United States
Environmental Protection
Agency
Office of Water EPA-821 -R-24-007
Washington, DC 20460 April 18, 2024
<&Efi^ Regulatory Impact Analysis
for Supplemental Effluent
Limitations Guidelines and
Standards for the Steam
Electric Power Generating
Point Source Category
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v»EPA
United States
Environmental Protection
Agency
Regulatory Impact Analysis for
Supplemental Effluent Limitations
Guidelines and Standards for the Steam
Electric Power Generating Point Source
Category
EPA-821 -R-24-007
April 18, 2024
U.S. Environmental Protection Agency
Office of Water (4303T)
Engineering and Analysis Division
1200 Pennsylvania Avenue, NW
Washington, DC 20460
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RIA for Supplemental Steam Electric Power Generating ELGs
Acknowledgements and Disclaimer
This report was prepared by the U.S. Environmental Protection Agency. Neither the United States
Government nor any of its employees, contractors, subcontractors, or their employees make any warranty,
expressed or implied, or assume any legal liability or responsibility for any third party's use of or the
results of such use of any information, apparatus, product, or process discussed in this report, or represent
that its use by such party would not infringe on privately owned rights.
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RIA for Supplemental Steam Electric Power Generating ELGs
Contents
Table of Contents
Table of Contents i
List of Tables v
List of Figures viii
Abbreviations ix
Executive Summary ES-1
1 Introduction 1-1
1.1 Background 1-1
1.2 Overview of the Costs and Economic Impacts Analysis 1-2
1.2.1 Main Regulatory Options Presented in the Final Rule 1-2
1.2.2 Baseline 1-4
1.2.3 Cost and Economic Analysis Requirements under the Clean Water Act 1-4
1.2.4 Analyses of the Regulatory Options and Report Organization 1-4
2 Overview of the Steam Electric Industry 2-1
2.1 Steam Electric Industry 2-1
2.1.1 Owner Type and Size 2-2
2.1.2 Geographic Distribution of Steam Electric Power Plants 2-4
2.1.3 Electricity Generation 2-7
2.2 Other Environmental Regulations and Policies 2-8
2.2.1 Coal Combustion Residuals Rule 2-8
2.2.2 Air Pollution Rules and Implementation 2-10
2.2.3 Greenhouse Gas Reduction Targets 2-13
2.2.4 Inflation Reduction Act of 2022 2-13
2.2.5 Recent Developments in Assuring Electric Reliability and Resource Adequacy 2-14
2.3 Market Conditions and Trends in the Electric Power Industry 2-15
3 Compliance Costs 3-1
3.1 Analysis Approach and Inputs 3-2
3.1.1 Plant-Specific Costs Approach 3-2
3.1.2 Plant-Level Costs 3-3
3.1.3 Technology Implementation Years 3-4
3.1.4 Total Compliance Costs 3-6
3.1.5 Voluntary Incentive Program 3-8
3.2 Key Findings for Regulatory Options 3-8
3.2.1 Estimated Industry-level Total Compliance Costs 3-8
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3.2.2 Estimated Regional Distribution of Incremental Compliance Costs 3-9
3.2.3 Key Uncertainties and Limitations 3-11
3.3 Costs to New Sources 3-12
3.3.1 Analysis Approach and Inputs 3-2
3.3.2 Key Findings for Regulatory Options 3-2
3.3.3 Key Uncertainties and Limitations 3-4
4 Cost and Economic Impact Screening Analyses 4-5
4.1 Analysis Overview 4-5
4.2 Cost-to-Revenue Analysis: Plant-Level Screening Analysis 4-5
4.2.1 Analysis Approach and Data Inputs 4-6
4.2.2 Key Findings for Regulatory Options 4-7
4.2.3 Uncertainties and Limitations 4-8
4.3 Cost-to-Revenue Screening Analysis: Parent Entity-Level Analysis 4-9
4.3.1 Analysis Approach and Data Inputs 4-9
4.3.2 Key Findings for Regulatory Options 4-10
4.3.3 Uncertainties and Limitations 4-12
5 Assessment of the Impact of the Final Rule on National and Regional Electricity Markets..5-1
5.1 Model Analysis Inputs and Outputs 5-3
5.1.1 Analysis Years 5-3
5.1.2 Key Inputs to IPM V6 for the Market Model Analysis of the Final Rule 5-4
5.1.3 Key Outputs of the Market Model Analysis Used in Assessing the Effects of the Final
Rule 5-5
5.2 Findings from the Market Model Analysis 5-5
5.2.1 National-level Analysis Results for Model Years 2028-2050 5-6
5.2.2 Detailed Analysis Results for Model Year 2035 5-9
5.3 Estimated Effects of the Regulatory Options on New Capacity 5-21
5.4 Uncertainties and Limitations 5-21
6 Assessment of Impacts on Employment 6-1
6.1 Background and Context 6-1
6.2 Analysis Overview 6-1
6.2.1 Quantification of Projected Actions 6-1
6.2.2 Resource Requirements of Changes in Projected Actions and Treatment Technology6-3
6.2.3 Estimation and Aggregation of Labor Impacts 6-5
6.3 Estimated Impacts of the Final Rule in 2030 6-7
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Contents
6.3.1 New Generation Capacity 6-7
6.3.2 New Treatment Technology 6-9
6.3.3 Fuel Consumption Changes 6-10
6.3.4 Total Impacts of the Final Rule by Industry 6-10
6.4 Estimated Impacts from Installation of Wastewater Treatment Technologies 6-11
6.5 Uncertainties and Limitations 6-13
7 Assessment of Potential Electricity Price Effects 7-1
7.1 Analysis Overview 7-1
7.2 Assessment of Impact of Compliance Costs on Electricity Prices 7-2
7.2.1 Analysis Approach and Data Inputs 7-2
7.2.2 Key Findings for Regulatory Options 7-2
7.2.3 Uncertainties and Limitations 7-6
7.3 Assessment of Impact of Compliance Costs on Household Electricity Costs 7-6
7.3.1 Analysis Approach and Data Inputs 7-6
7.3.2 Key Findings for Regulatory Options A through C 7-7
7.3.3 Uncertainties and Limitations 7-9
7.4 Distribution of Electricity Cost Impact on Household 7-10
8 Assessment of Potential Impact of the Regulatory Options on Small Entities - Regulatory
Flexibility Act (RFA) Analysis 8-1
8.1 Analysis Approach and Data Inputs 8-2
8.1.1 Determining Parent Entity of Steam Electric Power Plants 8-2
8.1.2 Determining Whether Parent Entities of Steam Electric Power Plants Are Small 8-2
8.1.3 Significant Impact Test for Small Entities 8-6
8.2 Key Findings for Regulatory options 8-6
8.3 Uncertainties and Limitations 8-10
8.4 Small Entity Considerations in the Development of Rule Options 8-10
9 Unfunded Mandates Reform Act (UMRA) Analysis 9-1
9.1 UMRA Analysis of Impact on Government Entities 9-2
9.2 UMRA Analysis of Impact on Small Governments 9-4
9.3 UMRA Analysis of Impact on the Private Sector 9-6
9.4 UMRA Analysis Summary 9-7
10 Other Administrative Requirements 10-1
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10.1 Executive Order 12866: Regulatory Planning and Review, Executive Order 13563:
Improving Regulation and Regulatory Review, and Executive Order 14094: Modernizing
Regulatory Review 10-1
10.2 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations, Executive Order 14008: Tackling the Climate Crisis at
Home and Abroad, and Executive Order 14096: Revitalizing our Nation's Commitment to
Environmental Justice for All 10-2
10.3 Executive Order 13045: Protection of Children from Environmental Health Risks and Safety
Risks 10-2
10.4 Executive Order 13132: Federalism 10-3
10.5 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments. 10-3
10.6 Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use 10-4
10.6. 1 Impact on Electricity Generation
10-5
10.6. 2 Impact on Electricity Generating Capacity
10-5
10.6. 3 Cost of Energy Production
10-5
10.6. 4 Dependence on Foreign Supply of Energy
10-6
10.6. 5 Overall Executive Order 13211 Finding
10-7
10.7 Paperwork Reduction Act of 1995 10-7
10.8 National Technology Transfer and Advancement Act 10-8
11 Cited References 11-1
A Summary of Changes to Costs and Economic Impact Analysis A-l
B Comparison of Incremental Costs and Pollutant Removals B-l
C Total Costs Based on 7 Percent Discount Rate C-l
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Contents
List of Tables
Table 1-1: Regulatory Options Analyzed for the Final Rule 1-3
Table 2-1: Steam Electric Industry Share of Total Electric Power Generation Plants and Capacity in 2021
2-2
Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity by
Ownership Type, 2021 2-2
Table 2-3: Parent Entities of Steam Electric Power Plants by Ownership Type and Size (assuming two
different ownership cases)a b 2-3
Table 2-4: Steam Electric Power Plants by Ownership Type and Size 2-4
Table 2-5: NERC regions 2-5
Table 2-6: Steam Electric Power Plants and Nameplate Capacity by NERC Region, 2021 2-7
Table 2-7: Net Generation by Energy Source and Ownership Type, 2015-2021 (TWh) 2-8
Table 3-1: Estimated Total Annualized Compliance Costs (in millions, 2023$, at 2024) - Lower Bound 3-
8
Table 3-2: Estimated Total Annualized Compliance Costs (in millions, 2023$, at 2024) - Upper Bound.3-
9
Table 3-3: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2023$, at 2024) -
Lower Bound 3-9
Table 3-4: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2023$, at 2024) -
Upper Bound 3-9
Table 3-5: Estimated Annualized Total Compliance Costs by NERC Region (in millions, 2023$, at 2024)
- Lower Bound 3-10
Table 3-6: Estimated Annualized Total Compliance Costs by NERC Region (in millions, 2023$, at 2024)
- Upper Bound 3-11
Table 3-7: Annualized Pre-tax Compliance Costs for a Hypothetical New 650 MW Plant Under Final
Rule (2023$, at 2024) 3-2
Table 3-8: One-Time & O&M costs for a Hypothetical New 650 MW Plant Under Final Rule 3-3
Table 4-1: Plant-Level Cost-to-Revenue Analysis Results by Owner Type and Regulatory Option -
Lower Bound 4-7
Table 4-2: Plant-Level Cost-to-Revenue Analysis Results by Owner Type and Regulatory Option - Upper
Bound 4-8
Table 4-3: Entity-Level Cost-to-Revenue Analysis Results - Lower Bound 4-11
Table 4-4: Entity-Level Cost-to-Revenue Analysis Results - Upper Bound 4-12
Table 5-1: IPM Run Years 5-4
Table 5-2: Baseline Projections, 2028-2050 5-6
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Contents
Table 5-3: Incremental National Impact of Final Option B Relative to Baseline, 2028-2050 5-7
Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2035 5-10
Table 5-5: Impact of the Final Rule on In-Scope Plants, as aGroup, in the Year 203 5a 5-16
Table 5-6: Impact of Final Rule on Individual In-Scope Plants in the Year 2035 5-20
Table 6-1: Estimated Change in Generating Capacity Under Option B Relative to Baseline in 2030 6-2
Table 6-2: Incremental Change in New Generation Capacity Under Construction in 2030 6-2
Table 6-3: Estimated Change in Fuel Consumption Under Option B Relative to Baseline in 2030 6-3
Table 6-4: Option B Technology Capital and Operation Costs (millions, 2023$) 6-3
Table 6-5: Capital and Labor Components for Construction of New Generation Capacity by Generation
Type 6-4
Table 6-6: NAICS Sectors Associated with Operation of New Generation Capacity 6-4
Table 6-7: Operation and Labor Components for New Wastewater Treatment Technologies 6-5
Table 6-8: Base Labor Productivity by Relevant Sector 6-6
Table 6-9: Coal and Natural Gas Labor Productivity Estimates 6-7
Table 6-10: Changes in Labor Inputs from Construction of New Generation Capacity in 2030 FTE) 6-7
Table 6-11: Changes in Labor Inputs from Operation of New Generation Capacity and Retirements in
2030 (# FTEs) 6-9
Table 6-12: Changes in Labor Inputs from Operation of New Technology in 2030 (# FTEs) 6-9
Table 6-13: Labor Demand from Fuel Use Changes (# Employees) 6-10
Table 6-14: Total Effects on Labor Inputs by NAICS Sector in 2030 (# FTEs) 6-11
Table 6-15: Capital and Labor Components for New Treatment Technology 6-12
Table 6-16: Total FTE Changes from Installation of New Technology 6-12
Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024 (2023$) -
Lower Bound 7-2
Table 7-2: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024 (2023$) -
Upper Bound 7-3
Table 7-3: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to Compliance
Costs by NERC Region and Regulatory Option (2023$) - Lower Bound 7-4
Table 7-4: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to Compliance
Costs by NERC Region and Regulatory Option (2023$) - Upper Bound 7-5
Table 7-5: Average Incremental Annual Cost per Household in 2024 by NERC Region and Regulatory
Option (2023$) - Lower Bound 7-7
Table 7-6: Average Incremental Annual Cost per Household in 2024 by NERC Region and Regulatory
Option (2023$) - Upper Bound 7-8
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Contents
Table 8-1: NAICS Codes and SBA Size Standards for Non-government Majority Owners Entities of
Steam Electric Power Plants 8-3
Table 8-2: Number of Entities by Sector and Size (assuming two different ownership cases) 8-4
Table 8-3: Steam Electric Power Plants by Ownership Type and Size 8-5
Table 8-4: Estimated Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and Ownership
Category - Lower Bound 8-8
Table 8-5: Estimated Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and Ownership
Category - Upper Bound 8-9
Table 9-1: Government-Owned Steam Electric Power Plants and Their Parent Entities 9-2
Table 9-2: Estimated Compliance Costs to Government Entities Owning Steam Electric Power Plants
(2023$) - Lower Bound 9-3
Table 9-3: Estimated Compliance Costs to Government Entities Owning Steam Electric Power Plants
(2023$) - Upper Bound 9-3
Table 9-4: Counts of Government-Owned Plants and Their Parent Entities, by Size 9-5
Table 9-5: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type and Size
(2023$) - Lower Bound 9-5
Table 9-6: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type and Size
(2023$) - Upper Bound 9-6
Table 9-7: Compliance Costs for Electric Generators by Ownership Type (2023$) - Lower Bound 9-7
Table 9-8: Compliance Costs for Electric Generators by Ownership Type (Millions of 2023$) - Upper
Bound 9-7
Table 10-1: Total Market-Level Capacity and Generation by Type for the Final Rule in Model Year 2035
10-6
Table 10-2: Total Market-Level Fuel Use by Fuel Type for the Final Rule in Model Year 2035 10-7
vii
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RIA for Supplemental Steam Electric Power Generating ELGs Contents
List of Figures
Figure 2-1: North American Electric Reliability Corporation (NERC) Regions 2-6
Figure B-l: Estimated Removals and Costs of the Regulatory Options, Relative to Baseline B-4
viii
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RIA for Supplemental Steam Electric Power Generating ELGs
Abbreviations
Abbreviations
AEO
Annual Energy Outlook
ASCC
Alaska Systems Coordinating Council
BA
Bottom ash
BAT
Best available technology economically achievable
BCA
Benefit and Cost Analysis
BEA
U.S. Bureau of Economic Analysis
BLS
U.S. Bureau of Labor Statistics
BMP
Best management practice
BPJ
Best professional judgment
BPT
Best practicable control technology currently available
BSER
Best system of emission reduction
CAA
Clean Air Act
CC
Carbon capture
CCI
Construction cost index
CCR
Coal combustion residuals
CCRMU
CCR management units
CCS
Carbon capture and storage
CEMS
Continuous emission monitoring systems
CES
Clean Energy Standards
CFR
Code of Federal Regulations
CP
Chemical precipitation
CPP
Clean Power Plan
CRL
Combustion residual leachate
CSAPR
Cross-State Air Pollution Rule
CWA
Clean Water Act
DOE
Department of Energy
EA
Environmental Assessment
ECI
Employment Cost Index
EGU
Electricity generating units
EIA
Energy Information Administration
EJ
Environmental justice
ELGs
Effluent limitations guidelines and standards
EO
Executive Order
EPA
U.S. Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
FGD
Flue gas desulfurization
FOM
Fixed O&M
fPM
Filterable particulate matter
FR
Federal Register
FRCC
Florida Reliability Coordinating Council
GDP
Gross domestic product
GHG
Greenhouse gas
ix
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Abbreviations
GW
Gigawatt
GWh
Gigawatt-hour
HICC
Hawaii Coordinating Council
HRI
Heat rate improvement
HRR
High recycle rate
HRTR
High Hydraulic Residence Time Reduction
IBR
Inverter-based resources
IPM
Integrated Planning Model
IRA
Inflation Reduction Act of 2022
ISO
Independent system operator
kWh
Kilowatt-hour
LRTR
Low Hydraulic Residence Time Reduction
MATS
Mercury and Air Toxics Standards
Mcf
Million cubic feet
MDS
Mechanical drag system
MRO
Midwest Reliability Organization
MT
Million short tons
MW
Megawatt
MWh
Megawatt-hour
NAAQS
National ambient air quality standards
NAICS
North American Industry Classification System
NERC
North American Electric Reliability Corporation
NOPP
Notice of planned participation
NPCC
Northeast Power Coordinating Council
NPDES
National Pollutant Discharge Elimination System
NPRM
Notice of proposed rulemaking
NSPS
New Source Performance Standards
NTTAA
National Technology Transfer and Advancement Act
O&M
Operation and maintenance
OMB
Office of Management and Budget
POTW
Publicly owned treatment works
PRA
Paperwork Reduction Act
PSES
Pretreatment Standards for Existing Sources
PSNS
Pretreatment Standards for New Sources
QA
Quality assurance
QC
Quality control
Quad
Quadrillion British thermal units
RCRA
Resource Recovery and Conservation Act
RIA
Regulatory Impact Analysis
RFA
Regulatory Flexibility Act
RF
Reliability First Corporation
RGGI
Regional Greenhouse Gas Initiative
RTO
Regional transmission organization
RULOF
Remaining Useful Life and Other Factors
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Abbreviations
SBA
Small Business Administration
SBREFA
Small Business Regulatory Enforcement Fairness Act
SDE
Spray dry evaporator
SERC
SERC Reliability Corporation
SISNOSE
Significant impact on a substantial number of small entities
SPP
Southwest Power Pool
TDD
Technical Development Document
TRE
Texas Reliability Entity
TWF
Toxic weighting factor
TWh
Terawatt-hour
TWPE
Toxic weighted pound equivalent
UMRA
Unfunded Mandates Reform Act
use
Ultra-supercritical coal
VIP
Voluntary Incentive Program
VOM
Variable O&M
WECC
Western Electricity Coordinating Council
WMU
Waste management unit
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Executive Summary
Executive Summary
The U.S. Environmental Protection Agency (EPA) is finalizing revisions to the technology-based effluent
limitations guidelines and standards (ELGs) for the steam electric power generating point source
category, 40 CFRpart 423, which EPA proposed on March 29, 2023 (88 FR 18824). The final rule
revises certain best available technology (BAT) effluent limitations and pretreatment standards
established in the rules EPA previously promulgated in November 2015 (80 FR 67838) and October 2020
(85 FR 64650) for existing sources for three wastestreams: flue gas desulfurization (FGD) wastewater,
bottom ash (BA) transport water, and combustion residual leachate (CRL). The rule also establishes
effluent limitations and pretreatment standards for legacy wastewater.
This action is an economically significant regulatory action that was submitted to the Office for
Management and Budget (OMB) for interagency review. This Regulatory Impact Analysis (RIA) presents
an assessment of the compliance costs and impacts associated with this final rule and presents analyses to
meet various statutory and Executive Order requirements. The accompanying Bene fit and Cost Analysis
for Supplemental Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (BCA) document presents social costs and benefits of the
action, consistent with Executive Orders 12866, 13563 and 14094.
Regulatory Options
For this final rule, EPA evaluated three regulatory options as summarized in Table ES-1. EPA established
BAT effluent limitations based on the technologies described in Option B.
ES-1
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Executive Summary
Table ES-1: Regulatory Options Analyzed for the Final Rule
Wastestream
Subcategory
Technology Basis for BAT/PSES Regulatory Options3
2020 Rule
(Baseline)
Option A
Option B
Option C
FGD
Wastewater
NA (default unless in subcategory)15
CP + Bio
ZLD
ZLD
ZLD
Boilers permanently ceasing the
combustion of coal by 2028
SI
SI
SI
SI
Boilers permanently ceasing the
combustion of coal by 2034
NS
CP + Bio
CP + Bio
NS
High FGD Flow Facilities or Low
Utilization Boilers
CP
NS
NS
NS
BA Transport
Water
NA (default unless in subcategory)15
HRR
ZLD
ZLD
ZLD
Boilers permanently ceasing the
combustion of coal by 2028
SI
SI
SI
SI
Boilers permanently ceasing the
combustion of coal by 2034
NS
HRR
HRR
NS
Low Utilization Boilers
BMP Plan
NS
NS
NS
CRL
NA (default)15
BPJ
CP
ZLD
ZLD
Discharges of unmanaged CRL
NA
NS
CP
CP
Boilers permanently ceasing the
combustion of coal by 2034
NA
CP
CP
NS
Legacy
Wastewater
Operate after 2024
NA
NS
CP
CP
Abbreviations: BMP = Best Management Practice; CP = Chemical Precipitation; HRR = High Recycle Rate Systems; SI = Surface Impoundment; ZLD = Zero Liquid Discharge; NS =
Not subcategorized (default technology basis applies); NA = Not applicable
a. See TDD for a description of these technologies (U.S. EPA, 2024e).
b. The table does not present existing subcategories included in the 2015 and 2020 rules as EPA did not reopen the existing subcategorization of oil-fired units or units with a
nameplate capacity of 50 MW or less.
Source: U.S. EPA Analysis, 2024
ES-2
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Executive Summary
Annualized Compliance Costs
EPA estimates that the regulatory options result in incremental costs to owners and operators of steam
electric power plants when compared to the baseline of the 2020 rule (Tables ES-2 and ES-3). On an
after-tax basis, the final rule (Option B) has estimated incremental annualized compliance costs ranging
from $479 million to $956 million.1
Table ES-2: Estimated Incremental Annualized After-tax Compliance Costs (Million of 2023$,
Discounted to 2024 using 3.76 Percent) - Lower
Regulatory
Other Initial One-
Option
Capital Technology
Time
Total O&M
Total Costs3
Option A
$186
1
O
¦uy
$200
$386
Option B
$229
r—1
o
¦uy
$250
$479
Option C
$270
$0.2
$286
$557
a. Costs analyzed over the period 2025-2049.
Source: U.S. EPA Analysis, 2024
Table ES-3: Estimated Incremental Annualized After-tax Compliance Costs (Million of 2023$,
Discounted to 2024 using 3.76 Percent) - Upper
Regulatory
Other Initial One-
Option
Capital Technology
Time
Total O&M
Total Costs3
Option A
$372
1
O
¦uy
$490
$863
Option B
$415
r—1
o
¦uy
$541
$956
Option C
$456
$0.2
$577
$1,033
a. Costs analyzed over the period 2025-2049.
Source: U.S. EPA Analysis, 2024
This analysis accounts for costs associated with the BA transport water, FGD wastewater, CRL
wastestreams (including unmanaged CRL), and legacy wastewater. Costs associated with legacy
wastewater limits would be incurred only as plants close and dewater their existing ponds. There is
uncertainty on when plants may do so; for the purposes of this analysis, EPA assumed all plants would
implement technologies to meet limits for legacy wastewater and incur costs in 2044. EPA believes this
could overestimate costs if plants are decommissioned in later years. Similarly, certain plants could incur
costs associated with the treatment of unmanaged CRL discharged from landfills, surface impoundments,
or other features. These limits would apply only in cases where a permitting authority deems, on a case-
by-case basis, that the discharge is functionally equivalent to a direct discharge and requires a permit.
Because these discharges are uncertain, EPA assumed that plants incurred costs associated with
1 These costs are the basis for social costs presented in Chapter 11 of the BCA with the main differences being the
applied discount rates, the way costs are distributed over the period of analysis, tax considerations, and the
annualization period. In the private cost analysis, all costs are annualized over the life of the technology or cost
recurrence period (e.g., 1 year, 5 years, 20 years), discounted according to the estimated plant compliance year, and
summed over each plant and across plants. After-tax costs are a more meaningful measure of compliance impact on
privately owned for-profit plants and incorporate approximate capital depreciation and other relevant tax treatments in
the analysis. By contrast, for the social cost analysis, costs are presented on a pre-tax basis and recorded in the year in
which they are estimated to be incurred during the analysis period of 2025-2049. Hie modeled stream of future costs is
then discounted back to the estimated rule promulgation year to obtain the total present value, and then annualized over
the 25-year analysis period.
ES-3
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RIA for Supplemental Steam Electric Power Generating ELGs
Executive Summary
unmanaged CRL costs at the same time as they would implement technologies to meet limits for CRL
wastestreams. See Section 3.1 for details.
EPA also evaluated whether the New Source Performance Standard (NSPS) requirements of the final rule
present a barrier to the entry of new generation. EPA notes that no new coal capacity additions are
projected between 2024 and 2050 in AEO2023 (EIA, 2023b) or in the Integrated Planning Model (IPM)
detailed in Chapter 5, making the assessment of the relative costs and of any barrier the final ELGs may
pose to additional generation hypothetical. Nonetheless, EPA assessed the costs imposed on new plants in
relation to the costs for building and operating a new plant and found that the costs for adding treatment
technology at a new plant would represent approximately 1 percent of the total annualized costs of
building and operating a new plant. Section 3.3 details the analysis.
Impacts on Steam Electric Industry and Electricity Market
EPA assessed the impacts of the regulatory options on the steam electric industry and the electricity
market in two ways:
1. A screening-level assessment reflecting historical characteristics of steam electric power plants
and with assignment of estimated compliance costs to the plants and their owners. Specifically,
EPA calculated cost-to-revenue ratios for individual steam electric power plants and for domestic
parent-entities owning these plants to assess the relative impact of compliance outlays. Overall,
this screening-level analysis shows that few entities are likely to experience significant changes in
compliance costs compared to revenues. See Chapter 4 for details.
2. A broader electricity market-level analysis using the Integrated Planning Model (IPM), which
provides a more comprehensive indication of the economic impacts of this final rule, looking
specifically at regulatory option B, including an assessment of changes in the operating
characteristics of steam electric power plants and other electricity generators resulting from
changes in electricity markets under the final rule. See Chapter 5 for details.
Table ES-4 and Table ES-5 summarize IPM results in the baseline (absent Option B) and under Option B
(absolute values and changes relative to the baseline). These analyses show that the final rule is estimated
to have small impacts on the steam electric power plants, on the entities that own these plants, and on the
electricity market as a whole. For example, IPM results for the market show net changes in total
generation capacity of 0.4 percent and generation costs of less than 0.2 percent across economic measures
for Option B in the model year 2035 after implementation of the revised ELGs (see Table ES-4). The
final rule results in a small projected increase in total generation, and a small projected increase in total
generation capacity (less than 0.4 percent of the baseline) as the net effect of increases in non-coal
generation sources (combination of renewables, natural gas, and energy storage) and decreases in coal-
fired generation capacity resulting from early retirements of coal-fired electricity generating units relative
to the baseline and already scheduled retirements. The final rule results in a small projected increase in
total electricity market costs, the net effect of decreases in fuel costs, variable O&M, and fixed O&M and
increases in capital and CCS costs. These projected changes depend on overall changes in capacity,
generation mix, and pollutant controls, among other factors (e.g., switch from generating units with
higher fixed O&M to units with lower fixed O&M would result in a decrease in total fixed O&M).
ES-4
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Executive Summary
Results for steam electric power plants in scope of the final rule (in Table ES-5) also show small impacts,
with a net decrease in total capacity under the final rule when compared to the baseline (2.6 percent), and
net decreases in total generation by steam electric power plants of 3 percent for the final rule. Projected
decreases in fixed O&M and capital costs for steam electric power plants in scope of the final rule reflect
projected capacity retirements. The IPM model determines the least cost approach to meeting demand
subject to modeled system and operational constraints. Therefore, changes in the national power sector
(e.g., generation mix, cost for non-steam electric generation, technology changes, cost for new capacity
relative to new coal-steam production costs) affect projected retirements of steam electric capacity.2
These findings suggest that the final rule will have small economic consequences for the steam electric
power generating industry and the electricity market overall.
Looking specifically at plants with estimated incremental compliance costs, the results for the final rule
show no change in generation for 1 of the 35 plants with compliance costs, and a slight decrease in
generation for another 4 plants. See Chapter 5 for details of these analyses, including results by region
and for different model years.
Table ES-4: Modeled Impact of Final Rule on National Electricity Market in the Model Year 2035
Economic Measures3
Option B
(all dollar values in 2023$)
Baseline Value
Value
Difference
% Change
Total Domestic Capacity (GW)
1,712
1,718
6.4
0.4%
Existing
-1.5
-0.1%
New Additions
7.9
0.5%
0.1%
Generation (TWh)
5,158
5,160
1.7
0.0%
Costs ($Millions)
$138,325
$138,544
$219
0.2%
Fuel Cost
$39,166
$38,975
-$191
-0.5%
Variable O&M
$5,351
$5,244
-$107
-2.0%
Fixed O&M
$65,915
$65,666
-$249
-0.4%
Capital Cost
$34,149
$34,536
$387
1.1%
CCS Costb
-$6,256
-$5,878
$379
-6.1%
Average Variable Production Cost
($/MWh)
$8.63
$8.57
-$0.06
-0.7%
C02 Emissions (Million Metric Tons)
724
713
-11.6
-1.6%
Mercury Emissions (Tons)
2
2
-0.050
-2.0%
NOx Emissions (Million Tons)
0
0
-0.009
-3.4%
S02 Emissions (Million Tons)
0
0
-0.013
-5.3%
HCL Emissions (Million Tons)
0
0
-0.00012
-8.1%
a. See Chapter 5 for a description of the economic measures.
b. "CCS Cost" is the cost of C02 transportation and storage and also includes expenses on equipment and pipelines, as well as
the total value of 45Q tax credits and enhanced oil recovery (EOR) revenues. In the baseline and under Option B, the total
2 Costs to replace retired capacity are not included in the estimate of compliance costs reported in Table ES-2 and Table
ES-3. However, as detailed in Chapter 5, the ELG compliance costs are entered as a fixed cost adder in IPM for units
subject to the ELGs and included in the modeled decision of whether to keep generating electricity from that unit or
shift to other generators with lower production costs. In cases where the modeled decision is the retirement of a steam
electric unit in favor of other generating sources or new capacity, the ELG compliance costs would not be incurred for
that unit and the compliance costs reflected in Table ES-2 and Table ES-3 are overestimated. Additionally, the final
rule results in projected retirements representing only a fraction of a percent of total capacity, and an even smaller
percentage of active capacity.
ES-5
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RIA for Supplemental Steam Electric Power Generating ELGs
Executive Summary
Table ES-4: Modeled Impact of Fina
Rule on National Electricity Market in the Model Year 2035
Economic Measures3
(all dollar values in 2023$)
Baseline Value
Option B
Value
Difference
% Change
private costs are negative because the sum of the tax credits and EOR revenues exceed the equipment and pipeline costs of C02
storage. Under Option B, total CCS Costs are less negative, and therefore these costs increase relative to the baseline, as the
total amount of the 45Q tax credit received by the sector and/or EOR revenues fall due to lower coal generation.
Source: U.S. EPA Analysis, 2024
Table ES-5: Impact of Final Rule on Plants in the Steam Electric Power Generating Point Source
Category, as a Group, in the Model Year 2035
Economic Measures3
Option B
(all dollar values in 2023$)
Baseline Value
Value
Difference
% Change
Total Domestic Capacity (MW)
220,237
214,455
-5,782
-2.6%
Early Retirements - Number of Plants
78
83
5
6.4%
Full & Partial Retirements-Capacity
104,544
110,326
5,782
5.5%
(MW)
Generation (GWh)
789,529
765,950
-23,579
-3.0%
Costs ($Millions)
$28,580
$27,740
-$840
-2.9%
Fuel Cost
$13,957
$13,454
-$503
-3.6%
Variable O&M
$1,976
$1,840
-$136
-6.9%
Fixed O&M
$15,419
$15,041
-$378
-2.5%
Capital Cost
$3,202
$3,000
-$202
-6.3%
CCS Costb
-$5,974
-$5,595
$379
-6.3%
Average Variable Production Cost ($/MWh)
$20.18
$19.97
-$0.21
-1.1%
a. See Chapter 5 for a description of the economic measures.
b. The "CCS Cost" is the cost of C02 transportation and storage and also includes expenses on equipment and pipelines, as well
as the total value of 45Qtax credits and enhanced oil recovery (EOR) revenues. In the baseline and under Option B, the total
private costs are negative because the sum of the tax credits and EOR revenues exceed the equipment and pipeline costs of C02
storage. Under Option B, total CCS Costs are less negative, and therefore these costs increase relative to the baseline, as the
total amount of the 45Q tax credit received by the sector and/or EOR revenues fall due to lower coal generation.
Source: U.S. EPA Analysis, 2024
Potential Impacts on Employment
In addition to addressing the costs and impacts of the regulatory options, EPA discusses the potential
impacts of this rulemaking on employment in Chapter 6. EPA estimates a net increase in employment as a
result of the final rule (Option B).
Potential Electricity Price Effects
EPA also assessed the estimated impacts of the regulatory options on electricity prices, assuming a worst-
case scenario of full cost pass-through of compliance costs in electricity prices. The Agency conducted
this analysis in two parts: (1) an assessment of the estimated annual changes in electricity costs per MWh
of total electricity sales; and (2) an assessment of the estimated annual changes in household electricity
costs. Chapter 7 details these analyses.
Changes in costs per MWh of total electricity sales are small for all regulatory options; the maximum
difference in price effect is a fraction of a cent per kWh. Overall, across the United States, the final rule
(Option B) results in an average estimated cost increase of between 0.0150 and 0.0300 per kWh.
ES-6
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RIA for Supplemental Steam Electric Power Generating ELGs
Executive Summary
On the national level, the final rule (Option B) results in estimated average compliance costs per
residential household of between $1.61 to $3.14 per year.
Potential Impacts on Small Entities
In accordance with the Regulatory Flexibility Act (RFA) requirements, EPA assessed whether the
regulatory options would have "a significant impact on a substantial number of small entities"
(SISNOSE). The analysis is detailed in Chapter 8.
Under the final rule (Option B), in the lower bound scenario, EPA estimates that 3 small cooperatives,
4 small nonutilities, and 3 small municipalities owning steam electric power plants would incur costs
exceeding one percent of revenue. On a percentage basis, small entities represent approximately 5 to
8.5 percent of the total number of small entities owning steam electric power plants (12 to 16 percent of
small cooperatives, 3 to 7 percent of small nonutilities, and 10 to 14 percent of small municipalities). In
the upper bound scenario, EPA estimates that 4 small cooperatives, 5 small nonutilities, and 3 small
municipalities owning steam electric power plants would incur costs exceeding one percent of revenue.
On a percentage basis, small entities represent approximately 6 to 10 percent of the total number of small
entities owning steam electric power plants. (16 to 21 percent of small cooperatives, 4 to 9 percent of
small nonutilities, and 10 to 14 percent of small municipalities).
In the lower bound scenario, the analysis shows that 2 small cooperatives, 2 small nonutilities, and 1
small municipality owning steam electric power plants would incur costs greater than three percent of
revenue. In the upper bound scenario, the analysis shows that 3 small cooperatives, 2 small nonutilities,
and 2 small municipalities owning steam electric power plants would incur costs greater than three
percent of revenue. Overall, this screening-level analysis suggests that the analyzed regulatory options are
unlikely to have a significant economic impact on a substantial number of small entities.
Unfunded Mandate Reform Act
Under Title II of the Unfunded Mandates Reform Act (UMRA) of 1995 section 202, EPA generally must
prepare a written statement, including a cost-benefit analysis, for final and final rules with "Federal
mandates" that might result in expenditures by State, local, and Tribal governments, in the aggregate, or
by the private sector, of $100 million (adjusted annually for inflation) or more in any one year (i.e..
$198 million in 2023 dollars).
EPA estimates that the final rule (Option B) would result in expenditures of at least $198 million for State
and local government entities under the upper bound scenario, in the aggregate, in any one year, but not in
the lower bound scenario. The Agency does estimate that the private sector would incur expenditures
greater than $198 million, in the aggregate, in any one year. For the final rule (Option B), the maximum
compliance costs incurred by the private sector in any one year are between $1,380 and $3,156 million in
2028, whereas total annualized compliance costs for plants owned by private sector entities are between
$603 and $1,207 million. The implementation period built into the final rule is one way that EPA
accounted for the site-specific needs of steam electric power plants.
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Executive Summary
Other Administrative Requirements
EPA conducted analyses to address other administrative requirements. Key findings, which are discussed
further in Chapter 10, include:
• Executive Order 12866: Regulatory Planning and Review, Executive Order 13563:
Improving Regulation and Regulatory Review, and Executive Order 14094 Modernizing
Regulatory Review: Pursuant to the terms of Executive Orders 12866, 13563, and 14094, this
action is a "significant regulatory action" because the action is likely to have an annual effect on
the economy of $200 million or more. As such, the action is subject to review by the OMB. Any
changes made during this period of review will be documented in the docket for this action. EPA
prepared an analysis of the estimated benefits and costs associated with this action; this analysis
is detailed in Chapter 13 of the BCA (U.S. EPA, 2024a).
• Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use: EPA's analyses show that the final rule will not have a significant
adverse effect at a national or regional level under Executive Order 13211. Specifically, the
Agency's analyses found that the final rule would not reduce electricity production in excess of
1 billion kilowatt hours per year or in excess of 500 megawatts of installed capacity, nor that it
would increase U.S. dependence on foreign supply of energy.
• Executive Orders 12898: Federal Actions to Address Environmental Justice (EJ) in
Minority Populations and Low-Income Populations; and Executive Order 14008: Tackling
the Climate Crisis at Home and Abroad: EPA examined whether the benefits from the
regulatory options may be differentially distributed among population subgroups in the affected
areas. This analysis is detailed in the accompanying Environmental Justice Analysis for
Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (EJA) document (U.S. EPA, 2024c). The analysis showed that
the human health or environmental risk addressed by this final action will not have potential
disproportionately high and adverse human health or environmental effects on minority, low-
income, or indigenous populations.
• Executive Order 13045: Protection of Children from Environmental Health Risks and
Safety Risks: As described in Section 10.3 and detailed in the BCA (U.S. EPA, 2024a), EPA
identified several ways in which the final rule could benefit children by reducing health risk from
exposure to pollutants present in steam electric power plant discharges, including neurological
effects from exposure to lead and mercury.
ES-8
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RIA for Supplemental Steam Electric Power Generating ELGs
1: Introduction
1 Introduction
1.1 Background
EPA is finalizing a regulation that revises the technology-based effluent limitations guidelines and
standards (ELGs) for the steam electric power generating point source category, 40 CFRpart 423, which
EPA previously proposed on March 29, 2023 (88 FR 18824). The final rule revises certain BAT effluent
limitations and pretreatment standards for existing sources previously established in the ELG published in
October 2020 (85 FR 64650) for four wastestreams: flue gas desulfurization (FGD) wastewater, bottom
ash (BA) transport water, combustion residual leachate (CRL), and legacy wastewater.
This document describes the Agency's analysis of the costs and economic impacts of the regulatory
options that were evaluated by EPA. EPA analyzed three regulatory options, including the final rule
(Option B). The document also provides information pertinent to meeting several legislative and
administrative requirements.
This document complements and builds on information presented separately in other reports, including:
• Technical Development Document for Supplemental Revisions to the Effluent Guidelines and
Standards for the Steam Electric Power Generating Point Source Category (TDD) (U.S. EPA,
2024e). The TDD provides background on the regulatory options; applicability and summary of
the regulatory options; industry description; wastewater characterization and identifying
pollutants; and treatment technologies and pollution prevention techniques. It also documents
EPA's engineering analyses to support the regulatory options including plant-specific compliance
cost estimates, pollutant loadings, and non-water quality environmental impact assessment.
• Bene fit and Cost Analysis for Supplemental Revisions to the Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category (BCA) (U.S. EPA,
2024a). The BCA summarizes the societal benefits and costs estimated to result from
implementation of the regulatory options.
• Environmental Assessment for Supplemental Revisions to the Effluent Guidelines and Standards
for the Steam Electric Power Generating Point Source Category (EA) (U.S. EPA, 2024b). The
EA summarizes the environmental and human health improvements that are estimated to result
from implementation of the regulatory options.
• Environmental Justice Analysis for Supplemental Effluent Limitations Guidelines and Standards
for the Steam Electric Power Generating Point Source Category (EJA) (U.S. EPA, 2024c). This
report presents a profile of the communities and populations potentially impacted by this final
rule, analysis of the distribution of impacts in the baseline and finalized changes, and summary of
input from potentially impacted communities that EPA met with prior to the final rule.
The revisions to the ELGs for the Steam Electric Power Generating Point Source 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 the
development, approval and implementation of Quality Assurance Project Plans for the use of
environmental data generated or collected from all sampling and analyses, existing databases and
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RIA for Supplemental Steam Electric Power Generating ELGs
1: Introduction
literature searches, and for the development of any models which used environmental data. Unless
otherwise stated within this document, the data used and associated data analyses were evaluated as
described in these quality assurance documents to ensure they are of known and documented quality,
meet EPA's requirements for objectivity, integrity and utility, and are appropriate for the intended use.
1.2 Overview of the Costs and Economic Impacts Analysis
This section describes the key components of the analysis framework. The Agency's analysis generally
follows the methodology EPA previously used to analyze the 2020 rule and 2023 proposal (see RIA; U.S.
EPA, 2020, 2023d). Appendix A describes the principal changes to the regulatory options analysis, as
compared to analyses of the 2020 rule and 2023 proposal. These changes include:
• Updating the information on the control and treatment technologies and associated costs for BA
transport water, FGD wastewater, CRL, and legacy wastewater (see TDD for details; U.S. EPA,
2024e).
• Updating the universe of steam electric power plants and their wastestreams to account for major
changes such as additional retirements, fuel conversions, ash handling system conversions,
wastewater treatment system updates and updated information on capacity utilization.
• Accounting for announced unit retirements and repowerings3 in estimating the stream of
expenditures under the baseline and each regulatory option during the period of analysis.
• Updating the baseline used in analyses using the Integrated Planning Model (IPM). IPM
incorporates the effects of existing regulations and programs or estimated to be in effect by the
time the rule resulting from this final rule is implemented. For the final rule, this baseline includes
the 2020 rule, as well as expected effects of provisions in the Inflation Reduction Act of 2022.
See Section 2.2 for additional discussion of these regulations and Chapter 5, Assessment of the
Impact of the Final Rule on National and Regional Electricity Markets, for further description of
the analysis using IPM, including a description of the analysis baseline.
• Updating electricity generation, sales, and electricity prices based on the most current data from
the Energy Information Administration (e.g., 2016-2021 vs. 2013-2018).
• Updating information about the entities that own steam electric generating units, based on EIA
data, and recategorizing these entities as small or large using SBA small business size thresholds.
1.2.1 Main Regulatory Options Presented in the Final Rule
For this final rule, EPA evaluated three regulatory options as shown in Table 1-1. EPA finalized BAT
effluent limitations based on the technologies described in Option B.
3 Repowering refers to the replacement of coal generation equipment with non-coal generation equipment.
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1: Introduction
Table 1-1: Regulatory Options Analyzed for the Final Rule
Wastestream
Subcategory
Technology Basis for BAT/PSES Regulatory Options3
2020 Rule
(Baseline)
Option A
Option B
Option C
FGD Wastewater
NA (default unless in subcategory)15
CP + Bio
ZLD
ZLD
ZLD
Boilers permanently ceasing the
combustion of coal by 2028
SI
SI
SI
SI
Boilers permanently ceasing the
combustion of coal by 2034
NS
CP + Bio
CP + Bio
NS
High FGD Flow Facilities or Low
Utilization Boilers
CP
NS
NS
NS
Bottom Ash
Transport Water
NA (default unless in subcategory)15
HRR
ZLD
ZLD
ZLD
Boilers permanently ceasing the
combustion of coal by 2028
SI
SI
SI
SI
Boilers permanently ceasing the
combustion of coal by 2034
NS
HRR
HRR
NS
Low Utilization Boilers
BMP Plan
NS
NS
NS
CRL
NA (default)15
BPJ
CP
ZLD
ZLD
Discharges of unmanaged CRL
NA
NS
CP
CP
Boilers permanently ceasing the
combustion of coal by 2034
NA
CP
CP
NR
Legacy
Wastewater
Operate after 2024
NA
NS
CP
CP
Abbreviations: BMP = Best Management Practice; CP = Chemical Precipitation; HRR = High Recycle Rate Systems; SI = Surface Impoundment; ZLD = Zero Liquid Discharge; NS = Not
subcategorized (default technology basis applies); NA = Not applicable
a. See TDD for a description of these technologies (U.S. EPA, 2024e).
b. The table does not present existing subcategories included in the 2015 and 2020 rules as EPA did not reopen the existing subcategorization of oil-fired units or units with a
nameplate capacity of 50 MW or less.
