United States
Environmental Protection
Agency
Office of Water
Washington, DC 20460
EPA-821 -R-23-002
February 28, 2023
<®ERA Regulatory Impact Analysis
for Proposed Supplemental
Effluent Limitations
Guidelines and Standards
for the Steam Electric Power
Generating Point Source
Category
-------
v»EPA
United States
Environmental Protection
Agency
Regulatory Impact Analysis for Proposed
Supplemental Effluent Limitations
Guidelines and Standards for the Steam
Electric Power Generating Point Source
Category
EPA-821-R-23-002
February 28, 2023
U.S. Environmental Protection Agency
Office of Water (4303T)
Engineering and Analysis Division
1200 Pennsylvania Avenue, NW
Washington, DC 20460
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RIAfor Revisions to 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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Contents
Table of Contents
Table of Contents i
List of Tables v
List of Figures vii
Abbreviations viii
Executive Summary 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 Proposed 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 Regulations 2-9
2.2.3 Greenhouse Gas Reduction Targets 2-11
2.2.4 Inflation Reduction Act of 2022 2-11
2.3 Market Conditions and Trends in the Electric Power Industry 2-12
3 Compliance Costs 3-1
3.1 Analysis Approach and Inputs 3-1
3.1.1 Plant-Specific Costs Approach 3-2
3.1.2 Plant-Level Costs 3-2
3.1.3 Technology Implementation Years 3-3
3.1.4 Total Compliance Costs 3-4
3.1.5 Voluntary Incentive Program 3-6
3.2 Key Findings for Regulatory Options 3-6
3.2.1 Estimated Industry-level Total Compliance Costs 3-6
3.2.2 Estimated Regional Distribution of Incremental Compliance Costs 3-7
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3.3 Key Uncertainties and Limitations 3-8
4 Cost and Economic Impact Screening Analyses 4-1
4.1 Analysis Overview 4-1
4.2 Cost-to-Revenue Analysis: Plant-Level Screening Analysis 4-1
4.2.1 Analysis Approach and Data Inputs 4-2
4.2.2 Key Findings for Regulatory Options 4-3
4.2.3 Uncertainties and Limitations 4-4
4.3 Cost-to-Revenue Screening Analysis: Parent Entity-Level Analysis 4-4
4.3.1 Analysis Approach and Data Inputs 4-5
4.3.2 Key Findings for Regulatory Options 4-6
4.3.3 Uncertainties and Limitations 4-8
5 Assessment of the Impact of the Proposed 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 Proposed Rule 5-4
5.1.3 Key Outputs of the Market Model Analysis Used in Assessing the Effects of the Proposed
Rule 5-5
5.2 Findings from the Market Model Analysis 5-5
5.2.1 National-level Analysis Results for Model Years 2028-2055 5-5
5.2.2 Detailed Analysis Results for Model Year 2030 5-8
5.3 Estimated Effects of the Regulatory Options on New Capacity 5-20
5.4 Uncertainties and Limitations 5-20
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 Proj ected Actions 6-1
6.2.2 Resource Requirements of Changes in Projected Actions and Treatment Technology 6-3
6.2.3 Estimation and Aggregation of Labor Impacts 6-6
6.3 Estimated Impacts of the Proposed Rule in 2030 6-7
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 Proposed Rule by Industry 6-10
6.4 Estimated Impacts from Installation of Wastewater Treatment Technologies 6-11
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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 7-5
7.3 Assessment of Impact of Compliance Costs on Household Electricity Costs 7-5
7.3.1 Analysis Approach and Data Inputs 7-5
7.3.2 Key Findings for Regulatory Options A through C 7-6
7.3.3 Uncertainties and Limitations 7-7
7.4 Distribution of Electricity Cost Impact on Household 7-7
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 8-5
8.2 Key Findings for Regulatory options 8-6
8.3 Uncertainties and Limitations 8-8
8.4 Small Entity Considerations in the Development of Rule Options 8-8
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 9-3
9.3 UMRA Analysis of Impact on the Private Sector 9-5
9.4 UMRA Analysis Summary 9-6
10 Other Administrative Requirements 10-1
10.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving
Regulation and Regulatory Review 10-1
10.2 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations
and Low-Income Populations and Executive Order 14008: Tackling the Climate Crisis at Home
and Abroad 10-2
10.3 Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
10-2
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10.4 Executive Order 13132: Federalism 10-3
10.5 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments 10-4
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
10.6.2Impact 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 E.O. 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 1
B Comparison of Incremental Costs and Pollutant Removals 1
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Contents
List of Tables
Table ES-1-1: Regulatory Options Analyzed for the Proposed Rule 2
Table 1-1: Regulatory Options Analyzed for the Proposed Rule 1-3
Table 2-1: Steam Electric Industry Share of Total Electric Power Generation Plants and Capacity in 2020
2-2
Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity by
Ownership Type, 2020 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, 2014-2020 (TWh) 2-8
Table 3-1: Estimated Total Annualized Compliance Costs (in millions, 2021$, at 2024) 3-7
Table 3-2: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2021$, at 2024)
3-7
Table 3-3: Estimated Annualized Total Compliance Costs by NERC Region (in millions, 2021$, at 2024)
3-8
Table 4-1: Plant-Level Cost-to-Revenue Analysis Results by Owner Type and Regulatory Option 4-3
Table 4-2: Entity-Level Cost-to-Revenue Analysis Results 4-7
Table 5-1: IPM Run Years 5-3
Table 5-2: Baseline Projections, 2028-2055 5-6
Table 5-3: Incremental National Impact of Proposed Option 3 Relative to Baseline, 2028-2055 5-7
Table 5-4: Impact of Proposed Rule on National and Regional Markets in the Year 2030 5-10
Table 5-5: Impact of the Proposed Rule on In-Scope Plants, as a Group, in the Year 2030a 5-15
Table 5-6: Impact of Proposed Rule on Individual In-Scope Plants in the Year 2030 5-19
Table 6-1: Estimated Change in Generating Capacity Under Option 3 Relative to Baseline in 2030 6-1
Table 6-2: Incremental Change in New Generation Capacity Under Construction in 2030 6-2
Table 6-3: Estimated Change in Fuel Consumption Under Option 3 Relative to Baseline in 2030 6-3
Table 6-4: Option 3 Technology Capital and Operation Costs (millions, 2021$) 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
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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) 6-8
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 (2021$) 7-2
Table 7-2: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to Compliance
Costs by NERC Region and Regulatory Option (2021$) 7-4
Table 7-3: Average Incremental Annual Cost per Household in 2024 by NERC Region and Regulatory
Option (2021$) 7-6
Table 8-1: NAICS Codes and SBA Size Standards for Non-government Majority Owners Entities of
Steam Electric Power Plants 8-3
Table 8-2: Number of Entities by Sector and Size (assuming two different ownership cases) 8-4
Table 8-3: Steam Electric Power Plants by Ownership Type and Size 8-5
Table 8-4: Estimated Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and Ownership
Category 8-7
Table 9-1: Government-Owned Steam Electric Power Plants and Their Parent Entities 9-2
Table 9-2: Estimated Compliance Costs to Government Entities Owning Steam Electric Power Plants
(Millions of 2021$) 9-3
Table 9-3: Counts of Government-Owned Plants and Their Parent Entities, by Size 9-4
Table 9-4: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type and Size
(2021$) 9-5
Table 9-5: Compliance Costs for Electric Generators by Ownership Type (2021$) 9-6
Table 10-1: Total Market-Level Capacity and Generation by Type for the Proposed Rule in 2030 10-6
Table 10-2: Total Market-Level Fuel Use by Fuel Type for the Proposed Rule in 2030 10-7
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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 3
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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
CAA
Clean Air Act
CCI
Construction cost index
CCR
Coal combustion residuals
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
FR
Federal Register
FRCC
Florida Reliability Coordinating Council
GDP
Gross domestic product
GHG
Greenhouse gas
GW
Gigawatt
GWh
Gigawatt-hour
HICC
Hawaii Coordinating Council
HRI
Heat rate improvement
HRR
High recycle rate
HRTR
High Hydraulic Residence Time Reduction
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Abbreviations
IPM
Integrated Planning Model
IRA
Inflation Reduction Act of 2022
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
SBA
Small Business Administration
SBREFA
Small Business Regulatory Enforcement Fairness Act
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
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Abbreviations
UMRA
Unfunded Mandates Reform Act
use
United States Code
VIP
Voluntary Incentive Program
VOM
Variable O&M
WECC
Western Electricity Coordinating Council
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Executive Summary
Executive Summary
The U.S. Environmental Protection Agency (EPA) is proposing revisions to the technology-based effluent
limitations guidelines and standards (ELGs) for the steam electric power generating point source
category, 40 CFR part 423, which EPA promulgated in October 2020 (85 FR 64650). The proposed rule
revises certain best available technology (BAT) effluent limitations and pretreatment standards for
existing sources for three wastestreams: flue gas desulfurization (FGD) wastewater, bottom ash (BA)
transport water, and combustion residual leachate (CRL).
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 proposal and presents analyses to
meet various statutory and Executive Order requirements. The accompanying Benefit and Cost Analysis
for Proposed 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 and 13563.
Regulatory Options
For this proposed rule, EPA evaluated four regulatory options as summarized in Table ES-1 and further
described in the notice of proposed rulemaking (NPRM) for the action. EPA proposes to establish BAT
effluent limitations based on the technologies described in Option 3.
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Executive Summary
Table ES-1-1: Regulatory Options Analyzed for the Proposed Rule
Wastestream
Subcategory
Technology Basis for BAT/PSES Regulatory Options3
2020 Rule (Baseline)
Option 1
Option 2
Option 3
(preferred option)
Option 4
FGD
Wastewater
NA (default unless in
subcategory)15
CP + Bio
CP + Bio
CP + Membrane
CP + Membrane
CP + Membrane
Boilers permanently ceasing
the combustion of coal by
2028
SI
SI
SI
SI
SI
Early adopters or boilers
permanently ceasing the
combustion of coal by 2032
NS
NS
CP + Bio
CP + Bio
NS
High FGD Flow Facilities or
Low Utilization Boilers
CP
CP + Bio
CP + Membrane
CP + Membrane
CP + Membrane
BA Transport
Water
NA (default unless in
subcategory)15
HRR
HRR
HRR
ZLD
ZLD
Boilers permanently ceasing
the combustion of coal by
2028
SI
SI
SI
SI
SI
Early adopters or boilers
permanently ceasing the
combustion of coal by 2032
NS
NS
NS
HRR
NS
Low Utilization Boilers
BMP Plan
HRR
HRR
ZLD
ZLD
CRL
NA (default)15
BPJ
CP
CP
CP
CP
Abbreviations: BMP = Best Management Practice; BPJ = Best Professional Judgement; 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, 2023e).
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, 2022
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Executive Summary
Annualized Private 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 (Table ES-2). On an after-tax basis,
the proposed rule (Option 3) has estimated incremental annualized compliance costs of $181 million.1
Table ES-2: Estimated Incremental Annualized After-tax Compliance Costs (Million of 2021$,
discounted to 2023 using 7 percent)
Regulatory Option
Capital Technology
Total O&M
Total Costs3
Option 1
00
^1-
¦uy
m
m
¦uy
1
00
¦uy
Option 2
m
00
¦uy
$66
$149
Option 3
$97
00
¦uy
$181
Option 4
$101
$89
$190
a. Costs analyzed over the period 2025-2049.
Source: U.S. EPA Analysis, 2022
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 the proposed rule, looking
specifically at regulatory option 3, 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 proposed rule. See Chapter 5 for details.
Results across these analyses show that the proposed 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 or generation costs of
less than 0.1 percent across economic measures for Option 3 in the model year 2030 after implementation
of the revised ELGs (see Table ES-3). The proposed rule results in a small projected decrease in total
generation capacity (less than 0.1 percent of the baseline) as the net effect of increases in non-coal
generation sources and decreases in coal-fired generation capacity resulting from early retirements of
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, 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. By contrast, for the social cost analysis, costs are recorded in the year in which they are estimated to be
incurred during the analysis period of 2025-2049. The 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.
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Executive Summary
coal-fired electricity generating units relative to the baseline and already scheduled retirements. Results
for steam electric power plants in scope of the proposed rule (in Table ES-4) also show small impacts,
with a net decrease in total capacity under the proposed rule when compared to the baseline (0.1 percent),
and net decreases in total generation by steam electric power plants of 0.5 percent for the proposed rule.
These findings suggest that the proposed 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 proposed
rule show no change in generation for 16 of the 46 plants with compliance costs, and a slight decrease in
generation for another 19 plants. See Chapter 5 for details of these analyses, including results by region
and for different model years.
Table ES-3: Modeled Impact of Proposed Rule on National Electricity Market in the Year 2030
Economic Measures3
Option 3
(all dollar values in 2021$)
Baseline Value
Value
Difference
% Change
Total Domestic Capacity (GW)
1,310
1,310
-0.1
0.0%
Existing
0.0
0.0%
New Additions
-0.1
0.0%
Early Retirements
0.0
0.0%
Generation (TWh)
4,581
4,581
0.26
0.0%
Costs ($Millions)
$149,601
$149,769
$168
0.1%
Fuel Cost
$54,429
$54,411
00
1
¦uy
i
0.0%
Variable O&M
$8,644
$8,675
i
m
¦uy
0.4%
Fixed O&M
$56,321
$56,471
$150
0.3%
Capital Cost
$30,207
$30,212
$5
0.0%
Average Variable Production Cost
($/MWh)
$13.77
$13.77
$0.00
0.0%
C02 Emissions (Million Metric Tons)
1,304
1,299
-4
-0.3%
Mercury Emissions (Tons)
3
3
0
-0.5%
NOx Emissions (Million Tons)
1
1
0
-0.6%
S02 Emissions (Million Tons)
1
1
0
-0.4%
HCL Emissions (Million Tons)
0
0
0
-1.0%
a. See Chapter 5 for a description of the economic measures.
Source: U.S. EPA Analysis, 2022
Table ES-4: Impact of Proposed Rule on Plants in the Steam Electric Power Generating Point
Source Category, as a Group, in the Year 2030
Economic Measures3
(all dollar values in 2021$)
Baseline Value
Option 3
Value
Difference
% Change
Total Domestic Capacity (MW)
274,256
274,007
-249
-0.1%
Early Retirements - Number of Plants
28
29
1
3.6%
Full & Partial Retirements - Capacity (MW)
56,422
56,671
249
0.4%
Generation (GWh)
1,226,067
1,220,364
-5,703
-0.5%
Costs ($Millions)
$44,427
$44,429
$2
0.0%
Fuel Cost
$22,187
$22,071
-$116
-0.5%
Variable O&M
$4,334
$4,355
$21
0.5%
Fixed O&M
$17,312
$17,410
$98
0.6%
Capital Cost
$594
$594
$0
0.0%
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Executive Summary
Table ES-4: Impact of Proposed Rule on Plants in the Steam Electric Power Generating Point
Source Category, as a Group, in the Year 2030
Economic Measures3
(all dollar values in 2021$)
Baseline Value
Option 3
Value
Difference
% Change
Average Variable Production Cost ($/MWh)
$21.63
$21.65
$0.02
0.1%
a. See Chapter 5 for a description of the economic measures.
Source: U.S. EPA Analysis, 2022
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 proposed Option 3.
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 proposed
rule (Option 3) results in an average estimated cost increase of 0.0060 per kWh.
On the national level, the proposed rule (Option 3) results in estimated average compliance costs per
residential household of $0.63 per year; across region, compliance costs range between $0.09 and $1.31
per year (not including the NERC regions ASCC and HICC where compliance costs are zero).
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 proposed rule (Option 3), EPA estimates that two small municipalities and one small nonutility
owning steam electric power plants would incur costs exceeding one percent of revenue. On the basis of
percentage, these entities represent 1 to 3 percent of the total number of small entities owning steam
electric power plants (7 to 9 percent of small municipalities and 1 to 2 percent of small nonutilities). The
analysis shows one small business (nonutility) entity incurring 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 impact on 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 proposed and final rules with "Federal
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Executive Summary
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..
$170 million in 2021 dollars).
EPA estimates that none of the regulatory options would result in expenditures of at least $170 million for
State and local government entities, in the aggregate, in any one year under any of the regulatory options
EPA analyzed. However, the Agency does estimate that the private sector would incur expenditures of
greater than $170 million, in the aggregate, in any one year. For the proposed rule (Option 3), the
maximum compliance costs incurred by the private sector in any one year are $504 million in 2026,
whereas total annualized compliance costs for plants owned by private sector entities are $201 million.
The implementation period built into the proposed rule is one way that EPA accounted for the site-
specific needs of steam electric power plants. EPA has also attempted to reduce impacts to early adopters
through the creation of a new subcategory under Option 3.
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 and Executive Order 13563:
Improving Regulation and Regulatory Review: Pursuant to the terms of Executive Order
12866, this action is an "economically significant regulatory action" because the action is likely
to have an annual effect on the economy of $100 million or more. As such, the action is subject to
review by the OMB under Executive Orders 12866 and 13563. Any changes made in response to
OMB suggestions or recommendations 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, 2023a).
• Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use: EPA's analyses show that the proposed 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 proposed rule will not reduce electricity
production in excess of 1 billion kilowatt hours per year or in excess of 500 megawatts of
installed capacity, nor will it 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 Proposed
Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (EJA) document (U.S. EPA, 2023d). The analysis showed that
the human health or environmental risk addressed by this proposed action will not have potential
disproportionately high and adverse human health or environmental effects on minority, low-
income, or indigenous populations.
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Executive Summary
• Executive Order 13045: Protection of Children from Environmental Health Risks and
Safety Risks: As described in Chapter 10 and detailed in the BCA (U.S. EPA, 2023a), EPA
identified several ways in which the proposed rule could benefit children, including by potentially
reducing health risk from exposure to pollutants present in steam electric power plant discharges.
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1: Introduction
1 Introduction
1.1 Background
EPA is proposing a regulation that revises the technology-based effluent limitations guidelines and
standards (ELGs) for the steam electric power generating point source category, 40 CFR part 423, which
EPA previously revised in October 2020 (85 FR 64650). The proposed rule revises certain BAT effluent
limitations and pretreatment standards for existing sources for three wastestreams: flue gas desulfurization
(FGD) wastewater, bottom ash (BA) transport water, and combustion residual leachate (CRL).
This document describes the Agency's analysis of the costs and economic impacts of the regulatory
options that were evaluated by EPA. EPA analyzed four regulatory options and is proposing Option 3.
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 Proposed Supplemental Revisions to the Effluent
Guidelines and Standards for the Steam Electric Power Generating Point Source Category
(TDD) (U.S. EPA, 2023e). 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.
• Benefit and Cost Analysis for Proposed Supplemental Revisions to the Effluent Limitations
Guidelines and Standards for the Steam Electric Power Generating Point Source Category
(BCA) (U.S. EPA, 2023a). The BCA summarizes the societal benefits and costs estimated to
result from implementation of the regulatory options.
• Environmental Assessment for Proposed Supplemental Revisions to the Effluent Guidelines and
Standards for the Steam Electric Power Generating Point Source Category (EA) (U.S. EPA,
2023c). The EA summarizes the environmental and human health improvements that are
estimated to result from implementation of the regulatory options.
• Environmental Justice Analysis for Proposed Supplemental Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category (EJA) (U.S. EPA,
2023d). This report presents a profile of the communities and populations potentially impacted by
this proposal, analysis of the distribution of impacts in the baseline and proposed changes, and
summary of input from potentially impacted communities that EPA met with prior to the
proposal.
The proposed 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
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environmental data generated or collected from all sampling and analyses, existing databases and
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 (see RIA; U.S. EPA, 2020b).
Appendix A describes the principal changes to the regulatory options analysis, as compared to the 2020
rule. These changes include:
• Updating the information on the control and treatment technologies and associated costs for BA
transport water, FGD wastewater, and CRL (see TDD for details).
• 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 repowerings2 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 proposal is implemented. For this proposed rule, this baseline
includes the 2020 rule. See Section 2.2 for additional discussion of these regulations and Chapter
5, Assessment of the Impact of the Proposed Rule on National and Regional Electricity Markets,
for further description of the analysis using IPM.
