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Regulatory Impact Analysis for the Repeal of
the Clean Power Plan, and the Emission
Guidelines for Greenhouse Gas Emissions from
Existing Electric Utility Generating Units

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EPA-452/R-19-003
June 2019
Regulatory Impact Analysis for the Repeal of the Clean Power Plan, and the Emission
Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Health and Environmental Impact Division
Research Triangle Park, NC
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CONTACT INFORMATION
This document has been prepared by staff from the Office of Air Quality Planning and
Standards, the Office of Atmospheric Programs, and the Office of Policy of the U.S.
Environmental Protection Agency. Questions related to this document should be addressed to
Brian Keaveny, U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, Research Triangle Park, North Carolina 27711 (email: keaveny.brian@epa.gov).
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TABLE OF CONTENTS
LIST OF TABLES	VIII
LIST OF FIGURES	XI
EXECUTIVE SUMMARY	ES-1
ES.l Introduction	ES-1
ES.2 Analysis	ES-1
ES.3 Compliance Costs	ES-5
ES.4 Emissions Changes	ES-6
ES.5 Climate and Health Co-Benefits	ES-7
ES.6 Net Benefits	ES-9
ES.7 Economic and Employment Impacts	ES-13
ES.8 Limitations and Uncertainty	ES-13
ES.9 References	ES-16
CHAPTER 1: INTRODUCTION AND BACKGROUND	1-1
1.1	Introduction	1-1
1.2	Legal and Economic Basis for this Rulemaking	1-1
1.2.1	Statutory Requirement	1-1
1.2.2	Market Failure	1-3
1.3	Background	1-3
1.3.1	Emission Guidelines	1-3
1.3.2	Regulated Pollutant	1-4
1.3.3	Definition of Affected Sources for the Affordable Clean Energy Rule	1-4
1.4	Overview of Regulatory Impact Analysis	1-4
1.4.1	Baseline	1-6
1.4.2	BSER and Illustrative Policy Scenario	1-7
1.4.3	Years of Analysis	1-7
1.5	B SER Technologies	1-8
1.5.1	Neural Network/Intelligent Sootblower	1-8
1.5.2	Boiler Feed Pumps	1-9
1.5.3	Air Heater and Duct Leakage Control	1-9
1.5.4	Variable Frequency Drives (VFDs)	1-9
1.5.5	Blade Path Upgrade (Steam Turbine)	1-10
1.5.6	Redesign/Replace Economizer	1-11
1.5.7	Additional Documentation	1-11
1.6	Development of Illustrative Policy Scenario	1-11
1.6.1	Introduction	1-11
1.6.2	Grouping EGUs by Performance	1-12
1.6.3	Heat Rate and Cost for each Bin	1-15
1.6.4	How HRI are Represented in the Illustrative Policy Scenario	1-18
1.7	Organization of the Regulatory Impact Analysis	1-19
1.8	References	1-20
CHAPTER 2: IMPACTS OF THE REPEAL OF THE CPP	2-1
2.1	Introduction	2-1
2.2	Market Trends for the Electric Sector Relevant to Consideration of the Impact of the
Repeal of the CPP	2-6
2.2.1	Recent Data Trends	2-7
2.2.2	Utility Climate and Clean Energy Announcements and Commitments	2-12
2.2.3	Recent Emissions Trends & Future Projections	2-14
2.3	CPP Stay/Delayed Implementation and Trading Assumptions	2-15
2.3.1 Delayed implementation of the CPP	2-16
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2.3.2 Interstate Trading under the CPP	2-19
2.4	Modeling Inputs and Key Areas of Uncertainty	2-28
2.4.1 Routine Baseline Updates and Model Considerations	2-28
2.5	Additional State-level Information	2-30
2.6	Conclusion	2-35
2.7	Addendum: IPM Power Sector Projections	2-35
CHAPTER 3: COST, EMISSIONS, ECONOMIC, AND ENERGY IMPACTS	3-1
3.1	Introduction	3-1
3.2	Overview	3-1
3.3	Power Sector Modeling Framework	3-2
3.4	Recent Updates to the EPA's Power Sector Modeling Platform v6 using IPM	3-4
3.5	Scenario Analyzed	3-5
3.6	Monitoring, Reporting, and Recordkeeping Costs	3-7
3.7	Projected Power Sector Impacts	3-11
3.7.1	Projected Emissions	3-11
3.7.2	Projected Compliance Costs	3-12
3.7.3	Projected Compliance Actions for Emissions Reductions	3-14
3.7.4	Projected Generation Mix	3-21
3.7.5	Projected Changes to Generating Capacity	3-23
3.7.6	Projected Coal Production and Natural Gas Use for the Electric Power Sector	3-25
3.7.7	Projected Fuel Price, Market, and Infrastructure Impacts	3-26
3.7.8	Projected Retail Electricity Prices	3-27
3.8	Sensitivity: 45QTax Credit Revisions under the Bipartisan Budget Act of 2018	3-27
3.9	Limitations of Analysis and Key Areas of Uncertainty	3-28
3.10	References	3-32
CHAPTER 4: ESTIMATED CLIMATE BENEFITS AND HUMAN HEALTH CO-
BENEFITS	4-1
4.1	Introduction	4-1
4.2	Climate Change Impacts	4-1
4.3	Approach to Estimating Climate Benefits from C02	4-2
4.4	Approach to Estimating Human Health Ancillary Co-Benefits	4-6
4.4.1	Air Quality Modeling Methodology	4-9
4.4.2	Estimating PM2 5 and Ozone Related Health Impacts	4-16
4.4.3	Economic Value of Ancillary Health Co-benefits	4-23
4.4.4	Characterizing Uncertainty in the Estimated Benefits	4-24
4.5	Air Quality and Health Impact Results	4-28
4.5.1 Air Quality Results	4-28
4.5.1 Estimated Number and Economic Value of Ancillary Health Co-Benefits	4-29
4.6	Total Estimated Climate and Health Benefits	4-36
4.7	Ancillary Co-Benefits Not Quantified	4-37
4.7.1	Hazardous Air Pollutant Impacts	4-40
4.7.2	NO Health Co-Benefits	4-44
4.7.3	SO-Health Co-Benefits	4-44
4.7.4	NO2 and SO2 Welfare Co-Benefits	4-45
4.7.5	Ozone Welfare Co-Benefits	4-46
4.7.6	Visibility Impairment Co-Benefits	4-46
4.8	References	4-48
CHAPTER 5: ECONOMIC AND EMPLOYMENT IMPACTS	5-1
5.1 Economic Impacts	5-1
5.1.1	Market Impacts	5-1
5.1.2	Distributional Impacts	5-4
5.1.3	Impacts on Small Entities	5-8
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5.2	Employment Impacts	5-9
5.3	References	5-15
CHAPTER 6: COMPARISON OF BENEFITS AND COSTS	6-1
6.1	Introduction	6-1
6.2	Methods	6-2
6.3	Results	6-3
6.3.1	Analysis of 2023-2037 for E.O. 13771, Reducing Regulation and Controlling Regulatory Costs.... 6-3
6.3.2	Net Benefits Analysis	6-5
6.4	References	6-13
CHAPTER 7: APPENDIX - UNCERTAINTY ASSOCIATED WITH ESTIMATING THE
SOCIAL COST OF CARBON	7-1
7.1	Overview of Methodology Used to Develop Interim Domestic SC-C02 Estimates	7-1
7.2	Treatment of Uncertainty in Interim Domestic SC-C02 Estimates	7-2
7.3	Global Climate Benefits	7-7
7.4	References	7-9
CHAPTER 8: APPENDIX - AIR QUALITY MODELING	8-1
8.1	Air Quality Modeling Platform	8-1
8.1.1	Air Quality Model, Meteorology and Boundary Conditions	8-1
8.1.2	2011 and 2023 Emissions	8-3
8.1.3	2011 Model Evaluation for Ozone and PM2.5	8-6
8.2	Source Apportionment Tags	8-10
8.3	Applying Source Apportionment Contributions to Create Air Quality Fields for the Baseline
and Illustrative Policy Scenario	8-18
8.3.1	Estimation methods for Emissions that Represent the Baseline and Illustrative Policy Scenario ... 8-18
8.3.2	Scaling Ratio Applied to Source Apportionment Tags	8-21
8.4	Creating Fused Fields Based on Observations and Model Surfaces	8-29
8.5	References	8-33
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LIST OF TABLES
Table ES-1 Present Value and Equivalent Annualized Value of Compliance Costs, Domestic Climate Benefits,
Ancillary Health Co-Benefits, and Net Benefits, Illustrative Policy Scenario, 3 and 7 Percent Discount
Rates, 2023-2037 (millions of 2016$)	ES-4
Table ES-2 Present Value and Equivalent Annualized Value of Compliance Costs, Domestic Climate Benefits,
and Net Benefits Associated with Targeted Pollutant (CO2), Illustrative Policy Scenario, 3 and 7
Percent Discount Rates, 2023-2037 (millions of 2016$)	ES-5
Table ES-3 Compliance Costs of Illustrative Policy Scenario in 2025, 2030, and 2035 (millions of 2016$)	ES-5
Table ES-4 Projected CO2 Emission Impacts of Illustrative Policy Scenario, Relative to Baseline in 2025, 2030,
and 2035	ES-6
Table ES-5 Projected SO2, NOx, and Hg Electricity Sector Emissions of Illustrative Policy Scenario in 2025,
2030, and 2035	ES-7
Table ES-6 Monetized Benefits of Illustrative Policy Scenario in 2025, 2030, and 2035 (millions of 2016$)...ES-9
Table ES-7 Present Value and Equivalent Annualized Value of Compliance Costs, Climate Benefits, and Net
Benefits Associated with Targeted Pollutant (CO2), Illustrative Policy Scenario, 3 and 7 Percent
Discount Rates, 2023-2037 (millions of 2016$)	ES-10
Table ES-8 Compliance Costs, Climate Benefits, and Net Benefits Associated with Targeted Pollutant (CO2) in
2025, 2030, and 2035, Illustrative Policy Scenario, 3 and 7 Percent Discount Rates (millions of
2016$)	ES-11
Table ES-9 Present Value and Equivalent Annualized Value of Compliance Costs, Total Benefits, and Net
Benefits, 2023-2037, Illustrative Policy Scenario, 3 and 7 Percent Discount Rates (millions of 2016$)
11
Table ES-10 Compliance Costs, Total Benefits, and Net Benefits in 2025, 2030, and 2035, Illustrative Policy
Scenario, 3 and 7 Percent Discount Rates (millions of 2016$)	ES-12
Table ES-11 Alternative Net Benefits Presentation: Present Value and Equivalent Annualized Value of
Compliance Costs, Total Benefits, and Net Benefits, 2023-2037, Illustrative Policy Scenario, 3 and 7
Percent Discount Rates, (millions of 2016$)	ES-13
Table 1-1 Heat Rate Ranges Defining Groups	1-13
Table 1-2 Number of Coal-Fired EGUs >=25MW and Total Capacity (MW) in Each Heat Rate Group Bin. 1-14
Table 1-3 Percent of Total Coal-Fired EGUs >-25MW and Percent of Coal-Fired Total Capacity (MW) in Each
Heat Rate Group Bin	1-15
Table 1-4 S&L Heat Rate Improvements (Percentage) by EGU Size	1-16
Table 1-5 S&L Heat Rate Improvement Costs [2016$/kW] by EGU Size	1-16
Table 1-6 Group Specific Heat Rate Improvements (Percentage)	1-17
Table 1-7 Group Specific Heat Rate Improvement Costs [$2016/kW]	1-18
Table 2-1 Select IPM Results for CPP	2-4
Table 2-2 Projected CO2 Electric Sector Emission Impacts, Relative to Baseline	2-25
Table 2-3 Annualized Compliance Costs, Relative to Baseline (millions of 2016$)	2-25
Table 2-4 2030 Projected Marginal Cost of Mass-Based State-Level CPP Emissions Goals, by State ($/ton CO2)
2-33
Table 2-5 Emissions Projections	2-37
Table 2-6 Annual Compliance Costs (Millions 2016$)	2-37
Table 2-7 Installed Generating Capacity (GW)	2-39
Table 3-1 HRI Cost and Performance Assumptions for Illustrative Policy Scenario, by Unit Capacity and Heat
Rate	3-6
Table 3-2 Years 2023, 2025, 2030, and 2035: Summary of State and Industry Annual Respondent Burden and
Cost of Reporting and Recordkeeping Requirements (million 2016$)	3-10
Table 3-3 Projected CO2 Electric Sector Emission Impacts, Relative to Baseline	3-11
Table 3-4 Projected Electric Sector CO2 Emission Impacts, Relative to 2005	 3-11
Table 3-5 Projected Electric Sector Emissions of SO2, NOx, and Hg	3-12
Table 3-6 Annualized Compliance Costs, Relative to Baseline (millions of 2016$)	3-13
Table 3-7 Total Production Costs (millions of 2016$)	3-14
Table 3-8 Projected CO2 Emissions by Generation Source (MM short tons)	3-15
Table 3-9 Projected SO2 Emissions by Generation Source (thousand short tons)	3-16
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Table 3-10 Projected NOx Emissions by Generation Source (thousand short tons)	3-16
Table 3-11 Projected Hg Emissions by Generation Source (short tons)	3-17
Table 3-12 Projected Generation Mix (thousand GWh)	3-22
Table 3-13 Total Generation Capacity by 2025-2035 (GW)	3-24
Table 3-14 Projected Natural Gas Combined Cycle and Renewable Capacity Additions and Changes Relative to
Baseline	3-25
Table 3-15 2025 Projected Coal Production for the Electric Power Sector (million short tons)	3-25
Table 3-16 2030 Projected Coal Production for the Electric Power Sector (million short tons)	3-25
Table 3-17 2035 Projected Coal Production for the Electric Power Sector (million short tons)	3-26
Table 3-18 Projected Power Sector Gas Use	3-26
Table 3-19 Projected Average Minemouth and Delivered Coal Prices (2016$/MMBtu)	3-26
Table 3-20 Projected Average Henry Hub (spot) and Delivered Natural Gas Prices (2016$/MMBtu)	3-27
Table 3-21 Projected Contiguous U.S. Retail Electricity Prices (cents/kWh), 2025-2035	 3-27
Table 4-1 Interim Domestic Social Cost of CO2, 2015-2050 (in 2016$ per metric ton)3	4-4
Table 4-2 Estimated Domestic Climate Benefits, Relative to Baseline (millions of 2016$)a	4-4
Table 4-3 Projected EGU Emissions of SO2, NOx, and PM2 5a	4-7
Table 4-4 Human Health Effects of Ambient PM2 5 and Ozone	4-18
Table 4-5 Estimated Avoided PM25 and Ozone-Related Premature Deaths and Illnesses in 2025, 2030 & 2035
(95% Confidence Interval)a	4-31
Table 4-6 Estimated Avoided PM-Related Premature Deaths Using Alternative Approaches Using Two
Approaches to Quantifying Avoided PM-Attributable Deaths (95% Confidence Interval) in 2025,
2030 & 2035 a	4-32
Table 4-7 Estimated Economic Value of Avoided PM2 5 and Ozone-Attributable Deaths and Illnesses for the
Illustrative Policy Scenario Using Alternative Approaches to Represent PM2 5 Mortality Risk Effects
(95% Confidence Interval; millions of 2016$)a	4-33
Table 4-8 Estimated Percent of Avoided PM2 5-related Premature Deaths Above and Below PM2 5 Concentration
Cut Points	4-34
Table 4-9 Avoided PM2 5-related Premature Deaths Estimated at Annual Mean PM2 5 Levels Corresponding to
the Air Quality Distribution Observed in the Krewski et al. (2009) American Cancer Society Study. 4-
34
Table 4-10 Estimated Climate Benefits and Ancillary Health Co-Benefits of Illustrative Policy Scenario (millions
of 2016$)	4-36
Table 4-11 Estimated Climate Benefits and Ancillary Health Co-Benefits of Illustrative Policy Scenario, showing
only PM2 5 Related Mortality Risk Benefits above the Lowest Measured Level of Each Long-Term
PM25 Mortality Study (millions of 2016$)	4-37
Table 4-12 Estimated Climate Benefits and Ancillary Health Co-Benefits of Illustrative Policy Scenario, showing
only PM2 5 Related Mortality Risk Benefits above PM2 5 National Ambient Air Quality Standard
(millions of 2016$)	4-37
Table 4-13 Unqualified Ancillary Health and Welfare Co-Benefits Categories	4-39
Table 5-1 Summary of Certain Energy Market Impacts (Percent Change)	5-2
Table 6-1 Compliance Costs for the Illustrative Policy Scenario, 2023-2037 (millions of 2016$)a	6-4
Table 6-2 Present Value and Equivalent Annualized Value of Compliance Costs for the Illustrative Policy
Scenario, 3 and 7 Percent Discount Rates, 2023-2037 (millions of 2016$)	6-5
Table 6-3 Present Value and Equivalent Annualized Value of Compliance Costs, Domestic Climate Benefits,
Ancillary Health Co-Benefits, and Net Benefits, Illustrative Policy Scenario, 3 and 7 Percent Discount
Rates, 2023-2037 (millions of 2016$)	6-6
Table 6-4 Present Value and Equivalent Annualized Value of Compliance Costs, Benefits, and Net Benefits
Associated with Targeted Pollutant (C02), Illustrative Policy Scenario, 3 and 7 Percent Discount
Rates, 2023-2037 (millions of 2016$)	6-8
Table 6-5 Present Value and Equivalent Annualized Value of Compliance Costs, Benefits (Inclusive of Health
Co-Benefits), and Net Benefits, Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-
2037 (millions of 2016$)	6-9
Table 6-6 Present Value and Equivalent Annualized Value of Compliance Costs, Benefits, and Net Benefits
assuming that Mortality Risk PM2 5 Related Benefits Fall to Zero Below the Lowest Measured Level
of Each Long-Term PM2 5 Mortality Study, Illustrative Policy Scenario, 3 and 7 Percent Discount
Rates, 2023-2037 (millions of 2016$)	6-11
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Table 6-7 Present Value and Equivalent Annualized Value of Compliance Costs, Benefits, and Net Benefits
assuming that Mortality Risk PM2 5 Related Benefits Fall to Zero Below the PM2 5 National Ambient
Air Quality Standard, Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
(millions of 2016$)	6-12
Table 8-1 Model Performance Statistics by Region for PM2 5	8-9
Table 8-2 Model Performance Statistics by Region for Ozone on Days Above 60 ppb (May-Sep)	8-10
Table 8-3 Source Apportionment Tags	8-11
Table 8-4 Tribal Fractions by State in the 2023 Emissions	8-21
Table 8-5 Primary PM2 5 Scaling Ratios for EGU tags	8-25
Table 8-6 Sulfate Scaling Ratios for EGU tags	8-26
Table 8-7 Nitrate Scaling Ratios for EGU tags	8-27
Table 8-8 Ozone Scaling Ratios for EGU tags	8-28
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LIST OF FIGURES
Figure 1-1 Distribution of Heat Rates and Unit Groups	1-14
Figure 2-1 U.S. Utility-scale Electric Generating Capacity Retirements (2008-2020), Gigawatts	2-8
Figure 2-2 Net Generation, United States, Electric Utility, Annual (thousand megawatthours)	2-8
Figure 2-3 U.S. Coal Consumption (1950-2018) (million short tons)	2-9
Figure 2-4 U.S. Annual Natural Gas Production (1940-2018) (billion cubic feet per day)	2-10
Figure 2-5 Average Cost of Fossil Fuels for Electricity Generation (per Btu) for All Sectors, Monthly (dollars per
million Btu)	2-10
Figure 2-6 Selected Historical Mean LCOE Values	2-11
Figure 2-7 Power Sector CO2 Emissions (million short tons)	2-15
Figure 2-8 State-Level CO2 Short Tons Emissions Comparison: Baseline Emissions vs. CPP Goals for 2030 2-18
Figure 2-9 State-Level CO2 Short Tons Emissions Comparison: Baseline Emissions in 2025 vs. CPP Goals for
2022	2-19
Figure 2-10 NERC Interconnections	2-22
Figure 2-11 RTO/ISO Regions	2-23
Figure 2-12 CPP Trading Regions: PJM (yellow), Southeast (green), Northeast/RGGI (purple), Midwest/Central
(red), West (blue), and California (orange)	2-24
Figure 2-13 CO2 Emissions for the Midwest/Central Region: Historical and Baseline Projections from IPM
(million short tons)	2-26
Figure 2-14 State-Level CO2 Emissions in the EPA Baseline for 2030, Ordered by Largest Shortfall to Greatest
Surplus Compared to CPP State Goals (thousand short tons)	2-31
Figure 2-15 Generation Mix (GWh)	2-38
Figure 3-1 Projected Distribution of Affected Unit Capacity in 2025, by Heat Rate Group (GW)	3-17
Figure 3-2 Projected Change in CO2 Emissions at Affected Units in 2025, by Heat Rate Group (million short
tons)	3-18
Figure 3-3 Projected Change in SO2 Emissions at Affected Units in 2025, by Heat Rate Group (thousand tons) 3-
18
Figure 3-4 Projected Change in Annual NOx Emissions at Affected Units in 2025, by Heat Rate Group
(thousand tons)	3-19
Figure 3-5 Projected Change in Ozone Season NOx Emissions at Affected Units in 2025, by Heat Rate Group
(thousand tons)	3-19
Figure 3-6 Generation Mix (thousand GWh)	3-23
Figure 4-1 Stylized Relationship between the PM2 5 Concentrations Considered in Epidemiology Studies and our
Confidence in the Estimated PM-related Premature Deaths	4-26
Figure 4-2 Estimated Percentage of PM2 5-Related Deaths and Number of Individuals Exposed by Annual Mean
PM2.5 Level in 2025	4-28
Figure 4-3 Change in Annual Mean PM2 5 (|ig/m3) and Summer Season Average Daily 8hr Maximum Ozone
(ppb) in 2025 (Difference Calculated as Illustrative Policy Scenario minus Baseline)	4-29
Figure 4-4 Avoided PM2.5-related Premature Deaths Estimated at Annual Mean PM2 5 Levels Corresponding to
the Air Quality Distribution Observed in the Krewski et al. (2009) American Cancer Society Study
(ACS)	4-35
Figure 7-1 Frequency Distribution of Interim Domestic SC-C02 Estimates for 2030 (in 2016$ per metric ton
C02)	7-5
Figure 8-1 Air Quality Modeling Domain	8-2
Figure 8-2 NOAA Climate Regions	8-8
Figure 8-3 Map of Pennsylvania Coal EGU Tag Contribution to Seasonal Average MDA8 Ozone (ppb)	8-12
Figure 8-4 Map of Pennsylvania Non-Coal EGU Tag Contribution to Seasonal Average MDA8 Ozone (ppb) 8-13
Figure 8-5 Map of Texas Coal EGU Tag Contribution to Seasonal Average MDA8 Ozone (ppb)	8-13
Figure 8-6 Map of Texas Non-Coal EGU Tag Contribution to Seasonal Average MD A8 Ozone (ppb)	8-14
Figure 8-7 Map of Indiana Coal EGU Tag Contributions to Wintertime Average (January-March) Nitrate
(Hg/m3)	8-15
Figure 8-8 Map of Indiana Coal EGU Tag Contributions to Summertime Average (July-September) Nitrate
(ug/m:)	8-15
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Figure 8-9 Map of Indiana Coal EGU Tag Contributions to Wintertime Average (January-March) Sulfate
(Hg/m3)	8-16
Figure 8-10 Map of Indiana Coal EGU Tag Contributions to Summertime Average (July-September) Sulfate
(Hg/m3)	8-16
Figure 8-11 Map of Indiana Coal EGU Tag Contributions to Wintertime Average (January-March) Primary PM2 5
(Hg/m3)	8-17
Figure 8-12 Map of Indiana Coal EGU Tag Contributions to Summertime Average (July-September) Primary
PM2.5 Oig/m3)	8-17
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EXECUTIVE SUMMARY
ES.l Introduction
In this action, the U.S. Environmental Protection Agency (EPA) is finalizing three
separate and distinct rulemakings. First, the EPA is repealing the Clean Power Plan (CPP)
because the Agency has determined that the CPP exceeded the EPA's statutory authority under
the Clean Air Act (CAA). Second, the EPA is finalizing the Affordable Clean Energy rule
(ACE), consisting of Emission Guidelines for Greenhouse Gas (GHG) Emissions from Existing
Electric Utility Generating Units (EGUs) under CAA section 111(d), that will inform states on
the development, submittal, and implementation of state plans to establish performance standards
for GHG emissions from certain fossil fuel-fired EGUs. In ACE, the Agency is finalizing its
determination that heat rate improvement (HRI) is the best system of emission reduction (BSER)
for reducing GHG—specifically carbon dioxide (CO2)—emissions from existing coal-fired
EGUs. Third, the EPA is finalizing new regulations for the EPA and state implementation of
ACE and any future emission guidelines issued under CAA section 111(d).
This final action is an economically significant regulatory action that was submitted to
the Office for Management and Budget (OMB) for interagency review. Any changes made in
response to interagency review have been documented in the docket. This regulatory impact
analysis (RIA) presents an assessment of the regulatory compliance costs and benefits associated
with this action and is consistent with Executive Orders 12866, 13563, and 13771.
ES.2 Analysis
In this RIA, the Agency provides both an analysis of the repeal of the CPP and a full
benefit-cost analysis of an illustrative policy scenario representing ACE, which models HRI at
coal-fired EGUs.
For the analysis of the repeal of the CPP (described in Chapter 2), the EPA examines a
number of lines of evidence including: several updated Integrated Planning Model (IPM)
scenarios that consider different assumptions regarding implementation of the CPP (including
that states are more likely to participate in interstate trading than previously considered and that
because of the supreme court stay, even if the rule were to be implemented, it would be
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implemented on a significantly delayed time-frame), consideration of the changes the EPA (and
others including the U.S. Energy Information Administration) have seen in CO2 reductions
across similar scenarios run over time, changing circumstances in the power sector (including
fuel prices, technology changes and the age of different portions of the generating fleet) as well
as commitments many power companies have made to significantly reduce CO2 emissions.
Based on this examination, the EPA concludes that even if the CPP were implemented, it would
not achieve emission reductions beyond those that would be achieved in a business-as-usual
projection.
For the ACE analysis, the illustrative policy scenario represents potential outcomes of
state determinations of standards of performance, and compliance with those standards by
affected coal-fired EGUs. ACE is being analyzed as a separate action that occurs only after
repeal of the CPP, therefore the EPA is performing its analysis of ACE against a baseline
without CPP (however as noted above, the EPA does not believe that there would be any
significant differences between a scenario with or without CPP).
The analysis in this RIA relies on EPA's Power Sector Modeling Platform v6 using IPM.
This accounts for changes in the power sector in recent years and projects our best understanding
of important technological and economic trends into the future.
The EPA has identified the BSER to be HRI. In the final Emission Guidelines, the EPA is
providing states with a list of candidate HRI technologies that must be evaluated when
establishing standards of performance. The cost, suitability, and potential improvement for any
of these HRI technologies depends on a range of unit-specific factors such as the size, age, fuel
use, and the operating and maintenance history of the unit. As such, the HRI potential can vary
significantly from unit to unit. The EPA does not have sufficient information to assess HRI
potential on a unit-by-unit basis. 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 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.
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Therefore, any analysis of the ACE rule must be illustrative. Nonetheless, the EPA believes that
such illustrative analysis can provide important insights.
In this RIA, we evaluated an illustrative policy scenario representing the ACE rule that
assumes HRI potential and costs will differ based on unit generating capacity and efficiency (i.e.,
heat rate). To establish categories of units and their assumed HRI potential for the illustrative
policy scenario, we developed a methodology that is explained in Chapter 1. Affected sources
were divided into twelve groups based on three size categories and four efficiency categories. A
representative cost and performance assumption for HRI from the candidate technologies was
identified for each grouping. The group-specific cost and performance assumptions were then
applied to each unit in the group in the illustrative analysis. We then modeled the application of
these assumptions in the power sector which provides a basis for the costs, emissions, and
benefits analyses that illustrate the potential impacts of the final ACE rule.
We evaluated the potential impacts of the illustrative policy scenario using the present
value (PV) of costs, benefits, and net benefits, calculated for the years 2023-2037 from the
perspective of 2016, using both a three percent and seven percent end-of-period discount rate. In
addition, the Agency presents the assessment of costs, benefits, and net benefits for specific
snapshot years, consistent with historic practice. These snapshot years are 2025, 2030, and 2035.
The Agency believes that these specific years are each representative of several
surrounding years, which enables the analysis of costs and benefits over the timeframe of 2025-
2037. The year 2025 is an approximation for when the standards of performance under the final
rule might be implemented, and the Agency estimates that monitoring, reporting, and
recordkeeping (MR&R) costs may begin in 2023. Therefore, MR&R costs analysis is presented
beginning in the year 2023, and full benefit-cost analysis is presented beginning in the year 2025.
The analytical timeframe concludes in 2037, as this is the last year that may be represented with
the analysis conducted for the specific year of 2035.
While the results are described and presented in more detail later in this executive
summary and throughout the RIA, we present the high-level results of the analysis here.
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Table ES-1 provides the PV and equivalent annualized value (EAV) of costs, domestic
climate benefits, ancillary health co-benefits, and net benefits of the illustrative policy scenario
over the timeframe of 2023-2037. The EAV represents a flow of constant annual values that, had
they occurred in each year from 2023 to 2037, would yield an equivalent present value. The
EAV represents the value of a typical cost or benefit for each year of the analysis, in contrast to
the year-specific estimates presented for the snapshot years of 2025, 2030, and 2035.
Table ES-1 Present Value and Equivalent Annualized Value of Compliance Costs,
Domestic Climate Benefits, Ancillary Health Co-Benefits, and Net Benefits,
Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
	(millions of 2016$)	
Domestic	Ancillary
Costs Climate	Health	Net Benefits
Benefits	Co-Benefits
3%
7%
3%
7%
3%
7%
3%
7%
Present
Value
1,600
970
640
62
4,000 to 9,800
2,000 to 5,000
3,000 to 8,800
1,100 to 4,100
Equivalent
Annualized
Value
140
110
53
6.9
330 to 820
220 to 550
250 to 730
120 to 450
Notes: All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
Climate benefits reflect the value of domestic impacts from CO2 emissions changes.
Table ES-2 provides the PV and EAV of costs, benefits, and net benefits associated with
the targeted pollutant, CO2, over the timeframe of 2023-2037. This method of comparing costs to
domestic climate benefits is consistent with how results were presented in the RIA for the ACE
proposal. In this table, negative net benefits are indicated with parentheses.
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Table ES-2
Present Value and Equivalent Annualized Value of Compliance Costs,
Domestic Climate Benefits, and Net Benefits Associated with Targeted
Pollutant (CO2), Illustrative Policy Scenario, 3 and 7 Percent Discount Rates,
2023-2037 (millions of 2016$)	
Costs
Domestic
Climate Benefits
Net Benefits
associated with the
3%
7%
3%
7%
3%
7%
Present Value
1,600
970
640
62
(980)
(910)
Equivalent
Annualized Value
140
110
53
6.9
(82)
(100)
Notes: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, so
figures may not sum due to independent rounding. Climate benefits reflect the value of domestic impacts from CO2
emissions changes. This table does not include estimates of ancillary health co-benefits from changes in electricity
sector SO2 and NOx emissions.
ES.3 Compliance Costs
The power industry's "compliance costs" are represented in this analysis as the change in
electric power generation costs between the baseline and the illustrative policy scenario,
including the cost of monitoring, reporting, and recordkeeping (MR&R). In simple terms, these
costs are an estimate of the additional power industry expenditures required to comply with the
final action, as represented by the illustrative policy scenario, minus the power generation costs
in the baseline. Table ES-3 presents the annualized compliance costs of the illustrative policy
scenario.1 The EPA uses the projection of private compliance costs as an estimate of the total
social cost, which is the appropriate metric for formal economic welfare analysis, of this final
action.
Table ES-3 Compliance Costs of Illustrative Policy Scenario in 2025, 2030, and 2035
	(millions of 2016$)	
Year
Cost
2025
290
2030
280
2035
25
Notes: Compliance costs equal the projected change in total power sector generating costs, plus the costs of
monitoring, reporting, and recordkeeping. All estimates are rounded to two significant figures.
1 This RIA does not identify who ultimately bears the compliance costs, such as owners of generating assets through
changes in their profits or electricity consumers through changes in their bills, although the potential impacts on
consumers and producers are described in Chapter 5.
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ES.4 Emissions Changes
Emissions are projected to be lower under the illustrative policy scenario than under the
baseline, as shown in Table ES-4 and Table ES-5. Table ES-4 shows projected aggregate CO2
emissions relative to the baseline.
Table ES-4 Projected CO2 Emission Impacts of Illustrative Policy Scenario, Relative to
Baseline in 2025, 2030, and 2035

CO2 Emissions
(MM Short Tons)
2025 2030 2035
CO2 Emissions Change
(MM Short Tons)
2025 2030 2035
CO2 Emissions Change
Percent Change
2025 2030 2035
Baseline
Illustrative Policy Scenario
1,774 1,743 1,719
1,762 1,732 1,709
(12) (11) (9.3)
(0.7%) (0.7%) (0.5%)
Table ES-5 shows projected aggregate emissions relative to the baseline for sulfur
dioxide (SO2) and nitrogen oxides (NOx), and mercury (Hg) from the electricity sector.
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Table ES-5 Projected SO2, NOx, and Hg Electricity Sector Emissions of Illustrative
	Policy Scenario in 2025, 2030, and 2035	

Baseline
Illustrative
Emissions
Percent Change

Policy Scenario
Change
from Baseline
SO2 (thousand tons)
2025
912.6
908.5
(4.1)
(0.4%)
2030
885.6
879.9
(5.7)
(0.6%)
2035
817.0
810.6
(6.4)
(0.8%)
NOx (thousand tons)
2025
844.4
837.1
(7.3)
(0.9%)
2030
810.1
803.0
(7.1)
(0.9%)
2035
752.8
746.8
(6.0)
(0.8%)
PM2.5 (thousand tons)
2025
108.7
108.1
(0.6)
(0.6%)
2030
110.1
109.7
(0.4)
(0.4%)
2035
113.0
112.3
(0.7)
(0.6%)
Hg (tons)
2025
4.7
4.7
(0.03)
(0.7%)
2030
4.5
4.4
(0.03)
(0.7%)
2035
4.0
4.0
(0.03)
(0.6%)
Source: Integrated Planning Model, 2018.
Notes: SO2, and NOx reductions are used for estimating the health benefits from reduced particulate matter and
ozone exposures. The SO2 and NOx emissions are direct outputs from the IPM simulations as reported in Chapter 3;
however, the PM2 5 emissions were derived based on IPM-predicted heat rate and other factors as described in
Chapter 8.
ES.5 Climate and Health Co-Benefits
We estimated climate-related impacts from changes in CO2 and the air quality-related
impacts from changes in SO2 and NOx. We refer to climate benefits as "targeted pollutant
benefits" because these are the direct benefits of reducing CO2. We refer to air pollution health
benefits as ancillary "co-benefits" because they result from policies affecting CO2 but are not the
goal of this policy. To estimate the climate benefits associated with changes in CO2 emissions,
we apply a measure of the domestic social cost of carbon (SC-CO2). The SC-CO2 is a metric that
estimates the monetary value of impacts associated with marginal changes in CO2 emissions in
each year. The SC-CO2 estimates used in this RIA account for the direct impacts of climate
change that are anticipated to occur within the United States. As discussed in Chapters 4.3 and 7,
the estimated domestic climate benefits presented for this rule are based on evolving
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methodologies and depend in important respects on assumptions that are uncertain and subject to
further revision with improvements in the science and modeling of climate change impacts.
We performed gridded photochemical air quality modeling to support the air quality
benefits assessment of the ACE rule and quantified the health benefits attributable to changes in
fine particles 2.5 microns and smaller (PM2.5) and ground-level ozone. This modeling accounted
for the current suite of local, state and federal policies expected to reduce PM2.5 and PM2.5
precursor emissions in future years.2 Table ES-6 reports the combined domestic climate benefits
and ancillary health co-benefits attributable to changes in SO2 and NOx emissions, discounted at
three percent and seven percent and presented in 2016 dollars, in the years 2025, 2030 and 2035.
This table reports the air pollution effects calculated using PM2.5 log-linear concentration-
response functions that quantify risk associated with the full range of PM2.5 exposures
experienced by the population (U.S. EPA, 2009; U.S. EPA, 2011; NRC, 2002).3 Nearly all the
PM2.5-related benefits reported for each year occur in locations where the annual mean PM2.5
concentrations are projected to be below the annual PM2.5 standard of 12 |ig/m3.
In general, we are more confident in the size of the risks we estimate from simulated
PM2.5 concentrations that coincide with the bulk of the observed PM concentrations in the
epidemiological studies that are used to estimate the benefits. Likewise, we are less confident in
the risk we estimate from simulated PM2.5 concentrations that fall below the bulk of the observed
data in these studies.4 Furthermore, when setting the 2012 PM NAAQS, the Administrator
acknowledged greater uncertainty in specifying the "magnitude and significance" of PM-related
health risks at PM concentrations below the NAAQS. As noted in the preamble to the 2012 PM
2	Policies expected to impact EGU sector emissions are accounted for out to 2025, 2030, and 2035 future years, but
policies expected to impact other emissions source sectors are only accounted for out to 2023.
3	This approach is consistent with employing a no-threshold assumption for estimating PM2 5-related health effects.
The preamble to the 2012 PM NAAQS noted that "[a]s both the EPA and CASAC recognize, in the absence of a
discernible threshold, health effects may occur over the full range of concentrations observed in the epidemiological
studies." (78 FR 3149, 15 January 2013). This log-linear, no-threshold approach to calculating, valuing and
reporting the avoided number of PM2 5-attributable deaths is consistent with recent RIAs (U.S. EPA 2009b, 2010c,
2010d, 2011a, 2011b, 2011c, 2012, 2013, 2014, 2015a, 2016).
4	The Federal Register Notice for the 2012 PM NAAQS indicates that "[i]n considering this additional population
level information, the Administrator recognizes that, in general, the confidence in the magnitude and significance of
an association identified in a study is strongest at and around the long-term mean concentration for the air quality
distribution, as this represents the part of the distribution in which the data in any given study are generally most
concentrated. She also recognizes that the degree of confidence decreases as one moves towards the lower part of
the distribution."
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NAAQS final rule, in the context of selecting and alternative NAAQS, the "EPA concludes that
it is not appropriate to place as much confidence in the magnitude and significance of the
associations over the lower percentiles of the distribution in each study as at and around the long-
term mean concentration." (78 FR 3154, 15 January 2013).
To give readers insight to the uncertainty in the estimated PM2.5 mortality benefits
occurring at lower ambient levels, we also report the PM benefits excluding benefits below
certain PM2.5 concentration cut-points and concentration-response parameters. The percentage of
estimated PIVh.s-related premature deaths occurring below the lowest measured levels (LML) of
the two long-term epidemiological studies we use to estimate risk varies between 5 percent
(Krewski et al. 2009) and 69 percent (Lepeule et al. 2012). The percentage of estimated
premature deaths occurring above the LML and below the NAAQS ranges between 94 percent
(Krewski et al. 2009) and 31 percent (Lepeule et al. 2012). Less than one percent of the
estimated premature deaths occur above the annual mean PM2.5 NAAQS of 12 |ig/m3. Estimates
of ancillary co-benefits excluding those below the LML and the NAAQS are provided in Chapter
4 and, along with climate benefits, are compared to costs in Chapter 6.
Table ES-6 reports the benefits to society for the illustrative policy scenario.
Table ES-6 Monetized Benefits of Illustrative Policy Scenario in 2025, 2030, and 2035
	(millions of 2016$)	
Discounted at 3%
Discounted at 7%

