United States
Environmental Protection
Agency
Office of Water
Washington, DC 20460
EPA-821 -R-20-004
August 28, 2020
Regulatory Impact Analysis
for Revisions to the Effluent
Limitations Guidelines and
Standards for the Steam
Electric Power Generating
Point Source Category
-------
S-EPA
United States
Environmental Protection
Agency
Regulatory Impact Analysis for Revisions to
the Effluent Limitations Guidelines and
Standards for the Steam Electric Power
Generating Point Source Category
EPA-821 -R-20-004
August 28, 2020
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 Final Rule 1-2
1.2.2 Baseline 1-4
1.2.3 Cost and Economic Analysis Requirements under the Clean Water Act 1-4
1.2.4 Analyses of the Regulatory Options and Report Organization 1-5
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 2-8
2.2.1 Affordable Clean Energy (ACE) Rule 2-8
2.2.2 Coal Combustion Residuals Rule 2-9
2.3 Market Conditions and Trends in the Electric Power Industry 2-10
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 3-4
3.1.4 Total Compliance Costs 3-6
3.1.5 Voluntary Incentive Program 3-8
3.2 Key Findings for Regulatory Options 3-8
3.2.1 Estimated Industry-level Total Compliance Costs 3-8
3.2.2 Estimated Regional Distribution of Incremental Compliance Costs 3-10
3.3 Key Uncertainties and Limitations 3-11
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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 4-5
4.3 Cost-to-Revenue Screening Analysis: Parent Entity-Level Analysis 4-5
4.3.1 Analysis Approach and Data Inputs 4-5
4.3.2 Key Findings for Regulatory Options 4-7
4.3.3 Uncertainties and Limitations 4-9
5 Assessment of the Impact of the Final Rule on National and Regional Electricity Markets..5-1
5.1 Model Analysis Inputs and Outputs 5-3
5.1.1 Analysis Years 5-3
5.1.2 Key Inputs to IPM V6 for the Market Model Analysis of the Final Rule 5-4
5.1.3 Key Outputs of the Market Model Analysis Used in Assessing the Effects of the Final Rule
5-5
5.2 Findings from the Market Model Analysis 5-5
5.2.1 National-level Analysis Results for Model Years 2021-2050 5-6
5.2.2 Detailed Analysis Results for Model Year 2030 5-9
5.3 Estimated Effects of the Regulatory Options on New Capacity 5-22
5.4 Uncertainties and Limitations 5-22
6 Assessment of the Impact of the Regulatory Options on Employment 6-1
6.1 Background and Context 6-1
6.1.1 Employment Impacts of Environmental Regulations 6-1
6.1.2 Discussion of Employment Impacts of the Final Rule 6-2
6.2 Analysis Overview 6-3
6.2.1 Estimated Employment Effects in Coal-Fired Electric Power Plants Affected by the
Regulatory Options 6-3
6.2.2 Coal Mining and Other Energy Sources 6-4
6.3 Findings 6-4
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
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7.2.2 Key Findings for Regulatory Options 7-2
7.2.3 Uncertainties and Limitations 7-7
7.3 Assessment of Impact of Compliance Costs on Household Electricity Costs 7-7
7.3.1 Analysis Approach and Data Inputs 7-8
7.3.2 Key Findings for Regulatory Options A through C 7-8
7.3.3 Uncertainties and Limitations 7-10
7.4 Distribution of Electricity Cost Impact on Household 7-10
8 Assessment of Potential Impact of the Regulatory Options on Small Entities - Regulatory
Flexibility Act (RFA) Analysis 8-1
8.1 Analysis Approach and Data Inputs 8-2
8.1.1 Determining Parent Entity of Steam Electric Power Plants 8-2
8.1.2 Determining Whether Parent Entities of Steam Electric Power Plants Are Small 8-2
8.1.3 Significant Impact Test for Small Entities 8-6
8.2 Key Findings for Regulatory options 8-6
8.3 Uncertainties and Limitations 8-9
8.4 Small Entity Considerations in the Development of Rule Options 8-10
9 Unfunded Mandates Reform Act (UMRA) Analysis 9-1
9.1 UMRA Analysis of Impact on Government Entities 9-2
9.2 UMRA Analysis of Impact on Small Governments 9-5
9.3 UMRA Analysis of Impact on the Private Sector 9-7
9.4 UMRA Analysis Summary 9-8
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 13771: Reducing Regulation and Controlling Regulatory Costs 10-2
10.3 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations
and Low-Income Populations 10-2
10.4 Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
10-3
10.5 Executive Order 13132: Federalism 10-4
10.6 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments 10-4
10.7 Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply,
Distribution, or Use 10-5
10.7.1 Impact on Electricity Generation 10-6
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10.7.2Impact on Electricity Generating Capacity 10-6
10.7.3 Cost of Energy Production 10-6
10.7.4 Dependence on Foreign Supply of Energy 10-7
10.7.5 Overall E.O. 13211 Finding 10-8
10.8 Paperwork Reduction Act of 1995 10-8
10.9 National Technology Transfer and Advancement Act 10-9
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
B.l Methodology 1
B.2 Results 2
Toxic Weights of Pollutants and POTW Removal 2
Evaluated Options 2
Pollutant Removals and Pound Equivalent Calculations 2
Annualized Compliance Costs 2
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Contents
List of Tables
Table ES-1: Regulatory Options 1
Table 1-1: Regulatory Options 1-3
Table 2-1: Steam Electric Industry Share of Total Electric Power Generation Plants and Capacity in 2018
2-2
Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity by
Ownership Type, 2018 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, 2018 2-6
Table 2-7: Net Generation by Energy Source and Ownership Type, 2012-2018 (TWh) 2-7
Table 3-1: Compliance Deadlines for the Baseline and Regulatory Options 3-4
Table 3-2: Estimated Total Annualized Compliance Costs (in millions, 2018$, at 2020) 3-9
Table 3-3: Estimated Incremental Annualized Compliance Costs (in millions, 2018$, at 2020) 3-9
Table 3-4: Estimated Incremental Annualized Compliance Costs, by Wastestream (in millions, 2018$, at
2020) 3-9
Table 3-5: Estimated Annualized Incremental Compliance Costs by NERC Region (in millions, 2018$, at
2020) 3-10
Table 4-1: Plant-Level Cost-to-Revenue Analysis Results for the Baseline by Owner Type 4-3
Table 4-2: Plant-Level Incremental Cost-to-Revenue Analysis Results by Owner Type and Regulatory
Option 4-4
Table 4-3: Baseline Entity-Level Cost-to-Revenue Analysis Results 4-8
Table 4-4: Entity-Level Incremental Cost-to-Revenue Analysis Results 4-8
Table 5-1: IPM Run Years 5-4
Table 5-2: Baseline Projections, 2021-2050 5-6
Table 5-3: National Impact of Final Rule Relative to Baseline, 2021-2050 5-7
Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2030 5-10
Table 5-5: Impact of the Final Rule on In-Scope Plants, as a Group, in the Year 2030a 5-16
Table 5-6: Impact of Final Rule on Individual In-Scope Plants in the Year 2030 5-21
Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2020 (2018$) 7-3
Table 7-2: Projected 2020 Price (Cents per kWh of Sales) and Potential Price Increase Due to Compliance
Costs by NERC Region and Regulatory Option (2018$) 7-5
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Table 7-3: Potential Incremental Price Changes Relative to Baseline Due to Compliance Costs by NERC
Region and Regulatory Option (2018$) 7-6
Table 7-4: Average Incremental Annual Cost per Household in 2020 by NERC Region and Regulatory
Option (2018$) 7-9
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) 8-5
Table 8-3: Steam Electric Power Plants by Ownership Type and Size 8-5
Table 8-4: Estimated Baseline Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and
Ownership Category 8-7
Table 8-5: Estimated Incremental Cost-To-Revenue Impact on Small Parent Entities, by Entity Type and
Ownership Category 8-8
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 2018$) 9-3
Table 9-3: Estimated Incremental Compliance Costs to Government Entities Owning Steam Electric
Power Plants (Millions of 2018$) 9-4
Table 9-4: Counts of Government-Owned Plants and Their Parent Entities, by Size 9-6
Table 9-5: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type and Size
(2018$) 9-6
Table 9-6: Compliance Costs for Electric Generators by Ownership Type (2018$) 9-8
Table 10-1: Total Market-Level Capacity and Generation by Type for the Final Rule in 2030 10-7
Table 10-2: Total Market-Level Fuel Use by Fuel Type for the Final Rule in 2030 10-8
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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
ACE
Affordable Clean Energy
AEO
Annual Energy Outlook
ASCC
Alaska Systems Coordinating Council
BAT
Best available technology economically achievable
BCA
Benefit and Cost Analysis
BEA
U.S. Bureau of Economic Analysis
BLS
U.S. Bureau of Labor Statistics
BMP
Best management practice
BPJ
Best professional judgment
BPT
Best practicable control technology currently available
BSER
Best system of emissions reduction
CAA
Clean Air Act
CCI
Construction cost index
CCR
Coal combustion residuals
CFR
Code of Federal Regulations
CP
Chemical precipitation
CPP
Clean Power Plan
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
GW
Gigawatt
GWh
Gigawatt-hour
HICC
Hawaii Coordinating Council
HRI
Heat rate improvement
HRR
High recycle rate
HRTR
High Hydraulic Residence Time Reduction
IPM
Integrated Planning Model
kWh
Kilowatt-hour
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Abbreviations
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
NAICS
North American Industry Classification System
NERC
North American Electric Reliability Corporation
NPCC
Northeast Power Coordinating Council
NPDES
National Pollutant Discharge Elimination System
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
RCRA
Resource Recovery and Conservation Act
RIA
Regulatory Impact Analysis
RFA
Regulatory Flexibility Act
RFC
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 Regional Reliability Entity
TWF
Toxic weighting factor
TWh
Terawatt-hour
TWPE
Toxic weighted pound equivalent
UMRA
Unfunded Mandates Reform Act
use
United States Code
VIP
Voluntary Incentive Program
VOM
Variable O&M
WECC
Western Energy Electricity Coordinating Council
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Executive Summary
Executive Summary
The U.S. Environmental Protection Agency (EPA) is finalizing revisions to the technology-based effluent
limitations guidelines and standards (ELGs) for the steam electric power generating point source
category, 40 CFR part 423, which EPA proposed in November 2019 (84 FR 64620). The final rule revises
certain best available technology (BAT) effluent limitations and pretreatment standards for existing
sources for two wastestreams: flue gas desulfurization (FGD) wastewater and bottom ash transport water.
This action is an economically significant deregulatory 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 action and presents analyses to
meet various statutory and Executive Order requirements. The accompanying Benefit Cost Analysis
(BCA) document presents social costs and benefits of the action, consistent with Executive Orders 12866,
13563, and 13771.
Regulatory Options
EPA analyzed four regulatory options at proposal, the details of which were discussed in the proposed
rule [84 FR 64620], For the final rule, EPA evaluated four regulatory options as shown in Table ES-1.
Proposed regulatory options 1, 2, 3, and 4 correspond generally to regulatory options D, A, B, and C here,
but do contain differences as detailed below. Public commenters generally supported three of the
regulatory options that EPA proposed or variants thereof.1 The availability and achievability of
technologies with better pollutant removals, as well as with the general lack of public comments in
support for proposed regulatory Option 1, led EPA to focus updates to the Agency's analysis on the
remaining three regulatory options. EPA did not update the analyses for regulatory Option D, but rather
retained the results of the proposed rule analyses for this option.
i
Some commenters also supported retaining the 2015 rule.
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Executive Summary
Table ES-1: Regulatory Options
Wastestream
Subcategory
Technology Basis for BAT/PSES Regulatory Options [Compliance Timing]13
2015 Rule (Baseline)
Option Dc
Option A
Option B
Option C
FGD
Wastewater
NA (default)3
Chemical
Precipitation + HRTR
Biological Treatment
[2021-2023]
Chemical
Precipitation [2021-
2023]
Chemical
Precipitation + LRTR
Biological Treatment
[2021-2025]
Chemical
Precipitation + LRTR
Biological Treatment
[2021-2025]
Membrane Filtration
[2024-2028]
High FGD Flow Facilities:
Plant-level scrubber purge
flow >4 MGD
NS
NS
Chemical
Precipitation [2021-
2023]
NS
NS
Low Utilization Boilers: All
units have 24-month
average utilization < 10%
NS
NS
Chemical
Precipitation [2021-
2023]
NS
NS
Generating units ceasing
combustion of coal by
December 31, 2028
NS
NSd
Surface
Impoundment
NS
NS
FGD Wastewater Voluntary Incentives
Program (Direct Dischargers Only)
Chemical
Precipitation +
Evaporation [2023]
Membrane Filtration
[2028]
Membrane Filtration
[2028]
Membrane Filtration
[2028]
NA
Bottom Ash
Transport
Water
NA (default)3
Dry Handling / Closed
loop
[2021-2023]
High Recycle Rate
Systems [2021-2023]
High Recycle Rate
Systems [2021-2025]
High Recycle Rate
Systems [2021-2025]
High Recycle Rate
Systems [2021-2025]
Low Utilization Boilers: All
units have 24-month
average utilization < 10%
NS
NS
Surface
Impoundment + BMP
Plan [2021-2023]
NS
NS
Generating units ceasing
combustion of coal by
December 31, 2028
NS
NSd
Surface
Impoundment
NS
NS
Abbreviations: BMP = Best Management Practice; HRTR = High Hydraulic Residence Time; LRTR = Low Hydraulic Residence Time; NS = Not subcategorized; NA = Not applicable
a. The table above does not present existing subcategories included in the 2015 rule as EPA did not reopen the existing subcategorization of oil-fired units or units with a
nameplate capacity of 50 MW or less.
b. The compliance timing is 2021-2023 for indirect dischargers across all options.
c. Option D corresponds to proposed Option 1.
d. Option 1 as proposed used surface Impoundment as the technology basis for electric generating units ceasing combustion of coal by December 31, 2028. In its 2019 analysis,
however, EPA did not specifically subcategorize these boilers but instead omitted these boilers from the analysis (see U.S. EPA, 2019a).
Source: U.S. EPA Analysis, 2020
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Executive Summary
Annualized Compliance Costs
EPA estimates that the regulatory options provide compliance cost savings when compared to the baseline
(Table ES-2). On an after-tax basis, the cost savings when compared to baseline compliance costs range
from $14 million to $140 million, with the final rule (Option A) providing the greatest estimated cost
savings of the regulatory options.
Table ES-2: Estimated Incremental Annualized After-tax Compliance Costs (Million of 2018$,
discounted to 2020 using 7 percent)
Regulatory Option
Net Capital
Technology
Net Other Initial One-
Time3
Net Total O&M
Net Total Costs
-$97
Option A
to
00
1
$0
-$54
-$140
Option B
-$74
$0
o
1
-$115
Option C
-$37
$0
$23
-$14
a. Costs analyzed over the period 2021-2047.
b. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2019, 2020
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, and all regulatory options further lessen economic
impacts to these entities. 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 final rule, including an
assessment of changes in the operating characteristics of steam electric power plants and other
electricity generators resulting from changes in electricity markets under the final rule. See
Chapter 5 for details.
Results across these analyses show that the final rule is estimated to have small impacts on the steam
electric power plants, on the entities that own these plants, and on the electricity market as a whole. For
example, IPM results for the market show net changes in total generation capacity or generation costs of
less than 0.5 percent across economic measures for Option A in the model year 2030 after implementation
of the final rule (see Table ES-3). The final rule results in a small projected decrease in total generation
capacity (less than 0.1 percent of the baseline) due to decreases in non-coal generation sources even as
coal-fired generation capacity increases slightly (0.8 percent). The increase in coal-fired generation
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Executive Summary
capacity is the result of net avoided early retirements of coal-fired electricity generating units relative to
the baseline and relative to any scheduled retirements. Results for steam electric power plants analysis
accompanying the final rule (in Table ES-4) also show small impacts, with a net increase in total capacity
under the final rule when compared to the baseline of approximately 0.3 percent, and net increases in total
generation by steam electric power plants of 0.3 percent for the final rule. These findings suggest that the
final rule will have small economic consequences for the steam electric power generating industry and the
electricity market overall. Looking specifically at plants with estimated compliance cost savings, the
results for the final rule show no change, or less than a one percent reduction or one percent increase in
capacity utilization, electricity generation, and variable production costs, providing further support for the
conclusion that the effects of the final rule on the steam electric industry will be small. See Chapter 5 for
details of these analyses, including results by region and for different model years.
Table ES-3: Modeled Impact of Final Rule on National Electricity Market in the Year 2030
Economic Measures3
Option A
(all dollar values in 2018$)
Baseline Value
Value
Difference
% Change
Total Domestic Capacity (GW)
1,169
1,169
-0.4
0.0%
Existing
1.1
0.1%
New Additions
-1.5
-0.1%
Early Retirements
| -1.1
-0.1%
Generation (TWh)
4,316
4,316
-0.3
0.0%
Costs ($Millions)
$161,476
$161,351
-$125
-0.1%
Fuel Cost
$66,408
$66,459
t—1
LO
0.1%
Variable O&M
$10,045
$10,039
-$5
-0.1%
Fixed O&M
$51,818
$51,823
$6
0.0%
Capital Cost
$33,205
$33,029
-$176
-0.5%
Average Variable Production Cost
($/MWh)
$17.71
$17.72
$0.01
0.1%
C02 Emissions (Million Metric Tons)
1,482
1,484
2.4
0.2%
Mercury Emissions (Tons)
4
4
0.0
0.2%
NOx Emissions (Million Tons)
1
1
0.0
0.1%
S02 Emissions (Million Tons)
1
1
0.0
0.2%
HCL Emissions (Million Tons)
0
0
0.0
0.5%
a. See Chapter 5 for a description of the economic measures.
Source: U.S. EPA Analysis, 2020
Table ES-4: Impact of Final Rule on Facilities in the Steam Electric Power Generating Point Source
Category, as a Group, in the Year 2030
Economic Measures3
Option A
(all dollar values in 2018$)
Baseline Value
Value
Difference
% Change
Total Domestic Capacity (MW)
314,952
315,752
800
0.3%
Early Retirements - Number of Plants
62
63
1
1.6%
Full & Partial Retirements - Capacity (MW)
68,959
68,159
-800
-1.2%
Generation (GWh)
1,475,819
1,479,979
4,160
0.3%
Costs ($Millions)
$57,620
$57,729
$109
0.2%
Fuel Cost
$32,448
$32,596
$148
0.5%
Variable O&M
$5,800
$5,804
$4
0.1%
Fixed O&M
$18,521
$18,478
-$43
-0.2%
Capital Cost
$851
$851
$0
0.0%
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Executive Summary
Table ES-4: Impact of Final Rule on Facilities in the Steam Electric Power Generating Point Source
Category, as a Group, in the Year 2030
Economic Measures3
(all dollar values in 2018$)
Baseline Value
Option A
Value
Difference
% Change
Average Variable Production Cost ($/MWh)
$25.92
$25.95
$0.03
0.1%
a. See Chapter 5 for a description of the economic measures.
Source: U.S. EPA Analysis, 2020
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. Overall, any job impacts of the regulatory
options, including the final rule, both positive and negative, are estimated to be small.
Potential Electricity Price Effects
EPA also assessed the estimated impacts of the regulatory options on electricity prices, assuming full cost
pass-through of compliance costs in electricity prices. The Agency conducted this analysis in two parts:
(1) an assessment of the estimated annual changes in electricity costs per MWh of total electricity sales;
and (2) an assessment of the estimated annual changes in household electricity costs. Chapter 7 details
these analyses.
Changes in costs per MWh of total electricity sales are small for all regulatory options; the maximum
difference in price effect is a fraction of a cent per kWh. Overall across the United States, the final rule
results in the highest cost savings of 0.0050 per kWh, and Option C results in the lowest cost savings of
0.0010 per kWh.
On the national level, cost savings relative to household electricity costs are greatest on average under the
final rule, with average cost savings of $0.49 per year per household; by region, cost savings range
between $0.09 and $1.03 per year per household. The average incremental annual cost savings per
residential household is greatest in the Southeastern Electric Reliability Council (SERC) region and the
least in the Northeast Power Coordinating Council (NPCC) region.
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.
This involved analyzing the baseline and regulatory options, and then drawing conclusions on the basis of
the differences between the options and the baseline. Given net cost savings described earlier, EPA
estimates that the final rule will also lessen impacts on small entities. EPA estimates that 76 to 127 small
entities own steam electric power plants within the scope of the final rule. In the baseline, EPA estimates
that 3 small entities owning steam electric power plants will incur costs exceeding one percent of revenue,
but none will incur costs exceeding three percent of revenue. Under the final rule (as well as Options B
and C), relative to the baseline 1 fewer small entity will incur costs exceeding one percent of revenue.
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Executive Summary
This screening-level analysis suggests that the final rule is estimated to further reduce the impact to small
entities as compared to the baseline by providing cost savings to 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
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.. $160
million in 2018 dollars). As discussed in Chapter 9, EPA estimates that the final rule will not result in
incremental expenditures of at least $160 million for State and local government entities, in the aggregate,
or for the private sector in any one year. In fact, the final rule will provide net cost savings when
compared to the baseline. Furthermore, 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 of UMRA, EPA presents four regulatory options which would all reduce impacts to
governments and the private sector. The final rule (Option A) provides the lowest impacts to governments
and the private sector of the options EPA analyzed for the final rule. The subcategories included in the
final rule provide additional flexibility to governments and private sector plant owners. Finally, the
implementation period built into the final rule is another way for permit writers to consider the site-
specific needs of steam electric power plants.
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, although the direction of the
effect is estimated to be a reduction in costs when compared to the baseline. 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, 2020a).
• Executive Order 13771: Reducing Regulation and Controlling Regulatory Costs: The final
rule is a deregulatory action under E.O. 13771, Reducing Regulation and Controlling Regulatory
Costs. See Chapter 12 in the BCA (U.S. EPA, 2020a) for details on the time profile of costs and
annualized discounted costs.
• Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use: EPA's analyses show that the final rule will not have a significant
adverse effect at a national or regional level under Executive Order 13211. Specifically, the
Agency's analyses found that the final rule will not reduce electricity production in excess of 1
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Executive Summary
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 Order 12898: Federal Actions to Address Environmental Justice (EJ) in Minority
Populations and Low-Income Populations: EPA examined whether the benefits from the
regulatory options may be differentially distributed among population subgroups in the affected
areas. As described in Chapter 10 of this RIA and detailed in Chapter 14 of the BCA (U.S. EPA,
2020a), the majority of communities in proximity to steam electric power plants have a higher
proportion of low income and/or minority residents than the state average. Therefore, the
regulatory options could benefit or harm populations with EJ concerns depending on each
option's pollutant exposure potential. EPA determined that the final rule will not deny
communities from the benefits of environmental improvements estimated to result from
compliance with the more stringent effluent limits, but it may disproportionally affect
communities in cases where the rule may result in small increases in pollutant exposure relative
to baseline. For example, because selected pollutant concentrations are generally estimated to
increase prior to the latest compliance dates of the rule the regulatory options are likely to
adversely affect populations with EJ concerns in the short term, although the effects are small.
• 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, 2020a), EPA
identified several ways in which the final rule could affect children, including by potentially
increasing health risk from exposure to pollutants present in steam electric power plant
discharges. However, EPA's analysis of the environmental health risks or safety risks addressed
by this action show the potential impacts are small and do not present a disproportionate risk to
children.
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1: Introduction
I Introduction
1.1 Background
EPA is finalizing a regulation that revises the technology-based effluent limitations guidelines and
standards (ELGs) for the steam electric power generating point source category, 40 CFRpart 423, which
EPA proposed in November 2019 (84 FR 64620). The final rule revises certain BAT effluent limitations
and pretreatment standards for existing sources for two wastestreams: bottom ash transport water and flue
gas desulfurization (FGD) wastewater.
This document describes the Agency's analysis of the costs and economic impacts of the final rule and
the other options that were evaluated by EPA but were not finalized. It also provides information
pertinent to meeting several legislative and administrative requirements.
This document complements and builds on information presented separately in other reports, including:
• Supplemental Technical Development Document for Revisions to the Effluent Guidelines and
Standards for the Steam Electric Power Generating Point Source Category (Supplemental TDD)
(U.S. EPA, 2020e). The Supplemental 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 facility-specific compliance cost estimates, pollutant loadings, and non-water quality
environmental impact assessment.
• Benefit and Cost Analysis for Revisions to the Effluent Limitations Guidelines and Standards for
the Steam Electric Power Generating Point Source Category (BCA) (U.S. EPA, 2020a). The
BCA summarizes the societal benefits and costs estimated to result from implementation of the
regulatory options.
• Supplemental Environmental Assessment for Revisions to the Effluent Guidelines and Standards
for the Steam Electric Power Generating Point Source Category (Supplemental EA) (U.S. EPA,
2020d). The Supplemental EA summarizes the environmental and human health improvements
that are estimated to result from implementation of the regulatory options.
The revisions to the ELGs for the Steam Electric Power Generating Point Source Category are based on
data generated or obtained in accordance with EPA's Quality Policy and Information Quality Guidelines.
EPA's quality assurance (QA) and quality control (QC) activities for this rulemaking include the
development, approval and implementation of Quality Assurance Project Plans for the use of
environmental data generated or collected from all sampling and analyses, existing databases and
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.
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1: Introduction
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 November 2019 proposal (see RIA; U.S.
EPA, 2019a). Appendix A describes the principal changes to the regulatory options analysis, as compared
to the 2019 proposal. These changes include:
• Updating the information on the control and treatment technologies and associated costs for
bottom ash transport water and FGD wastewater (see Supplemental 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 final rule is implemented. For the final rule, this baseline includes the final Affordable
Clean Energy rule, the final Coal Combustion Residuals (CCR) Part A rule, and an updated
representation of the 2015 rule. See Section 2.2 for additional discussion of these regulations and
Chapter 5, Assessment of the Impact of the Final Rule on National and Regional Electricity
Markets, for further description of the analysis using IPM.
• Updating electricity generation, sales, and electricity prices based on the most current data from
the Energy Information Administration (EIA) (e.g., 2013-2018 vs. 2011-2016).
• Updating the SBA small business size thresholds (August 2019 standards vs. October 2017
standards), updating information about the entities that own steam electric generating units, based
on EIA data, and recategorizing these entities as small or large.
1.2.1 Main Reguta tory Options Presented in the Final Rule
EPA analyzed four regulatory options at proposal, the details of which were discussed in the proposed
rule [84 FR 64620], For the final rule, EPA evaluated four regulatory options as shown in Table 1-1.
Proposed regulatory options 1, 2, 3, and 4 correspond generally to regulatory options D, A, B, and C here,
but do contain differences as detailed below. Public commenters generally supported three of the
regulatory options that EPA proposed or variants thereof.3 The availability and achievability of
technologies with better pollutant removals, as well as with the lack of public comments in support for
proposed regulatory option 1, led EPA to focus updates to the Agency's analysis on the remaining three
regulatory options. EPA did not update the analyses for regulatory option D, but rather retained the results
of the proposed rule analyses for this option.
Repowering refers to the replacement of coal generation equipment with non-coal generation equipment.
Some commenters also supported retaining the 2015 rule.
