benefit values using an
updated version of the meta-regressions of surface water valuation
studies used in the benefit analyses of the 2015 and 2020 rules. The
meta-regressions quantify average household willingness to pay (WTP)
for incremental improvements in surface water quality. Chapter 6 of the
BCA provides additional detail on the valuation methodology.
Table XII-4 of this preamble presents annualized total WTP values
for water quality changes associated with reductions in metal (arsenic,
cadmium, chromium, copper, lead, mercury, zinc, and nickel), nonmetal
(selenium), nutrient (phosphorus and nitrogen), and sediment pollutant
discharges to the reach miles affected by the proposed regulatory
options. An estimated 82 million households reside in Census block
groups within 100 miles of reaches with steam electric plants affected
under the proposed rule.\140\ The central tendency estimate of the
total annualized benefits of water quality changes for the proposed
rule are $4.1 million using a three percent discount rate ($3.6 million
using a seven percent discount rate).
---------------------------------------------------------------------------
\140\ A reach is a section of a stream or river along which
similar hydrologic conditions exist, such as discharge, depth, area,
and slope.
Table XII-4--Estimated Total WTP for Water Quality Improvements Under the Proposed ELG Options Compared to
Baseline
----------------------------------------------------------------------------------------------------------------
Total annualized WTP (million
Number of Average annual 2021$)
Regulatory option affected WTP per -------------------------------
households household 3% Discount 7% Discount
(million) (2021$) rate rate
----------------------------------------------------------------------------------------------------------------
Option 1........................................ 76.2 $0.05 $3.02 $2.64
Option 2........................................ 80.6 0.05 3.82 3.32
Option 3........................................ 82.1 0.06 4.09 3.56
Option 4........................................ 82.1 0.06 4.27 3.73
----------------------------------------------------------------------------------------------------------------
3. Changes in Air-Quality-Related Effects
EPA expects the proposed options to affect air pollution through
three main mechanisms: (1) changes in auxiliary electricity use by
steam electric facilities to operate wastewater treatment, ash
handling, and other systems that facilities may use under each proposed
option; (2) changes in transportation-related air emissions due to
changes in trucking of CCR waste to landfills; and (3) changes in the
electricity generation profile from increases in wastewater treatment
costs compared to baseline and the resulting changes in EGU relative
operating costs.
Changes in the electricity generation profile can increase or
decrease air pollutant emissions because emission factors vary for
different types of EGUs. For this analysis, the changes in air
emissions are based on the change in dispatch of EGUs as projected by
IPM after overlaying the costs of complying with the proposed rule onto
EGUs' production costs. As discussed in Section VIII of this preamble,
the IPM analysis accounts for the effects of other regulations on the
electric power sector.
EPA evaluated potential effects resulting from net changes in air
emissions of four pollutants: CO2, NOX,
SO2, and primary PM2.5. CO2 is a key
GHG linked to a wide range of climate-related effects, and also the
main GHG emitted from coal power plants. NOX and
SOX are precursors to fine particles sized 2.5 microns and
smaller (PM2.5), which are also emitted directly, and
NOX is an ozone precursor. These air pollutants cause a
variety of adverse health effects including premature death, nonfatal
heart attacks, hospital admissions, emergency department visits, upper
and lower respiratory symptoms, acute bronchitis, aggravated asthma,
lost work and school days, and acute respiratory symptoms.
Table XII-5 of this preamble shows the changes in emissions of
CO2, NOX, SO2, and primary
PM2.5 under the proposed rule (Option 3) relative to
baseline for selected IPM run years. The proposed rule would result in
a net reduction in air emissions of all four pollutants. This effect is
driven mostly by the estimated changes in the profile of electricity
generation, as emission reductions due to shifts in modeled EGU
dispatch and energy sources offsets relatively small increases in air
emissions from increased electricity use and trucking by steam electric
plants.
[[Page 18875]]
Table XII-5--Estimated Changes In Air Pollutant Emissions Under the Proposed Rule Compared to Baseline
----------------------------------------------------------------------------------------------------------------
Primary PM2.5
CO2 (million NOX (thousand SO2 (thousand (thousand
Year metric tonnes/ short tons/ short tons/ short tons/
year) year) year) year)
----------------------------------------------------------------------------------------------------------------
2028............................................ -0.7 -1.9 -1.0 -0.12
2030............................................ -4.7 -3.3 -2.0 -0.20
2035............................................ -10.5 -5.1 -5.8 -0.32
2040............................................ -7.2 -3.7 -4.4 -0.19
2045............................................ -11.9 -7.5 -9.3 -0.75
2050............................................ -3.0 -2.0 -7.6 -0.13
----------------------------------------------------------------------------------------------------------------
EPA estimated the monetized value of human health benefits among
populations exposed to changes in PM2.5 and ozone. The
proposed 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 United States. 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. EPA quantified effects using
concentration-response parameters, which are consistent with those the
Agency used 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 used estimates of the social cost of
carbon (SC-CO2) to value changes in CO2
emissions. The SC-CO2 is the monetary value of the net harm
to society associated with a marginal increase in CO2
emissions in a given year, or the benefit of avoiding that
increase.\141\
---------------------------------------------------------------------------
\141\ In principle, the SC-CO2 includes the value of
all climate change impacts, including (but not limited to) changes
in net agricultural productivity, human health effects, property
damage from increased flood risk and natural disasters, disruption
of energy systems, risk of conflict, environmental migration, and
the value of ecosystem services. The SC-CO2 therefore,
reflects the societal value of reducing emissions of by one metric
ton. EPA and other Federal agencies began regularly incorporating
estimates of SC-CO2 in their benefit-cost analyses
conducted under Executive Order (E.O.) 12866 since 2008, following a
Ninth Circuit Court of Appeals remand of a rule for failing to
monetize the benefits of reducing CO2 emissions in a
rulemaking process.
---------------------------------------------------------------------------
EPA estimates the climate benefits of CO2 emission
reductions expected from the proposed rule using the SC-CO2
estimates presented by the Interagency Working Group on the Social Cost
of Greenhouse Gases (IWG) in the February 2021 Technical Support
Document (TSD): Social Cost of Carbon, Methane, and Nitrous Oxide
Interim Estimates under E.O. 13990 (IWG 2021). These SC-CO2
estimates are interim values developed under E.O. 13990 for use in
benefit-cost analyses until updated estimates of the impacts of climate
change can be developed based on the best available climate science and
economics. EPA has evaluated the SC-CO2 estimates in the TSD
and have determined that these estimates are appropriate for use in
estimating the climate benefits of CO2 emission reductions
expected from this proposed rule. After considering the TSD, and the
issues and studies discussed therein, EPA finds that these estimates,
while likely an underestimate, are the best currently available SC-
CO2 estimates. These SC-CO2 estimates were
developed over many years, using a transparent process, peer-reviewed
methodologies, the best science available at the time of that process,
and with input from the public.\142\ The IWG is currently working on a
comprehensive update of the SC-CO2 estimates (under E.O.
13990) taking into consideration recommendations from the National
Academies of Sciences, Engineering and Medicine, recent scientific
literature, public comments received on the February 2021 TSD and other
input from experts and diverse stakeholder groups. The EPA is
participating in the IWG's work. In addition, while that process
continues, EPA is continuously reviewing developments in the scientific
literature on the SC-CO2, including more robust
methodologies for estimating damages from emissions, and looking for
opportunities to further improve SC-CO2 estimation going
forward. Most recently, EPA has developed a draft updated SC-
CO2 methodology within a sensitivity analysis in the
regulatory impact analysis of EPA's November 2022 supplemental proposal
for oil and gas standards that is currently undergoing external peer
review and a public comment process. See Chapter 8 of the BCA for more
discussion of this effort.
---------------------------------------------------------------------------
\142\ As discussed in Chapter 8 of the BCA, these interim SC-
CO2 estimates have a number of limitations, including
that the models used to produce them do not include all of the
important physical, ecological, and economic impacts of climate
change recognized in the climate-change literature and that several
modeling input assumptions are outdated. As discussed in the
February 2021 TSD, the IWG finds that, taken together, the
limitations suggest that these SC-CO2 estimates likely
underestimate the damages from CO2 emissions.
---------------------------------------------------------------------------
Table XII-6 of this preamble shows the annualized climate change,
PM2.5, and ozone-related human health benefits for the
proposed rule (Option 3). Climate change benefits are presented for
each of four SC-CO2 values and discounted using the same
discount rate used in developing the SC-CO2 values, whereas
the PM2.5 and ozone-related human health benefits are based
on long-term ozone exposure mortality risk estimates and with three and
seven percent discount rates. Consistent with the 2015 rule, summary
benefits and net benefits estimates focus on the three percent
(average) SC-CO2 value. See Chapter 8 of the BCA report for
benefits based on pooled short-term ozone exposure mortality risk
estimate.
[[Page 18876]]
Table XII-6--Estimated Changes in Air Pollutant Emissions Under the Proposed Rule Compared to Baseline
[Millions of 2021$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
PM2.5 and
ozone related PM2.5 and
Climate change human health Climate change ozone related
SC-CO2 benefits benefits at 3% Total benefits human health Total
discount rate benefits at 7%
\a\ discount rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% (Average)............................................ $440 $1,100 $1,540 $440 $840 $1,280
5% (Average)............................................ 140 1,100 1,240 140 840 980
2.5% (Average).......................................... 630 1,100 1,730 630 840 1,470
3% (95th Percentile).................................... 1,300 1,100 2,400 1,300 840 2,140
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Reflects long-term ozone exposure mortality risk estimate.
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 proposed 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.
4. Other Quantified and/or Monetized Benefits
a. Changes in Dredging Costs
The four regulatory options would affect discharge loadings of
various categories of pollutants, including TSS, thereby changing the
rate of sediment deposition to affected waterbodies, including
navigable waterways and reservoirs that require dredging for
maintenance. Sediment buildup in navigable waterways, including rivers,
lakes, bays, shipping channels, and harbors can reduce the navigable
depth and width of the waterway. In many cases, periodic dredging is
necessary to keep them passable. Reservoirs serve many functions,
including storage of drinking and irrigation water supplies, flood
control, hydropower supply, and recreation. Streams can carry sediment
into reservoirs, where it can settle and cause buildup of silt layers
over time. Sedimentation reduces reservoir capacity and the useful life
of reservoirs unless measures such as dredging are taken to reclaim
capacity. As it had done for the 2015 and 2020 rule analyses, EPA
estimated changes in sedimentation and associated maintenance dredging
costs in reaches and reservoirs affected by steam electric plant
discharges. Chapter 9 of the BCA provides additional detail on the
methodology.
EPA expects that the proposed rule may provide relatively small
annualized cost savings ranging from $3,900 to $5,500 per year, using
three percent and seven percent discount rates, respectively.
b. Benefits to Threatened and Endangered Species
To assess the potential for the rule to benefit threatened and
endangered species (both aquatic and terrestrial) relative to the 2020
ELG baseline, EPA analyzed the overlap between waters expected to see
reductions in wildlife water quality criteria exceedance status under a
particular option and the known critical habitat locations of high-
vulnerability threatened and endangered species. EPA examined the life
history traits of potentially affected threatened and endangered
species and categorized them by potential for population impacts due to
surface water quality changes. Chapter 7 of the BCA Report provides
additional detail on the methodology. EPA's analysis showed that there
are 28 species whose known critical habitats overlap with surface
waters where facilities may be affected by the proposed options.
Improvements under the proposed rule between 2025 and 2029 are
estimated to potentially benefit five species, including two species
EPA categorized as having a higher vulnerability to water pollution
(Colorado pikeminnow and Razorback sucker). Improvements projected
after 2030 are estimated to benefit three species, including one higher
vulnerability species (Topeka Shiner). Principal sources of uncertainty
include the specifics of how changes under the regulatory options will
impact threatened and endangered species, exact spatial distribution of
the species, and additional species of concern not considered.
C. Total Monetized Benefits
Using the analysis approach described above, EPA estimated
annualized benefits of the four regulatory options for all monetized
categories. Table XII-7 and Table XII-8 of this preamble summarize the
total annualized benefits using three percent and seven percent
discount rates, respectively. The proposed rule (Option 3) has
monetized benefits estimated at $1,557 million using a three percent
discount rate and $1,290 million using a seven percent discount rate.
Table XII-7--Summary of Total Estimated Annualized Monetized Benefits at Three Percent
[Millions of 2021$]
----------------------------------------------------------------------------------------------------------------
Benefit category Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Human Health Effects from Water Quality Changes. $3.4 $12.4 $12.7 $15.8
Changes in IQ losses in children from exposure <0.01 <0.01 0.01 0.01
to lead \a\....................................
Changes in IQ losses in children from exposure 2.9 3.0 3.1 3.1
to mercury.....................................
Reduced cancer risk from disinfection byproducts 0.5 9.4 9.6 12.7
in drinking water..............................
Ecological Conditions and Recreational Use 3.0 3.8 4.1 4.3
Changes........................................
Use and nonuse values for water quality 3.0 3.8 4.1 4.3
improvements...................................
Market and Productivity \a\..................... <0.01 <0.01 <0.01 <0.01
[[Page 18877]]
Changes in dredging costs \a\................... <0.01 <0.01 <0.01 <0.01
Air-Related Effects............................. 690 1,320 1,540 1,650
Changes in CO2 air emissions \b\ \c\............ 190 370 440 450
Changes in human health effects from Changes in 500 950 1,100 1,200
NOX and SO2 emissions \b\......................
---------------------------------------------------------------
Total....................................... 696 1,336 1,557 1,670
----------------------------------------------------------------------------------------------------------------
\a\ ``<$0.01'' indicates that monetary values are greater than $0 but less than $0.01 million.
\b\ EPA estimated the air-related benefits for Option 3 using IPM. EPA did not analyze Options 1, 2, and 4 using
IPM. Instead, EPA extrapolated estimates for air-related benefits from Options 1, 2, and 4 from the estimate
for Option 3 in proportion to social costs.
\c\ Changes in CO2 air emissions monetized using the SC-CO2 at 3% (average). See Section XII.B.3 of this
preamble for benefits monetized using other SC-CO2 values.
Table XII-8--Summary of Total Estimated Annualized Monetized Benefits at Seven Percent
[Millions of 2021$]
----------------------------------------------------------------------------------------------------------------
Benefit category Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Human Health Effects from Water Quality Changes. $0.8 $6.6 $6.8 $8.8
Changes in IQ losses in children from exposure <0.01 <0.01 <0.01 <0.01
to lead \a\....................................
Changes in IQ losses in children from exposure 0.5 0.6 0.6 0.6
to mercury.....................................
Reduced cancer risk from DBPs in drinking water. 0.3 6.1 6.2 8.3
Ecological Conditions and Recreational Use 2.6 3.3 3.6 3.7
Changes........................................
Use and nonuse values for water quality 2.6 3.3 3.6 3.7
improvements...................................
Market and Productivity \a\..................... <0.01 <0.01 <0.01 <0.01
Changes in dredging costs \a\................... <0.01 <0.01 <0.01 <0.01
Air-Related Effects............................. 570 1,070 1,280 1,320
Changes in CO2 air emissions \b\ \c\............ 190 370 440 450
Changes in human health effects from Changes in 380 700 840 870
NOX and SO2 emissions \b\......................
---------------------------------------------------------------
Total....................................... 573 1,080 1,290 1,333
----------------------------------------------------------------------------------------------------------------
\a\ ``<$0.01'' indicates that monetary values are greater than $0 but less than $0.01 million.
\b\ EPA estimated the air-related benefits for Option 3 using IPM. EPA did not analyze Options 1, 2, and 4 using
IPM. Instead, EPA extrapolated estimates for air-related benefits from Options 1, 2, and 4 from the estimate
for Option 3 in proportion to social costs.
\c\ Changes in CO2 air emissions monetized using the SC-CO2 at 3% (average). See Section XII.B.3 for benefits
monetized using other SC-CO2 values.
D. Additional Benefits
The monetary value of the proposed rule's effects on social welfare
does not account for all effects of the proposed options because, as
described above, EPA is currently unable to quantify and/or monetize
some categories. EPA anticipates the proposed rule would also generate
important unquantified benefits, including but not limited to:
health benefits to over 30 million people who will
experience reductions in PWS-level arsenic, lead, and thallium
concentrations, including reductions in unmonetized cancer and non-
cancer effects from exposure to toxic pollutants from consumption of
fish consumption or drinking water;
reduced cardiovascular disease from changes in exposure to
lead from fish consumption;
unquantified and unmonetized averted IQ losses and
educational effects from childhood lead exposure and in-utero mercury
exposure from fish consumption by households that do not engage in
recreational and subsistence fishing;
reduced cancer morbidity effects beyond medical expenses;
improved habitat conditions for plants, invertebrates,
fish, amphibians, and the wildlife that prey on aquatic organisms;
enhanced ecosystem productivity and health, including
reduced toxic discharges into habitats for over 100 high-vulnerability
threatened and endangered species;
changes to water treatment costs for drinking water,
irrigation, and agricultural uses;
changes in fisheries yield and harvest quality from
aquatic habitat changes;
changes in health hazards from recreational exposures; and
groundwater quality impacts.
While some health benefits and willingness to pay for water quality
improvements have been partially quantified and/or monetized, those
estimates may not fully capture all important water quality-related
benefits. Although the following quantifications cannot necessarily be
combined with other monetized effects, another way to characterize the
benefits is that the proposed rule is expected to result in a 12.5
percent reduction in chronic exceedances and a 100 percent reduction in
acute exceedances of the national recommended water quality criteria,
and up to an 82 percent reduction in the number of reaches with ambient
concentrations exceeding human health criteria for at least one
pollutant.
The BCA Report discusses changes in these potentially important
effects qualitatively, indicating their potential magnitude where
possible. EPA will continue to seek to enhance its approaches to
quantify and/or monetize a broader set of benefits for any final rule
and solicits comment on monetizing some of these additional
[[Page 18878]]
benefits categories consistent with the approach discussed in IPI
(2022).\143\
---------------------------------------------------------------------------
\143\ IPI (Institute for Policy Integrity). June 2022. Measuring
the Benefits of Power Plant Effluent Regulation: The 2020 Steam
Electric Reconsideration Rule and Potential Future Methods.