Source: U.S. EPA Analysis, 2024
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1: Introduction
1.2.2 Baseline
The baseline for the analyses supporting this final rule reflects the 2020 rule requirements. The Agency
estimated and presents in this report the incremental compliance costs that plants could incur under each
of the three regulatory options presented in Table 1-1 relative to this baseline.
EPA updated baseline information to incorporate major changes in the universe and operational
characteristics of steam electric power plants such as additional retirements and fuel conversions since the
analysis of the 2020 rule detailed in U.S. EPA (2020). EPA also incorporated updated information on the
technologies and other controls that plants employ. The current analysis focuses on four wastestreams for
which plants are expected to incur costs during the period of analysis: BA transport water, FGD
wastewater, CRL (including unmanaged CRL), and legacy wastewater.
1.2.3 Cost and Economic Analysis Requirements under the Clean Water Act
EPA's effluent limitations guidelines and standards for the steam electric industry are promulgated under
the authority of the Clean Water Act (CWA) Sections 301, 304, 306, 307, 308, 402, and 501 (33 U.S.C.
1311, 1314, 1316, 1317, 1318, 1342, and 1361). In establishing national effluent guidelines and
pretreatment standards for pollutants, EPA considers the availability and economic achievability of
control and treatment technologies, as well as specified statutory factors including "costs." 33 U.S.C.
1311(b)(2)(A), 1314(b)(2)(B).
EPA analyzed economic achievability; the cost and economic impact analysis for this rulemaking also
focuses on understanding the magnitude and distribution of compliance costs across the industry, and the
broader market impacts. This report also documents analyses required under other legislative (e.g.,
Regulatory Flexibility Act, Unfunded Mandates Reform Act) and administrative requirements (e.g.,
Executive Order 12866: Regulatory Planning and Review as supplemented by Executive Order 14094:
Modernizing Regulatory Review).
1.2.4 Analyses of the Regulatory Options and Report Organization
This document discusses the following analyses EPA performed in support of the regulatory options as
compared to the baseline:
• Overview of the steam electric industry (Chapter 2), which focuses on changes to the industry
since the 2020 rule.
• Compliance cost assessment (Chapter 3), which describes the cost components and calculates
the industry-wide incremental compliance costs for the regulatory options relative to the baseline.
• Cost and economic impact screening analyses (Chapter 4), which evaluates the incremental
impacts of compliance on plants and their owning entities on a cost-to-revenue basis.
• Assessment of impacts in the context of national electricity markets (Chapter 5), which
analyzes the impacts of the final rule (Option B) using IPM and provides insight into the
incremental effects of the final rule on the steam electric power generating industry and on
national electricity markets, relative to the baseline.
• Analysis of employment effects (Chapter 6), which assesses national-level changes in
employment in the steam electric industry, relative to the baseline.
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1: Introduction
• Assessment of potential electricity price effects (Chapter 7), which looks at the incremental
impacts of compliance in terms of increased electricity prices for households and for other
consumers of electricity.
• Regulatory Flexibility Act (RFA) analysis (Chapter 8) which assesses the change in impact of
the rule on small entities on the basis of a revenue test, i.e., cost-to-revenue comparison.
• Unfunded Mandates Reform Act (UMRA) analysis (Chapter 9) which assesses the change in
impact on government entities, in terms of (1) compliance costs to government-owned plants and
(2) administrative costs to governments implementing the rule. The UMRA analysis also
compares the impacts to small governments with those of large governments and small private
entities.
• Analyses to address other administrative requirements (Chapter 10), such as Executive Order
13211, which requires EPA to determine if this action would have a significant effect on energy
supply, distribution, or use.
These analyses generally follow the same methodology used by EPA for the analysis of the 2015 and
2020 rules and 2023 proposal and the discussion follows a presentation very similar to that in the
associated RIA documents (U.S. EPA, 2015, 2020, 2023d).
Chapter 11 provides detailed information on sources cited in the text and three appendices provide
supporting information:
• Appendix A: Summary of Changes to Costs and Economic Impact Analysis lists the principal
changes EPA made to its costs and economic impact analysis for the regulatory options, relative
to the methodology used to analyze the 2020 rule.
• Appendix B: Comparison of Incremental Costs and Pollutant Removals describes EPA's analysis
of the cost-effectiveness of the regulatory options.
• Appendix C: Total Costs Based on 7 Percent Discount Rate presents compliance cost estimates
for the regulatory options based on a 7 percent discount rate.
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RIA for Supplemental Steam Electric Power Generating ELGs
2: Industry Overview
2 Overview of the Steam Electric Industry
This section provides a general description of the steam electric industry, focusing on changes to the
universe of plants and entities that own the plants as compared to the profile used for the 2015 and 2020
rules (U.S. EPA, 2015, 2020). It also discusses the regulations applicable to the universe of plants subject
to this final rule.
2.1 Steam Electric Industry
The final rule revises BAT limitations and pretreatment standards for bottom ash transport water, FGD
wastewater, CRL, and legacy wastewater for existing sources in the steam electric industry. The Steam
Electric Power Generating Point Source Category covers "discharges resulting from the operation of a
generating unit by an establishment whose generation of electricity is the predominant source of revenue
or principal reason for operation, and whose generation of electricity results primarily from a process
utilizing fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis
gas), or nuclear fuel in conjunction with a thermal cycle employing the steam water system as the
thermodynamic medium/' (40 CFR 423.10)
EPA had identified 1,080 steam electric power plants - including plants that operate coal, oil, gas, and
nuclear generating units - and used this universe in its analysis of the 2015 rule (U.S. EPA, 2015), based
on an industry survey the Agency conducted in 2010.4 Review of more recent data revealed that some of
the plants EPA surveyed in 2010 have since retired their coal steam units, converted to different fuels, or
made other changes that affect discharge characteristics. The TDD describes the changes in the steam
electric industry population since the 2015 and 2020 rule analyses, including retirements, fuel
conversions, ash handling conversions, wastewater treatment updates, and updated information on
capacity utilization (U.S. EPA, 2024e).
EPA adjusted the 2015 universe to remove coal steam plants that no longer fit the definition of the Steam
Electric Power Generating point source category. As a result of these adjustments, EPA estimates that
there are 858 plants in the steam electric power generating industry, based on available EIA data. As
presented in Table 2-1, the 858 steam electric power plants represent 6.4 percent of the total number of
plants in the power generation sector, but represent 54.4 percent of the national total electric nameplate
generating capacity with 674,998 MW.5
Of the estimated 858 steam electric power plants in the universe, EPA expects only a subset to incur
compliance costs under the final rule: those coal fired power plants that discharge BA transport water,
FGD wastewater, or CRL. As presented in Table 2-1, EPA estimated between 141 and 170 plants would
incur non-zero compliance costs under the final rule (Option B); these plants represent 1 to 1.3 percent of
the total plants reported by EIA in 2021 and 15.4 to 17.5 percent of the total generating capacity.
4 See Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey; U. S.
Environmental Protection Agency. (2010). Questionnaire for the Steam Electric Power Generating Effluent Limitations
Guidelines. )
5 The total number of plants and electric generating capacity are for 2021. At the time EPA developed the industry
profile, 2021 was the most recent calendar year for which EIA had published detailed annual data.
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2: Industry Overview
Table 2-1: Steam Electric Industry Share of Total Electric Power Generation Plants and Capacity
in 2021
Steam Electric Industry13
Plants with Non-Zero Compliance Costs for
Final Rulec
Total3
Number
% of Total
Number
% of Total
Plants
13,455
858
6.4%
141 -170
1.0% -1.3%
Capacity (MW)
1,241,578
674,998
54.4%
189,572-217,184
15.3% -17.5%
a. Data for total electric power generation industry are from the 2021 EIA-860 database (EIA, 2022c).
b. Steam electric power plant count and capacity were calculated on a sample-weighted basis.
c. See Chapter 3 for details on compliance cost estimates, including number of plants with non-zero compliance costs under
the final rule (Option B) and other analyzed regulatory options. Number of affected plants and capacity are presented to
reflect the lower and upper bound cost estimates.
Source: U.S. EPA Analysis, 2024; EIA, 2022c.
The following sections present information on ownership, geographic distribution, and operating
characteristics of steam electric power plants.
2.1.1 Owner Type and Size
Entities that own electric power plants can be divided into seven major ownership categories: investor-
owned utilities, nonutilities6, federally-owned utilities, State-owned utilities, municipalities, rural electric
cooperatives, and other political subdivisions. These categories are important because EPA has to assess
the impact of the final rule on State, local, and tribal governments in accordance with UMRA of 1995 (see
Chapter 9, Unfunded Mandates Reform Act (UMRA) Analysis).
Table 2-2 reports the number of parent entities, plants, and capacity by ownership type for the 858 steam
electric power plants (for details on determination of parent entities for steam electric power plants, see
Section 4.3). The plurality of steam electric power plants (37 percent of all steam electric power plants)
are owned by investor-owned utilities, while nonutilities make up the second largest category (36 percent
of all steam electric power plants). In terms of steam electric nameplate capacity, investor-owned utilities
account for the largest share (50 percent) of total steam electric nameplate capacity.
Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity
by Ownership Type, 2021
Parent Entitiesa b c
Plantsabd
Capacity (MW)ad
Lower Bound
Upper Bound
% of
Ownership Type
Number
% of Total
Number
% of Total
Numberc
% of Total
Numberc
Total
Cooperative
22
10.0%
28
7.1%
59
6.9%
39,934
5.9%
Federal
2
0.9%
7
1.7%
23
2.7%
31,154
4.6%
Investor-owned
57
25.9%
88
22.5%
320
37.4%
338,005
50.1%
Municipality
50
22.7%
84
21.5%
111
12.9%
42,882
6.4%
Nonutility
76
34.5%
160
40.9%
308
35.9%
196,559
29.1%
Other political
subdivisions
11
5.0%
23
5.8%
33
3.8%
21,474
3.2%
State
2
0.9%
2
0.5%
4
0.5%
4,990
0.7%
6 Nonutilities are entities that own or operate facilities that generate electricity for use by the public but are not public
utilities.
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Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity
by Ownership Type, 2021
Parent Entitiesa b c
Plantsabd
Capacity (MW)ad
Lower Bound
Upper Bound
% of
Ownership Type
Number
% of Total
Number
% of Total
Numberc
% of Total
Numberc
Total
Total
220
100.0%
391
100.0%
858
100.0%
674,998
100.0%
a. Numbers may not add up to totals due to independent rounding.
b. Ownership information on steam electric power plants is based on EIA (2022c). Information on parent entities, including
type, revenue, and other characteristics, is based on information gathered through Dun and Bradstreet and additional
research of publicly available information.
c. Parent entity counts are calculated on a sample-weighted basis and represent the lower and upper bound estimates of the
number of entities owning steam electric power plants. For details see Chapter 4.
d. Steam electric power plant count and capacity were calculated on a sample-weighted basis. For details on sample weights,
see TDD.
Source: U.S. EPA Analysis, 2024; EIA, 2022c
EPA estimates that between 52 percent and 53 percent of entities owning steam electric power plants are
small entities (Table 2-3), according to Small Business Administration (SBA) (SBA, 2023) business size
criteria. By definition, states and the federal government are considered large entities.
The size distribution of parent entities owning steam electric power plants varies by ownership type.
Under the lower bound estimate, the lowest share of small entities is in the other political subdivision
category (18 percent), while small entities make up the largest share of nonutilities and cooperatives
(75 percent and 86 percent, respectively). The pattern is similar under the upper bound estimate, but small
entities represent 9 percent of other political subdivision entities, 89 percent of cooperatives, and
77 percent of nonutilities.
EPA estimates that, of 858 steam electric power plants, 267 plants (31 percent) are owned by small
entities (Table 2-4). Nonutilities represent the majority (50 percent) of plants owned by small entities (134
out of 263 plants), while investor-owned utilities, cooperatives, municipalities, and other political
subdivisions7 make up the remaining 50 percent. For a detailed discussion of the identification and size
determination of parent entities of steam electric power plants, see Chapter 4 and Chapter 8.
Table 2-3: Parent Entities of Steam Electric Power Plants by Ownership Type and Size (assuming
two different ownership cases)a b
Lower bound estimate of number of entities
owning steam electric power plants
Ownership Type
Small
Large
Total
% Small
Small
Large
Total
% Small
Cooperative
19
3
22
86.4%
25
3
28
89.3%
Federal
0
2
2
0.0%
0
7
7
0.0%
Investor-owned
17
40
57
29.8%
22
66
88
24.6%
Municipality
22
28
50
44.0%
30
54
84
35.6%
Nonutility
57
19
76
75.0%
123
36
160
77.3%
Other political
subdivision
2
9
11
18.2%
2
21
23
8.9%
State
0
2
2
0.0%
0
2
2
0.0%
Upper bound estimate of number of entities
owning steam electric power plants
Other political subdivisions include public power districts and irrigation projects.
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Table 2-3: Parent Entities of Steam Electric Power Plants by Ownership Type and Size (assuming
two different ownership cases)a b
Ownership Type
Lower bound estimate of number of entities
owning steam electric power plants
Upper bound estimate of number of entities
owning steam electric power plants
Small
Large
Total
% Small
Small
Large
Total
% Small
Total
117
103
220
53.2%
202
189
391
51.7%
a. Numbers may not add up to totals due to independent rounding.
b. For details on estimates of the number of majority owners of steam electric power plants see Chapter 4 and Chapter 8.
Source: U.S. EPA Analysis, 2024
Table 2-4: Steam Electric Power Plants by Ownership Type and Size
Number of Steam Electric Power Plantsa,b c
Ownership Type
Small
Large
Total
% Small
Cooperative
52
7
59
88.1%
Federal
0
23
23
0.0%
Investor-owned
44
276
320
13.9%
Municipality
31
80
111
28.0%
Nonutility
134
174
308
43.6%
Other political subdivisions
6
27
33
18.5%
State
0
4
4
0.0%
Total
267
590
858
31.2%
a. Numbers may not sum to totals due to independent rounding.
b. Plant counts are sample-weighted estimates.
c. Plant size was determined based on the size of majority owners. In case of multiple owners with equal
ownership shares, a plant was assumed to be small if it is owned by at least one small entity.
Source: U.S. EPA Analysis, 2024
2.1.2 Geographic Distribution of Steam Electric Power Plants
The U.S. bulk power system is composed of three major networks, or power grids, subdivided into
several smaller North American Electric Reliability Corporation (NERC) regions:
• The Eastern Interconnection covers the largest portion of the United States, from the eastern end
of the Rocky Mountains and the northern borders to the Gulf of Mexico states (including parts of
northern Texas) on to the Atlantic seaboard.
• The Western Interconnection covers nearly all areas west of the Rocky Mountains, including the
Southwest.
• The Texas Interconnected System, the smallest of the three major networks, covers the majority of
Texas.
The Texas system is not connected with the other two systems, while the other two have limited
interconnection to each other. The Eastern and Western systems are integrated with, or have links to, the
Canadian grid system. The Western and Texas systems have links with Mexico.
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These major networks contain extra-high voltage connections that allow for power transmission from one
part of the network to another. Wholesale transactions can take place within these networks to reduce
power costs, increase supply options, and ensure system reliability.
NERC is responsible for the overall reliability, planning, and coordination of the power grids. An
independent, not-for-profit organization, it has regulatory authority for ensuring electric reliability in the
United States, under the oversight of the Federal Energy Regulatory Commission (FERC). NERC is
organized into six regional entities that cover the 48 contiguous States, and two affiliated councils that
cover Hawaii, part of Alaska, and portions of Canada and Mexico.8 These regional organizations are
responsible for the overall coordination of bulk power policies that affect their regions" reliability and
quality of service. Interconnection between the bulk power networks is limited in comparison to the
degree of interconnection within the major bulk power systems. Further, the degree of interconnection
between NERC regions even within the same bulk power network is also limited. Consequently, each
NERC region deals with electricity reliability issues in its own region, based on available capacity and
transmission constraints. The regional organizations also facilitate the exchange of information among
member utilities in each region and between regions. Service areas of the member utilities determine the
boundaries of the NERC regions. Though limited by the larger bulk power grids described above, NERC
regions do not necessarily follow any State boundaries. Figure 2-1 provides a map of the NERC regions
listed in Table 2-5 that EPA used for the analysis of the regulatory options.9
Table 2-5: NERC regions
Bulk Power Network
NERC Region
NERC Entity
MRO
Midwest Reliability Organization
Eastern Interconnected System
NPCC
Northeast Power Coordinating Council (U.S.)
RF
Reliability First Corporation
SERC
SERC Reliability Corporation
Western Interconnected System
WECC
Western Electricity Coordinating Council (U.S.)
Texas Interconnected System
TRE
Texas Reliability Entity
ASCC
Alaska Systems Coordinating Council
HICC
Hawaii Coordinating Council
Source: NERC, undated
8 Energy concerns in the States of Alaska, Hawaii, the Dominion of Puerto Rico, and the Territories of American Samoa,
Guam, and the Virgin Islands are not under reliability oversight by NERC.
9 Some 2023 Annual Energy Outlook (AEO) data were based on an older version of NERC regions which contained
regions that are not used in this analysis. EPA used best professional judgement (BP.T) to allocate 2023 AEO data for
these regions into the appropriate NERC regions used in this analysis.
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Figure 2-1: North American Electric Reliability Corporation (NERC) Regions
Note: The AK and HICC regions are not shown.
Source: NERC, undated.
The evaluated options are estimated to have a different effect on profitability, electricity prices, and other
impact measures across NERC regions. This is because of variations in the economic and operational
characteristics of steam electric and other power plants across NERC regions, including the share of the
region's electricity demand met by steam electric power plants subject to the final rule under the different
options. Other factors include the baseline economic charactenstics of the NERC regions, together with
market segmentation due to limited interconnectedness among NERC regions. To assess the potential
reliability impact of the regulatory options, EPA assessed the distribution of steam electric power plants
and their capacity across NERC regions.
As reported in Table 2-6, NERC regions differ in terms of both the number of steam electric power plants
and their capacity. Steam electric power plants are primarily located in the RF, SERC, and WECC regions
(20 percent, 28 percent, and 18 percent of plants, respectively); these three regions also account for a
majority of the steam electric nameplate capacity in the United States (23 percent, 38 percent, and
15 percent, respectively).
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Table 2-6: Steam Electric Power Plants and Nameplate Capacity by NERC
Region, 2021
Plants3'"
Capacity (MW)ab
NERC Region
Number
% of Total
MW
% of Total
AK
2
0.2%
120
0.0%
HICC
10
1.2%
1,155
0.2%
MRO
136
15.9%
82,012
12.1%
NPCC
80
9.3%
28,669
4.2%
RF
170
19.8%
151,710
22.5%
SERC
238
27.8%
255,610
37.9%
TRE
66
7.7%
54,407
8.1%
WECC
155
18.1%
101,315
15.0%
TOTAL
858
100.0%
674,998
100.0%
a. Numbers may not add up to totals due to independent rounding.
b. The numbers of plants and capacity are calculated on a sample-weighted basis.
Source: U.S. EPA Analysis, 2024; EIA, 2022c
2.1.3 Electricity Generation
Total net electricity generation in the United States for 2021 was 4,110 TWh.1" The 2021 EIA data was
the most recent year of finalized EIA data that was available at the time of analysis. Coal generation
accounted for 22 percent of total electricity generation, behind natural gas (38 percent), but ahead of
nuclear (19 percent) and renewables (14 percent). Other energy sources accounted for comparatively
smaller shares of total generation, with hydropower representing 6 percent and petroleum less than
one percent.
As presented in Table 2-7, the 7-year period of 2015 through 2021 saw total net generation increase by
approximately 0.8 percent with the 269 TWh increase (89 percent) in generation from renewables and
246 TWh (18 percent) increase in generation from natural gas more than offset the 454 TWh (34 percent)
drop in generation from coal-fueled generators.11
Between 2015 and 2021, the amount of electricity generated by utilities declined by 4.5 percent while that
generated by nonutilities rose by 8 percent. Comparing 2015 and 2021 values, across all fuel-source
categories, utilities generated a larger share of their electricity using natural gas (a 26 percent increase)
and renewables (a 137 percent increase) even as their overall generation declined. For nonutilities, the
largest percent increase in electricity generation (82 percent) occurred for renewables, whereas generation
from natural gas increased 12 percent.
10 One terawatt-hour is 1012 watt-hours.
11 The decline in 2021 is likely partially driven by the economic effects of the COVID-19 pandemic and relatively
wanner winter weather (U.S. Energy Information Administration. (2021d). U.S. energy consumption fell by a record
7% in 2020. Today in Energy, https://www.eia.gov/todayinenergy/detail.php?id=47397 ).
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Table 2-7: Net Generation by Energy Source and Ownership Type, 2015-2021 (TWh)
Utilities
Nonutilities
Total
Energy Source
2015
2021
% Change
2015
2021
% Change
2015
2021
% Change
Coal
996
672
-32.5%
354
223
-37.0%
1,350
896
-33.6%
Hydropower
226
225
-0.3%
18
22
17.4%
244
246
1.0%
Nuclear
417
431
3.4%
380
349
-8.3%
797
780
-2.2%
Petroleum
18
15
-17.5%
10
5
-51.4%
27
19
-29.5%
Natural Gas
618
777
25.8%
716
802
12.1%
1,333
1,579
18.4%
Other Gases
4
2
-39.6%
13
11
-11.9%
17
14
-18.3%
Renewables3
38
89
137.3%
264
482
82.2%
302
571
89.1%
Other"
0
0
1.4%
7
4
-36.0%
7
5
-34.0%
Total
2,315
2,212
-4.5%
1,762
1,898
8%
4,078
4,110
0.8%
a. Renewables include wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, agriculture
byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and wind.
b. Other includes batteries, hydrogen, purchased steam, sulfur, tire-derived fuels and other miscellaneous energy sources.
Source: EIA, 2022d; 2016
2.2 Other Environmental Regulations and Policies
The 2015, 2020 and 2023 RIAs described factors, such as deregulation and environmental regulations and
programs, that have affected the steam electric power generating industry, and electrical power generation
more generally, over the last decades. See Chapter 2 in U.S. EPA (2015, 2020, 2023d).2015, 2020,
2023d). The sections below provide updated discussions on changes to key environmental regulations
since 2020 as well as greenhouse gas (GHG) reduction targets and energy provisions of the Inflation
Reduction Act (IRA) of 2022 that may affect the power generating industry.
2.2.1 Coal Combustion Residuals Rule
On April 17, 2015, the Agency 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 of coal ash (including its disposal),
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.
Additionally, the 2015 CCR rule 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. etal. v. EPA, No. 18-1289 (D.C. Cir. filed March
13, 2019), the EPA Administrator signed two rules: A Holistic Approach to Closure Part A: Deadline to
Initiate Closure and Enhancing Public Access to Information (CCR Part A rule) on July 29, 2020, and A
Holistic Approach to Closure Part B: Alternate Liner Demonstration (CCR Part B rule) on October 15,
2020. EPA finalized five amendments to the 2015 CCR rule which are relevant to the management of the
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wastewaters covered by this ELG because these wastewaters have historically been co-managed with
CCR in the same surface impoundments. First, the CCR Part A rule established a new deadline of April
11, 2021, for all unlined surface impoundments in which CCR are managed ("CCR surface
impoundments"), as well as CCR surface impoundments that failed the location restriction for placement
above the uppermost aquifer, to stop receiving waste and begin closure or retrofit. EPA established this
date after evaluating the steps that owners and operators need to take for CCR surface impoundments to
stop receiving waste and begin closure, and the timeframes needed for implementation. (This would not
affect the ability of plants to install new, composite-lined CCR surface impoundments.) Second, the Part
A rule established procedures for plants to obtain approval from EPA for additional time to develop
alternative disposal capacity to manage their wastestreams (both CCR and non-CCR) before they must
stop receiving waste and begin closing their CCR surface impoundments. Third, the Part A rule changed
the classification of compacted-soil-lined and clay-lined surface impoundments from lined to unlined.
Fourth, the Part B rule finalized procedures potentially allowing a limited number of facilities to
demonstrate to 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 EPA approve such a submission, these CCR surface impoundments would be
allowed to continue to operate.
As explained in the 2015 and 2020 ELG rules, the ELGs and CCR rule 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 as well revisions to both rules in 2020, the Agency coordinated the ELG and CCR rules to
minimize the complexity of implementing engineering, financial, and permitting activities. Likewise,
EPA considered the interaction of these two rules during the development of this final rule. EPA's
analytic baseline includes the final requirements of these rules using the most recent data provided under
the CCR rule reporting and recordkeeping requirements. This is further described in the TDD (see Section
3, U.S. EPA, 2024e).12
Concurrently with the final ELG, in a separate rulemaking, EPA is also finalizing regulatory requirements
for inactive CCR surface impoundments at inactive utilities ("legacy CCR surface impoundment" or
"legacy impoundment"). This action is being taken in response to the August 21, 2018, opinion by the
U.S. Court of Appeals for the District of Columbia Circuit in the USWAG decision that vacated and
remanded the provision exempting legacy impoundments from the CCR regulations. This action includes
adding a definition for legacy CCR surface impoundments and other terms relevant to this rulemaking. It
also requires that legacy CCR surface impoundments comply with certain existing CCR regulations with
tailored compliance deadlines.
EPA is also establishing requirements to address the risks from currently exempt solid waste management
that involves the direct placement of CCR on the land. EPA is extending a subset of the existing
requirements in 40 CFR part 257, subpart D to CCR surface impoundments and landfills that closed prior
to the effective date of the 2015 CCR rule, inactive CCR landfills, and other areas where CCR is managed
directly on the land. In this action, EPA refers to these as CCR management units, or CCRMU. This rule
12 For more information on the CCR Part A and Part B rules, including information about ongoing implementation of
these rules, visit https://www.epa.gov/coalash/coal-ash-rule.
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will apply to all existing CCR facilities and all inactive facilities with legacy CCR surface impoundments
subject to this final rule.
Finally, EPA is making a number of technical corrections to the existing regulations, such as correcting
certain citations and harmonizing definitions.13
2.2.2 Air Pollution Rules and Implementation
EPA is taking several actions to regulate a variety of conventional, hazardous, and greenhouse gas (GHG)
air pollutants, including actions to regulate the same steam electric plants subject to part 423. 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
power plant operations, EPA has accounted for these changed operations in its Integrated Planning Model
(IPM) modeling discussed in Chapter 5 of this document.
2.2.2.1 The Revised Cross State Air Pollution Rule Update and the Good Neighbor Plan for the 2015
Ozone National Ambient Air Quality Standards
On June 5, 2023, EPA promulgated its final Good Neighbor Plan, which secures significant reductions in
ozone-forming emissions of nitrogen oxides (NOx) from power plants and industrial facilities. 88 FR
36654. The Good Neighbor Plan ensures that 23 states meet the Clean Air Act's (CAA's) "Good
Neighbor" requirements by reducing pollution that significantly contributes to problems attaining and
maintaining EPA's health-based air quality standard for ground-level ozone (or "smog"), known as the
2015 Ozone National Ambient Air Quality Standards (NAAQS), in downwind states. Further information
on this action is available on EPA's website.14
As of September 21, 2023, the Good Neighbor Plan's "Group 3" ozone-season NOx control program for
power plants is being implemented in: Illinois, Indiana, Maryland, Michigan, New Jersey, New York,
Ohio, Pennsylvania, Virginia, and Wisconsin. Pursuant to court orders staying the Agency's State
Implementation Plan disapproval action in the following states, EPA is not currently implementing the
Good Neighbor Plan "Group 3" ozone-season NOx control program for power plants in: Alabama,
Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah, and
West Virginia.15
On January 16, 2024, EPA signed a proposal to partially approve and partially disapprove State
Implementation Plan submittals addressing interstate transport for the 2015 ozone NAAQS from Arizona,
Iowa, Kansas, New Mexico, and Tennessee and proposed to include these states in the Good Neighbor
Plan beginning in 2025.
13 For further information on the CCR regulations, including information about the CCR Part A and Part B rules' ongoing
implementation, visit www. eva. gov/coalash/'coal-ash-rule
14 See https://www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqs^
15 Further information on EPA's response to the stay orders can be found online at: https://www.epa.gov/CrossState-Air-
Polliition/epa-response-jiidicial-stay-orders.
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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). Together, these two rules establish the Group 2 and Group 3 market-based emissions trading
programs for 22 states in the eastern United States for emissions of NOx from fossil fuel-fired EGUs
during the summer ozone season.16
2.2.2.2 Clean Air Act Section 111 Proposed Rule
Concurrently with the final ELG, EPA is finalizing the repeal of the Affordable Clean Energy Rule,
establishing Best System of Emissions Reduction (BSER) determinations and emission guidelines for
existing fossil fuel-fired EGUs, and establishing BSER determinations and accompanying standards of
performance for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion
turbines and modified fossil fuel-fired EGUs. Specifically, for coal-fired EGUs, EPA is establishing final
standards based on carbon capture and storage/sequestration with 90 percent capture with a compliance
date of January 1, 2032. For coal-fired EGUs retiring by January 1, 2039, EPA is establishing final
standards based on 40 percent natural gas co-firing with a compliance date of January 1, 2030.
While four subcategories for coal-fired EGUs were proposed, EPA is finalizing just the two subcategories
for coal-fired EGUs as described in the preceding paragraph. Consistent with 40 CFR 60.24a(e) and the
Agency's explanation in the proposal, states have the ability to consider, inter alia, a particular source's
remaining useful life when applying a standard of performance to that source.17
In addition, EPA is creating an option for states to provide for a compliance date extension for existing
sources of up to one year under certain circumstances for sources that are installing control technologies
to comply with their standards of performance. States may also provide, by inclusion in their state plans, a
reliability assurance mechanism of up to one year that under limited circumstances would allow existing
EGUs that had planned to cease operating by a certain date to temporarily remain available to support
reliability. Any extensions exceeding 1-year must be addressed through a state plan revision.18
2.2.2.3 Mercury and Air Toxics Standards Final Rule
On March 6, 2023, EPA published a final rule which reaffirmed that it remains appropriate and necessary
to regulate hazardous air pollutants (HAP), including mercury, from power plants after considering cost.
This action revoked a 2020 finding that it was not appropriate and necessary to regulate coal- and oil-fired
power plants under CAA section 112, which covers toxic air pollutants. EPA reviewed the 2020 finding
and considered updated information on both the public health burden associated with HAP emissions
from coal- and oil-fired power plants, as well as the costs associated with reducing those emissions under
the Mercury and Air Toxics Standards (MATS). After weighing the public risks these emissions pose to
16 See www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqs._
17 See 88 FR 33383 (invoking Remaining Useful Life and Other Factors (RULOF) based on a particular coal-fired EGU's
remaining useful life "is not prohibited under these emission guidelines").
18 Further information about the CAA section 111 rule is available online at https://www.epa.gov/stationary-sonrces-air-
pollntion/greenhouse-gas-standards-and-gnidelines-fossil-fiiel-fired-power. https://www.epa.gov/stationarv-sources-
air-pollution/greenhouse-gas- standards- and-guidelines-fossil-fuel-fired-power.
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all Americans (and particularly exposed and sensitive populations) against the costs of reducing this
harmful pollution, EPA concluded that it remains appropriate and necessary to regulate these emissions.
This action ensures that coal- and oil-fired power plants continue to control emissions of hazardous air
pollution and that the Agency properly interprets the CAA to protect the public from hazardous air
emissions.
Concurrently with the final ELG, EPA is finalizing an update to the National Emission Standards for
Hazardous Air Pollutants for Coal- and Oil-Fired EGUs, commonly known as the Mercury and Air
Toxics Standards (MATS) for power plants, to reflect recent developments in control technologies and
the performance of these plants. This final rule includes an important set of improvements and updates to
MATS and also fulfills EPA's responsibility under the Clean Air Act to periodically re-evaluate its
standards in light of advancements in pollution control technologies to determine whether revisions are
necessary. The improvements consist of:
• Further limiting the emission of non-mercury HAP metals from existing coal-fired power plants
by significantly reducing the emission standard for filterable particulate matter (fPM), which is
designed to control non-mercury HAP metals. EPA is finalizing a two-thirds reduction in the fPM
standard;19
• Tightening the emission limit for mercury for existing lignite-fired power plants by 70 percent;2"
• Strengthening emissions monitoring and compliance by requiring coal-and oil-fired EGUs to
comply with the fPM standard using PM continuous emission monitoring systems (CEMS);21
• Revising the startup requirements in MATS to assure better emissions performance during
startup.
Additional information on the final MATS is available on EPA's website.22
2.2.2.4 National Ambient Air Quality Standards Rules for Particulate Matter Final Rule
On February 7, 2024, the EPA Administrator signed a final rule strengthening the National Ambient Air
Quality Standards for Particulate Matter (PM NAAQS) to protect millions of Americans from harmful
and costly health impacts, such as heart attacks and premature death. Particle or soot pollution is one of
the most dangerous forms of air pollution, and an extensive body of science links it to a range of serious
and in some cases deadly illnesses. EPA set the level of the primary (health-based) annual particulate
matter (PM2.5) standard at 9.0 micrograms per cubic meter to provide increased public health protection,
consistent with the available health science. EPA did not change the current primary and secondary
(welfare-based) 24-hour PM2 5 standards, the secondary annual PM2 5 standard, and the primary and
19 Also, EPA is finalizing the removal of the low-emitting EGU provisions for fPM and non-mercury HAP metals.
20 This level aligns with the mercury standard that other coal-fired power plants have been achieving under the current
MATS.
21 PM CEMS provide regulators, the public, and facility owners or operators with cost-effective, accurate, and continuous
emission measurements. This real-time, quality-assured feedback can lead to improved control device and power plant
operation, which will reduce air pollutant emissions and exposure for local communities.
22 See https://www.epa.gov/stationary-soitrces-air-pollittion/mercitry-and-air-toxics-standards.
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secondary PM10 standards. EPA also revised the Air Quality Index to improve public communications
about the risks from PM2.5 exposures and made changes to the monitoring network to enhance protection
of air quality in communities overburdened by air pollution. More information about this action is
available on EPA's website.23
2.2.3 Greenhouse Gas Reduction Targets
On April 22, 2021, President Biden announced 2030 GHG reduction targets for the United States.24 As
part of reaching net zero emissions by 2050, the nationally determined contribution submitted to the
United Nations Framework Convention on Climate Change includes a 50 percent to 52 percent reduction
from 2005 levels by 2030. These reduction targets were developed through the National Climate Task
Force and support the commitments of the United States under the Paris Agreement. These policies are
anticipated to result in significantly reduced reliance on coal-fired generation.
The steam electric sector is one of the largest contributors of U.S. GHG emissions. EPA estimates that
25 percent of 2021 GHG emissions in the U.S. came from electricity generation (largely comprised of
emissions from steam electric power plants).25 Although this fraction continues to decline, several models
looking at plausible pathways to meet the announced 2030 goal have determined that as much as 90 to
100 percent of coal combustion may have to be reduced (Bistline et al., 2022).
2.2.4 Inflation Reduction Act of 2022
On August 16, 2022, President Biden signed into law the Inflation Reduction Act (IRA). The IRA marks
the most significant action Congress has taken on clean energy and climate change in the nation's history.
The IRA provides tax credits, financing programs, and other incentives, some of which are administered
by EPA, that will accelerate the transition to forms of energy that produce little or no greenhouse gas
emissions and other water and air pollutants. As such, it includes many provisions that will affect the
steam electric power generating industry, causing both direct effects through changes in the production of
electricity and indirect effects on electricity demand and changes to fuel markets.
In September 2023 EPA published a report on the effect of the IRA on the electricity sector and on the
economy in general (U.S. EPA, 2023c).The report found that the IRA would lead to emission reductions
from the electric power sector of 49 to 83 percent below 2005 levels in 2030. The associated shifts from
fossil fuel generation would also lead to reductions in water and air pollution from the sector. The study
also found that the IRA would lower economy-wide CO2 emissions, including emissions from electricity
generation and use, by 35 percent to 43 percent below 2005 levels in 2030. Across the end-use sectors,
the study found that buildings exhibit the greatest reductions from 2005 levels of direct plus indirect CO2
emissions from electricity, followed by industry and transportation. Though it focuses on changes in
climate-forcing emissions (in part attributable to the models it uses), the study also implies important
changes in the emissions of other pollutants throughout the economy. EPA used IPM to evaluate the
impacts of the final ELG relative to a baseline that reflects impacts from other relevant policies and
23 See https://www.epa.gov/pm-pollittion/national-ambient-air-qnality-standards-naaqs-pm.
24 See https://www.wliitehoiise.gov/briefmg-room/statements-releases/2021/04/22/fact-sheet-president-biden-sets-2030-
greenlioiise-gas-polliition-rediiction-target-ainied-at-creating-good-paying-iinion-jobs-and-seciiring-11-s-leadership-on-
clean-energy-technologies/.
25 See https://www.epa.gov/ghgeniissions/soiirces-greenlioiise-gas-eniissions.
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environmental regulations that affect the power sector, including the IRA and other on-the-books federal
and state rules (see Chapter 5 for additional information).
2.2.5 Recent Developments in Assuring Electric Reliability and Resource Adequacy
The nature and components of the bulk power sector have been evolving away from older and less
efficient legacy fossil generation (mostly coal power plants) towards more decentralized, renewable assets
and flexible gas-fired generation. Stakeholders have raised concerns that centralized dispatchable power
plants are coming offline faster than new generation can replace the reliability attributes associated with
them. However, a combination of technology innovation, revised market signals from the Regional
Transmission Organizations (RTOs) and Independent System Operators (ISOs), and reforms recently
completed and underway by Federal Energy Regulatory Commission (FERC) are collectively poised to
address current reliability challenges associated with the transition along with expected higher load
growth and the increasing frequency of extreme weather events.
EPA has continued to learn and engage on reliability issues, particularly as part of the Agency's
implementation of the Joint Memorandum on Interagency Communication and Consultation on Electric
Reliability?6 As part of this process, EPA has engaged in regular meetings with Department of Energy
(DOE), North American Electric Reliability Corporation (NERC), FERC, and the various ISOs/RTOs.
FERC, NERC, RTOs, and ISOs are already taking steps to ensure reliability during this period of asset
evolution. Among FERC's actions to help address reliability is Order 2023, or "Improvements to
Generator Interconnection Procedures," which will help expedite interconnections for new assets waiting
to connect to the grid. This is a very important development to ensure future resource adequacy because
interconnection wait times for new energy assets entering energy markets have increased, which is stifling
the ability of replacement generation to connect to the grid. FERC's final action on extreme cold weather
preparedness will support the new peak demand hours, which have migrated to winter months. New
reliability standards issued for inverter-based resources "will help ensure reliability of the grid by
accommodating the rapid integration of new power generation technologies, known as inverter-based
resources (IBRs), that include solar photovoltaic, wind, fuel cell and battery storage resources... ,"27
FERC has also undertaken various transmission-related efforts, from inter-regional transmission capacity
efforts to reconductoring and dynamic line rating, that would help bolster reliability by increasing the
transmission capacity of existing lines and creating incentives for new, inter-regional transmission.
Increasing transmission capacity can enhance reliability by increasing the amount of generation that can
access the grid to help meet demand.
Furthermore, there are new technologies coming online that can also help provide reliability attributes.
The deployment of many of these technologies has been accelerating due to the incentives in the IRA.
The rapid increase in energy storage deployment across the nation is an important part of future grid
reliability, particularly as the duration of storage assets expands. Examples of existing and emerging
storage resources include various types of fuel cells, batteries, pumped hydro-electric reservoirs, and
underground hydrogen caverns. Energy storage can help buttress reliability by storing renewable energy
26 Available online at: https://www.epa.gov/power-sector/electric-reliability-mou.
27 For further information about FERC actions to address IBRs, see httvs://www.ferc.eov/news-events/news/ferc-maves-
vrotect-srid-transition-clean-eners\'-resources.
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for dispatch when demand is high. Improved management of demand response assets, better designed
electricity tariff structures, aggregation of distributed resources like roof-top solar panels, and integration
of behind-the-meter battery storage can further support balancing peak demand on power grids. For
example, programs to manage demand, which have shown value well before the recent energy transition,
incentivize customers to shift their demand during periods when there is ample supply, which can help
reduce instances when supply is tight.
Despite these concerns, there are also existing procedures in place to ensure electricity system reliability
and resource adequacy over both the short and long-term. For example, regional planning organizations
typically have incentive or planning procedures to ensure that there is sufficient capacity to meet future
demand such as day-ahead reserve and capacity markets and seasonal reserve margins. Furthermore, EPA
understands that before a unit implements a retirement decision, the unit's owner will follow the
processes put in place by the relevant RTO, balancing authority, or state regulator to protect electric
system reliability. These processes typically include analysis of the potential impacts of the proposed
EGU retirement on electrical system reliability, identification of options for mitigating any identified
adverse impacts, and, in some cases, temporary provision of additional revenues to support the EGU's
continued operation until longer-term mitigation measures can be put in place.
2.3 Market Conditions and Trends in the Electric Power Industry
The 34 percent decline in coal-fueled electricity generation summarized in Table 2-7 for the period of
2015 through 2021 exemplifies an ongoing trend over the last decade: the progressive reduction in coal-
fired generation capacity as coal units and plants retire. In 2023, EIA reported that retirements of coal
generation capacity in the US in 2022 were 11.5 GW, slightly higher than the average of 11 GW per year
between 2015 to 2020. Moreover, EIA predicted that coal-fired and natural gas utility-scale power plant
retirements in 2023 would account for 58 and 40 percent of total electric generating capacity retirements
for that year, corresponding to 8.9 and 6.2 GW respectively (EIA, 2022b; EIA, 2023c). Capacity additions
in the same year are predicted to consist primarily of solar (54 percent), natural gas (14 percent), and wind
(11 percent).
One factor in the decline in the coal-fueled power generation is the aging fleet of coal-fired power plants.
The life expectancy of coal plants is approximately 40 to 50 years, and with the majority of plants being
built in the 1970s and 1980s, almost all plants that retired in 2015 were more than 40 years old (Kolstad,
2017; EIA, 2023c). Mills, Wiser and Seel (2017) also found that coal plants that retired between 2010 and
2016 had an average age of 52 years, and plants with stated plans to retire were not younger on average.
Coal plant retirements due to aging are likely to continue in the coming years, as the average age of coal
plants in operation in the United States as of 2021 is 45 years (EIA, 2021b)
The lower costs of natural gas, as well as technological advances in solar and wind power have also been
important market factors. Fell and Kaffine (2018) found negative impacts on coal-fired generation from
both lower natural gas prices and increased wind generation, with declining natural gas prices having a
stronger effect. In 2019, coal-fired generation dropped to its lowest level since 1976, primarily driven by
increased availability of highly efficient, low-cost natural gas generation, which has reduced coal plant
utilization and resulted in the retirement of some coal plants (EIA, 2020).
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In 2021, EIA reported that coal generation increased for the first time since 2014. However, this was a
temporary divergence from a longer-term trend as additional retirements of coal-fired plants and lower
natural gas prices caused coal-fired electricity generation to fall once again in 2022 (EIA, 2023d). This
2022 decline was exacerbated by a coal supply shortage, precipitated by diminished electricity demand
due to pandemic-related economic impacts, as well as a 9 percent reduction in coal production resulting
from declining global coal demand and heightened competition from natural gas (EIA, 2023d).
Russia's 2022 invasion of Ukraine and the subsequent agreement between the United States and European
Commission to supply additional liquefied natural gas (LNG) to the European market resulted in
increased energy prices. With Russia being a huge supplier of the world's oil and natural gas, cutbacks in
supply and geopolitical uncertainty caused higher prices and volatility across global energy markets.
While coal was temporarily cost-competitive with natural gas, leading to the observed increases in coal-
fired generation, this short-term impact has ceased with natural gas prices falling to their pre-invasion
prices, at the start of 2023. (Federal Reserve Bank of St. Louis, 2023; The White House, 2022; Wilson,
2022).
Knittel, Metaxoglou and Trindade (2015) found that utilities invested more in natural gas capacity when
the prices dropped as a result of the boom in shale gas production, although the magnitude of their
investments differed depending on the structure of the electricity market in which they operated.
Additionally, in 2020, renewable electricity generation surpassed coal-fired electricity generation as much
of the US's coal-fired generation capacity has been replaced or converted to natural gas-fired generation
since 2007 (EIA, 2021c). Furthermore, in 2022, generation from renewable sources - wind, solar, hydro,
biomass, and geothermal - surpassed coal-fired generation in the electric power sector for the first time.
In the preceding year, 2021, renewables had already outpaced nuclear generation for the first time, and
this trend persisted, with renewable sources consistently providing more electricity than nuclear
generation throughout the subsequent year (EIA, 2023g).
