vvEPA—
United States
Environmental Protection
Agency
Technical Development Document for
Proposed Supplemental Effluent Limitations
Guidelines and Standards for the Steam
Electric Power Generating Point Source
Category
February 2023
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U.S. Environmental Protection Agency
Office of Water (4303T)
1200 Pennsylvania Avenue, NW
Washington, DC 20460
EPA-821-R-23-005
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Contents
1. Background 1
1.1 Legal Authority 1
1.2 Regulatory History 2
1.3 Other Key Regulatory Actions Affecting Steam Electric Power Generating 2
2. Data Collection Activities 5
2.1 Summary of Data Collection for the 2015 and 2020 Rulemakings 5
2.2 Site Visits and Industry-Submitted Data 6
2.2.1 CWA 308 Request 6
2.2.2 Voluntary Industry Sampling Requests 6
2.3 Technology Vendor Data 7
2.3.1 FGD Wastewater, CRL, and Legacy Wastewater Treatment 7
2.3.2 BA Handling 7
2.4 Other Data Sources 8
2.4.1 EPRI 8
2.4.2 Department of Energy 9
2.4.3 Office of Land and Emergency Management 9
2.4.4 Power Company CCR Websites 9
2.4.5 Literature and Internet Searches 10
2.4.6 Intergovernmental and Tribal Listening Sessions 10
2.4.7 Communities 10
2.4.8 Notices of Planned Participation (NOPPs) 11
2.5 Protection of Confidential Business Information 11
3. Current State of the Steam Electric Power Generating Industry 12
3.1 Changes in the Steam Electric Power Generating Industry Since the 2020 Rule 12
3.2 Current Information on Evaluated Wastestreams 14
3.2.1 FGD Wastewater 14
3.2.2 BA Transport Water 16
3.2.3 CRL 18
3.2.4 Legacy Wastewater 19
3.3 Other Regulations on the Steam Electric Power Generating Industry 20
4. Treatment Technologies and Wastewater Management Practices 22
4.1 FGD Wastewater Treatment Technologies 22
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4.1.1 LRTR Biological Treatment 22
4.1.2 Membrane Filtration 23
4.1.3 Spray Evaporation 25
4.1.4 Other Thermal Treatment Options 26
4.1.5 Encapsulation 26
4.2 BA Handling Systems and Transport Water Management and Treatment Technologies 27
4.2.1 Mechanical Drag System 27
4.2.2 Remote Mechanical Drag System 27
4.2.3 CSC 28
4.2.4 Mobile Mechanical Drag System 29
4.3 CRL Treatment Technologies and Management Practices 29
4.3.1 Chemical Precipitation 29
4.3.2 Biological Treatment 30
4.3.3 Membrane Filtration 30
4.3.4 Thermal Treatment Options 30
4.3.5 Management Strategies and Reuse 31
4.4 Legacy Wastewater Treatment Technologies and Management Practices 31
4.4.1 Legacy Wastewater Discharged Directly to Surface Waterbodies or Through
Intermediary Structures 31
4.4.2 Legacy Wastewater Discharged from Surface Impoundments Undergoing Closure 33
5. Engineering Costs 34
5.1 FGD Wastewater 35
5.1.1 FGD Cost Calculation Inputs 36
5.1.2 Cost Methodology for LRTR 37
5.1.3 Cost Methodology for Membrane Filtration 38
5.2 BA Transport Water 39
5.2.1 BA Transport Water Cost Calculation Inputs 39
5.2.2 Cost Methodology for HRR 41
5.2.3 Cost Methodology for ZLD 44
5.3 Combustion Residual Leachate 48
5.3.1 CRL Cost Calculation Inputs 48
5.3.2 Cost Methodology for CP 49
5.4 Summary of National Engineering Costs for Regulatory Options 50
6. Pollutant Loadings and Removals 53
6.1 General Methodology 53
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6.2 FGD Wastewater 56
6.2.1 FGD Wastewater Flows 57
6.2.2 Baseline and Post-compliance Loadings 57
6.3 BA Transport Water 58
6.3.1 BA Transport Water Flows 60
6.3.2 Baseline and Post-compliance Loadings 60
6.4 CRL 60
6.4.1 CRL Flows 62
6.4.2 Baseline and Post-compliance Loadings 62
6.5 Summary of Baseline and Regulatory Option Loadings and Removals 62
7. Non-Water-Quality Environmental Impacts 65
7.1 Energy Requirements 65
7.2 Air Emissions Pollution 66
7.3 Solid Waste Generation 68
7.4 Change in Water Use 69
8. TDD References 70
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List of Figures
Figure 1. Change in Population of Coal-Fired EGUs and Plants 14
Figure 2. Wet FGD Systems at Steam Electric Power Plants 15
Figure 3. Plant-Level BA Handling Systems in the Steam Electric Power Generating Industry 17
List of Tables
Table 1. EPRI Reports and Studies Reviewed by EPA for the 2023 Proposal 8
Table 2. Industry Profile Updates Since February 2020 by Type of Change in Operation 13
Table 3. FGD Wastewater Discharges for the Steam Electric Power Plants 16
Table 4. BA Handling Systems for Coal-Fired EGUs 17
Table 5. BA Transport Water Discharges for the Steam Electric Power Plants 18
Table 6. CRL Wastewater Discharges for the Steam Electric Power Plants 18
Table 7. Estimate of Total Volume of Wastewater in Surface Impoundments Identified as "In Closure" ... 19
Table 8. 2023 Rule Technology Bases 37
Table 9. 2023 Rule Technology Bases 41
Table 10. Estimated Cost of Implementation for FGD Wastewater by Regulatory Option (in Millions of
Pre-tax 2021 Dollars) 51
Table 11. Estimated Cost of Implementation for BA Transport Water by Regulatory Option (in
Millions of Pre-tax 2021 Dollars) 51
Table 12. Estimated Cost of Implementation for Combustion Residual Leachate by Regulatory Option
(in Millions of Pre-tax 2021 Dollars) 51
Table 13. Estimated Cost of Implementation by Regulatory Option (in Millions of Pre-tax 2021
Dollars) 52
Table 14. POTW Removals 55
Table 15. Average CP+LRTR Effluent Concentrations 56
Table 16. Average BA Transport Water Effluent Concentrations 59
Table 17. Average CRL Pollutant Concentrations 61
Table 18. Estimated Industry-Level FGD Wastewater Pollutant Loadings and Removals by Regulatory
Option 63
Table 19. Estimated Industry-Level BA Transport Water Pollutant Loadings and Removals by
Regulatory Option 63
Table 20. Estimated Industry-level CRL Pollutant Loadings and Removals by Regulatory Option 63
Table 21. Estimated Industry-level Pollutant Loadings and Removals by Regulatory Option 64
Table 22. Net Change in Energy Use for the Regulatory Options Compared to Baseline 66
Table 23. MOVES3.0.3 Emission Rates for Model Year 2010 Diesel-Fueled, Long-Haul Trucks
Operating in 2021 67
Table 24. Net Change in Industry-Level Air Emissions Associated with Power Requirements and
Transportation by Regulatory Option 68
Table 25. Estimated Net Change in Industry-Level Air Emissions associated with Changes in Power
Requirements, Transportation, and Electricity Generation for Proposed Option 3 Compared to
Baseline 68
Table 26. Net Change in Industry-Level Solid Waste by Regulatory Option 69
Table 27. Net Change in Industry-Level Process Water Use by Regulatory Option 69
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List of Abbreviations
ACE Affordable Clean Energy
BA bottom ash
BAT Best Available Technology Economically Achievable
BMP best management practices
BOD biochemical oxygen demand
CAA Clean Air Act
CBI confidential business
CH4 methane
C02 carbon dioxide
CPP Clean Power Plan
CRL combustion residual leachate
CSAPR Cross-State Air Pollution Rule
CSC compact submerged conveyor
CUR capacity utilization rates
CWA clean Water Act
CWT centralized waste treatment
DOE Department of Energy
EDR electrodialysis reversal
EGU electric generating unit
EIA Energy Information Administration
EJA environmental justice analysis
ELG effluent limitations guidelines and standards
EPA Environmental Protection Agency
EPRI Electric Power Research Institute
FBR fluidized bed reactor
FGD flue gas desulfurization
FGMC flue gas mercury control
FO forward osmosis
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GHG
Greenhouse gas
GPM
gallons per minute
HAP
hazardous air pollutant
HRR
high recycle rate
HRT
hydraulic residence times
HRTR
high residence time reduction
HVAC
heating, ventilation, or air conditioning
ICR
information collection request
IPM
Integrated Planning Model
LRTR
low residence time reduction
LUEGU
low utilization electric generating units
MATS
Mercury and Air Toxics Standards
MDS
mechanical drag systems
MGD
million gallons per day
MGY
million gallons per year
MW
megawatts
n2o
nitrous oxide
NAAQS
national ambient air quality standards
NOPP
notices of planned participation
NOx
oxides of nitrogen
NPDES
National Pollutant Discharge Elimination System
NSPS
New Source Performance Standards
NWQEI
non-water-quality environmental impacts
OLEM
Office of Land and Emergency Management
PM
particulate matter
POTW
publicly owned treatment works
PSES
Pretreatment Standards for Existing Sources
OA
quality assurance
QC
quality control
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RCRA
Resource Conservation and Recovery Act
RO
reverse osmosis
SCR
selective catalytic reduction
S02
sulfur dioxide
TCLP
toxicity characteristic leaching procedure
TDD
Technical Development Document
TDS
total dissolved solids
TMT
trimercapto-s-triazine
TPY
tons per year
TSS
total suspended solids
VIP
Voluntary Incentive Program
ZLD
zero liquid discharge
ZVI
Zero valent iron
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1. Background
This Technical Development Document describes background information for the Agency's proposed
supplemental rulemaking for the steam electric power generating point source category. This proposed
rulemaking is based on a review of the effluent limitations guidelines and standards (ELGs) promulgated in 2020
(referred to as the 2020 rule) under Executive Order 13990.
EPA is proposing revisions to the 2020 rule based on a review of publicly available data and additional data
collected from the steam electric power generating industry. The proposed revisions cover Best Available
Technology Economically Achievable (BAT) and Pretreatment Standards for Existing Sources (PSES) requirements
for flue gas desulfurization (FGD) wastewater, bottom ash (BA) transport water, combustion residual leachate
(CRL), and legacy wastewater from steam electric power plants. This document presents information for the
proposed revisions including details on EPA's data collection, industry profile updates (e.g., retirements and
treatment technology updates), methodologies for estimating costs, pollutant removals, and non-water-quality
impacts.
In addition to this report, other supporting reports include:
• Supplemental Environmental Assessment for Proposed Supplemental Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category (EA), Document No. EPA-821-R-23-
004. This report summarizes the potential environmental and human health impacts that are 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. EPA-821-R-23-003. This
report summarizes estimated societal benefits and costs that are 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. EPA-821-R-23-002. 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 Point Source Category (EJA), Document No. EPA-821-R-23-001. 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 summary of input from potentially
impacted communities that EPA met with prior to the proposal.
The ELGs for the steam electric power generating category are based on data generated or obtained in
accordance with EPA's Quality Policy and Information Quality Guidelines. EPA's quality assurance (QA) and quality
control (QC) activities for this rulemaking include developing, approving, and implementing quality assurance
project plans for the use of environmental data generated or collected from sampling and analyses, existing
databases, and literature searches, and for developing any models that use environmental data.
1.1 Legal Authority
EPA is revising the ELGs for the steam electric power generating point source category (40 CFR 423) under the
authority of sections 301, 304, 306, 307, 308, 402, and 501 of the Clean Water Act, 33 U.S.C. 1311, 1314, 1316,
1317, 1318, 1342, and 1361.
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," per 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
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
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Section 1 —Background
national technology-based ELGs for discharges from categories of point sources. Refer to the CWA for more
information on these limitations, which could affect direct dischargers and indirect dischargers. These proposed
revisions relate primarily to the standard for BAT and to a minor extent PSES.
1.2 Regulatory History
EPA first issued a steam electric ELG in 1974, with subsequent revisions in 1977 and 1982. These limitations
included requirements on once-through cooling water, cooling tower blowdown, fly ash transport water, BA
transport water, metal cleaning waste, coal pile runoff, and low-volume waste sources. Requirements do not
apply to discharges from generating units that primarily use nonfossil or nonnuclear fuel sources (e.g., wood
waste, municipal solid waste).
In 2015, EPA finalized new requirements for multiple wastestreams generated by new and existing steam electric
power plants: BA transport water, CRL, FGD wastewater, flue gas mercury control wastewater, fly ash transport
water, and gasification wastewater. Seven petitions for review of the 2015 rule were filed in various circuit courts
by industry members, environmental groups, and drinking water utilities. In April 2017, in response to petitions
from Utility Water Act Group and the Small Business Administration, EPA postponed compliance dates for the
2015 rule.
On August 11, 2017, the EPA Administrator announced a decision to review and revise BAT requirements for FGD
wastewater and BA transport water. The Fifth Circuit Court of Appeals granted EPA's request to sever and hold in
abeyance aspects of litigation related to those two wastestreams. The Fifth Circuit Court of Appeals continued to
review litigation related to legacy wastewater and leachate. In a decision on April 12, 2019, the court vacated
limitations on both legacy wastewater and leachate as arbitrary and capricious under the Administrative
Procedure Act and unlawful under the CWA.
On August 31, 2020, EPA finalized a revision to the regulations for the steam electric power generating category
that established revised effluent limitations for FGD wastewater and BA transport water. This 2020 rule revised
the technology basis for FGD wastewater and BA transport water, established a new compliance date, revised the
FGD Voluntary Incentive Program (VIP), and established additional subcategories. See the Supplemental Technical
Development Document for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (EPA-821-R-20-001) for details related to the 2020 rule.
1.3 Other Key Regulatory Actions Affecting Steam Electric Power Generating
Multiple EPA offices are taking actions to reduce emissions, discharges, and other environmental impacts
associated with steam electric power plants. EPA made every effort to appropriately account for other rules
affecting the industry in its analysis for the proposed rule. This section provides a brief overview of recent
changes to the regulatory requirements for steam electric power plants.
• Coal Combustion Residuals Disposal (CCR) 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
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Section 1 —Background
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 electric generating
unit (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 Section 3.3. 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.
• 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 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 the
preamble.
o The Revised Cross State Air Pollution Rule Update and the Proposed Good Neighbor Plan for the 2015
Ozone National Ambient Air Quality Standards. 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) 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 (Apr.
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-
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Section 1 —Background
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.1
o Clean Air Act Section 111 Rule. On October 23, 2015, EPA finalized New Source Performance Standards
(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 C02 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.
o 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.
o 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).2 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.
1 See www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqS;,
2 See www.epa.gov/newsreleases/epa-reexamine-health-standards-harmful-soot-previous-administration-left-unchanged.
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2. Data Collection Activities
EPA collected and evaluated information from various sources while developing the 2015 and 2020 rules,
as described in Section 3 of the 2015 Technical Development Document (2015 TDD) and Section 2 of the
2020 Supplemental TDD, respectively. EPA collected additional supplemental data for the 2023 proposal
to update the industry profile; identify the power plants affected by the rule; reevaluate industry
subcategorization; update plant-specific operations and wastewater characteristics; determine the
technology options; and estimate the compliance costs, pollutant loadings and removals, and non-water-
quality environmental impacts of the technology options. This section briefly summarizes past data
collection activities for the 2015 and 2020 rules (Section 2.1) and describes new data collection activities
for flue gas desulfurization (FGD) wastewater, bottom ash (BA) transport water, legacy wastewater, and
combustion residual leachate (CRL) for the 2023 proposal (Sections 2.2 through 2.4).
2.1 Summary of Data Collection for the 2015 and 2020 Rulemakings
For the 2015 and 2020 rules, EPA collected and obtained information on the steam electric power
generating industry from multiple sources including a detailed study of the industry, an information
collection request (ICR), site visits, field sampling, Clean Water Act (CWA) section 308 industry requests,
and voluntary requests as detailed below.
• Detailed study. EPA studied the steam electric power generating industry between 2005 and 2009.
Data collection included multiple site visits and six wastewater sampling episodes at steam electric
power plants, a screener questionnaire sent to 9 companies (operating 30 coal-fired power plants),
publicly available data sources, and outreach with EPA program offices, other governmental groups
and industry stakeholders. The detailed study focused on wastewater from coal ash handling
operations and from FGD air pollution control systems.
• 2009 Steam Electric Survey. EPA administered a survey to approximately 700 power plants to collect
technical information related to wastewater generation and treatment, as well as economic
information such as costs of wastewater treatment technologies and financial characteristics of
potentially affected companies. The Agency used the responses to evaluate pollution control options
for revising the effluent limitations guidelines and standards (ELGs) for the steam electric category, in
addition to costs, loadings, and other rulemaking analyses.
• Site visits. EPA conducted 73 site visits at steam electric power plants in 18 states between December
2006 and November 2014 to gather information about each plant's operation, pollution prevention
and wastewater treatment options, and whether the plant was appropriate to include in the field
sampling program. After promulgating the 2015 rule, between October and December 2017, EPA
conducted another seven site visits to power plants in five states to update information on methods
for managing FGD wastewater and BA transport water. EPA used data from site visits to update
industry profile data; learn more about pollution control and wastewater treatment options
evaluated as part of the rulemakings; and inform costs, loadings, and other rulemaking analyses.
• Field sampling program. For the 2015 rule, EPA conducted 4-day sampling episodes at seven U.S.
plants to obtain wastewater characterization data and wastewater treatment technology
performance data. EPA used these data in combination with other industry-supplied data to evaluate
wastewater discharges from steam electric power plants and to evaluate technology options for
managing these wastewaters. The sampling program primarily focused on wastewaters from wet FGD
systems. EPA also conducted a 3-day sampling episode at Enel's Federico II Power Plant (Brindisi),
located in Brindisi, Italy, to characterize an FGD wastewater treatment system consisting of chemical
precipitation followed by evaporation.
• CWA 308 monitoring program. For the 2015 rule, EPA required four plants to collect four consecutive
days of samples at two to four sampling locations chosen to characterize coal-gasification
wastewaters, carbon capture wastewaters, and the treatment of FGD wastewater and coal-
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Section 2—Data Collection Activities
gasification wastewater by vapor-compression evaporation. These data were used to supplement the
sampling data collected during the field sampling program.
• Voluntary requests. Following the 2015 rule, EPA invited seven steam electric power plants to
participate in a voluntary BA transport water sampling program. EPA requested information from
steam electric power plants operating impoundments that predominantly contain BA transport
water. Plants were asked to provide sampling data for ash impoundment effluent and untreated BA
transport water (i.e., ash impoundment influent). Two plants chose to participate in the voluntary BA
sampling program.
• Other data sources. EPA used Electric Power Research Institute (EPRI) reports, data from the U.S.
Department of Energy's (DOE's) Energy Information Administration (EIA), information from literature
and internet searches, and information from environmental groups to supplement the industry
profile; learn more about pollution control and wastewater treatment options evaluated as part of
the rulemakings; and inform costs, loadings, and other rulemaking analyses.
2.2 Site Visits and Industry-Submitted Data
In support of the latest rule revision, EPA participated in a virtual site visit with representatives from Duke
Energy in 2021. The visit focused on Duke Energy'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 also gathered information on steam electric power generating processes, wastewater treatment
technologies, and wastewater characteristics directly from the industry through a CWA 308 request, two
voluntary requests, and other industry data provided during the 2023 proposal. EPA used this information
to learn more about the performance of FGD, CRL, and legacy wastewater treatment systems and obtain
information useful for estimating the cost of installing candidate treatment technologies. EPA also used
this information to learn more about BA system performance, characterization and quantification of the
overflow and purge from remote mechanical drag systems (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.
2.2.1 CWA 308 Request
In January 2022, EPA requested the following information for coal-fired power plants from three steam
electric power companies:
• FGD wastewater installations: thermal technology; membrane filtration technology; paste,
solidification, or encapsulation of FGD wastewater brine; electrodialysis; and electrocoagulation.
• Overflow from an MDS, compact submerged conveyor (CSC), or remote MDS installation including
purge rate and management from remote MDS, 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.
After meeting with these three companies, EPA sent four other power companies a request inviting them
to provide the same data described above.
2.2.2 Voluntary Industry Sampling Requests
In December 2021, EPA invited eight steam electric power companies to participate in a voluntary
request program. The specific voluntary requests are outlined below.
• Existing CRL data consistent with EPA's request.
6
-------
Section 2—Data Collection Activities
• Untreated and treated samples of CRL on the sampling schedule laid out in EPA's request.
• Grab samples of landfill solids and leachate samples analyzed using EPA Methods 1313 and 1316
(leaching evaluations).
2.3 Technology Vendor Data
EPA gathered data from technology vendors through presentations, conferences, site visits, meetings,
and email and phone contacts regarding the FGD wastewater, BA handling, CRL, and legacy wastewater
technologies used in the industry. EPA used the data to inform the development of the technology costs
and pollutant removal estimates for FGD wastewater, BA transport water, CRL, and legacy wastewater.
For the development of the 2015 and 2020 rules, EPA participated in multiple technical conferences and
reviewed the papers presented for information relevant to the proposed rule.
2.3.1 FGD Wastewater, CRL, and Legacy Wastewater Treatment
EPA contacted companies that manufacture, distribute, or install various components of biological
wastewater treatment, membrane filtration, or thermal evaporation systems for FGD wastewater, CRL,
and legacy wastewater treatment. EPA also contacted consulting firms that design and implement
treatment technologies associated with these wastestreams. The vendors and consulting firms provided
the following types of information for EPA's analyses:
• Operating details.
• Performance data where available.
• Equipment used in the system.
• Estimated capital and operation and maintenance (O&M) costs.
• System energy requirements.
• Timeline to bid, procure, and install.
• Changes in the industry since 2020 including retirements or fuel conversions, new FGD installations,
and planned future installations.
2.3.2 BA Handling
EPA contacted vendors as well as consulting firms that design and implement BA handling systems. The
vendors and consulting firms provided the following types of information for EPA's analyses:
• Systems available for reducing or eliminating ash transport water.
• Equipment, modifications, and demolition required to convert wet sluicing systems to dry ash
handling or high recycle rate (HRR) systems.
• Equipment that can be reused as part of the conversion from wet to dry handling or in a HRR system.
• Outage time estimated for installing the different types of ash handling systems.
• Maintenance estimated for each type of system.
• Estimated capital and O&M costs.
• Changes in the industry since 2020 including retirements or fuel conversions, new BA installations,
and planned future installations.
• Purge from complete recycle systems, purge from under-boiler mechanical drag systems, and purge
wastewater characteristics.
7
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Section 2—Data Collection Activities
2.4 Other Data Sources
EPA gathered information on steam electric power generating processes, wastewater treatment,
wastewater characteristics, and regulations from sources including EPRI, Department of Energy (DOE),
literature and internet searches, notices of planned participation (NOPPs), environmental groups,
residents of affected communities, state and local governments, tribes, and reporting by utilities via the
"CCR Compliance Data and Information" websites required by the Coal Combustion Residuals (CCR) rule.
Sections 2.4.1 through 2.4.6 summarize the data collected from these additional sources.
2.4.1 EPRI
EPRI conducts studies funded by the steam electric power generating industry to evaluate and
demonstrate technologies that can potentially remove pollutants of concern from wastestreams or
eliminate wastestreams using zero discharge technologies. EPA reviewed reports—listed in Table 1—that
EPRI voluntarily provided, or that were provided in CWA 308 responses. These reports contained
information relevant to characteristics of FGD wastewater, CRL and legacy treatment pilot studies, BA
transport water characterization and BA handling practices.
