Regulatory Impact Analysis for the Proposed National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review

U.S. Environmental Protection Agency Office of Air and Radiation Office of Air Quality Planning and Standards Research Triangle Park, NC 27711

EPA-452/R-23-002 Month 2023

Regulatory Impact Analysis for the Proposed National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review

U.S. Environmental Protection Agency Office of Air Quality Planning and Standards Health and Environmental Impacts Division Research Triangle Park, NC

CONTACT INFORMATION This document has been prepared by staff from the Office of Air and Radiation, U.S. Environmental Protection Agency. Questions related to this document should be addressed to the Air Economics Group in the Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Office of Air and Radiation, Research Triangle Park, North Carolina 27711 (email: OAQPSeconomics@epa.gov).

Table of Contents Table of Contentsi List of Tablesiv List of Figuresvii 0Executive Summary0-1 0.1Introduction0-1 0.2Regulatory Requirements0-2 0.3Baseline and Analysis Years0-4 0.4Emissions Impacts0-5 0.5Compliance Costs0-6 0.6Benefits0-8 0.6.1Health Benefits0-8 0.6.2Climate Benefits0-10 0.6.3Additional Unquantified Benefits0-10 0.6.4Total Health and Climate Benefits0-11 0.7Environmental Justice Impacts0-11 0.8Comparison of Benefits and Costs0-13 0.9References0-15 1Introduction and Background1-1 1.1Introduction1-1 1.2Legal and Economic Basis for Rulemaking1-2 1.2.1Statutory Requirement1-2 1.2.2Regulated Pollutants1-2 1.2.3The Need for Air Emissions Regulation1-3 1.3Overview of Regulatory Impact Analysis1-4 1.3.1Regulatory Options1-4 1.3.2Baseline and Analysis Years1-7 1.4Organization of the Regulatory Impact Analysis1-7 2Industry Profile2-1 2.1Background2-1 2.2Power Sector Overview2-1 2.2.1Generation2-1 2.2.2Transmission2-9 2.2.3Distribution2-10 2.3Sales, Expenses, and Prices2-11 2.3.1Electricity Prices2-11 2.3.2Prices of Fossil Fuel Used for Generating Electricity2-13 2.3.3Changes in Electricity Intensity of the U.S. Economy from 2010 to 20212-14 3Costs, Emissions, and Energy Impacts3-1 3.1Introduction3-1 EPA's Post-IRA IPM 2022 Reference Case3-1 3.23-1 3.3Baseline3-4 3.4Regulatory Options Analyzed3-5 3.5Power Sector Impacts3-7 3.5.1Emissions3-7 3.5.2Compliance Costs3-8 3.5.3Projected Compliance Actions for Emissions Reductions3-13 3.5.4Generating Capacity3-14 3.5.5Generation Mix3-18 3.5.6Coal and Natural Gas Use for the Electric Power Sector3-19 3.5.7Fuel Price, Market, and Infrastructure3-21 3.5.8Retail Electricity Prices3-23 3.6Limitations of Analysis and Key Areas of Uncertainty3-27 3.7References3-29 4Benefits Analysis4-1 4.1Introduction4-1 4.2Hazardous Air Pollutant Benefits4-3 4.2.1Mercury4-3 4.2.2Non-mercury Metal HAP4-5 4.3Criteria Pollutant Benefits4-7 4.3.1Air Quality Modeling Methodology4-8 4.3.2Selecting Air Pollution Health Endpoints to Quantify4-9 4.3.3Calculating Counts of Air Pollution Effects Using the Health Impact Function4-11 4.3.4Calculating the Economic Valuation of Health Impacts4-13 4.3.5Benefits Analysis Data Inputs4-13 4.3.6Quantifying Cases of Ozone-Attributable Premature Death4-19 4.3.7Quantifying Cases of PM2.5-Attributable Premature Death4-21 4.3.8Characterizing Uncertainty in the Estimated Benefits4-21 4.3.9Estimated Number and Economic Value of Health Benefits4-24 4.4Climate Pollutant Benefits4-32 4.5Additional Unquantified Benefits4-46 4.5.1NO2 Health Benefits4-49 4.5.2SO2 Health Benefits4-50 4.5.3Ozone Welfare Benefits4-51 4.5.4NO2 and SO2 Welfare Benefits4-51 4.5.5Visibility Impairment Benefits4-52 4.5.6Water Quality and Availability Benefits4-53 4.6Total Benefits4-57 4.7References4-60 5Economic Impacts5-1 5.1Overview5-1 5.2Small Entity Analysis5-1 5.2.1Methodology5-2 5.2.2Results5-7 5.2.3Conclusion5-8 5.3Labor Impacts5-8 5.3.1Overview of Methodology5-10 5.3.2Overview of Power Sector Employment5-11 5.3.3Projected Sectoral Employment Changes due to the Proposed Rule5-12 5.3.4Conclusions5-14 5.4References5-14 6Environmental Justice Impacts6-1 6.1Introduction6-1 6.2Analyzing EJ Impacts in This Proposal6-3 6.3Qualitative Assessment of HAP Impacts6-4 6.4Demographic Proximity Analyses of Existing Facilities6-6 6.5EJ PM2.5 and Ozone Exposure Impacts6-9 6.5.1Populations Predicted to Experience PM2.5 and Ozone Air Quality Changes6-12 6.5.2PM2.5 EJ Exposure Analysis6-13 6.5.3Ozone EJ Exposure Analysis6-18 6.6Qualitative Assessment of Climate Impacts6-25 6.7Summary6-28 7Comparison of Benefits and Costs7-1 7.1Introduction7-1 7.2Methods7-1 7.3Results7-2 8Appendix A: Air Quality Modeling8-1 8.1Introduction8-1 8.2Air Quality Modeling Simulations8-1 8.3Applying Modeling Outputs to Create Spatial Fields8-8 8.4Scaling Factors Applied to Source Apportionment Tags8-15 8.5Air Quality Surface Results8-22 8.6Uncertainties and Limitations of the Air Quality Methodology8-26 8.7References8-27