Domestic
Climate
Benefits
Ancillary Health
Co-Benefits
Total
Benefits
Domestic
Climate
Benefits
Ancillary Health
Co-Benefits
Total
Benefits
2025
81
390 to 970
470 to 1,000
13
360 to 900
370 to 920
2030
81
490 to 1,200
570 to 1,300
14
460 to 1,100
470 to 1,100
2035
72
550 to 1,400
620 to 1,400
13
510 to 1,300
520 to 1,300
Notes: All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
Climate benefits reflect the value of domestic impacts from CO2 emissions changes. The ancillary health co-benefits
reflect the sum of the PM2 5 and ozone benefits from changes in electricity sector PM2 5, SO2 and NOx emissions and
reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to
Lepeule et al. (2012) with Jerrett et al. (2009))
ES.6 Net Benefits
In the decision-making process it is useful to consider the change in benefits due to the
targeted pollutant relative to the costs. Therefore, in Chapter 6 we present a comparison of the
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benefits from the targeted pollutant - CO2 - with the compliance costs.5 Excluded from this
comparison are the co-benefits from changes in PM2.5 and ozone concentrations from changes in
SO2 and NOx, emissions that are projected to accompany changes in CO2 emissions.6
Table ES-7 presents the PV and EAV of the estimated costs, benefits, and net benefits
associated with the targeted pollutant, CO2, for the timeframe of 2023-2037, relative to the
baseline. In Table ES-7, and all net benefit tables, negative net benefits are indicated with
parentheses.
Table ES-7 Present Value and Equivalent Annualized Value of Compliance Costs,
Climate Benefits, and Net Benefits Associated with Targeted Pollutant (CO2),
Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
	(millions of 2016$)	
„ Net Benefits
Domestic . , , ,,
associated with the
Climate Benefits _ . , „ „ . . ,
		 Targeted Pollutant (CO2)
3%
7%
3%
7%
3%
7%
Present Value
1,600
970
640
62
(980)
(910)
Equivalent
Annualized Value
140
110
53
6.9
(82)
(100)
Notes: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, so
figures may not sum due to independent rounding. Climate benefits reflect the value of domestic impacts from CO2
emissions changes. This table does not include estimates of ancillary health co-benefits from changes in electricity
sector PM2.5, SO2 and NOx emissions.
Table ES-8 presents the costs, benefits, and net benefits associated with the targeted
pollutant for the specific snapshot years.
5	While the benefits are limited to the targeted pollutant, the cost as discussed above is the change in generation cost
for the entire power sector plus MR&R costs. The cost reported in Table ES-7 is not limited solely to those costs
that occur at the sources regulated by this final action.
6	When considering whether a regulatory action is a potential welfare improvement (i.e., potential Pareto
improvement) it is necessary to consider all impacts of the action.
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Table ES-8
Compliance Costs, Climate Benefits, and Net Benefits Associated with
Targeted Pollutant (CO2) in 2025, 2030, and 2035, Illustrative Policy
Scenario, 3 and 7 Percent Discount Rates (millions of 2016$)	
Costs
Domestic
Climate Benefits
Net Benefits
associated with the
3%
7%
3%
7%
3%
7%
2025
290
290
81
13
(210)
(280)
2030
280
280
81
14
(200)
(260)
2035
25
25
72
13
47
(11)
Notes: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, so
figures may not sum due to independent rounding. Climate benefits reflect the value of domestic impacts from CO2
emissions changes. This table does not include estimates of ancillary health co-benefits from changes in electricity
sector PM2 5, SO2 and NOx emissions.
Table ES-9 and Table ES-10 provide the estimated costs, benefits, and net benefits,
inclusive of the ancillary health-co benefits. Table ES-9 presents the PV and EAV estimates, and
Table ES-10 presents the estimates for the specific years of 2025, 2030, and 2035.
Table ES-9 Present Value and Equivalent Annualized Value of Compliance Costs, Total
Benefits, and Net Benefits, 2023-2037, Illustrative Policy Scenario, 3 and 7
	Percent Discount Rates (millions of 2016$)	
Costs
Benefits
Net Benefits
3%
7%
3%
7%
3%
7%
Present
Value
1,600
970
4,600 to 10,000
2,100 to 5,000
3,000 to 8,800
1,100 to 4,100
Equivalent
Annualized Value
140
110
390 to 870
230 to 550
250 to 730
120 to 450
Notes: All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
Total benefits include both climate benefits and ancillary health co-benefits. Climate benefits reflect the value of
domestic impacts from CO2 emissions changes. The ancillary health co-benefits reflect the sum of the PM2 5 and
ozone benefits from changes in electricity sector PM2 5, SO2 and NOx emissions and reflect the range based on adult
PM2.5 and ozone mortality functions (i.e., from Krewski el al. (2009) with Smith el al. (2009) to Lepeule el al.
(2012) with Jerrett et al. (2009)).
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Table ES-10 Compliance Costs, Total Benefits, and Net Benefits in 2025, 2030, and 2035,
Illustrative Policy Scenario, 3 and 7 Percent Discount Rates (millions of
	2016$)	
Costs	Benefits	Net Benefits
3%
7%
3%
7%
3%
7%
2025
290
290
470 to 1,000
370 to 920
180 to 760
84 to 630
2030
280
280
570 to 1,300
470 to 1,100
300 to 1,000
200 to 860
2035
25
25
620 to 1,400
520 to 1,300
600 to 1,400
500 to 1,200
Notes: All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
Total benefits include both climate benefits and ancillary health co-benefits. Climate benefits reflect the value of
domestic impacts from CO2 emissions changes. The ancillary health co-benefits reflect the sum of the PM2 5 and
ozone benefits from changes in electricity sector PM2 5, SO2 and NOx emissions and reflect the range based on adult
PM2 5 and ozone mortality functions (i.e., from Krewski el al. (2009) with Smith el al. (2009) to Lepeule el al.
(2012) with Jerrett et al. (2009)).
The EPA typically reports the cost of a rule as the net change in production expenditures
by affected sources as they find the least costly way of complying with the rule (including costs
to states to implement the rule). Changes in compliance costs may arise from net changes in
capital, labor, intermediate inputs, and resources, including fuel, expenses. If prices in related
markets do not change, the sum of these expenditures approximate social cost of the rule to the
extent prices of goods reflect their social opportunity cost. The net change in these expenditures
are borne by consumers and producers as a result of the rule. An alternative presentation of
benefits and costs is to report the change in expenditures on fuels as a benefit, and not as a cost,
regardless of the sign of the change in expenditures on fuels. This accounting approach is
consistent with OMB accounting which is to account for changes in fuel expenditures as a
benefit.
Table ES-11 shows benefits, costs and net benefits where the change in expenditures on
fuels in the illustrative policy scenario is reported as a benefit, and not as a cost. The net-benefits
of the illustrative policy scenario do not change with this alternative presentation. The change in
the fuel expenditures include overall net reductions in expenditures on coal (resulting from
reduced coal use at the affected sources and projected increases and decreases in delivered coal
prices) as well as the net increases and decreases in the expenditures on other fuels in the
electricity sector (e.g., natural gas and uranium) as the sector responds in equilibrium. The costs
are the net changes in expenditures on capital, and fixed and variable O&M, some of which are
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positive and some negative changes depending on the year, as well as MR&R costs. See Table 3-
7 for a detailed breakdown of production costs, including fuel costs.
Table ES-11 Alternative Net Benefits Presentation: Present Value and Equivalent
Annualized Value of Compliance Costs, Total Benefits, and Net Benefits,
2023-2037, Illustrative Policy Scenario, 3 and 7 Percent Discount Rates,
	(millions of 2016$)	
Costs	Benefits	Net Benefits
3%
7%
3%
7%
3%
7%
Present 4 700
Value '
2,700
7,700 to 13,000
3,800 to 6,700
3,000 to 8,800
1,100 to 4,100
Equivalent
Annualized Value
290
650 to 1,100
410 to 740
250 to 730
120 to 450
Notes: All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
This table shows benefits, costs and net benefits where the change in expenditures on fuels in the illustrative policy
scenario is reported as a benefit, and not as a cost. Total benefits include climate benefits, ancillary health co-
benefits, and change in expenditures on fuels. Climate benefits reflect the value of domestic impacts from CO2
emissions changes. The ancillary health co-benefits reflect the sum of the PM2 5 and ozone benefits from changes in
electricity sector PM2 5, SO2 and NOx emissions and reflect the range based on adult PM2 5 and ozone mortality
functions (i.e., from Krewski et al. (2009) with Smith el al. (2009) to Lepeule el al. (2012) with Jerrett et al. (2009)).
ES.7 Economic and Employment Impacts
This final action has energy market implications. Environmental regulation may affect
groups of workers differently, as changes in abatement and other compliance activities cause
labor and other resources to shift. An employment impact analysis describes the characteristics
of groups of workers potentially affected by a regulation, as well as labor market conditions in
affected occupations, industries, and geographic areas. Market and employment impacts of this
final action are discussed in Chapter 5 of this RIA.
ES.8 Limitations and Uncertainty
Throughout this RIA we consider a number of sources of uncertainty, both quantitatively
and qualitatively. We also summarize other potential sources of benefits and costs that may
result from this final action that have not been quantified or monetized. We did not account for
certain benefits and costs including certain omitted benefits and costs from changes in CO2, SO2,
NOx and direct PM2.5, emissions from the electricity sector, from changes in other pollutants
within and outside the electricity sector, and effects outside of the electricity market. These
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limitations, including where possible how they directly may affect estimated benefits and costs,
are summarized below and discussed in more detail throughout the RIA.
There are important impacts that the EPA could not monetize. Due to current data and
modeling limitations, our estimates of the benefit impacts from reducing CO2 emissions do not
include important impacts like ocean acidification or potential tipping points in natural or
managed ecosystems. Ancillary benefits from changing direct exposure to SO2, NOx, as well as
ecosystem changes and visibility impairment, from changes in these pollutants are also omitted.
Changes in the health and ecosystems from changes in mercury from the electricity sector
are not monetized, although increases in mercury emissions are reported in Chapter 3. Potential
changes in other air and water emissions from the electricity sector, including hazardous air
pollutants (e.g., hydrochloric acid) and their associated effects on heath, ecosystems, and
visibility are not quantified. Potential changes in emissions from producing fuels, such as
methane from coal and gas production, are also unaccounted for.
The compliance costs reported in this RIA are not social costs, although in this analysis
we use compliance costs as a proxy for social costs. Changes in costs and benefits due to changes
in economic welfare of suppliers to the electricity market, including workers in the electricity
market and in related markets, and non-electricity consumers from those suppliers (net of
transfers), such as industrial consumers of fossil fuels, are not accounted for. Furthermore, costs
due to interactions with pre-existing market distortions outside the electricity sector are omitted.
Key uncertainties that affect the estimates of benefits and costs of this final regulation
include those that affect costs and emissions from the electricity sector. There is uncertainty in
the availability and cost of the candidate HRI technologies at affected coal-fired EGUs on a unit-
by-unit basis, and the illustrative policy scenario makes assumptions about the availability and
cost of HRI across and within groups of units with similar generating capacity and heat rates.
Furthermore, in the illustrative policy scenario HRI are imposed on units to represent the effect
of potential standards of performance, but the required standards of performance are not
represented in the electricity model directly. Affected sources may have certain flexibilities in
how they comply with the standards of performance that differ from the technologies used to
determine the sources' standards of performance, but this possibility is not captured in the
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illustrative policy scenario. In addition, there is uncertainty in future economic conditions that
could affect fuel supplies, technology costs, and electricity demand in the electricity sector.
The estimated health benefits from changes in PM2.5 and ozone concentrations are subject
to uncertainties related to: (1) the projected future PM2.5 and ozone concentrations; and, (2) the
relationship between air quality changes and health outcomes. For the first uncertainty, which is
discussed in more detail in Chapter 8, we are more confident in the estimated change in annual
mean PM2.5 concentrations than we are in the estimated absolute PM2.5 levels. Consequently, we
are more confident in the estimated total benefits than in sensitivity estimates of benefits over
specific concentration ranges as described in Chapter 4. We address the second uncertainty in
part by quantifying benefits using a range of adult mortality concentration-response relationships
(e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. (2012) with Jerrett et
al. (2009)). The PM2.5 concentration-response models assume that all fine particles, regardless of
their chemical composition, are equally potent in causing premature mortality because the
scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle
type.7 Furthermore, as discussed above, there is greater uncertainty in the effects of exposure at
low PM2.5 levels.
This RIA does not evaluate whether or not there will be any changes in PM attainment
status. However, there are few areas whose attainment status may be affected.8 The extent to
which the monetized health co-benefits and costs reported in this RIA are overestimated or
underestimated partially depends on a variety of federal and state decisions with respect to
NAAQS implementation and compliance, including Prevention of Significant Deterioration
(PSD) requirements.
7 More information on potential uncertainties and assumptions for PM25 benefits is available in OMB's 2017 Draft
Report to Congress on the Benefits and Costs of Federal Regulations and Agency Compliance with the Unfunded
Mandates Reform Act, pg. 13-18.
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ES.9 References
Jerrett, M., Burnett, R.T., Pope, C.A., Ito, K., Thurston, G., Krewski, D., Shi, Y., Calle, E., Thun,
M., 2009. Long-term ozone exposure and mortality. N. Engl. J. Med. 360, 1085-95.
http s://doi.org/10.105 6/NE JMoaO803894
Krewski, D., Jerrett, M., Burnett, R.T., Ma, R., Hughes, E., Shi, Y., Turner, M.C., Pope, C.A.,
Thurston, G., Calle, E.E., Thun, M.J., Beckerman, B., DeLuca, P., Finkelstein, N., Ito, K.,
Moore, D.K., Newbold, K.B., Ramsay, T., Ross, Z., Shin, H., Tempalski, B., 2009.
Extended follow-up and spatial analysis of the American Cancer Society study linking
particulate air pollution and mortality. Res. Rep. Health. Eff Inst. 5-114-36.
Lepeule, J., Laden, F., Dockery, D., Schwartz, J., 2012. Chronic exposure to fine particles and
mortality: an extended follow-up of the Harvard Six Cities study from 1974 to 2009.
Environ. Health Perspect. https://doi.org/10.1289/ehp.1104660
NRC, 2002. Estimating the Public Health Benefits of Proposed Air Pollution Regulations.
Washington, D.C.
Smith, R.L., Xu, B., Switzer, P., 2009. Reassessing the relationship between ozone and short-
term mortality in U.S. urban communities. Inhal. Toxicol. 21 Suppl 2, 37-61.
https://doi.org/10.1080/08958370903161612
U.S. EPA, 2009. Integrated Science Assessment for Particulate Matter. U.S. Environmental
Protection Agency, National Center for Environmental Assessment, Research Triangle
Park, NC.
U.S. EPA, 2011. Policy Assessment for the Review of the Particulate Matter National Ambient
Air Quality Standards. Research Triangle Park, NC.
U.S. EPA, 2015. Regulatory Impact Analysis for the Clean Power Plan Final Rule. EPA-452/R-
15-003. Office of Air Quality Planning and Standards, Health and Environmental Impacts
Division, Research Triangle Park, NC.
U.S. EPA, 2017. Regulatory Impact Analysis for the Review of the Clean Power Plan: Proposal.
EPA-452/R-17-004. Office of Air Quality Planning and Standards, Health and
Environmental Impacts Division, Research Triangle Park, NC
U.S. EPA, 2018. Regulatory Impact Analysis for the Proposed Emission Guidelines for
Greenhouse Gas Emissions from Existing Electric Utility Generating Units; Revisions to
Emission Guideline Implementing Regulations; Revisions to New Source Review
Program. EPA-452/R-18-006. Office of Air Quality Planning and Standards, Health and
Environmental Impacts Division, Research Triangle Park, NC
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CHAPTER 1: INTRODUCTION AND BACKGROUND
1.1	Introduction
In this action, the U.S. Environmental Protection Agency (EPA) is finalizing three
separate and distinct rulemakings. First, the EPA is repealing the Clean Power Plan (CPP)
because the Agency has determined that the CPP exceeded the EPA's statutory authority under
the Clean Air Act (CAA). Second, the EPA is finalizing the Affordable Clean Energy rule
(ACE), consisting of Emission Guidelines for Greenhouse Gas (GHG) Emissions from Existing
Electric Utility Generating Units (EGUs) under CAA section 111(d), that will inform states on
the development, submittal, and implementation of state plans to establish performance standards
for GHG emissions from certain fossil fuel-fired EGUs. In ACE, the Agency is finalizing its
determination that heat rate improvement (HRI) is the best system of emission reduction (BSER)
for reducing GHG—specifically carbon dioxide (CO2)—emissions from existing coal-fired
EGUs. Third, the EPA is finalizing new regulations for the EPA and state implementation of
ACE and any future emission guidelines issued under CAA section 111(d).
In this RIA, the Agency provides both an analysis of the repeal of the CPP and a full
benefit-cost analysis of an illustrative policy scenario representing ACE, which models HRI at
coal-fired EGUs.
This chapter contains background information on this rule, an overview of the regulatory
impact analysis conducted and scenario analyzed, as well as an outline of the chapters in this
report. The EPA's analysis in Chapter 2 satisfies any need for regulatory impact analysis that
may be required by statute or executive order for the repeal of the CPP.
1.2	Legal and Economic Basis for this Rulemaking
1.2.1 Statutory Requirement
Clean Air Act section 111, which Congress enacted as part of the 1970 Clean Air Act
Amendments, establishes mechanisms for controlling emissions of air pollutants from stationary
sources. This provision requires the EPA to promulgate a list of categories of stationary sources
that the Administrator, in his or her judgment, finds "causes, or contributes significantly to, air
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pollution which may reasonably be anticipated to endanger public health or welfare."1 The EPA
has listed more than 60 stationary source categories under this provision.2 Once the EPA lists a
source category, the EPA must, under CAA section 111(b)(1)(B), establish "standards of
performance" for emissions of air pollutants from new sources in the source categories.3 These
standards are known as new source performance standards (NSPS), and they are national
requirements that apply directly to the sources subject to them.
When the EPA establishes NSPS for sources in a source category under CAA section
111(b), the EPA is also required, under CAA section 111(d)(1), to prescribe regulations for states
to submit plans regulating existing sources in that source category for any air pollutant that, in
general, is not regulated under the CAA section 109 requirements for the NAAQS or regulated
under the CAA section 112 requirements for hazardous air pollutants (HAP). CAA section
111(d)'s mechanism for regulating existing sources differs from the one that CAA section 111(b)
provides for new sources because CAA section 111(d) contemplates states submitting plans that
establish "standards of performance" for the affected sources and that contain other measures to
implement and enforce those standards.
"Standards of performance" are defined under CAA section 111(a)(1) as standards for
emissions that reflect the emission limitation achievable from the "best system of emission
reduction," considering costs and other factors, that "the Administrator determines has been
adequately demonstrated." CAA section 111(d)(1) grants states the authority, in applying a
standard of performance, to take into account the source's remaining useful life and other factors.
Under CAA section 111(d), a state must submit its plan to the EPA for approval, and the
EPA must approve the state plan if it is "satisfactory."4 If a state does not submit a plan, or if the
EPA does not approve a state's plan, then the EPA must establish a plan for that state.5 Once a
state receives the EPA's approval of its plan, the provisions in the plan become federally
enforceable against the entity responsible for noncompliance, in the same manner as the
provisions of an approved State Implementation Plan (SIP) under the Act.
1	CAA §111(b)(1)(A).
2	See 40 CFR 60 subparts Cb - OOOO.
3	CAA §111(b)(1)(B), 111(a)(1).
4	CAA section 111(d)(2)(A).
5	CAA section 111(d)(2)(A).
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1.2.2 Market Failure
Many regulations are promulgated to correct market failures, which otherwise lead to a
suboptimal allocation of resources within the free market. Air quality and pollution control
regulations address "negative externalities" whereby the market does not internalize the full
opportunity cost of production borne by society as public goods such as air quality are unpriced.
While recognizing that optimal social level of pollution may not be zero, GHG emissions
impose costs on society, such as negative health and welfare impacts, that are not reflected in the
market price of the goods produced through the polluting process. For this regulatory action the
good produced is electricity. If a fossil fuel-fired electricity producer pollutes the atmosphere
when it generates electricity, this cost will be borne not by the polluting firm but by society as a
whole, thus the producer is imposing a negative externality, or a social cost of emissions. The
equilibrium market price of electricity may fail to incorporate the full opportunity cost to society
of generating electricity. Consequently, absent a regulation on emissions, the EGUs will not
internalize the social cost of emissions and social costs will be higher as a result. This regulation
will work towards addressing this market failure by causing affected EGUs to begin to
internalize the negative externality associated with CO2 emissions.
1.3 Background
1.3.1 Emission Guidelines
This analysis is intended to be an illustrative representation and analysis of the final
ACE rule.6 The final rule presents a framework for states to develop state plans that will establish
standards of performance for existing affected sources of GHG emissions. The final rule does not
itself specify any standard of performance, but rather establishes the "best system of emission
reduction"7 (BSER), i.e. technology for HRI. The HRI that were determined to be the BSER in
this case is a list of six technologies that collectively have been deemed candidate technologies.
States are responsible for applying the BSER to affected EGUs to determine standards of
performance that consider each of the candidate technologies (as they are collectively the
BSER). States may also take into account the remaining useful life and other source-specific
6	For more details on legal authority and justification of this action, see rule preamble.
7	The best system of emission reduction (BSER) informs the definition of "standard of performance" in CAA
111(a); see preamble for further discussion.
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factors in the determination of the standards of performance. It is within the states' discretion for
how to account for these unit specific considerations.
1.3.2	Regulated Pollutant
The purpose of this CAA section 111(d) rule is to address CO2 emissions from fossil
fuel-fired power plants in the U.S. because they are the largest domestic stationary source of
emissions of carbon dioxide (CO2). CO2 is the most prevalent of the greenhouse gases (GHG),
which are air pollutants that the EPA has determined endangers public health and welfare
through their contribution to climate change.
1.3.3	Definition of Affected Sources for the Affordable Clean Energy Rule
As described in the preamble for this action, the EPA is finalizing that a "designated
facility" subject to this regulation is any coal-fired electric utility steam generating unit that is
not an integrated gasification combined cycle (IGCC) unit (i.e., utility boilers, but not IGCC
units) that was in operation or had commenced construction as of August 31, 2018, and that
meets the following criteria. To be a designated facility, a coal-fired electric utility steam
generating unit must serve a generator capable of selling greater than 25 MW to a utility power
distribution system and have a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input
of coal fuel (either alone or in combination with any other fuel).
1.4 Overview of Regulatory Impact Analysis
In accordance with Executive Order 12866, Executive Order 13563, OMB Circular A-4,
and the EPA's Guidelines for Preparing Economic Analyses, the EPA prepared this RIA for this
"significant regulatory action." This action is an economically significant regulatory action
because it 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.8
8 The analysis in this final RIA constitutes the economic assessment required by CAA section 317. In EPA's
judgment, the assessment is as extensive as practicable taking into account EPA's time, resources, and other duties
and authorities.
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In this RIA, the Agency provides both an analysis of the repeal of the CPP and a full
benefit cost analysis of an illustrative policy scenario representing the final ACE rule, which
models HRI at coal-fired EGUs.
For the analysis of the repeal of CPP (described in Chapter 2), the EPA examines a
number of lines of evidence including: 1) several updated IPM modeling scenarios that consider
different assumptions regarding implementation of the CPP (including that states are more likely
to participate in interstate trading than previously analyzed, and that the Supreme Court stay
leads to a delayed implementation of CPP), 2) consideration of the changes the EPA (and others,
including EIA) have seen in CO2 emissions across similar modeled scenarios and projections
over time, 3) changing circumstances in the power sector (including fuel prices, technology
changes and the age of different portions of the generating fleet), and 4) commitments many
power companies have made to significantly reduce CO2 emissions. Based on this examination,
the EPA concludes that even if the CPP were implemented it would not achieve emission
reductions beyond those that would be achieved without the CPP in place.
For the ACE analysis, the illustrative policy scenario represents potential outcomes of
state determinations of standards of performance, and compliance with those standards by
affected coal-fired EGUs. Because ACE is being analyzed as a separate action that occurs only
after repeal of the CPP, the EPA is performing its analysis of ACE against a baseline without
CPP (however as noted above, the EPA does not believe that there would be any significant
differences between a scenario with or without CPP).
The illustrative policy scenario represents potential outcomes of state determinations of
standards of performance, and compliance with those standards by affected coal-fired EGUs.
This RIA has an updated representation of the expected future economic conditions affecting the
electricity sector in the baseline from the proposed ACE rule. This RIA also reports the impact of
climate benefits from changes in CO2 and the impact on ancillary health benefits attributable to
changes in SO2 and NOx emissions.
Additionally, this RIA includes information about potential impacts of the final rule on
electricity markets, employment, and markets outside the electricity sector. The RIA also
presents discussion of the uncertainties and limitations of the analysis.
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1.4.1 Baseline
The analysis relies on the EPA's Power Sector Modeling Platform v6 using the Integrated
Planning Model (IPM).9 This accounts for changes in the power sector in recent years and
projects our best understanding of important technological and economic trends into the future.
The U.S. electric power sector has become less carbon intensive over the past several years, and
this trend is projected to continue in the future, as documented in Chapters 2 and 3 of this RIA.
These changes and trends are reflected in the modeling used for this analysis. As described
earlier, the EPA is performing its analysis of ACE against a baseline without the CPP because
ACE is being analyzed as a separate action that occurs only after repeal of the CPP.
Because air quality modeling was used to determine health benefits from changes in
particulate matter and ozone concentrations that may occur because of this rule, the baseline
includes emissions from all sources. Consequently, in addition to rules and economic conditions
included in the IPM Reference Case, the baseline for this analysis included emissions from, and
rules for, non-EGU point sources, on-road vehicles, non-road mobile equipment and marine
vessels.10 Additional information on what is included in the air quality modeling inventory is
detailed in Chapter 4 and Chapter 8.
This analysis reflects the best data available to the EPA at the time it was conducted. As
with any modeling of future projections, many of the inputs are uncertain. In this context, notable
uncertainties include the cost of fuels, the cost to operate existing power plants, the cost to
construct and operate new power plants, infrastructure, demand, and policies affecting the
electric power sector. The modeling conducted for this RIA is based on estimates of these
variables, which were derived from the data currently available to the EPA. However, future
realizations of these characteristics may deviate from expectations. The results of counterfactual
simulations presented in this RIA are not a prediction of what will happen, but rather projections
of a plausible scenario describing how this final regulatory action may affect electricity sector
9	For documentation, see https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling
10	Using the air quality modeling techniques in this RIA, the impacts of these non-EGU rules are determined as of
2023, so any implementation or effects expected to occur after 2023 are not accounted for in this RIA. However, the
effect of non-EGU emissions on changes in pollution concentrations due to changes in emissions in the electricity
sector between the baseline and the illustrative policy scenario is likely small.
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outcomes in the absence of unexpected shocks. The results of this RIA should be viewed in that
context.
1.4.2	BSER and Illustrative Policy Scenario
The illustrative policy scenario models HRIs applied at affected coal-fired EGUs in the
contiguous U.S. beginning in 2025. The EPA has identified the BSER to be HRI. In the final
Emission Guidelines, the EPA provides states with a list of candidate HRI technologies that must
be evaluated when establishing standards of performance. The cost, suitability, and potential
improvement for any of these HRI technologies is dependent on a range of unit-specific factors
such as the size, age, fuel use, and the operating and maintenance history of the unit. As such, the
HRI potential can vary significantly from unit to unit. The EPA does not have sufficient
information to assess HRI potential on a unit-by-unit basis. CAA 111(d) also provides states with
the responsibility to establish standards of performance and provides considerable flexibility in
the establishment of those emission standards. States may take many factors into consideration -
including among other factors, the remaining useful life of the affected source - when applying
the standards of performance.11 Therefore, any analysis of the final rule is illustrative. However,
the EPA believes that such illustrative analyses can provide important insights at the national
level and can inform the public on a range of potential outcomes. Additional information
describing the analytical basis for the illustrative policy scenario is provide in Section 1.6.
1.4.3	Years of Analysis
We evaluate the potential regulatory impacts of the illustrative policy scenario using the
present value (PV) of costs, benefits, and net benefits, calculated for the years 2023-2037 from
the perspective of 2016, using both a three percent and seven percent end-of-period discount rate.
In addition, the Agency presents the assessment of costs, benefits, and net benefits for specific
snapshot years, consistent with historic practice. In this RIA, the regulatory impacts are
evaluated for the specific years of 2025, 2030, and 2035.
The Agency believes that these specific years are each representative of several
surrounding years, which enables the analysis of costs and benefits over the timeframe of 2025-
11 See Section III of the preamble for a discussion of factors that states may consider in establishing a standard of
performance in response to this emission guideline.
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2037. The year 2025 is an approximation for when the standards of performance under the final
rule might be implemented, and the Agency estimates that monitoring, reporting, and
recordkeeping (MR&R) costs may begin in 2023. Therefore, MR&R costs analysis is presented
beginning in the year 2023, and full benefit cost analysis is presented beginning in the year 2025.
The analytical timeframe concludes in 2037, as this is the last year that may be represented with
the analysis conducted for the specific year of 2035.
1.5 BSER Technologies
The list of candidate technologies that constitute the BSER are summarized below and
are described in greater detail in Section III of the preamble.
1.5.1 Neural Network/Intelligent Sootblower
1.5.1.1	Neural Networks
Computer models, known as neural networks, can be used to simulate the performance of
the power plant at various operating loads. Typically, the neural network system ties into the
plant's distributed control system for data input (process monitoring) and process control. The
system uses plant specific modeling and control modules to optimize the unit's operation and
minimize the emissions. This model predictive control can be particularly effective at improving
the plants performance and minimizing emissions during periods of rapid load changes. The
neural network can be used to optimize combustion conditions, steam temperatures, and air
pollution control equipment.
1.5.1.2	Intelligent Sootblowers
During operations at a coal-fired power plant, particulate matter (PM) (ash or soot) builds
up on heat transfer surfaces. This build-up degrades the performance of the heat transfer
equipment and negatively affects the efficiency of the plant. Power plant operators use steam
injection "sootblowers" to clean the heat transfer surfaces by removing the ash build-up. This is
often done on a routine basis or as needed based on monitored operating characteristics.
Intelligent sootblowers (ISB) are automated systems that use process measurements to monitor
the heat transfer performance and strategically allocate steam to specific areas to remove ash
buildup.
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The cost to implement an ISB system is relatively inexpensive if the necessary hardware
is already installed. The ISB software/control system is often incorporated into the neural
network software package mentioned above. As such, the HRIs obtained via installation of
neural network and ISB systems are not necessarily cumulative.
1.5.2	Boiler Feed Pumps
A boiler feed pump (or boiler feedwater pump) is a device used to pump feedwater into a
boiler. The water may be either freshly supplied or returning condensate produced from
condensing steam produced by the boiler. The boiler feed pumps consume a large fraction of the
auxiliary power used internally within a power plant. Boiler feed pumps can require power in
excess of 10 MW on a 500-MW power plant. Therefore, the maintenance on these pumps should
be rigorous to ensure both reliability and high-efficiency operation. Boiler feed pumps wear over
time and subsequently operate below the original design efficiency. The most pragmatic remedy
is to rebuild a boiler feed pump in an overhaul or upgrade.
1.5.3	Air Heater and Duct Leakage Control
The air pre-heater is a device that recovers heat from the flue gas for use in pre-heating
the incoming combustion air, and potentially for other uses such as coal drying. Properly
operating air pre-heaters play a significant role in the overall efficiency of a coal-fired EGU. The
air pre-heater may be regenerative (rotary) or recuperative (tubular or plate). A major difficulty
associated with the use of regenerative air pre-heaters is air in-leakage from the combustion air
side to the flue gas side. Air in-leakage affects boiler efficiency due to lost heat recovery and
affects the axillary load since any in-leakage requires additional fan capacity. The amount of air
leaking past the seals tends to increase as the unit ages. Improvements to seals on regenerative
air pre-heaters have enabled the reduction of air in-leakage.
1.5.4	Variable Frequency Drives (VFDs)
1.5.4.1 VFD on Induced Draft (ID) Fans
The increased pressure required to maintain proper flue gas flow through downstream air
pollutant control equipment may require additional fan power, which can be achieved by an ID
fan upgrade/replacement or an added booster fan. Generally, older power plant facilities were
designed and built with centrifugal fans.
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The most precise and energy-efficient method of flue gas flow control is use of VFD. The
VFD controls fan speed electrically by using a static controllable rectifier (thyristor) to control
frequency and voltage and, thereby, the fan speed. The VFD enables very precise and accurate
speed control with an almost instantaneous response to control signals. The VFD controller
enables highly efficient fan performance at almost all percentages of flow turndown. Due to
current electricity market conditions, many units no longer operate at base-load capacity and,
therefore, VFDs, also known as variable-speed drives on fans can greatly enhance plant
performance at off-peak loads.
1.5.4.2 VFD on Boiler Feed Pumps
VFDs can also be used on boiler feed water pumps as mentioned previously. Generally, if
a unit with an older steam turbine is rated below 350 MW, the use of motor-driven boiler
feedwater pumps as the main drivers may be considered practical from an efficiency standpoint.
If a unit cycles frequently then operation of the pumps with VFDs will offer the best results on
heat rate reductions, followed by fluid couplings. The use of VFDs for boiler feed pumps is
becoming more common in the industry for larger units. And with the advancements in low
pressure steam turbines, a motor-driven feed pump can improve the thermal performance of a
system up to the 600-MW range, as compared to the performance associated with the use of
turbine drive pumps. Smaller and older units will generally not upgrade to a VFD boiler feed
pump drive due to high capital costs.
1.5.5 Blade Path Upgrade (Steam Turbine)
Upgrades or overhauls of steam turbines offer the greatest opportunity for HRI on many
units. Significant increases in performance can be gained from turbine upgrades when plants
experience problems such as steam leakages or blade erosion. The typical turbine upgrade
depends on the history of the turbine itself and its overall performance. The upgrade can entail
myriad improvements, all of which affect the performance and associated costs. The availability
of advanced design tools, such as computational fluid dynamics (CFD), coupled with improved
materials of construction and machining and fabrication capabilities have significantly enhanced
the efficiency of modern turbines. These improvements in new turbines can also be utilized to
improve the efficiency of older steam turbines whose efficiency has degraded over time.
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1.5.6	Redesign/Replace Economizer
In steam power plants, economizers are heat exchange devices used to capture waste heat
from boiler flue gas which is then used to heat the boiler feedwater. This use of waste heat
reduces the need to use extracted energy from the system and, therefore, improves the overall
efficiency or heat rate of the unit. As with most other heat transfer devices, the performance of
the economizer will degrade with time and use, and power plant representatives contend that
economizer replacements are often delayed or avoided due to concerns about triggering NSR. In
some cases, economizer replacement projects have been undertaken concurrently with retrofit
installation of selective catalytic reduction (SCR) systems because the entrance temperature for
the SCR unit must be controlled to a specific range.
1.5.7	Additional Documentation
Government agencies and laboratories, industry research organizations, engineering
firms, equipment suppliers, and environmental organizations have conducted studies examining
the potential for improving heat rate in the U.S. EGU fleet or a subset of the fleet. Section III of
the preamble provides a list of some reports, case studies, and analyses of these HRI
technologies that are BSER, as well as those that are not BSER, in the U.S.
1.6 Development of Illustrative Policy Scenario
1.6.1 Introduction
The illustrative policy scenario, which represents the ACE rule, is based on a bottom-up
analyses of fleet-wide HRI potential by identifying HRI technologies that may be available to
certain categories of coal-fired EGUs.12 In the analyses, the EPA considered how the available
HRI measures that are included in the BSER list of candidate technologies may apply to these
categories. This approach defined a set of 12 bins for coal steam units that were then linked to
12 This methodology is similar to the bottom-up approach used by the Energy Information Administration (EIA,
2015) to identify the possible HRI available at different categories of coal-fired units. However, the suite of HRI
technologies, and their associated costs and performance, represented in the EIA study differ from those used here.
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potential HRIs based on technologies presented in the Sargent & Lundy (S&L) report13 and
discussed above as BSER for the final ACE rule.14
1.6.2 Grouping EGUs by Performance
The fleet of coal-fired EGU with greater than 25 MW of capacity - defined in the units in
the NEEDS_v6 database15 (September 2018 revision) that are not retiring by 2021 - was rank-
ordered by heat rate from most efficient (i.e., lowest heat rate) to least efficient (i.e., highest heat
rate).16 The NEEDS database contains the generation unit records used to construct the "model"
plants that represent existing and planned/committed units in the EPA modeling applications of
IPM. The fleet was then divided into four groups using a methodology described below and
referred to as Group 1 through Group 4. Group 1 represents the most efficient units in the fleet.
Those units are assumed to have little to no potential for further HRI applying the BSER
technologies. Group 4 represents the least efficient units in the fleet and those units are assumed
to have the most opportunity for HRI applying these technologies. Groups 2 and 3 represent the
remaining units and are assumed to have intermediate opportunities for HRI.
Specifically, we defined the groups using a capacity weighted heat rate distribution for
the fleet. Group 1 was defined as units with a heat rate one capacity weighted standard deviation
below the capacity weighted mean heat rate and Group 4 was defined as units with a heat rate
one capacity weighted standard deviation above the capacity weighted mean heat rate. Groups 2
and 3 were defined as units within one capacity weighted standard deviation below and above
the capacity weighted mean heat rate, respectively. The capacity weighted mean heat rate,
across the N coal steam units in the fleet is defined as
13	"Coal-Fired Power Plant Heat Rate Reductions" Sargent & Lundy Report SL-009597 (2009); available in the
rulemaking docket at EPA-HQ-OAR-2017-0355-21171.
14	For more information, see 83 FR 44746; Table 1 and Table 2.
15	National Electric Energy Data System, NEEDS v6, available in the rulemaking docket at EPA-HQ-OAR-2017-
0355-21141; available on-line at https://www.epa.gov/airmarkets/national-electric-energy-data-system-needs-v6.
16	The heat rates for the model plants in EPA Platform v6 are based on values from Annual Energy Outlook
2017 informed by fuel use and net generation data reported on Form EIA-923. For further explanation see IPM
documentation: https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling
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h... =-
ZCA
;'=!
N
2>.
hj is the heat rate for unit I and C(. is the capacity (in megawatts, MW). The weighted
standard deviation, Sw, is defined as
s... =


N
Based on these definitions and the approach for defining the groups, the heat rate cutoffs
for the four groups are presented below in Table 1-1 and the distribution of capacity across heat
rates and groups is presented in Figure 1-1.
Table 1-1 Heat Rate Ranges Defining Groups
Heat Rate Range [Btu/kWh]
Group 1 (Most Efficient)
< 9,773
Group 2
9,774 - 10,396
Group 3
10,397- 11,019
Group 4 (Least Efficient)
> 11,020
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30000-
o
03
$ 20000-
10000-
o-
Group 4
Group 3
Heat Rate [Btu/kWh]
Figure 1-1 Distribution of Heat Rates and Unit Groups
The units were further divided in each group according to amount of generating capacity
consistent with ranges presented in the proposal for the ACE rule.17 The breakdown of units - the
number of EGUs and the total capacity (MW) - in each of the 12 bins is shown in Table 1-2. The
breakdown of units - the percent of total units and the percent of total capacity - is provided in
Table 1-3.
Table 1-2 Number of Coal-Fired EGUs >=25MW and Total Capacity (MW) in Each
	Heat Rate Group Bin	
< 200 MW
200 - 500 MW
> 500 MW
Group 1	4 EGUs (130 MW)	6 EGUs (2,226 MW)	31 EGUs (23,225 MW)
Group 2	12 EGUs (1,827 MW)	45 EGUs (16,161 MW)	113 EGUs (82,203 MW)
Group 3	61 EGUs (8,232 MW)	86 EGUs (29,430 MW)	48 EGUs (29,259 MW)
Group 4	101 EGUs (8,877 MW)	48 EGUs (15,372 MW)	11 EGUs (7,549 MW)
Note: Source data is from National Electric Energy Data System, NEEDS_v6
17 For more information, see 83 FR 44746; Table 1 and Table 2.
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Table 1-3 Percent of Total Coal-Fired EGUs >-25MW and Percent of Coal-Fired Total
	Capacity (MW) in Each Heat Rate Group Bin	
< 200 MW
200 - 500 MW
> 500 MW
Group 1
Group 2
Group 3
Group 4
l%/< 1 %
2 % / 1 %
11 % / 4 %
18%/ 4%
1 % / 1 %
8%/7%
15%/ 13%
9%/7%
6%/10%
20 % / 37 %
9%/13%
2%/3%
1.6.3 Heat Rate and Cost for each Bin
While many potential HRI measures have been identified, some of those identified
technologies have limited applicability and many provide only negligible HRI.18 The EPA stated
in the ACE proposal that evaluation of the entire list of potential HRI options - including those
with limited applicability and with negligible benefits - may be overly burdensome to the states.
Therefore, the EPA identified and proposed a list of the "most impactful" HRI technologies,
equipment upgrades and best operating and maintenance practices that form the list of "candidate
technologies" constituting the BSER. Those technologies were ones that the EPA determined to
provide meaningful HRI opportunity, to be broadly applicable, and to be implementable at
reasonable cost and are being finalized as BSER in this rule.
Based on the S&L report, the potential ranges of HRI for these technologies are presented
in Table 1-4 and the ranges of costs (updated to $2016) for those improvements are presented in
Table 1-5. These are the six HRI "candidate technologies" identified as BSER in the proposed
ACE rule and are the six technologies that are identified as BSER in the final ACE rule. The first
four HRI options listed in each table are assumed to be broadly available. The last two HRI
options - "Blade Path Upgrade (Steam Turbine)" and "Redesign/Replace Economizer" - are
technologies that, based on program experience and industry comments, are assumed to be more
likely to trigger additional secondary costs including costs associated with NSR permitting. With
these and other additional costs, the remaining useful life of the facilities may be reduced such
that we assume that these two technologies are less likely to be implemented. This is consistent
with assumptions provided in cost and impact analyses supporting the ACE rule proposal.
18 For more information, see Table 3 in 82 FR 61515.
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Table 1-4 S&L Heat Rate Improvements (Percentage) by EGU Size

< 200 MW
200-
500 MW
> 500 MW

Min
Max
Min
Max
Min
Max
Neural Network/Intelligent Sootblowers
0.5
1.4
0.3
1.0
0.3
0.9
Boiler Feed Pumps
0.2
0.5
0.2
0.5
0.2
0.5
Air Heater & Duct Leakage Control
0.1
0.4
0.1
0.4
0.1
0.4
Variable Frequency Drives
0.2
0.9
0.2
1.0
0.2
1.0
Subtotal
1.0
3.2
0.8
2.9
0.8
2.8
Blade Path Upgrade (Steam Turbine)
0.9
2.7
1.0
2.9
1.0
2.9
Redesign/Replace Economizer
0.5
0.9
0.5
1.0
0.5
1.0
Total
2.4
6.8
2.3
6.8
2.3
6.7
Table 1-5 S&L Heat Rate Improvement Costs [2016$/kWl by EGU Size

< 200 MW
200-
500 MW
> 500 MW

Min
Max
Min
Max
Min
Max
Neural Network/Intelligent Sootblowers
4.7
4.7
2.5
2.5
1.4
1.4
Boiler Feed Pumps
1.4
2.0
1.1
1.3
0.9
1.0
Air Heater & Duct Leakage Control
3.6
4.7
2.51
2.7
2.1
2.4
Variable Frequency Drives
9.1
11.9
7.2
9.4
6.6
7.9
Subtotal
18.8
23.3
13.3
15.9
11.0
12.7
Blade Path Upgrade (Steam Turbine)
11.2
66.9
8.9
44.6
6.2
31.0
Redesign/Replace Economizer
13.1
18.7
10.5
12.7
10.0
11.2
Total
43.1
108.9
32.7
73.2
27.2
54.9
The EGUs in Group 1 are the most efficient units in the fleet and for the purposes of
modelling the illustrative policy scenario were assumed to have no opportunities to implement
any of the candidate technologies to improve their performance {i.e., these units are assumed to
be very well maintained and to have already implemented available HRI technologies). The
EGUs in Groups 2 and 3 are the mid-range units and were assumed to implement the first four
HRIs in Table 1-4. The units in Group 2 were assumed to achieve the minimum HRI in the range
while the units in Group 3 were assumed to make the same improvements but to achieve the
midpoint of the range in available HRI (in percent). The EGUs in Group 4 are the least efficient
units. Those EGUs were assumed to make the same four HRIs as the units in Groups 2 and 3 but
were assumed to achieve the maximum improvement within the range. None of the Groups were
assumed to adopt the last two HRIs as it was assumed (based on industry comments) that they
1-16

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are less likely to be installed to the extent they could trigger NSR permitting affecting remaining
useful life,19 as noted above.
Note that these assumptions regarding implementation and cost of HRI at particular
EGUs are illustrative and are only intended as a means of providing a reasonable estimate of the
possible costs, benefits and impacts for the final ACE rule. The assumptions are not intended to
imply applicability of any specific improvement measure at any specific type of EGU. The EPA
has limited information on the specific HRI options that may or may not be implemented at any
specific EGU. In developing their implementing plans, the states will evaluate the applicability
of each of the HRI options provided in Table 1-4 to each EGU within their borders and
determine a unit-specific emission standard based on implementation of those technologies
which represent the BSER.
Once the EGUs were ranked and grouped according to the heat rate, each of the four
resulting groups was further divided into three bins based on size in megawatts (MW) - resulting
in 12 total bins. Given these assumptions the HRI potential by group and size are presented in
Table 1-6. These assumed HRI potentials serve as inputs for the IPM modelling.
Table 1-6 Group Specific Heat Rate Improvements (Percentage)

< 200 MW
200 - 500 MW
> 500 MW
Group 1
0.0
0.0
0.0
Group 2
1.0
0.8
0.8
Group 3
2.1
1.9
1.8
Group 4
3.2
2.9
2.8
Independent of the group it was assumed that the HRI costs are defined by the maximum
value within the given size range. Several commenters noted that the improved performance
obtained from investment in HRI measures will degrade over time and that the EGUs will have
to reinvest to maintain the level of performance. The lifetime of these HRIs was assumed to be
approximately 8 years {i.e., it was assumed that the units would need to reinvest in additional
HRI at least once during the 2025-2037 timeframe in which costs are considered in this RIA).
19The EPA is not finalizing proposed changes to the New Source Review program in the final ACE rulemaking. If
the EPA decides to finalize changes to the NSR program, it will be done in a subsequent rulemaking action and
these modelling assumptions will be revisited at that time.
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The EPA conservatively assumed that all HRI technologies are implemented at the higher end of
the ranges presented in Table 1-5. The EPA also assumed that the costs are doubled as a way of
representing reinvestment over time to account for performance degradation. The total costs
associated with the HRIs (initial investment and a one-time reinvestment) are given in Table 1-7.
These assumed HRI costs serve as inputs for the IPM modelling. That is, each unit within a
group is assumed to incur the same percentage HRI and associated cost per kW as reported in
Tables 1-6 and 1-7 as all other units in that group.
Table 1-7 Group Specific Heat Rate Improvement Costs [$2016/kWl

< 200 MW
200 - 500 MW
> 500 MW
Group 1
0.0
0.0
0.0
Group 2
47.0
32.0
25.0
Group 3
47.0
32.0
25.0
Group 4
47.0
32.0
25.0
In the illustrative policy scenario the average capacity-weighted HRI is 1.5 percent with
an average cost of $29/kW (for those units assumed to implement HRIs, i.e., Groups 2 - 4). The
most comparable illustrative policy scenario presented in the ACE proposal assumed a fleetwide
HRI of 2 percent at a cost of $50/kW.20 That illustrative policy scenario also assumed lower HRI
opportunity without changes to the NSR program.
1.6.4 How HRI are Represented in the Illustrative Policy Scenario
As discussed above, the final rule requires states to develop standards of performance
based on the BSER, which the EPA has determined to be HRI at existing EGUs. Conceptually,
the illustrative policy scenario presumes required standards of performance that are established
by the states and assume an approach for how each affected source complies with its standard of
performance (and associated cost of that approach per kW of installed capacity). However, the
standards of performance are not represented in the model directly and, as discussed above, are
uncertain because the applicability of these HRI technologies across the fleet and the standards
20 The 2 percent HRI improvement and $50/kW was applied uniformly to each coal-fired EGU >=25 MW capacity.
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of performance the states will require are uncertain.21 In practice, affected sources may have
certain flexibilities in how they comply with the standards of performance that differ from the
technologies used to determine the sources' standards of performance, but this possibility is not
captured in the modeling for this RIA. For ease of modeling, in the illustrative policy scenario,
sources may adopt the assumed HRI level or may retire in the model, based on prevailing
economics. However, it is possible that States may use opportunities afforded to them in the final
rule when setting standards of performance that will vary based on source-specific factors, and
the illustrative policy scenario does not capture this possibility. A discussion of establishing
standards of performance by states can be found in section III.F.l. of the preamble.
The illustrative policy scenario reflects technology improvements applied to groups of
coal-fired units based upon unit size and efficiency. Again, it is important to note that current
data limitations hinder our ability to apply more customized HRI and cost functions to specific
units. Due to these limitations, as described above the EPA used the best available information,
research, and analysis to arrive at the assumptions used in the illustrative policy scenario.
1.7 Organization of the Regulatory Impact Analysis
This report presents the EPA's analysis of the potential costs, benefits, and other
economic effects of the final action to fulfill the requirements of an RIA. This RIA includes the
following chapters:
Chapter 2, Impacts of the Repeal of the CPP
Chapter 3, Costs, Emissions, Economic, and Energy Impacts
Chapter 4, Estimated Forgone Climate Benefits and Forgone Human Health Co-Benefits
Chapter 5, Economic and Employment Impacts
Chapter 6, Comparison of Benefits and Costs
Chapter 7, Appendix - Uncertainty Associated with Estimating the Social Cost of Carbon
Chapter 8, Appendix - Air Quality Modeling
21 Note that, in the modeling, the total cost of the HRI is reflected as a capital cost. However, for some HRI
technologies, a small share of the total cost may be variable, and thus might have a small effect on dispatch
decisions.
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1.8 References
40 CFR Chapter I [EPA-HQ-OAR-2009-0171; FRL-9091-8] RIN 2060-ZA14,
"Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section
202(a) of the Clean Air Act," Federal Register / Vol. 74, No. 239 / Tuesday, December
15, 2009 / Rules and Regulations.
U.S. Energy Information Administration (EIA), "Analysis of Heat Rate Improvement Potential at
Coal-Fired Power Plants", May 2015.
U.S. Environmental Protection Agency (EPA). 2018. Regulatory Impact Analysis for the
Proposed Emission Guidelines for Greenhouse Gas Emissions from Existing Electric
Utility Generating Units; Revisions to Emission Guideline Implementing Regulations;
Revisions to New Source Review Program. EPA-452/R-18-006. Office of Air Quality
Planning and Standards, Health and Environmental Impacts Division, Research Triangle
Park, NC.
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CHAPTER 2: IMPACTS OF THE REPEAL OF THE CPP
2.1 Introduction
As the EPA explained in the preamble, the repeal of the Clean Power Plan (CPP) and the
promulgation of a new set of 111(d) guidelines are two separate actions. Consistent with that
position, the EPA is providing a separate analysis of both actions in this RIA. The bulk of the
RIA focuses on an analysis of the ACE rule against a baseline that does not include the CPP.
This is because the ACE action only occurs after the repeal of the CPP.
This chapter presents EPA's analysis of the CPP repeal. It explains how after reviewing
the comments, the EPA ultimately concluded that while deregulatory in nature and important to
address the overreach of the CPP, fully considering a number of factors, the most likely result of
implementation of the CPP would be no change in emissions and therefore no cost savings or
changes in health disbenefits relative to a world without the CPP. This conclusion (i.e., that
repeal of the CPP has no effect against a baseline that includes the CPP) - is appropriate for
several reasons, consistent with OMB's guidance that the baseline for analysis "should be the
best assessment of the way the world would look absent the proposed action."1 It is the EPA's
consideration of the weight of the evidence, taking into account the totality of the available
information, as presented below, that leads to the finding and conclusion that there is likely to be
no difference between a world where the CPP is implemented and one where it is not. As further
explained in this section, the EPA comes to this conclusion not through the use of a single
analytical scenario or modeling alone, but rather through the weight of evidence that includes:
several IPM scenarios that explore a range of changes to assumptions about implementation of
the CPP, consideration of the ongoing evolution and change of the electric sector, and recent
commitments by many utilities that include long-term CO2 reductions across the EGU fleet.
Setting aside the Agency's position that the CPP is an unlawful exercise of authority
under section 111(d), the rule would have little or no impact regardless of the outcome of the
petitions for judicial review of the CPP. The EPA has conducted several IPM modeling scenarios
of CPP that demonstrate there is likely to be little or no difference between a future scenario with
1 OMB circular A-4, at 15.
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the CPP and one without it. To establish this, the EPA conducted updated modeling for three
CPP implementation scenarios, and also considered the most up-to-date information about the
electric sector that is not yet incorporated into the EPA's modeling. The EPA first modeled the
CPP under one of its previous implementation assumptions—i.e., with mass-based compliance
beginning in 2022 and no interstate trading, primarily for consistency purposes. This modeling
shows the CPP is "non-binding" in more than half of the states even under these conservative
assumptions. That is, the CPP does not require additional CO2 emission reductions beyond the
baseline (for many states) and thus does not "bind" affected sources to an emission reduction
requirement in the sense of driving further emission-reducing actions.
However, these implementation assumptions for the CPP no longer reflect reasonable
expectations regarding how the CPP hypothetically would be implemented. As explained below,
the EPA does not believe implementation of CPP state-level goals would be implemented
without interstate trading. Further, due to the judicial stay of the CPP in February of 2016, it is
not reasonable to assume CPP implementation would begin in 2022. For these reasons, the EPA
has conducted new analysis of the CPP using revised assumptions, with implementation
beginning in 2025 and states engaging in interstate trading.2
EPA examined two additional CPP scenarios: one with national trading and one with
regional trading (and both with delayed implementation of CPP). While the national trading
scenario is theoretically possible3, based on discussions that states were having prior to the stay
of CPP, EPA believes that some level of regional trading would have been the most likely
outcome of CPP implementation. As is further explained below, there are a number of reasons to
believe that these modeling scenarios are overstating future emissions and that given the small
differences seen between these modeling scenarios and the no CPP case, the CPP would
ultimately be extremely unlikely to result in emission reductions beyond a business as usual case.
The conclusions that can be drawn from this modeling are supported by the most up-to-
date information regarding this sector, including very recent changes not yet incorporated into
2	The preamble of the CPP final rule discusses multi-state plans and multi-state coordination that would facilitate
interstate trading under the CPP (80 Fed Reg 64838-40).
3	EPA views the development of a national GHG allowance trading market as less likely, due to a number of
considerations, such as the regionalized nature of organized electricity markets as well as efforts that were going on
at the state level when the rule was stayed.
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the EPA's modeling. There have been significant changes in the electric sector since the EPA
finalized the CPP in August of 2015 that lead the EPA to different conclusions about the
potential impacts of the CPP. These include fundamental shifts in fuel supply, continued
advances and cost declines for key power generating technologies, market operation and policy
evolution, and end-use demand influences. These changes can be observed using recent historical
data trends, current utility operations and planning, and utility announcements and power sector
projections.
These trends can also be seen in the evolution of the EPA's modeling of the CPP, even
under its prior assumptions. The EPA has modeled the CPP assuming a mass-based
implementation with no interstate trading four times, beginning with the final CPP in August of
2015. Key results of these modeling exercises are summarized in the table below. In each of the
cases summarized below, the EPA made a conservative assumption by assuming no interstate
trading. However, each iterative modeling effort reflected updated information on key inputs
such as the cost of new generation technologies, firmly committed coal retirements, state and
federal policies, and projected demand (amongst others). While these scenarios represent a less
likely current scenario (both because they assume no interstate trading and because they make no
account for the current stay of the Clean Power Plan), they do provide useful information to
document progress that has been made at the state level since the CPP was finalized. In
particular, EPA believes allowance prices provide a useful measuring stick to assess both the
degree of stringency and magnitude of impact of the CPP requirements.
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Table 2-1 Select IPM Results for CPP
IPM Modeling Projections of CPP
(Using a Mass-based approach where State-by-State Goals must be met)
Oyorip 1VAAOS
Scenario that includes CPP, Final CPP RIA " L XT JT.	Proposed ACE Final ACE
Transport NODA	' ^
for the year 2030 (v5.15) (v516)	(v6.17) (IPM 2018)
Average Marginal Cost, all
States ($/ton CO2)
$11
$4
$2
$2
Highest Marginal Cost
($/ton CO2)
$26
$17
$11
$13
# of States with $0/ton
18
30
27
Total Power Sector CO2
(million short tons)
1,814
1,839
1,737
1,681
% below 2005
32.4%
31.4%
35.3%
37.3%
As can be seen from the results in Table 2-1, if the CPP were to be implemented even with
the conservative assumption of no interstate cooperation and ignoring any delay in
implementation due to the Supreme Court stay, the impacts of the CPP would be significantly
less than the EPA projected in its original CPP analysis. In August of 2015, the EPA projected
that only 7 of the 47 states with CPP obligations were already on track to meet those obligations
(15%). Now the EPA is projecting that at least 27 states (57%) are on track to meet or exceed
their targets. These reductions are attributable to trends that result in emission reductions
regardless of the CPP. Even for states that are not currently projected as on track to meet their
goals, those targets have become significantly easier to attain. The marginal cost for achieving a
state goal in the state with the highest marginal cost has fallen from $26/ton to $13/ton.4 More
detail on the state by state results can be found in Table 2-4, which shows that in August of 2015,
EPA projected that 7 states would have allowance prices of $20 or more. In the modeling using
4 Marginal costs are reported in 2016$ per short ton of CO2 throughout this chapter.
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the 2018 IPM, EPA projects that none do (notably, for two of those states Arizona and Utah,
EPA is now projecting an allowance price of zero).The table also shows that 29 states had an
allowance price of $10 or more. In the IPM 2018 modeling, there are only two. One of those
states, Colorado, is home to utilities that have made significant CO2 reduction commitments that
are not fully reflected in the IPM modeling. Further, as presented below, under reasonable
revised assumptions of delayed implementation and interstate trading, the CPP is non-binding
entirely (in the sense of not requiring any additional CO2 emission reductions beyond the
baseline).
Given these findings, as well as ongoing market trends and numerous recent utility CO2
reduction announcements, the EPA believes repeal of the CPP under current and reasonably
projected market conditions and regulatory implementation is not anticipated to have a
meaningful effect on emissions of CO2 or other pollutants or regulatory compliance costs. As a
result, this analysis demonstrating no significant difference in a scenario with CPP
implementation and one without satisfies any regulatory impact analysis that may be required by
statute or executive order for repeal of the CPP.
Section 2.2 provides information pertaining to the changes that have occurred in the
electric sector that have led to these projected changes. Section 2.3 explores the impact of
alternative trading assumptions and Section 2.4 summarizes key changes that may not be fully
incorporated into the EPA's current modeling. Section 2.5 examines several states projected to
have emission-reduction shortfalls in the EPA's modeling (i.e., higher baseline emissions than
their CPP goals) and provides additional real-world context for interpreting these modeling
outputs. Section 2.6 summarizes why these considerations together lead the EPA to conclude
that, even if the CPP were upheld, emissions projections would not be noticeably different from
a case where the CPP is not implemented. As a result, the cost and benefit impacts of CPP repeal
are de minimis. Finally, Section 2.7 presents additional summary information from IPM runs
used to support this analysis.
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2.2 Market Trends for the Electric Sector Relevant to Consideration of the Impact of the
Repeal of the CPP
A critical element of ongoing assessment and evaluation of the power sector are the
current trends underway, whereby the sector is experiencing a greater degree of change in
generation mix than it has historically. While many of these trends are incorporated into the
EPA's updated modeling analysis and result in lower emissions projections absent any CO2
regulatory considerations for power plants at the federal level, there is significant evidence that
these trends are occuring at a faster rate than most electric sector modeling has been projecting
(see, for instance, the discussion of the evolution of the levelized cost of electricity by generation
type below). The anticipation of a lower emissions future in the baseline is due to large-scale
market trends that are multi-faceted in nature. These include fundamental shifts in fuel supply,
continued advances and cost declines for key power generating technologies, market operation
and policy evolution, and end-use demand influences. These changes can be observed using
recent historical data trends, current utility operations and planning, and utility announcements
and power sector projections for the future that go through 2030, and beyond.
Ultimately, these trends are anticipated to result in the continued decline of coal-fired
generation and capacity and significant increases in natural gas-fired generation and capacity. At
the same time, renewable energy has continued to be the fastest growing form of new utility-
scale electric-generating capacity and is expected to account for a significant portion of all new
capacity into the future. In addition, electricity demand is only slowly rising. This places
additional economic pressures on older and less-efficient technologies (like many existing coal-
fired plants), which struggle to compete with the newer capacity coming online that generally
has lower operating costs. These findings have been summarized in a recent report from DOE:5
•	"The biggest contributor to coal and nuclear plant retirements has been the
advantaged economics of natural gas-fired generation."
•	"Another factor contributing to the retirement of power plants is low growth in
electricity demand."
5 U.S. Department of Energy. (2017). Staff Report to the Secretary on Electricity Markets and Reliability. Retrieved
from
https://www.energy.gov/sites/prod/files/2017/08/f36/Staff%20Report%20on%20Electricity%20Markets%20and%2
0Reliability_0.pdf
2-6

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• "Dispatch of variable renewable energy (VRE) has negatively impacted the
economics of baseload plants."
The changes in the generation mix away from coal and toward lower- and zero-emitting
generation are significantly more pronounced than the EPA and other analysts projected when
the EPA finalized the CPP. These trends mean that the states would be able to meet their goals
and, ultimately, the sources to meet their emission standards, with less planning burden, at
significantly less cost, and with less impact on the sector than the EPA previously estimated
when it finalized the CPP.
2.2.1 Recent Data Trends
2.2.1.1 Age of the Coal Fleet & Retirements
The current fleet of coal-fired power plants was mostly built prior to 1990,6 with an
average age of 39 years. Nearly all of the utility-scale power plants in the U.S. that were retired
from 2008 through 2017 were fueled by fossil fuels, and coal-fired power plants accounted for
the highest percentage.7 The average age of coal-fired power plants that have retired since 2008
is 52 years. Older power plants tend to become uneconomic over time as they become more
costly to maintain and operate, and as newer and more efficient alternative generating
technologies are built. As a result, coal's share of total U.S. electricity generation has been
declining for over a decade, while generation from natural gas and renewables has increased
significantly. The reduction in coal demand from power plants has also resulted in declining coal
consumption, with expected total U.S. coal consumption in 2018 of 691 million short tons (a 4%
decline from 2017 and the lowest level since 1979).8
6	EIA, Today in Energy (April 17, 2017), available at https://www.eia.gov/todayinenergy/detail.php?id=30812.
7	EIA, Today in Energy (December 19, 2018), available at https://www.eia.gov/todayinenergy/detail.php?id=37814.
8	EIA, Today in Energy (December 28, 2018), available at https://www.eia.gov/todayinenergy/detail.php?id=37817.
2-7

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25
20
15
10
0
reported
planned
retirements
other
petroleum
natural gas
combustion tu
steam turbine
coal
2008 2009 2010 2 011 2D12 2013 2014 2015 2016 2017 2018 2019 2GQ0
Figure 2-1 U.S. Utility-scale Electric Generating Capacity Retirements (2008-2020),
Gigawatts
Source: EIA, Today in Energy' (December 19, 2018)
2,000,000
1,500,000
1,000,000
500,000
2009 2010 2011
— coal — natural gas
2012 2013 2014 2015 2016
nuclear — conventional hydroelectric
2017
2018
Data source: U.S. Energy Information Administration
Figure 2-2 Net Generation, United States, Electric Utility, Annual (thousand
megawatthours)
Source: EIA Electricity Data Browser
2-8