Changes in electricity generation have had impacts in fuel markets. Coal consumption in the electric
power industry declined by about 40 percent between 2005 and 2017, whereas natural gas consumption
increased by about 24 percent in the same time period, resulting in natural gas consumption doubling coal
consumption in 2017 (EIA, 2018). In 2021, EIA reported that the number of producing coal mines in the
United States was 548, representing a 62 percent drop since the most recent peak in 2008 of 1,435
producing mines (EIA, 2019, 2023a). EIA reported that this reduction in producing coal mines reflects
reductions in investments in the coal industry and declining international and domestic decline for coal
(EIA, 2021a). In 2022, EIA reported that natural gas consumption totaled 33.4 quadrillion British thermal
units (quads) and that coal consumption totaled 9.85 quads (EIA, 2023j). Market conditions have also
negatively affected nuclear-powered generation, though this final rule has no effect on the nuclear-
powered sector, except as it affects relative prices through its impacts on coal-fired generation (EIA,
2022e).
The decline in coal is not independent of environmental regulations affecting coal-fired electricity
generation, as power companies have cited regulations promulgated, particularly in the last decade, as
reasons for their decision when announcing unit or plant closures, fuel switching, or other operational
changes. However, fuel prices and trends toward alternative fuels also appear to be drivers of the shift
away from coal for electricity generation. Coglianese, Gerarden and Stock (2020) found that the decrease
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in natural gas prices accounted for 92 percent of the decline in coal production while environmental
regulations accounted for 6 percent. Linn and McCormack (2019) found that while air emissions
regulations were responsible for most reductions in nitrogen oxides from the electricity sector, they had
only a small effect on profitability and retirement at coal plants.
As the electric power infrastructure adjusts to market trends by moving toward optimal infrastructure and
operations to deliver the country's electricity, EPA recognizes that the changes can have negative effects
for some communities and positive effects for others.
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3 Compliance Costs
In developing the final rule, EPA assessed the costs and economic impacts for three regulatory options
summarized in Table 1-1. The options are labeled Option A through Option C in order of the stringency
of the effluent limits, relative to the baseline. Key inputs for these analyses include the estimated costs to
steam electric power plants (and their business, government, or non-profit owners) for implementing
control technologies upon which the final BAT limitations and pretreatment standards are based,28 and to
the state and federal government for administering this rule. This chapter summarizes EPA estimates of
the incremental compliance costs attributable to the regulatory options. EPA determined that state and
federal governments would not incur significant incremental administrative costs.29
EPA applied the same methodology used to analyze the 2015 and 2020 rules, as well as the 2023
proposed rule, to calculate industry-level annualized compliance costs. See Chapter 3 of the respective
RIA documents for details (U.S. EPA, 2015, 2020, 2023d). Additionally, EPA estimated that some plants
incurred compliance costs for CRL treatment after the expected retirement year.
Costs associated with legacy wastewater limits under Options B and C would be incurred only as plants
close and dewater their existing ponds. There is uncertainty on when plants may do so. For the purpose of
this analysis, EPA anticipates that pond closures will occur on 2044 for all plants and that plants will
incur initial one-time costs (e.g., capital costs) in this year followed by O&M costs in the following years
of the analysis (there are no incremental legacy wastewater costs under Option A).3" Similarly, certain
plants could incur costs associated with the treatment of unmanaged CRL discharged from landfills,
surface impoundments, or other features in cases where a permitting authority deems, on a case-by-case
basis, the discharge to be the functional equivalent of a direct discharge and requiring a permit. The costs
associated with treatment of unmanaged CRL are uncertain. As a result, the Agency estimated lower- and
upper-bound cost estimates for treating unmanaged CRL. These unmanaged CRL costs are added to the
costs associated with CRL treatment incurred by plants. As a result, the total costs for all regulatory
options as well as their estimated impacts on plants and entities are estimated using a lower and upper
bound of costs.
The TDD describes the control technologies and their respective wastewater treatment performance in
greater detail (U.S. EPA, 2024e). The TDD also describes how EPA estimated plant-specific capital and
operation and maintenance (O&M) costs for each treatment technology, as well as for BMP plans. The
cost analysis uses the 2020 rule as the baseline and incorporates technologies that plants have
implemented, or would implement, to meet the 2020 ELGs, in absence of the changes in this final rule.
28 Dischargers are not required to use the technologies specified as the basis for the rule. They are free to identify other
perhaps less expensive technologies as long as they meet the BAT limitations and pretreatment standards in the rule.
29 EPA estimates that the final rule will not impose significant additional administrative cost to the State and federal
governments. See Section 10.7, Paperwork Reduction Act of1995, for additional discussion.
30 Assuming the same 40-year surface impoundment operating life used in the 2015 CCR rule record and acknowledging
that these impoundments could be anywhere in that 40-year lifespan, EPA used the midpoint of 20-years as a
reasonable approximation for purposes of ensuring that these costs are included in the main cost analyses of the final
rule. To the extent that costs could be incurred before this date at some plants and after this date at other plants, these
nationwide costs may either over- or underestimate the site-specific costs at any particular plant.
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3.1 Analysis Approach and Inputs
EPA updated estimated costs to plants for meeting the limitations of the regulatory options. There are four
principal steps to compliance cost development, the last two of which are the focus of the discussion
below:
1. Determining the set of plants potentially implementing compliance technologies for each
regulatory option. See TDD for details (U.S. EPA, 2024e).
2. Developing plant-level costs for each wastestream and technology option. See TDD for details.
3. Estimating the year when each steam electric power plant would be required to meet new BAT
effluent limits and pretreatment standards. This schedule supports analysis of the timing of
compliance costs and benefits for analyses discussed in this document and in the BCA. EPA
accounted for any planned unit retirements or units ceasing the combustion of coal but did
estimate that some units will incur compliance costs associated with CRL treatment after
retirement or ceasing the combustion of coal (see the TDD for details regarding how EPA
estimated leachate flow rates for these plants).
4. Estimating total industry costs for all plants in the steam electric universe for each of the
regulatory options.
EPA reports costs in 2023 dollars and discounts the costs to 2024.
3.1.1 Plant-Specific Costs Approach
As detailed in the TDD (U.S. EPA, 2024e), EPA developed costs for steam electric power plants to
implement treatment technologies or process changes to control the wastestreams addressed by the
regulatory options.
EPA assessed the operations and treatment system components currently in place at a given unit (or
required to be in place to comply with other existing environmental regulations), identified equipment and
process changes that plants would likely make to meet each of the regulatory options presented in Table
1-1. EPA developed costs to meet each regulatory option based on current plant equipment, processes,
and treatment technologies, accounting for compliance with the 2020 rule in the baseline. Thus, the
estimated costs of the regulatory options are additive to the costs of treatment technologies that plants
have implemented or would implement to meet the 2020 rule. Plants that do not generate a wastestream or
that employ technologies which would already meet the given limitations or standards do not incur
incremental costs under the regulatory options.
In cases where several different technology options were available to meet the regulatory option limits,
EPA estimated the costs of each possible option and selected the least-cost technology for each plant. For
example, as detailed in the TDD, for zero-discharge systems used to meet FGD and CRL limits under
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Option B and Option C, EPA generally selected the least cost option between systems using membrane
filtration or spray dry evaporators (SDEs).31
As noted above, there is uncertainty on which plants may incur costs to meet effluent limits for
unmanaged CRL as it will depend on case-by-case findings by future permitting authorities. To account
for this uncertainty, EPA developed lower and upper bound scenarios that provide a range of probabilistic
cost estimates based on different sets of assumptions regarding which plants may incur costs and the
compliance approach. The upper bound scenario is based on probabilistically combining three sets of
plant-level cost estimates using equal weights: cost estimates based on (1) each plant's closest waste
management unit (WMU; either an impoundment or a landfill), (2) cases of corrective action at the WMU
level, and (3) cases of corrective action where surface impoundment flows are combined at the plant
level. The lower bound scenario is based on probabilistically combining plant-level costs estimates based
on corrective action remedies at the WMU level or at the plant level combined with the share of remedies
expected to use pumping and treating of groundwater (either alone or in combination with other remedies
with groundwater collection or extraction), which make unmanaged CRL most likely to be subject to the
limitations in the final rule and therefore to incur costs. Like for the upper bound scenario, EPA assumed
that cost estimates were equally probable in calculating a probabilistic average plant-level cost. U.S. EPA
(2024d) provides additional details on the approach used to estimate costs for unmanaged CRL treatment.
3.1.2 Plant-Level Costs
Following the approach used for the analysis of the 2015 and 2020 rules and 2023 proposal (U.S. EPA,
2015, 2020, 2023d), EPA estimated compliance costs for all existing steam electric power plants,
estimated to be a total 858 plants for the point source category overall. EPA assessed that only a fraction
of the universe of steam electric power plants — 232 plants — generate the wastestreams covered by the
regulatory options. Furthermore, out of these plants, only a subset would incur non-zero costs under any
of the scenarios analyzed for the regulatory options, based on existing control technologies. This subset of
plants that incur non-zero costs varies depending on the regulatory option and cost scenario (Between 139
and 170 plants incur non-zero costs across the three regulatory options and two cost scenarios). The TDD
provides additional details on this analysis.
The major components of technology costs are:
• Capital costs include the cost of compliance technology equipment, installation, site preparation,
construction, and other upfront, non-annually recurring outlays associated with compliance with
the regulatory options. EPA generally assumes that plants incur all capital costs in the year when
their permit is renewed to incorporate the new limitations or standards (see Technology
Implementation Years below). As explained in the TDD, all compliance technologies are assumed
to have a useful life of 20 years.
31 One exception to this approach is CRL where EPA selected membrane filtration as the basis of the estimated
compliance costs for five plants that are projected to cease operation after the period of analysis even though SDEs
costs would have been lower. This resulted in the estimated total compliance costs for Option B and Option C
presented in Section 3.2 being overstated by approximately $6 million (1.5 percent) on an after-tax basis.
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• Initial one-time costs (apart from capital costs above), if applicable, include a one-time
monitoring and recordkeeping cost in the first year if operation for plants operating membrane
filtration system to treat FGD wastewater or CRL wastewater (see TDD for more information).
• Annual fixed O&M costs, if applicable, include regular annual monitoring. Plants incur these
costs each year.
• Annual variable O&M costs, if applicable, include annual operating labor, maintenance labor and
materials, electricity required to operate wastewater treatment systems, chemicals, combustion
residual waste transport and disposal operation and maintenance, and savings from not operating
and maintaining ash/FGD pond systems. Plants incur these costs each year.
In addition to these initial one-time and annual outlays, certain other costs are estimated to be incurred on
a non-annual, periodic basis:
• 5-Yr fixed O&M costs, if applicable, include remote MDS chain replacement costs that plants are
estimated to incur every five years, beginning five years after the technology implementation
year.
• 6-Yr fixed O&M costs, if applicable, include mercury analyzer operations and maintenance costs
that plants are estimated to incur every six years, beginning in the technology implementation
year.
• 10-Yr fixed O&M costs, if applicable, include savings from not needing to periodically maintain
ash/FGD pond systems. Plants are estimated to incur savings every 10 years from not needing to
purchase earthmoving equipment for the pond systems, beginning 5 years after the technology
implementation year.
Based on information in the record concerning the normal downtime of electricity generating units, EPA
estimated that plants would be able to coordinate the implementation of wastewater treatment systems
during already scheduled downtime.
3.1.3 Technology Implementation Years
The years in which individual steam electric power plants are estimated to implement control
technologies are an important input to the time profile of costs that plants would incur due to the
regulatory options. This profile is used to estimate the annualized costs to the steam electric industry and
society associated with the regulatory options.
EPA envisions that each plant to which the regulatory options would apply would study available
technologies and operational measures, and subsequently install, incorporate, and optimize the technology
most appropriate for each site. As part of its consideration of the technological availability and economic
achievability of the BAT limitations and pretreatment standards in the rule and following the approach the
Agency used for the 2015 and 2020 rules as well as the 2023 proposal, EPA considered the magnitude
and complexity of process changes and new equipment installations that would be required at plants to
meet the requirements of the regulatory options in determining the time plant owners may need to comply
with any revised limitations or pretreatment standards. See discussion in the TDD (U.S. EPA, 2024e).
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As described in greater detail in the NPRM, EPA is establishing availability timing for BAT limitations
that is "as soon as possible" after the effective date of any final rule but "no later than" five years from the
effective date (i.e., a2029 deadline).32
The timing decision represents when the technologies are available, accounting for the need to provide
sufficient time for plant owners to raise capital, plan and design systems, procure equipment, and
construct and then test systems. EPA also considered the time frames needed for appropriate
consideration of any plant changes being made in response to other agency rules affecting the steam
electric power generating industry. Specifying compliance deadlines in the future enables plants to take
advantage of planned shutdown or maintenance periods to install new pollution control technologies. This
allows for the coordination of generating unit outages in order to maintain grid reliability and prevent any
potential impacts on electricity availability caused by forced outages. It is not possible to predict, for each
plant, exactly the date the final rule will be incorporated into permits, for purposes of determining exactly
when plants will incur costs to meet the new requirements. Similar to the approach used in analyzing the
2015, 2020, and proposed 2023 rules, EPA generally expects plants to meet the new BAT limitations and
pretreatment standards in a somewhat staggered fashion, given that (1) the permitting authority
determines the date after considering certain specified factors, and (2) all permits are not re-issued at the
same time due to their 5-year permit term. Thus, for the cost and economic impact analyses, EPA
assumed implementation over a 5-year period preceding the established "no later than" date.33'34
Costs associated with legacy wastewater limits under Options B and C would be incurred only as plants
close and dewater their existing ponds. Given the uncertainty on when plants may do so, for the purpose
of this analysis EPA assumed that any pond closures would occur after 2044 and further assumed that
costs to comply with the limits would be incurred starting in that year.
Similarly, certain plants could incur costs associated with the treatment of unmanaged CRL discharged
from landfills, surface impoundments, or other features in cases where a permitting authority deems, on a
case-by-case basis, the discharge to be the functional equivalent of a direct discharge and requiring a
permit. Because these discharges are uncertain, EPA assumed plants would incur costs associated with
treating unmanaged CRL at the same time as other wastewater treatment technologies.
For the purpose of this analysis, EPA accounted for the timing of announced unit retirements or
repowerings in determining the compliance year for the plant. Specifically, in cases where the announced
retirement occurs after the default compliance year based on the permit renewal cycle but before the rule
compliance deadline, EPA assumed that permit authorities would set the "no later than" compliance date
32 EPA did not estimate costs over different timeframes for indirect dischargers. The CWA mandates that such
dischargers meet applicable standards three years from promulgation of final PSES. This timing is consistent with the
modeling approach during Period 1 as described in the BCA.
33 For the purpose of the analysis, EPA assigned an estimated compliance year to each of the 232 steam electric power
plants analyzed for the final rule based on each plant's estimatedNPDES permit renewal year and, similar to the
approach used for the 2015 and 2020 rules and 2023 proposal, the assumption that all permits will be renewed promptly
(no administrative continuances). EPA projected future NPDES permit years by assuming permits are renewed every 5
years, i.e., a permit expiring in 2023 would be renewed in 2028 and 2033.
34 EPA initially estimated a compliance year for each plant based on a compliance deadline of 2030. During the analyses,
EPA subsequently revised the deadline to 2029 and revised plant-specific compliance years by subtracting one year for
each plant rather than re-estimating compliance years only for those plants whose compliance year did not meet the
deadline.
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to correspond to the retirement date. In these cases, the plant would incur no incremental costs to comply
with the final rule.
EPA also accounted for announced unit retirements or repowerings in the social cost analysis, which is
discussed and detailed in Chapter 12 of the BCA. Specifically, EPA assumed zero O&M costs for BA
transport water and FGD wastewater treatment in all years following a unit's retirement or repowering,
but continued O&M costs for CRL since treatment of the CRL wastewater is expected to continue even
after a unit ceases to generate electricity.
3.1.4 Total Compliance Costs
EPA used the following methodology and assumptions to aggregate compliance cost components,
described in the preceding sections, and develop total plant compliance costs for regulatory options A
through C:
• EPA estimated compliance costs (including zero costs) for each of the 232 steam electric power
plants with the relevant wastestreams, i.e., coal-fired power plants (see TDD for details). All
other plants covered by the steam electric power point source category do not generate
wastestreams covered by the regulatory options and therefore incur zero costs.
• EPA restated compliance costs estimated in the preceding step, accounting for the specific years
in which each plant is assumed to undertake compliance-related activities and in 2023 dollars,
using the Construction Cost Index (CCI) from McGraw Hill Construction (2023), the
Employment Cost Index (ECI) published by the Bureau of Labor Statistics (BLS) (2023), and the
Gross Domestic Product (GDP) deflator index published by the U.S. Bureau of Economic
Analysis (BEA) (2023).35
• EPA discounted all cost values to 2024, using a rate of 3.76 percent.36
35 Specifically, EPA brought all compliance costs to an estimated technology implementation year using the CCI from
McGraw Hill Construction (McGraw Hill Construction Engineering News-Record. (2023). Construction Cost Index
(CCI) ) or the ECI from the Bureau of Labor Statistics (U.S. Department of Labor. Bureau of Labor Statistics. (2023).
Total compensation for All Civilian workers in All industries and occupations, Index ), depending on the cost
component. The Agency used the average of the year-to-year changes in the CCI (or ECI) over the most recent ten-year
reporting period to bring these values to an estimated compliance year. Because the CCI (or ECI) is a nominal cost
adjustment index, the resulting technology cost values are as of the compliance year and in the dollars of the
technology implementation year. To restate compliance cost values in 2023 dollars, the Agency deflated the nominal
dollar values to 2023 using the average of the year-to-year changes in the GDP deflator index published by the BEA
over the most recent ten-year reporting period. As a result, all dollar values reported in this analysis are in constant
dollars of the year 2023.
36 Compliance costs are discounted and annualized using a rate of 3.76 percent, which is the estimated weighted average
cost of capital for the power sector (see U.S. Environmental Protection Agency. (2023a). Documentation for EPA's
Power Sector Modeling Platform v6 Using the Integrated Planning Model Post-IRA 2022 Reference Case. Retrieved
from https://www.epa.gov/system/files/documents/2023-03/EPA%20Platform%20v6%20Post-
IRA%202022%20Reference%20Case.pdf for details). This rate differs from the social discount rate of 2 percent
used when presenting the social costs and benefits in the BCA, following OMB guidance in Circular A-4 (U.S. Office
of Management and Budget. (2023). Circular A-4: Regulatory Analysis. Retrieved from
https://www.whitehouse.gov/wp-content/uploads/2023/ll/CircularA-4.pdf).
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• EPA annualized one-time costs and costs recurring on other than an annual basis over a specific
useful life, implementation, and/or event recurrence period, using a rate of 3.76 percent:37
- Capital costs of each compliance technology: 20 years
- Initial one-time costs: 20 years38
- 5-Yr O&M: 5 years
- 6-Yr O&M: 6 years
- 10-Yr O&M: 10 years
• EPA added annualized capital, initial one-time costs, and annualized O&M costs recurring on
other than an annual basis to the annual O&M costs to derive total annualized compliance costs.
EPA accounted for the timing of announced plant retirements in determining the useful life over which to
annualize recurring costs. In cases where a plant's announced retirement year occurs after the first
instance of a recurring O&M cost for BA transport water and FGD wastewater treatment but before the
second instance, EPA adjusted the useful life of that cost category to be the number of years that the plant
is expected to operate after the first instance.
EPA did not adjust the annualization of capital costs to reflect plant-specific considerations. EPA
annualized capital costs over 20 years but recognizes that some plants may retire units sooner than the 20-
year life of the equipment. EPA determined the 20-year annualization period to be reasonable for this
analysis because some regulators may allow utilities to recover the value of undepreciated assets in their
rate base on a case-by-case basis.39
For the assessment of compliance costs to steam electric power plants, EPA considered costs on both a
pre-tax and after-tax basis. Pre-tax costs provide insight on the total expenditures as initially incurred by
the plants. After-tax costs are a more meaningful measure of compliance impact on privately owned for-
profit plants, and incorporate approximate capital depreciation and other relevant tax treatments in the
analysis. EPA calculated the after-tax value of compliance costs by applying combined federal and State
tax rates to the pre-tax cost values for privately owned for-profit plants.4" For this adjustment, EPA used
State corporate rates from the Federation of Tax Administrators (2023) combined with a 21 percent
federal corporate tax rate. As discussed in the relevant sections of this document, EPA uses either pre- or
after-tax compliance costs in different analyses, depending on the concept appropriate to each analysis
37 U.S. Environmental Protection Agency. (2023d). 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).
38 EPA annualized these non-equipment outlays over 20 years to match the estimated performance life of compliance
technology components.
39 EPA received public comments on the 2023 proposed rule confirming that a typical depreciation and amortization
period is 20+ years. One commenter stated that "typical amortization periods for investments" on the scale of the 2020
Final Rule are 20 years (EPA-HQ-OW-2009-0819-10079). Another commenter described the rate recovery request of a
utility to comply with the 2020 Final Rule with a proposed 20-year depreciation and amortization period, though noted
that depreciation periods for equipment could be as long as 50 or 60 years (EPA-HQ-OW-2009-0819-10161).
40 Government-owned entities and cooperatives are not subject to income taxes. To distinguish among the government-
owned, privately owned, and cooperative ownership categories, EPA relied on the Steam Electric Survey and additional
research on parent entities using publicly available information. See Chapter 4: Cost and Economic Impact Screening
Analyses for further discussion of these determinations.
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(e.g., cost-to-revenue screening-level analyses are conducted using after-tax compliance costs). Note that
for social costs, which are discussed and detailed in Chapter 12 of the BCA, EPA uses pre-tax costs.41
3.1.5 Voluntary Incentive Program
As described in the 2020 rule and 2023 proposed rule, under the voluntary incentive program (VIP),
plants that discharge directly to waters can voluntarily commit to meeting more stringent FGD limitations
based on a membrane filtration treatment technology instead of limits based on CP+LRTR technology.
VIP participants had more time - until 2028 - to meet the lower limits based on membrane filtration, as
compared to having to meet the limits based on CP+LRTR by 2025. Plants identified as participating in
the VIP program in the baseline (i.e., to comply with the 2020 rule) incur zero FGD wastewater treatment
costs in this final rule.
3.2 Key Findings for Regulatory Options
3.2.1 Estimated Industry-level Total Compliance Costs
Table 3-1 and Table 3-2 present lower and upper bound compliance cost estimates for the regulatory
options.42
Table 3-1: Estimated Total Annualized Compliance Costs (in millions, 2023$, at 2024) - Lower
Bound
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Regulatory
Option
Capital
Technology
Other
Initial
One-
Time
Total
O&M
Total
Capital
Technology
Other
Initial
One-
Time
Total
O&M
Total
Option A
$232
$0.1
$247
$479
$186
$0.1
$200
$386
Option B
$284
$0.2
$312
$596
$229
$0.1
$250
$479
Option C
$336
$0.2
$359
$695
$270
$0.2
$286
$557
Source: U.S. EPA Analysis, 2024.
41 As described in Chapter 12 of the BCA, EPA used costs incurred by steam electric power plants for the labor,
equipment, material, and other economic resources needed to comply with the regulatory options as a proxy for social
costs. The social cost analysis considers costs on an as-incurred, year-by-year basis. In the social cost analysis, EPA
assumed that the market prices for labor, equipment, material, and other compliance resources represent the opportunity
costs to society for use of those resources in regulatory compliance. EPA further assumed that the regulatory options do
not affect the aggregate quantity of electricity that would be sold to consumers and, thus, that the rule's social cost
would include no changes in consumer and producer surplus from changes in electricity' sales by the electricity industry
in aggregate. Given the small impact of the regulatory options on electricity production cost for the total industry (see
Chapter 5), this is a reasonable assumption.
42 As discussed in Section 3.1.1 (see footnote 31), EPA did not select the lowest-cost technology for five plants to meet
zero-discharge limits for CRL. This resulted in the estimated total compliance costs for Option B and Option C
presented in this section being overstated by approximately $6 million (1.5 percent of total costs) on an after-tax basis.
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Table 3-2: Estimated Total Annualized Compliance Costs (in millions, 2023$, at 2024) - Upper
Bound
Regulatory
Option
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Capital
Technology
Other
Initial
One-
Time
Total
O&M
Total
Capital
Technology
Other
Initial
One-
Time
Total
O&M
Total
Option A
$453
$0.1
$595
$1,048
$372
$0.1
$490
$863
Option B
$505
$0.2
$659
$1,164
$415
$0.1
$541
$956
Option C
$557
$0.2
$706
$1,263
$456
$0.2
$577
$1,033
Source: U.S. EPA Analysis, 2024.
Table 3-3 and Table 3-4 show the breakout of total upper and lower bound compliance costs for each
option by wastestream 43
Table 3-3: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2023$, at
2024) - Lower Bound
Regulatory
Option
Pre-Tax Compliance Costs
After-Tax Compliance Costs
BA
Transport
Water
FGD
Wastewater
CRL
Legacy
Net
Total
Costs
BA
Transport
Water
FGD
Wastewater
CRL
Legacy
Net
Total
Costs
Option A
$19
$179
$281
$0
$479
$15
$139
$232
$0
$386
Option B
$19
$179
$370
$28
$596
$15
$139
$302
$23
$479
Option C
$30
$205
$433
$28
$695
$23
$160
$350
$23
$557
Source: U.S. EPA Analysis, 2024.
Table 3-4: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2023$, at
2024) - Upper Bound
Regulatory
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Option
BA
FGD
Wastewater
Net
BA
FGD
Wastewater
Net
Transport
Water
CRL
Legacy
Total
Costs
Transport
Water
CRL
Legacy
Total
Costs
Option A
$19
$179
$849
$0
$1,048
$15
$139
$709
$0
$863
Option B
$19
$179
$939
$28
$1,164
$15
$139
$778
$23
$956
Option C
$30
$205
$1,001
$28
$1,263
$23
$160
$826
$23
$1,033
Source: U.S. EPA Analysis, 2024.
3.2.2 Estimated Regional Distribution of Incremental Compliance Costs
Table 3-5 and Table 3-6 report the estimated lower and upper bound annualized total costs for each
regulatory option at the level of a North American Electric Reliability Corporation (NERC) region.44 As
43 One retired plant incurs legacy costs in the analysis. These costs are reflected in the total cost values in tables in Section
3.2. The costs for this plant are not incorporated in the rest of the RIA analyses because the plant does not have
generation revenue or ratepayers.
44 No steam electric power plant is estimated to incur compliance costs in the ASCC and HICC NERC regions and these
two regions are therefore omitted from the presentation of results.
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3: Compliance Costs
explained in Chapter 2 (Overview of the Steam Electric Industry), because of differences in operating
characteristics of steam electric power plants across NERC regions, as well as differences in the economic
and electric power system regulatory circumstances of the NERC regions themselves, the regulatory
options may affect costs, profitability, electricity prices, and other impact measures differently across
NERC regions.
Table 3-5: Estimated Annualized Total Compliance Costs by NERC Region (in millions, 2023$, at
2024) - Lower Bound
Pre-Tax Incremental Compliance Costs
After-Tax Incremental Compliance Costs
Other
Other
NERC
Capital
Initial One-
Capital
Initial One-
Region3
Technology
Time
Total O&M
Total
Technology
Time
Total O&M
Total
Option A
MRO
$29.1
$0.0
$24.9
$54.0
$23.6
$0.0
$20.1
$43.7
NPCC
$3.0
$0.0
$3.0
$6.0
$2.2
$0.0
$2.2
$4.4
RF
$70.3
$0.0
$76.0
$146.3
$54.3
$0.0
$58.7
$113.0
SERC
$111.4
$0.0
$116.7
$228.2
$91.6
$0.0
$97.4
$189.0
TRE
$4.1
$0.0
$3.8
$7.9
$3.6
$0.0
$3.2
$6.8
WECC
$13.5
$0.0
$22.7
$36.2
$10.6
$0.0
$17.9
$28.5
Total
$231.7
$0.1
$247.5
$479.2
$186.1
$0.1
$199.8
$386.0
Option B
MRO
$39.5
$0.0
$30.3
$69.8
$32.4
$0.0
$24.3
$56.7
NPCC
$3.3
$0.0
$2.9
$6.1
$2.4
$0.0
$2.1
$4.5
RF
$89.6
$0.1
$118.4
$208.0
$69.0
$0.1
$90.3
$159.3
SERC
$129.3
$0.1
$128.3
$257.7
$106.7
$0.0
$106.9
$213.6
TRE
1
LO
¦uy
o
o
¦uy
$4.1
$9.2
$4.3
$0.0
$3.5
$7.8
WECC
$17.1
o
o
¦uy
$27.4
$44.5
$14.0
o
o
¦uy
$22.4
$36.5
Total
$284.1
$0.2
$311.7
$596.0
$229.0
$0.1
$249.8
$479.0
Option C
MRO
$44.2
o
o
¦uy
$32.8
$77.0
$35.8
o
o
¦uy
$26.1
$61.9
NPCC
$3.3
o
o
¦uy
$2.9
$6.1
$2.4
$0.0
$2.1
$4.5
RF
$103.2
$0.1
$132.0
$235.3
$79.0
$0.1
$100.3
$179.3
SERC
$156.2
$0.1
$150.1
$306.4
$129.1
$0.1
$124.5
$253.6
TRE
$7.7
$0.0
$6.4
$14.1
$6.5
$0.0
$5.4
$11.9
WECC
$21.2
$0.0
$34.4
$55.6
$17.1
$0.0
$27.7
$44.8
Total
$335.9
$0.2
$358.9
$695.0
$270.1
$0.2
$286.4
$556.6
a. EPA estimated zero ELG compliance costs in the ASCC and HICC regions. These two regions are omitted from the table
presentation. This omission does not affect totals.
Source: U.S. EPA Analysis, 2024.
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Table 3-6: Estimated Annualized Total Compliance Costs by NERC Region (in millions, 2023$, at
2024) - Upper Bound
Pre-Tax Incremental Compliance Costs
After-Tax Incremental Compliance Costs
Other
Other
NERC
Capital
Initial One-
Capital
Initial One-
Region3
Technology
Time
Total O&M
Total
Technology
Time
Total O&M
Total
Option A
MRO
$54.8
o
o
¦uy
$63.3
$118.2
$43.2
o
o
¦uy
$48.6
$91.9
NPCC
$3.2
o
o
¦uy
$3.2
$6.4
$2.3
o
o
¦uy
$2.3
$4.7
RF
$109.9
o
o
¦uy
$135.2
$245.2
$86.4
o
o
¦uy
$106.9
$193.3
SERC
$225.3
o
o
¦uy
$292.7
$518.1
$192.1
o
o
¦uy
$252.3
$444.4
TRE
00
¦uy
o
o
¦uy
m
00
¦uy
$16.8
$7.3
o
o
¦uy
$7.2
$14.6
WECC
$49.8
o
o
¦uy
$90.9
$140.7
$39.4
o
o
¦uy
$71.8
$111.3
Total
$452.6
$0.1
$595.0
$1,047.7
$372.0
$0.1
$490.5
$862.6
Option B
MRO
$65.3
O
o
¦uy
$68.7
$134.0
$52.0
O
o
¦uy
$52.8
$104.9
NPCC
$3.5
o
o
¦uy
$3.0
$6.5
$2.6
o
o
¦uy
$2.2
00
¦uy
RF
$129.2
r—1
o
¦uy
$177.6
$306.9
$101.1
r—1
o
¦uy
$138.5
$239.6
SERC
$243.2
r—1
o
¦uy
$304.3
$547.6
$207.2
o
o
¦uy
$261.9
$469.1
TRE
$9.4
o
o
¦uy
00
¦uy
$18.0
1
00
¦uy
o
o
¦uy
$7.5
$15.6
WECC
$53.4
o
o
¦uy
$95.6
$149.0
$42.9
o
o
¦uy
$76.4
$119.2
Total
$505.1
$0.2
$659.2
$1,164.4
$414.9
$0.1
$540.5
$955.6
Option C
MRO
$69.9
o
o
¦uy
$71.2
$141.1
$55.4
O
o
¦uy
$54.6
$110.1
NPCC
$3.5
o
o
¦uy
$3.0
$6.5
$2.6
o
o
¦uy
$2.2
00
¦uy
RF
$142.8
r—1
o
¦uy
$191.3
$334.2
$111.0
r—1
o
¦uy
$148.5
$259.6
SERC
$270.0
r—1
o
¦uy
$326.1
$596.2
$229.6
r—1
o
¦uy
$279.5
$509.1
TRE
$12.0
o
o
¦uy
$11.0
$23.0
$10.3
o
o
¦uy
$9.4
$19.7
WECC
$57.5
o
o
¦uy
$102.5
$160.0
$46.0
o
o
¦uy
$81.6
$127.5
Total
$556.9
$0.2
$706.4
$1,263.5
$456.0
$0.2
$577.1
$1,033.3
a. EPA estimated zero ELG compliance costs in the ASCC and HICC regions. These two regions are omitted from the table
presentation. This omission does not affect totals.
Source: U.S. EPA Analysis, 2024.
3.2.3 Key Uncertainties and Limitations
Economic analyses are not perfect predictions and thus, like all such analyses, this analysis has some
uncertainties and limitations.
• The compliance costs used in this analysis for the regulatory options reflect unit retirements,
conversions, and repowerings that have occurred or have been announced and are scheduled to
occur by the end of 2029. For details, see TDD (U.S. EPA, 2024e). To the extent that actual unit
retirements, conversions, and repowerings at steam electric power plants differ from announced
changes, estimated annualized compliance costs of the regulatory options may differ from actual
costs.
• EPA assumed that the equipment installed to meet any new limitations could reasonably be
estimated to operate for 20 years or more, based on a review of reported performance
characteristics of the equipment components. EPA also determined the 20-year annualization
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period to be reasonable for this analysis because some regulators may allow utilities to recover
the value of undepreciated assets in their rate base on a case-by-case basis. EPA thus used 20
years as the basis for the cost and economic impact analyses that account for the estimated
operating life of compliance technology. To the extent that the actual service life is longer or
shorter than 20 years, costs presented on annual equivalent basis would be over- or under-stated.
This includes cases where a plant upgrades treatment technologies to comply with the ELGs but
ceases operating before the 20-year life of the equipment.
• Annualized compliance costs depend on the assumed technology implementation year. For the
purpose of the cost and economic impact analyses, EPA determined years in which technology
implementation would reasonably be estimated to occur across the universe of steam electric
power plants, based on plant-specific information about existing NPDES permits and
extrapolating future permit issuance dates assuming permits are renewed every five years. To the
extent that compliance costs are incurred in an earlier or later year, the annualized values
presented in this section may under or overstate the annualized total costs of the regulatory
options.
• Plants may incur compliance costs associated with meeting legacy wastewater limits when they
close and dewater their existing ponds. As there are no requirements for the ponds to be closed,
there is uncertainty on whether and when operators may incur such costs. EPA assumed that pond
closures will occur in 2044 at which time plants would incur initial one-time costs associated with
treatment of legacy wastewater. As a result, this analysis may under or overstate compliance costs
in cases where plants choose to close their ponds before or after 2044.
• Plants may incur compliance costs to comply with unmanaged CRL discharged from landfills,
surface impoundments, or other features in cases where a permitting authority deems, on a case-
by-case basis, the discharge to be the functional equivalent of a direct discharge and requiring a
permit. Because these discharges are uncertain, EPA developed lower and upper bound analyses
scenarios that rely on probabilistic estimates of plants that may be subject to the limits,
compliance approach, and associated costs. See Section 3.1.1 for a description of these scenarios.
Additionally, EPA assumed plants would incur these costs at the same time as they would incur
costs associated with other treatment technologies. This may under or overstate the costs of
unmanaged CRL treatment if plants incur these costs before or after the assumed compliance year
in the analysis.
3.3 Costs to New Sources
Electric power generating plants that meet the definition of a "new source" will be required to achieve the
final NSPS, in the case of direct dischargers, or Pretreatment Standards for New Sources (PSNS), in the
case of indirect dischargers. This section summarizes the data and methodology used to estimate
compliance costs for new steam electric power plants (for a more detailed description of the methodology,
see TDD, U.S. EPA, 2024e). The section also assesses the relative magnitude of the compliance costs by
comparing them to the costs of new coal steam generation. EPA's final rule is based on the suite of
technologies identified for Option B. EPA's approach to assess costs to new sources and the potential
barrier to entry for new plants is based on the same methodology used for the 2015 rule (U.S. EPA,
2015).
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3.3.1 Analysis Approach and Inputs
EPA developed compliance costs for new plants using a methodology similar to the one used to develop
compliance costs for existing plants (see TDD for details). EPA did not have information about which
entities will construct new plants, the exact characteristics of such plants, or the timing of new plant
construction. As a result, EPA calculated and analyzed compliance costs for a hypothetical plant. The
Agency treated the incurrence of costs in this analysis as though new plants would be constructed, and
additional wastewater treatment costs incurred, as of the rule promulgation, (i.e., 2024). This is a
conservative assumption since new sources would not incur costs until there is an NPDES permit
applying the NSPS to them.
Compliance costs for new plants under the final NSPS (Option B) include capital costs, initial one-time
costs, and annual O&M costs. EPA made the same adjustments to the plant-specific costs for new plants
described in the TDD, as those made to develop total compliance costs for existing plants:
• First, EPA brought all compliance costs to 2024 using CCI (or ECI) and restated in 2023 dollars
using GDP Deflator.
• EPA then annualized each non-annual cost component over the expected useful life of the
technology/processes it represents (capital cost and initial one-time costs over 20 years) using
3.76 percent as the assumed cost of capital.
• Finally, EPA added these annualized capital, initial one-time, and O&M costs.
Table 3-7 presents estimated new plant compliance costs under the final rule (Option B) for new sources.
The Agency estimated costs for a new 650 MW coal-fired steam electric power plant. Per MW, EPA
estimated that a new plant will cost $4,916 per MW. For more details on the methodology used to
estimate compliance costs for new plants, see the TDD (U.S. EPA, 2024e).
Table 3-7: Annualized Pre-tax Compliance Costs for a Hypothetical New 650 MW Plant Under
Final Rule (2023$, at 2024)
Total Costs
Costs per MWa
Total
Total
Capital
Non-Fuel
One-Time
Annualized
Capital
Non-Fuel
One-Time
Annualized
Costs
O&M Costs
Costs
Costs
Costs
O&M Costs
Costs
Costs
$1,482,503
$1,701,998
$11,088
$3,195,589
$2,281
$2,618
$17
$4,916
a. Unit costs are based on capacity of 650 MW.
Source: U.S. EPA analysis, 2024.
3.3.2 Key Findings for Regulatory Options
EPA assessed the effects of the final NSPS requirements under the final rule for new plants by comparing
the compliance costs for new plants to the overall cost of building and operating new plants, on a per
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MW basis. This analysis assesses the requirements and costs imposed on new plants in relation to the
costs that would be incurred for building and operating new plant without the new plant requirements,45
To assess the relative magnitude of compliance costs for new plants, EPA compared the pre-tax costs
presented in Section 3.2.1, to the total cost of building and operating a new plant, also on a pre-tax and
per MW basis. EPA obtained the overnight capital46 and O&M costs of building and operating a new
plant from EIA (2024). These costs are based on a new ultra-supercritical coal (USC) plant with no
carbon capture (CC) technology with a total generation capacity of 650 MW (EIA, 2024). EPA compared
the ELG cost estimates for the 650 MW plant presented in Table 3-7 to the costs of a new USC plant
without CC.
EPA also estimated annual fuel O&M costs for operating the plant based on an assumed capacity factor of
90 percent, annual heat rate of a new USC without CC from EIA (2024), and weighted average cost of
coal delivered to the power sector from EIA (2023h). EPA annualized new USC without CC plant
building and operating costs over 40 years using a discount rate of 3.76 percent.47 EPA then compared the
estimated compliance costs for new plants to the costs of constructing and operating new coal steam
capacity. Table 3-8 presents the results of this comparison. The Agency estimated that compliance costs
for adding treatment technology at a new plant would represent 1.1 percent of the total annualized costs of
building and operating a new plant.
Table 3-8: One-Time & O&M costs for a Hypothetical New 650 MW Plant Under Final Rule
Cost Component
Annualized Costs of New
Coal-fired Generation
(2023$/MW)
Compliance Costs
(2023$/MW)
% of New Generation Cost
Capital
$199,936
$2,281
1.1%
Non-Fuel Annual 0&Ma
$112,095
$2,618
1.0%
Fuel Annual O&M
$153,535
Total Annualized Costsb
$465,566
$4,916
1.1%
a. Fuel costs were estimated assuming heat rate of 8,638 Btu/kWh (EIA, 2024) and the cost of coal delivered to the power
sector of 2.25 2023$/MMbtu (EIA (2023h) weighted average cost for all coal ranks in 2022 dollars, converted to 2023 dollars
using GDP deflator).
b. Includes annualized initial one-time costs.
Source: EIA, 2024; U.S. EPA analysis, 2024.
45 Note that the market analyses described in Chapter 5 also incorporate costs to new sources as part of inputs to the
Integrated Planning Model (IPM). This analysis tests the impact of the new plant requirements in electricity markets
accounting for the expected number and timing of new plant installations, and provides additional insight on whether
the costs of meeting the standards specified by the final NSPS and PSNS would affect future capacity additions. Since
IPM projects no new coal-fired generating plant in the Base Case, however, the market analysis does not offer
additional insight on the impacts of the NSPS compliance costs on new generating capacity.
46 Overnight capital costs includes labor and material costs due to installation, mechanical equipment and labor, electrical
instrumentation, and indirect management costs according to U.S. Energy Information Administration. (2024). Capital
Cost and Performance Characteristics for Utility-Scale Electric Power Generating Technologies. Retrieved from
https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdl7capital_cost_AEO2025.pdf.
47 The Agency annualized capital costs for a new USC coal unit without CC based on the predicted performance life
reported in ibid..
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3.3.3 Key Uncertainties and Limitations
Despite EPA's use of the best available information and data available, including information provided to
EPA in the industry survey, this analysis has uncertainties and limitations.
• EPA notes that no new coal capacity additions are projected between 2024 and 2050 in AEO2023
(EIA, 2023b), making the assessment of the relative costs and of any barrier the final ELGs may
pose to additional generation hypothetical. Similarly, results of the electricity market model using
IPM (Chapter 5) shows no additional coal steam capacity being built through 2050 in the Base
Case (in the absence of the ELGs) or in the policy case (with the ELGs), and do not offer a basis
for determining, using IPM, whether the ELGs present a cost barrier to new coal generation.
However, as discussed in Chapter 5, the IPM results demonstrate that the ELGs do not pose a
barrier to new electricity generation overall; the model shows increases new capacity projected in
IPM under the final rule option.
• Second, EPA made assumptions about plant characteristics in the absence of the final rule. These
assumptions affect the types of wastestreams that a plant would generate and changes needed to
meet the final limitations and standards. To the extent that the characteristics of new plants differ
from EPA's assumed characteristics, the costs may be under or overstated.
• Finally, the costs of implementing and operating compliance technology vary based on the size of
the generating plant and plant configuration. To the extent that the size and configuration of a
potential new coal plant is different from assumptions that underlay new capacity costs, the
relative magnitude of the compliance costs for new steam electric capacity may be under- or
over-estimated. For instance, EPA used data from EIA on the cost of additional capacity based on
a new 650 MW USC without CC plant (EIA, 2024). The cost of building new capacity for a
smaller or larger plant may be smaller or larger on a per MW basis than those of a 650 MW plant.
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4 Cost and Economic Impact Screening Analyses
4.1 Analysis Overview
Following the same methodology used for the 2015, 2020 and proposed 2023 rule analyses (U.S. EPA,
2015, 2020, 2023d), EPA assessed the costs and economic impacts of the regulatory options in two ways:
1. A screening-level assessment reflecting current operating characteristics of steam electric power
plants and with assignment of estimated compliance costs to those plants. This analysis assumes
no changes in operating characteristics — e.g., quantity of generated electricity and revenue — as
a result of the regulatory options. This screening-level assessment, which is documented in this
chapter, includes two specific analyses:
- A cost-to-revenue screening analysis to assess the impact of compliance outlays on
individual steam electric power plants (Section 4.2)
- A cost-to-revenue screening analysis to assess the impact of compliance outlays on
domestic parent-entities owning steam electric power plants (Section 4.3)
2. A broader electricity market-level analysis based on IPM (the Market Model Analysis). This
analysis, which provides a more comprehensive indication of the economic achievability of the
final rule, including an assessment of incremental plant closures (or avoided closures), is
discussed in Chapter 5. Unlike the preceding analysis discussed in this chapter, the Market Model
Analysis accounts for estimated changes in the operating characteristics of plants from both
estimated changes in electricity markets and operating characteristics of plants independent of,
and as a result of, the regulatory options.