Table 1. EPRI Reports and Studies Reviewed by EPA for the 2023 Proposal
Title of Report/Study
Date
Published
Document Control
Number
Effects of Alkaline Sorbents and Mercury Controls on Fly Ash and FGD
Gypsum Characteristics and Implications for Disposal and Use
2014
SE10395
Coal Combustion Residuals Leachate Management: Characterization
of Leachate Quantity and Evolution of Leachate Minimization and
Management Methods
2015
SE10386
Coal Combustion Residuals Leachate Management: Characterization
of Leachate Quality
2016
SE10387
Evaporation Treatment of Flue Gas Desulfurization Wastewater
2017
SE06970
Landfill Leachate Characterization, Management and Treatment
Options
2017
SE06959
Brine Encapsulation Laboratory Study
2018
SE10296
Wastewater Encapsulation Testing References: Encapsulating Co-
Management of Liquid Waste with Combustion Byproducts at Bench
and Field Scale
2018
SE10295
MercuryMethylmercury, and Selenium Interactions in Freshwater
Fish
2018
SE10388
Performance Evaluation of the Vacom Thermal Vapor Recompression
Technology for FGD Wastewater Treatment
2019
SE10389
Membrane Treatment Guidelines
2019
SE10297
Considerations for Treating Flue Gas Desulfurization Wastewater
Using Membrane and Paste Encapsulation Technologies
2019
SE10396
Studies on the Encapsulation of Brine Generated from a Process
Using Selective Electrodialysis Reversal
SE10397
Landfill Leachate Treatment Study: Evaluations of Membrane,
Evaporation, and Encapsulation Technologies
2020
SE10385
The Impacts of Fligh Salinity Wastewater Chemistry and Fly Ash
Reactivity on Encapsulation
2020
SE10298
Thermal Water/Wastewater Treatment System Chemistry Guidelines
2020
SE10390
Real-Time Online Membrane Monitor Demonstration
2020
SE010300
Understanding Chemical Reactions and Mineral Additives for
Wastewater Encapsulation
2020
SE10299
8
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Section 2—Data Collection Activities
Table 1. EPRI Reports and Studies Reviewed by EPA for the 2023 Proposal
Title of Report/Study
Date
Published
Document Control
Number
Conference Proceedings of the 2020 Virtual Selenium Summit
2020
SE10391
FGD Wastewater Treatment Testing Using a Saltworks Flex EDR
Selective Electrodialysis Reversal System Technology
2020
SE10398
Quantifying Leachate Volumes at Four Coal Combustion Product
Landfills in the Southeastern United States
2021
SE10392
Review of Coal Combustion Product Leaching
2021
SE10393
Review of Established and Emerging Boron Treatment Technologies
for Water at Coal Combustion Product Sites
2021
SE10399
Water Flow in Coal Combustion Products and Drainage of Free
Water
2021
SE10394
Coal Combustion Product Landfill Terminology and Water
Management Fundamentals
2021
SE10400
2.4.2 Department of Energy
EPA compiled information on steam electric power plants from ElA's Form EIA-860, Annual Electric
Generator Report, and Form EIA-923, Power Plant Operations Report. The data collected in Form EIA-860
concern the design and operation of generators at plants, while data collected in Form EIA-923 concern
the design and operation of the entire plant. EPA has been using relevant data from EIA-923 and EIA-860
from 2009 to 2020 (U.S. DOE, 2020, 2020a). EPA used these data to update the industry profile from the
2020 rule, including commissioning dates, energy sources, capacity, net generation, operating statuses,
planned retirement dates, ownership, and pollution controls of the generating units. Consistent with the
2020 rule analyses, EPA also used data reported to DOE to estimate bromide loadings from FGD
discharges, including fuel consumption by coal type and coal purchases by county and coal type.
2.4.3 Office of Land and Emergency Management
The 2015 CCR rule established requirements for the safe disposal of CCRs from coal-fired steam electric
power plants. The CCR rule requires owners or operators of CCR surface impoundments and landfills to
record compliance with the rule's requirements and maintain a publicly available website of compliance
information.
EPA used plant-specific information on CCR landfills and surface impoundments from EPA's Office of Land
and Emergency Management (OLEM) as part of its CCR leachate in groundwater and legacy analyses. In
April 2022, EPA's OLEM provided the Office of Water with publicly available CCR compliance information
for 772 CCR management units, corresponding to 289 facilities, subject to the CCR Part A rule
requirements (U.S. EPA, 2022).
2.4.4 Power Company CCR Websites
As described in Section 2.4.3, the 2015 CCR rule established requirements for the safe disposal of CCRs
from coal-fired steam electric power plants and requires owners or operators of CCR surface
impoundments and landfills to record compliance with the rule's requirements and maintain a publicly
available website of compliance information. EPA searched these websites for CCR management-specific
documents including:
• Closure plans/reports
• Liner certifications
• Run-on/run-off control plans
• Annual inspection reports
9
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Section 2—Data Collection Activities
• Annual groundwater monitoring plans and corrective action reports
• Groundwater monitoring system design reports
See EPA's memoranda Evaluation of Potential CRL in Groundwater (U.S. EPA, 2023a) and Legacy
Wastewater at CCR Surface Impoundments (U.S. EPA, 2023b) for more details on how this information
was used as part of EPA's CCR leachate in groundwater and legacy analyses.
2.4.5 Literature and Internet Searches
EPA conducted literature and internet searches to gather information on FGD wastewater, CRL, and
legacy wastewater treatment technologies, including information on pilot studies, applications in the
steam electric power generating industry, and implementation costs and timeline. EPA also used internet
searches to identify or confirm reports of planned plant/unit retirements or reports of planned unit
conversions to dry or HRR ash handling systems. EPA used industry journals and company press releases
obtained from Internet searches to inform the industry profile and process modifications occurring in the
industry.
2.4.6 Intergovernmental and Tribal Listening Sessions
As part of the supplemental rulemaking process, EPA held consultation and coordination proceedings
with intergovernmental agencies and Tribal governments. Consultations pursuant to Executive Order
13132, entitled "Federalism," and the Unfunded Mandates Reform Act (UMRA) were held January 27,
2022. EPA received five sets of unique written comments after the meeting, including two comments
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 in the process of installing technologies to comply with the 2015 and 2020
rules compliant technologies. EPA also held listening sessions via webinars with Tribal representatives on
February 1 and 9, 2022. Following these 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 or encouraged
retirement or fuel conversion of old coal-fired units to protect those rights.
2.4.7 Communities
In support of its environmental justice analysis (EJA), EPA conducted a screening-level analysis of pollution
exposures to potentially affected communities and identified nine communities with EJ concerns. EPA
planned outreach to community members to discuss ideas and strategies for limiting pollution from
steam electric power plants, concerns related to these plants or other sources of pollution including
impacts to nearby rivers, lakes, and streams or drinking water; and community health, social, and
economic concerns. EPA conducted initial outreach to local environmental and community development
organizations, local government agencies, and individual community members. Between May and
September 2022, EPA held listening sessions with community members in five of the identified
communities. Each meeting began with a presentation providing background information about the
proposed supplemental 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. Three broad
themes conveyed consistently across communities included:
10
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Section 2—Data Collection Activities
• Community members perceive harmful impacts from steam electric power plants and desire more
stringent regulations to reduce these harmful impacts.
• Community members desire more transparency to overcome their decreasing trust in the regulated
plants and state regulatory agencies.
• Community members would prefer increased communication to understand the compliance of steam
electric power plants.
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 that cause additional
challenges in their community. See the Environmental Justice Analysis for Proposed Supplemental Effluent
Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category for
more details on these meetings (U.S. EPA, 2023c).
2.4.8 Notices of Planned Participation (NOPPs)
The 2020 rule required facilities to file a notice of planned participation (NOPP) with their permitting
authority no later than October 13, 2021, where the facility wished to participate in the low utilization
electric generating unit (LUEGU) subcategory, the permanent cessation of coal combustion subcategory,
or in the VIP. While EPA did not require that a copy be provided to the agency, EPA obtained a number of
these filings through various means including their standard permit review process, a facility providing
EPA a courtesy copy, EPA asking a state for their NOPPs, or environmental groups tracking NOPPs and
sharing the information they had collected with EPA. 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 (U.S. EPA, 2023d). EPA cautions that these counts are not a comprehensive
picture of facilities' plans. See Preamble Section VLB for more information about NOPPs.
2.5 Protection of Confidential Business Information
Certain data in the rulemaking record have been claimed as confidential business information (CBI). As
required by federal regulations at 40 CFR 2, EPA has taken precautions to prevent the inadvertent
disclosure of this CBI. The Agency has withheld CBI from the public docket in the Federal Docket
Management System. In addition, EPA has found it necessary to withhold from disclosure some data not
directly claimed as CBI because the release of these data could indirectly reveal CBI. Where necessary,
EPA has aggregated certain data in the public docket, masked plant identities, or used other strategies to
prevent the disclosure of CBI. The Agency's approach to protecting CBI ensures that the data in the public
docket explain the basis for the rule and provide the opportunity for public comment without
compromising data confidentiality.
11
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3. Current State of the Steam Electric Power Generating
Industry
For the 2015 rule, EPA generated a comprehensive industry profile using 2009 Department of Energy
(DOE) Energy Information Administration (EIA) data, data gathered through EPA's 2009 Questionnaire for
the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey) data, and Census Bureau
data from 2007. See Section 4 of the 2015 rule's Technical Development Document (TDD). For the 2020
rule, EPA updated the comprehensive profile to account for current plant operations and plans for future
modifications. See Section 3 of the 2020 Supplemental TDD.
For the proposed rule, EPA updated the comprehensive profile, evaluated changes in wastewater
management practices, and assessed impacts from other regulations affecting steam electric power
plants since the 2020 rule analysis. This section describes the current state of the steam electric power
generating industry, as it relates to the technical aspects of this 2023 proposal:
• Changes in the steam electric power plant population (Section 3.1).
• Current information on evaluated wastestreams (Section 3.2).
• Other regulations affecting the steam electric power generating industry (Section 3.3).
3.1 Changes in the Steam Electric Power Generating Industry Since the 2020
Rule
The steam electric power generating industry is dynamic: the Agency recognizes that industry
demographics and plant operations have changed after the 2020 rule analyses were completed.3
Therefore, EPA collected information on current plant operations and plans for future modifications to
augment industry profile data collected for the 2015 and 2020 rules. This section discusses changes in the
number and operating status of coal-fired electric generating units (EGUs) and updates to wet flue gas
desulfurization (FGD) systems, FGD wastewater treatment, bottom ash (BA) handling systems, and coal
combustion residual (CCR) landfills.
EPA gathered information from public sources, including company announcements and EIA data, to
account for the following types of operation changes that have occurred or been announced since the
2020 rule analyses:
• Commissioning of new coal-fired EGUs.
• Retirement of coal-fired EGUs.4
• Fuel conversions of coal-fired EGUs from coal to another fuel source, such as natural gas or hydrogen
fuel cells (e.g., natural gas).
• Installation of wet FGD systems.
• Modification or upgrade of FGD wastewater treatment systems.
3 EPA's 2020 rule analyses accounted for all industry profile changes announced and verified as of February 2020
that are in effect until 2028.
4 For the purposes of this analysis, EPA accounted for EGUs that will be indefinitely removed from service (i.e., idled
or mothballed) as retirements. See the preamble for discussion of EPA's evaluation of coal-fired EGUs nearing end of
life.
12
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Section 3—Current State of the Steam Electric Power Generating Industry
• Installation of, or conversion to, dry, closed-loop recycle, or high recycle rate (HRR) wet-sluicing BA
handling systems.5
• Installation of new CCR landfills.
EPA identified 171 coal-fired EGUs at 91 plants from the 2020 rule profile with at least one significant
change in operation taking place by December 31, 2028 (the date by which the final rule would be fully
implemented). Table 2 presents the count of steam EGU and plants, broken out by type of operation
change.
Table 2. Industry Profile Updates Since February 2020 by Type of Change in Operation
Change in Operation
EGUs
Retirement of coal-fired EGU
158
85
Fuel conversion to non-coal fuel type
13
8
Modification or upgrade of FGD wastewater treatment system3
0
0
Installation of new CCR landfill
NA
8
a - EPA identified an upgrade to an FGD wastewater treatment system at one coal-fired power plant, corresponding to four
EGUs; however, this upgrade was confirmed after the profile for this proposed rule was finalized on December 31, 2021 (U.S.
EPA, 2023d).
As shown in Figure 1, there has been an overall decrease in the number of EGUs operating in the industry.
The population of coal-fired EGUs and plants decreased to 304 EGUs at 163 plants, 29 percent fewer
EGUs than the 2020 rule population. Figure 1 illustrates the change in the number of operating coal-fired
EGUs and plants since the Steam Electric Survey, 2015 rule, 2020 rule, and 2023 proposed rule.
Section 5 and Section 6 describe how EPA accounted for the changes in operation identified in Table 2 in
estimating compliance costs, pollutant loadings, and pollutant removals for the proposed rule. More
information on the specific coal-fired EGUs and plants identified as implementing each type of operation
change is discussed in the memorandum titled Update to Industry Profile for the 2023 Steam Electric
Effluent Guidelines Proposed Rule (U.S. EPA, 2023d).
5 For this discussion, dry BA handling systems include all systems that do not generate BA transport water.
13
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Section 3—Current State of the Steam Electric Power Generating Industry
12 CO
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1000
300
500
400
200
Stesm Electric Sums/
(2009}
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2020 Rule
2023 Proposal
¦ EGUs
1099
735
427
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¦ Plants
471
347
218
163
Note: The 2015 rule analyses accounted for profile changes expected to occur before December 31, 2023 (the latest
date that power plants were subject to the established Best Available Technology Economically Achievable (BAT)
effluent limitations), whereas the 2020 rule and 2023 proposed rule account for changes expected to occur before
December 31. 202S.
Figure 1. Change in Population of Coal-Fired EGUs and Plants
3.2 Current Information on Evaluated Wastestreams
This section summarizes current information on the generation and discharge of FGD wastewater, BA
transport water, CRL, and legacy wastewater that EPA collected for the proposed rule.
3.2.1 FGD Wastewater
As discussed in Section 3.1, EPA updated the industry profile to reflect coal-fired EGUs that will retire,
convert fuels, or upgrade FGD wastewater treatment prior to December 31, 2028. Of the 304 coal-fired
EGUs at 163 coal-fired power plants in the updated profile, 105 EGUs at 54 plants are serviced by a wet
FGD system. EPA estimates EGUs with wet FGD systems have a total generating capacity of 66,270
megawatts (MW), representing approximately 50 percent of the total industry coal-fired capacity.
Figure 2 shows the locations of plants operating wet FGD systems servicing at least one coal-fired EGU. In
addition to wet FGD scrubbers, EPA estimates that there are 36 plants operating dry FGD scrubbers
servicing at least one coal-fired EGU in the industry. Although dry FGD scrubbers use water in their
operation, the water in most systems evaporates and they generally do not discharge wastewater. EPA
did not evaluate the wastewater generated from these dry FGD systems as part of the rulemaking, and
they would not be subject to the FGD wastewater requirements in the ELGs.
14
-------
Section 3—Current State of the Steam Electric Power Generating Industry
0 Plant with Wet FGD System(s)
Figure 2. Wet FGD Systems at Steam Electric Power Plants
Although the number of wet FGD systems operated at steam electric power plants has decreased since
promulgation of the 2020 rule, current FGD scrubber technologies are the same as those used at the time
of the 2015 rule. These wet FGD systems typically use a limestone slurry with forced oxidation to remove
S02 from flue gas from EGUs burning bituminous coal. Often, plants also operate selective catalytic
reduction (SCR) systems on these EGUs to reduce nitrogen oxide (NOx) emissions.
Following promulgation of the 2015 rule, EPA collected new information on air pollution control practices
at steam electric power plants that may affect the characteristics of FGD wastewater. Specifically, EPA
found that steam electric power plants may add halogens (e.g., bromine, chlorine, or iodine) to reduce
mercury air emissions. While all coal contains at least some naturally occurring halogens, steam electric
power plant operators can augment coal halogen concentrations at various points in the plant operations
to enhance mercury oxidation for mercury capture {e.g., directly injecting halogen during combustion;
mixing bromide with coal to produce refined coal; and using brominated activated carbon to control air
emissions). Halogens in flue gas at steam electric power plants are captured by wet FGD systems and
discharged in FGD wastewater.
Steam electric power plants have conducted on -site testing and/or installed a variety of technologies to
treat FGD wastewater, including chemical precipitation, constructed wetlands, zero valent iron
cementation, adsorption, ion exchange, and low residence time reduction (LRTR) biological treatment,
high residence time reduction (HRTR) biological treatment, advanced membrane filtration, and thermal
evaporative systems. EPA has identified that approximately seven percent of steam electric power plants
with wet FGD scrubbers have technologies in place able to meet the proposed BAT effluent limitations for
15
-------
Section 3—Current State of the Steam Electric Power Generating Industry
FGD wastewater, including membrane filtration systems or other FGD wastewater management
approaches that eliminate the discharge of FGD wastewater altogether. EPA also identified at least eight
installations of LRTR or HRTR systems in the steam electric power generating industry (the basis for BAT
limitations associated with the 2020 and 2015 FGD wastewater limitations, respectively). EPA identified
two domestic installations of spray evaporation technologies treating FGD wastewater and nine
installations of spray evaporation systems treating FGD wastewater in Asia. See Section 4 for more
details on these treatment technologies employed by some steam electric power plants to treat or
reduce FGD wastewater discharges. Table 3 summarizes FGD wastewater discharged by the steam
electric power plants included in EPA's costs and loadings analyses.
Table 3. FGD Wastewater Discharges for the Steam Electric Power Plants
FGD Wastewater Discharge Flow Rate
Number of
Plants
Number of
EGUs
Total Daily
Discharge Purge
Flow Rate
(MGD)
EGU Average
Daily Discharge
Purge Flow Rate
(MGD per EGU)
Total Annual
Discharge Purge
Flow Rate (MGY)
26
58
35.9
0.619
13,100
^^ 226^^n
MGD = million gallons per day.
MGY = million gallons per year.
Note: Counts and flow rates do not include EGUs that will retire or convert fuels by December 31, 2028, and wet FGD systems
that began operating after the Steam Electric Survey are excluded from the table.
3.2.2 BA Transport Water
Based on the Steam Electric Survey, approximately two-thirds of coal-fired power plants operated wet BA
handling systems in 2009. Some plants operating the wet BA handling systems recycled BA transport
water from impoundments, dewatering bins, or other handling systems back to the wet-sluicing system;
however, most BA transport water was discharged to surface water. At the time of the Steam Electric
Survey, less than 40 percent of EGUs operated dry, closed-loop recycle, or HRR BA handling systems.
Because of changes happening in the industry in the years following the Steam Electric Survey, by 2015
more than half of EGUs operated or planned to convert to dry, closed-loop recycle, or HRR BA handling
systems.
As discussed in Section 3.1, EPA updated the industry profile and corresponding analyses to account for
coal-fired EGUs that will retire, convert fuels, or install dry, closed-loop recycle, or HRR BA handling
systems prior to December 31, 2028. Since the 2015 and 2020 rules, more plants have converted or are
converting to dry, closed-loop recycle, or HRR BA handling systems, thereby eliminating or minimizing
discharge of BA transport water. In addition, based on data from the Steam Electric Survey, EGUs
commissioned after 2009 likely operate dry or closed-loop recycle BA handling systems.6 Further, the
number of coal-fired EGUs operating wet sluicing systems has decreased due to plant retirements and
fuel conversions. Table 4 presents the count and total generating capacity of the EGUs operating wet
sluicing, closed-loop recycle and/or HRR, or dry BA handling systems. For the 2020 rule, EPA estimated
that more than 75 percent of EGUs operate either dry, closed-loop recycle, or HRR BA handling systems.7
Based on conversations with industry, EPA is aware that plants are still working to comply with the 2020
6 Data from the Steam Electric Survey show that more than 80 percent of EGUs built in the 20 years preceding the
survey (1989-2009) installed dry BA handling at the time of construction. Because dry BA technologies are less
expensive to operate than wet-sluicing systems and facilitate beneficial use of the BA, it is unlikely that power
companies would find it advantageous to install wet-sluicing BA handling systems.
7 Counts presented in this paragraph and Table 4 do not reflect BA handling conversions expected as a result of the
CCR Part A rule.
16
-------
Section 3—Current State of the Steam Electric Power Generating Industry
rule. Figure 3 illustrates the geographic distribution of plants operating the systems noted in Table 4.
Plants that operate more than one type of system are shown as wet sluicing (with limited/no recycle or
closed-loop/HRR), whichever is applicable.
Table 4. BA Handling Systems for Coal-Fired EGUs
Type of System Number of Plants Number of EGUs Nameplate Capacity (MW)
Wet sluicing system with limited or
no recycle
41
116
48,300
Wet sluicing closed-loop/HRR
system
32
105
47,500
Dry BA handling system3
97
178
69,007
Total
163b
304
170,000
Note: Counts and flow rates do not include EGUs that will retire or convert fuels by December 31, 2028. Wet FGD systems that
began operating after the Steam Electric Survey are excluded from the table.
a—The dry BA handling system counts presented in this table reflect conversions identified by EPA in the Steam Electric
Survey and publicly available information from 2009 or later. Where data were available, EPA tracked the specific types of BA
handling conversions, such as MDS and remote MDS. However, EPA identified 35 EGUs, corresponding to 14,100 MW at 14
plants, for which the data confirmed that the plant was not discharging BA transport water but did not confirm the specific
type of nondischarging system.
b—Plant counts are not additive because plants may operate multiple types of BA handling systems.
3
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• ~ H #*
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Bottom Ash Handling System Type
• Wet Sluicing System with Limited or No Recycle
¦ Wet Sluicing Closed-Loop/High Recycle Rate System
~ Dry Bottom Ash Handling System
~ ~
~
Figure 3. Plant-Level BA Handling Systems in the Steam Electric Power Generating Industry
17
-------
Section 3—Current State of the Steam Electric Power Generating Industry
Table 5 summarizes BA transport water discharges by the steam electric power plants included in EPA's
costs and loadings analyses. The estimated flow rates are based on compliance with the 2020 rule, which
may represent full sluicing operations or a 10 percent allowable purge.
Table 5. BA Transport Water Discharges for the Steam Electric Power Plants
BA Wastewater Discharge Flow Rate
Number of
Plants
Number of
EGUs
Total Daily
Discharge Flow
Rate (MGD)
EGU Average
Daily Discharge
Flow Rate (MGD
per EGU)
Total Annual
Discharge Flow
Rate (MGY)
EGU Annual
Discharge
Flow Rate
(MGY per
EGU)
36
90
65.9
0.732
24,000
267
MG = million gallons per day.
MGY = million gallons per year.
3.2.3 CRL
EPA used data from the 2009 Steam Electric Survey to identify the population of landfills containing
combustion residuals that collect and discharge leachate to surface waters or publicly owned treatment
works (POTWs) (U.S. EPA, 2015). For the 2023 proposal, EPA updated this data set to remove plants that
intend to retire all coal-fired EGUs as of December 31, 2023 and add plants that have constructed new
landfills since 2015.8 Table 6 summarizes CRL discharges by the steam electric power plants included in
EPA's costs and loadings analyses.
Table 6. CRL Wastewater Discharges for the Steam Electric Power Plants
CRL Wastewater Discharge Flow Rate
Number of
Plants
Number of
EGUs
Total Daily
Discharge Flow
Rate (MGD)
EGU Average
Daily Discharge
Flow Rate (MGD
per EGU)
Total Annual
Discharge Flow
Rate (MGY)
EGU Annual
Discharge Flow
Rate (MGY per
EGU)
68
168
4.79
0.028
1,750
10.4
MGD = million gallons per day.
MGY = million gallons per year.
EPA also notes that unlined landfills and surface impoundments potentially discharge CRL through
groundwater before entering surface water. As stated in the preamble, EPA 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 waters of the U.S.
through groundwater is a functional equivalent of a discharge through this proposed action. 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 a sensitivity analysis documented in its memorandum Evaluation of Potential
CRL in Groundwater (U.S. EPA, 2023a).
8 If a plant in the CRL population converted to a different fossil fuel source {e.g., gas-fired), the 2023 proposal still
applies and it remains in the CRL population.
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Section 3—Current State of the Steam Electric Power Generating Industry
3.2.4 Legacy Wastewater
The definition of legacy wastewater provided in the 2015 rule preamble and wording of limitation
applicability in the actual regulation resulted in two distinct types of legacy water being captured at
steam electric power plants described below. Discharges of legacy wastewater include FGD wastewater,
BA transport water, fly ash transport water, CRL, gasification wastewater or flue gas mercury control
(FGMC) wastewater generated before the "as soon as possible" date that more stringent effluent
limitations from the 2015 or 2020 rules would apply.
The first category of legacy wastewater is 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).
Discharges of this type of legacy wastewater may occur through either an intermediary structure (e.g., a
tank or surface impoundment) or directly into a surface waterbody. The state permitting authority is
authorized by section 423.11(t) of the regulation to determine the date that is "as soon as possible" for
which these limitations can be complied with.