• Updating electricity generation, sales, and electricity prices based on the most current data from
the Energy Information Administration (EIA) (e.g., 2015-2020 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 Proposed Rule
For this proposed rule, EPA evaluated four regulatory options as shown in Table 1-1. EPA proposes to
establish BAT effluent limitations based on the technologies described in Option 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 Proposed Rule
Wastestream
Subcategory
Technology Basis for BAT/PSES Regulatory Options3
2020 Rule (Baseline)
Option 1
Option 2
Option 3
(Preferred Option)
Option 4
FGD Wastewater
NA (default unless in subcategory)15
CP + Bio
CP + Bio
CP + Membrane
CP + Membrane
CP + Membrane
Boilers permanently ceasing the
combustion of coal by 2028
SI
SI
SI
SI
SI
Early adopters or boilers
permanently ceasing the
combustion of coal by 2032
NS
NS
CP + Bio
CP + Bio
NS
High FGD Flow Facilities or Low
Utilization Boilers
CP
CP + Bio
CP + Membrane
CP + Membrane
CP + Membrane
Bottom Ash
Transport Water
NA (default unless in subcategory)15
HRR
HRR
HRR
ZLD
ZLD
Boilers permanently ceasing the
combustion of coal by 2028
SI
SI
SI
SI
SI
Early adopters or boilers
permanently ceasing the
combustion of coal by 2032
NS
NS
NS
HRR
NS
Low Utilization Boilers
BMP Plan
HRR
HRR
ZLD
ZLD
CRL
NA (default)15
BPJ
CP
CP
CP
CP
Abbreviations: BMP = Best Management Practice; BPJ = Best Professional Judgement; 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, 2023e).
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, 2022
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1: Introduction
1.2.2 Baseline
The baseline for the analyses supporting this proposed 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 four 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 (2020b). EPA also incorporated updated information on the
technologies and other controls that plants employ. The current analysis focuses on three wastestreams:
BA transport water, FGD wastewater, and CRL.
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.3 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).
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 proposed regulatory option (Option 3) using IPM and provides insight
into the incremental effects of the proposed option on the steam electric power generating
industry and on national electricity markets, relative to the baseline.
Since there have been many changes to the industry since the 2015 rule, EPA also evaluates impacts in light of these
changes to confirm its findings that the costs are economically achievable.
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• Analysis of employment effects (Chapter 6), which assesses national-level changes in
employment in the steam electric industry, relative to the baseline.
• 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 the discussion follows a presentation very similar to that in the associated RIA documents
(U.S. EPA, 2015, 2020b).
Chapter 11 provides detailed information on sources cited in the text and two 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.
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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 rule (U.S.
EPA, 2015). It also discusses the regulations applicable to the universe of plants subject to the proposed
rule.
2.1 Steam Electric Industry
The proposed rule revises BAT limitations and pretreatment standards for bottom ash transport water,
FGD wastewater, and CRL 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, 2023e).
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 871 plants in the steam electric power generating industry. As presented in Table 2-1, the 871
steam electric power plants represent approximately 7 percent of the total number of plants in the power
generation sector, but represent approximately 56 percent of the national total electric nameplate
generating capacity with 679,414 MW.5
Of the estimated 871 steam electric power plants in the universe, EPA expects only a subset to incur
compliance costs under the proposed rule: those coal fired power plants that discharge BA transport
water, FGD wastewater, or CRL. As presented in Table 2-1, EPA estimated that 93 plants would incur
non-zero compliance costs under proposed Option 3; these plants represent 0.7 percent of the total plants
reported by EIA in 2020 and 6.1 percent of the total generating capacity.
See Questionnaire for the Steam Electric Power Generating Effluent Guidelines (Steam Electric Survey; U. S. EPA,
2010)
The total number of plants and electric generating capacity are for 2020. At the time EPA developed the industry
profile, 2020 was the most recent calendar year for which EIA had published detailed annual data.
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Table 2-1: Steam Electric Industry Share of Total Electric Power Generation Plants and Capacity
in 2020
Steam Electric Industry13
Plants with Non-Zero Compliance
Costs for Proposed Rulec
Total3
Number
% of Total
Number
% of Total
Plants
12,636
871
6.9%
93
0.7%
Capacity (MW)
1,212,239
679,414
56.0%
73,897
6.1%
a. Data for total electric power generation industry are from the 2020 EIA-860 database (EIA, 2021d).
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 proposed rule (Option 3) and other analyzed regulatory options.
Source: U.S. EPA Analysis, 2022; EIA, 2021d.
The following sections present information on ownership, physical, geographic, 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 proposed 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 871 steam
electric power plants (for details on determination of parent entities for steam electric power plants, see
Chapter 4, Cost and Economic Impact Screening Analyses). The plurality of steam electric power plants
(38 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 (51 percent) of total
steam electric nameplate capacity.
Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity
by Ownership Type, 2020
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
21
9.2%
32
7.4%
59
6.8%
36,563
5.4%
Federal
3
1.3%
10
2.3%
23
2.6%
31,154
4.6%
Investor-owned
59
25.8%
102
23.8%
328
37.6%
345,674
50.9%
Municipality
51
22.3%
87
20.4%
111
12.8%
43,358
6.4%
Nonutility
82
35.8%
167
39.3%
313
35.9%
196,202
28.9%
Other Political
Subdivisions
8
3.5%
19
4.5%
29
3.3%
17,768
2.6%
State
5
2.2%
10
2.3%
8
1.0%
8,696
1.3%
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, 2020
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
229
100.0%
427
100.0%
871
100.0%
679,414
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 (2021d). 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, 2022; EIA, 2021d
EPA estimates that between 47 percent and 48 percent of entities owning steam electric power plants are
small entities (Table 2-3), according to Small Business Administration (SBA) (2019) 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 investor-owned category
(22 percent), while nonutilities and cooperatives make up the largest share of small entities (69 percent
and 67 percent, respectively). The pattern is similar under the upper bound estimate, but small entities
represent 20 percent of investor-owned entities, 70 percent of cooperatives, and 73 percent of nonutilities.
EPA estimates that out of 871 steam electric power plants, 250 (29 percent) are owned by small entities
(Table 2-4). Nonutilities represent the majority (54 percent) of plants owned by small entities (134 out of
250 plants), while investor-owned utilities, cooperatives, municipalities, and other political subdivisions7
make up the remaining 46 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
14
7
21
66.7%
22
9
32
70.4%
Federal
0
3
3
0.0%
0
10
10
0.0%
Investor-owned
13
46
59
22.0%
20
82
102
19.6%
Municipality
22
29
51
43.1%
29
58
87
32.9%
Nonutility
57
25
82
69.5%
122
45
167
72.9%
Other Political
Subdivision
3
5
8
37.5%
7
12
19
38.3%
State
0
5
5
0.0%
0
10
10
0.0%
Upper bound estimate of number of entities
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
109
120
229
47.6%
200
226
427
47.0%
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, 2022
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
43
16
59
73.4%
Federal
0
23
23
0.0%
Investor-owned
38
290
328
11.5%
Municipality
30
82
111
26.6%
Nonutility
134
179
313
42.7%
Other Political Subdivisions
6
23
29
21.3%
State
0
8
8
0.0%
Total
250
621
871
28.7%
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, 2022
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 Interconnected System 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 Interconnected System covers nearly all of 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 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
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.
Some 2021 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 2021 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 proposed rule under the
different options. Other factors include the baseline economic characteristics 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
Plants'3
Capacity (MW)ab
NERC Region
Number
% of Total
MW
% of Total
AK
2
0.2%
120
0.0%
HICC
10
1.1%
1,155
0.2%
MRO
138
15.9%
82,179
12.1%
NPCC
84
9.7%
30,336
4.5%
RF
174
20.0%
154,685
22.8%
SERC
241
27.7%
255,815
37.7%
TRE
66
7.6%
54,362
8.0%
WECC
155
17.8%
100,762
14.8%
TOTAL
871
100.0%
679,414
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, 2022; EIA, 2021d
2.1.3 Electricity Generation
Total net electricity generation in the United States for 2020 was 4,007 TWh.1" The 2020 EIA data was
the most recent year of finalized EIA data that was available at the time of analysis. Nuclear generation
accounted for 20 percent of total electricity generation, behind natural gas (41 percent), but ahead of coal
(19 percent) and renewables (13 percent). Other energy sources accounted for comparatively smaller
shares of total generation, with hydropower representing 7 percent; wind, solar and other renewable
energy, 13 percent; and petroleum, less than one percent.
As presented in Table 2-7, the 7-year period of 2014 through 2020 saw total net generation decrease by
approximately 2.1 percent with the 219 TWh increase (77 percent) in generation from renewables and
497 TWh (44 percent) increase in generation from natural gas being more than offset by the 808 TWh
(51 percent) drop in generation from coal-fueled generators.11
Between 2014 and 2020, the amount of electricity generated by utilities declined by 9 percent while that
generated by nonutilities rose by 7 percent. Comparing 2014 and 2020 values, across all fuel-source
categories, utilities generated a larger share of their electricity using natural gas (a 62 percent increase)
and renewables (a 102 percent increase) even as their overall generation declined. For nonutilities, the
largest percent increase in electricity generation (73 percent) occurred for renewables, whereas generation
from natural gas increased 30 percent.
One terawatt-hour is 1012 watt-hours.
The decline in 2020 is likely due to economic effects of the COVID-19 pandemic and relatively wanner winter weather
(EIA, 202 li).
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Table 2-7: Net Generation by Energy Source and Ownership Type, 2014-2020 (TWh)
Utilities
Nonutilities
Total
Energy Source
2014
2020
% Change
2014
2020
% Change
2014
2020
% Change
Coal
1,170
580
-50.4%
409
191
-53.3%
1,579
771
-51.2%
Hydropower
233
260
11.7%
20
20
-2.6%
253
280
10.6%
Nuclear
420
429
2.2%
377
361
-4.3%
797
790
-0.9%
Petroleum
19
13
-31.4%
10
4
-56.7%
29
17
-40.4%
Natural Gas
501
813
62.1%
625
811
29.8%
1,127
1,624
44.2%
Other Gases
4
2
-40.1%
12
12
-1.1%
16
14
-10.8%
Renewables3
35
70
101.5%
251
435
73.1%
286
505
76.5%
Other"
0.4
0.5
6.0%
6
5
-18.4%
7
5
-16.8%
Total
2,382
2,168
-9.0%
1,711
1,839
7%
4,094
4,007
-2.1%
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, 2021e; EIA, 2015
2.2 Other Environmental Regulations and Policies
The 2015 and 2020 RIA 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, 2020b). 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,
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2020. In particular, five amendments to the 2015 CCR rule were finalized which continue to impact the
wastewaters covered by this ELG. First, the CCR Part A rule established a new deadline of April 11,
2021, for all unlined surface impoundments, as well as those surface impoundments that failed the
location restriction for placement above the uppermost aquifer, to stop receiving waste and begin closure
or retrofit. EPA established this date after evaluating the steps that owners and operators need to take for
surface impoundments to stop receiving waste and begin closure, and the time frames needed for
implementation. (This would not affect the ability of plants to install new, composite-lined surface
impoundments.) Second, the Part A rule established procedures for plants to obtain approval from EPA
for additional time to develop alternative disposal capacity to manage their wastestreams (both coal ash
and non-coal ash) before they must stop receiving waste and begin closing their coal ash surface
impoundments. Third, the Part A rule changed the classification of compacted-soil-lined and clay-lined
surface impoundments from lined to unlined. Fourth, the Part B rule finalized procedures potentially
allowing a limited number of facilities to demonstrate to EPA that, based on groundwater data and the
design of a particular surface impoundment, the unit has and will continue to ensure there is no reasonable
probability of adverse effects to human health and the environment. Should such a submission be
approved, these CCR surface impoundments would be allowed to continue to operate.
As explained in the 2015 and 2020 ELG rules, the ELGs and CCR 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
facilitate and minimize the complexity of implementing engineering, financial, and permitting activities.
EPA continued to take into account the interaction of these two rules during the development of this
proposal. EPA's analysis builds in the final requirements of these rules in the baseline accounting for the
most recent data provided under the CCR rule reporting and recordkeeping requirements. This is further
described in the Supplemental TDD, Section 3 (U.S. EPA, 2023e). 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.12
2.2.2 Air Regulations
EPA is taking a number of actions to regulate a variety of conventional, hazardous, and GHG air
pollutants. Some of these actions are being taken to regulate the same steam electric plants subject to Part
423. Other actions impact steam electric plants indirectly when implemented by states.
2.2.2.1 The Revised CSAPR Update and the Proposed Good Neighbor Plan for the 2015 Ozone NAAQS
EPA recently completed a rulemaking to address "good neighbor" obligations for the 2008 ozone national
ambient air quality standards (NAAQS) and has proposed a rulemaking earlier this year with respect to
the same statutory obligations for the 2015 ozone NAAQS. These actions implement the Clean Air Act's
prohibition on emissions that significantly contribute to nonattainment, or interfere with maintenance, of
the NAAQS in other states.
On April 30, 2021, EPA published the final Revised Cross-State Air Pollution Rule (CSAPR) Update, 86
FR 23054, which resolved 21 states' good neighbor obligations for the 2008 ozone NAAQS, following
EPA will continue to incorporate the effects of forthcoming CCR actions to address matters raised in litigation,
legislation, petitions for reconsideration and implementation during the analysis of the final ELG rule.
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the remand of the 2016 CSAPR Update (81 FR 74504) in Wisconsin v. EPA, 938 F.3d 308 (D.C. Cir.
2019). Between them, these two rules establish the Group 2 and Group 3 market-based emissions trading
programs for 22 states in the eastern U.S. for emissions of oxides of nitrogen (NOx) from fossil fuel-fired
EGUs during the summertime ozone season.
On February 28, 2022, the Administrator signed a proposed rule, Federal Implementation Plan
Addressing Regional Ozone Transport for the 2015 Ozone National Ambient Air Quality Standards, 87
FR 20036 (Apr. 6, 2022) (also called the Good Neighbor Plan). This proposed rule includes further
ozone-season NOx pollution reduction requirements for fossil fuel-fired EGUs in 25 states to address
those states' good neighbor obligations for the 2015 ozone NAAQS. The proposed rule would establish
an enhanced Group 3 market-based emissions trading program with NOx budgets for EGUs in those 25
states, beginning in 2023. Further information about this proposal is available on EPA's website.13
2.2.2.2 Clean Air Act Section 111 Rule
On October 23, 2015, EPA finalized NSPS for emissions of GHGs from new, modified, and reconstructed
fossil fuel-fired EGUs under Clean Air Act (CAA) section 111(b). Specifically, the 2015 NSPS
established separate standards for emissions of carbon dioxide (CO2) from newly constructed, modified,
and reconstructed fossil fuel-fired electric utility steam generating units (i.e.. utility boilers and integrated
gasification combined cycle (IGCC) units) and from newly constructed and reconstructed fossil fuel-fired
stationary combustion turbines. The standards set in the 2015 NSPS reflected the degree of emission
limitation achievable through the application of the best system of emission reduction (BSER) that EPA
determined to have been adequately demonstrated for each type of unit and were codified in 40 CFR part
60, subpart TTTT. EPA is currently undertaking a review of the 2015 NSPS, including new technologies
to mitigate GHG emissions from new, modified, and reconstructed stationary combustion turbines, and
will, if warranted, propose to revise the NSPS in an upcoming rulemaking.
On August 3, 2015, under CAA section 111(d), EPA promulgated its first emission guidelines regulating
GHGs from existing fossil fuel-fired EGUs in the Clean Power Plan (CPP) (40 CFR part 60, subpart
UUUU), which was subsequently stayed by the U.S. Supreme Court. On June 19, 2019, EPA
promulgated new emission guidelines, known as the Affordable Clean Energy (ACE) Rule (40 CFR part
60, subpart UUUUa), and issued a repeal of the CPP. On January 19, 2021, the U.S. Court of Appeals for
the D.C. Circuit vacated the ACE Rule and remanded the rule to EPA for further consideration consistent
with its decision. The Supreme Court then overturned portions of the D.C. Circuit Court's decision in
West Virginia v. EPA, No. 20-1530, in June 2022. EPA is now considering the implications of the
Supreme Court's decision and is undertaking a new rulemaking to establish new emission guidelines
under CAA section 111(d) to limit GHG emissions from existing fossil fuel-fired EGUs.
2.2.2.3 Mercury and Air Toxics Standards Rule
EPA recently proposed to reaffirm the determination that it is appropriate and necessary to regulate
hazardous air pollutants (HAP), including mercury, from coal- and oil-fired steam generating power
plants after considering cost. These regulations are known as the Mercury and Air Toxics Standards
(MATS) for power plants. The proposed MATS action would revoke a 2020 finding that it is not
See https://www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqs.
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appropriate and necessary to regulate coal- and oil-fired power plants under CAA section 112, but which
did not disturb the underlying MATS regulations. The MATS proposal would ensure that coal- and oil-
fired power plants continue to control emissions of toxic air pollution, including mercury.
2.2.2.4 National Ambient Air Quality Standards Rules for Particulate Matter
EPA is currently reconsidering a December 7, 2020 decision to retain the primary (health-based) and
secondary (welfare-based) NAAQS for particulate matter (PM).14 EPA is reconsidering the December
2020 decision because available scientific evidence and technical information indicate that the current
standards may not be adequate to protect public health and welfare, as required by the CAA.
2.2.3 Greenhouse Gas Reduction Targets
On April 22, 2021, President Biden announced new 2030 GHG reduction targets for the United States.15
As part of reaching net zero emissions by 2050, the nationally determined contribution submitted to the
United Nations Framework Convention on Climate Change includes a 50-52 percent reduction from 2005
levels by 2030. These reduction targets were developed 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 2020 GHG emissions in the U.S. came from electricity generation (largely comprised of
emissions from steam electric power plants).16 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 IRA. It includes many provisions that will affect
the steam electric power generating industry. The IRA provides tax credits, financing programs, and other
incentives that will accelerate the transition to forms of energy that produce little or no greenhouse gas
emissions. An analysis conducted by the U.S. Department of Energy (DOE) shows that tax incentives
included in the IRA will increase the growth of wind and solar electricity generation while supporting the
maintenance of the country's existing nuclear power fleet (DOE, 2022). Thus, the DOE analysis suggests
the IRA may reduce the number of coal burning power plants in operation.
Based on these DOE analytic results EPA would expect reduced baseline emissions of air and water
pollution, lower the total incremental costs, and lower total incremental benefits of this rule that feed into
the regulatory impact analysis under E.O. 12866 and E.O. 13563. While the impacts of the IRA are not
reflected in the detailed analyses included with this proposal (because they were completed prior to the
passage of the Act), EPA is currently evaluating how the IRA can be incorporated into its Integrated
Planning Model (IPM) and will update the analyses to reflect the IRA for any final rule. EPA solicits
See https://www.epa.gov/newsreleases/epa-reexamine-health-standards-hannful-soot-previous-administration-left-
unchanged.
See https://www.whitehouse.gov/ceq/news-updates/2021/12/13/icvmi-president-biden-signs-executive-order-
catalvzing-americas-clean-energv-economv-through-federal-sustainabilitv/.
See https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
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comment on the incorporation of the IRA into the IPM modeling, including any specific
recommendations or data supporting a particular approach.
2.3 Market Conditions and Trends in the Electric Power Industry
The 51 percent decline in coal-fueled electricity generation summarized in Table 2-7 for the period of
2014 through 2020 exemplifies an ongoing trend over the last decade: the progressive reduction in
generation capacity as coal units and plants retire. In 2022, EIA reported that retirements of coal
generation capacity in the US in 2021 were 4.6 GW, a slower decline relative to the average of 11 GW
per year between 2015 to 2020. Moreover, EIA predicted that coal-fired power plant retirements in 2022
(12.6 GW) would account for 85 percent of total electric generating capacity retirements for that year
(EIA, 2022a). In 2022, capacity additions are predicted to consist primarily of solar (46 percent), natural
gas (21 percent), and wind (17 percent) capacity (EIA, 2022e).
In 2018, EIA reported that nearly all of the utility-scale power plants in the United States that were retired
from 2008 through 2017 were fueled by fossil fuels, with coal power plants accounting for 47 percent of
the total retired capacity (EIA, 2018a). Capacity additions in that same year primarily consisted of natural
gas (62 percent), wind (21 percent), and solar photovoltaic (16 percent) capacity (EIA, 2019). Multiple
factors contribute to this trend.