4.2 Cost-to-Revenue Analysis: Plant-Level Screening Analysis
The cost-to-revenue measure compares the cost of implementing and operating compliance technologies
with the plant's operating revenue and provides a screening-level assessment of the impact that might be
estimated of the regulatory options. As discussed in U.S. EPA (2015; see Chapter 2), the majority of
steam electric power plants operate in states with regulated electricity markets. EPA estimates that plants
located in these states may be able to recover compliance cost-based increases in their production costs
through increased electricity prices, depending on the business operation model of the plant owner(s), the
ownership and operating structure of the plant itself, and the role of market mechanisms used to sell
electricity. In contrast, in states in which electric power generation has been deregulated, cost recovery is
not guaranteed. While plants operating within deregulated electricity markets may be able to recover
some of their additional production costs through increased revenue, it is not possible to determine the
extent of cost recovery ability for each plant.48
In assessing the cost impact of the regulatory options on steam electric power plants in this screening-
level analysis, the Agency assumed that the plants would not be able to pass any of the change in their
48 While the regulatory status in a given state affects the ability of electric power plants and their parent entities to recover
electricity generation costs, it is not the only factor and should not be used solely as the basis for cost-pass-through
determination.
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production costs to consumers (zero cost pass-through). This assumption is used for analytic convenience
and provides a worst-case scenario of regulatory impacts to steam electric power plants.49
4.2.1 Analysis Approach and Data Inputs
As described in Chapter 1, EPA estimates all steam electric power plants to meet any new requirements
for bottom ash transport water, FGD wastewater, and CRL between 2026 and 2030. The Agency used the
same approach from the 2015 rule, 2020 rule, and 2023 proposed rule to conduct the analysis of the final
rule's regulatory options A through C.
EPA updated the approach used for the 2015 and 2020 rules and 2023 proposal to incorporate more recent
data. For the current analysis, EPA used 2024 as the basis for comparing after-tax compliance costs (see
Chapter 3) to revenue at the plant level.50 For this comparison, EPA developed plant-level revenue values
for all steam electric power plants using data from the Department of Energy's Energy Information
Administration (EIA) on electricity generation by prime mover, and utility/operator-level electricity
prices and disposition. Specifically, EPA multiplied the 6-year average of electricity generation values
over the period 2016 to 2021 from the EIA-923 database by 6-year average electricity prices over the
period 2016 to 2021 from the EIA-861 database (EIA, 2022a, 2022d).51'52 EPA estimated compliance
costs in 2023 dollars. To provide cost and revenue comparisons on a consistent analysis-year (2024) and
dollar-year (2023) basis, EPA adjusted the EIA electricity price data, which are reported in nominal
dollars of each year.
Cost-to-revenue ratios are used to describe impacts to entities because they provide screening-level
indicators of potential economic impacts. Just as for the plants owned by small entities under guidance in
U.S. EPA (2006), and the approach EPA has used previously in previous regulatory analyses (U.S. EPA,
2015, 2020, 2023d), EPA assesses plants incurring costs below one percent of revenue as unlikely to face
material economic impacts, plants with costs of at least one percent but less than three percent of revenue
49 Even though the majority of steam electric power plants may be able to pass increases in production costs to consumers
through increased electricity prices, it is difficult to determine exactly which plants would be able to do so.
Consequently, EPA concluded that assuming zero cost pass-through is appropriate as a screening-level, upper bound
estimate of the potential impact of compliance expenditures on steam electric power plants and their parent entities.
The analysis, while helpful to understand potential cost impact, does not generally indicate whether profitability is
jeopardized, cash flow is affected, or risk of financial distress is increased.
50 For private, tax-paying entities, after-tax costs are a more relevant measure of potential private cost burden than pre-tax
costs. For non-tax-paying entities (e.g., State government and municipality owners of steam electric power plants), the
estimated costs used in this calculation include no adjustment for taxes.
51 In using the year-by-year revenue values to develop an average over the data years, EPA set aside from the average
calculation any generation values that are anomalously low. Such low generating output likely results from temporary
disruption in operation, such as a generating unit being out of service for maintenance.
52 EPA's first step in calculating plant revenue was to restate electricity prices in 2023 dollars using the Gross Domestic
Product (GDP) deflator index published by the U.S. Bureau of Economic Analysis (BEA) (U.S. Bureau of Economic
Analysis. (2023). Table 1.1.9 Implicit Price Deflators for Gross Domestic Product (GDP Deflator). Retrieved from
https://apps.bea.gov/iTable/?reqid=19&step=3&isuri=l&1921=survey&1903=ll). These individual yearly values were
then averaged and brought forward to 2024 using electricity price projections from the Annual Energy Outlook
publication for 2023 (AEO2023) (U.S. Energy Information Administration. (2023b). Annual Energy Outlook 2023.
Retrieved from https://www.eia.gov/outlooks/aeo/). AEO2023 contains projections and analysis of U.S. energy supply,
demand, and prices through 2050. AEO2023 electricity price projections are in constant dollars; therefore, these
adjustments yield 2024 revenue values in dollars of the year 2023 (converted from 2022 dollars to 2023 dollars).
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as having a higher chance of facing material economic impacts, and plants incurring costs of at least three
percent of revenue as having a still higher probability of material economic impacts.
4.2.2 Key Findings for Regulatory Options
Table 4-1 and Table 4-2 present the lower and upper bound cost-to-revenue analysis results for each of
the regulatory options. Under all regulatory options analyzed, most plants would not experience
compliance costs exceeding one or three percent of revenue.
Table 4-1: Plant-Level Cost-to-Revenue Analysis Results by Owner Type and Regulatory Option -
Lower Bound
Owner Type
Total Number
of Plants3
Number of Plants with a Ratio of
0%a'b
#0 and <1%
>1 and 3%
>3%
Option A
Cooperative
59
44
10
3
2
Federal
23
17
4
2
0
Investor-owned
320
238
63
14
5
Municipality
111
100
4
2
5
Nonutility
308
289
15
1
3
Political Subdivision
33
29
3
0
1
State
4
2
2
0
0
Total
858
719
101
22
16
Option B
Cooperative
59
44
8
5
2
Federal
23
17
4
2
0
Investor-owned
320
237
59
17
7
Municipality
111
100
2
4
5
Nonutility
308
288
14
3
3
Political Subdivision
33
29
3
0
1
State
4
2
1
1
0
Total
858
717
91
32
18
Option C
Cooperative
59
44
8
5
2
Federal
23
17
4
2
0
Investor-owned
320
237
53
23
7
Municipality
111
100
2
4
5
Nonutility
308
288
14
3
3
Political Subdivision
33
29
3
0
1
State
4
2
1
0
1
Total
858
717
85
37
19
a. Plant counts are weighted estimates.
b. These plants already meet discharge requirements for the wastestreams controlled by a given regulatory option and
therefore are not estimated to incur compliance costs.
Source: U.S. EPA Analysis, 2024.
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4: Screening-Level Economic Impacts
Table 4-2: Plant-Level Cost-to-Revenue Analysis Results by Owner Type and Regulatory Option -
Upper Bound
Owner Type
Total Number
of Plants3
Number of Plants with a Ratio of
0%a'b
#0 and <1%
>1 and 3%
>3%
Option A
Cooperative
59
41
9
4
5
Federal
23
14
6
2
1
Investor-owned
320
224
64
19
13
Municipality
111
97
5
3
6
Nonutility
308
284
17
4
3
Political Subdivision
33
27
5
0
1
State
4
2
1
1
0
Total
858
688
107
33
29
Option B
Cooperative
59
41
7
6
5
Federal
23
14
5
3
1
Investor-owned
320
223
62
20
15
Municipality
111
97
3
5
6
Nonutility
308
284
15
6
3
Political Subdivision
33
27
5
0
1
State
4
2
1
1
0
Total
858
687
98
41
31
Option C
Cooperative
59
41
7
6
5
Federal
23
14
5
2
2
Investor-owned
320
223
57
25
15
Municipality
111
97
3
5
6
Nonutility
308
284
13
8
3
Political Subdivision
33
27
5
0
1
State
4
2
1
0
1
Total
858
687
91
46
33
a. Plant counts are weighted estimates.
b. These plants already meet discharge requirements for the wastestreams controlled by a given regulatory option and
therefore are not estimated to incur compliance costs.
Source: U.S. EPA Analysis, 2024.
4.2.3 Uncertainties and Limitations
Despite EPA's use of the best available information and data, this analysis of plant-level impacts has
uncertainties and limitations, including:
• The impact of the regulatory options may be over- or under-estimated as a result of differences
between actual 2024 plant revenue and those estimated using EIA databases for 2015 through
2021.
• As noted above, the zero cost pass-through assumption represents a worst-case scenario from the
perspective of the plant owner. To the extent that companies are able to pass some compliance
costs on to consumers through higher electricity prices, this analysis overstates the potential
impact of the regulatory options on steam electric power plants.
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• EPA assumes that owners of plants that retire or repower during the period of analysis, but after
installing equipment to comply with the final rule, will continue to amortize capital expenses over
the 20-year life of the technology. To the extent that plant owners use an accelerated amortization
schedule, this analysis may understate the potential impact of the baseline and regulatory options
on steam electric power plants.
4.3 Cost-to-Revenue Screening Analysis: Parent Entity-Level Analysis
Following the methodology EPA used for the analysis of the 2015 and 2020 rules and 2023 proposal
analyses (U.S. EPA, 2015, 2020, 2023d), EPA also assessed the economic impact of the regulatory
options at the parent entity level. The cost-to-revenue screening analysis at the entity level adds particular
insight on the impact of compliance requirements on those entities that own multiple plants.
EPA conducted this screening analysis at the highest level of domestic ownership, referred to as the
"domestic parent entity." For this analysis, the Agency considered only entities with the largest share of
ownership (e.g., majority owner) in at least one surveyed steam electric power plant.53,54 The entity-level
analysis maintains the worst-case analytical assumption of no pass-through of compliance costs to
electricity consumers used for the plant-level cost-to-revenue analysis in Section 4.2.
4.3.1 Analysis Approach and Data Inputs
Following the approach used in the 2015, 2020, and proposed 2023 rule analyses (U.S. EPA, 2015, 2020,
2023d), to assess the entity-level economic/financial impact of compliance requirements, EPA summed
plant-level annualized after-tax compliance costs calculated in Section 3.2 to the level of the steam
electric power plant owning entity and compared these costs to parent entity revenue.
Similar to the plant-level analysis, EPA used cost-to-revenue ratios of one and three percent as markers of
potential impact for this analysis. Also similar to the assumptions made for the plant-level analysis, for
this entity-level analysis the Agency assumed that entities incurring costs below one percent of revenue
are unlikely to face significant economic impacts, while entities with costs of at least one percent but less
than three percent of revenue have a higher chance of facing significant economic impacts, and entities
incurring costs of at least three percent of revenue have a still higher probability of significant economic
impacts.
Following the approach used in the 2015, 2020, and 2023 rule analyses (U.S. EPA, 2015, 2020, 2023d;
see Section 4.3), EPA analyzed two cases that provide approximate upper and lower bound estimates on:
(1) the number of entities incurring compliance costs and (2) the costs incurred by any entity owning one
or more steam electric power plant.
This entity-level cost-to-revenue analysis involved the following steps: (1) Determining the parent entity;
(2) Determining the parent entity revenue; and (3) Estimating compliance costs at the level of the parent
53 Throughout these analyses, EPA refers to the owner with the largest ownership share as the "majority owner" even
when the ownership share is less than 51 percent.
54 When two entities have equal ownership shares in a plant (e.g., 50 percent each), EPA analyzed both entities and
allocated plant-level compliance costs to each entity.
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4: Screening-Level Economic Impacts
entity. The sections below highlight updates to incorporate more recent data than were used for the 2015,
2020, and proposed 2023 rules.
Determining the Parent Entity
EPA used information from the 2021 EIA-860 database which provides owners and the share of
ownership in electric generating units (EIA, 2022c) to determine ownership of each coal-fired steam
electric power plant and surveyed non-coal steam electric power plants (see U.S. EPA, 2015 for
discussion of how non-coal steam electric power plants are incorporated in the analysis). EPA
supplemented this information with data from corporate/financial websites and from the Steam Electric
Survey to identify the highest-level domestic parent entity for each plant.
Determinins Parent Entity Revenue
For each parent entity identified in the preceding step, EPA determined revenue values based on
information from corporate or financial websites, if those values were available. EPA tried to obtain
revenue for years 2020 and 2021 and used the average of reported values. If revenue values were not
reported on corporate/financial websites, the Agency used 2019-2021 average revenue values from the
EIA-861 database (EIA, 2022a). Additionally, EPA used entity-level revenue values from Dun and
Bradstreet (Dun & Bradstreet, 2021) or Experian (Experian, 2023) if those values were available.
EPA updated entity revenue values to 2023 dollars using the GDP Deflator. For this analysis, the Agency
assumed that these average historical revenue values are representative of revenues as of 2024. Although
the entity-level revenue values might reasonably be estimated to change by 2024 (i.e.. have increased or
decreased relative to average historical revenue), EPA was less confident in the reliability of projecting
revenue values at the entity level than in that of projecting plant-level revenue values to reflect changes in
generation. For the entity-level analysis, therefore, EPA did not project or further adjust revenue values
developed using the sources and methodology described above but used these values as is. In effect,
plants and their parent entities are assumed to be the same 'business entities' in terms of constant dollar
revenue in 2024 as they were in the year for which revenue were reported.
Estimatins Compliance Costs at the Level of the Parent Entity
Following the approach used in the analysis of the 2015 rule, to account for the parent entities of all 858
steam electric power plants, EPA analyzed two approximate bounding cases that provide a range of
estimates for the number of entities incurring compliance costs and the costs incurred by any entity
owning a steam electric power plant: (1) A lower bound estimate that assumes that the surveyed owners
represent all owners, which effectively assumes that any non-surveyed plants are owned by the same
surveyed entities and maximizes the number of plants owned by any given entity; and (2) An upper bound
estimate that assumes that the non-surveyed owners are different from those surveyed but have similar
characteristics, which results in a greater number of owners but minimizes the number of plants owned by
each. See Chapter 4 in U.S. EPA (2015) for details.
4.3.2 Key Findings for Regulatory Options
Table 4-3 presents the results from the entity-level impact analysis under the lower bound (Case 1) and
upper bound (Case 2) estimates of the number of entities incurring costs for each regulatory option under
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4: Screening-Level Economic Impacts
the lower bound cost scenario. Table 4-4 presents the results for the upper bound cost scenario. The tables
show the number of entities that incur costs in four ranges: no cost, and non-zero costs less than one
percent of an entity's revenue, at least one percent but less than three percent of revenue, and at least three
percent of revenue.
Overall, this screening-level analysis shows that few entities are likely to experience significant changes
in cost-to-revenue ratios under any of the regulatory options compared to the baseline.
Table 4-3: Entity-Level Cost-to-Revenue Analysis Results - Lower Bound
Case 1: Lower bound estimate of change in number
of firms owning plants that face requirements
under the regulatory analysis
Number of Entities with a Ratio of
Total
Number of Entities with a Ratio of
Total
Number
Number
*0 and
>1 and
of
*0 and
>1 and
Entity Type
of Entities
0%a
<1%
3%
>3%
Unknown
Entities
0%a
<1%
3%
>3%
Unknown
Case 2: Upper bound estimate of change in
number of firms owning plants that face
requirements under the regulatory analysis
Option A
Cooperative
22
10
10
0
2
0
28
13
13
0
2
0
Federal
2
1
1
0
0
0
7
3
4
0
0
0
Investor-
owned
57
27
29
1
0
0
88
20
67
1
0
0
Municipality
50
39
6
4
1
0
84
71
8
4
1
0
Nonutility
76
65
9
0
2
0
160
139
19
0
2
0
Other"
11
9
2
0
0
0
23
20
3
0
0
0
State
2
1
1
0
0
0
2
1
1
0
0
0
Total
220
152
58
5
5
0
391
266
115
5
5
0
Option B
Cooperative
22
10
9
1
2
0
28
13
12
1
2
0
Federal
2
1
1
0
0
0
7
3
4
0
0
0
Investor-
owned
57
27
29
1
0
0
88
20
67
1
0
0
Municipality
50
39
6
3
2
0
84
71
8
3
2
0
Nonutility
76
65
7
2
2
0
160
139
17
2
2
0
Other"
11
9
2
0
0
0
23
20
3
0
0
0
State
2
1
1
0
0
0
2
1
1
0
0
0
Total
220
152
55
7
6
0
391
266
112
7
6
0
Option C
Cooperative
22
10
9
1
2
0
28
13
12
1
2
0
Federal
2
1
1
0
0
0
7
3
4
0
0
0
Investor-
owned
57
27
29
1
0
0
88
20
67
1
0
0
Municipality
50
39
6
3
2
0
84
71
8
3
2
0
Nonutility
76
65
7
2
2
0
160
139
17
2
2
0
Other"
11
9
2
0
0
0
23
20
3
0
0
0
State
2
1
0
1
0
0
2
1
0
1
0
0
Total
220
152
54
8
6
0
391
266
111
8
6
0
a. These entities own only plants that already meet discharge requirements
option and are therefore not estimated to incur any compliance technology
b. Other political subdivision.
for the wastestreams addressed by a given regulatory
costs.
Source: U.S. EPA Analysis, 2024.
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Table 4-4: Entity-Level Cost-to-Revenue Analysis Results - Upper Bound
Case 1: Lower bound estimate of change in number
of firms owning plants that face requirements
under the regulatory analysis
Number of Entities with a Ratio of
Total
Number of Entities with a Ratio of
Total
Number
Number
*0 and
>1 and
of
*0 and
>1 and
Entity Type
of Entities
0%a
<1%
3%
>3%
Unknown
Entities
0%a
<1%
3%
>3%
Unknown
Case 2: Upper bound estimate of change in
number of firms owning plants that face
requirements under the regulatory analysis
Option A
Cooperative
22
7
12
0
3
0
28
9
16
0
3
0
Federal
2
1
1
0
0
0
7
2
5
0
0
0
Investor-
owned
57
24
31
2
0
0
88
11
75
2
0
0
Municipality
50
37
8
1
4
0
84
69
10
1
4
0
Nonutility
76
63
10
1
2
0
160
137
20
1
2
0
Other"
11
6
5
0
0
0
23
14
9
0
0
0
State
2
1
1
0
0
0
2
1
1
0
0
0
Total
220
139
68
4
9
0
391
242
136
4
9
0
Option B
Cooperative
22
7
11
1
3
0
28
9
15
1
3
0
Federal
2
1
1
0
0
0
7
2
5
0
0
0
Investor-
owned
57
24
31
2
0
0
88
11
75
2
0
0
Municipality
50
37
8
1
4
0
84
69
10
1
4
0
Nonutility
76
63
8
3
2
0
160
137
18
3
2
0
Other"
11
6
5
0
0
0
23
14
9
0
0
0
State
2
1
0
1
0
0
2
1
0
1
0
0
Total
220
139
64
8
9
0
391
242
132
8
9
0
Option C
Cooperative
22
7
11
1
3
0
28
9
15
1
3
0
Federal
2
1
1
0
0
0
7
2
5
0
0
0
Investor-
owned
57
24
31
2
0
0
88
11
75
2
0
0
Municipality
50
37
8
1
4
0
84
69
10
1
4
0
Nonutility
76
63
8
3
2
0
160
137
18
3
2
0
Other"
11
6
5
0
0
0
23
14
9
0
0
0
State
2
1
0
1
0
0
2
1
0
1
0
0
Total
220
139
64
8
9
0
391
242
132
8
9
0
a. These entities own only plants that already meet discharge requirements
option and are therefore not estimated to incur any compliance technology
b. Other political subdivision.
for the wastestreams addressed by a given regulatory
costs.
Source: U.S. EPA Analysis, 2024.
4.3.3 Uncertainties and Limitations
Despite EPA's use of the best available information and data, this analysis of entity-level impacts has
uncertainties and limitations, including:
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• The entity-level revenue values obtained from the corporate and financial websites or EIA
databases are for 2019 through 2021. To the extent that actual 2024 entity revenue values are
different, on a constant dollar basis, from those estimated using historical data, the cost-to-
revenue measure for parent entities of steam electric power plants may be over- or under-
estimated.
• The assessment of entity-level impacts relies on approximate upper and lower bound estimates of
the number of parent entities and the numbers of steam electric power plants that these entities
own. EPA expects that the range of results from these analyses provides appropriate insight into
the overall extent of entity-level effects.
• As is the case with the plant-level analysis discussed in Section 4.2, the zero cost pass-through
assumption represents a worst-case scenario from the perspective of the plant owner. To the
extent that companies are able to pass some compliance costs on to consumers through higher
electricity prices, this analysis may overstate the potential impact of the baseline and regulatory
options on steam electric power plants. Also, as is the case with the plant-level analysis discussed
in Section 4.2, the assumption that owners of plants that retire or repower during the period of
analysis, but after installing equipment to comply with the final rule, will continue to amortize
capital expenses over the 20-year life of the technology, may understate the potential impact of
the baseline and regulatory options on steam electric power plants.
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5 Assessment of the Impact of the Final Rule on National and
Regional Electricity Markets
Following the approach used to analyze the impacts of the 2015 and 2020 rules and other various
regulatory actions affecting the electric power sector over the last decade, EPA used the Integrated
Planning Model (IPM®), a comprehensive electricity market optimization model that can evaluate such
impacts within the context of regional and national electricity markets. To assess market-level effects of
the final rule, EPA used the latest version of this analytic system: Integrated Planning Model Version 6
(IPM v6) Post-IRA 2022 Reference Case (U.S. EPA, 2023a).55 EPA ran IPM for Option B, excluding
costs associated with legacy wastewater limits or the treatment of unmanaged CRL, to evaluate the
impacts of the final rule.
This market model analysis is a more comprehensive analysis compared to the screening-level analyses
discussed in Chapter 4; it is meant to inform EPA's assessment of whether the proposed rule would result
in any capacity retirements (full or partial plant closures)56 and to provide insight on impacts on the
overall electricity market, including to assess whether the proposed rule may significantly affect the
energy supply, distribution or use under Executive Order 13211 (see Section 10.6).
In contrast to the screening-level analyses, which are static analyses and do not account for
interdependence of electric generating units in supplying power to the electric transmission grid, IPM
accounts for potential changes in the generation profile of steam electric and other units and consequent
changes in market-level generation costs, as the electric power market responds to changes in generation
costs for steam electric units due to the regulatory options. IPM is also dynamic in that it is capable of
using forecasts of future conditions to make decisions for the present. Additionally, in contrast to the
screening-level analyses in which EPA assumed no pass through of compliance costs, IPM depicts
production activity in wholesale electricity markets where some recovery of compliance costs through
increased electricity prices is possible but not guaranteed. Finally, IPM incorporates electricity demand
growth assumptions from the Department of EnergyAnnual Energy Outlook 2023 (U.S. EIA, 2023b),
whereas the screening-level analyses discussed in other chapters of this report assume that plants would
generate approximately the same quantity of electricity in 2024 as they did on average during 2015-2020.
Changes in electricity production costs and potential associated changes in electricity output at steam
electric power plants can have a range of broader market impacts that extend beyond the effect on steam
electric power plants. In addition, the impact of compliance requirements on steam electric power plants
may be seen differently when the analysis considers the impact on those plants in the context of the
broader electricity market instead of looking at the impact on a standalone, single-plant basis. Therefore,
use of a comprehensive, market model analysis system that accounts for interdependence of electric
generating units is important in assessing regulatory impacts on the electric power industry as a whole.
55 For more information on IPM, see https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling.
56 For the 2015 rule analysis, EPA used IPM to inform assessment of the economic achievability of the ELG options
under CWA Sections 301(b)(2)(A) and 304(b)(2) (see U.S. Environmental Protection Agency. (2015). Regulatory
Impact Analysis for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point
Source Category. (EPA-821-R-15-004). ).
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EPA's use of IPM v6 for this analysis is consistent with the intended use of the model to evaluate the
effects of changes in electricity production costs, on electricity generation costs, subject to specified
demand and emissions constraints. As discussed in greater detail in U.S. EPA (2023a), IPM generates
least-cost resource dispatch decisions based on user-specified constraints such as environmental, demand,
and other operational constraints. The model can be used to analyze a wide range of electric power market
scenarios. Applications of IPM have included capacity planning, environmental policy analysis and
compliance planning, wholesale price forecasting, and asset valuation.
IPM uses a long-term dynamic linear programming framework that simulates the dispatch of generating
capacity to achieve a demand-supply equilibrium on a seasonal basis and by region. The model computes
optimal capacity that combines short-term dispatch decisions with long-term investment decisions.
Specifically, IPM seeks the optimal solution to an "objective function," which is the summation of all the
costs incurred by the electric power sector, i.e., capital costs, fixed and variable O&M costs, and fuel
costs, on a net present value basis over the entire evaluated time horizon. The objective function is
minimized subject to a series of supply and demand constraints. Supply-side constraints include capacity
constraints, availability of generation resources, plant minimum operating constraints, transmission
constraints, fuel supply constraints, and environmental constraints. Demand-side constraints include
reserve margin constraints and minimum system-wide load requirements. The assumptions for total
electricity demand and demand growth over IPM's period of analysis (see Section 5.1.1) are obtained
from the Department of Energy's Annual Energy Outlook 2023 (EIA, 2023b). IPM runs under the
assumption that electricity demand must be met and maintains a consistent expectation of future load.
This analysis does not consider the relationship of the price of power on the quantity of electricity
demanded (U.S. EPA, 2023a).
The final difference between EPA's electricity market optimization model analysis and the analysis in
Chapter 4 is the inclusion of estimated market-level impacts of environmental rules in the analysis
baseline. The screening-level analysis estimates the impacts resulting from compliance with the final rule
only, relative to a baseline that includes compliance with the 2020 ELG. Though the screening-level
analysis and EPA's assumptions regarding baseline operating practices and plant and firm revenue
implicitly account for existing environmental rules (e.g., to the extent that these rules affect the status or
characteristics of generating units), it does not explicitly estimate the effects of these rules across the
entire electricity market over the period of analysis. The IPM analysis, on the other hand, dynamically
estimates changes in capacity and generation over the IPM analysis period that account for retrofits and
retirements as a result of a broader set of environmental rules. Notably, for the analysis for the final rule,
EPA started from an electricity market "reference case" (Summer 2022) that includes the Inflation
Reduction Act provisions directed towards electricity generators,57 the Good Neighbor Plan which
addresses transport under the National Ambient Air Quality Standards (NAAQS) for ozone, as well as the
requirements of the 2020 ELG, Cross-State Air Pollution Rule (CSAPR and CSAPR Update), Mercury
57 As detailed in U.S. Environmental Protection Agency. (2023a). Documentation for EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model Post-IRA 2022 Reference Case. Retrieved from
https://www.epa.gov/system/files/documents/2023-03/EPA%20Platform%20v6%20Post-
IRA%202022%20Reference%20Case.pdf, the IRA includes tax credit provisions that affect power sector operations.
IPM accounts for the Clean Electricity Investment and Production Tax Credits (provisions 48E and 45Y of the IRA),
the credit for Carbon Capture and Sequestration (provision 45Q), the impacts from the Zero-Emission Nuclear Power
Production Credit (provision 45U), the Credit for the Production of Clean Hydrogen (provision 45 V), and the
Advanced Manufacturing Production Tax Credit (45X).
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and Air Toxics Standards (MATS), CWA section 316(b) rule, and the final 2015 CCR rule and CCR Part
A rule, among others (U.S. EPA, 2023a). The reference case also includes the effects of the Regional
Greenhouse Gas Initiative (RGGI), California's Global Warming Solutions Act, Renewable Portfolio
Standards state-level policies, including recent Clean Energy Standards (CES) in Illinois, Oregon,
Delaware, North Carolina, and Massachusetts (U.S. EPA, 2023a).
In analyzing the effect of Option B using IPM v6, EPA specified incremental capital costs58 and fixed and
variable O&M costs that are estimated to be incurred by steam electric power plants and generating units
to comply with the final rule requirements for BA transport water, FGD wastewater, and CRL (in the IPM
documentation, these costs are referred to as "cost adders".59 Compliance costs were developed using the
same approach described in Chapter 3, based on the technology options and compliance deadlines for this
final rule (see Table 1-1 and Section 3.1.3 for the technology basis and compliance deadlines,
respectively). As described in Section 3.1.3 forthe screening analysis, the IPM analysis assumes an
implementation year based on the compliance deadline and each plant's expected permit renewal year.
EPA ran IPM to simulate the dispatch of electricity generating units that would meet demand at the
lowest costs subject to the same constraints as those present in the analysis baseline. Within this
optimization framework, IPM provides generating units the option to retrofit or retire a portion or all of
the unit's capacity, depending on the specified unit operating costs, which include ELG compliance costs.
The rest of this chapter is organized as follows:
• Section 5.1 summarizes the key inputs to IPM and the key outputs reviewed as indicators of the
effect of the final rule.
• Section 5.2 provides the findings from the market model analysis.
• Section 5.3 discusses the effects of the final rule on new coal capacity.
• Section 5.4 identifies key uncertainties and limitations in the market model analysis.
5.1 Model Analysis Inputs and Outputs
To assess the impact of the final rule, EPA compared the policy run (Option B) to an IPM v6 Baseline
projection of electricity markets and plant operations that includes the modeled effects of the 2020 rule,
among existing environmental regulations.
5.1.1 Analysis Years
As described in U.S. EPA (2023a), IPM v6 models the electric power market over the 34-year period
from 2028 to 2059, breaking this period into the seven representative run years shown in Table 5-1. As
discussed in Chapter 1, steam electric power plants are estimated to implement control technologies to
meet the regulatory option requirements starting in 2025 and no later than December 2029. This
58 Capital costs are represented as the net present value of levelized stream of annual capital outlays and were specified in
terms of the expected useful life of the capital outlay (20 years) using IPM's real discount rate for all expenditures
(3.76 percent; see Chapter 10 in the IPM documentation [ibid.] for more information on IPM's financial discount rate).
59 The costs modeled in IPM do not include compliance costs associated with legacy wastewater or CRL discharged via
groundwater.
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technology implementation window primarily falls within the time period captured by the 2028 run year.
The 2050 run year captures the last year in the analysis period (2049).
Table 5-1: IPM Run Years
Run Year
Years Represented
2028
2028
2030
2029-2031
2035
2032-2037
2040
2038-2042
2045
2043-2047
2050
2048-2052
2055
2053-2059
Source: U.S. EPA, 2023a
To assess the effect of the final rule on electricity markets during the period after technology
implementation by all steam electric power plants - the steady state post-compliance period - EPA
analyzed detailed results reported for the IPM 2035 run year. The Agency also analyzed results
summarized at the level of the overall electricity market for the other run years. As discussed in Chapter
3, under the final rule specifications considered for this analysis, this steady state period is estimated to
begin in the first year following the technology implementation window, i.e., 2030, and continue into the
future. Because the model run year 2035 captures decisions made through the end of 2031, by which time
all plants will have achieved the revised limitations and standards, EPA determined that 2035 is an
appropriate run year to capture steady-state regulatory effects. Effects that may occur during the post-
compliance "steady state" include potential permanent changes in generating capacity from changes in
early retirement (closure) of generating units,6" long-term changes in electricity production costs due to
changes in operating expenses, permanent changes in electric generating capability and production
efficiency at steam electric power plants, and, as described above, changes in dispatches of other
generating units resulting from the changes in electric generating capacity.
5.1.2 Key Inputs to IPM V6for the Market Model Analysis of the Final Rule
5.1.2.1 Existing Plants
The inputs for the electricity market analyses include compliance costs and the technology
implementation year. IPM models the entire electric power generating industry using a total of 20,239
generating units at 8,980 plants. EPA estimated that 105 steam electric power plants may incur non-zero
compliance costs under Option B, based on the costing methodologies described in the TDD (U.S. EPA,
2024e) and timing of any announced retirements and repowerings relative to compliance deadlines.
EPA input the final rule capital and O&M costs (including costs incurred on a non-annual, periodic basis
such as every 5 years or every 10 years) into IPM as capital and fixed O&M (FOM) cost adders that
60 Early retirement of generating units reflects reductions in generating capacity relative to the baseline and relative to any
scheduled retirements.
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represent an incremental annual charge for operating the relevant EGUs.61 The capital costs were
annualized using IPM's conventional framework for recognizing costs incurred overtime, assuming a
capital recovery period of 15 years.62 Annualized capital cost and FOM cost adders are represented in
IPM as incremental costs specific to individual model plants and begin in the same technology
implementation years discussed in Chapter 3.
5.1.2.2 New Capacity
EPA did not specify ELG compliance costs for new coal capacity. IPM projections include new
generating capacity as needed to meet demand. As described below, IPM projects no new coal capacity
under the baseline or under Option B.
5.1.3 Key Outputs of the Market Model Analysis Used in Assessing the Effects of the Final Rule
IPM generates a series of outputs at different levels of aggregation (model plant, region, and nation). For
this analysis, EPA used a subset of the available IPM output for each model run (baseline and Option B),
focusing on metrics that quantify projected changes in capacity (including early retirements63 and new
capacity), generation, production costs, electricity prices, and emissions. See U.S. EPA (2023a) for
descriptions of the IPM variables.
EPA compared national-level outputs for IPM run years (2028, 2030, 2035, 2040, 2045, and 2050). EPA
then looked at changes in more detailed regional and plant-level outputs for the 2035 run year.
Comparison of these outputs for the baseline and Option B provides insight into the incremental effect of
the final rule on steam electric power plants and the broader electric power markets.64
5.2 Findings from the Market Model Analysis
The impacts of the final rule are assessed as the difference between key economic and operational impact
metrics that compare the results for Option B to the baseline. This section presents two sets of analysis:
61 There were no variable O&M (VOM) cost adders for the final rule.
62 IPM seeks to minimize the total, discounted net present value, of the costs of meeting demand, accounting for power
operation constraints, and environmental regulations over the entire planning horizon. These costs include the cost of
any new plant, pollution control construction, fixed and variable operating and maintenance costs, and fuel costs. As
described in the IPM documentation, "Capital costs in IPM's objective function are represented as the net present
value oflevelized stream of annual capital outlays, not as a one-time total investment cost. The payment period used in
calculating the levelized annual outlays never extends beyond the model's planning horizon: it is either the book life of
the investment or the years remaining in the planning horizon, whichever is shorter. This approach avoids presenting
artificially lower capital costs for investment decisions taken closer to the model's time horizon boundary simply
because some of that cost would typically be serviced in years beyond the model's view. This treatment of capital costs
ensures both realism and consistency in accounting for the full cost of each of the investment options in the model."
(U.S. Environmental Protection Agency. (2023a). Documentation for EPA's Power Sector Modeling Platform v6 Using
the Integrated Planning Model Post-IRA 2022 Reference Case. Retrieved from
https://www.epa.gov/system/files/documents/2023-03/EPA%20Platform%20v6%20Post-
IRA%202022%20Reference%20Case.pdf, page 2-7).
63 Early retirement refers to the retirement of an EGU before its planned or previously announced retirement year.
64 IPM output also includes total fuel usage, which is not part of the analysis discussed in this Chapter.
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• Analysis of national-level impacts: EPA compared baseline and Option B IPM results reported for
a series of run years to provide insight on the direction and magnitude of market-level changes
attributable to the final rule over time.
• Analysis of long-term regulatory impacts: As discussed earlier, to assess the long-term impact of
the final rule, EPA compared baseline and Option B IPM results reported for 2035. These results
provide insight on the effect of the final rule both for the entire electricity market and for steam
electric power plants specifically.
5.2.1 National-level Analysis Results for Model Years 2028-2050
Table 5-2 shows baseline values of total system costs, wholesale electricity price, total existing capacity,
new capacity, plant retirements, and generation mix at the national-level based on IPM results for the
baseline (i.e., without the final rule). The baseline projections show a decline in total coal generation
capacity during the period (from 105.8 GW in 2028 to 28.4 GW in 2050; 73 percent reduction) and
nuclear generation capacity (from 93.6 GW in 2028 to 45.4 GW in 2050; 51 percent reduction), and
increases in generation capacity from renewables and natural gas. These projections are consistent with
the market trends discussed in Section 2.3. Table 5-3 provides incremental changes in these measures for
Option B relative to the baseline (negative values represent decreases relative to the baseline). Note that
while the table includes projections for the 2050 run year, the represented period (2048-2052) includes
years 2050-2052 outside of the analysis period EPA used in its analysis of the social costs and benefits,
which covers 2025 through 2049.
Table 5-2: Baseline Projections, 2028-2050
Economic Measures
Baseline
2028
2030
2035
2040
2045
2050
Total Costs
Total Costs (million 2023$)
$128,379
$134,505
$138,325
$142,675
$154,477
$164,934
Prices
National Wholesale
Electricity Price (mills/kWh)
34.50
39.71
32.77
31.52
26.46
34.16
Total Capacity (Cumulative GW)
Renewables3
496.5
543.8
805.8
1,055.3
1,344.2
1,368.9
Coal
105.8
85.0
51.6
42.4
29.6
28.4
Nuclear
93.6
90.9
83.7
79.1
64.8
45.4
Natural Gas
471.0
478.6
476.0
516.1
565.6
673.5
Oil/Gas Steam
62.6
64.3
55.3
54.2
53.9
52.3
Other0
53.2
65.1
120.1
146.0
182.9
184.0
Grand Total
1,282.7
1,327.7
1,592.4
1,893.0
2,241.2
2,352.5
New Capacity (Cumulative GW
b
Renewables3
78.9
126.2
388.4
637.9
926.8
951.5
Coal
0.0
0.0
0.0
0.0
0.0
0.0
Nuclear
0.0
0.0
0.0
0.0
0.0
0.0
Natural Gas
33.8
41.8
41.7
82.6
148.9
268.8
Other0
16.6
28.6
83.5
109.4
146.4
147.4
Grand Total
129.3
196.6
513.6
830.0
1,222.1
1367.7
Retirements (Cumulative GW)
Combined Cycle
0.8
0.8
2.1
2.7
8.7
16.2
Coal
37.8
56.7
83.7
93.0
105.7
106.9
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Table 5-2: Baseline Projections, 2028-2050
Economic Measures
Baseline
2028
2030
2035
2040
2045
2050
Combustion Turbine
0.5
0.9
2.2
2.4
13.2
17.6
Nuclear
0.0
2.7
9.9
14.5
28.7
48.2
Oil/Gas
12.4
12.4
22.7
23.7
24.0
25.6
Other0
3.0
3.0
3.1
3.2
3.2
3.2
Grand Total
54.4
76.5
123.7
139.4
183.4
217.7
Generation Mix (thousand GWh)d
Renewables3
1,433.5
1,626.9
2,548.3
3,432.4
4,375.7
4,438.4
Coal
472.4
409.6
235.7
136.8
48.5
99.6
Nuclear
751.1
729.1
667.0
614.4
470.8
351.7
Natural Gas
1,652.0
1,670.3
1,344.4
936.5
616.8
870.7
Oil/Gas Steam
25.5
24.5
7.7
4.9
4.5
4.5
Other0
83.4
99.4
178.4
223.1
309.0
315.1
Grand Total
4,418.0
4,559.9
4,981.4
5,348.1
5,825.3
6,079.9
a. Renewables include hydropower and non-hydropower renewables.
b. Reported values for new generation capacity include new modeled capacity and new hardwired capacity.
c. Values for energy storage are reported in the "Other" category.
d. Electricity generation reported in this table does not include generation from distributed solar photovoltaic and differs from
generation reported later in Table 5-4, which does include this source.
Source: U.S. EPA Analysis, 2024.
Table 5-3: Incremental National Impact of Final Option B Relative to Baseline, 2028-2050
Economic Measures
Option B Changes Relative to Baseline
2028
2030
2035
2040
2045
2050
Total Costs
Total Costs (million 2023$)
1
m
¦uy
$670
$219
$355
ID
1
¦uy
i
$47
Prices
National Wholesale
Electricity Price (mills/kWh)
0.08
0.53
0.05
0.00
-0.02
-0.02
Total Capacity (Cumulative GW)
Renewables3
1.8
2.1
2.2
1.1
-0.3
-0.3
Coal
-4.8
-5.6
-5.6
-1.1
-0.1
-0.1
Nuclear
0.0
0.0
0.0
0.0
0.0
0.0
Natural Gas
3.6
3.9
4.2
1.1
0.2
0.3
Oil/Gas Steam
-0.2
-0.2
-0.1
-0.1
-0.1
-0.1
Other0
0.1
0.1
1.4
0.2
0.0
0.0
Grand Total
0.5
0.3
2.1
1.1
-0.4
-0.2
New Capacity (Cumulative GW
b
Renewables3
1.8
2.1
2.2
1.1
-0.3
-0.3
Coal
0.0
0.0
0.0
0.0
0.0
0.0
Nuclear
0.0
0.0
0.0
0.0
0.0
0.0
Natural Gas
3.5
3.9
4.2
1.1
0.2
0.3
Other0
0.1
0.1
1.4
0.2
0.0
0.0
Grand Total
5.4
6.0
7.9
2.3
-0.1
0.0
Retirements (GW)
Combined Cycle
0.0
0.0
0.0
0.0
0.0
0.0
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Table 5-3: Incremental National Impact of Final Option B Relative to Baseline, 2028-2050
Economic Measures
Option B Changes Relative to Baseline
2028
2030
2035
2040
2045
2050
Coal
4.8
5.6
6.0
1.5
0.5
0.5
Combustion Turbine
0.0
0.0
0.0
0.0
0.0
0.0
Nuclear
0.0
0.0
0.0
0.0
0.0
0.0
Oil/Gas
0.2
0.2
0.1
0.1
0.1
0.1
Other0
0.0
0.0
0.0
0.0
0.0
0.0
Grand Total
4.9
5.7
6.1
1.6
0.6
0.6
Generation Mix (thousand GWh)
Renewables3
5.8
5.6
6.6
3.6
-0.3
-0.1
Coal
-18.1
-10.6
-21.2
-6.7
-1.1
-0.7
Nuclear
0.0
0.0
0.0
0.4
0.3
0.0
Natural Gas
12.6
6.3
14.9
2.4
1.2
1.0
Oil/Gas Steam
-1.0
-1.7
-0.6
0.0
-0.1
-0.1
Other0
0.2
0.2
2.1
0.0
0.0
-0.3
Grand Total
-0.5
-0.3
1.7
-0.3
0.1
0.0
a. Renewables include hydropower and non-hydropower renewables.
b. Reported values for new generation capacity includes new modeled capacity and new hardwired capacity.
c. Values for energy storage are reported in the "Other" category.
Source: U.S. EPA Analysis, 2024.
5.2.1.1 Findings for the Final Rule
Under Option B, total costs to electric power plants are projected to be greater than the baseline from
2028 to 2040. The increases in costs are greatest in the early years of the modeling period (e.g., by
$670 million in 2030), which is consistent with the timing of steam electric ELG implementation. IPM
projects small increases in wholesale electricity prices in 2028 through 2040 with an increase of 0.53
mills per kWh in 2030 relative to a baseline price of $40 mills/kWh. IPM projects no change or small
decreases in wholesale electricity prices in 2040 to 2050 with decreased of 0.02 mills per kWh in 2045
and 2050 relative to the baseline prices of 26 and 34 mills/kWh, respectively.
Looking at results for total capacity by energy source, coal capacity is estimated to decrease for all years
from 2028 to 2050, adding to the already significant reductions projected in the baseline. Meanwhile,
smaller decreases in capacity from oil/gas steam (0.1 to 0.2 GW), and greater increases in natural gas
capacity (0.2 to 4.2 GW) are estimated to occur from 2028 to 2050. Capacity from renewables is
estimated to increase during 2028 to 2040 but decrease during 2045 to 2050.
Additional coal retirements are estimated for all years, ranging between 0.5 to 6.0 GW of the 37.8 to
106.9 GW estimated to retire in the baseline. This accounts for most of the incremental retirements in the
electric market as a whole (for Option B relative to the baseline), which range between 0.6 to 6.1 GW.
Additional oil/gas steam retirements are also estimated for all years, ranging between 0.1 to 0.2 GW
above retirements estimated in the baseline.
Lastly, examining results for generation by energy source, generation from coal is estimated to decrease
for all years from 2028 to 2050 by 0.7 to 18.1 thousand GWh, with the largest declines occurring in the
first few years. These changes are offset in part by an increase in natural gas generation (1.0 to
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14.9 thousand GWh increase), nuclear generation (up to 0.4 thousand GWh increase), and generation by
renewables, which increases between 2028 and 2040 by 3.6 to 6.6 thousand GWh.
5.2.2 Detailed Analysis Results for Model Year 2035
In the following results which reflect conditions for model year 2035 (2032 through 2037), all plants are
estimated to meet the revised BAT limits and pretreatment standards associated with the final rule
(Option B). For this more detailed analysis, following the approach used for the 2015, 2020, and proposed
2023 rules (U.S. EPA, 2015, 2020, 2023d), EPA used parsed IPM outputs and considered impact metrics
of interest at three levels of aggregation:
• Impact on national and regional electricity markets (Section 5.2.2.1),
• Impact on steam electric power plants as a group (Section 5.2.2.2), and
• Impact on individual steam electric power plants (Section 5.2.2.3).