---------------------------------------------------------------------------
XIII. Environmental Justice Impacts
Consistent with EPA's commitment to integrating environmental
justice (EJ) in the Agency's actions, the Agency has analyzed the
impacts of this action on communities with EJ concerns and sought input
and feedback from stakeholders representing these communities. EPA has
prepared this analysis to implement the recommendations of the Agency's
EJ Technical Guidance.\144\ For ELG rulemakings, this analysis is
typically conducted as part of the BCA alongside other nonstatutorily
required analyses such as monetized benefits, but for this action was
placed in a standalone Environmental Justice Analysis (EJA) document to
present in more detail the potential EJ impacts of this proposal and
the initial outreach to communities with potential EJ impacts. This
analysis is intended to provide the public with a discussion of the
potential EJ impacts of this proposal. The analysis does not form a
basis or rationale for any of the actions EPA is proposing in this
rulemaking. Executive Order 12898 is discussed in Section XI.J of this
preamble.
---------------------------------------------------------------------------
\144\ U.S. EPA (Environmental Protection Agency). 2016.
Technical Guidance for Assessing Environmental Justice in Regulatory
Analysis. June. Available online at: www.epa.gov/environmentaljustice/technical-guidance-assessing-environmental-justice-regulatory-analysis.
---------------------------------------------------------------------------
Overall, the analysis showed that benefits associated with
improvements to water quality, wildlife, and human health resulting
from reductions in pollutants in surface water and drinking water will
accrue to minority and low-income populations at a higher rate under
some or all of the proposed regulatory options. Remaining exposures,
impacts, costs, and benefits analyzed either accrue at a higher rate to
populations which are not minority or low-income, accrue
proportionately to all populations, or are small enough that EPA could
not conclude whether changes in disproportionate impacts would occur.
While the changes in GHGs attributable to the proposed regulatory
options are relatively small compared to worldwide emissions, findings
from peer-reviewed evaluations demonstrate that actions that reduce GHG
emissions are also likely to reduce climate impacts on vulnerable
communities, including minority and low-income communities. The methods
and findings of the EJA are described in further detail below.
A. Literature Review
EPA conducted a literature review to identify academic research and
articles on EJ concerns related to coal-fired power plants. EPA
identified four papers that focused on coal-fired power plants in the
United States that were directly relevant to this proposed rule. The
findings of these papers suggest that coal-fired power plants tend to
be in poor, minority, and indigenous communities. Toomey (2013)
reported that 78 percent of African Americans in the United States live
within a 30-mile radius of a coal-fired power plant.\145\ Impacts
discussed in the reports included adverse health impacts resulting from
air pollutants (e.g., SO2, NOX, PM2.5)
for those living in proximity to coal-fired power plants, climate
justice issues resulting from GHG emissions, and risk of impoundment
failures for populations living in proximity to coal waste surface
impoundments where coal is mined.146 147 148 All these
impacts were found in one or more papers to disproportionately impact
poor, minority, and indigenous communities. EPA solicits comment on
additional literature that discusses EJ impacts related to the specific
changes being made to steam electric power plants. For further
discussion of the literature review, see section 5 of the EJA.
---------------------------------------------------------------------------
\145\ Toomey, Diane. 2013. Coal Pollution and the Fight for
Environmental Justice. Yale Environment 360. June 19. Available
online at: www.e360.yale.edu/features/naacp_jacqueline_patterson_coal_pollution_and_fight_for_environmental_justice.
\146\ Li[eacute]vanos, R.S., P. Greenberg, and R. Wishart. 2018.
In the Shadow of Production: Coal Waste Accumulation and
Environmental Inequality Formation in Eastern Kentucky. Social
Science Research, Vol. 71: pp. 37-55.
\147\ Israel, B. 2012. Coal Plants Smother Communities of Color.
Scientific American. www.scientificamerican.com/article/coal-plants-
smother-communities-of-color/
#:~:text=People%20living%20near%20coal%20plants,percent%20are%20peopl
e%20of%20color.
\148\ NAACP. 2012. National Association for the Advancement of
Colored People. Coal Blooded: Putting Profits Before People.
www.naacp.org/resources/coal-blooded-putting-profits-people.
---------------------------------------------------------------------------
B. Screening Analysis and Community Outreach
EPA performed a set of screening analyses with the EJSCREENBatch
tool to identify the environmental and socioeconomic characteristics of
the communities that are expected to be impacted by discharges from
steam electric plants via relevant exposure pathways. First, EPA
conducted a screening for potential air impacts using one- and three-
mile buffers around the facility GIS coordinates. Second, EPA conducted
a screening for potential impacts in downstream surface waterbodies
using one-, three-, 50-, and 100-mile buffer distances around each
waterbody segment downstream of the initial common identifiers (COMIDs)
identified for each effluent discharge.\149\ Finally, EPA conducted a
screening for potential drinking water impacts using ZIP code
information for downstream public water systems (PWSs) in the absence
of a complete data set of actual service area boundaries for all PWSs.
---------------------------------------------------------------------------
\149\ Defined as 300 kilometers (~187 miles).
---------------------------------------------------------------------------
Using the results of these screening analyses, EPA tiered
communities under all three screening analyses to prioritize
communities for potential outreach and engagement. To tier the
communities, EPA evaluated how many of the following criteria applied
to a community's screening results:
The community has both demographic (minority and low
income \150\) indicators and at least one environmental indicator \151\
above the 50th percentile nationally or has all environmental
indicators and at least one demographic indicator above the 50th
percentile nationally;
---------------------------------------------------------------------------
\150\ The minority and low-income indicators are derived from
EPA's Environmental Justice Screening and Mapping Tool (EJSCREEN).
For more information on EJSCREEN's definitions of minority and low
income, see U.S. EPA. 2019. U.S. Environmental Protection Agency.
EJSCREEN Technical Documentation. www.epa.gov/ejscreen/technical-information-about-ejscreen.
\151\ EPA used environmental indicators from EJSCREEN that
include direct and proxy indicators of potential pollution
exposures. For more information on the environmental indicators
included in EJSCREEN see U.S. EPA (2019).
---------------------------------------------------------------------------
The community has two or more demographic and/or
environmental indicators above the 80th percentile nationally;
The community has one or more demographic and/or
environmental indicators above the 90th percentile nationally; or
The community has one or more demographic and/or
environmental indicators above the 95th percentile nationally.
Tier 3 communities met one of the above criteria, Tier 2
communities met two or three of the above criteria, and Tier 1
communities met all four of the above criteria. EPA sought to conduct
initial outreach meetings with nine communities. Thus, for each of the
three screening analyses (air, surface water, and drinking water), EPA
selected the top three Tier 1 communities for outreach. For the latter
two screening analyses, there were no Tier 1 communities in scope. In
these cases,
[[Page 18879]]
EPA supplemented up to three by adding either the top Tier 2
communities or communities EPA had engaged with prior to the decision
to conduct the current rulemaking. A list of communities and selection
criteria is presented in Table XIII-1 of this preamble. The communities
that EPA engaged with prior to the initiation of the current rulemaking
are indicated by a ``YES'' in the Pre-Rule column.
EPA conducted initial outreach to local environmental and community
development organizations, local government agencies, and individual
community members involved in community organizing in all nine
communities. Between May and September of 2022, EPA was able to meet
with community members in five of the identified communities either
virtually (indicated in the table by ``Virtual Meeting'') or in a
hybrid format with some in-person participation (indicated in the table
by ``Hybrid Meeting''). While EPA has not been able to hold a virtual
or hybrid meeting with the remaining four communities (those indicated
in the table as ``Initial Outreach''), EPA is continuing to consider
whether and how to engage with these communities. Each meeting began
with a presentation providing background information about the
rulemaking before opening the meeting for questions and comments from
community members.
EPA received a broad range of input from individuals in these
communities on regulatory preferences, environmental concerns, human
health and safety concerns, economic impacts, cultural/spiritual
impacts, ongoing communication/public outreach, and interest in other
EPA actions. Two broad themes were conveyed consistently across
communities. First, community members conveyed several perceived
harmful impacts from steam electric power plants and their desire for
more stringent regulations to reduce these harmful impacts. Second,
community members expressed the desire for more transparency and
communication to overcome their decreasing trust in the regulated power
plants and state regulatory agencies and, thus, a corresponding
skepticism that their community would be protected from these harmful
impacts. In addition to these broad themes, commenters also raised
concerns unique to each community. For example, members of the Navajo
Nation discussed with EPA the spiritual and cultural impacts to the
community from pollution related to steam electric power plants. In
Jacksonville, Florida, community members raised concerns regarding
tidal flows of pollution upstream and storm surges during extreme
weather events which cause additional challenges in their community.
More detailed summaries of these meetings are described in section 7.5
of the EJA.
Table XIII-1--Initial Community Outreach Selection
----------------------------------------------------------------------------------------------------------------
Screening result
# (plant/waterbody/PWS) State Screen Tier Pre-Rule \b\ Proposal
\a\
----------------------------------------------------------------------------------------------------------------
1.......... EIA #667, Northside FL Air............. 1 ................ Virtual Meeting.
Generating Station.
2.......... EIA #3297, Wateree SC Air............. 1 ................ Initial
Station. Outreach.
3.......... EIA #2442, Four NM Air............. 1 YES............. Virtual Meeting.
Corners Steam
Electric Station.
4.......... COMID 10161978, Ohio KY Surface Water... 2 ................ Virtual Meeting.
River (EIA #6071,
Trimble County).
5.......... COMID 6499098, Etowah GA Surface Water... 2 ................ Initial
River (EIA #703, Outreach.
Plant Bowen).
6.......... COMID 3124250, Rabbs TX Surface Water... 2 ................ Hybrid Meeting.
Bayou (EIA #3470,
W.A. Parish E.G.S.).
7.......... PWSID 84690510, ND Drinking Water.. 2 ................ Initial
Standing Rock Rural Outreach.
Water System, Fort
Yates (EIA #2817,
Leland Olds Station).
8.......... PWSID MI0001800, City MI Drinking Water.. 2 ................ Initial
of Detroit (EIA Outreach.
#6034, Belle River
Power Plant and EIA
#1733, Monroe Power
Plant).
9.......... PWSID NC0279010, NC Drinking Water.. 3 YES............. Hybrid Meeting.
NC0279030,
NC0279040, and
NC3079031 Town of
Eden, Town of
Madison, Dan River
Water Inc,
Rockingham Co--220
Corridor (EIA #8042,
Belews Creek Steam
Station).
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ Steam electric power plants, surface waters, and PWSs are identified by their U.S. Energy Information
Administration (EIA) identification number, National Hydrography Dataset Plus (NHDPlus) V2.1 common identifier
(COMID), and Safe Drinking Water Information System (SDWIS) Public Water System ID (PWSID).
\b\ While not included in the list of communities for outreach, EPA also met with members of Clean Power Lake
County before the supplemental rule announcement to discuss potential EJ impacts of the Waukegan Power Plant,
a plant that is retired.
EPA considered all feedback received in these outreach meetings,
including feedback regarding the stringency of potential new
regulations and negative impacts experienced as a result of steam
electric discharges. The proposed rule, if finalized, would result in
more stringent limitations that would further reduce negative impacts
associated with steam electric discharges. EPA also considered feedback
expressing the desire for increased transparency and communication. As
discussed in Section XV.C.5 of this preamble, EPA is proposing posting
of required reports to a publicly available website to improve
transparency. Furthermore, EPA calls attention to the availability of
the more recent feature of Enforcement and Compliance History Online
(ECHO) called ECHO Notify. ECHO Notify provides weekly email
notifications of changes to enforcement and compliance data in ECHO.
Notifications are tailored to the geographic locations, facility IDs,
and notification options that users select. EPA encourages interested
community members to sign up for these alerts. Further information is
available on EPA's website at www.echo.epa.gov/tools/echo-notify. EPA
also encourages individual facilities to work with local communities to
foster trust and communication, for example, through text alert
systems. Finally, EPA solicits
[[Page 18880]]
comment on whether and how the Agency could update its analyses to
reflect the site-specific information presented in these meetings.
C. Distribution of Risks
EPA evaluated the distribution of pollutant loadings, estimated
human health, and estimated environmental impacts resulting from
polluted air, surface water, and drinking water. EPA examined these
distributions under both baseline and the regulatory options to
identify where current conditions and future improvements may have a
disproportionate impact on communities with potential EJ concerns
(PEJC). The following sections discuss EPA's methodology and findings.
1. Air
EPA evaluated air quality impacts in terms of changes in warm
season maximum daily average 8-hour (MDA8) ozone and average annual
PM2.5 concentrations, as described in the BCA. EPA used the
results of the analysis to further evaluate the distribution of air
quality impacts in the EJA to determine whether population groups of
concern experience disproportionately high exposures to MDA8 ozone and
average annual PM2.5 under baseline and Option 3.
The results of EPA's analysis of baseline MDA8 ozone and average
annual PM2.5 concentrations showed that there are
differences in baseline exposures across population groups and area
categories (no change, improving, worsening). EPA found that Option 3
results in similar absolute and relative changes in MDA8 ozone and
average annual PM2.5 exposures across population groups in
areas with improving and worsening air quality. The modeled changes in
MDA8 ozone and average annual PM2.5 exposures generated by
Option 3 are relatively small and not expected to have significant
impacts on distributional disparities. For more information on the
analysis of air quality impacts, see section 9.1 of the EJA.
2. Surface Water
EPA evaluated both immediate receiving waters \152\ and downstream
surface waters,\153\ as described in the EA and BCA.
---------------------------------------------------------------------------
\152\ The immediate receiving water analysis focused on
evaluating baseline and regulatory impacts at the point of
discharges in surface waters receiving wastewater discharges from
steam electric power plants.
\153\ The downstream analysis focused on evaluating baseline and
regulatory impacts 300 kilometers (~187 miles) downstream from the
point of discharges in surface waters receiving wastewater
discharges from steam electric power plants.
---------------------------------------------------------------------------
a. Immediate Receiving Waters
Using results from the immediate receiving water analysis performed
in the EA, EPA further evaluated the immediate receiving water impacts
in the EJA to determine whether these impacts disproportionately affect
population groups of concern. This analysis was done with respect to
waters that exceeded benchmarks for national recommended water quality
criteria (NRWQC) and maximum contaminant levels (MCLs), benchmarks for
sediment biota and piscivorous wildlife, and human health benchmarks.
b. Distribution of Water Quality Impacts
After examining baseline results of the EA where arsenic, cadmium,
selenium, or thallium concentrations exceeded benchmark NRWQC and MCL
values,\154\ EPA's analysis showed that, in communities with immediate
receiving waters with pollutant-specific benchmark exceedances, the
percent of the population identified as American Indian or Alaskan
Native (non-Hispanic) is larger than the national average. This result
is driven by baseline exceedances observed in the Unnamed tributary to
the Chaco River, which is in the Navajo Nation, an area in which about
98 percent of the population is identified as American Indian or Alaska
Native (non-Hispanic). When compared to communities with immediate
receiving waters without exceedances, communities with immediate
receiving waters with exceedances had larger proportions of the
population identifying as African-American (non-Hispanic), American
Indian or Alaskan Native (non-Hispanic), Other (non-Hispanic), and
Hispanic or Latino. Based on these findings regarding the distribution
of population groups of concern in communities with immediate receiving
waters with exceedances, EPA concluded that there are PEJC present
under the baseline. EPA's analysis of the regulatory options showed
that all regulatory options resulted in a reduction in the number of
immediate receiving waters with pollutant-specific benchmark
exceedances and in the population affected by these exceedances
compared to the baseline. Options 3 and 4 generated the largest
reductions in immediate receiving waters with exceedances and the
affected population relative to the baseline. Furthermore, Options 3
and 4 produced the greatest improvements in the distribution of water
quality impacts across population groups of concern relative to the
baseline when comparing proportions of these populations to the
national average and communities with immediate receiving waters
without exceedances. For more information on the results of the water
quality impact analysis, see section 9.2.1.1 of the EJA.
---------------------------------------------------------------------------
\154\ The IRW Model did not identify any immediate receiving
waters with benchmark value exceedances under the baseline for
copper, lead, mercury, nickel, and zinc loadings.
---------------------------------------------------------------------------
c. Distribution of Wildlife Impacts
After examining baseline results of the EA where sediment biota,
eagle, and mink impacts exceeded benchmark values, EPA's analysis
showed that communities with immediate receiving waters with
exceedances had a larger proportion of the population identified as
American Indian or Alaskan Native (non-Hispanic) than the national
average. Additionally, communities with immediate receiving waters with
exceedances under baseline had larger proportions of various population
groups of concern than communities with immediate receiving waters
without exceedances. Based on these findings regarding the distribution
of population groups of concern in communities with immediate receiving
waters with exceedances, EPA concluded that there are PEJC present
under the baseline. EPA's analysis of wildlife impacts under the
regulatory options showed that none of the regulatory options results
in increases in the number of immediate receiving waters with
exceedances of wildlife- and pollutant-specific benchmarks compared to
the baseline. Across the wildlife analyses, Options 3 and 4 generated
the largest reductions in the number of immediate receiving waters with
exceedances and in the affected population compared to the baseline.
Furthermore, relative to the baseline, Options 3 and 4 produced the
greatest improvements in the distribution of wildlife impacts across
population groups of concern when comparing proportions of these
populations to the national average and communities with immediate
receiving waters without exceedances. For more information on the
analysis of wildlife impacts, see section 9.2.1.2 of the EJA.
d. Distribution of Human Health Risks
After examining baseline results of the EA where fish consumer
cohort- and pollutant-specific noncancer hazard quotients and lifetime
excess cancer risks exceeded benchmark values,\155\ the record
indicates that across all fish consumer cohorts, communities with
[[Page 18881]]
immediate receiving waters with noncancer and cancer exceedances have
larger proportions of the population identified as population groups of
concern, particularly American Indian or Alaskan Native (non-Hispanic),
than the national average. This result is driven by baseline
exceedances observed in the Unnamed tributary to the Chaco River, which
is in the Navajo Nation. Additionally, communities with immediate
receiving waters with noncancer and cancer exceedances have larger
proportions of the population identified as population groups of
concern than communities with immediate receiving waters without
noncancer and cancer exceedances. Based on these findings regarding the
distribution of population groups of concern in communities with
immediate receiving waters with noncancer and cancer exceedances, EPA
concluded that there are PEJC present under the baseline. EPA's
analysis under the regulatory options showed human health improvements,
in terms of the reduction in the number of immediate receiving waters
with noncancer and cancer benchmark exceedances, across fish consumer
cohorts. Options 3 and 4 generated the largest reductions in the number
of immediate receiving waters with noncancer and cancer exceedances and
in the affected population. Additionally, Options 3 and 4 produced the
greatest improvements in the distribution of human health impacts
across population groups of concern relative to the baseline when
comparing proportions of these populations to the national average and
communities with immediate receiving waters without exceedances. For
more information on the analysis of human health risks, see section
9.2.1.3 of the EJA.