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1: Introduction
Table 1-1: Regulatory Options
Wastestream
Subcategory
Technology Basis for BAT/PSES Regulatory Options3
2015 Rule (Baseline)
Option Dc
Option A
Option B
Option C
FGD Wastewater
NA (default)15
Chemical
Precipitation + HRTR
Biological Treatment
[2021-2023]
Chemical
Precipitation [2021-
2023]
Chemical
Precipitation + LRTR
Biological Treatment
[2021-2025]
Chemical
Precipitation + LRTR
Biological Treatment
[2021-2025]
Membrane Filtration
[2025-2028]
High FGD Flow Facilities: Plant-
level scrubber purge flow >4 MGD
NS
NS
Chemical
Precipitation [2021-
2023]
NS
NS
Low Utilization Boilers: All units
have 24-month average utilization
< 10%
NS
NS
Chemical
Precipitation [2021-
2023]
NS
NS
Generating units ceasing
combustion of coal by 2028°
NS
NSd
Surface
Impoundment
NS
NS
FGD Wastewater Voluntary Incentives Program
(Direct Dischargers Only)
Chemical
Precipitation +
Evaporation
[2023]
Membrane Filtration
[2028]
Membrane Filtration
[2028]
Membrane Filtration
[2028]
NA
Bottom Ash
Transport Water
NA (default)15
Dry Handling /
Closed loop
[2023]
Dry Handling or High
Recycle Rate
Systems [2021-2023]
Dry Handling or High
Recycle Rate
Systems [2021-2025]
Dry Handling or High
Recycle Rate
Systems [2021-2025]
Dry Handling or High
Recycle Rate
Systems [2021-2025]
Low Utilization Boilers: All units
have 24-month average utilization
< 10%
NS
NS
Surface
Impoundment +
BMP Plan
[2021-2023]
NS
NS
Generating units ceasing coal
combustion by 2028
NS
NSd
Surface
Impoundment
NS
NS
Abbreviations: BMP = Best Management Practice; HRTR = High Hydraulic Residence Time; LRTR = Low Hydraulic Residence Time; NS = Not subcategorized; NA = Not applicable
a. See Supplemental TDD for a description of these technologies
b. The 2015 rule subcategorized units with nameplate capacity 50 MW or less and EPA is not revising requirements for these units in this proposal.
c. Option D corresponds to proposed Option 1.
d. Option 1 as proposed used surface Impoundment as the technology basis for generating units ceasing combustion of coal by December 31, 2028. In its 2019 analysis, however, EPA
did not specifically subcategorize these boilers but instead omitted these boilers from the analysis (see U.S. EPA, 2019a).
Source: U.S. EPA Analysis, 2020
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1: Introduction
1.2.2 Baseline
The baseline for the analyses supporting the final rule reflects the 2015 rule requirements as well as the
September 2017 postponement rule, which delayed by two years the earliest compliance dates for the
2015 rule applicable to FGD wastewater and bottom ash transport water (in absence of the final rule).
While this report evaluates the baseline and four main regulatory options, the Agency focuses on the
compliance costs that plants could incur under Options A, B, and C presented in Table 1-1, and estimates
presented for Option D have not been updated from proposal.4 For Options A through C, the Agency
calculated the difference between the updated baseline and the final regulatory options to determine the
net effect (as positive or negative change) of these regulatory options.
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 2019 proposal detailed in U.S. EPA (2019a). EPA also incorporated updated information
on the technologies and other controls that plants employ. The current analysis focuses on two
wastestreams: bottom ash transport water and FGD wastewater. Because of these updates, the estimated
costs and economic impacts of the baseline presented in this document differ from those presented in the
RIA document for the 2019 proposal and 2015 rule (U.S. EPA, 2015c; 2019a), and better reflect actual
costs of the 2015 rule today.
Unless otherwise specified, references to the 2015 rule baseline in the remainder of this document include
both the technical requirements of the 2015 rule as well as the revisions to compliance dates in the 2015
rule as a result of the 2017 steam electric postponement rule. It also includes the effects of the 2020 CCR
Part A rule (see Section 2.2.2).
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 cost savings across the industry,
and the broader market impacts.5 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).
The Agency includes values for Option D obtained from the 2019 RIA (see Option 1 in U.S. EPA, 2019a) in summary
tables to provide context for comparing the three analyzed options. Because of differences in the baseline information
noted above since the 2019 proposal, comparisons between Option D and Options A through C are approximate.
Additionally, values for Option D do not reflect changes in the plant universe and other analytical inputs for the
analysis of Options A, B, and C.
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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1: Introduction
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 2015 rule. This chapter includes updates to reflect changes to the industry since the
2019 proposal.
• Compliance cost assessment (Chapter 3), which describes the cost components and calculates
the industry-wide compliance costs for the baseline and regulatory options and estimates the
incremental costs attributable to the regulatory options.
• 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 regulatory options using IPM and provides insight into the
incremental effects of the regulatory options on the steam electric power generating industry and
on national electricity markets, relative to the baseline.
• Analysis of employment effects (Chapter 6), which assesses national-level changes in
employment in the steam electric industry, relative to the baseline.
• 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 rule and
2019 proposal and the discussion follows a presentation very similar to that in the associated RIA
documents (U.S. EPA, 2015c, 2019a).
Chapter 11 provides detailed information on sources cited in the text and two appendices provide
supporting information:
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1: Introduction
• 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 2019 proposal.
• 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, 2015c). It also discusses the regulations applicable to the universe of plants subject to the final rule.
2.1 Steam Electric Industry
The final rule revises BAT limitations and pretreatment standards for bottom ash transport water and
FGD wastewater for existing sources in the steam electric industry. The Steam Electric Power Generating
Point Source Category covers "discharges resulting from the operation of a generating unit by an
establishment whose generation of electricity is the predominant source of revenue or principal reason for
operation, and whose generation of electricity results primarily from a process utilizing fossil-type fuel
(coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear fuel in
conjunction with a thermal cycle employing the steam water system as the thermodynamic medium." (40
CFR 423.10)
EPA had identified 1,080 steam electric power plants - including plants that operate coal, oil, gas, and
nuclear generating units - and used this universe in its analysis of the 2015 rule (U.S. EPA, 2015c).
Review of more recent data revealed that some of the plants EPA surveyed in 20106 have since retired
their coal steam units, converted to different fuels, or made other changes that affect discharge
characteristics. The Supplemental TDD describes the changes in the steam electric industry population
since the 2015 rule analysis, including retirements, fuel conversions, ash handling conversions,
wastewater treatment updates, and updated information on capacity utilization (U.S. EPA, 2020e).
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 914 plants in the steam electric power generating industry. As presented in Table 2-1 (next
page), the 914 steam electric power plants represent approximately 8 percent of the total number of plants
in the power generation sector, but represent approximately 25 percent of the national total electric
nameplate generating capacity with 300,816 MW.7
Of the estimated 914 steam electric power plants in the universe, EPA expects only a subset to incur
compliance costs under the final rule: those coal fired power plants that discharge bottom ash transport
water or FGD wastewater. As presented in Table 2-1, EPA estimated that 108 plants would incur non-
zero compliance costs under the baseline; these plants represent 1.0 percent of the total plants reported by
EIA in 2018 and 2.9 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 2018. At the time EPA developed the industry
profile, 2018 was the most recent calendar year for which EIA had published detailed annual data.
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2: Industry Overview
Table 2-1: Steam Electric Industry Share of Total Electric Power Generation Plants and Capacity
in 2018
Steam Electric Industry13
Plants with Non-Zero Compliance
Costs for Baselinec
Total3
Number
% of Total
Number
% of Total
Plants
10,980
914
8.3%
108
1.0%
Capacity (MW)
1,196,488
300,816
25.1%
34,461
2.9%
a. Data for total electric power generation industry are from the 2018 EIA-860 database (EIA, 2019b).
b. Steam electric power plant count and capacity were calculated on a sample-weighted basis.
c. See Chapter 3 for details on compliance cost estimates, including number of plants with non-zero compliance costs under
the final rule and other regulatory options.
Source: U.S. EPA Analysis, 2020; EIA, 2019b.
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, nonutilities8, federally-owned utilities, State-owned utilities, municipalities, rural electric
cooperatives, and other political subdivisions. These categories are important because EPA has to assess
the impact of the final rule on State, local, and tribal governments in accordance with UMRA of 1995 (see
Chapter 9, Unfunded Mandates Reform Act (UMRA) Analysis).
Table 2-2 reports the number of parent entities, plants, and capacity by ownership type for the 914 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 majority of steam electric power plants
(54 percent of all steam electric power plants) are owned by investor-owned utilities, while nonutilities
make up the second largest category (20 percent of all steam electric power plants). In terms of steam
electric nameplate capacity, investor-owned utilities account for the largest share (58 percent) of total
steam electric nameplate capacity.
Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity
by Ownership Type, 2018
Parent Entitiesa bc
Plantsabd
Capacity (MW)ad
Lower Bound
Upper Bound
% of
Ownership Type
Number
% of Total
Number
% of Total
Numberc
% of Total
Numberc
Total
Cooperative
27
11.7%
49
10.7%
62
6.8%
25,793
8.6%
Federal
1
0.4%
3
0.7%
20
2.2%
11,844
3.9%
Investor-owned
66
28.6%
149
32.5%
489
53.6%
175,223
58.2%
Municipality
57
24.7%
92
20.1%
120
13.1%
48,557
16.1%
Nonutility
68
29.4%
142
30.9%
185
20.3%
28,550
9.5%
Other Political
Subdivisions
10
4.3%
21
4.7%
34
3.7%
6,640
2.2%
State
2
0.9%
2
0.4%
4
0.4%
4,209
1.4%
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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2: Industry Overview
Table 2-2: Existing Steam Electric Power Plants, Their Parent Entities, and Nameplate Capacity
by Ownership Type, 2018
Parent Entitiesabc
Plantsabd
Capacity (MW)ad
Lower Bound
Upper Bound
% of
Ownership Type
Number
% of Total
Number
% of Total
Numberc
% of Total
Numberc
Total
Total
231
100.0%
459
100.0%
914
100.00%
300,816
100.0%
a. Numbers may not add up to totals due to independent rounding.
b. Ownership information on steam electric power plants and their parent entities is based on information gathered through
the Steam Electric Survey (U.S. EPA, 2010) 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 Supplemental TDD.
Source: U.S. EPA Analysis, 2020; EIA, 2019b
EPA estimates that between 28 percent and 33 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 other political subdivision9
category (10 percent), while cooperatives and small municipalities make up the largest share of small
entities (74 percent and 47 percent, respectively). The pattern is similar under the upper bound estimate,
but small entities represent 5 percent of other political subdivision entities, 72 percent of cooperatives,
and 38 percent of municipalities.
EPA estimates that out of 914 steam electric power plants, 138 (15 percent) are owned by small entities
(Table 2-4). Cooperatives represent the largest share (29 percent) of small entities that own steam electric
power plants (40 out of 138 entities), while investor-owned utilities, nonutilities, municipalities, and other
political subdivisions make up the remaining 71 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
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
Cooperative
20
7
27
74.1%
35
14
49
71.6%
Federal
0
1
1
0.0%
0
3
3
0.0%
Investor-owned
11
55
66
16.7%
25
124
149
16.5%
Municipality
27
30
57
47.4%
35
57
92
37.8%
Nonutility
17
51
68
25.0%
31
111
142
21.8%
Other Political
Subdivision
1
9
10
10.0%
1
20
21
4.7%
State
0
2
2
0.0%
0
2
2
0.0%
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
76
155
231
32.9%
127
332
459
27.6%
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, 2020
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
40
22
62
64.7%
Federal
0
20
20
0.0%
Investor-owned
27
463
489
5.4%
Municipality
35
85
120
29.2%
Nonutility
35
150
185
18.9%
Other Political Subdivisions
1
33
34
3.0%
State
0
4
4
0.0%
Total
138
776
914
15.1%
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, 2020
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 seven regional entities that cover the
48 contiguous States, and two affiliated councils that cover Hawaii, part of Alaska, and portions of
Canada and Mexico.1" 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 EPA used for the analysis of the regulatory
options, listed in Table 2-5. The map uses the same regional breakout used for the 2015 rule analysis,
which was based on the 2012 EIA data and separates out the Southwest Power Pool (SPP) region.11
Table 2-5: NERC regions
Bulk Power Network
NERC Region
NERC Entity
FRCC
Florida Reliability Coordinating Council
MRO
Midwest Reliability Organization
Eastern Interconnected System
NPCC
Northeast Power Coordinating Council (U.S.)
RFC
Reliability First Corporation
SERC
SERC Reliability Corporation
SPP
Southwest Power Pool
Western Interconnected System
WECC
Western Energy Electricity Coordinating Council (U.S.)
Texas Interconnected System
TRE
Texas Regional Reliability Entity
ASCC
Alaska Systems Coordinating Council
HICC
Hawaii Coordinating Council
Source: EIA, 2012
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 NERC regions have been re-defined/re-named over time. This chapter provides NERC region data by the 2012
NERC regions.
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Figure 2-1: North American Electric Reliability Corporation (NERC) Regions
MRO
RFC
WECC
SPP
5ERC
TRE
FRCC
Note: The ASCC and HICC regions are not shown.
Source: EIA, 2012.
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 electnc power plants subject to the final 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 somewhat concentrated in the RFC, SERC, and WECC
regions (21 percent, 21 percent, and 17 percent, respectively); these three regions also account for a
majority of the steam electric nameplate capacity in the United States (18 percent, 27 percent, and
20 percent, respectively).
Table 2-6: Steam Electric Power Plants and Nameplate Capacity by NERC
Region, 2018
Plants15
Capacity (MW)ab
NERC Region
Number
% of Total
MW
% of Total
ASCC
2
0.2%
3,231
1.1%
FRCC
48
5.2%
27,244
9.1%
HICC
10
1.1%
1,517
0.5%
MRO
73
8.0%
13,235
4.4%
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Table 2-6: Steam Electric Power Plants and Nameplate Capacity by NERC
Region, 2018
Plants'3
Capacity (MW)ab
NERC Region
Number
% of Total
MW
% of Total
NPCC
89
9.7%
12,618
4.2%
RFC
189
20.7%
54,912
18.3%
SERC
194
21.2%
80,554
26.8%
SPP
79
8.7%
27,642
9.2%
TRE
71
7.8%
18,802
6.3%
WECC
159
17.4%
61,060
20.3%
TOTAL
914
100.0%
300,816
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, 2020; EIA, 2019b
2.1.3 Electricity Genera tion
Total net electricity generation in the United States for 2018 was 4,174 TWh.12 The 2018 EIA data was
the most recent year of finalized EIA data, and was not available at proposal. Coal accounted for
27 percent of total electricity generation, behind natural gas (35 percent), but ahead of nuclear power
(19 percent). Other energy sources accounted for comparatively smaller shares of total generation, with
hydropower representing 7 percent; wind, solar and other renewable energy, 10 percent; and petroleum,
1 percent.
As presented in Table 2-7, the 7-year period of 2012 through 2018 saw total net generation increase by
approximately 3.1 percent, with the 371 TWh drop in generation from coal-fueled generators (25 percent)
offset by growth in generation from natural gas (243 TWh, 19.8 percent increase) and renewables
(196 TWh, an 87 percent increase).
Between 2012 and 2018, the amount of electricity generated by utilities declined by 0.2 percent while that
generated by nonutilities rose by 7.7 percent. Comparing 2012 and 2018 values, across all fuel-source
categories, utilities generated a larger share of their electricity using natural gas (a 43 percent increase)
and renewables (a 75 percent increase) even as their overall generation declined. For nonutilities, the
largest percent increase in electricity generation (89 percent) occurred for renewables, whereas generation
from natural gas increased 4 percent.
Table 2-7: Net Generation by Energy Source and Ownership Type, 2012-2018 (TWh)
Utilities
Nonutilities
Total
Energy Source
2012
2018
% Change
2012
2018
% Change
2012
2018
% Change
Coal
1,146
857
-25.2%
368
286
-22.2%
1,514
1,143
-24.5%
Hydropower
249
263
5.6%
23
24
6.7%
271
287
5.7%
Nuclear
395
424
7.5%
375
383
2.2%
769
807
4.9%
Petroleum
15
17
14.9%
8
8
8.8%
22
25
12.8%
Natural Gas
505
720
42.6%
721
749
3.8%
1,226
1,469
19.8%
Other Gases
1
3
271.0%
12
13
11.9%
13
16
28.8%
Renewables3
28
49
74.8%
197
372
88.6%
225
421
86.9%
One terawatt-hour is 1012 watt-hours.
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Table 2-7: Net Generation by Energy Source and Ownership Type, 2012-2018 (TWh)
Utilities
Nonutilities
Total
Energy Source
2012
2018
% Change
2012
2018
% Change
2012
2018
% Change
Other"
0
0
-14.1%
6
6
-9.1%
7
6
-9.4%
Total
2,339
2,334
-0.2%
1,709
1,841
7.7%
4,048
4,174
3.1%
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, 2019c
2.2 Other Environmental Regulations
The 2015 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 (2015c). The sections below provide updated
discussions on changes to two environmental regulations since 2015.
2.2.1 Affordable Clean Energy (ACE) Rule
On June 19, 2019, EPA issued the ACE rule pursuant to Clean Air Act (CAA) sections 111(a)(1) and
111(d), providing states with guidelines for establishing standards of performance regulating CO2
emissions at existing coal-fired electric utility generating units (EGUs). This action was finalized in
conjunction with two related, but separate and distinct rulemakings: (1) the repeal of the Clean Power
Plan (CPP), and (2) revised implementing regulations for ACE, ongoing emission guidelines, and all
future emission guidelines for existing sources issued under the authority of CAA section 111(d).
Under CAA section 111(a)(1) and 111(d), respectively, EPA determines the best system of emission
reduction (BSER) and states submit plans establishing standards of performance based on the BSER. The
BSER must be applicable to, at, and on the premises of a source subject to CAA section 111(d). EPA
repealed the CPP on the basis that it in part improperly premised its BSER on generation shifting between
EGUs and other lower emitting sources. In ACE, EPA determined the BSER for coal-fired EGUs as six
heat rate improvements (HRI) "candidate technologies", as well as additional operating and maintenance
(O&M) practices, all of which are applicable to and at the source. For each candidate technology, EPA
has provided the degree of emission limitation achievable through application of the BSER as ranges of
expected improvement and costs. States are required to submit plans by July 8, 2022, which establish
standards of performance for their EGUs subject to the ACE rule. The standards of performance must
reflect the degree of emission limitation through application of the BSER, and states may take into
account remaining useful life and other factors in applying a standard to a particular EGU. Multiple legal
challenges to this rule were consolidated in American Lung Association v. EPA, No. 19-1140, and are
currently pending in the D.C. Circuit Court of Appeals.
The analyses supporting the final rule use the most up-to-date version of IPM available, which includes
an illustrative representation of the requirements of the final ACE rule (U.S. EPA, 2020b).13 See
As discussed in the ACE RIA, "EPA did not have sufficient information to assess HRI [heat rate improvement]
potential on a unit-by-unit basis. [Clean Air Act] CAA 111(d) also provides states with the responsibility to establish
standards of performance and provides considerable flexibility in applying those emission standards. States may take
source-specific factors into consideration - including the remaining useful life of the affected source - when applying
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additional discussion of IPM in Chapter 5, Assessment of the Impact of the Final Rule on National and
Regional Electricity Markets.
2.2.2 Coal Combustion Residuals Rule
On April 17, 2015, the Agency published the Disposal of Coal Combustion Residuals from Electric
Utilities final rule. This rule finalized national regulations to provide a comprehensive set of requirements
for the safe disposal of CCRs, commonly known as coal ash, from coal-fired power plants. The final CCR
rule was the culmination of extensive study on the effects of coal ash on the environment and public
health. The rule established technical requirements for CCR landfills and surface impoundments under
subtitle D of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for
regulating solid waste.
These regulations addressed coal ash disposal, including regulations designed to prevent leaking of
contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure
of coal ash surface impoundments. Additionally, the CCR rule set out recordkeeping and reporting
requirements as well as the requirement for each facility to establish and post specific information to a
publicly-accessible website. This final CCR rule also supported the responsible recycling of CCRs by
distinguishing beneficial use from disposal.
As a result of the DC Circuit Court rulings in USWAG v. EPA, No. 15-1219 (DC Cir. 2018) and
Waterkeeper Alliance Inc, et al. v. EPA, No. 18-1289 (DC Cir. 2019), the Administrator signed
amendments to the CCR rule (CCR Part A) on July 29, 2020. In particular, four amendments to the CCR
rule were finalized. First, the CCR Part A rule establishes a new deadline of April 11, 2021, for all
unlined surface impoundments and those surface impoundments that failed the location restriction for
placement above the uppermost aquifer to stop receiving waste and begin closure or retrofit. EPA
determined this date after evaluating the steps that owners and operators need to take to cease receipt of
waste and initiate closure and the time frames necessary for implementation. Second, the rule establishes
procedures for facilities to obtain additional time to develop alternate capacity to manage their waste
streams (both coal ash and non-coal ash) before they have to stop receiving waste and initiate closure of
their coal ash surface impoundments. Third, the rule changes the classification of compacted-soil lined or
clay-lined surface impoundments from "lined" to "unlined." Finally, the rule revises the coal ash
regulations to specify that all unlined surface impoundments are required to retrofit or close. This would
not impact the ability of facilities to install new, composite-lined surface impoundments.
As explained in the 2015 rule and 2019 proposal, the ELGs and CCR rules may affect the same unit or
activity at a power plant. As such, when EPA finalized the ELGs and CCR rules in 2015 and proposed
revisions to both rules in 2019, EPA coordinated the two rules to facilitate and minimize the complexity
of implementing engineering, financial, and permitting activities. EPA continued to coordinate these two
rules in the development of the final rule for ELG and CCR. EPA's analysis for the final ELG rule
estimates how the CCR Part A rule may affect surface impoundments and the ash handling systems and
the standards of performance. Generally, the EPA cannot sufficiently distinguish likely or representative standards of
performance across individual affected units or groups of units and their compliance strategies. Therefore, any analysis
of the ACE rule must be illustrative. Nonetheless, the EPA believes that such illustrative analysis can provide important
insights." (U.S. EPA, 2019a, see page ES-2)
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FGD treatment systems that send wastes to those impoundments. This is further described in
Supplemental TDD Section 3.14
In the 2015 CCR rule RIA (U.S. EPA, 2014b), EPA explicitly accounts for the baseline closure of all
surface impoundments (including composite lined surface impoundments) at the end of their useful life
(40 years). At the end of a surface impoundment's useful life, facilities are projected to face a decision
between multiple replacement disposal alternatives. EPA modeled these alternatives and selected the
least-cost alternative for each facility (see section 3.2.4.2 of the 2015 CCR RIA). Based on EPA's cost
estimates, the Agency found that the least-cost alternative universally involved some form of converting
away from disposal surface impoundments and incurring the costs of making a "wet-dry conversion."
In light of the changes from the USWAG and Waterkeeper mandates, the 2020 CCR Part A RIA (U.S.
EPA, 2020c) revises cost estimates to reflect the new timing and number of surface impoundment
closures and wet to dry conversions. All unlined surface impoundments are now required by these court
decisions to close. EPA estimated the increase in annualized costs as $40.5 million in the adjusted
baseline costs in Section 2.5 of the CCR Part A RIA.
In addition to the final CCR Part A rule, EPA has proposed further revisions to the CCR regulations
(CCR Part B). Specifically, EPA proposed four changes in the CCR Part B rule. First, EPA proposed
procedures to allow facilities to request approval to continue operating CCR surface impoundments
equipped with an alternate liner. Second, EPA proposed two options to allow the continued placement of
CCR in surface impoundments undergoing forced closure. Third, EPA proposed an additional closure
option for CCR units being closed by removal of CCR. Finally, EPA proposed requirements for annual
closure progress reports. EPA recognizes that, just as with the Part A rule, the first provision of the Part B
rule may affect the same boiler or activity at a facility that these final ELGs affect. To provide the public
with meaningful analysis of the potential overlap and impacts of the final rule with the CCR Part B rule,
EPA has conducted a sensitivity analysis. See the Supplemental TDD and the memorandum titled
"Assessment of the economic impacts of the final revised Steam Electric ELGs relative to an alternative
baseline including the CCR Part B Rule" (DCN SE09360 in the rule docket) for more information.
2.3 Market Conditions and Trends in the Electric Power Industry
The 25 percent decline in coal-fueled electricity generation summarized in Table 2-7 for the period of
2012 through 2018 exemplifies an ongoing trend over the last decade: the progressive reduction in
generation capacity as coal units and plants retire. 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, 2019d). 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 et 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
For more information on the CCR Part A rule and accompanying background documents, visit www.regulations.gov
Docket EPA-HQ-OLEM-2019-0172 and www.epa.gov/coalash/coal-ash-rule.
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not any younger on average. Coal plant retirements due to aging are likely to continue in the near future,
as the capacity-weighted average age of coal plants in operation as of 2017 is 39 years (EIA, 2017).
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). 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.
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, 2018d). 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, 2018c).
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 final rule, EPA updated the proposed rule costs and economic impacts for regulatory
options A through C described in Table 1-1. Key inputs for these analyses include the estimated costs to
steam electric power plants (and their business, government, or non-profit owners) for implementing
control technologies upon which the final BAT limitations and pretreatment standards are based,15 and to
the state and federal government for administering this rule. This chapter summarizes EPA estimates of
the incremental compliance costs attributable to the final rule, based on a comparison of steam electric
industry compliance costs for the baseline and regulatory options.16 EPA determined that state and federal
governments would not incur significant incremental administrative costs.17
EPA applied the same methodology used to analyze the 2015 rule and 2019 proposal to calculate
industry-level annualized compliance costs. See Chapter 3 of the respective RIA documents for details
(U.S. EPA, 2015c, 2019a). EPA did not update its evaluation of Option D (Option 1 described in the
proposal), but is presenting results from the 2019 analysis where appropriate to provide context to the
discussion of results for Options A, B, and C.
The Supplemental TDD describes the control technologies and their respective wastewater treatment
performance in greater detail (U.S. EPA, 2020e). The Supplemental TDD also describes how EPA
estimated plant-specific capital and operation and maintenance (O&M) costs for six technologies, as well
as for BMP plans.
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 Supplemental TDD for details.
2. Developing plant-level costs for each wastestream and technology option. See Supplemental 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 the regulatory option specifications and
any planned unit retirements or units ceasing the combustion of coal. This schedule supports
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 final rule will not impose significant additional administrative cost to the State and federal
governments. See Section 10.8, Paperwork Reduction Act of1995, for additional discussion, including related to
additional requirements for permitting authorities to use best professional judgement (BP J) in making bottom ash purge
water volume and technology determinations.
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analysis of the timing of compliance costs and benefits for analyses discussed in this document
and in the BCA.
4. Estimating total industry costs for all plants in the steam electric universe for each of the
regulatory options.
An additional step involves comparing the total industry costs from Step 4 to total industry costs similarly
obtained for the baseline to estimate the incremental costs attributable to each regulatory option.
EPA reports costs in 2018 dollars and discounts the costs to 2020.18
3.1.1 Plant-Specific Costs Approach
As detailed in the Supplemental 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.. bottom ash transport water and FGD wastewater).
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 the 2015 rule (for baseline) and each of the
regulatory options presented in Table 1-1, and estimated the cost to implement those changes. Because
the 2015 rule19 is the baseline for analysis but plants were not required to comply with the 2015 rule
limitations for the two wastestreams addressed in this rule until November 2020, EPA first developed
costs to meet the 2015 rule based on current plant equipment, processes, and treatment technologies. EPA
then developed similar costs for the regulatory options. The difference between the baseline and
regulatory option cost estimates reflect the incremental costs attributable to the regulatory options. Plants
that do not generate a wastewater or that employ technologies which would already meet the given
limitations or standards do not incur costs. For several regulatory options, including the final rule, the
costs of meeting the BAT imitations or pretreatment standards are less than those estimated for meeting
the 2015 rule, and the options therefore result in cost savings to the industry as compared to the baseline.
3.1.2 Plant-Level Costs
Following the approach used for the analysis of the 2015 rule and 2019 proposal (U.S. EPA, 2015c,
2019a), EPA estimated compliance costs for all existing steam electric power plants, estimated to be a
total 914 plants for the point source category overall. EPA assessed that only a fraction of the universe of
steam electric power plants - 294 plants - have the potential to incur any costs under the regulatory
options based on their wastestreams. 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: 110 plants under the baseline and up to 86 plants under regulatory options A through C. The
Supplemental TDD provides additional details on this analysis.
In its analysis of the 2015 rule, EPA presented costs in 2013 dollars and discounted these compliance costs to 2015 (see
U.S. EPA, 2015c).
This includes the September 2017 postponement rule which delayed the earliest compliance date for the ELGs
applicable to FGD wastewater and bottom ash transport water.
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3: Compliance Costs
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 2015 TDD and Supplemental TDD, all
compliance technologies are assumed to have a useful life of 20 years. While the analysis uses as
an input the cost to plant owners to purchase equipment, EPA also conducted a sensitivity
analysis that compares costs of leasing as opposed to purchasing equipment. This analysis
suggests that leasing may be more expensive for short cost recovery periods, such as when the
unit may operate over a shorter period than 20 years, but the results are highly uncertain. See the
memorandum entitled "Cost to Lease Flue Gas Desulfurization Wastewater Treatment" (DCN
SE08633 in the rule docket).