The second category of legacy wastewater is wastewater accumulated over years in a surface
impoundment (i.e., 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)9 that is later drained during the closure of that surface
impoundment. This type of legacy wastewater consists of surficial water located above the CCR solids
(i.e., "surface impoundment decant wastewater") and pore water in the saturated CCR layer (i.e., referred
to as "surface impoundment dewatering wastewater"). EPA also notes that there will be an interstitial
zone within these impoundments, where some disturbance of CCR solids may create sufficient mixing and
present similarly elevated pollutant concentrations as SI dewatering wastewater. While wastewater in
this interstitial zone is not pore water, it should be similarly situated with the pore water layer from a
regulatory perspective.
EPA used the list of CCR management units to identify the population of steam electric power plants and
EGUs that discharge legacy wastewater either directly into a surface waterbody or through an
intermediate structure that will remain open under the CCR rule, and the population or the steam electric
power plants and EGUs with surface impoundments containing legacy wastewater to be drained during a
closure stage. EPA estimates that surface impoundments remaining open discharge an average of
675,000 GPD. See the Legacy Wastewater at CCR Surface Impoundments memorandum (U.S., EPA, 2022;
U.S. EPA, 2023b) for details on the estimated volume and cost calculations. Table 7 summarizes
discharges of these types of legacy wastewater by the steam electric power generating industry.
Table 7. Estimate of Total Volume of Wastewater in Surface Impoundments Identified as "In
Closure"
Category
Total Number
of
Impoundments
Total Estimated
Volume of Decant
Wastewater
(million gallons)
Total Estimated
Volume of
Dewatering
Wastewater
(million gallons)
Total Estimated
Volume of
Wastewater
(million gallons)
Surface
impoundments in
closure process
116
19,900
35,700
56,700
Source: EPA, 2023b.
9 EPA has always sought to harmonize the CCR rule and this ELG. Therefore, this definition was taken from 40 CFR
257.53 to match the definition under the CCR rule.
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Section 3—Current State of the Steam Electric Power Generating Industry
3.3 Other Regulations on the Steam Electric Power Generating Industry
The Agency recognizes that effluent guidelines on steam electric power plants do not exist in isolation-
other EPA regulations set requirements for control of pollution emissions, discharges, and other releases
from steam electric power plants. For the 2020 rule, EPA assessed and incorporated impacts from the
CCR rule into the supporting analyses.
EPA continues to account for industry profile changes associated with the CCR rule. EPA coordinated the
requirements of the CCR rule and the 2015 rule to mitigate potential impacts from the overlapping
regulatory requirements and to facilitate implementation of engineering, financial, and permitting
activities. Based on the CCR rule requirements established in 2015, EPA expected plants might alter how
they operate their CCR surface impoundments, such as:
• Close the CCR-noncompliant disposal surface impoundment and open a new CCR-compliant disposal
surface impoundment in its place.
• Convert the CCR-noncompliant disposal surface impoundment to a new storage impoundment.
• Close the CCR-noncompliant disposal surface impoundment and convert to dry handling operations.
• Make no changes to the operation of the CCR-compliant disposal surface impoundment.
As discussed in Section 1.3, EPA finalized the CCR Part A rule on July 29, 2020, setting a deadline of April
11, 2021, for all unlined surface impoundments and those surface impoundments that failed the location
restriction for placement above the uppermost aquifer to stop receiving waste and begin closure. For the
2020 rule, EPA developed a methodology for using CCR surface impoundment liner data to estimate
operational changes at each coal-fired power plant under the CCR Part A rule. As described in Section 3.3
of the 2020 rule, plants with unlined or clay-lined CCR surface impoundments are required to change
operation or install a new CCR-compliant impoundment. EPA incorporated the CCR outputs into the 2020
rule (i.e., baseline) engineering costs and loadings analyses in one of the following ways:
• Where all active CCR surface impoundments are unlined or clay-lined, EPA predicted that a plant
would install tank-based FGD wastewater treatment or tank-based BA handling under the CCR Part A
rule.10
• For plants with at least one CCR surface impoundment not affected by the CCR Part A rule (i.e., not
identified as unlined or clay-lined,11 or where no data were available in the Office of Resource
Conservation and Recovery data set), EPA conservatively assumed the CCR Part A rule would have
little to no impact on a plant's existing FGD wastewater treatment or BA handling systems; thus, for
these plants, the estimated compliance cost and pollutant loadings remain unchanged for the 2023
proposed rule.
For the proposed rule, EPA determined that 50 plants within the BA engineering costs and loadings
analyses likely made changes to BA handling operations under the CCR Part A rule.12 EPA does not
10 For plants with at least one surface impoundment in the Office of Resource Conservation and Recovery data set,
EPA assumed the listed CCR surface impoundment(s) represent all impoundments receiving FGD wastewater and/or
BA transport water at the plant.
11 The Office of Resource Conservation and Recovery data set includes 34 active CCR surface impoundments without
liner designations. For these CCR surface impoundments, EPA did not assume they were unlined or clay-lined;
therefore, EPA may be underestimating the number of plants that will install tank-based FGD wastewater treatment
or BA handling in response to the CCR Part A rule.
12 Any plant that installs a remote MDS to comply with the CCR Part A rule may incur costs to install a reverse
osmosis system that will treat a slipstream of the recirculating BA transport water to remove dissolved solids and
facilitate long-term operation of the system as a closed loop to comply with the BA zero discharge requirements of
the 2015 rule. There are approaches other than reverse osmosis to remove dissolved solids from the BA system,
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Section 3—Current State of the Steam Electric Power Generating Industry
estimate any impacts on FGD operations as part of the proposed rule. Section 5 and Section 6 describe
how EPA accounted for CCR Part A rule impacts in estimating compliance costs, pollutant loadings, and
pollutant removals for the proposed rule.
such as using the transport water as makeup water for the FGD system. Dissolved solids will also be removed from
the system along with the dredged BA. As appropriate, EPA will update the compliance cost estimates for these
plants in future analyses.
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4. Treatment Technologies and Wastewater Management
Practices
This section provides an overview of treatment technologies and wastewater management practices at
steam electric power plants for flue gas desulfurization (FGD) wastewater, bottom ash (BA) transport
water, leachate collected from landfills and impoundments containing combustion residuals, and legacy
wastewater. This section focuses on only those technologies and practices considered as potential
technology options for this 2023 proposed rule: it is not a comprehensive listing of all technologies
available for treatment and management of FGD wastewater, BA transport water, leachate, or legacy
wastewater. For EPA's comprehensive evaluation of available technologies and practices forthe 2015 rule
and 2020 reconsideration, see the 2015 Technical Development Documents (TDD) and the 2020
Supplemental TDD. Also see the Technologies for the Treatment of Flue Gas Desulfurization Wastewater,
Coal Combustion Residual Leachate, and Pond Dewatering memorandum (U.S. EPA, 2023e) for details on
other types of treatment technologies available.
This section discusses the following:
• FGD wastewater treatment technologies (Section 4.1).
• BA handling systems and transport water management and treatment technologies (Section 4.2).
• Combustion residual leachate (CRL) treatment technologies and management practices (Section 4.3).
• Legacy wastewater treatment technologies (Section 4.4).
4.1 FGD Wastewater Treatment Technologies
For the 2023 proposed rule, EPA considered treatment technologies identified as part of the 2015 and
2020 rulemakings for those plants that are still operating and discharging FGD wastewater. These
technologies include low residence time reduction (LRTR) biological treatment and membrane filtration.
EPA also evaluated other treatment technologies capable of achieving zero discharge of FGD wastewater
including spray evaporation, other types of thermal treatment, and encapsulation.
4.1.1 LRTR Biological Treatment
Several types of biological treatment systems are used to treat FGD wastewater, including:
• Anoxic/anaerobic biological treatment systems, designed to remove selenium and other pollutants.
• Sequencing batch reactors, designed to remove nitrates and ammonia.
• Aerobic bioreactors for reducing biochemical oxygen demand (BOD).
These biological treatment processes are typically operated downstream of a chemical precipitation
system or a solids removal system (e.g., clarifier or surface impoundment).
The anoxic/anaerobic biological technology is designed to remove selenium, nitrate-nitrite, mercury, and
other pollutants. This process uses an anoxic/anaerobic fixed-film bioreactor that consists of an activated
carbon bed or other permanent porous substrate that is inoculated with naturally occurring, beneficial
microorganisms. The microorganisms grow within the substrate, creating a fixed film that retains the
microorganisms and precipitated solids within the bioreactor. The system uses microorganisms chosen
specifically for use in FGD systems because of their hardiness in the extreme water chemistry. The
microorganisms reduce the selenate and selenite to elemental selenium, which forms nanospheres that
adhere to the cell walls of the microorganisms. The technology can also remove other metals, including
arsenic, cadmium, nickel, and mercury, by forming metal sulfides (Pickett, 2006).
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Section 4—Treatment Technologies and Wastewater Management Practices
As defined in the 2020 reconsideration, an LRTR biological treatment system consists of chemical
precipitation13 followed by an anoxic/anaerobic fixed-film bioreactor. In the years since it first identified
anoxic/anaerobic biological technology in the 2015 rule, EPA identified different systems with varying
hydraulic residence times (HRT) in the bioreactor. During the development of the 2020 reconsideration,
EPA differentiated between high residence time reduction (HRTR) systems (which typically operate with
HRT in the bioreactor between 10 and 16 hours) and LRTR systems (with HRT between 1 to 4 hours).
Power companies and technology vendors have worked to develop processes that target removals of the
same pollutants in a smaller system with a lower HRT in the bioreactor. These LRTR technologies use
similar treatment mechanisms as HRTR to remove selenium, nitrate, nitrite, and other pollutants in less
time.
One LRTR technology includes a chemical precipitation system followed by an anoxic, upflow bioreactor
followed by a second stage downflow biofilter. The shorter HRT of this system allows for use of smaller
bioreactors and other equipment, resulting in a treatment system that is physically much smaller than the
HRTR system. Data provided by the power industry and an independent research organization show that
LRTR's performance is comparable to HRTR's. Much of the LRTR bioreactor and related equipment is
fabricated off site as modular components. Modular, prefabricated, skid-mounted components, coupled
with smaller physical size, result in lower installation costs and shorter installation times than for HRTR
systems, which are usually constructed on site. At least four plants have installed full-scale LRTR systems
and are using them to treat FGD wastewater, and this technology has been pilot tested using FGD
wastewater at more than a dozen steam electric power plants since 2012.
Another LRTR technology, fluidized bed reactors (FBRs), has been used to treat selenium in mining
wastewaters; it is now being tested on FGD wastewater. The FBR system is also an anoxic/anaerobic
fixed-film bioreactor design. It relies on an attached growth process, in which microbes grow on a
granular activated carbon medium that is fluidized by the upflow of FGD wastewater through the
suspended carbon medium. EPA identified 12 pilot studies of the FBR technology for selenium removal in
mining, refining/petrochemical, and steam electric power generating industries. For the steam electric
power generating industry, EPA identified three pilots involving FGD wastewater.
4.1.2 Membrane Filtration
Membrane filtration systems are specifically designed to treat wastestreams high in total dissolved solids
(TDS) and total suspended solids (TSS) using thin semi-permeable filters or film membranes. Membrane
filtration is used for the removal of dissolved materials from industrial wastewater and consists of one or
more of the following: microfiltration, ultrafiltration, nanofiltration, reverse osmosis (RO), forward
osmosis (FO), and electrodialysis reversal (EDR) membrane systems. As part of the 2020 reconsideration,
EPA identified several membrane filtration technologies being studied for use with FGD wastewater,
including nanofiltration membranes, RO, and FO. The membrane pore size determines the particle size
that can pass through the membrane, with RO membranes being the most restrictive and microfiltration
being the least restrictive. Most membrane filtration systems use pumps to apply pressure to the solution
from one side of the semi-permeable membrane to force wastewater through the membrane, leaving
behind dissolved solids retained ("rejected") by the membrane and a portion of the water. The rate at
which water passes through the membrane depends on the operating pressure, concentration of
dissolved materials, and temperature, as well as the permeability of the membrane.
Membrane systems separate feed wastewater into two product streams: a permeate stream, which is the
"clean" water that has passed through the membrane, and the concentrate stream, which is the water
(or brine) rejected by the membrane. The percentage of membrane system feed that emerges from the
system as permeate is known as the water recovery. Depending on wastewater characteristics,
membrane systems may require pretreatment to prevent scaling and fouling by removing excess TSS,
13 Consistent with both the 2015 and 2020 reconsideration rules, chemical precipitation includes hydroxide
precipitation, organosulfide precipitation, and iron coprecipitation to treat FGD wastewater.
23
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Section 4—Treatment Technologies and Wastewater Management Practices
calcium, magnesium, sulfate, or organics. Fouling occurs when either dissolved or suspended solids
deposit onto a membrane surface or a microbial biofilm grows on the membrane surface and degrades its
overall performance. To reduce fouling, membrane filtration systems have been designed with vortex
generating blades or vibratory movement. Other systems may use a microfiltration (or
uItrafiltration/nanofiItration) or chemical precipitation pretreatment step that targets scale-forming ions
where FGD wastewater characteristics indicate potential fouling.
FO uses a semi-permeable membrane and differences in osmotic pressures to achieve separation. FO
systems use a draw solution at a higher concentration than the feed (e.g., FGD wastewater) to induce a
net flow of water through the membrane. This results in diluting the draw solution and concentrating the
feed stream. This technology is different from RO, which uses hydraulic pressure to drive separation. FO
technology is typically better suited for high-fouling streams than traditional RO because external pumps
are not needed to drive treatment.
EDR uses a semi-permeable membrane and differences in electrical charges to achieve separation of
specific anions and cations. The first-of-its-kind domestic pilot of an electrodialysis reversal (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 the 2020 EPRI report FGD Wastewater Treatment
Testing Using a Saltworks Flex EDR Selective (Electrodialysis Reversal System) Technology, which found
that "[t]he 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 (over 1,440 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 (EPRI, 2020).
While MF, UF, and/or NF may provide sufficient pretreatment for membrane filtration systems,
incorporating chemical precipitation pretreatment can improve the efficiency of the membrane system
and may help lower the capital and operation and maintenance costs. Many of the systems piloted for
FGD wastewater have included some type of pretreatment (e.g., surface impoundment, chemical
precipitation, microfiltration) to reduce TSS and/or soften the wastewater before it enters the membrane
system. Membrane systems can be configured with polishing RO systems (e.g., multi-stage RO systems)
to further remove pollutants from the permeate. As well, membrane systems can be used in combination
with other technologies (e.g., thermal evaporation) to treat FGD wastewater or achieve zero discharge.
Permeate streams from these systems can be reused within the plant or discharged, while concentrate
streams (i.e., concentrated brine) would be disposed of in a landfill using encapsulation (see Section
4.1.5); in a commercial injection well; or through another process, such as thermal system treatment (see
Sections 4.1.3 and 4.1.4).
EPA identified three full-scale domestic installations of membrane technologies and installations in South
Africa and South America for treating wastewater in the mining industry, five domestic pilot studies in the
petroleum refining and agriculture industries, and installations in Mexico and China for treating municipal
landfill leachate. EPA further identified four full-scale installations of membrane filtration in the coal-to-
chemical industry in China and the textile industry in India.14 In the steam electric industry, EPA identified
17 pilot-scale studies of nanofiltration and RO used for FGD wastewater treatment world-wide (U.S. EPA,
14 EPA has limited data on the performance and configuration of the two full-scale membrane systems treating
mining wastewater and the pilot-scale systems in other industries (Wolkersdorfer, 2015; U.S. EPA, 2014; CH2M Hill,
2010; ERG, 2019; ERG, 2020). These systems may include a variety of membrane systems including nanofiltration,
microfiltration, and RO systems.
24
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Section 4—Treatment Technologies and Wastewater Management Practices
2023e).15 Some of the full-scale systems employ pretreatment before a combination of RO and FO.
Others operate pretreatment followed by nanofiltration and RO. At least one plant uses thermal
treatment to produce a crystallized salt from the concentrate stream, which is sold for industrial use. EPA
is also aware of one U.S. facility that is conducting a long-term pilot to test a membrane filtration system
for treating FGD wastewater (U.S. EPA, 20231).
See the Technologies for the Treatment of Flue Gas Desulfurization Wastewater, Coal Combustion
Residual Leachate, and Pond Dewatering memorandum (U.S. EPA, 2023e) for more information on pilot
testing of membrane filtration technologies.
4.1.3 Spray Evaporation
Spray evaporation technologies, which include spray dryers and other similar proprietary variations, are
an example of a thermal technology that is being applied to FGD wastewater treatment. Spray dryer
systems evaporate wastewater by spraying fine misted wastewater into hot gasses. The hot gases allow
the wastewater to evaporate before contacting the walls of the evaporation vessel, which allows spray
evaporation systems to remove TDS, TSS, or scale-forming pollutants.
For FGD application, a slipstream of hot flue gas from upstream of the air heater can be used to
evaporate FGD wastewater in a vessel. The FGD solids are carried along with the flue gas slipstream,
which is recombined with the main flue gas stream. All solids are then removed with the fly ash by the
main particulate control equipment (e.g., electrostatic precipitator or fabric filter) and disposed of in a
landfill. In cases where fly ash is marketable, and contamination is a concern, a separate particulate
control system can be operated on the flue gas slipstream to capture FGD solids alone.
Spray evaporation systems can be used in combination with other volume reduction technologies, such as
membranes, to maximize the efficiency of each process. For instance, RO systems can be installed
upstream of spray evaporation technologies to reduce influent flows. Concentrate from the RO system
can be processed through the spray evaporation system to achieve zero discharge. To achieve zero
discharge, permeate from the RO system needs to be recirculated back into plant operation as process
wastewater. Another method for reducing the volume of FGD wastewater influent to a spray evaporation
system may involve reconfiguring process flow to exclude non-FGD wastewater from the treatment
system (if wastewater is diluted by utility water streams prior to treatment).
EPA identified a vendor that has developed a proprietary technology that combines concepts of a brine
concentrator and spray dryer to achieve zero discharge. The system, referred to as an adiabatic
evaporator, injects wastewater into a hot feed gas stream to form water vapor and concentrated
wastewater. The air-water mixture is separated in an entrainment separator. Water vapor is exhausted,
and the concentrated wastewater is sent to a solid-liquid separator. The separated wastewater is recycled
and sent back through the system, while the solids can be la ndf i I led. An alternative configuration would
be to encapsulate the separated wastewater, by mixing it with fly ash, and then landfilling. Pretreatment
of FGD wastewater is not required, but—for situations where TSS exceeds 5 percent—it maybe be cost-
effective to operate a clarifier upstream of the evaporator to decrease solids. The vendor operated a full-
scale system at a coal-fired steam electric power plant for three years. FGD wastewater was pretreated
using a clarifier, then sent to the adiabatic evaporator, where 100 percent of the FGD wastewater was
evaporated and solids deposited in a landfill. Because propane was used as the heat source, operation
and maintenance costs proved to be too high, and the system was replaced.
15 EPA has limited details on these full-scale membrane systems. Some references include only plant name or
location. For this reason, some references may be describing the same installation, and EPA does not have enough
information to determine where this may be the case.
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Section 4—Treatment Technologies and Wastewater Management Practices
EPA identified two domestic installations of spray evaporation technologies treating FGD wastewater,
including one installation at the Boswell Energy Center in Minnesota (U.S. EPA, 2023e). EPA also identified
nine installations of spray evaporation systems treating FGD wastewater in Asia (U.S. EPA, 2023e).
See the Technologies for the Treatment of Flue Gas Desulfurization Wastewater, Coal Combustion
Residual Leachate, and Pond Dewatering memorandum (U.S. EPA, 2023e) for more information on pilot
testing of membrane filtration technologies.
4.1.4 Other Thermal Treatment Options
Thermal technologies use heat to evaporate water and concentrate solids and other contaminants. Some
of these systems can be operated to achieve full evaporation of all liquid, resulting in only a solid product,
or achieve partial evaporation of liquid. These thermal technologies can also be used in combination with
other technologies to treat FGD wastewater or achieve zero discharge.
One type of thermal treatment uses brine concentrators followed by crystallizers; this generates a
distillate stream and solid byproduct that can be disposed of in a landfill. As described in the 2015 and
2020 TDDs, four U.S. plants have installed brine concentrator systems for FGD treatment and at least four
coal-fired power plants in Italy also operate this type of system for FGD wastewater (U.S. EPA, 2015a).
EPA identified coal-fired steam electric power plants in China that have installed membrane treatment,
followed by brine concentrators and crystallizers to treat FGD wastewater. Brine concentration followed
by crystallization was evaluated as part of the 2015 rule as a possible treatment technology for the
industry; see Section 7.1.4 of the 2015 TDD for a detailed description of this treatment configuration (U.S.
EPA, 2015a).
EPA identified one vendor that has developed a modular brine concentration technology to heat FGD
wastewater and facilitate evaporation. As the wastewater boils, steam is collected, compressed, and
directed into a proprietary technology that allows the thermal energy to transfer from the steam to the
concentrated wastewater stream, causing it to become superheated. As water evaporates from the
superheated wastewater, the steam is collected and condensed. This distillate stream can be reused in
the plant as cooling tower make-up water or within the FGD scrubber. The concentrated wastewater,
referred to as brine, is discharged from the system once it reaches a set TDS concentration (not to exceed
200,000 parts per million). This brine stream is treated through hydrocyclones to remove suspended
solids. The resulting liquid can be encapsulated and landfilled. Pretreatment of FGD wastewater is only
required when TSS concentrations exceed 30 parts per million. Chemicals are added to maintain pH and
inhibit crystal and scale formation. This technology has been pilot tested at four coal-fired power plants
between 2015 and 2017.
4.1.5 Encapsulation
Encapsulation is a technology that can be used to eliminate FGD wastewater discharge. It uses chemical
reactions and/or absorption processes to bond materials together so that wastewater is incorporated
into the solid material. This process is also referred to as solidification. This technology has been used by
plants operating inhibited oxidation scrubber systems, where byproducts from the scrubber are mixed
with fly ash and lime to produce a non-hazardous landfillable material. This same approach has been
tested with pretreated FGD wastewater by mixing concentrated FGD wastewater with combinations of fly
ash, hydrated lime, sand, and/or Portland cement to encapsulate contaminants. Tests of these materials
have confirmed that the solids generated meet solid waste leaching requirements, toxicity characteristic
leaching procedure (TCLP), and other local landfill regulations (Pastore and Martin, 2017; Martin, 2019).
Encapsulation can be used alone or in combination with other treatment technologies. For instance, it
can be incorporated on reduced volumes of the concentrated stream downstream of a membrane and/or
thermal system. Additionally, as described in Section 4.1.3, encapsulation can be implemented
downstream of spray evaporation technologies that achieve only partial evaporation and produce
concentrated wastewater streams.
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Section 4—Treatment Technologies and Wastewater Management Practices
4.2 BA Handling Systems and Transport Water Management and Treatment
Technologies
EPA reviewed BA handling systems—operated at coal-fired steam electric power plants or marketed by
BA handling vendors—that are designed to minimize or eliminate the discharge of BA transport water.
Many plants have installed or are installing BA handling systems that minimize or eliminate the discharge
of BA transport water. The BA handling technologies evaluated by EPA and described in this section
include mechanical drag systems, remote mechanical drag systems, compact submerged conveyors
(CSCs), and mobile mechanical drag systems.
As part of previous rulemaking efforts in 2015 and 2020, EPA also evaluated types of dry ash handling
systems: dry mechanical conveyors and pneumatic systems (i.e., dry vacuum or pressure systems). See
the 2015 TDD and 2020 Supplemental TDD (U.S. EPA, 2015a; U.S. EPA 2020).
4.2.1 Mechanical Drag System
A mechanical drag system collects BA from the bottom of the EGU through a transition chute and sends it
into 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. The drag system uses a parallel pair of chains attached by crossbars at regular
intervals. In a continuous loop, the chains move along the bottom of the water bath, draggingthe BA
toward the far end of the bath. The chains then move up an incline, dewatering the BA by gravity and
draining the water back to the trough. Because the BA falls directly into the water bath from the bottom
of the EGU and the drag chain moves constantly on a loop, BA removal is continuous. 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. See Section 7.3.3 of the 2015
TDD for more specific system details (U.S. EPA, 2015a).