---------------------------------------------------------------------------
\155\ Fish consumer cohorts analyzed were child subsistence,
child recreational, adult subsistence, and adult recreational fish
consumers.
---------------------------------------------------------------------------
e. Downstream Waters
Using the results from the downstream analysis performed in the
BCA, EPA further evaluated the downstream surface water impacts in the
EJA to determine whether population groups of concern experience a
disproportionate share of noncancer and cancer health effects from
exposure to lead, mercury, and arsenic through consuming fish in
contaminated downstream surface waters. The results of EPA's analysis
are discussed in the following two sections.
f. Distribution of Noncancer Health Impacts
Noncancer health impacts evaluated by EPA were cognitive and
neurological impacts--expressed as total IQ points under baseline and
avoided IQ point losses under the regulatory options--among children
exposed to lead and mercury through consuming fish at subsistence and
recreational consumption rates caught in contaminated surface waters.
The distribution of impacts within the two consumer cohorts was
evaluated by racial and ethnic group (White, Black, Hispanic, Asian,
American Indian and Alaskan Native, and Other) and by income group
(below the poverty line or not below the poverty line). When comparing
across income groups and racial and ethnic groups, baseline results of
the analysis of neurological and cognitive health impacts from exposure
to lead and mercury showed that population groups of concern in the
children of subsistence and recreational cohorts had a proportional or
larger share of total baseline IQ points compared to their share of the
exposed population. The results of the analysis indicated no disparate
IQ impacts to minority and low-income groups under baseline.
Based on EPA's evaluation of the four regulatory options, each of
the regulatory options would result in avoided IQ point losses for
children of subsistence fishers and recreational fishers who regularly
consume fish caught in local water compared to baseline across all
racial, ethnic, and income groups in the children of both subsistence
and recreational consumer cohorts. While children of all racial and
ethnic population groups in the subsistence and recreational cohorts
are expected to experience avoided IQ point losses under the regulatory
options compared to baseline, these improvements were relatively small
and did not change the distribution of IQ points compared to baseline.
For more information on the analysis of noncancer health impacts in
downstream surface waters, see section 9.2.2.1 and section 9.2.2.2 of
the EJA.
g. Distribution of Cancer Health Impacts
EPA evaluated national cancer health impacts--in terms of cancer
cases (any type of cancer) under baseline and avoided cancer cases (any
type of cancer) under the regulatory options--among adult subsistence
and recreational fishers exposed to arsenic through fish consumption.
The distribution of impacts within the two fisher cohorts was evaluated
by racial and ethnic group and by income group.
When comparing total cancer cases across racial and ethnic groups,
the results of the baseline analysis showed that population groups of
concern (except for those in the Black population group) in the adult
subsistence fisher cohort had a larger proportion of cancer cases
compared to their share of the exposed population. In contrast, when
comparing total cancer cases across income groups, the results of the
baseline analysis showed that those below the poverty line in both the
adult subsistence and recreational fisher cohorts had a smaller
proportion of cancer cases compared to their share of the exposed
population, while those not below the poverty line in both fisher
cohorts had a larger proportion of cancer cases. The results of the
analysis indicate PEJC in the baseline related to the distribution of
cancer health impacts when comparing across racial and ethnic
population groups, but not across income groups.
Based on EPA's evaluation of the four regulatory options, each of
the regulatory options would result in avoided cancer cases compared to
baseline across all racial, ethnic, and income population groups in
both the adult subsistence and recreational fisher cohorts. While all
racial, ethnic, and income population groups in the adult subsistence
and recreational fisher cohorts were expected to experience avoided
cancer cases under the regulatory options compared to baseline, these
improvements were relatively small and did not change the distribution
of total cancer cases compared to baseline. For more information on the
analysis of cancer health impacts in downstream surface waters, see
section 9.2.2.3 of the EJA.
3. Drinking Water
Using the results from the drinking water analysis performed in the
BCA, EPA further evaluated downstream drinking water impacts in the EJA
to determine whether population groups of concern served by potentially
affected drinking water systems experience a disproportionate share of
bladder cancer cases from exposure to TTHM. In the BCA, EPA modeled
baseline incremental TTHM concentrations and bladder cancer cases
attributable to steam electric discharges.\156\ Since EPA evaluated
only the changes in TTHM concentrations and avoided bladder cancer
cases and deaths attributable to steam electric discharges in the BCA,
in this analysis, EPA only evaluated whether the distribution of
exposures and health effects indicated PEJC under the incremental
changes resulting from the regulatory options. The results of
[[Page 18882]]
EPA's analysis are discussed in the following two sections.
---------------------------------------------------------------------------
\156\ Background TTHM concentrations and bladder cancer cases
attributable to sources other than steam electric discharges were
not modeled under the baseline but would not impact the analysis of
incremental changes as discussed in the BCA.
---------------------------------------------------------------------------
a. Distribution of TTHM Exposures and Resulting Avoided Bladder Cancer
Cases and Deaths
Based on EPA's evaluation of the four regulatory options, EPA's
record shows that all regulatory options would result in decreases in
TTHM concentrations and cases of bladder cancer and deaths across
potentially affected drinking water systems. Of the regulatory options
EPA evaluated, across the states with affected systems, Option 4
generated the greatest reductions in TTHM concentrations and bladder
cancer cases and deaths. Under all of the regulatory options, for those
potentially affected systems with modeled reductions in TTHM
concentrations and in bladder cancer cases and deaths, most serve
populations that have a higher proportion of at least one population
group of concern as compared to the national average, with the largest
proportion serving populations with two population groups of concern
above the national average. Additionally, EPA found that states with
affected systems serving populations with one population group of
concern above the national average experienced the largest median
reductions in TTHM concentrations and bladder cancer cases and deaths.
Furthermore, EPA found that the magnitude of the median change in TTHM
and bladder cancers decreased with the more stringent regulatory
options in communities with one, two, or three or more population
groups of concern above the national average. EPA determined that this
was not due to there being fewer reductions in TTHM concentrations and
in bladder cancer cases and excess bladder cancer deaths with more
stringent options, but rather that more new states with affected
systems experiencing smaller changes were being added under the more
stringent options. Therefore, Option 4 still generated the greatest
improvements across analyses. For more information of the analysis of
drinking water impacts, see sections 9.3.1 and 9.3.2 of the EJA.
4. Cumulative Risks
In the EA, EPA expanded upon its assessment of human health impacts
from individual pollutant exposures to include an evaluation of
potential human health risks from exposures to mixtures of pollutants
present in steam electric power plant discharges. Using information on
human health risks related to pollutant mixtures from the Agency for
Toxic Substances and Disease Registry (ATSDR), EPA estimated potential
human health risks among fish consumer cohorts exposed to pollutant
mixtures of concern--Arsenic-Cadmium-Lead (As-Cd-Pb), Zinc-Lead (Zn-
Pb), and Methylmercury-Lead (MeHg-Pb)--from consuming fish caught in
potentially affected immediate receiving waters of steam electric power
plants. EPA used the results of this analysis to assess the
distribution of potential human health risks across population groups
of concern in communities with immediate receiving waters with human
health endpoint-specific Hazard Index (HI) exceedances.
After examining baseline results of the EA where human health
endpoint-specific HI values were greater than 1, the record indicates
that across mixtures of concern and fisher cohorts, EPA found that in
communities with immediate receiving waters with exceedances there are
larger proportions of the population identified as groups of concern,
particularly American Indian or Alaskan Native (non-Hispanic), than the
national average. This result is driven by baseline exceedances
observed in the Unnamed tributary to the Chaco River, which is in the
Navajo Nation. Additionally, the record indicates that across mixtures
of concern and cohorts, communities with immediate receiving waters had
larger proportions of various population groups of concern under the
baseline than communities with immediate receiving waters without
exceedances. Based on these findings regarding the distribution of
population groups of concern in communities with immediate receiving
waters with exceedances, EPA concluded that there are PEJC present
under the baseline.
EPA's analysis under the regulatory options showed that, across
mixture of concern and cohorts, none of the regulatory options results
in increases in the number of immediate receiving waters with
exceedances and in the population affected compared to the baseline.
Across mixtures of concern and cohorts, Options 3 and 4 most often
generated the largest reductions relative to the baseline in immediate
receiving water with exceedance and in the population affected.
Additionally, Options 3 and 4 most often produced the greatest
proportional reductions in the distribution of human health impacts for
population groups of concern in communities with immediate receiving
waters with exceedances compared to the national average and
communities with immediate receiving waters without exceedances. For
more information on the analysis of potential cumulative human health
risks, see section 9.4 of the EJA.
D. Distribution of Benefits and Costs
EPA examined the estimated benefits and costs of the regulatory
options in this proposal for potential differences in how they are
distributed across socioeconomic groups, in addition to evaluating the
distribution of exposures and health impacts discussed above. Office of
Management and Budget (OMB) Circular A-4, which implements E.O. 12866,
states that regulatory analyses ``should provide a separate description
of distributional effects (i.e., how both benefits and costs are
distributed among sub-populations of particular concern).'' As
discussed below, EPA research demonstrates that climate change impacts
are likely to accrue to minority and low-income populations, but other
benefits and costs under the proposed rule may not have substantial
impacts.
EPA began its evaluation of benefits with a screening of the
benefits categories. For Option 3, at both three percent and seven
percent discount rates, approximately 99 percent of monetized benefits
accrued from reductions in air pollution due to estimated shifts in
electric generation resulting from the incremental costs of the
proposed rule. Furthermore, these air benefits were always comprised of
approximately a 3-to-1 ratio of conventional air pollutant health
benefits to GHG benefits.\157\ Thus, while EPA evaluated a number of
exposures and endpoints for disproportionate baseline impacts, the
Agency screened these two benefit categories through this initial
comparison for further evaluation.
---------------------------------------------------------------------------
\157\ EPA scaled the air benefits to other regulatory options
based on total costs.
---------------------------------------------------------------------------
With respect to GHG benefits, scientific assessments and Agency
reports produced over the past decade by the U.S. Global Change
Research Program,158 159 the Intergovernmental Panel on
Climate Change,160 161 162 163
[[Page 18883]]
and the National Academies of Science, Engineering, and Medicine
164 165 provide evidence that the impacts of climate change
raise PEJC. These reports conclude that poorer or predominantly non-
White communities can be especially vulnerable to climate change
impacts because they tend to have limited adaptive capacities, are more
dependent on climate-sensitive resources such as local water and food
supplies, or have less access to social and information resources. Some
communities of color, specifically populations defined jointly by
ethnic/racial characteristics and geographic location, may be uniquely
vulnerable to climate change health impacts in the United States.
---------------------------------------------------------------------------
\158\ USGCRP, 2018. Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi.org/10.7930/NCA4.2018.
\159\ USGCRP, 2016. The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. Crimmins, A.,
J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J.
Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M.
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S.
Global Change Research Program, Washington, DC, 312 pp.
www.dx.doi.org/10.7930/J0R49NQX.
\160\ Oppenheimer, M., M. Campos, R.Warren, J. Birkmann, G.
Luber, B. O'Neill, and K. Takahashi, 2014: Emergent risks and key
vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of
Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, and L.L.White (eds.)].
Cambridge University Press, Cambridge, United Kingdom and New York,
NY, USA, pp. 10391099.
\161\ Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M.
Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food
security and food production systems. In: Climate Change 2014:
Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral
Aspects. Contribution of Working Group II to the Fifth Assessment
Report of the Intergovernmental Panel on Climate Change [Field,
C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E.
Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma,
E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and
L.L.White (eds.)]. Cambridge University Press, Cambridge, United
Kingdom and New York, NY, USA, pp. 485-533.
\162\ Smith, K.R., A.Woodward, D. Campbell-Lendrum, D.D. Chadee,
Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn, 2014:
Human health: impacts, adaptation, and co-benefits. In: Climate
Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global
and Sectoral Aspects. Contribution of Working Group II to the Fifth
Assessment Report of the Intergovernmental Panel on Climate Change
[Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea,
T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B.
Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and
L.L.White (eds.)]. Cambridge University Press, Cambridge, United
Kingdom and New York, NY, USA, pp. 709-754.
\163\ IPCC (Intergovernmental Panel on Climate Change), 2018.
Global Warming of 1.5 [deg]C, An IPCC Special Report on the impacts
of global warming of 1.5 [deg]C above pre-industrial levels and
related global greenhouse gas emission pathways, in the context of
strengthening the global response to the threat of climate change,
sustainable development, and efforts to eradicate poverty [Masson-
Delmotte, V., P. Zhai, H.-O. P[ouml]rtner, D. Roberts, J. Skea, P.R.
Shukla, A. Pirani, W. Moufouma-Okia, C. P[eacute]an, R. Pidcock, S.
Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy,
T. Maycock, M. Tignor, and T. Waterfield (eds.)]. In Press.
\164\ National Research Council. 2011. America's Climate
Choices. Washington, DC: The National Academies Press. www.doi.org/10.17226/12781.
\165\ NASEM. 2017. Communities in Action: Pathways to Health
Equity. Washington, DC: The National Academies Press. www./doi.org/10.17226/24624.
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EPA recently conducted a peer-reviewed analysis of the distribution
of climate change impacts. EPA (2021) evaluated the disproportionate
risks to socially vulnerable populations (defined based on age, income,
education, race, and ethnicity) associated with six impact categories:
air quality and health, extreme temperature and health, extreme
temperature and labor, coastal flooding and traffic, coastal flooding
and property, and inland flooding and property.\166\ EPA calculated
risks for each socially vulnerable group relative to its ``reference
population'' (all individuals outside of each group) for scenarios with
2 [deg]C of global warming or 50 centimeters of sea level rise. The
estimated risks were based on current demographic distributions in the
contiguous United States. EPA (2021) includes findings \167\ that the
following groups are more likely than their reference population to
currently live in areas with:
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\166\ U.S. EPA (Environmental Protection Agency). 2021. Climate
Change and Social Vulnerability in the United States: A Focus on Six
Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.
\167\ EPA (2021) also noted that American Indian and Alaska
Native individuals may place a high value on risks to subsistence,
cultural, and other natural resources that were not explored in the
report. This is consistent with concerns raised by tribal community
members as part of the outreach discussed above.
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The highest increases in childhood asthma diagnoses from
climate-driven changes in PM2.5 (low-income, Black and
African American, Hispanic and Latino, and Asian populations);
The highest percentage of land lost to inundation (low-
income and American Indian and Alaska Native populations);
The highest increases in mortality rates due to climate-
driven changes in extreme temperatures (low-income and Black and
African American populations);
The highest rates of labor hour losses for weather-exposed
workers due to extreme temperatures (low-income, Black and African
American, American Indian and Alaska Native, Hispanic and Latino, and
Pacific Islander populations);
The highest increases in traffic delays associated with
high-tide flooding (low-income, Hispanic and Latino, Asian, and Pacific
Islander populations); and
The highest damages from inland flooding (Pacific Islander
populations).
For further discussion of the impacts analyzed in U.S. EPA (2021)
and other peer-reviewed evaluations, see section 10.1.1 of the EJA.
EPA notes that the changes in GHG emissions attributable to the
proposed regulatory options are relatively small compared to worldwide
emissions. Nevertheless, the findings of peer-reviewed evaluations
demonstrate that actions that reduce GHG emissions are likely to reduce
climate impacts on vulnerable communities such as minority and low-
income populations.
With respect to conventional air pollutant health benefits, the
current EPA modeling methodology results in benefits that are
proportional to exposures. In other words, the distributional findings
of air pollutant exposures discussed above are the same findings EPA
has for this benefit category: exposure and health benefit improvements
and degradations attributable to this proposal will be proportionately
experienced by all demographic populations evaluated. However, there
are several important nuances and caveats to this conclusion owing to
differences in vulnerability and health outcomes across population
subgroups. For example, there is some information suggesting that the
same PM2.5 exposure reduction will reduce the hazard of
mortality more so in Black populations than in White
populations.168 169 In addition, demographic-stratified
information relating PM2.5 and ozone to other health effects
and valuation estimates is currently lacking.
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\168\ U.S. EPA (2019). Integrated Science Assessment (ISA) for
Particulate Matter (Final Report). U.S. Environmental Protection
Agency, Office of Research and Development, Center for Public Health
and Environmental Assessment. Research Triangle Park, NC. U.S. EPA.
EPA/600/R-19/188. December 2019. Available at: www.epa.gov/naaqs/particulate-matter-pm-standards-integrated-science-assessments-current-review.
\169\ U.S. EPA (2022). Supplement to the 2019 Integrated Science
Assessment for Particulate Matter (Final Report). U.S. Environmental
Protection Agency, Office of Research and Development, Center for
Public Health and Environmental Assessment. Research Triangle Park,
NC. U.S. EPA. EPA/600/R-22/028. May 2022. Available at: www.epa.gov/isa/integrated-science-assessment-isa-particulate-matter.
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With respect to costs, EPA notes that the impacts on ratepayers
will depend on the degree to which compliance costs are passed through
to electricity consumers via higher electricity rates. In general,
lower-income households spend less, in the absolute, on energy than
higher-income households, but energy expenditures represent a larger
share of their income. Therefore, electricity price increases tend to
have a relatively larger effect on lower-income households. Further
discussion of these disparities is provided in
[[Page 18884]]
section 10.2 of the EJA. EPA estimated the potential impacts of
incremental ELG compliance costs on households' utility bills based on
average electricity consumption and assuming a worst-case scenario
where all costs are passed through to consumers. EPA estimated that the
proposed rule corresponds to an average increase of $0.63 per household
per year, with a range of $0.09 to $1.31 per year across NERC regions.
These cost increases are too small to indicate the potential for
significant direct impacts to household electricity consumers.\170\
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\170\ EPA notes that other electricity consumers (e.g.,
industrial consumers) could also face increased electricity prices.
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E. Results of the Analysis
Overall, the analysis showed that benefits associated with
improvements to water quality, wildlife, and human health resulting
from reductions in pollutants in surface water and drinking water will
accrue to minority and low-income populations at a higher rate under
some or all of the proposed regulatory options. Remaining exposures,
impacts, costs, and benefits analyzed either accrue at a higher rate to
populations which are not minority or low-income, accrue
proportionately to all populations, or are small enough that EPA could
not conclude whether disproportionate positive or negative impacts from
the options being considered would occur. While the changes in GHGs
attributable to the proposed regulatory options are relatively small
compared to worldwide emissions, findings from peer-reviewed
evaluations demonstrate that actions that reduce GHG emissions are also
likely to reduce climate impacts on vulnerable communities, including
minority and low-income communities.