• Initial one-time costs (apart from capital costs, above), if applicable, consist of a one-time cost to
make the bottom ash system closed loop to eliminate discharges of bottom ash transport water
(e.g., under the baseline) or a one-time cost to develop a Best Management Practice (BMP) plan
to recycle bottom ash transport water (e.g., under Option A). Steam electric power plants are
estimated to incur these costs only once during their technology implementation year.
• Annual fixed O&M costs, if applicable, include regular annual monitoring. Plants incur these
costs each year.
• Annual variable O&M costs, if applicable, include annual operating labor, maintenance labor and
materials, electricity required to operate wastewater treatment systems, chemicals, combustion
residual waste transport and disposal operation and maintenance, and savings from not operating
and maintaining ash/FGD pond systems. Plants incur these costs each year.
In addition to these initial one-time and annual outlays, certain other costs are estimated to be incurred on
a non-annual, periodic basis:
• 3-Yr fixed O&M costs, if applicable, include mechanical drag system (MDS) chain replacement
costs that plants are estimated to incur every three years, beginning three years after the
technology implementation year.
• 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
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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 change in the annualized costs to the steam electric
industry and society associated with the regulatory options as compared to the baseline.
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 rule and 2019 proposal, EPA considered the magnitude and complexity of
process changes and new equipment installations that would be required at plants to meet the
requirements of the regulatory options in determining the time plant owners may need to comply with any
revised limitations or pretreatment standards. See discussion in the Supplemental TDD (U.S. EPA,
2019b).
As described in greater detail in the final rule preamble, EPA is establishing deadlines for meeting the
BAT limitations and pretreatment standards. In analyzing the regulatory options, EPA identified and
included in the analysis the differences in deadlines across the options, wastestreams, type of discharge
(direct or indirect), and whether a plant participates in the Voluntary Incentive Program (VIP). Table 3-1
summarizes the relevant deadlines for each regulatory option, based on the wastestream and plant
category.
Table 3-1: Compliance Deadlines for the Baseline and Regulatory Options
Wastestream
Plant Subset
Compliance "No Later Than" Deadline
(Technology Basis)b
Baseline
Option Dc
Option A
Option B
Option C
Bottom Ash
Transport Water
All3 plants unless
otherwise qualified
2023
(Dry
handling)
2023
(CP)
2025
(HRR)
2025
(HRR)
2025
(HRR)
Low utilization boilers
Not
applicable
Not
applicable
2023
(BMP)
Not
applicable
Not
applicable
Generating units
ceasing combustion of
coal
Not
applicable
2028
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Table 3-1: Compliance Deadlines for the Baseline and Regulatory Options
Wastestream
Plant Subset
Compliance "No Later Than" Deadline
(Technology Basis)b
Baseline
Option Dc
Option A
Option B
Option C
FGD Wastewater
All3 plants unless
otherwise qualified
2023
(CP + HRTR)
2023
(CP)
2025
(CP + LRTR)
2025
(CP + LRTR)
2028
(Membrane)
Low utilization boilers
Not
applicable
Not
applicable
2023
(CP)
Not
applicable
Not
applicable
High FGD flow facilities
VIP
2023
(CP +
Evaporation)
2028
(Membranes)
2028
(Membranes)
2028
(Membranes)
Not
applicable
Generating units
ceasing combustion of
coal
Not
applicable
Not
applicable
2028
Not
applicable
Not
applicable
CP = Chemical precipitation; LRTR = Low Residence Time Reduction; HRTR = High Residence Time Reduction; BMP = Best
Management Practices; HRR = High Recycle Rate.
a. For units with nameplate capacity greater than 50 MW
b. The compliance "no later than" deadline is 2023 for indirect discharges across all options.
c. Option D corresponds to proposed Option 1.
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, recognizing that some plant owners have already met or taken steps to
meet the ELGs EPA finalized in 2015. Moreover, specifying compliance deadlines in the future enables
plants to take advantage of planned shutdown or maintenance periods to install new pollution control
technologies. This allows for the coordination of generating unit outages in order to maintain grid
reliability and prevent any potential impacts on electricity availability caused by forced outages. It is not
possible to predict, for each plant, exactly the date the final rule will be incorporated into permits, for
purposes of determining exactly when plants will incur costs to meet the new requirements. Similar to the
approach used in analyzing the 2015 rule and 2019 proposal, EPA generally expects plants to meet the
new BAT limitations and pretreatment standards in a somewhat staggered fashion, given that (1) for some
regulatory options, 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 3- to 5-year period preceding any
established "no later than" date.20
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
applicable final rule compliance deadline, EPA assumed that permit authorities would set the "no later
For the purpose of the analysis, EPA assigned an estimated compliance year to each of the 294 steam electric power
plants analyzed for the final rule based on each plant's estimated NPDES permit renewal year and, similar to the
approach used for the 2015 rule and 2019 proposal, the assumption that all permits will be renewed promptly (no
administrative continuances). EPA projected future NPDES permit years by assuming permits are renewed every 5
years, i.e., a permit expiring in 2021 would be renewed in 2026 and 2031.
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than" compliance date to correspond to the retirement date. In these cases, the plant would incur no
incremental costs to comply with the final rule.
EPA also accounted for announced unit retirements or repowerings in the social cost analysis, which is
discussed and detailed in Chapter 12 of the BCA. Specifically, EPA assumed zero O&M costs in all years
following a unit's retirement or repowering.
3.1.4 Total Compliance Costs
EPA used the following methodology and assumptions to aggregate compliance cost components,
described in the preceding sections, and develop total plant compliance costs for regulatory options A
through C:
• EPA estimated compliance costs (including zero costs) for each of the 294 steam electric power
plants with the relevant wastestreams, i. e., coal-fired power plants (see Supplemental TDD for
details). All other plants covered by the steam electric power point source category are estimated
to incur zero costs.
• EPA restated compliance costs estimated in the preceding step, accounting for the specific years
in which each plant is assumed to undertake compliance-related activities and in 2018 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) (2019).21
• EPA discounted all cost values to 2020, using a rate of 7 percent.22
• 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:22
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 2018 dollars, the Agency deflated the nominal
dollar values to 2018 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 2018.
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.
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- Capital costs of each compliance technology: 20 years
- Initial one-time costs: 20 years23
- 3-Yr O&M: 3 years
- 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 but before the second instance, EPA adjusted the useful life of that cost
category to be the number of years that the plant is expected to operate after the first instance.
EPA did not adjust the annualization of capital costs to reflect plant-specific considerations. EPA
annualized capital costs over 20 years but recognizes that some plants may retire units sooner than the 20-
year life of the equipment. EPA determined the 20-year annualization period to be reasonable for this
analysis because some regulators may allow utilities to recover the value of undepreciated assets in their
rate base on a case-by-case basis. Additionally, actual capital costs may be less than estimated by EPA in
some cases should the plant owner elect to lease rather than purchase equipment, as discussed in a
sensitivity analysis summarized in the memorandum entitled "Cost to Lease Flue Gas Desulfurization
Wastewater Treatment'" (DCN SE08633 in the rule docket).
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.24 For this adjustment, EPA used
State corporate rates from the Federation of Tax Administrators (2019) combined with a 21 percent
federal corporate tax rate.25 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.26
EPA annualized these non-equipment outlays over 20 years to match the estimated performance life of compliance
technology components.
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
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3.1.5 Voluntary Incentive Program
As described in the proposal, under the VIP component of regulatory options A and B, 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 have 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.
Because participation in the VIP is voluntary, the set of plants participating in the program is uncertain.
For the purpose of the economic analysis, EPA estimated VIP participants by comparing the estimated
costs of the two technologies for each facility estimated to incur compliance costs and assuming that a
plant owner would select the less costly of the two. Specifically, the Agency compared the annualized and
discounted cost of implementing CP+LRTR between 2021 and 2025 (based on the plant-specific schedule
described in Section 3.1.3) or implementing membrane filtration in 2028. Based on this analysis, EPA
estimated that 8 plants may choose to participate in the VIP under Option A (final rule) and 13 plants may
choose to participate in the VIP under Option B. For these plants, EPA retained the membrane filtration
costs for estimating economics impacts in this document and for the benefit cost analysis in Chapter 12 of
the BCA.
3.2 Key Findings for Regulatory Options
3.2.1 Estima ted Industry-level Total Compliance Costs
Table 3-2 presents compliance cost estimates for the baseline and regulatory options, Table 3-3
summarizes incremental costs for each option as compared to the baseline, and Table 3-4 shows the
breakout of incremental total compliance costs for each option by wastestream. Table 3-3 and Table 3-4
include incremental costs previously estimated for Option D (Option 1 in U.S. EPA, 2019a) as context to
the estimates for Options A, B, and C.
EPA estimates that, on a pre-tax basis, steam electric power plants would incur annualized costs of
meeting the regulatory options ranging from $203 million under Option A to $359 million under Option
C compared to pre-tax costs of $378 million for the baseline. Thus, all three options reanalyzed provide
cost savings when compared to the 2015 rule, with pre-tax savings ranging from $20 million to
$175 million (cost savings are shown as negative values in Table 3-3 and Table 3-4). On an after-tax
basis, the total compliance costs range from $169 million to $295 million, and cost savings range from
$14 million to $140 million, depending on the option. On both the pre-and post-tax bases, compliance
costs are lowest, and savings greatest, for Option A (the final rule).
All three regulatory options reanalyzed yield annualized costs savings for the bottom ash transport water
wastestream. The greatest savings are achieved under Option A ($80 million after-tax), due to
subcategorization of low utilization units under Option A. Options A, B, and D provide annualized cost
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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savings for FGD wastewater. The greatest savings for FGD wastewater are achieved under Option A ($60
million after-tax) whereas Option C results in higher costs for FGD wastewater ($49 million on an
annualized, after-tax basis), when compared to the baseline.
Table 3-2: Estimated Total Annualized Compliance Costs (in millions, 2018$, at 2020)
Pre-Tax Compliance Costs
After-Tax Compliance Costs
Other
Other
Regulatory
Capital
Initial One-
Capital
Initial One-
Option
Technology
Time
Total O&M
Total
Technology
Time
Total O&M
Total
Baseline
$208
$0
$170
$378
$170
$0
$139
$310
$132
$94
Option A
$102
$0
$102
$203
00
$0
LO
00
$169
Option B
$116
$0
$119
$235
$96
$0
$99
$195
Option C
$162
$0
$196
$359
$134
$0
$162
$295
a. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020
Table 3-3: Estimated Incremental Annualized Compliance Costs (in millions, 2018$, at 2020)
Pre-Tax Incremental Costs
After-Tax Incremental Costs
Net Other
Net Other
Regulatory
Net Capital
Initial One-
Net Total
Net Total
Net Capital
Initial One-
Net Total
Net Total
Option
Technology
Timea
O&M
Costs
Technology
Timea
O&M
Costs
Option A
-$107
$0
-$69
-$175
-$86
$0
-$54
-$140
Option B
-$92
$0
-$51
-$143
-$74
$0
-$40
-$115
Option C
-$46
$0
$26
-$20
-$37
$0
$23
-$14
a. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2019, 2020
Table 3-4: Estimated Incremental Annualized Compliance Costs, by Wastestream (in millions,
2018$, at 2020)
Pre-Tax Incremental Costs
After-Tax Incremental Costs
Bottom Ash
Bottom Ash
Regulatory
Transport
FGD
Transport
FGD
Option
Water
Wastewater
Net Total Costs
Water
Wastewater
Net Total Costs
Option A
-$104
-$71
-$175
-$80
-$60
-$140
Option B
-$81
-$62
-$143
-$63
-$51
-$115
Option C
t—1
00
1
$62
-$20
-$63
$49
-$14
a. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2019, 2020
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3.2.2 Estima ted Regional Distribution of Incremental Compliance Costs
Table 3-5 reports incremental costs for each regulatory option at the level of a North American Electric
Reliability Corporation (NERC) region as compared to baseline (see Table 2-5).27 As explained in
Chapter 2 (Overview of the Steam Electric Industry), because of differences in operating characteristics
of steam electric power plants across NERC regions, as well as differences in the economic and electric
power system regulatory circumstances of the NERC regions themselves, the regulatory options may
affect costs, profitability, electricity prices, and other impact measures differently across NERC regions.
Annualized after-tax compliance costs are highest in the SERC and RFC regions for all reanalyzed
regulatory options (A through C) and, as shown in Table 3-5, these regions also see the greatest
incremental cost savings under option A and B. RFC also has the largest cost savings under Option C. For
corresponding result for Option D, see the 2019 RIA (U.S. EPA, 2019a).
Table 3-5: Estimated Annualized Incremental Compliance Costs by NERC Region (in millions,
2018$, at 2020)
Pre-Tax Incremental Compliance Costs
After-Tax Incremental Compliance Costs
Other
Other
NERC
Capital
Initial One-
Capital
Initial One-
Region3
Technology
Time
Total O&M
Total
Technology
Time
Total O&M
Total
Option A
FRCC
-$5
$0
$0
-$5
-$4
$0
$0
-$4
MRO
-$5
$0
-$4
-$9
-$4
$0
-$3
-$7
NPCC
-$1
$0
-$2
-$3
-$1
$0
-$1
-$2
RFC
-$37
$0
-$27
-$63
-$27
$0
-$19
-$47
SERC
-$45
$0
-$22
-$67
-$39
$0
-$18
-$58
SPP
-$7
$0
-$5
-$13
-$6
$0
-$4
-$10
TRE
-$2
$0
-$1
-$3
-$2
$0
-$1
-$3
WECC
-$5
$0
-$7
-$13
-$4
$0
-$6
-$10
Total
-$107
$0
-$69
-$175
-$86
$0
-$54
-$140
Option B
FRCC
-$4
$0
$0
-$4
-$3
$0
$0
-$3
MRO
-$3
$0
-$2
-$5
-$3
$0
-$2
-$5
NPCC
$0
$0
$0
$0
$0
$0
$0
$0
RFC
-$32
$0
-$22
-$54
-$24
$0
-$17
-$41
SERC
-$42
$0
-$18
-$59
-$35
$0
-$15
-$50
SPP
-$5
$0
-$3
-$8
-$4
$0
-$2
-$7
No steam electric power plant is estimated to incur compliance costs in the ASCC and HICC NERC regions and these
two regions are therefore omitted from the presentation of results.
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Table 3-5: Estimated Annualized Incremental Compliance Costs by NERC Region (in millions,
2018$, at 2020)
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
TRE
-$2
$0
-$1
-$3
-$2
$0
-$1
-$3
WECC
-$3
$0
-$5
-$8
-$3
$0
-$4
-$6
Total
-$92
$0
-$51
-$143
-$74
$0
-$40
-$115
Option C
FRCC
$0
$0
$5
$5
$0
$0
$4
$4
MRO
-$3
$0
-$2
-$5
-$3
$0
-$2
-$4
NPCC
$0
$0
$0
$0
$0
$0
$0
$0
RFC
-$22
$0
$5
-$17
-$17
$0
$4
-$12
SERC
-$11
$0
$25
LO
t—1
w
o
T—1
1
$0
$22
$12
SPP
-$4
$0
-$1
-$5
-$3
$0
-$1
-$4
TRE
-$2
$0
-$1
-$3
-$1
$0
-$1
-$2
WECC
-$3
$0
-$5
-$8
-$3
$0
-$4
-$6
Total
-$46
$0
$26
-$20
-$37
$0
$23
-$14
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.
b. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020
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 announced through January 2020 and scheduled to occur by the
end of 2028. For details, see memorandum entitled "Changes to Industry Profile for Coal-Fired
Generating Units for the Steam Electric Effluent Guidelines Final Rule" (DCN SE08688 in the
rule docket). To the extent that actual unit retirements, conversions, and repowerings at steam
electric power plants differ from announced changes, estimated annualized compliance costs of
the regulatory options may differ from actual costs.
• EPA assumed that the equipment installed to meet any new limitations could reasonably be
estimated to operate for 20 years or more, based on a review of reported performance
characteristics of the equipment components. EPA 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.
• 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
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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.
• EPA estimated VIP participants for options A and B based on the lowest cost technology on an
annualized and discounted basis, but plant owners may consider other factors in deciding whether
to participate in the VIP so actual participation may be higher or lower than projected.
• As described in Section 2.2.2, EPA accounted for the 2015 final CCR rule and incremental effects
of the final CCR Part A rule in its analysis of the final rule. EPA did not account for the proposed
CCR Part B rule in its analysis of this final ELG rule. Because the proposed CCR Part B rule is a
deregulatory action, EPA estimates that cost savings of this final ELG rule are underestimated.
For more details on the effects of the proposed CCR Part B rule on the total costs of the final rule,
see the memorandum entitled "Assessment of the economic impacts of the final revised Steam
Electric ELGs relative to an alternative baseline including the CCR Part B Rule " (DCN SE09360
in the rule docket).
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4 Cost and Economic Impact Screening Analyses
4.1 Analysis Overview
Following the same methodology used for the 2015 rule and 2019 proposal analyses (U.S. EPA, 2015c,
2019a), 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
regulatory options that EPA evaluated, 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 (2015c; 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 any 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.28 Note that EPA estimates that the converse
also applies - plants operating in regulated markets are more likely to pass on any decline in production
costs to their customer as reduced rates, whereas customer savings are not guaranteed in deregulated
markets.
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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In assessing the cost impact of the baseline and regulatory options (including the final rule) 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 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.29
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 and FGD wastewater beginning in 2021, with compliance occurring as late
as 2028 for certain plants, wastestreams, and regulatory options.
Using the same approach as used for the 2015 rule and 2019 proposal (U.S. EPA, 2015c, 2019a), EPA
updated the impacts of the baseline first, and then updated the analysis for regulatory options A through
C. The difference in findings between the regulatory options and baseline provides insight into the
potential impacts of the regulatory options.
EPA updated the approach used for the 2015 rule and 2019 proposal to incorporate more recent data. For
the current analysis, EPA used 2020 as the basis for comparing after-tax compliance costs (see Chapter 3)
to revenue at the plant level.30 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 2013 to 2018 from the EIA-923 database by 6-year average electricity prices over the
period 2013 to 2018 from the EIA-861 database (EIA, 2018b; EIA, 2019c).31'32 EPA estimated
compliance costs in 2018 dollars. To provide cost and revenue comparisons on a consistent analysis-year
(2020) and dollar-year (2018) 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
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 2018 dollars using the Gross Domestic
Product (GDP) deflator index published by the U.S. Bureau of Economic Analysis (BEA) (2019). These individual
yearly values were then averaged and brought forward to 2020 using electricity price projections from the Annual
Energy Outlook publication for 2019 (AEO2019) (EIA, 2019a). AEO2019 contains projections and analysis of U.S.
energy supply, demand, and prices through 2050. AEO2018 electricity price projections are in constant dollars;
therefore, these adjustments yield 2020 revenue values in dollars of the year 2018.
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4: Screening-Level Economic Impacts
U.S. EPA (2006), and the approach EPA has used previously in analyses of the 2015 ELG rule (U.S.
EPA, 2015c) and 316(b) Existing Facilities Rule (U.S. EPA, 2014a), 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.
4.2.2 Key Findings for Regulatory Options
EPA estimates that for 902 steam electric power plants, including those estimated to incur zero
compliance costs, costs would not exceed the one percent of revenue threshold under the baseline. Table
4-1 presents cost-to-revenue analysis results for the baseline, while Table 4-2 presents results for the
regulatory options relative to the baseline. Under all regulatory options reanalyzed, most plants would not
experience significant changes in their cost-to-revenue ratios compared to baseline costs. However,
additional plants would fall from the higher thresholds into the one percent of revenue threshold, as
shown in Table 4-2, which reports changes in plant-level cost-to-revenue results by owner type and
regulatory option. Under regulatory options A through C, almost all plants that experience changes in
cost-to-revenue thresholds shift downwards. For details on cost-to-revenue results for small entities, see
Section 8.2.
Table 4-1: Plant-Level Cost-to-Revenue Analysis Results for the Baseline by Owner Type
Total Number of
Number of Plants with a Ratio of
Owner Type
Plants3
0%a'b
*0 and <1%
>1 and <3%
>3%
Baseline
Cooperative
62
55
5
2
0
Federal
20
16
2
2
0
Investor-owned
489
407
79
2
1
Municipality
120
110
6
2
2
Nonutility
185
183
2
0
0
Political Subdivision
34
33
0
0
1
State
4
2
2
0
0
Total
914
806
96
8
4
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, 2020.
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Table 4-2: Plant-Level Incremental Cost-to-Revenue Analysis Results by Owner Type and
Regulatory Option
A Total
A Number of Plants with a Ratio of
Number of
Owner Type
Plants3
0%a'b
#0 and <1%
>1 and 3%
>3%
Option A
Cooperative
0
2
-2
0
0
Federal
0
0
0
0
0
Investor-owned
0
26
-24
-1
-1
Municipality
0
3
-2
-1
0
Nonutility
0
1
-1
0
0
Political Subdivision
0
0
0
0
0
State
0
1
-1
0
0
Total
0
33
-30
-2
-1
Option B
Cooperative
0
2
-2
0
0
Federal
0
0
0
0
0
Investor-owned
0
19
-19
1
-1
Municipality
0
2
-1
-1
0
Nonutility
0
1
-1
0
0
Political Subdivision
0
0
0
0
0
State
0
0
0
0
0
Total
0
24
-23
0
-1
Option C
Cooperative
0
2
-2
0
0
Federal
0
0
0
-1
1
Investor-owned
0
19
-20
1
0
Municipality
0
2
-1
-1
0
Nonutility
0
1
-1
0
0
Political Subdivision
0
0
0
0
0
State
0
0
0
0
0
Total
0
24
-24
-1
1
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.
c. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020.
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4.2.3 Uncertainties and Limita Hons
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 2020 plant revenue and those estimated using EIA databases for 2013 through
2018.
• 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 baseline and regulatory options (including the final rule) 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 final rule, will continue to amortize capital expenses over
the 20-year life of the technology. To the extent that plant owners use an accelerated amortization
schedule, this analysis may understate the potential impact of the baseline and regulatory options
on steam electric power plants. EPA also conducted a sensitivity analysis that compares costs of
leasing to the costs of purchasing equipment, but the analysis is highly uncertain. See the
memorandum entitled "Cost to Lease Flue Gas Desulfurization Wastewater Treatment" (DCN
SE08633 in the rule docket).
4.3 Cost-to-Revenue Screening Analysis: Parent Entity-Level Analysis
Following the methodology EPA used for the analysis of the 2015 rule and 2019 proposal analyses (U.S.
EPA, 2015 c, 2019a), 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.33'34 The entity-level
analysis maintains the worst-case analytical assumption of no pass-through of compliance costs to
electricity consumers used for the plant-level cost-to-revenue analysis in Section 4.2.
4.3.1 Analysis Approach and Data Inputs
Following the approach used in the 2015 rule and 2019 proposal (U.S. EPA, 2015c, 2019a), 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.
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: Screening-Level Economic Impacts
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 rule and 2019 proposal (U.S. EPA, 2015c, 2019a; 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 2015 rule
and the 2019 proposal.
Determining the Parent Entity
EPA used information from the 2018 EIA-860 database which provides owners and the share of
ownership in electric generating units (EIA, 2019b) to determine ownership of each coal-fired steam
electric power plant and surveyed non-coal steam electric power plants (see U.S. EPA, 2015c for
discussion of how non-coal steam electric power plants are incorporated in the analysis). EPA
supplemented this information with data from corporate/financial websites and from the Steam Electric
Survey to identify the highest-level domestic parent entity for each plant.
Determinins Parent Entity Revenue
For each parent entity identified in the preceding step, EPA determined revenue values based on
information from corporate or financial websites, if those values were available. EPA tried to obtain
revenue for as many years within 2015 through 2017 and used the average of reported values. If revenue
values were not reported on corporate/financial websites, the Agency used 2015-2018 average revenue
values from the EIA-861 database (EIA, 2018b).
EPA restated entity revenue values in 2018 dollars using the GDP Deflator. For this analysis, the Agency
assumed that these average historical revenue values are representative of revenues as of 2020. Although
the entity-level revenue values might reasonably be estimated to change by 2020 (i.e.. have increased or
decreased relative to average historical revenue), EPA was less confident in the reliability of projecting
revenue values at the entity level than in that of projecting plant-level revenue values to reflect changes in
generation. For the entity-level analysis, therefore, EPA did not project or further adjust revenue values
developed using the sources and methodology described above but used these values as is. In effect,
plants and their parent entities are assumed to be the same 'business entities' in terms of constant dollar
revenue in 2020 as they were in the year for which revenue were reported.
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Estimating Compliance Costs at the Level of the Parent Entity
Following the approach used in the analysis of the 2015 rule, to account forthe parent entities of all 914
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 (2015c) for details.
4.3.2 Key Findings for Regulatory Options
Table 4-3 and Table 4-4 summarize 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. Table 4-3
presents results under the baseline, while Table 4-4 presents results under the regulatory options relative
to the baseline. The tables show 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 231 and 459 parent entities own steam electric power plants based on the
range indicated by Case 1 and Case 2, respectively. Under the baseline in Case 1, 225 parent entities are
estimated to incur costs less than one percent of revenue, and in Case 2, this number is 452 parent entities.
When examining changes in number of parent entities that shift across cost-to-revenue thresholds, as
shown in Table 4-4, most entities stay within the same threshold.35 However, where there are changes
across thresholds, these changes all move downward, i.e., smaller impacts relative to revenue.
Overall, this screening-level analysis shows that few entities are likely to experience significant changes
in cost-to-revenue ratios compared to the baseline, and economic impacts to these entities would be
lessened under the final rule.
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 4-3: Baseline Entity-Level Cost-to-Revenue Analysis Results
Case 1: Lower bound estimate of number of firms
owning plants that face requirements under the
regulatory analysis
Case 2: Upper bound estimate of number of firms
owning plants that face requirements under the
regulatory analysis
Entity Type
Total
Number
of
Entities
Number of Entities with a Ratio of
Total
Number
of
Entities
Number of Entities with a Ratio of
0%a
*0 and
<1%
>1 and
3%
>3%
Unknown
0%a
*0 and
<1%
>1 and
3%
>3%
Unknown13
Baseline
Cooperative
27
20
6
1
0
0
49
42
6
1
0
0
Federal
1
0
1
0
0
0
3
2
1
0
0
0
Investor-
owned
66
33
32
1
0
0
149
116
32
1
0
0
Municipality
57
47
6
4
0
0
92
82
6
4
0
0
Nonutility
68
66
2
0
0
0
142
139
2
0
0
1
Other
Political
Subdivision
10
9
1
0
0
0
21
20
1
0
0
0
State
2
1
1
0
0
0
2
1
1
0
0
0
Total
231
176
49
6
0
0
459
403
49
6
0
1
a. These entities own only 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.
b. EPA was unable to determine revenues for one parent entity under Case 2.
Source: U.S. EPA Analysis, 2020.