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 almost all plants that retired in
2015 were more than 40 years old (Kolstad, 2017). Mills el al. (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 any 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 US as of 2021 is 45 years (EIA, 202 lg)
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). In 2021, EIA reported that coal
generation increased for the first time since 2014. However, EIA predicted that coal-fired generation in
the US would decline in 2022 by 5 percent due to more predicted retirements and lower natural gas prices
in 2022 (EIA, 2021b). In addition, 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 have resulted in increased energy prices. While coal is now cost-competitive with
natural gas, leading to recent increases in coal-fired generation, analysts believe this impact will be
temporary (The White House, 2022; Wilson, 2022).
Knittel el al. (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
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generation capacity has been replaced or converted to natural gas-fired generation since 2007 (EIA,
202 lh).
Changes in electricity generation have had impacts in fuel markets. Coal consumption in the electric
power industry has declined by about 40 percent between 2005 and 2017, whereas natural gas
consumption has increased by about 24 percent in the same time period, resulting in natural gas
consumption doubling coal consumption in 2017 (EIA, 2018c). In 2020, EIA reported that the number of
producing coal mines in the US (551 in 2020) dropped 62 percent since the most recent peak in 2008, an
18 percent average annual decrease. EIA reported that this reduction in producing coal mines reflects
recent reductions in investments in the coal industry and declining international and domestic decline for
coal (EIA, 202If). In 2022, EIA reported that natural gas consumption totaled 31.3 quadrillion British
thermal units (quads) and that coal consumption totaled 10.5 quads (EIA, 2022b). Market conditions have
also negatively affected nuclear-powered generation, though this proposed rule has no effect on the
nuclear-powered sector, except as it affects relative prices through its impacts on coal-fired generation
(EIA, 2022f).
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 in the shift
away from coal for electricity generation. Coglianese el al. (2020) found that the decrease 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
3 Compliance Costs
In developing the proposed rule, EPA assessed the costs and economic impacts for four regulatory options
summarized in Table 1-1. The options are labeled Option 1 through Option 4 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 proposed BAT limitations and pretreatment standards are based,17
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.18 EPA determined
that state and federal governments would not incur significant incremental administrative costs.19
EPA applied the same methodology used to analyze the 2015 and 2020 rules to calculate industry-level
annualized compliance costs. See Chapter 3 of the respective RIA documents for details (U.S. EPA, 2015,
2020b).
The TDD describes the control technologies and their respective wastewater treatment performance in
greater detail (U.S. EPA, 2023e). The TDD also describes how EPA estimated plant-specific capital and
operation and maintenance (O&M) costs for five technologies, 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 EPA is proposing in this action.
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.
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, accounting for any planned unit retirements or units
ceasing the combustion of coal. This schedule supports analysis of the timing of compliance costs
and benefits for analyses discussed in this document and in the BCA.
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.
The regulatory options would apply only to existing sources, with new sources continuing to be subject to the New
Source Performance Standards (NSPS) and Pretreatment Standards for New Sources (PSNS) promulgated in the 2015
rule.
EPA estimates that the proposed 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, including related to
additional requirements for permitting authorities to use BPJ in making BA purge water volume and technology
determinations.
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4. Estimating total industry costs for all plants in the steam electric universe for each of the
regulatory options.
EPA reports costs in 2021 dollars and discounts the costs to 2024.
3.1.1 Plant-Specific Costs Approach
As detailed in the TDD, EPA developed costs for steam electric power plants to implement treatment
technologies or process changes to control the wastestreams addressed by the regulatory options (i.e.. BA
transport water, FGD wastewater, and CRL).
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 proposed 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
wastewater or that employ technologies which would already meet the given limitations or standards do
not incur incremental costs under the regulatory options.
3.1.2 Plant-Level Costs
Following the approach used for the analysis of the 2015 and 2020 rules (U.S. EPA, 2015, 2020b), EPA
estimated compliance costs for all existing steam electric power plants, estimated to be a total 871 plants
for the point source category overall. EPA assessed that only a fraction of the universe of steam electric
power plants — 163 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: 69 plants under option 1, 80 plants under
option 2, 93 plants under option 3, and 92 plants under option 4.20 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 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.
• 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
The number of plants getting costs under Option 3 is greater than under Option 4 due to estimated one-time costs under
Option 3 (and Option 2) associated with early adopters or boilers permanently ceasing the combustion of coal by 2032.
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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, 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, 2023e).
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).21
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.
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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 proposed 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 and 2020 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.22
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
to correspond to the retirement date. In these cases, the plant would incur no incremental costs to comply
with the proposed 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 1
through 4:
• EPA estimated compliance costs (including zero costs) for each of the 122 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.
For the purpose of the analysis, EPA assigned an estimated compliance year to each of the 122 steam electric power
plants analyzed for the proposed rule based on each plant's estimated NPDES permit renewal year and, similar to the
approach used for the 2015 and 2020 rules, 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.
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• 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 2021 dollars,
using the Construction Cost Index (CCI) from McGraw Hill Construction (2020), the
Employment Cost Index (ECI) published by the Bureau of Labor Statistics (BLS) (2020), and the
Gross Domestic Product (GDP) deflator index published by the U.S. Bureau of Economic
Analysis (BEA) (2022).23
• EPA discounted all cost values to 2024, using a rate of 7 percent.24
• 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 7 percent:24
- Capital costs of each compliance technology: 20 years
- Initial one-time costs: 20 years25
- 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
Specifically, EPA brought all compliance costs to an estimated technology implementation year using the CCI from
McGraw Hill Construction (2020) or the ECI from the Bureau of Labor Statistics (2020), 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 2021 dollars, the Agency deflated the nominal
dollar values to 2021 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 2021.
The rate of 7 percent is used in the cost impact analysis as an estimate of the private opportunity cost of capital. For the
social cost analysis presented in Chapter 12 of the BCA, EPA uses both 3 percent and 7 percent discount rates. The 3
percent discount rate reflects society's valuation of differences in the timing of consumption; the 7 percent discount
rate reflects the opportunity cost of capital to society. In Circular A-4, the Office of Management and Budget (OMB)
recommends that 3 percent be used when a regulation affects private consumption, and 7 percent in evaluating a
regulation that will mainly displace or alter the use of capital in the private sector (U.S. OMB, 2003; updated 2009).
The same discount rates are used for both benefits and costs in the BCA.
EPA annualized these non-equipment outlays over 20 years to match the estimated performance life of compliance
technology components.
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analysis because some regulators may allow utilities to recover the value of undepreciated assets in their
rate base on a case-by-case basis.
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.26 For this adjustment, EPA used
State corporate rates from the Federation of Tax Administrators (2019) combined with a 21 percent
federal corporate tax rate.27 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
(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.28
3.1.5 Voluntary Incentive Program
As described in the 2020 rule, under the VIP component of regulatory options 1 to 4, 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 the baseline (i.e.. to comply with the 2020 rule) incur zero FGD wastewater treatment
costs in this proposed rule.
3.2 Key Findings for Regulatory Options
3.2.1 Estimated Industry-level Total Compliance Costs
Table 3-1 presents compliance cost estimates for the regulatory options and Table 3-2 shows the breakout
of total compliance costs for each option by wastestream.
EPA estimates that, on a pre-tax basis, steam electric power plants would incur annualized costs of
meeting the regulatory options ranging from $102 million under Option 1 to $241 million under Option 4.
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: Economic Impact Screening Analyses
for further discussion of these determinations.
This federal tax rate reflects the Tax Cuts and Jobs Act of 2017 which changed the top corporate tax rate from 35
percent to one flat rate of 21 percent after January 1,2018.
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.
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On an after-tax basis, the total compliance costs range from $81 million under Option 1 to $190 million
under Option 4. The proposed rule (Option 3) has estimated pre-tax costs of $230 million and after-tax
costs of $ 181 million. Across the options, slightly over half of the annualized costs (53 to 60 percent)
consists of annualized capital costs.
Table 3-1: Estimated Total Annualized Compliance Costs (in millions, 2021$, at 2024)
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Regulatory Option
Capital
Total O&M
Total
Capital
Total O&M
Total
Technology
Technology
Option 1
$61
$42
$102
00
^1-
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m
m
¦uy
1
00
¦uy
Option 2
$104
$85
$189
m
00
¦uy
$66
$149
Option 3
$123
$108
$230
$97
00
¦uy
$181
Option 4
$128
$114
$241
$101
$89
$190
Source: U.S. EPA Analysis, 2022.
All four regulatory options result in incremental annualized costs for the BA transport water wastestream,
with the costs highest under Option 4 ($36 million after-tax). Three of the four regulatory options also
result in incremental annualized costs for FGD wastewater, with the costs again highest under Option 4
($75 million after-tax). The costs for CRL treatment are the same across the four regulatory options
($79 million after-tax).
Table 3-2: Estimated Total Annualized Compliance Costs, by Wastestream (in millions, 2021$, at
2024)
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Regulatory
Option
BA
Transport
Water
FGD
Wastewater
CRL
Net Total
Costs
BA
Transport
Water
FGD
Wastewater
CRL
Net Total
Costs
Option 1
$3
$0
$99
$102
$2
$0
$79
$81
Option 2
$3
$87
$99
$189
$2
$68
$79
$149
Option 3
$45
$87
$99
$230
LO
m
¦uy
00
ID
¦uy
$79
$181
Option 4
$46
$96
$99
$241
$36
$75
$79
$190
Source: U.S. EPA Analysis, 2022.
3.2.2 Estimated Regional Distribution of Incremental Compliance Costs
Table 3-3 reports the estimated annualized total costs for each regulatory option at the level of a North
American Electric Reliability Corporation (NERC) region.29 As explained in Chapter 2 (Overview of the
Steam Electric Industry), because of differences in operating characteristics of steam electric power plants
across NERC regions, as well as differences in the economic and electric power system regulatory
circumstances of the NERC regions themselves, the regulatory options may affect costs, profitability,
electricity prices, and other impact measures differently across NERC regions. Overall, annualized after-
tax compliance costs are highest in the SERC and RF regions for all regulatory options (1 through 4) as
shown in Table 3-3.
No steam electric power plant is estimated to incur compliance costs in the ASCC and HICC NERC regions and these
two regions are therefore omitted from the presentation of results.
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Table 3-3:
2024)
Estimated Annualized Total Compliance Costs by NERC Region (in millions, 2021$, at
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 1
MRO
$10
$0
$5
$15
$8
$0
$4
$13
NPCC
$4
$0
$3
$7
$3
$0
$2
$5
RF
$24
$0
$20
$44
$18
$0
$15
$33
SERC
$19
$0
$12
$31
$17
$0
$10
$27
TRE
$2
$0
$2
$4
$2
$0
$1
$3
WECC
$1
$0
$0
$1
$1
$0
$0
$1
Total
$61
$0
$42
$102
$48
$0
$33
$81
Option 2
MRO
$13
$0
$8
$22
$11
$0
$7
$18
NPCC
$4
$0
$3
$7
$3
$0
$2
$5
RF
$44
$0
$39
$83
$34
$0
$30
$64
SERC
$39
$0
$32
$72
$32
$0
$26
$57
TRE
$3
$0
$2
$5
$3
$0
$2
$4
WECC
$1
$0
$0
$1
$1
$0
$0
$1
Total
$104
$0
$85
$189
$83
$0
$66
$149
Option 3
MRO
$17
$0
1
1
¦uy
$28
$14
$0
$9
$23
NPCC
$4
$0
$3
$7
$3
$0
$2
$5
RF
$51
$0
$48
$99
$39
$0
$36
$76
SERC
$44
$0
00
m
¦uy
1
00
¦uy
LO
m
¦uy
$0
o
m
¦uy
$66
TRE
$4
$0
$3
$7
$3
$0
$3
$6
WECC
$3
$0
$4
$7
$2
$0
$3
$5
Total
$123
$0
$108
$230
$97
$0
$84
$181
Option 4
MRO
$17
$0
$11
$28
$14
$0
$9
$23
NPCC
$4
$0
$3
$7
$3
$0
$2
$5
RF
$52
$0
$49
$101
$40
$0
$37
$77
SERC
$48
$0
$43
$90
$39
$0
$34
$73
TRE
$4
$0
$3
$7
$3
$0
$3
$6
WECC
$3
$0
$4
$7
$2
$0
$3
$5
Total
$128
$0
$114
$241
$101
$0
$89
$190
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, 2022.
3.3 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, 2023e). To the extent that actual unit
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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 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.
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4: Screening-Level Economic Impacts
4 Cost and Economic Impact Screening Analyses
4.1 Analysis Overview
Following the same methodology used for the 2015 and 2020 rule analyses (U.S. EPA, 2015, 2020b),
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
proposed 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.30
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
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.31
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 2025 and 2029. The Agency used the
same approach from the 2015 rule and 2020 rule to update the analysis for the proposed regulatory
options 1 through 4.
EPA updated the approach used for the 2015 and 2020 rules 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.32 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 2015 to 2020 from the EIA-923 database by 6-year average electricity prices over the period 2015
to 2020 from the EIA-861 database (EIA, 2021d, 2021e).33'34 EPA estimated compliance costs in 2021
dollars. To provide cost and revenue comparisons on a consistent analysis-year (2024) and dollar-year
(2021) 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, 2020b), 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
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.
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.
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.
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.
EPA's first step in calculating plant revenue was to restate electricity prices in 2021 dollars using the Gross Domestic
Product (GDP) deflator index published by the U.S. Bureau of Economic Analysis (BEA) (2022). These individual
yearly values were then averaged and brought forward to 2024 using electricity price projections from the Annual
Energy Outlook publication for 2021 (AEO2021) (EIA, 2021). AEO2021 contains projections and analysis of U.S.
energy supply, demand, and prices through 2050. AEO2021 electricity price projections are in constant dollars;
therefore, these adjustments yield 2024 revenue values in dollars of the year 2021 (converted from 2020 dollars to 2021
dollars).
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4.2.2 Key Findings for Regulatory Options
EPA estimates that the number of steam electric power plants that would not experience costs exceeding
one percent of revenue, including those estimated to incur zero compliance costs, is 866 for Option 1, 858
for Option 2, and 852 for Options 3 and 4. Table 4-1 presents the 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. However, additional plants would experience
costs greater than one percent of revenue (and less than three percent of revenue) with regulatory Options
3 and 4 compared to Options 1 and 2. Three plants experience costs above three percent of revenue under
all options. For details on cost-to-revenue results for small entities, see Section 8.2.
Table 4-1: Plant-Level Cost-to-Revenue Analysis Results by Owner Type and Regulatory Option
Owner Type
Total Number
of Plants3
Number of Plants with a Ratio of
0%a'b
*0 and <1%
>1 and 3%
>3%
Option 1
Cooperative
59
54
5
0
0
Federal
23
20
3
0
0
Investor-owned
328
293
33
1
1
Municipality
111
105
3
1
2
Nonutility
313
296
16
1
0
Political Subdivision
29
28
1
0
0
State
8
7
1
0
0
Total
871
803
62
3
3
Option 2
Cooperative
59
53
5
1
0
Federal
23
20
3
0
0
Investor-owned
328
286
35
6
1
Municipality
111
103
4
2
2
Nonutility
313
295
17
1
0
Political Subdivision
29
28
1
0
0
State
8
7
1
0
0
Total
871
792
66
10
3
Option 3
Cooperative
59
52
5
2
0
Federal
23
20
3
0
0
Investor-owned
328
279
40
8
1
Municipality
111
101
4
4
2
Nonutility
313
294
18
1
0
Political Subdivision
29
27
1
1
0
State
8
6
2
0
0
Total
871
779
73
16
3
Option 4
Cooperative
59
52
5
2
0
Federal
23
20
3
0
0
Investor-owned
328
279
40
8
1
Municipality
111
101
4
4
2
Nonutility
313
294
18
1
0
Political Subdivision
29
27
1
1
0
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Table 4-1: Plant-Level Cost-to-Revenue Analysis Results by Owner Type and Regulatory Option
Owner Type
Total Number
of Plants3
Number of Plants with a Ratio of
0%a'b
#0 and <1%
>1 and 3%
>3%
State
8
7
1
0
0
Total
871
780
72
16
3
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, 2022.
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
2020.
• 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.
• EPA assumes that owners of plants that retire or repower during the period of analysis, but after
installing equipment to comply with the proposed 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 rule analyses (U.S. EPA,
2015, 2020b), 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.35,36 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.
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.
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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4.3.1 Analysis Approach and Data Inputs
Following the approach used in the 2015 and 2020 rule analyses (U.S. EPA, 2015, 2020b), 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 and 2020 rule analyses (U.S. EPA, 2015, 2020b; 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
entity. The sections below highlight updates to incorporate more recent data than were used for the 2015
and 2020 rules.
Determining the Parent Entity
EPA used information from the 2020 EIA-860 database which provides owners and the share of
ownership in electric generating units (EIA, 202 Id) 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.
Determining 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 2018-2020 average revenue values from the
EIA-861 database (EIA, 2021a).
EPA updated entity revenue values to 2021 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
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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.
Estimating 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 871
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 4-2 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. The
table shows the number of entities that incur costs in four ranges: no cost, 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.
EPA estimates that between 229 and 427 parent entities own steam electric power plants based on the
range indicated by Case 1 and Case 2, respectively. Under Option 3 in Case 1, 225 parent entities are
estimated to incur no costs or costs less than one percent of revenue, and in Case 2, this number is 421
parent entities. When examining the number of parent entities below the same thresholds under the other
regulatory options, as shown in Table 4-2, most entities stay within the same threshold.37 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.
The results include entities that own only steam electric power plants that already meet discharge requirements for the
wastestreams addressed by a given regulatory option and are therefore not estimated to incur any compliance
technology costs.
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Table 4-2: Entity-Level Cost-to-Revenue Analysis Results
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 1
Cooperative
21
16
5
0
0
0
32
27
5
0
0
0
Federal
3
2
1
0
0
0
10
9
1
0
0
0
Investor-
owned
59
38
21
0
0
0
102
62
40
0
0
0
Municipality
51
46
4
1
0
0
87
80
4
1
0
2
Nonutility
82
69
12
0
1
0
167
144
22
0
1
0
Other"
8
7
1
0
0
0
19
18
1
0
0
0
State
5
4
1
0
0
0
10
9
1
0
0
0
Total
229
182
45
1
1
0
427
349
74
1
1
2
Option 2
Cooperative
21
15
5
1
0
0
32
26
5
1
0
0
Federal
3
2
1
0
0
0
10
9
1
0
0
0
Investor-
owned
59
36
23
0
0
0
102
60
42
0
0
0
Municipality
51
44
6
1
0
0
87
77
7
1
0
2
Nonutility
82
69
12
0
1
0
167
144
22
0
1
0
Other"
8
7
1
0
0
0
19
18
1
0
0
0
State
5
4
1
0
0
0
10
9
1
0
0
0
Total
229
177
49
2
1
0
427
343
79
2
1
2
Option 3
Cooperative
21
15
5
1
0
0
32
26
5
1
0
0
Federal
3
2
1
0
0
0
10
9
1
0
0
0
Investor-
owned
59
31
28
0
0
0
102
52
50
0
0
0
Municipality
51
42
7
2
0
0
87
75
8
2
0
2
Nonutility
82
68
13
0
1
0
167
142
24
0
1
0
Other"
8
6
2
0
0
0
19
17
2
0
0
0
State
5
4
1
0
0
0
10
9
1
0
0
0
Total
229
168
57
3
1
0
427
330
91
3
1
2
Option 4
Cooperative
21
15
5
1
0
0
32
26
5
1
0
0
Federal
3
2
1
0
0
0
10
9
1
0
0
0
Investor-
owned
59
32
27
0
0
0
102
53
49
0
0
0
Municipality
51
42
7
2
0
0
87
75
8
2
0
2
Nonutility
82
68
13
0
1
0
167
142
24
0
1
0
Other"
8
6
2
0
0
0
19
17
2
0
0
0
State
5
4
1
0
0
0
10
9
1
0
0
0
Total
229
169
56
3
1
0
427
331
90
3
1
2
a. These entities own only plants that already meet discharge requirements
option and are therefore not estimated to incur any compliance technology
for the wastestreams addressed by a given regulatory
costs.