F. Solicitations on Environmental Justice Analysis and Community
Outreach
EPA solicits comment on the data, analysis, and results of the EJA.
EPA solicits comment on additional data or methods that could be used
to further expand the EJA and better capture the potential impacts of
the proposed rule. In light of the considerations EPA discussed for
conventional air pollution health benefits, EPA solicits comment on
whether and how the Agency could further evaluate the distributional
impacts of this benefit category in a final rule analysis. EPA also
solicits comment on any regulatory options not explicitly analyzed that
would further benefit communities with PEJC and could be built into any
final rule analyses.
EPA solicits comment on how the Agency should continue to engage
with the communities from Table XIII-1 of this preamble that were
included in the initial outreach. EPA asks that comments suggesting
additional outreach activities, especially those that might occur
during the public comment period, be provided early in the comment
period to allow the Agency sufficient time to plan and execute any
outreach. EPA solicits comment on whether EPA should conduct in-person
or hybrid public hearings in any or all of these communities during the
public comment period, in addition to the two nationwide virtual public
hearings already planned. EPA solicits comment on the best means for
maximizing public participation at any such meetings. EPA also solicits
comment on other communities that may warrant additional outreach and
engagement based on the results of the full-scale analysis or for
reasons not well documented in the EJA due to site-specific information
that was not readily available to the Agency.
XIV. Development of Effluent Limitations and Standards
This section describes the statistical methodology used to
calculate the long-term averages, variability factors, and proposed BAT
limitations and PSES. The effluent limitations and standards are based
on long-term average effluent values and variability factors that
account for variation in treatment performance of the model technology.
The proposed effluent limitations and/or standards, collectively
referred to in the remainder of this section as ``limitations,'' for
pollutants for each technology option are provided 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 to be 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.'' In this section, the term
``option long-term average'' and ``option variability factor'' refer to
the long-term averages and variability factors for technology options
for an individual wastestream rather than the regulatory options
described in Section VII of this preamble.
A. Criteria Used To Select Data as the Basis for the Limitations and
Standards
In developing effluent limitations guidelines and standards for any
industry, EPA qualitatively reviews all the data before selecting data
that represents 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 and demonstrate consistently diligent and optimal
operation. Application of this criterion typically eliminates any plant
with treatment other than the model technology. EPA determines whether
a plant meets this criterion based upon site visits; discussions with
plant management; and/or comparison to the characteristics, operation,
and performance of treatment systems at other plants. EPA often
contacts plants 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 when the plant has not
optimized the performance of its treatment system to the degree that
represents the appropriate level of control (e.g., BAT).
The second criterion 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 plants where the
commingled wastewaters did not result in substantial dilution, un-
equalized 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
proposing effluent limitations.
The third criterion ensures that the pollutants are present in the
influent at sufficient concentrations to evaluate treatment
effectiveness. To evaluate whether the data meet this criterion for
inclusion as a basis of the limitations, EPA uses the long-term average
test for plants where EPA possesses paired influent and effluent data
(see section 13 of the 2015 TDD for details of the long-term average
test). The test measures the influent concentrations to ensure a
pollutant is present at a sufficient concentration to evaluate
treatment effectiveness. If a data set for a pollutant fails the test
(i.e., pollutant
[[Page 18885]]
not present at a treatable concentration), EPA excludes the data for
that pollutant at that plant when calculating the limitations.
The fourth criterion requires that the data are valid and
appropriate for their intended use (e.g., the data must be analyzed
with a sufficiently sensitive method). Also, EPA does not use data
associated with periods of treatment upsets because these data would
not reflect the performance of 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, and other available information. As part of this
evaluation, EPA reviews the process or treatment conditions that may
have resulted in extreme values (high and low). Because 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.
EPA also applies the fourth criterion when reviewing data
corresponding to the initial commissioning period for treatment
systems. Most industries incur commissioning periods during the
adjustment period associated with installing new 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'' as the plant staff and equipment and
chemical vendors work 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 like clarifier sludge
wasting protocols. It may also take several weeks or months for
treatment system operators to gain expertise on 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.\171\
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\171\ 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 differ significantly 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 installing 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, like that which may occur
from a treatment system that has undergone either short or extended
duration shutdown.
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B. Data Selection for Each Technology Option
For FGD wastewater and BA transport water, the preferred regulatory
option proposes zero discharge of pollutants; therefore, no effluent
concentration data were used to develop the limitations for these
wastestreams.\172\ As described in Section VII of this preamble, EPA is
proposing that permitting authorities establish limitations for
discharges of pollutants in SI decant wastewater, SI dewatering
wastewater, and legacy wastewater on a case-by-case basis. Thus, no
effluent concentration data were used to set national effluent
limitations. For the limitations on CRL based on the chemical
precipitation technology option, EPA is proposing to transfer the
limitations calculated based on the 2015 and 2020 rule chemical
precipitation technology option for FGD wastewater because while EPA
does not have effluent data for leachate from plants that employ
chemical precipitation technology on CRL, EPA's record demonstrates
that CRL is chemically similar to FGD wastewater and amenable to such
treatment. EPA used the same approach in the 2013 proposed rule and in
the final 2015 rule for NSPSs for CRL, and the Agency solicits comment
on additional pilot tests or full-scale installations that could be
used in lieu of, or to supplement, this approach.
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\172\ This is also true for some of the technologies EPA
solicits comment on for CRL, SI decant wastewater, SI dewatering
wastewater, and legacy wastewater.
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C. CRL
EPA is proposing limitations on mercury and arsenic in leachate
based on chemical precipitation. As discussed in Section VII.B.3 of
this preamble, some discharges of leachate may also occur through
groundwater. EPA solicits comment on whether site-specific variability
in the subsurface soils, sorbents, and other characteristics could
result in lowering measured concentrations of the two chosen indicator
pollutants (mercury and arsenic) below the proposed CRL limitations
without actually treating the full suite of pollutants that EPA
proposes chemical precipitation is able to treat. Thus, for leachate
discharged through groundwater, EPA solicits comment on whether the
Agency should calculate daily and monthly limitations for these other
pollutants in Table XIV-1.
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\173\ The pollutants treated by chemical precipitation are
discussed in Section 8 of the TDD.
Table XIV-1--Other Pollutants Treated by Chemical Precipitation \173\
------------------------------------------------------------------------
------------------------------------------------------------------------
Antimony Magnesium
Barium Manganese
Beryllium Molybdenum
Cadmium Nickel
Chromium Thallium
Cobalt Titanium
Copper Vanadium
Lead Zinc
------------------------------------------------------------------------
Should EPA elect to calculate daily and monthly limitations for the
pollutants in Table XIV-1, EPA solicits comment on whether to use the
same data sets and methods used to calculate limitations for arsenic
and mercury that the Agency used in the 2015 rule record. Specifically,
EPA solicits comment on the data set of FGD wastewater treated by
chemical precipitation with regard to each of these pollutants. EPA
also solicits comment on the methodology described in the 2015 and 2020
rule records, which consists of interim steps of calculating a long-
term average and variability factors. EPA also solicits comment on data
where leachate was treated in a pilot or full-scale chemical
precipitation system that could be used in the calculation of such
limitations either in lieu of, or in addition to, the data discussed
above.
XV. Regulatory Implementation
A. Continued Implementation of Existing Limitations and Standards
EPA has continually stressed, since the announcement of this
supplemental rulemaking, that the 2015 and 2020 limitations (or lack
thereof) continue to apply.\174\ In the sections below, EPA discusses
considerations for permitting authorities and regulated entities as
they continue to implement existing
[[Page 18886]]
regulations and look ahead to the regulations in this proposal.
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\174\ 86 FR 41801 (August 3, 2021).
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1. Reaffirmation of Expectation That Requirement That FGD and BA
Transport Water BAT Limitations Apply ``as Soon as Possible'' Requires
Careful Consideration of the Soonest Date That the Discharger Can Meet
the Limitations
EPA reaffirms that permitting authorities must continue to write
permits that include the current 2015 and 2020 rule BAT limitations,
whether as part of permit renewals or permit modifications. Similarly,
permittees must meet applicable permit limitations as soon as possible.
EPA stresses that the Agency did not issue a postponement rule for the
2020 rule FGD wastewater and BA transport water BAT limitations as it
did in 2017 for the 2015 rule. The 2017 rule postponed the earliest
compliance dates of the 2015 rule for FGD wastewater and BA transport
water to November 2020 to ``preserve the status quo for FGD wastewater
and bottom ash transport water until EPA completes its next
rulemaking.'' \175\ This made sense at the time because EPA had
received new information in petitions suggesting that the 2015 rule
limitations could not be met with the 2015 BAT technology basis.\176\
In contrast, EPA's 2020 rulemaking generally reaffirmed, and provided
further flexibilities for, the technology bases established in the 2015
rule. There is no basis in the record indicating that the limitations
finalized in 2020 are not available or economically achievable, and
thus there is no reason for EPA to postpone their implementation.
Instead, EPA focused on progress toward eliminating discharges,
consistent with CWA section 301(b)(2)(A). Thus, EPA's announcement of
this supplemental rulemaking stated that ``the pollutant reductions
accomplished by the existing Rules will occur while the Agency engages
in rulemaking to consider more stringent requirements'' (86 FR at
41802, August 3, 2021). This is consistent with the CWA's structure of
progressively more stringent limitations pushing technological advances
over time.
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\175\ U.S. EPA (Environmental Protection Agency). 2017. Fact
Sheet: Postponement of Certain Compliance Dates for the Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Industry. EPA 823-S-17-001. September. Available online
at: www.epa.gov/sites/default/files/2017-09/documents/steam-electric-elg_final_postpone-compliance-dates_fact-sheet_sept-2017.pdf.
\176\ EPA notes that upon review in the 2020 rule record, these
suggestions were found to be without merit.
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Since EPA did not postpone the earliest compliance dates,
permitting authorities should not establish an ``as soon as possible''
date that is anything other than as soon as possible for the selected
technology. For example, where an applicant provides site-relevant
information on its biological treatment system that demonstrates it can
meet limitations by 2023, it would not be appropriate for the applicant
to request an ``as soon as possible'' date that is later by using as an
``other factor'' the fact that EPA is currently undergoing a
supplemental rulemaking. This would serve to further postpone
compliance with limitations intended to reflect technological advances
since promulgation of steam electric ELGS in 1982. EPA also notes that
the Agency is soliciting comment in the sections above on alternative
flexibilities such as alternative formulations of an early adopter
subcategory, one of which may include plants that have already
contracted for, but not yet installed, biological treatment. Though EPA
solicits comment on various potential permutations of any final rule,
the Agency is not changing or postponing the existing 2020 rule. Thus,
anything but steadfast implementation of the current 2020 rule
limitations at this time is not warranted.
In some cases, however, a facility may not yet have contracted for
a specific technology and may be considering alternatives. In such
circumstances, a permitting authority may consider the timeframes of
more advanced technologies when determining the ``as soon as possible''
date. For example, if a permit applicant submitted timeframes for both
a ZVI system that could be operational in 2024 and an alternative
consisting of plant modifications to recycle wastewater and operate
zero discharge by 2025, it would be reasonable for the permitting
authority to set an ``as soon as possible'' date for the facility to
eliminate its discharge in 2025.\177\
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\177\ Note that a decision between biological vendors or between
a biological and ZVI vendor with essentially the same performance
would not warrant a later date just because one vendor cannot
complete its system until a later date.
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Similar parallels can be seen with BA transport water. Limitations
based on a high recycle rate system should still be included in a
permit with a date that is ``as soon as possible'' to meet the site-
specific purge limitation. If a facility has not yet contracted for a
technology and is deciding between a dry handling system (e.g.,
pneumatic) and a high recycle rate system, it would be reasonable for
the permitting authority to consider the longer timeframe necessary for
the dry handling system.
2. Reaffirmation That CRL and Legacy Wastewater BAT Limitations Require
a Site-Specific BPJ Analysis and Careful Consideration of Technologies
Beyond Surface Impoundments
Under current law, permitting authorities must continue to conduct
BPJ analyses and establish TBELs pursuant to 40 CFR 125.3(c)(2) and (3)
for BA purge water, CRL,\178\ and legacy wastewater unless and until
EPA promulgates nationwide BAT. In conducting these analyses, EPA has
discussed several technologies in the 2015, 2020, and current proposed
rule TDDs and preambles that permitting authorities may consider or
select as the basis for TBELs. Where these technologies are included in
a BPJ analysis, they must be evaluated by the permitting authority
pursuant to the factors set forth in section 125.3(d)(3).\179\
Furthermore, as EPA notes in the discussion of FGD wastewater above,
there may be multiple, separate legacy wastewaters at a single plant.
Thus, in some cases, permitting authorities may have to decide whether
these wastewaters should receive separate limitations.\180\ Due to the
ongoing rulemaking, EPA also recommends, but is not requiring, that
permits issued or modified between this proposal and any final rule
contain a reopener clause in accordance with 40 CFR 122.62(a)(7) and
124.5.
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\178\ For CRL discharged via groundwater, EPA notes that this is
a technology-based CWA requirement--a separate and distinct
requirement from any CCR rule corrective action requirements which
may apply.
\179\ Consistent with section 304(b)(2)(B) of the CWA, these
consist of: (i) The age of equipment and facilities involved; (ii)
The process employed; (iii) The engineering aspects of the
application of various types of control techniques; (iv) Process
changes; (v) The cost of achieving such effluent reduction; and (vi)
Non-water quality environmental impact (including energy
requirements).
\180\ Furthermore, permitting authorities could determine that
more stringent water quality-based effluent limitations are needed
to achieve water quality standards.
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3. Consideration of Late Notice of Planned Participation
In Section VII of this preamble above, EPA discussed the proposed
retention of the subcategory for EGUs permanently ceasing coal
combustion by 2028. EPA also solicited comment on extending the period
for filing a NOPP for this subcategory. EPA also solicits comment on
whether this extended period should be available to LUEGUs and high FGD
flow plants. Any final rule would not be promulgated until 2024.
Therefore, the effect of removing these subcategories in a final rule
would be that the three impacted plants of which EPA is aware
[[Page 18887]]
would still be required to meet any permitted subcategory limitations
presently, and in the next permit renewal these plants would be
required to meet the zero-discharge limitations for FGD wastewater in
this proposal. Given the five-year permit cycle and assuming
implementation through permitting immediately after promulgation of the
final rule in 2024, the ``no later than'' date would be December 31,
2029. Thus, under the flexibility of the permitting authority to
consider ``other factors'' under section 423.11(t), these plants could,
subject to permitting authority discretion, effectively have one
additional year to discharge under the current, less stringent
limitations than plants in the existing subcategory for EGUs
permanently ceasing coal combustion by 2028. EPA solicits comment on
the reasonableness of this possible result, including whether these
plants should be required to file a NOPP for limitations under the
subcategory for EGUs permanently ceasing coal combustion by 2028,
should they elect to retire.
B. Implementation of New Limitations and Standards
The limitations and standards in this proposed rule would apply to
discharges from steam electric power plants through incorporation into
NPDES permits issued by EPA and authorized states under CWA section
402, and through pretreatment programs under CWA section 307. NPDES
permits or control mechanisms issued after a final rule's effective
date must incorporate the ELGs, as applicable. Where permits with the
2015 and/or 2020 rule limitations have already been issued, EPA expects
that any final rule requirements would be incorporated in the next
permit. Also, under CWA section 510, states can require effluent
limitations under state law as long as they are no less stringent than
the requirements of any final rule. Finally, in addition to requiring
application of the technology-based ELGs in any final rule, CWA section
301(b)(1)(C) requires the permitting authority to impose more stringent
effluent limitations, as necessary, to meet applicable water quality
standards.
1. Availability Timing of Proposed Requirements
The direct discharge limitations in this rule apply only when
implemented in an NPDES permit issued to a discharger. Under the CWA,
the permitting authority must incorporate these ELGs into NPDES permits
as a minimum level of control. The proposed rule provides the plant's
permitting authority with discretion to determine the date when the new
effluent limitations for FGD wastewater and BA transport water would
apply to a given discharger. EPA proposes that the earliest date these
new limitations could apply to a discharger is the effective date of
any final rule. Except for the limitations in certain subcategories,
for any finalized effluent limitation that is specified to become
applicable after the effective date, the specified date must be as soon
as possible after that date, but in no case later than December 31,
2029. For dischargers subject to less stringent limitations based on
certifications that they qualify for a subcategory based on permanent
cessation of coal combustion, however, EPA proposes to require
permitting authorities to put the more stringent zero-discharge
limitations for FGD wastewater and BA transport water in the existing
permit effective the day after the date of closure. This way, EPA would
ensure that dischargers would not benefit from less stringent
limitations based on closure by a certain date if that closure does not
occur. This proposal would not impact dischargers choosing to meet the
2020 VIP effluent limitations for FGD wastewater; the date for meeting
those limitations is December 31, 2028.
Pretreatment standards, unlike effluent limitations, are directly
enforceable and must specify a time for compliance not to exceed three
years from the date of promulgation under CWA section 307(b)(1). Under
EPA's General Pretreatment Regulations for Existing and New Sources,
POTWs with flows in excess of five MGD must develop pretreatment
programs meeting prescribed conditions. These POTWs have the legal
authority to require compliance with applicable pretreatment standards
and control the introduction of pollutants to the POTW through permits,
orders, or similar means. POTWs with approved pretreatment programs act
as the control authorities for their industrial users. Among the
responsibilities of the control authority are the development of the
specific discharge limitations for the POTW's industrial users. Because
pollutant discharge limitations in categorical pretreatment standards
may be expressed as concentrations or mass limitations, in many cases,
the control authority must convert the 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 potential 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
any final rule is promulgated, even before the permit renewal process.
The ``as soon as possible'' date is the effective date of any final
rule, unless the permitting authority determines another date after
receiving relevant information submitted by the discharger.\181\ The
proposed rule would not revise the specified factors permitting
authorities must consider in determining the as soon as possible date
under the 2015 and 2020 rules. Based on receiving relevant information
from the discharger, the NPDES permitting authority may determine a
different date is ``as soon as possible'' within the implementation
period, using the factors below:
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\181\ 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 32-35
months, the FGD wastewater requirements within 28 months, and the
CRL requirements within 22 months (DCN SE08480).
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(1) Time to expeditiously plan (including to raise capital),
design, procure, and install equipment to comply with the requirements
of the final rule.