Table 4-4: Entity-Level Incremental 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
Case 2: Upper bound estimate of change in
number of firms owning plants that face
requirements under the regulatory analysis
A Total
Number
of
Entities
A Number of Entities with a Ratio of
A Total
Number
of
Entities
A Number of Entities with a Ratio of
0%a
*0 and
<1%
>1 and
3%
>3%
Unknown
0%a
*0 and
<1%
>1 and
3%
>3%
Unknow
n
Option iy
Cooperative
Federal
Investor-
owned
0
1
-1
0
0
0
0
1
-1
0
0
0
Municipality
Nonutility
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Table 4-4: Entity-Level Incremental 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
A Total
A Number of Entities with a Ratio of
A Total
A Number of Entities with a Ratio of
Number
Number
of
*0 and
>1 and
of
*0 and
>1 and
Unknow
Entity Type
Entities
0%a
<1%
3%
>3%
Unknown
Entities
0%a
<1%
3%
>3%
n
Case 2: Upper bound estimate of change in
number of firms owning plants that face
requirements under the regulatory analysis
Option A
Cooperative
0
2
-2
0
0
0
0
2
-2
0
0
0
Federal
0
0
0
0
0
0
0
0
0
0
0
0
Investor-
owned
0
10
-10
0
0
0
0
10
-10
0
0
0
Municipality
0
3
-1
-2
0
0
0
3
-1
-2
0
0
Nonutility
0
1
-1
0
0
0
0
1
-1
0
0
0
Other"
0
0
0
0
0
0
0
0
0
0
0
0
State
0
0
0
0
0
0
0
0
0
0
0
0
Total
0
16
-14
-2
0
0
0
16
-14
-2
0
0
Option B
Cooperative
0
2
-2
0
0
0
0
2
-2
0
0
0
Federal
0
0
0
0
0
0
0
0
0
0
0
0
Investor-
owned
0
7
-7
0
0
0
0
7
-7
0
0
0
Municipality
0
2
0
-2
0
0
0
2
0
-2
0
0
Nonutility
0
1
-1
0
0
0
0
1
-1
0
0
0
Other"
0
0
0
0
0
0
0
0
0
0
0
0
State
0
0
0
0
0
0
0
0
0
0
0
0
Total
0
12
-10
-2
0
0
0
12
-10
-2
0
0
Option C
Cooperative
0
2
-2
0
0
0
0
2
-2
0
0
0
Federal
0
0
0
0
0
0
0
0
0
0
0
0
Investor-
owned
0
7
-7
0
0
0
0
7
-7
0
0
0
Municipality
0
2
-1
-1
0
0
0
2
-1
-1
0
0
Nonutility
0
1
-1
0
0
0
0
1
-1
0
0
0
Other"
0
0
0
0
0
0
0
0
0
0
0
0
State
0
0
0
0
0
0
0
0
0
0
0
0
Total
0
12
-11
-1
0
0
0
12
-11
-1
0
0
a. These entities own only 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.
b. Other political subdivision.
c. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect changes
in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020.
4.3.3 Uncertainties and Limita tions
Despite EPA's use of the best available information and data, this analysis of entity-level impacts has
uncertainties and limitations, including:
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• The entity-level revenue values obtained from the corporate and financial websites or EIA
databases are for 2015 through 2018. To the extent that actual 2020 entity revenue values are
different, on a constant dollar basis, from those estimated using historical data, the cost-to-
revenue measure for parent entities of steam electric power plants may be over- or under-
estimated.
• The assessment of entity-level impacts relies on approximate upper and lower bound estimates of
the number of parent entities and the numbers of steam electric power plants that these entities
own. EPA expects that the range of results from these analyses provides appropriate insight into
the overall extent of entity-level effects.
• As is the case with the plant-level analysis discussed in Section 4.2, the zero cost pass-through
assumption represents a worst-case scenario from the perspective of the plant owner. To the
extent that companies are able to pass some compliance costs on to consumers through higher
electricity prices, this analysis may overstate the potential impact of the baseline and regulatory
options on steam electric power plants. Also, as is the case with the plant-level analysis discussed
in Section 4.2, the assumption that owners of plants that retire or repower during the period of
analysis, but after installing equipment to comply with the final rule, will continue to amortize
capital expenses over the 20-year life of the technology, may understate the potential impact of
the baseline and regulatory options on steam electric power plants. EPA also conducted a
sensitivity analysis that compares costs of leasing to the costs of purchasing equipment, but the
analysis is highly uncertain. See the memorandum entitled "Cost to Lease Flue Gas
Desulfurization Wastewater Treatment" (DCN SE08633 in the rule docket).
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5 Assessment of the Impact of the Final Rule on National and
Regional Electricity Markets
Following the approach used to analyze the impacts of the 2015 rule, the 2019 proposed rule, and other
various regulatory actions affecting the electric power sector over the last decade, EPA used the
Integrated Planning Model (IPM®), a comprehensive electricity market optimization model that can
evaluate such impacts within the context of regional and national electricity markets. To assess market-
level effects of the final rule, EPA used the latest version of this analytic system: Integrated Planning
Model Version 6 (IPM v6) January 2020 Reference Case (U.S. EPA, 2018, 2020b).36
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 final rule would result in any capacity retirements (full or partial plant
closures)37 and to provide insight on the impact of the regulatory options on the overall electricity market,
including to assess whether the regulatory options may significantly affect the energy supply, distribution
or use under Executive Order 13211 (see Section 10.7). EPA ran IPM for Option A to evaluate the
impacts of the final rule.
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 2018 (AEO2018), whereas
the screening-level analyses discussed in other chapters of this report assume that plants would generate
approximately the same quantity of electricity in 2021 as they did on average during 2013-2018.
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 (2018), IPM generates
36 For more information on IPM, see https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling.
37 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, 2015c).
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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 operation and
maintenance (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 2018
(AEO2018). 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, 2018).
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 final rule only. Though the screening-level
analysis and EPA's assumptions regarding baseline operating practices and facility and firm revenue
implicitly account for existing environmental rules, it does not explicitly estimate the effects of these rules
across the entire electricity market over the period of analysis. The IPM analysis, on the other hand,
dynamically estimates changes in capacity and generation over the IPM analysis period that account for
retrofits and retirements as a result of a broader set of environmental rules. Notably, for the analysis for
the final rule, EPA started from an electricity market "reference case" (January 2020) that includes
market-level impacts of the Cross-State Air Pollution Rule (CSAPR and CSAPR Update), Mercury and
Air Toxics Standards (MATS), CWA section 316(b) rule, the final 2015 CCR rule, and the ACE rule
(U.S. EPA, 2020b), among others. 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, and the 45Q tax credit for carbon dioxide sequestration. EPA added to this
reference case the incremental effects of the CCR Part A rule.
In analyzing the effect of the regulatory options using IPM v6, EPA first specified a baseline that
incorporates capital costs38 and fixed and variable O&M costs that are estimated to be incurred by steam
electric power plants and generating units to comply with the 2015 rule requirements for bottom ash
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
weighted average after tax cost of capital, 4.25 percent; see Chapter 10 in the IPM documentation [U.S. EPA, 2018] for
more information on IPM's financial discount rate).
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transport water and FGD wastewater (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]). Baseline costs were
developed using the same approach described in Chapter 3, based on the technology options and
compliance deadlines for the 2015 Rule (see Table 1-1 and Table 3-1 for the baseline 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. Results for this first model run provide the baseline against which to compare
outputs for regulatory options runs. In analyzing Option A, EPA modified the associated fixed and
variable costs input to IPM to reflect the difference between the bottom ash transport water and FGD
wastewater compliance costs under the 2015 rule and those for the final rule. 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 for performing the analyses of the regulatory
options and the key outputs reviewed as indicators of the effect of the final rule.
• Section 5.2 provides the findings from the market model analysis.
• Section 5.3 discusses the effects of the regulatory options on new coal capacity.
• Section 5.4 identifies key uncertainties and limitations in the market model analysis.
5.1 Model Analysis Inputs and Outputs
To assess the impact of the final rule, EPA compared the policy run (Option A) to an IPM v6 Baseline
projection of electricity markets and plant operations that includes the modeled effects of the 2015 rule,
among existing environmental regulations.
5.1.1 Analysis Years
As described in U.S. EPA (2018), IPM v6 models the electric power market over the 34-year period from
2021 to 2054, breaking this period into the eight 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 2021 and as late as 2028. This technology
implementation window primarily falls within the time periods captured by the 2021, 2023 and 2025 run
years (i.e., 2021-2027). The 2030 run year includes the last year of technology implementation, 2028, and
goes through 2032. The last year in the analysis period (2047) coincides with the end of the period
captured by the 2045 run year.
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Table 5-1: IPM Run Years
Run Year
Years Represented
2021
2021
2023
2022-2023
2025
2024-2027
2030
2028-2032
2035
2033-2037
2040
2038-2042
2045
2043-2047
2050
2048-2054
Source: U.S. EPA, 2018.
To assess the effect of the final rule on electricity markets during the period after technology
implementation by all steam electric power plants - the steady state post-compliance period - EPA
analyzed results reported for the IPM 2030 run year.39 As discussed in Chapter 3, under the final 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., 2028, and continue into the future. Because the model run
year 2030 captures decisions made through the end of 2032 by which time all plants will have achieved
the final 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,4" 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 V6 for the Market Model Analysis of the Final Rule
5.1.2.1 Existing Plants
The inputs for the electricity market analyses include compliance costs and the technology
implementation year. IPM models the entire electric power generating industry using a total of 18,617
generating units at 7,545 plants. EPA estimated that 75 steam electric power plants may incur non-zero
compliance costs under the final rule (Option A), based on the costing methodologies described in the
Supplemental TDD (U.S. EPA, 2020e) and timing of any announced retirements and repowerings relative
to compliance deadlines.
Although all rim years are reported in the IPM results, for the 2015 rule EPA detailed results for two rim years to cover
the range of potentially significant changes: one run year representing the period when plants would be in the process
of implementing technologies, and one run year falling after the compliance period. The regulatory options of the 2019
proposal and the requirements of the final rule (Option A) were detailed using the run year 2030 only because unlike
the 2015 rule analysis, the impacts associated with the final rule were too small to warrant detailed reporting based on
two run years. The Agency presents summary results for all other run years.
Early retirement of generating units reflects reductions in generating capacity relative to the baseline and relative to any
scheduled retirements.
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EPA input the final rule capital, initial one-time costs, annual fixed O&M (FOM), and annual variable
O&M (VOM) costs, as well as costs incurred on a non-annual, periodic basis (3-year, 5-year, 6-year, 10-
year) into IPM as FOM and VOM cost adders.41 IPM modelers calculated the net present value of
annualized costs using IPM's conventional framework for recognizing costs incurred overtime, by
assigning to each cost the same technology implementation years discussed in Chapter 3.42 Annualized
capital cost and FOM and VOM cost adders are represented in IPM as incremental costs specific to
individual model plants.
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 the final rule.
5.1.3 Key Outputs of the Market Model Analysis Used in Assessing the Effects of the Final Rule
IPM generates a series of outputs at different levels of aggregation (model plant, region, and nation). For
this analysis, EPA used a subset of the available IPM output for each model run (Baseline and Option A),
focusing on metrics that quantify projected changes in capacity (including early retirements and new
capacity), generation, production costs, electricity prices, and emissions. See Chapter 5 in the 2015 RIA
(U.S. EPA, 2015c) for descriptions of the IPM variables.
EPA compared national-level outputs for selected IPM run years (2021, 2023, 2025, 2030, 2040, and
2050).43 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 Option A provides insight into the incremental
effect of the final 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 final rule are assessed as the difference between key economic and operational impact
metrics that compare the results for Option A to the Baseline. This section presents two sets of analysis:
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
value of levelized 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, 2018, page 2-7).
IPM also provides estimates for four additional run years: 2023, 2025, 2035, and 2045.
IPM output also includes total fuel usage, which is not part of the analysis discussed in this Chapter.
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• Analysis of national-level impacts: EPA compared baseline and 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 final rule over time.
• Analysis of long-term regulatory impacts: As discussed earlier, to assess the long-term impact of
the final rule, EPA compared Baseline and Option A IPM results reported for 2030. These results
provide insight on the effect of the final rule both for the entire electricity market and for steam
electric power plants specifically.
5.2.1 National-level Analysis Results for Model Years 2021-2050
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. The baseline projections show a progressive decline in total coal generation
capacity during the period (from 170.6 GW in 2021 to 122.3 GW in 2050; 28 percent reduction) and
nuclear generation capacity (35 percent reduction), and increases in generation capacity from renewables
and natural gas. These projections are consistent with the market trends discussed in Section 2.3. Table
5-3 provides incremental changes in these measures for Option A relative to the baseline (negative values
represent decreases relative to the baseline). For conciseness, the tables show results for the years 2021,
2023, 2025, 2030, 2040, and 2050, but IPM v6 also provides projections for model years 2035 and 2045.
Note that while the table includes projections for the 2050 run year, the represented period (2048-2054) is
outside of the analysis period EPA used in its analysis of the social costs and benefits, which covers 2021
through 2047.
Table 5-2: Baseline Projections, 2021-2050
Economic Measures
Baseline
2021
2023
2025
2030
2040
2050
Total Costs
Total Costs (million 2018$)
$135,820
$141,433
$146,455
$158,473
$179,987
$175,584
Prices
National Wholesale Electricity
36.81
36.74
40.56
41.06
42.80
39.62
Price (mills/kWh)
Total Capacity (Cumulative GW)
Renewables3
289.6
316.7
341.0
438.9
483.6
664.3
Coal
170.6
167.3
165.6
158.9
150.4
122.3
Nuclear
90.5
78.5
77.4
68.5
68.4
58.7
Natural Gas
415.8
416.4
418.4
420.4
480.8
562.8
Oil/Gas Steam
66.4
66.7
66.9
66.0
65.5
63.3
Other
6.4
6.4
6.4
6.4
6.4
6.4
Grand Total
1,041.3
1,053.8
1,080.2
1,169.9
1,280.0
1,515.6
New Capacity (Cumulative GW)
Renewables3
67.0
94.4
118.7
216.7
261.4
442.1
Coal
0.0
0.0
0.0
0.0
0.0
0.0
Nuclear
0.0
0.0
0.0
0.0
0.0
0.0
Natural Gas
16.6
17.8
19.8
22.6
83.3
166.5
Other
0.0
0.0
0.0
0.0
0.0
0.0
Grand Total
84.8
113.4
142.4
249.2
368.8
645.8
Retirements (GW)b
Combined Cycle Retirements
3.8
3.8
3.8
4.2
4.2
4.2
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Table 5-2: Baseline Projections, 2021-2050
Economic Measures
Baseline
2021
2023
2025
2030
2040
2050
Coal Retirements
44.2
46.0
46.6
52.9
61.5
89.0
Combustion Turbine
Retirements
1.9
2.5
2.5
2.8
3.1
4.4
Nuclear Retirements
3.9
17.2
18.3
25.9
25.2
34.9
Oil/Gas Retirements
8.4
8.2
8.2
9.1
9.6
11.9
Grand Total
66.1
82.0
83.7
99.2
107.9
149.3
Generation Mix (thousand GWh
Renewables3
845.3
909.7
964.8
1,241.0
1,355.1
1,943.4
Coal
831.6
879.7
880.4
821.2
718.5
517.1
Nuclear
711.0
621.3
612.4
541.4
540.6
463.6
Natural Gas
1,602.7
1,626.4
1,630.7
1,621.9
1,897.6
1,948.4
Oil/Gas Steam
55.2
56.5
56.1
52.1
47.4
25.9
Other
31.7
31.7
31.7
31.1
31.2
31.0
Grand Total
4,079.7
4,127.6
4,181.6
4,322.8
4,625.3
4,982.8
a. Renewables include hydropower and non-hydropower renewables.
b. There were no changes in projected retirements for IGCC, biomass, fuel cell, other fossil fuel, geothermal, hydropower,
landfill gas, other non-fossil fuel, and energy storage plants.
Source: U.S. EPA Analysis, 2020
Table 5-3: National Impact of Final Rule Relative to Baseline, 2021-2050
Economic Measures
Option A Changes Relative to Baseline
2021
2023
2025
2030
2040
2050
Total Costs
Total Costs (million 2018$)
-$9
-$198
-$132
-$130
-$149
-$17
Prices
National Wholesale Electricity
-0.04
-0.12
-0.05
-0.11
-0.04
0.01
Price (mills/kWh)
Total Capacity (Cumulative GW)
Renewables3
-0.1
-0.4
-0.2
-0.5
-0.3
-0.4
Coal
1.3
1.3
1.3
1.2
1.0
2.0
Nuclear
0.0
-0.1
-0.1
0.3
0.4
0.4
Natural Gas
-0.2
-0.2
-0.5
-1.0
-1.3
-2.1
Oil/Gas Steam
-0.3
-0.3
-0.3
-0.3
-0.2
-0.3
Other
0.0
0.0
0.0
0.0
0.0
0.0
Grand Total
0.7
0.2
0.2
-0.4
-0.4
-0.4
New Capacity (Cumulative GW)
Renewables3
0.0
-0.4
-0.2
-0.5
-0.3
-0.4
Coal
0.0
0.0
0.0
0.0
0.0
0.0
Nuclear
0.0
0.0
0.0
0.0
0.0
0.0
Natural Gas
0.0
0.0
-0.3
-0.9
-1.2
-2.0
Other
0.0
0.0
0.0
0.0
0.0
0.0
Grand Total
0.0
-0.4
-0.5
-1.5
-1.5
-2.4
Retirements (GW)b
Combined Cycle Retirements
0.2
0.2
0.2
0.1
0.1
0.1
Coal Retirements
-1.3
-1.3
-1.3
-1.2
-1.0
-2.0
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Table 5-3: National Impact of Final Rule Relative to Baseline, 2021-2050
Economic Measures
Option A Changes Relative to Baseline
2021
2023
2025
2030
2040
2050
Combustion Turbine
0.0
0.0
0.0
0.0
0.0
0.0
Retirements
Nuclear Retirements
0.0
0.1
0.1
-0.3
-0.4
-0.4
Oil/Gas Retirements
0.3
0.3
0.3
0.3
0.2
0.3
Grand Total
-0.7
-0.6
-0.6
-1.1
-1.1
-2.0
Generation Mix (thousand GWh
Renewables3
-0.1
-1.5
-0.2
-1.7
-1.5
-1.8
Coal
0.1
3.3
2.9
4.7
3.0
-1.8
Nuclear
0.0
-0.7
-0.7
2.3
3.1
3.6
Natural Gas
0.1
-1.0
-1.7
-5.7
-4.1
0.1
Oil/Gas Steam
0.0
0.0
-0.1
0.3
-0.3
0.2
Other
0.0
0.0
0.0
0.0
0.0
0.0
Grand Total
0.2
0.2
0.1
0.1
0.3
0.1
a. Renewables include hydropower and non-hydropower renewables.
b. There were no changes in projected retirements for IGCC, biomass, fuel cell, other fossil fuel, geothermal, hydropower,
landfill gas, other non-fossil fuel, and energy storage plants.
Source: U.S. EPA Analysis, 2020
5.2.1.1 Findings for the Final Rule
Under the final rule (Option A), total costs to electric power plants are projected to be lower than the
baseline from 2021 to 2050. The reduction in costs is greatest in the early years of the modeling period
(e.g., by $197.7 million in 2023), which is consistent with the timing of steam electric ELG
implementation under the baseline and the final rule. By the end of the modeling period in 2050, costs are
projected to decrease by $17.1 million (0.01 percent of baseline costs). IPM projects changes in wholesale
electricity prices between 2021 and 2050 between 0.0 and 0.1 mills per kWh.
Looking at results for total capacity by energy source, coal capacity is estimated to increase for all years
from 2021 to 2050 with the increase ranging between 1.0 GW and 2.0 GW. The additional capacity under
the final rule (Option A) is projected to come from avoided retirements of existing units, as no new coal
capacity is projected (as is also the case in the baseline). Meanwhile, decreases in capacity from
renewables and natural gas are estimated to occur from 2021 to 2050. Capacity from renewables is
estimated to decrease by 0.1 to 0.5 GW, and natural gas capacity is estimated to decrease by 0.2 to 2.1
GW, with both of these changes due to avoided new capacity additions. The reduction in nuclear capacity
in 2023-2025, by contrast, is projected to result from incremental retirements of nuclear generation units,
as they become relatively less economical to operate.
Avoided coal retirements are estimated for all years, ranging between 1.0 to 2.0 GW of the 44.2 to 89 GW
estimated to retire in the baseline. This accounts for most of the avoided retirements in the electric market
as a whole, which range between 0.6 to 2.0 GW.
Lastly, examining results for generation by energy source, generation from coal is estimated to increase
from 2021 to 2040 by 0.1 to 4.7 GWh, and decline by 1.8 GWh in 2050. These changes are offset in part
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by a decline in generation by renewables (0.1 to 1.8 GWh reduction) and natural gas generation, which
decreases from 2023 to 2040 by 1.0 to 5.7 GWh, then increases in 2050 by 0.1 GWh.
5.2.2 Detailed Analysis Results for Model Year2030
In the following results which reflect conditions in the period of 2028 through 2032, all plants are
estimated to meet the final BAT limits and pretreatment standards associated with the final rule (Option
A). Forthis more detailed analysis, following the approach used for the 2015 rule (U.S. EPA, 2015b) and
2019 proposed rule (U.S. EPA, 2019a), EPA used parsed IPM outputs and considered impact metrics of
interest at three levels of aggregation:
• Impact on national and regional electricity markets (Section 5.2.2.1),
• Impact on steam electric power plants as a group (Section 5.2.2.2), and
• Impact on individual steam electric power plants (Section 5.2.2.3).
5.2.2.1 Impact on National and Regional Electricity Markets
The market-level analysis assesses national and regional changes as a result of the regulatory
requirements. EPA analyzed six measures:
• Changes in available capacity. This measure analyzes changes in the nameplate capacity
available to generate electricity. A long-term reduction in available capacity may result from
partial or full closures of steam electric power plants. Conversely, increased capacity may result
from avoided partial or full closure of the plants or the addition of new capacity. Only capacity
that is projected to remain operational in the baseline case but is closed in the policy case is
considered a closure attributable to the final rule. The Market Model Analysis may project partial
(i.e.. unit) or full plant early retirements (closures) for the final rule. It may also project partial or
full avoided closures in which a unit or plant that is estimated to close in the baseline is estimated
to continue operation in the policy case. Avoided closures may occur, in particular, when the
regulation results in lower costs for a given plant.
• Changes in the wholesale price of electricity. This measure represents the change in the annual
average energy price (the marginal cost of meeting demand in each time segment, averaged
annually) plus any capacity prices associated with maintaining a reserve margin. In the long term,
electricity prices may change as a result of changes in generation costs at steam electric power
plants or due to generating unit and/or plant closures.
• Changes in generation: This measure considers the amount of electricity generated. At a regional
level, long-term changes in generation may result from plant closures or a change in the amount
of electricity traded between regions. At the national level, the demand for electricity does not
change between the baseline and the final 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.
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• Changes in costs: This measure considers changes in the overall cost of generating electricity,
including fuel costs, variable and fixed O&M costs, and capital costs. These costs are not limited
to steam electric generating units or to compliance costs of the final rule, but more broadly reflect
changes in the cost of generating electricity across all units. Fuel costs and variable O&M costs
are production costs that vary with the level of generation. Fuel costs generally account for the
single largest share of production costs. Fixed O&M costs and capital costs do not vary with
generation. They are fixed in the short-term and therefore do not affect the dispatch decision of a
unit (given sufficient demand, a unit will dispatch as long as the price of electricity is at least
equal to its per MWh production costs). However, in the long-run, these costs need to be
recovered for a unit to remain economically viable.
• Changes in average variable production costs per MWh\ This measure considers the change in
average variable production cost per MWh. Variable production costs are a subset of the costs in
the bullet above and include fuel costs and other variable O&M costs but exclude fixed O&M
costs and capital costs. Production cost per MWh is a primary determinant of how often a
generating unit is dispatched. This measure presents similar information to total fuel and variable
O&M costs, but normalized for changes in generation.
• Changes in CO2, Nox, SO2, Hg, and HCL emissions: This measure considers the change in
emissions resulting from electricity generation, for example due to changes in the fuel mix.
Compliance with the final rule is estimated to reduce generation costs when compared to the
baseline and make electricity generated by some steam electric units less expensive compared to
that generated at other steam electric or non-steam electric units. These changes may in turn result
in changes in air pollutant emissions, depending on the emissions profile of dispatched units.
Projected changes in air emissions are used as inputs for the analysis of air-related benefits of the
final rule (see Chapter 8 in the BCA [U.S. EPA, 2020a]).
Table 5-4 summarizes IPM results for the final rule at the level of the national market and also for
regional electricity markets defined on the basis of NERC regions. All of the impact metrics described
above are reported at both the national and NERC level except electricity prices, which are calculated in
IPM only at the regional level (i.e.. not aggregated to national level). Differences in the relative
magnitude of impacts across the NERC regions largely reflect regional differences in compliance costs
for the final rule as compared to the baseline (/'. e., number of plants incurring costs and the magnitude of
these costs) and the generation mix.
Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2030
Economic Measures
(all dollar values in 2018$)
Baseline Value
Option A
Value
Difference
% Change
National Totals
Total Domestic Capacity (GW)
1,169
1,169
-0.4
0.0%
Existing
1.1
0.1%
New Additions
-1.5
-0.1%
Early Retirements
-1.1
-0.1%
Wholesale Price ($/MWh)
$41.59
$41.48
-$0.11
-0.3%
Generation (TWh)
4,316
4,316
-0.3
0.0%
Costs ($Millions)
$161,476
$161,351
-$125
-0.1%
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Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2030
Economic Measures
Option A
(all dollar values in 2018$)
Baseline Value
Value
Difference
% Change
Fuel Cost
$66,408
$66,459
t—1
LO
0.1%
Variable O&M
$10,045
$10,039
-$5
-0.1%
Fixed O&M
$51,818
$51,823
$6
0.0%
Capital Cost
$33,205
$33,029
-$176
-0.5%
Average Variable Production Cost ($/MWh)
$17.71
$17.72
$0.01
0.1%
C02 Emissions (Million Metric Tons)
1,482
1,484
2.4
0.2%
Mercury Emissions (Tons)
4
4
0.0
0.2%
NOx Emissions (Million Tons)
1
1
0.0
0.1%
S02 Emissions (Million Tons)
1
1
0.0
0.2%
HCL Emissions (Million Tons)
0
0
0.0
0.5%
Florida Reliability Coordinating Council (FRCC)
Total Domestic Capacity (GW)
62
61
-0.7
-1.1%
Existing
1 1 o.o
0.0%
New Additions
-0.7
-1.1%
Early Retirements
0.0%
Wholesale Price ($/MWh)
$43.63
$43.61
-$0.02
0.0%
Generation (TWh)
257
257
0
-0.1%
Costs ($Millions)
$10,738
$10,707
-$31
-0.3%
Fuel Cost
$6,245
$6,270
$25
0.4%
Variable O&M
$572
$575
$3
0.5%
Fixed O&M
$2,548
$2,537
t—1
t—1
1
-0.4%
Capital Cost
$1,373
$1,325
00
1
-3.5%
Average Variable Production Cost ($/MWh)
$26.54
$26.67
$0.13
0.5%
C02 Emissions (Million Metric Tons)
87
87
0.6
0.7%
Mercury Emissions (Tons)
0
0
0.0
0.5%
NOx Emissions (Million Tons)
0
0
0.0
1.0%
S02 Emissions (Million Tons)
0
0
0.0
12.1%
HCL Emissions (Million Tons)
0
0
0.0
13.5%
Midwest Reliability Organization (MRO)
Total Domestic Capacity (GW)
75
75
0.1
0.1%
Existing
1 1 °'°
0.1%
New Additions
O.i
0.1%
Early Retirements
1 1 o.o
-0.1%
Wholesale Price ($/MWh)
$37.23
$37.26
$0.03
0.1%
Generation (TWh)
291
291
0
0.1%
Costs ($Millions)
$9,854
$9,867
$13
0.1%
Fuel Cost
$3,308
$3,311
$2
0.1%
Variable O&M
$741
$741
-$1
-0.1%
Fixed O&M
$2,858
$2,860
$2
0.1%
Capital Cost
$2,947
$2,956
$9
0.3%
Average Variable Production Cost ($/MWh)
$13.93
$13.92
-$0.01
0.0%
C02 Emissions (Million Metric Tons)
122
122
0.0
0.0%
Mercury Emissions (Tons)
0
0
0.0
0.1%
NOx Emissions (Million Tons)
0
0
0.0
0.1%
S02 Emissions (Million Tons)
0
0
0.0
0.0%
HCL Emissions (Million Tons)
0
0
0.0
0.0%
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Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2030
Economic Measures
(all dollar values in 2018$)
Baseline Value
Option A
Value
Difference
% Change
Northeast Power Coordinating Council (NPCC)
Total Domestic Capacity (GW)
81
81
0.2
0.2%
Existing
1 1 °'°
0.0%
New Additions
0,2
0.2%
Early Retirements
1 1 o.o
0.0%
Wholesale Price ($/MWh)
$40.95
$40.79
-$0.16
-0.4%
Generation (TWh)
255
256
0
0.1%
Costs ($Millions)
$10,856
$10,882
$26
0.2%
Fuel Cost
$3,261
$3,241
-$20
-0.6%
Variable O&M
$393
$393
$0
0.0%
Fixed O&M
$3,770
$3,781
$11
0.3%
Capital Cost
$3,432
$3,467
$35
1.0%
Average Variable Production Cost ($/MWh)
$14.31
$14.22
-$0.09
-0.6%
C02 Emissions (Million Metric Tons)
47
47
0.0
0.0%
Mercury Emissions (Tons)
0
0
0.0
0.5%
NOx Emissions (Million Tons)
0
0
0.0
0.2%
S02 Emissions (Million Tons)
0
0
0.0
6.5%
HCL Emissions (Million Tons)
0
0
0.0
1.8%
ReliabilityFirst Corporation (RFC)
Total Domestic Capacity (GW)
231
230
-0.8
-0.4%
Existing
1 1 "°'4
-0.2%
New Additions
1 1 "0.5
-0.2%
Early Retirements
0.2%
Wholesale Price ($/MWh)
$40.32
$40.27
-$0.05
-0.1%
Generation (TWh)
937
936
-1
-0.1%
Costs ($Millions)
$37,201
$37,075
-$126
-0.3%
Fuel Cost
$15,694
$15,695
$1
0.0%
Variable O&M
$2,467
$2,435
-$32
-1.3%
Fixed O&M
$10,847
$10,823
-$23
-0.2%
Capital Cost
$8,193
$8,121
-$71
-0.9%
Average Variable Production Cost ($/MWh)
$19.38
$19.36
-$0.02
-0.1%
C02 Emissions (Million Metric Tons)
405
403
-1.3
-0.3%
Mercury Emissions (Tons)
1
1
0.0
-0.3%
NOx Emissions (Million Tons)
0
0
0.0
-0.3%
S02 Emissions (Million Tons)
0
0
0.0
-0.3%
HCL Emissions (Million Tons)
0
0
0.0
-0.6%
Southeast Electric Reliability Council (SERC)
Total Domestic Capacity (GW)
269
270
1.2
0.4%
Existing
1.5
0.6%
New Additions
-0.3
-0.1%
Early Retirements
-1.5
-0.6%
Wholesale Price ($/MWh)
$43.32
$42.98
-$0.34
-0.8%
Generation (TWh)
1,116
1,117
0
0.0%
Costs ($Millions)
$43,420
$43,445
$25
0.1%
Fuel Cost
$20,902
$20,930
$28
0.1%
Variable O&M
$2,672
$2,695
$24
0.9%
Fixed O&M
$15,982
$16,023
$41
0.3%
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Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2030
Economic Measures
(all dollar values in 2018$)
Baseline Value
Option A
Value
Difference
% Change
Capital Cost
$3,864
$3,796
00
to
1
-1.8%
Average Variable Production Cost ($/MWh)
$21.11
$21.16
$0.04
0.2%
C02 Emissions (Million Metric Tons)
400
403
2.5
0.6%
Mercury Emissions (Tons)
1
1
0.0
1.3%
NOx Emissions (Million Tons)
0
0
0.0
0.2%
S02 Emissions (Million Tons)
0
0
0.0
-0.9%
HCL Emissions (Million Tons)
0
0
0.0
1.6%
Southwest Power Pool (SPP)
Total Domestic Capacity (GW)
83
83
-0.3
-0.4%
Existing
0.0
0.0%
New Additions
1
-0.3
-0.3%
Early Retirements
0.0
0.0%
Wholesale Price ($/MWh)
$37.91
$37.85
-$0.06
-0.2%
Generation (TWh)
264
264
0
-0.1%
Costs ($Millions)
$8,572
$8,547
-$26
-0.3%
Fuel Cost
$3,538
$3,551
$13
0.4%
Variable O&M
$708
$709
$1
0.1%
Fixed O&M
$2,818
$2,807
t—1
t—1
1
-0.4%
Capital Cost
$1,507
$1,479
-$28
-1.9%
Average Variable Production Cost ($/MWh)
$16.06
$16.12
$0.06
0.4%
C02 Emissions (Million Metric Tons)
117
117
0.6
0.5%
Mercury Emissions (Tons)
0
0
0.0
2.0%
NOx Emissions (Million Tons)
0
0
0.0
0.9%
S02 Emissions (Million Tons)
0
0
0.0
2.3%
HCL Emissions (Million Tons)
0
0
0.0
0.4%
Electric Reliability Organization of Texas (TRE)
Total Domestic Capacity (GW)
123
123
0.0
0.0%
Existing
0.0
0.0%
New Additions
0.0
0.0%
Early Retirements
0.0
0.0%
Wholesale Price ($/MWh)
$38.91
$38.92
$0.01
0.0%
Generation (TWh)
417
417
0
0.0%
Costs ($Millions)
$14,983
$14,981
-$1
0.0%
Fuel Cost
$6,745
$6,748
$2
0.0%
Variable O&M
$839
$838
$0
0.0%
Fixed O&M
$4,740
$4,738
-$2
0.0%
Capital Cost
$2,658
$2,657
-$1
0.0%
Average Variable Production Cost ($/MWh)
$18.18
$18.18
$0.00
0.0%
C02 Emissions (Million Metric Tons)
137
137
0.0
0.0%
Mercury Emissions (Tons)
0
0
0.0
-1.0%
NOx Emissions (Million Tons)
0
0
0.0
0.0%
S02 Emissions (Million Tons)
0
0
0.0
1.5%
HCL Emissions (Million Tons)
0
0
0.0
0.0%
Western Electricity Coordinating Council (WECC)
Total Domestic Capacity (GW)
246
246
0.0
0.0%
Existing
0.0
0.0%
New Additions
1
0.0
0.0%
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Table 5-4: Impact of Final Rule on National and Regional Markets in the Year 2030
Economic Measures
Option A
(all dollar values in 2018$)
Baseline Value
Value
Difference
% Change
Early Retirements
0.0
0.0%
Wholesale Price ($/MWh)
$44.32
$44.32
$0.00
0.0%
Generation (TWh)
778
778
0
0.0%
Costs ($Millions)
$25,852
$25,848
-$4
0.0%
Fuel Cost
$6,714
$6,714
$0
0.0%
Variable O&M
$1,652
$1,652
$0
0.0%
Fixed O&M
$8,254
$8,253
-$1
0.0%
Capital Cost
$9,232
$9,228
-$4
0.0%
Average Variable Production Cost ($/MWh)
$10.75
$10.75
$0.00
0.0%
C02 Emissions (Million Metric Tons)
168
168
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, 2020
5.2.2.1.1 Findings for Regulatory Option A
As reported in Table 5-4, the Market Model Analysis indicates that the final rule can be expected to have
small effects on the electricity market, relative to the baseline, on both a national and regional sub-market
basis, in the year 2030.
At the national level, total annual costs decrease by an estimated $125 million (approximately
0.1 percent) relative to baseline. Total annual costs vary by region, with estimated decreases in costs in
some regions offset by increases in other regions. Total costs in the RFC region decline by the largest
amount, $126 million (0.3 percent), followed by the FRCC region with a decrease of $31 million
(0.3 percent); changes in estimated total annual costs in the other regions range between savings of
$26 million (SPP) to increases of $26 million (NPCC). Overall at the national level, the net change in
total capacity, including increases in existing capacity (which includes avoided early retirements) and
reductions in new plants/units, is a decrease of approximately 0.4 GW in capacity, which is less than
0.1 percent of total market capacity. Although effects differ geographically, the final rule is estimated to
have minimal effect on capacity availability and supply reliability at the national level. The net capacity
decrease is a result of a decrease in capacity in the FRCC region of about 0.7 GW (1.1 percent of SERC
region capacity), in the RFC region of 0.8 GW (0.4 percent), and in the SPP region of 0.3 GW
(0.4 percent), due to an increase in early retirements and reduced new capacity additions in those regions.
Overall impacts on wholesale electricity prices are similarly minimal. Wholesale electricity prices are
estimated to increase in some NERC regions, and fall in others. Price changes in individual regions range
from -$0.34 per MWh (-0.8 percent) in SERC to $0.03 per MWh (0.1 percent) in MRO. Finally, at the
national level, total costs decrease by approximately 0.3 percent.
At the national level, there are increases in emissions among all air pollutants modeled. NOx emissions
increase by 0.1 percent; SO2 emissions increase by 0.2 percent; CO2 emissions increase by 0.2 percent,
mercury emissions increase by 0.2 percent; and HCL emissions increase by 0.5 percent. The impact on
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emissions varies across regions and by pollutant. Emissions increase in some and decrease in other NERC
regions.45
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 final rule on the subset of plants to which the ELGs apply, i. e., steam
electric power plants. The purpose of the previously described electricity market-level analysis is to
assess the impact of the final rule on the entire electric power sector, i. e., including generators such as
combustion turbines, wind or solar to which the ELGs do not apply. By contrast, the purpose of this
analysis is to assess the impact of the final rule specifically on steam electric power plants. The analysis
results for the group of steam electric power plants overall show a slightly greater impact on a percentage
basis than that observed over all generating units in the IPM universe (i.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 final
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, 2015c]).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):
• 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.
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 Supplemental TDD
for details).
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 914 plants in the total steam electric power generating industry, calculated on a
sample-weighted basis. For details on sample weights, see Supplemental 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 perMWh: These changes are defined in the same way as in
the preceding section (Impact on National and Regional Electricity Markets).
Table 5-5 reports results of the Market Impact Analysis for steam electric power plants, as a group.
The impacts of the final rule on steam electric power plants differ from the total market impacts as these
plants become more competitive compared to plants that see no savings under the final rule. As a result,
capacity and generation impacts are greater for this set of plants than for the entire electricity market,
relative to the baseline, but absolute differences are still small. As described above for the market-level
analysis, those impacts vary across the NERC regions.
Table 5-5: Impact of the Final Rule on In-Scope Plants, as a Group, in the Year 2030a
Economic Measures
Option A
(all dollar values in 2018$)
Baseline Value
Value
Difference
% Change
National Totals
Total Domestic Capacity (MW)
314,952
315,752
800
0.3%
Early Retirements - Number of Plants
62
63
1
1.6%
Full & Partial Retirements-Capacity (MW)
68,959
68,159
-800
-1.2%
Generation (GWh)
1,475,819
1,479,979
4,160
0.3%
Costs ($Millions)
$57,620
$57,729
$109
0.2%
Fuel Cost
$32,448
$32,596
$148
0.5%
Variable O&M
$5,800
$5,804
$4
0.1%
Fixed O&M
$18,521
$18,478
-$43
-0.2%
Capital Cost
$851
$851
$0
0.0%
Average Variable Production Cost ($/MWh)
$25.92
$25.95
$0.03
0.1%
Florida Reliability Coordinating Council (FRCC)
Total Domestic Capacity (MW)
22,614
22,614
0
0.0%
Early Retirements - Number of Plants
2
2
0
0.0%
Full & Partial Retirements-Capacity (MW)
3,868
3,868
0
0.0%
Generation (GWh)
104,874
105,486
612
0.6%
Costs ($Millions)
$4,318
$4,343
$25
0.6%
Fuel Cost
$2,894
$2,920
$26
0.9%
Variable O&M
$256
$259
$3
1.3%
Fixed O&M
$1,169
$1,164
-$4
-0.4%
Capital Cost
$0
$0
$0
NA
Average Variable Production Cost ($/MWh)
$30.03
$30.13
$0.10
0.3%
Midwest Reliability Organization (MRO)
Total Domestic Capacity (MW)
21,992
21,981
-11
0.0%
Early Retirements - Number of Plants
8
8
0
0.0%
Full & Partial Retirements-Capacity (MW)
6,589
6,598
8
0.1%
Generation (GWh)
120,975
120,799
-176
-0.1%
Costs ($Millions)
$4,260
$4,251
-$9
-0.2%
Fuel Cost
$2,480
$2,475
-$5
-0.2%
Variable O&M
$639
$637
-$3
-0.4%
Fixed O&M
$1,046
$1,044
-$3
-0.3%
Capital Cost
$95
$96
$1
1.2%
Average Variable Production Cost ($/MWh)
$25.78
$25.75
-$0.02
-0.1%
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Table 5-5: Impact of the Final Rule on In-Scope Plants, as a Group, in the Year 2030a
Economic Measures
Option A
(all dollar values in 2018$)
Baseline Value
Value
Difference
% Change
Northeast Power Coordinating Council (NPCC)
Total Domestic Capacity (MW)
9,662
9,594
-67
-0.7%
Early Retirements - Number of Plants
4
5
1
25.0%
Full & Partial Retirements-Capacity (MW)
3,480
3,548
67
1.9%
Generation (GWh)
26,660
26,735
75
0.3%
Costs ($Millions)
$1,209
$1,216
$7
0.6%
Fuel Cost
$553
$557
$4
0.7%
Variable O&M
$42
$43
$1
2.4%
Fixed O&M
$615
$617
$2
0.3%
Capital Cost
$0
$0
$0
NA
Average Variable Production Cost ($/MWh)
$22.29
$22.42
$0.13
0.6%
ReliabilityFirst Corporation (RFC)
Total Domestic Capacity (MW)
72,733
72,116
-617
-0.8%
Early Retirements - Number of Plants
26
25
-1
-3.8%
Full & Partial Retirements-Capacity (MW)
25,149
25,767
617
2.5%
Generation (GWh)
358,944
357,771
-1,173
-0.3%
Costs ($Millions)
$13,723
$13,594
-$129
-0.9%
Fuel Cost
$7,843
$7,822
-$21
-0.3%
Variable O&M
$1,562
$1,528
-$34
-2.2%
Fixed O&M
$4,288
$4,214
-$74
-1.7%
Capital Cost
$29
$29
$0
0.6%
Average Variable Production Cost ($/MWh)
$26.20
$26.14
-$0.07
-0.3%
Southeast Electric Reliability Council (SERC)
Total Domestic Capacity (MW)
98,515
100,007
1,492
1.5%
Early Retirements - Number of Plants
11
12
1
9.1%
Full & Partial Retirements-Capacity (MW)
20,739
19,247
-1,492
-7.2%
Generation (GWh)
467,976
472,134
4,159
0.9%
Costs ($Millions)
$18,831
$19,040
$209
1.1%
Fuel Cost
$10,850
$10,979
$129
1.2%
Variable O&M
$1,624
$1,660
$36
2.2%
Fixed O&M
$6,250
$6,294
$44
0.7%
Capital Cost
$107
$107
$0
0.1%
Average Variable Production Cost ($/MWh)
$26.66
$26.77
$0.11
0.4%
Southwest Power Pool (SPP)
Total Domestic Capacity (MW)
26,684
26,687
2
0.0%
Early Retirements - Number of Plants
1
1
0
0.0%
Full & Partial Retirements-Capacity (MW)
1,879
1,879
0
0.0%
Generation (GWh)
105,630
106,211
581
0.6%
Costs ($Millions)
$4,121
$4,129
$8
0.2%
Fuel Cost
$2,328
$2,341
$13
0.6%
Variable O&M
$548
$549
$1
0.2%
Fixed O&M
$1,186
$1,181
-$5
-0.4%
Capital Cost
$60
$59
-$1
-2.4%
Average Variable Production Cost ($/MWh)
$27.22
$27.21
-$0.01
-0.1%
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Table 5-5: Impact of the Final Rule on In-Scope Plants, as a Group, in the Year 2030a
Economic Measures
(all dollar values in 2018$)
Baseline Value
Option A
Value
Difference
% Change
Texas Regional Entity (TRE)
Total Domestic Capacity (MW)
25,037
25,037
0
0.0%
Early Retirements - Number of Plants
0
0
0
NA
Full & Partial Retirements-Capacity (MW)
0
0
0
NA
Generation (GWh)
111,060
111,031
-29
0.0%
Costs ($Millions)
$4,554
$4,550
-$4
-0.1%
Fuel Cost
$2,425
$2,423
-$1
-0.1%
Variable O&M
$447
$446
-$1
-0.1%
Fixed O&M
$1,541
$1,539
-$2
-0.2%
Capital Cost
$142
$142
$0
0.0%
Average Variable Production Cost ($/MWh)
$25.85
$25.84
-$0.01
0.0%
Western Electricity Coordinating Council (WECC
Total Domestic Capacity (MW)
37,714
37,716
1
0.0%
Early Retirements - Number of Plants
10
10
0
0.0%
Full & Partial Retirements-Capacity (MW)
7,253
7,252
-1
0.0%
Generation (GWh)
179,701
179,811
110
0.1%
Costs ($Millions)
$6,603
$6,606
$3
0.0%
Fuel Cost
$3,076
$3,078
$3
0.1%
Variable O&M
$683
$683
$0
0.1%
Fixed O&M
$2,427
$2,427
$0
0.0%
Capital Cost
$418
$418
$0
0.0%
Average Variable Production Cost ($/MWh)
$20.91
$20.92
$0.00
0.0%
a. Numbers may not add up due to rounding.
Source: U.S. EPA Analysis, 2020.
5.2.2.2.1 Findings for the Final Rule (Regulatory Option A) in the 2030 Model Year
Under the final rule, the steam electric capacity is estimated to increase, as opposed to decreasing for the
electricity market as a whole, although the change in capacity for the group of steam electric power plants
is still small at less than one percent.
For the group of steam electric power plants, total capacity increases by 800 MW or approximately
0.3 percent of the 314,952 MW in baseline capacity. This increase is almost entirely attributable to
avoided retirements in the SERC region of 1,492 MW (1.5 percent). Two plants (one in SERC and one in
NPCC) are projected to close under the final rule (this impact is indirectly the result of the rule for one of
the affected plants, as this plant does not incur ELG compliance costs under the final rule). One plant in
RFC is estimated to avoid a full retirement, resulting in a net increase of one early full retirement at the
national level. In addition, three plants are projected to partially close under the final rule (two in RFC
and one in SERC), while two plants (one in SERC and one in NPCC) are projected to avoid a partial
retirement.47
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
A plant is defined as a partial retirement if it is not a full retirement but has at least one generating unit that is projected
to retire 100 percent of its capacity.
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electricity generation,48 for steam electric power plants, total generation is estimated to increase by
4,160 GWh (0.3 percent). SERC is projected to experience the largest increase in generation from steam
electric power plants, 4,159 GWh (0.9 percent), while FRCC, NPCC, SPP, and WECC are estimated to
experience increases of 0.1 to 0.6 percent. MRO and RFC are projected to experience decreases of 0.1
and 0.3 percent, respectively. TRE is projected to experience a less than 0.1 percent decrease in
generation.
Unlike the results for the whole electricity market, where total costs are estimated to decrease under the
final rule at the national level, the results for the group of steam electric power plants show a net increase
in total costs of $109 million (0.2 percent), which is consistent with the projected increase in electricity
generated by the group of plants. Total costs in the regions also follow the increases in electricity
generation with costs in SERC increasing the most, by $209 million (1.1 percent), WECC experiencing
the smallest increase of less than 0.1 percent, and MRO, RFC, and TRE experiencing decreases between
0.1 to 0.9 percent. At the national level, variable production costs for steam electric power plants increase
by $0.03 per MWh (0.1 percent). Effects vary by region, with changes ranging from -$0.07 per MWh in
RFC to $0.13 per MWh in NPCC.
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 final 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 final rule. In addition to the category of all plants,
the table also reports these metrics for plants that incur costs under Option A and plants that incur no
costs under Option A separately. Metrics of greatest interest for assessing the adverse impacts of the final
rule on steam electric power plants include the number of plants with reductions in capacity utilization or
generation (on the left side of the table), and the number of plants with increases in variable production
costs (on the right side of the table).
This table excludes steam electric power plants with estimated 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 either the baseline or the regulatory option. The measures presented in Table 5-5, such as
change in electricity generation, are not meaningful for these plants. For example, for a plant that is
projected to close in the baseline but avoids closure under the final rule, the percent change in electricity
generation relative to baseline cannot be calculated. On this basis, 302 plants are excluded from
assessment of effects on individual steam electric power plants under the final rule. In addition, the
change in variable production cost per MWh of generation could not be developed for 32 plants with zero
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.
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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generation in either the baseline or under the final rule (because the divisor, MWh, is zero). For change in
variable production cost per MWh, these plants are recorded in the "N/A" column.
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Table 5-6: Impact of Final Rule on Individual In-Scope Plants in the Year 2030
Reduction
Increase
Economic Measures
>3%
>1% and
<3%
<1%
No Change
<1%
>1% and
<3%
>3%
N/Abc
Total
Steam Electric Power Plants that Incur Costs under Option A
Change in Capacity Utilization3
1
2
9
27
11
2
3
20
75
Change in Generation
2
1
7
27
9
3
6
20
75
Change in Variable Production Costs/MWh
1
0
36
3
11
1
0
23
75
Steam Electric Power Plants that Incur No Costs under Option A
Change in Capacity Utilization3
4
5
44
224
41
8
3
282
611
Change in Generation
19
10
24
225
29
9
13
282
611
Change in Variable Production Costs/MWh
0
3
88
148
55
5
1
311
611
All Steam Electric Power Plants
Change in Capacity Utilization3
5
7
53
251
52
10
6
302
686
Change in Generation
21
11
31
252
38
12
19
302
686
Change in Variable Production Costs/MWh
1
3
124
151
66
6
1
334
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 A, "N/A" reports
240 full and 54 partial baseline closures; 2 additional full and 3 additional partial closures as a result of the regulatory option; and 1 avoided full and 2 avoided
partial closures as a result of the regulatory option.
c. The change in variable production cost per MWh could not be developed for 32 plants with zero generation in either the baseline case or Option A policy case.
Source: U.S. EPA Analysis, 2020
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5.2.2.3.1 Findings for the Final Rule (Regulatory Option A) in Model Year 2030
For the final rule, the analysis of changes in individual plants indicates that most plants experience only
slight effects - i.e., no change or less than a one percent reduction or one percent increase. Only 18 plants
(3 percent) are estimated to incur a reduction in capacity utilization of at least one percent and 32 plants
(5 percent) incur a reduction in generation of at least one percent. Finally, only 7 plants (1.0 percent) are
estimated incur an increase in variable production costs of at least one percent. For the set of 75 plants
that incur costs under Option A, more plants incur an increase in generation (18 plants) than a decrease in
generation (10 plants).
5.3 Estimated Effects of the Regulatory Options on New Capacity
IPM results show no new coal-fired capacity projected during the analysis period in the baseline. This
continues to be the case for the final rule.
5.4 Uncertainties and Limitations
Despite EPA's use of the best available information and data, EPA's analyses of the electric power
market and the overall economic impacts of the final rule involve several sources of uncertainty:
• 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, 2018). 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 avoided retirements resulting
from cost savings under the final rule.
• Demand for electricity. IPM assumes that electricity demand at the national level will not change
between the baseline and the final rule (generation within the regions is allowed to vary); this
constraint is exogenous to the model. IPM v6 embeds a baseline energy demand forecast that is
derived from the Department of Energy's Annual Energy Outlook 2018 (AEO2018). IPM does
not capture changes in demand that may result from electricity price changes associated with the
final rule {i.e., demand is inelastic with respect to price). While this constraint may underestimate
total demand in analyses of policy options that have lower compliance costs relative to the
baseline, EPA assumes that relaxing the constraint would not affect the results analyzed. As
described in Section 5.2.1 and Section 5.2.2, the price changes associated with the final rule in all
NERC regions are less than $0.34 per MWh. EPA therefore concludes that the assumption of
inelastic demand-responses over these changes in prices is reasonable.
• Fuel prices: Prices of fuels (e.g., natural gas and coal) are determined endogenously within IPM.
IPM modeling of fuel prices uses both short- and long-term price signals to balance supply of,
and demand in, competitive markets for the fuel across the modeled time horizon. The model
relies on AEO2018'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, would be estimated
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to affect the cost of electricity generation and therefore the amount of electricity generated by
steam electric power plants, irrespective of the final rule. More generally, differences in fuel
prices, and related changes in electricity production costs, can affect the modeled dispatch
profiles, planning for new/repowered capacity, and contribute to differences in a number of
policy-relevant parameters such as electricity production costs, prices, and emission changes.
• International imports: IPM assumes that imports from Canada and Mexico do not change
between the baseline and the final rule. Holding international imports fixed potentially
understates the impacts of changes in production costs and electricity prices in U.S. domestic
markets. EPA does not expect that this assumption materially affects results, however, since IPM
projects that only one of the eight NERC regions will import electricity (WECC) in 2030, and the
level of imports compared to domestic generation in this region is very small (about 0.8 percent).
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6: Employment Effects
6 Assessment of the Impact of the Regulatory Options on
Employment
6.1 Background and Context
In addition to addressing the costs and impacts of the regulatory options, EPA discusses the potential
impacts of this rulemaking on employment in this section. 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 explains the methods and estimates of employment impacts due to the final rule. It begins
with an explanation of employment impacts due to environmental regulation and discusses a selection of
the peer-reviewed literature on this topic. It then qualitatively describes potential employment impacts of
the final rule on coal-fired steam electric power plants and pollution control suppliers. In addition, EPA
discusses labor effects for coal mining and other energy sources.
6.1.1 Employment Impacts of Environmental Regulations
Economic theory of labor demand indicates that employers affected by environmental regulation may
increase their demand for some types of labor, decrease demand for other types, or for still other types,
not change it at all. To present a complete picture, an employment impact analysis will describe both
positive and negative changes in employment. A variety of conditions can affect employment impacts of
environmental regulation, including baseline labor market conditions and employer and worker
characteristics such as industry, and region.
A growing body of literature has investigated employment effects of environmental regulation.
Morgenstern el al. (2002) decompose the labor consequences in a regulated industry facing increased
abatement costs. They identify three separate components. First there is a demand effect caused by higher
production costs raising market prices. Higher prices reduce consumption (and production) reducing
demand for labor within the regulated industry. Second there is a cost effect: as production costs increase,
plants use more of all inputs including labor in order to be able to produce the same level of output. Third,
there is a factor-shift effect, a consequence of the potential effect of regulation on production technologies
leading to different labor intensity.
Additional papers approach employment effects through different frameworks. Deschenes (2018)
describes environmental regulations as requiring additional capital equipment for pollution abatement that
does not increase productivity. This can be included in a labor demand model as an increase in the rental
rate of productive capital. These higher production costs induce regulated firms to lower output and
decrease labor demand (an output effect) as well as shift away from the use of more expensive capital
towards increased labor demand (a substitution effect).51 Berman and Bui (2001) discuss how affected
firms' overall labor demand could increase, decrease, or remain unaffected, depending, in part, on the
labor-intensity of environmental protection activities needed for regulatory compliance compared to the
labor-intensity of producing output. To study labor demand impacts empirically, researchers have
For an overview of the neoclassical theory of production and factor demand, see Chapter 9 of Layard and Walters
(1978). For a discussion specific to labor demand, see chapter 4 of Boijas (1996). When using this theoretic framework,
authors have conceptualized regulation as an increase in the price of pollution (Greenstone, 2002, Holland, 2012), an
increase in the price of capital (Deschenes, 2018), an increase in energy prices (Deschenes, 2011), an increase in
pollution abatement costs (Morgenstern et al., 2002), or with pollution abatement requirements modeled as quasi-fixed
factors of production (Berman & Bui, 2001).
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compared employment levels at facilities subject to an environmental regulation to employment levels at
similar facilities not subject to that environmental regulation; some studies find no employment effects,
and others find significant differences. For example, see Berman and Bui (2001), Greenstone (2002),
Ferris et al. (2014), Walker (2013), and Curtis (2018).
Workers affected by changes in labor demand due to regulation may experience a variety of impacts
including job gains or involuntary job loss and unemployment. Localized reductions in employment may
adversely impact individuals and communities just as localized increases may have positive impacts.
Workforce adjustments can be costly to firms as well as workers, so employers may choose to adjust their
workforce over time through natural attrition or reduced hiring, rather than incur costs associated with job
separations.52
As described above, the small empirical literature on employment effects of environmental regulations
focuses primarily on labor demand impacts. However, there is nascent literature focusing on regulation-
induced effects on labor supply, though this literature remains very limited due to empirical challenges.
This new research uses innovative methods and new data, and indicates that there may be observable
impacts of environmental regulation on labor supply, even at pollution levels below mandated regulatory
thresholds. Many researchers have found that lost workdays and sick days as well as mortality are
reduced when pollution is reduced, although the studies focus specifically on air quality. Another
literature estimates how worker productivity declines at the work site when pollution increases. Graff
Zivin and Neidell (2013) review the work in this literature, focusing on how health and human capital
may be affected by environmental quality, particularly air pollution.