The mechanical drag system does generate some wastewater (i.e., residual water that collects in the
storage area as the BA continues to dewater). This wastewater is either recycled back to the quench
water bath or directed to the low volume waste system. This wastewater is not BA transport water
because the transport mechanism is the drag chain, not the water (see 40 CFR 423.11(p)).16
This system may not be suitable for all EGU configurations and may be difficult to install if there is limited
space below the EGU.17 These systems cannot combine and collect BA from multiple EGUs, and most
installations require a straight exit from the EGU to the outside of the building. In addition, these systems
may be susceptible to maintenance outages due to BA fragments falling directly onto the drag chain.
4.2.2 Remote Mechanical Drag System
Remote mechanical drag systems collect BA using the same operations and equipment as wet-sluicing
systems at the bottom of the EGU. However, instead of sluicing the BA directly to an impoundment, the
plant pumps the BA transport water to a remote mechanical drag system. This type of system has the
same configuration as a mechanical drag system, but with additional dewatering equipment in the trough
to enable recycling BA transport water back to the system. Also, it does not operate under the EGU, but
rather in an open space on the plant property. See Section 7.3.4 in the 2015 TDD for more specific system
design details (U.S. EPA, 2015a).
16 The mechanical drag system does not need to operate as a closed-loop system because it does not use water as
the transport mechanism to remove the BA from the boiler; the conveyor is the transport mechanism. Therefore,
any water leaving with the BA does not fall under the definition of "bottom ash transport water," but rather is a low
volume waste.
17 In comments on the 2013 proposed ELG, three plants reported space constraints below the boiler such that a
mechanical drag system could not be installed.
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Section 4—Treatment Technologies and Wastewater Management Practices
Plants converting their current BA handling systems can use this system if space or other restrictions limit
the changes that can be made to the bottom of the EGU. Currently, over 50 coal-fired power plants have
installed, or are planning to install, remote mechanical drag systems to handle BA.
Because of the chemical properties of BA transport water, some plants may need to add flocculant or
polymer to aid in the settling of fines to prevent potential plugging of the sluice pipes. Other plants may
have to treat the overflow (or a slipstream of the overflow) before recycling to prevent scaling and fouling
in the system. Plants that require treatment to achieve complete recycling of BA transport water could
install a pH adjustment system, chemical addition, or an RO membrane (as described in EPA's cost
methodology in Section 5) depending on the BA transport water characteristics and materials of
construction.
Similar to the mechanical drag system, the drag chain conveys the ash to a collection area and the plant
then sells or disposes of it in a landfill. There is also an opportunity for multiple unit synergies and
redundancy with remote mechanical drag systems because they are not operating directly underneath
the EGU. This system needs less maintenance than the mechanical drag system because the BA particles
entering it have already been through the grinder prior to sluicing.
4.2.3 CSC
A CSC, also referred to as submerged grind conveyor, collects BA from the bottom of the EGU. A CSC uses
existing equipment—BA hoppers or slag tanks, the BA gate, clinker grinders, and a transfer enclosure—to
remove BA from the hopper continuously. From the bottom of the EGU, BA falls into the water
impounded hopper or slag tank. It is then directed to the existing grinders to be ground into smaller
pieces and is then transferred to a fully enclosed bottom carry chain and flight conveyor system. Similar
to a mechanical drag system (except for the fully enclosed bottom carry design), a drag chain
continuously carries and dewaters BA up an incline, away from the EGU. Because the transport
mechanism is the conveyor instead of water, CSCs do not generate BA transport water.18 The dewatered
BA is transferred to one or more additional conveyors, which transports it to a BA silo or bunker where
the BA is collected in a truck and transported to its final destination. CSCs use additional conveyors to
avoid existing structures such as pillars and coal pulverizers while conveying BA out of the EGU house.
This makes it possible to install CSCs in some plants where physical constraints prevent installation of
mechanical drag systems; however, physical constraints could prevent CSC installation at other plants.
CSCs can also use smaller chains and are narrower and shorter than mechanical drag systems, features
that potentially allow them to fit in places with insufficient space for the larger mechanical drag system
conveyors.
A CSC can be isolated from the hopper using the existing transfer enclosures to perform maintenance
while the EGU remains online (made possible by the BA storage capacity of the hopper). It is also possible
for some plants to install parallel conveyors for redundancy (ERG, 2020a; ERG, 2020b; ERG, 2020c; ERG,
2020d).
For plants that can repurpose their wet sluicing equipment (hoppers, slag tanks, and/or clinker grinders,
etc.), the capital costs of converting to CSC systems are typically lower, and installation and outage times
are shorter, than for other under-the-EGU BA handling systems. However, because a CSC serves just one
EGU, the more EGUs a plant has, the less economical this technology becomes.
EPA is aware of at least five plants that have installed and are operating CSC systems in the United States.
EPA understands that these facilities do not have vertical space constraints under the EGUs.
18 Like mechanical drag systems, CSCs are considered a dry handling technology, because they do not use water as
the transport mechanism.
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Section 4—Treatment Technologies and Wastewater Management Practices
4.2.4 Mobile Mechanical Drag System
A mobile mechanical drag system is a BA transport water dewatering unit—similar to a remote
mechanical drag system—with an additional clarification system (U.S. EPA, 2022b). This technology is not
intended to be set on a permanent location, which reduces capital costs associated with permanent
infrastructure. Depending on the facility, a mobile mechanical drag system can either remain on a truck
or be installed on facility grounds. From the mechanical drag system, BA transport water is taken to a
mobile clarifier and polished to a level suitable for recirculation. This mixture is sent up an incline,
dewatered, and discharged.
The mobile clarifiers are typically equipped with lamella separators, polymer addition, and mobile
chemical injection systems, including coagulant (typically ferric chloride) and flocculant for solids removal
and caustic and acid injection for pH control. Typically, thickened sludge from the mobile clarifier is
pumped back to the mechanical drag unit, with the coarse particulates acting as ballast to assist the
sludge up the ramp to the mechanical drag system. The fines from the underflow of the clarifier can be
pumped to a mobile belt filter press to make filter cake.
In addition to reducing capital costs, benefits of mobile systems include reduced construction costs, a
smaller footprint compared to other BA treatment options, increased flexibility, minimal invasion to the
facility's existing systems, manual controls to reduce complexity of control system tie-in, and the ability to
serve as a recirculation system.
Mobile mechanical drag systems may have relatively higher operation and maintenance costs: the system
is often a single remote mechanical drag system and an upset condition may require the unit to be shut
down, and nonpermanent infrastructure (such as flexible HDPE piping and hose connections) lacks the
robust nature of carbon steel or ballast line materials.
EPA is aware of one installation of a mobile system at a plant serving two coal-fired units and a full-scale
pilot demo at a facility using a mobile system combined with a hydrocyclone vibrating screen to treat
dewatering impoundment water.
4.3 CRL Treatment Technologies and Management Practices
In promulgating the 2015 rule, EPA determined that CRL from landfills and impoundments includes
similar types of constituents as FGD wastewater, albeit at potentially lower concentrations and smaller
volumes. Based on this characterization of the wastewater and knowledge of treatment technologies,
EPA determined that certain treatment technologies identified for FGD wastewater could also be used to
treat leachate from landfills and impoundments containing combustion residuals.
In support of the 2015 rule, EPA identified facilities using surface impoundments, biological treatment,
and constructed wetlands to treat CRL, sometimes comingled with FGD wastewater. EPA also identified
facilities using other management practices to manage leachate, including recycling the wastewater in
other plant operations or for moisture conditioning of fly ash. This section describes treatment
technologies EPA considered for the treatment of leachate as part of this 2023 proposal, including
technologies already being used by the industry.
4.3.1 Chemical Precipitation
In a chemical precipitation wastewater treatment system, chemicals are added to the wastewater to alter
the physical/chemical state of dissolved and suspended solids to help precipitate, settle, and remove
them. The specific chemical(s) used depends on the type of pollutant requiring removal. Steam electric
power plants using chemical precipitation systems to treat FGD wastewater may include stages of
hydroxide (lime), iron, and organosulfide addition, as well as clarification stages. Plants may either add all
three chemicals to a single reaction tank or add the chemicals to separate tanks. Plants operating
separate tanks typically target different pH set points within each tank for optimal precipitation of certain
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Section 4—Treatment Technologies and Wastewater Management Practices
metals. Similar strategies may be applied to treat CRL, since this wastestream includes similar
constituents as FGD wastewater.
In a hydroxide precipitation system, plants add lime (calcium hydroxide) to elevate the pH of the
wastewater to a designated set point, helping precipitate metals into insoluble metal hydroxides that can
be removed by settling or filtration. Sodium hydroxide can also be used in this type of system, but it is
more expensive than lime and, therefore, not as common in the industry.
Plants use iron coprecipitation to increase the removal of certain metals in a hydroxide precipitation
system. Steam electric power plants typically use ferric chloride to coprecipitate additional metals and
organic matter. The ferric chloride also acts as a coagulant, forming a dense floe that enhances settling of
the precipitated metals in downstream clarification stages.
Organosulfide precipitation systems use organosulfide chemicals (e.g., trimercapto-s-triazine [TMT],
Nalmet® 1689, MetClear™, sodium sulfide) to precipitate and remove heavy metals. Plants may test
several organosulfide chemicals to determine which one is most appropriate for their treatment systems.
Organosulfide precipitation can also optimize removal of metals with lower solubilities, such as mercury,
more effectively than hydroxide precipitation or hydroxide precipitation with iron coprecipitation. EPA
sampling data show that adding organosulfide to the FGD wastewater can reduce dissolved mercury
concentrations to less than 10 parts per trillion (ERG, 2012). Organosulfide precipitation is more effective
than hydroxide precipitation in removing metals with low solubilities because metal sulfides have lower
solubilities than metal hydroxides. Due to the relatively low costs of hydroxide precipitation, plants
usually use hydroxide precipitation first to remove most of the metals, and then organosulfide
precipitation to remove the remaining low solubility metals. This configuration overall requires less
organosulfide, therefore reducing costs.
EPA's data demonstrate that well-operated systems maintain their chemical precipitation effluent
concentrations because they actively monitor target metals, allowing them to adjust the operation of the
chemical precipitation system as necessary. Some plants actively monitor the influent to the treatment
system and adjust chemical addition in an equalization tank with a 24-hour holding time as the first step
in the treatment system.
See Section 7.1.2 in the 2015 TDD for more specific chemical precipitation system design details (U.S.
EPA, 2015a).
4.3.2 Biological Treatment
Some plants use the same biological wastewater treatment systems to treat both FGD wastewater and
leachate, in some cases as a combined stream. Microorganisms consume biodegradable soluble organic
contaminants and bind much of the less soluble fractions into floe. Pollutant concentrations may be
reduced aerobically, anaerobically, and/or by using anoxic zones to remove metals and nutrients. EPA
identified two facilities using fixed-film bioreactors that reduce selenium and nitrate/nitrite to treat CRL.
See Section 4.1.1 for more details on the LRTR system specific to FGD wastewater treatment, which can
also be used to treat leachate.
4.3.3 Membrane Filtration
See Section 4.1.2 for a description of membrane treatment technologies, which can also be used to treat
leachate from landfills and impoundments containing combustion residuals.
4.3.4 Thermal Treatment Options
See Sections 4.1.3 and 4.1.4 for a description of thermal treatment technologies, including spray
evaporation, that can also be used to treat leachate from landfills and impoundments containing
combustion residuals. EPA's review of thermal treatment options to treat CRL show that four technology
vendors are operating these systems at municipal landfills. See EPA's Technologies for the Treatment of
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Section 4—Treatment Technologies and Wastewater Management Practices
Flue Gas Desulfurization Wastewater, Coal Combustion Residual Leachate, and Pond Dewatering
memorandum for more information (U.S. EPA, 2023e).
4.3.5 Management Strategies and Reuse
In promulgating the 2015 rule, EPA also identified steam electric power plants using other types of
management strategies for CRLfrom landfills and impoundments (U.S. EPA, 2015a):
• As of 2009, 24 plants collect combustion residual landfill or impoundment leachate and use it as
water for moisture conditioning dry fly ash prior to disposal or dust control around dry unloading
areas and landfills.
• As of 2009, EPA identified five plants that use collected leachate from landfills or impoundments as
truck wash and route it back to impoundments.
• As of 2009, approximately 40 percent of plants collect CRL from impoundments and recycle it directly
back to the impoundments from which it was collected.
4.4 Legacy Wastewater Treatment Technologies and Management Practices
As described in the preamble for the proposed rule, legacy wastewater consists of the following:
• Wastewater generated between new permit issuance and the "as soon as possible" date for more
stringent effluent limitations to apply that is continuously generated and discharged.
• Wastewater accumulated over years in a surface impoundment (i.e., a natural topographic
depression, artificial excavation, or diked area that is designed to hold an accumulation of CCR and
liquids and treats, stores, or disposes of those residuals) that is later drained during the closure of
that surface impoundment.
The following technologies can be applied to treat each type of legacy wastewater being captured at
steam electric power plants.
4.4.1 Legacy Wastewater Discharged Directly to Surface Waterbodies or Through Intermediary
Structures
Discharges of legacy wastewater generated between new permit issuance and the "as soon as possible"
date for more stringent effluent limitations to apply may occur through an intermediary structure (e.g., a
tank or surface impoundment) or directly into a surface waterbody. EPA has determined that the
following technologies, which can also treat FGD wastewater, can be applied to treat this type of legacy
wastewater.
4.4.1.1 Chemical Precipitation
See Section 4.3.1 for a description of chemical precipitation technologies that can also be used to treat
this type of legacy wastewater.
4.4.1.2 Biological Treatment
See Sections 4.1.1 and 4.3.2 for descriptions of biological treatment technologies that can also be used to
treat this type of legacy wastewater. Furthermore, Section 7.1.3 of the 2015 TDD and Section 4.1.1 of the
2020 TDD include additional biological treatment system design details (U.S. EPA, 2015a; U.S. EPA, 2020).
4.4.1.3 Zero Valent Iron
Zero valent iron (ZVI), in combination with other systems such as chemical and physical treatment, can be
used to target specific inorganics, including selenium, arsenic, nitrate, and mercury, in this type of legacy
wastewater.
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Section 4—Treatment Technologies and Wastewater Management Practices
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 the number of reaction vessels can
be varied based on the composition and amount of wastewater being treated.
Treatment configurations may include chemical precipitation followed by ZVI treatment and may also
include pretreatment to partially reduce influent nitrate concentrations. The purpose of the nitrate
pretreatment is to reduce the consumption rate of the ZVI media, which reacts with both the nitrates and
selenium in the wastewater.
EPA identified two full-scale installations of the ZVI technology for selenium removal in mining
wastewater and seven completed pilot-scale studies of ZVI used for FGD wastewater treatment.19,20 At
least four additional pilot-scale studies for FGD wastewater treatment were in the planning stage at
plants in the eastern United States, as of 2016. The data from a subset of these pilot tests indicate that
the combination of chemical precipitation and ZVI technology, along with nitrate pretreatment where
warranted, can produce effluent quality comparable to chemical precipitation followed by low residence
time reduction (CP+LRTR), and chemical precipitation followed by high residence time reduction
(CP+HRTR) technologies.
4.4.1.4 Membrane Filtration
See Section 4.1.2 for a description of membrane treatment technologies that can also be used to treat
this type of legacy wastewater.
4.4.1.5 Thermal Treatment
See Sections 4.1.3 and 4.1.4 for a description of thermal treatment technologies, including spray
evaporation, that can also be used to treat this type of legacy wastewater.
4.4.1.6 Encapsulation
See Section 4.1.5 for a description of encapsulation technologies that can also be used to treat this type
of legacy wastewater.
4.4.1.7 Other Emerging Technologies
See Section 4.1.6 of the 2020 TDD for descriptions of emerging technologies for FGD wastewater
treatment that can also be applied to treat this type of legacy wastewater (U.S. EPA, 2020). These
19 EPA has limited data on the performance and configuration of the two full-scale ZVI systems treating mining
wastewater (Butler, 2010). At least one of the systems includes ZVI in combination with an RO membrane system to
target selenium removal.
20 In addition to the seven FGD pilots of ZVI, EPA has observed ZVI technology in treating ash transport water during
impoundment dewatering at a plant. In this application, the impoundment water was first treated by RO membrane
filtration, and the membrane reject stream was sent to ZVI reactors for treatment. The membrane permeate and
ZVI effluent streams were both discharged by the plant to surface waters. Although this application was not treating
FGD wastewater, many of the pollutants present in FGD wastewater are also present in ash impoundments, and
these pollutants were effectively removed by the ZVI process (ERG, 2019a). A similar treatment train has been
suggested for FGD wastewater: chemical precipitation followed by RO membrane filtration, with the membrane
reject stream sent to a ZVI stage consisting of three reactors in series. As with the treatment system for the
impoundment, the RO permeate and ZVI effluent would be discharged (unless the RO permeate was reused within
the plant).
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Section 4—Treatment Technologies and Wastewater Management Practices
emerging technologies include electrodialysis reversal and RO technology, closed-loop mechanical vapor
recompression, and distillation-based thermal transfer systems.
4.4.2 Legacy Wastewater Discharged from Surface Impoundments Undergoing Closure
Legacy wastewater that is accumulated over years in a surface impoundment and drained during the
closure of that surface impoundment consists of surficial water located above the CCR solids (i.e.,
"surface impoundment decant wastewater") and pore water in the saturated CCR layer at levels beyond
that needed for conditioning (i.e., "surface impoundment dewatering wastewater"). EPA notes that there
will be an interstitial zone within these impoundments, where some disturbance of CCR solids may create
enough mixing between these zones for pollutant concentrations to be elevated in impoundment decant
wastewater.
EPA recognizes that the wastewater characteristics of decant and dewatering water may differ within a
CCR impoundment. Therefore, treatment requirements may change as closure continues. Wastewater
characteristics also differ across CCR impoundments due to fuel type burned, duration of impoundment
operation, and ash type. The treatment technologies listed in Section 4.4.1 are applicable to the decant
and dewatering wastewaters; however, treatment may require a combination of technologies (e.g.,
chemical precipitation and membrane filtration).
For example, the state of North Carolina issued several permits to Duke Energy that applied water quality-
based effluent limitations on several pollutants once the surface impoundment reached lower water
levels. These pollutants differ for each permit, but the permits generally have led to the inclusion of
physical settling, chemical precipitation, and (for at least one facility) ZVI treatment. These systems can be
operated to remove TSS, metals, selenium, and nutrients from surface impoundment decant and
dewatering wastewaters. See Sections 4.3.1 and 4.4.1.3 for a description of chemical precipitation and
ZVI technologies. EPA also is aware of one plant that is treating legacy wastewater with spray
evaporators, which are equipped to treat the variable characteristics often encountered when
dewatering impoundments and treating legacy wastewater.
Solids dewatering can also occur when CCR materials are dredged from the impoundment as part of clean
closure. It typically involves mobile dewatering systems that are self-contained on a trailer and can thus
be easily moved on and off site. Decant wastewater from a holding area (e.g., pit, impoundment,
collection tank) is pumped through a filter press to generate a filter cake and water stream. A shaker
screen can be added 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 wastewater stream may be further treated to meet any discharge
requirements.
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5. Engineering Costs
For the proposed rule, EPA estimated compliance costs for flue gas desulfurization (FGD) wastewater,
bottom ash (BA) transport water, and combustion residual leachate (CRL) from landfills.21 These estimates
further develop the estimated costs from the 2015 and 2020 rules. Section 9 of the 2015 rule TDD
presents EPA's methodology for estimating compliance costs for FGD wastewater, BA transport water,
and CRL from landfills. Section 5 of the 2020 rule TDD describes EPA's cost estimates for FGD wastewater
and BA transport water. Here, EPA is presenting cost estimates for baseline compliance, post-compliance,
and incremental costs defined as follows:
• Baseline compliance costs. The costs for plants to comply with effluent limitations based on the
technologies considered in the 2023 proposed rule technology options. 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. 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 changes to the
existing 2020 limitations and standards. For more information, see the Regulatory Impact Analysis for
Proposed Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (RIA, U.S. EPA, 2023f). For FGD wastewater and BA transport
water, the baseline compliance costs anticipate that plants will have met the requirements of the
2020 rule; for CRL, baseline compliance costs consider current treatment in place.
• Post-compliance costs. The costs for plants to comply with effluent limitations based on the
technologies considered in the 2023 proposed rule technology options. EPA estimated post-
compliance costs with the expectation that all steam electric power plants subject to the
requirements of the proposed rule will install and operate wastewater treatment and pollution
prevention technologies equivalent to the technology bases for the regulatory options.
• Incremental costs. The difference between the baseline compliance costs and 2023 proposed rule
post-compliance costs for each regulatory option.
EPA's compliance cost estimates include the following components:
• Capital costs (one-time costs). Capital costs comprise the direct and indirect costs associated with
purchasing, delivering, and installing pollution control technologies. Capital cost elements include
purchased equipment and freight, equipment installation, buildings, site preparation, engineering
costs, construction expenses, contractor's fees, and contingencies.
• Annual operation and maintenance (O&M) costs (incurred every year). Annual O&M costs comprise all
costs related to operating and maintaining the pollution control technologies for a period of one year.
O&M cost elements include costs associated with operating labor, maintenance labor, maintenance
materials (routine replacement of equipment due to wear and tear), chemical purchases, energy
requirements, residuals disposal, and compliance monitoring.
• Other one-time or recurring costs. In some cases, the technology options may also result in costs that
recur less often than annually (e.g., three-year recurring costs for equipment replacement) or one-
time costs other than capital investment (e.g., one-time cost to consult with an engineer).
EPA updated its industry profile as follows:
21 Consistent with the 2015 rule, EPA assumed that plants required to treat surface impoundment leachate would
decide to recycle the leachate back to the impoundment where it was generated.
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Section 5—Engineering Costs
• EPA began by updating its profile to reflect retirements of electric generating units (EGUs) that will
occur by December 31, 2028, for the FGD wastewater and BA transport water populations. For CRL,
EPA removed plants that will have retired all coal-fired EGUs by December 31, 2023.
• EPA also removed any EGUs that will have converted to a non-coal fuel source by December 31,
2028, for FGD wastewater and BA transport water populations. EPA did not remove refuels from the
CRL population. These EGUs, which previously burned coal and generated coal combustion residuals
(CCRs) that were disposed of in landfills, remained in the population because the corresponding
power plant is still operating. Based on the applicability of 40 CFR 423, the plant and landfill leachate
are still subject to the guidelines. See Section 5.3.1 for details on how EPA developed the CRL
population.
• Through January 2022, EPA incorporated any notices of planned participation (NOPPs) to meet
limitations for low utilization electric generating units (LUEGUs) for BA transport water into its
analyses. EPA also accounted for any plants that opted into the Voluntary Incentives Program (VIP)
through January 2022 for FGD wastewater.
The remainder of this section describes EPA's methodology for estimating baseline compliance costs,
post-compliance costs, and incremental costs by wastestream, as well as industry-level compliance cost
estimates for each of the 2023 proposed regulatory options:
• FGD wastewater (Section 5.1).
• BA transport water (Section 5.2).
• CRL (Section 5.3).
Finally, this section summarizes baseline and regulatory option costs (Section 5.4).
5.1 FGD Wastewater
For the proposed rule, EPA estimated costs for plants to install and operate two technologies: chemical
precipitation followed by low residence time reduction (CP+LRTR) and membrane filtration.
For CP+LRTR, EPA included the following treatment components for FGD wastewater, consistent with the
2020 rule methodology:
• CP treatment equipment (equalization and storage tanks, pumps, reaction tanks, solids-contact
clarifier, and gravity sand filter).
• CP chemical feed systems (lime, organosulfide, ferric chloride, and polymers).
• CP solids-contact clarifier to remove suspended solids.
• LRTR treatment equipment (anoxic/anaerobic bioreactor, flow control, backwash supply, storage
tanks).
• LRTR chemical feed system for nutrients.
• Pretreatment system for nitrate/nitrites (for plants with nitrate/nitrite concentrations above 50 parts
per million [ppm]).
• Heat exchanger.
• Ultrafilter.
• Compliance monitoring (including sample collection and analysis).
• Solids handling (sludge holding tank and filter press).