List of Tables

Table 01Summary of Proposed Regulatory Options Examined in this RIA0-4 Table 02Projected EGU Emissions and Emissions Changes for the Baseline and the Regulatory Control Alternatives for 2028, 2030, and 2035 a0-5 Table 03Total National Compliance Cost Estimates for the Proposed Rule and the Less and More Stringent Alternatives (discounted to 2023, millions of 2019 dollars)0-7 Table 04Monetized Health Benefits and Climate Benefits for the Proposed Rule from 2028 through 2037 (millions of 2019 dollars)a0-11 Table 05Monetized Benefits, Costs, and Net Benefits of the Proposed Rule and Less and More Stringent Alternatives (millions of 2019 dollars, discounted to 2023) a,b0-14 Table 11Summary of Proposed Regulatory Options Examined in this RIA1-7 Table 21Total Net Summer Electricity Generating Capacity by Energy Source, 2015 and 20212-3 Table 22Net Generation in 2015 and 2021 (Trillion kWh = TWh)2-4 Table 23Coal and Natural Gas Generating Units, by Size, Age, Capacity, and Average Heat Rate in 20202-7 Table 24Total U.S. Electric Power Industry Retail Sales, 2015 and 2021 (billion kWh)2-11 Table 31Summary of Proposed Regulatory Options Examined in this RIA3-5 Table 32PM Control Technology Modeling Assumptions3-6 Table 33EGU Emissions and Emissions Changes for the Baseline Run and the Proposed Rule and More Stringent Alternatives for 2028, 2030, and 2035 a3-8 Table 34 National Power Sector Compliance Cost Estimates (millions of 2019 dollars) for the Proposed Rule and More Stringent Alternative for 2028, 2030, and 20353-9 Table 35Costs of Proposed Continuous Emissions Monitoring (CEMS) Requirement3-11 Table 36Stream of Projected Compliance Costs across Proposed Rule and Less and More Stringent Regulatory Alternatives (millions of 2019 dollars)3-13 Table 37Affected Capacity Operational in the Baseline by PM Control Strategy for the Proposed Rule and More Stringent Alternative in 2028 (GW)3-14 Table 38 2028, 2030, and 2035 Projected U.S. Capacity by Fuel Type for the Baseline Run and the Proposed Rule and More Stringent Alternative3-15 Table 39 2028, 2030, and 2035 Projected U.S. Retirements by Fuel Type for the Baseline Run and the Proposed Rule and More Stringent Alternative3-16 Table 310 2028, 2030, and 2035 Projected U.S. New Capacity Builds by Fuel Type for the Baseline Run and the Proposed Rule and More Stringent Alternative3-17 Table 311 2028, 2030, and 2035 Projected U.S. Generation by Fuel Type for the Baseline Run and the Proposed Rule and More Stringent Alternative3-19 Table 3122028, 2030, and 2035 Projected U.S. Power Sector Coal Use by Coal Supply Region for the Baseline Run and the Proposed Rule and More Stringent Alternative3-20 Table 3132028, 2030, and 2035 Projected U.S. Power Sector Coal Use by Rank for the Baseline Run and the Proposed Rule and More Stringent Alternative3-21 Table 3142028, 2030, and 2035 Projected U.S. Power Sector Natural Gas Use for the Baseline Run and the Proposed Rule and More Stringent Alternative3-21 Table 3152028, 2030, and 2035 Projected Minemouth and Power Sector Delivered Coal Price (2019 dollars) for the Baseline Run and the Proposed Rule and More Stringent Alternative3-22 Table 3162028, 2030, and 2035 Projected Henry Hub and Power Sector Delivered Natural Gas Price (2019 dollars) for the Baseline Run and the Proposed Rule and More Stringent Alternative3-22 Table 317Average Retail Electricity Price by Region for the Baseline Run and the Proposed Rule and More Stringent Alternative, 20283-24 Table 318Average Retail Electricity Price by Region for the Baseline Run and the Proposed Rule and More Stringent Alternative, 20303-25 Table 319Average Retail Electricity Price by Region for the Baseline Run and the Proposed Rule and More Stringent Alternative, 20353-26 Table 41Health Effects of Ambient Ozone and PM2.5 and Climate Effects4-10 Table 42Estimated Avoided Ozone-Related Premature Respiratory Mortalities and Illnesses for the Proposed Regulatory Option for 2028, 2030, and 2035 (95 percent confidence interval) a4-25 Table 43Estimated Avoided Ozone-Related Premature Respiratory Mortalities and Illnesses for the More Stringent Regulatory Option for 2028, 2030, and 2035 (95 percent confidence interval) a4-26 Table 44Estimated Avoided PM2.5-Related Premature Respiratory Mortalities and Illnesses for the Proposed Regulatory Option in 2028, 2030, and 2035 (95 percent confidence interval)4-27 Table 45Estimated Avoided PM2.5-Related Premature Respiratory Mortalities and Illnesses for the More Stringent Regulatory Option in 2028, 2030, and 2035 (95 percent confidence interval)a,b4-28 Table 46Estimated Discounted Economic Value of Avoided Ozone and