6.1.2 Discussion of Employment impacts of the Final Rule
An environmental regulation affecting the steam electric industry will likely have a variety of
employment impacts. Transitional impacts include reduced employment at retiring coal-fired plants, as
well as increased employment for the manufacture, installation, and operation of pollution control
equipment and construction of new generation sources to replace retiring units (Smith, 2015). Other
employment impacts include effects on labor supply and productivity resulting from changes in pollution,
as well as effects on labor demand in generation of energy from other sources, such as natural gas and
renewable energy.
I extent to which workers in declining industries will be significantly affected by the final rule depends on
such factors as the transferability of affected workers' skills with shifting labor demand in different
sectors due to the action, the availability of local employment opportunities for affected workers in
communities or industries with high unemployment, and the extent to which migration costs serve as
barriers to job search. This latter factor is a bigger concern in areas with historically low migration rates.
On the other hand, dislocated workers operating in tight labor markets may have experienced relatively
brief periods of transitional unemployment. Some job seekers may find new employment opportunities
due to the final rule; for example, if their skill set qualified them for new jobs procuring, installing,
operating, and maintaining wastewater treatment technologies.
52See, for example, Curtis (2018) and Hafstead and Williams III (2018).
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Speaking more generally, localized reductions in employment may adversely affect individuals and
communities, just as localized increases may have positive effects (U.S. EPA, 2015a; p. 6-5). If
potentially dislocated workers are vulnerable, for example as those in Appalachia likely are, besides
experiencing persistent job loss as already mentioned, earnings can be permanently lowered, and the
wider community may be negatively affected. Communitywide effects can include effects on the local tax
base, the provision and quality of local public goods, and changes in demand for local goods and services.
Neighborhood effects, when people influence neighbors' behaviors, may be possible. As an example,
consider the influence that social networks can have on job acquisition. Many job vacancies are filled by
people who know an employee at the firm with the vacancy. This type of networking is weakened by high
unemployment rates (Durlauf, 2004).
6.2 Analysis Overview
6.2.1 Estimated Employment Effects in Coal-Fired Electric Power Plants Affected by the Regulatory
Options
The final rule would have two broad categories of effect on the coal-fired power plants:
1. Coal-fired plants that are expected to incur costs as a result of the final rule are estimated to install
and operate compliance technology that is less costly than the technology that formed the basis for the
2015 rule. To the extent that some of these costs are driven by labor inputs, the savings may lead to
decreased employment in these plants compared to the baseline. This is reflective of the cost effect
discussed above and introduced by Morgenstern etal. (2002).
2. Coal-fired plants may generate more electricity than would otherwise occur in the absence of the final
rule due to decreased production costs. In addition, some plants may avoid retirement that would
otherwise occur. These effects may lead to increased employment at coal fired power plants
compared to the baseline. This is reflective of the demand effect discussed above and introduced by
Morgenstern etal. (2002).
EPA estimates that changes in employment may occur due to incorporation of different pollution controls.
As summarized in Chapter 3, EPA estimated that annualized capital costs would be lower under all four
regulatory options compared to the baseline. Approximately 45-59 percent of the annualized compliance
costs for the regulatory options are annualized capital costs. These capital cost savings are not estimated
to significantly affect employment at steam electric power plants themselves, but could decrease
employment in industries that manufacture and install pollution control equipment.
The remaining cost savings consist of wastewater treatment O&M costs, including labor costs for the
maintenance, repair, and operations of treatment equipment. Options A, B, and D yield O&M cost savings
While Option C actually increases annualized O&M costs. Some of these changes in O&M costs savings
could potentially affect employment in the steam electric power generating industry, but the changes are
small relative to overall electricity production costs.53
As summarized in Table 5-5, IPM projections for the model year 2030 show net reductions of 0.2 percent in fixed
O&M costs by steam electric power plants for Option A (the final rule) as compared to the baseline.
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IPM projects that total coal-fired generating capacity is estimated to increase between 2021 and 2050 by
approximately 0.5-1.6 percent under the final rule relative to the baseline.54 In addition, IPM projects that,
in 2030, the final rule would lead to avoided retirement of 1.2 GW (2.4 percent) of coal-fired capacity.
The direction of estimated changes in coal-fired generation capacity projected by IPM indicates potential
increase in total O&M labor at coal-fired electricity plants, compared to the baseline. However, given the
relatively small effect of the final rule on total capacity and avoided generating unit retirements described
above, EPA expects any increase in labor in the steam electric generating industry to be small.
6.2.2 Coal Mining and Other Energy Sources
This analysis uses the results from IPM to discuss potential labor effects in the coal mining, natural gas
extraction, and non-hydro renewable generation. The IPM analysis of the final rule provides estimates of
the changes in coal usage (in million short tons per year, or MT), natural gas usage (in trillion cubic feet),
and non-hydro renewable generation (in thousand GWh) in 2021-2050. IPM provides changes in coal
demand (in short tons) in three coal supply regions: Appalachia (Pennsylvania through Mississippi),
Interior (Indiana through Texas), and the West (North Dakota through Arizona).
IPM projects increases in coal use between less than 0.1 percent and 0.3 percent as a result of the final
rule from 2023-2045, before declining 0.4 percent in 2050. This could lead to a small overall increase in
coal mining employment. However, changes in coal use vary by region, with Appalachia estimated to
experience the largest changes in coal use over the period of analysis (-0.7 percent to 3.2 percent), while
the West and the Interior are estimated to experience changes in coal use ranging from -0.6 percent to 0.3
percent and -0.3 percent to 0.4 percent, respectively, during that period. Natural gas usage and non-hydro
renewable generation are estimated to slightly decrease overall as a result of the final rule, which may
lead to declines in employment in the extraction and generation of energy from these other sources.
6.3 Findings
In conclusion, analyzing how environmental regulations will impact employment is challenging. It
requires consideration of changes in labor demand in both the regulated and environmental protection
sectors, as well as in other related sectors which in the case of the current rulemaking would include fuel
suppliers. Effects of the final rule on O&M labor demand at coal-fired steam electric power plants seem
likely to be positive given the net increase in capacity and generation in the steam electric power sector.
However, effects due to lowered costs of environmental controls may lower demand for labor. In
industries supplying fuels to the electricity sector, given projections of small changes in production across
fuels, there may also be a mix of small positive and small negative changes in employment. Overall, any
employment impacts of the final rule, both positive and negative, are expected to be small.
See Chapter 5 for a description of the IPM analysis and results.
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7: Electricity Price Effects
7 Assessment of Potential Electricity Price Effects
7.1 Analysis Overview
EPA assessed the potential impacts of regulatory options A through C on electricity prices. Following the
methodology EPA used to analyze the 2015 rule and 2019 proposal (U.S. EPA, 2015c, 2019a), the
Agency conducted this analysis for the baseline and each of the regulatory options 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,55 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.
EPA-821-R-20-004
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7: Electricity Price Effects
7.2 Assessment of Impact of Compliance Costs on Electricity Prices
EPA assessed the potential increase in electricity prices to the four electricity consumer groups:
residential, commercial, industrial, and transportation.
7.2.1 Analysis Approach and Data Inputs
For this analysis, EPA assumed that compliance costs would be fully passed through as increased
electricity prices and allocated these costs among consumer groups (residential, commercial, industrial,
and transportation) in proportion to the historical quantity of electricity consumed by each group. EPA
performed this analysis at the level of the North American Electric Reliability Corporation (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 rule analysis (see Chapter 7 in the 2015 RIA
[U.S. EPA, 2015c]), involves the following steps:
• EPA summed weighted pre-tax plant-level annualized compliance costs by NERC region.56'57
• 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 2020 by NERC
region, from AEO2019.
• EPA compared the estimated average price effect to the projected electricity price by consumer
group and NERC region for 2020 from AEO2019.
7.2.2 Key Findings for Regulatory Options
As reported in Table 7-1, changes are very small for all reanalyzed regulatory options; the maximum
difference in price effect is a fraction of a cent per kWh. Under Options A and B, the regions with the
greatest cost savings per unit of electricity are SERC and RFC, whereas under Option C, SPP and MRO
are the regions with the greatest cost savings. Overall across the United States, Option A (the final rule)
results in the highest cost savings of 0.0050 per kWh, and Option C results in the lowest cost savings of
0.0010 per kWh.
These compliance costs are in 2018 dollars as of a given technology implementation year (2021 through 2028) and
discounted to 2020 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 (2021 through 2028) and then discounting these effects to a single analysis year (2020) accounts
for this consideration.
For this analysis, EPA brought compliance costs forward to a given compliance year using the CCI and ECI.
EPA-821-R-20-004
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7: Electricity Price Effects
Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2020
(2018$)
Costs per Unit
Incremental
Incremental Costs
Total Electricity
National Pre-Tax
of Sales
Annualized Pre-Tax
per Unit of Sales
Sales
Compliance Costs
(2018C/kWh
Compliance Costs
(2018C/kWh
NERC3
(at 2020; MWh)
(at 2020; 2018$)
Sales)
(at 2020; 2018$)
Sales)
Baseline
FRCC
226,245,590
$9,504,276
0.004C
N/A
N/A
MRO
222,014,957
$19,661,060
0.009 C
N/A
N/A
NPCC
264,949,388
$4,553,635
0.002 C
N/A
N/A
RFC
838,308,571
$146,122,338
0.017C
N/A
N/A
SERC
1,005,073,883
$163,337,158
0.016C
N/A
N/A
SPP
207,157,569
$14,638,444
0.007 C
N/A
N/A
TRE
362,982,758
$5,211,212
0.001C
N/A
N/A
WECC
690,781,289
$15,425,634
0.002 C
N/A
N/A
usa
3,831,848,389
$378,453,756
o.oioe
N/A
N/A
Option Db
US"
3,806,416,322
$276,778,404
0.007C
-$165,615,626
-0.004C
Option A
FRCC
226,245,590
$4,448,262
0.002 C
-$5,056,014
-0.002 C
MRO
222,014,957
$10,614,532
0.005 C
-$9,046,527
-0.004C
NPCC
264,949,388
$1,633,832
0.001C
-$2,919,803
-0.001C
RFC
838,308,571
$83,038,191
0.010C
-$63,084,146
-0.008C
SERC
1,005,073,883
$96,499,929
0.010C
-$66,837,229
-0.007 C
SPP
207,157,569
$2,116,666
0.001C
-$12,521,778
-0.006 C
TRE
362,982,758
$1,993,637
0.001C
-$3,217,576
-0.001C
WECC
690,781,289
$2,905,383
o.oooc
-$12,520,250
-0.002 C
usa
3,831,848,389
$203,250,432
0.005 C
-$175,203,324
-0.005 C
Option B
FRCC
226,245,590
$5,306,656
0.002 C
-$4,197,620
-0.002 C
MRO
222,014,957
$14,336,965
0.006 C
-$5,324,094
-0.002 C
NPCC
264,949,388
$4,055,126
0.002 C
-$498,509
O.OOOC
RFC
838,308,571
$91,677,805
0.011C
-$54,444,532
-0.006 C
SERC
1,005,073,883
$104,093,676
0.010C
-$59,243,482
-0.006 C
SPP
207,157,569
$6,512,037
0.003 C
-$8,126,406
-0.004C
TRE
362,982,758
$1,993,637
0.001C
-$3,217,576
-0.001C
WECC
690,781,289
$7,333,494
0.001C
-$8,092,139
-0.001C
usa
3,831,848,389
$235,309,397
0.0064
-$143,144,359
-0.004C
Option C
FRCC
226,245,590
$14,443,023
0.006 C
$4,938,747
0.002 C
MRO
222,014,957
$14,742,980
0.007 C
-$4,918,079
-0.002 C
NPCC
264,949,388
$4,055,126
0.002 C
-$498,509
O.OOOC
RFC
838,308,571
$128,694,043
0.015C
-$17,428,295
-0.002 C
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7: Electricity Price Effects
Table 7-1: Compliance Cost per KWh Sales by NERC Region and Regulatory Option in 2020
(2018$)
Costs per Unit
Incremental
Incremental Costs
Total Electricity
National Pre-Tax
of Sales
Annualized Pre-Tax
per Unit of Sales
Sales
Compliance Costs
(2018C/kWh
Compliance Costs
(2018C/kWh
NERC3
(at 2020; MWh)
(at 2020; 2018$)
Sales)
(at 2020; 2018$)
Sales)
SERC
1,005,073,883
$177,846,117
0.018C
$14,508,958
0.001C
SPP
207,157,569
$9,281,755
0.004C
-$5,356,689
-0.003 C
TRE
362,982,758
$2,549,164
0.001C
-$2,662,049
-0.001C
WECC
690,781,289
$7,333,494
0.001C
-$8,092,139
-0.001C
usa
3,831,848,389
$358,945,702
0.009 C
-$19,508,054
-0.001C
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.
b. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020
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 (AEO2019; EIA,
2019a) by consuming group and for the average of the groups. As reported in Table 7-2, across the United
States, the baseline is estimated to result in an average electricity price increase for all sectors of 0.01
cents per kWh (0.10 percent of the average price of 10.2 cents per kWh). Table 7-3 presents incremental
impacts on electricity prices under the regulatory options relative to the baseline. Across all reanalyzed
options, average electricity price increases are less than under the baseline, with cost savings ranging
from 0.001 cents per kWh (0.005 percent) under Option C, to 0.005 cents per kWh (0.04 percent) under
Option A.
Looking across the four consumer groups and assuming that any price change would apply equally to all
consumer groups, under all scenarios industrial consumers are estimated to experience the highest price
changes relative to the electricity price basis, while residential consumers are estimated to experience the
lowest price changes, shown in Table 7-2. As with the average national results for all sectors, industrial
and residential price increases under options A through C are less than under the baseline, yielding
estimated cost savings to these consumer groups when compared to the 2015 rule. As presented in Table
7-3, industrial consumers and residential consumers are estimated to experience cost savings of 0.07
percent and 0.04 percent, respectively under Option A. Under Option C, industrial and residential
consumers are estimated to experience cost savings of 0.01 percent and 0.004 percent, respectively. The
higher relative price effect 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.
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7: Electricity Price Effects
Table 7-2: Projected 2020 Price (Cents per kWh of Sales) and Potential Price Increase Due to
Compliance Costs by NERC Region and Regulatory Option (2018$)
Residential
Commercial
Industrial
Transportation
All Sectors
Average
EIA
EIA
EIA
EIA
Compliance
Price
Price
EIA Price
Price
Price
Costs
Basis
%
Basis
%
Basis
%
Basis
%
Basis
(20184
(20184
Change
(20184
Change
(20184
Change
(20184
Change
(20184
% Change
NERCb
/kWh)
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
Baseline
FRCC
0.004C
10.9 C
0.04%
8.8C
0.05%
7.2C
0.06%
11.8C
0.04%
9.8C
0.04%
MRO
0.009 C
11.3C
0.08%
8.8C
0.10%
6.2C
0.14%
12.4C
0.07%
8.6C
0.10%
NPCC
0.002 C
18.4C
0.01%
15.9C
0.01%
12.3C
0.01%
13.1C
0.01%
16.4C
0.01%
RFC
0.017C
13.7C
0.13%
10.3C
0.17%
7.5C
0.23%
9.9C
0.18%
10.7C
0.16%
SERC
0.016C
11.1C
0.15%
9.2C
0.18%
5.6C
0.29%
12.1C
0.13%
9.0C
0.18%
SPP
0.007 C
11.6C
0.06%
9.5C
0.07%
6.4C
0.11%
12.5C
0.06%
9.4C
0.08%
TRE
0.001C
9.5C
0.02%
8.8C
0.02%
5.6C
0.03%
8.1C
0.02%
8.2C
0.02%
WECC
0.002 C
13.2C
0.02%
11.6C
0.02%
7.5C
0.03%
14.8C
0.02%
11.2C
0.02%
US
0.0104
12.44
0.08%
10.54
0.09%
6.84
0.15%
12.24
0.08%
10.24
0.10%
Option Dc
US
0.007C
13.1C
0.06%
10.9C
0.07%
7.3C
0.10%
11.4C
0.06%
10.8C
0.07%
Option A
FRCC
0.002 C
10.9 C
0.02%
8.8C
0.02%
7.2C
0.03%
11.8C
0.02%
9.8C
0.02%
MRO
0.005 C
11.3C
0.04%
8.8C
0.05%
6.2C
0.08%
12.4C
0.04%
8.6C
0.06%
NPCC
0.001C
18.4C
0.00%
15.9C
0.00%
12.3C
0.01%
13.1C
0.00%
16.4C
0.00%
RFC
0.010C
13.7C
0.07%
10.3C
0.10%
7.5C
0.13%
9.9C
0.10%
10.7C
0.09%
SERC
0.010C
11.1C
0.09%
9.2C
0.10%
5.6C
0.17%
12.1C
0.08%
9.0C
0.11%
SPP
0.001C
11.6C
0.01%
9.5C
0.01%
6.4C
0.02%
12.5C
0.01%
9.4C
0.01%
TRE
0.001C
9.5C
0.01%
8.8C
0.01%
5.6C
0.01%
8.1C
0.01%
8.2C
0.01%
WECC
o.oooc
13.2C
0.00%
11.6C
0.00%
7.5C
0.01%
14.8C
0.00%
11.2C
0.00%
US
0.0054
12.44
0.04%
10.54
0.05%
6.84
0.08%
12.24
0.04%
10.24
0.05%
Option B
FRCC
0.002 C
10.9 C
0.02%
8.8C
0.03%
7.2C
0.03%
11.8C
0.02%
9.8C
0.02%
MRO
0.006 C
11.3C
0.06%
8.8C
0.07%
6.2C
0.10%
12.4C
0.05%
8.6C
0.07%
NPCC
0.002 C
18.4C
0.01%
15.9C
0.01%
12.3C
0.01%
13.1C
0.01%
16.4C
0.01%
RFC
0.011C
13.7C
0.08%
10.3C
0.11%
7.5C
0.15%
9.9C
0.11%
10.7C
0.10%
SERC
0.010C
11.1C
0.09%
9.2C
0.11%
5.6C
0.18%
12.1C
0.09%
9.0C
0.12%
SPP
0.003 C
11.6C
0.03%
9.5C
0.03%
6.4C
0.05%
12.5C
0.03%
9.4C
0.03%
TRE
0.001C
9.5C
0.01%
8.8C
0.01%
5.6C
0.01%
8.1C
0.01%
8.2C
0.01%
WECC
0.001C
13.2C
0.01%
11.6C
0.01%
7.5C
0.01%
14.8C
0.01%
11.2C
0.01%
US
0.0064
12.44
0.05%
10.54
0.06%
6.84
0.09%
12.24
0.05%
10.24
0.06%
EPA-821-R-20-004
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RIA for Revisions to Steam Electric Power Generating ELGs
7: Electricity Price Effects
Table 7-2: Projected 2020 Price (Cents per kWh of Sales) and Potential Price Increase Due to
Compliance Costs by NERC Region and Regulatory Option (2018$)
All Sectors
Residential
Commercial
Industrial
Transportation
Average
EIA
EIA
EIA
EIA
Compliance
Price
Price
EIA Price
Price
Price
Costs
Basis
%
Basis
%
Basis
%
Basis
%
Basis
(20184
(20184
Change
(20184
Change
(20184
Change
(20184
Change
(20184
% Change
NERCb
/kWh)
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
/kWh)
a
Option C
FRCC
0.006 C
10.9 C
0.06%
8.8C
0.07%
7.2C
0.09%
11.8C
0.05%
9.8C
0.07%
MRO
0.007 C
11.3C
0.06%
8.8C
0.08%
6.2C
0.11%
12.4C
0.05%
8.6C
0.08%
NPCC
0.002 C
18.4C
0.01%
15.9C
0.01%
12.3C
0.01%
13.1C
0.01%
16.4C
0.01%
RFC
0.015C
13.7C
0.11%
10.3C
0.15%
7.5C
0.20%
9.9C
0.15%
10.7C
0.14%
SERC
0.018C
11.1C
0.16%
9.2C
0.19%
5.6C
0.32%
12.1C
0.15%
9.0C
0.20%
SPP
0.004C
11.6C
0.04%
9.5C
0.05%
6.4C
0.07%
12.5C
0.04%
9.4C
0.05%
TRE
0.001C
9.5C
0.01%
8.8C
0.01%
5.6C
0.01%
8.1C
0.01%
8.2C
0.01%
WECC
0.001C
13.2C
0.01%
11.6C
0.01%
7.5C
0.01%
14.8C
0.01%
11.2C
0.01%
US
0.0094
12.44
0.08%
10.54
0.09%
6.84
0.14%
12.24
0.08%
10.24
0.09%
a. The rate impact analysis assumes full pass-through of all compliance costs to electricity consumers.
b. ELG compliance costs are zero in the AK and HICC regions and these regions are therefore omitted from the presentation.
c. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Sources: U.S. EPA Analysis, 2020; EIA, 2018b; EIA, 2019a
Table 7-3: Potential Incremental Price Changes Relative to Baseline Due to Compliance Costs by
NERC Region and Regulatory Option (2018$)
A Compliance
A
Costs (20184/
A Residential
A Commercial
A Industrial
Transportation
A All Sectors
NERCb
kWh)
Price3
Price3
Price3
Price3
Average Price3
Option iy
US
-0.004 (
-0.03%
-0.04%
-0.06%
-0.04%
-0.04%
Option A
FRCC
-0.002C
-0.02%
-0.03%
-0.03%
-0.02%
-0.02%
MRO
-0.004C
-0.04%
-0.05%
-0.07%
-0.03%
-0.05%
NPCC
-0.001C
-0.01%
-0.01%
-0.01%
-0.01%
-0.01%
RFC
-0.008C
-0.05%
-0.07%
-0.10%
-0.08%
-0.07%
SERC
-0.007C
-0.06%
-0.07%
-0.12%
-0.05%
-0.07%
SPP
-0.006C
-0.05%
-0.06%
-0.09%
-0.05%
-0.06%
TRE
-0.001C
-0.01%
-0.01%
-0.02%
-0.01%
-0.01%
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Table 7-3: Potential Incremental Price Changes Relative to Baseline Due to Compliance Costs by
NERC Region and Regulatory Option (2018$)
A Compliance
A
Costs (2018C/
A Residential
A Commercial
A Industrial
Transportation
A All Sectors
NERCb
kWh)
Price3
Price3
Price3
Price3
Average Price3
WECC
-0.002C
-0.01%
-0.02%
-0.02%
-0.01%
-0.02%
US
-0.005C
-0.04%
-0.04%
-0.07%
-0.04%
-0.04%
Option B
FRCC
-0.002C
-0.02%
-0.02%
-0.03%
-0.02%
-0.02%
MRO
-0.002C
-0.02%
-0.03%
-0.04%
-0.02%
-0.03%
NPCC
O.OOOC
0.00%
0.00%
0.00%
0.00%
0.00%
RFC
-0.006C
-0.05%
-0.06%
-0.09%
-0.07%
-0.06%
SERC
-0.006C
-0.05%
-0.06%
-0.11%
-0.05%
-0.07%
SPP
-0.004C
-0.03%
-0.04%
-0.06%
-0.03%
-0.04%
TRE
-0.001C
-0.01%
-0.01%
-0.02%
-0.01%
-0.01%
WECC
-0.001C
-0.01%
-0.01%
-0.02%
-0.01%
-0.01%
US
-0.004C
-0.03%
-0.04%
-0.06%
-0.03%
-0.04%
Option C
FRCC
0.002C
0.02%
0.02%
0.03%
0.02%
0.02%
MRO
-0.002C
-0.02%
-0.03%
-0.04%
-0.02%
-0.03%
NPCC
O.OOOC
0.00%
0.00%
0.00%
0.00%
0.00%
RFC
-0.002C
-0.02%
-0.02%
-0.03%
-0.02%
-0.02%
SERC
0.001C
0.01%
0.02%
0.03%
0.01%
0.02%
SPP
-0.003C
-0.02%
-0.03%
-0.04%
-0.02%
-0.03%
TRE
-0.001C
-0.01%
-0.01%
-0.01%
-0.01%
-0.01%
WECC
-0.001C
-0.01%
-0.01%
-0.02%
-0.01%
-0.01%
US
-0.00K
0.00%
0.00%
-0.01%
0.00%
0.00%
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.
c. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Sources: U.S. EPA Analysis, 2020; EIA, 2018b; EIA, 2019a
7.2.3 Uncertainties and Limita tions
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 baseline and 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.
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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 rule and 2019 proposal (U.S. EPA, 2015c, 2019a), 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.58
• 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 2020 from AEO2019.59
• To calculate average annual electricity sales per household, EPA divided the total quantity of
residential sales (in MWh) for 2018 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 2018 EIA-861 database (EIA, 2018b). For this analysis, EPA assumed that the average
quantity of electricity sales per household by NERC region would remain the same in 2020 as in
2018.
• 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 2018 by NERC region.
7.3.2 Key Findings for Regulatory Options A through C
Table 7-4 reports the results of this analysis by NERC region for each regulatory option, and overall for
the United States.60
The average incremental annual cost savings per residential household is greatest in SERC and the least in
NPCC under Options A and B. On the national level, cost savings are greatest on average under Option A
(the final rule), with average cost savings per residential household of $0.49 per year; by region, cost
savings range between $0.08-$0.94 per year. The least cost savings occur under Option C, with average
cost savings per residential household of $0.05 per year; by region, cost savings range between $0.01-
$0.34 per year, with two regions (FRCC and SERC) projected to see an increase in average cost per
household of $0.29 and $0.20, respectively.
Compliance costs in the ASCC and HICC regions are zero and EPA therefore did not include these regions in its
analysis.
AEO does not provide information for HICC and ASSC. None of the plants estimated to incur compliance costs as a
result of the proposed ELG, however, are located in these two NERC regions.
Average annual cost per residential household is zero in ASCC and HICC for the baseline and the three options and
these regions are therefore omitted from the details. They are included in the U.S. totals.
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Table 7-4: Average Incremental Annual Cost per Household in 2020 by NERC Region and
Regulatory Option (2018$)
Constant values
Incremental values3
Total
Incremental
Residential
Incremental
Incremental
Compliance
Sales per
P re-Tax
Compliance
Costs per
Total
Residential
Residential
Compliance
Costs per Unit
Residential
Electricity
Electricity
Number of
Household
Costs (at 2020;
of Sales
Household
NERCb
Sales (MWh)
Sales (MWh)
Households
(MWh)
2018$)
(2018$/MWh)
(2018$)
Option iy
US"
3,806,416,322
1,492,029,155
140,547,123
10.62
-$165,615,626
-$0.04
-$0.46
Option A
FRCC
226,245,590
118,262,427
8,896,093
13.29
-$5,056,014
-$0.02
-$0.30
MRO
222,014,957
60,224,622
5,854,099
10.29
-$9,046,527
-$0.04
-$0.42
NPCC
264,949,388
108,614,150
14,403,876
7.54
-$2,919,803
-$0.01
-$0.08
RFC
838,308,571
327,985,018
32,502,385
10.09
-$63,084,146
-$0.08
-$0.76
SERC
1,005,073,883
395,682,720
28,041,052
14.11
-$66,837,229
-$0.07
-$0.94
SPP
207,157,569
72,449,763
5,567,843
13.01
-$12,521,778
-$0.06
-$0.79
TRE
362,982,758
82,521,266
6,097,030
13.53
-$3,217,576
-$0.01
-$0.12
WECC
690,781,289
242,702,979
28,807,025
8.43
-$12,520,250
-$0.02
-$0.15
usb
3,831,848,389
1,412,947,745
130,883,366
10.80
-$175,203,324
-$0.05
-$0.49
Option B
FRCC
226,245,590
118,262,427
8,896,093
13.29
-$4,197,620
-$0.02
-$0.25
MRO
222,014,957
60,224,622
5,854,099
10.29
-$5,324,094
-$0.02
-$0.25
NPCC
264,949,388
108,614,150
14,403,876
7.54
-$498,509
$0.00
-$0.01
RFC
838,308,571
327,985,018
32,502,385
10.09
-$54,444,532
-$0.06
-$0.65
SERC
1,005,073,883
395,682,720
28,041,052
14.11
-$59,243,482
-$0.06
-$0.83
SPP
207,157,569
72,449,763
5,567,843
13.01
-$8,126,406
-$0.04
-$0.51
TRE
362,982,758
82,521,266
6,097,030
13.53
-$3,217,576
-$0.01
-$0.12
WECC
690,781,289
242,702,979
28,807,025
8.43
-$8,092,139
-$0.01
-$0.10
usb
3,831,848,389
1,412,947,745
130,883,366
10.80
-$143,144,359
-$0.04
-$0.40
Option C
FRCC
226,245,590
118,262,427
8,896,093
13.29
$4,938,747
$0.02
$0.29
MRO
222,014,957
60,224,622
5,854,099
10.29
-$4,918,079
-$0.02
-$0.23
NPCC
264,949,388
108,614,150
14,403,876
7.54
-$498,509
$0.00
-$0.01
RFC
838,308,571
327,985,018
32,502,385
10.09
-$17,428,295
-$0.02
-$0.21
SERC
1,005,073,883
395,682,720
28,041,052
14.11
$14,508,958
$0.01
$0.20
SPP
207,157,569
72,449,763
5,567,843
13.01
-$5,356,689
-$0.03
-$0.34
TRE
362,982,758
82,521,266
6,097,030
13.53
-$2,662,049
-$0.01
-$0.10
WECC
690,781,289
242,702,979
28,807,025
8.43
-$8,092,139
-$0.01
-$0.10
usb
3,831,848,389
1,412,947,745
130,883,366
10.80
-$19,508,054
-$0.01
-$0.05
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Table 7-4: Average Incremental Annual Cost per Household in 2020 by NERC Region and
Regulatory Option (2018$)
Constant values
Incremental values3
NERCb
Total
Electricity
Sales (MWh)
Residential
Electricity
Sales (MWh)
Number of
Households
Residential
Sales per
Residential
Household
(MWh)
Total
Incremental
P re-Tax
Compliance
Costs (at 2020;
2018$)
Incremental
Compliance
Costs per Unit
of Sales
(2018$/MWh)
Incremental
Compliance
Costs per
Residential
Household
(2018$)
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.