5.2.2.1 Impact on National and Regional Electricity Markets
The market-level analysis assesses national and regional changes as a result of the regulatory
requirements. EPA analyzed six measures:
• Changes in available capacity: This measure analyzes changes in the nameplate capacity
available to generate electricity. A long-term reduction in available capacity may result from
partial or full closures of steam electric power plants. Conversely, increased capacity may result
from avoided partial or full closure of the plants or the addition of new capacity. Only capacity
that is projected to remain operational in the baseline case but is closed in the policy case is
considered a closure attributable to the final rule. The model may project partial (i.e.. unit) or full
plant early retirements (closures) for the final rule. It may also project partial or full avoided
closures in which a unit or plant that is estimated to close in the baseline is estimated to continue
operation in the policy case. Avoided closures may occur, in particular, when the regulation
results in lower costs for a given plant.
• Changes in the wholesale price of electricity: This measure represents the change in the annual
average energy price (the marginal cost of meeting demand in each time segment, averaged
annually) plus any capacity prices associated with maintaining a reserve margin. In the long term,
electricity prices may change as a result of changes in generation costs at steam electric power
plants or due to generating unit and/or plant closures.
• Changes in generation: This measure considers the amount of electricity generated. At a regional
level, long-term changes in generation may result from plant closures or a change in the amount
of electricity traded between regions. The quantity of electricity demanded does not change
between the baseline and the final rule because meeting demand is an exogenous constraint
imposed by the model. However, the quantity of electricity demanded for electricity does vary
across the modeling horizon according to the model's underlying electricity demand growth
assumptions.
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• Changes in costs: This measure considers changes in the overall cost of generating electricity,
including fuel costs, variable and fixed O&M costs, capital costs, and carbon capture and storage
(CCS) costs. These costs are not limited to steam electric generating units or to compliance costs
of the final rule, but more broadly reflect changes in the cost of generating electricity across all
units. Fuel costs and variable O&M costs are production costs that vary with the level of
generation. Fuel costs generally account for the single largest share of production costs. Fixed
O&M costs and capital costs do not vary with generation. They are fixed in the short-term and
therefore do not affect the dispatch decision of a unit (given sufficient demand, a unit will
dispatch as long as the price of electricity is at least equal to its per MWh production costs).
However, in the long-run, these costs need to be recovered for a unit to remain economically
viable.
• Changes in average variable production costs per MWh\ This measure considers the change in
average variable production cost per MWh. Variable production costs are a subset of the costs in
the bullet above and include fuel costs and other variable O&M costs but exclude fixed O&M
costs and capital costs. Production cost per MWh is a primary determinant of how often a
generating unit is dispatched. This measure presents similar information to total fuel and variable
O&M costs, but normalized for changes in generation between the baseline and policy case.
• Changes in C02, NOx, S02, Hg, and HCL emissions: This measure considers the change in
emissions resulting from electricity generation, for example due to changes in the fuel mix.
Compliance with the final rule is estimated to increase generation costs when compared to the
baseline and make electricity generated by some steam electric units more expensive compared to
that generated at other steam electric or non-steam electric units. These changes may in turn result
in changes in air pollutant emissions, depending on the emissions profile of dispatched units.
Projected changes in air emissions are used as inputs for the analysis of air-related benefits of the
final rule (see Chapter 8 in the BCA (U.S. EPA, 2024a)).
Table 5-4 summarizes IPM results for the final rule at the level of the national market and also for
regional electricity markets defined on the basis of NERC regions. All of the impact metrics described
above are reported at both the national and NERC level except electricity prices, which are calculated in
IPM only at the regional level (i.e.. not aggregated to national level). Differences in the relative
magnitude of impacts across the NERC regions largely reflect regional differences in the number of
plants incurring costs and the magnitude of these costs for the final rule as compared to the baseline and
the generation mix.
Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2035
Economic Measures
(all dollar values in 2023$)
Baseline Value
Option B
Value
Difference
% Change
National Totals
Total Domestic Capacity (GW)
1,712
1,718
6.4
0.4%
Existing
-1.5
-0.1%
New Additions
7.9
0.5%
Early Retirements
1.5
0.1%
Wholesale Price ($/MWh)
$32.77
$32.82
$0.05
0.1%
Generation (TWh)
5,158
5,160
1.7
0.0%
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Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2035
Economic Measures
Option B
(all dollar values in 2023$)
Baseline Value
Value
Difference
% Change
Costs ($Millions)
$138,325
$138,544
$219
0.2%
Fuel Cost
$39,166
$38,975
-$191
-0.5%
Variable O&M
$5,351
$5,244
-$107
-2.0%
Fixed O&M
$65,915
$65,666
-$249
-0.4%
Capital Cost
$34,149
$34,536
$387
1.1%
CCS Costb
-$6,256
-$5,878
$379
-6.1%
Average Variable Production Cost ($/MWh)
$8.63
$8.57
-$0.06
-0.7%
C02 Emissions (Million MetricTons)
724
713
-11.6
-1.6%
Mercury Emissions (Tons)
2
2
-0.050
-2.0%
NOx Emissions (Million Tons)
0
0
-0.009
-3.4%
S02 Emissions (Million Tons)
0
0
-0.013
-5.3%
HCL Emissions (Million Tons)
0
0
-0.00012
-8.1%
Midwest Reliability Organization (MRO)
Total Domestic Capacity (GW)
224
228
3.9
1.8%
Existing
1 1 24
1.1%
New Additions
1,5
0.7%
Early Retirements
-2.4
-1.1%
Wholesale Price ($/MWh)
$25.88
$25.83
-$0.05
-0.2%
Generation (TWh)
641
642
1
0.2%
Costs ($Millions)
$11,368
$11,469
$101
0.9%
Fuel Cost
$1,627
$1,578
-$49
-3.0%
Variable O&M
$292
$286
-$6
-1.9%
Fixed O&M
$7,076
$7,137
$61
0.9%
Capital Cost
$3,835
$3,929
$94
2.5%
CCS Costb
-$1,462
-$1,461
$0
0.0%
Average Variable Production Cost ($/MWh)
$2.99
$2.90
-$0.09
-3.0%
C02 Emissions (Million MetricTons)
53
52
-1.526
-2.9%
Mercury Emissions (Tons)
1
1
-0.002
-0.4%
NOx Emissions (Million Tons)
0
0
-0.001
-2.3%
S02 Emissions (Million Tons)
0
0
-0.0004
-0.7%
HCL Emissions (Million Tons)
0
0
-0.000005
-1.4%
Northeast Power Coordinating Council (NPCC)
Total Domestic Capacity (GW)
128
129
0.9
0.7%
Existing
1 1 10
0.8%
New Additions
0.0
0.0%
Early Retirements
1 1 -lo
-0.8%
Wholesale Price ($/MWh)
$32.99
$32.91
-$0,086
-0.3%
Generation (TWh)
346
346
0
0.0%
Costs ($Millions)
$11,078
$11,073
-$6
-0.1%
Fuel Cost
$1,682
$1,678
-$4
-0.3%
Variable O&M
$283
$283
$0
-0.1%
Fixed O&M
$5,068
$5,071
$3
0.1%
Capital Cost
$4,044
$4,041
-$3
-0.1%
CCS Costb
$0
$0
$0
NA
Average Variable Production Cost ($/MWh)
$5.68
$5.67
-$0.01
-0.2%
C02 Emissions (Million MetricTons)
33
33
-0.108
-0.3%
Mercury Emissions (Tons)
0
0
0.000
0.0%
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Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2035
Economic Measures
Option B
(all dollar values in 2023$)
Baseline Value
Value
Difference
% Change
NOx Emissions (Million Tons)
0
0
-0.0001
-0.3%
S02 Emissions (Million Tons)
0
0
0.000
0.0%
HCL Emissions (Million Tons)
0
0
0.000
0.0%
Reliability First Corporation (RF)
Total Domestic Capacity (GW)
306
306
0.1
0.0%
Existing
I I "3.6
-1.2%
New Additions
I I 3.7
1.2%
Early Retirements
1.2%
Wholesale Price ($/MWh)
$31.99
$32.09
$0.10
0.3%
Generation (TWh)
1,039
1,039
0
0.0%
Costs ($Millions)
$30,899
$30,865
-$34
-0.1%
Fuel Cost
$9,702
$9,647
-$55
-0.6%
Variable O&M
$1,389
$1,318
-$71
-5.1%
Fixed O&M
$14,505
$14,294
-$211
-1.5%
Capital Cost
$6,402
$6,707
$305
4.8%
CCS Costb
-$1,099
-$1,101
-$2
0.2%
Average Variable Production Cost ($/MWh)
$10.67
$10.56
-$0.12
-1.1%
C02 Emissions (Million MetricTons)
192
183
-9.031
-4.7%
Mercury Emissions (Tons)
0
0
-0.027
-8.0%
NOx Emissions (Million Tons)
0
0
-0.005
-8.5%
S02 Emissions (Million Tons)
0
0
-0.008
-13.3%
HCL Emissions (Million Tons)
0
0
-0.00007
-17.5%
Southeast Electric Reliability Council (SERC)
Total Domestic Capacity (GW)
448
449
1.0
0.2%
Existing
1 1 "L6
-0.3%
New Additions
1 1 2.5
0.6%
Early Retirements
| 1.6
0.3%
Wholesale Price ($/MWh)
$33.14
$33.25
$0.11
0.3%
Generation (TWh)
1,534
1,535
1
0.0%
Costs ($Millions)
$46,339
$46,488
$149
0.3%
Fuel Cost
$17,681
$17,604
-$77
-0.4%
Variable O&M
$2,045
$2,016
-$29
-1.4%
Fixed O&M
$20,546
$20,441
-$105
-0.5%
Capital Cost
$8,656
$8,638
-$17
-0.2%
CCS Costb
-$2,589
-$2,212
$377
-14.6%
Average Variable Production Cost ($/MWh)
$12.86
$12.78
-$0.07
-0.6%
C02 Emissions (Million MetricTons)
267
266
-0.6565
-0.2%
Mercury Emissions (Tons)
0
0
-0.0202
-4.8%
NOx Emissions (Million Tons)
0
0
-0.0029
-3.3%
S02 Emissions (Million Tons)
0
0
-0.0037
-4.7%
HCL Emissions (Million Tons)
0
0
-0.00005
-13.1%
Texas Reliability Entity (TRE)
Total Domestic Capacity (GW)
201
201
0.04
0.0%
Existing
0.02
0.0%
New Additions
1
0.03
0.0%
Early Retirements
-0.02
0.0%
Wholesale Price ($/MWh)
$28.02
$28.03
$0.0124
0.0%
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Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2035
Economic Measures
Option B
(all dollar values in 2023$)
Baseline Value
Value
Difference
% Change
Generation (TWh)
507
507
0.09
0.0%
Costs ($Millions)
$11,258
$11,260
$2
0.0%
Fuel Cost
$1,518
$1,517
-$1
-0.1%
Variable O&M
$194
$193
$0
-0.2%
Fixed O&M
$7,180
$7,181
$1
0.0%
Capital Cost
$2,903
$2,902
-$1
-0.1%
CCS Costb
-$537
-$534
$3
-0.6%
Average Variable Production Cost ($/MWh)
$3.38
$3.37
$0.00
-0.1%
C02 Emissions (Million MetricTons)
37
37
-0.0271
-0.1%
Mercury Emissions (Tons)
0
0
-0.0001
-0.1%
NOx Emissions (Million Tons)
0.01143
0.01143
0.000007
0.1%
S02 Emissions (Million Tons)
0.00861
0.00856
-0.0001
-0.6%
HCL Emissions (Million Tons)
0.00010
0.00010
-0.0000002
-0.2%
Western Electricity Coordinating Council (WECC)
Total Domestic Capacity (GW)
406
406
0.4
0.1%
Existing
1 1 03
0.1%
New Additions
0.2
0.0%
Early Retirements
1 1 "0.3
-0.1%
Wholesale Price ($/MWh)
$39.03
$39.04
$0,014
0.0%
Generation (TWh)
1,091
1,092
0
0.0%
Costs ($Millions)
$27,383
$27,389
$6
0.0%
Fuel Cost
$6,956
$6,951
-$5
-0.1%
Variable O&M
$1,148
$1,147
-$1
-0.1%
Fixed O&M
$11,539
$11,542
$2
0.0%
Capital Cost
$8,309
$8,319
o
1
¦uy
0.1%
CCS Costb
-$570
-$570
$0
0.0%
Average Variable Production Cost ($/MWh)
$7.43
$7.42
-$0.01
-0.1%
C02 Emissions (Million MetricTons)
142
142
-0.2301
-0.2%
Mercury Emissions (Tons)
1
1
0.0000
0.0%
NOx Emissions (Million Tons)
0
0
-0.00003
-0.1%
S02 Emissions (Million Tons)
0
0
-0.0002
-0.6%
HCL Emissions (Million Tons)
0
0
0.0000
0.0%
a. Numbers may not add up due to rounding.
b. The "CCS Cost" is the cost of C02 transportation and storage and also includes expenses on equipment and pipelines, as well
as the total value of 45Q tax credits and enhanced oil recovery (EOR) revenues. In the baseline and under Option B, the total
private costs are negative because the sum of the tax credits and EOR revenues exceed the equipment and pipeline costs of C02
storage. Under Option B, total CCS Costs are less negative, and therefore these costs increase relative to the baseline, as the
total amount of the 45Q tax credit received by the sector and/or EOR revenues fall due to lower coal generation.
Source: U.S. EPA Analysis, 2024.
5.2.2.1.1 Findings for Regulatory Option B
As reported in Table 5-4, the Market Model Analysis indicates that the final rule can be expected to have
small effects on the electricity market, relative to the baseline, on both a national and regional sub-market
basis, in the year 2035.
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At the national level, total annual costs increase by an estimated $219 million (approximately 0.2 percent)
relative to the baseline. Total annual costs vary by region and are estimated to increase in the MRO,
SERC, and WECC regions and decrease in the NPCC, RF, and TRE. Total costs in the SERC region
change by the largest amount with an increase of $149 million (0.5 percent), followed by the MRO region
with an increase of $101 million (0.8 percent); changes in estimated total annual costs in the other regions
range between $6 million (WECC) and -$34 million (RF). Overall, at the national level, the net change in
total capacity, including decreases in existing capacity (which includes early retirements) and reductions
in new plants/units, is an increase of approximately 6.4 GW in capacity, which is 0.4 percent of total
market capacity. Overall, the final rule is estimated to have a minimal effect on capacity availability and
supply reliability across the regions and at the national level. The net capacity increase is a result of an
increases in capacity in the SERC region of 1 GW and the MRO region of 3.9 GW (0.2 and 1.8 percent of
total market capacity in those regions, respectively) due to greater increases of new capacity additions and
existing capacity that more than offset decreases from early retirements. Overall impacts on wholesale
electricity prices are similarly minimal. Wholesale electricity prices are estimated to increase in the RF,
SERC, TRE, and WECC regions with decreases in the MRO and NPCC regions. Price changes in
individual regions range from $0.09 per MWh (0.3 percent) in NPCC to $0.10 per MWh 0.3 percent) in
RF. Finally, at the national level, total costs are estimated to increase by $0.05 (approximately
0.1 percent).
At the national level in the year 2035, there are decreases in emissions among all air pollutants modeled.
NOx emissions decrease by 3.4 percent; SO2emissions decrease by 5.3 percent; CO2 emissions decrease
by 1.6 percent, mercury emissions decrease by 2 percent; and HCL emissions decrease by 8.1 percent.
The impact on emissions varies across regions and by pollutant. Emissions increase in some and decrease
in other NERC regions, but the general trend is a decrease in air emissions at the U.S. and regional
levels.65 Furthermore, emission increases modeled in some regions are transient; for example, IPM state-
level outputs shows emissions for some pollutants in Texas (part of the TRE NERC region) increasing in
some years and decreasing in other years.
5.2.2.2 Impact on Steam Electric Power Plants as a Group
For the analysis of impact on steam electric power plants as a group, EPA used the same IPM v6 results
for 2035 used above to analyze the impact on national and regional electricity markets; however, this
analysis considers the effect of the final rule on the subset of plants to which the ELGs apply, i. e., steam
electric power plants. The purpose of the previously described electricity market-level analysis is to
assess the impact of the final rule on the entire electric power sector, i. e., including generators such as
combustion turbines, wind or solar to which the ELGs do not apply. By contrast, the purpose of this
analysis is to assess the impact of the final rule specifically on steam electric power plants. The analysis
results for the group of steam electric power plants overall show a slightly greater impact on a percentage
basis than that observed over all generating units in the IPM universe (/'. e., market-level analysis
discussed in the preceding section [Impact on National and Regional Electricity Markets})', this is
because, at the market level, impacts on steam electric units are offset by changes in capacity and energy
production in the non-steam electric units.
65 The changes in emissions only accounts for changes in the profile of electricity generation, and do not include
emissions associated with transportation or auxiliary power, which EPA analyzed separately (see TDD for details).
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The metrics of interest are largely the same as those presented above in assessing the effect of the final
rule on the aggregate of the 688 steam electric power plants explicitly represented in IPM (as opposed to
additional steam electric power plants that were not surveyed by EPA in the Steam Electric Survey [see
U.S. EPA, 2015]).66 In addition, a few measures differ: (1) new market-wide capacity additions and prices
are not relevant at the level of steam electric power plants, (2) changes in emissions at only the 688 steam
electric power plants provide incomplete insight for the overall estimated effect of the rule on emissions
and are therefore not presented, and (3) the number of steam electric power plants with projected closure
(or avoided closure) is presented.
The following four measures are reported in the analysis of steam electric power plants as a group. In all
instances, the measures are tabulated for 688 steam electric power plants explicitly included in EPA's
Steam Electric Survey and analyzed in the Market Model Analysis (note that steam electric power plants
not included in the tabulation incur no compliance costs for the options EPA analyzed in IPM or are
retired and not represented in IPM):
• Changes in available capacity: These changes are defined in the same way as in the preceding
section (Impact on National and Regional Electricity Markets), with the exception of the units
used (MW).
• Changes in generation: Long-term changes in generation may result from either changes in
available capacity (see discussion above) or in the dispatch of a plant due to changes in
production cost resulting from compliance response.
• Changes in costs: These changes are defined in the same way as in the preceding section (Impact
on National and Regional Electricity Markets).
• Changes in variable production costs per MWh\ These changes are defined in the same way as in
the preceding section (Impact on National and Regional Electricity Markets).
Table 5-5 reports results of the Market Impact Analysis for steam electric power plants, as a group.
The impacts of the final rule on steam electric power plants differ from the total market impacts as these
plants become less competitive compared to plants that see no production cost increases under the final
rule. As a result, capacity and generation impacts are greater for this set of plants than for the entire
electricity market, relative to the baseline, but absolute differences are still small. As described above for
the market-level analysis, those impacts vary across the NERC regions.
66 There are 688 steam electric power plants that were surveyed by EPA in the Steam Electric Survey and are represented
in IPM. EPA estimates that there are 858 plants in the total steam electric power generating industry, calculated on a
sample-weighted basis. For details on sample weights, see TDD.
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Table 5-5: Impact of the Final Rule on In-Scope Plants, as a Group, in the Year 2035a
Economic Measures
Option B
(all dollar values in 2023$)
Baseline Value
Value
Difference
% Change
National Totals
Total Domestic Capacity (MW)
220,237
214,455
-5,782
-2.6%
Early Retirements - Number of Plants
78
83
5
6.4%
Full & Partial Retirements-Capacity
104,544
110,326
5,782
5.5%
(MW)
Generation (GWh)
789,529
765,950
-23,579
-3.0%
Costs ($Millions)
$28,580
$27,740
-$840
-2.9%
Fuel Cost
$13,957
$13,454
-$503
-3.6%
Variable O&M
$1,976
$1,840
-$136
-6.9%
Fixed O&M
$15,419
$15,041
-$378
-2.5%
Capital Cost
$3,202
$3,000
-$202
-6.3%
CCS Costb
-$5,974
-$5,595
$379
-6.3%
Average Variable Production Cost ($/MWh)
$20.18
$19.97
-$0.21
-1.1%
Midwest Reliability Organization (MRO)
Total Domestic Capacity (MW)
27,018
27,018
0
0.0%
Early Retirements - Number of Plants
25
26
1
4.0%
Full & Partial Retirements-Capacity
21,954
21,954
0
0.0%
(MW)
Generation (GWh)
69,410
68,117
-1,293
-1.9%
Costs ($Millions)
$2,400
$2,399
-$1
0.0%
Fuel Cost
$1,156
$1,129
-$27
-2.3%
Variable O&M
$192
$189
-$3
-1.7%
Fixed O&M
$1,671
$1,704
m
m
¦uy
2.0%
Capital Cost
$842
$837
-$4
-0.5%
CCS Costb
-$1,462
-$1,461
$0
0.0%
Average Variable Production Cost ($/MWh)
$19.43
$19.36
-$0.07
-0.4%
Northeast Power Coordinating Council (NPCC)
Total Domestic Capacity (MW)
7,626
7,626
0
0.0%
Early Retirements - Number of Plants
2
2
0
0.0%
Full & Partial Retirements-Capacity
2,709
2,709
0
0.0%
(MW)
Generation (GWh)
18,184
18,131
-53
-0.3%
Costs ($Millions)
$857
$856
-$1
-0.1%
Fuel Cost
$242
$241
-$1
-0.4%
Variable O&M
$24
$24
$0
-0.5%
Fixed O&M
$591
$591
$0
0.0%
Capital Cost
$0
$0
$0
NA
CCS Costb
$0
$0
$0
NA
Average Variable Production Cost ($/MWh)
$14.64
$14.62
-$0.02
-0.1%
ReliabilityFirst Corporation (RF)
Total Domestic Capacity (MW)
48,588
44,410
-4,178
-8.6%
Early Retirements - Number of Plants
14
17
3
21.4%
Full & Partial Retirements-Capacity
24,251
28,429
4,178
17.2%
(MW)
Generation (GWh)
143,716
130,430
-13,286
-9.2%
Costs ($Millions)
$5,996
$5,387
-$610
-10.2%
Fuel Cost
$2,289
$2,043
-$246
-10.8%
Variable O&M
$490
$400
-$90
-18.3%
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5: Electricity Market Analysis
Table 5-5: Impact of the Final Rule on In-Scope Plants, as a Group, in the Year 2035a
Economic Measures
Option B
(all dollar values in 2023$)
Baseline Value
Value
Difference
% Change
Fixed O&M
$3,737
$3,467
-$271
-7.2%
Capital Cost
$578
$578
-$1
-0.1%
CCS Costb
-$1,099
-$1,101
-$2
0.2%
Average Variable Production Cost ($/MWh)
$19.34
$18.73
-$0.61
-3.1%
Southeast Electric Reliability Council (SERC)
Total Domestic Capacity (MW)
93,041
91,447
-1,594
-1.7%
Early Retirements - Number of Plants
21
22
1
4.8%
Full & Partial Retirements-Capacity
38,147
39,741
1,594
4.2%
(MW)
Generation (GWh)
407,266
398,315
-8,950
-2.2%
Costs ($Millions)
$13,938
$13,706
-$232
-1.7%
Fuel Cost
$7,976
$7,746
-$231
-2.9%
Variable O&M
$939
$896
-$43
-4.6%
Fixed O&M
$6,257
$6,118
-$139
-2.2%
Capital Cost
$1,354
$1,158
-$196
-14.4%
CCS Costb
-$2,589
-$2,212
$377
-14.6%
Average Variable Production Cost ($/MWh)
$21.89
$21.70
-$0.20
-0.9%
Texas Reliability Entity (TRE)
Total Domestic Capacity (MW)
13,834
13,849
15
0.1%
Early Retirements - Number of Plants
5
5
0
0.0%
Full & Partial Retirements-Capacity
8,887
8,872
-15
-0.2%
(MW)
Generation (GWh)
37,973
37,944
-29
-0.1%
Costs ($Millions)
$1,419
$1,420
$1
0.1%
Fuel Cost
$535
$534
-$1
-0.2%
Variable O&M
$70
$70
$0
-0.4%
Fixed O&M
$1,067
$1,068
$1
0.1%
Capital Cost
$282
$281
-$1
-0.4%
CCS Costb
-$537
-$534
$3
-0.6%
Average Variable Production Cost ($/MWh)
$15.95
$15.92
-$0.02
-0.1%
Western Electricity Coordinating Council (WECC
Total Domestic Capacity (MW)
30,131
30,105
-26
-0.1%
Early Retirements - Number of Plants
11
11
0
0.0%
Full & Partial Retirements-Capacity
8,596
8,622
26
0.3%
(MW)
Generation (GWh)
112,981
113,014
32
0.0%
Costs ($Millions)
$3,971
$3,972
$1
0.0%
Fuel Cost
$1,758
$1,761
$3
0.2%
Variable O&M
$260
$261
$0
0.1%
Fixed O&M
$2,095
$2,093
-$2
-0.1%
Capital Cost
$146
$146
$0
0.0%
CCS Costb
-$288
-$288
$0
0.0%
Average Variable Production Cost ($/MWh)
$17.86
$17.89
$0.03
0.1%
a. Numbers may not add up due to rounding.
b. The "CCS Cost" is the cost of C02 transportation and storage and also includes expenses on equipment and pipelines, as
well as the total value of 45Qtax credits and enhanced oil recovery (EOR) revenues. In the baseline and under Option B, the
total private costs are negative because the sum of the tax credits and EOR revenues exceed the equipment and pipeline costs
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5: Electricity Market Analysis
Table 5-5: Impact of the Final Rule on In-Scope Plants, as a Group, in the Year 2035a
Economic Measures
(all dollar values in 2023$)
Baseline Value
Option B
Value
Difference
% Change
of C02 storage. Under Option B, total CCS Costs are less negative, and therefore these costs increase relative to the baseline,
as the total amount of the 45Q tax credit received by the sector and/or EOR revenues fall due to lower coal generation.
Source: U.S. EPA Analysis, 2024.
5.2.2.2.1 Findings for the Final Rule (Regulatory Option B) in the 2035 Model Year
Under the final rule, the steam electric capacity is estimated to decrease approximately 2.6 percent.
For the group of steam electric power plants, total capacity decreases by 5,782 MW or approximately
2.6 percent of the 220,237 MW in baseline capacity. This decrease is largely attributable to net decreases
in total capacity of 4,178 MW (8.6 percent) and 1,594 MW (1.7 percent) in the RF and SERC regions,
respectively. One plant in SERC, one plant in MRO, and three plants in RF are projected to close under
the final rule.
The change in total generation is an indicator of how steam electric power plants fare, relative to the rest
of the electricity market. While at the market level there is essentially no projected change in total
electricity generation,67 for steam electric power plants, total generation is estimated to decrease by
23,579 GWh (3 percent). RF is projected to experience the largest decrease in generation from steam
electric power plants, 13,286 GWh (9.2 percent), with SERC estimated to experience the second largest
decrease in generation from steam electric power plants at 8,950 GWh (2.2 percent). Generation from
steam electric power plants is estimated to change in the remaining regions by less than <0.1 to -
1.9 percent.
The results for the group of steam electric power plants show a net decrease in total costs of $840 million
(2.9 percent). Total costs vary be region with the largest decrease in costs coming from the RF region
($610 million; 10.2 percent) followed by the SERC region ($232; 1.7 percent) and the largest increase68 in
costs coming from the WECC and TRE regions ($1 million; <0.1 percent and $1 million; 0.1 percent,
respectively). At the national level, variable production costs for steam electric power plants decrease by
$0.21 per MWh (1.1 percent). Effects vary by region, with changes ranging from $0.03 per MWh in
WECC and TRE to -$0.61 per MWh in RF.
5.2.2.3 Impact on Individual Steam Electric Power Plants
Results for the group of steam electric power plants as a whole may mask shifts in economic performance
among individual steam electric power plants. To assess potential plant-level effects, EPA analyzed the
67 At the national level, the demand for electricity does not change between the baseline and the analyzed regulatory
options (generation within the regions is allowed to vary) because meeting demand is an exogenous constraint imposed
by the model.
68 While costs decrease under Option B, this does not mean that plant owners would be undertaking changes on their own
in the absence of the rule in order to save costs. The values reported in this table are for in-scope plants only. The
negative changes follow from the decline in capacity and generation. Individual plants would not necessarily face lower
costs than the rest of the market in the absence of the final rule.
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distribution of plant-specific changes between the baseline and the final rule for three metrics: capacity
utilization,69 electricity generation, and variable production costs per MWh.70
Table 5-6 presents the estimated number of steam electric power plants with specific degrees of change in
operations and financial performance as a result of the final rule. In addition to the category of all plants,
the table also reports these metrics for plants that incur costs under Option B and plants that incur no costs
under Option B separately. Metrics of greatest interest for assessing the adverse impacts of the final rule
on steam electric power plants include the number of plants with reductions in capacity utilization or
generation (on the left side of the table), and the number of plants with increases in variable production
costs (on the right side of the table).
This table excludes steam electric power plants with modeled significant status changes in 2035 that
render these metrics of change not meaningful - i.e., a plant is assessed as either a full, partial, or avoided
closure in the IPM results for either the baseline or the regulatory option. The measures presented in
Table 5-5, such as change in electricity generation, are not meaningful for these plants. For example, for
a plant that is projected to close in the baseline but avoids closure under the final rule, the percent change
in electricity generation relative to baseline cannot be calculated. On this basis, 382 plants are excluded
from assessment of effects on individual steam electric power plants under the final rule. In addition, the
change in variable production cost per MWh of generation could not be developed for 58 plants with zero
generation in either the baseline or under the final rule (because the divisor, MWh, is zero).71 For change
in variable production cost per MWh, these plants are recorded in the "N/A" column.
69 Capacity utilization is defined as generation divided by capacity times 8,760 hours.
70 Variable production costs per MWh is defined as variable O&M cost plus fuel cost divided by net generation projected
in IPM.
71 In some cases, non-retired plants will be modeled to have zero generation in 2035. These plants may generate
electricity in later years.
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5: Electricity Market Analysis
Table 5-6: Impact of Final Rule on Individual In-Scope Plants in the Year 2035
Reduction
Increase
>1% and
>1% and
Economic Measures
>3%
<3%
<1%
No Change
<1%
<3%
>3%
N/Abc
Total
Steam Electric Power Plants that Incur Costs under Option B
Change in Capacity Utilization3
1
0
1
1
2
0
3
27
35
Change in Generation
3
1
0
1
1
0
2
27
35
Change in Variable Production Costs/MWh
0
0
4
0
4
0
0
27
35
Steam Electric Power Plants that Incur No Costs under Option B
Change in Capacity Utilization3
10
6
45
196
34
3
4
355
653
Change in Generation
16
16
29
196
22
7
12
355
653
Change in Variable Production Costs/MWh
1
11
25
35
164
4
0
413
653
All Steam Electric Power Plants
Change in Capacity Utilization3
11
6
46
197
36
3
7
382
688
Change in Generation
19
17
29
197
23
7
14
382
688
Change in Variable Production Costs/MWh
1
11
29
35
168
4
0
440
688
a. The change in capacity utilization is the difference between the capacity utilization percentages in the baseline and policy cases. For all other measures, the
change is expressed as the percentage change between the baseline and policy values.
b. Plants with operating status changes in either baseline or policy scenario have been excluded from general table calculations. Thus, for Option B, "N/A" reports
322 full and 52 partial baseline closures; 5 full closures as a result of the regulatory option; 3 avoided partial closures.
c. The change in variable production cost per MWh could not be developed for 58 plants with zero generation in either the baseline case or Option B policy case.
Source: U.S. EPA Analysis, 2024.
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5: Electricity Market Analysis
5.2.2.3.1 Findings for the Final Rule (Option B) in Model Year 2035
For the final rule, the analysis of changes in individual plants indicates that most plants experience only
slight effects - i.e., no change or less than a one percent reduction or one percent increase. Across the full
set of steam electric plants modeled, 36 plants (5 percent) incur a reduction in generation of at least one
percent; 17 of these plants (2.5 percent) are also estimated to incur a reduction in capacity utilization of at
least one percent. Finally, only 12 plants (2 percent) are estimated incur an increase in variable production
costs of at least one percent. For the set of 35 plants that incur costs under Option B, 4 plants incur a
decrease in generation and 1 plant is estimated to have no change in generation. Of the plants that incur
costs under Option B, three are estimated to increase electricity generation.
5.3 Estimated Effects of the Regulatory Options on New Capacity
IPM results show no new coal-fired capacity projected during the analysis period in the baseline. This
continues to be the case for the final rule.
5.4 Uncertainties and Limitations
Despite EPA's use of the best available information and data, EPA's analyses of the electric power
market and the overall economic impacts of the final rule involve several sources of uncertainty:
• Length of capital recovery period. Some of the EGUs estimated to incur ELG costs during the
period of analysis have planned retirement dates in IPM that are less than 15 years after the year
in which they are estimated to install wastewater treatment technologies to meet the revised
limits. The early retirement of these EGUs in IPM relative to the length of the capital recovery
period and the associated truncation of the annual charges results in ELG costs represented in the
model that are lower than the total estimated capital costs for meeting ELG limits for these
units.72 Overall, IPM recognizes 87 percent of the estimated capital costs of the final rule. See
ICF (2024) for details.
• Steam electric power plant response to changes in production costs: IPM includes information
about announced retirements only to the extent that there is a high degree of certainty about the
future implementation of the announced action (U.S. EPA, 2023a). To the extent that some
utilities" business strategy and integrated resource plans call for the retirement of coal generation
assets and transition toward other sources of energy such as renewables or natural gas that is
separate from the factors modeled in IPM, then IPM may overstate retirements resulting from
incremental costs under the final rule.
• Demand for electricity: IPM assumes that electricity demand at the national level will not change
between the baseline and the final rule (generation within the regions is allowed to vary); this
constraint is exogenous to the model. IPM v6 embeds a baseline energy demand forecast that is
derived from the Department of Energy's Annual Energy Outlook 2023 (EIA, 2023b). IPM does
not capture changes in demand that may result from electricity price changes associated with the
72 EGUs with a planned retirement date are removed from the inventory of modeled units on that date irrespective of the
modeled market conditions. The removal of such units pre-empts IPM from making any further decisions regarding the
operational status or configuration of the units. It also stops any operating costs associated with the units.
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5: Electricity Market Analysis
final rule (i.e.. demand is inelastic with respect to price73). While this constraint may
underestimate total demand in analyses of policy options that have lower compliance costs
relative to the baseline, EPA assumes that relaxing the constraint would not affect the results
analyzed. As described in Section 5.2.1 and Section 5.2.2, the price changes associated with the
final rule in all NERC regions are very small (less than 0.11 $/MWh). EPA therefore concludes
that the assumption of inelastic demand-responses over these changes in prices is reasonable.
• Fuel, prices: Prices of fuels (e.g., natural gas and coal) are determined endogenously within IPM.
IPM modeling of fuel prices uses both short- and long-term price signals to balance supply of,
and demand in, competitive markets for the fuel across the modeled time horizon. The model
relies on AEO2023's electric demand forecast for the US and employs a set of EPA assumptions
regarding fuel supplies and the performance and cost of electric generation technologies as well
as pollution controls. Differences in actual fuel prices relative to those modeled by IPM, such as
lower natural gas prices that may result from increased domestic production or short-term
increases in natural gas prices resulting from Russia's invasion of Ukraine, would be estimated to
affect the cost of electricity generation and therefore the amount of electricity generated by steam
electric power plants, irrespective of the final rule. More generally, differences in fuel prices, and
related changes in electricity production costs, can affect the modeled dispatch profiles, planning
for new/repowered capacity, and contribute to differences in a number of policy-relevant
parameters such as electricity production costs, prices, and emission changes.
• Electricity imports: IPM assumes that electricity imports from Canada and Mexico do not change
between the baseline and the final rule. Holding international imports fixed potentially
understates the impacts of changes in production costs and electricity prices in U.S. domestic
markets. EPA does not expect that this assumption materially affects results, however, since IPM
projects that only one of the eight NERC regions will import electricity (WECC) in 2035, and the
level of imports compared to domestic generation in this region is very small (about 0.3 percent).
73 Electricity demand has been found to be inelastic with respect to price in the short-term. See, for example, Burke, P. J.,
& Abayasekara, A. (2018). The price elasticity of electricity demand in the United States: A three-dimensional
analysis. The Energy Journal, 39(2). and Bernstein, M. A., & Griffin, J. (2005). Regional Differences in the Price-
Elasticity of Demand For Energy. RAND Corporation. https://www.rand.org/pubs/teclinical_reports/TR292.html.
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6: Impacts on Employment
6 Assessment of Impacts on Employment
6.1 Background and Context
In addition to addressing the costs and impacts of the regulatory options, EPA estimated the potential
impacts of this rulemaking on employment, measured in terms of changes in full-time equivalent (FTE)
labor inputs.74 Evaluation of employment impacts is required by many environmental statutes, including
the Clean Water Act (CWA section 5071, 33 U.S.C. § 13671). This section first provides an overview of
the analysis methodology. It then quantitatively presents the Agency's estimates of the potential impacts
of the final rule on labor inputs at power plants and other relevant economic sectors.
6.2 Analysis Overview
This section describes the Agency's approach to quantitatively estimate the labor impacts (FTEs) of the
final rule.75 The agency is using an approach outlined in U.S. EPA (2018) to develop a bottom-up analysis
that evaluates first order impacts, i.e., the direct changes in the amount of labor needed in the power
generation sector and in directly related sectors such as equipment manufacturing and fuel production.
This analysis does not account for other indirect and induced effects of the rule on the broader economy
due to, for example, changes in forecasted electricity prices. (As discussed in Chapter 7, the potential
electricity price effects of the final rule are estimated to be small.)
6.2.1 Quantification of Projected Actions
EPA quantified two categories of actions resulting from the final rule that may affect labor inputs:
• The changes in the profile of electricity generation and in fuel consumption, based on electricity
market modeling using IPM, as described in Chapter 5; and
• The ELG compliance technology expenditures (including total capital, initial one-time, and O&M
costs) by steam electric power generating plants, as described in Chapter 3.
EPA conducted this analysis for regulatory Option B and the year 2030 to be consistent with the period
when plants would comply with the final rule (2025-2029).
Table 6-1 presents the estimated changes in new generation capacity and retirements in 2030 due to
Option B relative to the baseline. The Agency calculated the net change in generation capacity by
subtracting the projected retirements, in terms of GW of generation capacity, from projected new
generation capacity for each generation type. The net change in generation capacity is used in this
analysis for determining the required resources of new generation capacity by generation type.
74 One FTE equals 2,080 labor hours per year.
75 Because the employment analysis is based, in part, on electricity market modeling using IPM, this analysis does not
include the employment impacts associated with legacy wastewater limits or the treatment of unmanaged CRL.
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6: Impacts on Employment
Table 6-1: Estimated Change in Generating Capacity Under Option B Relative to Baseline in
2030
Generation Type3
New Generation
Baseline Option B
GW)
Change
Retirements (GW)b
Baseline Option B Change
Net Capacity
Change (GW)C
Solar
11.06
12.05
1.00
0
0
0
1.00
Wind
77.77
78.85
1.08
1.08
Energy Storage
15.19
15.25
0.05
0.05
Combined Cycle
(without CCS)
20.35
23.73
3.39
0.80
0.75
-0.04779
3.43
Combustion
Turbine
13.91
14.39
0.48
0.95
0.95
0.48
Coal steam
0
0
56.44
62.05
5.62
-5.62
Oil & Natural Gas
Steam
12.39
12.55
0.16
-0.16
Nuclear
0
0
0
2.69
2.69
0.00
0.00
Total
138.28
144.28
6.00
73.26
78.99
5.73
0.27
a. Only generation types with non-zero changes in new generation or retirements under Option B relative to the baseline are
presented.
b. New generation capacity reported for analysis year 2030 is online in 2030, and retirements reported for analysis year 2030
are offline by 2030.
c. Net capacity change is calculated as new generation less retirements (in GW) under Option B relative to the baseline.
Source: U.S. EPA Analysis, 2024.
EPA also used IPM projections to estimate the quantity of new generation capacity being built in 2030.
As described in Chapter 5, IPM outputs are reported for several analysis years, including 2030 and 2035.
EPA assumed that the incremental change in new generation capacity between 2030 and 2035 is
representative of capacity possibly under construction in 2030. Based on the build duration (years) for
each type of generating capacity, EPA estimated the fraction of the incremental change in new capacity
that would be under construction in each year. For example, construction for capacity with a build
duration of 3 years that is not online by 2030 but is online by 2035 could begin in 2028, 2029, 2030,
2031, or 2032. Of these construction start years, only 2028, 2029, and 2030 would be under construction
in 2030. For this example, EPA therefore assumes that 3/5 of the incremental change in new generation
capacity would be under construction in 2030. Table 6-2 presents the Agency's estimates of the
incremental change in new generation capacity under construction in 2030 for each generation type.
Table 6-2: Incremental Change in New Generation Capacity Under
Construction in 2030
Incremental Change in New Generation
Generation Type
Capacity (GW)
Solar
<0.01
Wind
0.08
Energy Storage
1.43
Combined Cycle (without CCS)
<0.01
Combustion Turbine
0.15
Total
1.66
Source: U.S. EPA Analysis, 2024.
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6: Impacts on Employment
Table 6-3 presents the estimated changes in consumption of natural gas and coal in 2030 under Option B
relative the baseline. EPA calculated the net change in fuel consumption for Option B by subtracting the
estimated fuel use under the baseline from the fuel use estimated under Option B in 2030. EPA used these
estimates of net fuel consumption to determine the changes in labor inputs in associated sectors due to
fuel use changes under the final rule relative to the baseline.
Table 6-3: Estimated Change in Fuel Consumption Under Option B Relative to Baseline in 2030
Fuel Type
Region
Appalachia
Interior
Waste
West
All regions
Baseline
Coal (Million Short Tons)
34.54
34.17
7.15
142.53
218.39
Natural Gas (Trillion Cubic Feet)
N/A
N/A
N/A
N/A
11.70
Option B
Coal (Million Short Tons)
38.75
35.07
7.15
141.49
222.46
Natural Gas (Trillion Cubic Feet)
N/A
N/A
N/A
N/A
11.70
Change in Fuel Consumption (Option B less Baseline)
Coal (Million Short Tons)
-4.21
-0.91
0.00
1.04
-4.07
Natural Gas (Trillion Cubic Feet)
N/A
N/A
N/A
N/A
0.00
Source: U.S. EPA Analysis, 2024.
Table 6-4 presents the estimated capital and operating costs associated with installation and operation of
the wastewater treatment technology used as basis for the final rule ELGs. EPA used these total cost
estimates to determine the associated effects on labor inputs.
Table 6-4: Option B Technology Capital and Operation Costs (millions, 2023$)
Cost Type
Wastestream
BA
FGD
CRL
Total
Capital Costs
$165
$1,309
$1,700
$3,173
Pre-Tax Annualized O&M Costs
$8
$91
$113
$212
Source: U.S. EPA Analysis, 2024.
6.2.2 Resource Requirements of Changes in Projected Actions and Treatment Technology
EPA estimated the resource requirements associated with the changes in projected actions and new
wastewater treatment technologies used as basis for the final rule in dollars. This section of the analysis is
separated in four parts, described below:
1) Construction of new generation capacity;
2) Operation of new generation capacity and retirements;
3) Installation of new treatment technology; and
4) Operation of new wastewater treatment technology.
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6.2.2.1 Construction of New Generation Capacity
EPA first estimated the costs associated with construction of new generation capacity for several different
cost components (e.g., equipment, materials, construction labor, and engineering services). EPA
calculated the annual construction cost ($/year) as the product of the unit capital cost ($/kW) from U.S.
EPA (2023b) and the estimated new capacity construction in 2030 (kW/year), as described in Section
6.2.1. EPA then calculated construction costs for specific cost components by multiplying the total capital
costs associated with construction of new generation capacity by the estimated percentage of costs that
correspond with each cost component based on information from U.S. EPA (2018). EPA further mapped
each cost component to the most relevant NAICS sector. Table 6-5 displays the estimated percentage of
costs for new generation capacity (for each relevant generation type) that corresponds with each cost
component and associated NAICS sector.
Table 6-5: Capital and Labor Components for Construction of New Generation Capacity by
Generation Type
Cost Component
NAICS
Sector
NAICS Sector Description
Average % of Total Operation Costs
Renewables
& Biomass
Combined
Cycle
Combustion
Turbine
Equipment
333
Machinery Manufacturing
54%
65%
65%
Material
33111
Iron and Steel Mills and
Ferroalloy Manufacturing
6%
10%
10%
Labor
236210
Industrial Building
Construction
31%
18%
18%
Engineering and
Construction
Management
541330
Engineering Services
9%
7%
7%
Source: U.S. EPA Analysis, 2024; U.S. EPA, 2018.
6.2.2.2 Operation of New Generation Capacity and Retirements
As described in Section 6.2.1, EPA used IPM projections to estimate the incremental quantity of
generation capacity in operation in 2030 due to the final rule (see Table 6-1). EPA estimated the annual
resource costs for operating new generation capacity, or reduction in resource costs from projected
retirements, based on annual fixed operating and maintenance (FOM) costs, as reported in U.S. EPA
(2023b). The Agency estimated annual FOM cost ($/year) by multiplying the FOM cost ($/kW-year) by
the projected changed in capacity (kW). EPA then matched each generation type in the analysis to its
corresponding NAICS electricity generation sector, as shown in Table 6-6.