PM2.5-Attributable Premature Mortality and Illness for the Proposed Regulatory Option in 2028, 2030, and 2035 (95 percent confidence interval; millions of 2019 dollars)a,b4-29 Table 47Estimated Discounted Economic Value of Avoided Ozone and PM2.5-Attributable Premature Mortality and Illness for the More Stringent Regulatory Option in 2028, 2030, and 2035 (95 percent confidence interval; millions of 2019 dollars)a,b4-30 Table 48Stream of Estimated Human Health Benefits from 2028 through 2037: Monetized Benefits Quantified as Sum of Long-Term Ozone Mortality and Long-Term PM2.5 Mortality (discounted at 3 percent; millions of 2019 dollars)a4-31 Table 49Stream of Estimated Human Health Benefits from 2028 through 2037: Monetized Benefits Quantified as Sum of Long-Term Ozone Mortality and Long-Term PM2.5 Mortality (discounted at 7 percent; millions of 2019 dollars)a4-31 Table 410Interim Social Cost of Carbon Values, 2025-2040 (2019 dollars per Metric Tonne CO2)4-40 Table 411Estimated Climate Benefits from Changes in CO2 Emissions for 2028, 2030, and 2035 (millions of 2019 dollars)a4-44 Table 412Stream of Projected Climate Benefits under Proposed Rule from 2028 through 2037 (millions of 2019 dollars)4-45 Table 413Stream of Projected Climate Benefits under More Stringent Regulatory Option from 2028 through 2037 (millions of 2019 dollars)4-46 Table 414Additional Unquantified Benefit Categories4-47 Table 415Combined PM2.5 and O3-related Health Benefits and Climate Benefits for the Proposed Requirements and More Stringent Alternative for 2028 (millions of 2019 dollars)4-58 Table 416Combined PM2.5 and O3-related Health Benefits and Climate Benefits for the Proposed Requirements and More Stringent Alternative for 2030 (millions of 2019 dollars)4-58 Table 417Combined PM2.5 and O3-related Health Benefits and Climate Benefits for the Proposed Requirements and More Stringent Alternative for 2035 (millions of 2019 dollars)4-58 Table 418Stream of Combined PM2.5 and O3-related Health Benefits and Climate Benefits for the Proposed Rule from 2028 through 2037 (millions of 2019 dollars)a4-59 Table 419Stream of Combined PM2.5 and O3-related Health Benefits and Climate Benefits for the More Stringent Regulatory Option from 2028 through 2037 (millions of 2019 dollars)a4-60 Table 51SBA Size Standards by NAICS Code5-4 Table 52Projected Impacts on Small Entities in 20285-7 Table 66Changes in Labor Utilization: Construction-Related (Number of Job-Years of Employment in a Single Year)5-13 Table 67Changes in Labor Utilization: Recurring Non-Construction (Number of Job-Years of Employment in a Single Year)5-13 Table 61Proximity Demographic Assessment Results Within 10 km of Coal-Fired Units Greater than 25 MW Without Retirement or Gas Conversion Plans Before 2029 Affected by this Proposed Rulemaking a,b6-9 Table 62Demographic Populations Included in the PM2.5 and Ozone EJ Exposure Analyses6-12 Table 71Monetized Benefits, Costs, and Net Benefits of the Proposed Rule and Less and More Stringent Alternatives for 2028 for the U.S. (millions of 2019 dollars) a,b7-3 Table 72Monetized Benefits, Costs, and Net Benefits of the Proposed Rule and Less and More Stringent Alternatives for 2030 for the U.S. (millions of 2019 dollars) a,b7-3 Table 73Monetized Benefits, Costs, and Net Benefits of the Proposed Rule and Less and More Stringent Alternatives for 2035 for the U.S. (millions of 2019 dollars) a,b7-4 Table 74Proposed Rule: Present Values and Equivalent Annualized Values of Projected Monetized Compliance Costs, Benefits, and Net Benefits for 2028 to 2037 (millions of 2019 dollars, discounted to 2023) a7-5 Table 75Less Stringent Regulatory Option: Present Values and Equivalent Annualized Values for the 2028 to 2037 Timeframe for Estimated Monetized Compliance Costs, Benefits, and Net Benefits (millions of 2019 dollars, discounted to 2023) a7-6 Table 76More Stringent Regulatory Option: Present Values and Equivalent Annualized Values for the 2028 to 2037 Timeframe for Estimated Monetized Compliance Costs, Benefits, and Net Benefits (millions of 2019 dollars, discounted to 2023) a7-7 Table 812026 Emissions Allocated to Each Modeled State-EGU Source Apportionment Tag8-4 Table 82Ozone Scaling Factors for EGU Tags in the Baseline, the Proposed Rule, and More Stringent Alternative8-15 Table 83Nitrate Scaling Factors for EGU Tags in the Baseline, the Proposed Rule, and More Stringent Alternative8-17 Table 84Sulfate Scaling Factors for EGU Tags in the Baseline, the Proposed Rule, and More Stringent Alternative8-19 Table 85Primary PM2.5 Scaling Factors for EGU Tags in the Baseline, the Proposed Rule, and More Stringent Alternative8-21