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1:200
1000
200
600
400
300
electric power sector
Figure 2-3 U.S. Coal Consumption (1950-2018) (million short tons)
Source: EI A9
2.2.1.2 Natural Gas Supply and Price Trends
Technological advances in the natural gas industry have led to an abundance of natural
gas supply, resulting in a highly competitive (low price) fuel supply that is increasingly being
relied upon by the power sector, particularly as new pipeline infrastructure continues to be built
across the country. U.S. natural gas production hit a new record in 2018, with both the highest
volume and largest annual increase in production on record.10
9EIA, Today in Energy (December 28,2018), available at lutps://\vww.cia.gov/todayincncrgy/detail.php'.'id=37817.
111EIA, Today in Energy (March 14, 2019), available at https://www.eia.gov/todayinenergy/detail.php?id=38692.
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120
gross withdrawals
marketed production
dry production
100
80
60
40
20
0
1940
1950
1960
1970 1930
1990 2000 2010
Figure 2-4 U.S. Annual Natural Gas Production (1940-2018) (billion cubic feet per day)
Source: EI A11
United States : natural gas
eia1 Source: U.S. Energy Information Administration
Figure 2-5 Average Cost of Fossil Fuels for Electricity Generation (per Btu) for All
Sectors, Monthly (dollars per million Btu)
Source: EIA, Natural Gas Monthly Report
11 EIA, Today in Energy (March 14, 2019), available at https://www.eia.gov/todayinenergy/detail.php?id=38692.
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2.2.1.1 Renewable Energy
The costs of renewable generati on have fallen significantly due to technological
advances, improvements in performance, and local, state, and federal incentives such as the
recent extension of federal tax credits.1- According to Lazard, a financial advisory and asset
management firm, current unsubsidized levelized cost of electricity for alternative energy
technologies is lower than the operating cost alone of conventional technologies like coal or
nuclear, which is expected to lead to ongoing and significant deployment of renewable energy.
Levelized cost of electricity is only one metric used to compare the cost of different generating
technologies. It contains a number of uncertainties including utilization and regional factors.13
While this chart illustrates general trends, unit specific build decisions will incorporate many
other variables.
Mean LCOE
S/MWh
Selected Historical Mean LCOE Values*2'
LCOE Version 3.0	4.0	5.0	6.0	7.0	8.0	9.0	10.0	11.0
Source Lazard estimates
Note Reflects average of unsubsidized high and low LCOE range for given version of LCOE study
(1)	Primarily relates to North American alternative energy landscape, but reflects broader/global cost declines
(2)	Reflects total decrease in mean LCOE since the later of Lazard's LCOE—Version 3 0 or the first year Lazard has tracked the relevant technology
f3) Reflects mean of fixed-tilt i high end) and single-axis tracking (tow end) crystalline PV installations	
Nuclear
20%
Coai
(8%)
Gas—Combined Cycle
(27%)
Utility Scale Solar'
(86%)
Wind
(67%)
Figure 2-6 Selected Historical Mean LCOE Values
Source: Lazard. Levelized Cost of Energy 2017
As a result, the existing coal fleet continues to experience economic pressures. The cost
trends, along with other developments, have served as the main drivers for pronounced, ongoing
changes in the nation's generation mix that have resulted in lower CO2 emissions.
12	Lazard, Levelized Cost of Energy 2017. https://www.lazard.coin/perspective/levelized-cost-of-energy-2017/
13	U.S. Energy' Information Administration 2019. https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf
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2.2.2 Utility Climate and Clean Energy Announcements and Commitments
The broad trends away from coal-fired generation and toward lower-emitting generation
are reflected in the recent actions and recently announced plans of many power plants across the
industry — spanning all types of companies in all locations. Furthermore, many utilities have
made commitments to move toward cleaner energy. Throughout the country, utilities have
included commitments towards cleaner energy in public releases, planning documents, and
integrated resource plans (IRPs). For strategic business reasons, most major utilities plan to
increase their renewable energy holdings and continue reducing CO2 emissions, regardless of
what federal regulatory requirements might exist. The Edison Electric Institute (EEI) has
confirmed these developments: "While the CPP was stayed by the Supreme Court in 2016, the
power sector will have complied with the final 2030 goals of the rule—in terms of gross
emissions reductions—before the 2022 start date included in that program."14 This trend is not
unique to the largest owner-operators of coal-fired generation; smaller utilities, public power,
cooperatives, and municipal entities are also contributing to these changes.
There are many recent examples of electric utilities who have publicly announced near-
and long-term emission reduction commitments. Here are but a few examples of emission
reduction targets of 80%+ (relative to 2005 levels) that have recently been announced by major
utilities:
•	Xcel Energy (with power plants that operate in MN, CO, MI, MN, NM, ND, SD, TX, and
WI): 50% reduction in CO2 emissions by 2022 (and 100%) and carbon-free by 2050)15
This includes a commitment to close all coal plants in Minnesota by 203016
•	DTE Energy (MI): 30% reduction in CO2 by the early 2020s, 50% by 2030, 80% by 2040
and 80%>+ by 205017 (these goals were recently accelerated)18
14	EEI Comments on ACE, at 4 (Oct. 31, 2018).
15	Xcel Energy, Integrated Resource Plan(s), available at
https://www.xcelenergy.com/environment/carbon_reduction_plan.
16https://www.xcelenergy.com/company/media_room/news_releases/xcel_energy_to_end_all_coal_use_in_the_upp
ermidwest
17	DTE Energy, IRP (under public review), available at
http://newsroom.dteenergy.com/index.php?s=26817&item=137217#sthash.6EU4Hz0y.mSpR9OKB.dpbs.
18	http://newsroom.dteenergy.com/2019-03-28-DTE-Energy-accelerates-carbon-reduction-goal-a-full-decade-will-
reduce-emissions-80-percent-by-2040#sthash.UY40RqAg.dpbs
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•	Ameren Energy (MO): 35% by 2030, 50% by 2040, and 80% by 205019
•	Consumers Energy (MI): 80% by 2040 and transition to zero coal use20
•	MidAmerican Energy (IA): 100% RE goal21
•	NIPSCO (IN): 90% reduction by 2028, and phase-out all coal22
•	First Energy (FE): 90% reduction by 204523
•	American Electric Power (AEP): 60% reduction by 2030 and 80% by 205024 (from year
2000 levels)
•	Alliant Energy: 40% reduction by 2030 and 80% by 205025 and phase-out all coal
•	WEC Energy Group: 40% reduction by 2030 and 80% by 20 5 026
While the EPA does not account for statements from utilities regarding their future plans
in the economic modeling that are not technically legally enforceable, the number and scale of
these announcements is significant on a systemic level. These statements are also part of long-
term planning processes that cannot be easily revoked, since there is considerable stakeholder
involvement, including by regulators, in the planning process. The direction in which these
companies have publicly stated they are moving is consistent across the sector and undergirded
by market fundamentals lending economic credibility to these commitments and confidence that
there is a high likelihood that most will be implemented. Thus, these announcements are
sufficiently consequential to be considered in identifying the appropriate economic baseline.
19	Ameren Missouri, Integrated Resource Plan, available at
https://www.ameren.com/missouri/company/environment-and-sustainability/integrated-resource-plan.
20	Consumers Energy IRP, available at https://www.consumersenergy.com/community/sustainability/energy-
mix/renewables/integrated-resource-plan.
21	MidAmerica Energy, Our 100% Renewable Vision, https://www.midamericanenergy.com/our-renewable-energy-
vision.aspx.
22	NIPSCO IRP, available at https://www.nipsco.com/docs/librariesproviderll/rates-and-tariffs/irp/2018-nipsco-
irp.pdf?s!Vrsn=15
23	First Energy, available at https://firstenergycorp.com/content/fecorp/environmental/initiatives.html
24	AEP, available at https://www.aep.eom/news/releases/read/1503/AEPs-Clean-Energy-Strategy-Will-Achieve-
Significant-Future-Carbon-Dioxide-Reductions
25	Alliant Energy, available at https://sustainability.alliantenergy.com/energy-climate/
26	WEC Energy, available at https://www.wecenergygroup.com/csr/climate-report.pdf
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2.2.3 Recent Emissions Trends & Future Projections
The aforementioned market trends and business decisions have resulted in declining
power sector CO2 emissions since 2005, which are also expected to produce a notably lower
emissions future as higher emitting sources of electricity are replaced with lower-emitting
sources. In 2012, aggregate CO2 emissions from sources covered by the CPP were 19 percent
below 2005 levels. When the EPA finalized the CPP in August 2015, the Agency projected that,
by 2030, the power sector would reduce its CO2 emissions 32 percent below 2005 levels with the
CPP. By the end of 2015, several months after the CPP was finalized, those sources already had
achieved CO2 emission levels 24 percent below 2005 levels, in the aggregate. Even after the CPP
was stayed, in 2016, sources were 28 percent below 2005 levels. In both 2017 and 2018 sources
were 30 percent below 2005 levels.27
The evolution of these overarching power sector trends can be seen in the EIA's Annual
Energy Outlook (AEO), which includes energy projections of the future. The AEO includes a
CO2 projection in a baseline scenario, similar to the EPA's baseline projections using IPM,
which show how these trends have been absorbed into the AEO over time (see Figure 2-7).
Figure 2-7 also demonstrates the extent to which recent power sector modeling has consistently
tended to under-estimate the degree of CO2 projected in the future. If the current trendline in this
figure continues, power sector emissions will be well below the original 2022 and 2030
aggregate mass-based goals in the CPP, marked by "Xs" in the graph.
27 EPA, Air Markets Program Data (affected sources under CPP), available at https://ampd.epa.gov/ampd.
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4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
¦ — •Historical
	AEO 2005
AEO 2010
	AEO 2015
	AEO 2017
	AEO 2019
X CPP Aggregate Goal (2022 & 2030)
Trendline
2000
2005
2010
2015
2020
2025
2030
Figure 2-7 Power Sector CO2 Emissions (million short tons)
Source: EIA AEO, and EPA for CO2 data (AMPD database).
For example, the AEO estimates from 2005 and 2010 were just prior to the large
domestic expansion of gas supplies. Also, while renewable energy was being deployed in that
time period, it was on a much smaller scale and at a cost not nearly as competitive as it is today.
As such, there was an expectation of continued generation from coal-fired sources for the
foreseeable future. Only after 2015 did the AEO begin to more concretely factor these trends into
the projections, which can be seen in the notable decline in the CO2 emissions projection. The
most recent AEO, for 2019, shows CO2 emissions significantly lower than the AEO from four
years earlier (2015). As Figure 2-7 demonstrates, each successive AEO projection has suggested
that CO2 emissions would either flatten or decrease from previous iterations of the AEO, and has
been continually revised downward following the trendline of the historical data.
2.3 CPP Stay/Delayed Implementation and Trading Assumptions
The implementation timing of the CPP, and the manner in which it would be
implemented, are no longer valid due to changed circumstances since the CPP was finalized in
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2015. These changes, in conjunction with the trends discussed above, have further weakened the
effect the CPP was previously anticipated to have relative to a no-CPP baseline.
2.3.1 Delayed implementation of the CPP
The Supreme Court issued a stay of the CPP in February of 2016, effectively pausing the
rule during judicial review. The litigation challenging the CPP has been held in abeyance since
2017, when the EPA announced its intentions to reconsider and potentially repeal the CPP.
Given the resulting delay in implementation already to-date, the timing of reduction
requirements under the CPP, as it was finalized in 2015, is no longer reasonable to assume, since
states and sources have been under no obligation to plan for or to implement the rule. In a
hypothetical world where CPP comes back into effect, its deadlines for compliance would likely
require adjustment.
Under the original schedule for CPP implementation, state plans were due in September
of 2018 at the latest. The first compliance period was scheduled to begin in 2022. Subsequent
compliance periods, corresponding with increasingly stringent state goals would have run from
2025-2027, and 2028-2029, with final CPP goals going into effect in 2030. Two-year compliance
periods would have run perpetually from 2030 with no further change in stringency.
The deadline for state plan submittals in 2018 has already passed. Thus, the start of the
initial compliance period would unlikely be 2022, as originally promulgated in the CPP, since
States have been under no obligation to develop and submit state plans to implement the program
since it was stayed. As such, for purposes of this analytical exercise, an appropriate
implementation time horizon for CPP would involve adjusting the compliance deadlines,
possibly by delaying them for several years.28 Over three years have passed since the stay was
issued, which is a logical starting point when considering a tolling timeframe. Hence, the EPA
considers a three-year delayed implementation of CPP as a reasonable starting point when
28 Although not determinative, a similar period of tolling was the result in the Cross-State Air Pollution Rule
(CSAPR) litigation, where roughly three years elapsed between the D.C. Circuit Court of Appeals' stay of the rule
and its order granting EPA's motion to lift the stay. See Order, Document #1518738, EME Homer City Generation,
L.P. v. EPA, No. 11-1302 (D.C. Cir. issued Oct. 23, 2014); Interim Final Rule, 79 Fed. Reg. 71663 (Dec. 3, 2014);
Final Rule, 81 Fed. Reg. 13275 (March 14, 2016). And a similar approach to tolling was taken in lifting the stay of
the NOx SIP Call. Order, Michigan v. EPA, No. 98-1497 (D.C. Cir. issued June 22, 2000).
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considering a hypothetical implementation of that rule.29 For purposes of the EPA's updated
modeling in this analysis, we assume that CPP compliance commences in 2025, with final goals
going into effect beginning in 2033.This serves to further diminish the effect of the CPP, since
the later it is implemented the more likely that market trends will have already resulted in
emissions that are lower than the CPP goals. Furthermore, in a mass-based implementation
scenario, with emissions already generally below the goals for the first compliance period
(starting in 2025), there will be more allowances available to be banked for use in subsequent
compliance periods than there otherwise would have been without tolling the deadlines.
To demonstrate the effect of delaying implementation of the CPP, in the maps below,
State-level emissions from existing sources are shown in two ways. The first map shows
emissions for each state from the baseline projection (i.e. a scenario with no 111(d) CO2
requirement for existing EGUs) for the year 2030, relative to each state's respective mass-based
goal for CPP for 2030 (prior to any consideration of implementation delay for CPP). Positive
values indicate that a state's projected baseline CO2 emissions in the baseline projection are
lower than the state-level CPP goal (i.e., the state's emissions in 2030 are below the 2030 goal),
while negative values indicate that a state's emissions in the baseline in 2030 are higher than the
goal. It should be noted that these values from the baseline are conservative in light of additional
long-term changes in the generation mix (e.g., coal plant retirements and utility announcements)
that have been announced or included in IRPs since this modeling was performed, as discussed
in Section 2.2.3 above. In other words, the shortfalls in emission reductions apparently facing
some states are in all likelihood smaller than the numbers below suggest, and again, these figures
do not factor in any delay in CPP implementation.
29 The EPA does not intend for this hypothetical scenario for implementation of the CPP to reflect or imply a
binding commitment at this stage to adjust deadlines in this manner for the CPP in the unlikely event that it would
be implemented. Such a determination would require a full analysis of all the facts and circumstances at the time
such a determination would need to be made.
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-2.1
-10.0
2.0
-0.2
2.4'
9.9
7Jl
-14.2
,4.3
31!
-11.3
-4.6
11.2
,3.4
2.1
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42.7
18.0
12.8
10.7
-5.3
-0.2
15.7
5.5
-4.0
-2.3
2.2
<— Above Goal
At Goal
Below Goal —>
Figure 2-8 State-Level CO2 Short Tons Emissions Comparison: Baseline Emissions vs.
CPP Goals for 2030
Source: EPA, State-level goals for CPP and baseline projections of CO2 from IPM.
The second map shows data in a similar manner, but uses baseline emi ssions from 2025
(instead of 2030) and compares the annual CPP goals for the interim compliance period
beginning in year 2022. This comparison is intended to show how a three-year delayed
implementation of CPP would appear, relative to the baseline projection in the initial year of the
program. This comparison shows even more states with emissions in the baseline below the CPP
goals, and fewer states above the goal (as well as the potential number of allowances that are
available for compliance in later years). Collectively, all states taken together are considerably
below the goals.
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7.4
0.4
-5.0
-1.3
3.1
-0.1
,2.2
0.3
12.1
~1IL
2.0
-4.0
7.7
43.2
-2.0
-5.5
3.3
23.!
13.;
7.5
20.!
15.7
-11.7
0.4
-4.1
-7.4
55.4
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10.1
19.5
-0.0
0.5
19.1
19.0
5.7
5.3
22.7
24.1
<— Above Goal
At Goal
Below Goal —>
Figure 2-9 State-Level CO2 Short Tons Emissions Comparison: Baseline Emissions in
2025 vs. CPP Goals for 2022
Source: EPA, State-level goals for CPP and baseline projections of CO2 from IPM.
2.3.2 Interstate Trading under the CPP
The CPP provided significant flexibility to States to meet their goals and allowed for
multiple compliance pathways for implementing the rule. In particular, interstate mass-based
trading was of interest to many states and sources. To facilitate efficient and flexibl e
implementation of the CPP, the EPA released draft Model Trading Rules language in 2016 to
assist States as they considered possible compliance pathways. Emissions trading systems allow
for compliance with an overall emissions limit or goal by allocating or auctioning emissions
allowances (equal to the overall budget or goal) to emitting sources. Sources must surrender
allowances equal to their emissions for that period, thus ensuring that total emissions are no more
than the goal expressed as an emissions budget. This system can be implemented at the State
level, i.e., without interstate trading, which was represented in the RIA for the final CPP (2015)
and subsequent representations of the CPP (2018 ACE Proposed Rule RIA, 2017 CPP repeal
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RIA and in this Chapter). The assumed implementation of trading at the state-level in the 2015
final CPP RIA was determined to be most appropriate to demonstrate that each state could meet
the goals cost-effectively, even without the assumption of broader trading.30
The EPA did not analyze interstate trading scenarios at the time it promulgated the CPP,
even though the EPA encouraged states to join multi-state plans to increase compliance
flexibility. This increased compliance flexibility may lead to lower CO2 reductions. Applying
Circular A-4's guidance that the baseline used in an analysis "should be the best assessment of
the way that the world would look absent the proposed action," and because the analysis is no
longer being used to make a regulatory decision that could be impacted by consideration of the
CPP on individual states, the EPA believes it is appropriate to revisit this approach and assess
interstate trading scenarios under the CPP.
There is a significant history of states using interstate trading when such flexibility is
allowed (e.g., such opportunities were generally welcomed by states or implemented by them
directly in the NOx SIP Call, CAIR, CSAPR and WRAP). There was significant interest
amongst a broad and diverse set of stakeholders during the CPP rulemaking who advocated for
allowing such implementation flexibility. Such a scenario would still be as reasonable to assume
as no interstate trading, and in fact represents a more likely CPP implementation scenario.
Stakeholders and commenters to the EPA have consistently sought compliance flexibility
through averaging or trading programs, which the CPP explicitly allowed. Many industry and
state commenters on ACE again sought for the EPA to allow broad-based trading options as a
flexible means of implementation of a section 111(d) program for the power sector.31
The EPA has now modeled and analyzed a new CPP scenario with IPM to help shed light
on a potential interstate-trading compliance scenario (coupled with a three-year delay in
implementation). Another possible implementation of CPP is sub-national, regional trading. To
shed light on possible quantitative effects of these alternatives, the EPA has conducted additional
modeling, as described below. As noted elsewhere in this chapter, the EPA has also modeled the
CPP again for purposes of the final ACE rule, with no interstate trading and without any
30	See CPP Final Rule RIA (2015), Chapter 3 for more detail.
31	See, e.g., EEI Comments on ACE, at 22 (Oct. 31, 2018); UARG Comments on ACE, at 73-75 (Oct. 31, 2018);
Texas CEQ Comments on ACE, at 8 (Oct. 31, 2018); Pennsylvania DEP Comments on ACE, at 8 (Oct. 31, 2018).
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consideration of delayed implementation of CPP in order to provide the public with the ability to
understand the analysis in a manner consistent with previous CPP modeling.
2.3.2.1 National Trading
The EPA has looked at the impacts of interstate trading in two ways. First the agency has
done new CPP modeling essentially assuming nation-wide trading combined with a three-year
implementation delay.32 Second, the agency modeled regional trading and used information from
state-level goals and baseline modeling to explore the impacts of regional trading.
The nation-wide trading scenario allows for greater flexibility across sources and States
(i.e., interstate trading) and assumes delayed implementation timeframes as described previously
(i.e., compliance beginning in 2025 and final goals taking effect in 2033). In this scenario,
sources must collectively comply with a national-level mass-based CPP emission target. The
CPP scenarios included in this chapter focus on mass-based implementation due to the relative
ease of modeling mass (vs. rate) in the model. In addition, the rate-based and mass-based forms
of implementation of the CPP goals were included to provide flexibility and specifically
designed to produce equivalent levels of stringency. All of the numeric values, data, and
formulas used for establishing goals under CPP were developed with a consistent framework.
As the more detailed results in section 2.7 show, this scenario results in almost no impact
from the CPP. A CPP scenario that allows for broader trading, when implemented in IPM, shows
that the CPP has no impact because business-as-usual industry trends result in emission levels at
the national scale that are already within the collective state budgets of the CPP under this form
of implementation. While there are very small changes in costs (less than $5 million nationwide
in any given year), there are no changes in CO2 emissions. In other words, when modeled, this
scenario produces essentially the same outcomes as the baseline scenario.33 This supports the
conclusion that CPP would likely have little or no impact.
32	California and the states that comprise the Regional Greenhouse Gas Initiative were excluded from the national
CPP trading scenario; the state requirements from those existing programs were kept in place, and the CPP goals for
CA and RGGI were met independently without trading (CPP goals were non-binding).
33	For more detail on these scenarios, see Addendum.
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2.3.2.2 Regional Trading
The EPA has also modeled an IPM scenario with regional (i.e., sub-national) trading
using six smaller hypothetical trading regions. Based on discussions that states were having prior
to the stay of CPP, EPA believes that some level of regional trading would have been the most
likely outcome of CPP implementation. The regions that the EPA examined are roughly based
upon a combination of the North American Electric Reliability Corporation regional alignment
for the U.S. and Regional Transmission Organizations (RTO)/Independent System Operators
(ISO) regions.34 NERC is tasked with ensuring the reliability of the North American bulk power
system, while RTO/ISO boundaries help facilitate organized wholesale electricity markets (see
Figures 2-10 and 2-11).
Interconnections
Quebec
Interconnection
> — — V,
Western Interconnection /	x
/
'	ERCOT
Eastern
Interconnection
¦ FRCC ¦ MRO
Interconnection „
INPCC I~1RF BSERC nTexas RE BWECC
Figure 2-10 NERC Interconnections
Source: North American Electric Reliability Corporation
34 https://www.nerc.coin/AboutNERC/keyplayers/pages/default.aspx and
https://www.ferc.gov/industries/electric/indus-act/rto.asp
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NowYortilSO
-------
Figure 2-12 CPP Trading Regions: PJM (yellow), Southeast (green), Northeast/RGGI
(purple), Midwest/Central (red), West (blue), and California (orange)
This scenario yields very small impacts, and the collective regional CPP goals require
CO2 emission reductions beyond the baseline for only one region (the Midwest/Central region).
This hypothetical regional trading scenario would result in compliance with the CPP goals with
no additional effort, except for one region. In addition, the CPP is only minimally binding in that
region, with a marginal cost of less than $l/ton of CO2. The marginal cost for all other regions is
zero. Table 2-2 presents national CO2 emissions changes and Table 2-3 presents compliance
costs, which is the increase in system-wide generation costs, for the CPP with Regional Trading
and Tolling relative to a baseline with no 111(d) requirement for existing EGUs.36
In addition to the regions chosen for this illustrative scenario, there are a variety of
alternative regional trading groupings that would result in compliance with the CPP targets with
little or no additional effort, if modeled. Further, even if some regions faced a shortfall, it is
reasonable to anticipate that utilities in those regions could easily take steps to avoid any
36 These costs do not include costs for monitoring, reporting, and recordkeeping.
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meaningful impact of a CPP emissions budget. Any administrative boundaries for the
hypothetical trading groups don't constrain the flow of electricity. Generation will, in part, shift
to where the mass-based goals are already below the CPP budget in a business as usual, and
therefore existing fossil generation will increase in other regions in response to emission
reductions in regions with a shortfall.
Table 2-2 Projected CO2 Electric Sector Emission Impacts, Relative to Baseline

CO2 Emissions
(MM Short Tons)
2025 2030 2035
CO2 Emissions
Change (MM
Short Tons)
2025 2030 2035
CO2 Emissions
Change Percent
Change
2025 2030 2035
Baseline
1,774 1,743 1,719


CPP with Regional Trading and Tolling
1,767 1,733 1,709
O
l
O
l
00
1
-0.4% -0.6% -0.6%
Table 2-3 Annualized Compliance Costs, Relative to Baseline (millions of 2016$)

2025
2030
2035
CPP with Regional Trading and Tolling
-$32
$27
$139
Additional information is presented below for the Midwest/Central region in order to
provide more context, since it is the only binding region from the Regional Trading and Tolling
scenario. Figure 2-13 presents the historical CO2 emissions from affected sources in the
Midwest/Central region, and compares regional CO2 emissions projections from the previous
baseline projection (used in 2015 when CPP was finalized) to the current baseline from this Final
ACE rule. This figure also shows the regional CPP goals for the Midwest/Central Region that are
reflected in the Regional Trading scenario, although the figure does not show the goals being
tolled (3 years). First, the figure demonstrates how much lower baseline emissions are now
projected to be for this region than they were in 2015, due to the ongoing trends and changes in
the electric power sector. Second, the data shows that the current baseline emissions projections
are very close to the goals, and only a modest amount of additional reductions would be
necessary to meet the regional goals (indeed, the projected marginal cost of doing so is less than
$l/ton CO2). Third, the baseline projections should be considered in the context of the recent
utility and announcements that are not reflected in the baseline, which were mentioned earlier in
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this chapter. These long-term planning announcements from utilities in this region, if realized,
would reduce baseline emissions well below the CPP goals shown in the figure.
1,200
1,000
800
600
400
200
0
2000	2005	2010	2015	2020	2025	2030
	IPM Baseline (vintage 2015 used for CPP)
— IPM Baseline (vintage 2018 used for Final ACE)
	Historical
X CPP Regional Goal
Figure 2-13 CO2 Emissions for the Midwest/Central Region: Historical and Baseline
Projections from IPM (million short tons)
Figure 2-13 also shows that the previous baseline projections for the Midwest/Central
region were well above the regional CPP goals, while the updated modeling projects emissions
to be well below the CPP goals prior to 2030 for this region. This highlights the dramatic
changes underway in the industry. More specifically, the previous modeling projected baseline
emissions to be roughly 4 percent above the 2022 CPP goal, while the updated modeling projects
emissions in this region to be 11 percent below the 2022 CPP goal. In 2030, affected sources are
projected to further reduce CO2 emissions significantly in the updated modeling, making 63
percent of the reduction merely under baseline conditions (comparing the deficit in 2030 from
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2-26
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previous projections to the remaining deficit in the current projections). It is important to note
that the baseline does not necessarily include all the numerous commitments that major utilities
have announced and are planning in this particular geographic region (also discussed earlier in
this chapter). These activities are partially quantified below, for additional context.
Several large investor-owned electric utilities have made long-term decarbonization
commitments across their respective generating fleets in the Midwest/Central region, and have
also recently accelerated these plans due to continually evolving market dynamics. Some of these
commitments are not included in the projected baseline, but it is possible to estimate the
emissions implications attributable to these kinds of commitments in a simple manner (because
banking is not accounted for in this static analysis looking solely at the impact of the retirements
in a single year, the true impact may be understated since some of these newly announced
retirements occur before 2030, they allow for additional banking of allowances). EPA's current
modeling assumes operation of these units post 2030, such that removal of those units based on
utility plans not only reduces the emissions shortfall, but also reduces the demand for
allowances. The subsequent data focuses on utilities that have announced longer-term goals with
specificity, with regards to particular power plants that will be removed from service by 2030,
and is only a partial list. In the recent reference case, some of these units are projected to emit
roughly 31 million tons of CO2 in 2030 (these estimates are not incorporated into the modeled
emissions projections shown in Table 2-2).37 This accounts for over 40 percent of the difference
between the baseline emissions in 2030 compared to the CPP goals for the Midwest/Central
region (the difference between the "X" and the yellow line on Figure 2-13). These particular CO2
emission reduction estimates that are not in the baseline, along with the other non-quantified
reductions that are anticipated, lead EPA to believe that CPP would be non-binding in the
Midwest/Central region. Removing these units from service will result in reductions of criteria
pollutants and toxic emissions, in addition to the CO2 emissions reductions that are planned. It is
also important to note that the CPP scenario with regional trading and tolling resulted in a
37IPM Reference Case parsed file for 2030, CO2 emissions for the following operating power plants: Allen S. King,
Belle River, Dan E Karn, JH Campbell, Michigan City, RM Schahfer, and Sherburne County. These units were
chosen due to the specificity of plans laid out by their owners, and is not meant to be a comprehensive reflection of
all units that might be part of long term climate commitments.
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projected marginal cost for the Midwest/Central region of only 75 cents in 2030, while the
projected marginal cost in all other regions was zero.
This analysis is only partial and does not include a quantitative assessment of other power
plants that are owned by utilities with longer-term climate commitments because they have not
clearly indicated which power plants will be retired. Also, many of the utility commitments
begin prior to 2030 but also include additional significant milestones for 2030, 2040 and 2050.
The non-modeled CO2 reduction commitments in this region, along with the marginal cost of 75
cents from the CPP Regional Trading and Tolling scenario, suggests that the baseline emissions
will be lower than the CPP goal for this region.
2.4 Modeling Inputs and Key Areas of Uncertainty
The EPA conducts power sector analysis using IPM, a sophisticated modeling tool with
detailed representation of the electric power system. This tool undergoes continual updates and
enhancements to best represent the electric power system and is similar to the AEO, in that it
provides baseline projections that help guide and shape regulatory efforts. As previously
discussed, there have been notable fuel, technology, and other system changes that have led to
revised projections of CO2, which are incorporated into the EPA's current analysis of CPP and
Final ACE and inform the EPA's choice of baseline. However, given the pace of change, key
uncertainties are identified and discussed below.
2.4.1 Routine Baseline Updates and Model Considerations
The EPA routinely updates its analytics and modeling platforms in order to provide the
most current framework in which to evaluate its actions. Over the past few years, there have been
changes to the market economics for power plants that involve a myriad of changes that have
been incorporated to best reflect the behaviors and the relative economics of power plant
operators. For example:
• Routine EGU inventory updates:
o New Electric Capacity: Inclusion of recent builds and deployment of new
capacity across the country, which consists mostly of renewable energy (wind and
solar) and natural gas (simple and combined cycle) due to low-cost natural gas
supply
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o Retirements of Existing Capacity: Retirement of existing capacity that has been
removed from service due to economic and regulatory considerations (mostly
aging coal capacity and some nuclear capacity)
•	Electric Demand: Changes to expected electric demand levels, whereby overall growth is
expected to be very small for the foreseeable future
•	Fuels: Robust and cost-effective supplies of natural gas with additional pipeline capacity,
particularly in the Eastern U.S.
•	New or Amended State Laws or Regulations: Examples include updated climate or
energy programs, energy storage mandates, new or revised RPS standards, consent
decrees, and other regulatory requirements for certain power plants at the State level
•	Changes to Federal Law: Examples include changes to corporate income taxes and
extensions to renewable energy tax credits found in the December 2017 Tax Reform Bill
These updates and changes are reflected in the EPA's current modeling framework using
IPM (see Chapter 3 of this RIA for more detail).
While the EPA makes every effort to incorporate the most up-to-date information into its
modeling and analysis, such modeling may overstate emissions projections and costs of emission
reductions whenever there are important and unanticipated developments in clean energy policy
and technology not incorporated in previous analysis. Several examples illustrate why the pace
of change in the power sector is likely to be greater than what the modeling produces:
•	Legislative changes at the national and state levels. These include: 1) Changes to the 45Q
tax credit to encourage more carbon capture and storage, 2) State legislative efforts in
New Jersey to join RGGI, and 3) Increased renewable and clean energy mandates in
states like New Mexico.38
•	The EPA does not include in its modeling commitments made as part of IRPs that States
and electric utilities develop for long-term planning, since they are not legally binding
documents and can be changed and amended over time (some specific IRPs were
mentioned above). However, these documents often undergo significant public review
and stakeholder engagement, and utilities typically follow through with such plans unless
there are unusual circumstances.
•	Models do not reflect the future perfectly, and there may be greater and/or faster
technology evolution and change than assumed in this modeling as many nascent
38 New Mexico recently passed legislation that will double renewable energy use in the state by 2025, require 50%
renewable energy by 2030 and 100 percent carbon free electricity generation by 2045 (New Mexico SB 489,
available at https://www.nmlegis.gov).
2-29
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technologies continue to develop. For example, energy storage (battery technology),
advanced gas turbines, distributed energy, and end-use efficiency technologies are
emerging and increasingly important areas of policymaking and investment that are likely
to have impacts on the turnover of the existing fleet.
•	Increased corporate commitments to procure renewable power that may go beyond State
renewable standards.
•	Potential changes to the cost to operate coal plants, since they have increased ramping up
and down more routinely (as a group) due to market conditions, causing increased wear
and tear to coal-fired units. This is important both because so many units are now being
operated in a more cyclic function and because the coal-fired fleet is continuing to age.
The average age of coal-steam EGUs greater than 25 MW is projected to be over 50 years
old in 2030, and nearly 30 percent of these units (or almost 20 percent of total capacity)
will be over 60 years old.
Other areas of uncertainty include:
•	Uncertainty about the compliance pathways states would take if the CPP were eventually
upheld and implemented. The EPA's analysis has primarily focused on a mass-based
approach for existing sources at the state level with some additional analysis of larger
trading regions.
•	States also had the flexibility to use state goals that include new sources and to use rate-
based trading. Full consideration of these options would likely show additional states
already in compliance with the CPP.
Any of these changes would further ease the CPP compliance burden and further increase
the chance that baseline emissions would be further below CPP requirements in most, if not all
states, even under conservative implementation assumptions.
2.5 Additional State-level Information
This section presents several perspectives using the EPA analysis to assess the degree of
effort needed to meet the CPP goals in various states. State-level data is presented showing state-
level emissions, CPP goals, and the cost to meet the CPP state goals. These costs, consistent with
the electric sector trends, have decreased over time for the vast majority of states.
First, emissions for each state in the baseline in 2030 are shown in Figure 2-14, along
with their mass-based CPP goals. The states are ordered, from left to right, with the greatest
emission-reduction shortfall on the far left and the greatest surplus in emission reduction on the
2-30
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far right. This approach does not incorporate any delay in CPP implementation and shows many
more states already meeting their goals in the baseline in 2030 than states that are not.
200
200
180
160
140
120
100
80
60
40
20



-
¦I Lil i,
ill
jJ
l.il
Hill 1
180
160
140
120
100
80
60
40
20
TO TO O TO TO "O f OOQJ'p: C _TO
TO OJ •
I 2030 Baseline Emissions — CPP State Goal
Figure 2-14 State-Level CO2 Emissions in the EPA Baseline for 2030, Ordered by Largest
Shortfall to Greatest Surplus Compared to CPP State Goals (thousand short
tons)
Source: EPA, State-level goals for CPP and baseline projections of CO2 from IPM.
The degree of shortfall shown in some states is likely overstated. As indicated earlier in
this chapter, there are many states with hypothetical shortfalls that also have major investor-
owned utilities that have announced clean energy targets well below what is modeled in the
baseline, since the EPA does not incorporate these longer-term goals or IRPs into the modeling.
These states include Missouri (Ameren), Michigan (DTE Energy and Consumers Energy), Iowa
(MidAmerican Energy), Colorado, Minnesota, North Dakota, and Wisconsin (Xcel Energy).
2-31
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Second, when the CPP is modeled with each state required to meet its goal, the model
produces a marginal cost of compliance on a dollar per ton basis for each state. This data is
shown below in Table 2-4 for various modeling iterations of CPP over the last few years,
including for final ACE, using IPM. A closer look shows the marginal cost to meet the CPP state
goal in 2030 has decreased over time for the vast majority of states. This is true even without
implementation delay or interstate emissions trading.
In addition, the states with the highest projected marginal costs of complying with their
respective state-level CPP goal are also states with electric utilities that have committed to large
reductions in carbon emissions by 2030 and beyond. For example, New Jersey has committed to
joining the RGGI trading program while the CPP was stayed, and was one of the states with
slightly higher marginal cost under the CPP modeling. In Colorado, the state with the highest
projected marginal cost of CChreductions, Xcel energy (the largest utility in the state) has
committed to an 80% reduction in CO2 from 2005 levels (Xcel also has generating assets in
seven other states). Additionally, the Platte River Power Authority board of directors has
committed to 100% renewable power by 2030 (also operating in Colorado).39 These
commitments would significantly reduce the chance that the CPP would be binding in Colorado.
In Missouri, Ameren has committed to a 35% reduction in GHGs by 2030 (relative to 2005) on
the way to an 80% reduction in 2050. In Michigan, the states' two largest utilities, Detroit Edison
and Consumers Power, have announced ambitious carbon reduction targets.
39 https://www.prpa.org/news/platte-river-board-passes-energy-policy/.
2-32
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Table 2-4 2030 Projected Marginal Cost of Mass-Based State-Level CPP Emissions
	Goals, by State ($/ton CO2)	
For 2030
Final CPP RIA40
(v5.15)
Ozone NAAQS
Transport NODA41
(v5.16)
Proposed ACE42
(v6.17)
Final ACE (IPM
2018)
AL
$11
$0
$0
$0
AR
$10
$8
$2
$4
AZ
$20
$5
$0
$0
CA
$15
$0
$0
$0
CO
$21
$11
$11
$13
CT
$1
$7
$0
$0
DE
$0
$0
$0
$0
FL
$12
$3
$0
$0
GA
$15
$2
$1
$0
IA
$15
$6
$3
$6
ID
$24
$1
$2
$2
IL
$10
$5
$1
$0
IN
$17
$4
$0
$0
KS
$20
$10
$4
$5
KY
$2
$2
$0
$0
LA
$2
$0
$0
$0
MA
$0
$4
$0
$0
MD
$4
$0
$0
$0
ME
$2
$9
$0
$0
MI
$5
$0
$5
$5
MN
$17
$4
$2
$3
MO
$16
$10
$4
$5
MS
$10
$1
$0
$0
40	https://19j anuary2017 snapshot, epa. gov/airmarkets/analy sis -clean-power-plan_.html.
41	https://www.epa.gov/airmarkets/epas-power-sector-modeling-support-notice-data-availability-preliminary-
interstate-ozone.
42	https://www.epa.gov/airmarkets/analysis-proposed-ace-rule.
2-33
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MT
$20
$12
$8
$8
NC
$1
$0
$0
$0
ND
$12
$7
$7
$8
NE
$24
$17
$9
$10
NH
$0
$0
$0
$0
NJ
$5
$9
$7
$7
NM
$13
$0
$0
$0
NV
$14
$3
$0
$0
NY
$0
$0
$0
$0
OH
$14
$5
$0
$0
OK
$14
$0
$0
$0
OR
$0
$0
$0
$0
PA
$6
$0
$0
$0
RI
$0
$3
$0
$0
SC
$6
$0
$0
$1
SD
$14
$3
$1
$1
TN
$15
$3
$0
$0
TX
$13
$8
$0
$0
UT
$26
$10
$1
$0
VA
$4
$0
$0
$0
WA
$0
$0
$0
$0
WI
$16
$8
$2
$3
WV
$15
$5
$5
$4
WY
$18
$0
$0
$0
The modeling presented in Table 2-4 shows more than half of the states have no marginal
cost, indicating that the CPP is likely to have no effect in those states. Several more states show
marginal costs of less than $2/ton. Of the remaining states, several have major utilities that have
announced long-term plans to support cleaner energy sources and replace existing coal plants
2-34
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with renewable energy. Given this information—which, again, uses the older, more conservative
assumptions for CPP implementation—it is clear that there are multiple, flexible compliance
pathways that states and utilities could undertake to implement the CPP either for no or virtually
no cost.
2.6	Conclusion
Based on the analysis presented above, it is abundantly clear that national existing-source
power sector emissions even without the CPP in effect are below the requirements set forth
under the CPP, when the goals of the CPP are viewed collectively. This is also true at the
regional level. Considering the national emission trends, the regional trends, the flexibility of the
CPP, and the delayed time-line of the CPP, it is likely that there would be no difference between
a baseline that includes the CPP and one that does not. For all these reasons, the EPA believes
that repeal of the CPP under current and reasonably projected market conditions and regulatory
implementation is not anticipated to have a meaningful effect on emissions of CO2 other
pollutants or regulatory compliance costs. As a result, this analysis demonstrating no significant
difference in a scenario with CPP implementation and one without also satisfies any regulatory
impact analysis that may be required by statute or executive order for repeal of the CPP.
2.7	Addendum: IPM Power Sector Projections
This section presents new results and projections from IPM for four scenarios:43
•	Baseline: No regulatory requirements for existing EGUs under 111(d).
•	CPP with National Trading and Tolling: This includes delaying implementation of CPP
by three years and allowing nearly unlimited trading across all states.44
•	CPP with Regional Trading and Tolling: This includes delaying implementation of CPP
by three years and allowing trading within six geographic regions shown in Figure 2-12.
43	All of these CPP scenarios capture the ability for EGUs to bank allowances. The detailed IPM results for these
scenarios can be found in the ACE docket and onEPA's IPM website at: https://www.epa.gov/airmarkets/clean-air-
markets-power-sector-modeling
44	For purposes of this scenario, California and the Regional Greenhouse Gas Initiative (RGGI) states are excluded
from trading with other states for CPP, and must meet their respective legally binding state/regional commitments in
addition to the CPP goals (for RGGI, the CPP goals are aggregated and trading is allowed amongst RGGI states).
The CPP requirements are non-binding for California and RGGI because the state commitments are more stringent.
2-35
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• CPP with Limited Trading: This follows the same assumed CPP implementation as
presented in the Final CPP and proposed ACE RIAs, where each state had to meet its
goal individually and implementation begins in 2022.
The modeling results and projections show that the CPP, accounting for trading and
tolling, produces the same outcomes as the baseline scenario. That is, the CPP has no impact
under this form of CPP implementation. Below are key results of the IPM scenarios, including
CO2 emissions, systemwide costs, and generation mix.
Note that the modeling for both CPP scenarios reflects an option to improve heat rates
between about 2% and 4% at a cost of $110/kW, based on assumptions made in conjunction with
the finalization of the CPP in 2015. This option is not available in the baseline modeling. In the
CPP with Trading and Tolling scenario, the model projects the deployment of a small amount of
HRI-retrofitted capacity (about 150 MW) based on market fundamentals. This small deployment
of HRI affects the cost and emissions projections in the modeling, as reflected in the small
differences presented below. These differences in projections do not result from the CPP-based
CO2 emissions constraints, for which the model projects a $0 allowance price.
2-36
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Table 2-5 Emissions Projections
Baseline
CPP
(National
Trading
and
Tolling)
Percent
Change
from
Baseline
CPP
(Limited
Trading)
Percent
Change
from
Baseline
CPP
(Regional
Trading
and
Tolling)
Percent
Change
from
Baseline
CO2 (million short tons

2025
1,774
1,774
0.0%
1,733
-2.3%
1,767
-0.4%
2030
1,743
1,743
0.0%
1,681
-3.5%
1,733
-0.6%
2035
1,719
1,719
0.0%
1,667
-3.0%
1,709
-0.6%
SO2 (thousand tons)
2025
912.6
913.2
0.1%
894.8
-1.9%
902.4
-1.1%
2030
885.6
887.2
0.2%
853.6
-3.6%
878.7
-0.8%
2035
817.0
815.6
-0.2%
769.7
-5.8%
807.5
-1.2%
NOx (thousand tons)
2025
844.4
844.4
0.0%
803.1
-4.9%
838.1
-0.7%
2030
810.1
810.1
0.0%
761.6
-6.0%
803.7
-0.8%
2035
752.8
753.2
0.0%
712.6
-5.3%
747.1
-0.8%
Hg (tons)
2025
4.7
4.7
0.0%
4.5
-3.4%
4.7
-0.6%
2030
4.5
4.5
0.0%
4.3
-4.5%
4.4
-0.7%
2035
4.0
4.0
0.0%
3.9
-3.4%
4.0
-1.0%
Note: million short tons, thousand short tons, and short tons for CO2, SCh/NOx, and Hg respectively.
Table 2-6 Annual Compliance Costs (Millions 2016$)	
2025	2030	2035
CPP (National Trading and Tolling)	$1.8	$0.2	$5.1
CPP (Limited Trading)	$689.6	$929.0	$517.8
CPP (Regional Trading and Tolling)	-$32.0	$27.2	$138.6
2-37
-------
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CPP (Limited
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CPP (Regional
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Table 2-7 Installed Generating Capacity (GW)
Baseline
CPP
(National
Trading
and
Tolling
Percent
Change
from
Baseline
CPP
(Limited
Trading)
Percent
Change
from
Baseline
CPP
(Regional
Trading
and
Tolling)
Percent
Change
from
Baseline
2025
Coal
172
172
0%
167
-3%
171
-1%
NG Combined Cycle (existing)
262
262
0%
262
0%
262
0%
NG Combined Cycle (new)
3
3
0%
5
79%
3
21%
Combustion Turbine
151
151
0%
151
0%
151
0%
Oil/Gas Steam
72
72
0%
72
0%
72
0%
Non-Hydro Renewables
210
210
0%
213
1%
211
0%
Hydro
110
110
0%
110
0%
110
0%
Nuclear
81
81
0%
81
0%
81
0%
Other
12
12
0%
12
0%
12
0%
Total
1,073
1,073
0%
1,073
0%
1073
0%
2030
Coal
170
170
0%
165
-3%
168
-1%
NG Combined Cycle (existing)
262
262
0%
262
0%
262
0%
NG Combined Cycle (new)
12.7
12.7
0%
15
22%
13
5%
Combustion Turbine
152
152
0%
151
0%
152
0%
Oil/Gas Steam
72
72
0%
71
0%
72
0%
Non-Hydro Renewables
266
266
0%
272
3%
267
1%
Hydro
111
111
0%
110
0%
110
0%
Nuclear
77
77
0%
77
1%
77
0%
Other
13
13
0%
13
0%
13
0%
Total
1,133
1,133
0%
1,138
0%
1134
0%
2035
Coal
165
165
0%
162
-2%
165
0%
NG Combined Cycle (existing)
262
262
0%
262
0%
262
0%
NG Combined Cycle (new)
38
38
0%
42
9%
39
2%
Combustion Turbine
164
164
0%
161
-2%
163
-1%
Oil/Gas Steam
72
72
0%
71
0%
72
0%
Non-Hydro Renewables
270
270
0%
277
3%
272
1%
Hydro
111
111
0%
111
0%
111
0%
Nuclear
75
75
0%
76
1%
76
0%
Other
13
13
0%
13
0%
13
0%
Total
1,170
1,170
0%
1,175
0%
1171
0%
2-39
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CHAPTER 3: COST, EMISSIONS, ECONOMIC, AND ENERGY IMPACTS
3.1	Introduction
This chapter presents the compliance cost, emissions, economic, and energy impact
analysis for the power sector, in support of this final rulemaking. The results are generated from
a detailed power sector model called the Integrated Planning Model (IPM),1 a version of which is
developed and used by the EPA to support regulatory efforts. The model can be used to examine
air pollution control policies for a variety of pollutants throughout the contiguous United States
for the entire power system.
3.2	Overview
This analysis is intended to be an illustrative representation and analysis of the final ACE
rule.2 The final rule presents a framework for states to develop state plans that will establish
standards of performance for existing affected sources of GHG emissions. The final rule does not
itself specify any standard of performance, but rather establishes the "best system of emission
reduction"3 (BSER), i.e. technology options for heat rate improvements (HRI), that states
consider as they develop standards of performance and state plans. States are able to consider
remaining useful life and other source-specific factors in applying the BSER and determining a
standard of performance. In turn, the specific technologies that a source might use to comply
with its standard of performance is generally within the discretion of the source. In addition, the
baseline for this analysis, as shown in Chapter 2, and is called the "baseline".
For these reasons, there is considerable uncertainty regarding the specific standards of
performance states will apply to their sources and the technology measures that might be
implemented as a result of that process. Hence, this analysis presents an illustrative policy
scenario that is intended to broadly reflect how states might apply BSER and develop state plans
and is intended to inform and present the potential impacts of the final rule. The illustrative
policy scenario is described in detail in Chapter 1. This illustrative policy scenario assigns the
same group-specific percentage HRI and associated average capital cost to each unit within each
1	The specific version model used in this RIA is operated by ICF International, at EPA's direction.
2	For more details on legal authority and justification of this action, see rule preamble.
3	The best system of emission reduction (BSER) is outlined in the CAA 111(d), see preamble for further discussion.
3-1
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of 12 groups of affected coal steam unit in the contiguous U.S. The coal-fired EGUs are grouped
based on generating capacity and reported heat rate (see below). The analysis is not meant to
reflect what the EPA believes can be undertaken at each affected source, but rather to estimate
potential national impacts by applying control measures that the EPA believes are reasonable, on
an average basis. Given the unique nature of each individual generating unit and the lack of data
and information on specific individual unit-level actions with regards to the BSER technologies,
in addition to uncertainty about the standards of performance states will apply to their sources,
the EPA believes that this illustrative modeling approach is suitable to inform the potential
impacts of the rule from a national perspective.
As with any detailed modeling and analysis that attempts to quantify the potential future
impact of a regulatory requirement on an industry, there are key areas of uncertainty. Some
uncertainties pertain to how states choose to implement to rule, while there are also are
uncertainties for how affected sources will implement and respond to the regulatory
requirements. There are also broader uncertainties about the overall operation of the electric
system. These factors are discussed later in this chapter and help provide context to the overall
rule, and its potential impacts. Although there are areas of uncertainty, the EPA believes that this
analysis reflects the best available information at the time of analysis, and is a meaningful,
credible, and appropriate reflection of the potential impacts of the rule using the best available
tools.
3.3 Power Sector Modeling Framework
IPM is a state-of-the-art, peer-reviewed, dynamic linear programming model that can be
used to project power sector behavior and examine prospective air pollution control policies
throughout the contiguous United States for the entire electric power system. It provides
forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies
while meeting energy demand and environmental, transmission, dispatch, and reliability
constraints. The EPA has used IPM for over two decades to better understand power sector
behavior into the future and to evaluate the economic and emission impacts of prospective
environmental policies. The EPA uses the best available information from utilities, industry
experts, gas and coal market experts, financial institutions, and government statistics as the basis
for the detailed power sector modeling in IPM. The model documentation provides additional
3-2
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information on the assumptions summarized here as well as all other model assumptions and
inputs.4 The model also incorporates a detailed representation of the fossil-fuel supply system
that is used to forecast equilibrium fuel prices for natural gas and coal. The model accounts for
all significant existing federal and state air, water and land use regulations.
The costs presented in this RIA reflect the IPM-projected annualized estimates of private
compliance costs. The IPM-projected annualized estimates of private compliance costs provided
in this analysis are meant to show the change in production (generating) costs to the power sector
in response to various regulatory changes. The private compliance costs equal the difference
between capital, operating, and fuel expenditures net of taxes and subsidies in the electricity
sector between a baseline and policy scenario. This RIA does not identify who ultimately bears
these compliance costs, such as owners of generating assets through changes in their profits or
electricity consumers through changes in their bills, although the potential impacts on consumers
and producers are described in Chapter 5.5 Furthermore, the EPA uses the projection of private
compliance costs as an estimate of the social cost of the final requirements, as the social cost is
the appropriate metric for formal economic welfare analysis.6 Section 3.9 describes the
limitations with using this estimate of private compliance costs as an estimate of the social cost.
To estimate these annualized capital costs, the EPA uses a conventional and widely
accepted approach that applies a capital recovery factor (CRF) multiplier to capital investments
and adds that to the annual incremental operating expenses. The CRF is derived from estimates
of the cost of capital (private discount rate), the amount of insurance coverage required, local
property taxes, and the life of capital. It is important to note that there is no single CRF factor
applied in the model; rather, the CRF varies across technologies in the model to better simulate
power sector decision-making.
While the CRF is used to annualize costs within IPM, a discount rate is used to estimate
the net present value of the intertemporal flow of the annualized capital and operating costs. The
optimization model then identifies power sector investment decisions that minimize the net
4	For documentation, see https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling
5	As discussed in further detail in Chapter 5, the ultimate incidence of this final action will depend on the
distribution of both the costs and the health and welfare impacts presented in Chapter 4 across households.
6	See, Tietenberg and Lewis, 2008; Freeman, 2003, and USEPA, 2010.
3-3
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present value of all private costs over the full planning horizon while satisfying a wide range of
demand, capacity, reliability, emissions, and other constraints. As explained in model
documentation, the discount rate is derived as a weighted average cost of capital that is a
function of capital structure, post-tax cost of debt, and post-tax cost of equity. It is important to
note that this discount rate is selected for the purposes of best simulating power sector behavior,
and not for the purposes of discounting social costs or benefits.
The EPA has used IPM extensively over the past two decades to analyze options for
reducing power sector emissions. Previously, the model has been used to forecast the costs,
emission changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), Cross-
State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), and the
Clean Power Plan (CPP). IPM has also been used to estimate the air pollution reductions and
power sector impacts of water and waste regulations affecting EGUs, including Cooling Water
Intakes (316(b)) Rule, Disposal of Coal Combustion Residuals from Electric Utilities (CCR) and
Steam Electric Effluent Limitation Guidelines (ELG).
The model and the EPA's input assumptions undergo periodic formal peer review. The
rulemaking process also provides opportunity for expert review and comment by a variety of
stakeholders, including owners and operators of capacity in the electricity sector that is
represented by the model, public interest groups, and other developers of U.S. electricity sector
models. The feedback that the Agency receives provides a highly-detailed review of key input
assumptions, model representation, and modeling results.
3.4 Recent Updates to the EPA's Power Sector Modeling Platform v6 using IPM
In early 2019 the EPA updated its application of IPM to the IPM v6 November 2018
Reference Case. The Reference Case for this analysis is a business-as-usual scenario that would
be expected under market and regulatory conditions in the electricity and related sectors in the
absence of this rule. As such, the IPM Reference Case represents the power sector component of
the baseline for this RIA. This latest application incorporates routine data updates and reflects a
robust representation of electricity generation and related fuel markets. Important updates to the
model since the ACE proposal RIA include:
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•	Use of the Energy Information Agency's (EIA) Annual Energy Outlook (AEO) 2018
demand projections
•	Updated inventory of State and Federal power sector regulations
•	Updates to the EPA's National Electric Energy Data System, the database of existing and
planned-committed units and their emission control configurations
•	Adjustments and updates to nuclear operating costs, based on information from EIA
•	Updated assumptions regarding NOx emissions rates for small fossil units
•	Incorporated the implications of the December 2017 Tax Reform Bill in the discount rate
and capital charge rate calculations
More information on these updates is available in the comprehensive model
documentation, which is available on the EPA's website.7
This analysis reflects the best data available to the EPA at the time the modeling was
conducted. As with any modeling of future projections, many of the inputs are uncertain. In this
context, notable uncertainties include the cost of fuels, the cost to operate existing power plants,
the cost to finance, construct, and operate new power plants, infrastructure, demand, and policies
affecting the electric power sector. The modeling conducted for this RIA is based on estimates of
these variables, which were derived from the data currently available to the EPA. However,
future realizations of these characteristics may deviate from expectations. The results of
counterfactual simulations presented in this RIA are not a prediction of what will happen, but
rather projections of plausible scenarios describing how this final regulatory action may affect
electricity sector outcomes in the absence of unexpected shocks. The results of this RIA should
be viewed in that context.
3.5 Scenario Analyzed
An illustrative policy scenario was analyzed to estimate potential costs and benefits of the
final rules. In this illustrative policy scenario, we assume that HRI potential and costs will differ
based on unit size and efficiency, and not other sources of heterogeneity including location of
units. Affected sources were divided into twelve groups based on three size categories and four
efficiency categories. A representative cost and performance assumption for HRI from the
7 See Documentation for the EPA's Power Sector Modeling Platform v6 Using the Integrated Planning Model,
available at: https://www.epa.gov/airmarkets/epas-power-sector-modeling-platform-v6-using-ipm
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candidate technologies was identified for each grouping. The assumed HRI cost and performance
differs across the groups. The group-specific cost and performance assumptions were then
applied to each unit in the group in the illustrative analysis. We then modeled the application of
these assumptions in the power sector which provides a basis for the costs, emissions, and
benefits analyses that illustrate the potential impacts of the final rules. More information on the
development of the illustrative policy scenario assumptions can be found in Chapter 1.
Table 3-1 HRI Cost and Performance Assumptions for Illustrative Policy Scenario, by
Unit Capacity and Heat Rate

Small
(<25 MW to 200
MW)
Medium
(200 MW to 500 MW)
Large
(>500 MW)
Group 1
(Most Efficient) < 9,773 Btu/kWh
N/A
(<1%)
N/A
(1%)
N/A
(10%)
Group 2
9,774 -10,396 Btu/kWh
1.0% at $47/kW
(1%)
0.8% at $32/kW
(7%)
0.8% at $25/kW
(36%)
Group 3
10,397- 11,019 Btu/kWh
2.1% at $47/kW
(4%)
1.9% at $32/kW
(13%)
1.8% at $25/kW
(15%)
Group 4
(Least Efficient) > 11,020 Btu/kWh
3.2% at $47/kW
(4%)
2.9% at $32/kW
(7%)
2.8% at $25/kW
(3%)
Note: Share of total capacity represented by each category in parentheses.
The year of implementation for the illustrative policy scenario is 2025, as an
approximation for when the standards for performance under the final rule might be
implemented. The requirements do not change over time.
As discussed above, the final rule requires states to develop standards of performance
based on EPA's determination of BSER, which are methods of HRI that reduce CO2 emissions.
The standards of performance are not represented in the model directly and, as discussed above,
are uncertain because the applicability of these technologies across the fleet and the standards of
performance the states will require are uncertain.8 In practice, affected sources may have certain
flexibilities in how they comply with the standards of performance that differs from the
8 Note that, in the modeling, the total cost of the HRI is reflected as a capital cost. However, for some HRI
technologies, a small share of the total cost may be variable, and thus the cost of the HRI might have a small effect
on dispatch decisions.
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technologies used to determine the sources' standards of performance, but this possibility is not
captured in the modeling for this RIA.
In addition, the implementation of HRI at units to meet a standard of performance under
ACE is considerably different than "building block 1" under CPP. Under CPP, the building
blocks represented different groups of technologies (blocks) that were used to establish state-
level CO2 emission goals. Sources were required to meet the state-level emissions goals of the
rule, but were not required to adopt any particular building block as a requirement of the rule. As
such, the modeling for CPP did not require HRI, although it was included as one of many
compliance options in the modeling. The modeling of CPP, as shown in Chapter 2, also shows
that the CPP goals are not expected to produce reductions beyond the baseline in most scenarios,
and thus CPP has no costs or benefits. In the illustrative policy scenario for ACE, the HRI is
implemented as unit-level requirement, and thus has costs and benefits relative to the baseline
(regardless of whether the CPP is included in the baseline). It is not appropriate to think of ACE
as the same as building block 1 under CPP, since there are important differences.
For ease of modeling, in the scenario representing the final ACE rule, sources may adopt
the assumed HRI level or may retire in the model, based on prevailing economics. However, it is
possible that states may use opportunities afforded to them in the final rule when applying BSER
to avoid retirement of affected sources, and the scenario does not capture this possibility.
However, as discussed in Section 3.7.5, the modeling of the illustrative policy scenario projects
about 2 GW of coal retirements, which is a small share of total coal capacity.
It is important to note that current data limits our ability to apply more customized HRI
and cost functions to specific units. Due to these limitations, the EPA used the best available
information, research, and analysis to arrive at the assumptions used in this scenario.
3.6 Monitoring, Reporting, and Recordkeeping Costs
The EPA projected monitoring, reporting and recordkeeping (MR&R) costs for both state
entities and affected EGUs for the years 2023, 2025, 2030, and 2035. The MR&R cost estimates
presented below apply to the illustrative policy scenario.
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In calculating the costs for states, the EPA estimated personnel costs to oversee
compliance, and review and report annually to the EPA on program progress relative to meeting
the state's reduction goal. To calculate the national costs, the EPA estimated that 43 states and
277 facilities would be affected. The EPA estimated that the majority of the additional
monitoring cost to EGUs would be in calculating net energy output. Since the majority of EGUs
have some energy usage meters or other equipment available to them, EPA believes a new
system for calculating net energy output is not needed.
The EPA has made it a priority to streamline reporting and monitoring requirements. In
this rule, the EPA is making implementation as efficient as possible for both the states and the
affected EGUs by allowing state plans to use the current monitoring and recordkeeping
requirements and pathways that have already been well established in other EPA rulemakings.
For example, under the Acid Rain Program's continuous emissions monitoring, 40 CFR Part 75,
The EPA has established requirements for the majority of the EGUs that would be affected by a
111(d) state plan to monitor CO2 emissions and report that data using the Emissions Collection
and Monitoring Plan System (ECMPS). Additionally, since the CO2 hourly data is already
reported to the EPA's ECMPS there is no additional burden associated with the reporting of that
data. Since the ECMPS pathway is already in place, the EPA will allow for states to use the
ECMPS system to facilitate the data reporting of the additional energy output data required under
the emission guidelines.
While not a requirement, if states choose the form of standard to be reflective of net
energy output there may be additional burden for an affected EGU. The EPA estimates that it
would take three working months for a technician to retrofit any existing energy meters to reflect
net energy output. Additionally, the EPA believes that 40 hours will be needed for each EGU
operator to read the rule and understand how the facility will comply with the rule, based on an
average reading rate of 100 words per minute and a projected rule word count of 300,000 words.9
Also, after all modifications are made at a facility to measure net energy output, each EGU's
9 According to one source, the average person can proofread at about 200 words per minute on paper and 180 words
per minute on a monitor. (Source: Ziefle, M. 1988. "Effects of Display Resolution on Visual Performance." Human
Factors 40(4):554-68). Due to the highly technical nature of the rule requirements in subpart UUUUa, a more
conservative estimate of 100 words per minute was used to determine the burden estimate for reading and
understanding rule requirements.
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Data Acquisition System (DAS) would need to be upgraded to supply the rate-based emissions
value to either the state or the EPA's Emissions Collection and Monitoring Plan System
(ECMPS). Note the costs to develop net energy output monitoring and to upgrade each facility's
DAS system are one-time costs incurred in 2023. Recordkeeping and reporting costs
substantially decrease after 2023. The projected costs for 2023, 2025, 2030, and 2035 are
summarized below.
In calculating the cost for states to comply, the EPA estimates that each state will rely on
the equivalent of two full time staff to oversee program implementation, assess progress, develop
possible contingency measures, perform state plan revisions and host the subsequent public
meetings if revisions are indeed needed, download data from the ECMPS for their annual
reporting and develop their annual EPA report. The burden estimate was based on an analysis of
similar tasks performed under the Regional Haze Program, whereby states were required to
develop their list of eligible sources, draft implementation plans, revise initial drafts, identify
baseline controls, identify data gaps, identify initial strategies, conduct various reviews, and
manage their programs. A total estimate of 78,000 hours of labor performed by seven states over
a three-year period resulted in 3,714 hours per year, per entity. Due to the nature of this final rule
whereby we believe each state's air office and the energy office will both be involved in
performing the above-mentioned tasks, we rounded up to the equivalent of two full time staff,
which totaled 4,160 hours per year.10 Table 3-2 presents the estimates of the annual state and
industry respondent burden and costs of reporting and recordkeeping for the illustrative policy
scenario in 2023, 2025, 2030, and 2035.
10 Renewal of the ICR for the Regional Haze Rule, Section 6(a) Tables 1 through 4 based on 7 states' burden. EPA-
HQ-OAR-2003 -0162-0001.
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Table 3-2 Years 2023, 2025, 2030, and 2035: Summary of State and Industry Annual
Respondent Burden and Cost of Reporting and Recordkeeping
	Requirements (million 2016$)	
Totals
Total Annual
Labor Burden
(Hours)
Total
Annual
Labor
Costs
Total
Annualized
Capital
Costs
Total
Annual
O&M Costs
Total
Annualized
Costs
Total
Annual
Respondent
Costs
States
2023
180,000
14
0
0.031
0.031
14
2025
190,000
15
0
0.021
0.021
15
2030
190,000
15
0
0.021
0.021
15
2035
190,000
15
0
0.021
0.021
15
Industry
2023
150,000
14
0
0.28
0.28
14
2025
0
0
0
0
0
0
2030
0
0
0
0
0
0
2035
0
0
0
0
0
0
Total
2023
330,000
28
0
0.31
0.31
28
2025
190,000
15
0
0.021
0.021
15
2030
190,000
15
0
0.021
0.021
15
2035
190,000
15
0
0.021
0.021
15
Note: All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
The labor costs associated with MR&R activities represent part of the total costs of the
rule. Other categories of labor that may be impacted by the rule are described in Section 5.2
"Employment Impacts". Estimates in Table 3-2 of the total annual labor burden in hours, for
MR&R activities, can be converted to estimates of full-time equivalent (FTE) jobs using the
above estimate of 4,160 hours per year for two full time staff, i.e. 2,080 hours per year for one
FTE job. Within this category of MR&R labor, we estimate approximately 73 FTE for industry
in illustrative policy scenario year 2023, and no impact in years 2025, 2030, and 2035.
As shown in Table 3-2, almost all MR&R costs are labor costs. In the context of other
categories of labor potentially impacted by the rule, such as labor associated with HRI, labor
needed for production of electricity by type of fuel, or labor needed for coal or natural gas fuel
production, which are all described in Section 5.2 "Employment Impacts", MR&R labor is a
smaller category. See Section 5.2 for a discussion of the current U.S. economic climate with low
unemployment and full employment conditions, which indicates that while affected workers may
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experience potential impacts due to the rule, overall, such impacts would most likely be
temporary and aggregate employment would be unchanged.
3.7 Projected Power Sector Impacts
The following sections report the results from the power sector modeling, comparing the
illustrative policy scenario to the baseline as the primary comparison point of reference.11 Note
that, unlike the RIA for the proposed rule, the baseline does not include the CPP.
3.7.1 Projected Emissions
Relative to the baseline, the EPA projects that the illustrative policy scenario results in an
annual CO2 emissions decrease from the electricity sector in the contiguous U.S. of less than one
percent in 2025, 2030, and 2035, as shown in Table 3-3. The EPA projects that both baseline and
illustrative policy case system-wide CO2 emissions are 36% lower than 2005 emissions levels by
2035, as shown in Table 3-4 (inclusion of 2005 emissions provides a static comparison point and
is consistent with past RIAs).
Table 3-3 Projected CO2 Electric Sector Emission Impacts, Relative to Baseline