Table 6-6: NAICS Sectors Associated with Operation of New Generation Capacity
NAICS Sector
NAICS Sector Description
Generation Type
221112
Fossil fuel electric power generation
Combined cycle
Combustion turbine
Coal steam
Oil & natural gas steam
221113
Nuclear electric power generation
Nuclear
221114
Solar electric power generation
Wind
221115
Wind electric power generation
Solar
Source: U.S. EPA Analysis, 2024.
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6.2.2.3 Installation of New Wastewater Treatment Technologies
The compliance years for installation of the wastewater treatment technologies used as basis for the final
rule are between 2025-2029. As such, EPA does not expect plants to incur compliance costs from
installation of new treatment technology in the analysis year of 2030. Thus, EPA estimated that there will
be no employment impacts due to installation of new treatment technology in 2030. See Section 6.4 for
additional discussion of the effects on labor inputs associated with the installation of new treatment
technology prior to 2030.
6.2.2.4 Operation of New Wastewater Treatment Technologies
Plants will incur resource costs for operating and maintaining the wastewater treatment systems to meet
the ELGs in the final rule, including operating labor, maintenance labor and materials, energy costs, and
chemical purchases. EPA estimated the percentage of total annualized O&M costs that would be required
for each of these cost components (Eastern Research Group, 2022). EPA applied these percentages to the
total, pre-tax annualized O&M cost for each treatment technology to estimate the costs associated with
each cost component. EPA associated each identified cost component with the most relevant NAICS
sector. Table 6-7 presents the average percentage of total O&M costs and the relevant NAICS sector
associated with each cost component.
Table 6-7: Operation and Labor Components for New Wastewater Treatment Technologies
Cost Component
NAICS
Sector
NAICS Sector Description
Average % of Total O&M
Costs (All Treatment
Technologies)
Chemicals
3251
Basic Chemical Manufacturing
20%
Energy
22111
Electric power generation
5%
Monitoring
22111
Electric power generation
10%
Maintenance Materials
33111
Iron and Steel Mills and Ferroalloy
Manufacturing
10%
Operating Labor
221112
Fossil fuel electric power generation
25%
Transportation Operation
484230
Specialized Freight (except Used Goods)
Trucking, Long-Distance
5%
Disposal Operation
562211
Hazardous Waste Treatment and
Disposal
15%
Maintenance Labor
811310
Commercial and Industrial Machinery
and Equipment (except Automotive and
Electronic) Repair and Maintenance
10%
Source: U.S. EPA Analysis, 2024; Eastern Research Group, 2022.
6.2.3 Estimation and Aggregation of Labor Impacts
To estimate the total labor impacts of the final rule, EPA converted the estimated resource costs from
Section 6.2.2 into FTE estimates using the estimated labor productivity for each economic sector, based
on U.S. Census Bureau Economic Census data (U.S. Census Bureau, 2021a; U.S. Census Bureau, 2012).
Table 6-8 presents labor productivity estimates based on 2017 Economic Census data for the relevant
sectors identified in Section 6.2.2.
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Table 6-8: Base Labor Productivity by Relevant Sector
NAICS
Sector
NAICS Sector Description
Value of
shipments
(2023$
Millions) [A]
(2017)
Total
employees
[B] (2017)
Labor
productivity
[B/A] (2017)
Growth rate
(2012-2017)
333
Machinery manufacturing
$410,800
1,029,068
2.51
3.0%
3251
Basic Chemical Manufacturing
$245,653
148,181
0.60
6.4%
22111
Electric power generation
$134,418
138,647
1.03
0.5%
33111
Iron and Steel Mills and
Ferroalloy Manufacturing
$98,681
84,792
0.86
2.7%
221111
Hydroelectric power generation
$3,758
3,642
0.97
-3.6%
221112
Fossil fuel electric power
generation
$85,041
76,058
0.89
1.5%
221113
Nuclear electric power
generation
$32,699
48,521
1.48
0.3%
221114
Solar electric power generation
$2,030
2,163
1.07
-19.0%
221115
Wind electric power generation
$8,748
4,986
0.57
-8.1%
221116
Geothermal electric power
generation
$1,097
1,214
1.11
1.3%
221117
Biomass electric power
generation
$1,021
1,968
1.93
3.5%
221118
Other electric power generation
$24
95
4.04
-1.0%
236210
Industrial Building Construction
$28,689
71,562
2.49
0.6%
237130
Power and Communication Line
and Related Structures
Construction
$72,844
232,861
3.20
-5.3%
238910
Site Preparation Contractors
$109,842
385,177
3.51
-3.4%
335911
Storage battery manufacturing
$8,489
25,126
2.96
2.9%
484121
General Freight Trucking, Long-
Distance, Truckload
$126,726
519,358
4.10
-0.5%
484230
Specialized Freight (except Used
Goods) Trucking, Long-Distance
$46,023
174,571
3.79
-0.2%
541330
Engineering Services
$267,451
1,081,471
4.04
0.7%
562211
Hazardous Waste Treatment and
Disposal
$9,819
34,035
3.47
0.3%
562212
Solid Waste Landfill
$8,492
20,525
2.42
-1.4%
811310
Commercial and Industrial
Machinery and Equipment
(except Automotive and
Electronic) Repair and
Maintenance
$44,245
202,493
4.58
-2.2%
Source: U.S. Census Bureau, 2012; U.S. Census Bureau, 2021a; U.S. EPA Analysis, 2024.
EPA calculated the compound annual growth rate of labor productivity in each sector using U.S. Census
data from a five-year period (2012 to 2017). EPA estimated the labor productivity in 2030 using this
calculated growth rate. Due to uncertainty surrounding future labor productivity rates, EPA presents the
results of the employment analysis as a range: using the 2017 labor productivity rate, assuming labor
productivity remains constant between 2017 and 2030, and using a projected 2030 labor productivity rate
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assuming labor productivity grows between 2017 and 2030 at the same compound annual growth rate
observed from 2012 to 2017. EPA multiplied the estimated costs by NAICS sector (Section 6.2.2) by the
estimated labor productivity to estimate employment effects.
To estimate FTE changes associated with fuel consumption (e.g., coal, natural gas), EPA used 2022
regional coal mining productivity estimates from EIA (EIA, 2023i) and 2021 natural gas production and
employment estimates from EIA (EIA, 2023f; EIA, 2023e) and U.S. Census Bureau's County Business
Patterns (U.S. Census Bureau, 2023), respectively (Table 6-9). EPA divided the projected changes in coal
and natural gas use (by region for coal consumption) by the labor productivity estimates for coal and
natural gas to obtain the total labor hours required for fuel production. EPA converted labor hours to
employees assuming one FTE equals 2,080 labor hours per year. Total employment in the coal mining
industry in 2022 was 43,582 (EIA, 2023i). Total employment for the natural gas extraction industry was
28,547, respectively (NAICS code 21113; U.S. Census Bureau, 2023).
Table 6-9: Coal and Natural Gas Labor Productivity Estimates
Labor
Resource
productivity
Unit
Data vintage
Coal-Appalachian region
2.7
Short tons per labor hour
2022
Coal - Interior region
5.87
Short tons per labor hour
2022
Coal-Western region
16.04
Short tons per labor hour
2022
Coal - Waste
6.11
Short tons per labor hour
2022
Natural gas
728
Million Btu per labor hour
2021
Source: EIA, 2023e; EIA, 2023f; EIA, 2023i; U.S. Census Bureau, 2023; U.S. EPA Analysis 2024.
6.3 Estimated Impacts of the Final Rule in 2030
6.3.1 New Generation Capacity
Table 6-10 and Table 6-11 present the results of EPA's analysis of the impacts on labor inputs of changes
in generation capacity, by generation type and NAICS sector. In each sector identified and for both labor
productivity rates, EPA estimated increased FTEs associated with construction of new generation
capacity. Using the 2017 and adjusted 2030 labor productivity rates, the storage battery manufacturing
sector (NAICS code 335911) is expected to see the second greatest rise in FTE. In total, the Agency
estimated an increase of 3,786 to 5,450 FTEs using the 2017 and adjusted 2030 labor productivity rates,
respectively.
Table 6-10: Changes in Labor Inputs from Construction of New Generation Capacity in 2030 FTE)
Generation Type
Labor
T3
a>
£
¦9
two
Productivity
NAICS
£ u
o >
£
§
J2
o
E -8
O 3
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6: Impacts on Employment
Table 6-10: Changes in Labor Inputs from Construction of New Generation Capacity in 2030 FTE)
Labor
Productivity
Rates
NAICS
Sector
NAICS Sector Description
Generation Type
Combined
Cycle
Wind
Solar
Combustion
Turbine
Energy
Storage
All Types
335911
Storage Battery
Manufacturing
0
0
0
0
3,587
3,587
541330
Engineering Services
<0.01
10
<0.01
15
0
25
Total
-
<0.01
69
<0.01
130
3,587
3,786
Adjusted
2030
333
Machinery Manufacturing
<0.01
54
<0.01
127
0
181
33111
Iron and Steel Mills and
Ferroalloy Manufacturing
<0.01
2
<0.01
6
0
8
236210
Industrial Building
Construction
<0.01
23
<0.01
26
0
49
335911
Storage Battery
Manufacturing
0
0
0
0
5,185
5,185
541330
Engineering Services
<0.01
11
<0.01
17
0
27
Total
-
<0.01
89
<0.01
176
5,185
5,450
a. Only generation types with non-zero changes in new generation capacity are reported.
Source: U.S. EPA Analysis, 2024.
EPA estimated that overall labor inputs for operation of new generation capacity would decrease by 148
to 247 FTEs using the 2017 and adjusted 2030 labor productivity rates, respectively (Table 6-11). Under
both sets of labor productivity rates, labor inputs are expected to increase for certain generation types and
decrease for others. FTEs are expected to increase in sectors involved in combined cycle, combustion
turbine, wind, and solar. The increases for these generation types are a result of additional generation
capacity due to the final rule relative to the baseline. For combined turbine, a minority of increases in
FTEs are due to avoided retirements. Using the 2017 labor productivity rate, labor inputs are expected to
increase the most for wind and solar generation with 44 and 19 FTEs, respectively. Using the adjusted
2030 labor productivity rate, labor inputs are expected to increase the most for combined cycle and
combustion turbine with 14 and 12 FTEs, respectively. By contrast, the analysis shows estimated
decreases in FTEs associated with coal steam and oil and natural gas steam generation with the greatest
decrease occurring from reduced capacity of coal steam generation. Decreases for coal steam and oil and
natural gas steam generation are the result of capacity retirements due to the final rule. The total changes
in labor inputs for all generation types are small relative to overall employment in the electric power
generation sector (138,647 employees in 2017; see Table 6-8).
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Table 6-11: Changes in Labor Inputs from Operation of New Generation Capacity and
Retirements in 2030 (# FTEs)
Generation Typea,b
Labor Productivity
Rates
Combined
Cycle
Wind
Solar
Combustion
Turbine
Coal Steam
Oil &
Natural Gas
Steam
Nuclear
All Types
2017
12
44
19
10
-228
-4
0
-148
Adjusted 2030
14
3
6
12
-277
-5
0
-247
a. Results are presented as the net employment generated from new generation capacity minus retirements.
b. Only generation types with non-zero changes in employment are reported. Estimated employment impacts from hydro,
biomass, geothermal, landfill gas, and energy storage (pumped storage) were zero.
Source: U.S. EPA Analysis, 2024.
6.3.2 New Treatment Technology
Table 6-12 presents the impacts of new wastewater treatment technologies used as basis for the ELGs in
the final rule. Estimates of impacts on labor inputs are presented by wastestream and NAICS sectors
involved in operation of new treatment technology (see Section 6.4 for construction impacts).
EPA estimated that labor inputs would increase by 371 to 402 FTEs using the 2017 and 2030 adjusted
labor productivity rates, respectively due to operation of new treatment technologies, with all NAICS
sectors seeing an increase. Operation of CRL treatment technology is estimated to have the greatest
increase on labor inputs using either the 2017 and 2030 labor productivity rates (197 and 214 FTEs,
respectively) followed by FGD (160 and 173 FTEs, respectively) and BA (14 and 15 FTEs, respectively).
Additionally, the sector with the highest associated labor increases under both labor productivity rates is
the hazardous waste treatment and disposal sector (NAICS code 562211) with 110 and 114 FTEs,
respectively. Using 2017 labor productivity rates, the sector with the second highest increase is the repair
and maintenance for commercial and industrial machinery and equipment (except automotive and
electronic) sector (NAICS code 811310) with 97 FTEs. Using adjusted 2030 labor productivity rates, the
sector with the second highest increase is the electric power generation sector (NAICS code 22111) with
93 FTEs.
Table 6-12: Changes in Labor Inputs from Operation of New Technology in 2030 (# FTEs)
Labor
Wastestream
Productivity
NAICS
Rates
Sector
NAICS Sector Description
FGD
BA
CRL
Total
3251
Basic Chemical Manufacturing
11
1
14
26
22111
Electric Power Generation
35
3
43
80
33111
Iron and Steel Mills and Ferroalloy
Manufacturing
8
1
10
18
484230
Specialized Freight (except Used Goods)
2017
Trucking, Long-Distance
17
2
21
40
562211
Hazardous Waste Treatment and Disposal
47
4
59
110
Commercial and Industrial Machinery and
811310
Equipment (except Automotive and
Electronic) Repair and Maintenance
42
4
52
97
Total
-
160
14
197
371
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Table 6-12: Changes in Labor Inputs from Operation of New Technology in 2030 (# FTEs)
Labor
Wastestream
Productivity
NAICS
Rates
Sector
NAICS Sector Description
FGD
BA
CRL
Total
3251
Basic Chemical Manufacturing
25
2
30
57
22111
Electric Power Generation
40
4
49
93
33111
Iron and Steel Mills and Ferroalloy
Manufacturing
11
1
14
26
Adjusted
2030
484230
Specialized Freight (except Used Goods)
Trucking, Long-Distance
17
1
21
39
562211
Hazardous Waste Treatment and Disposal
49
4
61
114
Commercial and Industrial Machinery and
811310
Equipment (except Automotive and
Electronic) Repair and Maintenance
31
3
39
73
Total
-
173
15
214
402
Source: U.S. EPA Analysis, 2024.
6.3.3 Fuel Consumption Changes
Table 6-13 presents the impacts on labor inputs associated with changes in fuel consumption for
electricity generation, by region and fuel type. Overall, EPA estimated a net reduction of 793 FTEs. The
Appalachia region is estimated to experience the greatest reduction in labor input associated with coal
production, followed by the Interior region. EPA estimated a negligible change in labor input associated
with coal production in the West region and a negligible change in national labor input associated with
natural gas extraction.
Table 6-13: Labor Demand from Fuel Use Changes (# Employees)
NAICS
NAICS Sector
Coal Region
Fuel Type
Sector
Description
Appalachia
Interior
West
Waste Coal
Total
Coal
2121
Coal Mining
-750
-74
0
31
-793
Natural gas
21113
Natural Gas
Extraction
0
0
0
0
<0.01
Source: U.S. EPA Analysis, 2024.
6.3.4 Total Impacts of the Final Rule by Industry
Table 6-14 presents the total estimated impacts by NAICS sector. The number of FTEs is expected to
increase or remain the same in every relevant sector identified in the analysis except for the coal mining
and electric power generation sectors (NAICS codes 2121 and 22111, respectively). The Agency
estimated that the coal mining sector will experience a decrease in FTEs due to a decline in fuel
consumption for electricity generation. The Agency also estimated that the decrease in FTEs in the
electric power generation sector is driven by retirements of coal steam generation. Overall, EPA estimated
the final rule to increase labor inputs by 3,218 to 4,813 FTEs using the 2017 and adjusted 2030 labor
productivity rates, respectively. The sector with the greatest estimated increase in labor inputs under both
labor productivity rates is the storage batter manufacturing sector (NAICS code 335910). Using both
labor productivity rates, the sector with the second greatest increase in labor inputs is the machinery
manufacturing sector (NAICS code 333) followed by the hazardous waste treatment and disposal sector
(NAICS code 562211).
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The analysis estimates changes in labor inputs at power generating plants, coal mining, natural gas
extraction, and in the sectors involved most directly in generation capacity additions or wastewater
treatment technologies. Even though this final rule may affect many sectors, the overall impacts on labor,
both positive and negative, are quite small. Furthermore, this impact assessment does not reach a
quantitative estimate of the overall effects of the final rule on employment or even whether the net effect
will be positive or negative. However, given that the modeled increase in electricity production costs is
small (0.5 percent, based on IPM projections of Option B for 2030), the magnitude of all effects
combined can also be expected to be small.
Table 6-14: Total Effects on Labor Inputs by NAICS Sector in 2030 (# FTEs)
NAICS
Labor Productivity Rates
Sector3
NAICS Sector Description
2017
Adjusted 2030
333
Machinery Manufacturing
123
181
2121
Coal Mining3
-793
-793
3251
Basic Chemical Manufacturing
26
57
21113
Natural Gas Extraction3
0
0
22111
Electric Power Generation
-66
-154
33111
Iron and Steel Mills and Ferroalloy Manufacturing
24
34
236210
Industrial Building Construction
45
49
237130
Power and Communication Line and Related Structures
Construction
0
0
238910
Site Preparation Contractors
0
0
335911
Storage Battery Manufacturing
3,587
5,185
484121
General Freight Trucking, Long-Distance, Truckload
0
0
484230
Specialized Freight (except Used Goods) Trucking, Long-
Distance
40
39
541330
Engineering Services
25
27
562211
Hazardous Waste Treatment and Disposal
110
114
562212
Solid Waste Landfill
0
0
Commercial and Industrial Machinery and Equipment
811310
(except Automotive and Electronic) Repair and
Maintenance
97
73
Total
-
3,218
4,813
a. EPA identified NAICS Sector 2121 (coal mining) and 21113 (natural gas extraction) as the relevant sectors that would
incur impacts from changes in fuel consumption for electricity generation.
Source: U.S. EPA Analysis, 2024.
6.4 Estimated Impacts from Installation of Wastewater Treatment Technologies
Installation of wastewater treatment technologies used as basis for ELGs in the final rule is projected to
occur before the analysis year of 2030. In this section, EPA reports the estimated impacts on labor inputs
associated with the installation of each treatment technology during the compliance years of 2025 to
2029.
EPA calculated the resource requirements, in dollars, for different cost components of installation of new
treatment technology (e.g., materials, construction labor, engineering services). Table 6-15 presents the
average percentage of total capital costs associated with each cost component, applicable to all
wastestreams (Eastern Research Group, 2022).
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6: Impacts on Employment
Table 6-15: Capital and Labor Components for New Treatment Technology
Average % of Total
Cost Component
NAICS Sector
NAICS Sector Description
Capital Costs
Installation Materials3
332
Fabricated Metal Product
Manufacturing
43%
Equipment
333
Machinery manufacturing
25%
Indirect Capital Labor
23829
Other Building Equipment
10%
(Construction/Installation)
Contractors
Indirect Capital Labor (Site
238910
Site Preparation Contractors
10%
Preparation)
Indirect capital labor
541330
Engineering Services
(Engineering Services)
10%
Disposal Capital Cost
562212
Solid Waste Landfill
2%
a. Installation materials refers to the labor required for the manufacturing of materials required for installation of new
treatment technology.
Source: Eastern Research Group, 2022; U.S. EPA Analysis, 2024.
Table 6-16 presents the estimated impacts associated with installation of wastewater treatment
technologies in the final rule. These impacts include the employment impacts related to the initial one-
time cost incurred by plants to comply with recordkeeping and monitoring under the final rule. Overall,
EPA estimated that labor inputs would increase due to installation of new treatment technologies by
10,484 FTEs using the 2017 labor productivity rates and by 11,366 FTEs using the adjusted 2030 labor
productivity rates. Under both labor productivity rates, the number of FTEs is estimated to increase the
most, by 4,828 to 5,506 FTEs, in the fabricated metal product manufacturing sector (NAICS code 332).
The sector with the second greatest increase in labor input is machinery manufacturing (NAICS code
333), followed by the engineering services sector (NAICS code 541330).
Table 6-16: Total FTE Changes from Installation of New Technology
Labor
Productivity
NAICS
Sector
NAICS Sector Description
Wastestream
FGD
BA
CRL
Total
2017
332
Fabricated Metal Product
Manufacturing
1,991
250
2,586
4,828
333
Machinery manufacturing
819
103
1,064
1,987
23829
Other Building Equipment
Contractors
461
58
599
1,118
2211123
Fossil Fuel Electric Power
Generation
1
0
2
3
238910
Site Preparation Contractors
459
58
596
1,113
484121
General Freight Trucking, Long-
Distance, Truckload
0
0
0
0
541330
Engineering Services
529
67
687
1,283
562212
Solid Waste Landfill
63
8
82
153
Total
-
4,324
543
5,617
10,484
Adjusted
2030
332
Fabricated Metal Product
Manufacturing
2,271
285
2,949
5,506
333
Machinery manufacturing
1,203
151
1,562
2,917
23829
Other Building Equipment
Contractors
285
36
370
691
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Table 6-16: Total FTE Changes from Installation of New Technology
Labor
Productivity
NAICS
Sector
NAICS Sector Description
Wastestream
FGD
BA
CRL
Total
221112s
Fossil Fuel Electric Power
Generation
1
0
2
4
238910
Site Preparation Contractors
293
37
381
711
484121
General Freight Trucking, Long-
Distance, Truckload
0
0
0
0
541330
Engineering Services
582
73
755
1,410
562212
Solid Waste Landfill
52
7
68
127
Total
-
4,688
589
6,089
11,366
a. EPA estimated impacts related to initial one-time recordkeeping and monitoring costs using the labor productivity rate for
the fossil fuel electric power generation sector.
Source: U.S. EPA Analysis, 2024.
6.5 Uncertainties and Limitations
Despite EPA's use of the best available information and data, EPA's analysis of the potential impacts of
the final rule on labor input involves several sources of uncertainty:
• EPA used a bottom-up engineering analysis to estimate direct FTE impacts. This analysis does
not account for other indirect and induced effects of the rule on the broader economy due to, for
example, changes in forecasted electricity prices. However, EPA expects these effects to be small
given the relatively small changes in electricity production costs modeled in IPM (see Chapter 5)
and small potential electricity price effects (see Chapter 7).
• EPA estimated FTE impacts based on projected changes in electricity generation for a single year
(2030) to correspond to the detailed outputs of the market analysis in Chapter 5, but the final rule
also has incremental effects in other years.
• Labor productivity in the analysis year 2030 is unknown. To the extent that labor productivity in
2030 diverges from recent trends, this analysis may over- or underestimate employment impacts.
• EPA mapped cost components to the most relevant NAICS sectors, but FTEs in other NAICS
sectors may be affected. In addition, if those NAICS sectors have different labor productivity
rates, this analysis may over- or underestimate FTE impacts.
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RIA for Supplemental Steam Electric Power Generating ELGs
7: Electricity Price Effects
7 Assessment of Potential Electricity Price Effects
7.1 Analysis Overview
EPA assessed the potential impacts of regulatory options A through C on electricity prices. Following the
methodology EPA used to analyze the 2015 and 2020 rules, and 2023 proposal (U.S. EPA, 2015, 2020,
2023d), the Agency conducted this analysis in two parts:
• An assessment of the potential annual increase in electricity costs per MWh of total electricity
sales (Section 7.2)
• An assessment of the potential annual increase in household electricity costs (Section 7.3).
As is the case with the plant-level and parent entity-level cost-to-revenue screening analyses discussed in
Chapter 4 (Economic Impact Screening Analyses), this analysis of electricity price effects uses a
historical snapshot of electricity generation against which to assess the relative impacts of the regulatory
options. However, unlike the plant- and entity-level screening analyses which assume that steam electric
power plants and their parent entities would absorb 100 percent of the compliance burden (zero cost pass-
through), this electricity price impact assessment assumes the opposite: 100 percent pass-through of
compliance costs through electricity prices (i.e., full cost pass-through).
Although this convenient analytical simplification does not reflect actual market conditions,76 EPA judges
this assumption appropriate for two reasons: (1) the majority of steam electric power plants operate under
a cost-of-service framework and may be able to recover increases in their production costs through
increased electricity prices and (2) for plants operating in states where electric power generation has been
deregulated, it would not be possible to estimate this consumer price effect at the state level. Thus, this
100 percent cost pass-through assumption represents a "worst-case" impact scenario from the perspective
of the electricity consumers. To the extent that all compliance-related costs are not passed forward to
consumers but are absorbed, at least in part, by electric power generators, this analysis overstates
consumer impacts.
It is also important to note that, if the full cost pass-through condition assumed in this analysis were to
occur, then the screening analyses assessed in Chapter 4 would overstate the impacts to plants and owners
of these plants because the two conditions (full cost pass-through and no cost pass-through) could not
simultaneously occur for the same steam electric power plant.
76 Plants located in states where electricity prices remain regulated under the traditional cost-of-service rate regulation
framework may be able to recover compliance cost-based increases in their production costs through increased
electricity rates, depending on the business operation model of the plant owner(s), the ownership and operating
structure of the plant itself, and the role of market mechanisms used to sell electricity. In contrast, in states in which
electric power generation has been deregulated, cost recovery is not guaranteed. While plants operating within
deregulated electricity markets may be able to recover some of their additional production costs in increased revenue, it
is not possible to determine the extent of cost recovery ability for each plant. Moreover, even though individual plants
may not be able to recover all of their compliance costs through increased revenues, the market-level effect may still be
that consumers would see higher overall electricity prices because of changes in the cost structure of electricity supply
and resulting changes in market-clearing prices in deregulated generation markets.
7-1
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RIA for Supplemental Steam Electric Power Generating ELGs
7: Electricity Price Effects
7.2 Assessment of Impact of Compliance Costs on Electricity Prices
EPA assessed the potential increase in electricity prices to the four electricity consumer groups:
residential, commercial, industrial, and transportation.
7.2.1 Analysis Approach and Data Inputs
For this analysis, EPA assumed that compliance costs would be fully passed through as increased
electricity prices and allocated these costs among consumer groups (residential, commercial, industrial,
and transportation) in proportion to the historical quantity of electricity consumed by each group. EPA
performed this analysis at the level of the NERC region. Using the NERC region as the basis for this
analysis is appropriate given the structure and functioning of sub-national electricity markets, around
which NERC regions are defined. The analysis, which uses the exact same approach as used for the 2015
and 2020 rules and 2023 proposal analyses, involves the following steps (for additional details, see
Chapter 7 in U.S. EPA, 2015):
• EPA summed weighted pre-tax plant-level annualized compliance costs by NERC region.77,78
• EPA estimated the approximate average price impact per unit of electricity consumption by
dividing total annualized compliance costs by the projected total MWh of sales in 2024 by NERC
region, from AEO2023 (EIA, 2023b).
• EPA compared the estimated average price effect to the projected electricity price by consumer
group and NERC region for 2024 from AEO2023 (EIA, 2023b).
7.2.2 Key Findings for Regulatory Options
As reported in Table 7-1, the compliance costs per unit of sales are very small for all analyzed regulatory
options; the maximum cost per kWh is a fraction of a cent. Under all three regulatory options, the regions
with the greatest cost per kWh are RF and SERC under both the lower and upper bound scenarios.
Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024
(2023$) - Lower Bound
NERCa
Total Electricity Sales
National Pre-Tax Compliance
Costs per Unit of Sales
(at 2024; MWh)
Costs (at 2024; 2023$)
(2023C/kWh Sales)
Option A
MRO
456,121,788
$54,026,214
0.012C
NPCC
253,369,049
$5,992,572
0.002C
RF
732,859,497
$146,301,472
0.020C
SERC
1,324,847,581
$228,184,395
0.017C
TRE
389,170,380
$7,931,750
0.002C
77 These compliance costs are in 2023 dollars as of a given technology implementation year (2025 through 2029) and
discounted to 2024 at 3.76 percent. This analysis accounts for the different years in which plants are estimated to
implement the compliance technologies in order to reflect the effect of differences in timing of these electricity price
impacts in terms of cost to household ratepayers and society. Costs and ratepayer effects occurring farther in the future
(e.g., in the last year of the technology implementation period) have a lower present value of impact than those that
occur sooner following rule promulgation. Estimating the cost and ratepayer effect as of the assumed technology
implementation year (2025 through 2029) and then discounting these effects to a single analysis year (2024) accounts
for this consideration.
78 For this analysis, EPA brought compliance costs forward to a given compliance year using the CCI and ECI.
7-2
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RIA for Supplemental Steam Electric Power Generating ELGs
7: Electricity Price Effects
Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024
(2023$) - Lower Bound
NERCa
Total Electricity Sales
National Pre-Tax Compliance
Costs per Unit of Sales
(at 2024; MWh)
Costs (at 2024; 2023$)
(2023C/kWh Sales)
WECC
691,321,258
$36,218,573
0.005C
US
3,868,347,589
$479,230,884
0.0124
Option B
MRO
456,121,788
$69,824,715
0.015C
NPCC
253,369,049
$6,122,629
0.002C
RF
732,859,497
$208,025,785
0.028C
SERC
1,324,847,581
$256,608,152
0.019C
TRE
389,170,380
$9,215,116
0.002C
WECC
691,321,258
$44,513,228
0.006C
US
3,868,347,589
$594,885,534
0.0154
Option C
MRO
456,121,788
$76,979,491
0.017C
NPCC
253,369,049
$6,122,629
0.002C
RF
732,859,497
$235,300,734
0.032C
SERC
1,324,847,581
$305,278,400
0.023C
TRE
389,170,380
$14,139,636
0.004C
WECC
691,321,258
$55,553,917
0.008C
US
3,868,347,589
$693,950,715
0.0184
a. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
Because of this, the sum of electricity sales for all regions do not sum to the total for the United States.
Source: U.S. EPA Analysis, 2024.
Table 7-2: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024
(2023$) - Upper Bound
NERCa
Total Electricity Sales
National Pre-Tax Compliance
Costs per Unit of Sales
(at 2024; MWh)
Costs (at 2024; 2023$)
(20234/kWh Sales)
Option A
MRO
456,121,788
$118,176,904
0.026C
NPCC
253,369,049
$6,405,553
0.003C
RF
732,859,497
$245,175,269
0.033C
SERC
1,324,847,581
$518,050,509
0.039C
TRE
389,170,380
$16,758,365
0.004C
WECC
691,321,258
$140,691,334
0.020C
US
3,868,347,589
$1,047,696,932
0.0274
Option B
MRO
456,121,788
$133,975,405
0.029C
NPCC
253,369,049
$6,535,610
0.003C
RF
732,859,497
$306,899,583
0.042C
SERC
1,324,847,581
$546,474,267
0.041C
TRE
389,170,380
$18,041,731
0.005C
WECC
691,321,258
$148,985,988
0.022C
US
3,868,347,589
$1,163,351,581
0.0304
Option C
MRO
456,121,788
$141,130,180
0.031C
NPCC
253,369,049
$6,535,610
0.003C
RF
732,859,497
$334,174,531
0.046C
7-3
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RIA for Supplemental Steam Electric Power Generating ELGs
7: Electricity Price Effects
Table 7-2: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024
(2023$) - Upper Bound
NERCa
Total Electricity Sales
National Pre-Tax Compliance
Costs per Unit of Sales
(at 2024; MWh)
Costs (at 2024; 2023$)
(2023C/kWh Sales)
SERC
1,324,847,581
$595,144,514
0.045C
TRE
389,170,380
$22,966,251
0.006C
WECC
691,321,258
$160,026,678
0.023C
US
3,868,347,589
$1,262,416,762
0.033C
a. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
Because of this, the sum of electricity sales for all regions do not sum to the total for the United States.
Source: U.S. EPA Analysis, 2024.
To determine the relative significance of compliance costs on electricity prices across consumer groups,
EPA compared the per kWh compliance cost to retail electricity prices projected by EIA (EIA, 2023b) by
consuming group and for the average of the groups. This analysis is presented in Table 7-3 and Table 7-4
for the lower and upper bound scenarios, respectively.
Looking across the four consumer groups and assuming that any price change would apply equally to all
consumer groups, under all scenarios industrial consumers are estimated to experience the highest price
changes relative to the electricity price basis, while residential consumers are estimated to experience the
lowest price changes, shown in Table 7-3. The comparably higher relative price changes to industrial
consumers are due to their lower electricity rates and EPA's assumption of uniform changes across all
consumer groups; they do not reflect differential distribution of the incremental costs across consumer
groups.
Table 7-3: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to
Compliance Costs by NERC Region and Regulatory Option (2023$) - Lower Bound
Residential
Commercial
Industrial
Transportation
All Sectors
Average
EIA
EIA
EIA
EIA
Compliance
Price
Price
EIA Price
Price
Price
Costs
Basis
%
Basis
%
Basis
%
Basis
%
Basis
(2023C
(2023C
Change
(2023C
Change
(2023C
Change
(2023C
Change
(2023C
% Change
NERCb
/kWh)
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
Option A
MRO
0.012C
11.58C
0.10%
9.48C
0.12%
6.59C
0.18%
11.00C
0.11%
9.15C
0.13%
NPCC
0.002 C
20.94C
0.01%
17.15C
0.01%
12.12C
0.02%
13.96C
0.02%
17.95C
0.01%
RF
0.020C
14.33C
0.14%
12.07C
0.17%
8.90C
0.22%
10.13C
0.20%
12.05C
0.17%
SERC
0.017C
12.42C
0.14%
10.22C
0.17%
6.65C
0.26%
11.45C
0.15%
10.30C
0.17%
TRE
0.002 C
12.08C
0.02%
10.47C
0.02%
7.59C
0.03%
9.13C
0.02%
10.22C
0.02%
WECC
0.005 C
16.15C
0.03%
14.34C
0.04%
9.81C
0.05%
18.17C
0.03%
13.91C
0.04%
US
0.012C
13.90C
0.09%
11.94C
0.10%
7.95C
0.16%
13.844
0.09%
11.67C
0.11%
Option B
MRO
0.015C
11.58C
0.13%
9.48C
0.16%
6.59C
0.23%
11.00C
0.14%
9.15C
0.17%
NPCC
0.002 C
20.94C
0.01%
17.15C
0.01%
12.12C
0.02%
13.96C
0.02%
17.95C
0.01%
RF
0.028C
14.33C
0.20%
12.07C
0.24%
8.90C
0.32%
10.13C
0.28%
12.05C
0.24%
SERC
0.019C
12.42C
0.16%
10.22C
0.19%
6.65C
0.29%
11.45C
0.17%
10.30C
0.19%
TRE
0.002 C
12.08C
0.02%
10.47C
0.02%
7.59C
0.03%
9.13C
0.03%
10.22C
0.02%
7-4
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RIA for Supplemental Steam Electric Power Generating ELGs
7: Electricity Price Effects
Table 7-3: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to
Compliance Costs by NERC Region and Regulatory Option (2023$) - Lower Bound
All Sectors
Residential
Commercial
Industrial
Transportation
Average
EIA
EIA
EIA
EIA
Compliance
Price
Price
EIA Price
Price
Price
Costs
Basis
%
Basis
%
Basis
%
Basis
%
Basis
(20234
(20234
Change
(20234
Change
(20234
Change
(20234
Change
(20234
% Change
NERCb
/kWh)
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
WECC
0.006 C
16.15C
0.04%
14.34C
0.04%
9.81C
0.07%
18.17C
0.04%
13.91C
0.05%
US
0.0154
13.904
0.11%
11.944
0.13%
7.954
0.19%
13.844
0.11%
11.674
0.13%
Option C
MRO
0.017C
11.58C
0.15%
9.48C
0.18%
6.59C
0.26%
11.00C
0.15%
9.15C
0.18%
NPCC
0.002 C
20.94C
0.01%
17.15C
0.01%
12.12C
0.02%
13.96C
0.02%
17.95C
0.01%
RF
0.032C
14.33C
0.22%
12.07C
0.27%
8.90C
0.36%
10.13C
0.32%
12.05C
0.27%
SERC
0.023C
12.42C
0.19%
10.22C
0.23%
6.65C
0.35%
11.45C
0.20%
10.30C
0.22%
TRE
0.004C
12.08C
0.03%
10.47C
0.03%
7.59C
0.05%
9.13C
0.04%
10.22C
0.04%
WECC
0.008C
16.15C
0.05%
14.34C
0.06%
9.81C
0.08%
18.17C
0.04%
13.91C
0.06%
US
0.0184
13.904
0.13%
11.944
0.15%
7.954
0.23%
13.844
0.13%
11.674
0.15%
a. The rate impact analysis assumes full pass-through of all compliance costs to electricity consumers.
b. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
Sources: U.S. EPA Analysis, 2024; EIA, 2022c, 2023b.
Table 7-4: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to
Compliance Costs by NERC Region and Regulatory Option (2023$) - Upper Bound
All Sectors
Residential
Commercial
Industrial
Transportation
Average
EIA
EIA
EIA
EIA
Compliance
Price
Price
EIA Price
Price
Price
Costs
Basis
%
Basis
%
Basis
%
Basis
%
Basis
(20234
(20234
Change
(20234
Change
(20234
Change
(20234
Change
(20234
% Change
NERCb
/kWh)
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
Option A
MRO
0.026C
11.58C
0.22%
9.48C
0.27%
6.59C
0.39%
11.00C
0.24%
9.15C
0.28%
NPCC
0.003 C
20.94C
0.01%
17.15C
0.01%
12.12C
0.02%
13.96C
0.02%
17.95C
0.01%
RF
0.033C
14.33C
0.23%
12.07C
0.28%
8.90C
0.38%
10.13C
0.33%
12.05C
0.28%
SERC
0.039C
12.42C
0.31%
10.22C
0.38%
6.65C
0.59%
11.45C
0.34%
10.30C
0.38%
TRE
0.004C
12.08C
0.04%
10.47C
0.04%
7.59C
0.06%
9.13C
0.05%
10.22C
0.04%
WECC
0.020C
16.15C
0.13%
14.34C
0.14%
9.81C
0.21%
18.17C
0.11%
13.91C
0.15%
US
0.0274
13.904
0.19%
11.944
0.23%
7.954
0.34%
13.844
0.20%
11.674
0.23%
Option B
MRO
0.029C
11.58C
0.25%
9.48C
0.31%
6.59C
0.45%
11.00C
0.27%
9.15C
0.32%
NPCC
0.003 C
20.94C
0.01%
17.15C
0.02%
12.12C
0.02%
13.96C
0.02%
17.95C
0.01%
RF
0.042 C
14.33C
0.29%
12.07C
0.35%
8.90C
0.47%
10.13C
0.41%
12.05C
0.35%
SERC
0.041C
12.42C
0.33%
10.22C
0.40%
6.65C
0.62%
11.45C
0.36%
10.30C
0.40%
TRE
0.005 C
12.08C
0.04%
10.47C
0.04%
7.59C
0.06%
9.13C
0.05%
10.22C
0.05%
WECC
0.022C
16.15C
0.13%
14.34C
0.15%
9.81C
0.22%
18.17C
0.12%
13.91C
0.15%
US
0.0304
13.904
0.22%
11.944
0.25%
7.954
0.38%
13.844
0.22%
11.674
0.26%
7-5
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RIA for Supplemental Steam Electric Power Generating ELGs
7: Electricity Price Effects
Table 7-4: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to
Compliance Costs by NERC Region and Regulatory Option (2023$) - Upper Bound
All Sectors
Residential
Commercial
Industrial
Transportation
Average
EIA
EIA
EIA
EIA
Compliance
Price
Price
EIA Price
Price
Price
Costs
Basis
%
Basis
%
Basis
%
Basis
%
Basis
(20234
(2023C
Change
(2023C
Change
(2023C
Change
(2023C
Change
(2023C
% Change
NERCb
/kWh)
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
Option C
MRO
0.031C
11.58C
0.27%
9.48C
0.33%
6.59C
0.47%
11.00C
0.28%
9.15C
0.34%
NPCC
0.003 C
20.94C
0.01%
17.15C
0.02%
12.12C
0.02%
13.96C
0.02%
17.95C
0.01%
RF
0.046 C
14.33C
0.32%
12.07C
0.38%
8.90C
0.51%
10.13C
0.45%
12.05C
0.38%
SERC
0.045 C
12.42C
0.36%
10.22C
0.44%
6.65C
0.68%
11.45C
0.39%
10.30C
0.44%
TRE
0.006 C
12.08C
0.05%
10.47C
0.06%
7.59C
0.08%
9.13C
0.06%
10.22C
0.06%
WECC
0.023C
16.15C
0.14%
14.34C
0.16%
9.81C
0.24%
18.17C
0.13%
13.91C
0.17%
US
0.033C
13.90C
0.23%
11.94C
0.27%
7.95C
0.41%
13.844
0.24%
11.67C
0.28%
a. The rate impact analysis assumes full pass-through of all compliance costs to electricity consumers.
b. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
Sources: U.S. EPA Analysis, 2024; EIA, 2022c, 2023b.
7.2.3 Uncertainties and Limitations
As noted above, the assumption of 100 percent pass-through of compliance costs to electricity prices
represents a worst-case scenario from the perspective of consumers. To the extent that some steam
electric power plants do not pass their compliance costs to consumers through higher electricity rates, this
analysis may overstate the potential impact of the regulatory options on electricity consumers.
In addition, this analysis assumes that costs would be passed on in the form of a flat-rate price increase
per unit of electricity, to be applied equally to all consumer groups. This assumption is appropriate to
assess the general magnitude of potential price increases. The allocation of costs to different consumer
groups could be higher or lower than estimated by this approach.
7.3 Assessment of Impact of Compliance Costs on Household Electricity Costs
EPA also assessed the potential increases in the cost of electricity to residential households.
7.3.1 Analysis Approach and Data Inputs
For this analysis, EPA again assumed that compliance costs would be fully passed through as increased
electricity prices and allocated these costs to residential households in proportion to the baseline
electricity consumption. EPA analyzed the potential impact on annual electricity costs at the level of the
'average" household, using the estimated household electricity consumption quantity by NERC region.
Following the approach used in analyzing the 2015 and 2020 rules and 2023 proposal (U.S. EPA, 2015,
2020, 2023d), the steps in this calculation are as follows:
7-6
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RIA for Supplemental Steam Electric Power Generating ELGs
7: Electricity Price Effects
• As done for the electricity price analysis discussed in Section 7.2, to estimate total annual cost in
each NERC region, EPA summed weighted pre-tax, plant-level annualized compliance costs by
NERC region.79
• As was done for the analysis of impact of compliance costs on electricity prices, EPA divided
total compliance costs by the total MWh of sales reported for each NERC region. EPA used
electricity sales (in MWh) for 2024 from AEO2023 (EIA, 2023b).8"
• To calculate average annual electricity sales per household, EPA divided the total quantity of
residential sales (in MWh) for 2021 in each NERC region by the number of households in that
region; the Agency obtained both the quantity of residential sales and the number of households
from the 2021 EIA-861 database (EIA, 2022a). For this analysis, EPA assumed that the average
quantity of electricity sales per household by NERC region would remain the same in 2024 as in
2021.
• To assess the potential annual cost impact per household, EPA multiplied the estimated average
price impact by the average quantity of electricity sales per household in 2021 by NERC region.
7.3.2 Key Findings for Regulatory Options A through C
Table 7-5 and Table 7-6 report the upper and lower bound scenario results of this analysis by NERC
region for each regulatory option, and overall for the United States.81
Table 7-5: Average Incremental Annual Cost per Household in 2024 by NERC Region and
Regulatory Option (2023$) - Lower Bound
Total
Residential
Total
Compliance
Sales per
Total Pre-Tax
Compliance
Costs per
Total
Residential
Residential
Compliance
Costs per Unit
Residential
Electricity
Electricity
Number of
Household
Costs (at 2024;
of Sales
Household
NERCb
Sales (MWh)
Sales (MWh)
Households
(MWh/year)
2023$/year)
(2023$/MWh)
(2023$/year)
Option A
MRO
456,121,788
119,927,337
10,807,443
11.10
54,026,214
$0.12
$1.31
NPCC
253,369,049
111,525,266
14,886,378
7.49
5,992,572
$0.02
$0.18
RF
732,859,497
320,906,246
32,782,678
9.79
146,301,472
$0.20
$1.95
SERC
1,324,847,581
501,406,381
38,022,008
13.19
228,184,395
$0.17
$2.27
TRE
389,170,380
79,238,157
6,202,682
12.77
7,931,750
$0.02
$0.26
WECC
691,321,258
252,010,889
29,828,524
8.45
36,218,573
$0.05
$0.44
usb
3,861,716,503
1,389,584,033
133,240,696
10.43
479,230,884
$0.12
$1.29
Option B
MRO
456,121,788
119,927,337
10,807,443
11.10
69,824,715
$0.15
$1.70
NPCC
253,369,049
111,525,266
14,886,378
7.49
6,122,629
$0.02
$0.18
79 Compliance costs in the ASCC and HICC regions are zero and EPA therefore did not include these regions in its
analysis.
80 AEO does not provide information for HICC and ASSC. None of the plants estimated to incur compliance costs as a
result of the final ELG, however, are located in these two NERC regions.
81 Average annual cost per residential household is zero in ASCC and HICC for the baseline and the three options and
these regions are therefore omitted from the details. They are included in the U.S. totals.