List of Figures

Figure 21National Coal-fired Capacity (GW) by Age of EGU, 20212-5 Figure 22Average Annual Capacity Factor by Energy Source2-6 Figure 23Cumulative Distribution in 2019 of Coal and Natural Gas Electricity Capacity and Generation, by Age2-8 Figure 24Fossil Fuel-Fired Electricity Generating Facilities, by Size2-9 Figure 25Real National Average Electricity Prices (including taxes) for Three Major End-Use Categories2-12 Figure 26Relative Increases in Nominal National Average Electricity Prices for Major End-Use Categories (including taxes), With Inflation Indices2-13 Figure 27Relative Real Prices of Fossil Fuels for Electricity Generation; Change in National Average Real Price per MMBtu Delivered to EGU2-14 Figure 28Relative Growth of Electricity Generation, Population and Real GDP Since 20142-15 Figure 29Relative Change of Real GDP, Population and Electricity Generation Intensity Since 20102-16 Figure 31Electricity Market Module Regions3-27 Figure 41Data Inputs and Outputs for the BenMAP-CE Tool4-14 Figure 42Frequency Distribution of SC-CO2 Estimates for 20304-41 Figure 61Number of People Residing in the Contiguous U.S., Areas Improving or Not Changing (Teal) or Worsening (Red) in 2028, 2030, and 2035 for PM2.5 and Ozone and the National Average Magnitude of Pollutant Concentration Changes (ug/m3 and ppb) for the Proposed and More Stringent Regulatory Options6-13 Figure 62Heat Map of the National Average PM2.5 Concentrations in the Baseline and Reductions in Concentrations Due to the Proposed and More Stringent Regulatory Options Across Demographic Groups in 2028, 2030, and 2035 (ug/m3)6-15 Figure 63Heat Map of the State Average PM2.5 Concentration Reductions (Blue) and Increases (Red) Due to the Proposed and More Stringent Regulatory Options Across Demographic Groups in 2028, 2030, and 2035 (ug/m3)6-16 Figure 64Distributions of PM2.5 Concentration Changes Across Populations, Future Years, and Regulatory Options6-18 Figure 65Heat Map of the National Average Ozone Concentrations in the Baseline and Reductions in Concentrations Due to the Proposed and More Stringent Regulatory Options Across Demographic Groups in 2028, 2030, and 2035 (ppb)6-21 Figure 66Heat Map of the State Average Ozone Concentrations Reductions (Green) and Increases (Red) Due to the Proposed and More Stringent Regulatory Options Across Demographic Groups in 2028, 2030, and 2035 (ppb)6-23 Figure 67Distributions of Ozone Concentration Changes Across Populations, Future Years, and Regulatory Options6-25 Figure 81Air Quality Modeling Domain8-3 Figure 82Maps of California EGU Tag Contributions to a) April-September Seasonal Average MDA8 Ozone (ppb); b) Annual Average PM2.5 Nitrate (ug/m3); c) Annual Average PM2.5 Sulfate (ug/m3); d) Annual Average PM2.5 Organic Aerosol (ug/m3)8-6 Figure 83Maps of Texas EGU Tag Contributions to a) April-September Seasonal Average MDA8 Ozone (ppb); b) Annual Average PM2.5 Nitrate ug/m3); c) Annual Average PM2.5, Sulfate (ug/m3); d) Annual Average PM2.5 Organic Aerosol (ug/m3)8-7 Figure 84Maps of Iowa EGU Tag contributions to a) April-September Seasonal Average MDA8 Ozone (ppb); b) Annual Average PM2.5 Nitrate (ug/m3); c) Annual Average PM2.5 Sulfate (ug/m3); d) Annual Average PM2.5 Organic Aerosol (ug/m3)8-7 Figure 85Maps of Ohio EGU Tag Contributions to a) April-September Seasonal Average MDA8 Ozone (ppb); b) Annual Average PM2.5 Nitrate (ug/m3); c) Annual Average PM2.5 Sulfate (ug/m3); d) Annual Average PM2.5 Organic Aerosol (ug/m3)8-8 Figure 86Maps of ASM-O3 in 2028. Baseline ozone concentrations (ppb) shown in left panel. Change in ozone in proposed policy option compared to baseline values (ppb) shown in center panel. Change in ozone in more stringent policy option compared to baseline values (ppb) shown in right panel.8-24 Figure 87Maps of ASM-O3 in 2030. Baseline ozone concentrations (ppb) shown in left panel. Change in ozone in proposed policy option compared to baseline values (ppb) shown in center panel. Change in ozone in more stringent policy option compared to baseline values (ppb) shown in right panel.8-25 Figure 88Maps of ASM-O3 in 2035. Baseline ozone concentrations (ppb) shown in left panel. Change in ozone in proposed policy option compared to baseline values (ppb) shown in center panel. Change in ozone in more stringent policy option compared to baseline values (ppb) shown in right panel.8-25 Figure 89Maps of PM2.5 in 2028. Baseline PM2.5 concentrations (ug/m3) shown in left panel. Change in PM2.5 in proposed policy option compared to baseline values (ug/m3) shown in center panel. Change in PM2.5 in more stringent policy option compared to baseline values (ug/m3) shown in right panel.8-25 Figure 810Maps of PM2.5 in 2030. Baseline PM2.5 concentrations (ug/m3) shown in left panel. Change in PM2.5 in proposed policy option compared to baseline values (ug/m3) shown in center panel. Change in PM2.5 in more stringent policy option compared to baseline values (ug/m3) shown in right panel.8-26 Figure 811Maps of PM2.5 in 2035. Baseline PM2.5 concentrations (ug/m3) shown in left panel. Change in PM2.5 in proposed policy option compared to baseline values (ug/m3) shown in center panel. Change in PM2.5 in more stringent policy option compared to baseline values (ug/m3) shown in right panel.8-26