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Table 4-2: Entity-Level Cost-to-Revenue Analysis Results
Entity Type
Case 1: Lower bound estimate of change in number
of firms owning plants that face requirements
under the regulatory analysis
Total
Number
of Entities
Number of Entities with a Ratio of
0%a
*0 and
<1%
>1 and
3%
>3%
Unknown
Case 2: Upper bound estimate of change in
number of firms owning plants that face
requirements under the regulatory analysis
Total
Number
of
Entities
Number of Entities with a Ratio of
0%a
*0 and
<1%
>1 and
3%
>3%
Unknown
b. Other political subdivision.
Source: U.S. EPA Analysis, 2022.
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:
• The entity-level revenue values obtained from the corporate and financial websites or EIA
databases are for 2018 through 2020. 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 proposed 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 Proposed 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 proposed rule, EPA used the latest version of this analytic system: Integrated Planning Model Version
6 (IPM v6) Summer 2022 Reference Case (U.S. EPA, 2018a, 2023b).38 EPA ran IPM for Option 3 to
evaluate the impacts of the proposed rule.
The market model analysis is a more comprehensive analysis compared to the screening-level analyses
discussed in Chapter 4, Cost and Economic Impact Screening Analyses', it is meant to inform EPA's
assessment of whether the proposed rule would result in any capacity retirements (full or partial plant
closures)39 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 Energy's Annual Energy Outlook 2021 (AEO2021), 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.
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 (2018a), IPM generates
38 For more information on IPM, see https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling.
39 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. EPA, 2015).
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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 2021 (AEO2021). 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 to electricity demand (U.S. EPA,
2018a).
The final difference between EPA's electricity market optimization model analysis and the screening-
level analyses in Chapter 4, Cost and Economic Impact Screening Analyses 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 proposed 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 proposed rule, EPA started from an electricity
market "reference case" (Summer 2022) that includes market-level impacts of the 2020 ELG, Cross-State
Air Pollution Rule (CSAPR and CSAPR Update), Mercury 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, 2018a,
2023b). 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,
and the 45Q tax credit for carbon dioxide sequestration (U.S. EPA, 2018a, 2023b).
In analyzing the effect of Option 3 using IPM v6, EPA specified incremental capital costs40 and fixed and
variable O&M costs that are estimated to be incurred by steam electric power plants and generating units
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 (the
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to comply with the proposed rule requirements for BA transport water, FGD wastewater, and CRL (in the
IPM documentation, these costs are referred to as "FOM and VOM adders" and correspond to fixed
O&M [FOM] and variable O&M [VOM]). Compliance costs were developed using the same approach
described in Chapter 3, based on the technology options and compliance deadlines for this proposed 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 for the 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 proposed rule.
• Section 5.2 provides the findings from the market model analysis.
• Section 5.3 discusses the effects of the proposed 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 proposed rule, EPA compared the policy run (Option 3) 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 (2018a, 2023b), 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 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
weighted average after tax cost of capital, 4.25 percent; see Chapter 10 in the IPM documentation [U.S. EPA, 2018a]
for more information on IPM's financial discount rate).
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Table 5-1: IPM Run Years
Run Year
Years Represented
2055
2053-2059
Source: U.S. EPA, 2018a.
To assess the effect of the proposed 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 2030 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 proposed rule specifications considered for this analysis, this steady state period is estimated
to begin in the last year of the technology implementation window, i. e., 2029, and continue into the
future. Because the model run year 2030 captures decisions made through the end of 2031 by which time
all plants will have achieved the revised limitations and standards, EPA determined that 2030 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,41 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 Proposed 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 93 steam electric power plants may incur non-zero
compliance costs under proposed Option 3, based on the costing methodologies described in the TDD
(U.S. EPA, 2023e) and timing of any announced retirements and repowerings relative to compliance
deadlines.
EPA input the proposed rule capital, annual fixed O&M (FOM), and annual variable O&M (VOM) costs,
as well as costs incurred on a non-annual, periodic basis (5-year, 6-year, 10-year) into IPM as FOM and
VOM cost adders.42 IPM modelers calculated the net present value of annualized costs using IPM's
conventional framework for recognizing costs incurred over time, by assigning to each cost the same
technology implementation years discussed in Chapter 3.43 Annualized capital cost and FOM and VOM
cost adders are represented in IPM as incremental costs specific to individual model plants.
Early retirement of generating units reflects reductions in generating capacity relative to the baseline and relative to any
scheduled retirements.
In the IPM documentation, the compliance costs are referred to as "FOM and VOM cost adders" and correspond to
fixed O&M [FOM] and variable O&M [VOM],
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
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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 proposed Option 3.
5.1.3 Key Outputs of the Market Model Analysis Used in Assessing the Effects of the Proposed 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 3),
focusing on metrics that quantify projected changes in capacity (including early retirements and new
capacity), generation, production costs, electricity prices, and emissions. See U.S. EPA (2018a) for
descriptions of the IPM variables.
EPA compared national-level outputs for IPM run years (2028, 2030, 2035, 2040, 2045, 2050, and 2055).
EPA then looked at changes in more detailed regional and plant-level outputs for the 2030 run year.
Comparison of these outputs for the baseline and proposed Option 3 provides insight into the incremental
effect of the proposed rule on steam electric power plants and the broader electric power markets.44
5.2 Findings from the Market Model Analysis
The impacts of the proposed rule are assessed as the difference between key economic and operational
impact metrics that compare the results for Option 3 to the baseline. This section presents two sets of
analysis:
• Analysis of national-level impacts: EPA compared baseline and policy IPM results reported for a
series of run years to provide insight on the direction and magnitude of market-level changes
attributable to the proposed rule over time.
• Analysis of long-term regulatory impacts: As discussed earlier, to assess the long-term impact of
the proposed rule, EPA compared baseline and Option 3 IPM results reported for 2030. These
results provide insight on the effect of the proposed rule both for the entire electricity market and
for steam electric power plants specifically.
5.2.1 National-level Analysis Results for Model Years 2028-2055
Table 5-2 shows baseline values of total costs to electric power plants, 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 proposed rule). The baseline projections show a decline in total
coal generation capacity during the period (from 131.7 GW in 2028 to 41.7 GW in 2055; 68 percent
reduction) and nuclear generation capacity (from 86.8 GW in 2028 to 28.2 GW in 2055; 67 percent
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. EPA, 2018a, page 2-7).
IPM output also includes total fuel usage, which is not part of the analysis discussed in this Chapter.
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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 3 relative to the baseline (negative values represent decreases relative to the
baseline). Note that while the table includes projections for the 2050 and 2055 run year, the represented
period (2048-2059) includes years 2050-2059 outside of the analysis period EPA used in its analysis of
the social costs and benefits, which covers 2024 through 2049.
Table 5-2: Baseline Projections, 2028-2055
Economic Measures
Baseline
2028
2030
2035
2040
2045
2050
2055
Total Costs
Total Costs (million
2021$)
$145,785
$149,177
$169,110
$184,626
$197,126
$208,788
$223,291
Prices
National Wholesale
Electricity Price
(mills/kWh)
41.83
39.30
39.24
38.70
38.79
35.93
36.50
Total Capacity (Cumulative GW)
Renewables3
395.5
465.0
588.2
723.7
867.9
1,077.0
1,155.5
Coal
131.7
111.8
88.3
70.4
62.2
42.7
41.7
Nuclear
86.8
78.1
60.3
58.7
55.7
28.2
28.2
Natural Gas
474.1
478.0
516.9
575.3
638.8
753.2
816.1
Oil/Gas Steam
66.0
64.8
58.6
57.5
57.5
54.9
53.3
Other0
31.8
39.5
55.4
65.3
74.0
88.9
93.9
Grand Total
1,185.9
1,237.1
1,367.8
1,550.9
1,756.2
2,044.9
2,188.8
New Capacity (Cumulative GW)b
Renewables3
133.1
203.9
327.1
462.6
606.9
816.0
894.5
Coal
0.0
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
0.0
Natural Gas
57.9
62.7
102.3
162.0
225.4
353.9
417.2
Other0
24.0
31.6
47.5
57.5
66.1
81.1
86.1
Grand Total
215.0
298.2
477.0
682.0
898.4
1250.9
1397.7
Retirements (Cumulative GW)
Combined Cycle
1.0
1.0
1.5
2.1
2.1
11.1
11.1
Coal
26.3
45.9
67.6
85.5
93.7
113.2
114.2
Combustion Turbine
0.0
0.3
0.5
1.1
1.1
6.2
6.6
Nuclear
6.6
15.4
33.1
34.8
37.7
65.2
65.2
Oil/Gas
1.5
2.7
10.7
11.8
11.8
14.4
16.0
Other0
2.0
3.3
3.3
3.4
3.4
3.4
3.4
Grand Total
37.4
68.5
116.7
138.6
149.8
213.5
216.4
Generation Mix (thousand GWh)
Renewables3
1,175.9
1,403.9
1,812.7
2,319.0
2,830.5
3,530.3
3,806.8
Coal
634.4
557.9
469.7
336.7
280.3
166.9
170.9
Nuclear
694.6
628.5
486.5
473.8
450.3
228.9
228.9
Natural Gas
1,764.2
1,780.1
1,886.3
1,828.5
1,705.7
1,672.1
1,703.2
Oil/Gas Steam
37.6
35.5
20.9
9.7
5.6
5.4
7.5
Other0
65.2
75.1
97.7
111.8
124.5
145.2
153.2
Grand Total
4,371.8
4,480.9
4,773.8
5,079.4
5,396.9
5,748.9
6,070.5
a. Renewables include hydropower and non-hydropower renewables.
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Table 5-2: Baseline Projections, 2028-2055
Economic Measures
Baseline
2028
2030
2035
2040
2045
2050
2055
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, 2022
Table 5-3: Incremental National Impact of Proposed Option 3 Relative to Baseline, 2028-2055
Economic Measures
Option 3 Changes Relative to Baseline
2028
2030
2035
2040
2045
2050
2055
Total Costs
Total Costs (million
2021$)
$364
$168
$249
ID
00
¦uy
00
¦uy
$22
$28
Prices
National Wholesale
Electricity Price
(mills/kWh)
0.03
0.02
0.08
0.00
0.02
0.00
0.00
Total Capacity (Cumulative GW)
Renewables3
-0.1
-0.1
1.0
0.5
1.6
0.1
-0.1
Coal
-0.1
-0.3
-1.7
-1.2
-1.8
-0.7
-0.7
Nuclear
0.0
0.2
0.6
0.6
0.6
0.2
0.2
Natural Gas
0.3
0.0
0.5
0.2
0.5
0.3
0.4
Oil/Gas Steam
0.0
0.0
0.4
0.4
0.4
0.1
0.0
Other0
0.0
0.0
0.1
0.0
0.1
0.0
0.0
Grand Total
0.0
-0.1
0.9
0.5
1.5
0.0
-0.1
New Capacity (Cumulative GW)b
Renewables3
-0.1
-0.1
1.0
0.5
1.6
0.1
-0.1
Coal
0.0
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
0.0
Natural Gas
0.3
0.0
0.5
0.2
0.5
0.3
0.4
Other0
0.0
0.0
0.1
0.0
0.1
0.0
0.0
Grand Total
0.1
-0.1
1.6
0.7
2.2
0.4
0.4
Retirements (GW)
Combined Cycle
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Coal
0.1
0.3
1.7
1.2
1.8
0.7
0.7
Combustion Turbine
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Nuclear
0.0
-0.2
-0.6
-0.6
-0.6
-0.2
-0.2
Oil/Gas
0.0
0.0
-0.4
-0.4
-0.4
-0.1
0.0
Other0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Grand Total
0.1
0.0
0.7
0.2
0.8
0.3
0.5
Generation Mix (thousand GWh)
Renewables3
-0.1
0.1
4.4
1.8
5.8
0.4
-0.2
Coal
-1.2
-6.3
-9.7
-6.6
-11.5
-3.1
-2.9
Nuclear
0.0
1.7
4.6
4.6
4.7
2.1
2.1
Natural Gas
1.4
4.7
1.2
0.4
1.4
0.2
1.2
Oil/Gas Steam
-0.1
-0.1
-0.1
-0.1
-0.3
0.1
-0.2
Other0
0.0
0.7
0.8
1.1
1.2
1.2
1.2
Grand Total
0.1
0.3
0.5
0.0
0.2
-0.4
0.0
a. Renewables include hydropower and non-hydropower renewables.
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Table 5-3: Incremental National Impact of Proposed Option 3 Relative to Baseline, 2028-2055
Economic Measures
Option 3 Changes Relative to Baseline
2028
2030
2035
2040
2045
2050
2055
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, 2022
5.2.1.1 Findings for the Proposed Rule
Under proposed Option 3, total costs to electric power plants are projected to be greater than the baseline
from 2028 to 2055. The increases in costs are greatest in the beginning of the modeling period (e.g., by
$364 million in 2028), which is consistent with the proposed timing of steam electric ELG
implementation. IPM projects small increases in wholesale electricity prices over the modeling period.
The increases are 0.03 mills per kWh in 2028 and 0.001 mills per kWh in 2055, relative to baseline prices
of 40 and 35 mills/kWh, respectively.
Looking at results for total capacity by energy source, coal capacity is estimated to decrease for all years
from 2028 to 2055, adding to the already significant reductions projected in the baseline. Meanwhile,
smaller decreases in capacity from nuclear and oil/gas steam, and greater increases in natural gas capacity
are estimated to occur from 2028 to 2055. Capacity from renewables is estimated to increase overall
during the modeling period, but by smaller increments in 2028, 2030, and 2055 when compared to the
increase projected in the baseline. Natural gas capacity is estimated to increase by 0.3 to 0.5 GW while
nuclear and oil/gas steam capacity are estimated to increase by 0.2 to 0.6 GW and 0.1 to 0.4, respectively.
Coal retirements are estimated for all years, ranging between 0.1 to 1.8 GW of the 26.3 to 114.2 GW
estimated to retire in the baseline. This accounts for all of the incremental retirements in the electric
market as a whole (for Option 3 relative to the baseline), which range between 0.1 to 0.8 GW.
Lastly, examining results for generation by energy source, generation from coal is estimated to decrease
for all years from 2028 to 2055 by 1.2 to 11.5 thousand GWh. These changes are offset in part by an
increase in natural gas generation (0.2 to 4.7 thousand GWh increase), nuclear generation (1.7 to 4.7
thousand GWh increase), and generation by renewables, which increases between 2030 and 2050 by 0.1
to 5.8 thousand GWh.
5.2.2 Detailed Analysis Results for Model Year 2030
In the following results which reflect conditions in the period of 2029 through 2031, all plants are
estimated to meet the revised BAT limits and pretreatment standards associated with the proposed rule
(Option 3). For this more detailed analysis, following the approach used for the 2015 and 2020 rules (U.S.
EPA, 2015, 2020b), 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).
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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 proposed rule. The Market Model Analysis may project
partial (i.e., unit) or full plant early retirements (closures) for the proposed 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. At the national level, the demand for electricity does not
change between the baseline and the proposed rule (generation within the regions is allowed to
vary) because meeting demand is an exogenous constraint imposed by the model. However,
demand for electricity does vary across the modeling horizon according to the model's underlying
electricity demand growth assumptions.
• Changes in costs: This measure considers changes in the overall cost of generating electricity,
including fuel costs, variable and fixed O&M costs, and capital costs. These costs are not limited
to steam electric generating units or to compliance costs of the proposed 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
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generating unit is dispatched. This measure presents similar information to total fuel and variable
O&M costs, but normalized for changes in generation.
• Changes in CO 2, NOx, SO 2, 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 proposed 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 proposed rule (see Chapter 8 in the BCA [U.S. EPA, 2023a]).
Table 5-4 summarizes IPM results for the proposed 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 proposed rule as compared to the baseline
and the generation mix.
Table 5-4: Impact of Proposed Rule on National and Regional Markets in the Year 2030
Economic Measures
Option 3
(all dollar values in 2021$)
Baseline Value
Value
Difference
% Change
National Totals
Total Domestic Capacity (GW)
1,310
1,310
-0.1
0.0%
Existing
1 1 °'°
0.0%
New Additions
1 1 -0.1
0.0%
Early Retirements
| 0.0
0.0%
Wholesale Price ($/MWh)
$39.30
$39.32
$0.02
0.1%
Generation (TWh)
4,581
4,581
0.3
0.0%
Costs ($Millions)
$149,601
$149,769
$168
0.1%
Fuel Cost
$54,429
$54,411
00
1
¦uy
1
0.0%
Variable O&M
$8,644
$8,675
1
m
¦uy
0.4%
Fixed O&M
$56,321
$56,471
$150
0.3%
Capital Cost
$30,207
$30,212
$5
0.0%
Average Variable Production Cost ($/MWh)
$13.77
$13.77
$0.00
0.0%
C02 Emissions (Million MetricTons)
1,304
1,299
-4.4
-0.3%
Mercury Emissions (Tons)
3
3
0.0
-0.5%
NOx Emissions (Million Tons)
1
1
0.0
-0.6%
S02 Emissions (Million Tons)
1
1
0.0
-0.4%
HCL Emissions (Million Tons)
0
0
0.0
-1.0%
Midwest Reliability Organization (MRO)
Total Domestic Capacity (GW)
163
163
0.0
0.0%
Existing
0.0
0.0%
New Additions
0.1
0.0%
Early Retirements
0.0
0.0%
Wholesale Price ($/MWh)
$34.32
$34.33
$0.01
0.0%
Generation (TWh)
541
540
0
-0.1%
Costs ($Millions)
$14,978
$14,988
O
1
¦uy
0.1%
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Table 5-4: Impact of Proposed Rule on National and Regional Markets in the Year 2030
Economic Measures
Option 3
(all dollar values in 2021$)
Baseline Value
Value
Difference
% Change
Fuel Cost
$4,462
$4,454
-$8
-0.2%
Variable O&M
$1,088
$1,088
$0
0.0%
Fixed O&M
$6,447
$6,459
$12
0.2%
Capital Cost
$2,982
$2,987
$5
0.2%
Average Variable Production Cost ($/MWh)
$10.27
$10.26
-$0.01
-0.1%
C02 Emissions (Million MetricTons)
177
176
-0.6
-0.3%
Mercury Emissions (Tons)
0
0
0.0
-0.3%
NOx Emissions (Million Tons)
0
0
0.0
-0.2%
S02 Emissions (Million Tons)
0
0
0.0
1.3%
HCL Emissions (Million Tons)
0
0
0.0
-0.7%
Northeast Power Coordinating Council (NPCC)
Total Domestic Capacity (GW)
102
102
0.0
0.0%
Existing
1 1 "01
-0.1%
New Additions
0.0
0.0%
Early Retirements
0.1%
Wholesale Price ($/MWh)
$39.48
$39.48
$0.00
0.0%
Generation (TWh)
285
286
1
0.2%
Costs ($Millions)
$10,491
$10,504
$13
0.1%
Fuel Cost
$2,675
$2,687
1
1
¦uy
0.4%
Variable O&M
$373
$374
$i
0.3%
Fixed O&M
$4,087
$4,086
-$i
0.0%
Capital Cost
$3,356
$3,357
$i
0.0%
Average Variable Production Cost ($/MWh)
$10.69
$10.71
$0.03
0.2%
C02 Emissions (Million MetricTons)
50
50
0.1
0.2%
Mercury Emissions (Tons)
0
0
0.0
-0.1%
NOx Emissions (Million Tons)
0
0
0.0
-1.8%
S02 Emissions (Million Tons)
0
0
0.0
-2.5%
HCL Emissions (Million Tons)
0
0
0.0
-0.4%
Reliability First Corporation (RF)
Total Domestic Capacity (GW)
245
245
-0.1
0.0%
Existing
1 1 °'2
0.1%
New Additions
-0.3
-0.1%
Early Retirements
1 1 -0.2
-0.1%
Wholesale Price ($/MWh)
$36.35
$36.35
$0.01
0.0%
Generation (TWh)
1,010
1,009
-1
-0.1%
Costs ($Millions)
$33,806
$33,869
$63
0.2%
Fuel Cost
$12,985
$12,953
-$31
-0.2%
Variable O&M
$2,179
$2,197
00
1
¦uy
0.8%
Fixed O&M
$13,075
$13,175
$100
0.8%
Capital Cost
$5,567
$5,543
-$24
-0.4%
Average Variable Production Cost ($/MWh)
$15.02
$15.02
$0.00
0.0%
C02 Emissions (Million MetricTons)
356
353
-2.3
-0.7%
Mercury Emissions (Tons)
1
1
0.0
-0.9%
NOx Emissions (Million Tons)
0
0
0.0
-0.9%
S02 Emissions (Million Tons)
0
0
0.0
-1.2%
HCL Emissions (Million Tons)
0
0
0.0
-1.0%
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Table 5-4: Impact of Proposed Rule on National and Regional Markets in the Year 2030
Economic Measures
Option 3
(all dollar values in 2021$)
Baseline Value
Value
Difference
% Change
Southeast Electric Reliability Council (SERC)
Total Domestic Capacity (GW)
346
346
0.0
0.0%
Existing
1 1 "°'2
0.0%
New Additions
0,2
0.1%
Early Retirements
1 1 0.2
0.0%
Wholesale Price ($/MWh)
$39.73
$39.80
$0.07
0.2%
Generation (TWh)
1,409
1,410
1
0.1%
Costs ($Millions)
$48,931
$49,001
$70
0.1%
Fuel Cost
$22,760
$22,768
$7
0.0%
Variable O&M
$2,890
$2,897
$7
0.2%
Fixed O&M
$17,662
$17,694
$32
0.2%
Capital Cost
$5,618
$5,642
$24
0.4%
Average Variable Production Cost ($/MWh)
$18.21
$18.20
$0.00
0.0%
C02 Emissions (Million MetricTons)
444
443
-1.6
-0.4%
Mercury Emissions (Tons)
1
1
0.0
-1.4%
NOx Emissions (Million Tons)
0
0
0.0
-0.8%
S02 Emissions (Million Tons)
0
0
0.0
-1.1%
HCL Emissions (Million Tons)
0
0
0.0
-2.5%
Texas Reliability Entity (TRE)
Total Domestic Capacity (GW)
132
132
0.0
0.0%
Existing
0.0
0.0%
New Additions
1
0.0
0.0%
Early Retirements
0.0
0.0%
Wholesale Price ($/MWh)
$31.74
$31.74
$0.00
0.0%
Generation (TWh)
440
440
0
0.0%
Costs ($Millions)
$12,879
$12,886
$7
0.1%
Fuel Cost
$4,474
$4,476
$3
0.1%
Variable O&M
$683
$684
$1
0.1%
Fixed O&M
$5,302
$5,306
$4
0.1%
Capital Cost
$2,420
$2,420
$0
0.0%
Average Variable Production Cost ($/MWh)
$11.72
$11.73
$0.00
0.0%
C02 Emissions (Million MetricTons)
119
119
0.1
0.1%
Mercury Emissions (Tons)
0
0
0.0
0.0%
NOx Emissions (Million Tons)
0
0
0.0
0.1%
S02 Emissions (Million Tons)
0
0
0.0
0.0%
HCL Emissions (Million Tons)
0
0
0.0
0.1%
Western Electricity Coordinating Council (WECC)
Total Domestic Capacity (GW)
321
321
0.0
0.0%
Existing
0.0
0.0%
New Additions
0.0
0.0%
Early Retirements
0.0
0.0%
Wholesale Price ($/MWh)
$48.58
$48.58
$0.00
0.0%
Generation (TWh)
897
897
0
0.0%
Costs ($Millions)
$28,516
$28,522
$6
0.0%
Fuel Cost
$7,073
$7,073
$0
0.0%
Variable O&M
$1,430
$1,434
$4
0.3%
Fixed O&M
$9,749
$9,751
$2
0.0%
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Table 5-4: Impact of Proposed Rule on National and Regional Markets in the Year 2030
Economic Measures
(all dollar values in 2021$)
Baseline Value
Option 3
Value
Difference
% Change
Capital Cost
$10,264
$10,264
-$1
0.0%
Average Variable Production Cost ($/MWh)
$9.48
$9.49
$0.00
0.0%
C02 Emissions (Million MetricTons)
158
158
0.0
0.0%
Mercury Emissions (Tons)
1
1
0.0
0.0%
NOx Emissions (Million Tons)
0
0
0.0
0.0%
S02 Emissions (Million Tons)
0
0
0.0
0.0%
HCL Emissions (Million Tons)
0
0
0.0
0.0%
a. Numbers may not add up due to rounding.