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7: Electricity Price Effects
Table 7-5: Average Incremental Annual Cost per Household in 2024 by NERC Region and
Regulatory Option (2023$) - Lower Bound
Total
Residential
Total
Compliance
Sales per
Total Pre-Tax
Compliance
Costs per
Total
Residential
Residential
Compliance
Costs per Unit
Residential
Electricity
Electricity
Number of
Household
Costs (at 2024;
of Sales
Household
NERCb
Sales (MWh)
Sales (MWh)
Households
(MWh/year)
2023$/year)
(2023$/MWh)
(2023$/year)
RF
732,859,497
320,906,246
32,782,678
9.79
208,025,785
$0.28
$2.78
SERC
1,324,847,581
501,406,381
38,022,008
13.19
256,608,152
$0.19
$2.55
TRE
389,170,380
79,238,157
6,202,682
12.77
9,215,116
$0.02
$0.30
WECC
691,321,258
252,010,889
29,828,524
8.45
44,513,228
$0.06
$0.54
usb
3,861,716,503
1,389,584,033
133,240,696
10.43
594,885,534
$0.15
$1.61
Option C
MRO
456,121,788
119,927,337
10,807,443
11.10
76,979,491
$0.17
$1.87
NPCC
253,369,049
111,525,266
14,886,378
7.49
6,122,629
$0.02
$0.18
RF
732,859,497
320,906,246
32,782,678
9.79
235,300,734
$0.32
$3.14
SERC
1,324,847,581
501,406,381
38,022,008
13.19
305,278,400
$0.23
$3.04
TRE
389,170,380
79,238,157
6,202,682
12.77
14,139,636
$0.04
$0.46
WECC
691,321,258
252,010,889
29,828,524
8.45
55,553,917
$0.08
$0.68
USb
3,861,716,503
1,389,584,033
133,240,696
10.43
693,950,715
$0.18
$1.87
a. This analysis assumes full pass-through of all compliance costs to electricity consumers.
b. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
For this reason, electricity sales shown for the United States is greater than the total for NERC regions included in the table.
Sources: U.S. EPA Analysis, 2024; EIA, 2022c, 2023b.
Table 7-6: Average Incremental Annual Cost per Household in 2024 by NERC Region and
Regulatory Option (2023$) - Upper Bound
Total
Residential
Total
Compliance
Sales per
Total Pre-Tax
Compliance
Costs per
Total
Residential
Residential
Compliance
Costs per Unit
Residential
Electricity
Electricity
Number of
Household
Costs (at 2024;
of Sales
Household
NERCb
Sales (MWh)
Sales (MWh)
Households
(MWh/year)
2023$/year)
(2023$/MWh)
(2023$/year)
Option A
MRO
456,121,788
119,927,337
10,807,443
11.10
118,176,904
$0.26
$2.88
NPCC
253,369,049
111,525,266
14,886,378
7.49
6,405,553
$0.03
$0.19
RF
732,859,497
320,906,246
32,782,678
9.79
245,175,269
$0.33
$3.27
SERC
1,324,847,581
501,406,381
38,022,008
13.19
518,050,509
$0.39
$5.16
TRE
389,170,380
79,238,157
6,202,682
12.77
16,758,365
$0.04
$0.55
WECC
691,321,258
252,010,889
29,828,524
8.45
140,691,334
$0.20
$1.72
USb
3,861,716,503
1,389,584,033
133,240,696
10.43
1,047,696,932
$0.27
$2.83
Option B
MRO
456,121,788
119,927,337
10,807,443
11.10
133,975,405
$0.29
$3.26
NPCC
253,369,049
111,525,266
14,886,378
7.49
6,535,610
$0.03
$0.19
RF
732,859,497
320,906,246
32,782,678
9.79
306,899,583
$0.42
$4.10
SERC
1,324,847,581
501,406,381
38,022,008
13.19
546,474,267
$0.41
$5.44
TRE
389,170,380
79,238,157
6,202,682
12.77
18,041,731
$0.05
$0.59
WECC
691,321,258
252,010,889
29,828,524
8.45
148,985,988
$0.22
$1.82
USb
3,861,716,503
1,389,584,033
133,240,696
10.43
1,163,351,581
$0.30
$3.14
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7: Electricity Price Effects
Table 7-6: Average Incremental Annual Cost per Household in 2024 by NERC Region and
Regulatory Option (2023$) - Upper Bound
Total
Residential
Total
Compliance
Sales per
Total Pre-Tax
Compliance
Costs per
Total
Residential
Residential
Compliance
Costs per Unit
Residential
Electricity
Electricity
Number of
Household
Costs (at 2024;
of Sales
Household
NERCb
Sales (MWh)
Sales (MWh)
Households
(MWh/year)
2023$/year)
(2023$/MWh)
(2023$/year)
Option C
MRO
456,121,788
119,927,337
10,807,443
11.10
141,130,180
$0.31
$3.43
NPCC
253,369,049
111,525,266
14,886,378
7.49
6,535,610
$0.03
$0.19
RF
732,859,497
320,906,246
32,782,678
9.79
334,174,531
$0.46
$4.46
SERC
1,324,847,581
501,406,381
38,022,008
13.19
595,144,514
$0.45
$5.92
TRE
389,170,380
79,238,157
6,202,682
12.77
22,966,251
$0.06
$0.75
WECC
691,321,258
252,010,889
29,828,524
8.45
160,026,678
$0.23
$1.96
usb
3,861,716,503
1,389,584,033
133,240,696
10.43
1,262,416,762
$0.33
$3.41
a. This analysis assumes full pass-through of all compliance costs to electricity consumers.
b. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
For this reason, electricity sales shown for the United States is greater than the total for NERC regions included in the table.
Sources: U.S. EPA Analysis, 2024; EIA, 2022c, 2023b.
To address concerns that cost increase may affect households served by certain types of operators more
than others, the Agency also estimated the potential increases in electricity costs for households by plant
ownership type for the final rule. In this analysis, the Agency estimated the potential increase in
electricity costs for the average household under each plant ownership type based on the average
household electricity sales (10.43 MWh/year) in Table 7-5 and Table 7-6 and the compliance costs per
MWh under each plant ownership type.82 The analysis shows that the compliance costs per average
residential consumer are relatively similar under each plant ownership type with an average of $3.57 and
$6.48 in the lower and upper bound scenarios, respectively.83 The compliance costs of the final rule per
average residential consumer were greatest for cooperatives (between $6.73 and $19.26) and lowest for
federal entities (between $0.62 and $1.63).
7.3.3 Uncertainties and Limitations
As noted above, the assumption of 100 percent pass-through of compliance costs to electricity prices
represents a worst-case scenario from the perspective of households. To the extent that some steam
electric power plants do not pass their compliance costs to consumers through higher electricity rates, this
analysis may overstate the potential impact of the regulatory options on households.
This analysis also assumes that costs would be passed on in the form of a flat-rate price increase per unit
of electricity, an assumption EPA concluded is reasonable to characterize the magnitude of compliance
82 The Agency estimated compliance costs per MWh for each plant ownership type by dividing the total compliance costs
incurred by plants under each ownership type by the sum of retail sales (MWh) and sales for resale (MWh) for the
utilities associated with plants under each ownership type from EIA-861 2021 data (U.S. Energy Information
Administration. (2022a). Annual Electric Power Industry Report, Form EL4-861 detailed data files: Final 2021 Data ).
83 The compliance costs per average residential consumer are different from what is reported in Table 7-5 because only a
subset of utilities incurred compliance costs under the final rule (Option B).
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7: Electricity Price Effects
costs relative to household electricity consumption. The allocation of costs to the residential class could
be higher or lower than estimated by this approach.
7.4 Distribution of Electricity Cost Impact on Household
In general, lower-income households spend less, in the absolute, on energy than do higher-income
households, but energy expenditures represent a larger share of their income. Therefore, electricity price
increases tend to have a relatively larger effect on lower-income households, compared to higher-income
households. In analyzing the impacts of the 2015 rule, EPA conducted a distributional analysis of the
2015 rule to assess (1) whether an increase in electricity rates that may occur under the 2015 rule would
disproportionately affect lower-income households and (2) whether households would be able to pay for
these electricity rate increases without experiencing economic hardship (i.e.. whether the increase is
affordable). The analysis provided additional insight on the distribution of impacts among residential
electricity consumers to help respond to concerns regarding the impacts of the rule on utilities and
cooperatives in service areas that include a relatively high proportion of low-income households.
In the 2015 analysis, EPA had concluded that even when looking at a worst-case scenario of 100 percent
pass through of the compliance costs, the "incremental economic burden of any final rule based on the
regulatory options in the proposal on households is small both relative to income and relative to the
baseline energy burden of households in different income ranges. While the incremental burden relative
to income is not distributionally neutral, i.e.. any increase would affect lower-income households to a
greater extent than higher-income households, the small impacts may be further moderated by existing
pricing structures (see Section 7.4 in U.S. EPA, 2015)." As presented in the preceding sections, EPA
estimates that regulatory options A through C would result in compliance costs for FGD wastewater, BA
transport water, and CRL treatment. To the extent that these costs are in turn passed through to electricity
consumers in the form of higher prices, the resulting higher electricity prices may have a larger negative
effect on lower-income households. However, given the small increase to household electricity costs
corresponding to the incremental compliance costs for the rule (between $1.61 and $3.14 per household
per year for Option B), EPA finds that the earlier conclusion of small impacts from the 2015 rule still
holds given the lower compliance costs of the three regulatory options relative to the 2015 rule.
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8: RFA
8 Assessment of Potential Impact of the Regulatory Options on Small
Entities - Regulatory Flexibility Act (RFA) Analysis
The Regulatory Flexibility Act (RFA) of 1980, as amended by the Small Business Regulatory
Enforcement Fairness Act (SBREFA) of 1996, requires federal agencies to consider the impact of their
rules on small entities, to analyze alternatives that minimize those impacts,84 and to make their analyses
available for public comments. The RFA is concerned with three types of small entities: small businesses,
small nonprofits, and small government jurisdictions.
The RFA describes the regulatory flexibility analyses and procedures that must be completed by federal
agencies unless they certify that the rule, if promulgated, would not have a significant economic impact
on a substantial number of small entities. This certification must be supported by a statement of factual
basis, e.g., addressing the number of small entities affected by the final rule, estimated cost impacts on
these entities, and evaluation of the economic impacts.
In accordance with RFA requirements and as it has consistently done in developing effluent limitations
guidelines and standards, EPA assessed whether the regulatory options would have "a significant impact
on a substantial number of small entities" (SISNOSE). Following the approach used in the analysis of the
2015 and 2020 rules and 2023 proposal (U.S. EPA, 2015, 2020, 2023d), this assessment involved the
following steps:
• Identifying the domestic parent entities of steam electric power plants.
• Determining which of those domestic parent entities are small entities, based on SBA size
criteria.
• Assessing the change in potential impact of the regulatory options on those small entities by
comparing the estimated entity-level annualized compliance cost to entity-level revenue; the cost-
to-revenue ratio indicates the magnitude of economic impacts. Following EPA guidance (U.S.
EPA, 2006), EPA used threshold compliance costs of one percent or three percent of entity-level
revenue to categorize the degree of significance of the economic impacts on small entities.
• Assessing the change in whether those small entities incurring potentially significant impacts
represent a substantial number of small entities. Following EPA guidance (U.S. EPA, 2006), EPA
determined whether the number of small entities impacted is substantial based on (1) the
estimated absolute numbers of small entities incurring potentially significant impacts according
to the two cost impact criteria, and (2) the percentage of small entities in the relevant entity
categories that are estimated to incur these impacts.
EPA performed this assessment for each of the regulatory options. This chapter describes the analytic
approach (Section 8.1), summarizes the findings of EPA's RFA assessment (Section 8.2), and reviews
84 Section 603(c) of the RFA provides examples of such alternatives as: (1) the establishment of differing compliance or
reporting requirements or timetables that take into account the resources available to small entities; (2) the clarification,
consolidation, or simplification of compliance and reporting requirements under the rule for such small entities; (3) the
use of performance rather than design standards; and (4) an exemption from coverage of the rule, or any part thereof,
for such small entities.
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8: RFA
uncertainties and limitations in the analysis (Section 8.3). The chapter also discusses how regulatory
options developed by EPA served to mitigate the impact of the regulatory options on small entities
(Section 8.4).
8.1 Analysis Approach and Data Inputs
EPA used the same methodology and assumptions used for the analysis of the 2015, 2020, and proposed
2023 rules (U.S. EPA, 2015, 2020, 2023d), but updated input data to reflect more recent information
about plant ownership, entity size, and compliance costs as described in the sections below.
8.1.1 Determining Parent Entity of Steam Electric Power Plants
Consistent with the entity-level cost-to-revenue analysis (see Chapter 4), EPA conducted the RFA
analysis at the highest level of domestic ownership, referred to as the "domestic parent entity" or
"domestic parent firm", including only entities with the largest share of ownership (majority owner)85 in
at least one of the estimated 858 steam electric power plants in the steam electric point source category.
As was done for the entity-level cost-to-revenue analysis in Section 4.3, EPA identified the majority
owner for each plant using 2022 databases published by EIA (EIA, 2022c), Dun and Bradstreet (Dun &
Bradstreet, 2021), Experian (Experian, 2023), corporate and financial websites, information provided in
the comments on the 2023 proposed rule, and the Steam Electric Survey (U.S. EPA, 2010).
8.1.2 Determining Whether Parent Entities of Steam Electric Power Plants Are Small
EPA identified the size of each parent entity using the SBA size threshold guidelines in effect as of March
17, 2023 (SBA, 2023). The criteria for entity size determination vary by the organization/operation
category of the parent entity, as follows:
• Privately owned (non-government) entities: Privately owned entities include investor-owned
utilities, nonutility entities, and entities with a primary business other than electric power
generation. For entities with electric power generation as a primary business, small entities are
those with less than the threshold number of employees specified by SBA for each of the relevant
North American Industry Classification System (NAICS) sectors (NAICS 2211) (see Table 8-1).
For entities with a primary business other than electric power generation, the relevant size criteria
are based on revenue or number of employees by NAICS sector.86
• Publicly owned entities: Publicly owned entities include federal, State, municipal, and other
political subdivision entities. The federal and State governments were considered to be large;
municipalities and other political units with population less than 50,000 were considered to be
small.
85 Throughout the analyses, EPA refers to the owner with the largest ownership share as the "majority owner" even when
the ownership share is less than 51 percent.
86 Certain steam electric power plants are owned by entities whose primary business is not electric power generation. EPA
determined the NAICS code of each privately owned entity based on Dun and Bradstreet (Dun & Bradstreet. (2021).
Hoovers Data Services Version [Data set]). ).
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8: RFA
• Rural Electric Cooperatives: Small entities are those with less than the threshold number of
employees specified by SBA for each of the relevant NAICS sectors, depending on the type of
electricity generation (see Table 8-1).
Table 8-1: NAICS Codes and SBA Size Standards for Non-government Majority Owners Entities of
Steam Electric Power Plants
NAICS Code3
NAICS Description
SBA Size Standard13
212114
Surface Coal Mining
1,250 Employees
221111
Hydroelectric Power Generation
750 Employees
221112
Fossil Fuel Electric Power Generation
950 Employees
221113
Nuclear Electric Power Generation
1,150 Employees
221114°
Solar Electric Power Generation
250 Employees
221115°
Wind Electric Power Generation
250 Employees
221116°
Geothermal Electric Power Generation
250 Employees
221117°
Biomass Electric Power Generation
250 Employees
221118°
Other Electric Power Generation
250 Employees
221121
Electric Bulk Power Transmission and Control
950 Employees
221122
Electric Power Distribution
1,100 Employees
221210
Natural Gas Distribution
1,150 Employees
221310
Water Supply and Irrigation Systems
$41.0 million in revenue
237130
Power and Communication Line and Related Structures Construction
$45.0 million in revenue
332410
Power Boiler and Heat Exchanger Manufacturing
750 Employees
333611
Turbine and Turbine Generator Set Unit Manufacturing
1,500 Employees
523940
Portfolio Management and Investment Advice
$47.0 million in revenue
524113
Direct Life Insurance Carriers
$47.0 million in revenue
524126
Direct Property and Casualty Insurance Carriers
1,500 employees
541614
Process, Physical Distribution and Logistics Consulting Services
$20.0 million in revenue
551112
Offices of Other Holding Companies
$45.5 million in revenue
562219
Other Nonhazardous Waste Treatment and Disposal
$47.0 million in revenue
a. Certain plants affected by this rulemaking are owned by non-government entities whose primary business is not electric
power generation.
b. Based on size standards effective at the time EPA conducted this analysis (SBA size standards, effective March 17, 2023).
c. NAICS code used as proxy for determining size threshold for entities categorized in NAICS 221119.
Source: SBA, 2023.
To determine whether a majority owner is a small entity according to these criteria, EPA compared the
relevant entity size criterion value estimated for each parent entity to the SBA threshold value. EPA used
the following data sources and methodology to estimate the relevant size criterion values for each parent
entity:
• Employment: EPA used entity-level employment values from Dun and Bradstreet, Experian, or
corporate/financial websites, if those values were available.
• Revenue: EPA used entity-level revenue values from Dun and Bradstreet, Experian, or
corporate/financial website, if those values were available.
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• Population: Population data for municipalities and other non-state political subdivisions were
obtained from the U.S. Census Bureau (estimated population for 2021) (U.S. Census Bureau,
2021b).
Parent entities for which the relevant measure is less than the SBA size criterion were identified as small
entities and carried forward in the RFA analysis.
As discussed in Chapter 4, EPA estimated the number of small entities owning steam electric power
plants as a range, based on alternative assumptions about the possible ownership of electric power plants
that fall within the definition of the point source category. Following the approach used in the analysis of
the 2015, 2020, proposed 2023 rules, EPA analyzed two cases that provide a range of estimates for (1) the
number of firms incurring compliance costs and (2) the costs incurred by any firm owning a regulated
plant (U.S. EPA, 2015, 2020, 2023d).
Table 8-2 presents the total number of entities with steam electric power plants as well as the number and
percentage of those entities determined to be small. Table 8-3 presents the distribution of steam electric
power plants by ownership type and owner size. Analysis results are presented by ownership type for
each of the regulatory options under the lower (Case 1) and upper (Case 2) bound estimates of the number
of entities owning steam electric power plants.
As reported in Table 8-2 and Table 8-3, EPA estimates that between 220 and 391 entities own 858 steam
electric power plants (for Case 1 and Case 2, respectively).87 A typical parent entity on average is
estimated to own four steam electric power plants (for both Case 1 and Case 2). The Agency estimates
that between 117 (53 percent) and 202 (51 percent) parent entities are small (Table 8-2), and these small
entities own 267 steam electric power plants (Table 8-3), or approximately 31 percent of all steam electric
power plants. Across ownership types, cooperative entities have the largest share of small entities (86 and
89 percent, for Case 1 and Case 2 respectively) and the largest share of steam electric power plants owned
by small entities (88 percent).
Table 8-2: Number of Entities by Sector and Size (assuming two different ownership cases)
Case 1: Lower bound estimate of
Case 2: Upper bound estimate of
number of entities owning steam
number of entities owning steam
Small Entity Size
electric power plants3
electric power plants3
Ownership Type
Standard
Total
Small
% Small
Total
Small
% Small
Cooperative
number of employees
22
19
86.4%
28
25
89.3%
Federal
assumed large
2
0
0.0%
7
0
0.0%
Investor-owned
number of employeesd
57
17
29.8%
88
22
24.6%
Municipality
50,000 population served
50
22
44.0%
84
30
35.6%
Nonutility
number of employeesd
76
57
75.0%
160
123
77.3%
87 As described in Chapter 8 in the 2015 RIA (U.S. Environmental Protection Agency. (2015). Regulatory Impact
Analysis for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source
Category. (EPA-821-R-15-004). ), Case 1 assumed that any entity owning a surveyed plant(s) owns the known
survey ed plant(s) and all of the sample weight associated with the survey ed plant(s). This case minimizes the count of
affected entities, while tending to maximize the potential cost burden to any single entity. Case 2 assumed (1) that an
entity owns only the surveyed plant(s) that it is known to own from the Steam Electric Survey and (2) that this pattern
of ownership, observed for surveyed plants and their owning entities, extends over the entire plant population. This
case minimizes the possibility of multi-plant ownership by a single entity and thus maximizes the count of affected
entities, but also minimizes the potential cost burden to any single entity.
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8: RFA
Table 8-2: Number of Entities by Sector and Size (assuming two different ownership cases)
Small Entity Size
Case 1: Lower bound estimate of
number of entities owning steam
electric power plants3
Case 2: Upper bound estimate of
number of entities owning steam
electric power plants3
Ownership Type
Standard
Total
Small
% Small
Total
Small
% Small
Other Political
Subdivision0
50,000 population served
11
2
18.2%
23
2
8.9%
State
assumed large
2
0
0.0%
2
0
0.0%
Total"
220
117
53.2%
391
202
51.7%
a. Eight plants are owned by a joint venture of two entities.
b. Of these entities, 68 entities, 28 of which are small, own steam electric power plants that are estimated to incur compliance
technology costs under Option B under both Case 1 and Case 2 under the lower bound scenario. Under the upper bound
scenario, 81 entities, 32 of which are small, own steam electric power plants that are estimated to incur compliance technology
costs under Option B under both Case 1 and Case 2.
c. EPA was unable to determine the size of 11 parent entities; for this analysis, these entities are assumed to be small.
d. Entity size may be based on revenue, depending on the NAICS sector (see Table 8-1).
Source: U.S. EPA Analysis, 2024.
Table 8-3: Steam Electric Power Plants by Ownership Type and Size
Number of Steam Electric Power Plantsa,b c
Ownership Type
Small Entity Size Standard
Total
Small
% Small
Cooperative
number of employees
59
52
88.1%
Federal
assumed large
23
0
0.0%
Investor-owned
number of employees6
320
44
13.9%
Municipality
50,000 population served
111
31
28.0%
Nonutility
number of employees6
308
134
43.6%
Other Political Subdivisions
50,000 population served
33
6
18.5%
State
assumed large
4
0
0.0%
Totald
858
267
31.2%
a. Numbers may not add up to totals due to independent rounding.
b. The number of plants is calculated on a sample-weighted basis.
c. Plant size was determined based on the size of the owner with the largest share in the plant. In case of multiple owners with
equal ownership shares (e.g., two entities with 50/50 shares), a plant was assumed to be small if it is owned by at least one
small entity.
d. Of these, 142 steam electric power plants are estimated to incur compliance costs under Option B; 33 of the 142 steam
electric power plants are owned by small entities under the lower bound. Under the upper bound, 171 steam electric power
plants are estimated to incur compliance costs under Option B; 39 of the 171 steam electric power plants are owned by small
entities.
e. Entity size may be based on revenue, depending on the NAICS sector (see Table 8-1).
Source: U.S. EPA Analysis, 2024.
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8: RFA
8.1.3 Significant Impact Test for Small Entities
As outlined in the introduction to this chapter, two criteria are assessed in determining whether the
regulatory options would qualify for a no-SISNOSE finding:
• Is the absolute number of small entities estimated to incur a potentially significant impact, as
described above, substantial?
and
• Do these significant impact entities represent a substantial fraction of small entities in the electric
power industry that could potentially be within the scope of a regulation?
A measure of the potential impact of the regulatory options on small entities is the fraction of small
entities that have the potential to incur a significant impact. For example, if a high percentage of
potentially small entities incur significant impacts even though the absolute number of significant impact
entities is low, then the rule could represent a substantial burden on small entities.
To assess the extent of economic/financial impact on small entities, EPA compared estimated compliance
costs to estimated entity revenue (also referred to as the "sales test")- The analysis is based on the ratio of
estimated annualized after-tax compliance costs to annual revenue of the entity. For this analysis, EPA
categorized entities according to the magnitude of economic impacts that entities would incur due to the
regulatory options. EPA identified entities for which annualized compliance costs are at least one percent
and three percent of revenue. EPA then evaluated the absolute number and the percent of entities in each
impact category, and by type of ownership. The Agency assumed that entities incurring costs below one
percent of revenue are unlikely to face significant economic impacts, while entities with costs of at least
one percent of revenue have a higher chance of facing significant economic impacts, and entities
incurring costs of at least three percent of revenue have a still higher probability of significant economic
impacts. Consistent with the parent-level cost-to-revenue analysis discussed in Chapter 4, EPA assumed
that steam electric power plants, and consequently, their parents, would not be able to pass any of the
increase in their production costs to consumers (zero cost pass-through). This assumption is used for
analytic convenience and provides a worst-case scenario of regulatory impacts to steam electric power
plants.
A detailed summary of how EPA developed these entity-level compliance cost and revenue values is
presented in Chapter 3 and Chapter 4.
8.2 Key Findings for Regulatory options
As described above, EPA developed estimates of the number of small parent entities in the specified cost-
to-revenue impact ranges. Table 8-4 and Table 8-5 summarize the results of the analysis based on lower
and upper bound costs. In terms of number of entities in each of the impact categories, analysis results for
each option are the same under Case 1 and Case 2; however, these numbers represent different
percentages of all small entities owning steam electric power plants under each weighting case.
In the lower bound scenario, EPA estimates that 3 small cooperatives, 4 small nonutilities, and 3 small
municipalities owning steam electric power plants would incur costs exceeding one percent of revenue
(Table 8-4), under the final rule (Option B). On the basis of percentage, the 3 small cooperatives
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8: RFA
represent approximately 12 to 16 percent of the number of small cooperatives owning steam electric
power plants. The 4 small nonutilities represent approximately 3 to 7 percent of the number of small
nonutilities owning steam electric power plants. The 3 small municipalities represents approximately 10
to 14 percent of the number of small municipalities owning steam electric power plants. These small
entities represent approximately 5 to 8.5 percent of the total number of small entities owning steam
electric power plants.
In the upper bound scenario, EPA estimates that 4 small cooperatives, 5 small nonutilities, and 3 small
municipalities owning steam electric power plants would incur costs exceeding one percent of revenue
(Table 8-5), under the final rule (Option B). On the basis of percentage, the 4 small cooperatives
represent approximately 16 to 21 percent of the number of small cooperatives owning steam electric
power plants. The 5 small nonutilities represent approximately 4 to 9 percent of the number of small
nonutilities owning steam electric power plants. The 3 small municipalities represents approximately 10
to 14 percent of the number of small municipalities owning steam electric power plants. These small
entities represent approximately 6 to 10 percent of the total number of small entities owning steam
electric power plants.
In the lower bound scenario, the analysis shows 5 small businesses (2 small cooperatives, 2 small
nonutilities, and 1 small municipality) entity incurring costs greater than three percent of revenue under
all regulatory options. These small entities represent approximately 2.5 to 4 percent of the small entities
owning steam electric power plants. Overall, this worst-case screening-level analysis suggests that the
analyzed regulatory options are unlikely to have a significant economic impact on a substantial impact on
small entities. In the upper bound scenario, the analysis shows 7 small businesses (3 small cooperatives, 2
small nonutilities, and 2 small municipalities) entity incurring costs greater than three percent of revenue
under all regulatory options. These small entities represent approximately 3.5 to 6 percent of the small
entities owning steam electric power plants. Overall, this worst-case screening-level analysis suggests that
the analyzed regulatory options are unlikely to have a significant economic impact on a substantial impact
on small entities under the lower and upper bound scenario.
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Table 8-4: Estimated Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and
Ownership Category - Lower Bound
Case 1: Lower bound estimate of number of
Case 2: Upper bound estimate of number
entities owning steam electric power plants
of entities owning steam electric power
(out of total of 117 small entities)
plants (out of total of 202 small entities)
>1%
>3%a
>1%
>3%a
Entity
Number
% of all
Number
% of all
Number
% of all
Number
% of all
Type/Ownership
of small
small
of small
small
of small
small
of small
small
Category
entities
entities'5
entities
entities'5
entities
entities'5
entities
entities'5
Option A
Small Business
Cooperative
2
10.5%
2
10.5%
2
8.0%
2
8.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
2
3.5%
2
3.5%
2
1.6%
2
1.6%
Small Government
Municipality
3
13.6%
1
4.5%
3
10.0%
1
3.3%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
7
6.0%
5
4.3%
7
3.5%
5
2.5%
Option B
Small Business
Cooperative
3
15.8%
2
10.5%
3
12.0%
2
8.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
4
7.0%
2
3.5%
4
3.2%
2
1.6%
Small Government
Municipality
3
13.6%
1
4.5%
3
10.0%
1
3.3%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
10
8.5%
5
4.3%
10
5.0%
5
2.5%
Option C
Small Business
Cooperative
3
15.8%
2
10.5%
3
12.0%
2
8.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
4
7.0%
2
3.5%
4
3.2%
2
1.6%
Small Government
Municipality
3
13.6%
1
4.5%
3
10.0%
1
3.3%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
10
8.5%
5
4.3%
10
5.0%
5
2.5%
a. The number of entities with cost-to-revenue impact of at least three percent is a subset of the number of entities with such
ratios exceeding one percent.
b. Percentage values were calculated relative to the total of 117 (Case 1) and 202 (Case 2) small entities owning steam electric
power plants regardless of whether these plants are estimated to incur compliance technology costs under any of the
regulatory options.
Source: U.S. EPA Analysis, 2024.
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8: RFA
Table 8-5: Estimated Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and
Ownership Category - Upper Bound
Case 1: Lower bound estimate of number of
Case 2: Upper bound estimate of number
entities owning steam electric power plants
of entities owning steam electric power
(out of total of 117 small entities)
plants (out of total of 202 small entities)
>1%
>3%a
>1%
>3%a
Entity
Number
% of all
Number
% of all
Number
% of all
Number
% of all
Type/Ownership
of small
small
of small
small
of small
small
of small
small
Category
entities
entities'5
entities
entities'5
entities
entities'5
entities
entities'5
Option A
Small Business
Cooperative
3
15.8%
3
15.8%
3
12.0%
3
12.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
3
5.3%
2
3.5%
3
2.4%
2
1.6%
Small Government
Municipality
3
13.6%
2
9.1%
3
10.0%
2
6.7%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
9
7.7%
7
6.0%
9
4.5%
7
3.5%
Option B
Small Business
Cooperative
4
21.1%
3
15.8%
4
16.0%
3
12.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
5
8.8%
2
3.5%
5
4.1%
2
1.6%
Small Government
Municipality
3
13.6%
2
9.1%
3
10.0%
2
6.7%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
12
10.3%
7
6.0%
12
5.9%
7
3.5%
Option C
Small Business
Cooperative
4
21.1%
3
15.8%
4
16.0%
3
12.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
5
8.8%
2
3.5%
5
4.1%
2
1.6%
Small Government
Municipality
3
13.6%
2
9.1%
3
10.0%
2
6.7%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
12
10.3%
7
6.0%
12
5.9%
7
3.5%
a. The number of entities with cost-to-revenue impact of at least three percent is a subset of the number of entities with such
ratios exceeding one percent.
b. Percentage values were calculated relative to the total of 117 (Case 1) and 202 (Case 2) small entities owning steam electric
power plants regardless of whether these plants are estimated to incur compliance technology costs under any of the
regulatory options.
Source: U.S. EPA Analysis, 2024.
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8.3 Uncertainties and Limitations
Despite EPA's use of the best available information and data, the RFA analysis discussed in this chapter
has sources of uncertainty, including:
• None of the sample-weighting approaches used for this analysis accounts precisely for the
number of parent-entities and compliance costs assigned to those entities simultaneously. EPA
assesses the values presented in this chapter as reasonable estimates of the numbers of small
entities that could incur a significant impact according to the cost-to-revenue metric.
• In cases where available information was insufficient to determine the size of an entity, the
Agency assumed the entity to be small. EPA was unable to determine the size of nine parent
entities and assumed all to be small for this analysis.
• As discussed in Chapter 4, the zero cost pass-through assumption represents a worst-case scenario
from the perspective of the plants and parent entities. To the extent that some entities are able to
pass at least some compliance costs to consumers through higher electricity prices, this analysis
may overstate potential impact of regulatory options A through C on small entities.
8.4 Small Entity Considerations in the Development of Rule Options
As described in the introduction to this chapter, the RFA requires federal agencies to consider the impact
of their regulatory actions on small entities and to analyze alternatives that minimize those impacts. As
EPA explicitly states in the final rule, the implementation period built into the rule is another way for
permit writers to consider the needs of small entities, as these entities may need additional time to plan
and finance capital improvements.
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9 Unfunded Mandates Reform Act (UMRA) Analysis
Title II of the Unfunded Mandates Reform Act of 1995, Pub. L. 104-4, requires that federal agencies
assess the effects of their regulatory actions on State, local, and Tribal governments and the private sector.
Under UMRA section 202, EPA generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with "Federal mandates" that might result in expenditures by State,
local, and Tribal governments, in the aggregate, or by the private sector, of $100 million (adjusted
annually for inflation) or more in any one year (i.e., about $198 million in 2023 dollars). Before
promulgating a regulation for which a written statement is needed, UMRA section 205 generally requires
EPA to "identify and consider a reasonable number of regulatory alternatives and adopt the least costly,
most cost-effective, or least burdensome alternative that achieves the objectives of the rule." (2 U.S.C.
1535(a) The provisions of section 205 do not apply when they are inconsistent with applicable law.
Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effective,
or least burdensome alternative, if the Administrator publishes with the rule an explanation of why that
alternative was not adopted. Before EPA establishes any regulatory requirements that might significantly
or uniquely affect small governments, including Tribal governments, it must develop a small government
agency plan, under UMRA section 203. The plan must provide for notifying potentially affected small
governments, enabling officials of affected small governments to have meaningful and timely input in the
development of EPA regulatory proposals with significant intergovernmental mandates, and informing,
educating, and advising small governments on compliance with regulatory requirements.
EPA estimated the compliance costs associated with each of the regulatory options for different categories
of entities. The Agency estimates that the maximum compliance cost in any one year to government
entities (excluding federal government) range from $155 million under the lower bound cost scenario to
$220 million under the upper bound cost scenario.88,89 The maximum compliance cost in any given year to
the private sector range from $1,380 million under the lower bound cost scenario to $3,156 million under
the upper bound cost scenario. From these compliance cost values, EPA determined that the final rule
does contain a mandate that may result in expenditures of $ 198 million (in 2023 dollars) or more for the
public (including State, local, and Tribal governments) and private sectors in any one year.
This chapter contains additional information to support the above statements, including information on
compliance and administrative costs, and on impacts to small governments. Following the approach used
for the analysis of the 2015 and 2020 rules and 2023 proposal (U.S. EPA, 2015, 2020, 2023d; see Chapter
9), the annualized costs presented in this UMRA analysis are calculated using the social cost framework
presented in Chapter 12 of the BCA (U.S. EPA, 2024a). Specifically, this analysis uses costs in 2024
stated in 2023 dollars and accounts for costs in the year they are anticipated to be incurred between 2025
and 2049. The discounted stream of costs is then annualized over a 25-year period. As discussed in
Chapter 10 (Other Administrative Requirements; see Section 10.7) in this document, the reporting and
recordkeeping requirements in this final rule would increase the reporting and recordkeeping burden for
the review, oversight, and administration of the rule relative to baseline requirements. NPDES permitting
authorities are required to review notices of planned participation (NOPPs), leachate groundwater
88 Maximum costs are costs incurred by the entire universe of steam electric power plants in a given year of occurrence
under a given regulatory option.
89 For this analysis, rural electric cooperatives are considered to be a part of the private sector.
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9: UMRA
information reports (LGIRs), and progress reports associates with EPA's voluntary incentive program
(VIP) to administer this rule. Government entities owning steam electric power plants would potentially
incur costs as the result of this rule associated with the cost to implement control technologies at power
plants they own. For more details on how social costs were developed, see Chapter 12 in the BCA.
9.1 UMRA Analysis of Impact on Government Entities
This part of the UMRA analysis assesses the compliance cost burden to State, local, and Tribal
governments that own existing steam electric power plants. The use of the phrase "government entities"
in this section does not include the federal government, which owns 23 of the 858 steam electric power
plants; three of these plants incur compliance costs under the regulatory options. Additionally, in
evaluating the magnitude of the impact of the options on government entities, EPA analyzed only
compliance costs incurred by government entities owning steam electric power plants. EPA estimated that
government entities will not incur significant incremental administrative costs to implement the rule,
regardless of whether or not they own steam electric power plants. As discussed in Section 10.7, EPA
estimated some increase in the burden associated with this rule. In the case of plant owners, EPA
estimated new reporting burdens from notices of planned participation (NOPPs), annual progress reports,
leachate function equivalency reports, annual combustion residual leachate monitoring reports, and
website posting of all of these documents.
Table 9-1 summarizes the number of State, local and Tribal government entities and the number of steam
electric power plants they own. The determination of owning entities, their type, and their size is detailed
in Section 4.3 and Chapter 8 (Assessment of Potential Impact of the Regulatory Options on Small Entities
- Regulatory Flexibility Act (RFA) Analysis).
Table 9-1: Government-Owned Steam Electric Power Plants and Their Parent
Entities
Entity Type
Parent Entities3
Steam electric power plantsb
Municipality
50
111
Other Political Subdivision
11
33
State
2
4
Tribal
0
0
Total
63
148
a. Counts of entities under weighting Case 1, which provides an upper bound of total compliance costs for
any given parent entity. For details see Chapter 8.
b. Plant counts are relative to the estimated 858 plants covered under the point source category.
Source: U.S. EPA Analysis, 2024.
Out of 858 steam electric power plants, 148 are owned by 63 government entities.9" The majority
(75 percent) of these government-owned plants are owned by municipalities, followed by other political
subdivisions (22 percent), and State governments (3 percent).
Table 9-2 and Table 9-3 show upper and lower bound compliance costs for government entities owning
steam electric power plants. Compliance costs to government entities under the final rule range from
90 Counts exclude federal government entities and steam electric power plants they own. The owning entity is determined
based on the entity with the largest ownership share in each plant, as described in Chapter 4.
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approximately $40 million to $66 million in the aggregate. Average annualized costs per plant are $0.3
million under the lower bound cost scenario and $0.5 million under the upper bound cost scenario. The
maximum annualized compliance costs range from $8.65 million to $12.54 million.
Table 9-2: Estimated Compliance Costs to Government Entities Owning Steam Electric Power
Plants (2023$) - Lower Bound
Number of
Total Weighted,
Average
Average
Maximum
Steam Electric
Annualized Pre-
Annualized Cost
Annualized Cost
Annualized Cost
Power Plants
Tax Cost
per MW of
per Plant
per Plant
Ownership Type
(weighted)3
(Millions)3
Capacity13
(Millions)c
(Millions)d
Option A
Municipality
111
$20
$592
$0.2
$7.79
Other Political Subdivision
33
$5
$266
$0.2
$1.93
State
4
$2
$363
$0.4
$1.16
Total
148
$28
$462
$0.2
$7.79
Option B
Municipality
111
$28
$804
$0.3
$8.65
Other Political Subdivision
33
$7
$354
$0.2
$2.48
State
4
$5
$959
$1.2
$2.65
Total
148
$40
$663
$0.3
$8.65
Option C
Municipality
111
$29
$842
m
o
¦uy
$8.65
Other Political Subdivision
33
$7
$354
$0.2
$2.48
State
4
$14
$2,936
$3.6
$11.57
Total
148
$51
$845
$0.3
$11.57
a. Plant counts are relative to the estimated 858 plants covered under the point source category.
b. Average cost per MW values were calculated using total compliance costs and capacity for all steam electric power plants
owned by entities in a given ownership category. In case of multiple ownership structure where parent entities of a given
plant have equal ownership shares and are in different ownership categories, compliance costs and capacity were allocated to
appropriate ownership categories in accordance with ownership shares.
c. Average cost per plant values were calculated using the total number of steam electric power plants owned by entities in a
given ownership category.
d. Reflects maximum of un-weighted costs to surveyed plants only.
Source: U.S. EPA Analysis, 2024.
Table 9-3: Estimated Compliance Costs to Government Entities Owning Steam Electric Power
Plants (2023$) - Upper Bound
Number of
Total Weighted,
Average
Average
Maximum
Steam Electric
Annualized Pre-
Annualized Cost
Annualized Cost
Annualized Cost
Power Plants
Tax Cost
per MW of
per Plant
per Plant
Ownership Type
(weighted)3
(Millions)3
Capacity13
(Millions)c
(Millions)d
Option A
Municipality
111
$43
$1,261
$0.4
$11.67
Other Political Subdivision
33
$7
$350
$0.2
$1.93
State
4
$4
$795
$1.0
$2.04
Total
148
$54
$912
$0.4
$11.67
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Table 9-3: Estimated Compliance Costs to Government Entities Owning Steam Electric Power
Plants (2023$) - Upper Bound
Number of
Total Weighted,
Average
Average
Maximum
Steam Electric
Annualized Pre-
Annualized Cost
Annualized Cost
Annualized Cost
Power Plants
Tax Cost
per MW of
per Plant
per Plant
Ownership Type
(weighted)3
(Millions)3
Capacity13
(Millions)'
(Millions)d
Option B
Municipality
111
o
LO
¦uy
$1,472
$0.5
$12.54
Other Political Subdivision
33
$9
$438
m
o
¦uy
$2.48
State
4
$7
$1,392
$1.7
$4.09
Total
148
$66
$1,113
$0.5
$12.54
Option C
Municipality
111
$52
$1,511
LO
o
¦uy
$12.54
Other Political Subdivision
33
$9
$438
m
o
¦uy
$2.48
State
4
$16
$3,369
$4.1
$12.23
Total
148
$77
$1,295
$0.5
$12.54
a. Plant counts are relative to the estimated 858 plants covered under the point source category.
b. Average cost per MW values were calculated using total compliance costs and capacity for all steam electric power plants
owned by entities in a given ownership category. In case of multiple ownership structure where parent entities of a given
plant have equal ownership shares and are in different ownership categories, compliance costs and capacity were allocated to
appropriate ownership categories in accordance with ownership shares.
c. Average cost per plant values were calculated using the total number of steam electric power plants owned by entities in a
given ownership category.
d. Reflects maximum of un-weighted costs to surveyed plants only.
Source: U.S. EPA Analysis, 2024.
9.2 UMRA Analysis of Impact on Small Governments
As part of the UMRA analysis, EPA also assessed whether the regulatory options would significantly and
uniquely affect small governments. To assess whether the regulatory options would affect small
governments in a way that is disproportionately burdensome in comparison to the effect on large
governments, EPA compared total incremental costs and costs per plant estimated to be incurred by small
governments with those values estimated to be incurred by large governments. EPA also compared the
changes in per plant costs incurred for small government-owned plants with those incurred by non-
government-owned plants. The Agency evaluated costs per plant on the basis of both average and
maximum annualized incremental cost per plant.
Table 9-4 presents the distribution of plants by entity type and size. Out of 148 government-owned steam
electric power plants, EPA identified 37 plants that are owned by 24 small government entities. These 37
plants constitute approximately 25 percent of all government-owned plants.91
91 Counts exclude federal government entities and steam electric power plants they own.
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Table 9-4: Counts of Government-Owned Plants and Their Parent Entities, by Size
Entities3
Steam Electric Power Plantsb
Entity Type
Large
Small
Total
Large
Small
Total
Municipality
28
22
50
80
31
111
Other Political Subdivision
9
2
11
27
6
33
State
2
0
2
4
0
4
Total
39
24
63
111
37
148
a. Counts of entities under weighting Case 1, which provides an upper bound of total compliance costs for any given parent
entity. For details see Chapter 8.
b. Plant counts are relative to the estimated 858 plants covered under the point source category.
Source: U.S. EPA Analysis, 2024.
As presented in Table 9-5 and Table 9-6, under the final rule, overall compliance costs range from $633
million in the lower bound cost scenario to $1,245 million in the upper bound cost scenario.
Table 9-5: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type
and Size (2023$) - Lower Bound
Average
Average
Maximum
Total Annualized
Annualized Pre-
Annualized Pre-
Annualized Pre-
Entity
Number of
Pre-Tax Costs
tax Cost per MW
tax Cost per
tax Cost per
Ownership Type
Size
Plants3
(Millions)3
of Capacity13
Plant (Millions)c
Plant (Millions)
Option A
Government
(excl. federal)
Small
37
$9
$1,385
$0.24
$2.6
Large
111
$19
$350
$0.17
00
¦uy
Private
Small
230
$117
$1,104
$0.51
$40.8
Large
457
$355
$1,011
$0.78
$42.8
All Plants
858
$509
$805
$0.59
$42.8
Option B
Government
(excl. federal)
Small
37
o
1
¦uy
$1,566
$0.27
$2.6
Large
111
o
m
¦uy
$553
$0.27
00
¦uy
Private
Small
230
$132
$1,245
$0.57
$42.7
Large
457
$452
$1,285
$0.99
$77.5
All Plants
858
$633
$1,001
$0.74
$77.5
Option C
Government
(excl. federal)
Small
37
O
1
¦uy
$1,566
$0.27
$2.6
Large
111
$40
$757
$0.37
$11.6
Private
Small
230
$133
$1,258
$0.58
$42.7
Large
457
$537
$1,528
$1.18
$77.5
All Plants
858
$734
$1,160
$0.86
$77.5
a. Plant counts are relative to the estimated 858 plants covered under the point source category.
b. Average cost per MW values were calculated using total compliance costs and capacity for all steam electric power plants
owned by entities in a given ownership category, including plants that incur zero costs. In case of multiple ownership structure
where parent entities of a given plant have equal ownership shares and are in different ownership categories, compliance costs
and capacity were allocated to appropriate ownership categories in accordance with ownership shares.
c. Average cost per plant values were calculated using total number of steam electric power plants owned by entities in a given
ownership category. As a result, plants with multiple majority owners are represented more than once in the denominator of
relevant cost per plant calculations.