CO2 Emissions
(MM Short Tons)
2025 2030 2035
CO2 Emissions Change
(MM Short Tons)
2025 2030 2035
CO2 Emissions Change
Percent Change
2025 2030 2035
Baseline
Illustrative Policy Scenario
1,774 1,743 1,719
1,762 1,732 1,709
-12 -11 -9.3
-0.7% -0.7% -0.5%
Table 3-4 Projected Electric Sector CO2 Emission Impacts, Relative to 2005

CO2 Emissions
(MM Short Tons)
2025 2030 2035
CO2 Emissions:
Change from 2005
(MM Short Tons)
2025 2030 2035
CO2 Emissions:
Percent Change from
2005
2025 2030 2035
Baseline
Illustrative Policy Scenario
1,774 1,743 1,719
1,762 1,732 1,709
-909 -940 -964
-921 -951 -974
-34% -35% -36%
-34% -35% -36%
11 The detailed modeling output files for all of the scenarios described in this chapter are available in the docket and
on the EPA's website, which include additional data and information, including results from additional model run
years.
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Table 3-5 shows that under the illustrative policy scenario, the EPA projects a less than
one percent decrease in sulfur dioxide (SO2) emissions annually in 2025, 2030, and 2035.
Additionally, the EPA projects a less than one percent decrease in nitrogen oxides (NOx)
emissions annually in 2025, 2030, and 2035. In addition to decreases in SO2 and NOx emissions,
the EPA also projects a less than one percent decrease in mercury (Hg) emissions in 2025, 2030,
and 2035.
Table 3-5 Projected Electric Sector Emissions of SO2, NOx, and Hg

Baseline
Illustrative Policy
Scenario
Emissions
Change
Percent Change
from Base
SO2 (thousand tons)
2025
912.6
908.5
-4.1
-0.4%
2030
885.6
879.9
-5.7
-0.6%
2035
817.0
810.6
-6.4
-0.8%
NOx (thousand tons)
2025
844.4
837.1
-7.3
-0.9%
2030
810.1
803.0
-7.1
-0.9%
2035
752.8
746.8
-6.0
-0.8%
Hg (tons)
2025
4.7
4.7
-0.03
-0.7%
2030
4.5
4.4
-0.03
-0.7%
2035
4.0
4.0
-0.03
-0.6%
3.7.2 Projected Compliance Costs
The power industry's compliance costs are represented in this analysis as the change in
total electric power generation costs, also known as the system costs, between the baseline and
the illustrative policy scenario, including the cost of MR&R. The system costs include projected
power industry expenditures on capital, operating and fuels, and reflect the least cost power
system outcome in response to assumed market and regulatory requirements. In simple terms, the
compliance costs are an estimate of the change in projected system costs between two scenarios.
This RIA does not identify who ultimately bears these compliance costs, such as owners of
generating assets through changes in their profits or electricity consumers through changes in
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their bills, although the potential impacts on consumers and producers are described in Chapter
5.12
As shown in Table 3-6, the EPA projects that the annual compliance costs of the
illustrative policy scenario range from about $290 million in 2025 to $25 million in 2035. The
lower 2035 compliance cost estimate results from a temporal shift in projected new generation
capacity and projected changes in fuel prices over time and between scenarios.13
Table 3-6 Annualized Compliance Costs, Relative to Baseline (millions of 2016$)

2025
2030
2035
Illustrative Policy Scenario
$290
$280
$25
Note: Includes MR&R costs (see Section 3.6). All estimates are rounded to two significant figures.
The annual compliance cost of the illustrative policy scenario is the difference in total
annualized production costs between the baseline and the illustrative policy scenario, plus the
costs of monitoring, reporting, and recordkeeping. The breakdown of the costs that compose the
production costs are also shown below. The total production costs can be broken down into
operations and maintenance costs (both variable and fixed), fuel expenditures, and capital
expenditures. The changes in projected costs are related to the HRI assumed that most affected
sources are assumed to install in the illustrative policy scenario. For example, the HRI assumes
some modest increase in capital cost investment, while improving overall performance and heat
rate of affected sources (which leads to slightly less fuel expenditures).14
12	Note that the projected compliance costs in this RIA reflect changes in total system costs and do not reflect
potential projected changes in electricity consumer expenditures (e.g., expenditures on net imports, which are a very
small percentage of total system costs).
13	Changes in the cost of generation in the power sector arise because of the cost of investing in HRI, changes in fuel
consumption at affected sources, and changes in costs from other non-regulated sources. The HRI assumed to be
adopted in the illustrative policy scenario are energy (fuel) efficiency investments. For the purposes of this analysis,
the fuel savings for affected sources associated with these energy efficiency investments are treated as an offsetting
cost, and not a benefit, of this regulatory action.
14	Note that the projected total system fuel costs decrease includes overall net decreases for some fuels (e.g., coal)
and increases for other fuels (e.g., nuclear).
3-13
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Table 3-7 Total Production Costs (millions of 2016$)

2025
2030
2035
Variable O&M
Baseline
10,057
9,963
9,931
Illustrative Policy Scenario
10,052
9,978
9,948
Change
-5
15
18
Fixed O&M
Baseline
50,211
51,383
52,644
Illustrative Policy Scenario
50,126
51,312
52,590
Change
-85
-70
-53
Fuel
Baseline
67,405
67,943
69,948
Illustrative Policy Scenario
67,075
67,616
69,464
Change
-329
-326
-484
Capital
Baseline
14,077
23,085
27,420
Illustrative Policy Scenario
14,770
23,727
27,949
Change
693
643
529
Total Production Costs
Baseline
141,750
152,374
159,942
Illustrative Policy Scenario
142,024
152,634
159,951
Change
274
260
10
Note: Does not include MR&R costs (see Section 3.6).
3.7.3 Projected Compliance Actions for Emissions Reductions
As discussed above, the illustrative policy scenario requires that most affected sources
invest in measures that improve the heat rate performance of each source to continue operation,
or they must otherwise retire. A relatively small number of affected sources (see below) are
projected to retire while all others are assumed to adopt the HRI, which reduces the amount of
fuel necessary to generate electricity, and thus decreases the CO2 emissions rate (per unit output)
of affected sources. The generation-weighted average CO2 emissions rate from coal-fired EGUs
larger than 25 MW is 1.2 percent lower in the illustrative policy scenario than the baseline in the
years 2025, 2030, and 2035. In the modeling of the illustrative policy scenario, the sources that
are projected to operate are projected to, on average, increase generation as a result of the HRI.
This increase in generation, coupled with a decrease in the CO2 emissions rate, largely results in
an overall decrease in CO2 emissions from the affected sources, relative to the baseline. Under
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the illustrative policy scenario, emissions are projected to increase at some EGUs, representing a
small share of overall capacity. See Table 3-8 below for a summary of projected CO2 emissions
by generation sources under each scenario, and Table 3-9, Table 3-10, and Table 3-11 for a
summary of projected SO2, NOx, and Hg emissions, respectively. Emission changes are reported
for all coal-fired EGUs, which are those subject to the final rule, and all other emitting electricity
generators. See Figure 3-1, Figure 3-2, Figure 3-3, Figure 3-4, and Figure 3-5 for a summary of
the distribution of projected CO2, SO2, and NOx emissions increases and decreases at affected
units in 2025 in the illustrative policy scenario. These figures present the total capacity and total
2025 emissions changes in the illustrative policy scenario relative to the baseline, aggregated into
two groups: units projected to increase emissions, and units projected to decrease emissions.
These aggregate projected changes are further broken down by the four heat rate groups on
which the assumed HRI are assigned in the modeling (see Table 3-1). It is important to again
note the illustrative nature of the policy scenario when interpreting these results. For further
discussion, see Limitations section below.
Table 3-8 Projected CO2 Emissions by Generation Source (MM short tons)

Coal > 25 MW
All Other
Total
2025
Baseline
1,004
770
1,774
Illustrative Policy Scenario
995
767
1,762
Change
-10
-3
-12
2030
Baseline
964
778
1,743
Illustrative Policy Scenario
955
776
1,732
Change
-9
-2
-11
2035
Baseline
859
860
1,719
Illustrative Policy Scenario
850
860
1,709
Change
-9
0
-9
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Table 3-9
Projected SO2 Emissions by Generation Source (thousand short tons)
Coal > 25 MW	All Other	Total
2025
Baseline
877
35
913
Illustrative Policy Scenario
873
35
908
Change
-4
0
-4
2030
Baseline
859
27
886
Illustrative Policy Scenario
853
27
880
Change
-6
1
-6
2035
Baseline
798
19
817
Illustrative Policy Scenario
791
20
811
Change
-8
1
-6
Table 3-10 Projected NOx Emissions by Generation Source (thousand short tons)

Coal > 25 MW
All Other
Total
2025
Baseline
608
237
844
Illustrative Policy Scenario
603
235
837
Change
-5
-2
-7
2030
Baseline
578
232
810
Illustrative Policy Scenario
572
231
803
Change
-6
-1
-7
2035
Baseline
511
242
753
Illustrative Policy Scenario
504
242
747
Change
-6
0
-6
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Table 3-11 Projected Hg Emissions by Generation Source (short tons)
Coal > 25 MW
All Other
Total
2025
Baseline
3.3
1.4
4.7
Illustrative Policy Scenario
3.3
1.4
4.7
Change
0.0
0.0
0.0
2030
Baseline
3.1
1.4
4.5
Illustrative Policy Scenario
3.1
1.4
4.4
Change
0.0
0.0
0.0
2035
Baseline
2.7
1.3
4.0
Illustrative Policy Scenario
2.7
1.3
4.0
Change
0.0
0.0
0.0
Note: Values may not sum due to rounding.
12D
100
BO
60
40
20
Group 1
Group 2
I Increase C02
Group 3
Decrease C02

Group 4
Figure 3-1 Projected Distribution of Affected Unit Capacity in 2025, by Heat Rate
Group (GW)
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Group 1
Group 2
Group 3
Group 4
-2
-4
-6
-S
-10
I Increase C02
Decrease €02
Figure 3-2 Projected Change in CO2 Emissions at Affected Units in 2025, by Heat Rate
Group (million short tons)


















Group 1
Group 2

Group 3

Group 4

















-10
¦ Incr ease 502 ¦ Deer ease 502
Figure 3-3 Projected Change in SO2 Emissions at Affected Units in 2025, by Heat Rate
Group (thousand tons)
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Group 1
Group 2

Group 3

Group 4























-5
-6
¦ Increase NOx ¦ Decrease NOx
Figure 3-4 Projected Change in Annual NOx Emissions at Affected Units in 2025, by
Heat Rate Group (thousand tons)
Figure 3-5 Projected Change in Ozone Season NOx Emissions at Affected Units in 2025,
by Heat Rate Group (thousand tons)
As described in Chapter 1, coal-fired EGUs decrease their heat rate 0.8 percent to 3.2
percent, which assumes an approach for how each affected source complies with its standard of
performance (there are four groups, with three making heat rate improvements). As shown in
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Figure 3-1 through Figure 3-5, each Group has many units that decrease emissions and some that
increase their emissions of CO2 and other pollutants, while on net total emissions from the coal-
fired EGUs is lower, consistent with their collective fuel efficiency increase. Therefore,
consistent with the requirements of the rule, the market modeling shows that units affected by
ACE are expected to make small changes in their emissions relative to the baseline. Furthermore,
the modeling shows that no set of EGUs that increase or decrease their emissions in each Group
has a dominant effect on the total system-wide emissions changes, consistent with the rule and
expected market behavior. The system-wide emission reductions are expected to be a small
percentage of total emissions, as the emissions changes at each coal unit is small and these
changes are diffuse across the coal units in the fleet.15
Furthermore, regardless of various sources of uncertainty in baseline market conditions,
since all coal units in the baseline would be subject to the regulation and may make incremental
changes in their emissions, the emissions changes and market outcomes would be consistent with
the baseline population of coal generating units. If there are more coal EGUs in the baseline,
there would be more coal EGUs making incremental changes, and the system-wide emissions
reductions would likely be higher and commensurate with the greater number of coal units, all
else equal.16 Likewise, if there were fewer coal units, there be lower system-side emissions
reductions. Similarly, if units were subject to more or less stringent standards of performance
consistent with the application of BSER (relative the assumptions in the illustrative policy
scenario), emission reductions as a result of ACE would rise or fall accordingly, but consistent
with the range of the standards of performance that could be achieved from the application of
HRI that is BSER.
15	The emissions from other generating sources not affected by the rule also fall, contributing to system-wide
emission reductions. However, as shown in Tables 3-8 through 3-11, the majority of the projected system-wide
emission reductions for each pollutant are from emissions changes at coal-fired EGUs >25MW. Given the potential
for small increases in generation associated with small changes in fuel efficiency at affected coal EGUs, the
reduction in emissions at other generating sources as a result of ACE is expected to be small, regardless of baseline
economic conditions and the requirements imposed on each affected coal EGU as a result of ACE.
16	Hypothetically, even if the reduction or increase in the baseline number of coal units were concentrated amongst
those units that increase or decrease their emissions in one of the groups in the illustrative policy scenario, the net
effect on total system-wide emissions, and relative to the emissions reductions projected in the illustrative policy
scenario, would be small, as indicated by the magnitude of the bars in Figures 3 -2 through 3-5. Furthermore, as
discussed below, other regulatory and market conditions would likely mitigate notable emissions increases at
individual units as a result of ACE.
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3.7.4 Projected Generation Mix
Generation by generator type for each of the scenarios is reported in Table 3-12. As can
be seen, the illustrative policy scenario shows an overall increase in generation from the coal
steam units covered by this final rule, and an overall decrease in generation from natural gas
combined cycles. Overall, the absolute changes in generation are very small in the context of
total electric generating mix and the uncertainties previously discussed. Figure 3-6 summarizes
the information in the table.
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Table 3-12 Projected Generation Mix (thousand GWh)

Baseline
Illustrative Policy
Scenario
Percent
Change from
Baseline
2025
Coal
915
917
0.3%
NG Combined Cycle (existing)
1,555
1,548
-0.4%
NG Combined Cycle (new)
21
27
24.3%
Combustion Turbine
38
36
-3.8%
Oil/Gas Steam
61
60
-1.5%
Non-Hydro Renewables
583
584
0.3%
Hydro
324
323
-0.1%
Nuclear
643
643
0.0%
Other
41
41
0.1%
Total
4,179
4,179
0.0%
2030
Coal
878
880
0.2%
NG Combined Cycle (existing)
1,520
1,514
-0.4%
NG Combined Cycle (new)
97
102
5.9%
Combustion Turbine
39
39
-1.9%
Oil/Gas Steam
57
56
-1.4%
Non-Hydro Renewables
730
729
-0.1%
Hydro
326
327
0.2%
Nuclear
604
605
0.1%
Other
41
41
0.3%
Total
4,293
4,293
0.0%
2035
Coal
780
781
0.1%
NG Combined Cycle (existing)
1,521
1,520
-0.1%
NG Combined Cycle (new)
292
291
-0.4%
Combustion Turbine
54
55
1.0%
Oil/Gas Steam
60
61
2.2%
Non-Hydro Renewables
742
741
-0.1%
Hydro
328
328
0.0%
Nuclear
597
597
0.1%
Other
41
41
0.2%
Total
4,414
4,415
0.0%
3-22
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5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
I Coal ¦ Natural Gas ¦ Nuclear ¦ Non-hydro Renewables ¦ Hydroelectric BOther
2025	2030	2035
597
598
643
Base Case
Illustrative Policy
Scenario
604
1,713
Base Case
605
1,711
Illustrative Policy
Scenario
Figure 3-6 Generation Mix (thousand GWh)
597
Base Case
597
Illustrative Policy
Scenario
3.7.5 Projected Changes to Generating Capacity
Capacity by generator type for the illustrative policy scenario is reported in Table 3-13.
Relative to the baseline, the EPA projects a decrease in overall coal capacity of approximately 2
GW or one percent. Commensurately, by 2035, the EPA projects a small increase in operating
combustion turbine, renewable, and nuclear capacity. Although the EPA projects a 24 percent
increase in new NGCC capacity (~1 GW) relative to the baseline in 2025, the absolute change is
relatively small in the context of total electric system operation. There is relatively small or no
change in 2030 and 2035, reflecting a temporal shift in projected new NGCC capacity
construction. Table 3-14 shows the incremental capacity additions over time in the illustrative
policy scenario relative to the baseline for natural gas combined cycle capacity and renewable
technologies, which were highlighted in the 2015 CPP RIA. These tables more readily reveal
how the temporal flows of these capacity increases differ across the scenarios than the preceding
tables.
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Table 3-13 Total Generation Capacity by 2025-2035 (GW)

Baseline
Illustrative Policy
Scenario
Percent
Change from
Baseline
2025
Coal
172
170
-1.2%
NG Combined Cycle (existing)
262
262
0.0%
NG Combined Cycle (new)
3
4
24.3%
Combustion Turbine
151
151
0.1%
Oil/Gas Steam
72
72
0.5%
Non-Hydro Renewables
210
212
0.5%
Hydro
110
110
0.0%
Nuclear
81
81
0.0%
Other
12
12
0.0%
Total
1,073
1,073
0.0%
2030
Coal
170
168
-1.2%
NG Combined Cycle (existing)
262
262
0.0%
NG Combined Cycle (new)
12.7
134
5.9%
Combustion Turbine
152
152
0.4%
Oil/Gas Steam
72
72
0.5%
Non-Hydro Renewables
266
266
0.1%
Hydro
111
111
0.1%
Nuclear
77
77
0.1%
Other
13
13
0.0%
Total
1,133
1,133
0.0%
2035
Coal
165
163
-1.0%
NG Combined Cycle (existing)
262
262
0.0%
NG Combined Cycle (new)
38
38
-0.4%
Combustion Turbine
164
165
0.8%
Oil/Gas Steam
72
72
0.5%
Non-Hydro Renewables
270
271
0.0%
Hydro
111
111
0.0%
Nuclear
75
76
0.1%
Other
13
13
0.0%
Total
1,170
1,170
0.0%
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Table 3-14 Projected Natural Gas Combined Cycle and Renewable Capacity Additions
	and Changes Relative to Baseline	

Cumulative Capacity Additions:
NGCC (GW)
Cumulative Capacity Additions:
Renewables (GW)

2025
2030
2035
2025
2030 2035
Baseline
2.8
12.7
38.3
97.7
153.4 158.5
Illustrative Policy Scenario
3.5
13.4
38.1
98.9
153.7 158.6
Incremental
0.7
0.7
-0.1
1.1
©
©
Percent Change
24.3%
5.9%
-0.4%
1.2%
0.2% 0.1%
3.7.6 Projected Coal Production and Natural Gas Use for the Electric Power Sector
Relative to the baseline, the EPA projects a one percent decrease in annual overall coal
production for use by the electric power sector in the illustrative policy scenario over 2025-2035,
as shown in Table 3-15, Table 3-16, and Table 3-17. Most of this decrease is projected to occur
in production of western subbituminous coals.
Table 3-15 2025 Projected Coal Production for the Electric Power Sector (million short
	tons)	

Baseline
Illustrative Policy
Scenario
Change
Percent
Change
Appalachia
Interior
West
Waste Coal
Total
64
120
319
0.24
503
64
119
315
0.17
497
-1
-1
-4
-0.07
-5
-1.0%
-0.6%
-1.2%
-28.0%
-1.1%
Table 3-16
2030 Projected Coal Production for the Electric Power Sector (million short
tons)

Baseline
Illustrative Policy
Scenario
Change
Percent Change
Appalachia
Interior
West
Waste Coal
Total
55
117
311
0.19
484
54
117
308
0.17
479
-1
-1
-3
-0.02
-5
-1.8%
-0.6%
-1.0%
-10.5%
-1.0%
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Table 3-17 2035 Projected Coal Production for the Electric Power Sector (million short
tons)

Baseline
Illustrative Policy
Scenario
Change
Percent Change
Appalachia
35
34
-1
-4.1%
Interior
108
108
0
0.1%
West
291
288
-3
-1.1%
Waste Coal
0.17
0.17
0.00
0.0%
Total
435
430
-4
-1.0%
Relative to the baseline the EPA projects a less than one percent reduction in total gas use
in the electric power sector, as shown in Table 3-18.
Table 3-18 Projected Power Sector Gas Use


Power Sector Gas Use (TCF)


2025
2030
2035
Baseline
11.92
12.11
13.46
Illustrative Policy Scenario
11.88
12.08
13.46
Incremental
-0.04
-0.03
0.00
Percent Change
-0.4%
-0.3%
0.0%
3.7.7 Projected Fuel Price, Market, and Infrastructure Impacts
Relative to the baseline, the illustrative policy scenario results in small changes in electric
power sector delivered coal and natural gas prices, on a Btu-weighted average basis. Depending
on the year, the EPA projects a very small reduction in delivered natural gas prices on the order
of up to one tenth of one percent, as shown in Table 3-19 and Table 3-20.
Table 3-19 Projected Average Minemouth and Delivered Coal Prices (2016$/MMBtu)


Minemouth

Delivered
- Electric Power Sector

2025
2030
2035
2025
2030
2035
Baseline
1.25
1.31
1.38
2.00
2.06
2.10
Illustrative Policy Scenario
1.25
1.31
1.38
2.00
2.06
2.10
Incremental
0.00
0.00
0.00
0.00
0.00
0.00
Percent Change
0.2%
0.0%
-0.1%
0.1%
0.0%
-0.1%
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Table 3-20 Projected Average Henry Hub (spot) and Delivered Natural Gas Prices
(2016$/MMBtu)


Henry Hub

Delivered
- Electric Power Sector

2025
2030
2035
2025
2030
2035
Baseline
3.56
3.64
3.70
3.57
3.60
3.51
Illustrative Policy Scenario
3.56
3.64
3.68
3.57
3.60
3.49
Incremental
0.00
0.00
-0.02
0.00
0.00
-0.02
Percent Change
0.0%
0.0%
-0.6%
0.0%
-0.1%
-0.6%
3.7.8 Projected Retail Electricity Prices
Relative to the baseline, the EPA estimates the impact of the illustrative policy scenario
on retail electricity prices to be very small, on average.17 See Table 3-21. Given the limitations of
this analysis, including the uncertainty regarding state implementation and availability of BSER
HRI technologies at individual coal-fired EGUs (see Chapter 1 and Section 3.9), the RIA
presents retail price projections at a national level. Under the illustrative policy scenario, the
EPA projects changes in average retail electricity prices across the contiguous U.S. ranging up to
an increase of one-tenth of one percent, relative to the baseline.
Table 3-21 Projected Contiguous U.S. Retail Electricity Prices (cents/kWh), 2025-2035

2025
2030
2035
Baseline
10.49
10.71
10.83
Illustrative Policy Scenario
10.50
10.72
10.83
Percent Change
0.1%
0.1%
0.0%
3.8 Sensitivity: 45Q Tax Credit Revisions under the Bipartisan Budget Act of 2018
The baseline modeling for this analysis, completed with the EPA's Power Sector
Modeling Platform v6 using IPM, does not reflect the revisions to section 45Q tax credits for
carbon dioxide sequestration stipulated in the Bipartisan Budget Act of 2018. This legislation
provides a credit for sequestered carbon dioxide that increases to $35 per metric tonne by 2026.
Preliminary EPA analysis suggests that this credit may have an impact on the future deployment
17 The electricity price impacts are estimated using the Retail Price Model (RPM) and IPM model outputs.
Documentation for the RPM is available at: https://www.epa.gov/airmarkets/epas-power-sector-modeling-platform-
v6-using-ipm
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of carbon capture and storage technology, and consequently might impact how affected sources
might comply with the final rule.
The EPA projects that incorporating the revised 45Q tax credits into the baseline would
reduce total electric sector CO2 emissions between 22 and 24 million short tons annually over the
2025-2035 period. This decrease in electric sector emissions is largely attributable to the
sequestration of carbon dioxide projected by IPM at just over 3 GW of projected CCS retrofits at
existing coal-fired EGUs. This retrofit capacity is projected by the model to be installed at
approximately 8 facilities throughout the contiguous U.S. and is associated with enhanced oil
recovery (EOR) at all projected installations. For modeling purposes, the EPA assumes that these
retrofits are capable of reducing the CO2 emissions rate by 90%.18 The EPA does not expect that
that inclusion of this tax credit would have a significant impact on the incremental results
presented in this RIA. For further details regarding this scenario, see IPM v6 November 2018
Reference Case with 45Q, available in the docket.
3.9 Limitations of Analysis and Key Areas of Uncertainty
Cost estimates for the illustrative policy scenario are based on rigorous power sector
modeling using ICF's Integrated Planning Model. IPM assumes "perfect foresight" of market
conditions over the time horizon modeled deterministically; to the extent that utilities and/or
energy regulators have different judgments about future conditions affecting the economics of
operation or pollution control, costs may be understated or overstated. The modeling reported in
this chapter is based on expert judgment of various input assumptions for variables whose
outcomes are in fact uncertain, including fuel supplies, technology costs, and electricity demand.
As a general matter, the Agency reviews the best available information regarding these and other
variables to support a reasonable modeling framework for analyzing the cost, emission changes,
and other impacts of regulatory actions.
As previously stated, this analysis is intended to be illustrative, based on a reasonable
estimate of how states might apply the BSER taking account of source-specific factors in setting
standards of performance, and how sources might comply with those standards. It is important to
18 For documentation, see https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling
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note that the EPA has not analyzed or modeled a specific standard of performance, given that
this rule establishes BSER, and it is up to states to determine appropriate standards of
performance for sources. As such, there is inadequate and incomplete information regarding how
states might specifically implement this rule, and the estimated range of costs and impacts
presented in this chapter is based on the assumptions described above in this Chapter and in
detail in Chapter 1. If sources use compliance options that were not modeled, costs could be
lower. Additionally, while the results presented in this RIA indicate the potential for emissions
increases at some units in conjunction with making the assumed HRIs (though total emissions
are projected to decline), this RIA does not evaluate any potential associated impacts related to
New Source Review and how it may mitigate these increases and affect the cost and emissions
impacts of this final rule.
In addition to the uncertainty regarding state implementation of the policy, there are
several key areas of uncertainty related to the electric power sector that are worth noting,
including:
•	Electric demand: The analysis includes an assumption for future electric demand. To the
extent electric demand is higher and lower, it may increase/decrease the projected future
composition of the fleet.
•	Natural gas supply and demand: Large increases in supply over the last few years, and
relatively low prices, are represented in the analysis. To the extent prices are higher or
lower, it would influence the use of natural gas for electricity generation and overall
competitiveness of other EGUs (e.g., coal and nuclear units).
•	Longer-term planning by utilities: Many utilities have announced long-term clean energy
and/or climate commitments, with a phasing out of large amounts of coal capacity by
2030 and continuing through- 2050. These announcements, some of which are not legally
binding, are not necessarily reflected in the baseline, and may alter the amount of coal
capacity projected in the baseline that would be covered under ACE.
These are key uncertainties that may affect the overall composition of electric power
generation fleet, and could thus have an effect on the estimated costs and impacts of this action.
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However, these uncertainties would affect the modeling of the baseline and illustrative policy
scenario similarly, and therefore the impact on the incremental projections (reflecting the
potential costs/benefits of the illustrative policy scenario) would be more limited and are not
likely to result in notable changes to the assessment of ACE found in this chapter.
While it is important to recognize these key areas of uncertainty, they do not change the
EPA's overall confidence in the estimated impacts of the illustrative policy scenario presented in
this chapter. The EPA continues to monitor industry developments, and makes appropriate
updates to the modeling platforms in order to reflect the best and most current data available.
The EPA made different heat rate assumptions in the baseline for this RIA than the
illustrative policy scenario. In the baseline the EPA assumed that HRI options (beyond the heat
rates already demonstrated at units in recently reported data) were not under active consideration
by facility operators in the absence of a regulatory requirement to do so, and this baseline
therefore does not represent any endogenous HRI potential.
The analysis in this chapter is limited to the effects of the final rule in the contiguous U.S.
The analysis in this RIA excludes the potential costs and emission changes incurred in non-
contiguous states and territories from the final rule (as well as the benefits from changes in
emissions from and in those areas).19
IPM assumes a fixed quantity of electricity demand over the modeling timeframe, which
does not change in response to changes in retail electricity prices. In reality, the quantity of
electricity demanded may change either through consumer response or the adoption of demand-
side energy efficiency programs. Changes in the demand for electricity affect both compliance
and social costs. Generally, an assumption that the quantity of electricity demanded does not
change with changes in electricity prices leads to higher partial equilibrium estimates of the cost
of policy, but this is not always the case. As noted above, the estimated impact on average retail
electricity prices under this rule is very small.
19 The limited exception to this is MR&R costs, as MR&R costs are estimated for 43 states. Five contiguous states
are estimated to have no MR&R costs and are expected to submit a negative declaration.
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Potential changes in emissions other than emissions of CO2, SO2, NOx and Hg from the
electricity sector are not modeled endogenously in IPM and are not reported in this chapter. This
includes hazardous air pollutants and direct fine particulate matter (PM2.5) emissions and water
emissions. Changes in direct PM2.5 emissions are modeled using ancillary IPM outputs and other
information as described in Chapter 4. Similarly, the potential changes in emissions from
producing fuels, such as methane from coal and gas production, are not estimated in this Chapter.
Therefore, the associated effects on heath, ecosystems, and visibility from these potential
changes in other pollutants from the electricity and other sectors are not quantified in subsequent
chapters.
As discussed in the EPA's Guidelines for Preparing Economic Analyses, social costs are
the total economic burden of a regulatory action. This burden is the sum of all opportunity costs
incurred due to the regulatory action, where an opportunity cost is the value lost to society of any
goods and services that will not be produced and consumed as a result of reallocating some
resources related to changes in pollution levels. Estimates of social costs may be compared to the
social benefits expected as a result of a regulation to assess its net impact on society. The social
costs of a regulatory action will not necessarily be equivalent to the expenditures associated with
compliance. Nonetheless, here we use compliance costs as a proxy for social costs. Differences
between estimates of social cost include the treatment of tax payments and subsidy receipts, the
changes in which are accounted for in compliance costs but would be excluded from the estimate
of social costs as they are a transfer. Social costs also include the effect of the regulation on
profitability of suppliers to the electricity sector.20 Also, a social cost estimate would account for
how the regulation would affect preexisting distortions in the economy that reduce economic
efficiency. Chapter 5 discusses these other potential effects of the regulation and how they may
affect the estimates of social costs and benefits.
20 Much of the social cost borne by electricity consumers is accounted for in the compliance cost estimate as they
ultimately will bear part of this cost through changes in electricity prices. Note that this analysis does not identify
who ultimately bears the compliance costs, which also include owners of generating assets through changes in their
profits.
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3.10 References
Freeman, Myrick. 2003. The Measurement of Environmental and Resource Values. 2nd Edition.
Resources for the Future: Washington D.C.
Tietenberg, Tom and Lynne Lewis. 2009. Environmental & Natural Resource Economics. 10th
Edition. Routledge: New York.
U.S. Energy Information Administration (U.S. EIA), 2017. Assumptions to the Annual Energy
Outlook 2017. Available at
https://www.eia.gov/outlooks/aeo/assumptions/pdf/0554(2017).pdf.
U.S. Environmental Protection Agency (EPA), 2010. Guidelines for Preparing Economic
Analyses. Available at: https://www.epa.gov/environmental-economics/guidelines-
preparing-economic-analyses
U.S. Environmental Protection Agency (EPA). 2015a. Regulatory Impact Analysis for the Clean
Power Plan Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and
Standards, Health and Environmental Impacts Division, Research Triangle Park, NC.
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CHAPTER 4: ESTIMATED CLIMATE BENEFITS AND HUMAN HEALTH CO-
BENEFITS
4.1	Introduction
Implementing the final rule is expected to decrease emissions of carbon dioxide (CO2)
and certain pollutants in the atmosphere that adversely affect human health as compared to the
baseline. Pollutant emissions include directly emitted fine particles (PM2.5; particles with an
aerodynamic diameter of 2.5 microns or smaller), sulfur dioxide (SO2), oxides of nitrogen
(NOx), and mercury (Hg). SO2 and NOx are each a precursor to ambient PM2.5, and NOx
emissions are also a precursor in the formation of ambient ground-level ozone.
This chapter describes the methods used to estimate the domestic climate benefits
associated with the decrease in CO2 emissions and domestic health benefits associated with the
decrease in PM2.5 and ground-level ozone. The EPA refers to the climate benefits as "targeted
pollutant benefits" as they reflect the direct benefits of reducing CO2, and to the ancillary health
benefits derived from reductions in emissions other than CO2 as "co-benefits" as they are not
direct benefits from reducing the targeted pollutant. Data, resource, and methodological
limitations prevent the EPA from estimating all domestic climate benefits and health and
environmental co-benefits, including those from health effects from direct exposure to SO2, NO2,
and hazardous air pollutants (HAP) including Hg, and ecosystem effects and visibility
impairment. We discuss these unquantified effects in Section 4.7.
4.2	Climate Change Impacts
In 2009, the EPA Administrator found that elevated concentrations of greenhouse gases
in the atmosphere may reasonably be anticipated both to endanger public health and to endanger
public welfare.1 It is these adverse impacts that necessitate the EPA regulation of GHGs from
EGU sources. Since 2009, other science assessments suggest accelerating trends.2
1	"Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air
Act," 74 Fed. Reg. 66,496 (Dec. 15, 2009) ("Endangerment Finding").
2	Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United
States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp.
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4.3 Approach to Estimating Climate Benefits from CO2
We estimate the climate benefits from this final rulemaking using a measure of the
domestic social cost of carbon (SC-CO2). The SC-CO2 is a metric that estimates the monetary
value of projected impacts associated with marginal changes in CO2 emissions in a given year. It
includes a wide range of anticipated climate impacts, such as net changes in agricultural
productivity and human health, property damage from increased flood risk, and changes in
energy system costs, such as reduced costs for heating and increased costs for air conditioning. It
is typically used to assess the avoided damages as a result of regulatory actions (i.e., benefits of
rulemakings that lead to an incremental reduction in cumulative global CO2 emissions). The SC-
CO2 estimates used in this RIA focus on the projected impacts of climate change that are
anticipated to directly occur within U.S. borders.
The SC-CO2 estimates presented in this RIA are interim values developed under E.O.
13783 for use in regulatory analyses until an improved estimate of the impacts of climate change
to the U.S. can be developed based on the best available science and economics. E.O. 13783
directed agencies to ensure that estimates of the social cost of greenhouse gases used in
regulatory analyses "are based on the best available science and economics" and are consistent
with the guidance contained in OMB Circular A-4, "including with respect to the consideration
of domestic versus international impacts and the consideration of appropriate discount rates"
(E.O. 13783, Section 5(c)). In addition, E.O. 13783 withdrew the technical support documents
(TSDs) used in the 2015 CPP RIA for describing the global social cost of greenhouse gas
estimates developed under the prior Administration as no longer representative of government
policy.
Regarding the two analytical considerations highlighted in E.O. 13783 - how best to
consider domestic versus international impacts and appropriate discount rates - current guidance
in OMB Circular A-4 is as follows. Circular A-4 states that analysis of economically significant
proposed and final regulations "should focus on benefits and costs that accrue to citizens and
residents of the United States." We follow this guidance by adopting a domestic perspective in
our central analysis. Regarding discount rates, Circular A-4 states that regulatory analyses
doi:10.7930/J0Z31WJ2; andUSGCRP, 2017: Climate Science Special Report: Fourth National Climate Assessment,
Volume I [Wuebbles, D.J., D.W. Fahey, K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. U.S.
Global Change Research Program, Washington, DC, USA, 470 pp., doi: 10.7930/J0J964J6.
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"should provide estimates of net benefits using both 3 percent and 7 percent." The 7 percent rate
is intended to represent the average before-tax rate of return to private capital in the U.S.
economy. The 3 percent rate is intended to reflect the rate at which society discounts future
consumption, which is particularly relevant if a regulation is expected to affect private
consumption directly. The EPA follows this guidance below by presenting estimates based on
both 3 and 7 percent discount rates in the main analysis. See Chapter 7 for a discussion the
modeling steps involved in estimating the domestic SC-CO2 estimates based on these discount
rates. These SC-CO2 estimates developed under E.O. 13783 presented below will be used in
regulatory analysis until more comprehensive domestic estimates can be developed, which would
take into consideration recent recommendations from the National Academies of Sciences,
Engineering, and Medicine3 to further update the current methodology to ensure that the SC-CO2
estimates reflect the best available science.
Table 4-1 presents the average domestic SC-CO2 estimate across all of the integrated
assessment model runs used to estimate the SC-CO2 for each discount rate for the years 2015 to
2050.4 As with the global SC-CO2 estimates, the domestic SC-CO2 increases over time because
future emissions are expected to produce larger incremental damages as physical and economic
systems become more stressed in response to greater climatic change, and because GDP is
growing over time and many damage categories are modeled as proportional to gross GDP. For
emissions occurring in the year 2030, the two domestic SC-CO2 estimates are $1 and $8 per
metric ton of CO2 emissions (2016$), using a 7 and 3 percent discount rate, respectively.
3 See National Academies of Sciences, Engineering, and Medicine, Valuing Climate Damages: Updating Estimation
of the Social Cost of Carbon Dioxide, Washington, D.C., January 2017. http://www.nap.edu/catalog/24651/valuing-
climate-changes-updating-estimation-of-the-social-cost-of
4The SC-CO2 estimates rely on an ensemble of three integrated assessment models (IAMs): Dynamic Integrated
Climate and Economy (DICE) 2010; Climate Framework for Uncertainty, Negotiation, and Distribution (FUND)
3.8; and Policy Analysis of the Greenhouse Gas Effect (PAGE) 2009. See Chapter 7 for an overview of the
modeling methodology.
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Table 4-1
Interim Domestic Social Cost of CO2, 2015-2050 (in 2016$ per metric ton)3
Discount Rate and Statistic
Year
3% Average
7% Average
2015
$6
$1
2020
7
1
2025
7
1
2030
8
1
2035
9
2
2040
9
2
2045
10
2
2050
11
2
a These SC-CO2 values are stated in $/metric ton CO2 and rounded to the nearest dollar. These values may be
converted to $/short ton using the conversion factor 0.90718474 metric tons per short ton for application to the short
ton CO2 emission impacts provided in this rulemaking. Such a conversion does not change the underlying
methodology, nor does it change the meaning of the SC-CO2 estimates. For both metric and short tons denominated
SC-CO2 estimates, the estimates vary depending on the year of CO2 emissions and are defined in real terms, i.e.,
adjusted for inflation using the GDP implicit price deflator.
Table 4-2 reports the domestic climate benefits in the three analysis years (2025, 2030,
2035) for the illustrative policy scenario, compared to the baseline.
Table 4-2 Estimated Domestic Climate Benefits, Relative to Baseline (millions of
	2016$)a	

3% Discount Rate
7% Discount Rate
2025
81
13
2030
81
14
2035
72
13
a Values rounded to two significant figures. The SC-CO2 values are dollar-year and emissions-year specific. SC-CO2
values represent only a partial accounting of climate impacts.
The limitations and uncertainties associated with the SC-CO2 analysis, which were
discussed at length in the 2015 CPP RIA, likewise apply to the domestic SC-CO2 estimates
presented in this RIA. Some uncertainties are captured within the analysis, as discussed in detail
in Chapter 7, while other areas of uncertainty have not yet been quantified in a way that can be
modeled. For example, limitations include the incomplete way in which the integrated
assessment models capture catastrophic and non-catastrophic impacts, their incomplete treatment
of adaptation and technological change, the incomplete way in which inter-regional and inter-
sectoral linkages are modeled, uncertainty in the extrapolation of damages to high temperatures,
and inadequate representation of the relationship between the discount rate and uncertainty in
economic growth over long time horizons. The science incorporated into these models
understandably lags behind the most recent research, and the limited amount of research linking
climate impacts to economic damages makes this comprehensive global modeling exercise even
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more difficult. These individual limitations and uncertainties do not all work in the same
direction in terms of their influence on the SC-CO2 estimates. In accordance with guidance in
OMB Circular A-4 on the treatment of uncertainty, Chapter 7 provides a detailed discussion of
the ways in which the modeling underlying the development of the SC-CO2 estimates used in
this RIA addressed quantified sources of uncertainty and presents a sensitivity analysis to show
consideration of the uncertainty surrounding discount rates over long time horizons.
Recognizing the limitations and uncertainties associated with estimating the SC-CO2, the
research community has continued to explore opportunities to improve SC-CO2 estimates.
Notably, the National Academies of Sciences, Engineering, and Medicine conducted a multi-
discipline, multi-year assessment to examine potential approaches, along with their relative
merits and challenges, for a comprehensive update to the current methodology. The task was to
ensure that the SC-CO2 estimates that are used in Federal analyses reflect the best available
science, focusing on issues related to the choice of models and damage functions, climate science
modeling assumptions, socioeconomic and emissions scenarios, presentation of uncertainty, and
discounting. In January 2017, the Academies released their final report, Assessing Approaches to
Updating the Social Cost of Carbon, and recommended specific criteria for future updates to the
SC-CO2 estimates, a modeling framework to satisfy the specified criteria, and both near-term
updates and longer-term research needs pertaining to various components of the estimation
process (National Academies 2017).5
The Academies' 2017 report also discussed the challenges in developing domestic SC-
CO2 estimates, noting that current integrated assessment models do not model all relevant
regional interactions - i.e., how climate change impacts in other regions of the world could affect
the United States, through pathways such as global migration, economic destabilization, and
political destabilization. The Academies concluded that it "is important to consider what
constitutes a domestic impact in the case of a global pollutant that could have international
implications that impact the United States. More thoroughly estimating a domestic SC-CO2
would therefore need to consider the potential implications of climate impacts on, and actions by,
5 National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide. National Academies Press. Washington, DC Available at
 Accessed
May 30, 2017.
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other countries, which also have impacts on the United States." (National Academies 2017, pg.
12-13).
In addition to requiring reporting of impacts at a domestic level, Circular A-4 states that
when an agency "evaluate[s] a regulation that is likely to have effects beyond the borders of the
United States, these effects should be reported separately" (page 15). This guidance is relevant to
the valuation of damages from CO2 and other GHGs, given that GHGs contribute to damages
around the world independent of the country in which they are emitted. Therefore, in accordance
with this guidance in OMB Circular A-4, Chapter 7 presents the global climate benefits from this
final rulemaking using global SC-CO2 estimates based on both 3 and 7 percent discount rates.
Note the EPA did not quantitatively project the full impact of ACE on international trade and the
location of production, so it is not possible to present analogous estimates of international costs
resulting from the final action. However, to the extent that the IPM analysis endogenously
models international electricity and natural gas trade, and to the extent that affected firms have
some foreign ownership, some of the costs accruing to entities outside U.S. borders is captured in
the compliance costs presented in this RIA. See Chapter 5 for more discussion of challenges
involved in estimating the ultimate distribution of compliance costs.
4.4 Approach to Estimating Human Health Ancillary Co-Benefits
As noted above, this final rule is designed to affect emissions of CChfrom the EGU
sector but will also influence the level of other pollutants emitted in the atmosphere that
adversely affect human health; these include directly emitted PM2.5' as well as SO2 and NOx,
which are both precursors to ambient PM2.5. NOx emissions are also a precursor to ambient
ground-level ozone. The EGU emissions associated with the baseline and the illustrative policy
scenario are shown in Table 4-3. The change in emissions between the baseline and the
illustrative policy scenario will in turn alter the ambient concentrations, population exposure and
human health impacts associated with PM2.5 and ozone. Finally, ambient concentrations of both
SO2 and NOx pose health risks independent of PM2.5 and ozone, though we do not quantify these
impacts in this analysis (U.S. EPA 2016b, 2017).
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Table 4-3 Projected EGU Emissions of SO2, NOx, and PJVh.s a
NOx