(2) Changes being made or planned at the plant in response to GHG
regulations for new or existing fossil fuel-fired plants under the CAA,
as well as regulations for the disposal of coal combustion residuals
under subtitle D of the RCRA.
(3) For FGD wastewater requirements only, an initial commissioning
period to optimize the installed equipment.
(4) Other factors as appropriate.
The ``as soon as possible'' date determined by the permitting
authority may or may not be different for each wastestream. The NPDES
permitting authority should provide a well-documented justification of
how it determined the ``as soon as possible'' date in the fact sheet or
administrative record for the permit. If the permitting authority
determines a date later than the effective date of any final rule, the
justification should explain why allowing additional time to meet any
final limitations is appropriate, and why the discharger cannot meet
the effluent limitations as of the effective date. Finally, while the
Agency is proposing a ``no later than'' date of December 31, 2029, EPA
solicits comment on earlier
[[Page 18888]]
or later ``no later than'' dates such as five years from the effective
date of the rule or a date that would harmonize with air regulations
currently being developed for this same industry.
2. Conforming Changes for Transfers in Sections 423.13(o) and 423.19(i)
EPA is proposing to remove the LUEGU subcategory as discussed in
Section VII.C of this preamble above. For consistency, EPA is proposing
to remove the portions of section 423.13(o) that refer to this
subcategory. This includes removal of paragraph (o)(1)(i), removal of
paragraphs (o)(1)(ii)(C)-(E), and a renumbering of the remaining
paragraphs. EPA is also revising paragraph (o)(3) as it would now apply
to all remaining transfers. EPA is proposing to revise the reporting
and recordkeeping requirements of section 423.19(i) to reflect the
remaining transfer provisions. EPA solicits comment on whether any
additional conforming changes are necessary for the transfer provisions
of section 423.13(o).
3. Conforming Changes for Voluntary and Involuntary Delays in Sections
423.18(a) and 423.19(j)
EPA is proposing to remove the LUEGU subcategory and add an early
adopter subcategory, as discussed in Section VII.C of this preamble
above. For consistency, EPA is proposing to remove reference to LUEGUs
and add a reference to early adopter EGUs in the permit conditions of
section 423.18(a). EPA is also proposing conforming changes to the
reporting and recordkeeping requirements in section 423.19(i).
Specifically, EPA is proposing to add reference to the filings for
material delays associated with the early adopter subcategory and
associated 2032 permanent cessation of coal combustion date. EPA
solicits comment on whether any additional conforming changes are
necessary for the permit conditions or reporting and recordkeeping
provisions to document these voluntary and involuntary delays.
EPA also wishes to clarify the applicability of section 423.18(a)
with respect to TVA. TVA is not subject to regulation or oversight by
either a public utility commission or an independent system operator
but rather serves those functions for itself in its service territory.
In addition, as of May 31, 2007, TVA was certified by NERC as the
reliability coordinator for itself, as well as for TVA Reliability
Coordinator Members.\182\ As the NERC-certified reliability
coordinator, TVA has the authority to issue operating instructions and
emergency operating instructions with which the TVA Reliability
Coordinator Members must comply. It is in every respect a competent
electricity regulator. The current regulations broadly refer to ``a
competent electricity regulator (e.g., an independent system
operator)'' and therefore would reasonably include unique situations
such as that of TVA. Nevertheless, EPA solicits comment on whether this
unique situation should explicitly be included in the regulatory text.
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\182\ These members consist of Memphis Light, Gas, and Water
(MLGW), Associated Electric Cooperative, Inc. (AECI), Louisville Gas
& Electric and Kentucky Utilities (LG&E/KU), Owensboro Municipal
Authority, and Smoky Mountain Transmission.
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4. Recommended Information To Be Submitted With a Permit Application
for a Potential Discharge of CRL Through Groundwater
The question of whether facilities in this sector require a permit
for any wastewater that travels through groundwater is a long-standing
one. The Supreme Court recently clarified that discharges of pollutants
through groundwater to WOTUS are subject to the NPDES permit program if
they are the functional equivalent of a direct discharge. See County of
Maui v. Hawaii Wildlife Fund, 140 S. Ct. 1462 (2020). The record
indicates that it is currently uncommon for CRL discharges through
groundwater to be controlled in NPDES permits. Thus, EPA is
recommending that all facilities with CCR landfills or surface
impoundments evaluate whether there are any such discharges that are
subject to the NPDES permit program. For any such discharges that are
not currently authorized by an NPDES permit, EPA strongly recommends
that the permittee expeditiously seek permit coverage. CWA section
301(a) explains that, except as in compliance with certain provisions
of the act, ``. . . the discharge of any pollutant by any person shall
be unlawful.'' The process to obtain NPDES permit authorization for any
discharges typically begins when a permittee submits a permit
application to seek permit coverage for discharge(s).
To help permitting authorities decide whether to issue a permit
authorizing such discharges, EPA recommends that the permittees submit
a permit application with sufficient information to inform that
decision. NPDES regulations at 40 CFR 122.21(e) prohibit permitting
authorities from issuing an individual permit until and unless a
prospective discharger provides a complete application. Section
122.21(e)(1) states, ``an application for a permit is complete when the
Director receives an application form and any supplemental information
which are completed to his or her satisfaction.'' Absent EPA or state
permit application forms specific to discharges through groundwater,
EPA recommends that permit applicants with potential CRL discharges
through groundwater subject to 40 CFR part 423 submit a permit
application using the existing form(s) the permitting authority
requires for industrial facilities, along with any supplemental
information that would assist the permitting authority, including any
of the information described below.
EPA recommends that permitting authorities also meet with
applicants early in the process to understand what supplemental
information they may need. The itemized elements of general and
technical information described below are provided for consideration;
the permitting authority may determine it needs this information, only
a subset of this information, or other information. Providing the
supplemental information that the permitting authority deems
appropriate will help expedite the permitting authority's review of the
permit application and potential permit issuance. As discussed in the
NPDES Permit Writer's Manual: \183\
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\183\ Available online at: www.epa.gov/npdes/npdes-permit-writers-manual.
``[A]fter the initial application review, the permit writer may
request that an applicant submit other information needed to decide
whether to issue a permit and for permit development. The requested
information could include the following: additional information,
---------------------------------------------------------------------------
quantitative data . . .''
Supplemental information also can be obtained later when the permit
writer is drafting the permit. The applicant may submit additional
information voluntarily or be required to do so under CWA section 308
or a similar provision of state law. This process can be time consuming
and intensive, as described in the Permit Writer's Manual: ``in some
situations, a considerable amount of correspondence might be required
before the permit writer obtains all the information that he or she
believes is necessary to draft the permit.'' For permittees that
request NPDES permit authorization for discharges of CRL through
groundwater, EPA recommends that the permittee provide the information
described below as soon as possible to the permitting authority. This
information is unique to the steam electric industrial
[[Page 18889]]
sector and may not be warranted for other industrial sectors at this
time. This sector contains hundreds of large, unlined landfills and
surface impoundments that are within a mile of a surface waterbody (and
often substantially closer). Furthermore, EPA believes much of the
supplemental data and information described below (and that would be
part of the permit application) is already required and made publicly
available under the CCR rule. Thus, the incremental burden to
facilities should be minimal, especially when compared to the potential
burden of the permitting authorities seeking out and compiling this
same information.
EPA Recommended General Information. General information
helps the permitting authority identify the major site features and
monitoring capabilities of the facility. The general information could
include:
(1) Facility name and owner(s).
(2) The identification number of the most recent final national
pollution discharge elimination permit, if any, and the date of
issuance.
(3) A table listing all coal-fired EGUs, if any, or a statement
that all EGUs have permanently ceased combustion of coal. The table
shall also include the name or identifier, commission year, and
nameplate capacity of each such EGU.
(4) A table listing all landfills and surface impoundments subject
to 257.50 et seq. For each such landfill or surface impoundment, the
table should also include the name or identifier, commission year,
acreage, the liner status consistent with the definitions of sections
257.70-257.72, types of solid wastes present, quantity of waste
present, and a statement that the landfill or surface impoundment is
either active or has ceased receipt of waste, listing the date it
ceased receipt of waste.
(5) A table listing all groundwater monitoring wells. For each such
well, the table should also include the name or identifier, commission
year, location information, screen depths, and type of geologic
material in which the well was screened (e.g., sand, silt, clay).
(6) A table listing all surface waterbodies located within one mile
of any landfill or surface impoundment from the table in #4 above, if
any, or the closest such waterbody if none are located within one mile.
The table should also include the hydraulic unit code and the shortest
measurable distance from any edge of the nearest landfill or surface
impoundment to any edge of the waterbody. This shortest distance should
be measured and reported at an average water level, maximum water level
(e.g., flood conditions), and minimum water level.
(7) A map with a legend depicting the location and boundaries of
all items listed in the above information, including labels identifying
such items.
EPA Recommended Technical Information. Technical
information on groundwater and subsurface data provides permitting
authorities a compiled set of information to evaluate the seven factors
identified in Maui. EPA notes that permitting authorities may request
any other information or data as appropriate. Technical information
could include:
(1) For each aquifer underlying the landfills and surface
impoundments identified in the general information above, a time series
of groundwater elevations as measured in the groundwater monitoring
wells covering either 2015 through the present, or the groundwater
monitoring well commission year through the present, whichever is
shorter.
(2) For each surface water identified in the general information
above, a time series of surface water elevations covering the same date
range of as in #1.
(3) For each landfill or surface impoundment from the general
information above, the elevation of the waste bottom. For each surface
impoundment, the operating level and freeboard shall also be included.
(4) A graph plotting the elevations in #1-3 over time.
(5) Measured, calculated, or estimated values of the site hydraulic
conductivity, hydraulic gradient, velocity of groundwater, and
effective porosity, giving particular consideration to these along the
trajectory of groundwater flow from the landfill or surface impoundment
to the surface waterbody.
(6) Estimated groundwater travel time from each landfill or surface
impoundment into each surface waterbody in the general information. In
addition to average estimates, minimum and maximum travel times should
be estimated.
(7) A groundwater potentiometric surface map of the facility
illustrating the average travel times estimated in #6. To the extent
possible, such a map should be created with data collected during the
same sampling round.
(8) Summary statistics including the minimum, maximum, and average
of the data and estimates in #1, 2, and 6.
(9) Using all available data, summary statistics (including
minimum, maximum, and average) of the concentration of each pollutant
in the table following this section for each groundwater monitoring
well supported by appendix tables containing all groundwater monitoring
data. Where no data exist for any pollutant in this table, there should
be a certification for each such pollutant that no groundwater
monitoring data exist. Erroneous data (e.g., due to lab error) may be
excluded with a narrative explaining the exclusions.
(10) Three isoconcentration plots showing the horizontal extent of
the most dispersed pollutant reported in #9 using the minimum, maximum,
and average values from each well. These plots should be supported by
an appendix containing isoconcentration plots showing the horizontal
extent of all remaining pollutants reported in #9 in the same manner.
(11) Three isoconcentration plots showing the vertical extent of
the most dispersed pollutant reported in #9 using the minimum, maximum,
and average values. These plots should be supported by appendix
isoconcentration plots showing the vertical extent of all remaining
pollutants reported in #9 in the same manner.
(12) Boring logs, geotechnical laboratory reports, and sieve
analyses from the initial safety factor assessment, if any, other site-
specific data and evaluations of the subsurface, and supplemental
geologic subsurface data from regional databases where necessary.
(13) A list of sorbents for the pollutants listed in the table
following this section, a list of which pollutants are known to sorb to
each, and a discussion of which sorbents are present in the subsurface
that contaminated groundwater would pass through to the surface
waterbodies listed in the general information. If available, include
laboratory measurements of contaminated uppermost aquifer material.
(14) The estimated cross-sectional surface area through which CRL
enters each surface waterbody listed in the table in the general
information.
(15) For each pollutant listed in the table following this section,
a minimum, maximum, and average estimate of the mass flux from each
landfill or surface impoundment and into each surface waterbody in the
general information, the mass sorbed in the subsurface, and the mass
dissolved in the groundwater.
BAT/PSES Treated Pollutants in CRL
------------------------------------------------------------------------
------------------------------------------------------------------------
Antimony Magnesium
Arsenic Manganese
Barium Mercury
Beryllium Molybdenum
Cadmium Nickel
Chromium Thallium
Cobalt Titanium
[[Page 18890]]
Copper Vanadium
Lead Zinc
------------------------------------------------------------------------
EPA solicits comment on every aspect of these recommendations.
While administrative burden to permitting agencies may initially
increase, given the Maui decision and the high visibility of the data
collected under the CCR rule, EPA anticipates that some of these
facilities may need permit coverage in the future. EPA's intent is to
assist permitting agencies by clarifying some of the supplemental data
that would be useful for determining the presence and nature of a
discharge of CRL through groundwater. EPA solicits comment on the
extent to which this recommended information would reduce the existing
burden to permitting authorities post-Maui and on alternatives that
might further reduce this burden.
EPA also solicits comment on three alternative approaches for
obtaining this information. First, EPA solicits comment on directly
obtaining this information through a series of CWA 308(a) information
request letters to all plants subject to 40 CFR part 423. Second, EPA
solicits comment on placing the recommendations above directly in a
regulation that would require provision of this information under CWA
308 authority. Third, EPA solicits comment on adding a requirement to
the permit application regulations of part 122 that a facility must
provide this information to the permitting authority as part of the
permit application process. Under all these alternatives, EPA solicits
comment on whether and how this information could be made publicly
available to increase transparency.
C. Reporting and Recordkeeping Requirements
EPA is proposing several new reporting and recordkeeping
requirements or changes and soliciting comment on others. First, to
implement the proposed rule's removal of two subcategories and addition
of an early adopter subcategory, under CWA sections 304(i) and 308,
this proposal includes four proposed changes to the individual
reporting and recordkeeping requirements of section 423.19. In
particular, EPA is proposing to add an additional component to the
annual progress reports under the subcategory for EGUs permanently
ceasing coal combustion. As with the reporting and recordkeeping
requirements of the 2020 rule, for the early adopter subcategory, EPA
is proposing to balance the additional flexibilities for certifying to
the subcategory at a later date with additional reporting and
recordkeeping to provide extra certainty that plants still intend to
avail themselves of those provisions. Moreover, EPA is proposing to add
reporting and recordkeeping requirements to facilitate evaluation of
CRL discharges through groundwater. EPA is also proposing to make
conforming changes that would remove reporting and recordkeeping
requirements applying to LUEGUs.
Second, to increase transparency for impacted communities, EPA is
proposing to require all steam electric plants subject to the reporting
and recordkeeping requirements of 423.19(d)-(k) to post this reporting
and recordkeeping information to a public-facing website.\184\
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\184\ EPA is seeking to adopt provisions for the websites
consistent with those of the CCR rule.
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Finally, EPA is soliciting comment on a potential reporting
requirement intended to enhance flexibility for the transition to zero-
discharge limitations for FGD wastewater and BA transport water.
1. Summary of Proposed Changes to the Annual Progress Reports for EGUs
Permanently Ceasing Coal Combustion by 2028
EPA proposes to modify the annual progress reports for the
subcategory of EGUs permanently ceasing coal combustion by 2028.
Specifically, EPA proposes adding a requirement that the annual
progress reports include either the official filing to the facility's
reliability authority or a certification providing an estimate of when
such a filing will be made. Furthermore, EPA is proposing that the
final annual progress report prior to permanent cessation of coal
combustion must include the official filing. While facilities may
already include these filings in the NOPP or annual progress reports,
these filings were not explicitly required in the 2020 rule and provide
the strongest assurance that a facility will not voluntarily change its
plans and continue operations beyond 2028. EPA solicits comment on
whether this or additional requirements would further support the
operation of the subcategory without unduly burdening regulated
facilities.
2. Summary of the Proposed Reporting and Recordkeeping Requirements for
Early Adopters
EPA is proposing new reporting and recordkeeping requirements for
early adopters, including an initial NOPP and annual progress reports.
EPA is proposing that the initial NOPP contain three items. First, EPA
is proposing the NOPP include a statement that the facility discharged
FGD wastewater after the effective date of the 2020 rule (85 FR 64650,
October 13, 2020). Second, EPA is proposing the NOPP include a
demonstration that the facility already complies with the limitations
for FGD wastewater and BA transport water in the 2020 rule by March 29,
2023. Third, EPA is proposing the NOPP include information, with
milestones, about plans for the permanent cessation of coal combustion
by 2032 from the relevant EGUs. EPA is proposing the first two
reporting requirements to ensure that early adopters relied on EPA's
rules when incurring the costs to comply with existing regulations and
subsequently did comply with these regulations. Specifically, EPA is
proposing that this information include diagrams and descriptions of
the relevant treatment chains, commission dates, and monitoring data
demonstrating compliance. EPA is proposing the latter requirement to
ensure that facility have a firm commitment to permanently cease coal
combustion by 2032. For this requirement, EPA is proposing to require
the same information and milestones as were required for the permanent
cessation of coal combustion subcategory by 2028 in the 2020 rule.
Finally, EPA is proposing that, as with the permanent cessation of coal
combustion subcategory in the 2020 rule (and consistent with the
proposed modification above), the early adopter subcategory also
include annual progress reports on completion of milestones, upcoming
milestones, and including certifications and official filings made to
the reliability authority. Thus, EPA proposes the same language for
consistency.
3. Summary of Proposed Reporting and Recordkeeping Requirements for CRL
Discharges Through Groundwater
As discussed in Section VII of this preamble above, EPA is
proposing BAT limitations and PSES for CRL. EPA further discusses in
that section and in the implementation section above that CRL can be
discharged not only through end-of-pipe discharges, but also through
groundwater. EPA is proposing to include annual reporting and
recordkeeping requirements to facilitate the permitting authorities'
review of CRL discharges through groundwater to surface waters that are
subject to NPDES permits. It would also facilitate compliance
monitoring and make compliance information available to the public.
[[Page 18891]]
EPA is proposing that facilities with discharges of CRL through
groundwater file an Annual Combustion Residual Leachate Monitoring
Report with the permitting authority, or control authority in the case
of indirect dischargers, annually. This annual reporting requirement
would be implemented via NPDES permits that authorize discharges of CRL
through groundwater or directly where an indirect discharger eliminates
the discharge through groundwater and subsequently discharges the
treated CRL to a POTW. EPA is proposing that this report provide a
comprehensive set of monitoring data. EPA is proposing this requirement
to facilitate permitting and control authorities' ability to determine
compliance with CRL limitations and to increase transparency to local
communities. Thus, in addition to the data provided under 40 CFR part
127, where a CRL discharge occurs through groundwater, EPA is proposing
to require groundwater monitoring data on the CRL leaving each landfill
and surface impoundment and where it enters surface waterbodies. To
increase transparency to local communities, EPA is proposing to require
the report to include monitoring data on all the pollutants treated by
chemical precipitation, rather than just mercury and arsenic. EPA
solicits comment on this approach.