Source: U.S. EPA Analysis, 2024.
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Table 9-6: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type
and Size (2023$) - Upper Bound
Average
Average
Maximum
Total Annualized
Annualized Pre-
Annualized Pre-
Annualized Pre-
Entity
Number of
Pre-Tax Costs
tax Cost per MW
tax Cost per
tax Cost per
Ownership Type
Size
Plants3
(Millions)'
of Capacity13
Plant (Millions)c
Plant (Millions)
Option A
Government
(excl. federal)
Small
37
$20
$3,046
$0.53
$10.5
Large
111
LO
m
¦uy
$652
$0.31
$11.7
Private
Small
230
$306
$2,884
$1.33
$173.9
Large
457
$735
$2,090
$1.61
$127.2
All Plants
858
$1,121
$1,772
$1.31
$173.9
Option B
Government
(excl. federal)
Small
37
$21
$3,227
$0.57
$10.5
Large
111
$46
$856
$0.41
$12.5
Private
Small
230
$321
$3,025
$1.39
$175.8
Large
457
$831
$2,364
$1.82
$128.8
All Plants
858
$1,245
$1,968
$1.45
$175.8
Option C
Government
(excl. federal)
Small
37
$21
$3,227
$0.57
$10.5
Large
111
$57
$1,060
$0.51
$12.5
Private
Small
230
$322
$3,038
$1.40
$175.8
Large
457
$917
$2,607
$2.01
$130.6
All Plants
858
$1,346
$2,126
$1.57
$175.8
a. Plant counts are relative to the estimated 858 plants covered under the point source category.
b. Average cost per MW values were calculated using total compliance costs and capacity for all steam electric power plants
owned by entities in a given ownership category, including plants that incur zero costs. In case of multiple ownership structure
where parent entities of a given plant have equal ownership shares and are in different ownership categories, compliance costs
and capacity were allocated to appropriate ownership categories in accordance with ownership shares.
c. Average cost per plant values were calculated using total number of steam electric power plants owned by entities in a given
ownership category. As a result, plants with multiple majority owners are represented more than once in the denominator of
relevant cost per plant calculations.
Source: U.S. EPA Analysis, 2024.
9.3 UMRA Analysis of Impact on the Private Sector
As the final part of the UMRA analysis, this section reports the compliance costs projected to be incurred
by private entities.
Table 9-7 and Table 9-8 summarize the lower and upper bound total annualized costs, maximum one-year
costs, and the year when maximum costs are incurred by type of owner. EPA estimates the final rule to
have total annualized pre-tax compliance costs for private entities ranging from $603 million under the
lower bound cost scenario to $1,207 million under the upper bound cost scenario.
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Table 9-7: Compliance Costs for Electric Generators by Ownership Type (2023$) - Lower
Bound
Ownership Type
Total Annualized
Costs (Millions)
Maximum One-
Year Costs
(Millions)
Year of Maximum
Costs3
Option A
Government (excl. federal)
$28
$135
2026
Private
$490
$1,096
2028
Option B
Government (excl. federal)
$40
$155
2026
Private
$603
$1,380
2028
Option C
Government (excl. federal)
1
LO
¦uy
$256
2026
Private
$693
$1,596
2028
a. The year when the maximum cost occurs is driven by the modeled technology implementation schedule and is determined
based on the renewal of individual NPDES permits for plants owned by the different categories of entities. See Section 3.1.3
in this report and Chapter 11 in the BCA for more details on the technology implementation years and assumptions on the
timing of cost incurrence.
Source: U.S. EPA Analysis, 2024.
Table 9-8: Compliance Costs for Electric Generators by Ownership Type (Millions of 2023$) -
Upper Bound
Ownership Type
Total Annualized
Costs (Millions)
Maximum One-
Year Costs
(Millions)
Year of Maximum
Costs3
Option A
Government (excl. federal)
$55
$200
2026
Private
$1,095
$2,872
2028
Option B
Government (excl. federal)
$67
$220
2026
Private
$1,207
$3,156
2028
Option C
Government (excl. federal)
00
¦uy
$320
2026
Private
$1,298
$3,372
2028
a. The year when the maximum cost occurs is driven by the modeled technology implementation schedule and is determined
based on the renewal of individual NPDES permits for plants owned by the different categories of entities. See Section 3.1.3
in this report and Chapter 11 in the BCA for more details on the technology implementation years and assumptions on the
timing of cost incurrence.
Source: U.S. EPA Analysis, 2024.
9.4 UMRA Analysis Summary
EPA estimated that State and local government entities would incur expenditures of greater than
$198 million, in the aggregate, in any one year under the final rule, Option B, in the upper bound scenario
only. Additionally, the Agency estimated that the private sector would incur expenditures of greater than
$198 million, in the aggregate, in any one year under all regulatory options, under the upper and lower
scenario. Furthermore, as discussed above, neither permitted plants nor permitting authorities are
estimated to incur significant additional administrative costs as the result of the regulatory options.
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Consistent with Section 205, EPA presents three regulatory options which would all result in compliance
costs to governments and the private sector. For Option B, the final rule, the maximum compliance costs
incurred by the private sector in any one year range from $1,380 million to $3,156 million in 2028
whereas total annualized compliance costs for plants owned by private sector entities range from
$603 million to $1,207 million. The implementation period built into this final rule is one way that EPA
accounted for the site-specific needs of steam electric power plants.
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10: Other Administrative Requirements
10 Other Administrative Requirements
This chapter presents analyses conducted in support of the regulatory options to address the requirements
of applicable Executive Orders and Acts. These analyses complement EPA's assessment of the
compliance costs, economic impacts, and economic achievability of the final rule, and other analyses
done in accordance with the RFA and UMRA, presented in previous chapters.
10.1 Executive Order 12866: Regulatory Planning and Review, Executive Order 13563:
Improving Regulation and Regulatory Review, and Executive Order 14094: Modernizing
Regulatory Review
Under Executive Order (E.O.) 12866 (58 FR 51735, October 4, 1993), as amended by E.O. 13563 (76 FR
3821, January 21, 2011) and E.O. 14094 (88 FR 21879, April 11, 2023), EPA must determine whether the
regulatory action is "significant" and therefore subject to review by the Office of Management and
Budget (OMB) and other requirements of the Executive Order. The order defines a "significant regulatory
action" as one that is likely to result in a regulation that may:
• Have an annual effect on the economy of $200 million or more (adjusted every 3 years by the
Administrator of the Office of Information and Regulatory Affairs (OIRA) for changes in gross
domestic product), or adversely affect in a material way the economy, a sector of the economy,
productivity, competition, jobs, the environment, public health or safety, or State, local, or Tribal
governments or communities; or
• Create a serious inconsistency or otherwise interfere with an action taken or planned by another
agency; or
• Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the
rights and obligations of recipients thereof; or
• Raise novel legal or policy issues for which centralized review would meaningfully further the
President's priorities or the principles set forth in the Executive Order, as specifically authorized
in a timely manner by the Administrator of OIRA in each case.
Pursuant to the terms of Executive Order 12866, as amended by E.O. 14094, EPA determined that the
final rule (Option B) is a "significant regulatory action" because the action is likely to have an annual
effect on the economy of $200 million or more. As such, the action is subject to review by OMB. Any
changes made during this period of review will be documented in the docket for this action.
EPA prepared an analysis of the potential benefits and costs associated with this action; this analysis is
described in Chapter 13 of the BCA (U.S. EPA, 2024a).
As detailed in earlier chapters of this report, EPA also assessed the impacts of the regulatory options on
the wholesale price of electricity (Chapter 5: Electricity Market Analyses), retail electricity prices by
consumer group (Chapter 7: Electricity Price Effects), and on employment or labor markets (Chapter 6:
Employment Effects).
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10.2 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations, Executive Order 14008: Tackling the Climate
Crisis at Home and Abroad, and Executive Order 14096: Revitalizing our Nation's
Commitment to Environmental Justice for All
E.O. 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice.
Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to
make environmental justice part of their mission by identifying and addressing, as appropriate,
disproportionately high and adverse human health or environmental effects of their programs, policies,
and activities on minority populations and low-income populations in the United States. E.O. 14008 (86
FR 7619, February 1, 2021) expands on the policy objectives established in E.O.12898 and directs federal
agencies to develop programs, policies, and activities to address the disproportionately high and adverse
human health, environmental, climate-related and other cumulative impacts on disadvantaged
communities, as well as the accompanying economic challenges of such impacts.
EPA's analysis showed that the human health or environmental risk addressed by this final rule will not
have potential disproportionately high and adverse human health or environmental effects on minority,
low-income, or indigenous populations. The results of this evaluation are contained in the EJA (U.S.
EPA, 2024c).
10.3 Executive Order 13045: Protection of Children from Environmental Health Risks and
Safety Risks
E.O. 13045 (62 FR 19885, April 23, 1997) applies to any rule that (1) is determined to be "economically
significant" as defined under E.O. 12866 and (2) concerns an environmental health or safety risk that EPA
has reason to believe might have a disproportionate effect on children. If the regulatory action meets both
criteria, the Agency must evaluate the environmental health and safety effects of the planned rule on
children and explain why the planned regulation is preferable to other potentially effective and reasonably
feasible alternatives considered by the Agency.
As detailed in the EA and BCA (U.S. EPA, 2024a, 2024b), EPA identified several ways in which the
regulatory options would affect children, including by potentially reducing health risk from exposure to
pollutants present in steam electric power plant discharges. The reductions are estimated to be relatively
small and arise from more stringent limits under the regulatory options as compared to the baseline. EPA
quantified neurological changes, as measured by Intellectual Quotient (IQ) points, from lead exposure
among pre-school children and from mercury exposure in-utero resulting from maternal fish consumption
under the regulatory options, as compared to the baseline. EPA also estimated changes in the number of
children with very high blood lead concentrations (above 20 ug/dL) and IQs less than 70 who may require
compensatory education tailored to their specific needs.
EPA estimated that the final rule could benefit children. The analysis shows relatively small potential
changes in lead exposure (from fish consumption) for an average of 1.55 million children annually, and in
mercury exposure (from maternal fish consumption) for an average of 201,850 infants born annually.
However, EPA estimates the resulting health impacts to be relatively small. EPA estimated that the final
rule (Option B) would lead to slight reductions in lead and mercury exposure, decreasing IQ losses by less
than 1 point from lead exposure and 1,377 points from mercury exposure over the entire exposed
population. The annualized social welfare effects from reduced IQ loss associated with children's
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10: Other Administrative Requirements
exposure to lead and mercury are $2.0 million using a 2 percent discount rate, with most of these benefits
associated with reduced mercury exposure. Chapter 5 in the BCA provides further details, including
results for the other regulatory options (U.S. EPA, 2024a). EPA did not quantify additional benefits to
children from changes in exposure to steam electric pollutant discharges due to data limitations, but
discussed them qualitatively. These include changes in the incidence or severity of other health effects
from exposure to lead, mercury, and other pollutants including arsenic, boron, cadmium, copper, nickel,
selenium, thallium, and zinc. They also include potential effects from reductions in exposure to
disinfection byproducts in households served by drinking water systems that use source waters
downstream of steam electric power plant outfalls.
10.4 Executive Order 13132: Federalism
E.O. 13132 (64 FR 43255, August 10, 1999) requires EPA to develop an accountable process to ensure
"meaningful and timely input by State and local officials in the development of regulatory policies that
have federalism implications." Policies that have federalism implications are defined in the Executive
Order to include regulations that have "substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power and responsibilities among the
various levels of government."
Under section 6 of E.O. 13132, EPA may not issue a regulation that has federalism implications, that
imposes substantial direct compliance costs, and that is not required by statute unless the federal
government provides the funds necessary to pay the direct compliance costs incurred by State and local
governments or unless EPA consults with State and local officials early in the process of developing the
regulation. EPA also may not issue a regulation that has federalism implications and that preempts State
law, unless the Agency consults with State and local officials early in the process of developing the
regulation.
EPA has concluded that this action will have federalism implications, because it may impose substantial
direct compliance costs on State or local governments, and the Federal government would not provide the
funds necessary to pay those costs. As discussed in earlier chapters of this document, EPA anticipates that
the final rule will not impose a significant incremental administrative burden on States from issuing,
reviewing, and overseeing compliance with discharge requirements.
Specifically, EPA has identified 148 steam electric power plants that are owned by State or local
government entities or other political subdivisions. EPA estimates that the maximum compliance cost in
any one year to governments (excluding federal government) ranges from $155 million to $220 million
under the final rule (Option B) (see Chapter 9, Unfunded Mandates Reform Act (UMRA), for details).
Annualized compliance costs incurred by governments are $40 million to $67 million under the final rule
(Option B).
10.5 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
E.O. 13175 (65 FR 67249, November 6, 2000) requires EPA to develop an accountable process to ensure
"meaningful and timely input by tribal officials in the development of regulatory policies that have tribal
implications." "Policies that have tribal implications" is defined in the Executive Order to include
regulations that have "substantial direct effects on one or more Indian Tribes, on the relationship between
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10: Other Administrative Requirements
the Federal government and the Indian Tribes, or on the distribution of power and responsibilities
between the federal government and Indian Tribes/'
EPA assessed potential tribal implications for the regulatory options arising from three main changes, as
described below: (1) direct compliance costs incurred by plants; (2) impacts on drinking water systems
downstream from steam electric power plants; and (3) administrative burden on governments that
implement the NPDES program.
• Direct compliance costs: EPA's analyses show that no plant estimated to be affected by the
regulatory options is owned by tribal governments.
• Impacts on drinking water systems: EPA identified one public water system (PWS) operated by
tribal governments that may be affected by bromide and iodine discharges from steam electric
power plants.92 In total, this systems serves approximately 6,800 people. EPA estimated small
reductions in bromide and iodine concentrations in the source waters of this PWS under the final
rule, providing health benefits to the populations served by the PWS. The analysis is detailed in
Chapter 4 of the BCA (U.S. EPA, 2024a). Due to data limitations, EPA was not able to quantify
the potential drinking water treatment cost savings for this system in the analysis detailed in
Chapter 9 of the BCA (U.S. EPA, 2024a).
• Administrative burden: No tribal governments are currently authorized pursuant to section 402(b)
of the CWA to implement the NPDES program.
10.6 Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use
E.O. 13211 requires Agencies to prepare a Statement of Energy Effects when undertaking certain agency
actions. Such Statements of Energy Effects shall describe the effects of certain regulatory actions on
energy supply, distribution, or use, notably: (i) any adverse effects on energy supply, distribution, or use
(including a shortfall in supply, price increases, and increased use of foreign supplies) should the proposal
be implemented, and (ii) reasonable alternatives to the action with adverse energy effects and the
estimated effects of such alternatives on energy supply, distribution, and use.
The OMB implementation memorandum for E.O. 13211 outlines specific criteria for assessing whether a
regulation constitutes a "significant energy action"' and would have a "significant adverse effect on the
supply, distribution or use of energy."93 Those criteria include:
• Reductions in crude oil supply in excess of 10,000 barrels per day;
• Reductions in fuel production in excess of 4,000 barrels per day;
• Reductions in coal production in excess of 5 million tons per year;
92 EPA included public water systems identified in EPA's Safe Drinking Water Information System as having a tribe as
the primacy agency and one tribe-operated system with the state of Oklahoma as the primacy agency.
93 Executive Order 13211 was issued May 18,2002. The OMB later released an Implementation Guidance memorandum
on July 13, 2002.
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• Reductions in natural gas production in excess of 25 million mcf per year;
• Reductions in electricity production in excess of 1 billion kilowatt-hours per year, or in excess of
500 megawatts of installed capacity;
• Increases in the cost of energy production in excess of 1 percent;
• Increases in the cost of energy distribution in excess of 1 percent;
• Significant increases in dependence on foreign supplies of energy; or
• Having other similar adverse outcomes, particularly unintended ones.
None of the criteria above regarding potential significant adverse effects on the supply, distribution, or
use of energy (listed above) apply to this final rule. While the regulatory options might affect (1) the
production of electricity, (2) the amount of installed capacity, (3) the cost of energy production, and (4)
the dependence on foreign supplies of energy, as described below and demonstrated by the results from
the national electricity market analyses conducted for the final rule (see Chapter 5),94 changes for the first
three factors are smaller than the thresholds of concern specified by OMB.
10.6.1 Impact on Electricity Generation
The electricity market analyses (Chapter 5) estimate that the final rule will decrease coal-fired generation,
including generation from power plants to which the final rule applies, by 3.8 percent to approximately
0.7 percent in 2028 through 2050, relative to baseline generation. The changes in coal-fired generation
would be offset by roughly corresponding changes in production from other plants, resulting in no net
decrease in overall production; electricity generated in 2035 increases by 1,693 GWh, which is
approximately 0.3 percent of baseline generation. These changes are very small and support EPA's
assessment that the final rule does not constitute a "significant energy action" in terms of overall impact
on electricity generation.
10.6.2 Impact on Electricity Generating Capacity
As documented in Chapter 5, the Agency's electricity market analysis estimated that the final rule would
result in net cumulative capacity decrease of 370 MW of generating capacity by 2045. This is the largest
projected decrease in generating capacity in the analysis years.
10.6.3 Cost of Energy Production
Based on the IPM analysis results, EPA estimated that the final rule will not significantly affect the total
cost of electricity production. At the national level, total electricity generation costs (fuel, variable O&M,
fixed O&M, capital, and CCS) under the final rule are projected to increase by 0.2 percent. At the
regional level, the change in electricity generation costs varies. Table 5-4 in Chapter 5 summarizes
changes projected in IPM for the 2035 run year and shows range from an increase of 0.9 percent in MRO
94 As described in Chapter 5, this analysis does not consider the costs associated with legacy wastewater limits or the
treatment of unmanaged CRL.
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to a decrease of 0.1 percent in the RF and NPCC regions under the final rule. None of the NERC regions
show increases approaching 1 percent.
Consequently, no region would experience net energy price increases greater than the 1 percent threshold
as a result of the final rule in either the short or the long run. This supports EPA's assessment that the
final rule does not constitute a "significant energy action" in terms of estimated potential effects on the
cost of energy production.
10.6.4 Dependence on Foreign Supply of Energy
EPA's electricity market analyses did not support explicit consideration of the effects of the regulatory
options on foreign imports of energy. However, the regulatory options directly affect electric power
plants, which generally do not face significant foreign competition. Only Canada and Mexico are
connected to the U.S. electricity grid, and transmission losses are substantial when electricity is
transmitted over long distances. In addition, the effects on installed capacity and electricity prices are
estimated to be small.
Table 10-1 presents IPM projected generating capacity and generation by type in 2035 under the baseline
and the final rule. The final rule is estimated to decrease coal-based electricity generation by 9 percent,
while generation using several other sources of energy is estimated to either increase (natural gas, wind,
solar, and landfill gas), or decrease (i.e.. hydro, landfill gas, oil/gas steam). Apart from coal generation
and oil/gas steam generation, and natural gas, changes are less than 1 percent across all generation types.
Table 10-1: Total Market-Level Capacity and Generation by Type for the Final Rule in Model Year
2035
Generating Capacity
GW)
Electricity Generation (Thousand GWh)
Type
Baseline
Option B
% Change
Baseline
Option B
% Change
Hydro
107.3
107.3
0.00%
319.3
318.7
-0.17%
Biomass
0.2
0.2
0.00%
0.4
0.4
0.00%
Geothermal
3.2
3.2
0.00%
21.3
21.3
0.00%
Landfill Gas
3.0
3.0
0.00%
19.1
19.1
-0.08%
Solar
298.2
299.2
0.33%
705.5
708.0
0.35%
Wind
394.0
395.2
0.31%
1,482.7
1,487.3
0.31%
Coal
51.6
46.0
-10.94%
235.7
214.5
-9.00%
Nuclear
83.7
83.7
0.00%
667.0
667.0
0.00%
Natural Gas
476.0
480.2
0.89%
1,344.4
1,359.3
1.11%
Oil/Gas Steam
55.3
55.1
-0.20%
7.7
7.1
-7.67%
Other"
6.5
6.5
0.00%
30.5
30.5
-0.02%
Total3
1,478.9
1,479.6
0.05%
4,833.5
4,833.2
-0.01%
a. Numbers may not add up due to rounding.
b. Values for energy storage are reported in the "Other" category.
Source: U.S. EPA Analysis, 2024.
Table 10-2 presents the corresponding projections of the quantity of fuel used for power generation.
Changes are consistent with changes in generation presented in Table 10-1 with less coal (6.97 percent)
and more natural gas (0.83 percent) consumed under the final rule. Changes are less than 1 percent for
natural gas, lignite and subbituminous coal. However, bituminous coal consumption decreases by
21.82 percent.
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Table 10-2: Total Market-Level Fuel Use by Fuel Type for the Final Rule in Model Year 2035
Fuel Consumption
Fuel Type
Baseline
Option B
% Change
Coal (million tons)
141
131
-6.97%
Bituminous Coal (million tons)
42
33
-21.82%
Subbituminous Coal (million tons)
74
74
-0.81%
Lignite (million tons)
24
24
0.07%
Natural Gas (trillion cubic feet)
9
9
0.83%
Source: U.S. EPA Analysis, 2024.
Given the very small changes in coal and other fuels use under the final rule, it is reasonable to assume
that any increase in demand for fuel used in electricity generation would be met through domestic supply,
thereby not increasing U.S. dependence on foreign supply of energy. Consequently, EPA assesses that the
final rule does not constitute a "significant energy action" from the perspective of energy independence.
10.6.5 Overall Executive Order 13211 Finding
From these analyses and the electricity markets analysis in Chapter 5, EPA concludes that the final rule
would not have a significant adverse effect at a national or regional level under E.O. 13211. Specifically,
the Agency's analysis found that the rule would not reduce net electricity production in excess of 1 billion
kilowatt hours per year nor or installed capacity in excess of 500 megawatts, nor would the rule increase
U.S. dependence on foreign supply of energy. As such, the final rule does not constitute a significant
regulatory action under E.O. 13211 and EPA did not prepare a Statement of Energy Effects.
10.7 Paperwork Reduction Act of 1995
The Paperwork Reduction Act of 1995 (PRA) (superseding the PRA of 1980) is implemented by OMB
and requires that agencies submit a supporting statement to OMB for any information collection that
solicits the same data from more than nine parties. The PRA seeks to ensure that Federal agencies balance
their need to collect information with the paperwork burden imposed on the public by the collection.
The definition of "information collection" includes activities required by regulations, such as permit
development, monitoring, record keeping, and reporting. The term "burden" refers to the "time, effort, or
financial resources" the public expends to provide information to or for a Federal agency, or to otherwise
fulfill statutory or regulatory requirements. PRA paperwork burden is measured in terms of annual time
and financial resources the public devotes to meet one-time and recurring information requests (44 U.S.C.
3502(2); 5 C.F.R. 1320.3(b)). Information collection activities may include:
• reviewing instructions;
• using technology to collect, process, and disclose information;
• adjusting existing practices to comply with requirements;
• searching data sources;
• completing and reviewing the response; and
• transmitting or disclosing information.
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Agencies must provide information to OMB on the parties affected, the annual reporting burden, the
annualized cost of responding to the information collection, and whether the request significantly impacts
a substantial number of small entities. An agency may not conduct or sponsor, and a person is not
required to respond to, an information collection unless it displays a currently valid OMB control number.
OMB has previously approved the information collection requirements contained in the existing
regulations 40 CFR part 423 under the provisions of the Paperwork Reduction Act.95
EPA is finalizing several changes to the individual reporting and recordkeeping requirements of section
423.19 for specific subcategories of plants and/or plants that have certain types of discharges. EPA is
adding reporting and recordkeeping requirements to plants in the permanent cessation of coal combustion
by 2034 subcategory and for plants that discharge unmanaged CRL. EPA is also removing reporting and
recordkeeping requirements for low-utilization electric generating units and finalizing a new requirement
for plants to post reports to a publicly available website. EPA estimates it would take a total annual
average of 24,300 hours and $2,540,000 for 236 affected steam electric power plants to collect and report
the information in the final rule. These costs are in addition to those detailed in Chapter 3.3 through
Chapter 9 of this document.
EPA estimates it would take a total annual average of 3,230 hours and $273,000 for permitting or control
authorities to review the information submitted by plants. EPA estimates that there would be no start-up
or capital costs associated with the information described above. Here also, these costs are in addition to
those detailed in Chapter 3.3 through Chapter 9 of this document.
10.8 National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995, Pub L. No.
104-113, Sec. 12(d) directs EPA to use voluntary consensus standards in its regulatory activities unless
doing so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus
standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary consensus standard bodies. The NTTAA
directs EPA to provide Congress, through the OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
The regulatory options do not involve technical standards, for example in the measurement of pollutant
loads. Nothing in the regulatory options would prevent the use of voluntary consensus standards for such
measurement where available, and EPA encourages permitting authorities and regulated entities to do so.
Therefore, EPA did not include any voluntary consensus standards in the final rule.
95 OMB has assigned control number 2040-0281 to the information collection requirements under 40 CFR part 423.
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11: References
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RIA for Supplemental Steam Electric Power Generating ELGs
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U.S. Bureau of Economic Analysis. (2023). Table 1.1.9 Implicit Price Deflators for Gross Domestic
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U.S. Census Bureau. (2012). Economic Census Data Tables https://www.census.gov/programs-
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U.S. Census Bureau. (2021a). 2017 Economic Census Core Statistics www.data.census.gov
U.S. Census Bureau. (2021b). 2021: ACS 1-Year Estimates Total Population by Geography.
U.S. Census Bureau. (2023). All Sectors: County Business Patterns, including ZIP Code Business
Patterns, by Legal Form of Organization and Employment Size Class for the U.S., States, and
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https://data.census.gov/table/CBP2021.CB2100CBP?q=CBP2021.CB2100CBP&n=211130
U.S. Department of Labor. Bureau of Labor Statistics. (2023). Total compensation for All Civilian
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U.S. Energy Information Administration. (2016). Form EIA-923 Detailed Data: Annual Release 2015
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%2C%20decreasing%20demand%20for%20coal.mines%20in%202008%20to%20671%20mines
%20in%202017.
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year low. Today in Energy. https://www.eia.gov/todavinenergy/detail.php?id=43675
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Today in Energy. https://www.eia.gov/todavinenergy/detail.php?id=48936
U.S. Energy Information Administration. (2021b). Of the operating U.S. coal-fired power plants, 28%
plan to retire by 2035. Today in Energy, https://www .eia. gov/todavinenergy/detail .php?id=5 0658
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U.S. Energy Information Administration. (2022a). Annual Electric Power Industry Report, Form EIA-861
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U.S. Energy Information Administration. (2022b). Coal will account for 85% of U.S. electric generating
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Final Data
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U.S. Energy Information Administration. (2022d). Form EIA-923 Detailed Data: Annual Release 2021
Final Data
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as more reactors retire. Today in Energy, https://www.eia.gov/todavinenergy/detail .php ?id=51978
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U.S. capacity requirements in 2023. Today in Energy.
https ://www .eia. gov/todavinenergy/detail ,php?id=5 543 9
U.S. Energy Information Administration. (2023d). Coal generation decreased in 2022, but overall U.S.
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.85.Coal%20production%20in%202022%20was%20about%2012.04%20quads.
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U.S. Environmental Protection Agency. (2010). Questionnaire for the Steam Electric Power Generating
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11: References
U.S. Environmental Protection Agency. (2020). Regulatory Impact Analysis for Revisions to the Effluent
Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source
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U.S. Environmental Protection Agency. (2023a). Documentation for EPA's Power Sector Modeling
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from https://www.epa.gov/svstem/files/documents/2023-03/EPA%20Platform%20v6%20Post-
IRA%202022%20Reference%20Case.pdf
U.S. Environmental Protection Agency. (2023b). Documentation for EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model Post-IRA 2022 Reference Case. Retrieved
from https://www.epa.gov/svstem/files/documents/2023-03/EPA%20Platform%20v6%20Post-
IRA%202022%20Reference%20Case.pdf
U.S. Environmental Protection Agency. (2023c). Electricity Sector Emissions Impacts of the Inflation
Reduction Act: Assessment of Projected C02 Emission Reductions from Changes in Electricity
Generation and Use. (EPA 430-R-23-004). Retrieved from https://www.epa.gov/inflation-
reduction-act/electric-sector-emissions-impacts-inflation-reduction-act
U.S. Environmental Protection Agency. (2023d). 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).
U.S. Environmental Protection Agency. (2024a). Benefit and Cost Analysis for Supplemental Effluent
Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source
Category. (821-R-24-006).
U.S. Environmental Protection Agency. (2024b). Environmental Assessment for Supplemental Effluent
Guidelines and Standards for the Steam Electric Power Generating Point Source Category. (821 -
R-24-005).
U.S. Environmental Protection Agency. (2024c). Environmental Justice Analysis for Supplemental
Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power
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U.S. Environmental Protection Agency. (2024e). Technical Development Document for Supplemental
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Wilson, M. (2022). What the Russia crisis means for U.S. electricity mix. E&E News.
https://www.eenews.net/articles/what-the-russia-crisis-means-for-u-s-electricitv-mix/
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Appendix A: Summary of Changes
A Summary of Changes to Costs and Economic Impact Analysis
Table A-l summarizes the principal methodological changes EPA made to analyses of the costs and economic impacts of this final ELG rule as
compared to the analyses of the 2020 rule and the 2023 proposal (U.S. EPA, 2020, 2023d).
Table A-1: Changes to Costs and Economic Impacts Analysis Since 2020 Rule and 2023 Proposed Rule
Cost or Impact Category
Analysis Component (2020 Rule Analysis)
Change from 2020 Rule to 2023 Proposed
Rule
Change from 2023 Proposed Rule to 2024
Final Rule
General inputs for
screening-level analyses
Compliance costs discounted and
annualized (7 percent)
No change
Compliance costs discounted and
annualized using a weighted average cost
of capital for the power sector of
3.76 percent
Generation, plant revenue, and estimated
electricity prices using EIA-861 and EIA-
923 databases; six-year (2013-2018)
average values
Updated with data from more current EIA-
861 and EIA-923 databases to use more
recent six-year [2015-2020] average values
Updated with data from more current EIA-
861 and EIA-923 databases to use more
recent six-year [2016-2021] average values
Generating capacity from 2018 EIA-860
Updated using 2020 EIA-860
Updated using 2021 EIA-860
NERC regions from 2017 EIA-860
Updated using 2020 EIA-860
Updated using 2021 EIA-860
Electricity revenue, sales, and number of
consumers by consumer class (residential,
industrial, commercial, and
transportation) for ASCC and HICC regions
from EIA-861 for [2018]
Updated to use data from EIA-861 for
[2020]
Updated to use data from EIA-861 for
[2021]
Electricity revenue, sales, and number of
consumers by consumer class (residential,
industrial, commercial, and
transportation) for NERC regions other
than ASCC and HICC regions from [2019]
AEO projections
Updated using [2021] AEO projections
Updated using [2023] AEO projections
Industry profile
Total count of plants (914 plants)
Updated universe of 871 plants reflects
information on actual, planned, and
announced unit retirements through the
end of 2028
Updated universe of 858 plants reflects
information on actual, planned, and
announced unit retirements through the
end of 2028
Industry data (i.e., capacity, generation,
number of plants, etc.) from 2018 EIA
databases
Updated using 2020 EIA databases
Updated using 2021 EIA databases
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Appendix A: Summary of Changes
Table A-1: Changes to Costs and Economic Impacts Analysis Since 2020 Rule and 2023 Proposed Rule
Cost or Impact Category
Analysis Component (2020 Rule Analysis)
Change from 2020 Rule to 2023 Proposed
Rule
Change from 2023 Proposed Rule to 2024
Final Rule
Screening-level plant
impacts
Cost-to-revenue impact indicators (1% and
3%) based on 6-year (2013-2018) average
values of electricity generation and
electricity prices (to estimate plant-level
revenue)
Updated to use average electricity
generation and electricity prices for [2015-
2020]
Updated to use average electricity
generation and electricity prices for [2016-
2021]
Market-level impacts
(IPM)
The Baseline includes existing regulatory
requirements as of January 2020, plus the
final CCR Part A rule and an updated
representation of the 2015 ELG based on
2020 data.
The Baseline includes existing regulatory
requirements as of August 2021 and an
updated representation of the 2020 ELG
based on 2021 data.
The Baseline includes regulatory
requirements as of March 2023 including
the Inflation Reduction Act of 2022.
Potential electricity
price effects
Projected total electricity sales in [2020]
from [AEO 2019]
Projected total electricity sales in [2024]
from [AEO 2021]
Projected total electricity sales in [2024]
from [AEO 2023]
Electricity sales data by consumer group
from [2018] EIA-860 database
Electricity sales data by consumer group
from [2020] EIA-860 database
Electricity sales data by consumer group
from [2021] EIA-860 database
Owner-level impacts
and RFA/SBREFA
Owners identified in EIA-860 [2018]
Owners identified in EIA-860 [2020]
Owners identified in EIA-860 [2021]
Small business size determination metrics
[Dun and Bradstreet for private entities;
Census ACS 2017 for governments]
Small business size determination metrics
[Dun and Bradstreet for private entities;
Census ACS 2019 for governments]
Small business size determination metrics
[Dun and Bradstreet for private entities;
Census ACS 2021 for governments]
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Appendix B: Costs and Pollutant Removals
B Comparison of Incremental Costs and Pollutant Removals
This appendix describes EPA's analysis of the incremental costs and pollutant removals of the regulatory
options. The information provides insight into how regulatory options compare to each other in terms of
reducing toxic pollutant discharges to surface waters.
B.1 Methodology
Cost-effectiveness is defined as the incremental annualized cost of a pollution control option in an
industry or industry subcategory per incremental pound equivalent of pollutant (/. e., pound of pollutant
adjusted for toxicity) removed by that control option. The analysis compares removals for pollutants
directly regulated by the ELGs and incidentally removed along with regulated pollutants.
As described forthe 2015 and 2020 rules and 2023 proposed rule, EPA's cost-effectiveness analysis
involves the following steps to generate input data and calculate the desired values (for details, see
Appendix F in U.S. EPA, 2015):
1. Determine the pollutants considered for regulation.
2. For each pollutant, obtain relative toxic weights and POTW removal factors.
3. Define the regulatory pollution control options.
4. Calculate pollutant removals and toxic-weighted pollutant removals for each control option and
for each of direct and indirect discharges. For indirect dischargers, the calculations include
applying a factor that reflects the ability of a POTW or sewage treatment plant to remove
pollutants prior to discharge to water. See TDD (U.S. EPA, 2024e) for details.
5. Determine the total annualized compliance cost for each control option and for direct and indirect
dischargers.
6. Adjust the cost obtained in step 5 to 1981 dollars.96
7. Calculate the cost-effectiveness ratios for each control option and for direct and indirect
dischargers.
EPA calculated the cost-effectiveness ratios for the final rule regulatory options, but did not include the
costs or loading reductions resulting from the unmanaged CRL limits. EPA only estimated changes in
total dissolved solids and total suspended solids for unmanaged CRL discharges. Since these broad
parameters cannot be easily translated into toxic pollutants, EPA did not include the costs associated with
treatment of unmanaged CRL discharges to be consistent. The next section provides results for steps 1
through 5, where the total annualized compliance costs calculated in step 5 are relative to the 2020 rule
baseline.
96 Adjustment of costs to 1981 dollars is a convention to facilitate comparison of cost-effectiveness values across rules.
Since EPA is not estimating cost-effectiveness ratios in this analysis, this adjustment was not needed.
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Appendix B: Costs and Pollutant Removals
B.2 Results
Toxic Weights of Pollutants and POTW Removal
The TDD provides information on the pollutants addressed by the regulatory options (U.S. EPA, 2024e).
The pollutants include several metals (e.g., arsenic, mercury, selenium), various non-metal compounds
(e.g., chloride, fluoride, sulfate), nutrients, and conventional pollutants (e.g., oil and grease, biochemical
oxygen demand.)
The toxic weighted pound equivalent (TWPE) analysis involves multiplying the changes in loadings of
each pollutant by a pollutant-specific toxic weighting factor (TWF) that represents the toxic effect level
relative to the toxicity of copper. For indirect dischargers, the changes are multiplied by a second factor
that reflects the ability of a POTW or sewage treatment plant to remove pollutants prior to discharge to
waters.
Evaluated Options
EPA analyzed Options A through C summarized in Table 1-1.
Pollutant Removals and Pound Equivalent Calculations
Table B-l, below, presents estimated annual reduction in the mass loading of pollutant anticipated from
direct and indirect dischargers for each regulatory option, relative to the baseline. The toxic weighted
removals account for pollutant toxicity and, for indirect dischargers,97 for POTW removals. The
calculations do not account for the removal of pollutants that do not have TWFs, either because data are
not available to set a TWF or toxicity is not the pollutant's primary environmental impact (e.g., nutrients
contributing to eutrophication, bromide contributing to formation of disinfection byproducts).
Furthermore, the pound equivalent pollutant removal analysis does not address routes of potential
environmental damage and human exposure, and therefore potential benefits from reducing pollutant
exposure.
Annualized Compliance Costs
EPA developed costs for technology controls to address each of the wastestreams present at each steam
electric power plant. The TDD provides additional details on the methods used to estimate the costs of
meeting the limitations and standards under the baseline and each of the regulatory options (U.S. EPA,
2024e). The method used to calculate the incremental annualized compliance costs is described in greater
detail in Chapter 3, Compliance Costs. EPA categorized these annualized compliance costs as either
direct or indirect based on the discharge associated with each wastestream at each plant. Table B-l
summarizes the annualized compliance costs of the regulatory options relative to the baseline.
Cost Effectiveness
Table B-l summarizes the cost-effectiveness ratios for the regulatory options, calculated as the annual
cost of that option divided by to the pound-equivalents removed by that option. The incremental
effectiveness of progressively more stringent regulatory options can be assessed both in comparison to the
baseline scenario and to another regulatory option. By convention, EPA presents the cost-effectiveness
97 Plants that discharge pollutants to a POTW.
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Appendix B: Costs and Pollutant Removals
values in 1981 dollars per pound-equivalent removed. Figure B-l compares the pollutant removals and
costs of the regulatory options graphically.
Table B-1: Estimated Pollutant Removal and Costs of Regulatory Options by Discharger Category
Discharger
Total Annual TWF-Weighted
Pollutant Removals (lb-eq.)a
Total Annual Pre-tax
Compliance Costs
(million, 2023$)
Cost- Effect iven ess
(1981$/lb-eq.)b
Category
Optionc
Totald
Incremental®
Totald
Incremental®
Totald
Incremental®
A
199,121
199,121
$317.81
$317.81
$422
$422
Direct
B
247,191
48,070
$432.45
$114.64
$463
$631
C
271,621
24,430
$529.11
$96.66
$515
$1,047
A
2,989
2,989
$9.45
$9.45
$837
$837
Indirect
B
3,194
205
$10.15
$0.70
$841
$900
C
3,214
20
$12.56
$2.41
$1,034
$31,302
a. The Agency estimated zero TWPE but non-zero BA compliance costs for one plant in this analysis. EPA included the costs for
this plant in this analysis even though there are no corresponding removals.
b. Compliance costs adjusted to 1981 dollars using the CCI (3,535 / 13,358 = 0.265)
c. Options are listed in increasing order of pollutant removals, relative to the baseline.
d. Total removals and costs are compared to those for the baseline.
e. Incremental removals and costs are compared to those for the next least stringent option in the order listed in the table. For
direct dischargers, the incremental removals and costs under Option A are calculated relative to the baseline, the incremental
removals and costs for Option B are calculated relative to those of Option A, etc.
Source: U.S. EPA Analysis, 2024
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Appendix B: Costs and Pollutant Removals
Figure B-1: Estimated Removals and Costs of the Regulatory Options, Relative to Baseline.
Option C
•
i
) Option B
) Option A
$600
$500
CD
c
TO
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$400 >
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CM
$300 tS o
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U 1=
$200 ~ 1
Q. ^
E
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u
$100 "§
N
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3
C
$0 <
50,000 100,000 150,000 200,000 250,000 300,000
Pollutant removals, relative to baseline (TWPE)
Source: U.S. EPA Analysis, 2024.
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Appendix C: Total Costs with 7 Percent Discount
C Total Costs Based on 7 Percent Discount Rate
Table C-l and Table C-2 present compliance cost estimates for the regulatory options, and Table and
Table C-4 show the breakout of total compliance costs for each option by wastestream, based on the 7
percent discount rate that was previously used for the 2023 proposed rule analysis as representing the
private cost of capital (U.S. EPA, 2023d). For comparison, the tables include values from Table 3-1 and
Table 3-3 estimated using the 3.76 percent discount rate used as the revised estimate of the private cost of
capital.
Table C-1: Estimated Total Annualized Compliance Costs (in millions, 2023$, at 2024) - Lower
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Regulatory
Option
Capital
Other
Initial
Total
Total
Capital
Other
Initial
Total
Total
Technology
One-
Time
O&M
Technology
One-
Time
O&M
3.76% Discount Rate
Option A
$232
$0.1
$247
$479
$186
$0.1
$200
$386
Option B
$284
$0.2
$312
$596
$229
$0.1
$250
$479
Option C
$336
$0.2
$359
$695
$270
$0.2
$286
$557
7% Discount Rate
Option A
$271
$0.1
$228
$499
$218
1
o
¦uy
$184
$401
Option B
$325
$0.2
$282
$608
$262
$0.2
$226
$488
Option C
$385
$0.2
$325
$711
$310
$0.2
$259
$569
Source: U.S. EPA Analysis, 2024.
Table C-2: Estimated Total Annualized Compliance Costs (in millions, 2023$, at 2024) - Upper
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Regulatory
Option
Capital
Technology
Other
Initial
One-
Time
Total
O&M
Total
Capital
Technology
Other
Initial
One-
Time
Total
O&M
Total
3.76% Discount Rate
Option A
$453
1
o
¦uy
$595
$1,048
$372
1
o
¦uy
$490
$863
Option B
$505
$0.2
$659
$1,164
$415
$0.1
$541
$956
Option C
$557
$0.2
$706
$1,263
$456
$0.2
$577
$1,033
7% Discount Rate
Option A
$526
$0.1
$543
$1,069
$432
$0.1
$447
$878
Option B
$580
$0.2
$597
$1,177
$476
$0.2
$489
$965
Option C
$640
$0.2
$640
$1,281
$524
$0.2
$522
$1,046
Source: U.S. EPA Analysis, 2024.
C-1
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RIA for Supplemental Steam Electric Power Generating ELGs
Appendix C: Total Costs with 7 Percent Discount
Table C-3: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2023$, at
2024) - Lower
Regulatory
Option
Pre-Tax Compliance Costs
After-Tax Compliance Costs
BA
Transport
Water
FGD
Wastewater
CRL
Legacy
Net
Total
Costs
BA
Transport
Water
FGD
Wastewater
CRL
Legacy
Net
Total
Costs
3.76% Discount Rate
Option A
$19
$179
$281
$0
$479
$15
$139
$232
$0
$386
Option B
$19
$179
$370
$28
$596
$15
$139
$302
$23
$479
Option C
$30
$205
$433
$28
$695
$23
$160
$350
$23
$557
7% Discount Rate
Option A
$20
$190
$289
$0
$499
$16
$147
$238
$0
$401
Option B
$20
$190
$381
$17
$608
$16
$147
$310
$14
$488
Option C
1
m
¦uy
$216
$446
$17
$711
$25
$170
$360
$14
$569
Source: U.S. EPA Analysis, 2024.
Table C-4: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2023$, at
2024) - Upper
Regulatory
Option
Pre-Tax Compliance Costs
After-Tax Compliance Costs
BA
Transport
Water
FGD
Wastewater
CRL
Legacy
Net
Total
Costs
BA
Transport
Water
FGD
Wastewater
CRL
Leg
acy
Net
Total
Costs
3.76% Discount Rate
Option A
$19
$179
$849
$0
$1,048
$15
$139
$709
$0
$863
Option B
$19
$179
$939
$28
$1,164
$15
$139
$778
$23
$956
Option C
$30
$205
$1,001
$28
$1,263
$23
$160
$826
$23
$1,033
7% Discount Rate
Option A
$20
$190
$859
$0
$1,069
$16
$147
$715
$0
$878
Option B
$20
$190
$950
$17
$1,177
$16
$147
$787
$14
$965
Option C
1
m
¦uy
$216
$1,016
$17
$1,281
$25
$170
$838
$14
$1,046
Source: U.S. EPA Analysis, 2024.
C-2
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