• Transportation and disposal of solids in a landfill.
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Section 5—Engineering Costs
For membrane filtration, EPA included the following FGD wastewater treatment components, consistent
with the 2020 rule methodology:
• CP treatment equipment (equalization and storage tanks, pumps, reaction tanks, solids-contact
clarifier, and gravity sand filter).
• CP chemical feed systems (lime, organosulfide, ferric chloride, and polymers).
• CP solids-contact clarifier to remove suspended solids.
• Membrane filtration treatment equipment (membrane filtration, reverse osmosis (RO), and storage
tanks).
• Brine encapsulation.
• Transportation and disposal of solids in a landfill.
Section 5.1.1 describes the cost inputs and the methodology for updating the FGD wastewater flow rates
from the 2020 rule. Sections 5.1.2 and 5.1.3 present EPA's methodology for estimating costs for LRTR and
membrane filtration, respectively.
5.1.1 FGD Cost Calculation Inputs
To estimate plant-level baseline and post-compliance costs of implementing FGD wastewater treatment
technologies, EPA developed a cost calculation database. This database combines plant-specific input
values, including wastewater flow rates and existing wastewater treatment, with the relationships
between costs and FGD flow rates described in Sections 5.1.2 and 5.1.3 to estimate baseline and post-
compliance costs for each plant (ERG, 2023). For the proposed rule, EPA used input data compiled from
the 2015 and 2020 rules, including Steam Electric Survey data, site visits, sampling episodes, and other
industry-provided data, and updated these data using new information gathered from industry (see
Section 2). This section describes the updates to cost inputs from the 2020 rule.
5.1.1.1 Population
EPA identified coal-fired power plants that discharge FGD wastewater to surface water or a publicly
owned treatment works (POTW) and that are not expected to retire or convert fuel sources by December
31, 2028. EPA started with the population of plants from the 2020 rule and updated the population based
on new publicly available data on operational changes and industry-provided data. EPA also compiled a
list of the EGUs at these plants that discharge FGD wastewater, keeping in mind that some plants retire or
convert individual EGUs and not the entire plant.
5.1.1.2 Flow Rate
For each plant, EPA estimated two FGD purge flow rates: the FGD purge flow rate (the typical amount of
wastewater from the FGD scrubber that is sent to FGD wastewater treatment) and the FGD optimized
flow rate (a reduced rate that considers a reduction in FGD wastewater purged from the system, where
equipment metallurgy could accommodate increased chloride concentration in the FGD system). As in
the 2020 rule, EPA used the FGD purge flow rate to calculate capital costs to ensure that the installed
treatment technologies would be able to accommodate the maximum possible FGD flow. EPA also
concluded that plants would optimize the FGD purge flow rate to reduce the flow that must be treated,
and thereby reduce overall O&M compliance costs. As flows are recycled through the FGD system,
chloride concentrations increase; therefore, when calculating an optimized flow rate, EPA considered
plant-specific constraints such as maximum design chloride concentrations and operating chloride
concentrations for the FGD systems.
For the proposed rule, EPA largely used plant-specific FGD wastewater flows consistent with the 2020
rule (U.S EPA, 2020). EPA identified some facilities where changes to plant operations warranted updates
to FGD wastewater flow rates. At plants where some, but not all, EGUs plan to retire or convert fuels
before December 31, 2028, EPA adjusted FGD wastewater flow rates (purge and optimized) to remove
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Section 5—Engineering Costs
flow for these EGUs. Refer to the Flue Gas Desulfurization Flow Methodology for Compliance Costs and
Pollutant Loadings memorandum for a summary of these updates (U.S. EPA, 2023g).
5.1.1.3 Baseline Treatment Technology
For this cost analysis, EPA assumed that plants subject to the FGD wastewater discharge requirements in
the 2020 rule would install the treatment technology basis defined for the 2020 rule. If a plant opted into
the 2020 rule VIP, then EPA assumed membrane filtration as the baseline treatment technology. For all
other FGD wastewater discharges, EPA assumed CP+LRTR baseline treatment technology. Table 8 outlines
the baseline scenarios for the plants included in EPA's 2023 proposal analyses and the corresponding
estimated compliance costs.
Table 8. 2023 Rule Technology Bases
CP+LRTR
VIP
Membrane
filtration
Costs are equal to zero
Costs are equal to zero
All other FGD
wastewater
discharges
CP+LRTR
Costs are equal to zero
Costs for monitoring only
Membrane
filtration
VIP
Membrane
filtration
Costs are equal to zero
Costs are equal to zero
All other FGD
wastewater
discharges
CP+LRTR
Costs for membrane
filtration (no CP costs)
Costs for membrane
filtration minus LRTR (no
CP costs)b
a—EPA did not evaluate costs associated with the 2020 rule FGD high-flow subcategory because the one applicable plant is
scheduled to retire its coal-fired EGUs by December 31, 2028.
b—EPA estimated O&M costs as the incremental costs between operating and maintaining an LRTR system (see Section 5.1.2)
versus operating and maintaining a membrane filtration system (see Section 5.1.3). For the membrane filtration technology
option, EPA assumed plants will stop operating the LRTR portion of the system but continue operating the CP portion as
pretreatment for membrane filtration.
5.1.2 Cost Methodology for LRTR
As described in the RIA, EPA's baseline appropriately includes the costs of achieving the 2020 rule
limitations and standards, and the policy cases show the impacts resulting from changes to the existing
2020 limitations and standards. Therefore, EPA assumed that plants have come into compliance with the
2020 rule; thus, all plants in the proposed rule analysis are assumed to have installed CP+LRTR,
membrane filtration, or equivalent treatment. Since both technology bases include CP, EPA did not
estimate additional compliance costs for CP treatment.
EPA updated the 2020 rule LRTR cost curves by adjusting the cost indexing values to estimate costs in
2021 dollars using data from the RSMeans Historical Cost Index (RSMeans 2018; RSMeans 2021). The
2018 cost index value was 215.8, and the 2021 cost index value was 236.7. EPA multiplied the cost curve
components by the ratio of these indices (the 2021 index divided by the 2018 index equals 1.097),
resulting in the equations presented below. To determine plant-specific nitrate/nitrite concentrations and
consequently which LRTR cost curve to use, EPA used sampling data from the 2015 rule analytical
database (ERG, 2015 and 2015a) and the Steam Electric Survey (U.S. EPA, 2015). Plants with
nitrate/nitrite concentrations above 50 milligrams per liter (mg/L) in untreated FGD wastewater require
nitrate/nitrite pretreatment and are considered "high nitrates."
The resulting adjusted cost curves are as follows:
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Section 5—Engineering Costs
LRTR capital cost - low nitrates (2021$) = 5.69 x FGD flow (GPD) + 4,659,327
LRTR O&M cost - low nitrates (2021$/year) = 0.806 x FGD flow (GPD) + 358,299
LRTR capital cost - high nitrates (2021$) = 6.75 x FGD flow (GPD) + 5,542,021
LRTR O&M cost - high nitrates (2021$/year) = 1.2 x FGD flow (GPD) + 378,901
In addition, as part of the 2020 and 2015 rules, EPA estimated compliance monitoring costs to account
for sampling labor and materials as well as the costs associated with sample preservation, shipping, and
analysis for the pollutants selected for regulation (arsenic, mercury, nitrate/nitrite, and selenium for
CP+LRTR). EPA also updated the compliance monitoring cost to 2021 dollars, resulting in an amount of
$82,936.
EPA estimated CP+LRTR plant-level costs as follows:
• For plants opting in to the 2020 VIP, EPA estimated zero capital and zero O&M costs.
• For all other plants with FGD discharges, EPA estimated capital costs as zero and O&M costs as
compliance monitoring only ($82,936).
5.1.3 Cost Methodology for Membrane Filtration
As with the LRTR cost methodology, EPA did not estimate additional costs for CP pretreatment for the
membrane filtration technology option, as plants are assumed to have come into compliance with the
2020 rule and already have this treatment in place. EPA updated the 2020 rule membrane filtration cost
curves by escalating them to 2021 dollars as described in Section 5.1.2.
The resulting curves are as follows:
membrane filtration capital cost with on-site transport/disposal (2021$) =
43.0 x FGD flow (GPD) + 1,784,805
membrane filtration O&M cost with on-site transport/disposal (2021$/year) =
6.28 x FGD flow (GPD) + 509,287
membrane filtration capital cost with off-site transport/disposal (2021$) =
39 x FGD flow (GPD) + 1,822,650
membrane filtration O&M cost with off-site transport/disposal (2021$/year) =
12.6 x FGD flow (GPD) + 509,585
EPA estimated plant-level membrane filtration costs as follows:
• For plants opting in to the 2020 VIP, EPA estimated zero capital and zero O&M costs.
• For all other plants with FGD discharges, EPA estimated plant-specific capital and O&M costs.
o EPA estimated capital costs for membrane filtration only, using the capital cost equations in
Section 5.1.3 and FGD purge flow rate. To determine which plants have on-site landfills for CCR
material, EPA used data from the Steam Electric Survey and public permit data. All other plants
were assumed to dispose of solids in off-site landfills.
o EPA estimated O&M costs as the difference in costs between LRTR and membrane filtration only.
(All plants are assumed to be currently operating LRTR systems, which they will replace with
membrane systems for this technology option.) To estimate this difference, EPA estimated LRTR
O&M costs using equations in Section 5.1.2 and membrane O&M costs using equations in Section
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Section 5—Engineering Costs
5.1.3, with both using FGD optimized flows. O&M costs for the membrane filtration technology
option were calculated as the difference between LRTR and membrane values.
5.2 BA Transport Water
EPA estimated BA transport water costs for wastewater treatment and pollutant prevention technologies
equivalent to the technology bases defined by the proposed regulatory options. The BA transport water
technology options considered as part of the proposed rule include high recycle rate (HRR) and zero liquid
discharge (ZLD). For the proposed HRR option, EPA estimated costs for mechanical drag system (MDS)
installations and remote MDS installations with a purge. See Section 5.2.1 for the HRR cost methodology.
For the proposed ZLD option, EPA estimated costs for MDS installations and closed loop remote MDS
installations. (A closed loop remote MDS installation includes an RO system to allow complete recycle,
along with return pumps, pipes, and surge tank capacity.) See Section 5.2.2 for the detailed cost
methodology for ZLD.
For the MDS, EPA included costs to replace the existing boiler hopper and associated equipment, and to
install and operate a semi-dry silo for temporary storage of the BA.
For the remote MDS, EPA included the costs to install and operate the following, consistent with the 2020
rule methodology:
• Remote MDS (away from the boiler).
• Sump.
• Recycle pumps.
• Chemical feed system.22
• Semi-dry silo.
For EGUs with low utilization, EPA estimated costs to prepare and implement best management practices
(BMP) plans.23 These costs include the initial development and annual review of a BMP plan to recycle as
much BA transport water as practicable, as well as the capital and O&M costs for pumps and piping
associated with the recycle system.
EPA also included the capital and O&M costs of transporting and disposing of all BA in a landfill for both
technology options considered.
Section 5.1.1 describes the cost inputs for the proposed rule. Sections 5.2.2 and 5.2.3 present EPA's
methodology for estimating costs for HRR and ZLD, respectively.
5.2.1 BA Transport Water Cost Calculation Inputs
To estimate plant-level baseline and post-compliance costs of implementing BA transport water
technologies, EPA developed a cost calculation database. This database uses plant-specific input values
including BA production, current BA handling system details, and information on the use of on-site and
off-site landfills in combination with relationships between costs and EGU capacity or BA generation
described in Sections 5.2.2 and 5.2.3 to estimate baseline and post-compliance costs for each plant (ERG,
22 EPA included costs for a chemical feed system to control pH of the recirculating system to prevent scaling within
the system. Information in the record indicates that few, if any, plants are likely to need such systems. However,
because EPA could not conclusively determine that none would, or which plants would be more likely to need
chemical feed systems, EPA estimated this cost for all plants. This likely overestimates the compliance costs for most
plants; however, the cost for chemical addition is relatively small in relation to other costs for the remote MDS.
23 Applied only to plants with EGUs with a two-year average capacity utilization of less than 10 percent, excluding
plants with a generation capacity less than or equal to 50 MW.
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Section 5—Engineering Costs
2023a). For the proposed rule, EPA used input data compiled from 2015 and 2020 rules—including Steam
Electric Survey data, site visits, sampling episodes, and other industry-provided data—and updated based
on new information gathered from industry and information available from the Department of Energy
and NPDES permits (see Section 2). This section describes the updates to cost inputs from the 2020 rule.
5.2.1.1 Population
EPA identified coal-fired power plants that operate wet BA handling systems and discharge BA transport
water to surface water or a POTW, and that are not expected to retire or convert fuel sources by
December 31, 2028. EPA started with the population of units from the 2020 rule and updated that
population based on new publicly available data on operational changes and industry-provided data.
5.2.1.2 Production Data
For each applicable EGU, EPA estimated the amount of wet BA produced in tons per year (TPY),
generating capacity in megawatts (MW), and net generation in megawatt-hours (MWh). EPA used BA
production and capacity values reported in the Steam Electric Survey as input values for estimating
compliance costs for the final rule. EPA used EGU-level net generation values reported in the 2017 and
2018 EIA data to identify low utilization EGUs.
5.2.1.3 Cost Type Flags
EPA used data from the Steam Electric Survey, site visits, public comments, and other industry sources,
discussed in Section 2, to identify the types of BA handling systems currently operating at each plant. For
each type of BA handling system, EPA determined the equipment or services needed to implement each
technology option. EPA categorized each EGU into the following cost categories:
• Steam electric EGUs equipped with only wet BA handling systems that discharge BA transport water.
• Steam electric EGUs equipped with only wet BA handling systems that discharge BA transport water
and have space constraints preventing the installation of MDSs.
• Steam electric EGUs already operating remote MDSs.
• Steam electric EGUs equipped with only wet BA handling systems that recycle all of their BA sluice,
but can discharge BA transport water from emergency outfalls. EPA defined these as BA management
plants.
• Steam electric EGUs operating dry BA handling systems.
5.2.1.4 Flow Rate
EPA used industry-submitted data, data from public comments, and data from the Steam Electric Survey
(discussed in Section 2) to calculate BA transport water flow rates for baseline conditions and each
technology option evaluated for the proposed rule.
EPA defined the baseline as plants complying with the 2020 rule. For baseline conditions, EPA estimated
BA transport water flow rates for the HRR technology option, which would allow plants to discharge a
portion of their BA transport water. EPA estimated BA transport water flow rates for three compliance
approaches available to most plants:
• Zero flow. For a plant using a dry BA handling system to comply with baseline or a technology option
(e.g., under-boiler mechanical drag system), the discharge flow rate equals zero.
• Purge flow. For each plant using a recirculating BA handling system to comply with baseline or a
technology option (e.g., remote MDS operated with a purge instead of completely closed-loop), EPA
estimated a BA transport water purge flow rate. EPA calculated BA transport water purge flow rates
for remote MDS installations based on a relationship between the plant's generating capacity and the
volume of the total wetted, active components of the remote MDS, consistent with the methodology
40
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Section 5—Engineering Costs
described in Section 5.2.3. Where EPA identified EGUs retiring or converting fuel sources, EPA
adjusted the plant generating capacity to account for changes.
• Sluice flow. For plants using a surface impoundment plus BMP plan to comply with baseline (per the
2020 rule), EPA identified one plant in the low utilization subcategory for which the discharge flow
rate would equal the plant's BA sluice flow.
5.2.1.5 Baseline Treatment Technology
For this cost analysis, EPA assumed that plants subject to the BA transport water discharge requirements
in the 2020 rule would install the treatment technology basis defined for the 2020 rule and any applicable
subcategories (i.e., baseline). For baseline and regulatory options costs, EPA accounted for updates to the
industry profile including retirements and NOPPs through January 2022. Table 9 outlines the baseline
scenarios for the plants included in EPA's 2023 proposal analyses and the corresponding estimated
compliance costs. Baseline assumptions for BA transport water account for the CCR Part A rule (40 CFR
257).
Table 9. 2023 Rule Technology Bases
202
Technc
Opti<
Evalua
3
logy
an
ted
2020 Rule
Subcategory
2023 Baseline
Treatment
Technology
Estimated
Incremental Capital
Compliance Cost
Estimated
Incremental O&M
Compliance Cost
HRR
All other BA
discharges
Dry handling or HRR
system
Costs are equal to
zero
Costs are equal to
zero
Low utilization
boilers: all EGUs
have 24-month
average utilization <
10%
Surface
impoundment +
BMP plan
Costs for
MDS/remote MDS
with purge
Costs for
MDS/remote MDS
with purge
ZLD
All other BA
discharges
Dry handling or HRR
system
Costs for RO
Costs for RO
Low utilization
boilers: All EGUs
have 24-month
average utilization <
10%
Surface
impoundment +
BMP plan
Costs for
MDS/remote MDS
with purge
Costs for
MDS/remote MDS
with purge
EPA identified eight EGUs from five plants as BA management. EPA assumed, based on information from the Steam Electric
Survey, that these plants have retained the capability to discharge BA transport water only from emergency outfalls but generally
operate as closed-loop systems.
5.2.2 Cost Methodology for HRR
As described in the RIA, EPA's baseline appropriately includes the costs of achieving the 2020 rule
limitations and standards, and the policy cases show the impacts resulting from changes to the existing
2020 limitations and standards. Therefore, EPA assumed that plants in compliance with the 2020 rule will
have installed MDS or remote MDS and therefore are estimated to incur zero costs to comply with
proposed HRR technology options. EPA compared the costs of installing an MDS and a remote MDS for
each plant and chose the least cost option as the technology basis for HRR. EPA calculated plant-specific
MDS and remote MDS compliance costs for the 2023 proposal EGU-level BA generation and/or EGU
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Section 5—Engineering Costs
capacity.24 EPA updated the 2020 rule cost curves by escalating them to 2021 dollars as described in
Section 5.1.2. The recurring expenses for MDS and rMDS installations account for the cost for chain
replacement that may be needed every three and five years, respectively. To estimate plant-level costs,
EPA first calculated the capital and O&M costs at the EGU-level, using the following curves:
EGU MDS capital cost (2021$) = (39,288 x [MW]) + 5,499,451
MDS annual O&M cost (2021$/year) = (18.823 x [TPY]) + 575,891
MDS three-year recurring O&M cost (2021$) = $225,767
EGU remote MDS capital cost (2021$) = [(28,787 x [MW]) + 3,784,115] + building cost
remote MDS annual O&M cost (2021$/year) = (19.385 x [TPY]) + 855,210
remote MDS five-year recurring O&M cost (2021$) = $225,767
EPA added surface impoundment cost savings to the MDS and remote MDS capital and O&M EGU-level
costs. Consistent with the 2020 rule methodology, EPA used Steam Electric Survey data to identify plants
that have at least one impoundment containing BA transport water and not designated as retired or
planned. Where EPA had data indicating plants had installed dry or HRR BA handling systems since the
2020 rule, EPA assumed these plants would opt to no longer operate impoundments for BA handling,
resulting in surface impoundment cost savings. EPA also assumed that plants whose impoundments are
expected to close due to CCR Part A rule requirements would no longer use impoundments for BA
handling, resulting in surface impoundment cost savings. EPA estimated plant-level cost savings for no-
longer-operating impoundments based on the total amount of BA solids currently handled wet at the
plant. EPA updated the 2020 rule BA impoundment O&M cost savings by escalating them to 2021 dollars
as described in Section 5.1.2.
total BA impoundment O&M cost savings (2021$/year) =
(BA impoundment operating cost savings + BA earthmoving cost savings)
Where:
BA impoundment operating cost savings = Total impoundment operating cost savings.
BA earthmoving cost savings = O&M cost associated with the earthmoving equipment
savings.
EPA estimated the BA impoundment operating cost savings by first calculating the plant MW factor and
the plant-specific unitized cost.
plant MW factor = 7.569 x (plant size)"0,32
Where:
Plant size = Plant size in MW (the plant nameplate capacity for only those EGUs in the BA costed
population).
24 EPA identified two plants that submitted NOPPs for the low utilization subcategory. EPA used only on-site cost
equations from the 2020 rule, as Whitewater Valley and PSNH-Merrimack Station both have landfills containing CCR
on-site and are expected to dispose of solids on-site.
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Section 5—Engineering Costs
plant-specific unitized cost = (impoundment operating unitized cost) x (plant MW factor)
Where:
plant-specific unitized cost = Plant-specific cost to operate a front-end loader (in
2021$/ton).
impoundment operating unitized cost = 2010 unitized annual cost to operate a combustion residual
impoundment. EPA used the unitized cost value of $8.06 per
ton (in 2021$).
plant MW factor = Factor to adjust combustion residual handling costs based on
plant capacity
Next, EPA calculated the BA impoundment operating cost savings by multiplying the plant-specific
unitized cost by the amount of BA produced by the plant, in tons per year TPY.
BA impoundment operating cost savings (2021$/year) =
(plant-specific unitized cost) x (plant BA tonnage)
Where:
plant-specific unitized cost = Plant-specific cost to operate a front-end loader (in 2021$/ton).
plant BA tonnage = Total BA tonnage, dry basis, for each plant (in TPY). EPA calculated this
value by multiplying the wet BA generation rate (in TPY) for each EGU,
then summing the EGU-level values to the plant level.
To calculate BA earthmoving cost savings, EPA first calculated the plant-specific front-end loader unitized
cost by multiplying the plant MW factor and the front-end loader unitized cost.
plant-specific front-end loader unitized cost (2021$/ton) =
(front-end loader 2010 unitized O&M cost) x (plant MW factor)
Where:
front-end loader 2021 unitized O&M Cost = 2010 unitized cost value that represents the O&M of the
front-end loader used to redistribute ash at an
impoundment. EPA calculated this value to be $2.73 per
ton (in 2021$).
plant MW factor = Factor to adjust combustion residual handling costs based
on plant capacity.
Next, EPA calculated the BA earthmoving cost savings by multiplying the plant-specific unitized cost by
the amount of BA tonnage produced by the plant in TPY.
BA impoundment earthmoving cost savings =
(plant-specific front-end loader unitized cost) x (plant BA tonnage)
Where:
plant-specific front-end loader unitized cost = Plant-specific cost value that represents the O&M of
the front-end loader used to redistribute ash at an
impoundment.
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Section 5—Engineering Costs
plant BA tonnage
Total BA tonnage, dry basis, for each plant (in TPY). EPA
calculated this value by multiplying the wet BA
generation rate in TPY for each EGU, then summing the
EGU-level values to the plant level.
EPA calculated 10-year recurring costs associated with operating the earthmoving equipment (i.e., front-
end loader) using the estimated cost and average expected life of a front-end loader. EPA determined the
cost of the earthmoving equipment to be $520,000 (2021$) and assumed an expected life of 10 years.
EPA then summed the MDS and remote MDS EGU-level costs to the plant level. EPA also added a plant-
level capital cost of $1,146,630 (2021$) to build a roof over the remote MDS to mitigate stormwater
contributions to the system. This additional roof cost was applied at the plant level because a plant would
likely use one roof to cover the entire fleet of remote MDS installations. O&M costs for the roof were
assumed to be zero, as the structure is only intended to protect from stormwater and does not have
heating, ventilation, or air conditioning (HVAC).
EPA estimated HRR plant-level costs using the following assumptions:
• EPA identified two plants, Whitewater Valley (Plant ID 3024) and PSNH-Merrimack Station (Plant ID
3095), that submitted NOPPs for the low utilization subcategory. For these plants, estimated capital
costs are equal to MDS or remote MDS with purge. EPA estimated HRR O&M costs using equations in
Section 5.2.2.
• For all other plants with BA discharges, EPA estimated zero capital and zero O&M costs.
5.2.3 Cost Methodology for ZLD
EPA estimated costs to treat a BA transport water purge stream using a high-pressure RO system to
remove dissolved solids and facilitate complying with a zero-discharge standard. Based on information
provided by industry (expressing concerns about potential adverse consequences associated with long-
term closed-loop operation of a remote MDS), and consistent with EPA's purge allowance described in
the preamble to the 2020 rule, EPA conservatively assumed a daily purge rate equal to 10 percent of the
total estimated BA transport system volume (i.e., the plant-level volume associated with the BA hoppers,
remote MDS, sluice pipes, and surge tanks), excluding redundant spare systems, maintenance tanks, and
similar infrequently used equipment. Permeate from the RO system would be recycled back into the
remote MDS while the RO reject, or brine, would be transported to a centralized waste treatment (CWT)
facility for disposal. EPA also assumed that managing the remote MDS as a zero-discharge system may
require additional surge tank capacity to hold BA hopper water during maintenance activities. These
additional costs associated with zero-discharge operation were calculated at the plant level because one
RO system can treat the remote MDS slipstream from all remote MDSs operating at the plant.