EPA solicits comment on all aspects of the proposed CRL monitoring
report including the scope, types of information to be included, and
the timeframes for submitting these reports to the permitting
authority. EPA also solicits comment on whether there are additional
pieces of information that would increase transparency or that the
public or permitting authorities would find helpful. For example, one
comment in a community meeting suggested that EPA require some limited
independent monitoring and reporting to increase local community
members' trust in any results presented. EPA also solicits comment on
whether alternatives with a lower burden should be available in certain
circumstances.
4. Proposed Deletion of Reporting and Recordkeeping Requirements for
LUEGUs
EPA is proposing to remove the reporting and recordkeeping
requirements for LUEGUs in current section 423.19(c) and for the
associated BMP plans in current section 423.19(d), since EPA is
proposing to eliminate this subcategory, as described in Section VII of
this preamble above.
5. Proposed Requirement To Post Information to a Publicly Available
Website
The reporting and recordkeeping requirements of the CCR rule
included a novel approach for posting information to a publicly
available website. This was initially done because at the time the CCR
rule was signed, EPA did not have enforcement authority over the CCR
rule. Thus, given the self-implementing nature of the regulations, EPA
sought to make information more readily available to states and the
public who could enforce the CCR rule through citizen suits.\185\
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\185\ While the Water Infrastructure Improvements for the Nation
Act later provided EPA with permitting and oversight authority, the
CCR rule continues to require posting to publicly available
websites.
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In contrast to the CCR rule, ELGs are implemented largely through
authorized state permitting programs with EPA oversight. Nevertheless,
one message that EPA received in initial outreach to communities was
that there was a lack of trust of utilities (and in some cases, the
states that regulate them). Another message was that there was an
interest in more accessible information. Given the success CCR websites
have achieved in disseminating information to a variety of
stakeholders, EPA proposes a comparable posting requirement for the
ELG. Specifically, EPA proposes that all reporting and recordkeeping
information not only be retained by the regulated entity and provided
to the permitting authority, but that it also be posted to a public
website for 10 years, or the length of the permit plus five years,
whichever is longer. EPA solicits comment on this timeframe.
Furthermore, EPA's proposal would include NOPPs and other filings that
have occurred since the 2020 rule. These new requirements are detailed
in proposed regulatory text for section 423.19(c), and EPA solicits
comment on the appropriateness of this approach, as well as any
modifications to the approach that could improve transparency. EPA also
proposes to allow this posting on existing CCR compliance websites to
reduce paperwork burden and make it easier for communities to access.
The Agency solicits comment on other ways such postings could be done
while minimizing burdens.
6. Additional Solicitation on Providing a More Flexible Transition to
Zero Discharge
EPA solicits comment on creation of a temporary reporting
requirement, which would be in place prior to the facility meeting a
zero-discharge limitation. Under such an approach, a plant would not
include an optimization period in the calculation of its ``as soon as
possible'' date. Rather, the plant would monitor and report any
necessary discharges over the first year of attempted zero discharge
while the system was being optimized and these discharges would not be
a violation of the zero-discharge requirements. For subsequent years,
such a flexibility would be discontinued.
D. 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 each NPDES permit to include any
requirements, in addition to or more stringent than ELGs or standards
promulgated pursuant to sections 301, 304, 306, 307, 318, and 405 of
the CWA, necessary to achieve water quality standards established under
section 303 of the CWA, including state narrative criteria for water
quality. Those same regulations require that limitations must control
all pollutants or pollutant parameters (either conventional,
nonconventional, or toxic pollutants) that the Director determines are
or may be discharged at a level that will cause, have the reasonable
potential to cause, or contribute to an excursion above any state water
quality standard, including state narrative criteria for water quality
(40 CFR 122.44(d)(1)(i)).
The preamble to the 2015 rule discussed bromide 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.
While the 2020 rule did not include limitations on bromide for FGD
wastewater or BA transport water (beyond the removals that would be
required of plants choosing to meet the VIP limitations), the current
proposal would require zero discharge of FGD wastewater and BA
transport water for most plants. Nevertheless, EPA is proposing
subcategories for these wastewaters, and new data submitted to EPA on
CRL show measurable levels of
[[Page 18892]]
bromide.\186\ Therefore, the records for the 2015 rule, the 2020 rule,
and this proposal continue to suggest that permitting authorities
should consider establishing water quality-based effluent limitations
where necessary to meet applicable water quality standards to protect
of populations served by downstream drinking water treatment plants.
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\186\ The record also includes iodide in these discharges,
another pollutant which should be considered alongside bromide for
water quality-based effluent limitations.
---------------------------------------------------------------------------
In consultations conducted with state and local government
entities, EPA received comments from the American Water Works
Association (AWWA) and the Association of Metropolitan Water Agencies.
These comments requested that EPA consider technologies that could
treat upstream pollutants at the point of discharge, but also suggested
that EPA empower states to address the issue as well. The latter
discussion referenced the approaches discussed in Methods to Assess
Anthropogenic Bromide Loads from Coal-Fired Power Plants and Their
Potential Effect on Downstream Drinking Water Utilities.\187\ This
document, provided in comments during the 2020 rulemaking and again
during consultations on the current rulemaking, describes
methodologies, data sources, and considerations for constructing an
approach to bromide issues on a site-specific basis. This document
presents additional data sources that NPDES permitting authorities
could use to establish site-specific, water quality-based effluent
limitations (see, e.g., figure 29 in AWWA's document). The document
also provides examples of where states have already taken similar
action. For example, AWWA cites California's 0.05 mg/L standard for in-
river bromide to protect public health for specific waterways and
drinking water treatment systems.
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\187\ Available online at: www.awwa.org/Portals/0/AWWA/ETS/Resources/17861ManagingBromideREPORT.pdf?ver=2020-01-09-151706-107.
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In addition to considering water quality-based effluent limitations
for parameters present in the wastestreams in this proposal, EPA also
calls attention to the need to address potential for per- and
polyfluoroalkyl substance (PFAS) discharges. In EPA's PFAS Strategic
Roadmap,\188\ the Agency laid out actions that would prevent PFAS from
entering the environment. Specifically, EPA stated it would
``proactively use existing NPDES authorities to reduce discharges of
PFAS at the source and obtain more comprehensive information through
monitoring on the sources of PFAS and quantity of PFAS discharged by
these sources.'' EPA has already drafted a memorandum covering
facilities where EPA is the permitting authority,\189\ as well as
guidance to state permitting authorities to address PFAS in NPDES
permits.\190\ While the steam electric power sector was not identified
as one of the top PFAS dischargers, EPA notes that PFAS may
nevertheless be present in steam electric discharges. For example, the
Wisconsin Department of Natural Resources has found PFAS at eight power
plants.\191\ In addition, firefighting foam used in exercises or actual
fires at steam electric plants could contain PFAS. Therefore,
permitting or control authorities may appropriately consider whether
PFAS monitoring and any further restrictions (e.g., BMPs) would be
appropriate at a given facility.
---------------------------------------------------------------------------
\188\ U.S. EPA (Environmental Protection Agency). 2021. PFAS
Strategic Roadmap: EPA's Commitments to Action 2021-2024. October
18. Available online at: www.epa.gov/system/files/documents/2021-10/pfas-roadmap_final-508.pdf.
\189\ Fox, Radhika. 2022. Addressing PFAS Discharges in EPA-
Issued NPDES Permits and Expectations Where EPA is the Pretreatment
Control Authority. April 28. Available online at: www.epa.gov/system/files/documents/2022-04/npdes_pfas-memo.pdf.
\190\ Fox, Radhika. 2022. Addressing PFAS Discharges in NPDES
Permits and Through the Pretreatment Program and Monitoring
Programs. December 5. Available online at: https://www.epa.gov/system/files/documents/2022-12/NPDES_PFAS_State%20Memo_December_2022.pdf.
\191\ The maximum sampled concentrations in discharge from eight
power plants was 28 ng/L for PFOS and 35 ng/L for PFOA, which the
Wisconsin Department of Natural Resources theorized was due to
concentration in cooling tower effluent.
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XVI. Related Acts of Congress, E.O.s, and Agency Initiatives
Additional information about these statutes and E.O.s can be found
at www.epa.gov/laws-regulations/laws-and-executive-orders.
A. E.O.s 12866 (Regulatory Planning and Review) and 13563 (Improving
Regulation and Regulatory Review)
This proposed rule was submitted to the OMB for review as
significant under Section 3(f)(1) of Executive Order 12866. Any changes
made in response to OMB recommendations have been documented in the
docket. EPA prepared an analysis of the potential social costs and
benefits associated with this action. This analysis is contained in
Chapter 12 of the BCA and is available in the docket.
B. Paperwork Reduction Act
EPA has submitted the information collection activities in this
proposed rule to the OMB for approval under the Paperwork Reduction
Act. The Information Collection Request (ICR) document EPA prepared has
been assigned EPA ICR number 2752.01 and OMB Control Number 2040-NEW. A
copy of the ICR is available in the docket for this rule and is briefly
summarized here.
As described in Section XV.C of this preamble, EPA is proposing
several changes to the individual reporting and recordkeeping
requirements of section 423.19 for specific subcategories of plants
and/or plants that have certain types of discharges. EPA is proposing
to add reporting and recordkeeping requirements to plants in the early
adopter subcategory and plants that discharge CRL through groundwater,
and to remove reporting and recordkeeping requirements for LUEGUs. EPA
is also proposing a new requirement for plants to post reports to a
publicly available website.
Respondents/affected entities: The respondents affected by this ICR
are steam electric power plants. The North American Industry
Classification System (NAICS) identification number applicable to
respondents is 221112: Electric Power Generation Plants--Fossil Fuel
Electric Power Generation. The U.S. Census Bureau describes this U.S.
industry as establishments primarily engaged in operating fossil fuel
powered electric power generation facilities. These facilities use
fossil fuels, such as coal, oil, or gas, in internal combustion or
combustion turbine conventional steam process to produce electric
energy. The electric energy produced in these establishments is
provided to electric power transmission systems or to electric power
distribution systems.
Respondent's obligation to respond: Proposed language at 40 CFR
423.19 (c)-(l).
Estimated number of respondents: EPA estimates 100 steam electric
facilities would be subject to this proposed rulemaking.
Frequency of response: EPA made the following assumptions for
estimating frequency:
NOPPs, notices, and the Leachate Groundwater Information
Report (LGIR) would be submitted one time (in the first year of the
requirements).
Progress reports and the annual LGIR would be submitted
once a year following the submittal of the official NOPP (i.e., twice
over a three-year period).
[[Page 18893]]
Progress reports associated with EPA's VIP program or
NOPPs that have already been submitted would be submitted once a year
following the publication of the final rule.
Total estimated burden: For facilities, the estimated facility
universe for any reporting for the purpose of this estimate is 100
facilities. EPA estimates the total one-time labor hours associated
with this ICR for facilities is 11,525 and total annual labor hours
ranging from 1,400 to 7,260 for a total annual average of 9,160 hours.
For permitting/control authorities, the estimated total one-time labor
hours associated with this ICR is 4,350 and total annual labor hours
ranging from 30 to 1,900 for a total annual average of 2,700 hours.
Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: For facilities, EPA estimates the total one-
time labor costs to be $667,000 and total annual labor costs to range
from $81,000 to $422,300 for a total annual average of $531,000. For
permitting/control Authorities, EPA estimates the total one-time labor
costs to be $212,000 and total annual labor costs to range from $1,300
to $89,800 for a total annual average of $131,000.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on EPA's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden using the docket identified at the
beginning of this rule. Written comments and recommendations for the
proposed information collection may also be sent within 30 days of
publication of this notice to www.reginfo.gov/public/do/PRAMain. Find
this particular information collection by selecting ``Currently under
30-day Review--Open for Public Comments'' or by using the search
function. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after receipt, OMB must receive comments no
later than April 28, 2023. EPA will respond to any ICR-related comments
in the final rule.
C. Regulatory Flexibility Act
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the Regulatory
Flexibility Act. The small entities subject to the requirements of this
action include small businesses and small governmental jurisdictions
that own steam electric plants. EPA has determined that 229 to 427
entities own steam electric plants subject to the ELGs, of which 109 to
200 entities are small. These small entities own a total of 250 steam
electric plants (out of the total of 871 plants), including 20 plants
estimated to incur costs under the regulatory options. EPA considered
the impacts of the regulatory options in this proposal on small
businesses using a cost-to-revenue test. The analysis compares the cost
of implementing wastewater controls under the four regulatory options
to those under baseline (which reflects the 2020 rule, as explained in
Section V of this preamble). Small entities estimated to incur
compliance costs exceeding one or more of the one percent and three
percent impact thresholds were identified as potentially incurring a
significant impact. For the proposed rule (Option 3), EPA's analysis
shows only three small entities (one non-utility and two
municipalities) expected to incur incremental costs equal to or greater
than one percent of revenue. For one of these small entities (non-
utility), the incremental cost of the proposed rule exceeds three
percent of revenue. Details of this analysis are presented in Chapter 8
of the RIA, included in the docket.
These results support EPA's finding of no significant impact on a
substantial number of small entities.
D. Unfunded Mandates Reform Act
This action contains a Federal mandate under the Unfunded Mandates
Reform Act (UMRA), 2 U.S.C. 1531-1538 that may result in expenditures
of $100 million (adjusted annually for inflation) or more for state,
local, and tribal governments, in the aggregate, or the private sector
in any one year ($170 million in 2021 dollars). Accordingly, EPA has
prepared a written statement required under section 202 of UMRA. The
statement is included in the docket for this action (see Chapter 9 in
the RIA report) and briefly summarized below.
Consistent with the intergovernmental consultation provisions of
section 204 of the UMRA, EPA has initiated consultations with
government entities potentially affected by this proposed rule. As
described in Section XVI.E of this preamble, EPA held consultation
meetings with elected officials or their designated employees in
January 2022 to ensure their meaningful and timely input into the
proposed ELGs development. As described in Section XVI.F of this
preamble, EPA also initiated consultation and coordination with
federally recognized tribal governments in February 2022.
Consistent with section 205, EPA has identified and considered a
reasonable number of regulatory alternatives to develop proposed BAT.
These regulatory options are discussed in Section VII of this preamble.
These options included a range of technology-based approaches. As
discussed in detail in Section VII.B of this preamble, EPA is proposing
Option 3 as the preferred BAT after considering the factors required
under CWA section 304(b)(2)(B). The technologies are available, are
economically achievable, and have acceptable non-water quality
environmental impacts.
This proposed rule is not subject to the requirements of section
203 of UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. To assess the
impact of compliance requirements on small governments (i.e.,
governments with a population of less than 50,000), EPA compared total
costs and costs per plant estimated to be incurred by small governments
with the costs estimated to be incurred by large governments. EPA also
compared costs for small government-owned plants with those of non-
government-owned facilities. The Agency evaluated both the average and
maximum annualized costs per plant. Chapter 9 of the RIA report
provides details of these analyses. In all these comparisons, both for
the cost totals and, in particular, for the average and maximum cost
per plant, the costs for small government-owned facilities were less
than those for large government-owned facilities or small non-
government-owned facilities. On this basis, EPA concludes that the
compliance cost requirements of the proposed steam electric ELGs would
not significantly or uniquely affect small governments.
E. E.O. 13132: Federalism
EPA has concluded that this action has federalism implications
because it imposes direct compliance costs on state or local
governments, and the Federal Government will not provide the funds
necessary to pay those costs.
As discussed in Section XVI.B of this preamble, EPA anticipates
that this proposed action would not impose incremental administrative
burden on states from issuing, reviewing, and overseeing compliance
with discharge requirements. EPA has identified 148 steam electric
plants owned by 64 state or local government entities. Under the
proposed regulatory Option 3 (BAT and PSES), EPA projects that 17
government-owned plants would incur
[[Page 18894]]
compliance costs. EPA estimates that the maximum compliance cost in any
one year to governments (excluding the Federal Government) for the four
regulatory options ranges from $31 million under Option 1 to $46
million under Options 3 and 4 (see Chapter 9 of the RIA report for
details).
EPA provides the following federalism summary impact statement.
EPA consulted with state and local officials early in the process
of developing the proposed action to permit them to have meaningful and
timely input into its development. EPA invited government officials to
a consultation meeting held on January 27, 2022. EPA conducted outreach
with several intergovernmental associations representing elected
officials and encouraged their members to participate in the meeting,
including the National Governors Association, the National Conference
of State Legislatures, the Council of State Governments, the National
Association of Counties, the National League of Cities, the U.S.
Conference of Mayors, the County Executives of America, and the
National Associations of Towns and Townships.
Participants representing 15 state and local government
organizations participated in the virtual consultation meeting. EPA
representatives were also present. EPA received five sets of unique
written comments after the meeting. Two comments came from trade
associations representing public water systems. These comments
generally recommended more advanced treatment to reduce the pollutants
making their way downstream to intakes for government-owned public
water systems or, alternatively, to empower states to more effectively
address these discharges. The remaining three comments came from the
American Public Power Association and two of its member utilities.
These comments recommended the retention of existing limitations and
subcategories, a careful consideration of the CRL definition and BAT,
and a compliance pathway for utilities that installed or are installing
technologies to comply with the 2015 and 2020 rules.
As explained in Section VII of this preamble, EPA is proposing more
stringent limitations on several wastestreams that would alleviate
concerns raised by the public water systems. At the same time, EPA's
preferred option (Option 3) includes retention of the permanent
cessation of coal combustion subcategory and a proposed subcategory for
early adopters. EPA believes these differentiated requirements would
alleviate some of the concerns raised by publicly owned utilities.
Further, as explained in Section VIII of this preamble, EPA's analysis
demonstrates that the proposed requirements are economically achievable
for the steam electric industry as a whole and for plants owned by
state or local government entities. EPA is including in the docket for
this proposed action a memorandum that responds to the comments it
received through this consultation and the consultations described in
Section XVI.F of this preamble below. For further information regarding
the consultation process and supplemental materials provided to state
and local government representatives, please go to the steam electric
power generating effluent guidelines website at: www.epa.gov/eg/2021-supplemental-steam-electric-rulemaking. In the spirit of E.O. 13132,
and consistent with EPA policy to promote communications between EPA
and state and local governments, EPA specifically solicits comment on
the proposed ELGs from state and local officials.