For this reason, electricity sales shown for the United States is greater than the total for NERC regions included in the table.
c. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Sources: U.S. EPA Analysis, 2020; EIA, 2018b; EIA, 2019a
7.3.3 Uncertainties and Limita Hons
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
final rule to assess (1) whether an increase in electricity rates that may occur under the final rule would
disproportionately affect lower-income households and (2) whether households would be able to pay for
these electricity rate increases without experiencing economic hardship {i.e., whether the increase is
affordable). The analysis provided additional insight on the distribution of impacts among residential
electricity consumers to help respond to concerns regarding the impacts of the rule on utilities and
cooperatives in service areas that include a relatively high proportion of low-income households.
In the 2015 analysis, EPA had concluded that even when looking at a worst-case scenario of 100 percent
pass through of the compliance costs, the "incremental economic burden of any final rule based on the
regulatory options in the proposal on households is small both relative to income and relative to the
baseline energy burden of households in different income ranges. While the incremental burden relative
to income is not distributionally neutral, i.e., any increase would affect lower-income households to a
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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, 2015c)." As presented in the preceding sections, EPA
estimates that regulatory options A through C would reduce compliance costs for FGD wastewater and
bottom ash transport water when compared to the baseline. To the extent that these savings are in turn
passed through to electricity consumers in the form of lower prices, the resulting lower electricity prices
may have a larger positive 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 baseline.
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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,61 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 rule and 2019 proposal (U.S. EPA, 2015c, 2019a), 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 Small Business
Administration (SBA) size criteria.
• Assessing the change in potential impact of the regulatory options on those small entities by
comparing the estimated entity-level annualized compliance cost to entity-level revenue; the cost-
to-revenue ratio indicates the magnitude of economic impacts. Following EPA guidance (U.S.
EPA, 2006), EPA used threshold compliance costs of one percent or three percent of entity-level
revenue to categorize the degree of significance of the economic impacts on small entities.
• Assessing the change in whether those small entities incurring potentially significant impacts
represent a substantial number of small entities. Following EPA guidance (U.S. EPA, 2006), EPA
determined whether the number of small entities impacted is substantial based on (1) the
estimated absolute numbers of small entities incurring potentially significant impacts according
to the two cost impact criteria, and (2) the percentage of small entities in the relevant entity
categories that are estimated to incur these impacts.
EPA performed this assessment for the baseline and each of the regulatory options, with the differences
between the findings indicative of the impacts of the options on small entities. This chapter describes the
analytic approach (Section 8.1), summarizes the findings of EPA's RFA assessment (Section 8.2), and
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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reviews uncertainties and limitations in the analysis (Section 8.3). The chapter also discusses how
regulatory options developed by EPA served to mitigate the impact of the regulatory options on small
entities (Section 8.4).
8.1 Analysis Approach and Data Inputs
EPA used the same methodology and assumptions used for the analysis of the 2015 rule and 2019
proposal (U.S. EPA, 2015c, 2019a), but updated input data to reflect more recent information about plant
ownership, entity size, and compliance costs as described in the sections below.
One difference from the approach used for the 2015 rule analysis is the explicit analysis of the impacts of
the baseline on small entities, which serves as contrast for analyzed impacts of the regulatory options.
This two-part analysis enables the Agency to understand how the regulatory options mitigate any impacts
to small entities projected under the baseline.
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)62 in
at least one of the estimated 914 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 2018 databases published by EIA (EIA, 2019b), 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). 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.
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.
Certain steam electric power plants are owned by entities whose primary business is not electric power generation.
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• Rural Electric Cooperatives: Small entities are those with less than the threshold number of
employees specified by SB A for each of the relevant NAICS sectors, depending on the type of
electricity generation (see Table 8-1).
Table 8-1: NAICS Codes and SBA Size Standards for Non-government Majority Owners Entities of
Steam Electric Power Plants
NAICS Code3
NAICS Description
SBA Size Standard13
212111
Bituminous Coal and Lignite Surface Mining
1250 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
$30.0 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
$16.5 million in revenue
551112
Offices of Other Holding Companies
$22.0 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 August 19, 2019).
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 corporate/financial websites, if
those values were available, or from the Steam Electric Survey if more recent data were not
available.
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• Revenue: EPA used entity-level revenue values described in Section 4.3.1. For entities with
values reported for more than one year, EPA used the average of reported values.
• Population: Population data for municipalities and other non-state political subdivisions were
obtained from the U.S. Census Bureau (estimated population for 2017) (U.S. DOC, 2017).
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 rule, 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,
2015c).
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 the
baseline and the three reanalyzed 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 231 and 459 entities own 914 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 76 (33 percent) and 127 (28 percent) parent entities are small (Table 8-2), and these small
entities own 138 steam electric power plants (Table 8-3), or approximately 15 percent of all steam electric
power plants. Across ownership types, cooperatives have the largest share of small entities (74 and
72 percent, for Case 1 and Case 2 respectively); cooperatives also have the largest share of steam electric
power plants owned by small entities (65 percent).
As described in Chapter 8 in the 2015 RIA (U.S. EPA, 2015c), 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)
Small Entity Size
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
Ownership Type
Standard
Total
Small
% Small
Total
Small
% Small
Cooperative
number of employees
27
20
74.07%
49
35
71.59%
Federal
assumed large
1
0
0.00%
3
0
0.00%
Investor-owned
number of employeesd
66
11
16.67%
149
25
16.53%
Municipality
50,000 population served
57
27
47.37%
92
35
37.80%
Nonutility
number of employeesd
68
17
25.00%
142
31
21.84%
Other Political
Subdivision0
50,000 population served
10
1
10.00%
21
1
4.69%
State
assumed large
2
0
0.00%
2
0
0.00%
Total
231
76
32.90%
459
127
27.61%
a. Eleven plants are owned by a joint venture of two entities.
b. Of these, 39 entities, 6 of which are small, own steam electric power plants that are estimated to incur compliance
technology costs under Option A under both Case 1 and Case 2.
c. EPA was unable to determine the size of one parent entity owned by a political subdivision; for this analysis, this entity is
assumed to be large.
d. Entity size may be based on revenue, depending on the NAICS sector (see Table 8-1).
Source: U.S. EPA Analysis, 2020.
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
62
40
64.7%
Federal
assumed large
20
0
0.0%
Investor-owned
number of employees6
489
27
5.4%
Municipality
50,000 population served
120
35
29.2%
Nonutility
number of employees6
185
35
18.9%
Other Political Subdivisions
50,000 population served
34
1
3.0%
State
assumed large
4
0
0.0%
Total
914
138
15.1%
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.
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, 107 steam electric power plants are estimated to incur compliance costs under the baseline, whereas 74 plants
incur compliance costs under Option A; 6 of the 74 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, 2020.
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8.1.3 Significant impact Test for Small Entities
As outlined in the introduction to this chapter, two criteria are assessed in determining whether the
regulatory options would qualify for a no-SISNOSE finding:
• Is the absolute number of small entities estimated to incur a potentially significant impact, as
described above, substantial?
and
• Do these significant impact entities represent a substantial fraction of small entities in the electric
power industry that could potentially be within the scope of a regulation?
A measure of the potential impact of the regulatory options on small entities is the fraction of small
entities that have the potential to incur a significant impact. For example, if a high percentage of
potentially small entities incur significant impacts even though the absolute number of significant impact
entities is low, then the rule could represent a substantial burden on small entities.
To assess the extent of economic/financial impact on small entities, EPA compared estimated compliance
costs to estimated entity revenue (also referred to as the "sales test"). The analysis is based on the ratio of
estimated annualized after-tax compliance costs to annual revenue of the entity. For this analysis, EPA
categorized entities according to the magnitude of economic impacts that entities would incur as a result
of the regulatory options. EPA identified entities for which annualized compliance costs are at least
one percent and three percent of revenue. EPA then evaluated the absolute number and the percent of
entities in each impact category, and by type of ownership. The Agency assumed that entities incurring
costs below one percent of revenue are unlikely to face significant economic impacts, while entities with
costs of at least one percent of revenue have a higher chance of facing significant economic impacts, and
entities incurring costs of at least three percent of revenue have a still higher probability of significant
economic impacts. Consistent with the parent-level cost-to-revenue analysis discussed in Chapter 4, EPA
assumed that steam electric power plants, and consequently, their parents, would not be able to pass any
of the increase in their production costs to consumers (zero cost pass-through). This assumption is used
for analytic convenience and provides a worst-case scenario of regulatory impacts to steam electric power
plants.
A detailed summary of how EPA developed these entity-level compliance cost and revenue values is
presented in Chapter 3 and Chapter 4.
8.2 Key Findings for Regulatory options
As described above, EPA developed estimates of the number of small parent entities in the specified cost-
to-revenue impact ranges. Table 8-4 and Table 8-5 summarize the results of the analysis, with Table 8-4
showing baseline results and Table 8-5 showing incremental results of the regulatory options relative to
this baseline. In terms of number of entities in each of the impact categories, analysis results for each
option are the same under Case 1 and Case 2; however, these numbers represent different percentages of
all small entities owning steam electric power plants under each weighting case.
In the baseline, EPA estimates that 3 small entities owning steam electric power plants, two small
municipalities and one small cooperative, would incur costs exceeding one percent of revenue (Table
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8-4). On the basis of percentage, the two small municipalities represent approximately 6 to 7 percent of
the number of small municipalities owning steam electric power plants. The small cooperative represents
approximately 3 to 5 percent of the number of small cooperatives owning steam electric power plants.
The three small entities represent 2 to 4 percent of the total number of small entities owning steam electric
power plants. The analysis shows no small business entity incurring costs greater than three percent of
revenue in the baseline.
As shown in Table 8-5, under the final rule, relative to the baseline 1 fewer small entity would incur costs
exceeding one percent of revenue. There are still no entities incurring costs exceeding three percent of
revenue. These results are the same under options B and C.
On the basis of percentage of small entities by entity type across the range of owning entities, the analysis
of regulatory options A through C shows 3 to 4 percent fewer small government entities incurring costs
greater than one percent of revenue (Table 8-5).
This screening-level analysis suggests that the baseline is unlikely to have a significant economic impact
on a substantial impact on small entities. And because the regulatory options reduce this impact further by
providing cost savings to many small entities, the same conclusion can be reached for the final rule.
Table 8-4: Estimated Baseline Cost-To-Revenue Impact on Small Parent Entities, by Entity Type
and Ownership Category
Case 1: Lower bound estimate of number of
Case 2: Upper bound estimate of number of
entities owning steam electric power plants
entities owning steam electric power plants
(out of total of 76 small entities)
(out of total of 127 small entities)
>1%
>3%a
>1%
>3%a
Entity
Number
% of all
Number
% of all
Number
% of all
Number
% of all
Type/Ownership
of small
small
of small
small
of small
small
of small
small
Category
entities
entities'5
entities
entities'5
entities
entities'5
entities
entities'5
Baseline
Small Business
Cooperative
1
5.0%
0
0.0%
1
2.8%
0
0.0%
Investor-Owned
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Nonutility
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Small Government
Municipality
2
7.4%
0
0.0%
2
5.7%
0
0.0%
Political
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Subdivision
Total
3
3.9%
0
0.0%
3
2.4%
0
0.0%
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 76 (Case 1) and 127 (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, 2020
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Table 8-5: Estimated Incremental Cost-To-Revenue Impact on Small Parent Entities, by Entity
Type and Ownership Category
Case 1: Lower bound estimate of number
Case 2: Upper bound estimate of number
of entities owning steam electric power
of entities owning steam electric power
plants
plants
(out of total of 76 small entities)
(out of total of 127 small entities)
>1%
>3%a
>1%
>3%a
Entity
ANumber
A% of all
ANumber
A% of all
ANumber
A% of all
ANumber
A% of all
Type/Ownership
of small
small
of small
small
of small
small
of small
small
Category
entities
entities'5
entities
entities'5
entities
entities'5
entities
entities'5
Option Dc
Small Business
Cooperative
Investor-Owned
Nonutility
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Small Government
Municipality
Political Subdivision
Option A
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
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Small Government
Municipality
-1
-3.7%
0
0.0%
-1
-2.9%
0
0.0%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
-1
-1.3%
0
0.0%
-1
-0.8%
0
0.0%
Option B
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
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Small Government
Municipality
-1
-3.7%
0
0.0%
-1
-2.9%
0
0.0%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
-1
-1.3%
0
0.0%
-1
-0.8%
0
0.0%
Option C
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
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Small Government
Municipality
-1
-3.7%
0
0.0%
-1
-2.9%
0
0.0%
Political Subdivision
0
0.0%
0
0.0%
0
0.0%
0
0.0%
Total
-1
-1.3%
0
0.0%
-1
-0.8%
0
0.0%
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Table 8-5: Estimated Incremental Cost-To-Revenue Impact on Small Parent Entities, by Entity
Type and Ownership Category
Case 1: Lower bound estimate of number
Case 2: Upper bound estimate of number
of entities owning steam electric power
of entities owning steam electric power
plants
plants
(out of total of 76 small entities)
(out of total of 127 small entities)
>1%
>3%a
>1%
>3%a
Entity
ANumber
A% of all
ANumber
A% of all
ANumber
A% of all
ANumber
A% of all
Type/Ownership
of small
small
of small
small
of small
small
of small
small
Category
entities
entities'5
entities
entities'5
entities
entities'5
entities
entities'5
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 76 (Case 1) and 127 (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.
c. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020
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 generally assumed the entity to be small, with one exception. As noted in Table 8-2, EPA
assumed one entity owned by a political subdivision to be large based on publicly available
information about the entity's identified assets. However, this large entity does not incur
compliance costs under the baseline or any of the three regulatory options and therefore the
assumption only affects the total number of entities in each size category (i.e., denominator used
to estimate the percent of entities).
• As discussed in Chapter 4, the zero cost pass-through assumption represents a worst-case scenario
from the perspective of the plants and parent entities. To the extent that some entities are able to
pass at least some compliance costs to consumers through higher electricity prices, this analysis
may overstate potential impact of regulatory options A through C on small entities and affect the
assessment of incremental effects of the regulatory options, although it would not affect the
direction of those effects.
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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.
Although EPA presents three regulatory options which would all reduce impacts to small entities, the
final rule is the least costly option presented, and thus would result in the lowest impacts to small entities.
Furthermore, as EPA explicitly states in the final rule, the implementation period built into the final 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.. $160 million in 2018 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 incremental costs for compliance with the regulatory options for different categories of
entities. All four regulatory options analyzed by EPA result in lower compliance costs (cost savings)
when compared to the baseline. The Agency estimates that the maximum incremental cost in any one year
to government entities (excluding federal government) range from -$74 million under Option A
to -$30 million under Option C.65,66 The maximum incremental cost in any given year to the private sector
range from -$738 million under Option C to -$914 million under Option A. From these incremental cost
values, EPA determined that the final rule does not contain a federal mandate that may result in
expenditures of $160 million (in 2018 dollars) or more for State, local, and Tribal governments, in the
aggregate, or the private sector in any one year, and in any case the final (Option A) is the least costly
option presented.
This chapter contains additional information to support that statement, including information on
compliance and administrative costs, and on impacts to small governments. Following the approach used
for the analysis of the 2015 rule and 2019 proposal (U.S. EPA, 2015c, 2019a; 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, 2020a). Specifically, this analysis uses costs in 2020
stated in 2018 dollars and accounts for costs in the year they are anticipated to be incurred between 2021
and 2047. Non-recurring costs are annualized over a 27-year period. As discussed in Chapter 10 (Other
Administrative Requirements; see Section 10.8) in this document, the reporting and recordkeeping
requirements in the final rule would not increase the reporting and recordkeeping burden for the review,
65 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 all regulatory options, these maximum costs are smaller than the maximum costs
projected under the baseline, resulting in net cost savings.
66 For this analysis, rural electric cooperatives are considered to be a part of the private sector.
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oversight, and administration of the rule relative to baseline requirements. NPDES permitting 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 20 of the 914 steam electric power
plants; four 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 10.8, EPA
estimated no significant net change (increase or decrease) in the burden associated with this rule. In the
case of plant owners, EPA estimated that changes that may increase the reporting burden will be offset by
burden savings of not having to undergo a full permit modification process.67 And while permitting
authorities will need to use BPJ to determine the site-specific volumes and technology-based BAT
effluent limitations for bottom ash purge water, EPA has taken steps to reduce the burden on NPDES
permitting authorities of making these determinations (see preamble section XIV(A)(2)).
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
57
120
Other Political Subdivision
10
34
State
2
4
Tribal
0
0
Total
69
157
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 914 plants covered under the point source category.
Source: U.S. EPA Analysis, 2020
For government entities that own steam electric power plants, the eight reporting and recordkeeping requirements of
the rule are in the context of larger burden reductions. For example, while there is a burden of reporting when
transferring between alternatives under 40 CFR 423.13(o), that burden is more than offset by the burden savings of not
having to undergo a full permit modification process.
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Out of 914 steam electric power plants, 157 are owned by 69 government entities.68 The majority
(76 percent) of these government-owned plants are owned by municipalities, followed by other political
subdivisions (21 percent), and State governments (3 percent).
All three reanalyzed regulatory options result in government entities incurring lower compliance costs
compared to the baseline. Table 9-2 shows compliance costs for government entities owning steam
electric power plants. Compliance costs to government entities under the baseline are approximately $28
million in the aggregate, with an average of $0.2 million per plant. As shown in Table 9-3, which shows
the difference between the options and the baseline, all three reanalyzed regulatory options by comparison
provide cost savings to government owned plants. The estimated pre-tax savings range from $6 million
(Option C) to $11 million (Option A), with most of the aggregate savings going to municipalities. The
maximum annualized compliance costs estimated to be incurred by any single government-owned plant is
also generally lower under the regulatory options, with the sole exceptions being municipality under
Option C which have greater maximum costs, at $6 million, than the maximum costs projected under the
baseline ($5 million).
Table 9-2: Estimated Compliance Costs to Government Entities Owning Steam Electric Power
Plants (Millions of 2018$)
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
Baseline
Municipality
120
$21
$479
$0.2
$4.6
Other Political Subdivision
34
$2
$84
$0.1
$2.2
State
4
$5
$909
$1.2
$3.4
Total
157
$28
$374
$0.2
$4.6
Option De
Municipality
Other Political Subdivision
160
$23
$285
$0.1
$3.1
Option A
Municipality
120
$14
$318
$0.1
$3.5
Other Political Subdivision
34
$2
$72
$0.1
$1.9
State
4
$1
$170
$0.2
$0.9
Total
157
$17
$223
$0.1
$3.5
Option B
Municipality
120
$14
$330
T—1
o
$3.5
Other Political Subdivision
34
$2
$72
$0.1
$1.9
State
4
$1
$184
$0.2
$0.9
Total
157
$17
$231
$0.1
$3.5
Counts exclude federal government entities and steam electric power plants they own. The owning entity is determined
based on the entity with the largest ownership share in each plant, as described in Chapter 4.
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Table 9-2: Estimated Compliance Costs to Government Entities Owning Steam Electric Power
Plants (Millions of 2018$)
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 C
Municipality
120
00
T—1
$411
$0.2
$5.9
Other Political Subdivision
34
$2
$72
t—1
o
$1.9
State
4
$2
$385
LO
o
00
t-H
-c/>
Total
157
$22
$292
$0.1
$5.9
a. Plant counts are relative to the estimated 914 plants covered under the point source category.
b. Average cost per MW values were calculated using total compliance costs and capacity for all steam electric power plants
owned by entities in a given ownership category. In case of multiple ownership structure where parent entities of a given
plant have equal ownership shares and are in different ownership categories, compliance costs and capacity were allocated to
appropriate ownership categories in accordance with ownership shares.
c. Average cost per plant values were calculated using the total number of steam electric power plants owned by entities in a
given ownership category.
d. Reflects maximum of un-weighted costs to surveyed plants only.
e. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2019, 2020.
Table 9-3: Estimated Incremental Compliance Costs to Government Entities Owning Steam
Electric Power Plants (Millions of 2018$)
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 De
Municipality
Other Political Subdivision
160
-$15
-$192
-$0.1
-$1.6
Option A
Municipality
120
-$7
-$161
-$0.1
-$1.2
Other Political Subdivision
34
-$o
-$13
$0.0
-$0.3
State
4
-$4
-$739
-$1.0
-$2.5
Total
157
-$11
-$151
-$0.1
-$1.2
Option B
Municipality
120
-$7
-$149
-$0.1
-$1.2
Other Political Subdivision
34
-$o
-$13
$0.0
-$0.3
State
4
-$4
-$725
-$1.0
-$2.5
Total
157
-$11
-$143
-$0.1
-$1.2
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Table 9-3: Estimated Incremental Compliance Costs to Government Entities Owning Steam
Electric Power Plants (Millions of 2018$)
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 C
Municipality
120
-$3
00
to
1
o
o
-oo-
$1.3
Other Political Subdivision
34
o
1
-$13
o
o
-$0.3
State
4
-$38
-$524
-$0.7
-$1.6
Total
157
-$6
-$82
$0.0
$1.3
a. Plant counts are relative to the estimated 914 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.
e. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2019, 2020.
9.2 UMRA Analysis of Impact on Small Governments
As part of the UMRA analysis, EPA also assessed whether the regulatory options would significantly and
uniquely affect small governments. To assess whether the regulatory options would affect small
governments in a way that is disproportionately burdensome in comparison to the effect on large
governments, EPA compared total incremental costs and costs per plant estimated to be incurred by small
governments with those values estimated to be incurred by large governments. EPA also compared the
changes in per plant costs incurred for small government-owned plants with those incurred by non-
government-owned plants. The Agency evaluated costs per plant on the basis of both average and
maximum annualized incremental cost per plant.
Out of 157 government-owned steam electric power plants, EPA identified 36 plants that are owned by
28 small government entities. These 36 plants constitute approximately 23 percent of all government-
owned plants.69
Counts exclude federal government entities and steam electric power plants they own.
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Table 9-4: Counts of Government-Owned Plants and Their Parent Entities, by Size
Entities3
Steam Electric Power Plantsb
Entity Type
Large
Small
Total
Large
Small
Total
Municipality
31
27
58
85
35
120
Other Political Subdivision
9
1
10
33
1
34
State
1
0
1
4
0
4
Total
41
28
69
121
36
157
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 914 plants covered under the point source category.
Source: U.S. EPA Analysis, 2020.
All regulatory options result in small government entities incurring lower compliance costs compared to
the baseline. As presented in Table 9-5, under regulatory options A through C, overall compliance cost
savings are greatest under Option A and smallest under Option C, and the distribution of cost savings
among different entity categories and sizes is uniform. For all options, aggregate compliance cost savings
are the largest for large private entities, followed by large governments, small private entities, and small
governments. On a per MW basis, small governments are projected to see larger cost savings - as much
as $328 per MW under Option A - than large governments or private entities. Because plants owned by
small governments tend to be smaller compared to those owned by large governments or small private
entities, the same is not necessarily true on a per plant basis under the regulatory options. Given these
results, EPA finds that small governments would not be significantly or uniquely affected by the
regulatory options, including the final rule.
Table 9-5: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type
and Size (2018$)
Average
Average
Maximum
Total Annualized
Annualized Pre-
Annualized Pre-
Annualized Pre-
Entity
Number of
Pre-Tax Costs
tax Cost per MW
tax Cost per
tax Cost per
Ownership Type
Size
Plants3
(Millions)3
of Capacity13
Plant (Millions)c
Plant (Millions)
d
Government
(excl. federal)
Large
Private
Large
All Plants
951
-$154
-$218
-$0.15
-$15.7
Option A
Government
(excl. federal)
Small
36
-$2
-$382
-$0.05
-$1.0
Large
121
O
t—1
1
-$137
-$0.08
-$1.8
Private
Small
111
-$4
-$118
-$0.04
-$0.7
Large
625
-$118
-$222
-$0.19
-$1.2
All Plants
914
-$154
-$228
-$0.17
-$16.0
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Table 9-5: Estimated Incremental Compliance Costs for Electric Generators by Ownership Type
and Size (2018$)
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 B
Government
(excl. federal)
Small
36
-$2
-$382
-$0.05
-$1.0
Large
121
-$9
-$129
-$0.08
-$1.8
Private
Small
111
-$4
-$118
-$0.04
-$0.7
Large
625
-$99
-$186
-$0.16
-$1.2
All Plants
914
-$127
-$188
-$0.14
-$8.7
Option C
Government
(excl. federal)
Small
36
-$1
-$321
-$0.04
-$0.8
Large
121
-$5
-$67
-$0.04
$1.3
Private
Small
111
-$3
-$103
-$0.03
-$0.7
Large
625
to
T—1
1
-$31
-$0.03
$2.3
All Plants
914
-$19
-$28
-$0.02
$5.4
a. Plant counts are relative to the estimated 914 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.
d. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect changes
in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020.
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 9-6 summarizes the total annualized costs, maximum one-year costs, and the year when maximum
costs are incurred by type of owner. As shown in the last two columns of the table, all regulatory options
result in cost savings, both on an annualized basis and for the maximum one-year costs, when compared
to the baseline. EPA estimates the incremental annualized pre-tax compliance costs for private entities to
range from -$121.4 million under Option A to -$19.1 million under Option C.
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Table 9-6: Compliance Costs for Electric Generators by Ownership Type (2018$)
Incremental
Incremental
Maximum One-
Total
Year of
Annualized
Year Costs
Annualized
Maximum One-
Maximum
Costs Relative to
Relative to
Ownership Type
Costs
Year Costs
Costs3
Baseline
Baselineb
Baseline
Government (excl. federal)
$28
$113.5
2023
NA
NA
Private
$254
$1,312.7
2023
NA
NA
Option Dc
Government (excl. federal)
Private
$197
$514
2023
-$114.0
-$327.5
Option A
Government (excl. federal)
$17
$39.4
2028
-$11.4
-$74.1
Private
$133
$399.1
2025
-$121.4
-$913.6
Option B
Government (excl. federal)
$17
$39.4
2028
-$10.8
-$74.1
Private
$152
$440.3
2025
-$102.3
-$872.4
Option C
Government (excl. federal)
$22
$84.0
2028
t—1
to
i
-$29.6
Private
$235
$574.7
2025
-$19.1
-$738.1
NA: Not applicable for the baseline.