Source: U.S. EPA Analysis, 2022
5.2.2.1.1 Findings for Regulatory Option 3
As reported in Table 5-4, the Market Model Analysis indicates that the proposed 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 2030.
At the national level, total annual costs increase by an estimated $168 million (approximately 0.1 percent)
relative to the baseline. Total annual costs vary by region and are estimated to increase in all regions.
Total costs in the SERC region increase by the largest amount, $70 million (0.1 percent), followed by the
RF region with an increase of $63 million (0.2 percent); changes in estimated total annual costs in the
other regions range between $6 million (WECC) and $13 million (NPCC). 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 a decrease of approximately 0.1 GW in capacity, which
is less than 0.1 percent of total market capacity. Overall, the proposed 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 decrease is a result of a decrease in capacity in the RF region of 0.1 GW (less than 0.1 percent of
total market capacity in that region) due to greater reductions of new capacity additions that more than
offset avoided early retirements. Overall impacts on wholesale electricity prices are similarly minimal.
Wholesale electricity prices are estimated to increase in all NERC regions except for TRE. Price changes
in individual regions range from -$0,002 per MWh (less than 0.1 percent) in TRE to $0.07 per MWh (0.2
percent) in SERC. Finally, at the national level, total costs are estimated to increase by $0.02
(approximately 0.1 percent).
At the national level in the year 2030, there are decreases in emissions among all air pollutants modeled.
NOx emissions decrease by 0.6 percent; SO2 emissions decrease by 0.4 percent; CO2 emissions decrease
by 0.3 percent, mercury emissions decrease by 0.5 percent; and HCL emissions decrease by 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.45 Furthermore, emission increases modeled in some regions are transient; for example, IPM state-
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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level outputs shows pollutant emissions in Texas (part of the TRE NERC region) increasing in 2030,
relative to the baseline, but decreasing in 2035 through 2050.
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 2030 used above to analyze the impact on national and regional electricity markets; however, this
analysis considers the effect of the proposed 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 proposed 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 proposed 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.
The metrics of interest are largely the same as those presented above in assessing the effect of the
proposed rule on the aggregate of the 686 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]) 46 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 686 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 686 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.
There are 686 steam electric power plants that were surveyed by EPA in the Steam Electric Survey and are represented
in IPM. EPA estimates that there are 871 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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• 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 proposed 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
proposed 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.
Table 5-5: Impact of the Proposed Rule on In-Scope Plants, as a Group, in the Year 2030a
Economic Measures
Option 3
(all dollar values in 2021$)
Baseline Value
Value
Difference
% Change
National Totals
Total Domestic Capacity (MW)
274,256
274,007
-249
-0.1%
Early Retirements - Number of Plants
28
29
1
3.6%
Full & Partial Retirements - Capacity (MW)
56,422
56,671
249
0.4%
Generation (GWh)
1,226,067
1,220,364
-5,703
-0.5%
Costs ($Millions)
$44,427
$44,429
$2
0.0%
Fuel Cost
$22,187
$22,071
-$116
-0.5%
Variable O&M
$4,334
$4,355
$21
0.5%
Fixed O&M
$17,312
$17,410
$98
0.6%
Capital Cost
$594
$594
$0
0.0%
Average Variable Production Cost ($/MWh)
$21.63
$21.65
$0.02
0.1%
Midwest Reliability Organization (MRO)
Total Domestic Capacity (MW)
38,899
38,855
-44
-0.1%
Early Retirements - Number of Plants
8
8
0
0.0%
Full & Partial Retirements - Capacity (MW)
8,094
8,139
44
0.5%
Generation (GWh)
175,766
175,246
-520
-0.3%
Costs ($Millions)
$6,129
$6,133
$4
0.1%
Fuel Cost
$2,875
$2,868
-$7
-0.2%
Variable O&M
$838
$838
$0
0.0%
Fixed O&M
$2,240
$2,250
o
1
¦uy
0.5%
Capital Cost
$176
$176
$0
0.0%
Average Variable Production Cost ($/MWh)
$21.12
$21.15
$0.03
0.1%
Northeast Power Coordinating Council (NPCC)
Total Domestic Capacity (MW)
8,662
8,611
-51
-0.6%
Early Retirements - Number of Plants
2
2
0
0.0%
Full & Partial Retirements - Capacity (MW)
1,825
1,876
51
2.8%
Generation (GWh)
16,920
16,862
-58
-0.3%
Costs ($Millions)
$838
$835
-$3
-0.4%
Fuel Cost
$405
$403
-$2
-0.5%
Variable O&M
$43
$43
$0
-0.2%
Fixed O&M
$389
$388
-$1
-0.3%
Capital Cost
$0
$0
$0
NA
Average Variable Production Cost ($/MWh)
$26.49
$26.47
-$0.02
-0.1%
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Table 5-5: Impact of the Proposed Rule on In-Scope Plants, as a Group, in the Year 2030a
Economic Measures
Option 3
(all dollar values in 2021$)
Baseline Value
Value
Difference
% Change
ReliabilityFirst Corporation (RF)
Total Domestic Capacity (MW)
63,056
63,056
0
0.0%
Early Retirements - Number of Plants
4
4
0
0.0%
Full & Partial Retirements - Capacity (MW)
17,919
17,919
0
0.0%
Generation (GWh)
291,915
289,059
-2,855
-1.0%
Costs ($Millions)
$10,699
$10,715
$16
0.2%
Fuel Cost
$5,041
$4,988
-$54
-1.1%
Variable O&M
$1,145
$1,162
$17
1.5%
Fixed O&M
$4,505
$4,558
m
LO
¦uy
1.2%
Capital Cost
$7
$7
$0
0.0%
Average Variable Production Cost ($/MWh)
$21.19
$21.28
$0.08
0.4%
Southeast Electric Reliability Council (SERC)
Total Domestic Capacity (MW)
109,561
109,407
-154
-0.1%
Early Retirements - Number of Plants
9
10
1
11.1%
Full & Partial Retirements - Capacity (MW)
22,692
22,847
154
0.7%
Generation (GWh)
526,515
524,194
-2,321
-0.4%
Costs ($Millions)
$18,804
$18,778
-$27
-0.1%
Fuel Cost
$10,390
$10,335
-$56
-0.5%
Variable O&M
$1,516
$1,516
-$1
0.0%
Fixed O&M
$6,820
$6,849
o
m
¦uy
0.4%
Capital Cost
00
¦uy
00
¦uy
$0
0.0%
Average Variable Production Cost ($/MWh)
$22.61
$22.61
-$0.01
0.0%
Texas Reliability Entity (TRE)
Total Domestic Capacity (MW)
20,035
20,035
0
0.0%
Early Retirements - Number of Plants
1
1
0
0.0%
Full & Partial Retirements - Capacity (MW)
2,990
2,990
0
0.0%
Generation (GWh)
68,899
68,929
29
0.0%
Costs ($Millions)
$2,578
$2,583
$5
0.2%
Fuel Cost
$1,151
$1,151
$1
0.1%
Variable O&M
$279
$279
$1
0.2%
Fixed O&M
$1,148
$1,152
$4
0.3%
Capital Cost
$0
$0
$0
NA
Average Variable Production Cost ($/MWh)
$20.74
$20.75
$0.01
0.0%
Western Electricity Coordinating Council (WECC
Total Domestic Capacity (MW)
34,042
34,042
0
0.0%
Early Retirements - Number of Plants
4
4
0
0.0%
Full & Partial Retirements - Capacity (MW)
2,901
2,901
0
0.0%
Generation (GWh)
146,052
146,074
22
0.0%
Costs ($Millions)
$5,379
$5,386
$7
0.1%
Fuel Cost
$2,325
$2,325
$1
0.0%
Variable O&M
$513
$517
$4
0.7%
Fixed O&M
$2,209
$2,212
$3
0.1%
Capital Cost
$332
$332
$0
0.0%
Average Variable Production Cost ($/MWh)
$19.43
$19.46
$0.03
0.1%
a. Numbers may not add up due to rounding.
Source: U.S. EPA Analysis, 2022.
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5.2.2.2.1 Findings for the Proposed Rule (Regulatory Option 3) in the 2030 Model Year
Under the proposed rule, the steam electric capacity is estimated decrease approximately 0.1 percent.
For the group of steam electric power plants, total capacity decreases by 249 MW or approximately
0.1 percent of the 274,256 MW in baseline capacity. This decrease is largely attributable to net decreases
in total capacity of 154 MW (0.1 percent), 51 MW (0.6 percent), and 44 MW (0.1 percent) in the SERC,
NPCC, and MRO regions, respectively. One plant in SERC is projected to close under the proposed 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,47 for steam electric power plants, total generation is estimated to decrease by
5,703 GWh (0.5 percent). RF is projected to experience the largest decrease in generation from steam
electric power plants, 2,855 GWh (1 percent), with SERC estimated to experience the second largest
decrease in generation from steam electric power plants at 2,321 GWh (0.4 percent). Generation from
steam electric power plants is estimated to change in the remaining regions by less than 0.1 to -
0.3 percent.
The results for the group of steam electric power plants show a net increase in total costs of $2 million
(less than 0.1 percent). Total costs vary be region with the largest increases in costs coming from the RF
region ($16 million; 0.2 percent) and the largest decrease48 in costs coming from the SERC region
($27 million; 0.1 percent). Total costs increase by 0.1 percent in WECC and MRO and by 0.2 percent in
TRE. Total costs decrease in NPCC by 0.4 percent. At the national level, variable production costs for
steam electric power plants increase by $0.02 per MWh (0.1 percent). Effects vary by region, with
changes ranging from -$0.02 per MWh in NPCC to $0.08 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
distribution of plant-specific changes between the baseline and the proposed rule for three metrics:
capacity utilization,49 electricity generation, and variable production costs per MWh.50
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 proposed rule. In addition to the category of all
plants, the table also reports these metrics for plants that incur costs under Option 3 and plants that incur
no costs under Option 3 separately. Metrics of greatest interest for assessing the adverse impacts of the
proposed rule on steam electric power plants include the number of plants with reductions in capacity
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.
While costs decrease under Option 3, 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 proposed rule.
Capacity utilization is defined as generation divided by capacity times 8,760 hours.
Variable production costs per MWh is defined as variable O&M cost plus fuel cost divided by net generation projected
inlPM.
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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 2030 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 proposed rule, the percent
change in electricity generation relative to baseline cannot be calculated. On this basis, 305 plants are
excluded from assessment of effects on individual steam electric power plants under the proposed rule. In
addition, the change in variable production cost per MWh of generation could not be developed for
70 plants with zero generation in either the baseline or under the proposed rule (because the divisor,
MWh, is zero).51 For change in variable production cost per MWh, these plants are recorded in the "N/A"
column.
In some cases, non-retired plants will be modeled to have zero generation in 2030. These plants may generate
electricity in later years.
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Table 5-6: Impact of Proposed Rule on Individual In-Scope Plants in the Year 2030
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 3
Change in Capacity Utilization3
4
7
8
16
0
0
0
11
46
Change in Generation
11
3
5
16
0
0
0
11
46
Change in Variable Production Costs/MWh
0
0
2
1
17
14
1
11
46
Steam Electric Power Plants that Incur No Costs under Option 3
Change in Capacity Utilization3
1
6
24
269
37
4
5
294
640
Change in Generation
11
5
13
273
27
6
11
294
640
Change in Variable Production Costs/MWh
1
4
40
182
47
2
0
364
640
All Steam Electric Power Plants
Change in Capacity Utilization3
5
13
32
285
37
4
5
305
686
Change in Generation
22
8
18
289
27
6
11
305
686
Change in Variable Production Costs/MWh
1
4
42
183
64
16
1
375
686
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 3, "N/A" reports
267 full and 37 partial baseline closures; 1 full closure is a result of the regulatory option.
c. The change in variable production cost per MWh could not be developed for 70 plants with zero generation in either the baseline case or Option 3 policy case.
Source: U.S. EPA Analysis, 2022
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5.2.2.3.1 Findings for the Proposed Rule (Option 3) in Model Year 2030
For the proposed 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, 30 plants (4 percent) incur a reduction in generation of at
least one percent; 18 of these plants are also estimated to incur a reduction in capacity utilization of at
least one percent. Finally, only 17 plants (2.5 percent) are estimated incur an increase in variable
production costs of at least one percent. For the set of 46 plants that incur costs under Option 3, 19 plants
incur a decrease in generation and 16 plants are estimated to have no change in generation. Of the plants
that incur costs under Option 3, none 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 proposed 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 proposed rule involve several sources of uncertainty:
• 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, 2018a). 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 proposed rule.
• Demand for electricity. IPM assumes that electricity demand at the national level will not change
between the baseline and the proposed 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 2021 (AEO2021; EIA, 2021).
IPM does not capture changes in demand that may result from electricity price changes associated
with the proposed rule (i.e.. demand is inelastic with respect to price52). 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
proposed rule in all NERC regions are very small (less than 0.07 $/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
52 Electricity demand has been found to be inelastic with respect to price in the short-term. See, for example, Burke and
Abayasekara (2018) and Bernstein and Griffin (2005).
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relies on AEO2021'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 proposed 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 proposed 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 2030, and the
level of imports compared to domestic generation in this region is very small (about 0.3 percent).
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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.53 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 proposed 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 estimating the net employment impacts of
the proposed rule. The agency is using an approach outlined in U.S. EPA (2018b) 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 proposed rule are estimated to be small.)
6.2.1 Quantification of Projected Actions
EPA quantified two categories of actions resulting from the proposed 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 both total capital and O&M costs) by
steam electric power generating plants, as described in Chapter 3.
EPA conducted this analysis for regulatory Option 3 and the year 2030, based on the market analysis of
Chapter 5 which provides detailed output for this regulatory option and run year.
Table 6-1 presents the estimated changes in new generation capacity and retirements in 2030 due to
Option 3 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.
Table 6-1: Estimated Change in Generating Capacity Under Option 3 Relative to Baseline in
2030
Generation Type3
New Generation
GW)b
Retirements (GW)b
Net Capacity
Change (GW)C
Baseline
Option 3
Change
Baseline
Option 3
Change
Solar
36.98
36.83
-0.15
0
0
0
-0.15
Wind
50.56
50.59
0.03
0
0
0
0.03
One FTE equals 2,080 labor hours per year.
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Table 6-1: Estimated Change in Generating Capacity Under Option 3 Relative to Baseline in
2030
Generation Type3
New Generation
GW)b
Retirements (GW)b
Net Capacity
Change (GW)C
Baseline
Option 3
Change
Baseline
Option 3
Change
Energy Storage
15.06
15.07
0.01
0
0
0
0.01
Combined Cycle
(without CCS)
8.30
8.53
0.22
0.98
0.98
0
0.22
Combustion
Turbine
38.48
38.27
-0.20
0.33
0.33
0
-0.20
Coal steam
0
0
0
45.68
45.96
0.27
-0.27
Oil & Natural Gas
Steam
0
0
0
2.69
2.66
-0.03
0.03
Nuclear
0
0
0
15.36
15.12
-0.24
0.24
Total
149.38
149.29
-0.10
65.04
65.05
0.01
-0.10
a. Only generation types with non-zero changes in new generation or retirements under Option 3 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 3 relative to the baseline.
Source: U.S. EPA Analysis, 2022.
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
0.08
Wind
0.42
Energy Storage
0.06
Combined Cycle (without CCS)
0.28
Combustion Turbine
0.02
Total
0.86
Source: U.S. EPA Analysis, 2022.
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Table 6-3 presents the estimated changes in consumption of natural gas and coal in 2030 under Option 3
relative the baseline. EPA calculated the net change in fuel consumption for Option 3 by subtracting the
estimated fuel use under the baseline from the fuel use estimated under Option 3 in 2030. EPA uses these
estimates of net fuel consumption to determine the changes in labor inputs in associated sectors due to
fuel use changes under the proposed rule relative to the baseline.
Table 6-3: Estimated Change in Fuel Consumption Under Option 3 Relative to Baseline in 2030
Fuel Type
Region
Appalachia
Interior
Waste
West
All regions
Baseline
Coal (Million Short Tons)
51.03
63.35
4.33
176.92
295.64
Natural Gas (Trillion Cubic Feet)
N/A
N/A
N/A
N/A
12.93
Option 3
Coal (Million Short Tons)
49.60
62.76
4.33
176.10
292.79
Natural Gas (Trillion Cubic Feet)
N/A
N/A
N/A
N/A
12.96
Change in Fuel Consumption (Option 3 less Baseline)
Coal (Million Short Tons)
-1.43
-0.59
0.00
-0.82
-2.84
Natural Gas (Trillion Cubic Feet)
N/A
N/A
N/A
N/A
0.03
Source: U.S. EPA Analysis, 2022.