F. E.O. 13175: Consultation and Coordination With Indian Tribal
Governments
This proposed action would not have tribal implications, as
specified in E.O. 13175 (65 FR 67249 (November 9, 2000)). It would not
have substantial direct effects on tribal governments, on the
relationship between the Federal Government and the Indian Tribes, or
the distribution of power and responsibilities between the Federal
Government and Indian Tribes as specified in E.O. 13175. EPA's analyses
show that no facility subject to these proposed ELGs is owned by tribal
governments. Thus, E.O. 13175 does not apply to this proposed action.
Although E.O. 13175 does not apply to this action, EPA consulted
with tribal officials in developing this action. EPA initiated
consultation and coordination with federally recognized tribal
governments in January 2022, sharing information about the steam
electric effluent guidelines rulemaking with the National Tribal
Caucus, the National Tribal Water Council, and several individual
tribes. EPA continued this government-to-government dialogue and, on
February 1 and February 9, 2022, invited tribal representatives to
participate in further discussions about the rulemaking process and
objectives, with a focus on identifying specific ways the rulemaking
may affect tribes.\192\ The consultation process ended on March 29,
2022. While no tribal governments requested direct government-to-
government consultations, EPA received written comments from three
tribes: the Sault Ste. Marie Tribe of Chippewa Indians, the Mille Lacs
Band of Ojibwe, and the Little Traverse Bay Bands of Odawa Indians.
These comments conveyed the importance of historical tribal waters and
rights (e.g., fishing, trapping) and recommended more stringent
technological controls to protect those rights or encourage retirement
or fuel conversion of old coal-fired units. EPA is including in the
docket for this action a memorandum that provides a response to the
comments it received through this consultation and the consultations
described in Sections XVI.D and XVI.E of this preamble above. For
further information regarding the consultation process and supplemental
materials provided to tribal representatives, please go to the steam
electric power generating effluent guidelines website at: www.epa.gov/eg/2021-supplemental-steam-electric-rulemaking. EPA specifically
solicits additional comment on this proposed action from tribal
officials.
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\192\ As discussed in Sections XIII and XVI.J of this preamble,
EPA also did targeted outreach to communities in the top tier of its
EJ screening analysis which included two tribal communities.
---------------------------------------------------------------------------
G. E.O. 13045: Protection of Children From Environmental Health Risks
and Safety Risks
This action is not subject to E.O. 13045 because EPA does not
believe the environmental health risks or safety risks addressed by
this action present a disproportionate risk to children. This action's
health and risk assessments are discussed in Chapters 4 and 5 of the
BCA and are summarized below.
EPA identified several ways in which the proposed regulatory
options could benefit children, including by potentially reducing
health risks from exposure to pollutants present in steam electric
plant discharges, or through impacts of the discharges on the quality
of source water used by public water systems. This reduction arises
from more stringent pollutant limitations as compared to baseline. In
particular, EPA quantified the changes in IQ losses from lead exposure
among preschool children and from mercury exposure in utero resulting
from maternal fish consumption under the four regulatory options as
compared to baseline. EPA also estimated changes in the lifetime risk
of developing bladder cancer due to exposure to TTHM in drinking water.
For this analysis, EPA did not estimate children-specific risks because
these adverse health effects normally follow
[[Page 18895]]
long-term exposure. Finally, EPA estimated changes in air-related
adverse health effects resulting from changes in the profile of
electricity generation under Option 3 as compared to baseline. The
analysis found that the resulting reductions in PM2.5 and
ozone will benefit children by reducing asthma onset and symptoms,
allergy symptoms, emergency room visits and hospital visits for
respiratory conditions, and school absences. These analyses show that
all the regulatory options presented in this proposal would benefit
children.
H. E.O. 13211: Actions That Significantly Affect Energy Supply,
Distribution, or Use
This proposed action is not a ``significant energy action'' because
it is not likely to have a significant adverse effect on the supply,
distribution, or use of energy. EPA analyzed the potential energy
effects of the proposed rule relative to baseline and found minimal or
no impacts on electricity generation, generating capacity, cost of
energy production, or dependence on a foreign supply of energy.
Specifically, the Agency's analysis found that the proposed rule would
not reduce electricity production by more than 1 billion kWhs per year
or by 500 MW of installed capacity, nor would the proposed rule
increase U.S. dependence on foreign energy supplies. For more detail on
the potential energy effects of the regulatory options in this
proposal, see section 10.7 in the RIA, available in the docket.
I. National Technology Transfer and Advancement Act
This rulemaking does not involve technical standards.
J. E.O. 12898: Federal Actions To Address Environmental Justice in
Minority Populations and Low-Income Populations
E.O. 12898 (59 FR 7629, February 16, 1994) directs Federal
agencies, to the greatest extent practicable and permitted by law, to
make EJ part of their missions by identifying and addressing
disproportionately high and adverse human health or environmental
effects of their programs, policies, and activities on minority
populations (people of color and/or Indigenous peoples) and low-income
populations.
EPA believes that the human health or environmental conditions
existing prior to this action result in or have the potential to result
in disproportionate and adverse human health or environmental effects
on people of color, low-income populations, and/or Indigenous peoples.
EPA believes that this action is likely to reduce existing
disproportionate and adverse effects on people of color, low-income
populations, and/or Indigenous peoples. A summary of the projected
effects on these populations are contained in the EJA, which is
available in the docket and summarized in Section XIII of this preamble
above.
Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations
Used in This Preamble
The following acronyms, abbreviations, and terms are used in this
preamble. These terms are provided 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 proposed
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).
BCA. Benefit Cost Analysis.
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 over time
by the organism.
BMP. Best management practice.
BA. Bottom ash. The ash, including EGU slag, that settles in a
furnace or is dislodged from furnace walls. Economizer ash is
included when it is collected with BA.
BA purge water. The water discharged from a wet BA handling
system that recycles some, but not all, of its BA transport water.
BPT. The best practicable control technology currently
available, as defined by CWA sections 301(b)(1) and 304(b)(1).
CBI. Confidential business information.
CCR. Coal combustion residuals.
CWA. Clean Water Act; The Federal Water Pollution Control Act
Amendments of 1972 (33 U.S.C. 1251 et seq.), as amended, e.g., by
the Clean Water Act of 1977 (Pub. L. 95-217) and the Water Quality
Act of 1987 (Pub. L. 100-4).
Combustion residuals. Solid wastes associated with combustion-
related power plant processes, including fly ash and BA from coal-,
petroleum coke-, or oil-fired units; FGD solids; FGMC wastes; and
other wastewater treatment solids associated with combustion
wastewater. In addition to the residuals associated with coal
combustion, this also includes residuals associated with the
combustion of other fossil fuels.
Direct discharge. (1) Any addition of any ``pollutant'' or
combination of pollutants to ``waters of the United States'' from
any ``point source'' or (2) any addition of any pollutant or
combination of pollutant to waters of the ``contiguous zone'' or the
ocean from any point source other than a vessel or other floating
craft that is being used as a means of transportation. This
definition includes additions of pollutants into waters of the
United States from surface runoff that is collected or channeled by
man; discharges through pipes, sewers, or other conveyances owned by
a state, municipality, or other person that do not lead to a
treatment works; and discharges through pipes, sewers, or other
conveyances that lead into privately owned treatment works. This
term does not include addition of pollutants by any ``indirect
discharger.''
Direct discharger. A plant that discharges treated or untreated
wastewaters into waters of the United States.
DOE. Department of Energy.
Dry BA handling system. A system that does not use water as the
transport medium to convey BA away from the EGU. Dry handling
systems include systems that collect and convey the BA without using
any water, as well as systems in which BA is quenched in a water
bath and then mechanically or pneumatically conveyed away from the
EGU. Dry BA handling systems do not include wet sluicing systems
(such as remote MDS or complete recycle systems).
Effluent limitation. Under CWA section 502(11), any restriction,
including schedules of compliance, established by a state or the
Administrator on quantities, rates, and concentrations of chemical,
physical, biological, and other constituents that are discharged
from point sources into navigable waters, the waters of the
contiguous zone, or the ocean.
EGU. Electric generating unit.
EIA. Energy Information Administration.
EJA. Environmental Justice Analysis
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 contacts the flue gas or the FGD solids,
including, but not limited to, the blowdown or purge from the FGD
scrubber system, overflow or underflow from the solids separation
process, FGD solids wash water, and the filtrate from the solids
dewatering process. Wastewater generated from cleaning the FGD
scrubber, cleaning FGD solids separation equipment, cleaning FGD
solids dewatering equipment, or that is collected in floor drains in
the FGD process area is not considered FGD wastewater.
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.
[[Page 18896]]
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 an EGU in a water-filled trough. The water bath in the
trough quenches the hot BA as it falls from the EGU and seals the
EGU gases. A drag chain operates in a continuous loop to drag BA
from the water trough up an incline, which dewaters the BA by
gravity, draining the water back to the trough as the BA moves
upward. The dewatered BA is often conveyed to a nearby collection
area, such as a small bunker outside the EGU building, from which it
is loaded onto trucks and either sold or transported to a landfill.
The MDS is considered a dry BA handling system because the ash
transport mechanism is mechanical removal by the drag chain, not the
water.
Mortality. Death rate or proportion of deaths in a population.
NAICS. North American Industry Classification System.
NPDES. National Pollutant Discharge Elimination System.
NSPSs. New Source Performance Standards.
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. These include sewers, pipes, or other
conveyances only if they convey wastewater to a POTW providing
treatment. See CWA section 212, 33 U.S.C. 1292; 40 CFR 122.2, 403.3.
PSC. Public service commission.
PUC. Public utility commission.
RCRA. The Resource Conservation and Recovery Act of 1976, 42
U.S.C. 6901 et seq.
Remote MDS. BA handling system that collects BA at the bottom of
the EGU, then uses transport water to sluice the ash to a remote MDS
that dewaters BA using a similar configuration as the MDS. The
remote MDS is considered a wet BA handling system because the ash
transport mechanism is water.
RO. Reverse osmosis.
RFA. Regulatory Flexibility Act.
SBA. Small Business Administration.
Sediment. Particulate matter lying below water.
Surface water. All waters of the United States, including
rivers, streams, lakes, reservoirs, and seas.
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 (e.g., remote MDS or complete recycle systems).
Wet FGD system. Wet FGD systems capture sulfur dioxide from the
flue gas using a sorbent that has mixed with water to form a wet
slurry, and that generates a water stream that exits the FGD
scrubber absorber.
List of Subjects in 40 CFR Part 423
Environmental protection, Electric power generation, Power
facilities, Waste treatment and disposal, Water pollution control.
Michael S. Regan,
Administrator.
For the reasons stated in the preamble, the Environmental
Protection Agency proposes to amend 40 CFR part 423 as follows:
PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY
0
1. The authority citation for part 423 is revised to read as follows:
Authority: Secs. 101; 301; 304(b), (c), (e), (g), and (i)(A) and
(B); 306; 307; 308 and 501, Clean Water Act (Federal Water Pollution
Control Act Amendments of 1972, as amended; 33 U.S.C. 1251 et seq.;
1311; 1314(b), (c), (e), (g), and (i)(A) and (B); 1316; 1317; 1318
and 1361).
0
2. Amend Sec. 423.11 by:
0
a. Revising paragraphs (x), (y), and (z);
0
b. Removing paragraph (bb);
0
c. Redesignating paragraph (cc) as paragraph (bb) and revising new
paragraph (bb);
0
d. Redesignating paragraph (dd) as paragraph (cc); and
0
e. Adding new paragraphs (dd) and (ee).
The revisions and additions read as follows:
Sec. 423.11 Specialized definitions.
* * * * *
(x) The term ``early adopter'' means the owner or operator
certifies under Sec. 423.19(e) that an electric generating unit that
generated FGD wastewater on or after October 13, 2020, has installed by
March 24, 2023 biological treatment equipment or zero valent iron
treatment equipment to meet all applicable limitations in Sec.
423.13(g) or 423.16(e) as those provisions existed on October 13, 2020,
and bottom ash handling equipment to meet all applicable limitations in
Sec. 423.13(k) or 423.16(g) as those provisions existed on October 13,
2020; that the installed equipment does meet such applicable
limitations as of March 24, 2023; and that such electric generating
unit will and does permanently cease combustion of coal no later than
December 31, 2032.
(y) The term ``surface impoundment'' means a natural topographic
depression, man-made excavation, or diked area, which is designed to
hold an accumulation of coal combustion residuals and liquids, and the
unit treats, stores, or disposes of coal combustion residuals.
(z) 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) that
provide structural support, and which is not a surface impoundment.
* * * * *
(bb) The term ``bottom ash purge water'' means any water being
discharged subject to Sec. 423.13(k)(2)(i) or 423.16(g)(3).
(cc) 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.
(dd) The term ``surface impoundment decant wastewater'' means the
layer of a closing surface impoundment's wastewater which is located
from the water surface down to the level sufficiently above any coal
combustion
[[Page 18897]]
residuals that, when drained, does not resuspend the coal combustion
residuals.
(ee) The term ``surface impoundment dewatering wastewater'' means
the layer of a closing surface impoundment's wastewater which is
located below surface impoundment decant wastewater due to its contact
with either stationary or resuspended coal combustion residuals. * * *
* *
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, bottom ash purge water, surface impoundment
decant wastewater, and surface impoundment dewatering wastewater shall
not exceed the quantity determined by multiplying the flow of the
applicable wastewater times the concentration listed in the following
table:
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), (2)(ii), (2)(iii), (3)(ii), (k)(1),
(2)(i), (2)(iii), (l);
0
b. Redesignating paragraph (n) as paragraph (p);
0
c. Redesignating paragraph (m) as paragraph (n) and adding new
paragraph (m); and
0
d. Revising paragraphs (o)(1), and (3).
The revisions and additions read as follows:
Sec. 423.13 Effluent limitations guidelines representing the degree
of effluent reduction attainable by the application of the best
available technology economically achievable (BAT).
* * * * *
(g)(1)(i) FGD wastewater. Except for those discharges to which
paragraph (g)(2) or (3) of this section applies, there shall be no
discharge of pollutants in FGD wastewater. Dischargers must meet the
discharge limitation in this paragraph by a date determined by the
permitting authority that is as soon as possible beginning [DATE 60
DAYS AFTER DATE OF PUBLICATION OF FINAL RULE], but no later than
December 31, 2029. These effluent limitations apply to the discharge of
FGD wastewater generated on and after the date determined by the
permitting authority for meeting the effluent limitations, as specified
in this paragraph.
(ii) FGD wastewater generated before the date determined by the
permitting authority as specified in paragraph (g)(1)(i) of this
section.
(A) [Reserved]
* * * * *
(2) * * *
(ii) For any electric generating unit subject to paragraph
(g)(2)(i) of this section for which the owner has submitted a
certification for the permanent cessation of coal combustion pursuant
to Sec. 423.19(f) and has not transferred between subcategories under
paragraph (o) of this section, after December 31, 2028, there shall be
no discharge of pollutants in FGD wastewater. Any permit issued
beginning [DATE 60 DAYS AFTER DATE OF PUBLICATION OF FINAL RULE] must
contain this no discharge requirement applicable as of January 1, 2029.
(iii) For FGD wastewater discharges from an early adopter electric
generating unit, on or before December 31, 2032, 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)(iii) of this
section. After December 31, 2032, there shall be no discharge of
pollutants in FGD wastewater. Any permit issued beginning [DATE 60 DAYS
AFTER DATE OF PUBLICATION OF FINAL RULE] must contain this no discharge
requirement applicable as of January 1, 2033.
Table 6 to Paragraph (g)(2)(iii)
------------------------------------------------------------------------
BAT effluent limitations
-------------------------------
Average of
daily values
Pollutant or pollutant property Maximum for for 30
any 1 day consecutive
days shall not
exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L)............. 18 8
Mercury, total (ng/L)................... 103 34
Selenium, total ([micro]g/L)............ 70 29
Nitrate/nitrite as N (mg/L)............. 4 3
------------------------------------------------------------------------
[[Page 18898]]
* * * * *
(3) * * *
(ii) FGD wastewater generated before December 31, 2028.
(A) For discharges of FGD wastewater generated before December 31,
2023, the quantity of pollutants discharged in FGD wastewater shall not
exceed the quantity determined by multiplying the flow of FGD
wastewater times the concentration listed for TSS in Sec.
423.12(b)(11).
(B) [Reserved].
* * * * *
(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 [DATE 60
DAYS AFTER DATE OF PUBLICATION OF FINAL RULE], but no later than
December 31, 2029. 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.
(ii) Bottom ash transport water generated before the date
determined by the permitting authority as specified in paragraph
(k)(1)(i) of this section.
(A) [Reserved]
(2)(i) For early adopter electric generating units:
(A) The discharge of pollutants in bottom ash transport water from
a properly installed, operated, and maintained bottom ash system on or
before December 31, 2032, is authorized under the following conditions,
and after December 31, 2032, there shall be no discharge of pollutants
in BA transport water. Any permit issued beginning [DATE 60 DAYS AFTER
DATE OF PUBLICATION OF FINAL RULE] must contain this no discharge
requirement.
(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.
(B) The total volume that may be discharged for the activities in
paragraph (k)(2)(i)(A) of this section shall be reduced or eliminated
to the extent achievable using control measures (including best
management practices) that are technologically available and
economically achievable in light of best industry practice. The total
volume of the discharge authorized in this paragraph 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.
* * * * *
(iii) For any electric generating unit subject to paragraph
(k)(2)(ii) of this section for which the owner has submitted a
certification for the permanent cessation of coal combustion pursuant
to Sec. 423.19(f), and has not transferred to another subcategory
under paragraph (o) of this section, after December 31, 2028, there
shall be no discharge of pollutants in bottom ash transport water. Any
permit issued beginning [DATE 60 DAYS AFTER DATE OF PUBLICATION OF
FINAL RULE] must contain this no discharge requirement applicable as of
January 1, 2029.
(l) Combustion residual leachate. The quantity of pollutants in
combustion residual leachate shall not exceed the quantity determined
by multiplying the flow of combustion residual leachate times the
concentration listed in the table following this paragraph (l).
Dischargers must meet the effluent limitations in this paragraph by a
date determined by the permitting authority that is as soon as possible
beginning [DATE 60 DAYS AFTER DATE OF PUBLICATION OF FINAL RULE], but
no later than December 31, 2029. These effluent limitations apply to
the discharge of combustion residual leachate generated on and after
the date determined by the permitting authority for meeting the
effluent limitations, as specified in this paragraph.