For plants identified as likely to install remote MDSs to comply with the 2020 rule or the CCR Part A rule
requirements, EPA added capital costs for RO, surge tank, pipe, and pump to the plant-level total remote
MDS capital cost described in Section 5.2.2. EPA added O&M costs for the additional equipment and
transportation and disposal costs of the RO brine to the remote MDS O&M cost described in Section 5.2.2
to estimate the total cost for a zero-discharge remote MDS. For plants identified as having installed
remote MDSs to comply with the 2020 rule, EPA assumed the additional capital and annual O&M costs
associated with treating a remote MDS slipstream with RO would be the only incremental costs incurred
to operate the system as zero discharge.
To estimate the RO capital and O&M costs, EPA used cost curves from the 2020 rule and escalated them
to 2021 dollars as described in Section 5.1.2.
EPA first estimated the total remote MDS volume based on information provided by equipment vendors
knowledgeable on boiler configurations (including ash hopper volumes) and remote MDS configurations
and sizes. For plant-level capacities less than or equal to 200 MW, EPA assumed the total remote MDS
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Section 5—Engineering Costs
volume is 175,000 gallons based on data provided by vendors and best professional judgement (ERG,
2019b). For plant-level capacities greater than 200 MW, EPA used the following equation, developed
from industry-level data on remote MDS installations, to estimate the total system volume (ERG, 2019b).
total remote MDS volume (gallons) = (347.29 x plant-level capacity) + 146,398
Where:
plant level capacity = Sum of EGU capacities (MW) flagged for BA compliance costs.
Based on the estimated total remote MDS volume, EPA calculated the slipstream flow rate in gallons per
minute (GPM) as follows:
slipstream flow (GPM) = (total remote MDS volume x 0.1/day) -f 1,440 minutes/day
Where:
Total remote MDS volume = Total volume of all remote MDS expected to be operating at the plant
(in gallons).
EPA developed a relationship between total RO capital cost and purge flow, based on data collected from
wastewater treatment vendors and best professional judgement (ERG, 2019b). The RO capital cost curve
(equation shown below) was used to estimate EGU-level capital costs for RO treatment of the remote
MDS slipstream.
RO capital cost (2021$) = (64,545 x slipstream flow) + 2,521,619
EPA developed a relationship between annual O&M cost and purge flow, based on data collected from
wastewater treatment vendors (ERG, 2019b). The RO O&M cost curve (equation shown below) was used
to estimate plant-level annual O&M costs for RO treatment of a BA transport water slipstream from the
remote MDS.
RO O&M cost (2021$) = $0.01097 x slipstream flow x 60 minutes/hour
x 24 hours/day x 365 days/year
EPA calculated capital costs for the surge tank. EPA assumed that only one EGU will need to empty the BA
hopper at any one time; therefore, EPA developed a relationship between tank size and the capacity of
the largest EGU at the plant (defined by capacity in MW) derived from information received by the
industry and vendors (ERG, 2019b).
Once the EGU with the largest nameplate capacity (MW) was identified, EPA calculated the size of the
surge tank in gallons. EPA accounted for an additional 50 percent capacity for the surge tank by
multiplying the relationship by a tank sizing factor (1.5).
tank size (gallons) = 63 x EGU capacity x tank sizing factor
Where:
EGU capacity = Capacity of the EGU (MW).
tank sizing factor = 1.5.
EPA then estimated the cost as a function of tank size based on information provided by vendors during
the 2015 rule. For tanks smaller than 50,000 gallons:
tank capital cost (2021$) = [(2.369 x tank size) + 24.9 x (tank size x 1.65)0548]
45
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Section 5—Engineering Costs
Where:
tank size = Size of the surge tank (in gallons).
For tanks larger than 50,000 gallons:
tank capital cost (2021$) = [(3.78 x tank size) + 24.9 x (tank size x 1.65)0,548]
Where:
tank size = Size of surge tank (in gallons).
EPA estimated the purchased equipment capital costs for the piping and pumps using the methodology
for the FGD wastewater recycle piping and wastewater forwarding pumps (to return wastewater back to
the scrubber). EPA then calculated the pump as a function of this flow using cost information provided by
vendors duringthe 2015 rule.
pump capital cost (2021$) = [3,227 x In (1.61 x flow) - 3,389.8] x 4.56
Where:
flow = Daily flow rate from the surge tank (in GPM assuming discharge over five hours).
EPA estimated the capital cost of 2,640 feet of piping using an assumed distance of 0.25 miles between
the surge tank and the BA hopper, based on EPA's best professional judgement and information from BA
handling vendors about remote MDS placement at a plant, and costs data provided by pipe vendors for
the 2015 rule: $41,000 (2021$).
EPA estimated the direct capital costs by multiplying the sum of the purchased equipment costs for the
tank, pumps, and piping (i.e., the total purchased equipment cost) by 2. EPA used this relationship to
account for delivery of purchased equipment, installation of purchased equipment, instrumentation and
controls, piping and electrical, service facilities, building services, and land if purchase is required.
direct capital costs = 2 x total purchased equipment cost
EPA then estimated the indirect capital costs by multiplying the sum of the total purchased equipment
and direct capital costs by 0.43. EPA used this relationship to account for engineering and supervision,
construction expenses, contractor's fees, and contingency.
indirect capital costs = 0.43 x (total purchased equipment cost + direct capital costs)
Finally, EPA estimated total capital costs by summing the total purchased equipment, direct, and indirect
capital costs.
total capital costs = total purchased equipment cost + direct capital costs + indirect capital costs
EPA calculated plant-level O&M costs associated with operating the surge tank, pumps, and pipe. Total
O&M costs include the energy cost associated with operating the pumps and the maintenance cost
associated with the surge tank, pumps, and pipes.
total tank/pump/pipe O&M costs = energy cost + maintenance cost
To calculate the energy cost, EPA estimated the annual energy requirement to operate the pumps, based
on the 2015 rule cost methodology.
annual energy requirement (kWh/year) = (0.02219 x flow + 2.019) x 17.89
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Section 5—Engineering Costs
Where:
Flow = Daily flow rate from the surge tank (in GPM assuming discharge over 5 hours).
EPA estimated the cost of operating the pumps using the pump energy requirement and the national
energy cost per kWh, based on data reported by the U.S. EIA (U.S. DOE, 2011), in 2021 dollars.
energy cost (2021$) = national energy cost x annual energy requirement
Where:
national energy cost = ($0.0485/kWh x 1.097) (in 2021$).
annual energy requirement = Annual energy requirement to operate pumps (in kWh/year).
For the 2015 rule, EPA developed a relationship between BA slipstream flow and the cost to maintain the
surge tank, pumps, and piping to estimate the total maintenance costs.
maintenance cost (2021$) = 457 x flow
Where:
Flow = Daily flow rate from the surge tank (in GPM assuming discharge over 5 hours).
To estimate costs for transportation and disposal of the RO brine, EPA calculated O&M costs associated
with hauling the brine off site to a CWT and the costs incurred for using a CWT.
EPA calculated brine flow rate based on the average recovery from the membrane treatment vendors
used for FGD wastewater.
brine flow = 0.30 x purge flow
EPA estimated the weight of the brine based on the weight of the solids in the brine and the weight of the
water. Solids in the brine were estimated based on the average total suspended solids (TSS)25
concentration in BA transport water for the entire purge flow (this assumes that all suspended solids from
the BA purge will be retained in the brine, which is likely an overestimate).
annual brine solids (tons/year) = BA purge (GPD) x average TSS concentration x 3.78 L/gal x 0.001 g/mg x
(1.102 x 10~6 tons/g) x 365 days per year
Where:
BA purge = 10 percent of the total BA system volume in GPD.
average TSS concentration = Average TSS concentration in BA transport water (see Table 6-2 of the
Supplemental TDD), 13.4 mg/L.
annual brine water weight (TPY) = brine flow (GPD) x 0.00417 tons/gal x 365 days per year
EPA calculated the total weight of brine to be disposed of annually as the sum of the brine solids and the
water weight.
annual brine weight (tons/year) = annual brine solids + annual brine water weight
25 EPA expects to update the average TSS concentration with average TDS concentration (1,290 mg/L TDS) for future
cost analyses. This would affect the brine annual transportation and disposal cost by less than one percent.
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Section 5—Engineering Costs
EPA estimated the annual cost of transporting brine solids to a CWT facility using the 2015 methodology
for off-site transportation, which is based on transportation of solids to an off-site location 25 miles from
the plant.
transportation cost (2021$) = annual brine weight x $10.10 per ton
EPA estimated disposal costs using data compiled as part of the rulemaking establishing pretreatment
standards for Oil and Gas Extraction, Subpart C (i.e., onshore unconventional oil and gas). Wastewater
management using a CWT for total dissolved solids (TDS) removal ranged from $3 to $11 per barrel (U.S.
EPA, 2016). Using the average value of $7 per barrel, EPA estimated disposal cost at a CWT of
$0.167/gallon (2005$), which escalated to $0.183/gallon in 2021$. Annual disposal costs were estimated
using the following equation:
disposal cost (2021$) = brine flow (GPD) x $0.183/gallon
To estimate the annual cost for brine transportation and disposal, EPA summed the transportation and
disposal costs.
brine T&D annual cost = transportation cost + disposal cost
EPA estimated ZLD plant-level costs according to the following assumptions:
• For plants opting in to the low utilization subcategory, EPA estimated costs equal to an MDS or a
remote MDS with a purge. For a plant to achieve ZLD, the steps outlined in Section 5.2.3 must be
added to the plant's overall cost calculation from Section 5.2.2.
• For all other plants with BA discharges, EPA estimated costs equal to the addition of an RO system
only.
5.3 Combustion Residual Leachate
For the proposed rule, EPA estimated costs for plants to install and operate CP treatment of CRL. EPA
included the following treatment components for CRL:
• CP treatment equipment (equalization and storage tanks, pumps, reaction tanks, solids-contact
clarifier, and gravity sand filter).
• CP chemical feed systems for lime, organosulfide, ferric chloride, and polymers.
• CP solids-contact clarifier to remove suspended solids.
• Mercury analyzer.
• Compliance monitoring (including sample collection and analysis).
• Solids handling (sludge holding tank and filter press).
• Transportation and disposal of solids in a landfill.
Section 5.3.1 describes the process for developing the CRL cost calculation inputs.
As described in Section 3.2.3, EPA also notes that unlined landfills and surface impoundments potentially
discharge CRL through groundwater before entering surface water. To evaluate the potential costs and
loads of such discharges, EPA conducted a sensitivity analysis documented in its memorandum Evaluation
of Potential CRL in Groundwater (U.S. EPA, 2023a).
5.3.1 CRL Cost Calculation Inputs
To estimate plant-level baseline and post-compliance costs of implementing CRL treatment technologies,
EPA developed a cost calculation database. This database uses plant-specific input values including CRL
48
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Section 5—Engineering Costs
flow and existing treatment in combination with relationships between costs and CRL flow rates
described in Section 5.3.2 to estimate baseline and post-compliance costs for each plant (ERG, 2023b).
For this proposal, EPA started with input data from the 2015 rule, including the Steam Electric Survey, and
then updated the data with other publicly available data described in Section 2. This section describes the
cost inputs.
5.3.1.1 Population
EPA identified the population of landfills containing combustion residuals that collect and discharge
leachate to surface waters or POTWs using data from the Steam Electric Survey (U.S. EPA, 2015). EPA
updated this population to reflect recent changes to the profile of steam electric power plants. After
removing plants where all EGUs will be retired by December 31, 2023, EPA added plants that have
constructed new landfills since 2015 using data from utilities' "CCR Rule Compliance Data and
Information" websites.
For each new landfill, EPA used data from the Steam Electric Survey to identify the most appropriate
discharge location and receiving water. Where a plant reported all discharges to a single receiving water
(i.e., all outfalls discharge to the same waterbody), EPA used this receiving water. Where a plant reported
discharges to multiple waterbodies, EPA evaluated outfall data and water balance diagrams to identify
the most appropriate receiving water for leachate.
5.3.1.2 Flow Rate
EPA used the methodology described in Section 9.4.1 of the 2015 TDD to estimate CRL flow rates. Where
information on leachate flow rate was available in the Steam Electric Survey, EPA used this value. Where
landfill size (acreage) information was available in the Steam Electric Survey, EPA estimated that plants
collect leachate from 75 percent of the total acreage for active landfills and 5 percent of the total acreage
for inactive landfills. EPA also used survey data to estimate the leachate flow based on this landfill size.
For active landfills:
leachate flow (GPD) = 887 x 0.75 x leachate acreage
For inactive landfills:
leachate flow (GPD) = 887 x 0.05 x leachate acreage
Where no leachate flow or landfill size information was available, EPA used the median leachate volume
from the Steam Electric Survey, 46,160 gallons per day.
5.3.1.3 Treatment-in-Place Data
In 2015, EPA identified one plant currently operating a biological treatment system to treat landfill
leachate (combined with FGD wastewater) and one plant building a biological treatment system to treat
its combustion residual landfill leachate. In 2020, EPA also identified one plant currently operating a
thermal treatment system to treat landfill leachate (combined with FGD wastewater) (ERG, 2020e). EPA
did not identify any other plants with treatment in place for the proposed rule.
5.3.2 Cost Methodology for CP
To estimate CP costs for CRL, EPA used cost data from the 2015 and 2020 rules for CP as stand-alone
treatment for FGD wastewater. Starting with the capital and O&M cost curves presented in Section 5.2.2
of the 2020 TDD, EPA sized the treatment system for leachate flows (rather than FGD flows). EPA used
only cost curves for on-site transportation and disposal, as all plants with leachate have landfills. EPA
updated the 2020 rule cost curves by escalating them to 2021 dollars as described in Section 5.1.2.
EPA used the following cost curves to estimate CP capital and O&M costs:
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Section 5—Engineering Costs
CP capital costs (2021$) = 38.35 x leachate flow + 7,724,092.2
CP O&M costs (2021$/year) = 4.4385 x leachate flow + 251,880
The CP system includes an in-line mercury analyzer. This process control mechanism has an expected life
of six years. EPA estimated this six-year recurring cost to replace the mercury analyzer using costs
originally obtained for the 2015 rule and escalating them to 2021 dollars: $110,039 (2021$).
Where existing treatment of leachate was identified, EPA estimated no additional capital costs or
recurring costs, but estimated O&M costs equal to $80,739 to account for compliance monitoring of the
treated effluent. Compliance monitoring includes sampling labor and materials as well as the costs
associated with sample preservation, shipping, and analysis for the pollutants selected for regulation
(arsenic and mercury).
5.4 Summary of National Engineering Costs for Regulatory Options
To estimate total industry compliance costs for each regulatory option, EPA first estimated plant-level
FGD wastewater, BA transport water, and CRL compliance costs (as described in Sections 5.1, 5.2, and
5.3) for all technologies evaluated. Next, EPA estimated EGU-level costs (including capital, O&M, one-
time, 5-, 6-, and 10-year recurring costs) using the equation below.
EGU-level cost = plant-level cost x (EGU-level capacity -f plant-level capacity)
Where:
plant-level cost = Technology option plant-level cost in 2021$. Includes capital, O&M, one-time, and
recurring costs.
EGU-level capacity = EGU-level generating nameplate capacity in MW (from the Steam Electric Survey
and 2018 Form EIA-860 data for new EGUs).
plant-level capacity = Plant-level generating nameplate capacity in MW (from Form EIA-860 data for
2020).
For each EGU, EPA chose the appropriate technology cost to coincide with the regulatory option being
evaluated. See the preamble for details on the combinations of wastestreams and treatment
technologies based on the regulatory option. EPA then summed the EGU-level costs for only those EGUs
included in each regulatory option to estimate total industry-level regulatory option costs. See the
Generating Unit-Level Regulatory Option Costs and Loads Memorandum for the details by EGU on
technologies selected for each regulatory option and estimates of compliance costs (U.S. EPA, 2023h).
Table 10, Table 11, and Table 12 present the total industry compliance cost estimates for FGD
wastewater, BA transport water, and CRL, respectively, by regulatory option. For each wastestream, the
number of plants incurring costs is also included for each evaluated option. Table 13 presents the
aggregated, industry-level compliance costs by regulatory option. All cost estimates are expressed in pre-
tax 2021 dollars and represent costs that would be incurred once all plants and EGUs achieve compliance
with the regulatory option presented. Values presented in this document do not account for the timing or
exact date of implementation (e.g., when costs are incurred by the industry).
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Section 5—Engineering Costs
Table 10. Estimated Cost of Implementation for FGD Wastewater by Regulatory Option (in Millions
of Pre-tax 2021 Dollars)
Regulatory
Option
Number of
Plants
Capital
Cost
Annual
O&M Cost
One-time
Costs
5-Year
Recurring
Cost
6-Year
Recurring
Cost
10-Year
Recurring
Cost
Baseline
29
$0
$0
$0
NA
NA
NA
1
29
$0
$0
$0
NA
NA
NA
2
29 a
$547
$47.0
$2.51
NA
NA
NA
3
29 b
$547
$47.0
$2.85
NA
NA
NA
4
29 c
$604
$53.4
$0
NA
NA
NA
Note: Costs and savings are rounded to three significant figures.
NA: Not applicable.
a - Seven of these plants incur zero cost, resulting in 22 plants with non-zero estimated costs for implementation of Regulatory
Option 2.
b - Seven of these plants incur zero cost, resulting in 22 plants with non-zero estimated costs for implementation of Regulatory
Option 3.
c - Three of these plants incur zero cost, resulting in 26 plants with non-zero estimated costs for implementation of Regulatory
Option 4.
Table 11. Estimated Cost of Implementation for BA Transport Water by Regulatory Option (in
Millions of Pre-tax 2021 Dollars)
Regulatory
Option
Number
of Plants
Capital Cost
Annual
O&M Cost
One-time
Costs
5-Year
Recurring
Cost
6-Year
Recurring
Cost
10-Year
Recurring
Costa
Baseline
42
$0
$0
NA
$0
NA
$0
1
42 b
$21.9
$1.97
NA
$0,451
NA
($0,520)
2
42 b
$21.9
$1.97
NA
$0,451
NA
($0,520)
3
42 c
$257
$27.3
NA
$0
NA
$0
4
42 d
$263
$27.9
NA
$0
NA
$0
Note: Costs and savings are rounded to three significant figures.
NA: Not applicable.
a -The values in this column are negative and presented in parentheses because they represent cost savings,
b - 41 of these plants incur zero cost, resulting in one plant with non-zero estimated costs for implementation of Regulatory
Options 1 and 2.
c - Seven of these plants incur zero cost, resulting in 35 plants with non-zero estimated costs for implementation of Regulatory
Option 3.
d - Six of these plants incur zero cost, resulting in 36 plants with non-zero estimated costs for implementation of Regulatory
Option 4.
Table 12. Estimated Cost of Implementation for Combustion Residual Leachate by Regulatory
Option (in Millions of Pre-tax 2021 Dollars)
Regulatory
Option
Number of
Plants
Capital
Cost
Annual
O&M Cost
One-time
Costs
5-Year
Recurring
Cost
6-Year
Recurring
Cost
10-Year
Recurring
Cost
Baseline
69
$0
$0
NA
NA
$0
NA
1
69
$747
$43.5
NA
NA
$7.37
NA
2
69
$747
$43.5
NA
NA
$7.37
NA
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Section 5—Engineering Costs
Table 12. Estimated Cost of Implementation for Combustion Residual Leachate by Regulatory
Option (in Millions of Pre-tax 2021 Dollars)
Regulatory
Option
Number of
Plants
Capital
Cost
Annual
O&M Cost
One-time
Costs
5-Year
Recurring
Cost
6-Year
Recurring
Cost
10-Year
Recurring
Cost
3
69
$747
$43.5
NA
NA
$7.37
NA
4
69
$747
$43.5
NA
NA
$7.37
NA
Note: Costs and savings are rounded to three significant figures.
NA: Not applicable.
Table 13. Estimated Cost of Implementation by Regulatory Option (in Millions of Pre-tax 2021
Dollars)
Regulatory
Option
Number of
Plants
Capital
Cost
Annual
O&M Cost
One-time
Costs
5-Year
Recurring
Cost
6-Year
Recurring
Cost
10-Year
Recurring
Cost3
Baseline
97
$0
$0
$0
$0
$0
$0
1
97 b
$768
$45.5
$0
$0,451
$7.37
($0,520)
2
97 c
$1,320
$92.5
$2.51
$0,451
$7.37
($0,520)
3
97 d
$1,550
$118
$2.85
$0
$7.37
$0
4
97 e
$1,610
$125
$0
$0
$7.37
$0
Note: Costs and savings are rounded to three significant figures.
NA: Not applicable.
a -The values in this column are negative and presented in parentheses because they represent cost savings,
b - 28 of these plants incur zero cost, resulting in 69 plants with non-zero estimated costs for implementation of Regulatory
Option 1.
c - 19 of these plants incur zero cost, resulting in 78 plants with non-zero estimated costs for implementation of Regulatory
Option 2.
d - Six of these plants incur zero cost, resulting in 91 plants with non-zero estimated costs for implementation of Regulatory
Option 3.
e - Five of these plants incur zero cost, resulting in 92 plants with non-zero estimated costs for implementation of Regulatory
Option 4.
52
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6. Pollutant Loadings and Removals
This section describes the annual pollutant discharge loading estimates for the steam electric power
generating industry and pollutant loading removal estimates associated with the proposed rule. Estimates
for the 2023 proposed rule build on the pollutant loadings and removals calculations for regulated
wastestreams from the 2015 and 2020 rules. Section 10 of the 2015 Technical Development Document
(2015 TDD) includes pollutant loadings and removals estimates for flue gas desulfurization (FGD)
wastewater, bottom ash (BA) transport water, and combustion residual leachate (CRL) (U.S. EPA, 2015a).
Section 6 of the 2020 rule TDD estimates FGD wastewater and BA transport water pollutant removals as
the change in loadings from the 2015 to the 2020 regulatory requirements. For this 2023 proposed rule,
EPA estimated pollutant loadings and removals for the three wastestreams for which this proposal is
establishing new requirements (FGD wastewater, BA transport water, and CRL). EPA evaluated loadings
and removals for the same industry population for which EPA estimated regulatory compliance costs
(refer to Section 5 for the industry population evaluated for this proposal). EPA estimated baseline and
post-compliance pollutant loadings and pollutant removals as follows:
• Baseline loadings. Pollutant loadings, in pounds per year, in wastewater discharged to surface water
or through publicly owned treatment works (POTWs) to surface water under 2020 final rule
conditions. For FGD wastewater and BA transport water, baseline loadings characterize wastewater
discharged from plants assumed to be in full compliance with the requirements of the 2020 rule; for
CRL, baseline loadings characterize current discharges.
• Post-compliance loadings. Pollutant loadings, in pounds per year, in wastewater discharged to surface
water or through POTWs to surface water after full implementation of the 2023 proposed rule
technology options. EPA estimated post-compliance pollutant loadings with the expectation that all
steam electric power plants subject to the requirements of the proposed rule will install and operate
wastewater treatment and pollution prevention technologies equivalent to the technology bases for
the regulatory options.
• Pollutant removals. The difference between the baseline loadings and post-compliance loadings for
each regulatory option.
This section describes EPA's methodology for estimating plant-specific pollutant loadings and removals as
well as industry-level results for each of the 2023 proposed regulatory options:
• General methodology for estimating pollutant removals (Section 6.1).
• FGD wastewater (Section 6.2).
• BA transport water (Section 6.3).
• CRL (Section 6.4).
• Summary of industry-level baseline and regulatory option loadings and removals (Section 6.5).