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 proposed rule ELGs. EPA used these total cost
estimates to determine the associated effects on labor inputs.
Table 6-4: Option 3 Technology Capital and Operation Costs (millions, 2021$)
Cost Type
Wastestream
BA
FGD
CRL
Total
Capital Costs
$256.7
$549.6
$746.6
$1,552.8
Pre-Tax Annualized O&M Costs
$24.6
$42.8
$40.1
$107.5
Source: U.S. EPA Analysis, 2022.
6.2.2 Resource Requirements of Changes in Projected Actions and Treatment Technology
EPA estimated the resource requirements associated with the changes in projected actions and new
wastewater treatment technologies used as basis for the proposed rule in dollars. This section of the
analysis is separated in four parts, described below:
1) Construction of new generation capacity;
2) Operation of new generation capacity and retirements;
3) Installation of new treatment technology; and
4) Operation of new wastewater treatment technology.
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6.2.2.1 Construction of New Generation Capacity
EPA first estimated the costs associated with construction of new generation capacity for several different
cost components (e.g., equipment, materials, construction labor, and engineering services). EPA
calculated the annual construction cost ($/year) as the product of the unit capital cost ($/kW) from U.S.
EPA (2021) and the estimated new capacity construction in 2030 (kW/year), as described in Section
6.2.1. EPA then calculated construction costs for specific cost components by multiplying the total capital
costs associated with construction of new generation capacity by the estimated percentage of costs that
correspond with each cost component based on information from U.S. EPA (2018b). EPA further mapped
each cost component to the most relevant NAICS sector. Table 6-5 displays the estimated percentage of
costs for new generation capacity (for each relevant generation type) that corresponds with each cost
component and associated NAICS sector.
Table 6-5: Capital and Labor Components for Construction of New Generation Capacity by
Generation Type
Cost Component
NAICS
Sector
NAICS Sector Description
Average % of Total Operation Costs
Renewables
& Biomass
Combined
Cycle
Combustion
Turbine
Equipment
333
Machinery Manufacturing
54%
65%
65%
Material
33111
Iron and Steel Mills and
Ferroalloy Manufacturing
6%
10%
10%
Labor
236210
Industrial Building
Construction
31%
18%
18%
Engineering and
Construction
Management
541330
Engineering Services
9%
7%
7%
Source: U.S. EPA Analysis, 2022; U.S. EPA, 2018b.
6.2.2.2 Operation of New Generation Capacity and Retirements
As described in Section 6.2.1, EPA used IPM projections to estimate the incremental quantity of
generation capacity in operation in 2030 due to the proposed rule (see Table 6-1). EPA estimated the
annual resource costs for operating new generation capacity, or reduction in resource costs from projected
retirements, based on annual fixed operating and maintenance (FOM) costs, as reported in U.S. EPA
(2021). The Agency estimated annual FOM cost ($/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
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Table 6-6: NAICS Sectors Associated with Operation of New Generation Capacity
NAICS Sector
NAICS Sector Description
Generation Type
221115
Wind electric power generation
Solar
Source: U.S. EPA Analysis, 2022.
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
proposed 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 proposed 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, 2022; Eastern Research Group, 2022.
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6.2.3 Estimation and Aggregation of Labor Impacts
To estimate the total labor impacts of the proposed 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.
Table 6-8: Base Labor Productivity by Relevant Sector
NAICS
Sector
NAICS Sector Description
Value of
shipments ($
Millions) [A]
(2017)
Total
employees [B]
(2017)
Labor
productivity
[B/A] (2017)
Growth rate
(2012-2017)
333
Machinery manufacturing
$397,104
1,029,068
2.59
6.4%
3251
Basic Chemical Manufacturing
$237,463
148,181
0.62
9.9%
22111
Electric power generation
$129,936
138,647
1.07
3.8%
33111
Iron and Steel Mills and
Ferroalloy Manufacturing
$95,391
84,792
0.89
6.1%
221111
Hydroelectric power
generation
$3,633
3,642
1.00
-0.4%
221112
Fossil fuel electric power
generation
$82,206
76,058
0.93
4.9%
221113
Nuclear electric power
generation
$31,609
48,521
1.54
3.6%
221114
Solar electric power
generation
$1,962
2,163
1.10
-16.3%
221115
Wind electric power
generation
$8,457
4,986
0.59
-5.1%
221116
Geothermal electric power
generation
$1,061
1,214
1.14
4.7%
221117
Biomass electric power
generation
$987
1,968
1.99
6.9%
221118
Other electric power
generation
$23
95
4.18
2.2%
236210
Industrial Building
Construction
$27,732
71,562
2.58
3.9%
237130
Power and Communication
Line and Related Structures
Construction
$70,416
232,861
3.31
-2.2%
238910
Site Preparation Contractors
$106,179
385,177
3.63
-0.2%
335911
Storage battery
manufacturing
$8,206
25,126
3.06
6.3%
484121
General Freight Trucking,
Long-Distance, Truckload
$122,501
519,358
4.24
2.8%
484230
Specialized Freight (except
Used Goods) Trucking, Long-
Distance
$44,489
174,571
3.92
3.1%
541330
Engineering Services
$258,534
1,081,471
4.18
4.1%
562211
Hazardous Waste Treatment
and Disposal
$9,491
34,035
3.59
3.6%
562212
Solid Waste Landfill
$8,209
20,525
2.50
1.8%
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Table 6-8: Base Labor Productivity by Relevant Sector
NAICS
Sector
NAICS Sector Description
Value of
shipments ($
Millions) [A]
(2017)
Total
employees [B]
(2017)
Labor
productivity
[B/A] (2017)
Growth rate
(2012-2017)
811310
Commercial and Industrial
Machinery and Equipment
(except Automotive and
Electronic) Repair and
Maintenance
$42,770
202,493
4.73
1.1%
Source: U.S. Census Bureau, 2012; U.S. Census Bureau, 2021a; U.S. EPA Analysis, 2022.
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
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 2020
regional coal mining productivity estimates from EIA (EIA, 2021c) and 2019 natural gas production and
employment estimates from EIA (EIA, 2022c; EIA, 2022d) and U.S. Census Bureau (U.S. Census
Bureau, 2021b), 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. Based on 2017 Economic Census, total employment in the coal
mining (NAICS 2121) and natural gas extraction (NAICS 21113) industries was 48,466 and 36,940,
respectively (U.S. Census Bureau, 2021a).
Table 6-9: Coal and Natural Gas Labor Productivity Estimates
Labor
Resource
productivity
Unit
Data vintage
Coal-Appalachian region
2.74
Short tons per labor hour
2020
Coal - Interior region
5.72
Short tons per labor hour
2020
Coal-Western region
14.58
Short tons per labor hour
2020
Coal - Waste
6.12
Short tons per labor hour
2020
Natural gas
626
Million Btu per labor hour
2019
Source: EIA, 2022c; EIA, 2022d; EIA, 2021c; U.S. Census Bureau, 2021b; EIA, 2021c, U.S. EPA Analysis 2022
6.3 Estimated Impacts of the Proposed 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
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productivity rates, EPA estimated increased FTEs associated with construction of new generation
capacity. Under both labor productivity rates, the machinery manufacturing sector (NAICS code 333) is
expected to see the greatest increase in FTE. Using the 2017 labor productivity rates, the industrial
building construction sector (NAICS code 236210) is expected to see the second greatest rise in FTE.
Using the adjusted 2030 labor productivity rates, the storage battery manufacturing sector (NAICS code
335911) is expected to see the second greatest increase in FTE. In total, the Agency estimated an increase
of 1,365 to 2,776 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)
Labor
Productivity
Rates
NAICS
Sector
NAICS Sector Description
Generation Type
Combined
Cycle
Wind
Solar
Combustion
Turbine
Energy
Storage
All Types
2017
333
Machinery Manufacturing
171
311
144
10
0
636
33111
Iron and Steel Mills and
Ferroalloy Manufacturing
9
12
5
1
0
27
236210
Industrial Building
Construction
47
178
82
3
0
310
335911
Storage Battery
Manufacturing
0
0
0
0
238
238
541330
Engineering Services
30
84
39
2
0
154
Total
-
256
585
270
16
238
1,365
Adjusted
2030
333
Machinery Manufacturing
382
697
321
23
0
1,424
33111
Iron and Steel Mills and
Ferroalloy Manufacturing
19
25
12
1
0
58
236210
Industrial Building
Construction
78
294
136
5
0
512
335911
Storage Battery
Manufacturing
0
0
0
0
525
525
541330
Engineering Services
50
140
65
3
0
258
Total
-
529
1,157
533
32
525
2,776
a. Only generation types with non-zero changes in new generation capacity are reported.
Source: U.S. EPA Analysis, 2022.
EPA estimated that overall labor inputs for operation of new generation capacity would increase by 56 to
87 FTEs using the 2017 and adjusted 2030 labor productivity rates, respectively. 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, wind, oil and natural gas
steam, and nuclear generation. For oil and natural gas steam and nuclear generation, the increases are due
to avoided retirements, whereas for combined cycle and wind generation, the increases are a result of
additional generation capacity due to the proposed rule relative to the baseline. Using the 2017 and
adjusted 2030 labor productivity rates, labor inputs are expected to increase the most for nuclear
generation with 72 and 113 FTEs, respectively. By contrast, the analysis shows estimated decreases in
FTEs associated with solar, combustion turbine, and coal steam generation with the greatest decrease
occurring from reduced capacity of coal steam generation. Decreases for coal steam generation are the
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result of capacity retirements as a result of the proposed rule. Decreases for combustion turbine and solar
generation are a result of reductions in projected new generation capacity due to the proposed rule.
These changes in labor inputs are small relative to overall employment in the electric power generation
sector (138,647 employees in 2017; see Table 6-8).
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
1
1
-3
-4
-11
1
72
56
Adjusted 2030
1
0
-1
-8
-21
1
113
86
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, 2022.
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 proposed 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 195 to 322 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 FGD treatment technology is estimated to have the greatest
increase on labor inputs using either the 2017 and 2030 labor productivity rates (78 and 128 FTEs,
respectively) followed by CRL (73 and 120 FTEs, respectively) and BA (44 and 73 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 58 and 92 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 58 FTEs. Using adjusted 2030 labor productivity rates, the
sector with the second highest increase is the electric power generation sector (NAICS code 22111) with
74 FTEs.
Table 6-12: Changes in Labor Inputs from Operation of New Technology in 2030 (# FTEs)
Labor
Wastestream
Productivity
Rates
NAICS
Sector
NAICS Sector Description
FGD
BA
CRL
Total
3251
Basic Chemical Manufacturing
5
3
5
13
2017
22111
Electric Power Generation
17
10
16
42
33111
Iron and Steel Mills and Ferroalloy
Manufacturing
4
2
4
10
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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
484230
Specialized Freight (except Used Goods)
Trucking, Long-Distance
8
5
8
21
562211
Hazardous Waste Treatment and Disposal
23
13
22
58
Commercial and Industrial Machinery and
811310
Equipment (except Automotive and
Electronic) Repair and Maintenance
20
12
19
51
Total
-
78
44
73
195
3251
Basic Chemical Manufacturing
18
10
17
46
22111
Electric Power Generation
30
17
28
74
33111
Iron and Steel Mills and Ferroalloy
Manufacturing
8
5
8
21
Adjusted
2030
484230
Specialized Freight (except Used Goods)
Trucking, Long-Distance
13
7
12
32
562211
Hazardous Waste Treatment and Disposal
37
21
34
92
Commercial and Industrial Machinery and
811310
Equipment (except Automotive and
Electronic) Repair and Maintenance
23
13
22
59
Total
-
128
73
120
322
Source: U.S. EPA Analysis, 2022.
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 328 FTEs. The
Appalachia region is estimated to experience the greatest reduction in labor input associated with coal
production, followed by the Interior and West regions. EPA estimated a negligible change in national
labor input associated with natural gas extraction.
Table 6-13: Labor Demand from Fuel Use Changes (# Employees)
Fuel
NAICS
NAICS Sector
Coal Region
Type
Sector
Description
Appalachia
Interior
West
Waste Coal
Total
Coal
2121
Coal Mining
-251
-50
-27
0
-328
Natural
gas
21113
Natural Gas
Extraction
N/A
N/A
N/A
N/A
<1
Source: U.S. EPA Analysis, 2022.
6.3.4 Total Impacts of the Proposed 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
sector (NAICS code 2121) which is estimated to experience a decrease in FTEs due to a decline in fuel
consumption for electricity generation. Overall, EPA estimated the proposed rule to increase labor inputs
by 1,288 to 2,856 FTEs using the 2017 and adjusted 2030 labor productivity rates, respectively. The
sector with the greatest estimated increase in labor inputs is the machinery manufacturing sector (NAICS
code 333). Using the 2017 labor productivity rates, the sector with the second greatest increase in labor
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inputs is the industrial building construction sector (NAICS code 236210) followed by the storage battery
manufacturing sector (NAICS code 335911). Using the adjusted 2030 labor productivity rates, the
industry with the second greatest increase in labor inputs is the storage battery manufacturing sector,
followed by the industrial building construction sector.
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 proposed 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 proposed 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 (0.1 percent, based on IPM projections of Option 3 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
Sector
NAICS Sector Description
Labor Productivity Rates
2017
Adjusted 2030
333
Machinery Manufacturing
636
1,424
2121
Coal Mining3
-328
-328
3251
Basic Chemical Manufacturing
13
46
21113
Natural Gas Extraction3
0
0
22111
Electric Power Generation
98
160
33111
Iron and Steel Mills and Ferroalloy Manufacturing
36
78
236210
Industrial Building Construction
310
512
237130
Power and Communication Line and Related Structures
Construction
0
0
238910
Site Preparation Contractors
0
0
335911
Storage Battery Manufacturing
238
525
484121
General Freight Trucking, Long-Distance, Truckload
0
0
484230
Specialized Freight (except Used Goods) Trucking, Long-
Distance
21
32
541330
Engineering Services
154
258
562211
Hazardous Waste Treatment and Disposal
58
92
562212
Solid Waste Landfill
0
0
811310
Commercial and Industrial Machinery and Equipment
(except Automotive and Electronic) Repair and
Maintenance
51
59
Total
-
1,288
2,856
. 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, 2022.
6.4 Estimated Impacts from Installation of Wastewater Treatment Technologies
Installation of wastewater treatment technologies used as basis for ELGs in the proposed 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.
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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).
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, 2022.
Table 6-16 presents the estimated impacts associated with installation of wastewater treatment
technologies in the proposed rule. Overall, EPA estimated that labor inputs would increase due to
installation of new treatment technologies by 5,307 FTEs using the 2017 labor productivity rates and by
8,774 FTEs using the adjusted 2030 labor productivity rates. Under both labor productivity rates, the
number of FTEs is estimated to increase the most, by 2,444 to 4,252 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
865
404
1,175
2,444
333
Machinery manufacturing
356
166
484
1,006
23829
Other Building Equipment
Contractors
200
94
272
566
238910
Site Preparation Contractors
199
93
271
563
484121
General Freight Trucking, Long-
Distance, Truckload
0
0
0
0
541330
Engineering Services
230
107
312
650
562212
Solid Waste Landfill
27
13
37
78
Total
-
1,878
877
2,551
5,307
Adjusted
2030
332
Fabricated Metal Product
Manufacturing
1,505
703
2,044
4,252
333
Machinery manufacturing
797
372
1,083
2,252
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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
23829
Other Building Equipment
Contractors
189
88
257
534
238910
Site Preparation Contractors
194
91
264
549
484121
General Freight Trucking, Long-
Distance, Truckload
0
0
0
0
541330
Engineering Services
385
180
523
1,089
562212
Solid Waste Landfill
35
16
47
98
Total
-
3,105
1,450
4,218
8,774
Source: U.S. EPA Analysis, 2022.
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 proposed 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 proposed
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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7 Assessment of Potential Electricity Price Effects
7.1 Analysis Overview
EPA assessed the potential impacts of regulatory options 1 through 4 on electricity prices. Following the
methodology EPA used to analyze the 2015 and 2020 rules (U.S. EPA, 2015, 2020b), 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,54 EPA judges
this assumption appropriate for two reasons: (1) the majority of steam electric power plants operate in the
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.
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.
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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 rule analyses, involves the following steps (for details, see Chapter 7 in U.S. EPA, 2015):
• EPA summed weighted pre-tax plant-level annualized compliance costs by NERC region.55,56
• 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 AEO2021 (EIA, 2021).
• EPA compared the estimated average price effect to the projected electricity price by consumer
group and NERC region for 2024 from AEO2021 (EIA, 2021).
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 Option 1, the regions with the greatest
cost per kWh are RF and MRO. For Option 2, the regions with the greatest cost per kWh are RF and
SERC. For Options 3 and 4, the regions with the greatest cost per kWh are RF and MRO. Overall, across
the United States, Options 3 and 4 result in the highest cost per kWh (0.0060 per kWh), and Option 1
results in the lowest cost per kWh (0.0030 per kWh).
Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024
(2021$)
NERCa
Total Electricity Sales
National Pre-Tax Compliance
Costs per Unit of Sales
(at 2024; MWh)
Costs (at 2024; 2021$)
(2021C/kWh Sales)
Option 1
MRO
446,139,645
$15,496,118
0.003C
NPCC
254,340,668
$6,522,322
0.003C
RF
736,231,063
$44,084,601
0.006C
These compliance costs are in 2021 dollars as of a given technology implementation year (2025 through 2029) and
discounted to 2024 at 7 percent. This analysis accounts for the different years in which plants are estimated to
implement the compliance technologies in order to reflect the effect of differences in timing of these electricity price
impacts in terms of cost to household ratepayers and society. Costs and ratepayer effects occurring farther in the future
(e.g., in the last year of the technology implementation period) have a lower present value of impact than those that
occur sooner following rule promulgation. Estimating the cost and ratepayer effect as of the assumed technology
implementation year (2025 through 2029) and then discounting these effects to a single analysis year (2024) accounts
for this consideration.
For this analysis, EPA brought compliance costs forward to a given compliance year using the CCI and ECI.
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Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2024
(2021$) J
NERCa
Total Electricity Sales
National Pre-Tax Compliance
Costs per Unit of Sales
(at 2024; MWh)
Costs (at 2024; 2021$)
(2021C/kWh Sales)
SERC
1,323,492,257
$31,370,943
0.002C
TRE
375,128,510
$3,733,720
0.001C
WECC
683,737,640
$1,181,515
o.oooc
US
3,839,529,792
$102,389,219
0.0034
Option 2
MRO
446,139,645
$21,563,593
0.005C
NPCC
254,340,668
$6,522,322
0.003C
RF
736,231,063
$82,765,033
0.011C
SERC
1,323,492,257
$71,523,555
0.005C
TRE
375,128,510
$5,433,679
0.001C
WECC
683,737,640
$1,181,515
O.OOOC
US
3,839,529,792
$188,989,696
0.005C
Option 3
MRO
446,139,645
$28,448,631
0.006C
NPCC
254,340,668
$7,142,264
0.003C
RF
736,231,063
$99,186,958
0.013C
SERC
1,323,492,257
$81,421,703
0.006C
TRE
375,128,510
$7,256,307
0.002C
WECC
683,737,640
$7,036,299
0.001C
US
3,839,529,792
$230,492,162
0.0064
Option 4
MRO
446,139,645
$28,415,289
0.006C
NPCC
254,340,668
$7,142,264
0.003C
RF
736,231,063
$100,952,963
0.014C
SERC
1,323,492,257
$90,494,258
0.007 C
TRE
375,128,510
$7,236,830
0.002C
WECC
683,737,640
$7,036,299
0.001C
US
3,839,529,792
$241,277,902
0.0064
a. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
Because of this, the sum of electricity sales for all regions do not sum to the total for the United States.