SO2
ozone
seasonb
annual
PM25
Baseline Emissions
(thousand tons)
2025
2030
2035
912.6
885.6
817.0
386.7
384.7
374.3
844.4
810.1
752.8
108.7
110.1
113.0
Illustrative Policy
2025
908.5
382.7
837.1
108.1
Scenario Emissions
2030
879.9
381.4
803.0
109.7
(thousand tons)
2035
810.6
370.4
746.8
112.3
Emissions change
2025
-4.1
-4.0
-7.3
-0.6
(Illustrative Policy -
Baseline)2030
-5.7
-3.3
-7.1
-0.4
(thousand tons)
2035
-6.4
-3.9
-6.0
-0.7
Emissions change
2025
-0.4
-1.0
-0.9
-0.6
(Illustrative Policy -
Baseline)2030
-0.6
-0.9
-0.9
-0.4
(%)
2035
-0.8
-1.1
-0.8
-0.6
" The SO2 and NOx emissions are direct outputs from the IPM simulations as reported in Chapter 3; however, the
PM2 5 emissions were derived based on IPM-predicted heat rate and other factors as described in Chapter 8.
b "ozone season" NOx emissions refer to total NOx (ton) emitted during the period of May-September.
This section is a summary of our approach to estimating the incidence and economic
value of the PM2.5 and ozone-related ancillary co-benefits estimated for this final rule. The
Regulatory Impact Analysis (RIA) for the Particulate Matter (PM) National Ambient Air Quality
Standards (NAAQS) (U.S. EPA 2012b) the RIA for the Ozone NAAQS (U.S. EPA 2015e) and
the user manual for the BenMAP-CE program (U.S. EPA 2018) provide a full discussion of the
Agency's approach for quantifying the number and value of estimated air pollution-related
impacts. In these documents the reader can find the rationale for selecting health endpoints to
quantify; the demographic, health and economic data we apply within the environmental
Benefits Mapping and Analysis Program—Community Edition (BenMAP-CE); modeling
assumptions; and our techniques for quantifying uncertainty.
These estimated ancillary health co-benefits do not account for the influence of future
changes in the climate on ambient concentrations of pollutants (USGCRP 2016). For example,
recent research suggests that future changes to climate may create conditions more conducive to
forming ozone; the influence of changes in the climate on PM2.5 concentrations are less clear
(Fann et al. 2015). The estimated ancillary health co-benefits also do not consider the potential
for climate-induced changes in temperature to modify the relationship between ozone and the
risk of premature death (Jhun et al. 2014; Ren et al. 2008b, 2008a).
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Implementing the final guidelines will affect the distribution of PM2.5 and ozone
concentrations throughout the U.S.; this includes locations both meeting and exceeding the
NAAQS for PM and ozone. This RIA estimates avoided PM2.5- and ozone-related health impacts
that are distinct from those reported in the RIAs for both NAAQS (U.S. EPA 2012b, 2015e). The
PM2.5 and ozone NAAQS RIAs hypothesize, but do not predict, the benefits and costs of
strategies that States may choose to enact when implementing a revised NAAQS; these costs and
benefits are illustrative and cannot be added to the costs and benefits of policies that prescribe
specific emission control measures.
The illustrative policy scenario projects both decreased and increased levels of PM2.5 and
ozone, depending on the location, compared to the baseline. Furthermore, some portion of the air
quality and health benefits from the illustrative policy scenario occur in areas not attaining the
PM2.5 or Ozone NAAQS, the requirements of which should be accounted for in the baseline.
However, the analysis does not account for how interaction with NAAQS compliance would
affect the benefits (and costs) of the illustrative policy scenario, which introduces uncertainty in
the benefit (and costs) estimates. If the final rule increases or decreases SO2 and NOx and
consequentially PM2.5 and/or ozone, these changes may affect compliance with existing NAAQS
standards and subsequently affect the actual benefits and costs of the rule. In the case of areas
that do not meet the NAAQS that see decreased concentrations of PM2.5 or ozone, states may be
able to avoid applying certain other measures to assure NAAQS attainment. As a result, there
would be avoided compliance costs and the PM2.5 and ozone health and ecological benefits of the
rule would likely be lessened. In areas not attaining the NAAQS where PM2.5 or ozone
concentrations may increase due to the rule, states may instead need to identify additional
approaches to reduce emissions from local sources relative to the baseline, thus mitigating any
increased PM2.5 and ozone concentrations. In this case, the health benefits would be higher and
there would be additional costs associated with these additional approaches.
Similarly, the illustrative policy scenario may project increases in PM2.5 and ozone
concentrations in areas attaining the NAAQS in the baseline. In practice, these potential changes
in concentrations may be mitigated by Prevention of Significant Deterioration (PSD)
requirements. Again, this RIA does not account for how interaction with NAAQS compliance
would affect the benefits and costs of the illustrative policy scenario.
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4.4.1 Air Quality Modeling Methodology
We performed nationwide photochemical modeling and related analyses to develop
spatial fields of air quality across the U.S. for input to BenMAP-CE, which was used to quantify
the benefits from this final rule. Spatial fields of air quality were prepared for the baseline and an
illustrative policy scenario for each of the following health-impact metrics: annual mean PM2.5,
May through September seasonal average 8-hour daily maximum (MDA8) ozone, April through
October seasonal average 1-hour daily maximum (MDA1) ozone. The illustrative policy scenario
reflects EGU emissions analyzed in this final rule RIA. The EGU emissions for the baseline and
illustrative policy scenario were obtained from the outputs of the corresponding IPM runs, as
described in Chapter 3.
All of the air quality model simulations (i.e., model runs) were performed using the
Comprehensive Air Quality Model with Extensions (CAMx)6 (Ramboll Environ, 2016). Our
CAMx nationwide modeling domain (i.e., the geographic area included in the modeling) covers
all lower 48 states plus adjacent portions of Canada and Mexico using a horizontal grid
resolution of 12 x 12 km. In this section we provide an overview of the air quality modeling and
the methodologies we used to develop spatial fields of annual PM2.5 and seasonal average ozone
concentrations. More information on the air quality modeling platform (inputs and set-up), model
performance evaluation for ozone and PM2.5, emissions processing for this analysis, and
additional details and numerical examples of the methodologies for developing PM2.5 and ozone
spatial fields are provided in Chapter 8. It should be noted that the air quality modeling platform
used in this final action is the same as that used in the RIA for the ACE proposal.
Wherein this rule the Agency employed full-scale photochemical modeling, in some
other rules, including the proposed CPP Repeal, EPA applied a benefit per ton approach. A
benefit per-ton is a reduced-form approach for relating changes in emissions to estimated counts
of premature death and illnesses and the economic value of these impacts (U.S. EPA 2013 c). In
the proposed CPP repeal, EPA highlighted the difficulty associated with delineating benefits
above and below given air quality concentrations predicted by regulatory changes (e.g., above
and below the NAAQS and the Lowest Measured Level (LML) in the studies used to derive the
6 CAMx version 6.40 was used for the modeling to support the proposal RIA. This version of CAMx was the latest
public release version of the model at the time this analysis was performed.
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concentration response function). At that time, EPA committed to conducting full-scale air
quality modeling for the final regulation, and also committed to characterize the uncertainty
associated with applying benefit-per-ton estimates by comparing the EPA's approach with a
benefits assessment based on full-scale modeling and other reduced-form techniques found in the
literature for projecting PM2.5 concentrations changes and the associated monetized impacts of
those changes (see page 7 of the RIA for the proposed CPP repeal). Over the last year and a half,
the EPA systematically compared the changes in benefits, and concentrations where available,
from its benefit-per-ton technique and other reduced-form techniques to the changes in benefits
and concentration derived from full-form photochemical model representation of a few different
specific emissions scenarios.7 The Agency's goal was to better understand the suitability of
alternative reduced-form air quality modeling techniques for estimating the health impacts of
criteria pollutant emissions changes in EPA's benefit-cost analysis, including the extent to which
reduced form models may over- or under-estimate benefits (compared to full-scale modeling)
under different scenarios and air quality concentrations. The scenario-specific emission inputs
developed for this project are currently available online.8 The study design and methodology will
be thoroughly described in the final report summarizing the results of the project, which is
planned to be completed by the end of 2019.
In the analysis supporting this rule, we conducted several full-scale photochemical model
simulations. The modeling included annual model simulations for a 2011 base year and a 2023
future year to provide hourly concentrations of ozone as well as primary and secondarily formed
PM2.5 component species (e.g., sulfate, nitrate, ammonium, elemental carbon, organic matter,
and crustal material) for both years nationwide. The year 2023 was used as the future year
because emissions from all anthropogenic source types in the modeling domain for 2023
represent EPA's most up to date future year projections that are available for the analysis of this
final rule. As described below, the photochemical modeling results for 2011 and 2023 were part
of the inputs used to construct the air quality spatial fields that reflect the influence of EGU
7	This analysis compared the benefits estimated using full-form photochemical air quality modeling simulations
(CMAQ and CAMx) against four reduced-form tools, including: InMAP; AP2/3; EASIUR and the EPA's Benefit
per-Ton.
8	The scenario-specific emission inputs developed for this project are currently available online at:
https://github.com/epa-kpc/RFMEVAL Upon completion and publication of the final report, the final report and all
associated documentation will be online and available at this URL.
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emissions in 2025, 2030, and 2035 on PM2.5 and ozone concentrations for the baseline and
illustrative policy scenario.9 Due to timing constraints we did not perform explicit air quality
modeling for baseline and illustrative policy scenarios for each of these years. Rather, we used
emissions data and the results of the 2011 and 2023 air quality modeling in conjunction with
source apportionment modeling for 2023 to estimate the ozone and PM2.5 concentrations
associated with the baseline and illustrative policy scenario for 2025, 2030 and 2035. In general,
source apportionment modeling quantifies the air quality concentrations formed from individual,
user-defined groups of emissions sources or "tags". These source tags are tracked through the
transport, dispersion, chemical transformation, and deposition processes within the model to
obtain hourly gridded10 contributions from the emissions in each individual tag to hourly
modeled concentrations of ozone and PM2.5.11 For this analysis we performed source
apportionment modeling for ozone and PM2.5 based on 2023 emissions using tools in CAMx12 to
obtain the contributions from EGU emissions as well as other sources to ozone and to PM2.5
component species concentrations.13 The source apportionment method provides an estimate of
the effect of changes in emissions from the groups of emissions sources to changes in both PM2.5
or ozone concentrations.
The source apportionment modeling was used to quantify the contributions from EGU
emissions on a state-by-state or, in some cases, on a multi-state basis. For ozone, we modeled the
contributions from the 2023 EGU sector emissions of NOx and VOC to hourly ozone
concentrations for the period April through October to provide data for developing spatial fields
for the two seasonal ozone benefits metrics identified above (i.e. for the May-September
seasonal average MDA8 ozone and the April-October seasonal average MDA1 ozone). For
9	2025, 2030 and 2035 are snapshot years of analysis in this RIA. See Section 1.4.3 of this RIA for further
discussion.
10	Hourly contribution information is provided for each grid cell to provide spatial patterns of the contributions from
each tag.
11	Note that the sum of the contributions in a model grid cell from each tag for a particular pollutant equals the total
concentration of that pollutant in the grid cell.
12	Ozone contributions were modeled using the Ozone Source Apportionment Technique/Anthropogenic Precursor
Culpability Assessment (OSAT/APCA) tool and PM2 5 component species contributions were modeled using the
Particulate Source Apportionment Technique (PSAT) tool as described in "Ramboll Environ, 2016. User's Guide
Comprehensive Air Quality Model with Extensions version 6.40. Ramboll Environ International Corporation,
Novato, CA."
13	In the source apportionment modeling for PM2 5 we tracked the source contributions from primary, but not
secondary organic aerosols (SOA). The method for treating SOA concentrations is described later in this section.
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PM2.5, we modeled the contributions from the 2023 EGU sector emissions of SO2, NOx, and
directly emitted PM2.5 for the entire year to inform the development of spatial fields of annual
mean PM2.5. For each state, or multi-state group, we separately tagged EGU emissions depending
on whether the emissions were from coal-fired units or non-coal units.14 In addition to tagging
coal-fired and non-coal EGU emissions we also tracked the ozone and PM2.5 contributions from
the following "domain-wide" tags (i.e., tags that are not geographically grouped by state or
multi-state area):
•	two tags for emissions from all of those EGUs in the 2023 emissions inventory that were
operating in the 2023, but are now expected to retire before 203015; one EGU retirement
tag includes emissions from sources that have announced retirements before 2025, and a
second tag for EGUs with announced retirements between 2025 and 2030;16
•	one tag for all U.S. anthropogenic emissions from source sectors other than EGUs;
•	one tag for international emissions that are located within the modeling domain, including
anthropogenic emissions in Canada, Mexico, as well as offshore marine vessels and
drilling platforms;
•	one tag that includes emissions from wildfires and prescribed fires;
•	one tag for biogenic source emissions; and
•	one tag to provide the contributions from concentrations along the outer boundary of the
modeling domain.
The development of the EGU tags and the other tags listed above is described in more
detail in Chapter 8.
The following data were used to create the spatial fields of ozone and PM2.5
concentrations for the baseline and illustrative policy scenario in 2025, 2030, and 2035. Of these
inputs, only input 2) has been updated since the analysis for the ACE proposal RIA:
(1)	2023 annual EGU SO2, NOx, and directly emitted PM2.5 emissions and 2023 ozone
season17 EGU NOx emissions for each EGU tag as described in Chapter 8;
(2)	2025, 2030, and 2035 annual EGU emissions of SO2, NOx, and directly emitted PM2.5
and EGU ozone season NOx emissions for the baseline and illustrative policy scenario
14	For the purposes of this analysis non-coal fuels include emissions from natural gas, oil, biomass, municipal waste
combustion and waste coal EGUs.
15	Note that emissions associated with units in the two EGU retirements tags are not included in the state-level EGU
tags (i.e. there is no double-counting of emissions contributions).
16	At the time of this analysis, there were no announced EGU retirements after 2030.
17	"Ozone season NOx emissions" refers to total NOx (tons) emitted during the period of May-September.
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that correspond to each of the 2023 EGU tags defined for the 2023 source apportionment
modeling;
(3)	Daily 2011 and 2023 modeling-based concentrations of 24-hour average PM2.5
component species and MDA1 and MDA8 ozone;
(4)	2023 daily contributions to 24-hour average PM2.5 component species and MDA1 and
MDA8 ozone from each of the various source tags; and
(5)	Base period (2011) "fused surfaces" of measured and modeled air quality18 representing
quarterly average PM2.5 component species concentrations and ozone concentrations for
the two seasonal average ozone metrics. These "fused surfaces" use the ambient data to
adjust modeled fields to match observed data at locations of monitoring sites. Details on
the methods for creating fused surfaces are provided in Chapter 8.
Next, we identify the general process for developing the spatial fields for PM2.5 using the
2025 baseline as an example to illustrate the procedure. The steps in this process are as follows:
(1)	We use the EGU annual SO2, NOx, and directly emitted PM2.5 emissions19 for the 2025
baseline and the corresponding 2023 SO2, NOx, and directly emitted PM2.5 emissions to
calculate the ratio of 2025 baseline emissions to 2023 emissions for each of these
pollutants for each EGU tag (i.e. a scaling ratio for each pollutant and each tag).
(2)	The tag-specific 2025 to 2023 EGU emissions-based scaling ratios from step (1) are
multiplied by the corresponding 365 daily 24-hour average PM2.5 component species
contributions from the 2023 contribution modeling. The emissions ratios for SO2 are
applied to sulfate contributions; ratios for annual NOx are applied to nitrate contributions;
and ratios for directly emitted PM2.5 are applied to the EGU contributions to primary
organic matter, elemental carbon and crustal material. This step results in 365 adjusted
daily PM2.5 component species contributions for each EGUs tag that reflects the
emissions in the 2025 baseline.
(3)	For each individual PM2.5 component species, the adjusted contributions for each EGU
tag from step (2) are added together to produce a daily EGU tag total. Then the 24-hour
average contributions, if any, from units that will retire by 2030 (i.e., the 2025-2030
retirements tag) are included by adding their contribution from the corresponding daily
EGU tag total.20
(4)	The daily total EGU contributions for each PM2.5 component species from step (3) are
then combined with the species contributions from each of the other source tags, as
identified above. As part of this step we also add the total secondary organic aerosol
18	In this analysis, a "fused surface" represents a spatial field of concentrations of a particular pollutant that was
derived by applying the Enhanced Voronoi Neighbor Averaging with adjustment using modeled and measured air
quality data (i.e., eVNA) technique (Ding et al. 2016).
19	The 2025, 2030, and 2035 EGU SO2 and NOx emissions for the baseline and illustrative policy scenario were
obtained from IPM outputs described in Chapter 3. EGU emissions of directly emitted PM2.5 were derived based on
heat rate data from the IPM outputs, using a methodology described in Chapter 8.
20	Note that contributions from units that will retire before 2025 (i.e. the 2025 retirements tag) are not added to the
EGU surface since those sources are not expected to have any contributions to PM2 5 in 2025.
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concentrations from the 2023 modeling to the net EGU contributions of primary organic
matter. Note that the secondary organic aerosol concentration does not change between
scenarios. This step results in 24-hour average PM2.5 component species concentrations
for the 2025 baseline in each model grid cell, nationwide for each day in the year.
(5)	For each PM2.5 component species, we average the daily concentrations from step (4) for
each quarter of the year.
(6)	The quarterly average PM2.5 component species concentrations from step (5)21 are divided
by the corresponding quarterly average species concentrations from the 2011 CAMx
model run. This step provides a Relative Response Factor (i.e., RRF) between 2011 and
the 2025 baseline for each species in each model grid cell.
(7)	The species-specific quarterly RRFs from step (6) are then multiplied by the
corresponding species-specific quarterly average concentrations from the base period
(2011) fused surfaces to produce quarterly average species concentrations for the 2025
baseline.
(8)	The 2025 baseline quarterly average species concentrations from step (7) are summed
over the species to produce total PM2.5 concentrations for each quarter. Finally, total
PM2.5 concentrations for the four quarters of the year are averaged to produce the spatial
field of annual average PM2.5 concentrations for the 2025 baseline that are input to
BenMAP-CE.
The steps above are repeated for the baseline in each of the 3 analysis years22 as well as
for the illustrative policy scenario in each year.
For generating the spatial fields for each of the two ozone concentration metrics (MDA1
and MDA8) we follow steps similar to those above for PM2.5. Again, we use the 2025 baseline to
illustrate the steps for producing ozone spatial fields for each of the cases we analyzed. We use
the EGU May through September (i.e., Ozone Season - OS) NOx for the 2025 baseline and the
corresponding 2023 OS NOx emissions to calculate the ratio of 2025 baseline emissions to 2023
emissions for each EGU tag (i.e. an ozone-season scaling factor for each tag).
(1) We use the EGU ozone season NOx, emissions23 for the 2025 baseline and the
corresponding 2023 ozone season NOx emissions to calculate the ratio of 2025 baseline
emissions to 2023 emissions for each EGU tag (i.e. a scaling ratio for each tag).
21	Ammonium concentrations are calculated assuming that the degree of neutralization of sulfate ions remains at
2011 levels (see Chapter 8 for details).
22	For 2030 and 2035 analysis years, the 2025-2030 retirements tag is not added to the state-level EGU emissions
since those sources are not expected to impact PM2 5 in those year.
23	The 2025, 2030, and 2035 EGU NOx emissions for the baseline and illustrative policy scenario were obtained
from IPM outputs described in Chapter 3.
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(2)	The source apportionment modeling provided separate ozone contributions for ozone
formed in VOC-limited chemical regimes (O3V) and ozone formed in NOx-limited
chemical regimes (O3N).24 The tag-specific 2025 to 2023 EGU NOx emissions-based
scaling ratios from step (1) are multiplied by the corresponding O3N daily contributions
to MDA1 and MDA8 concentrations from the 2023 contribution modeling. This step
results in adjusted gridded daily MDA1 and MDA8 contributions due to NOx changes for
each EGUs tag that reflect the emissions in the 2025 baseline.
(3)	For MDA1 and MDA8, the adjusted contributions for each EGU tag from step (2) are
added together to produce a daily EGU tag total. Since IPM does not output VOC from
EGUs, there are no predicted changes in VOC emissions in these scenarios so the O3V
contributions remain unchanged. The contributions from the unaltered 2023 O3V tags are
added to the summed adjusted O3N EGU tags. Finally, the contributions, if any, to
MDA1 and MDA8 concentrations from units that will retire by 2030 (i.e., the 2025-2030
retirements tag) are included by adding their contribution from the corresponding daily
EGU tag total.25
(4)	The daily total EGU contributions for MDA1 and MDA8 from step (3) are then
combined with the contributions to MDA1 and MDA8 from each of the other source tags.
This step results in MDA1 and MDA8 concentrations for the baseline EGU emissions in
each model grid cell, nationwide for each day in the ozone season.
(5)	For MDA1, we average the daily concentrations from step (4) across all the days in the
period April 1 through October 31. For MDA8, we average the daily concentrations
across all days in the period May 1 through September 30.
(6)	The seasonal mean concentrations from step (5) are divided by the corresponding
seasonal mean concentrations from the 2011 CAMx model run. This step provides a
Relative Response Factor (i.e., RRF) between 2011 and the 2025 baseline for MDA1 and
MDA8 in each model grid cell.
(7)	Finally, the RRFs for the seasonal mean metrics from step (6) are then multiplied by the
corresponding seasonal mean concentrations from the base period (2011) MDA1 and
MDA8 fused surfaces to produce seasonal mean concentrations for MDA1 and MDA8
for the 2025 baseline that are input to BenMAP-CE.
As with PM2.5, the steps outlined for ozone are repeated for the baseline in each of the 3
analysis years26 as well as for the illustrative policy scenario in each year.
As noted above, additional information on the emissions data and analytic steps
summarized in this section can be found in Chapter 8. Select maps showing changes in air
24	Information on the treatment of ozone contributions under NOx-limited and VOC-limited chemical regimes in the
CAMx APCA source apportionment technique can be found in the CAMx v6.40 User's Guide (Ramboll, 2016).
25	Note that contributions from units that will retire before 2025 (i.e. the 2025 retirements tag) are not added to the
EGU surface since those sources are not expected to have any contributions to ozone in 2025.
26	For 2030 and 2035 analysis years, the 2025-2030 retirements tag is not added to the state-level EGU emissions
since those sources are not expected to impact ozone in those years.
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quality concentrations between the illustrative policy scenario and the baseline are provided later
in this chapter.
4.4.2 Estimating PM2. sand Ozone Related Health Impacts
We estimate the quantity and economic value of air pollution-related effects using a
"damage-function." This approach quantifies counts of air pollution-attributable cases of adverse
health outcomes and assigns dollar values to those counts, while assuming that each outcome is
independent of one another. We construct this damage function by adapting primary research—
specifically, air pollution epidemiology studies and economic value studies—from similar
contexts. This approach is sometimes referred to as "benefits transfer." Below we describe the
procedure we follow for: (1) selecting air pollution health endpoints to quantify; (2) calculating
counts of air pollution effects using a health impact function; (3) specifying the health impact
function with concentration-response parameters drawn from the epidemiological literature.
4.4.2.1 Selecting air pollution health endpoints to quantify
As a first step in quantifying PM2.5 and ozone-related human health impacts, the Agency
consults the Integrated Science Assessment for Particulate Matter (PM ISA) (U.S. EPA 2009)
and the Integrated Science Assessment for Ozone and Related Photochemical Oxidants (Ozone
ISA) (U.S. EPA 2013a). These two documents synthesize the toxicological, clinical and
epidemiological evidence to determine whether each pollutant is causally related to an array of
adverse human health outcomes associated with either acute (i.e., hours or days-long) or chronic
(i.e. years-long) exposure; for each outcome, the ISA reports this relationship to be causal, likely
to be causal, suggestive of a causal relationship, inadequate to infer a causal relationship or not
likely to be a causal relationship.
In brief, the ISA for PM2.5 found acute exposure to PM2.5 to be causally related to
cardiovascular effects and mortality (i.e., premature death), and respiratory effects as likely-to-
be-causally related. The ISA identified cardiovascular effects and total mortality as being
causally related to long-term exposure to PM2.5 and respiratory effects as likely-to-be-causal; and
the evidence was suggestive of a causal relationship for reproductive and developmental effects
as well as cancer, mutagenicity and genotoxicity. The ISA for ozone found acute exposure to
ozone to be causally related to respiratory effects, a likely-to-be-causal relationship with
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cardiovascular effects and total mortality and a suggestive relationship for central nervous
system effects. Among chronic effects, the ISA reported a likely-to-be-causal relationship for
respiratory outcomes and respiratory mortality, and suggestive relationship for cardiovascular
effects, reproductive and developmental effects, central nervous system effects, and total
mortality.
The Agency estimates the incidence of air pollution effects for those health endpoints
above where the ISA classified as either causal or likely-to-be-causal. Table 4-4 reports the
effects we quantified and those we did not quantify in this RIA. The list of benefit categories not
quantified is not exhaustive. And, among the effects we quantified, we might not have been able
to quantify completely either the full range of human health impacts or economic values. The
table below omits health effects associated with SO2, NO2, and mercury, and any welfare effects
such as acidification and nutrient enrichment; these effects are described in Chapters 5 and 6 of
the PM NAAQS RIA (U.S. EPA 2012b) and summarized later in this chapter.
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Table 4-4 Human Health Effects of Ambient PM2.5 and Ozone
Category
Effect
Effect
Quantified
Effect
Monetized
More
Information
Premature mortality
from exposure to
Adult premature mortality based on cohort study
estimates and expert elicitation estimates (age >25
or age >30)
~
~
PM ISA
PM2.5
Infant mortality (age <1)
~
~
PM ISA

Non-fatal heart attacks (age >18)
~
~
PM ISA

Hospital admissions—respiratory (all ages)
~
~
PM ISA

Hospital admissions—cardiovascular (age >20)
~
~
PM ISA

Emergency room visits for asthma (all ages)
~
~
PM ISA

Acute bronchitis (age 8-12)
~
~
PM ISA

Lower respiratory symptoms (age 7-14)
~
~
PM ISA

Upper respiratory symptoms (asthmatics age 9-11)
~
~
PM ISA

Exacerbated asthma (asthmatics age 6-18)
V
~
PM ISA

Lost work days (age 18-65)
S
~
PM ISA
Morbidity from
Minor restricted-activity days (age 18-65)
S
~
PM ISA
exposure to PM2 5
Chronic Bronchitis (age >26)
—
—
PM ISA1

Emergency room visits for cardiovascular effects


PM ISA1

(all ages)



Strokes and cerebrovascular disease (age 50-79)
—
—
PM ISA1

Other cardiovascular effects (e.g., other ages)
—
—
PM ISA2

Other respiratory effects (e.g., pulmonary function,
non-asthma ER visits, non-bronchitis chronic


PM ISA2

diseases, other ages and populations)




Reproductive and developmental effects (e.g., low
birth weight, pre-term births, etc.)
—
—
PM ISA2'3

Cancer, mutagenicity, and genotoxicity effects
—
—
PM ISA2'3
Mortality from
Premature mortality based on short-term study
estimates (all ages)
~
~
Ozone ISA
exposure to ozone
Premature mortality based on long-term study
estimates (age 30-99)
~
~
Ozone ISA1

Hospital admissions—respiratory causes (age > 65)
V
~
Ozone ISA

Emergency department visits for asthma (all ages)
V
~
Ozone ISA

Exacerbated asthma (asthmatics age 6-18)
s
~
O/.onc ISA

Minor restricted-activity days (age 18-65)
V
~
Ozone ISA
Morbidity from
School absence days (age 5-17)
V
~
Ozone ISA
exposure to ozone
Decreased outdoor worker productivity (age 18-65)
—
—
Ozone ISA1

Other respiratory effects (e.g., premature aging of
lungs)
—
—
Ozone ISA2

Cardiovascular and nervous system effects
—
—
Ozone ISA2

Reproductive and developmental effects
—
—
Ozone ISA2,3
1	We assess these co-benefits qualitatively due to data and resource limitations for this analysis. In other analyses we quantified
these effects as a sensitivity analysis.
2	We assess these co-benefits qualitatively because we do not have sufficient confidence in available data or methods.
3	We assess these co-benefits qualitatively because current evidence is only suggestive of causality or there are other significant
concerns over the strength of the association.
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4.4.2.2 Calculating counts of air pollution effects using the health impact
function
We use the environmental Benefits Mapping and Analysis Program—Community
Edition (BenMAP-CE) software program to quantify counts of premature deaths and illnesses
attributable to photochemical modeled changes in annual mean PM2.5 and summer season
average ozone concentrations for the years 2025, 2030 and 2035 using a health impact function
(Fann et al. 2017; Hubbell et al. 2005). A health impact function combines information regarding
the: concentration-response relationship between air quality changes and the risk of a given
adverse outcome; population exposed to the air quality change; baseline rate of death or disease
in that population; and, air pollution concentration to which the population is exposed.
The following provides an example of a health impact function, in this case for PM2.5
mortality risk. We estimate counts of PIVh.s-related total deaths (yij) during each year i (i=2025)
among adults aged 30 and older (a) in each county in the contiguous U.S. j (j=l,.. ,,J where J is
the total number of counties) as
yij= Ea yija
yija = moija x(ep ACij-l) x Pija, Eq[l]
where moija is the baseline all-cause mortality rate for adults aged a=30-99 in county j in year i
stratified in 10-year age groups, P is the risk coefficient for all-cause mortality for adults
associated with annual average PM2.5 exposure, Cij is the annual mean PM2.5 concentration in
county j in year i, and Pija is the number of county adult residents aged a=30-99 in county j in
year i stratified into 5-year age groups.27
The BenMAP-CE tool is pre-loaded with: projected population; projected death rates;
recent-year baseline rates of hospital admissions, emergency department visits and other
morbidity outcomes; concentration-response parameters; and, economic unit values for each
27 In this illustrative example, the air quality is resolved at the county level. For this RIA, we simulate air quality
concentrations at 12km by 12km grids. The BenMAP-CE tool assigns the rates of baseline death and disease stored
at the county level to the 12km by 12km grid cells using an area-weighted algorithm. This approach is described in
greater detail in the appendices to the BenMAP-CE user manual appendices.
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endpoint. PM2.5 and ozone concentrations are taken from the air pollution spatial surfaces
described above in Section 4.4.1.
This health impact assessment quantifies outcomes using a suite of concentration-
response parameters described in the PM NAAQS RIA (U.S. EPA 2012b), Ozone NAAQS RIA
(U.S. EPA 2015e) and the user manual for the BenMAP-CE program (U.S. EPA 2018). These
documents describe in detail our rationale for selecting air pollution-related health endpoints, the
source of the epidemiological evidence, the specific concentration-response parameters applied,
and our approach for pooling evidence across epidemiological studies. Given both the severity of
air pollution-related mortality and its large economic value, below we describe the source of the
concentration-response parameters for this endpoint.
4.4.2.3 Quantifying Cases of PM2.5-A ttributable Premature Death
For adult PM-related mortality, we use the effect coefficients from two epidemiology
studies examining two large population cohorts: the American Cancer Society cohort (Krewski et
al. 2009) and the Harvard Six Cities cohort (Lepeule et al. 2012). The Integrated Science
Assessment for Particulate Matter (PM ISA) (U.S. EPA 2009) concluded that the analyses of the
ACS and Six Cities cohorts provide the strongest evidence of an association between long-term
PM2.5 exposure and premature mortality with support from additional cohort studies. The SAB's
Health Effects Subcommittee (SAB-HES) also supported using effect estimates from these two
analyses to estimate the benefits of PM reductions (U.S. EPA-SAB 2010). There are distinct
attributes of both the ACS and Six Cities cohort studies that make them well-suited to being used
in a PM benefits assessment and so here we present PM2.5 related effects derived using relative
risk estimates from both cohorts.
The PM ISA, which was twice reviewed by the Clean Air Scientific Advisory Committee
of EPA's Science Advisory Board (SAB-CASAC) (EPA-SAB 2008a, 2009), concluded that
there is a causal relationship between mortality and both long-term and short-term exposure to
PM2.5 based on the entire body of scientific evidence. The PM ISA also concluded that the
scientific literature supports the use of a no-threshold log-linear model to portray the PM-
mortality concentration-response relationship while recognizing potential uncertainty about the
exact shape of the concentration-response function. The PM ISA, which informed the setting of
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the 2012 PM NAAQS, reviewed available studies that examined the potential for a population-
level threshold to exist in the concentration-response relationship. Based on such studies, the ISA
concluded that the evidence supports the use of a "no-threshold" model and that "little evidence
was observed to suggest that a threshold exists" (U.S. EPA 2009) (pp. 2-25 to 2-26). Consistent
with this evidence, the Agency historically has estimated health impacts above and below the
prevailing NAAQS (U.S. EPA 2010b, 2010c, 2015c, 2015a, 2015d, 2015b, 2016c, 2011c, 2011b,
2012a, 2013b, 2014a, 2014c, 2014b, 2015e).28
Following this approach, we report the estimated PIVh.s-related benefits (in terms of both
health impacts and monetized values) calculated using a log-linear concentration-response
function that quantifies risk from the full range of simulated PM2.5 exposures (NRC 2002; U.S.
EPA 2009). When setting the 2012 PM NAAQS, the Administrator also acknowledged greater
uncertainty in specifying the "magnitude and significance" of PM-related health risks at PM
concentrations below the NAAQS. As noted in the preamble to the 2012 PM NAAQS final rule,
the "EPA conclude[d] that it [was] not appropriate to place as much confidence in the magnitude
and significance of the associations over the lower percentiles of the distribution in each study as
at and around the long-term mean concentration." (78 FR 3154, 15 January 2013). The preamble
separately noted that "[a]s both the EPA and CASAC recognize, in the absence of a discernible
threshold, health effects may occur over the full range of concentrations observed in the
epidemiological studies." (78 FR 3149, 15 January 2013). In general, we are more confident in
the size of the risks we estimate from simulated PM2.5 concentrations that coincide with the bulk
of the observed PM concentrations in the epidemiological studies that are used to estimate the
benefits. Likewise, we are less confident in the risk we estimate from simulated PM2.5
concentrations that fall below the bulk of the observed data in these studies.29 To give insight to
28	The Federal Reference Notice for the 2012 PM NAAQS notes that "[i]n reaching her final decision on the
appropriate annual standard level to set, the Administrator is mindful that the CAA does not require that primary
standards be set at a zero-risk level, but rather at a level that reduces risk sufficiently so as to protect public health,
including the health of at-risk populations, with an adequate margin of safety. On balance, the Administrator
concludes that an annual standard level of 12 |-ig/m3 would be requisite to protect the public health with an
adequate margin of safety from effects associated with long- and short-term PM2 5 exposures, while still
recognizing that uncertainties remain in the scientific information."
29	The Federal Register Notice for the 2012 PM NAAQS indicates that "[i]n considering this additional population
level information, the Administrator recognizes that, in general, the confidence in the magnitude and significance of
an association identified in a study is strongest at and around the long-term mean concentration for the air quality
distribution, as this represents the part of the distribution in which the data in any given study are generally most
concentrated. She also recognizes that the degree of confidence decreases as one moves towards the lower part of
the distribution."
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the level of uncertainty in the estimated PM2.5 mortality benefits at lower ambient concentrations,
we report the PM benefits according to alternative concentration cut-points. Below we further
describe our rationale for selecting these cut-points. In addition to adult mortality discussed
above, we use effect coefficients from a multi-city study to estimate PM-related infant mortality
(Woodruff et al. 1997).
4.4.2.4 Quantifying Cases of Ozone-A ttributable Premature Death
In 2008, the National Academies of Science (NRC 2008) issued a series of
recommendations to the EPA regarding the procedure for quantifying and valuing ozone-related
mortality due to short-term exposures. Chief among these was that"... short-term exposure to
ambient ozone is likely to contribute to premature deaths" and the committee recommended that
"ozone-related mortality be included in future estimates of the health benefits of reducing ozone
exposures..The NAS also recommended that".. .the greatest emphasis be placed on the
multicity and [National Mortality and Morbidity Air Pollution Studies (NMMAPS)] ... studies
without exclusion of the meta-analyses" (NRC 2008). Prior to the 2015 Ozone NAAQS RIA, the
Agency estimated ozone-attributable premature deaths using an NMMAPS-based analysis (Bell
et al. 2004), two multi-city studies (Huang et al. 2004; Schwartz 2005) and effect estimates from
three meta-analyses (Bell et al. 2005; Ito et al. 2005; Levy et al. 2005). Beginning with the 2015
Ozone NAAQS RIA, the Agency began quantifying ozone-attributable premature deaths using
two newer multi-city studies (Smith et al. 2009; Zanobetti and Schwartz 2008) and one long-
term cohort study (Jerrett et al. 2009).30 We report the ozone-attributable deaths in this RIA as a
range reflecting the concentration-response parameters from Smith et al. (2009) on the low end
to Jerrett et al. (2009) on the high end.
30 Support for modeling long-term exposure-related mortality incidence comes from the ozone ISA as well as
recommendations provided by CASAC in their review of the ozone HREA (U.S. EPA-SAB, 2014, p. 3 and 9),
despite the lower confidence in quantifying this endpoint because the ISA's consideration of this endpoint is
primarily based on one study (Jerrett et al, 2009), though that study is well designed, and because of the uncertainty
in that study about the existence and identification of a potential threshold in the concentration-response function.
Whereas the ozone ISA concludes that evidence is suggestive of a causal association between total mortality and
long-term ozone exposure, specifically with regard to respiratory health effects (including mortality), the ISA
concludes that there is likely to be a causal association (U.S. EPA, 2013a). Consistent with the ozone HREA, we use
Jerrett et al. (2009) to estimate premature respiratory mortality from long-term ozone exposure.
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4.4.3 Economic Value of Ancillary Health Co-benefits
We next quantify the economic value of the PM2.5 and ozone-related deaths and illnesses
estimated above. Changes in ambient concentrations of air pollution generally yield small
changes in the risk of future adverse health effects for a large number of people. Therefore, the
appropriate economic measure is willingness to pay (WTP) for changes in risk of a health effect.
For some health effects, such as hospital admissions, WTP estimates are not generally available,
so we use the cost of treating or mitigating the effect. These cost-of-illness (COI) estimates
generally (although not necessarily in every case) understate the true value of reductions in risk
of a health effect. They tend to reflect the direct expenditures related to treatment but not the
value of avoided pain and suffering from the health effect. The unit values applied in this
analysis are provided in Table 5-9 of the PM NAAQS RIA for each health endpoint (U.S. EPA
2012b).
The value of avoided premature deaths account for 98 percent of ancillary monetized
PM-related co-benefits and over 90 percent of monetized ozone-related co-benefits. The
economics literature concerning the appropriate method for valuing reductions in premature
mortality risk is still developing. The value for the projected reduction in the risk of premature
mortality is the subject of continuing discussion within the economics and public policy analysis
community. Following the advice of the SAB's Environmental Economics Advisory Committee
(SAB-EEAC), the EPA currently uses the value of statistical life (VSL) approach in calculating
estimates of mortality benefits, because we believe this calculation provides the most reasonable
single estimate of an individual's willingness to trade off money for changes in the risk of death
(U.S. EPA-SAB 2000). The VSL approach is a summary measure for the value of small changes
in the risk of death experienced by a large number of people.
The EPA continues work to update its guidance on valuing mortality risk reductions, and
the Agency consulted several times with the SAB-EEAC on this issue. Until updated guidance is
available, the Agency determined that a single, peer-reviewed estimate applied consistently, best
reflects the SAB-EEAC advice it has received. Therefore, the EPA applies the VSL that was
vetted and endorsed by the SAB in the Guidelines for Preparing Economic Analyses (U.S. EPA
2016a) while the Agency continues its efforts to update its guidance on this issue. This approach
calculates a mean value across VSL estimates derived from 26 labor market and contingent
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valuation studies published between 1974 and 1991. The mean VSL across these studies is $6.3
million (2000$).31 We then adjust this VSL to account for the currency year and to account for
income growth from 1990 to the analysis year. Specifically, the VSLs applied in this analysis in
2016$ after adjusting for income growth is $10.5 million for 2025.
The Agency is committed to using scientifically sound, appropriately reviewed evidence
in valuing changes in the risk of premature death and continues to engage with the SAB to
identify scientifically sound approaches to update its mortality risk valuation estimates. Most
recently, the Agency proposed new meta-analytic approaches for updating its estimates (U.S.
EPA 2010d), which were subsequently reviewed by the SAB-EEAC. The EPA is taking the
SAB's formal recommendations under advisement (U.S. EPA 2017).
In valuing PM2.5-related premature mortality, we discount the value of premature
mortality occurring in future years using rates of 3 percent and 7 percent (U.S. Office of
Management and Budget 2003). We assume that there is a multi-year "cessation" lag between
changes in PM exposures and the total realization of changes in health effects. Although the
structure of the lag is uncertain, the EPA follows the advice of the SAB-HES to use a segmented
lag structure that assumes 30 percent of premature deaths are reduced in the first year, 50 percent
over years 2 to 5, and 20 percent over the years 6 to 20 after the reduction in PM2.5 (U.S. EPA-
SAB 2004). Changes in the cessation lag assumptions do not change the total number of
estimated deaths but rather the timing of those deaths. Because short-term ozone-related
premature mortality occurs within the analysis year, the estimated ozone-related co-benefits are
identical for all discount rates.
4.4.4 Characterizing Uncertainty in the Estimated Benefits
This analysis includes many data sources as inputs that are each subject to uncertainty.
Input parameters include projected emission inventories, air quality data from models (with their
associated parameters and inputs), population data, population estimates, health effect estimates
from epidemiology studies, economic data for monetizing co-benefits, and assumptions
regarding the future state of the world (i.e., regulations, technology, and human behavior).
Uncertainties particular to this analysis include the emissions changes projected in the illustrative
31 In 1990$, this base VSL is $4.8 million.
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policy scenario, where we assumed availability of the candidate HRI technologies across the
fleet of coal-fired EGUs, the performance standards states would adopt, and the means by which
the affected sources would comply with the rule, despite significant uncertainty in these aspects
of the final rule.32 When compounded, even small uncertainties can greatly influence the size of
the total quantified benefits.
Our estimate of the total monetized co-benefits is based on EPA's interpretation of the
best available scientific literature and methods and supported by the SAB-HES and the National
Academies of Science (NRC 2002). Below are key assumptions underlying the estimates for
PM2.5-related premature mortality.
We assume that all fine particles, regardless of their chemical composition, are equally
potent in causing premature mortality. This is an important assumption, the PM ISA concluded
that "many constituents of PM2.5 can be linked with multiple health effects, and the evidence is
not yet sufficient to allow differentiation of those constituents or sources that are more closely
related to specific outcomes" (U.S. EPA 2009)
As noted above, we assume that the health impact function for fine particles is log-linear
without a threshold. Thus, the estimates include health co-benefits from reducing fine particles in
areas with different concentrations of PM2.5, including both areas that do not meet the fine
particle standard and those areas that are in attainment and reflect the full distribution of PM2.5
air quality simulated above.
Also, as noted above, we assume that there is a "cessation" lag between the change in PM
exposures and the total realization of changes in mortality effects. Specifically, we assume that
some of the incidences of premature mortality related to PM2.5 exposures occur in a distributed
fashion over the 20 years following exposure based on the advice of the SAB-HES (U.S. EPA-
SAB 2004), which affects the valuation of mortality co-benefits at different discount rates. The
above assumptions are subject to uncertainty.
In general, we are more confident in the magnitude of the risks we estimate from
simulated PM2.5 concentrations that coincide with the bulk of the observed PM concentrations in
32 See Chapter 1 for further discussion of these uncertainties.
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the epidemiological studies that are used to estimate the benefits. Likewise, we are less confident
in the risk we estimate from simulated PM2.5 concentrations that fall below the bulk of the
observed data in these studies. There are uncertainties inherent in identifying any particular point
at which our confidence in reported associations decreases appreciably, and the scientific
evidence provides no clear dividing line. This relationship between the air quality data and our
confidence in the estimated risk is represented below in Figure 4-1.
Less confident	More confident
Below LML of PM2.5 data in
epidemiology study
(extrapolation)
I standard deviation below
the mean PM2.5 observed in
epidemiology study
Mean of PM2.5 data in
epidemiology study
Figure 4-1 Stylized Relationship between the PM2.5 Concentrations Considered in
Epidemiology Studies and our Confidence in the Estimated PM-related
Premature Deaths
In this analysis, we build upon the concentration benchmark approach (also referred to as
the Lowest Measured Level analysis) that has been featured in recent RIAs and EPA's Policy
Assessment for Particulate Matter (U.S. EPA 201 la) by reporting the estimated PM-related
deaths according to alternative concentration cutpoints.
Concentration benchmark analyses allow readers to determine the portion of population
exposed to annual mean PM2.5 levels at or above different concentrations, which provides some
insight into the level of uncertainty in the estimated PM2.5 mortality benefits. The EPA does not
view these concentration benchmarks as concentration thresholds below which we would not
quantify health co-benefits of air quality improvements.33 Rather, the co-benefits estimates
reported in this RIA are the most appropriate estimates because they reflect the full range of air
quality concentrations associated with the emission reduction strategies being evaluated in this
33 For a summary of the scientific review statements regarding the lack of a threshold in the PM2 5-mortality
relationship, see the TSD entitled Summary of Expert Opinions on the Existence of a Threshold in the
Concentration-Response Function for PM2.5-related Mortality (U.S. EPA, 2010b).
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final rule. The PM ISA concluded that the scientific evidence collectively is sufficient to
conclude that there is a causal relationship between long-term PM2.5 exposures and mortality and
that overall the studies support the use of a no-threshold log-linear model to estimate mortality
attributed to long-term PM2.5 exposure (U.S. EPA 2009).
Figure 4-2 reports the percentage of the population, and number of PM-related deaths,
both above and below concentration benchmarks in the final policy modeling for the year 2025.
The figure identifies the LML for each of the major cohort studies and the annual mean PM2.5
NAAQS of 12 |ig/m3. For Krewski, the LML is 5.8 |ig/m3 and for Lepeule et al., the LML is 8
|ig/m3. These results are sensitive to the annual mean PM2.5 concentration the air quality model
predicted in each 12km by 12km grid cell (see section 4.4.1). The air quality modeling predicts
PM2.5 concentrations to be at or below the PM2.5 NAAQS (12 |ig/m3) in nearly all locations. The
photochemical modeling we employ accounts for the suite of local, state and federal policies
expected to reduce PM2.5 and PM2.5 precursor emissions in future years, such that we project a
very small number of locations exceeding the annual standard. After presenting the full suite of
results below (Table 4-5) we stratify these estimated PM2.5 mortality deaths according to the
concentration at which they occurred: below the LML, between the LML and the NAAQS, and
above the NAAQS in future years across different policy scenarios (Table 4-8). The results
above should be viewed in the context of the air quality modeling technique we used to estimate
PM2.5 concentrations. As described in Chapter 8 and above, we are more confident in our ability
to use the air quality modeling technique described above to estimate changes in annual mean
PM2.5 concentrations than we are in our ability to estimate absolute PM2.5 concentrations.
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LML	LML
Krewski (2009) Lepeule (2012)
2012
PM NAAQS
Mortality
Population Exposed
Figure 4-2 Estimated Percentage of PIVh.s-Related Deaths and Number of Individuals
Exposed by Annual Mean PM2.5 Level in 2025
4.5 Air Quality and Health Impact Results
4.5.1 Air Quality Results
Below we present the model-predicted change in annual mean PM2.5 concentrations and
summer-season average daily 8 hour maximum ozone concentrations for the illustrative policy
scenario (Figure 4-3). All maps display the change in air pollution calculated as the policy case
minus the baseline. The spatial fields used to create these maps serve as an input to the benefits
analysis, the results of which are described further below.
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i
58
58
a
a
a
a
2
s
s-
a
c
60
a
i
§3
>5
241
221
201
181
161
141
121
101
81
61
41
21
1
393
January 01, 2011 00:00:00 UTC
Min (77, 217) = -0.035, Max (297, 155) = 0.033
57
113
169
225
281
337
393
January 01, 2011 00:00:00 UTC
Min (271, 106) = -0.381. Max (294, 87) = 0.065
0.050
0.040
0.025
j= 0.010
D>
-0.005
-0.020
-0.035
-0.050
I
I
0.400
0.320
0.200
0.080
-0.040
-0.160
-0.280
-0.400
I
I
Figure 4-3
Change in Annual Mean PM2.5 (jig/m3) and Summer Season Average Daily
8hr Maximum Ozone (ppb) in 2025 (Difference Calculated as Illustrative
Policy Scenario minus Baseline)
4.5.1 Estimated Number and Economic Value of Ancillary Health Co-Benefits
Below we report the estimated number of reduced PM2.5 and ozone-related premature
deaths and illnesses in each year (Table 4-5) relative to the baseline along with the 95%
confidence interval. The number of reduced estimated deaths and illnesses from the illustrative
policy scenario are calculated from the sum of individual reduced mortality and illness risk
across the population. The table below is followed by the estimated number of avoi ded PM2.5-
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related premature deaths calculated using different approaches to help the reader determine the
fraction of PM2.5 attributable deaths occuring at lower ambient concentrations. We summarize
the dollar value of these impacts for the illustrative policy scenario across all PM2.5 and ozone-
related premature deaths and illnesses, using alternative approaches to representing and
quantifying PM mortality risk effects (Table 4-7).
When estimating benefits at or above the PM NAAQS, the percentage of total benefits
attributable to reducing PM exposure ranges from 5 percent to 9 percent, with the remainder
being attributable to reducing ozone exposure. When estimating benefits at or above the Lowest
Measured Levels of the two long-term exposure cohort studies, the percentage of total benefits
attributable to reducing PM ranges from 51 percent to 80 percent, with the remainder being
attributable to reducing ozone exposure. Finally, when estimating the benefits using the no-
threshold approach, the percentage of total benefits attributable to reducing PM ranges from 78
percent to 81 percent, with the remainder being attributable to reducing ozone.
The alternative approaches to quantifying and presenting mortality risk effects include
both different means for quantifying expected impacts using concentration-response functions
over the entire domain of exposure (i.e., the no-threshold model) along with different means of
presenting impacts by limiting consideration to only those impacts at exposures above the LML
or above the NAAQS (Table 4-8; Table 4-9; Figure 4-4).34
34 The EPA continues to refine its approach for estimating and reporting PM-related effects at lower concentrations,
particularly at levels below those considered by the long-term exposure epidemiology studies used here to quantify
PM-related premature deaths. The Agency acknowledges the additional uncertainty associated with effects estimated
at these lower levels (particularly below the LML of the long-term exposure mortality studies) and seeks to develop
quantitative approaches for reflecting this uncertainty in the estimated PM benefits.
4-30
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Table 4-5 Estimated Avoided PM2.5 and Ozone-Related Premature Deaths and Illnesses
in 2025, 2030 & 2035 (95% Confidence Interval)3

2025
2030
2035
Avoided premature death among adults


S Krewski et al. (2009)
33
(22 to 43)
44
(30 to 58)
48
(32 to 63)
Ph
Lepeuleetal. (2012)
74
(37 to 110)
99
(49 to 150)
110
(54 to 160)
^ Smith el al. (2009)
0
6
(3 to 9)
6
(3 to 9)
7
(4 to 11)
^ Jerrett et al. (2009)
23
(8 to 38)
23
(8 to 38)
28
(9 to 46)
PM2.5- related non-fatal heart attacks among adults


Peters et al. (2001)
37
(9 to 64)
48
(12 to 84)
50
(12 to 88)
Pooled estimate
4
(2 to 11)
5
(2 to 14)
5
(2 to 14)
All other morbidity effects



Hospital admissions—
9
12
13
cardiovascular (PM2 5)
(4 to 16)
(5 to 22)
(5 to 23)
Hospital admissions—
19
23
25
respiratory (PM2 5 & O3)
((6) to 40)
((7) to 48)
((8) to 53)
ED visits for asthma
54
55
65
(PM2.5 & 03)
((3) to 150)
((5) to 150)
((5) to 180)
Exacerbated asthma
14,000
14,000
17,000
(PM2.5 & 03)
((11,000) to 35,000)
((11,000) to 34,000)
((13,000) to 41,000)
Minor restricted-activity
48,000
52,000
58,000
days (PM25 & O3)
(28,000 to 67,000)
(32,000 to 71,000)
(36,000 to 80,000)
Acute bronchitis
42
56
60
(PM25)
((10) to 94)
((13) to 130)
((14) to 130)
Upper resp. symptoms
770
1,000
1,100
(PM25)
(140 to 1,400)
(190 to 1,900)
(200 to 2,000)
Lower resp. symptoms
540
720
770
(PM25)
(200 to 870)
(270 to 1,200)
(290 to 1,200)
Lost work days
3,700
4,600
5,000
(PM25)
(3,100 to 4,200)
(3,900 to 5,400)
(4,300 to 5,800)
School absence days
8,400
8,200
9,700
(03)
(3,000 to 19,000)
(2,900 to 18,000)
(3,400 to 22,000)
" Values rounded to two significant figures.
4-31
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Table 4-6 Estimated Avoided PM-Related Premature Deaths Using Alternative
Approaches Using Two Approaches to Quantifying Avoided PM-
	Attributable Deaths (95% Confidence Interval) in 2025, 2030 & 2035 a
Log-Linear no-threshold model
2025
2030
2035
Krewski et al. (2009)
33
(22 to 43)
44
(30 to 58)
48
(32 to 63)
Lepeule et al. (2012)
74
(37 to 110)
99
(49 to 150)
110
(54 to 160)
Quantifying effect of PM2.5 above the LML
in each study


Krewski et al. (2009)
31
39
41
(LML= 5.8 ug/m3)
(21 to 41)
(26 to 51)
(28 to 55)
Lepeule et al. (2012)
23
28
31
(LML=8ng/m3)
(12 to 35)
(14 to 42)
(16 to 47)
" Values rounded to two significant figures
4-32
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Table 4-7 Estimated Economic Value of Avoided PM2.5 and Ozone-Attributable Deaths
and Illnesses for the Illustrative Policy Scenario Using Alternative
Approaches to Represent PM2.5 Mortality Risk Effects (95% Confidence
Interval; millions of 2016$)a	
2025 2030 2035
Ozone benefits summed with PM benefits:
XT U .,4 $390 $970
No-threshold . ,M,,
« modelb ($37t0 t0 ($86t0
| $1,100) $2,800)
$490 $1,200
($47 to to ($110 to
$1,300) $3,500)
$550 $1,400
($52 to to ($120 to
$1,500) $3,900)
£ T . .t , t , $370 $480
g Limited to above
8 T MT c ($36 to to ($42 to
g $1,000) $1,400)
$440 $520
($42 to to ($47 to
$1,200) $1,500)
$480 $610
($25 to to ($16 to
$1,300) $1,800)
= , . $76 $250
£ Effects above .
NA AO
-------
Table 4-8 Estimated Percent of Avoided PM2.5-related Premature Deaths Above and
Below PM2.5 Concentration Cut Points
Avoided PM2.s-related premature deaths
reported by air quality cutpoint
Year
Epidemiological
study
Total
mortality
Above
NAAQS
Below NAAQS and
Above LMLa
Below LMLa

Krewski
33
<1
31
1.5
2025
(< 1%)
<1
(< 1%)
(94%)
23
(31%)
(5%)
51
(69%)

Lepeule
74

Krewski
44
<1
38
5.2
2030
(<1%)
<1
(<1%)
(86%)
27
(27%)
(12%)
71
(72%)

Lepeule
99

Krewski
48
<1
41
6.3
2035
(< 1%)
<1
(< 1%)
(85%)
31
(28%)
(13%)
78
(71%)

Lepeule
110
a The LML of the Krewski study is 5.8 |ig/m3 and 8 |ig/m3 for Lepeule et al study.
Table 4-9 Avoided PM2.5-related Premature Deaths Estimated at Annual Mean PM2.5
Levels Corresponding to the Air Quality Distribution Observed in the
Krewski et al. (2009) American Cancer Society Study
Less Confident	More Confident

Year
Below LML
(<5.8)
LML to 1st
%ile
(>5.8 &
<6.7)
1st to 5th
%ile
(>6.7 &
<8.8)
5th to 10th
%ile
(>8.8 &
<10.2)
10th to 25th
%ile
(>10.2 &
<11.8)
25th %ile &
Above
(>11.8)
2025
2
(1 to 2)
5
(4 to 7)
22
(15 to 30)
3
(2 to 4)
0
(0 to 0)
0
(0 to 0)
2030
5
(4 to 7)
8
(5 to 10)
26
(18 to 35)
4
(3 to 5)
0
(0 to 0)
0
(0 to 0)
2035
6
(4 to 8)
9
(6 to 12)
28
(19 to 37)
4
(3 to 6)
0
(0 to 0)
0
(0 to 0)
4-34
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Annual Mean PM2.5 Levels	Future Year
Below LML of ACS (<5. S 2025
ug/m3) 2030
2035
m
mam
: ——	
LML to 1st " bile of ACS 2025
(>5.8 & <6.7 fig/m3) 2030
2035
mtm
j		
1st to 5th %ile of ACS (>6.7 & 2025
<8.8 ng'm3) 2030
2035

5th to 10th %ile of ACS 2025
(>8.8 & <10.2 ng/m3) 2030
2035
mmm
^m*
1 Oth to 25th 0 bile of ACS 2025
(>10.2 & <11.8 fjig'in3) 2030
2035
~i
0 The colored circles represent the estimated
g avoidedPM2.5-relatedpremature deaths
and the grey lines represent the 2.5% to the
97.5% confidence interval.
•
25th ° bile & Above of ACS 2025
(<118 Ug/m3) 2030
2035

0 5 10 15 20 25 30 35
Avoided PM2.5-related Premature Deaths
Annual Mean PM2.5 Levels
¦	Below LML of ACS (<5.8 (Jg/m3)
¦	LML to 1st %ile of ACS (>5.8 8. <6.7 pg/m3)
¦	1st to 5 th %ile of ACS (>6.7 & <8.8 ^&'m3)
5th to I Oth %ile of ACS (>8.8 & < 10.2 pg/m3)
¦	I Oth to 25th %iie of ACS <>10.2 & <1 1.8 Mg'm3)
25th %ile & Above of ACS (< I 1.8 pg/m3)
Figure 4-4 Avoided PM2.5-related Premature Deaths Estimated at Annual Mean PM2.5
Levels Corresponding to the Air Quality Distribution Observed in the
Krewski et al. (2009) American Cancer Society Study (ACS)
The estimated number of deaths above and below the LML varies considerably according
to the epidemiology study used to estimate risk. Thus, for any year analyzed, we estimate a
substantially larger fraction of PM-related deaths above the LML of the Krewski et al. (2009)
study than we do the Lepeule et al. (2012) study as shown in Table 4-8. Likewise, we estimate a
greater percentage of PM2.5-related deaths below the LML of the Lepeule et al. (2012) study than
we do the Krewski et al. (2009) study. Table 4-8 also shows we estimate a very small percentage
of PM-related premature deaths occurring above the NAAQS in any future year using either of
these two studies.
4-35
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4.6 Total Estimated Climate and Health Benefits
In this analysis, we estimated the dollar value of changes in CO2 emissions and the
ancillary co-benefits of changes in exposure to PM2.5 and ozone, but were unable to quantify the
economic value of changes in exposure to mercury, carbon monoxide, SO2, and NO2, ecosystem
effects or visibility impairment. Table 4-10 through Table 4-12 report the combined domestic
climate benefits, and health co-benefits discounted at rates of 3 percent and 7 percent for the
illustrative policy scenario evaluated for each analysis year: 2025, 2030, and 2035.
Table 4-10 Estimated Climate Benefits and Ancillary Health Co-Benefits of Illustrative
Policy Scenario (millions of 2016$)
Values Calculated using 3% Discount Rate
Values Calculated using 7% Discount Rate

Domestic Climate
Health Total
Domestic Climate
Health Total

Benefits
Co-Benefits Benefits
Benefits
Co-Benefits Benefits
2025
81
390 to 970 470 to 1,000
13
360 to 900 370 to 920
2030
81
490 to 1,200 570 to 1,300
14
460 to 1,100 470 to 1,100
2035
72
550 to 1,400 620 to 1,400
13
510 to 1,300 520 to 1,300
Notes: Estimates rounded to two significant figures, so figures may not sum due to independent rounding. The
climate benefit estimates in this table reflect the value of domestic impacts from CO2 emission changes and do not
account for changes in non-CCh GHG emissions. Ozone co-benefits occur in analysis year, so they are the same for
all discount rates. The health co-benefits reflect the sum of the PM2 5 and ozone co-benefits and reflect the range
based on adult mortality functions (e.g., from Krewski el al. (2009) with Smith el al. (2009) to Lepeule el al. (2012)
with Jerrett et al. (2009)). The health co-benefits do not account for direct exposure to NO2, SO2, and HAP;
ecosystem effects; or, visibility impairment.
4-36
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Table 4-11 Estimated Climate Benefits and Ancillary Health Co-Benefits of Illustrative
Policy Scenario, showing only PM2.5 Related Mortality Risk Benefits above
the Lowest Measured Level of Each Long-Term PM2.5 Mortality Study
(millions of 2016$)	
Values Calculated using 3% Discount Rate
Values Calculated using 7% Discount Rate

Domestic
Climate
Benefits
Health
Total
Domestic
Climate
Benefits
Health
Total

Co-Benefits
Benefits
Co-Benefits
Benefits
2025
81
370 to 480
450 to 560
13
350 to 460
360 to 470
2030
81
440 to 520
520 to 600
14
410 to 500
420 to 510
2035
72
480 to 610
560 to 680
13
450 to 590
460 to 600
Notes: Estimates rounded to two significant figures, so figures may not sum due to independent rounding. The
climate benefit estimates in this table reflect the value of domestic impacts from CO2 emission changes and do not
account for changes in non-CCh GHG emissions. Ozone co-benefits occur in analysis year, so they are the same for
all discount rates. The health co-benefits reflect the sum of the PM2 5 and ozone co-benefits and reflect the range
based on adult mortality functions (e.g., from Krewski el al. (2009) with Smith el al. (2009) to Lepeule el al. (2012)
with Jerrett et al. (2009)). The health co-benefits do not account for direct exposure to NO2, SO2, and HAP;
ecosystem effects; or, visibility impairment.
Table 4-12 Estimated Climate Benefits and Ancillary Health Co-Benefits of Illustrative
Policy Scenario, showing only PM2.5 Related Mortality Risk Benefits above
	PM2.5 National Ambient Air Quality Standard (millions of 2016$)	
Values Calculated using 3% Discount Rate
Values Calculated using 7% Discount Rate