Table 9 to Paragraph (l)
------------------------------------------------------------------------
BAT effluent limitations
-------------------------------
Average of
daily values
Pollutant or pollutant property Maximum for for 30
any 1 day consecutive
days shall not
exceed
------------------------------------------------------------------------
Arsenic, total ([micro]g/L)............. 11 8
Mercury, total (ng/L)................... 788 356
------------------------------------------------------------------------
[[Page 18899]]
(m)(1) Surface impoundment decant wastewater.
(A) [Reserved].
(2) Surface impoundment dewatering wastewater.
(A) [Reserved].
(3) Bottom ash purge water.
(A) [Reserved].
(n) At the permitting authority's discretion, the quantity of
pollutant allowed to be discharged may be expressed as a concentration
limitation instead of any mass-based limitations specified in
paragraphs (b) through (m) of this section. Concentration limitations
shall be those concentrations specified in this section.
(o)(1) Transfer between subcategories and applicable limitations in
a permit. Where, in the permit, the permitting authority has included
alternative limitations subject to eligibility requirements, upon
timely notification to the permitting authority under Sec. 423.19(i),
a facility can become subject to the alternative limitations under the
following circumstances:
(i) On or before December 31, 2025, a facility may convert:
(A) From voluntary incentives program limitations under paragraph
(g)(3)(i) of this section to limitations for electric generating units
permanently ceasing coal combustion under paragraph (g)(2)(i) of this
section; or
(B) From limitations for electric generating units permanently
ceasing coal combustion under 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.
* * * * *
(3) Where a facility seeking a transfer is currently subject to
more stringent limitations than the limitations being sought, the
facility must continue to meet those more stringent limitations.
(p) In the event that wastestreams from various sources are
combined for treatment or discharge, the quantity of each pollutant or
pollutant property controlled in paragraphs (a) through (n) of this
section attributable to each controlled waste source shall not exceed
the specified limitation for that waste source.
0
5. Amend Sec. 423.16 by revising paragraphs (e)(1) and (g)(1), and
adding paragraphs (j) and (k) to read as follows:
Sec. 423.16 Pretreatment standards for existing sources (PSES).
* * * * *
(e)(1) FGD wastewater. (i) 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 permanently cease coal combustion pursuant to
Sec. 423.19(f), there shall be no discharge of pollutants in FGD
wastewater. Dischargers must meet the standards in this paragraph by
[DATE 3 YEARS AFTER DATE OF PUBLICATION OF FINAL RULE] except as
provided for in paragraph (e)(2) of this section. These standards apply
to the discharge of FGD wastewater generated on and after [DATE 3 YEARS
AFTER DATE OF PUBLICATION OF FINAL RULE].
(ii) For any electric generating unit excepted from paragraph
(e)(1)(i) of this section because the owner has submitted a
certification for the permanent cessation of coal combustion pursuant
to Sec. 423.19(f), after December 31, 2028, there shall be no
discharge of pollutants in FGD wastewater.
(2) For FGD wastewater discharges from an early adopter electric
generating unit, on or before December 31, 2032, 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 (e)(2) of this section.
After December 31, 2032, there shall be no discharge of pollutants in
FGD wastewater.
Table 3 to Paragraph (e)(2)
------------------------------------------------------------------------
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
------------------------------------------------------------------------
* * * * *
(g) Bottom ash transport water. (1) Except for those discharges to
which paragraph (g)(2) of this section applies, or when the bottom ash
transport water is used in the FGD scrubber, for any electric
generating unit with a total nameplate generating capacity of more than
50 megawatts, that is not an oil-fired unit, and that the owner has not
certified to the permitting authority that the electric generating unit
will permanently cease coal combustion pursuant to Sec. 423.19(f),
there shall be no discharge of pollutants in bottom ash transport
water. This standard applies to the discharge of bottom ash transport
water generated on and after [DATE 60 DAYS AFTER DATE OF PUBLICATION OF
FINAL RULE]. Except for those discharges to which paragraph (g)(3) of
this section applies, whenever bottom ash transport water is used in
any other plant process or is sent to a treatment system at the plant
the resulting effluent must comply with the discharge standard in this
paragraph.
(2) For any electric generating unit excepted from paragraph (g)(1)
because the owner has submitted a certification for the permanent
cessation of coal combustion pursuant to Sec. 423.19(f), after
December 31, 2028, there shall be no discharge of pollutants in bottom
ash transport water.
(3) For early adopter electric generating units:
(i) The discharge of pollutants in bottom ash transport water from
a properly installed, operated, and maintained bottom ash system on or
before December 31, 2032, is authorized under the following conditions,
and after December 31, 2032, there shall be no discharge of pollutants
in BA transport water.
(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
[[Page 18900]]
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)(3)(i)(A), (B), or (C) of this paragraph and not exempted from the
definition of transport water in Sec. 423.11(p), and when water
volumes cannot be managed by installed spares, redundancies,
maintenance tanks, and other secondary bottom ash system equipment.
(ii) The total volume that may be discharged to a POTW for the
activities in paragraph (g)(3)(i) of this section shall be reduced or
eliminated to the extent achievable as determined by the control
authority. The control authority may also include control measures
(including best management practices) that are technologically
available and economically achievable in light of best industry
practice. In no event shall the total volume of the discharge exceed a
30-day rolling average of ten percent of the primary active wetted
bottom ash system volume. The volume of daily discharges used to
calculate the 30-day rolling average shall be calculated using
measurements from flow monitors.
* * * * *
(j) Combustion residual leachate. The quantity of pollutants in
combustion residual leachate shall not exceed the quantity determined
by multiplying the flow of combustion residual leachate times the
concentration listed in the table following this paragraph (j).
Dischargers must meet the standards in this paragraph [DATE 60 DAYS
AFTER DATE OF PUBLICATION OF FINAL RULE].
Table 5 to Paragraph (j)
------------------------------------------------------------------------
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
------------------------------------------------------------------------
(k) Surface impoundment decant wastewater, surface impoundment
dewatering wastewater, and bottom ash purge water.
(1) Surface impoundment decant wastewater.
(A) [Reserved].
(2) Surface impoundment dewatering wastewater.
(A) [Reserved].
(3) Bottom ash purge water.
(A) [Reserved].
0
6. Amend Sec. 423.18 by revising paragraph (a) to read as follows.
Sec. 423.18 Permit conditions.
(a) All permits subject to this part shall include the following
permit conditions:
(1) An electric generating unit shall qualify as permanently
ceasing the combustion of coal by December 31, 2028, or December 31,
2032, if such qualification would have been demonstrated absent the
following qualifying event:
(i) An emergency order issued by the Department of Energy under
Section 202(c) of the Federal Power Act;
(ii) A reliability must run agreement issued by a Public Utility
Commission; or
(iii) 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
(2)(i) 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:
(A) An ``Emergency''; or
(B) A ``Major Disaster''; and
(3) That load balancing was due to the event that caused the
``Emergency'' or ``Major Disaster'' in paragraph (a)(2)(i) of this
section to be declared.
* * * * *
0
7. Amend Sec. 423.19 by:
0
a. Removing paragraph (d);
0
b. Redesignating paragraph (c) as paragraph (d) and adding a new
paragraph (c) and revising the newly designated paragraph (d);
0
c. Revising paragraphs, (e), (f)(1) and (4), (i), and (j); and
0
d. Adding paragraph (k).
The revisions and additions read as follows:
Sec. 423.19 Reporting and recordkeeping requirements.
* * * * *
(c) Publicly accessible internet site requirements.
(1) Except as provided in paragraph (c)(2) of this section, each
facility subject to the requirements of this part must maintain a
publicly accessible internet site (ELG website) containing the
information specified in paragraphs (d) through (l) of this section, if
applicable. This website shall be titled ``ELG Rule Compliance Data and
Information.'' The facility must ensure that all information required
to be posted is immediately available to anyone visiting the site,
without requiring any prerequisite, such as registration or a
requirement to submit a document request. All required information must
be clearly identifiable and must be able to be immediately downloaded
by anyone accessing the site in a format that enables additional
analysis (e.g., comma-separated values text file format). When the
facility initially creates, or later changes, the web address (i.e.,
Uniform Resource Locator (URL)) at any point, they must notify EPA via
the ``contact us'' form on EPA's Effluent Guidelines website and the
permitting authority or control authority within 14 days of creating
the website or making the change. The facility's ELG website must also
have a ``contact us'' form or a specific email address posted on the
website for the public to use to submit questions and issues relating
to the availability of information on the website.
[[Page 18901]]
(2) Combined websites.
(i) When an owner or operator subject to this section already
maintains a ``CCR Rule Compliance Data and Information'' website
pursuant to 40 CFR 257.107, the postings required under this section
may be made to the existing ``CCR Rule Compliance Data and
Information'' website and shall be delineated under a separate heading
that shall state ``ELG Rule Compliance Data and Information.'' When
electing to use an existing website pursuant to this paragraph, the
facility shall notify EPA via the ``contact us'' form on EPA's Effluent
Guidelines website and the permitting authority or control authority no
later than [DATE 60 DAYS AFTER DATE OF PUBLICATION OF FINAL RULE].
(ii) When the same owner or operator is subject to the provisions
of this part for multiple facilities, the owner or operator may comply
with the requirements of this section by using the same internet site
for multiple facilities provided the ELG website clearly delineates
information by the name of each facility.
(3) Unless otherwise required in this section, the information
required to be posted to the ELG website must be made available to the
public for at least 10 years following the date on which the
information was first posted to the ELG website, or the length of the
permit plus five years, whichever is longer. All required information
must be clearly identifiable and must be able to be immediately
downloaded by anyone accessing the site in a format that enables
additional analysis (e.g., comma-separated values text file format).
(4) Unless otherwise required in this section, the information must
be posted to the ELG website:
(i) Within 30 days of submitting the information to the permitting
authority or control authority; or
(ii) Where information was submitted to the permitting authority or
control authority prior to [DATE 60 DAYS AFTER DATE OF PUBLICATION OF
FINAL RULE], by [DATE 60 DAYS AFTER DATE OF PUBLICATION OF FINAL RULE].
(d) Requirements for early adopter electric generating units
discharging bottom ash transport water pursuant to Sec.
423.13(k)(2)(i) or 423.16(g)(3).
(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)(3), an initial certification shall be submitted to the
permitting authority by [DATE 60 DAYS AFTER DATE OF PUBLICATION OF
FINAL RULE].
(2) Signature and certification. The certification statement must
be signed and certified by a professional engineer.
(3) Contents. An initial certification shall include the following:
(i) A statement that the professional engineer is a licensed
professional engineer.
(ii) A statement that the professional engineer is familiar with
the regulation requirements.
(iii) A statement that the professional engineer is familiar with
the facility.
(iv) The primary active wetted bottom ash system volume in Sec.
423.11(aa).
(v) Material assumptions, information, and calculations used by the
certifying professional engineer to determine the primary active wetted
bottom ash system volume.
(vi) A list of all potential discharges under Sec.
423.13(k)(2)(i)(A)(1) through (A)(4) or 423.16(g)(3)(i) through (iv),
the expected volume of each discharge, and the expected frequency of
each discharge.
(vii) Material assumptions, information, and calculations used by
the certifying professional engineer to determine the expected volume
and frequency of each discharge including a narrative discussion of why
such water cannot be managed within the system and must be discharged.
(viii) A list of all wastewater treatment systems at the facility
currently, or otherwise required by a date certain under this section.
(ix) A narrative discussion of each treatment system including the
system type, design capacity, and current or expected operation.
(e) Requirements for early adopter electric generating units.
(1) Notice of Planned Participation. For sources seeking to qualify
as early adopter electric generating units that will achieve permanent
cessation of coal combustion by December 31, 2032, under this part, a
Notice of Planned Participation shall be submitted to the permitting
authority or control authority no later than [DATE 1 YEAR AFTER DATE OF
PUBLICATION OF FINAL RULE].
(2) Contents. A Notice of Planned Participation shall identify the
early adopter electric generating unit intended to achieve the
permanent cessation of coal combustion. A Notice of Planned
Participation shall include:
(i) A statement that the electric generating unit discharged FGD
wastewater on or after October 13, 2020;
(ii) A statement that the facility was in compliance with the FGD
wastewater limitations of Sec. 423.13(g)(2)(iii) or 423.16(e)(2)(i) as
those provisions existed on October 13, 2020, and where applicable the
bottom ash transport water limitations of Sec. 423.13(k)(2)(i) or
423.16(g)(2)(i) as those provisions existed on October 13, 2020, by
March 24, 2023 with the following additional details:
(A) A diagram of the treatment chain for FGD wastewater, including
the biological treatment or zero valent iron component, with a complete
narrative discussion explaining the components of the treatment chain
including the flows entering, leaving, or passing through each
component, a description of any solids generated by each component, and
measurements (or where necessary, estimates) of both the flows and
solids (e.g., gallons per minute, tons per day, etc.);
(B) A diagram of the bottom ash handling system with a complete
narrative discussion explaining the treatment chain including the flows
entering, leaving, or passing through each component, a description of
any solids generated by each component, and measurements (or where
necessary, estimates) of both the flows and solids (e.g., gallons per
minute, tons per day, etc.);
(C) The dates the treatment chains in paragraph (e)(2)(ii) of this
section were commissioned, or where separate components were
commissioned on different dates, the commission dates of each;
(D) All effluent monitoring data from the relevant outfall(s) or,
where an internal monitoring location(s) was used, from the internal
monitoring location(s); and
(E) Where applicable, the data and calculations demonstrating
compliance of the diluted FGD wastewater where monitoring data from the
relevant outfall captures a diluted wastestream shall include a
narrative discussion of all data, assumptions, and calculations such
that an independent party could duplicate the work.
[[Page 18902]]
(iii) 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, or other
documentation supporting that the electric generating unit will
permanently cease the combustion of coal by December 31, 2032. 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 (e)(1) of this section, a
progress report shall be filed with the permitting authority, or
control authority in the case of an indirect discharger.
(4) Contents. An Annual Progress Report shall detail the completion
of any interim milestones listed in the Notice of Planned Participation
since the previous progress report, provide a narrative discussion of
any completed, missed, or delayed milestones, and provide updated
milestones. An annual progress report shall also include one of the
following:
(i) A copy of the official suspension filing (or equivalent filing)
made to the facility's reliability authority detailing the conversion
to a fuel source other than coal;
(ii) A copy of the official retirement filing (or equivalent
filing) made to the facility's reliability authority which must include
a waiver of recission rights; or
(iii) An initial certification, or recertification for subsequent
annual progress reports, containing either a statement that the
facility will make the filing required in paragraph (e)(4)(i) of this
section or a statement that the facility will make the filing required
in paragraph (e)(4)(ii) of this section. The certification or
recertification must include the estimated date that such a filing will
be made.
(iv) A facility shall not include a certification or
recertification under paragraph (e)(4)(iii) of this section in the
final annual progress report submitted prior to permanent cessation of
coal combustion. Rather, this final annual progress report must include
the filing under paragraph (e)(4)(i) or (ii) of this section.
* * * * *
(f) * * *
(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 [DATE 60 DAYS AFTER DATE OF PUBLICATION OF FINAL RULE].
* * * * *
(4) Contents. An Annual Progress Report shall detail the completion
of any interim milestones listed in the Notice of Planned Participation
since the previous progress report, provide a narrative discussion of
any completed, missed, or delayed milestones, and provide updated
milestones. An annual progress report shall also include one of the
following:
(i) A copy of the official suspension filing (or equivalent filing)
made to the facility's reliability authority detailing the conversion
to a fuel source other than coal;
(ii) A copy of the official retirement filing (or equivalent
filing) made to the facility's reliability authority which must include
a waiver of recission rights; or
(iii) An initial certification, or recertification for subsequent
annual progress reports, containing either a statement that the
facility will make the filing required in paragraph (f)(4)(i) of this
section or a statement that the facility will make the filing required
in paragraph (f)(4)(ii) of this section. The certification or
recertification must include the estimated date that such a filing will
be made.
(iv) A facility shall not include a certification or
recertification under paragraph (f)(4)(iii) of this section in the
final annual progress report submitted prior to permanent cessation of
coal combustion. Rather, this final annual progress report must include
the filing under paragraph (f)(4)(i) or (ii) of this section.
* * * * *
(i) Requirements for facilities seeking to transfer between
subcategories and 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 (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 (e)(2), (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, or December 31, 2032, for early
adopter electric generating units, 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.
(k) Requirements for facilities with coal combustion residual
landfills or surface impoundments
(1) Annual Combustion Residual Leachate Monitoring Report. In
addition to reporting pursuant to 40 CFR part 127, each facility
treating combustion residual leachate in groundwater to comply with
Sec. 423.13(l) or 423.16(j) shall file an annual combustion residual
leachate monitoring report each calendar year to the permitting
authority or control authority for indirect discharges of the treated
CRL.
[[Page 18903]]
(2) Contents. The annual combustion residual leachate monitoring
report shall provide the following monitoring data for each pollutant
listed in the table following this section. For paragraphs (k)(2)(ii)
and (iii) of this section the report shall also describe the location
of monitoring wells, screening depth, and frequency of sampling. The
report shall include summary statistics including monthly minimum,
maximum, and average concentrations for each pollutant. The report
shall be supported by an appendix of all samples.
(i) Effluent monitoring data reported pursuant to 40 CFR part 127.
(ii) Groundwater monitoring data as the combustion residual
leachate leaves each of the landfills and surface impoundments
discharging through groundwater.
(iii) Groundwater monitoring at the point the combustion residual
leachate enters each surface waterbody.
(iv) Summary statistics for the data described in paragraphs
(k)(2)(i) through (iii) of this section including the monthly average
and daily maximum of each pollutant and a comparison to any limitation
in Sec. 423.13(l) or 423.16(j).
Table 1 to Paragraph (k)(2)(iv)
------------------------------------------------------------------------
------------------------------------------------------------------------
BAT/PSES Treated Pollutants in Combustion Residual Leachate
------------------------------------------------------------------------
Antimony Magnesium
Arsenic Manganese
Barium Mercury
Beryllium Molybdenum
Cadmium Nickel
Chromium Thallium
Cobalt Titanium
Copper Vanadium
Lead Zinc
------------------------------------------------------------------------
[FR Doc. 2023-04984 Filed 3-28-23; 8:45 am]
BILLING CODE 6560-50-P