Source: U.S. EPA Analysis, 2022
To determine the relative significance of compliance costs on electricity prices across consumer groups,
EPA compared the per kWh compliance cost to retail electricity prices projected by EIA (AEO2021; EIA,
2021) by consuming group and for the average of the groups. As reported in Table 7-2, across the United
States, Options 3 and 4 are estimated to result in the largest average electricity price increase (0.006 cents
per kWh) for all sectors, relative to the other options (0.06 percent of the average price of 10.76 cents per
kWh). For the other analyzed options, average electricity price increases are less than under Options 3 and
4, with cost per kWh increases ranging from 0.003 cents per kWh (0.02 percent) under Option 1, to
0.005 cents per kWh (0.05 percent) under Option 2.
Looking across the four consumer groups and assuming that any price change would apply equally to all
consumer groups, under all scenarios industrial consumers are estimated to experience the highest price
changes relative to the electricity price basis, while residential consumers are estimated to experience the
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lowest price changes, shown in Table 7-2. The higher relative price changes to industrial consumers is
due to their lower electricity rates and EPA's assumption of uniform changes across all consumer groups;
it does not reflect differential distribution of the incremental costs across consumer groups.
Table 7-2: Projected 2024 Price (Cents per kWh of Sales) and Potential Price Increase Due to
Compliance Costs by NERC Region and Regulatory Option (2021$)
All Sectors
Residential
Commercial
Industrial
Transportation
Average
EIA
EIA
EIA
EIA
Compliance
Price
Price
EIA Price
Price
Price
Costs
Basis
%
Basis
%
Basis
%
Basis
%
Basis
(20214
(20214
Change
(20214
Change
(20214
Change
(20214
Change
(20214
% Change
NERCb
/kWh)
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
Option 1
MRO
0.003 C
12.36C
0.03%
9.94C
0.03%
6.89C
0.05%
12.25C
0.03%
9.76C
0.04%
NPCC
0.003 C
19.29C
0.01%
15.88C
0.02%
11.31C
0.02%
12.49C
0.02%
16.69C
0.02%
RF
0.006 C
12.90C
0.05%
10.86C
0.06%
7.76C
0.08%
9.21C
0.07%
10.85C
0.06%
SERC
0.002 C
11.31C
0.02%
9.60C
0.02%
6.26C
0.04%
11.41C
0.02%
9.59C
0.02%
TRE
0.001C
10.53C
0.01%
9.46C
0.01%
6.73C
0.01%
7.92C
0.01%
9.13C
0.01%
WECC
O.OOOC
13.70C
0.00%
12.82C
0.00%
8.68C
0.00%
15.66C
0.00%
12.22C
0.00%
US
0.0034
12.614
0.02%
11.044
0.02%
7.304
0.04%
12.284
0.02%
10.764
0.02%
Option 2
MRO
0.005 C
12.36C
0.04%
9.94C
0.05%
6.89C
0.07%
12.25C
0.04%
9.76C
0.05%
NPCC
0.003 C
19.29C
0.01%
15.88C
0.02%
11.31C
0.02%
12.49C
0.02%
16.69C
0.02%
RF
0.011C
12.90C
0.09%
10.86C
0.10%
7.76C
0.14%
9.21C
0.12%
10.85C
0.10%
SERC
0.005 C
11.31C
0.05%
9.60C
0.06%
6.26C
0.09%
11.41C
0.05%
9.59C
0.06%
TRE
0.001C
10.53C
0.01%
9.46C
0.02%
6.73C
0.02%
7.92C
0.02%
9.13C
0.02%
WECC
O.OOOC
13.70C
0.00%
12.82C
0.00%
8.68C
0.00%
15.66C
0.00%
12.22C
0.00%
US
0.0054
12.614
0.04%
11.044
0.04%
7.304
0.07%
12.284
0.04%
10.764
0.05%
Option 3
MRO
0.006 C
12.36C
0.05%
9.94C
0.06%
6.89C
0.09%
12.25C
0.05%
9.76C
0.07%
NPCC
0.003 C
19.29C
0.01%
15.88C
0.02%
11.31C
0.02%
12.49C
0.02%
16.69C
0.02%
RF
0.013C
12.90C
0.10%
10.86C
0.12%
7.76C
0.17%
9.21C
0.15%
10.85C
0.12%
SERC
0.006 C
11.31C
0.05%
9.60C
0.06%
6.26C
0.10%
11.41C
0.05%
9.59C
0.06%
TRE
0.002 C
10.53C
0.02%
9.46C
0.02%
6.73C
0.03%
7.92C
0.02%
9.13C
0.02%
WECC
0.001C
13.70C
0.01%
12.82C
0.01%
8.68C
0.01%
15.66C
0.01%
12.22C
0.01%
US
0.0064
12.614
0.05%
11.044
0.05%
7.304
0.08%
12.284
0.05%
10.764
0.06%
Option 4
MRO
0.006 C
12.36C
0.05%
9.94C
0.06%
6.89C
0.09%
12.25C
0.05%
9.76C
0.07%
NPCC
0.003 C
19.29C
0.01%
15.88C
0.02%
11.31C
0.02%
12.49C
0.02%
16.69C
0.02%
RF
0.014C
12.90C
0.11%
10.86C
0.13%
7.76C
0.18%
9.21C
0.15%
10.85C
0.13%
SERC
0.007 C
11.31C
0.06%
9.60C
0.07%
6.26C
0.11%
11.41C
0.06%
9.59C
0.07%
TRE
0.002 C
10.53C
0.02%
9.46C
0.02%
6.73C
0.03%
7.92C
0.02%
9.13C
0.02%
WECC
0.001C
13.70C
0.01%
12.82C
0.01%
8.68C
0.01%
15.66C
0.01%
12.22C
0.01%
US
0.0064
12.614
0.05%
11.044
0.06%
7.304
0.09%
12.284
0.05%
10.764
0.06%
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, 2022; EIA, 2021; 2021d
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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 are not able to 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 (U.S. EPA, 2015, 2020b), the steps in
this calculation are as follows:
• 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.57
• 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 AEO2021 (EIA, 2021).58
• To calculate average annual electricity sales per household, EPA divided the total quantity of
residential sales (in MWh) for 2020 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 2020 EIA-861 database (EIA, 2018b; EIA, 2021a). 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 2020.
• 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 2020 by NERC region.
Compliance costs in the ASCC and HICC regions are zero and EPA therefore did not include these regions in its
analysis.
AEO does not provide information for HICC and ASSC. None of the plants estimated to incur compliance costs as a
result of the proposed ELG, however, are located in these two NERC regions.
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7.3.2 Key Findings for Regulatory Options A through C
Table 7-3 reports the results of this analysis by NERC region for each regulatory option, and overall for
the United States.59
The average annual compliance costs per residential household is greatest in RF and the least in WECC
under each regulatory option. On the national level, compliance costs are greatest on average under
Option 4, with average compliance costs per residential household of $0.66 per year; across regions,
compliance costs range between $0.09-$ 1.33 per year. For Option 3, average compliance costs per
residential household are estimated at $0.63 per year; across region, compliance costs range between
$0.09 and $1.31 per year (not including the NERC regions ASCC and HICC where compliance costs are
zero).
Table 7-3: Average Incremental Annual Cost per Household in 2024 by NERC Region and
Regulatory Option (2021$)
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)
2021$)
(2021$/MWh)
(2021$)
Option 1
MRO
446,139,645
118,537,826
10,692,505
11.09
15,496,118
$0.03
$0.39
NPCC
254,340,668
110,579,464
14,565,729
7.59
6,522,322
$0.03
$0.19
RF
736,231,063
315,011,380
32,389,972
9.73
44,084,601
$0.06
$0.58
SERC
1,323,492,257
496,825,528
37,402,822
13.28
31,370,943
$0.02
$0.31
TRE
375,128,510
79,509,120
6,065,496
13.11
3,733,720
$0.01
$0.13
WECC
683,737,640
256,274,134
29,450,648
8.70
1,181,515
$0.00
$0.02
USb
3,832,909,593
1,381,341,721
131,299,538
10.52
102,389,219
$0.03
$0.28
Option 2
MRO
446,139,645
118,537,826
10,692,505
11.09
21,563,593
$0.05
$0.54
NPCC
254,340,668
110,579,464
14,565,729
7.59
6,522,322
$0.03
$0.19
RF
736,231,063
315,011,380
32,389,972
9.73
82,765,033
$0.11
$1.09
SERC
1,323,492,257
496,825,528
37,402,822
13.28
71,523,555
$0.05
$0.72
TRE
375,128,510
79,509,120
6,065,496
13.11
5,433,679
$0.01
$0.19
WECC
683,737,640
256,274,134
29,450,648
8.70
1,181,515
$0.00
$0.02
USb
3,832,909,593
1,381,341,721
131,299,538
10.52
188,989,696
$0.05
$0.52
Option 3
MRO
446,139,645
118,537,826
10,692,505
11.09
28,448,631
$0.06
$0.71
NPCC
254,340,668
110,579,464
14,565,729
7.59
7,142,264
$0.03
$0.21
RF
736,231,063
315,011,380
32,389,972
9.73
99,186,958
$0.13
$1.31
SERC
1,323,492,257
496,825,528
37,402,822
13.28
81,421,703
$0.06
$0.82
TRE
375,128,510
79,509,120
6,065,496
13.11
7,256,307
$0.02
$0.25
WECC
683,737,640
256,274,134
29,450,648
8.70
7,036,299
$0.01
$0.09
USb
3,832,909,593
1,381,341,721
131,299,538
10.52
230,492,162
$0.06
$0.63
Average annual cost per residential household is zero in ASCC and HICC for the baseline and the three options and
these regions are therefore omitted from the details. They are included in the U.S. totals.
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Table 7-3: Average Incremental Annual Cost per Household in 2024 by NERC Region and
Regulatory Option (2021$)
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)
2021$)
(2021$/MWh)
(2021$)
Option 4
MRO
446,139,645
118,537,826
10,692,505
11.09
28,415,289
$0.06
$0.71
NPCC
254,340,668
110,579,464
14,565,729
7.59
7,142,264
$0.03
$0.21
RF
736,231,063
315,011,380
32,389,972
9.73
100,952,963
$0.14
$1.33
SERC
1,323,492,257
496,825,528
37,402,822
13.28
90,494,258
$0.07
$0.91
TRE
375,128,510
79,509,120
6,065,496
13.11
7,236,830
$0.02
$0.25
WECC
683,737,640
256,274,134
29,450,648
8.70
7,036,299
$0.01
$0.09
usb
3,832,909,593
1,381,341,721
131,299,538
10.52
241,277,902
$0.06
$0.66
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, 2022; EIA, 2021; 2021d
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 are not able to 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
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
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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 1 through 4 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. EPA finds that the earlier conclusion of small impacts from the 2015
rule still holds given the lower compliance costs of the four regulatory options relative to the 2015 rule.
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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,60 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 proposed action, 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 (U.S. EPA, 2015, 2020b), 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 SB A 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
uncertainties and limitations in the analysis (Section 8.3). The chapter also discusses how regulatory
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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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 and 2020 rules (U.S.
EPA, 2015, 2020b), 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)61 in
at least one of the estimated 871 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 2020 databases published by EIA (EIA, 202Id), Dun and Bradstreet (Dun &
Bradstreet, 2021), corporate and financial websites, 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
August 19, 2019 (SBA, 2019).62 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, non-utility 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.63
• 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.
• 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).
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.
These size standards are those in effect at the time EPA conducted the analysis. Subsequent revisions to the size
standards in December 2022 (SBA, 2022) would result in one additional entity being categorized as small. EPA will
incorporate these revised size standards in the final rule analysis.
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).
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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
212111
Bituminous Coal and Lignite Surface Mining
1,250 Employees
221111
Hydroelectric Power Generation
500 Employees
221112
Fossil Fuel Electric Power Generation
750 Employees
221113
Nuclear Electric Power Generation
750 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
500 Employees
221122
Electric Power Distribution
1,000 Employees
221210
Natural Gas Distribution
1,000 Employees
221310
Water Supply and Irrigation Systems
$36.0 million in revenue
237130
Power and Communication Line and Related Structures
Construction
$39.5 million in revenue
332410
Power Boiler and Heat Exchanger Manufacturing
750 Employees
333611
Turbine and Turbine Generator Set Unit Manufacturing
1,500 Employees
523920
Portfolio Management
$41.5 million in revenue
524113
Direct Life Insurance Carriers
$41.5 million in revenue
524126
Direct Property and Casualty Insurance Carriers
1,500 employees
541614
Process, Physical Distribution and Logistics Consulting Services
$17.5 million in revenue
551112
Offices of Other Holding Companies
$40.0 million in revenue
562219
Other Nonhazardous Waste Treatment and Disposal
$41.5 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 May 2, 2022).
c. NAICS code used as proxy for determining size threshold for entities categorized in NAICS 221119.
Source: SBA, 2019
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 or
corporate/financial websites, if those values were available.
• Revenue: EPA used entity-level revenue values from Dun and Bradstreet 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 2019) (U.S. Census Bureau,
2019).
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 and 2020 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, 2015,2020b).
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 229 and 427 entities own 871 steam
electric power plants (for Case 1 and Case 2, respectively).64 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 109 (48 percent) and 200 (47 percent) parent entities are small (Table 8-2), and these small
entities own 250 steam electric power plants (Table 8-3), or approximately 29 percent of all steam electric
power plants. Across ownership types, nonutility entities have the largest share of small entities (69.5 and
73 percent, for Case 1 and Case 2 respectively); however, cooperatives have the largest share of steam
electric power plants owned by small entities (73 percent).
Table 8-2: Number of Entities by Sector and Size (assuming two different ownership cases)
Ownership Type
Small Entity Size
Standard
Case 1: Lower bound estimate of
number of entities owning steam
electric power plantsa,b
Case 2: Upper bound estimate
of number of entities owning
steam electric power plantsa,b
Total
Small
% Small
Total
Small
% Small
Cooperative
number of employees
21
14
66.67%
32
22
70.44%
Federal
assumed large
3
0
0.00%
10
0
0.00%
Investor-owned
number of employeesd
59
13
22.03%
102
20
19.63%
Municipality
50,000 population served
51
22
43.14%
87
29
32.87%
Nonutility
number of employeesd
82
57
69.51%
167
122
72.91%
Other Political
Subdivision0
50,000 population served
8
3
37.50%
19
7
38.31%
As described in Chapter 8 in the 2015 RIA (U.S. EPA, 2015), Case 1 assumed that any entity owning a surveyed
plant(s) owns the known surveyed plant(s) and all of the sample weight associated with the surveyed 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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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
number of entities owning steam
of number of entities owning
Small Entity Size
electric power plantsa b
steam electric power plantsa b
Ownership Type
Standard
Total
Small
% Small
Total
Small
% Small
State
assumed large
5
0
0.00%
10
0
0.00%
Total
229
109
47.60%
427
200
46.95%
a. Eleven plants are owned by a joint venture of two entities.
b. Of these, 61 entities, 17 of which are small, own steam electric power plants that are estimated to incur compliance
technology costs under Option 3 under both Case 1 and Case 2.
c. EPA was unable to determine the size of nine 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, 2022.
Table 8-3: Steam Electric Power Plants by Ownership Type and Size
Ownership Type
Small Entity Size Standard
Number of Steam Electric Power Plantsa bcd
Total
Small
% Small
Cooperative
number of employees
59
43
73.4%
Federal
assumed large
23
0
0.0%
Investor-owned
number of employees6
328
38
11.5%
Municipality
50,000 population served
111
30
26.6%
Nonutility
number of employees6
313
134
42.7%
Other Political Subdivisions
50,000 population served
29
6
21.3%
State
assumed large
8
0
0.0%
Total
871
250
28.7%
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, 93 steam electric power plants are estimated to incur compliance costs under proposed Option 3; 20 of the 93
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, 2022.
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?
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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 summarizes the results of the analysis. 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.
Under Options 1 and 2, EPA estimates that 1 small municipality and 1 small nonutility owning steam
electric power plants would incur costs exceeding one percent of revenue (Table 8-4). On the basis of
percentage, the small municipality represents approximately 4 to 5 percent of the number of small
municipalities owning steam electric power. The small nonutility represents approximately 1 to 2 percent
of the number of small nonutilities owning steam electric power plants. This small municipality and small
nonutility represent approximately 1 to 2 percent of the total number of small entities owning steam
electric power plants. Under Options 3 and 4, EPA estimates that two small municipalities and one small
nonutility owning steam electric power plants would incur costs exceeding one percent of revenue. On the
basis of percentage, these small municipalities represent approximately 7 to 9 percent of the number of
small municipalities owning steam electric power plants. The small nonutility represents approximately 1
to 2 percent of the number of small nonutilities owning steam electric power plants. These two small
municipalities and 1 small nonutility represent 1 to 3 percent of the total number of small entities owning
steam electric power plants. The analysis shows one small business (one nonutility) entity incurring costs
greater than three percent of revenue under any of the regulatory options. Overall, this worst-case
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screening-level analysis suggests that the analyzed regulatory options are unlikely to have a significant
economic impact on a substantial impact on small entities.
Table 8-4: Estimated Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and
Ownership Category
Entity
Type/Ownership
Category
Case 1: Lower bound estimate of number
of entities owning steam electric power
plants (out of total of 109 small entities)
Case 2: Upper bound estimate of number
of entities owning steam electric power
plants (out of total of 200 small entities)
>1%
>3%a
>1%
>3%a
Number
of small
entities
% of all
small
entities'5
Number
of small
entities
% of all
small
entities'5
Number
of small
entities
% of all
small
entities'5
Number
of small
entities
% of all
small
entities'5
Option 1
Small Business
Cooperative
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
1
1.8%
1
1.8%
1
0.8%
1
0.8%
Small Government
Municipality
1
4.5%
0
0.0%
1
3.5%
0
0.0%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
2
1.8%
1
0.9%
2
1.0%
1
0.5%
Option 2
Small Business
Cooperative
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
1
1.8%
1
1.8%
1
0.8%
1
0.8%
Small Government
Municipality
1
4.5%
0
0.0%
1
3.5%
0
0.0%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
2
1.8%
1
0.9%
2
1.0%
1
0.5%
Option 3
Small Business
Cooperative
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
1
1.8%
1
1.8%
1
0.8%
1
0.8%
Small Government
Municipality
2
9.1%
0
0.0%
2
7.0%
0
0.0%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
3
2.8%
1
0.9%
3
1.5%
1
0.5%
Option 4
Small Business
Cooperative
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
1
1.8%
1
1.8%
1
0.8%
1
0.8%
Small Government
Municipality
2
9.1%
0
0.0%
2
7.0%
0
0.0%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
3
2.8%
1
0.9%
3
1.5%
1
0.5%
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Table 8-4: Estimated Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and
Ownership Category
Entity
Type/Ownership
Category
Case 1: Lower bound estimate of number
of entities owning steam electric power
plants (out of total of 109 small entities)
Case 2: Upper bound estimate of number
of entities owning steam electric power
plants (out of total of 200 small entities)
>1%
>3%a
>1%
>3%a
Number
of small
entities
% of all
small
entities'5
Number
of small
entities
% of all
small
entities'5
Number
of small
entities
% of all
small
entities'5
Number
of small
entities
% of all
small
entities'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 109 (Case 1) and 200 (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, 2022
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 1 through 4 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 proposed 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 $170 million in 2021 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 $31 million under Option 1 to $46 million under
Options 3 and 4.65'66 The maximum compliance cost in any given year to the private sector range from
$248 million under Option 1 to $515 million under Option 4. From these compliance cost values, EPA
determined that the proposed rule does not contain a federal mandate that may result in expenditures of
$170 million (in 2021 dollars) or more for State, local, and Tribal governments, in the aggregate, in any
one year. However, EPA determined that the proposed rule does contain a federal mandate that may result
in expenditures of $170 million (in 2021 dollars) or more for the private sector 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 (U.S. EPA, 2015, 2020b; 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, 2023a). Specifically, this analysis uses costs in 2024 stated in 2021 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 proposed rule would not increase the reporting and recordkeeping burden for the
review, oversight, and administration of the rule relative to baseline requirements. NPDES permitting
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.
For this analysis, rural electric cooperatives are considered to be a part of the private sector.
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authorities are required to determine site-specific volumes and technologies for bottom as purge water
using BPG but are estimated to see no significant change in costs 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 871 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 Chapter 4 (Cost and Economic Impact Screening Analyses) 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
51
111
Other Political Subdivision
8
29
State
5
8
Tribal
0
0
Total
64
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 871 plants covered under the point source category.