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.
b. The maximum one-year cost does not necessarily occur on the same year for a given plant across all the options analyzed. For
the purpose of comparing the regulatory options to the baseline, EPA used the maximum costs in any year rather than
comparing costs on a year-to-year basis to obtain the maximum difference.
c. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect changes
in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2020.
9.4 UMRA Analysis Summary
EPA estimates that none of the regulatory options would result in incremental expenditures of at least
$160 million for State and local government entities, in the aggregate, or for the private sector in any one
year. In fact, all regulatory options provide net cost savings when compared to the baseline. 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 reduce impacts to
governments and the private sector. The final rule (Option A) is the least costly option EPA analyzed, and
thus would result in the lowest impacts to governments and the private sector. Furthermore, several
government and private sector plants would likely fall into subcategories which would provide additional
flexibility. Finally, the implementation period built into the final rule is another way for permit writers to
consider the site-specific needs of steam electric power plants.
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10: Other Administrative Requirements
10 Other Administrative Requirements
This chapter presents analyses conducted in support of the regulatory options to address the requirements
of applicable Executive Orders and Acts. These analyses complement EPA's assessment of the
compliance costs, economic impacts, and economic achievability of the final rule, and other analyses
done in accordance with the RFA and UMRA, presented in previous chapters.
10.1 Executive Order 12866: Regulatory Planning and Review 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 final rule is an "economically
significant regulatory action" because the action is likely to have an annual effect on the economy of
$100 million or more, although the direction of the effect is estimated to be a reduction in costs when
compared to the baseline. 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, 2020a).
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 13771: Reducing Regulation and Controlling Regulatory Costs
The final rule is considered a deregulatory action under E.O. 13771, Reducing Regulation and Controlling
Regulatory Costs. As presented in Chapter 3 (Table 3-3), all four regulatory options analyzed have total
compliance costs less than zero, when compared to the baseline. Accounting for the timing of the costs
shows net social cost savings for all four options using a 7 percent discount rate. Using a 3 percent
discount rate options A, B, and D show a net social cost savings while option C shows a net social cost
increase. See Chapter 12 in the BCA (U.S. EPA, 2020a) for details on the time profile of costs and
annualized discounted costs.
10.3 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations
E.O. 12898 (59 FR 7629, February 11, 1994) requires that, to the greatest extent practicable and permitted
by law, each Federal agency must make the achievement of environmental justice (EJ) part of its mission.
E.O. 12898 provides that each Federal agency must conduct its programs, policies, and activities that
substantially affect human health or the environment in a manner that ensures such programs, policies,
and activities do not have the effect of (1) excluding persons (including populations) from participation
in, or (2) denying persons (including populations) the benefits of, or (3) subjecting persons (including
populations) to discrimination under such programs, policies, and activities because of their race, color, or
national origin.
To meet the objectives of E.O 12898 and consistent with EPA guidance on considering EJ in the
development of regulatory actions (U.S. EPA, 2015b), EPA examined whether the benefits from the
regulatory options may be differentially distributed among population subgroups in the affected areas.
EPA conducted two main analyses, described in Chapter 14 of the BCA (U.S. EPA, 2020a), to evaluate
the EJ considerations for the final rule: (1) Summarizing the demographic characteristics of the
households living in proximity to steam electric power plants, plant air emissions and surface water
discharges, and to the downstream reaches affected by plant discharges; and (2) Analyzing the
distribution of estimated human health impacts among minority and/or low-income populations from
estimated changes in exposure to pollutants in drinking water, self-caught fish, and the air.
The first analysis provides insight on the distribution of estimated regulatory option effects (e.g.,
estimated effects on water quality and air pollutant emissions) on communities in proximity to steam
electric power plants. The second analysis seeks to provide more specific insight on the distribution of
estimated changes in adverse health effects and benefits and to assess whether minority and/or low-
income populations incur disproportionately high environmental impacts and/or will be
disproportionately excluded from realizing benefits under the regulatory options.
Overall, the various analyses show that estimated environmental changes under the regulatory options
analyzed, including the final rule, may affect minority and/or low income populations to different degrees
across environmental media, exposure pathways, and over time, but the estimated effects (positive or
negative) of the changes will be small.
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Communities living near steam electric power plants (i.e., up to 50 miles) tend to have a lower proportion
of low-income households and minority population than the national average, when considered in the
aggregate, but there may be localized EJ considerations for some communities near individual plants (up
to 50 miles) that have higher proportions of low-income or minority populations than the national and/or
state average.
EPA's analysis considered the distribution of estimated effects on populations near both immediate and
downstream reaches, in downstream PWS service areas, and in adjacent airsheds to assess whether low-
income and/or minority populations may be disproportionately affected by changes under the final rule.
The analysis shows that the EJ population subgroups are not excluded from the benefits of the final rule.
For example, projected air quality changes under the final rule may disproportionately benefit minority
and low-income populations based on the socioeconomic characteristics of populations of counties with
changes in PM2 5 and ozone levels during the period of analysis. Additionally, estimated foregone benefits
related to water quality changes may disproportionately affect minority and subsistence fisher
populations. However, the magnitude of the changes (positive and negative) and associated benefits
(including foregone benefits) is small, relative to the baseline, both overall across the exposed population,
and across socioeconomic and fisher subgroups.
10.4 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 Supplemental EA and BCA (U.S. EPA, 2020a, 2020d), EPA identified several ways in
which the regulatory options would affect children, including by potentially increasing health risk from
exposure to pollutants present in steam electric power plant discharges. The potential increases are
estimated to be small and arise from less stringent limits or later deadlines for meeting effluent limits
under certain 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 three 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 requiring compensatory education tailored to their specific needs.
EPA estimated that the final rule could have a small impact on children. The analysis shows small
potential changes in lead exposure (from fish consumption) for an average of 1.6 million children
annually, and in mercury exposure (from maternal fish consumption) for an average of 226,000 infants
born annually. However, EPA estimates the resulting health impacts to be small. EPA estimated that the
final rule (Option A) would lead to slight increases in lead and mercury exposure, increasing IQ losses by
approximately 18 points from lead exposure and between 2001 points from mercury exposure over the
entire exposed population. The social welfare effects from increased IQ loss associated with children's
exposure to lead and mercury are -$0.1 million and -$0.3 million using 3 percent and 7 percent discount
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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. 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 small adverse effects from increases in exposure to disinfection byproducts for children in
households served by drinking water systems that use source waters downstream of steam electric power
plant outfalls.
10.5 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 not have federalism implications. As discussed in earlier chapters
of this document, EPA anticipates that the final rule will not impose a significant incremental
administrative burden on States from issuing, reviewing, and overseeing compliance with discharge
requirements. With respect to direct compliance costs, while the regulatory options may impose such
costs on State or local governments that own steam electric power plants, and the Federal government
would not provide the funds necessary to pay those costs, the regulatory options are estimated to provide
savings to State or local governments when compared to the costs they would incur under the baseline.
Specifically, EPA has identified 157 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 $39.4 million under Option A
to $84 million under Option C (see Chapter 9, Unfunded Mandates Reform Act (UMRA), for details). This
is compared to a maximum compliance cost to governments of $114 million under the baseline.
Annualized cost savings to governments range from $6 million under Option C to $ 11 million under
Option A.
10.6 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
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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 14 public water systems (PWS) operated by
tribal governments that may be affected by bromide and iodine discharges from steam electric
power plants.70 In total, these systems serve approximately 27,600 people. This analysis finds
small changes in incremental bromide and iodine concentrations at 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.
10.7 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."71 Those criteria include:
• Reductions in crude oil supply in excess of 10,000 barrels per day;
• Reductions in fuel production in excess of 4,000 barrels per day;
• Reductions in coal production in excess of 5 million tons per year;
• Reductions in natural gas production in excess of 25 million mcf per year;
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 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 the final rule. While the regulatory options might affect (1) the
production of electricity, (2) the amount of installed capacity, (3) the cost of energy production, and (4)
the dependence on foreign supplies of energy, the four regulatory options provide cost savings when
compared to the baseline, reducing electricity generation costs. As described below and demonstrated by
the results from the national electricity market analyses conducted for Option A (the final rule) (see
Chapter 5), changes for the first three factors are in a direction than does not present a concern under this
Executive Order or are smaller than the thresholds of concern specified by OMB.
10.7.1 Impact on Electricity Generation
The electricity market analyses (Chapter 5) estimate that the final rule will increase coal-fired generation,
including generation from power plants to which the final rule applies, by less than 0.1 percent to
approximately 0.6 percent in 2021 through 2045, 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 322 GWh,
which is less than 0.01 percent of baseline generation. These changes are very small and support EPA's
assessment that the final rule does not constitute a "significant energy action" in terms of overall impact
on electricity generation.
10.7.2 impact on Electricity Generating Capacity
As documented in Chapter 5, the Agency's electricity market analysis estimated that the final rule would
result in net cumulative avoided retirement of 1,127 MW of generating capacity by 2030, and net
cumulative avoided retirement of 2,010 MW by 2050.
10.7.3 Cost of Energy Production
Based on the IPM analysis results, EPA estimated that the final rule will not significantly affect the total
cost of electricity production. At the national level, total electricity generation costs (fuel, variable O&M,
fixed O&M and capital) under the final rule are projected to decrease by 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 a decrease of 0.3 percent in FRCC, RFC,
and SPP under the final rule to an increase of 0.2 percent in NPCC. None of the NERC regions show
increases approaching 1 percent.
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 final
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rule does not constitute a "significant energy action" in terms of estimated potential effects on the cost of
energy production.
10.7.4 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 final rule. The final rule is estimated to increase coal-based electricity generation by 0.6 percent,
while generation using several other sources of energy is estimated to either decrease (natural gas,
biomass, solar, wind, hydro) or increase {i.e., oil/gas steam, nuclear). Changes are less than 1 percent
across all generation types.
Table 10-1: Total Market-Level Capacity and Generation by Type for the Final Rule in 2030
Generating Capacity
GW)
Electricity Generation (Thousand GWh)
Type
Baseline
Option A
% Change
Baseline
Option A
% Change
Hydro
110.5
110.5
0.00%
327.3
327.1
-0.04%
Biomass
0.6
0.6
0.00%
1.7
1.7
-0.16%
Geothermal
2.9
2.9
0.00%
20.6
20.6
0.00%
Landfill Gas
1.8
1.8
0.00%
9.4
9.4
0.00%
Solar
134.7
134.5
-0.15%
245.6
245.2
-0.15%
Wind
188.5
188.2
-0.14%
636.5
635.3
-0.19%
Coal
158.9
160.2
0.78%
821.2
825.9
0.57%
Nuclear
68.5
68.8
0.38%
541.4
543.7
0.42%
Natural Gas
420.4
419.4
-0.24%
1,621.9
1,616.2
-0.35%
Oil/Gas
Steam
66.0
65.8
-0.43%
52.1
52.5
0.63%
Others
17.1
16.9
-0.74%
45.1
44.9
-0.49%
Total3
1,169.9
1,169.5
-0.03%
4,322.8
4,322.4
-0.01%
a. Numbers may not add up due to rounding.
Source: U.S. EPA Analysis, 2020.
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 more coal (0.3 percent)
and less natural gas (0.3 percent) consumed under the final rule. Changes are less than 1 percent for
natural gas and lignite, but bituminous and subbituminous coal consumption increases by 2.8 percent and
decreases by 1.1 percent, respectively.
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Table 10-2: Total Market-Level Fuel Use by Fuel Type for the Final Rule in 2030
Fuel Consumption
Fuel Type
Baseline
Option A
% Change
Coal (million tons)
446
448
0.29%
Bituminous Coal (million tons)
143
147
2.75%
Subbituminous Coal (million tons)
252
249
-1.06%
Lignite (million tons)
52
52
0.01%
Natural Gas (trillion cubic feet)
12
12
-0.27%
Source: U.S. EPA Analysis, 2020.
Given the very small changes in coal and other fuels use under the final rule, it is reasonable to assume
that any increase in demand for fuel used in electricity generation would be met through domestic supply,
thereby not increasing U.S. dependence on foreign supply of energy. Consequently, EPA assesses that the
final rule does not constitute a "significant energy action" from the perspective of energy independence.
10.7.5 Overall £ 0.13211 Finding
From these analyses and the electricity markets analysis in Chapter 5, EPA concludes that the final rule
would not have a significant adverse effect at a national or regional level under 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 final rule does not constitute a
significant regulatory action under Executive Order 13211 and EPA did not prepare a Statement of
Energy Effects.
10.8 Paperwork Reduction Act of 1995
The Paperwork Reduction Act of 1995 (PRA) (superseding the PRA of 1980) is implemented by OMB
and requires that agencies submit a supporting statement to OMB for any information collection that
solicits the same data from more than nine parties. The PRA seeks to ensure that Federal agencies balance
their need to collect information with the paperwork burden imposed on the public by the collection.
The definition of "information collection" includes activities required by regulations, such as permit
development, monitoring, record keeping, and reporting. The term "burden" refers to the "time, effort, or
financial resources" the public expends to provide information to or for a Federal agency, or to otherwise
fulfill statutory or regulatory requirements. PRA paperwork burden is measured in terms of annual time
and financial resources the public devotes to meet one-time and recurring information requests (44 U.S.C.
3502(2); 5 C.F.R. 1320.3(b)). Information collection activities may include:
• reviewing instructions;
• using technology to collect, process, and disclose information;
• adjusting existing practices to comply with requirements;
• searching data sources;
• completing and reviewing the response; and
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• 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.72
The final rule will not result in any significant change in the information collection requirements
associated with initial permit application, re-permitting activities, and activities associated with
monitoring and reporting after the permit is issued beyond those already required under the existing
NPDES program.
EPA estimated small changes in monitoring costs due to changes in the number of pollutants for which
EPA is finalizing limits and standards, as well as monitoring of flow under the high recycle rate systems
for bottom ash; the Agency accounted for these costs as part of its analysis of the economic impacts of the
regulatory options (see Chapter 3, Compliance Costs). In some cases, in lieu of these monitoring
requirements, steam electric power plants would have additional paperwork burden such as that
associated with certifications and applicable BMP plans. However, plants would also realize savings,
relative to the baseline, by no longer monitoring pollutants for some subcategories (and because their
requirements are based on less costly technologies). EPA projects that the burden associated with the new
paperwork requirements would be largely offset by the reduced burden associated with less monitoring;
therefore, it projects that the final rule will have no net effect on the burden in the approved information
collection requirements.
With respect to permitting authorities, based on the information in its record EPA does not expect the
regulatory options (including the final rule, Option A), to affect the total administrative burden. The
regulatory options do not change permit application requirements or the associated review, nor do they
affect the number of permits issued to steam electric power plants. While permitting authorities will need
to use BPJ to determine the site-specific volumes and technology-based BAT effluent limitations for
bottom ash purge water, EPA has taken steps to reduce the burden on NPDES permitting authorities of
making these determinations. EPA is requiring information on the types of discharges and available
treatment technologies in the reporting and recordkeeping requirements and EPA provides principles that
permitting authorities may consider (see preamble section XIV(A)(2)). Accordingly, EPA estimated no
significant net change (increase or decrease) in the cost burden to federal or state governments or
dischargers associated with any of the regulatory options in this rule.
10.9 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
OMB has assigned control number 2040-0281 to the information collection requirements under 40 CFR part 423.
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business practices) that are developed or adopted by voluntary consensus standard bodies. The NTTAA
directs EPA to provide Congress, through the OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
The regulatory options do not involve technical standards, for example in the measurement of pollutant
loads. Nothing in the regulatory options would prevent the use of voluntary consensus standards for such
measurement where available, and EPA encourages permitting authorities and regulated entities to do so.
Therefore, EPA did not include any voluntary consensus standards in the final rule.
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11: References
ii Cited References
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Refineries. The Review of Economics and Statistics, 83(3), 498-510.
Boijas, G. J. (1996). Labor Economics: McGraw-Hill.
Coglianese, J., Gerarden, T., & Stock, J. H. (2020). The Effects of Fuel Prices, Regulations, and Other
Factors on U.S. Coal Production, 2008-2016. The Energy Journal, 41.
Curtis, E. M. (2018). Who loses under cap-and-trade programs? the labor market effects of the nox budget
trading program. Review of Economics and Statistics, 700(1), 151-166.
Deschenes, O. (2011). Climate policy and labor markets. In The design and implementation of US climate
policy (pp. 37-49): University of Chicago Press.
Deschenes, O. (2018). Environmental regulations and labor markets. IZA World of Labor.
Durlauf, S. N. (2004). Neighborhood effects. In Handbook of regional and urban economics (Vol. 4, pp.
2173-2242): Elsevier.
Federation of Tax Administrators. (2019). Range of State Corporate Income Tax Rates (for Tax Year
2019, as of January 1, 2019). Retrieved from https://www.taxadmin.org/current-tax-rates
Fell, H., & Kaffine, D. T. (2018). The Fall of Coal: Joint Impacts of Fuel Prices and Renewables on
Generation and Emissions. American Economic Journal: Economic Policy, 10(2), 90-116.
doi:https://doi.org/10.1257/pol.20150321
Ferris, A. E., Shadbegian, R. J., & Wolverton, A. (2014). The effect of environmental regulation on
power sector employment: Phase I of the title IV S02 trading program. Journal of the Association
of Environmental and Resource Economists, 7(4), 521-553.
Graff Zivin, J., &Neidell, M. (2013). Environment, health, and human capital. Journal of Economic
Literature, 57(3), 689-730. doi:http://dx.doi.org/10.1257/iel.51.3.689
Greenstone, M. (2002). The impacts of environmental regulations on industrial activity: Evidence from
the 1970 and 1977 clean air act amendments and the census of manufactures. Journal of political
economy, 110(6), 1175-1219.
Hafstead, M. A., & Williams III, R. C. (2018). Unemployment and environmental regulation in general
equilibrium. Journal of Public Economics, 160, 50-65.
Holland, S. P. (2012). Spillovers from Climate Policy to Other Pollutants. In The Design and
Implementation of U.S. Climate Policy. University of Chicago Press.
Knittel, C. R., Metaxoglou, K., & Trindade, A. (2015). Natural Gas Prices and Coal Displacement:
Evidence from Electricity Markets. National Bureau of Economic Research Working Paper
Series, No. 21627. doi:10.3386/w21627
Kolstad, C. D. (2017). What Is Killing the U.S. Coal Industry? Retrieved from
https://siepr.stanford.edu/sites/default/files/publications/PolicvBrief-Marl7.pdf
Layard, P. R. G., & Walters, A. A. {\91%).Microeconomic theory.
Linn, J., & McCormack, K. (2019). The roles of energy markets and environmental regulation in reducing
coal-fired plant profits and electricity sector emissions. The RAND Journal of Economics, 50(4),
733-767. doi:10.1111/1756-2171.12294
McGraw Hill Construction Engineering News-Record. (2020). Construction Cost Index (CCI).
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Mills, A., Wiser, R., & Seel, J. (2017). Power Plant Retirements: Trends and Possible Driver. Retrieved
from https://emp.lbl.gov/sites/default/files/lbnl retirements data synthesis final.pdf
Morgenstern, R. D., Pizer, W. A., & Shih, J.-S. (2002). Jobs versus the environment: an industry-level
perspective. Journal of Environmental Economics and Management, 43(3), 412-436.
Smith, V. K. (2015). Should benefit-cost methods take account of high unemployment? symposium
introduction. Review of Environmental Economics and Policy, 9(2), 165-178.
U.S. Bureau of Economic Analysis. (2019). Table 1.1.9 Implicit Price Deflators for Gross Domestic
Product (GDP Deflator).
U.S. Department of Commerce, & U.S. Census Bureau. (2017). American Community Survey 2013-2017
5-Year Estimates.
U.S. Department of Labor. Bureau of Labor Statistics. (2020). Total compensation for All Civilian
workers in All industries and occupations, Index.
U.S. Energy Information Administration. (2012). North American Electric Reliability Corporation
(NERC) Regions. In.
U.S. Energy Information Administration. (2017). Most coal plants in the United States were built before
1990.
U.S. Energy Information Administration. (2018a). Almost all power plants that retired in the past decade
were powered by fossil fuels. Today in Energy.
U.S. Energy Information Administration. (2018b). Annual Electric Power Industry Report, Form EIA-861
detailed data files: Final 2018 Data.
U.S. Energy Information Administration. (2018c). Nuclear Power Outlook. Retrieved from
https://www.eia.gov/outlooks/aeo/pdf/nuclear power outlook.pdf
U.S. Energy Information Administration. (2018d). Petroleum, natural gas, and coal still dominate U.S.
energy consumption. Today in Energy.
U.S. Energy Information Administration. (2019a). Annual Energy Outlook 2019.
U.S. Energy Information Administration. (2019b). Form EIA-860 Detailed Data: Final 2018 Data.
Retrieved January 3, 2020
U.S. Energy Information Administration. (2019c). Form EIA-923 Detailed Data: Annual Release 2018
Final Data. Retrieved January 2, 2020
U.S. Energy Information Administration. (2019d). More than 60% of electric generating capacity
installed in 2018 was fueled by natural gas. Today in Energy.
U.S. Energy Information Administration. (2020). U.S. coal-fired electricity generation in 2019 falls to 42-
year low. Today in Energy.
U.S. Environmental Protection Agency. (2006). Final Guidance for EPA Rulewriters: Regulatory
Flexibility Act as Amended by the Small Business Regulatory Enforcement Fairness Act.
U.S. Environmental Protection Agency. (2010). Questionnaire for the Steam Electric Power Generating
Effluent Limitations Guidelines.
U.S. Environmental Protection Agency. (2014a). Economic Analysis forthe Final Section 316(b)
Existing Facilities Rule. (EPA 821-R-14-001).
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11: References
U.S. Environmental Protection Agency. (2014b). Regulatory Impact Analysis (R1A) for EPA's 2015 Coal
Combustion Residuals (CCR) Final Rule Retrieved from https://downloads.regulations.gov/EPA-
HO-RCRA-2009-0640-12034/content.pdf
U.S. Environmental Protection Agency. (2015a). Benefit and Cost Analysis for the Effluent Limitations
Guidelines and Standards for the Steam Electric Power Generating Point Source Category. (EPA-
821-R-15-005).
U.S. Environmental Protection Agency. (2015b). Guidance on Considering Environmental Justice during
the Development of Regulatory Actions. Retrieved from
http://www.epa.gov/environemntaliustice/resources/plicv/ei-rulemaking.html
U.S. Environmental Protection Agency. (2015c). Regulatory Impact Analysis for the Effluent Limitations
Guidelines and Standards for the Steam Electric Power Generating Point Source Category. (EPA-
821-R-15-004).
U.S. Environmental Protection Agency. (2018). Documentation for EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model. 1200 Pennsylvania Avenue, NW, Washington
D C. 20460
U.S. Environmental Protection Agency. (2019a). Regulatory Impact Analysis for Proposed Revisions to
the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point
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Proposed Revisions to Effluent Limitations Guidelines and Standards for the Steam Electric
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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 the final ELG reconsideration rule as compared to the proposed ELG
reconsideration rule described in the 2019 RIA (U.S. EPA, 2019a).
Table A-1: Changes to Costs and Economic Impacts Analysis Since Proposal
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 (2011-2016)
average values
Updated with data from more current EIA-
861 and EIA-923 databases to use more
recent six-year [2013-2018] average values
Generating capacity from 2016 EIA-860
Updated using 2018 EIA-860
NERC regions from 2016 EIA-860
Updated using 2017 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 [2016]
Updated to use data from EIA-861 for
[2018]
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 [2018]
AEO projections
Updated using [2019] AEO projections
Industry profile
Total count of plants (951 plants)
Updated universe of 914 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 2016 EIA
databases
Updated using 2018 EIA databases
Screening-level plant
impacts
Cost-to-revenue impact indicators (1% and
3%) based on 6-year (2011-2016) average
values of electricity generation and
electricity prices (to estimate plant-level
revenue)
Updated to use average electricity
generation and electricity prices for [2013-
2018]
Market-level impacts
(IPM)
The Baseline includes existing regulatory
requirements as of December 2019 and
representation of the 2015 ELG based on
2018 data.
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.
Potential electricity
price effects
Projected total electricity sales in [2020]
from [AEO 2018]
Projected total electricity sales in [2020]
from [AEO 2019]
Electricity sales data by consumer group
from [2016] EIA-860 database
Electricity sales data by consumer group
from [2018] EIA-860 database
Owner-level impacts
and RFA/SBREFA
Owners identified in EIA-860 [2016]
Owners identified in EIA-860 [2018]
Small business size determination metrics
[mostly publicly available sources for
private entities; Census ACS 2016 for
governments]
Small business size determination metrics
[mostly publicly available sources for
private entities; Census ACS 2017 for
governments]
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Appendix A: Summary of Changes
Table A-1: Changes to Costs and Economic Impacts Analysis Since Proposal
Cost or Impact Category
Analysis Component
Cost or Impact Category
EO 12898: EJ
Refers to BCA Chapter 14. Qualitative
discussion draws on benefits analyses. See
Table 2 for details.
Presents profile of population in the
vicinity of steam electric power plants and
selected results of the benefits analyses by
income and minority status
Update profile and discussion of
distributional effects to reflect exposure
via drinking water
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Appendix B: Costs and Pollutant Removals
nparisori 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 (i.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 rule, EPA's cost-effectiveness analysis involves the following steps to generate
input data and calculate the desired values (see Appendix F in U.S. EPA, 2015c):
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 Supplemental TDD (U.S. EPA, 2020e) 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 the final rule represent only a subset of the requirements contained in
the ELG for the steam electric industry since they address only two 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, 2015c) 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 2015 rule baseline.73
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 Supplemental TDD provides information on the pollutants addressed by the regulatory options (U.S.
EPA, 2020e). 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, 2015c.
Evaluated Options
EPA updated its analyses of Options A, B, and C summarized in Table 1-1. To provide context for the
results, EPA did not update, but also includes results for Option D, which the Agency previously analyzed
in the 2019 proposal (see Option 1 in U.S. EPA, 2019a).
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, high BOD resulting in anoxia). 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.
The incremental pollutant removals for Option D are relative to the baseline analyzed for the 2019
proposal, whereas incremental pollutant removals of Options A, B, and C are estimated relative to the
revised baseline for the final rule analysis.
Annualized Compliance Costs
EPA developed costs for technology controls to address each of the wastestreams present at each steam
electric power plant. The Supplemental 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, 2020e). 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 2015 rule
baseline, whereas Figure B-l compares the pollutant removals and costs of the regulatory options
graphically.
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Appendix B: Costs and Pollutant Removals
The incremental compliance costs for Option D were calculated relative to the baseline analyzed for the
2019 proposal, whereas incremental compliance costs of Options A, B, and C are estimated relative to the
revised baseline for the final rule analysis.
Table B-1: Estimated Pollutant Removal and Costs of Regulatory Options by Discharger Category
Total Annual TWF-Weighted
Pollutant Removals (Ib-eq.)
Total Annual Pre-tax Compliance
Costs
(million, 2018$)
Discharger Category
Option3
Totalb
Incremental
Totalb
Incremental
Direct
Ae
-16,415
-16,415
-$173.5
-$173.5
B
5,630
22,045
-$142.3
$31.2
C
472,478
466,848
-$18.4
$123.9
Indirect
Ae
0
0
-$1.7
-$1.7
B
0
0
-$0.9
$0.9
C
4,506
4,506
-$1.1
-$0.2
a. Options are listed in increasing order of pollutant removals, relative to the baseline.
b. Total removals and costs are compared to those for the baseline.
c. 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.
d. Option D corresponds to the proposed Option 1. EPA did not reanalyze this option for the final rule. All results shown for
Option D are based on the 2019 analysis, as detailed in the 2019 RIA (U.S. EPA, 2019a). As such, the values do not reflect
changes in the baseline, plant universe, and other analytical inputs for the analysis of Options A, B, and C.
Source: U.S. EPA Analysis, 2019, 2020
Figure B-1: Estimated Removals and Costs of the Regulatory Options, Relative to Baseline.
$10
J-100,000 -$10 0 100,000 200,000 300,000 400,000 500,000
if Option C •
£ -$30
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| -$5°
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