    Executive Summary Introduction On January 20, 2021, President Biden signed E.O. 13990, "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis" (86 FR 7037; January 25, 2021). The executive order instructs EPA, inter alia, to review the 2020 final action titled, "National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units - Reconsideration of Supplemental Finding and Residual Risk and Technology Review" (85 FR 31286; May 22, 2020) (2020 Final Action) and to consider publishing a notice of proposed rulemaking suspending, revising, or rescinding that action. The 2020 Final Action included a finding that it is not appropriate and necessary to regulate coal and oil-fired electric utility steam generating units (EGUs) under Clean Air Act (CAA) section 112 as well as the RTR for the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired EGUs, commonly referred to, including within this document, as the Mercury and Air Toxics Standards (MATS). The results of EPA's review of the appropriate and necessary finding were proposed on February 9, 2022 (87 FR 7624) (2022 Proposal). This RIA presents the expected economic consequences of EPA's proposed MATS Risk and Technology Review. In accordance with E.O. 12866 and 13563, the guidelines of OMB Circular A-4 and EPA's Guidelines for Preparing Economic Analyses (U.S. EPA, 2014), the RIA analyzes the benefits and costs associated with the projected emissions reductions under the proposed requirements, a less stringent set of requirements, and a more stringent set of requirements to inform the EPA and the public about these projected impacts. The benefits and costs of the proposed rule and regulatory alternatives are presented for the 2028 to 2037 time period.  This proposed rule is projected to reduce emissions of mercury and non-mercury metal HAP at a national level. Mercury emitted from U.S. EGUs can deposit to watersheds and associated waterbodies where it can accumulate as methylmercury (MeHg) in fish. MeHg is known to adversely impact neurological function and development and to exert some genotoxic activity and EPA has classified MeHg as a "possible" human carcinogen. Reductions in methylmercury fish burden and human exposure reduces the potential for these adverse effects. In addition, U.S. EGUs are a major source of non-mercury metallic HAP emissions The proposed controls are expected to reduce human exposure to non-Hg metallic HAPs and therefore reduce the potential for adverse effects, including cancer.  Regulatory Requirements For coal-fired EGUs, the MATS rule established standards to limit emissions of mercury, acid gas HAP, non-mercury HAP metals (e.g., nickel, lead, chromium), and organic HAP (e.g., formaldehyde, dioxin/furan). 77 FR 9310. Standards for hydrochloric acid (HCl) serve as a surrogate for the acid gas HAP, with an alternate standard for sulfur dioxide (SO2) that may be used as a surrogate for acid gas HAP for those coal-fired EGUs with flue gas desulfurization (FGD) systems and SO2 continuous emission monitoring systems (CEMS) installed and operational. Standards for filterable particulate matter serve as a surrogate for the non-mercury HAP metals, with standards for total non-mercury HAP metals and individual non-mercury HAP metals provided as alternative equivalent standards. Work practice standards limit formation and emission of the organic HAP. For oil-fired EGUs, the rule established standards to limit emissions of HCl and hydrogen fluoride (HF), total HAP metals (e.g., mercury, nickel, lead), and organic HAP (e.g., formaldehyde, dioxin/furan). Standards for PM serve as a surrogate for total HAP metals, with standards for total HAP metals and individual HAP metals provided as alternative equivalent standards. Work practice standards limit formation and emission of the organic HAP. While more detail can be found in the preamble of the proposed rule and in Section 1.3.1 of this document, this RIA focuses on evaluating the benefits, costs and other impacts of four proposed amendments to the MATS rule, as follows: Tightening the Standard for Non-Hg Metal HAP Emissions for Existing Coal-fired EGUs: Existing coal-fired EGUs are subject to numeric emission limits for filterable PM, a surrogate for the total non-Hg HAP metals. MATS currently requires existing coal-fired EGUs to meet a filterable particulate matter emission standard of 0.030 pounds per million British thermal units (lb/MMBtu) of heat input. After reviewing updated information on the current emission levels of filterable PM from existing coal-fired EGUs and the costs of meeting a standard more stringent than 0.030 lb/MMBtu, EPA is proposing to revise the filterable PM emission standard for existing coal-fired EGUs to 0.010 lb/MMBtu. EPA also solicits comment on requiring existing coal-fired EGUs to meet a filterable PM standard of 0.006 lb/MMBtu.  Mercury Emission Standard for Lignite-fired EGUs: EPA is also proposing to revise the mercury emission standard for existing lignite-fired EGUs. Currently, lignite-fired EGUs must meet a mercury emission standard of 4.0 pounds per trillion British thermal units (lb/TBtu) or 4.0E-2 pounds per gigawatt hour (lb/GWh). EPA is proposing that lignite-fired EGUs meet the same standard as existing EGUs firing other types of coal, 1.2 lb/TBtu or 1.3E-2 lb/GWh.  Continuous Emissions Monitoring Systems: After considering updated information on the costs for performance testing compared to the cost of CEMS and capabilities of PM CEMS measurement abilities, as well as the benefits of using PM CEMS, which include increased transparency and accelerated identification of anomalous emissions, EPA is proposing to require that all coal-fired EGUs demonstrate compliance with the PM emission standard by using PM CEMS. Currently EGUs have a choice of demonstrating compliance with the non-mercury HAP metals by monitoring filterable PM with quarterly sampling or CEMS.  Startup Definitions: EPA is proposing to remove one of the two options for defining the startup period for EGUs. The first option defines startup as either the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. In the second option, startup is defined as the period in which operation of an EGU is initiated for any purpose. EPA is proposing to remove the second option, which is currently being used by fewer than 10 EGUs.        Table 01 summarizes how we have structured the regulatory options to be analyzed in this RIA. The proposed regulatory option includes the proposed amendments just discussed in this section: the proposed revision to the filterable PM standard to 0.010 lb/MMBtu, in which PM is a surrogate for non-mercury metal HAP, the proposed revision to the mercury standard for lignite-fired EGUs to 1.2 lb/TBtu, the proposal to require CEMS to demonstrate compliance, and the removal of the startup definition number two. The more stringent regulatory option examined in this RIA tightens the proposed revision to the filterable PM standard to 0.006 lb/MMBtu. Note EPA is soliciting comment on this more stringent filterable PM standard. The other three proposed amendments are not changed in the more stringent regulatory option examined in this RIA. Finally, the less stringent regulatory option examined in this RIA assumed the filterable PM and mercury limits remain unchanged and examines just the proposed CEMS requirement and removal of startup definition number two.  Table 01Summary of Proposed Regulatory Options Examined in this RIA    Regulatory Options Examined in this RIA Provision Less Stringent Proposed More Stringent Filterable PM Standard (Surrogate Standard for Non-Hg metal HAP) Retain existing filterable PM standard of 0.030 lb/MMBtu Revised filterable PM standard of 0.010 lb/MMBtu Revised filterable PM standard of 0.006 lb/MMBtu Mercury Standard Retain mercury standard for lignite-fired EGUs of 4.0 lb/TBtu  Revised mercury standard for lignite-fired EGUs of 1.2 lb/TBtu Revised mercury standard for lignite-fired EGUs of 1.2 lb/TBtu Continuous Emissions Monitoring Systems (CEMS) Require installation of PM CEMS to demonstrate compliance Require installation of PM CEMS to demonstrate compliance Require installation of PM CEMS to demonstrate compliance Startup definition Remove startup definition #2 Remove startup definition #2 Remove startup definition #2