Domestic
Climate
Benefits
Health
Total
Domestic
Climate
Benefits
Health
Total

Co-Benefits
Benefits
Co-Benefits
Benefits
2025
81
76 to 250
160 to 330
13
76 to 250
89 to 270
2030
81
75 to 260
160 to 340
14
75 to 260
89 to 270
2035
72
90 to 320
160 to 390
13
90 to 320
100 to 330
Notes: Estimates rounded to two significant figures, so figures may not sum due to independent rounding. The
climate benefit estimates in this table reflect the value of domestic impacts from CO2 emission changes and do not
account for changes in non-C02 GHG emissions. Ozone co-benefits occur in analysis year, so they are the same for
all discount rates. The health co-benefits reflect the sum of the PM2 5 and ozone co-benefits and reflect the range
based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith el al. (2009) to Lepeule et al. (2012)
with Jerrett et al. (2009)). The health co-benefits do not account for direct exposure to NO2, SO2, and HAP;
ecosystem effects; or, visibility impairment.
4.7 Ancillary Co-Benefits Not Quantified
The monetized co-benefits estimated above are a subset of those we expect to occur.
Data, time, and resource limitations prevented the EPA from quantifying the impacts to, or
monetizing the co-benefits from, several important benefit categories; these include co-benefits
associated with exposure to several HAPs (including mercury and hydrogen chloride), SO2 and
4-37
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N02, as well as ecosystem effects, and visibility impairment. Below is a qualitative description
of these benefits (Table 4-13).
We group endpoints effected by these pollutants into "health" and "welfare" categories.
These are legal terms used in the context of setting the primary and secondary NAAQS standards
and come from the Clean Air Act (CAA). The primary standards are based on human health
considerations while the secondary standards are based on welfare considerations, which
essentially are non-human health impacts that may be considered when setting a secondary
NAAQS standard (e.g., ecosystem effects, visibility impairment, material damage). The
definition of the term welfare used in this section is not the same as the term is commonly
applied in benefit-cost analysis, which is as a measure of individual well-being that accounts for
both health and non-health outcomes. While the CAA only applies these terms to criteria
pollutants, they are applied here to both criteria and non-criteria pollutants.
4-38
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Table 4-13 Unquantified Ancillary Health and Welfare Co-Benefits Categories
Category
Effect
Effect
Quantified
Effect
Monetized
More
Information
Improved Human Health

Asthma hospital admissions (all ages)
—
—
NO2 ISA1

Chronic lung disease hospital admissions (age >
65)
—
—
NO2 ISA1

Respiratory emergency department visits (all
ages)
—
—
NO2 ISA1
morbidity from
Asthma exacerbation (asthmatics age 4-18)
—
—
NO2 ISA1
exposure to NO2
Acute respiratory symptoms (age 7-14)
—
—
NO2 ISA1

Premature mortality
—
—
NO2 ISA1'2'3

Other respiratory effects (e.g., airway
hyperresponsiveness and inflammation, lung
function, other ages and populations)
—
—
NO2 ISA2-3

Respiratory hospital admissions (age > 65)
—
—
SO2 ISA1

Asthma emergency department visits (all ages)
—
—
SO2 ISA1
Reduced incidence of
morbidity from
Asthma exacerbation (asthmatics age 4-12)
Acute respiratory symptoms (age 7-14)
—
—
SO2 ISA1
SO2 ISA1
exposure to SO2
Premature mortality
—
—
SO2 ISA1-2-3

Other respiratory effects (e.g., airway
hyperresponsiveness and inflammation, lung
function, other ages and populations)
—
—
SO2 ISA1-2

Cardiovascular effects
—
—
CO ISA 1'2
Reduced incidence of
morbidity from
exposure to CO
Respiratory effects
Central nervous system effects
—
—
CO ISA 1'2'3
CO ISA 1-2'3
Premature mortality
—
—
CO ISA 1-2'3

Neurologic effects—IQ loss
—
—
IRIS; NRC,
20001
Reduced incidence of
morbidity from
Other neurologic effects (e.g., developmental
delays, memory, behavior)
—
—
IRIS; NRC,
20002
exposure to
methylmercury
Cardiovascular effects
—
—
IRIS; NRC,
20002'3

Genotoxic, immunologic, and other toxic effects
—
—
IRIS; NRC,
20002'3
Improved Environment
Reduced visibility
Visibility in Class 1 areas
—
—
PM ISA1
impairment
Visibility in residential areas
—
—
PM ISA1
Reduced effects on
materials
Household soiling
—
—
PM ISA1,2
Materials damage (e.g., corrosion, increased
wear)
—
—
PM ISA2
Reduced effects from




PM deposition (metals
and organic s)
Effects on Individual organisms and ecosystems
—
—
PM ISA2

Visible foliar injury on vegetation
—
—
Ozone ISA1

Reduced vegetation growth and reproduction
—
—
Ozone ISA1
Reduced vegetation
Yield and quality of commercial forest products
and crops
—
—
Ozone ISA1
and ecosystem effects
from exposure to
ozone
Damage to urban ornamental plants
Carbon sequestration in terrestrial ecosystems
—
—
Ozone ISA2
Ozone ISA1

Recreational demand associated with forest
aesthetics
—
—
Ozone ISA2

Other non-use effects


Ozone ISA2
4-39
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Category
Effect
Effect
Quantified
Effect
Monetized
More
Information

Ecosystem functions (e.g., water cycling,
biogeochemical cycles, net primary productivity,
leaf-gas exchange, community composition)
—
—
Ozone ISA2

Recreational fishing
—
—
NOxSOxISA1
Reduced effects from
acid deposition
Tree mortality and decline
Commercial fishing and forestry effects
Recreational demand m terrestrial and aquatic
ecosystems
Other non-use effects
Ecosystem functions (e.g., biogeochemical
cycles)
—
—
NOxSOxISA2
NOxSOxISA2
NOxSOxISA2
NOxSOxISA2
NOxSOxISA2

Species composition and biodiversity in terrestrial
and estuarine ecosystems
—
—
NOxSOxISA2

Coastal eutrophication
—
—
NOxSOxISA2
Reduced effects from
nutrient enrichment
Recreational demand in terrestrial and estuarine
ecosystems
—
—
NOxSOxISA2

Other non-use effects


NOxSOxISA2

Ecosystem functions (e.g., biogeochemical
cycles, fire regulation)
—
—
NOxSOxISA2
Reduced vegetation
Injury to vegetation from SO2 exposure
—
—
NOxSOxISA2
effects from ambient
exposure to SO2 and
NOx
Injury to vegetation from NOx exposure
—
—
NOxSOxISA2
Reduced ecosystem
effects from exposure
to methylmercury
Effects on fish, birds, and mammals (e.g.,
reproductive effects)
—
—
Mercury Study
RTC2
Commercial, subsistence and recreational fishing
—
—
Mercury Study
RTC1
1	We assess these co-benefits qualitatively due to data and resource limitations.
2	We assess these co-benefits qualitatively because we do not have sufficient confidence in available data or methods.
3	We assess these co-benefits qualitatively because current evidence is only suggestive of causality or there are other significant
concerns over the strength of the association.
4.7.1 Hazardous Air Pollutant Impacts
Due to methodology and resource limitations, we were unable to estimate the impacts
associated with changes in emissions of the hazardous air pollutants in this analysis. EPA's
SAB-HES concluded that "the challenges for assessing progress in health improvement as a
result of reductions in emissions of HAPs are daunting...due to a lack of exposure-response
functions, uncertainties in emissions inventories and background levels, the difficulty of
extrapolating risk estimates to low doses and the challenges of tracking health progress for
diseases, such as cancer, that have long latency periods" (EPA-SAB 2008b). In 2009, the EPA
convened a workshop to address the inherent complexities, limitations, and uncertainties in
current methods to quantify the benefits of reducing HAP. Recommendations from this
workshop included identifying research priorities, focusing on susceptible and vulnerable
populations, and improving dose-response relationships (Gwinn et al. 2011).
4-40
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4.7.1.1 Mercury
Mercury (Hg) in the environment is transformed into a more toxic form, methylmercury
(MeHg). Because Hg is a persistent pollutant, MeHg accumulates in the food chain, especially
the tissue of fish. When people consume these fish, they consume MeHg. In 2000, the NAS
Study was issued which provides a thorough review of the effects of MeHg on human health
(NRC 2000).35 Many of the peer-reviewed articles cited in this section are publications originally
cited in the Mercury Study.36 In addition, the EPA has conducted literature searches to obtain
other related and more recent publications to complement the material summarized by the NRC
in 2000.
In its review of the literature, the NAS found neurodevelopmental effects to be the most
sensitive and best documented endpoints and appropriate for establishing a reference dose (RfD)
(NRC 2000); in particular NAS supported the use of results from neurobehavioral or
neuropsychological tests. The NAS report noted that studies on animals reported sensory effects
as well as effects on brain development and memory functions and supported the conclusions
based on epidemiology studies. The NAS noted that their recommended endpoints for a RfD are
associated with the ability of children to learn and to succeed in school. They concluded the
following: "The population at highest risk is the children of women who consumed large
amounts of fish and seafood during pregnancy. The committee concludes that the risk to that
population is likely to be sufficient to result in an increase in the number of children who have to
struggle to keep up in school."
The NAS summarized data on cardiovascular effects available up to 2000. Based on these
and other studies, the NRC concluded that "Although the data base is not as extensive for
cardiovascular effects as it is for other end points (i.e., neurologic effects), the cardiovascular
system appears to be a target for MeHg toxicity in humans and animals." The NRC also stated
that "additional studies are needed to better characterize the effect of methylmercury exposure on
blood pressure and cardiovascular function at various stages of life."
35	National Research Council (NRC). 2000. Toxicological Effects of Methylmercury. Washington, DC: National
Academies Press.
36	U.S. Environmental Protection Agency (U.S. EPA). 1997. Mercury Study Report to Congress, EPA-HQ-OAR-
2009-0234-3054. December. Available at http://www.epa.gov/hg/report.htm.
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Additional cardiovascular studies have been published since 2000. The EPA did not
develop a quantitative dose-response assessment for cardiovascular effects associated with
MeHg exposures, as there is no consensus among scientists on the dose-response functions for
these effects. In addition, there is inconsistency among available studies as to the association
between MeHg exposure and various cardiovascular system effects. The pharmacokinetics of
some of the exposure measures (such as toenail Hg levels) are not well understood. The studies
have not yet received the review and scrutiny of the more well-established neurotoxicity data
base.
The Mercury Study noted that MeHg is not a potent mutagen but is capable of causing
chromosomal damage in a number of experimental systems. The NAS concluded that evidence
that human exposure to MeHg caused genetic damage is inconclusive; they note that some earlier
studies showing chromosomal damage in lymphocytes may not have controlled sufficiently for
potential confounders. One study of adults living in the Tapajos River region in Brazil (Amorim
et al. 2000) reported a direct relationship between MeHg concentration in hair and DNA damage
in lymphocytes, as well as effects on chromosomes.37 Long-term MeHg exposures in this
population were believed to occur through consumption of fish, suggesting that genotoxic effects
(largely chromosomal aberrations) may result from dietary and chronic MeHg exposures similar
to and above those seen in the Faroes and Seychelles populations.
Although exposure to some forms of Hg can result in a decrease in immune activity or an
autoimmune response (ATSDR 1999), evidence for immunotoxic effects of MeHg is limited
(NRC 2000).38 Based on limited human and animal data, MeHg is classified as a "possible"
human carcinogen by the International Agency for Research on Cancer (IARC 1994)39 and in
37	Amorim, M.I.M., D. Mergler, M.O. Bahia, H. Dubeau, D. Miranda, J. Lebel, R.R. Burbano, and M. Lucotte.
2000. Cytogenetic damage related to low levels of methyl mercury contamination in the Brazilian Amazon. An.
Acad. Bras. Cienc. 72(4): 497-507.
38	Agency for Toxic Substances and Disease Registry (ATSDR). 1999. Toxicological Profile for Mercury. U.S.
Department of Health and Human Services, Public Health Service, Atlanta, GA.
39	International Agency for Research on Cancer (IARC). 1994. IARC Monographs on the Evaluation of
Carcinogenic Risks to Humans and their Supplements: Beryllium, Cadmium, Mercury, and Exposures in the Glass
Manufacturing Industry. Vol. 58. Jalili, H.A., and A.H. Abbasi. 1961. Poisoning by ethyl mercury toluene
sulphonanilide. Br. J. Indust. Med. 18(0ct.):303-308 (as cited in NRC, 2000).
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IRIS (U.S. EPA 2002).40 The existing evidence supporting the possibility of carcinogenic effects
in humans from low-dose chronic exposures is tenuous. Multiple human epidemiological studies
have found no significant association between Hg exposure and overall cancer incidence,
although a few studies have shown an association between Hg exposure and specific types of
cancer incidence (e.g., acute leukemia and liver cancer) (NRC 2000).
There is also some evidence of reproductive and renal toxicity in humans from MeHg
exposure. However, overall, human data regarding reproductive, renal, and hematological
toxicity from MeHg are very limited and are based on either studies of the two high-dose
poisoning episodes in Iraq and Japan or animal data, rather than epidemiological studies of
chronic exposures at the levels of interest in this analysis.
4.7.1.2 Hydrogen Chloride
Hydrogen chloride (HC1) is a corrosive gas that can cause irritation of the mucous
membranes of the nose, throat, and respiratory tract. Brief exposure to 35 ppm causes throat
irritation, and levels of 50 to 100 ppm are barely tolerable for 1 hour.41 Concentrations in typical
human exposure environments are much lower than these levels and rarely exceed the reference
concentration.42 The greatest impact is on the upper respiratory tract; exposure to high
concentrations can rapidly lead to swelling and spasm of the throat and suffocation. Most
seriously exposed persons have immediate onset of rapid breathing, blue coloring of the skin,
and narrowing of the bronchioles. Exposure to HC1 can lead to Reactive Airways Dysfunction
Syndrome (RADS), a chemically, or irritant-induced type of asthma. Children may be more
vulnerable to corrosive agents than adults because of the relatively smaller diameter of their
airways. Children may also be more vulnerable to gas exposure because of increased minute
40	U.S. Environmental Protection Agency (EPA). 2002. Integrated Risk Information System (IRIS) on
Methylmercury. National Center for Environmental Assessment. Office of Research and Development. Available at
http ://www.epa. gov/iris/subst/0073. htm.
41	Agency for Toxic Substances and Disease Registry (ATSDR). Medical Management Guidelines for Hydrogen
Chloride. Atlanta, GA: U.S. Department of Health and Human Services. Available at
http://www.atsdr.cdc.gov/mmg/mmg.asp?id=758&tid=147#bookmark02.
42	Table of Prioritized Chronic Dose-Response Values: http://www2.epa.gov/sites/production/files/2014-
05/documents/table 1 .pdf
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ventilation per kg and failure to evacuate an area promptly when exposed. Hydrogen chloride has
not been classified for carcinogenic effects.43
4.7.2	NO2Health Co-Benefits
In addition to being a precursor to PM2.5 and ozone, NOx emissions are also linked to a
variety of adverse health effects associated with direct exposure. We were unable to estimate the
health co-benefits associated with reduced NO2 exposure in this analysis. Therefore, this analysis
only quantified and monetized the PM2.5 and ozone co-benefits associated with the reductions in
NO2 emissions. Following a comprehensive review of health evidence from epidemiologic and
laboratory studies, the Integrated Science Assessment for Oxides of Nitrogen —Health Criteria
(NOx ISA) (U.S. EPA 2016b) concluded that there is a likely causal relationship between
respiratory health effects and short-term exposure to NO2. These epidemiologic and experimental
studies encompass a number of endpoints including emergency department visits and
hospitalizations, respiratory symptoms, airway hyperresponsiveness, airway inflammation, and
lung function. The NOx ISA also concluded that the relationship between short-term NO2
exposure and premature mortality was "suggestive but not sufficient to infer a causal
relationship," because it is difficult to attribute the mortality risk effects to NO2 alone. Although
the NOx ISA stated that studies consistently reported a relationship between NO2 exposure and
mortality, the effect was generally smaller than that for other pollutants such as PM.
4.7.3	SO2 Health Co-Benefits
In addition to being a precursor to PM2.5, SO2 emissions are also linked to a variety of
adverse health effects associated with direct exposure. We were unable to estimate the health co-
benefits associated with reduced SO2 in this analysis. Therefore, this analysis only quantifies and
monetizes the PM2.5 co-benefits associated with the reductions in SO2 emissions.
Following an extensive evaluation of health evidence from epidemiologic and laboratory
studies, the Integrated Science Assessment for Oxides of Sulfur —Health Criteria (SO2 ISA)
concluded that there is a causal relationship between respiratory health effects and short-term
43 U.S. Environmental Protection Agency (U.S. EPA). 1995. "Integrated Risk Information System File of Hydrogen
Chloride." Washington, DC: Research and Development, National Center for Environmental Assessment. This
material is available at http://www.epa.gov/iris/subst/0396.htm.
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exposure to SO2 (U.S. EPA 2017). The immediate effect of SO2 on the respiratory system in
humans is bronchoconstriction. Asthmatics are more sensitive to the effects of SO2 likely
resulting from preexisting inflammation associated with this disease. A clear concentration-
response relationship has been demonstrated in laboratory studies following exposures to SO2 at
concentrations between 20 and 100 ppb, both in terms of increasing severity of effect and
percentage of asthmatics adversely affected. Based on our review of this information, we
identified three short-term morbidity endpoints that the SO2 ISA identified as a "causal
relationship": asthma exacerbation, respiratory-related emergency department visits, and
respiratory-related hospitalizations. The differing evidence and associated strength of the
evidence for these different effects is described in detail in the SO2 ISA. The SO2 ISA also
concluded that the relationship between short-term SO2 exposure and premature mortality was
"suggestive of a causal relationship" because it is difficult to attribute the mortality risk effects to
SO2 alone. Although the SO2 ISA stated that studies are generally consistent in reporting a
relationship between SO2 exposure and mortality, there was a lack of robustness of the observed
associations to adjustment for other pollutants. We did not quantify these co-benefits due to data
constraints.
4.7.4 NO2 and SO2 Welfare Co-Benefits
As described in the Integrated Science Assessment for Oxides of Nitrogen and Sulfur —
Ecological Criteria (NOx/SOx ISA) (U.S. EPA 2008), SO2 and NOx emissions also contribute to
a variety of adverse welfare effects, including those associated with acidic deposition, visibility
impairment, and nutrient enrichment. Deposition of nitrogen causes acidification, which can
cause a loss of biodiversity of fishes, zooplankton, and macro invertebrates in aquatic
ecosystems, as well as a decline in sensitive tree species, such as red spruce (Picea rubens) and
sugar maple (Acer saccharum) in terrestrial ecosystems. In the northeastern U.S., the surface
waters affected by acidification are a source of food for some recreational and subsistence
fishermen and for other consumers and support several cultural services, including aesthetic and
educational services and recreational fishing. Biological effects of acidification in terrestrial
ecosystems are generally linked to aluminum toxicity, which can cause reduced root growth,
restricting the ability of the plant to take up water and nutrients. These direct effects can, in turn,
increase the sensitivity of these plants to stresses, such as droughts, cold temperatures, insect
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pests, and disease leading to increased mortality of canopy trees. Terrestrial acidification affects
several important ecological services, including declines in habitat for threatened and endangered
species (cultural), declines in forest aesthetics (cultural), declines in forest productivity
(provisioning), and increases in forest soil erosion and reductions in water retention (cultural and
regulating) (U.S. EPA 2008).
Deposition of nitrogen is also associated with aquatic and terrestrial nutrient enrichment.
In estuarine waters, excess nutrient enrichment can lead to eutrophication. Eutrophication of
estuaries can disrupt an important source of food production, particularly fish and shellfish
production, and a variety of cultural ecosystem services, including water-based recreational and
aesthetic services. Terrestrial nutrient enrichment is associated with changes in the types and
number of species and biodiversity in terrestrial systems. Excessive nitrogen deposition upsets
the balance between native and nonnative plants, changing the ability of an area to support
biodiversity. When the composition of species changes, then fire frequency and intensity can
also change, as nonnative grasses fuel more frequent and more intense wildfires (U.S. EPA
2008).
4.7.5	Ozone Welfare Co-Benefits
Exposure to ozone has been associated with a wide array of vegetation and ecosystem
effects in the published literature (U.S. EPA 2013a). Sensitivity to ozone is highly variable
across species, with over 65 plant species identified as "ozone-sensitive", many of which occur
in state and national parks and forests. These effects include those that damage or impair the
intended use of the plant or ecosystem. Such effects can include reduced growth and/or biomass
production in sensitive plant species, including forest trees, reduced yield and quality of crops,
visible foliar injury, species composition shift, and changes in ecosystems and associated
ecosystem services.
4.7.6	Visibility Impairment Co-Benefits
Reductions in emissions of N02 and S02 will improve the level of visibility throughout
the United States because these gases (and the particles of nitrate and sulfate formed from these
gases) impair visibility by scattering and absorbing light (U.S. EPA 2009). Visibility is also
referred to as visual air quality (VAQ), and it directly affects people's enjoyment of a variety of
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daily activities (U.S. EPA 2009). Good visibility increases quality of life where individuals live
and work, and where they travel for recreational activities, including sites of unique public value,
such as the Great Smoky Mountains National Park (U.S. EPA 2009).
Reducing secondary formation of PM2.5 would improve levels of visibility in the U.S.
because suspended particles and gases degrade visibility by scattering and absorbing light (U.S.
EPA 2009). Fine particles with significant light-extinction efficiencies include sulfates, nitrates,
organic carbon, elemental carbon, and soil (Sisler 1996). Visibility has direct significance to
people's enjoyment of daily activities and their overall sense of wellbeing. Good visibility
increases the quality of life where individuals live and work, and where they engage in
recreational activities. Particulate sulfate is the dominant source of regional haze in the eastern
U.S. and particulate nitrate is an important contributor to light extinction in California and the
upper Midwestern U.S., particularly during winter (U.S. EPA 2009). Previous analyses show that
visibility co-benefits can be a significant welfare benefit category (U.S. EPA 201 Id). In this
analysis, we did not estimate visibility related benefits or whether the emission reductions
associated with the final emission guidelines would be likely to have a significant impact on
visibility in urban areas or mandatory Class I areas, i.e., federal wilderness areas and national
parks.
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Ito K, De Leon SF, Lippmann M. 2005. Associations Between Ozone and Daily Mortality.
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Jerrett M, Burnett RT, Pope CA, Ito K, Thurston G, Krewski D, et al. 2009. Long-term ozone
exposure and mortality. NEngl J Med 360:1085-95; doi:10.1056/NEJMoa0803894.
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Krewski D, Jerrett M, Burnett RT, Ma R, Hughes E, Shi Y, et al. 2009. Extended follow-up and
spatial analysis of the American Cancer Society study linking particulate air pollution and
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Lepeule J, Laden F, Dockery D, Schwartz J. 2012. Chronic exposure to fine particles and
mortality: an extended follow-up of the Harvard Six Cities study from 1974 to 2009.
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Levy JI, Chemerynski SM, Sarnat JA. 2005. Ozone exposure and mortality: an empiric bayes
metaregression analysis. Epidemiology 16: 458-68.
Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change
Impacts in the United States: The Third National Climate Assessment. U.S. Global
Change Research Program, 841 pp. doi:10.7930/J0Z31WJ2.
NRC. 2008. Estimating Mortality Risk Reduction and Economic Benefits from Controlling
Ozone Air Pollution. National Academies Press: Washington, D.C.
NRC. 2002. Estimating the Public Health Benefits of Proposed Air Pollution Regulations.
Washington, D.C.
NRC. 2000. Toxicological Effects of Methylmercury. National Academies Press: Washington,
D.C.
Ramboll Environ International Corporation. User's Guide: Comprehensive Air Quality Model
with Extensions version 6.40.
Ren C, Williams GM, Mengersen K, Morawska L, Tong S. 2008a. Does temperature modify
short-term effects of ozone on total mortality in 60 large eastern US communities? An
assessment using the NMMAPS data. Environ Int 34:451-8;
doi: 10.1016/j.envint.2007.10.001.
Ren C, Williams GM, Morawska L, Mengersen K, Tong S. 2008b. Ozone modifies associations
between temperature and cardiovascular mortality: analysis of the NMMAPS data. Occup
Environ Med 65:255-60; doi:10.1136/oem.2007.033878.
Schwartz J. 2005. How sensitive is the association between ozone and daily deaths to control for
temperature? Am JRespir Crit Care Med 171:627-31; doi:10.1164/rccm.200407-9330C.
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Schwartz J, Coull B, Laden F, Ryan L. 2008. The effect of dose and timing of dose on the
association between airborne particles and survival. Environ Health Perspect 116:64-9;
doi:10.1289/ehp.9955.
Sisler JF. 1996. Spatial and Seasonal Patterns and Long - Term Variability of the Composition of
the Haze in the United States: An analysis of data from the IMPROVE network.;
doi:ISSN 0737- 5352 -32.
Smith RL, Xu B, Switzer P. 2009. Reassessing the relationship between ozone and short-term
mortality in U.S. urban communities. Inhal Toxicol 21 Suppl 2:37-61;
doi: 10.1080/08958370903161612.
U.S. EPA-SAB. 2000. An SAB Report on EPA's White Paper Valuing the Benefits of Fatal
Cancer Risk Reduction.
U.S. EPA-SAB. 2004. Advisory Council on Clean Air Compliance Analysis Response to
Agency Request on Cessation Lag.
U.S. EPA-SAB. 2008a. Review of EPA's Integrated Science Assessment for Particulate Matter
(First External Review Draft, December 2008).
U.S. EPA-SAB. 2008b. Subject: Benefits of Reducing Benzene Emissions in Houston, 1990-
2020.
U.S. EPA-SAB. 2009. Review of Integrated Science Assessment for Particulate Matter (Second
External Review Draft, July 2009).
U.S. EPA-SAB. 2010. Review of EPA's Draft Health Benefits of the Second Section 812
Prospective Study of the CAA.
U.S. EPA-SAB. 2011. Review of: Valuing Mortality Risk Reductions for Environmental Policy:
A White Paper.
U.S. EPA. 2002. Methylmercury (MeHg) CASRN 22967-92-6 | IRIS | US EPA, ORD.
U.S. EPA. 2008a. Integrated Science Assessment (ISA) for Nitrogen Dioxide (Health Criteria).
U.S. EPA. 2008b. Integrated Science Assessment (ISA) for Oxides of Nitrogen and Sulfur -
Ecological Criteria (Final Report, Dec 2008).
U.S. EPA. 2008c. Integrated Science Assessment (ISA) for Sulfur Oxides (Health Criteria).
U.S. EPA. 2009. Integrated Science Assessment for Particulate Matter. EPA/600/R-.
U.S. EPA. 2010a. Integrated Science Assessment (ISA) for Carbon Monoxide (Final Report).
U.S. EPA. 2010b. Regulatory Impact Analysis (RIA) for Existing Stationary Compression
Ignition Engines NESHAP Final Draft.
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U.S. EPA. 2010c. Regulatory Impact Analysis for the Proposed Federal Transport Rule.
U.S. EPA. 2010d. Valuing Mortality Risk Reductions for Environmental Policy: A White Paper.
U.S. EPA. 201 la. Policy Assessment for the Review of the Particulate Matter National Ambient
Air Quality Standards.
U.S. EPA. 201 lb. Regulatory Impact Analysis for the Federal Implementation Plans to Reduce
Interstate Transport of Fine Particulate Matter and Ozone in 27 States; Correction of SIP
Approvals for 22 States.
U.S. EPA. 201 lc. Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards.
U.S. EPA. 201 Id. Regulatory Impact Assessment for the Mercury and Air Toxics Standards.
U.S. EPA. 2012a. Regulatory Impact Analysis for the Proposed Revisions to the National
Ambient Air Quality Standards for Particulate Matter.
U.S. EPA. 2012b. Regulatory Impact Assessment for the Particulate Matter National Ambient
Air Quality Standards.
U.S. EPA. 2013a. Integrated Science Assessment of Ozone and Related Photochemical Oxidants
(Final Report).; doi:EPA/600/R-10/076F.
U.S. EPA. 2013b. Regulatory Impact Analysis for the Final Revisions to the National Ambient
Air Quality Standards for Particulate Matter.
U.S. EPA. 2014a. Regulatory Impact Analysis (RIA) for Proposed Residential Wood Heaters
NSPS Revision.
U.S. EPA. 2014b. Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for
Existing Power Plants and Emission Standards for Modified and Reconstructed Power
Plants.
U.S. EPA. 2014c. Regulatory Impact Analysis of the Proposed Revisions to the National
Ambient Air Quality Standards for Ground-Level Ozone.
U.S. EPA. 2015a. Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS
Revision: Final Report.
U.S. EPA. 2015b. Regulatory Impact Analysis for the Clean Power Plan Final Rule.
U.S. EPA. 2015c. Regulatory Impact Analysis for the Proposed Cross-State Air Pollution Rule
(CSAPR) Update for the 2008 Ozone National Ambient Air Quality Standards
(NAAQS).
U.S. EPA. 2015d. Regulatory Impact Analysis for the Proposed Federal Plan Requirements for
Greenhouse Gas Emissions from Electric Utility Generating Units Constructed on or
Before January 8, 2014; Model Trading Rules; Amendments to Framework Regulations.
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U.S. EPA. 2015e. Regulatory Impact Analysis of the Revisions to the National Ambient Air
Quality Standards for Ground-Level Ozone.
U.S. EPA. 2016a. Guidelines for Preparing Economic Analyses.
U.S. EPA. 2016b. Integrated Science Assessment for Oxides of Nitrogen: Final Report.
U.S. EPA. 2016c. Regulatory Impact Analysis of the Cross-State Air Pollution Rule (CSAPR)
Update for the 2008 National Ambient Air Quality Standards for Ground-Level Ozone.
U.S. EPA. 2017. Integrated Science Assessment for Sulfur Oxides: Final Report.
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(BenMAP-CE).
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(BenMAP). User Man.
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CHAPTER 5: ECONOMIC AND EMPLOYMENT IMPACTS
5.1 Economic Impacts
5.1.1 Market Impacts
The energy sector impacts presented in Chapter 3 of this RIA include potential changes in
the prices for electricity, natural gas, and coal resulting from this final rule. This chapter
addresses the impact of these potential changes on other markets and discusses some of the
determinants of the magnitude of these potential impacts. We refer to these changes as secondary
market impacts.
Under these final emission guidelines, coal-fired EGUs are not directly required to use
any of the measures that the EPA determines constitute BSER. Rather, CAA section 111(d)
allows each state in applying standards of performance based on the BSER candidate
technologies to take into account remaining useful life and other factors. Given the flexibility
afforded states in implementing the emission guidelines under 111(d) and the flexibilities coal-
fired EGUs have in complying with the subsequent, state-established emission standards, the
benefits, cost and economic impacts of the policy scenario reported in this RIA is necessarily
illustrative of actions that states and coal-fired EGUs may take. The implementation approaches
adopted by the states, and the strategies adopted by affected EGUs, will ultimately drive the
magnitude and timing of secondary impacts from changes in the price of electricity, and the
demand for inputs by the electricity sector, on other markets that use and produce these inputs.
To estimate the costs, benefits, and impacts of implementing the final guidelines, the
EPA modeled an illustrative policy scenario. Chapter 1 and Chapter 3 describe the illustrative
policy scenario. This chapter provides a quantitative assessment of the energy price impacts for
the illustrative policy scenario and a qualitative assessment of the factors that will in part
determine the timing and magnitude of potential effects in other markets. Table 5-1 summarizes
projected changes in energy prices and fuel use resulting from the illustrative policy scenario.
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Table 5-1 Summary of Certain Energy Market Impacts (Percent Change)
2025	2030	2035
Retail electricity prices
0.1%
0.1%
0.0%
Average price of coal delivered to the power sector
0.1%
0.0%
-0.1%
Coal production for power sector use
-1.1%
-1.0%
-1.0%
Price of natural gas delivered to power sector
0.0%
-0.1%
-0.6%
Price of average Henry Hub (spot)
0.0%
0.0%
-0.6%
Natural gas use for electricity generation
-0.4%
-0.3%
0.0%
Note: Positive values indicate increases relative to the baseline.
To provide some historical context to Table 5-1, we present below recent trends observed
over the last decade (2008 to 2018) for the energy market impacts listed:1
•	The annual percent change in electricity price over this period has been from -1.3 percent
to 2.0 percent, and averaged 0.8 percent.
•	The percent change to the annual price of coal for electricity generation has ranged from -
6 percent to 6.8 percent over the past decade, and averaged 0.1 percent.
•	The percent change to annual coal use for electricity plants has ranged from -17 percent
to 4.3 percent over the past decade, and averaged -5.9 percent.
•	The percent change to the average cost of natural gas for electricity generation has ranged
from -6 percent to 6.8 percent over the past decade, and averaged 0.1 percent.
•	The percent change to annual natural gas use for electricity plants has ranged from -10.5
percent to 17.2 percent over the past decade, and averaged 2.8 percent.
Overall, these projected changes are relatively small in the context of recent historical
changes.
The projected energy market and electricity retail rate impacts of this final rule are
discussed more extensively in Chapter 3, which also presents projections of power sector
generation and capacity changes by technology and fuel type. The change in wholesale energy
prices and the changes in power generation were forecasted using IPM. The change in retail
electricity prices reported in Chapter 3 is a national average across residential, commercial, and
1 Source: EIA Electricity Data Browser, all data is nominal dollars, available at
https://www.eia.gov/electricity/data/browser/. For natural gas use and coal production, receipts of both fuels for
electricity generators are used as a close proxy.
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industrial consumers. The change in electricity retail prices and bills were forecasted using
outputs of IPM.
Changes in supply or demand for electricity, natural gas, and coal can impact markets for
goods and services produced by sectors that use these energy inputs in the production process or
that supply those sectors. Changes in cost of production may result in changes in price and/or
quantity produced by these sectors and these market changes may affect the profitability of firms
and the economic welfare of their consumers and owners. Any potential changes in the operation
of the electric power sector due to the final action may also have an effect on upstream industries
that supply goods and services to the sector. For example, losses for owners and workers at firms
that supply new generation technologies and gains for firms that supply the parts and labor
necessary to improve heat rates at existing coal steam generators. The magnitude and direction of
these potential effects outside the electricity sector and related fuel markets are not analyzed in
this RIA.
One potential approach to evaluating whether there are important secondary market
impacts is to use an economy-wide model. Economy-wide models - and, more specifically,
computable general equilibrium (CGE) models - are analytical tools that can be used to evaluate
the impacts of a regulatory action beyond the directly-regulated sector. CGE models provide
aggregated representations of the entire economy in equilibrium in the baseline and under a
regulatory or policy scenario. CGE models are designed to capture substitution possibilities
between production, consumption and trade; interactions between economic sectors; and
interactions between a policy shock and pre-existing distortions, such as taxes. They can provide
information on changes outside of the directly-regulated sector attributable to a regulation. For
example, CGE studies of air pollution regulations for the power sector have found that the social
costs and benefits may be greater or lower than partial equilibrium estimates when these
secondary market impacts are taken into account, and that the direction of the estimates may
depend on the form of the regulation (e.g. Goulder et al. 1999, Williams 2002, Goulder et al.
2016).
In March 2015, the EPA established a Science Advisory Board (SAB) panel to consider
the technical merits and challenges of using economy-wide models to evaluate costs, benefits,
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and economic impacts in regulatory development. In September 2017, the SAB issued its final
report, which provided recommendations on how the EPA can use CGE models to offer a more
comprehensive assessment of the benefits, costs, and economic impacts of regulatory actions.2
The report noted that the case for using CGE models to evaluate a regulation's effects is
strongest when the costs of abatement are expected to be large in magnitude and the sector has
strong linkages to the rest of the economy, although the CGE models may also be useful to
evaluate impacts of smaller regulations in some situations. The report also noted that the extent
to which CGE models add value to the analysis depends on data availability, in that data
limitations are a significant obstacle to achieving the granularity needed to adequately represent
a regulation in the model to estimate its effects. In response to these and other SAB
recommendations, the EPA is in the process of building capacity to allow for the use of CGE
models in the analysis of future regulatory actions when warranted, developing guidance for
analysts on when CGE analysis is most likely to add value, and pursuing research priorities
highlighted by the SAB in its report.
5.1.2 Distributional Impacts
Any potential costs or benefits of this final action are not expected to be experienced
uniformly across the population, and may not accrue to the same individuals or communities.
OMB recommends including a description of distributional effects, as part of a regulatory
analysis, "so that decision makers can properly consider them along with the effects on economic
efficiency [i.e., net benefits]. Executive Order 12866 authorizes this approach." (U.S. Office of
Management and Budget 2003). Understanding the distribution of the compliance costs and
benefits can aid in understanding community-level impacts associated with this final action.3
This section discusses the general expectations regarding how compliance costs, and health
benefits might be distributed across the population, relying on a review of recent literature. For
2	Science Advisory Board, USEPA. 2017. SAB Advice on the Use of Economy-Wide Models in Evaluating the
Social Costs, Benefits, and Economic Impacts of Air Regulations.
https://yosemite.epa.gov/sab/SABPRODUCT.NSF/0/4B3BAF6C9EA6F503852581AA0057D565/$File/EPA-SAB-
17-012.pdf
3	Executive Order 12898, Federal Actions to Address Environmental Justice in Minority Populations and Low-
Income Populations, directs agencies to address impacts on minority and low-income populations, particularly those
that may be considered disproportionate. The EPA developed guidance, both in its Guidelines for Preparing
Economic Analyses (U.S. EPA 2010) and Technical Guidance for Assessing Environmental Justice in Regulatory
Analyses (U.S. EPA 2016) to provide recommendations for how to consider distributional impacts of rules on
vulnerable populations.
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example, Fullerton (2011) discussed six potential distributional impacts related to environmental
policy using a carbon permit system: impacts on consumers (e.g. higher energy prices); impacts
on producers or factors (e.g., lower returns to capital); scarcity rents (e.g. value of right to
pollute); benefits associated with pollution reduction; and transition costs (e.g., from changes in
employment or capital mix). The EPA did not conduct a quantitative assessment of these
distributional impacts for this final action, but the qualitative discussion in this section provides a
general overview of the types of impacts that could result from this action. We begin each sub-
section below with a general discussion of the incidence from the literature, followed by a brief
discussion of the distributional consequences we might expect from this final action.
5.1.2.1 Distributional Aspects of Compliance Costs
The compliance costs associated with a regulatory action can impact households by
raising the prices of goods and services; the extent of the price increase depends on if and how
producers pass-through those costs to consumers. Expenditures on energy are usually a larger
share of low-income household income than that of other households, and this share falls as
income increases. Therefore, policies that increase energy prices have been found to be
regressive, placing a greater burden on lower income households (e.g., Burtraw et al., 2009;
Hassett et al., 2009; Williams et al. 2015). However, compliance costs will not be solely passed
on in the form of higher energy prices, but also through lower labor earnings and returns to
capital in the sector. Changes in employment associated with lower labor earnings can have
distributional consequences depending on several factors (Section 5.2 discusses employment
effects further). Capital income tends to make up a greater proportion of overall income for high
income households. As result, the costs passed through to households via lower returns to capital
tend to be progressive, placing a greater share of the burden on higher income households in
these instances (Rausch et al., 2011; Fullerton et al., 2011). On net, capital owners in the power
sector may even see a higher return to capital as output is restricted or the economic position of
certain competitors is improved relative to their competitors (Maloney and McCormick, 1982;
Buchanan and Tullock, 1975) due to a regulation. In these circumstances the incidence through
capital may be regressive.
The ultimate distributional outcome will depend on how changes in electricity and other
fuel and input prices and lower returns to labor and capital propagate through the economy and
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interact with existing government transfer programs.4 Some studies using an economy-wide
framework find that the overall distribution of compliance costs is progressive due to the changes
in capital payments and the expectation that existing government transfer indexed to inflation
will offset the burden to lower income households (Fullerton et al., 2011; Blonz et al., 2012).5
However, others have found the distribution of compliance costs to be regressive due to a
dominating effect of changes in energy prices to consumers (Fullerton 2011; Burtraw, et. al.,
2009; Williams, et al., 2015). There may also be significant heterogeneity in the costs borne by
individuals within income deciles (Rausch et al., 2011; Cronin et al., 2019). Different
classifications of households, for example based on lifetime income rather than contemporaneous
annual income, may provide notably different results (Fullerton and Metcalf, 2002; Fullerton et
al., 2011).
Furthermore, there may be important regional differences in the incidence of regulations.
There are differences in the composition of goods consumed, regional production methods (e.g.,
the composition of the generation fleet), the stringency of a rule, as well as the location of
affected labor and capital ownership (the latter of which may be foreign-owned) (e.g. Caron et. al
2018; Hassett et al. 2009).
Given the complexity of the problem, estimating all of the distributional impacts of
compliance costs may require an economy-wide analysis (Rausch and Mowers, 2014), which as
discussed above can be challenging. While such an analysis was not conducted for this final
action, we can attempt to understand the distributional impacts of a policy by examining its
various components in their relevant partial equilibrium settings (Fullerton 2011). For example,
using partial-equilibrium modeling, studies that have focused on the incidence of electricity
sector regulations have generally found that consumers bear more of the compliance cost of a
regulation than producers because demand for electricity is relatively inelastic and, in cost-of-
service regions, increased production costs may be passed through electricity prices (e.g.
4	Some of these programs target low-income households. For example, the Low Income Home Energy Assistance
Program (LIHEAP): "assists eligible households with heating and cooling energy costs, bill payments,
weatherization and energy-related home repairs" and may mitigate increases in electricity prices on low-income
households as a result of this final rule. See: https://www.benefits.gov/benefit/623.
5	The incidence of government transfer payments (e.g., Social Security) is generally progressive because these
payments represent a significant source of income for lower income deciles and only a small source for high income
deciles. Government transfer programs are often, implicitly or explicitly, indexed to inflation. For example, Social
Security payments and veterans' benefits are adjusted every year to account for changes in prices (i.e., inflation).
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Burtraw and Palmer 2008). Even in these studies, the details of the form of the regulation
matters.
While the aforementioned components are important for understanding the ultimate
distribution of compliance costs in this context, it is not clear the degree to which the specific
results may be transferred to the current context. For example, much of the previous literature
has focused on the distributional impacts of first best policies, such as an economy-wide
emissions fee or permit trading program. Subsequent research focusing on second best policy
designs such as economy-wide clean or renewable energy standards or power sector only permit
trading programs have found the net distribution of costs to be relatively regressive even when
accounting for the impacts on consumers and factors of production, as well as the indexing of
transfer payments to inflation (Rausch and Mowers, 2014). This suggests that moving from a
more flexible to a less flexible regulatory design with EGU-specific requirements, will in and of
itself, affect the distribution of regulatory burden. Ultimately, the distribution of compliance
costs may be regressive or progressive, depending on the factors indicated above as well as other
implementation choices.
5.1.2.2 Distributional Aspects of the Health Benefits
Executive Order 12898, Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations, directs agencies to address impacts on minority
populations, low-income populations and indigenous peoples, particularly those that may be
considered disproportionate. A distributional, or Environmental Justice, analysis may
characterize the change in air pollution exposure and risk among minority populations, low-
income populations and indigenous peoples (see U.S. EPA 2015b, 2016). Often the baseline
incidence of health outcomes is greater among minority populations, low-income populations
and indigenous peoples due to a variety of factors, including a greater number of pollution
sources located where low-income and minority populations live, work and play (Bullard, et al.
2007; United Church of Christ 1987); greater susceptibility to a given exposure due to
physiology or other triggers (Akinbami et al. 2012); and pre-existing conditions (Schwartz et al.
2011). For these reasons, an EJ analysis can characterize the change in the estimated distribution
of risk occurring as a result of implementing the policy.
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This final action will affect the level and distribution of air pollutants in the atmosphere.
When evaluating policies prescribing specific emission control measures, we can more
confidently characterize the change in the distribution of pollutant concentrations and risk (US
EPA 2011). This analysis, by contrast, simulates the expected change in air quality from an
illustrative policy scenario (Figure 4-3). While this rule prescribes the development of CO2
emissions standards at coal-fired EGUs, for reasons discussed in Chapter 1 and elsewhere in this
RIA, the air emission changes at individual units from the final rule may differ than modeled in
the illustrative policy scenario, and therefore the level and location of changes in air pollutant
concentrations may differ as well. Furthermore, the illustrative policy scenario was not
constructed to consider possible local conditions that may influence eventual emission outcomes.
For these reasons and consistent with analysis presented elsewhere in this RIA (e.g. Section
3.7.8), we do not quantitatively assess the change in air pollution concentrations or risk among
minority populations, low-income populations and indigenous peoples from the illustrative
policy scenario as doing so would suggest greater certainty in the regional impacts of this final
rule than is warranted. Furthermore, we do not evaluate the effect of potential non-air
environmental impacts nor market effects such as changes in electricity prices on EJ
communities. As a result, we cannot conclude whether this rule will have disproportionate
impacts on EJ communities. However, in light of the results of the simulated air quality changes
depicted in Chapter 4, it is reasonable to infer that U.S. populations will, on balance, experience
a small but meaningful decrease in annual mean PM2.5 and summer season ozone concentrations
(Figure 4-3). Furthermore, as noted in Chapter 3, increases in emissions at individual units
indicated in the modeling scenario may in practice be mitigated by other economic and
regulatory factors.
5.1.3 Impacts on Small Entities
Emission guidelines established under CAA section 111(d) do not impose any
requirements on regulated entities and, thus, will not have direct impacts on these entities. After
emission guidelines are promulgated, states establish emission standards on existing sources, and
it is those requirements that could potentially impact small entities. As a result, this action will
not have a significant economic impact on a substantial number of small entities under the RFA.
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Our analysis here is consistent with the analysis of the analogous situation arising when
the EPA establishes NAAQS, which do not impose any requirements on regulated entities. As
here, any impact of a NAAQS on small entities would only arise when states take subsequent
action to maintain and/or achieve the NAAQS through their state implementation plans. See
American Trucking Assoc. v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not
have significant impacts upon small entities because NAAQS themselves impose no regulations
upon small entities).
5.2 Employment Impacts
Environmental regulation may affect groups of workers differently, as changes in
abatement and other compliance activities cause labor and other resources to shift. An
employment impact analysis describes the characteristics of groups of workers potentially
affected by a regulation, as well as labor market conditions in affected occupations, industries,
and geographic areas. Standard benefit-cost analyses have not typically included a separate
analysis of regulation-induced employment impacts.6 In this section we discuss the potential
employment impacts of the ACE rule.
Employment impacts of environmental regulations are composed of a mix of potential
declines and gains in different sectors of the economy over time. Impacts on employment can
vary according to labor market conditions and may differ across occupations, industries, and
regions. Isolating employment impacts of regulation is a challenge, as they are difficult to
disentangle from employment impacts caused by a wide variety of ongoing concurrent economic
changes.
Environmental regulation "typically affects the distribution of employment among
industries rather than the general employment level" (Arrow et. al. 1996). Even if they are
mitigated by long-run market adjustments to full employment, many regulatory actions have
transitional effects in the short run (U.S. Office of Management and Budget 2015). These
movements of workers in and out of jobs in response to environmental regulation are potentially
important distributional impacts of interest to policy makers. Of particular concern are
6 Labor expenses do, however, contribute toward total costs in EPA's standard benefit-cost analyses. See Section 3.6
of this RIA, for a discussion of labor expenses required for monitoring, reporting, and record keeping.
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transitional job losses experienced by workers operating in declining industries, exhibiting low
migration rates, or living in communities or regions where unemployment rates are high.
If the U.S. economy is at full employment, as current economic conditions indicate is
likely, even a large-scale environmental regulation is unlikely to have a noticeable impact on
aggregate net employment.7 Instead, labor in affected sectors would primarily be reallocated from
one productive use to another (e.g., from producing electricity or steel to producing high
efficiency equipment), and net national employment effects from environmental regulation
would be small and transitory (e.g., as workers move from one job to another). There may still be
employment effects, negative and positive, for groups of affected workers, even if the overall net
effect is small or zero. Some workers may retrain or relocate in anticipation of new requirements
or require time to search for new jobs, while shortages in some sectors or regions could bid up
wages to attract workers. These adjustment costs can lead to local labor disruptions. Although
the net change in the national workforce is expected to be small under conditions of full
employment, localized reductions in employment may adversely impact individuals and
communities just as localized increases may have positive impacts.
An environmental regulation affecting the power sector is expected to have a variety of
transitional employment impacts, including reduced employment at retiring coal-fired facilities,
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
(Schmalensee and Stavins, 2011). For the ACE rule, the EPA expects potential for changes in the
amount of labor needed in different parts of the utility power sector.8 These employment impacts,
both negative and positive, are likely to be small, particularly when considered in light of larger
power sector trends as discussed in Chapter 2.
Illustrative compliance cost projections for the electric power sector and for the fuel
production sector (coal and natural gas) are described in more detail in Chapter 3 of this RIA,
and may include effects attributable to heat rate improvements (HRIs), changes in construction
7	Full employment is a conceptual target for the economy where everyone who wants to work and is available to
do so at prevailing wages is actively employed. The unemployment rate at Ml employment is not zero.
8	The employment analysis in this RIA is part of EPA's ongoing effort to "conduct continuing evaluations of
potential loss or shifts of employment which may result from the administration or enforcement of [the Act]"
pursuant to CAA section 321(a).
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of new EGUs, generation shifts, and changes in fuel production and use. Considering first the
electric power sector, transitional employment impacts may occur in the short-run, where we
project a small increase in construction of new capacity, and during plant installation or
modification of equipment and buildings, and training of new processes. Over a longer time
frame, transitional employment impacts are replaced by ongoing operation and maintenance
labor requirements.
An important impact of these final rules is the implementation of measures that improve
heat rate at existing coal-fired generators which are associated with two main categories of
employment. In the short-run, there will be construction-related work; e.g., engineering, design,
and installation of boilermakers and associated materials and equipment. In the long-run, there
may be operation and maintenance employment to ensure the HRI is maintained in future years.
(Staudt 2014). Likewise, there are similar categories of employment for the other shifts caused
by the final rules such as shifts in the construction and operation of new EGUs, shifts in
generation, and for the fuel production sectors - coal and natural gas - employment impacts may
occur with changes in projected coal extraction and natural gas extraction.
Given the range of approaches to HRI that may be used to meet the requirements of the
final rules, and the flexibility for States to determine these requirements, it is challenging to
quantify the associated employment impacts. For this regulatory action, based on the illustrative
policy scenario modeled in IPM which are described in more detail in Chapter 3 of this RIA, the
EPA expects there may be potential for changes in the amount of labor needed in different parts
of the power sector.
The U.S. Department of Energy, in cooperation with BLS, gathered and published
detailed information on energy employment (U.S. DOE (2017a & 2017b)).9 Detailed information
on characteristics of workers, by job tasks, is available for the electricity sector and related
9 Main website: https://energy.gov/downloads/2017-us-energy-and-employment-report, with links to the 2017 report
(https://energy.gOv/sites/prodyfiles/2017/01/f34/2017%20US%20Energy%20and%20Jobs%20Report_0.pdf) and
associated state charts
(https://energy.gov/sites/prod/files/2017/01/f34/2017%20US%20Energy%20and%20Jobs%20Report%20State%20C
harts%202_0.pdf). U.S. DOE produced the U.S. Energy and Employment Report in 2016 and 2017, and did not
produce a report in 2018. In 2018, Energy Futures Initiative (EFI) with support from the National Association of
State Energy Officials (NASEO) drafted a report on employment in the energy sector, available here:
https://www.usenergyjobs.org/.
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sectors, and by state. To shed light on who will be affected by any potential employment changes
associated with the final rules, we review the characteristics of potentially affected workers.
For workers in coal-fired utilities, there are notable differences in the characteristics of
average groups of workers relative to national workforce averages. At coal-fired utilities, there
are more men than women in the workforce (63 percent versus 53 percent), and they are, on
average, younger (13 percent are 55 and over, versus 22 percent nationally) (U.S. DOE 2017a).
These characteristics for workers in natural gas electricity generation are similar, in that there are
more men than women in the workforce (60 percent versus 53 percent), and they are, on average,
younger (17 percent are 55 and over, versus 22 percent nationally) (U.S. DOE 2017a). For
hydroelectric and nuclear generation, there are more men in the workforce (66 percent for
traditional hydroelectric, 62 percent for nuclear), and they are as a group, younger (14 percent
are 55 and over, in traditional hydroelectric generation, and 12 percent in nuclear). Finally, for
renewables, there are more male than female workers in solar electric generation (67 percent),
also in wind (68 percent male), and in bioenergy for electricity generation (66 percent male).
These workforces are also, on average, younger: in solar generation 13 percent of workers are 55
and over, versus 22 percent nationally, in wind 14 percent are 55 and over, and for workers in
bioenergy for electric generation; 11 percent are 55 and over. Electric utilities and their
workforce are distributed widely across the country. This lessens concerns that they are
regionally concentrated in a high unemployment location.
The demographic differences of employees in coal mining and natural gas fuels, relative
to national workforce averages, are more notable than for electric utility workers. Men compose
most of the coal mining workforce (76 percent versus national average 53 percent), and they are,
on average, older, with 28 percent of the coal mining workforce age 55 and over, versus 22
percent nationally (U.S. DOE 2017a). Similarly, men compose most of the natural gas fuels
workforce (76 percent), and they are, on average, older, with 24 percent of the natural gas fuels
workforce age 55 and over (U.S. DOE 2017a). Coal mines are necessarily located on coal seams,
and natural gas fuels are extracted from basins; these are not distributed evenly throughout the
U.S. As such, coal and natural gas fuels workers may be more tied to local labor markets and
economies in terms of available employment opportunities. This raises a concern discussed
further below.
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The location of energy generation and fuel extraction activities is an important issue for
considering distributional effects. Department of Energy (2017a) observes: "But within this
overall story of [energy employment] growth is also an uneven trajectory where some states
experience new jobs and others grapple with decline. States such as California and Texas, which
have abundant solar, wind, and fossil fuel resources, have shown dramatic employment gains,
despite some losses linked to low fossil fuel prices. Coal-dependent states, such as West Virginia
and Wyoming, have seen declines in employment since 2015." (U.S. DOE, 2017a). In addition to
the main report, Department of Energy has published similarly detailed information on energy
employment, by state (DOE 2017a, 2017b).
The extent to which workers in declining industries will be significantly affected by the
final action, 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 these final rules; for example, if their skill set qualified
them for new jobs implementing HRIs.
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. Community-
wide 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
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an employee at the firm with the vacancy. This type of networking is weakened by high
unemployment rates (Durlauf 2004).
The distributional effects of workforce disruptions may extend beyond impacts on
employment. Sociological studies examine different effects than those that are typically
examined in economic studies. Workers experiencing unemployment may also experience
negative health impacts. The unemployed population is observed to be less healthy than those
who are employed, and the differences in health across these groups can be significant (see, for
example, Roelfs, et al. 2011) including different rates of substance abuse (Compton, et al. 2014).
The literature describes difficulties in identifying the cause of poorer health for the unemployed
population. Associations between unemployment and poorer health may be partially driven by
the possibility that workers in poorer health may be more likely to become unemployed.
Estimates of the magnitude of the association may be biased, in part, by factors not easily
observed or addressed by researchers that contribute both to unemployment risk as well as poorer
health (Jin 1995, Sullivan and von Wachtner 2009). Several recent papers have attempted to
identify a causal relationship between unemployment and health. These papers examined the
health effects of involuntary job loss by focusing on workers who have lost their jobs due to
layoffs or other firm-level employment reductions. For example, Sullivan and von Wachtner
(2009) found increased mortality rates among displaced workers in Pennsylvania; and in a study
of displaced Austrian workers, Kuhn, et al. (2007) found that job loss negatively affected men's
mental health.
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U.S. Department of Energy (U.S. DOE). 2017b. U.S. Energy and Employment Report - State
Charts. January. Available at: <
https://www.energy.gov/sites/prod/files/2017/0 l/f34/2017%20US%20Energy%20and%2
0Jobs%20Report%20State%20Charts%202_0.pdf >. Accessed 5/14/2018.
U.S. Office of Management and Budget. 2003. "Circular A-4, Regulatory Analysis". Available
at: . Accessed May 23,
2017.
U.S. Office of Management and Budget. 2015. 2015 Report to Congress on the Benefits and
Costs of Federal Regulations and Agency Compliance with the Unfunded Mandates
Reform Act. Available at:
. Accessed Sept. 15, 2017.
Williams, R. 2002. "Environmental Tax Interactions when Pollution Affects Health or
Productivity." Journal of Environmental Economics and Management, 44(2): 261-270.
Williams, R., Gordon, H., Burtraw, D., Carbone, J., and Morgenstern, R. 2015. "The Initial
Incidence of a Carbon Tax Across Income Groups." National Tax Journal, 68(1): 195-
214.
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CHAPTER 6: COMPARISON OF BENEFITS AND COSTS
6.1 Introduction
This chapter presents the estimates of the climate benefits, ancillary health co-benefits,
compliance costs and net benefits associated with the ACE rule, as represented by the illustrative
policy scenario, relative to the baseline. We evaluate the potential regulatory impacts of the
illustrative policy scenario using the present value (PV) of costs, benefits, and net benefits,
calculated for the years 2023-2037 from the perspective of 2016, using both a three percent and
seven percent end-of-period discount rate. All benefit analysis, and most cost analysis, begins in
the year 2025. The only cost analysis for a year prior to 2025 is that for monitoring, reporting,
and recordkeeping (MR&R), as MR&R costs are estimated to begin in 2023. In addition, the
Agency presents the assessment of costs, benefits, and net benefits for specific snapshot years,
consistent with historic practice. In this RIA, the regulatory impacts are evaluated for the specific
years of 2025, 2030, and 2035.
There are potential sources of benefits and costs that may result from this final rule that
have not been quantified or monetized. Due to current data and modeling limitations, our
estimates of the benefits from reducing CO2 emissions do not include important impacts like
ocean acidification or potential tipping points in natural or managed ecosystems. Unquantified
benefits also include climate benefits from reducing emissions of non-CCh greenhouse gases and
benefits from reducing exposure to SO2, NOx, and hazardous air pollutants (e.g., mercury), as
well as ecosystem effects and visibility impairment. The compliance costs reported in this RIA
are not social costs, although in this analysis we use compliance costs as a proxy for social costs.
We do not account for changes in costs and benefits due to changes in economic welfare of
suppliers to the electricity market, or to non-electricity consumers from those suppliers.
Furthermore, costs due to interactions with pre-existing market distortions outside the electricity
sector are omitted. Additional limitations of the analysis and sources of uncertainty are described
throughout the RIA and summarized in the Executive Summary.
6-1
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6.2 Methods
The EPA calculated the PV of costs, as well as the benefits and net benefits, for the years
2023 through 2037, using both a three percent and seven percent end-of-period discount rate
from the perspective of 2016. This calculation of a PV requires an annual stream of costs for
each year of the 2023-2037 timeframe. The EPA used IPM to estimate cost and emission
changes for the projection years 2025, 2030, and 2035. The Agency believes that these specific
years are each representative of several surrounding years, which enables the analysis of costs
and benefits over the timeframe of 2025-2037. The year 2025 is an approximation for when the
standards of performance under the final rule might be implemented, and the Agency estimates
that monitoring, reporting, and recordkeeping (MR&R) costs may begin in 2023. Therefore,
MR&R costs analysis is presented beginning in the year 2023, and full benefit cost analysis is
presented beginning in the year 2025. The analytical timeframe concludes in 2037, as this is the
last year that may be represented with the analysis conducted for the specific year of 2035.
Estimates of costs and emission changes in other years are determined from the mapping
of projection years to the calendar years that they represent. In the IPM modeling for this RIA,
the 2025 projection year represents 2025-2027, 2030 represents 2028-2032, and 2035 represents
2033-2037.1 Consequently, the cost and emission estimates from IPM in each projection year are
applied to the years which it represents.2 Climate benefits estimates are based on these projection
year emission estimates, and also account for year-specific interim domestic SC-CO2 values.3
Ancillary health co-benefits are based on projection year emission estimates, and also account
for year-specific variables that influence the size and distribution of the benefits; these include
population growth, income growth, and the baseline rate of death.4 The EPA has estimated
MR&R costs for 2023, and applies these costs only to 2023 in the PV analysis. MR&R costs for
1	For more information regarding the mapping of projection years to calendar years, see Documentation for EPA's
Power Sector Modeling Platform v6 Using the Integrated Planning Model (2018), available at:
https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling
2	MR&R costs estimates are not based on IPM. For information on MR&R costs, see Chapter 3.
3	As the interim domestic SC-CO2 value varies by year, the climate benefit estimates vary by year, even when
different years are based on the same IPM projection year emission estimate.
4	As these variables differ by year, the ancillary health co-benefit estimates vary by year, even when different years
are based on the same IPM projection year emission estimate.
6-2
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2025 are applied to 2024, and all subsequent MR&R costs are applied to the 2025-2037
timeframe in the same fashion as other cost estimates.
The EPA calculated the PV and equivalent annualized value (EAV) of costs, benefits,
and net benefits over the 2023-2037 timeframe for the illustrative policy scenario under different
methodologies for calculating benefits. The EAV represents a flow of constant annual values
that, had they occurred in each year from 2023 to 2037, would yield an equivalent present value.
The EAV represents the value of a typical cost or benefit for each year of the analysis, in contrast
to the year-specific estimates presented elsewhere for the snapshot years of 2025, 2030, and
2035.
6.3 Results
6.3.1 Analysis of2023-2037for E. O. 13771, Reducing Regulation and Controlling
Regulatory Costs
This final action is considered a regulatory action under E.O. 13771, Reducing
Regulation and Controlling Regulatory Costs.
Table 6-1 presents the undiscounted compliance costs for the illustrative policy scenario,
representing the ACE rule, relative to the baseline. As noted earlier, the avoided compliance cost
estimates from each IPM model year are applied to the appropriate surrounding years.
6-3
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Table 6-1 Compliance Costs for the Illustrative Policy Scenario, 2023-2037 (millions of
2016$)a
Year
Compliance Costb
2023
28
2024
15
2025
290
2026
290
2027
290
2028
280
2029
280
2030
280
2031
280
2032
280
2033
25
2034
25
2035
25
2036
25
2037
25
a All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
b Compliance costs included compliance costs and MR&R costs.
The EPA calculated the PV of costs using both a three percent and seven percent discount
rate. The EPA used an end-of-period discount rate for E.O. 13771 analysis. The estimates for the
illustrative policy scenario are presented in Table 6-2 and are from the perspective of 2016. For
purposes of E.O. 13771 accounting, the PV and EAV estimates assume an infinite timeframe
(i.e., over go). This is different than elsewhere in this RIA, where PV and EAV estimates are for
the timeframe of 2023 to 2037.
Under the illustrative policy scenario, the PV of the stream of costs is $4.5 billion when
discounted at 3 percent, and $1.5 billion when discounted at 7 percent. These compliance cost
estimates represent the regulatory costs related to the regulatory allowance under E.O. 13771.
Table 6-2 also presents the EAV.
6-4
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Table 6-2 Present Value and Equivalent Annualized Value of Compliance Costs for the
Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
	(millions of 2016$)	