6.1 General Methodology
For each plant discharging FGD wastewater, BA transport water, and/or CRL, EPA estimated plant-level
baseline loadings and post-compliance loadings and removals for each of the technology options
described in Section 5. EPA used sampling data collected in support of the 2015 rule and 2020 rule to
characterize baseline and post-compliance pollutant concentrations, including data from EPA's sampling
program (described in Section 3 of the 2015 TDD), the Steam Electric Survey, public comments, industry
submissions, and publicly available data sources. EPA evaluated these data sources to identify analytical
data that meet EPA's acceptance criteria for inclusion in analyses for characterizing discharges of FGD
wastewater, BA transport water, and CRL. EPA's acceptance criteria include:
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Section 6—Pollutant Loadings and Removals
• Sample locations must be unambiguous and clearly described such that the sample can be
categorized by wastestream and level of treatment (e.g., untreated, partially treated).
• Analytical data must provide sufficient information to identify units of measure and determine
usability in EPA's analyses.
• Analytical data must represent individual sample results, rather than average results for multiple
plants or long-term averages for single plants.26
• Analytical data must not be duplicative of other accepted data.
• Sample analyses must be performed using accepted analytical methods.
• Nondetect results are not acceptable if no detection or quantitation limit is provided.
• Sample results must represent total results for a pollutant (i.e., dissolved results are not acceptable
except for total dissolved solids).
• For biphasic samples, sample results must include both phases.
To ensure analytical data were representative, EPA excluded data that did not meet the acceptance
criteria as they were not fit for use in estimating pollutant loadings. Sections 6.2.2, 6.3.2, and 6.4.2
describe additional wastestream-specific data acceptance criteria and present the average discharge
pollutant concentrations used to estimate baseline and post-compliance loadings for FGD wastewater, BA
transport water, and CRL, respectively.
First, EPA calculated baseline loadings and post-compliance loadings for each plant using the plant-
specific wastewater flow for the wastestream (as described in Section 5) and average pollutant
concentrations for the specific wastestream using the following equation:
Loadingpoiiutant (lb/year) = flow rate x discharge days x Concpoiiutantx (2.20462 lb/109 ng) x (1,000 L/264.17
gallons)
= Reported flow rate of the waterstream being discharged, in gallons per day,
from the plant
= number of days per year the waterstream is discharged from the plant.
= Concentration of a specific pollutant in the wastestream, in micrograms per
liter (ng/L). Refer to Table 15 for FGD wastewater, Table 16 for BA transport
water, and Table 17 for CRL.
EPA identified several plants that reported transferring wastewater to POTWs rather than directly
discharging to surface waters. For these plants, EPA adjusted the baseline and post-compliance loadings
to account for pollutant removals expected during treatment at a well-operated POTW for each pollutant,
shown in Table 14. EPA used the following equation to adjust baseline and post-compliance loading
estimates for each pollutant to account for removals achieved by the POTW:
Loadingpoiiutantjndirect (lb/year) = Loadingpoiiutant x (1 - (RemovalPOTw/100))
Where:
Loadingpoiiutant = Estimated pollutant loading from a specific pollutant if it was being discharged directly
to surface water, in pounds peryear.
26 Where individual sample results and plant-level average sample concentrations were both available for a data set,
EPA preferentially used the individual sample results.
Where:
Flow rate
Discharge days
ConCpollutant
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Section 6—Pollutant Loadings and Removals
Removalpojw = Estimated percentage of the pollutant loading that would be removed by a POTW (see
Table 14).
Finally, EPA calculated pollutant removals (i.e., the change in pollutant loadings) for each plant by
subtracting the baseline loadings from the post-compliance loadings, as shown in the following equation:
Removalpoiiutant (lb/year) = Loadingp0st-compiiance - Loadingbaseiine
Where:
Loading post-compliance = Estimated pollutant loading discharged for a specific pollutant for the post-
compliance technology option, in pounds per year (accounting for removals
achieved by POTWs where appropriate).
Loadingbaseiine = Estimated pollutant loading discharged for a specific pollutant for the baseline
technology option, in pounds per year (accounting for removals achieved by
POTWs where appropriate).
Table 14. POTW Removals
Pollutant
Median POTW Removal Percentage
Aluminum
91.0%
Ammonia
39.0%
Antimony
66.8%
Arsenic
65.8%
Barium
55.2%
Beryllium
61.2%
Biochemical oxygen demand
NA
Boron
NA
Cadmium
90.1%
Calcium
NA
Chemical oxygen demand
NA
Chloride
NA
Chromium
80.3%
Hexavalent chromium
NA
Cobalt
10.2%
Copper
84.2%
Cyanide, total
NA
Iron
NA
Lead
77.5%
Magnesium
NA
Manganese
40.6%
Mercury
90.2%
Molybdenum
NA
Nickel
51.4%
Nitrate nitrite as N
90.0%
Nitrogen, Kjeldahl
NA
Phosphorus, total
NA
Selenium
34.3%
Silver
88.3%
Sodium
NA
Sulfate
NA
Thallium
53.8%
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Section 6—Pollutant Loadings and Removals
Table 14. POTW Removals
Pollutant
Median POTW Removal Percentage
Tin
NA
Titanium
NA
Total dissolved solids
NA
Total suspended solids
NA
Vanadium
8.3%
Zinc
79.1%
Source: ERG, 2005.
NA—not available.
6.2 FGD Wastewater
For each plant discharging FGD wastewater, as described in Section 5, EPA estimated three pollutant
loading values:
• Baseline conditions, where plants were assumed to comply with the 2020 rule.
• Compliance with the chemical precipitation followed by low residence time reduction (CP+LRTR)
technology option.
• Compliance with the membrane filtration technology option.
As noted in Section 6.1, EPA calculated pollutant loadings using a flow rate multiplied by an average
pollutant concentration. For the 2023 proposal, EPA used data from the 2020 rule to characterize
pollutant concentrations in FGD wastewater. See the Development Memo for FGD Wastewater Data in
the Analytical Database for details on the acceptance criteria used to generate EPA's FGD analytical data
set (ERG, 2015a). Table 15 presents the average effluent concentrations for CP+LRTR treatment.
Regarding membrane treatment, EPA expects that plants will choose to reuse permeate as FGD scrubber
make-up; therefore, membrane filtration average effluent concentrations were assumed to be zero.
As noted in the 2020 TDD, EPA supplemented these analytical data with additional data for bromide and
iodide. Because sampling data for these pollutants were insufficient, EPA developed a methodology to
estimate pollutant loadings from both the naturally occurring bromine and iodine in the coal burned and
any bromide or iodide additives that were being used for mercury emission control at each plant. This
methodology is described in the FGD Haloqen Loadinqs from Steam Electric Power Plants Memorandum
(U.S. EPA, 2022c).
Section 6.2.1 describes FGD wastewater flow rates used for pollutant loading calculations, and Section
6.2.2 discusses EPA's methodology for estimating baseline and post-compliance loadings.
Table 15. Average CP+LRTR Effluent Concentrations
Pollutant
Average Concentration (tig/L)
Conventional Pollutants
Total suspended solids
8,590
Priority pollutants
Antimony
4.25
Arsenic
5.83
Beryllium
1.34
Cadmium
4.21
Chromium
6.45
Copper
3.78
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Section 6—Pollutant Loadings and Removals
Table 15. Average CP+LRTR Effluent Concentrations
Pollutant
Average Concentration (m*/L)
Cyanide, total
949
Lead
3.39
Mercury
0.0507
Nickel
6.30
Selenium
5.72
Thallium
9.81
Zinc
20.0
Nonconventional Pollutants
Aluminum
120
Ammonia as N
6,850
Barium
140
Boron
225,000
Calcium
1,920,000
Chloride
7,120,000
Cobalt
9.30
Iron
110
Magnesium
3,370,000
Manganese
12,500
Molybdenum
125
Nitrate nitrite as N
647
Phosphorus, total
319
Sodium
276,000
Titanium
9.30
Total dissolved solids
24,100,000
Vanadium
12.6
Source: U.S. EPA, 2015a ERG, 2023c.
Note: Concentrations are rounded to three significant figures
6.2.1 FGD Wastewater Flows
To estimate all pollutant loadings, EPA used the same set of flow rates as described in Section 5.1.1 for
compliance cost estimates. As in the 2020 rule, EPA used optimized flow rates, consistent with the O&M
compliance cost assumption that plants will choose to optimize FGD flow through their treatment system.
6.2.2 Baseline and Post-compliance Loadings
EPA multiplied the average effluent pollutant concentrations shown in Table 15 by the plant-specific FGD
wastewater optimized flow rate described in Section 6.2.1 to calculate the pollutant loadings discharged
to surface water for each plant. EPA did not identify any plants transferring FGD wastewater to a POTW.27
6.2.2.1 Baseline Loadings
For all plants discharging FGD wastewater that did not opt into the Voluntary Incentive Programn (VIP),
EPA used CP+LRTR concentrations from Table 15 to represent baseline. EPA assumes that plants subject
27 EPA previously identified two plants for the 2020 rule that reported transferring FGD wastewater to a POTW.
CWLP Dallman has since installed an enhanced chemical precipitation system to treat FGD wastewater with the
option to directly discharge (U.S. EPA, 2022a). C.D. Mcintosh Jr. Power Plant (City of Lakeland, FL) retired in 2021.
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Section 6—Pollutant Loadings and Removals
to the 2020 rule have installed the Best Available Technology Economically Achievable (BAT), CP+LRTR, or
equivalent technology.
For plants that opted into the VIP, EPA estimated baseline loadings of zero, reflecting membrane filtration
treatment and reuse. EPA assumes that plants will choose to reuse membrane permeate within the plant
rather than discharge permeate and monitor the effluent for compliance with NPDES permit limitations,
due to the cost associated with monitoring and potential for noncompliance.
6.2.2.2 CP+LRTR Post-compliance Loadings
For the CP+LRTR technology option, EPA assumed that plants already comply with the 2020 rule and
estimated post-compliance loadings identical to baseline loadings.
6.2.2.3 Membrane Filtration Post-compliance Loadings
For the membrane filtration technology option, EPA estimated post-compliance loadings of zero for all
plants discharging FGD wastewater.
6.3 BA Transport Water
For each plant discharging BA transport water, as described in Section 5, EPA estimated three pollutant
loading values:
• Baseline conditions based on a high rate recycle system with a purge.
• Compliance with the dry handling or high rate recycle BA system with a purge (high recycle rate, or
HRR) technology option.
• Compliance with the zero liquid discharge (ZLD) technology option.
As noted in Section 6.1, pollutant loadings were calculated using a flow rate multiplied by average
pollutant concentrations. For the 2023 proposal, EPA used data from the 2020 rule to characterize
pollutant concentrations in BA transport water. See the Development of the Bottom Ash Transport Water
Analytical Dataset and Calculation of Pollutant Loadings for the Steam Electric Effluent Guidelines
Proposed Rule for additional details on EPA's data sources, acceptance criteria, and development of the
analytical data set used to characterize BA transport water (ERG, 2019b).
Data for BA transport water were typically collected from surface impoundments that receive multiple
wastestreams, and these different wastestreams have the potential to dilute or otherwise alter the
characteristics of the impoundment effluent. Because of this, EPA has additional acceptance criteria
specific to BA transport water samples:
• Sample must be at least 75 percent by volume BA transport water and not include any contribution of
fly ash transport water.
• Sample must be representative of actual BA surface impoundment effluent collected during full-scale,
typical plant operations.
EPA used the BA transport water analytical data to calculate an industry average concentration for each
pollutant present.28 Table 16 presents the average effluent concentrations for pollutants present in BA
transport water.
28 BA surface impoundments typically include other wastestreams {e.g., low volume wastewaters, cooling water); as
a result, the effluent concentrations due to BA transport water are likely suppressed somewhat due to dilution.
Because of this, baseline pollutant loadings and post-compliance pollutant loadings are underestimated to some
degree. Nevertheless, EPA considers that the pollutant removal estimates calculated for this rule represent a
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Section 6—Pollutant Loadings and Removals
Table 16. Average BA Transport Water Effluent Concentrations
Pollutant
Bfjff
Conventional Pollutants
Chemical oxygen demand
20,800
Total suspended solids
13,400
Priority Pollutants
Antimony
17.3
Arsenic
9.32
Cadmium
0.721
Chromium
5.08
Copper
3.95
Lead
10.4
Mercury
0.102
Nickel
17.5
Selenium
12.3
Thallium
1.13
Zinc
33.8
Nonconventional Pollutants
Aluminum
854
Barium
106
Boron
5,310
Bromide
5,100
Calcium
154,00
Chloride
321,000
Cobalt
9.19
Iron
676
Magnesium
55,700
Manganese
153
Molybdenum
28.3
Nitrate-nitrite as N
1,670
Phosphorus
222
Potassium
19,600
Silica
8,160
Sodium
119,000
Strontium
1,430
Sulfate
504,000
Sulfite
3,920
Titanium
35.9
Total dissolved solids
1,290,000
Total Kjeldahl nitrogen
968
Vanadium
10.1
Sources: U.S. EPA, 2015a; ERG, 2023d.
Notes: Concentrations are rounded to three significant figures. EPA did not calculate average pollutant concentrations for
pollutants where all sample results are less than the quantitation limit.
EPA identified ammonia (as N) as a pollutant present in BA transport water; however, EPA excluded this parameter from the
calculation of pollutant loadings to avoid double-counting of nitrogen compounds. EPA has no data on iodine concentrations
in BA transport water and therefore could not calculate an average pollutant concentration.
reasonable estimate of the degree of pollutant removal that would be achieved by the BAT/Pretreatment Standards
for Existing Sources (PSES) limitations.
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Section 6—Pollutant Loadings and Removals
6.3.1 BA Transport Water Flows
To estimate all pollutant loadings, EPA used the same set of flow rates as described in Section 5.2.1 for
compliance cost estimates.
6.3.2 Baseline and Post-compliance Loadings
For baseline and post-compliance loadings, EPA calculated electric generating unit (EGU)-level pollutant
loadings by multiplying the average concentration of each pollutant in Table 16 by the EGU-level
discharge flow rate described in Section 6.3.1. Using the EGU-level loadings, EPA then calculated the
baseline and post-compliance loadings for each plant as the sum of pollutant loadings for all EGUs. EPA
did not identify any plants transferring BA transport water to a POTW.
6.3.2.1 Baseline Loadings
For all plants discharging BA transport water, EPA used BA transport water concentrations from Table 16
to represent baseline. EPA assumed that plants subject to the 2020 rule have installed BAT, HRR using a
mechanical drag system (MDS) or remote MDS, both with a purge option. If a plant falls under the low
utilization subcategory, EPA assumed post-compliance loadings reflecting a surface impoundment plus
best management practices (BMP) plan29.
6.3.2.2 HRR Post-Compliance Loadings
Under the HRR technology option, which would allow plants to discharge a portion of their BA transport
water, EPA estimated loadings associated with MDS and remote MDS installations with a purge. EPA
assumed that plants that already have HRR technologies installed have post-compliance loadings identical
to baseline loadings.
6.3.2.3 ZLD Post-Compliance Loadings
Under the ZLD technology option, EPA estimated pollutant loadings associated with MDS and closed loop
remote MDS installations. Closed loop remote MDS installations include a reverse osmosis (RO) system to
allow for complete recycle. EPA estimated post-compliance loadings of zero for all plants.
6.4 CRL
EPA estimated CRL pollutant loadings under baseline conditions as well as for the chemical precipitation
(CP) technology option. EPA used data collected through the Steam Electric Survey from the 2015 rule to
estimate the average effluent concentrations for untreated CRL. As described in the 2015 TDD, EPA
combined data from 26 landfills reported in the Steam Electric Survey to estimate the average effluent
concentration of landfill leachate (U.S. EPA, 2015b). These average concentrations are presented in Table
17. EPA used all data provided by the plants in the Steam Electric Survey, except for the following:
• For any value reported as less than the quantitation limit, EPA assumed the concentration was equal
to half the quantitation limit provided.
• If the plant did not provide a quantitation limit, EPA assumed the concentration was equal to the
method detection limit.
In 2015, EPA identified one plant operating a biological treatment system to treat landfill leachate
(combined with FGD wastewater) and one plant building a biological treatment system to treat its landfill
29For plants subject to the implementation of a BMP plan under the 2020 rule subcategories, EPA assumed that the
plant will continue to discharge BA transport water consistent with current operations (i.e., the BA sluice flow rate).
EPA used information from the Steam Electric Survey to calculate a normalized BA transport water discharge flow
rate consistent with the methodology described in Section 10.3.2 of the 2015 TDD (U.S. EPA, 2015a).
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Section 6—Pollutant Loadings and Removals
CRL. As described in Section 5.3.1, EPA accounted for this treatment-in-place information in the 2023
proposal analyses.
At the time loading estimates for the proposed rule were calculated, EPA did not have analytical data
from steam electric power plants using CP or biological treatment to treat landfill leachate; therefore,
EPA used the same methodology as that of the 2015 rule, transferring the average FGD effluent
concentrations for CP and biological treatment. These concentrations are presented in Table 17.
Table 17. Average CRL Pollutant Concentrations
Untreated CRL
Chemical Precipitation
Biological Treatment
Pollutant
Average
Average
Average
Conventional Pollutants
Total suspended solids
35,800
8,590
8,590
Priority Pollutants
Antimony
3.75
3.75
3.75
Arsenic
38.4
5.83
5.83
Cadmium
10.1
4.21
4.21
Chromium
2,120
6.45
6.45
Copper
7.58
3.78
3.78
Mercury
1.06
0.139
0.0507
Nickel
46.5
9.11
6.30
Selenium
111
111
5.72
Thallium
1.16
1.16
1.16
Zinc
211
20.0
20.0
Nonconventional Pollutants
Aluminum
2,990
120
120
Barium
53.2
53.2
53.2
Boron
22,400
22,400
22,400
Calcium
408,000
408,000
408,000
Chloride
413,000
413,000
413,000
Cobalt
38.6
9.30
9.30
Iron
37,100
110
110
Magnesium
118,000
118,000
118,000
Manganese
2,720
2,720
2,720
Molybdenum
1,380
125
125
Sodium
308,000
276,000
276,000
Sulfate
1,790,000
1,240,000
1,240,000
Total dissolved solids
3,500,000
3,500,000
3,500,000
Vanadium
1,910
12.6
12.6
Sources: U.S. EPA, 2015a; ERG, 2023e.
In cases where the average concentration of the untreated CRL was less than the FGD treated concentration for the technology
option, EPA assumed that the treated concentration was equal to the untreated CRL average concentration. EPA did not calculate
removals of these particular pollutants by the wastewater treatment system.
As described in Section 3.2.3, EPA also notes that unlined landfills and surface impoundments potentially
discharge CRL through groundwater before entering surface water. To evaluate the potential costs and
loads of such discharges, EPA conducted a sensitivity analysis documented in its memorandum Evaluation
of Potential CRL in Groundwater (U.S. EPA, 2023a).
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Section 6—Pollutant Loadings and Removals
6.4.1 CRL Flows
As described in Section 5.3.1, EPA used the same methodology from the 2015 rule to estimate CRL flow
rates for the proposed rule, with estimates deriving from the Steam Electric Survey.
6.4.2 Baseline and Post-compliance Loadings
To estimate baseline and post-compliance loadings for the 2023 proposal, EPA multiplied the appropriate
average effluent pollutant concentrations from Table 17 by the plant-specific CRL flow rate to calculate
the pollutant loadings for each plant. For plants with new landfills, and those not included in the 2015
Rule population, ERG used the average landfill leachate flow per landfill (46,160 gpd). This average flow is
based on the 2015 methodology and data from the Steam Electric Survey and was used for plants where
a flow rate could not be determined. See Section 4.1.3.1 of EPA's 2015 Incremental Costs and Pollutant
Removals for Final Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating
Point Source Category report (U.S. EPA, 2015b). Calculations for both baseline and the CP technology
option use the same CRL flow rate. EPA adjusted pollutant loadings for plants discharging to a POTW to
account for additional removals achieved by the POTW.
6.4.2.1 Baseline Loadings
For all plants except those with treatment in place, EPA estimated baseline loadings using the untreated
concentrations shown in Table 17.
For the two plants with biological treatment in place for landfill leachate, EPA used a methodology
consistent with the 2015 rule and transferred the effluent concentrations from the FGD biological
treatment, shown in Table 17, to calculate baseline loadings.
6.4.2.2 CP Post-compliance Loadings
To estimate CP post-compliance loadings for those plants without leachate treatment in place, EPA used
plant-specific CRL flow rates and the CP effluent concentrations shown in Table 17. For the two plants
with biological treatment, EPA estimated option loadings identical to baseline loadings.
6.5 Summary of Baseline and Regulatory Option Loadings and Removals
EPA evaluated four regulatory options to control FGD wastewater, BA transport water, and CRL
discharges. For each regulatory option, EPA combined the wastestream-level pollutant loadings for
baseline and each technology option to obtain total regulatory option loadings; EPA also calculated
pollutant removals as the difference between baseline and each regulatory option (ERG, 2023f). This
section discusses the specific loadings and removals calculations for each regulatory option evaluated by
EPA. This section also presents aggregated industry-level loadings and removals for each wastestream
and regulatory option.
EPA applied different effluent limitations to the following:
• Steam electric EGUs with less than 50 megawatts generating capacity.
• EGUs with a specific net power generation.
• Early adopters of the 2020 rule FGD wastewater BAT limitations.
• Plants that opted into the 2020 rule VIP.
In calculating the pollutant loading estimates for each regulatory option, EPA considered the
subcategorizations established by each option. The preamble describes the subcategories and
requirements applicable for each of the regulatory options evaluated by EPA.
Table 18, Table 19, and Table 20 present EPA's estimated total industry pollutant loadings and removals
for FGD wastewater, BA transport water, and CRL, respectively, in pounds per year for baseline and each
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Section 6—Pollutant Loadings and Removals
regulatory option. Table 21 presents EPA's aggregated, industry-level pollutant loadings and removals at
baseline and each regulatory option. Pollutant loadings and removals presented in these tables are
calculated as the sum of TDS and TSS. EPA estimated the pollutant removals by subtracting the post-
compliance loadings from the baseline loadings. The Generating Unit-Level Costs and Loadings Estimates
by Regulatory Option memorandum presents the baseline and post-compliance loadings for each
wastestream and each regulatory option at the plant level (U.S. EPA, 2023h). Post-compliance loadings
represent loadings once all plants and EGUs comply with the regulatory option presented. Values
presented in this document do not account for the timing or exact date of implementation (e.g., when
treatment systems are installed by the industry).
Table 18. Estimated Industry-Level FGD Wastewater Pollutant Loadings and Removals by Regulatory
Option
Regulatory Option
Baseline
612,000,000
-
1
612,000,000
0
2
54,700,000
557,000,000
3
54,700,000
557,000,000
4
0
612,000,000
Note: Loadings and removals are rounded to three significant figures.
Table 19. Estimated Industry-Level BA Transport Water Pollutant Loadings and Removals by
Regulatory Option
Regulatory Option
Baseline
26,100,000
-
1
8,540,000
17,600,000
2
8,540,000
17,600,000
3
230,000
25,900,000
4
0
26,100,000
Note: Loadings and removals are rounded to three significant figures.
Table 20. Estimated Industry-level CRL Pollutant Loadings and Removals by Regulatory Option
Regulatory Option
Estimated Total Industry Loadings
(lb/Year)
Estimated Total Industry Removals
(lb/Year)
Baseline
67,700,000
-
1
67,200,000
496,000
2
67,200,000
496,000
3
67,200,000
496,000
4
67,200,000
496,000
Note: Loadings and removals are rounded to three significant figures.
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Section 6—Pollutant Loadings and Removals
Table 21. Estimated Industry-level Pollutant Loadings and Removals by Regulatory Option
Regulatory Option
Estimated Total Industry Loadings
(lb/Year)
Estimated Total Industry Removals
(lb/Year)
Baseline
706,000,000
-
1
688,000,000
18,000,000
2
130,000,000
575,000,000
3
122,000,000
584,000,000
4
67,200,000
639,000,000
Note: Loadings and removals are rounded to three significant figures.
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7. Non-Water-Quality Environmental Impacts
Eliminating or reducing one form of pollution can aggravate other environmental problems, an effect
often referred to as a cross-media impact. Sections 304(b) and 306 of the Clean Water Act (CWA) require
the EPA to consider non-water-quality environmental impacts (NWQEIs), including energy impacts,
associated with effluent limitations guidelines and standards (ELGs). Accordingly, EPA has considered the
potential impacts of the proposed regulatory options considered for flue gas desulfurization (FGD)
wastewater, bottom ash (BA) transport water, and combustion residual leachate (CRL) discharged from
steam electric power plants on energy consumption (including fuel usage), air emissions, solid waste
generation, and water use. Like the costs discussed in Section 5, the NWQEIs associated with the
proposed regulatory options for this rulemaking are measured as incremental changes from baseline (i.e.,
the 2020 rule).