Baseline and Analysis Years The impacts of proposed regulatory actions are evaluated relative to a modeled baseline that represents expected behavior in the electricity sector under market and regulatory conditions in the absence of a regulatory action. EPA frequently updates the power sector modeling baseline to reflect the latest available electricity demand forecasts from the U.S. Energy Information Administration (EIA) as well as expected costs and availability of new and existing generating resources, fuels, emission control technologies, and regulatory requirements. The baseline includes the proposed Good Neighbor Plan (GNP), the Revised Cross-State Air Pollution Rule (CSAPR) Update, CSAPR Update, and CSAPR, as well as the Mercury and Air Toxics Standards. The power sector baseline also includes the 2015 Effluent Limitation Guidelines (ELG) and the 2015 Coal Combustion Residuals (CCR), and the recently finalized 2020 ELG and CCR rules. This version of the model ("EPA's Post-IRA IPM 2022 Reference Case") also includes recent updates to state and federal legislation affecting the power sector, including Public Law 117-169, 136 Stat. 1818 (August 16, 2022), commonly known as the Inflation Reduction Act of 2022 (IRA). The modeling documentation, available in the docket, includes a summary of all legislation reflected in this version of the model as well as a description of how that legislation is implemented in the model. Also, see Section 3.3 for additional detail about the power sector baseline for this RIA. All analysis begins in the year 2028, the compliance year for the proposed standards. In addition, the regulatory impacts are evaluated for the specific analysis years of 2030 and 2035. These results are used to estimate the present value (PV) and equivalent annualized value (EAV) of the 2028 through 2037 period, discounted to 2023. Emissions Impacts The emissions reductions presented in this RIA are from years 2028, 2030, and 2035 and are based on IPM projections. Table 02 presents the estimated impact on power sector emissions resulting from compliance with the evaluated regulatory control alternatives in the contiguous U.S. As the incremental cost of requiring CEMS is negative and small relative to other aspects of this proposed rulemaking, the less stringent regulatory alternative was not modeled using IPM. The projections indicate that both the proposed rule and the more stringent alternative result in emissions reductions in all run years, and those emission reductions follow an expected pattern: the proposed rule, which revises the filterable PM standard to 0.010 lb/MMBtu, produces smaller emissions reductions than the more stringent alternative, which evaluates a lower filterable PM standard to limit of 0.006 lb/MMBtu. The additional reductions of mercury emissions in the more stringent alternative are largely attributable to the additional projected coal steam retirements in this scenario. Table 02Projected EGU Emissions and Emissions Changes for the Baseline and the Regulatory Control Alternatives for 2028, 2030, and 2035 a