3%
7%
Present Value (over 
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Table 6-3 Present Value and Equivalent Annualized Value of Compliance Costs,
Domestic Climate Benefits, Ancillary Health Co-Benefits, and Net Benefits,
Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
	(millions of 2016$)	
Domestic	Ancillary
Costs Climate	Health	Net Benefits
Benefits	Co-Benefits
3%
7%
3%
7%
3%
7%
3%
7%
2023
2024
2025
22
12
220
17
8.4
150
60
6.7
290 to 720
180 to 460
(22)
(12)
130 to 560
(17)
(8.4)
43 to 320
2026
210
140
59
6.5
290 to 710
170 to 440
140 to 560
44 to 310
2027
200
130
59
6.2
280 to 710
170 to 420
140 to 560
45 to 300
2028
190
110
53
5.5
320 to 790
180 to 450
190 to 650
72 to 340
2029
180
110
52
5.3
320 to 780
170 to 430
190 to 650
72 to 320
2030
180
100
52
5.1
320 to 780
170 to 410
190 to 650
71 to 310
2031
170
93
51
4.9
310 to 770
160 to 390
190 to 650
69 to 300
2032
170
87
50
4.8
310 to 770
150 to 370
200 to 650
69 to 290
2033
15
7.4
41
3.8
310 to 760
140 to 360
330 to 780
140 to 350
2034
14
6.9
40
3.6
310 to 750
140 to 340
330 to 780
130 to 340
2035
14
6.4
40
3.5
300 to 750
130 to 330
330 to 770
130 to 320
2036
13
6.0
39
3.4
300 to 740
130 to 310
330 to 770
120 to 310
2037
13
5.6
39
3.2
300 to 730
120 to 300
320 to 760
120 to 290
Present
Value
1,600
970
640
62
4,000 to 9,800
2,000 to 5,000
3,000 to 8,800
1,100 to 4,100
Equivalent
Annualized
Value
140
110
53
6.9
330 to 820
220 to 550
250 to 730
120 to 450
Notes: All estimates are rounded to two significant figures, so figures may not sum due to independent rounding.
Climate benefits reflect the value of domestic impacts from CO2 emissions changes.
6.3.2.1 Targeted Pollutant
In the decision-making process it is useful to consider the change in benefits due to the
targeted pollutant relative to the costs.5 In Table 6-4 we offer one perspective on the costs and
5 Regulating pollutants jointly can promote a more efficient outcome in pollution control management (Tietenberg,
1973). However, in practice regulations are promulgated sequentially and therefore, the benefit-cost analyses
supporting those regulations are also performed sequentially. The potential for interaction between regulations
suggests that their sequencing may affect the realized efficiency of their design and the estimated net benefits for
each regulation. For this rulemaking, the EPA did not consider alternative regulatory approaches to jointly control
CO2, direct PM2 5, SO2, and NOx emission from existing power plants. This leaves open the possibility that an
option which jointly regulates CO2, direct PM2 5, SO2, and NOx emissions from power plants could have achieved
these reductions more efficiently than through a single regulation targeting CO2 emissions, conditional on statutory
authority to promulgate such a regulation.
6-6
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benefits of this rule by presenting a comparison of the benefit impact associated with the targeted
pollutant - CO2 - with the compliance cost impact.6 It is important to recognize that the
estimated domestic climate benefits presented for this rule are based on evolving methodologies
and depend in important respects on assumptions that are uncertain and subject to further
revision with improvements in the science and modeling of climate change impacts. These
uncertainties are discussed in greater detail in Chapter 4.3 and Chapter 7 of this RIA. Chapter 7
explains the methodology, modeling, and assumptions that inform the social cost of carbon
estimates used here, identifies key uncertainties, and presents a sensitivity analysis exploring
how the monetized climate benefits of the final rule would change under different assumptions.
Under certain assumptions, as presented in that analysis, the climate benefits of this action
exceed its compliance costs. Nonetheless, the EPA is not relying on social cost of carbon
estimates to support this action and presents these data solely for informational purposes in
compliance with E.O. 12866.7 Excluded from this comparison are the benefit impacts from direct
PM2.5, SO2 and NOx emission changes that are projected to accompany the CO2 changes.8 Table
6-4 presents a summary of the PV and EAV of costs, domestic climate benefits, and net benefits
associated with the targeted pollutant (i.e., CO2).
6	While the benefits are limited to the targeted pollutant, the cost as discussed above is the change in generation cost
for the entire power sector plus MR&R costs. The costs reported in Table 6-4 are not limited solely to those costs
that occur at the sources regulated by this final rule.
7	See Portland Cement Ass 'n v. Train, 513 F.2d 506, 508 (D.C. Cir. 1975) (benefit-cost analysis not required under
CAA section 111(a)(1).
8	When considering whether a regulatory action is a potential welfare improvement (i.e., potential Pareto
improvement) it is necessary to consider all impacts of the action.
6-7
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Table 6-4 Present Value and Equivalent Annualized Value of Compliance Costs,
Benefits, and Net Benefits Associated with Targeted Pollutant (CO2),
Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
	(millions of 2016$)	
Costs
Domestic
Climate Benefits
Net Benefits
associated with the
3%
7%
3%
7%
3%
7%
2023
22
17
-
-
(22)
(17)
2024
12
8.4
-
-
(12)
(8.4)
2025
220
150
60
6.7
(160)
(140)
2026
210
140
59
6.5
(150)
(130)
2027
200
130
59
6.2
(140)
(120)
2028
190
110
53
5.5
(130)
(110)
2029
180
110
52
5.3
(130)
(100)
2030
180
100
52
5.1
(130)
(95)
2031
170
93
51
4.9
(120)
(88)
2032
170
87
50
4.8
(120)
(83)
2033
15
7.4
41
3.8
26
(3.6)
2034
14
6.9
40
3.6
26
(3.3)
2035
14
6.4
40
3.5
26
(3.0)
2036
13
6.0
39
3.4
26
(2.7)
2037
13
5.6
39
3.2
26
(2.4)
Present
Value
1,600
970
640
62
(980)
(910)
Equivalent
Annualized
Value
140
110
53
6.9
(82)
(100)
figures may not sum due to independent rounding.
6.3.2.2 Net Benefits Including Air Pollutant Co-Benefits
When considering whether a regulatory action is a potential welfare improvement (i.e.,
potential Pareto improvement) it is necessary to consider all impacts of the action. Therefore,
tables in this section provide the estimates of the benefits, costs, and net benefits of the
illustrative policy scenario, inclusive of the benefit impacts from the direct PM2.5, SO2 and NOx
emission changes that are projected to accompany the CO2 changes. In these tables, the estimates
for the ancillary health co-benefits are derived using PM2.5 log-linear concentration-response
functions that quantify risk associated with the full range of PM2.5 exposures experienced by the
population.
6-8
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Table 6-5 contains PV and EAV estimates of compliance costs, benefits, and net benefits
inclusive of ancillary health co-benefits for the illustrative policy scenario.
Table 6-5 Present Value and Equivalent Annualized Value of Compliance Costs,
Benefits (Inclusive of Health Co-Benefits), and Net Benefits, Illustrative
Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037 (millions of
	2016$)	
Costs	Benefits	Net Benefits
3%
7%
3%
7%
3%
7%
2023
22
17
0 to 0
0 to 0
(22)
(17)
2024
12
8.4
0 to 0
0 to 0
(12)
(8.4)
2025
220
150
350 to 780
190 to 470
130 to 560
43 to 320
2026
210
140
350 to 770
180 to 450
140 to 560
44 to 310
2027
200
130
340 to 770
170 to 430
140 to 560
45 to 300
2028
190
110
370 to 840
190 to 450
190 to 650
72 to 340
2029
180
110
370 to 830
180 to 430
190 to 650
72 to 320
2030
180
100
370 to 830
170 to 410
190 to 650
71 to 310
2031
170
93
360 to 820
160 to 390
190 to 650
69 to 300
2032
170
87
360 to 820
160 to 380
200 to 650
69 to 290
2033
15
7.4
350 to 800
150 to 360
330 to 780
140 to 350
2034
14
6.9
350 to 790
140 to 340
330 to 780
130 to 340
2035
14
6.4
340 to 790
130 to 330
330 to 770
130 to 320
2036
13
6.0
340 to 780
130 to 310
330 to 770
120 to 310
2037
13
5.6
340 to 770
120 to 300
320 to 760
120 to 290
Present Value
1,600
970
4,600 to 10,000
2,100 to 5,000
3,000 to 8,800
1,100 to 4,100
Equivalent
Annualized Value
140
110
390 to 870
230 to 550
250 to 730
120 to 450
Note: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, so
figures may not sum due to independent rounding.
6.3.2.3 Net Benefits Including Air Pollution Co-Benefits Calculated
According to Sensitivity Analysis Assumptions
Table 6-6 and Table 6-7 report the estimated benefits, costs, and net benefits of the
illustrative policy scenario according to different sensitivity analysis assumptions. These results
reflect different assumptions regarding the relationship between PM2.5 exposure and the risk of
premature death, as detailed in Chapter 4. In Table 6-5, we report the net benefits calculated
using the sum of the estimated ozone and PM2.5-related benefits using a no-threshold
concentration-response parameter for PM2.5. In Table 6-6, we report the net benefits calculated
using the sum of the estimated ozone and PIVh.s-related benefits assuming that the PM2.5-
6-9
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attributable risks fall to zero below the lowest measured levels of the two long-term PM2.5
mortality studies used to quantify risk. In Table 6-7, we report the net benefits calculated using
the sum of the estimated ozone and PIVh.s-related benefits assuming that PM2.5 related benefits
fall to zero below the PM2.5 National Ambient Air Quality Standard (NAAQS). These are PV
and EAV estimates, similar to the presentation of results in Table 6-5.
The EPA has generally expressed a greater confidence in the effects observed around the
mean PM2.5 concentrations in the long-term epidemiological studies; this does not necessarily
imply a concentration threshold below which there are no effects. As such, these analyses are
designed to increase transparency rather than imply a specific lower bound on the size of the
ancillary health co-benefits. As noted at the beginning of this Chapter, there are additional
important benefit impacts that the EPA could not monetize.
6-10
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Table 6-6 Present Value and Equivalent Annualized Value of Compliance Costs,
Benefits, and Net Benefits assuming that Mortality Risk PM2.5 Related
Benefits Fall to Zero Below the Lowest Measured Level of Each Long-Term
PM2.5 Mortality Study, Illustrative Policy Scenario, 3 and 7 Percent Discount
	Rates, 2023-2037 (millions of 2016$)	
Benefits Excluding Benefits Net Benefits Excluding Benefits
below LML	below LML
3%
7%
3%
7%
3%
7%
2023
22
17
-
-
(22)
(17)
2024
12
8.4
-
-
(12)
(8.4)
2025
220
150
340 to 420
180 to 240
120 to 200
36 to 93
2026
210
140
340 to 410
180 to 230
130 to 200
38 to 92
2027
200
130
330 to 410
170 to 220
130 to 210
39 to 91
2028
190
110
340 to 390
170 to 200
150 to 200
54 to 89
2029
180
110
340 to 390
160 to 190
160 to 210
54 to 87
2030
180
100
330 to 390
150 to 190
160 to 210
53 to 86
2031
170
93
330 to 380
150 to 180
160 to 210
53 to 84
2032
170
87
330 to 380
140 to 170
160 to 210
54 to 83
2033
15
7.4
310 to 390
130 to 170
300 to 370
120 to 160
2034
14
6.9
310 to 380
130 to 160
300 to 370
120 to 160
2035
14
6.4
310 to 380
120 to 160
290 to 370
110 to 150
2036
13
6.0
310 to 380
110 to 150
290 to 360
110 to 140
2037
13
5.6
300 to 370
110 to 140
290 to 360
100 to 130
Present Value
1,600
970
4,200 to 5,100
1,900 to 2,400
2,600 to 3,500
920 to 1,400
Equivalent
Annualized Value
140
110
350 to 420
210 to 260
220 to 290
100 to 160
Note: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, so
figures may not sum due to independent rounding.
6-11
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Table 6-7 Present Value and Equivalent Annualized Value of Compliance Costs,
Benefits, and Net Benefits assuming that Mortality Risk PM2.5 Related
Benefits Fall to Zero Below the PM2.5 National Ambient Air Quality
Standard, Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-
	2037 (millions of 2016$)	
Benefits Excluding Benefits Net Benefits Excluding Benefits
below PM2.5 NAAQS	below PM2.5 NAAQS
3%
7%
3%
7%
3%
7%
2023
22
17
-
-
(22)
(17)
2024
12
8.4
-
-
(12)
(8.4)
2025
220
150
120 to 250
45 to 140
(99) to 33
(100) to (12)
2026
210
140
120 to 250
43 to 130
(94) to 41
(95) to (5.8)
2027
200
130
110 to 250
41 to 130
(89) to 46
(88) to (2.2)
2028
190
110
100 to 220
35 to 110
(86) to 34
(79) to (6.2)
2029
180
110
100 to 220
34 to 100
(82) to 38
(73) to (3.3)
2030
180
100
100 to 220
32 to 99
(77) to 42
(68) to (0.44)
2031
170
93
98 to 220
31 to 95
(73) to 45
(63) to 1.2
2032
170
87
98 to 220
29 to 91
(69) to 49
(58) to 3.6
2033
15
7.4
92 to 220
29 to 93
77 to 200
22 to 85
2034
14
6.9
91 to 220
28 to 89
76 to 200
21 to 82
2035
14
6.4
90 to 210
27 to 85
76 to 200
20 to 79
2036
13
6.0
89 to 210
25 to 81
75 to 200
19 to 75
2037
13
5.6
87 to 210
24 to 77
74 to 200
19 to 71
Present Value
1,600
970
1,300 to 2,900
420 to 1,300
(330) to 1,300
(550) to 340
Equivalent
Annualized Value
140
110
110 to 240
47 to 140
(27) to 110
(60) to 38
Note: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, so
figures may not sum due to independent rounding.
6-12
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6.4 References
Tieteneberg, T. 1973. "Specific Taxes and the Control of Pollution: A General Equilibrium
Analysis." The Quarterly Journal of Economics, 86:503-522.
6-13
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CHAPTER 7: APPENDIX - UNCERTAINTY ASSOCIATED WITH ESTIMATING THE
SOCIAL COST OF CARBON
7.1 Overview of Methodology Used to Develop Interim Domestic SC-CO2 Estimates
The domestic SC-CO2 estimates rely on the same ensemble of three integrated
assessment models (IAMs) that were used to develop the IWG global SC-CO2 estimates (DICE
2010, FUND 3.8, and PAGE 2009).1 The three IAMs translate emissions into changes in
atmospheric greenhouse concentrations, atmospheric concentrations into changes in temperature,
and changes in temperature into economic damages. The emissions projections used in the
models are based on specified socio-economic (GDP and population) pathways. These emissions
are translated into atmospheric concentrations, and concentrations are translated into warming
based on each model's simplified representation of the climate and a key parameter, equilibrium
climate sensitivity. The effect of the changes is estimated in terms of consumption-equivalent
economic damages. As in the IWG exercise, three key inputs were harmonized across the three
models: a probability distribution for equilibrium climate sensitivity; five scenarios for
economic, population, and emissions growth; and discount rates.2 All other model features were
left unchanged. Future damages are discounted using constant discount rates of both 3 and 7
percent, as recommended by OMB Circular A-4. The domestic share of the global SC-CO2 - i.e.,
an approximation of the climate change impacts that occur within U.S. borders - are calculated
directly in both FUND and PAGE. However, DICE 2010 generates only global SC-CO2
estimates. Therefore, the EPA approximated U.S. damages as 10 percent of the global values
from the DICE model runs, based on the results from a regionalized version of the model (RICE
2010) reported in Table 2 of Nordhaus (2017).3
The steps involved in estimating the social cost of CO2 are as follows. The three
integrated assessment models (FUND, DICE, and PAGE) are run using the harmonized
1	The Ml models' names are as follows: Dynamic Integrated Climate and Economy (DICE); Climate Framework for
Uncertainty, Negotiation, and Distribution (FUND); and Policy Analysis of the Greenhouse Gas Effect (PAGE).
2	See the IWG's summary of its methodology in the 2015 Clean Power Plan docket, document ID number EPA-HQ-
OAR-2013-0602-37033, "Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866, Interagency Working Group on Social Cost of Carbon (May 2013, Revised July 2015)". See
also National Academies (2017) for a detailed discussion of each of these modeling assumptions.
3	Nordhaus, William D. 2017. Revisiting the social cost of carbon. Proceedings of the National Academy of
Sciences of the United States, 114(7): 1518-1523.
7-1
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equilibrium climate sensitivity distribution, five socioeconomic and emissions scenarios,
constant discount rates described above. Because the climate sensitivity parameter is modeled
probabilistically, and because PAGE and FUND incorporate uncertainty in other model
parameters, the final output from each model run is a distribution over the SC-CO2 in year t
based on a Monte Carlo simulation of 10,000 runs. For each of the IAMs, the basic
computational steps for calculating the social cost estimate in a particular year t is 1.) calculate
the temperature effects and (consumption-equivalent) damages in each year resulting from the
baseline path of emissions; 2.) adjust the model to reflect an additional unit of emissions in year
t; 3.) recalculate the temperature effects and damages expected in all years beyond t resulting
from this adjusted path of emissions, as in step 1; and 4.) subtract the damages computed in step
1 from those in step 3 in each model period and discount the resulting path of marginal damages
back to the year of emissions. In PAGE and FUND step 4 focuses on the damages attributed to
the US region in the models. As noted above, DICE does not explicitly include a separate US
region in the model and therefore, the EPA approximates U.S. damages in step 4 as 10 percent of
the global values based on the results of Nordhaus (2017). This exercise produces 30 separate
distributions of the SC-CO2 for a given year, the product of 3 models, 2 discount rates, and 5
socioeconomic scenarios. Following the approach used by the IWG, the estimates are equally
weighted across models and socioeconomic scenarios in order to reduce the dimensionality of
the results down to two separate distributions, one for each discount rate.
7.2 Treatment of Uncertainty in Interim Domestic SC-CO2 Estimates
There are various sources of uncertainty in the SC-CO2 estimates used in this RIA. Some
uncertainties pertain to aspects of the natural world, such as quantifying the physical effects of
greenhouse gas emissions on Earth systems. Other sources of uncertainty are associated with
current and future human behavior and well-being, such as population and economic growth,
GHG emissions, the translation of Earth system changes to economic damages, and the role of
adaptation. It is important to note that even in the presence of uncertainty, scientific and
economic analysis can provide valuable information to the public and decision makers, though
the uncertainty should be acknowledged and when possible taken into account in the analysis
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(National Academies 2013).4 OMB Circular A-4 also requires a thorough discussion of key
sources of uncertainty in the calculation of benefits and costs, including more rigorous
quantitative approaches for higher consequence rules. This section summarizes the sources of
uncertainty considered in a quantitative manner in the domestic SC-CO2 estimates.
The domestic SC-CO2 estimates consider various sources of uncertainty through a
combination of a multi-model ensemble, probabilistic analysis, and scenario analysis. We
provide a summary of this analysis here; more detailed discussion of each model and the
harmonized input assumptions can be found in the 2017 National Academies report. For
example, the three IAMs used collectively span a wide range of Earth system and economic
outcomes to help reflect the uncertainty in the literature and in the underlying dynamics being
modeled. The use of an ensemble of three different models at least partially addresses the fact
that no single model includes all of the quantified economic damages. It also helps to reflect
structural uncertainty across the models, which is uncertainty in the underlying relationships
between GHG emissions, Earth systems, and economic damages that are included in the models.
Bearing in mind the different limitations of each model and lacking an objective basis upon
which to differentially weight the models, the three integrated assessment models are given equal
weight in the analysis.
Monte Carlo techniques were used to run the IAMs a large number of times. In each
simulation the uncertain parameters are represented by random draws from their defined
probability distributions. In all three models the equilibrium climate sensitivity is treated
probabilistically based on the probability distribution from Roe and Baker (2007) calibrated to
the IPCC AR4 consensus statement about this key parameter.5 The equilibrium climate
sensitivity is a key parameter in this analysis because it helps define the strength of the climate
response to increasing GHG concentrations in the atmosphere. In addition, the FUND and PAGE
models define many of their parameters with probability distributions instead of point estimates.
For these two models, the model developers' default probability distributions are maintained for
all parameters other than those superseded by the harmonized inputs (i.e., equilibrium climate
4	Institute of Medicine of the National Academies. 2013. Environmental Decisions in the Face of Uncertainty. The
National Academies Press.
5	Specifically, the Roe and Baker distribution for the climate sensitivity parameter was bounded between 0 and 10
with a median of 3 °C and a cumulative probability between 2 and 4.5 °C of two-thirds.
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sensitivity, socioeconomic and emissions scenarios, and discount rates). More information on the
uncertain parameters in PAGE and FUND is available upon request.
For the socioeconomic and emissions scenarios, uncertainty is included in the analysis by
considering a range of scenarios selected from the Stanford Energy Modeling Forum exercise,
EMF-22. Given the dearth of information on the likelihood of a full range of future
socioeconomic pathways at the time the original modeling was conducted, and without a basis
for assigning differential weights to scenarios, the range of uncertainty was reflected by simply
weighting each of the five scenarios equally for the consolidated estimates. To better understand
how the results vary across scenarios, results of each model run are available in the docket.
The outcome of accounting for various sources of uncertainty using the approaches
described above is a frequency distribution of the SC-CO2 estimates for emissions occurring in a
given year for each discount rate. Unlike the approach taken for consolidating results across
models and socioeconomic and emissions scenarios, the SC-CO2 estimates are not pooled across
different discount rates because the range of discount rates reflects both uncertainty and, at least
in part, different policy or value judgements; uncertainty regarding this key assumption is
discussed in more detail below. The frequency distributions reflect the uncertainty around the
input parameters for which probability distributions were defined, as well as from the multi-
model ensemble and socioeconomic and emissions scenarios where probabilities were implied
by the equal weighting assumption. It is important to note that the set of SC-CO2 estimates
obtained from this analysis does not yield a probability distribution that fully characterizes
uncertainty about the SC-CO2 due to impact categories omitted from the models and sources of
uncertainty that have not been fully characterized due to data limitations.
Figure 7-1 presents the frequency distribution of the domestic SC-CO2 estimates for
emissions in 2030 for each discount rate. Each distribution represents 150,000 estimates based
on 10,000 simulations for each combination of the three models and five socioeconomic and
emissions scenarios. In general, the distributions are skewed to the right and have long right tails,
which tend to be longer for lower discount rates. To highlight the difference between the impact
of the discount rate on the SC-CO2 and other quantified sources of uncertainty, the bars below
the frequency distributions provide a symmetric representation of quantified variability in the
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SC-CO2 estimates conditioned on each discount rate. The full set of SC-CO2 results through
2050 is available in the docket.
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Interim U.S. Domestic Social Cost of Carbon in 2030 [2016$ / metric ton C02]
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Figure 7-1 Frequency Distribution of Interim Domestic SC-C02 Estimates for 2030 (in
2016$ per metric ton CO2)
As illustrated by the frequency distributions in Figure 7-1, the assumed discount rate
plays a critical role in the ultimate estimate of the social cost of carbon. This is because CO2
emissions today continue to impact society far out into the future, so with a higher discount rate,
costs that accrue to future generations are weighted less, resulting in a lower estimate. Circular
A-4 recommends that costs and benefits be discounted using the rates of 3 percent and 7 percent
to reflect the opportunity cost of consumption and capital, respectively. Circular A-4 also
recommends quantitative sensitivity analysis of key assumptions6, and offers guidance on what
sensitivity analysis can be conducted in cases where a rule will have important intergenerational
benefits or costs. To account for ethical considerations of future generations and potential
uncertainty in the discount rate over long time horizons, Circular A-4 suggests "further
6 "If benefit or cost estimates depend heavily on certain assumptions, you should make those assumptions explicit
and carry out sensitivity analyses using plausible alternative assumptions." (OMB 2003, page 42).
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sensitivity analysis using a lower but positive discount rate in addition to calculating net benefit
using discount rates of 3 and 7 percent" (page 36) and notes that research from the 1990s
suggests intergenerational rates "from 1 to 3 percent per annum" (OMB 2003). We consider the
uncertainty in this key assumption by calculating the domestic SC-CO2 based on a 2.5 percent
discount rate, in addition to the 3 and 7 percent used in the main analysis. Using a 2.5 percent
discount rate, the average domestic SC-CO2 estimate across all the model runs for emissions
occurring over 2025-2035 ranges from $10 to $12 per metric ton of CO2 (2016$). In this case the
domestic climate benefits in 2025 are $120 million under the illustrative policy scenario; by
2035, the estimated benefits decrease to $100 million under the illustrative policy scenario.
In addition to the approach to accounting for the quantifiable uncertainty described
above, the scientific and economics literature has further explored known sources of uncertainty
related to estimates of the SC-CO2. For example, researchers have published papers that explore
the sensitivity of IAMs and the resulting SC-CO2 estimates to different assumptions embedded in
the models (see, e.g., Hope (2013), Anthoff and Tol (2013), andNordhaus (2014)). However,
there remain additional sources of uncertainty that have not been fully characterized and
explored due to remaining data limitations. Additional research is needed in order to expand the
quantification of various sources of uncertainty in estimates of the SC-CO2 (e.g., developing
explicit probability distributions for more inputs pertaining to climate impacts and their
valuation). On the issue of intergenerational discounting, some experts have argued that a
declining discount rate would be appropriate to analyze impacts that occur far into the future
(Arrow et al., 2013). However, additional research and analysis is still needed to develop a
methodology for implementing a declining discount rate and to understand the implications of
applying these theoretical lessons in practice. The 2017 National Academies report also provides
recommendations pertaining to discounting, emphasizing the need to more explicitly model the
uncertainty surrounding discount rates over long time horizons, its connection to uncertainty in
economic growth, and, in turn, to climate damages using a Ramsey-like formula (National
Academies 2017). These and other research needs are discussed in detail in the 2017 National
Academies' recommendations for a comprehensive update to the current methodology, including
a more robust incorporation of uncertainty.
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7.3 Global Climate Benefits
In addition to requiring reporting of impacts at a domestic level, OMB Circular A-4
states that when an agency "evaluate[s] a regulation that is likely to have effects beyond the
borders of the United States, these effects should be reported separately" (page 15).7 This
guidance is relevant to the valuation of damages from CO2 and other GHGs, given that GHGs
contribute to damages around the world independent of the country in which they are emitted.
Therefore, in this section we present the global climate benefits in 2030 from this proposed
rulemaking using the global SC-CO2 estimates corresponding to the model runs that generated
the domestic SC-CO2 estimates used in the main analysis. The average global SC-CO2 estimate
across all the model runs for emissions occurring over 2025-2035 range from $6 to $9 per metric
ton of CO2 emissions (in 2016 dollars) using a 7 percent discount rate, and $53 to $63 per metric
ton of CO2 emissions (2016$) using a 3 percent discount rate. The domestic SC-CO2 estimates
presented above are approximately 19 percent and 14 percent of these global SC-CO2 estimates
for the 7 percent and 3 percent discount rates, respectively.
Applying these estimates to the CO2 emission reductions results in estimated global
climate benefits in 2025 of $70 million (2016$) under the illustrative policy scenario, using a 7
percent discount rate; this increases to $590 million (2016$) under the illustrative policy
scenario, using a 3 percent discount rate. By 2035, the global climate benefits are estimated at
$77 million (2016$) under the illustrative policy scenario, using a 7 percent discount rate. Using
a 3 percent discount rate, this increases to $530 million under the illustrative policy scenario.
Under the sensitivity analysis considered above using a 2.5 percent discount rate, the
average global SC-CO2 estimate across all the model runs for emissions occurring over 2025-
2035 ranges from $77 to $90 per metric ton of CO2 (2016$); in this case the global climate
7 While Circular A-4 does not elaborate on this guidance, the basic argument for adopting a domestic only
perspective for the central benefit-cost analysis of domestic policies is based on the fact that the authority to regulate
only extends to a nation's own residents who have consented to adhere to the same set of rules and values for
collective decision-making, as well as the assumption that most domestic policies will have negligible effects on the
welfare of other countries' residents (EPA 2010; Kopp et al. 1997; Whittington et al. 1986). In the context of
policies that are expected to result in substantial effects outside of U.S. borders, an active literature has emerged
discussing how to appropriately treat these impacts for purposes of domestic policymaking (e.g., Gayer and Viscusi
2016, 2017; Anthoff and Tol, 2010; Fraas et al. 2016; Revesz et al. 2017). This discourse has been primarily focused
on the regulation of greenhouse gases (GHGs), for which domestic policies may result in impacts outside of U.S.
borders due to the global nature of the pollutants.
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benefits in 2025 are $870 million (2016$) under the illustrative policy scenario; by 2035, the
global benefits in this sensitivity case decrease to $760 million (2016$) under the illustrative
policy scenario.
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7.4 References
Anthoff, D., and R. J. Tol. 2010. On international equity weights and national decision making
on climate change. Journal of Environmental Economics and Management, 60(1): 14-20.
Anthoff, D. and Tol, R.S.J. 2013. "The uncertainty about the social cost of carbon: a
decomposition analysis using FUND." Climatic Change, 117: 515-530.
Arrow, K., M. Cropper, C. Gollier, B. Groom, G. Heal, R. Newell, W. Nordhaus, R. Pindyck, W.
Pizer, P. Portney, T. Sterner, R.S.J. Tol, and M. Weitzman. 2013. "Determining Benefits
and Costs for Future Generations." Science, 341: 349-350.
Fraas, A., R. Lutter, S. Dudley, T. Gayer, J. Graham, J.F. Shogren, and W.K. Viscusi. 2016.
Social Cost of Carbon: Domestic Duty. Science, 351(6273): 569.
Gayer, T., and K. Viscusi. 2016. Determining the Proper Scope of Climate Change Policy
Benefits in U.S. Regulatory Analyses: Domestic versus Global Approaches. Review of
Environmental Economics and Policy, 10(2): 245-63.
Hope, Chris. 2013. "Critical issues for the calculation of the social cost of C02: why the
estimates from PAGE09 are higher than those from PAGE2002." Climatic Change, 117:
531-543.
Kopp, R.J., A.J. Krupnick, and M. Toman. 1997. Cost-Benefit Analysis and Regulatory Reform:
An Assessment of the Science and the Art. Report to the Commission on Risk
Assessment and Risk Management.
National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages:
Updating Estimation of the Social Cost of Carbon Dioxide. National Academies Press.
Washington, DC Available at  Accessed May 30, 2017.
Nordhaus, W. 2014. "Estimates of the Social Cost of Carbon: Concepts and Results from the
DICE-2013R Model and Alternative Approaches." Journal of the Association of
Environmental and Resource Economists, 1(1/2): 273-312.
Nordhaus, William D. 2017. "Revisiting the social cost of carbon." Proceedings of the National
Academy of Sciences of the United States, 114 (7): 1518-1523.
Revesz R.L., J. A. Schwartz., P.H. Howard Peter H., K. Arrow, M. A. Livermore, M.
Oppenheimer, and T. Sterner Thomas. 2017. The social cost of carbon: A global
imperative. Review of Environmental Economics and Policy, 11(1): 172-173.
Roe, G., and M. Baker. 2007. "Why is climate sensitivity so unpredictable?" Science, 318:629-
632.
U.S. Environmental Protection Agency (U.S. EPA). 2010. Guidelines for Preparing Economic
Analyses. Office of the Administrator. EPA 240-R-10-001 December 2010. Available at:
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.
Whittington, D., & MacRae, D. (1986). The Issue of Standing in Cost-Benefit Analysis. Journal
of Policy Analysis and Management, 5(4): 665-682.
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CHAPTER 8: APPENDIX - AIR QUALITY MODELING
8.1 Air Quality Modeling Platform
In this section we describe the air quality modeling platform that was used to support the
benefits analysis for this final rule. As part of this assessment we used existing air quality
modeling for 2011 and 2023 to estimate PM2.5 and ozone concentrations in 2025, 2030, and 2035
for both the baseline and illustrative policy scenario identified in Chapter 4. The modeling
platform consists of several components including the air quality model, meteorology, estimates
of international transport, and base year and future year emissions from anthropogenic and
natural sources. An overview of each of these platform comments is provided in the subsections
below.
8.1.1 Air Quality Model, Meteorology and Boundary Conditions
We used the Comprehensive Air Quality Model with Extensions (CAMx version 6.40)
with the Carbon Bond chemical mechanism CB6r4 for modeling base year and future year ozone
and PM2.5 concentrations (Ramboll, 2016). CAMx is a three-dimensional grid-based
photochemical air quality model designed to simulate the formation and fate of oxidant
precursors, primary and secondary particulate matter concentrations, and deposition over
national, regional and urban spatial scales. Consideration of the different processes (e.g.,
transport and deposition) that affect primary (directly emitted) and secondary (formed by
atmospheric processes) pollutants in different locations is fundamental to understanding and
assessing the effects of emissions on air quality concentrations.
The geographic extent of the modeling domain covers the 48 contiguous states along with
the southern portions of Canada and the northern portions of Mexico as shown in 8-1. This
modeling domain contains 25 vertical layers with a top at about 17,550 meters1 and horizontal
grid resolution of 12 km x 12 km. The model simulations produce hourly air quality
concentrations for each 12-km grid cell across the modeling domain.
1 Since the model top is defined based on atmospheric pressure, the actual height of the model top varies somewhat
with time and location.
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a'srjsrr^ ' "		V'
Figure 8-1 Air Quality Modeling Domain
The 2011 meteorological data for air quality modeling were derived from running
Version 3.4 of the Weather Research Forecasting Model (WRF) (Skamarock, et al., 2008). The
meteorological outputs from WRF include hourly-varying horizontal wind components (i.e.,
speed and direction), temperature, moisture, vertical diffusion rates, and rainfall rates for each
vertical layer in each grid cell. The 2011 meteorology was used for both the 2011 base year and
2023 future year air quality modeling. Details of the annual 2011 meteorological model
simulation and evaluation are provided in a separate technical support document (US EPA,
2014a) which can be obtained at:
http://www.epa.gov/ttn/scram/reports/MET_TSD_201 l_fmal_l l-26-14.pdf
The lateral boundary and initial species condition concentrations are provided by a three-
dimensional global atmospheric chemistry model, GEOS-Chem (Yantosca, 2004) standard
version 8-03-02 with 8-02-01 chemistry. The global GEOS-Chem model simulates atmospheric
chemical and physical processes driven by assimilated meteorological observations from the
NASA's Goddard Earth Observing System (GEOS-5),2 GEOS-Chem was run for 2011 with a
grid resolution of 2.0 degrees x 2.5 degrees (latitude-longitude). The predictions were used to
provide one-way dynamic boundary condition concentrations at three-hour intervals and an
initial concentration field for the CAMx simulations. The 2011 boundary concentrations from
2 Additional information available at:
http://gmao.gsfc.nasa.gov/GEOS/ and http://wiki.seas.harvard.edu/geos-chem/index.php/GEOS-5).
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GEOS-Chem were used for both the 2011 and 2023 model simulations. The procedures for
translating GEOS-Chem predictions to initial and boundary concentrations are described
elsewhere (Henderson, 2014). More information about the GEOS-Chem model and other
applications using this tool is available at: http://www-as.harvard.edu/chemistry/trop/geos.
8.1.2 2011 and 2023 Emissions
The purpose of the 2011 current year modeling is to represent the year 2011 in a manner
consistent with the methods used in corresponding future-year cases, including the 2023 future
year base case. The emissions data in this platform are primarily based on the 201 INational
Emissions Inventory (NEI) v2 for point sources, nonpoint sources, commercial marine vessels,
nonroad mobile sources and fires. The onroad mobile source emissions are similar to those in the
2011 NEIv2, but were generated using the 2014a version of the Motor Vehicle Emissions
Simulator (MOVES2014a) (http://www.epa.gov/otaq/models/moves/). The 2011 and 2023
emission inventories incorporate revisions implemented based on comments received on the
Notice of Data Availability (NOD A) issued in January 2017 "Preliminary Interstate Ozone
Transport Modeling Data for the 2015 Ozone National Ambient Air Quality Standard" (82 FR
1733), along with revisions made from prior notices and rulemakings on earlier versions of the
2011 platform. The preparation of the emission inventories for air quality modeling is described
in the Technical Support Document (TSD) Additional Updates to Emissions Inventories for the
Version 6.3, 2011 Emissions Modeling Platform for the Year 2023 (US EPA, 2017a). Electronic
copies of the emission inventories and ancillary data used to produce the emissions inputs to the
air quality model are available from the 201 len and 2023en section of the EPA Air Emissions
Modeling website for the 201 lv6.3 emissions modeling platform: https://www.epa.gov/air-
emissions-modeling/201 l-version-63-platform.
The emission inventories for the future year of 2023 were developed using projection
methods that are specific to the type of emission source. Future emissions are projected from the
2011 current year either by running models to estimate future year emissions from specific types
of emission sources (e.g., EGUs, and onroad and nonroad mobile sources), or for other types of
sources by adjusting the base year emissions according to the best estimate of changes expected
to occur in the intervening years. For sectors which depend strongly on meteorology (such as
biogenic and fires), the same emissions are used in the base and future years to be consistent with
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the 2011 meteorology used when modeling 2023. For the remaining sectors, rules and specific
legal obligations that go into effect in the intervening years, along with changes in activity for
the sector, are considered when possible. Emissions inventories for neighboring countries used in
our modeling are included in this platform, specifically 2011 and 2023 emissions inventories for
Mexico, and 2013 and 2025 emissions inventories for Canada. The meteorological data used to
create and temporalize emissions for the future year cases is held constant and represents the
year 2011. The same ancillary data files3 are used to prepare the future year emissions
inventories for air quality modeling as were used to prepare the 2011 base year inventories with
the exception of chemical speciation profiles for mobile sources and temporal profiles for EGUs.
The projected EGU emissions reflect the emissions reductions expected due to the Final
Mercury and Air Toxics (MATS) rule announced on December 21, 2011, the Cross-State Air
Pollution Rule (CSAPR) issued July 6, 2011, and the CSAPR Update issued October 26, 2016.
The 2023 EGU projected inventory was developed using an engineering analysis approach. The
EPA started with 2016 reported, seasonal, historical emissions for each unit. The emissions data
for NOx and SO2 for units that report data under either the Acid Rain Program (ARP) and/or the
CSAPR were aggregated to the summer/ozone season period (May-September) and winter/non-
ozone period (January-April and October-December).4 Adjustments to 2016 levels were made to
account for retirements, coal to gas conversion, retrofits, state-of-the-art combustion controls,
along with other unit-specific adjustments. Details and these adjustments, and information about
handling for units not reporting under Part 75 and pollutants other than NOx and SO2 are
described in the emissions modeling TSD (US EPA, 2017a).
The 2023 non-EGU stationary source emissions inventory includes impacts from
enforceable national rules and programs including the Reciprocating Internal Combustion
Engines (RICE) and cement manufacturing National Emissions Standards for Hazardous Air
Pollutants (NESHAPs) and Boiler Maximum Achievable Control Technology (MACT)
reconsideration reductions. Projection factors and percent reductions for non-EGU point sources
reflect comments received by the EPA in response to the January 2017 NOD A, along with
3	Ancillary data files include temporal, spatial, and VOC/PM2 5 chemical speciation surrogates.
4	The EPA notes that historical state-level ozone season EGU NOx emission rates are publicly available and quality
assured data. They are monitored using continuous emissions monitors (CEMs) data and are reported to the EPA
directly by power sector sources. They are reported under Part 75 of the CAA.
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emissions reductions due to national and local rules, control programs, plant closures, consent
decrees and settlements. Growth and control factors provided by states and by regional
organizations on behalf of states were applied. Reductions to criteria air pollutant (CAP)
emissions from stationary engines resulting as co-benefits to the Reciprocating Internal
Combustion Engines (RICE) National Emission Standard for Hazardous Air Pollutants
(NESHAP) are included. Reductions due to the New Source Performance Standards (NSPS)
VOC controls for oil and gas sources, and the NSPS for process heaters, internal combustion
engines, and natural gas turbines were also included.
For point and nonpoint oil and gas sources, state projection factors were generated using
historical oil and gas production data available for 2011 to 2015 from EIA and information from
AEO 2017 projections to year 2023. Co-benefits of stationary engines CAP reductions (RICE
NESHAP) and controls from New Source Performance Standards (NSPS) are reflected for select
source categories. Mid-Atlantic Regional Air Management Association (MARAMA) factors for
the year 2023 were used where applicable. Projection factors for other nonpoint sources such as
stationary source fuel combustion, industrial processes, solvent utilization, and waste disposal,
reflect emissions reductions due to control programs along with comments on the growth and
control of these sources as a result of the January 2017 NODA and information gathered from
prior rulemakings and outreach to states on emission inventories.
The MOVES2014a-based 2023 onroad mobile source emissions account for changes in
activity data and the impact of on-the-books national rules including: the Tier 3 Vehicle
Emission and Fuel Standards Program, the 2017 and Later Model Year Light-Duty Vehicle
Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards (LD GHG), the
Renewable Fuel Standard (RFS2), the Mobile Source Air Toxics Rule, the Light Duty Green
House Gas/Corporate Average Fuel Efficiency (CAFE) standards for 2012-2016, the Greenhouse
Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines
and Vehicles, the Light-Duty Vehicle Tier 2 Rule, and the Heavy-Duty Diesel Rule. The
MOVES-based emissions also include state rules related to the adoption of LEV standards,
inspection and maintenance programs, Stage II refueling controls, and local fuel restrictions.
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The nonroad mobile 2023 emissions, including railroads and commercial marine vessel
emissions also include all national control programs. These control programs include the Clean
Air Nonroad Diesel Rule - Tier 4, the Nonroad Spark Ignition rules, and the Locomotive-Marine
Engine rule. For ocean-going vessels (Class 3 marine), the emissions data reflect the 2005
voluntary Vessel Speed Reduction (VSR) within 20 nautical miles, the 2007 and 2008 auxiliary
engine rules, the 40 nautical mile VSR program, the 2009 Low Sulfur Fuel regulation, the 2009-
2018 cold ironing regulation, the use of 1 percent sulfur fuel in the Emissions Control Area
(ECA) zone, the 2012-2015 Tier 2 NOx controls, the 2016 0.1 percent sulfur fuel regulation in
ECA zone, and the 2016 International Marine Organization (IMO) Tier 3 NOx controls. Non-
U.S. and U.S. category 3 commercial marine emissions were projected to 2025 using consistent
methods that incorporated controls based on ECA and IMO global NOx and SO2 controls.
8.1.3 2011 Model Evaluation for Ozone and PM2.5
An operational model performance evaluation was conducted to examine the ability of
the 2011 base year model run to simulate the corresponding 2011 measured ozone and PM2.5
concentrations. This evaluation focused on four statistical metrics comparing model predictions
to the corresponding observations. The performance statistics include mean bias, mean error,
normalized mean bias, and normalized mean error. Mean bias (MB) is the sum of the difference
(predicted - observed) divided by the total number of replicates (n). Mean bias is given in units
of ppb and is defined as:
MB =	(Eq-1)
Where:
•	P is the model-predicted concentration;
•	O is the observed concentrations; and
•	n is the total number of observations
Mean error (ME) calculates the sum of the absolute value of the difference (predicted -
observed) divided by the total number of replicates (n). Mean error is given in units of ppb and is
defined as:
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ME = i2;|P-0|
(Eq-2)
Normalized mean bias (NMB) is the sum of the difference (predicted - observed) over the
sum of observed values. NMB is a useful model performance indicator because it avoids over
inflating the observed range of values, especially at low concentrations. Normalized mean bias is
given in percentage units and is defined as:
Normalized mean error (NME) is the sum of the absolute value of the difference
(predicted - observed) divided by the sum of observed values. Normalized mean error is given in
percentage units and is defined as:
For PM2.5, performance statistics were calculated for modeled and observed 24-hour
average concentrations paired by day and location for the entire year. Performance statistics were
calculated for monitoring data in the Chemical Speciation Network (CSN)5 and, separately, for
monitoring data in the Interagency Monitoring of Protected Visual Environments (IMPROVE)6
network. For ozone, performance statistics were calculated for modeled concentrations with
observed 8-hour daily maximum (MDA8) ozone concentrations at or above 60 ppb7 over the
period May through September for monitoring sites in the Air Quality System (AQS)8'9 network.
For both PM2.5 and ozone, the modeled and predicted pairs of data were aggregated by 9 regions
5	Additional information on the measurements made at CSN monitoring sites can be found at the following web link:
https://www.epa.gov/amtic/chemical-speciation-network-csn.
6	Additional information on the measurements made at IMPROVE monitoring sites can be found at the following
web link: https://www3.epa.gov/ttnamtil/visdata.html.
7	Performance statistics are calculated for days with measured values at or above 60 ppb in order to focus the
evaluation on days with high rather than low concentrations.
8	Additional information on the measurements made at AQS monitoring sites can be found at the following web
link: https://www.epa.gov/aqs.
9	Note that the AQS data base also includes measurements made at monitoring sites in the Clean Air Status and
Trends Network (CASTNet).
nmb = £;(np 0) * 100
Zi(0)
(Eq-3)
NME =	* 100
Zi(o)
(Eq-4)
8-7
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across the U.S. for the calculation of model performance statistics. These 9 regions are shown in
Figure 8-2.10
U.S. Climate Regions
Figure 8-2	NO A A Climate Regions
Model performance statistics for PM2.5 for each region are provided in Table 8-1. These
data indicate that over the year as a whole, PM2.5 is over predicted in the Northeast, Ohio Valley,
Upper Midwest, Southeast, and Northwest regions and under predicted in the South and
Southwest regions. Normalized mean bias is within ±30 percent in all regions except the
Northwest which has somewhat larger model over-predictions. Model performance for PM2.5 for
the 2011 modeling platform is similar to the model performance results for other contemporary,
state of the science photochemical model applications (Simon et al., 2012). Additional details on
PM2.5 model performance for the 2011 base year model am can be found in the Technical
Support Document for EPA's preliminary regional haze modeling (US EPA, 2017b).
10 Source: http://www.ncdc.110aa.g0v/m011it0ring-references/maps/us-climate-regi0ns.php#references.
8-8
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Table 8-1 Model Performance Statistics by Region for PM2.5
Region
Network
No. of Obs
MB
(ug/m3)
ME
(ug/m3)
NMB
(%)
NME
(%)
Northeast
IMPROVE
1577
0.87
2.21
17.70
44.90
CSN
2788
0.97
4.04
9.70
40.40
Ohio Valley
IMPROVE
680
0.10
2.96
1.20
35.50
CSN
2475
0.13
3.85
1.10
32.80
Upper Midwest
IMPROVE
CSN
700
1343
0.83
1.37
2.37
3.66
14.20
13.60
40.40
36.30
Southeast
IMPROVE
1172
0.52
3.54
6.30
43.20
CSN
1813
0.19
3.92
1.70
34.20
South
IMPROVE
933
-0.47
2.69
-6.50
37.40
CSN
962
-0.08
4.48
-0.75
39.50
Southwest
IMPROVE
3695
-1.12
1.86
-28.00
46.30
CSN
746
-0.08
3.93
-1.00
47.10
N. Rockies/
IMPROVE
1952
0.07
1.39
2.40
44.90
Plains
CSN
275
-2.07
4.18
-21.80
43.90
Northwest
IMPROVE
1901
1.19
2.28
43.20
82.90
CSN
668
5.77
7.25
69.90
87.90
West
IMPROVE
1782
-1.08
2.08
-25.30
48.50
CSN
936
-2.92
5.08
-23.10
40.30
Model performance statistics for May through September MDA8 ozone concentrations for
each region are provided in Table 8-2. Overall, measured ozone is under predicted in most
regions, except for the Northeast and Southeast where over prediction is found. Normalized
mean bias is within ±15 percent in all regions. Model performance for ozone for the 2011
modeling platform is similar to the model performance results for other contemporary, state of
the science photochemical model applications (Simon et al., 2012). Additional details on ozone
model performance for the 2011 base year model run can be found in the Air Quality Technical
Support Document for EPA's preliminary interstate ozone transport modeling for the 2015 ozone
National Ambient Air Quality Standard (US EPA, 2017c).
8-9
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Table 8-2 Model Performance Statistics by Region for Ozone on Days Above 60 ppb
(May-Sep)
Region
No. of Obs
MB
(ppb)
ME
(ppb)
NMB
(%)
NME
(%)
Northeast
4085
1.20
7.30
1.80
10.70
Ohio Valley
6325
-0.60
7.50
-0.90
11.10
Upper Midwest
1162
-4.00
7.60
-5.90
11.10
Southeast
4840
2.30
6.80
3.40
10.20
South
5694
-5.30
8.40
-7.60
12.20
Southwest
6033
-6.20
8.50
-9.40
12.90
N. Rockies/Plains
380
-7.20
8.40
-11.40
13.40
Northwest
79
-5.60
9.00
-8.70
14.00
West
8655
-8.60
10.30
-12.20
14.50
Thus, the model performance results demonstrate the scientific credibility of our 2011
modeling platform for predicting PM2.5 and ozone concentrations. These results provide
confidence in the ability of the modeling platform to provide a reasonable projection of expected
future year ozone concentrations and contributions.
8.2 Source Apportionment Tags
As described in Chapter 4, CAMx source apportionment modeling was used to track
ozone and PM2.5 component species impacts from pre-defined groups of emissions sources
(source tags). Separate tags were created for state-level EGUs split by fuel type (coal units versus
non-coal units11). For some states with low EGU emissions, EGUs are grouped with nearby states
that also have low EGU emissions. In addition, there are no coal EGUs operating in the 2023
emissions case for the following states: Idaho, Oregon, and Washington. Therefore, there is no
coal EGU tag for those states. Similarly, there were no EGUs (coal or non-coal) in Washington
D.C. in the 2023 emissions scenario, so there were no EGU tags for Washington D.C. There
were also several domain-wide tags for sources other than EGUs. Table 8-3 provides a full list of
the emissions group tags that were tracked in the source apportionment modeling
11 For the purposes of this analysis non-coal fuels include emissions from natural gas, oil, biomass, and waste coal-
fired EGUs.
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Table 8-3 Source Apportionment Tags
Coal-fired EGU tags
Non-coal EGU tags
Domain-wide tags
Alabama
Arizona
Arkansas
California
Colorado
Connecticut + Rhode Island
Delaware + New Jersey
Florida
Georgia
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine + Mass. + New Hamp. +
Vermont
Maryland
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Carolina
North Dakota + South Dakota
Ohio
Oklahoma
Pennsylvania
South Carolina
Tennessee
Texas
Utah
Virginia
West Virginia
Wisconsin
Wyoming
Tribal Data*
Alabama
Arizona
Arkansas
California
Colorado
Connecticut + Rhode Island
Delaware + New Jersey
Florida
Georgia
Idaho + Oregon + Washington
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine + Mass. + New Hamp. +
Vermont
Maryland
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Carolina
North Dakota + South Dakota
Ohio
Oklahoma
Pennsylvania
South Carolina
Tennessee
Texas
Utah
Virginia
West Virginia
Wisconsin
Wyoming
Tribal Data12
EGU retirements
through 2025
EGU retirements
2026-2030
All U.S.
anthropogenic
emissions from
source sectors
other than EGUs
International
within-domain
emissions
(sources
occurring in
Canada, Mexico,
and from
offshore marine
vessels and
drilling
platforms)
Fires (wildfires
and prescribed
fires)
Biogenic sources
Boundary
conditions
Examples of the magnitude and spatial extent of ozone tagged contributions are provided
in Figure 8-3 through Figure 8-6 for coal and non-coal EGUs in Pennsylvania and Texas. These
figures show how both the magnitude and the spatial patterns of contributions can differ between
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coal and non-coal EGU units within a state and downwind. In addition, the figures demonstrate
that the spatial extent of contributions can vary substantially from state to state depending on the
location of sources, the magnitude of their emissions, and meteorology. Moreover, day to day
variations in meteorology can have a substantial impact on day to day patterns in contributions,
which we capture in our analysis. While we used the daily contributions in our calculations,
seasonal average contributions are presented here to provide a general illustration of the
differential spatial patterns of contribution.
>2.00
1.80
1.60
1.40
1.20
1.00
0.80
0.60
0.40
<0.20
PA Coal EGU Ozone Contributions
May-Sep Mean of MDA8
Min = 0.00E+0 at (1,1), Max = 2.039 at (327,151)
Figure 8-3 Map of Pennsylvania Coal EGU Tag Contribution to Seasonal Average
MDA8 Ozone (ppb)
12 EGUs operating on tribal lands were tracked together in a single tag. There are EGUs on tribal land in the
following states: Utah (coal). New Mexico (coal), Arizona (coal and non-coal), Idaho (non-coal). EGU emissions
occurring on tribal lands were not included in the state-level EGU source tags.
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PA Non-coal EGU Ozone Contributions
May-Sep Mean of MDA8
1			 	 k
1	396 PPD
Min = 0.00E+0 at (1,1), Max = 1.808 at (344,152)
Figure 8-4 Map of Pennsylvania Non-Coal EGU Tag Contribution to Seasonal Average
MDA8 Ozone (ppb)
TX Coal EGU Ozone Contributions
May-Sep Mean of MDA8
Min =0.00E-H] at (1,1), Max = 4.818 at (221,66)
396ppb
Figure 8-5 Map of Texas Coal EGU Tag Contribution to Seasonal Average MDA8
Ozone (ppb)
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TX Non-coal EGU Ozone Contributions
May-Sep Mean of MDA8
il			,		
1	396ppb
Min = 0.00E+0 at (1,1), Max = 2.310 at (227,44)
Figure 8-6 Map of Texas Non-Coal EGU Tag Contribution to Seasonal Average MDA8
Ozone (ppb)
Examples of the magnitude and spatial extent of tagged contributions for PM2.5
component species are provided in Figure 8-7 through Figure 8-12. Examples are provided for
coal-fired EGUs in Indiana. These figures show how both the magnitude and the spatial patterns
of contributions can differ by season and by PM2.5 component species. The species which are
formed through chemical reactions in the atmosphere (sulfate and nitrate) have a more regional
signal than directly emitted primary PM2.5 (organic aerosol (OA), elemental carbon (EC), and
crustal material13) whose impact is more local in nature. In addition, the chemistry and transport
can vary by season with nitrate contributions being higher in the winter than in the summer and
sulfate contributions being higher in the summer than in the winter.
13 Crustal material refers to metals that are commonly found in the earth's crust such as Aluminum, Calcium, Iron,
Magnesium, Manganese, Potassium Silicon, Titanium and the associated oxygen atoms.
8-14
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IN Coal EGU Nitrate Contributions
Quarterly Avg ¦ Winter
1	396 ug/m3
Min = 0.00E+0 at (1,1), Max = 0.151 at (274,124)
Figure 8-7 Map of Indiana Coal EGU Tag Contributions to Wintertime Average
(January-March) Nitrate (jig/m3)
IN Coal EGU Nitrate Contributions
Quarterly Avg - Summer
1	396ug/m3
Min = 0.00E+0 at (1,1), Max = 0.022 at (274,125)
Figure 8-8 Map of Indiana Coal EGU Tag Contributions to Summertime Average (July-
September) Nitrate (jig/m3)
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396 ug/m3
Min = O.OOE+O at (1,1), Max = 0.129 at (269,120)
IN Coal EGU Sulfate Contributions
Quarterly Avg ¦ Winter
Figure 8-9 Map of Indiana Coal EGU Tag Contributions to Wintertime Average
(January-March) Sulfate (fig/m3)
396 ug/m3
IN Coal EGU Sulfate Contributions
Quarterly Avg - Summer
Min =0.00E+€ at (1,1), Max = 0.229 at (272,126)
Figure 8-10 Map of Indiana Coal EGU Tag Contributions to Summertime Average (July-
September) Sulfate (jig/m3)
8-16
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IN Coal EGU Primary PM Contributions
Quarterly Avg ¦ Winter
Min = 0.00E+0 at (1,1), Max = 0.108 at (272,120)
396 ug/m'3
Figure 8-11 Map of Indiana Coal EGU Tag Contributions to Wintertime Average
(January-March) Primary PM2.5 (jig/m3)
Figure 8-12 Map of Indiana Coal EG1J Tag Contributions to Summertime Average (July-
September) Primary PM2.5 (jxg/m3)
IN Coal EGU Primary PM Contributions
Quarterly Avg - Summer
Min = O.OOE+O at (1,1), Max = 0.099 at (272,120)
396 ug/m3
8-17
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The contributions represent the spatial and temporal distribution of the emissions within
each source tag. Thus, the contribution modeling results do not allow us to represent any changes
to any "within tag" spatial distributions. For example, the location of coal-fired EGUs in
Michigan are held in place based on locations in the 2023 emissions. Additionally, the relative
magnitude of sources within a source tag do not change from what was modeled with the 2023
emissions inventory.
8.3 Applying Source Apportionment Contributions to Create Air Quality Fields for the
Baseline and Illustrative Policy Scenario
As explained in Chapter 4, we created air quality surfaces for the future year baseline and
illustrative policy scenario by scaling the EGU sector tagged contributions from the 2023
modeling based on relative changes in EGU emissions associated with each tagged category
between the 2023 emissions case and the baseline or illustrative policy scenario of interest. The
following subsections describe in more detail the emissions used to represent each scenario and
provide equations used to apply these scaling ratios along with tables of the ratios.
8.3.1 Estimation methods for Emissions that Represent the Baseline and Illustrative
Policy Scenario
Annual NOx, SO2, and heat input by state and fuel (coal and noncoal) as well as ozone
season14 NOx by state and fuel were obtained for the baseline and illustrative policy scenario
described in Chapter 3. In addition to NOx and SO2, emissions, PM2.5 emissions were also
needed for the baseline and illustrative policy scenario. Since these were not generated by IPM,
we estimated PM2.5 emissions by using the ratio of 2023 heat input for combustion-based EGUs15
to the heat input of each scenario from combustion-based EGUs to scale the 2023 PM2.5.
However, 2023 heat input totals were only available for units with Continuous Emissions
Monitoring Systems (CEMS) data so an additional scalar was used to adjust the CEMS heat
value before the PM2.5 emissions are calculated as follows. First, the following data were
obtained:
14	For the purpose of this analysis the ozone season is defined as the months of May-September
15	Heat input for nuclear units and other non-combustion based EGUs that do not emit PM2 5 were not included in
any heat input numbers described in this chapter.
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•	Projected 2023 CEMS heat input values (MMBtu) by ORIS facility and unit ID16 along
with Carbon Monoxide (CO) and PM2.5 emissions (tons/yr) for each CEMS unit
•	2023 EGU total CO and PM2.5 emissions (tons/yr) by state and fuel type
•	Baseline and illustrative policy scenario heat input values (MMBtu) by state and fuel
type
Next, the CEMS EGU unit-level emissions values for CO and PM2.5 were aggregated to
state and fuel type. Since CO emissions correlate with heat input, the ratio of CO from all EGUs
to CO from CEMS units in each state-fuel category was used to scale CEMS heat inputs to
represent total EGU heath input for combustion units as shown in Equation (5) and Equation (6).
Total 2023 EGU COstate fUei	(Eq-5)
2023 Heat ScalarstateJuel =	stateJuel	Vq ;
2023 CEMS COstateJuei
Total 2023 Heats^a^e fuel ~ 2023 Heat Scalavs^a^e fuel ^ 2023 CEMS Heats^a^e fuel
(Eq-6)
Finally, using Equation (7) and Equation (8), the 2023 PM2.5 emissions were scaled to
represent PM2.5 emissions for the baseline and illustrative policy scenario based on relative
changes in heat input from 2023 (as obtained by Equation 6).
mi* r 7	IPM HeatScenario,state, fuel	rFfl-7^
PM? c bCCLlCLY'qrprinrjn ct-nt-p fnpi —	\ H /
/.b	scenario,state,fuel Total 2023 Heatstatejuei
scenario,state,fuel ~ ^^2,5 ScalaTSCenario,state,fuel * 2023 EGU PMi 5 state,fuel (Eq_8)
For states and fuels without CEMS CO data or where 2023 CO emissions equal zero, the
2023 EGU PM2.5 value was passed through to the baseline or illustrative policy scenario
unchanged. This was the case for North Dakota non-coal and California coal only.
One limitation of this methodology was identified after emissions scaling was complete.
Waste coal units were included in the non-coal EGU tags. There are 3 states in which some
EGUs are fueled by waste coal: Montana, Pennsylvania and West Virginia. Only in West
16 Data obtained from files available at:
https://www.cmascenter.Org/smoke/documentation/4.5/html/ch02s09sl9.html
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Virginia do the majority of non-coal primary PM2.5 emissions come from waste coal. The
baseline and illustrative policy scenario predict substantial growth compared to 2023 in non-coal
heat input in West Virginia from natural gas units which have low PM2.5 emissions rates. The
methodology described above scales PM2.5 emissions from relatively high emitting waste coal
EGUs in West Virginia to predict new heat input from lower emitting natural gas EGUs.
Therefore, this methodology likely overestimates the direct PM2.5 emissions associated with non-
coal EGUs in West Virginia for the baseline and the illustrative policy scenario. This was not as
problematic for the two other states, Pennsylvania and Montana, with waste coal EGUs. In
Pennsylvania, waste coal makes up a relatively small fraction of PM2.5 emissions within the non-
coal EGU tag. In Montana, non-coal EGU heat input is predicted to decrease substantially from
2023 levels in the baseline and illustrative policy scenario and therefore PM2.5 emissions are
predicted to be quite small.
As discussed above, EGU emissions occurring on tribal lands were tagged separately
from state-level emissions in the 2023 source apportionment tracking. Since the IPM summaries
included tribal emissions within the state (i.e. tribal emissions were not split-out from state
emissions), we estimated tribal emissions by reallocating a portion of EGU emissions from
Arizona, Idaho, New Mexico and Utah using the fraction of tribal emissions within each state
from the 2023 emissions. For instance, emissions occurring on tribal lands accounted for 23
percent of total EGU NOx from Utah, 17 percent of EGU NOx from New Mexico, 36 percent of
EGU NOx from Arizona and 7 percent of EGU NOx from Idaho in 2023. We use these
percentages to estimate total EGU tribal NOx emissions for the baseline and illustrative policy
scenario for both coal and non-coal fuel types. We also adjust the state-level emissions to
exclude those emissions from state totals so that our IPM break-outs match the definitions of the
source apportionment tags. Table 8-4 provides fractions of EGU emissions coming from tribal
lands for all pollutants and states. The relatively high scaling ratios for tribal non-coal EGU
emissions shown in Table 8-5 thought Table 8-8, are the result of not breaking out the state-
fractions by fuel type to calculate tribal emissions combined with the fact that tribal non-coal
EGU emissions in 2023 were much smaller than tribal coal EGU emissions. However, since the
ozone and PM2.5 contributions from 2023 non-coal EGU units were extremely small, these large
scaling factors did not have a noticeable impact on the final air quality surfaces.
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Table 8-4
Tribal Fractions by State in the 2023 Emissions
State
NOx
SO2
PM2S
Arizona
Idaho
New Mexico
Utah
0.36
0.07
0.17
0.23
0.20
0.11
0.62
0.12
0.38
0.14
0.69
0.23
8.3.2 Scaling Ratio Applied to Source Apportionment Tags
Scaling ratios for PM2.5 components that are emitted directly from the source (OA, EC,
crustal) were based on relative changes in annual primary PM2.5 emissions between the 2023
emissions case and the baseline and the illustrative policy scenario. Scaling ratios for
components that are formed through chemical reactions in the atmosphere were created as
follows: scaling ratios for sulfate were based on relative changes in annual SO2 emissions;
scaling ratios for nitrate were based on relative changes annual NOx emissions; and scaling
ratios for ozone formed in NOx-limited regimes17 ("03N") were based on relative changes in
ozone season (May-September) NOx emissions. The scaling ratios that were applied to each
species and scenario are provided in Table 8-5 through Table 8-8.18
Scaling ratios were applied to create air quality surfaces for ozone using equation (9):
Ozonemg d iy — Cmg age + Cm,g,d,int Cm,g,d,bio ^m,g,d,fires
17	The CAMx model internally determines whether the ozone formation regime is NOx-limited or VOC-limited
depending on predicted ratios of indicator chemical species.
18	Note that while there were no EGU emissions from Washington D.C. in the 2023 source apportionment
simulations, there were extremely small emissions predicted in the baseline and illustrative policy scenario (~1 ton
per year of NOx and 0 tons per year of SO2,). Since the emissions were negligible and there was no associated
source apportionment tag to scale to, we did not include any impact of Washington D.C. EGU emissions in the air
quality surfaces.
T
rn,g,d,USanthro
m.,g,d,y,EGUret
VOC,m,g,d,t
(Eq-9)
t=1
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where:
•	Ozonem g d i y is the estimated ozone for metric, "m" (MDA8 or MDA1), grid-
cell, "g", day, "d", scenario, "i", and year, "y";
•	Cmg d BC is the total ozone contribution from the modeled boundary inflow;
Cm,g,d,int is the total ozone contribution from international emissions within the
model domain;
•	Cmg d bio is the total ozone contribution from biogenic emissions;
•	Cm,g,d,fireS's the total ozone contribution from fires;
•	Cmg d uSanthro is the total ozone contribution from U.S. anthropogenic sources
other than EGUs;
•	Cm,g,d,y,EGUret is the total ozone contribution from retiring EGUs after year, "y"
(this term is equal to 0 in 2030 and 2035);
•	CV0C mg d t is the ozone contribution from EGU emissions of VOCs from tag, "t";
•	CNOx,m,g,d,t is the ozone contribution from EGU emissions of NOx from tag, "t";
and
•	St iy is the ozone scaling ratio for tag, "t", scenario, "i", and year, "y".
Scaling ratios were applied to create air quality surfaces for PM2.5 species using equation
(10) (for sulfate, nitrate, EC or crustal material) or using equation (11) (for OA):
P^s,g,d,i,y ~ Cs,g,d,BC Cs,g,d,int Cs,g,d,bio ^s,g,d,fires
T
Cs,g,d,USanthro ^s,g,d,y,EGUret ^ ' ^s,g,d,t^s,t,i,y
(Eq-10)
t=1
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OAgdiy — CpoA,g,d,BC + CpoA,g,d,int CpOA,g,d,bio CpOA,g,d,fires
CpoA,g,d,USanthro CpOA,g,d,y,EGUret SOAgd
T	(Eq-11)
^ ' CpOA,g,d,tSpri,t,i,y
t=1
where:
•	PMSgid iiy is the estimated concentration for species, "s" (sulfate, nitrate, EC, or crustal
material), grid-cell, "g", day, "d", scenario, "i", and year, "y";
•	Cs g d BC is the species contribution from the modeled boundary inflow;
•	Cs,g,d,irit's the species contribution from international emissions within the model
domain;
•	Cs,g,d,bi0 is the species contribution from biogenic emissions;
•	Cs,g,d,fireS's the species contribution from fires;
•	Csg d uSanthro is the species contribution from U.S. anthropogenic sources other than
EGUs;
•	Cs,g,d,y,EGUret's the species contribution from retiring EGUs after year, "y" (this term is
equal to 0 in 2030 and 2035);
•	Cs,g,d,t is the species contribution from EGU emissions from tag, "t"; and
•	Ss,t,i,y is the scaling ratio for species, "s", tag, "t", scenario, "i", and year, "y".
Similarly, for Equation (11):
•	OAg d iy is the estimated OA concentration for grid-cell, "g", day, "d", scenario, "i",
and year, "y";
•	Each of the contribution terms refers to the contribution to primary OA (POA); and
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• SOAgd represents the modeled secondary organic aerosol concentration for gird-
cell, "g", and day, "d", which does not change among scenarios
The scaling methodology described above treats air quality changes from the tagged
sources as linear and additive. It therefore does not account for nonlinear atmospheric chemistry
and also doesn't account for non-linear interactions between emissions of different pollutants and
between emissions from different tagged sources. This is consistent with how air quality
estimations have been treated in past regulatory analyses (EPA, 2015). We note that air quality is
calculated in the same manner for the baseline and the illustrative policy scenario, so any
uncertainty associated with these assumptions is carried through both sets of scenarios in the
same manner and is thus not expected to impact the air quality differences between scenarios. In
addition, emissions changes between scenarios are relatively small compared to 2023 totals.
Previous studies have shown that air pollutant concentrations generally respond linearly to small
emissions changes of up to 30 percent (Dunker et al., 2002; Cohan et al., 2005; Napelenok et al.,
2006; Koo et al., 2007; Zavala et al., 2009; Cohan and Napelenok, 2011) and therefore it is
reasonable to expect that the differences between the baseline and the illustrative policy scenario
can be adequately represented using this methodology.
We note that there is somewhat larger uncertainty in the estimations of absolute PM2.5
and ozone concentrations associated with each of the scenarios due to fact that the emissions in
the scenarios are quite different from the 2023 emissions for some tagged source categories as
shown in Table 8-5 through Table 8-8. For example, in Table 8-6 the scaling ratio for sulfate
impacts of coal EGU's in Louisiana for the 2035 baseline is 0.30 indicating that emissions of
SO2 for this source category decreased by 70 percent compared to the 2023 modeled year,
although the net change in emissions when accounting for all sources will be much lower. The
assumption of linearity in sulfate impacts to this relatively large change in emissions adds
uncertainty to the total predicted sulfate concentrations. However, the 2035 illustrative policy
scenario had a scaling ratio of 0.31 which are relatively close to the baseline. Consequently, the
linear response assumption should not drastically impact the estimates of changes in sulfate
concentrations due to emissions changes from Louisiana coal EGU's between scenarios. In
addition, the absolute concentrations do not represent a single year of predicted air pollution but
rather a combination of emissions expected in 2023 for all source other than EGUs and
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emissions expected in 2025, 2030, or 2035 from EGU sources. This adds uncertainty to what is
represented by the absolute air pollution predictions but not to the differences in air quality
between the baseline and illustrative policy scenario within a single year.
Table 8-5 Primary PM2.5 Scaling Ratios for EGU tags