Source: U.S. EPA Analysis, 2022
Out of 871 steam electric power plants, 148 are owned by 64 government entities.67 The majority
(75 percent) of these government-owned plants are owned by municipalities, followed by other political
subdivisions (20 percent), and State governments (5 percent).
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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Table 9-2 shows compliance costs for government entities owning steam electric power plants.
Compliance costs to government entities under the regulatory options range from approximately
$8 million to $12 million in the aggregate. Average annualized costs per plant are $0.1 million for each
regulatory option. Additionally, for each of the analyzed options, municipalities incur the majority of
compliance costs. The maximum annualized compliance costs range from $1.15 million to $1.77 million.
Table 9-2: Estimated Compliance Costs to Government Entities Owning Steam Electric Power
Plants (Millions of 2021$)
Number of
Average
Steam Electric
Total Weighted,
Annualized Cost
Average
Maximum
Power Plants
Annualized Pre-
per MW of
Annualized Cost
Annualized Cost
Ownership Type
(weighted)3
Tax Cost3
Capacity13
per Plantc
per Plantd
Option 1
Municipality
111
$6
$154
1
o
¦uy
$1.15
Other Political Subdivision
29
$1
$64
$0.0
$1.08
State
8
$1
$131
$0.1
$1.12
Total
148
$8
$127
$0.1
$1.15
Option 2
Municipality
111
$8
$204
$0.1
$1.77
Other Political Subdivision
29
$1
$64
o
o
¦uy
$1.08
State
8
$1
$131
i
o
¦uy
$1.12
Total
148
$10
$157
$0.1
$1.77
Option 3
Municipality
111
$9
$243
1
o
¦uy
$1.77
Other Political Subdivision
29
$2
$90
i
o
¦uy
$1.08
State
8
$1
$132
i
o
¦uy
$1.12
Total
148
$12
$187
$0.1
$1.77
Option 4
Municipality
111
$9
$242
1
o
¦uy
$1.76
Other Political Subdivision
29
$2
$90
$0.1
$1.08
State
8
$1
$131
$0.1
$1.12
Total
148
$12
$187
$0.1
$1.76
a. Plant counts are relative to the estimated 871 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, 2022.
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
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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.
Out of 148 government-owned steam electric power plants, EPA identified 36 plants that are owned by
25 small government entities. These 36 plants constitute approximately 24 percent of all government-
owned plants.68
Table 9-3: 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
29
22
51
81
30
111
Other Political Subdivision
5
3
8
23
6
29
State
5
0
5
8
0
8
Total
39
25
64
112
36
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 871 plants covered under the point source category.
Source: U.S. EPA Analysis, 2022.
As presented in Table 9-4, under regulatory options 1 through 4, overall compliance costs are greatest
under Option 4 ($224 million) and smallest under Option 1 ($97 million), and the distribution of
compliance costs among different entity categories and sizes is uniform. For all options, aggregate
compliance costs are the largest for large private entities, followed by small private entities, large
governments, and small governments. On a per MW basis, small governments are projected to see the
largest annualized compliance costs - as much as $417 per MW under Option 3 - compared to large
governments or private entities. Because plants owned by small governments tend to be smaller compared
to those owned by large governments or small private entities, the same is not necessarily true on a per
plant basis under the regulatory options. Given these results, EPA finds that small governments would not
be significantly or uniquely affected by the regulatory options, including the proposed rule.
68
Counts exclude federal government entities and steam electric power plants they own.
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Table 9-4: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type
and Size (2021$)
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 1
Government
(excl. federal)
Small
36
$1
$149
$0.03
$1.0
Large
113
$7
$124
$0.06
$1.1
Private
Small
214
$17
$185
$0.08
$2.0
Large
485
$69
$150
$0.14
$9.3
All Plants
871
$97
$151
$0.11
$9.3
Option 2
Government
(excl. federal)
Small
36
$1
$192
$0.03
$1.0
Large
113
$9
$153
$0.08
$1.8
Private
Small
214
$20
$220
$0.09
$3.5
Large
485
$147
$323
$0.30
$21.1
All Plants
871
$180
$282
$0.21
$21.1
Option 3
Government
(excl. federal)
Small
36
$3
$417
$0.08
$1.0
Large
113
$9
$161
$0.08
00
¦uy
Private
Small
214
$25
$265
$0.11
$3.5
Large
485
$176
$387
$0.36
$23.0
All Plants
871
$216
$339
$0.25
$23.0
Option 4
Government
(excl. federal)
Small
36
$3
$416
$0.08
$1.0
Large
113
$9
$161
$0.08
00
¦uy
Private
Small
214
$25
$265
$0.11
$3.5
Large
485
$183
$402
$0.38
$23.0
All Plants
871
$224
$350
$0.26
$23.0
a. Plant counts are relative to the estimated 871 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, 2022.
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 9-5 summarizes the total annualized costs, maximum one-year costs, and the year when maximum
costs are incurred by type of owner. EPA estimates the total annualized pre-tax compliance costs for
private entities to range from $86 million under Option 1 to $208 million under Option 4.
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Table 9-5: Compliance Costs for Electric Generators by Ownership Type (2021$)
Ownership Type
Total Annualized
Maximum One-
Year of Maximum
Costs
Year Costs
Costs3
Option 1
Government (excl. federal)
$8
1
m
¦uy
2027
Private
ID
00
¦uy
$249
2029
Option 2
Government (excl. federal)
o
i
¦uy
$37
2027
Private
$167
$449
2026
Option 3
Government (excl. federal)
$12
$46
2027
Private
$201
$504
2026
Option 4
Government (excl. federal)
$12
$46
2027
Private
$208
$515
2026
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, 2022.
9.4 UMRA Analysis Summary
EPA estimates that none of the regulatory options would result in expenditures of at least $170 million for
State and local government entities, in the aggregate, in any one year under any of the regulatory options
EPA analyzed for the proposed rule. However, the Agency does estimate that the private sector would
incur expenditures of greater than $170 million, in the aggregate, in any one year. 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.
Consistent with Section 205, EPA presents four regulatory options which would all result in compliance
costs to governments and the private sector. For Proposed Option 3, the maximum compliance costs
incurred by the private sector in any one year are $504 million in 2026, whereas total annualized
compliance costs for plants owned by private sector entities are $201 million. The implementation period
built into the proposed rule is one way that EPA accounted for the site-specific needs of steam electric
power plants. EPA has also attempted to reduce impacts to early adopters through the creation of a new
subcategory under Option 3.
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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 proposed 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 and Executive Order 13563:
Improving Regulation and Regulatory Review
Under Executive Order (E.O.) 12866 (58 FR 51735, October 4, 1993), 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 $100 million or more, 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 arising out of legal mandates, the President's priorities, or the
principles set forth in the Executive Order.
Executive Order 13563 (76 FR 3821, January 21, 2011) was issued on January 18, 2011. This Executive
Order supplements Executive Order 12866 by outlining the President's regulatory strategy to support
continued economic growth and job creation, while protecting the safety, health and rights of all
Americans. Executive Order 13563 requires considering costs, reducing burdens on businesses and
consumers, expanding opportunities for public involvement, designing flexible approaches, ensuring that
sound science forms the basis of decisions, and retrospectively reviewing existing regulations.
Pursuant to the terms of Executive Order 12866, EPA determined that the proposed rule (Option 3) is an
"economically significant regulatory action" because the action is likely to have an annual effect on the
economy of $100 million or more. As such, the action is subject to review by OMB under Executive
Orders 12866 and 13563. Any changes made in response to OMB suggestions or recommendations 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, 2023a).
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
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consumer group (Chapter 7: Electricity Price Effects), and on employment or labor markets (Chapter 6:
Employment Effects).
10.2 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations and Executive Order 14008: Tackling the
Climate Crisis at Home and Abroad
Executive Order 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.
Executive Order 14008 (86 FR 7619, February 1, 2021) expands on the policy objectives established in
E.0.12898 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 proposed action
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, 2023d).
10.3 Executive Order 13045: Protection of Children from Environmental Health Risks and
Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that (1) is determined to be
"economically significant" as defined under Executive Order 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, 2023a; U.S. EPA, 2023c), 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 the changes in IQ losses 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 may require compensatory education tailored
to their specific needs.
EPA estimated that the proposed rule could benefit children. The analysis shows relatively small potential
changes in lead exposure (from fish consumption) for an average of 1.4 million children annually, and in
mercury exposure (from maternal fish consumption) for an average of 187,500 infants born annually.
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However, EPA estimates the resulting health impacts to be relatively small. EPA estimated that the
proposed rule (Option 3) would lead to slight reductions in lead and mercury exposure, increasing IQ
losses by approximately 6 points from lead exposure and 3,923 points from mercury exposure over the
entire exposed population. The social welfare effects from reduced IQ loss associated with children's
exposure to lead and mercury are $3.1 million and $0.6 million using 3 percent and 7 percent discount
rates, respectively. Chapter 5 in the BCA provides further details, including results for the other
regulatory options (U.S. EPA, 2020a). 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
Executive Order 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 Executive Order 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 proposed 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 $31 million under Option 1 to
$46 million under Options 3 and 4 (see Chapter 9, Unfunded Mandates Reform Act (UMRA), for details).
Annualized compliance costs incurred by governments range from $8 million under Option 1 to
$12 million under Options 3 and 4.
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10.5 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
Executive Order 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 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 9 public water systems (PWS) operated by
tribal governments that may be affected by bromide and iodine discharges from steam electric
power plants.69 In total, these systems serve approximately 11,600 people. This analysis finds
relatively small reductions in bromide and iodine concentrations in the source waters of these
PWS. The analysis is detailed in Chapter 4 of the BCA (U.S. EPA, 2020a).
• 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
Executive Order 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 Executive Order 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."70 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;
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.
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 coal production in excess of 5 million tons per year;
• 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 proposed 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 proposed Option 3 (see Chapter 5), 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 proposed rule will decrease coal-fired
generation, including generation from power plants to which the proposed rule applies, by 0.2 percent to
approximately 4.1 percent in 2028 through 2055, 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 2030 decreases by 262 GWh,
which is less than 0.01 percent of baseline generation. These changes are very small and support EPA's
assessment that the proposed 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 proposed rule
would result in net cumulative retirements of 6 MW of generating capacity by 2030, and net cumulative
retirement of 500 MW by 2055.
10.6.3 Cost of Energy Production
Based on the IPM analysis results, EPA estimated that the proposed 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 and capital) under the proposed rule are projected to increase 0.1 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 2030 run year and shows range from an increase of less than 0.1 percent
in WECC to an increase of 0.2 percent in RF under the proposed rule. None of the NERC regions show
increases approaching 1 percent.
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Consequently, no region would experience 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
proposed 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 2030 under the baseline
and the proposed rule. The proposed rule is estimated to decrease coal-based electricity generation by
1.12 percent, while generation using several other sources of energy is estimated to either increase
(natural gas, nuclear, wind, hydro, and landfill gas), or decrease (i.e.. oil/gas steam, solar). Apart from
coal generation, changes are less than 1 percent across all generation types.
Table 10-1: Total Market-Level Capacity and Generation by Type for the Proposed Rule in 2030
Generating Capacity
GW)
Electricity Generation (Thousand GWh)
Type
Baseline
Option 3
% Change
Baseline
Option 3
% Change
Hydro
103.3
103.3
0.00%
304.9
305.2
0.09%
Biomass
0.3
0.3
0.00%
0.2
0.2
0.00%
Geothermal
2.9
2.9
0.00%
20.2
20.2
0.00%
Landfill Gas
2.8
2.8
0.00%
17.3
17.3
0.01%
Solar
148.2
148.0
-0.10%
348.9
348.6
-0.08%
Wind
207.6
207.6
0.01%
712.4
712.5
0.02%
Coal
111.8
111.6
-0.24%
557.9
551.6
-1.12%
Nuclear
78.1
78.3
0.30%
628.5
630.2
0.28%
Natural Gas
478.0
478.0
0.00%
1,780.1
1,784.8
0.27%
Oil/Gas
Steam
64.8
64.8
0.04%
35.5
35.4
-0.32%
Other"
39.5
39.5
0.02%
75.1
75.1
0.06%
Total3
1,237.1
1,237.0
-0.01%
4,480.9
4,481.1
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, 2022.
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 (0.78 percent)
and more natural gas (0.24 percent) consumed under the proposed rule. Changes are less than 1 percent
for natural gas, lignite and subbituminous coal. However, bituminous coal consumption decreases by 2.04
percent.
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Table 10-2: Total Market-Level Fuel Use by Fuel Type for the Proposed Rule in 2030
Fuel Consumption
Fuel Type
Baseline
Option 3
% Change
Coal (million tons)
291
288
-0.98%
Bituminous Coal (million tons)
99
97
-2.04%
Subbituminous Coal (million tons)
153
152
-0.69%
Lignite (million tons)
40
40
0.58%
Natural Gas (trillion cubic feet)
13
13
0.24%
Source: U.S. EPA Analysis, 2022.
Given the very small changes in coal and other fuels use under the proposed 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 proposed rule does not constitute a "significant energy action" from the perspective of energy
independence.
10.6.5 Overall E.0.13211 Finding
From these analyses and the electricity markets analysis in Chapter 5, EPA concludes that the proposed
rule would not have a significant adverse effect at a national or regional level under Executive Order
13211. Specifically, the Agency's analysis found that the 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 would
the rule increase U.S. dependence on foreign supply of energy. As such, the proposed rule does not
constitute a significant regulatory action under Executive Order 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;
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• completing and reviewing the response; and
• transmitting or disclosing information.
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.71
EPA is proposing several changes to the individual reporting and recordkeeping requirements of section
423.19 for specific subcategories of plants and/or plants that have certain types of discharges. EPA is
proposing to add reporting and recordkeeping requirements to plants in the early adopter subcategory and
plants that discharge CRL through groundwater, and to remove reporting and recordkeeping requirements
for low utilization EGUs. EPA is also proposing a new requirement for plants to post reports to a publicly
available website. EPA estimated small changes in reporting and recordkeeping costs at steam electric
power plants under the regulatory options presented in today's proposal relative to the baseline. EPA
estimates it would take a total annual average of 6,900 hours and $399,000 for affected steam electric
power plants to collect and report the information in the proposed rule. These costs are in addition to
those detailed in Chapter 4 through Chapter 9 of this document.
EPA estimates it would take a total annual average of 2,025 hours and $99,000 for permitting or control
authorities to review the information submitted by facilities. 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 4 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 proposed rule.
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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Platform v6 Using the Integrated Planning Model. 1200 Pennsylvania Avenue, NW, Washington
D C. 20460
U.S. Environmental Protection Agency. (2018b). EPA Methodology for Power Sector-Specific
Employment Analysis. Retrieved from https://www.epa.gov/airmarkets/power-sector-labor-
analvsis-methodology
U.S. Environmental Protection Agency. (2020a). Benefit and Cost Analysis for Revisions to the Effluent
Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source
Category. (EPA-82 l-R-20-003).
U.S. Environmental Protection Agency. (2020b). Regulatory Impact Analysis for Revisions to the Effluent
Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source
Category. (EPA-821-R-23-002).
U.S. Environmental Protection Agency. (2021). Documentation for EPA's Power Sector Modeling
Platform v6- Summer 2021 Reference Case. Retrieved from
https://www.epa.gov/airmarkets/documentation-epas-power-sector-modeling-platform-v6-
summer-2021 -reference-case
U.S. Environmental Protection Agency. (2023a). Benefit and Cost Analysis for Proposed Revisions to the
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point
Source Category.
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11: References
U.S. Environmental Protection Agency. (2023b). Documentation for EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model - 2022 Reference Case. Retrieved from
https://www.epa.gov/power-sector-modeling/documentation-pre-ira-2022-reference-case
U.S. Environmental Protection Agency. (2023c). Environmental Assessment for Proposed Supplemental
Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category.
U.S. Environmental Protection Agency. (2023d). Environmental Justice Analysis for Proposed
Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category
U.S. Environmental Protection Agency. (2023e). Technical Development Document for Proposed
Supplemental Revisions to the Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category.
U.S. Small Business Administration. (2019). Table of Small Business Size Standards Matched to North
American Industry Classification System Codes. Effective August 19, 2019. Retrieved from
https://www.sba.gov/document/support-table-size-standards
U.S. Small Business Administration. (2022). Table of Small Business Size Standards Matched to North
American Industry Classification System Codes. Effective December 19, 2022. Retrieved from
https://www.sba.gov/document/support-table-size-standards
Wilson, M. (2022). What the Russia crisis means for U.S. electricity mix. E&E News.
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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 proposed ELG rule as compared to the final ELG reconsideration rule described
in the 2020 RIA (U.S. EPA, 2020b).
Table A-1: Changes to Costs and Economic Impacts Analysis Since 2020 Rule
Cost or Impact Category
Analysis Component
Cost or Impact Category
General inputs for
screening-level analyses
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
Generating capacity from 2018 EIA-860
Updated using 2020 EIA-860
NERC regions from 2017 EIA-860
Updated using 2020 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]
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
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.
Industry data (i.e., capacity, generation,
number of plants, etc.) from 2018 EIA
databases
Updated using 2020 EIA databases
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]
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.
Potential electricity
price effects
Projected total electricity sales in [2020]
from [AEO 2019]
Projected total electricity sales in [2024]
from [AEO 2021]
Electricity sales data by consumer group
from [2018] EIA-860 database
Electricity sales data by consumer group
from [2020] EIA-860 database
Owner-level impacts
and RFA/SBREFA
Owners identified in EIA-860 [2018]
Owners identified in EIA-860 [2020]
Small business size determination metrics
[Dun and Bradstreet for private entities;
Census ACS 2017 for governments]
Small business size determination metrics
[Dunn and Bradstreet for private entities;
Census ACS 2017 for governments]
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Appendix B: Costs and Pollutant Removals
nparison 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 for the 2015 and 2020 rules, 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, 2023e) 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.
7. Calculate the cost-effectiveness ratios for each control option and for direct and indirect
dischargers.
The regulatory options analyzed for this proposed rule represent only a subset of the requirements
contained in the ELG for the steam electric industry since they address only three of the relevant
wastestreams. Accordingly, EPA did not calculate the cost-effectiveness ratios for the regulatory options
since these ratios would not be comparable to cost-effectiveness values EPA estimated for the 2015 rule
(see Appendix F in U.S. EPA, 2015) or for ELGs for other point source categories. 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.72
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, 2023e).
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. For TWF and POTW removal factors, see Appendix F in U.S. EPA, 2015.
Evaluated Options
EPA analyzed Options 1 through 4 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, 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,
2023e). 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
values in 1981 dollars per pound-equivalent removed. Figure B-l compares the pollutant removals and
costs of the regulatory options graphically.
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Appendix B: Costs and Pollutant Removals
Table B-1: Estimated Pollutant Removal and Costs of Regulatory Options by Discharger Category
Discharger
Total Annual TWF-Weighted
Pollutant Removals (Ib-eq.)
Total Annual Pre-tax
Compliance Costs
(million, 2021$)
Cost- Effect iven ess
(1981$/lb-eq.)a
Category
Optionb
Totalc
Incremental
Totalc
Incremental
Totalc
Incremental
1
34,944
34,944
$99.0
$99.0
$825
$825
Direct
2
210,564
175,619
$185.6
$86.6
$257
$144
3
212,651
2,088
$227.1
$41.5
$311
$5,792
4
229,949
17,298
$237.9
$10.8
$301
$182
1
341
0
$3.4
o
o
¦uy
$2,886
Indirect
2
341
0
$3.4
o
o
¦uy
$2,886
3
341
0
$3.4
o
o
¦uy
$2,886
4
341
0
$3.4
o
o
¦uy
$2,886
a. Compliance costs adjusted to 1981 dollars using the CCI (3,535 / 12,133 = 0.291)
b. Options are listed in increasing order of pollutant removals, relative to the baseline.
c. Total removals and costs are compared to those for the baseline.
d. 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 1 are calculated relative to the baseline, the incremental
removals and costs for Option 2 are calculated relative to those of Option 1, etc.
Source: U.S. EPA Analysis, 2022
Figure B-1: Estimated Removals and Costs of the Regulatory Options, Relative to Baseline.
Option 4
•
•
Option 3
•
Option 2
•
Option 1
$300
$250
£ ^
C
Q) o
U —
C ~
$100 ~ ^
Q. —
E
o
U
$50 "S
N
c
$0 <
0 50,000 100,000 150,000 200,000 250,000
Pollutant removals, relative to baseline (TWPE)
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