7.1 Energy Requirements
Steam electric power plants use energy (including fuel) when transporting ash and other solids on or off
site, operating wastewater treatment systems, or operating ash handling systems. For those plants that
are estimated to incur costs associated with the proposed rule, EPA considered whether there would be
an associated incremental change in energy need compared to the baseline. That need varies depending
on the regulatory option evaluated and the current operations of the plant. Therefore, as applicable, EPA
estimated the change in annual energy consumption in megawatt hours (MWh) for equipment added to
the plant systems or in consumed fuel (gallons) for transportation or equipment operation. Specifically,
EPA estimated energy usage associated with operating equipment for the FGD wastewater treatment
systems, BA handling systems, and CRL treatment systems considered for this proposed rule.
• To estimate changes in energy consumption associated with operating FGD wastewater treatment
equipment, EPA developed relationships between FGD wastewater flow and energy usage for the
following technologies: chemical precipitation, low residence time reduction (LRTR) biological
treatment, and membrane filtration.
• To estimate energy usages for operating bottom ash (BA) handling systems, EPA developed
relationships between electric generating unit (EGU) capacity and energy usage for the following
technologies: mechanical drag system (MDS), remote mechanical drag system (rMDS) with a purge,
and remote MDS with RO treatment of a slipstream to achieve complete recycle. EPA estimated
electrical energy use from horsepower ratings of system equipment (e.g., pumps, mixers, silo
unloading equipment) and energy usage data provided by wastewater treatment vendors. See the
Non-Water Quality Environmental Impacts for Revisions to the Steam Electric Effluent Limitations
Guidelines and Standards memorandum for additional details (U.S. EPA, 2023j).
• To estimate energy usages for operating CRL systems, EPA relied on the methodology developed for
the chemical precipitation technology. EPA summed plant-specific energy usage estimates to
calculate the net change in annual energy consumption for the regulatory options considered for the
proposed rule; this information is presented in Table 22.
Energy usage also includes the fuel consumption associated with the changes in transportation. These
changes include transportation needed to landfill solid waste and combustion residuals [e.g., ash) at
steam electric power plants to on-site or off-site landfills using open dump trucks and disposal of
concentrated brine from the treatment of a remote MDS BA slipstream with an RO system to a
centralized waste treatment (CWT) facility using a tanker truck. In general, EPA calculated fuel usage
based on the estimated amount of time spent loading and unloading solid waste, combustion residuals,
or concentrated brine into trucks and the fuel consumption during idling plus the estimated total
transportation distance, number of trips required per year to dispose of the solid waste, combustion
residuals, or concentrated brine, and fuel consumption. The frequency and distance of transport to a
landfill depends on a plant's operation and configuration. For example, the volume of waste generated
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Section 7—Non-Water-Quality Environmental Impacts
per day determines the frequency with which trucks will be travelling to and from the storage sites. The
availability of either an on-site or off-site landfill, and its estimated distance from the plant, determines
the length of travel time. See the Non-Water Quality Environmental Impacts for Revisions to the Steam
Electric Effluent Limitations Guidelines and Standards memorandum, for more information on the specific
calculations used to estimate fuel consumption associated with the transport and disposal of solid waste,
combustion residuals, and concentrated brine (U.S. EPA, 2023j). Table 22 shows the net change in
national annual fuel consumption associated with the proposed regulatory options compared to baseline
(i.e., the 2020 rule).
Table 22. Net Change in Energy Use for the Regulatory Options Compared to Baseline
Non-Water Quality Impact
Net Change in Energy Use Associated with the ELG
Option 1
Option 2
Option 3
Option 4
Electrical energy usage (MWh)
38,000
126,000
139,000
151,000
Fuel (gallons peryear)
53,000
122,000
622,000
639,000
7.2 Air Emissions Pollution
The proposed rule is expected to affect air pollution through three main mechanisms:
• Changes in power requirements by steam electric power plants to operate wastewater treatment and
BA handling systems in compliance with the regulatory options.
• Changes to transportation-related emissions due to the trucking of combustion residual waste to
landfills.
• Changes in the profile of electricity generation due to the regulatory options.
This section provides more detail on air emission changes associated with the first two mechanisms and
presents the estimated net change in air emissions associated with all three. See EPA's Benefit and Cost
Analysis for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category for further discussion of the third mechanism (U.S. EPA, 2023 k).
Air pollution is generated when fossil fuels burn. Steam electric power plants also generate air emissions
from operating vehicles such as dump trucks, tanker trucks, vacuum trucks, dust suppression water
trucks, and earthmoving equipment, which all release criteria air pollutants and greenhouse gases.
Criteria air pollutants are those pollutants for which a national ambient air quality standard (NAAQS) has
been set and include sulfur dioxide (S02) and nitrogen oxides (NOx). Greenhouse gases are gases such as
carbon dioxide (C02), methane (CH4), and nitrous oxide (N20) that absorb radiation, thereby trapping heat
in the atmosphere and contributing to a wide range of domestic effects.30 Conversely, decreasing energy
use or less vehicle operation will result in decreased air pollution.
EPA calculated air emissions resulting from the change in power requirements31 using year-explicit
emission factors estimated by the Integrated Planning Model (IPM)32 for C02, NOx, and S02. The IPM
output provides estimates of electricity generation and resulting emissions by plant and North American
Electric Reliability Corporation (NERC) region. EPA used detailed outputs for the 2035 IPM run year to
30 EPA did not specifically evaluate N2O emissions as part of the NWQEI analysis. To avoid double-counting air
emission estimates, EPA calculated only NOx emissions, which would include N2O emissions.
31 Power requirements refers to the electricity needed to operate FGD wastewater treatment and/or BA handling
technologies. Plants may generate this electricity on site or purchase the electricity from the grid.
32 IPM is a comprehensive electricity market optimization model that can evaluate cost and economic impacts within
the context of regional and national electricity markets. IPM is used by EPA to analyze the estimated impact of
environmental policies on the U.S. power sector.
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Section 7—Non-Water-Quality Environmental Impacts
estimated plant- and NERC-level emission factors (mass of pollutant emitted per kilowatt-hour of
electricity generated) over the period of analysis. This run year represents steady-state conditions after
rule implementation, when all plants are estimated to meet the revised BAT limits and pretreatment
standards associated with each analyzed regulatory option.
EPA calculated NOx, C02, and S02 emissions resulting from changes in power requirements based on the
incremental auxiliary power electricity consumption, the pollutant- and year-specific emission factors,
and the timing plants are assumed to install the compliance technology and start incurring additional
electricity consumption.
EPA assumed that plants with capacity utilization rates (CUR) of 90.4 percent or less would generate the
additional auxiliary electricity on site and therefore estimated emissions using plant-specific and year-
explicit emission factors obtained from IPM outputs.33
EPA assumed that plants with CUR greater than 90.4 percent would draw additional electricity from the
grid within the NERC region, instead of generating it on site. These plants will be using part of their
existing generation to power equipment; however, other plants within the same NERC region would need
to generate electricity to compensate for this reduction and meet electricity demands. Therefore, for
these high-CUR plants, EPA used NERC-average emission factors instead of plant-specific emissions
factors.
Because, for the proposed rule, EPA ran IPM for proposed Regulatory Option 3 only, EPA used IPM
emission factors calculated for proposed Regulatory Option 3 to estimate changes in power requirements
air emissions for all other proposed regulatory options.
To estimate air emissions associated with operation of transport vehicles, EPA used the MOVES3.0.3
model to generate air emission factors for NOx, S02, C02, and CH4. EPA assumed the general input
parameters such as the year of the vehicle and the annual mileage accumulation by vehicle class to
develop these factors (U.S. EPA, 2021). Table 23 lists the transportation emission factors for each air
pollutant considered in the NWQEI analysis.
Table 23. MOVES3.0.3 Emission Rates for Model Year 2010 Diesel-Fueled, Long-Haul Trucks
Operating in 2021
Roadway Type
NOx
(Tons/mi)
S02
(Tons/mi)
C02
(Tons/mi)
cm
(Tons/mi)
Highway
4.47E-06
6.84E-09
0.0020
6.18E-08
Local
5.88E-06
7.11E-09
0.0021
8.79E-08
Source: MOVES3.0.3 (database version "movesdb20220105").
Vehicle types: Single and combination unit long-haul trucks, together.
Road types: Restricted access roads are "Highway" and unrestricted access are "Local"
EPA calculated the air emissions associated with the operation of transport vehicles estimated for the
regulatory options using the transportation pollutant-specific emission rate per mile, the estimated
round-trip distance to and from the on-site or off-site landfill, and the number of calculated trips for one
year in the transportation methodology to truck all solid waste or combustion residuals to the on-site or
off-site landfill and concentrated brine to a CWT.
EPA estimated the annual number of miles that dump trucks moving ash or wastewater treatment solids
to on- or off-site landfills or tanker trucks transporting concentrated brine to CWTs would travel to
comply with limitations associated with the regulatory options. See EPA's memorandum Non-Water
Quality Environmental Impacts for Revisions to the Steam Electric Effluent Limitations Guidelines and
33 Emission factors are calculated as plant-level emissions divided by plant-level generation.
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Section 7—Non-Water-Quality Environmental Impacts
Standards for more information on the specific calculations used to estimate transport distance and
number of trips per year (U.S. EPA, 2023j). The changes in national annual air emissions associated with
auxiliary electricity and transportation for each of the regulatory options are shown in Table 24.
Table 24. Net Change in Industry-Level Air Emissions Associated with Power Requirements and
Transportation by Regulatory Option
Air Emissions Associated with the ELG
Non-Water Quality Impact
Option 1
Option 2
Option 3
Option 4
NOx (thousand tons/year)
0.02
0.065
0.081
0.085
SO2(thousand tons/year)
0.022
0.06
0.07
0.072
CO2 (million metric tons/year)
0.03
0.12
0.134
0.145
CH4 (tons/year)
0.0038
0.029
0.163
0.18
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, S02, and C02 emissions from steam electric power plants. A
summary of the net change in annual air emissions associated with Option 3 for all three mechanisms are
shown in Table 25. Similar to costs, the IPM from these options reflect the range of NWQEI associated
with all four regulatory options. To provide some perspective on the estimated changes in annual air
emissions, EPA compared the estimated change in air emissions to the net amount of air emissions
generated in a year by all electric power plants throughout the U.S. For a detailed breakout of each of the
three sources of air emission changes, see EPA's BCA Report (U.S. EPA, 2023k).
Table 25. Estimated Net Change in Industry-Level Air Emissions associated with Changes in Power
Requirements, Transportation, and Electricity Generation for Proposed Option 3 Compared to
Baseline
Non-Water Quality Impact
Change in Emissions - Proposed
Option 3
2020 Em
G
CO2 (million tons/year)
-11
1,650
NOx (thousand tons/year)
-5.1
1,020
SO2(thousand tons/year)
-5.8
954
Source: eGRID.
7.3 Solid Waste Generation
Solid waste associated with the implementation of the proposed rule is based on the generation of
residual treatment solids from the change in solids from membrane filtration versus LRTR, RO systems,
and CP. EPA estimated the amount of solid waste generated from each technology for each applicable
plant.
• EPA determined the FGD solids generated from membrane with encapsulation by multiplying an
aggregate solids value by the plant specific optimized FGD flow rate (expressed in GPD). EPA then
subtracted out the backwash dry solids generated from an LRTR system.
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Section 7—Non-Water-Quality Environmental Impacts
• EPA determined the BA solids (expressed in tons of brine solids per year) generated from RO systems
by multiplying the purge flow (10 percent of the total BA system volume) by the average TSS
concentration in BATW.34
• EPA determined the CRL solids generated from CP treatment by multiplying a flow-normalized
dewatered sludge generation rate (expressed in tons per day of sludge per gallon per minute CRL
flow) by the plant's CRL flow rate.
The net change in national solid waste production associated with the regulatory options is shown in
Table 26.
Table 26. Net Change in Industry-Level Solid Waste by Regulatory Option
Non-Water Quality Impact
Solid Waste Generation with the ELG
Option 1
Option 2
Option 3
Option 4
Solids (tons/year)
236,000
1,220,000
1,240,000
1,340,000
7.4 Change in Water Use
Steam electric power plants generally use water for handling solid waste, including BA, and for operating
wet FGD scrubbers. EPA estimated the plant-specific change in water intake, or process water use,
associated with FGD wastewater treatment and BA handling for each evaluated technology options and
baseline.
Plants expected to install a membrane filtration system for FGD wastewater treatment under the
proposed regulatory options are expected to experience a decrease in water use compared to baseline
because EPA anticipates they will reuse the membrane permeate in the FGD scrubber. EPA estimated the
reduction in water use resulting from membrane filtration treatment compared to baseline is 70 percent
of the optimized FGD flow for each plant expected to install membrane filtration under the regulatory
option being evaluated.
EPA estimates that the proposed regulatory options evaluated will decrease water intake associated with
BA handling as the proposed options require zero discharge of the BA purge. EPA used the purge volume
for each plant, equivalent to 10 percent of the total rMDS volume as defined in Section 5.2.1, to estimate
the decrease in water intake for each plant for BA.EPA does not expect the proposed regulatory options
for CRL to have an impact on water use.
Table 27 presents the estimated incremental change in process water use for each regulatory option
evaluated for the ELGs compared to baseline. The change in water use for each regulatory option is
equivalent to the change in wastewater discharge. The industry-level process water use for membrane
filtration is the same for all brine management options considered.
Table 27. Net Change in Industry-Level Process Water Use by Regulatory Option
Change in Water Use with the Option
Water reduction
(MGD)
4.47
ll^l
9.79
iwijrtjpn
11.;
Option 4
12.4
34 Similar to the 2020 rule methodology, EPA assumed plants would transfer RO brine to a centralized waste
treatment (CWT) facility at an average distance of 40 miles.
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8. TDD References
1. Butler, Barbara. 2010. U.S. EPA. Selenium Treatment Technologies. 2010 Mining NPDES States
Meeting. Pittsburgh, PA. (24 June). EPA-HQ-OW-2009-0819-8537. DCN SE08580.
2. CH2M Hill. 2010. Review of Available Technologies for the Removal of Selenium from Water.
(June). EPA-HQ-OW-2009-0819-8540. DCN SE08583.
3. EPRI. 2020. Electric Power Research Institute. FGD Wastewater Treatment Testing Using a
Saltworks Flex EDR Selective (Electrodialysis Reversal System) Technology. (November). DCN
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4. ERG. 2005. Eastern Research Group, Inc. Memorandum to 2006 Effluent Guidelines Program
Plan Docket, From Ellie Codding and Deb Bartram, ERG, "Publicly Owned Treatment Works
(POTW) Percent Removals Used for the TRI Releases2002 Database." (August 12). EPA-HQ-OW-
2009-0819-2185.
5. ERG. 2012. Final Sampling Episode Report, Allegheny Energy's Hatfield's Ferry Power Station.
(13 March). EPA-HQ-OW-2009-0819-0813. DCN SE01310.
6. ERG. 2015. Eastern Research Group, Inc. Analytical Database for the Steam Electric Rulemaking.
(30 September). EPA-HQ-OW-2009-0819-5640. DCN SE05359.
7. ERG. 2015a. Eastern Research Group, Inc. Development Memo for FGD Wastewater Data in the
Analytical Database. (September 30). EPA-HQ-OW-2009-0819-6145. DCN SE05880.
8. ERG. 2015b. Eastern Research Group, Inc. Final Steam Electric Technical Questionnaire
Database. (September 30). EPA-HQ-OW-2009-0819-6306. DCN SE05903.
9. ERG. 2019. Final Notes from Meeting with Pall Water. (5 March). EPA-HQ-OW-2009-0819-7613.
10. ERG. 2019a. Eastern Research Group, Inc. Sutton Site Visit Notes. (7 June). EPA-HQ-OW-2009-
0819-7338. DCN SE07139.
11. ERG. 2019b. Eastern Research Group, Inc. Development of the Bottom Ash Transport Water
Analytical Dataset and Calculation of Pollutant Loadings for the Steam Electric Effluent
Guidelines Proposed Rule. (August 6). EPA-HQ-OW-2009-0819-7835. DCN SE07208.
12. ERG. 2020. Eastern Research Group, Inc. Final DuPont Meeting Notes. (20 June). EPA-HQ-OW-
2009-0819-8887. DCN SE08618.
13. ERG. 2020a. Eastern Research Group, Inc. Notes from Conference Call with Burns & McDonnell.
(13 April). EPA-HQ-OW-2009-0819-8550. DCN SE08680.
14. ERG. 2020b. Eastern Research Group, Inc. PRPA Rawhide Site Call Notes. (16 April). EPA-HQ-
OW-2009-0819-8496. DCN SE08682.
15. ERG. 2020c. Eastern Research Group, Inc. Sanitized Notes from Conference Call with Babcock &
Wilcox. (4 May). EPA-HQ-OW-2009-0819-8551. DCN SE08684.
16. ERG. 2020d. Eastern Research Group, Inc. Notes from Conference Call with United Conveyor
Corporation. (21 May). EPA-HQ-OW-2009-0819-8552. DCN SE08686.
17. ERG. 2020e. Eastern Research Group, Inc. Final Notes from Site Call with Duke Energy's Mayo
Steam Station. (15 June). EPA-HQ-OW-2009-0819-8558. DCN SE08964.
18. ERG. 2023. Eastern Research Group, Inc. FGD Wastewater Cost Calculation Database.
(February). DCN SE10416.
19. ERG. 2023a. Eastern Research Group, Inc. Bottom Ash Cost Calculation Database. (January).
DCN SE09710.
20. ERG. 2023b. Eastern Research Group, Inc. Combustion Residual Leachate (CRL) Proposed Rule
Cost Database. (February). DCN SE10420.
21. ERG. 2023c. Eastern Research Group, Inc. FGD Wastewater Proposed Rule Loadings Database.
(February). DCN SE10422.
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22. ERG 2023d. Bottom Ash Transport Water Proposed Rule Pollutant Loadings Database.
(February). DCN SE10423.
23. ERG. 2023e. Eastern Research Group, Inc. Combustion Residual Leachate (CRL) Proposed Rule
Loadings Database. (February). DCN SE10421.
24. ERG. 2020f. Eastern Research Group, Inc. Regulatory Options Proposed Rule Cost and Loads
Database. (February). DCN SE10418.
25. Martin. 2019. Concrete Solidification Report. (March). EPA-HQ-OW-2009-0819-7626. DCN
SE07368.
26. Pastore and Martin. 2017. Advanced Micro Filtration and Reverse Osmosis for ELG Compliance
and ZLD. (November). EPA-HQ-OW-2009-0819-7627. DCN SE07369.
27. Pickett, Tim et al. 2006. Using Biology to Treat Selenium. Power Engineering. (November).
Available online at:
http://pepei.pennnet.com/display article/278443/6/ARTCL/none/none/Using-Biology-to-Treat-
Selleniiuin/. Date accessed: May 16, 2008. EPA-HQ-OW-2009-0819-2177. DCN SE02926.
28. RSMeans. 2018. 2018 RSMeans Cost Index. (6 April). EPA-HQ-OW-2009-0819-8132. DCN
SE06922.
29. RSMeans. 2021. 2021 RSMeans Cost Index. (January). DCN SE10286.
30. U.S. DOE. 2011. U.S. Department of Energy, Energy Information Administration (EIA). Electric
Power Annual 2009. Washington, D.C. (January). EPA-HQ-OW-2009-0819-2143. DCN SE02023.
31. U.S. DOE. 2020. U.S. Department of Energy. EIA-923. EPA-HQ-OW-2009-0819-8556. DCN
SE08704.
32. U.S. DOE. 2020a. U.S. Department of Energy. EIA-860. EPA-HQ-OW-2009-0819-8527. DCN
SE08703.
33. U.S. EPA. 2014. Office of Superfund and Remediation and Technology Innovation. Reference
Guide to TreatmentTechnologies for Mining-Influenced Water. EPA 542-R-14-001. (March).
EPA-HQ-OW-2009-0819-8539. DCN SE08582.
34. U.S. EPA, 2015. 2009 Steam Electric Survey. (September). EPA-HQ-OW-2009-0819-6306. DCN
SE05924.
35. U.S. EPA. 2015a. U.S. Environmental Protection Agency. Technical Development Document for
the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating
Point Source Category (2015 TDD). (September 30). EPA-HQ-OW-2009-0819-6432. DCN
SE05904.
36. U.S. EPA. 2015b. Incremental Costs and Pollutant Removals for Final Effluent Limitation
Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost
& Loads Report). (30 September). EPA-HQ-OW-2009-0819-6023. DCN SE05831.
37. U.S. EPA. 2016. U.S. Environmental Protection Agency. Unconventional Oil and Gas Wastewater
Treatment Technologies - Attachment 1: Treatment Technology Costs Spreadsheet. (June 28).
EPA-HQ-OW-2014-0598-1257.
38. U.S. EPA. 2020. U.S. Environmental Protection Agency. Supplemental Technical Development
Document for Revisions to the Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category (2020 TDD). (September 2020) EPA-HQ-OW-
2009-0819-8935. DCN SE08650.
39. U.S. EPA. 2021. U.S. Environmental Protection Agency. MOVES3.0.3 Long Haul Tanker Truck
Emissions Data and Truck Idling Data. (January). DCN SE10407.
40. U.S. EPA. 2022. Environmental Protection Agency. List of CCR Management Units from CCR Rule
Database. (9 February). DCN SE10373.
41. U.S. EPA. 2022a. Environmental Protection Agency. Notes from Call with City Water, Light, and
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Section 8—TDD References
42. U.S. EPA. 2022b. U.S. Environmental Protection Agency. Notes from Meeting with EPA, UCC,
and ERG on August 26, 2021. (January). DCN SE10368.
43. U.S. EPA. 2022c. U.S. Environmental Protection Agency. FGD Halogen Loadings from Steam
Electric Power Plants. (November). DCN SE10317.
44. U.S. EPA. 2023a. U.S. Environmental Protection Agency. Evaluation of Potential CRL in
Groundwater. DCN SE10250.
45. U.S. EPA. 2023b. Environmental Protection Agency. Legacy Wastewater at CCR Surface
Impoundments. DCN SE10252.
46. U.S. EPA. 2023c. Environmental Protection Agency. Environmental Justice Analysis for Proposed
Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category. EPA-821-R-23-001.
47. U.S. EPA. 2023d. U. S. Environmental Protection Agency. Update to Industry Profile for the 2023
Steam Electric Effluent Guidelines Proposed Rule. (February). DCN SE10241.
48. U.S. EPA. 2023e. U.S. Environmental Protection Agency. Technologies for the Treatment of Flue
Gas Desulfurization Wastewater, Coal Combustion Residual Leachate, and Pond Dewatering
memorandum. (February). DCN SE10281.
49. U.S. EPA. 2023f. U.S. Environmental Protection Agency. Regulatory Impact Analysis for
Proposed Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category. EPA-821-R-23-002.
50. U.S. EPA. 2023g. U.S. Environmental Protection Agency. Flue Gas Desulfurization Flow
Methodology for Compliance Costs and Pollutant Loadings. DCN SE10287.
51. U.S. EPA. 2023h. U.S. Environmental Protection Agency. Generating Unit-Level Costs and
Loadings Estimates by Regulatory Option. (February). DCN SE10381.
52. U.S. EPA. 2023j. U.S. Environmental Protection Agency. Non-Water Quality Environmental
Impacts for Revisions to the Steam Electric Effluent Limitations Guidelines and Standards
memorandum. DCN SE10244.
53. U.S. EPA. 2023k. U.S. Environmental Protection Agency. Benefit and Cost Analysis for Proposed
Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category. EPA-821-R-23-003.
54. U.S. EPA. 20231. U.S. Environmental Protection Agency. Notes from Meeting with EPA, Southern
Company, and ERG on November 15, 2021. (February). DCN SE10424.
55. Wolkersdorfer, Christian et al. 2015. Intelligent mine water treatment—recent international
developments. (21 July). EPA-HQ-OW-2009-0819-8538. DCN SE08581.
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