Baseline (Coal)
Policy (Coal)
Base
State
2025
2030
2035
2025
2030
2035
2025
AL
0.45
0.53
0.47
0.45
0.54
0.47
0.48
AZ
0.34
0.31
0.28
0.34
0.31
0.27
0.71
AR
0.50
0.48
0.41
0.50
0.47
0.41
1.89
CA
1.00
1.00
1.00
1.00
1.00
1.00
0.34
CO
1.11
1.00
0.94
1.09
0.98
0.93
0.52
CT+RI
0.00
0.00
0.00
0.00
0.00
0.00
0.32
DE+NJ
0.00
0.00
0.00
0.00
0.00
0.00
0.74
FL
0.44
0.47
0.51
0.47
0.48
0.51
0.44
GA
0.46
0.49
0.47
0.47
0.50
0.47
1.44
ID + OR
+WA
N/A
N/A
N/A
N/A
N/A
N/A
0.53
IL
0.77
0.77
0.72
0.73
0.74
0.69
0.86
IN
0.62
0.63
0.56
0.61
0.62
0.57
1.08
IA
0.95
0.97
0.92
0.97
0.96
0.92
1.28
KS
0.93
0.87
0.77
0.93
0.86
0.77
0.45
KY
0.26
0.25
0.21
0.26
0.24
0.21
3.49
LA
0.19
0.25
0.26
0.19
0.25
0.27
0.85
ME+MA+
NH+VT
0.00
0.00
0.00
0.00
0.00
0.00
0.14
MD
0.14
0.05
0.00
0.13
0.05
0.00
3.05
MI
0.95
0.96
0.84
0.94
0.96
0.84
1.15
MN
1.29
0.98
0.94
1.29
1.02
0.94
1.22
MS
0.22
0.22
0.20
0.21
0.21
0.21
0.93
MO
1.01
0.97
0.93
1.00
0.97
0.92
1.56
MT
1.04
1.04
1.04
1.02
1.02
1.02
0.03
NE
1.01
1.00
0.99
0.99
0.99
0.98
0.94
NV
0.80
0.44
0.38
0.79
0.42
0.37
0.90
NM
0.51
0.48
0.44
0.51
0.47
0.44
0.30
NY
0.00
0.00
0.00
0.00
0.00
0.00
0.72
NC
0.49
0.39
0.27
0.48
0.39
0.25
1.77
ND+SD
0.90
0.91
0.89
0.88
0.89
0.87
1.77
OH
0.76
0.73
0.58
0.75
0.72
0.55
2.15
OK
0.48
0.40
0.34
0.49
0.43
0.35
1.01
PA
0.29
0.24
0.19
0.29
0.21
0.19
1.46
SC
0.73
0.62
0.52
0.73
0.63
0.52
0.92
TN
0.42
0.38
0.33
0.35
0.31
0.29
2.36
2030
oal)
Policy (Non-Coal)
2035
2025
2030
2035
0.51
0.48
0.48
0.51
0.89
0.71
0.83
0.89
2.04
1.89
1.97
2.03
0.19
0.34
0.20
0.19
0.76
0.52
0.68
0.76
0.27
0.32
0.27
0.27
0.78
0.73
0.75
0.78
0.47
0.44
0.45
0.47
1.50
1.44
1.49
1.49
0.55
0.54
0.55
0.55
1.21
0.84
1.03
1.21
1.50
1.08
1.11
1.44
1.70
1.28
1.46
1.70
0.72
0.45
0.42
0.72
5.27
3.43
4.49
5.38
0.99
0.85
0.86
0.99
0.01
0.02
0.01
0.01
3.26
3.07
3.12
3.27
1.62
1.15
1.16
1.62
2.01
1.13
1.61
1.99
1.01
0.93
1.00
0.99
1.95
1.49
1.60
1.90
0.05
0.03
0.04
0.05
0.95
0.95
1.01
0.96
1.09
0.90
1.02
1.09
0.27
0.29
0.27
0.27
0.70
0.72
0.68
0.69
2.30
1.75
2.02
2.34
2.37
1.54
1.98
2.37
3.19
2.32
2.96
3.18
1.35
0.98
1.07
1.35
1.58
1.45
1.45
1.58
1.51
0.92
1.24
1.50
3.03
2.37
2.41
2.99
0.49
0.84
1.98
0.20
0.68
0.27
0.76
0.45
1.50
0.54
1.07
1.13
1.45
0.42
4.39
0.86
0.01
3.11
1.17
1.68
1.00
1.63
0.04
1.01
1.02
0.27
0.68
2.03
2.00
2.98
1.09
1.45
1.26
2.39
8-25
-------
Baseline (Coal) Policy (Coal) Baseline (Non-Coal)	Policy (Non-Coal)
State 2025 2030 2035 2025 2030 2035 2025 2030 2035	2025	2030	2035
TX 1.13 1.07 1.01 1.14 1.06 1.00 0.80 0.80 0.89	0.80	0.80	0.89
UT 0.64 0.64 0.57 0.63 0.63 0.57 0.47 0.52 0.62	0.48	0.52	0.63
VA 0.17 0.15 0.05 0.17 0.14 0.04 0.99 1.04 1.19	0.99	1.05	1.20
WV 0.70 0.67 0.43 0.70 0.66 0.42 1.00 2.40 221	1.00	4.38	22.88
WI 0.58 0.59 0.53 0.57 0.58 0.53 2.27 2.30 2.38	2.26	2.30	2.38
WY 0.95 0.93 0.91 0.93 0.92 0.90 0.37 4.62 4.53	0.37	4.45	4.53
1 © ©
Tribal 0.28 0.27 0.24 0.28 0.26 0.24 16.31 17.75 °	16.13	17.67 18.89
O
Table 8-6 Sulfate Scaling Ratios for EGU tags

Baseline (Coal)
Policy (Coal)
State
2025
2030
2035
2025
2030
2035
AL
0.75
0.86
0.75
0.75
0.85
0.75
AZ
1.16
1.12
0.96
1.16
1.13
0.94
AR
2.19
2.07
1.72
2.19
2.04
1.74
CA
0.98
0.00
0.00
0.98
0.00
0.00
CO
1.00
0.93
0.88
0.98
0.92
0.86
CT+RI
0.00
0.00
0.00
0.00
0.00
0.00
DE+NJ
0.00
0.00
0.00
0.00
0.00
0.00
FL
0.73
0.82
0.88
0.81
0.83
0.88
GA
1.83
1.68
1.58
1.82
1.70
1.61
ID + OR
+WA
N/A
N/A
N/A
N/A
N/A
N/A
IL
0.77
0.78
0.73
0.75
0.75
0.70
IN
0.91
0.88
0.81
0.90
0.87
0.82
IA
0.49
0.49
0.47
0.50
0.49
0.47
KS
2.34
2.18
1.99
2.34
2.16
1.99
KY
0.26
0.27
0.23
0.26
0.27
0.23
LA
0.27
0.29
0.30
0.27
0.28
0.31
ME+MA+
NH+VT
0.00
0.00
0.00
0.00
0.00
0.00
MD
0.07
0.03
0.00
0.07
0.03
0.00
MI
0.97
1.00
0.78
0.97
1.00
0.81
MN
1.39
1.33
1.31
1.40
1.35
1.32
MS
0.66
0.67
0.62
0.65
0.66
0.65
MO
1.23
1.28
1.27
1.22
1.28
1.26
MT
0.52
0.61
0.61
0.51
0.60
0.60
NE
0.78
0.78
0.96
0.77
0.77
0.95
NV
13.26
2.84
2.43
12.95
2.73
2.41
NM
1.41
1.31
1.23
1.40
1.30
1.22
NY
0.01
0.01
0.01
0.01
0.01
0.01
Baseline (Non-Coal)
2025 2030 2035
Policy (Non-Coal)
2025 2030 2035
0.00
0.00
0.00
0.17
0.00
1.96
2.67
0.68
0.04
0.00
0.20
0.00
0.00
0.03
0.06
0.60
0.45
0.06
0.36
0.00
0.00
0.00
0.00
0.00
0.00
1.92
0.00	0.00
0.00	0.00
0.00	0.00
0.01	0.01
0.00	0.00
1.96	1.96
2.67	2.67
0.68	0.67
0.05	0.05
0.00	0.00	0.00
0.00	0.00	0.00
0.00	0.00	0.00
0.17	0.01	0.01
0.00	0.00	0.00
1.96	1.96	1.96
2.67	2.67	2.67
0.68	0.68	0.67
0.02	0.05	0.05
0.07 0.07 0.07 0.07
0.07 0.07
0.00
0.20
0.00
0.00
0.03
0.06
0.54
0.00
0.20
0.00
0.00
0.02
0.06
0.55
0.00	0.00	0.00
0.20	0.20	0.20
0.00	0.00	0.00
0.00	0.00	0.00
0.03	0.02	0.02
0.06	0.06	0.06
0.59
0.54
0.55
0.45	0.45
0.06	0.06
0.36	0.36
0.00	0.00
0.00	0.00
0.00	0.00
0.00	0.00
0.00	0.00
0.00	0.00
0.64	0.64
0.45	0.45	0.45
0.06	0.06	0.06
0.36	0.36	0.36
0.00	0.00	0.00
0.00	0.00	0.00
0.00	0.00	0.00
0.00	0.00	0.00
0.00	0.00	0.00
0.00	0.00	0.00
1.92	0.64	0.64
8-26
-------

Baseline (Coal)
Policy (Coal)
Baseline (Non-Coal)
Policy (Non-Coal)
State
2025
2030
2035
2025
2030
2035
2025
2030
2035
2025
2030
2035
NC
0.56
0.47
0.35
0.56
0.47
0.33
0.01
0.01
0.01
0.01
0.01
0.01
ND+SD
0.62
0.64
0.63
0.60
0.62
0.62
0.00
0.00
0.00
0.00
0.00
0.00
OH
0.68
0.69
0.49
0.67
0.70
0.48
0.08
0.08
0.08
0.08
0.08
0.08
OK
1.22
0.97
0.85
1.25
1.01
0.84
0.00
0.00
0.00
0.00
0.00
0.00
PA
0.15
0.12
0.09
0.15
0.11
0.09
0.04
0.04
0.04
0.04
0.04
0.04
SC
2.70
2.13
1.78
2.68
2.15
1.77
0.01
0.01
0.01
0.01
0.01
0.01
TN
0.45
0.34
0.28
0.40
0.29
0.26
0.00
0.00
0.00
0.00
0.00
0.00
TX
0.92
0.86
0.84
0.93
0.86
0.83
0.04
0.04
0.04
0.04
0.04
0.04
UT
1.09
1.24
1.34
1.07
1.23
1.32
0.00
0.00
0.00
0.00
0.00
0.00
VA
0.60
0.56
0.19
0.60
0.55
0.14
0.20
0.20
0.20
0.20
0.20
0.20
WV
0.88
0.85
0.55
0.87
0.84
0.54
0.00
0.00
0.00
0.00
0.00
0.00
WI
0.92
0.93
0.82
0.91
0.92
0.82
0.00
0.00
0.00
0.00
0.00
0.00
WY
0.64
0.56
0.68
0.61
0.55
0.67
0.00
0.00
0.00
0.00
0.00
0.00
Tribal
1.26
1.22
1.14
1.25
1.22
1.13
0.00
0.00
0.00
0.00
0.00
0.00
Table 8-7 Nitrate Scaling Ratios for EGU tags

Baseline (Coal)
Policy (Coal)
State
2025
2030
2035
2025
2030
2035
AL
0.35
0.41
0.37
0.35
0.41
0.37
AZ
0.40
0.38
0.31
0.39
0.38
0.30
AR
1.57
1.41
1.16
1.57
1.39
1.17
CA
0.12
0.00
0.00
0.12
0.00
0.00
CO
0.87
0.83
0.79
0.86
0.82
0.77
CT+RI
0.00
0.00
0.00
0.00
0.00
0.00
DE+NJ
0.00
0.00
0.00
0.00
0.00
0.00
FL
0.52
0.54
0.59
0.55
0.57
0.59
GA
0.52
0.55
0.51
0.53
0.57
0.53
ID + OR
+WA
N/A
N/A
N/A
N/A
N/A
N/A
IL
0.99
1.00
0.93
0.93
0.95
0.88
IN
0.78
0.79
0.71
0.76
0.77
0.71
IA
1.25
1.26
1.19
1.28
1.26
1.19
KS
1.17
1.10
0.97
1.19
1.09
0.98
KY
0.39
0.36
0.31
0.40
0.36
0.31
LA
0.30
0.31
0.33
0.29
0.31
0.33
ME+MA+
NH+VT
0.00
0.00
0.00
0.00
0.00
0.00
MD
0.10
0.04
0.00
0.10
0.04
0.00
MI
1.19
1.22
1.01
1.19
1.22
1.03
MN
1.28
0.97
0.93
1.28
1.00
0.94
MS
0.24
0.24
0.22
0.23
0.23
0.23
Baseline (Non-Coal)
2025 2030 2035
Policy (Non-Coal)
2025 2030 2035
0.58	0.69	0.92
0.50	0.59	0.61
0.78	0.82	0.90
0.92	0.32	0.34
0.33	0.53	0.54
1.13	1.10	1.10
1.29	1.30	1.37
1.00	1.02	0.99
0.75	0.90	0.94
0.58	0.68	0.97
0.50	0.59	0.62
0.77	0.82	0.90
0.92	0.32	0.34
0.33	0.53	0.53
1.13	1.10	1.10
1.29	1.30	1.37
0.99	1.01	0.99
0.74	0.89	0.94
0.49 0.57 0.54 0.50 0.57 0.54
0.69	0.81	0.88
0.83	0.84	1.04
0.97	0.99	1.22
1.54	1.49	1.28
1.44	1.48	1.60
0.40	0.36	0.34
0.87	0.71	0.73
1.21	1.23	1.22
1.06	1.09	1.15
0.65	0.70	0.86
0.42	0.47	0.45
0.68	0.79	0.88
0.82	0.82	1.01
0.94	0.99	1.21
1.53	1.50	1.28
1.41	1.43	1.60
0.40	0.36	0.34
0.80	0.71	0.73
1.21	1.22	1.22
1.06	1.07	1.15
0.64	0.70	0.84
0.42	0.46	0.44
8-27
-------
Baseline (Coal)	Policy (Coal)	Baseline (Non-Coal) Policy (Non-Coal)
State
2025
2030
2035
2025
2030
2035
2025
2030
2035
2025
2030
2035
MO
1.16
1.08
1.03
1.15
1.09
1.02
0.56
0.59
0.88
0.54
0.59
0.86
MT
0.95
0.95
0.95
0.93
0.93
0.93
0.01
0.02
0.03
0.01
0.02
0.03
NE
1.13
1.12
1.11
1.11
1.11
1.09
1.01
0.98
0.93
0.99
0.98
0.93
NV
4.91
0.99
0.85
4.80
0.95
0.84
0.89
1.03
1.10
0.89
1.04
1.11
NM
0.76
0.67
0.54
0.74
0.66
0.53
0.41
0.24
0.18
0.41
0.24
0.18
NY
0.00
0.00
0.00
0.00
0.00
0.00
0.95
0.92
0.93
0.95
0.92
0.92
NC
0.87
0.69
0.47
0.86
0.67
0.42
0.86
0.83
0.84
0.84
0.83
0.88
ND+SD
0.77
0.78
0.75
0.76
0.76
0.74
0.45
0.53
0.62
0.46
0.53
0.62
OH
1.04
0.98
0.76
1.03
0.98
0.73
1.55
1.87
1.77
1.61
1.85
1.75
OK
1.84
1.62
1.38
1.94
1.71
1.41
0.64
0.67
0.74
0.62
0.65
0.74
PA
0.38
0.30
0.24
0.37
0.27
0.24
1.25
1.12
1.24
1.22
1.11
1.24
SC
1.12
0.99
0.81
1.12
1.00
0.81
0.67
0.71
0.77
0.67
0.69
0.76
TN
0.48
0.45
0.40
0.36
0.32
0.31
0.80
0.94
0.99
0.84
1.00
0.97
TX
1.12
1.05
0.98
1.12
1.04
0.96
0.85
0.84
0.90
0.85
0.83
0.90
UT
1.07
1.07
0.96
1.07
1.07
0.95
0.38
0.42
0.51
0.39
0.42
0.51
VA
0.16
0.13
0.05
0.16
0.13
0.03
0.96
1.03
1.09
0.96
1.03
1.09
WV
0.95
0.89
0.59
0.94
0.88
0.58
0.16
0.26
1.02
0.16
0.33
1.05
WI
0.63
0.65
0.57
0.62
0.64
0.57
0.78
0.82
0.88
0.77
0.82
0.88
WY
0.91
0.84
0.83
0.88
0.82
0.81
0.05
0.64
0.62
0.05
0.61
0.62
Tribal
0.60
0.58
0.50
0.59
0.57
0.49
13.90
15.17
15.3
e.
13.87
15.10
15.46
Table 8-8 Ozone Scaling Ratios for EGU tags

Baseline (Coal)
Policy (Coal)
State
2025
2030
2035
2025
2030
2035
AL
0.45
0.60
0.63
0.44
0.60
0.62
AZ
0.41
0.43
0.45
0.39
0.43
0.44
AR
1.44
1.44
1.45
1.44
1.44
1.45
CA
0.11
0.00
0.00
0.11
0.00
0.00
CO
0.89
0.85
0.85
0.88
0.84
0.84
CT+RI
0.00
0.00
0.00
0.00
0.00
0.00
DE+NJ
0.00
0.00
0.00
0.00
0.00
0.00
FL
0.70
0.79
1.03
0.72
0.84
1.04
GA
0.90
1.01
1.13
0.93
1.05
1.20
ID + OR
+WA
N/A
N/A
N/A
N/A
N/A
N/A
IL
0.96
1.00
0.96
0.91
0.94
0.90
IN
0.91
0.93
0.81
0.88
0.92
0.82
IA
1.12
1.13
1.13
1.13
1.14
1.12
KS
1.17
1.19
1.19
1.14
1.16
1.16
Baseline (Non-Coal)
2025 2030 2035
Policy (Non-Coal)
2025 2030 2035
0.77
0.43
0.65
0.81
0.43
1.11
1.14
0.96
0.66
0.39
0.88
1.03
1.24
2.19
0.78	0.88
0.50	0.49
0.63	0.60
0.31	0.34
0.66	0.54
1.09	1.12
1.11	1.11
0.95	0.89
0.85	0.71
0.42	0.41
0.91	1.00
0.98	1.10
1.15	1.52
2.06	1.76
0.77	0.76	0.98
0.43	0.50	0.48
0.65	0.63	0.60
0.79	0.31	0.34
0.43	0.67	0.52
1.11	1.09	1.12
1.14	1.11	1.11
0.94	0.95	0.89
0.65	0.85	0.71
0.39
0.42 0.40
0.86	0.85	1.00
1.03	0.94	1.06
1.19	1.17	1.50
2.18	2.09	1.76
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Baseline (Coal)	Policy (Coal)	Baseline (Non-Coal) Policy (Non-Coal)
State 2025 2030 2035 2025 2030 2035 2025 2030 2035 2025 2030 2035
KY
0.45
0.46
0.45
0.49
0.45
0.45
1.60
1.36
1.24
1.55
1.31
1.23
LA
0.41
0.45
0.49
0.40
0.44
0.51
0.45
0.40
0.28
0.45
0.40
0.28
ME+MA+
NH+VT
0.00
0.00
0.00
0.00
0.00
0.00
0.88
0.74
0.79
0.81
0.74
0.79
MD
0.13
0.00
0.00
0.13
0.00
0.00
1.08
1.09
1.05
1.08
1.08
1.05
MI
1.10
1.17
1.13
1.10
1.17
1.14
1.16
1.10
1.16
1.16
1.10
1.16
MN
1.28
0.99
0.99
1.26
1.02
0.98
0.75
0.79
1.11
0.73
0.78
1.06
MS
0.29
0.30
0.30
0.29
0.29
0.29
0.40
0.40
0.33
0.41
0.40
0.32
MO
1.12
1.15
1.14
1.11
1.17
1.12
0.60
0.61
0.66
0.60
0.60
0.64
MT
1.07
1.07
1.07
1.05
1.05
1.05
0.03
0.05
0.08
0.03
0.05
0.08
NE
1.14
1.14
1.14
1.12
1.12
1.12
1.07
1.03
0.97
1.05
1.02
0.97
NV
0.80
0.91
0.91
0.80
0.91
0.91
0.70
0.76
1.00
0.70
0.76
1.01
NM
0.84
0.84
0.84
0.82
0.82
0.82
0.52
0.43
0.26
0.52
0.42
0.26
NY
0.00
0.00
0.00
0.00
0.00
0.00
0.87
0.85
0.84
0.88
0.85
0.84
NC
0.92
0.78
0.60
0.90
0.73
0.50
1.10
0.95
0.84
1.06
0.95
0.91
ND+SD
0.81
0.84
0.82
0.79
0.82
0.81
0.65
0.75
0.87
0.72
0.74
0.87
OH
1.00
0.95
0.82
0.99
0.95
0.81
1.57
1.73
1.67
1.61
1.72
1.63
OK
2.27
2.24
2.14
2.28
2.19
2.14
0.83
0.77
0.73
0.80
0.79
0.72
PA
0.39
0.37
0.34
0.38
0.38
0.34
1.04
0.88
0.90
1.01
0.88
0.89
SC
1.09
1.11
1.04
1.09
1.12
1.04
0.81
0.77
0.82
0.81
0.74
0.81
TN
0.51
0.51
0.51
0.37
0.37
0.41
0.69
0.75
0.69
0.78
0.78
0.69
TX
1.07
1.19
1.22
1.07
1.18
1.20
0.95
0.88
0.86
0.94
0.87
0.86
UT
1.11
1.11
1.11
1.11
1.11
1.11
0.19
0.21
0.23
0.20
0.22
0.23
VA
0.17
0.17
0.06
0.17
0.17
0.04
0.92
0.93
0.94
0.92
0.93
0.94
WV
1.10
1.10
0.93
1.09
1.09
0.92
0.25
0.28
0.95
0.25
0.33
0.98
WI
0.52
0.61
0.54
0.54
0.60
0.54
0.70
0.76
0.84
0.70
0.76
0.83
WY
0.89
0.83
0.83
0.86
0.83
0.82
0.07
0.12
0.07
0.07
0.09
0.07
Tribal
0.63
0.63
0.64
0.62
0.63
0.63
16.21
17.84
16.6
7
16.21
17.74
16.54
8.4 Creating Fused Fields Based on Observations and Model Surfaces
In Chapter 4 we describe steps taken to estimate PM2.5 and ozone gridded surfaces
associated with the baseline and the illustrative policy scenario for every year. For PM2.5, steps
(4) - (8) (Chapter 4) describe how daily gridded PM2.5 species were processed into annual
average surfaces which combine observed values with model predictions using the enhanced
Veronoi Neighbor Average (eVNA) method (Gold et al., 1997; US EPA, 2007; Ding et al.,
2015). These steps were performed using EPA's software package, Software for the Modeled
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Attainment Test - Community Edition (SMAT-CE)19 and have been previously documented both
in the user's guide for the predecessor software (Abt, 2014) and in EPA's modeling guidance
document (U.S. EPA, 2014b). As explained in Chapter 4, we first create a 2011 eVNA surface
for each PM component species. To create the 2011 eVNA surface, SMAT-CE first calculates
quarterly average values (January-March; April-June; July-September; October-December) for
each PM2.5 component species at each monitoring site with available measured data. For this
calculation we used 3 years of monitoring data (2010-2012)20. SMAT-CE then creates an
interpolated field of the quarterly-average observed data for each PM2.5 component species using
inverse distance squared weighting resulting in a separate 3-year average interpolated observed
field for each PM2.5 species and each quarter. The interpolated observed fields are then adjusted
to match the spatial gradients from the modeled data. These two steps can be calculated using
Equation (12):
eVNAg,s,q,2011 = Z VKeightxMonitorx s q 2010_2012 ^^fl,s,g,2°11	(Eq-12)
Moaeix,s,q, 2011
Where:
•	eVNAg s q current is the gradient adjusted quarterly-average eVNA value at grid-
cell, g, for PM component species, s, during quarter, q for the year 2011;
•	Weightx is the inverse distance weight for monitor x at the location of grid-cell,
g;
•	Monitorxsq,2010-2012 is the 3-year (2010-2012) average of the quarterly
monitored concentration for species, s, at monitor, x, during quarter, q;
•	Modelg s q 2011 is the 2011 modeled quarterly-average concentrations of species,
s, at grid cell, g, during quarter, q; and
19	Software download and documentation available at https://www.epa.gov/scram/photochemical-modeling-tools
20	Three years of ambient data is used to provide a more representative picture of air pollution concentrations.
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• Modelx s q 2011 is the 2011 modeled quarterly-average concentration of species, s,
at the location of monitor, x, during quarter q.
The 2011 eVNA field serves as the starting point for future-year projections. As
described in Chapter 4, to create a gridded future-year eVNA surfaces for the baseline and
illustrative policy scenario for 2025/2030/2035, we take the ratio of the modeled future year21
quarterly average concentration to the modeled 2011 concentration in each grid cell and multiply
that by the corresponding 2011 eVNA quarterly PM2.5 component species value in that grid cell
(Equation 13).
eVNAg,s,q,future = (eVNAgsq2011) x Mod°lgqs'fq20ii	(Eq-13)
This results in a gridded future-year projection which accounts for adjustments to match
observations in the 2011 modeled data.
Finally, particulate ammonium concentrations are impacted both by emissions of
precursor ammonia gas as well as ambient concentrations of particulate sulfate and nitrate.
Because of uncertainties in ammonium speciation measurements combined with sparse
ammonium measurements in rural areas, the SMAT-CE default is to calculate ammonium values
using the degree of sulfate neutralization (i.e., the relative molar mass of ammonium to sulfate
with the assumption that all nitrate is fully neutralized). Degree of neutralization values are
mainly available in urban areas while sulfate measurements are available in both urban and rural
areas. Ammonium is thus calculated by multiplying the interpolated degree of neutralization
value by the interpolated sulfate value at each grid-cell location which allows the ammonium
fields to be informed by rural sulfate measurements in locations where no rural ammonium
measurements are available. The degree of neutralization is not permitted to exceed the
maximum theoretical molar ratio of 2:1 for ammonium:sulfate. When creating the future year
surface for particulate ammonium, we use the default SMAT-CE assumption that the degree of
neutralization for the aerosol remains at 2011 levels.
21 In this analysis the "future year" modeled concentration is the result of Equations 9, 10 or 11 that represents either
the baseline or the illustrative policy scenario for 2025, 2030, or 2035.
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A similar method for creating future-year eVNA surfaces is followed for the two ozone
metrics with a few key differences. First, while PM2.5 is split into quarterly averages and then
averaged up to an annual value, we look at ozone as a summer-season average using definitions
that match metrics from epidemiology studies (May-Sep for MDA8 and Apr-Oct for MDA1).
The other main difference in the SMAT-CE calculation for ozone is that the spatial interpolation
of observations uses an inverse distance weighting rather than an inverse distance squared
weighting. This results in interpolated observational fields that better replicate the more gradual
spatial gradients observed in ozone compared to PM2.5.
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8.5 References
82 FR 1733. Notice of Availability of the Environmental Protection Agency's Preliminary
Interstate Ozone Transport Modeling Data for the 2015 Ozone National Ambient Air
Quality Standard (NAAQS), (January 6, 2017).
Abt Associates, 2014. User's Guide: Modeled Attainment Test Software.
http://www.epa.gov/scram001/modelingapps_mats.htm
Cohan, D.S., Hakami, A., Hu, Y.T., Russell, A.G., 2005. Nonlinear response of ozone to
emissions: Source apportionment and sensitivity analysis. Environ. Sci. Technol. 39,
6739-6748.
Cohan, D.S., Napelenok, S.L., 2011. Air Quality Response Modeling for Decision Support.
Atmosphere. 2, 407-425.
Ding, D., Zhu, Y., Jang, C., Lin, C., Wang, S., Fu, J., Gao, J., Deng, S., Xie, J., Qui, X., 2015.
Evaluation of heath benefit using BenMAP-CE with an integrated scheme of model and
monitor data during Guangzhou Asian Games. Journal of Environmental Science. 29,
178-188.
Dunker, A.M., Yarwood, G., Ortmann, J.P., Wilson, G.M., 2002. The decoupled direct method
for sensitivity analysis in a three-dimensional air quality model—Implementation,
accuracy, and efficiency. Environ. Sci. Technol. 36, 2965-2976.
Gold C, Remmele P.R., Roos T., 1997. In: Algorithmic Foundation of Geographic Information
Systems. In: Lecture Notes in Computer Science, Vol. 1340 (van Kereveld M, Nievergelt
J, Roos T, Widmayer P, eds) Berlin, Germany: Springer-Verlag. Voronoi methods in
GIS. pp. 21-35.
Henderson, B.H., Akhtar, F., Pye, H.O.T., Napelenok, S.T., Hutzell, W.T., 2014. A Database and
Tool for Boundary Conditions for Regional Air Quality Modeling: Description and
Evaluations, Geoscientific Model Development. 7, 339-360.
Koo, B., Dunker, A.M., Yarwood, G., 2007. Implementing the decoupled direct method for
sensitivity analysis in a particulate matter air quality model. Environ. Sci. Technol. 41,
2847-2854.
Napelenok, S.L., Cohan, D.S., Hu, Y., Russell, A.G., 2006. Decoupled direct 3D sensitivity
analysis for particulate matter (DDM-3D/PM). Atmospheric Environment. 40, 6112-
6121.
Ramboll Environ, 2016. User's Guide Comprehensive Air Quality Model with Extensions
version 6.40. Ramboll Environ International Corporation, Novato, CA.
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Simon, H., Baker, K. R., Phillips, S., 2012. Compilation and interpretation of photochemical
model performance statistics published between 2006 and 2012, Atmos. Environ. 61,
124-139.
Skamarock, W.C., Klemp, J.B., Dudhia,J., Gill, D.O., Barker, D.M., Duda, M.G., Huang, X.-Y.,
Wang, W., Powers, J.G., 2008. A Description of the Advanced Research WRF Version 3.
NCAR Tech. Note NCAR/TN-475+STR.
(http://wwww.mmm.ucar.edu/wrf/users/docs/arw_v3.pdf).
US EPA, 2007, Technical Report on Ozone Exposure, Risk, and Impact Assessments for
Vegetation. EPA 452/R-07-002. Prepared by Abt Associates Inc. for U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards, Health and
Environmental Impacts Division. Research Triangle Park, NC.
(https://www3.epa.gov/ttn/naaqs/standards/ozone/data/2007_01_environmental_tsd.pdf).
US EPA, 2014a. Meteorological Model Performance for Annual 2011 Simulation WRF v3.4,
Research Triangle Park, NC. (http://www.epa.gov/scram001/).
US EPA, 2014b, Modeling Guidance for Demonstrating Attainment of Air Quality Goals for
Ozone, PM2.5, and Regional Haze- December 2014 DRAFT, Research Triangle Park,
NC. (https://www3.epa.gov/ttn/scram/guidance/guide/Draft_03-PM-
RH_Modeling_Guidance-2014.pdf).
US EPA, 2015, Regulatory Impact Analysis of the Final Revisions to the National Ambient Air
Quality Standards for Ground-Level Ozone, EPA-452/R-15-07, Research Triangle Park,
NC. (https://www.epa.gOv/sites/production/files/2016-02/documents/20151001ria.pdf).
US EPA, 2017a, Technical Support Document (TSD) Additional Updates to Emissions
Inventories for the Version 6.3, 2011 Emissions Modeling Platform for the Year 2023,
Research Triangle Park, NC. (https://www.epa.gov/sites/production/files/2017-
11/documents/ 201 Iv6.3_2023en_update_emismod_tsd_oct2017.pdf).
US EPA, 2017b. Documentation for the EPA's Preliminary 2028 Regional Haze Modeling.
Research Triangle Park, NC
(https://www3.epa.gov/ttn/scram/reports/2028_Regional_Haze_Modeling-TSD.pdf).
US EPA, 2017c. Air Quality Modeling Technical Support Document for the 2015 Ozone
NAAQS Preliminary Interstate Transport Assessment. Research Triangle Park, NC
(https://www.epa.gov/airmarkets/notice-data-availability-preliminary-interstate-ozone-
transport-modeling-data-2015 -ozone).
Yantosca, B. 2004. GEOS-CHEMv7-01-02 User's Guide, Atmospheric Chemistry Modeling
Group, Harvard University, Cambridge, MA.
Zavala, M., Lei, W., Molina, M.J., Molina, L.T., 2009. Modeled and observed ozone sensitivity
to mobile-source emissions in Mexico City. Atmos. Chem. Phys. 9, 39-55.
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United States	Office of Air Quality Planning and Standards	Publication No. EPA-452/R-19-003
Environmental Protection	Health and Environmental Impacts Division	June 2019
Agency	Research Triangle Park, NC
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