Total Emissions Change from Baseline

Year Baseline  Run Proposed Rule More-Stringent Alternative Proposed Rule More-Stringent Alternative Mercury (lbs.) 2028 5,019 4,957 4,811 -62 -208

2030 4,206 4,139 4,037 -67 -169

2035 3,219 3,137 3,052 -82 -168 PM2.5 (thousand tons) 2028 74.6 74.2 72 -0.4 -2.6

2030 65.5 65.1 64 -0.4 -1.5

2035 46.6 45.8 45.3 -0.8 -1.3 SO2 (thousand tons) 2028 394 393 382 -0.9 -11.6

2030 282 282 282 -0.5 -0.3

2035 130 128 121 -1.5 -8.8 Ozone-season NOX (thousand tons) 2028 195 195 188 -0.2 -7.2

2030 163 163 158 -0.4 -5.1

2035 104 101 99 -3.2 -5.6 Annual NOX (thousand tons) 2028 457 456 439 -0.4 -18.1

2030 368 367 358 -0.8 -9.5

2035 214 211 205 -3.4 -8.7 HCl (million tons) 2028 2.6 2.6 2.5 0.0 -0.2

2030 1.8 1.8 1.7 0.0 -0.1

2035 0.9 0.9 0.8 0.0 -0.1 CO2 (million metric tons) 2028 1222 1222 1200 -0.2 -21.9

2030 972 971 963 -0.8 -8.7

2035 608 604 605 -4.6 -2.9  a This analysis is limited to the geographically contiguous lower 48 states.

Compliance Costs  The baseline includes approximately 7 GW of operational EGU capacity designed to burn low rank virgin coal (i.e. lignite) in 2028. All of this capacity is currently equipped with Activated Carbon Injection (ACI) technology, which is designed to reduce mercury emissions, and operation of this technology for compliance with existing mercury emissions limits (e.g., MATS and other enforceable state regulations) is reflected in the baseline. In the proposed and more stringent modeling scenarios, each of these EGUs projected to consume lignite is assigned an additional variable operating cost that is consistent with improvements in sorbent that EPA assumes is necessary to achieve the lower proposed limit.. In the proposed option, this additional cost does not result in incremental retirements for these units, nor does it result in a significant change to the projected generation level for these units. In 2028, the baseline projection also includes 4.8 GW of operational coal capacity that, based on the analysis documented in the EPA memorandum titled: "2023 Technology Review for the Coal- and Oil-Fired EGU Source Category" EPA assumes would either need to improve existing PM controls or install new PM controls to comply with the proposed option. The vast majority of that 4.8 GW is currently operating existing electrostatic precipitators (ESPs) and/or fabric filters, and nearly all of that capacity is projected to install control upgrades and remain operational in 2028. About 500 MW of that coal steam capacity is projected to retire in response to the proposed rule. Under the more stringent alternative, EPA assumes that 22.7 GW of capacity that is projected to be operational in the baseline in 2028 would need to take some compliance action in order to meet the proposed standards. About half of that capacity (11.3 GW) is projected to remain operational with the installation of PM control upgrades in 2028. Table 03 below summarizes the PV and EAV of the total national compliance cost estimates for EGUs for the proposed rule and the less and more stringent alternatives. We present the PV of the costs over the 10-year period of 2028 to 2037. We also present the EAV, which represents a flow of constant annual values that, had they occurred annually, would yield a sum equivalent to the PV. The EAV represents the value of a typical cost for each year of the analysis. These compliance cost estimates are used as a proxy for the social cost of the rule. Section 4 reports how annual power costs are projected to change over the time period of analysis.  Table 03Total National Compliance Cost Estimates for the Proposed Rule and the Less and More Stringent Alternatives (discounted to 2023, millions of 2019 dollars)   3  Discount Rate 7% Discount Rate Regulatory Option PV EAV PV EAV Proposed 320 37 230 33 Less Stringent  -53 -6.2 -37 -5.3 More Stringent 4,600 540 3,400 490 Note: Values have been rounded to two significant figures. Benefits Health Benefits Hazardous Air Pollutants This proposed rule is projected to reduce emissions of mercury and non-mercury metal HAP at a national level. Mercury emitted from U.S. EGUs can deposit to watersheds and associated waterbodies where it can accumulate as MeHg in fish. MeHg is formed by microbial action in the top layers of sediment and soils, after mercury has precipitated from the air and deposited into waterbodies or land. Once formed, MeHg is taken up by aquatic organisms and bioaccumulates up the aquatic food web. Methylmercury in fish, originating from U.S. EGUs, is consumed both as self-caught fish by subsistence fishers and as commercial fish by the general population. Exposure to MeHg is known to have adverse impacts on neurodevelopment and the cardiovascular system. MeHg is known to exert some genotoxic activity and EPA has classified MeHg as a "possible" human carcinogen. Reductions in mercury emission from EGUs is anticipated to reduce methylmercury fish burden and human exposure, which is anticipated to reduce the potential for these adverse effects.   In addition, U.S. EGUs are a major source of metallic HAP emissions including selenium (Se), arsenic (As), chromium (Cr), nickel (Ni), and cobalt (Co), cadmium (Cd), beryllium (Be), lead (Pb), and manganese (Mn). Some metal HAPs emitted by U.S. EGUs are known to be persistent and bioaccumulative and others have the potential to cause cancer. Exposure to these metal HAPs, depending on exposure duration and levels of exposures, is associated with a variety of adverse health effects. The proposed controls are expected to reduce human exposure to non-Hg metallic HAPs and therefore reduce the potential for adverse effects, including cancer.  The projected reductions in mercury under this proposed rule are expected to reduce the bioconcentration of MeHg in fish. In 2020, EPA examined risk to subsistence fishers from MeHg exposure at a lake near three U.S. EGU lignite-fired facilities. The results of this site-specific analysis suggest that exposure to MeHg from lignite-fired facilities falls well below the current health benchmark for adverse effects (U.S. EPA, 2020). However, while exposure to MeHg from lignite-fired facilities may be well below the health benchmark, subsistence fishers may still experience MeHg exposures that are elevated relative to  the general population. Subsistence fishing is associated with vulnerable populations, including minorities and those of low socioeconomic status. Further, the projected reductions in non-mercury metal HAP from the use of PM controls are expected to help EPA reduce exposure to carcinogenic HAP.  Criteria Pollutants This rule is expected to reduce emissions of direct PM2.5, NOX and SO2 throughout the year. Because NOX and SO2 are also precursors to secondary formation of ambient PM2.5, reducing these emissions would reduce human exposure to ambient PM2.5 throughout the year and would reduce the incidence of PM2.5-attributable health effects. This proposed rule is expected to reduce ozone season NOX emissions. In the presence of sunlight, NOX and volatile organic compounds (VOCs) can undergo a chemical reaction in the atmosphere to form ozone. Reducing NOX emissions generally reduces human exposure to ozone and the incidence of ozone-related health effects, though the degree to which ozone is reduced will depend in part on local concentration levels of VOCs.  In this RIA, EPA reports estimates of the health benefits of changes in PM2.5 and ozone concentrations. The health effect endpoints, effect estimates, benefit unit-values, and how they were selected, are described in the Technical Support Document (TSD) titled Estimating PM2.5- and Ozone-Attributable Health Benefits (U.S. EPA, 2023). This document, hereafter referred to as the "Health Benefits TSD," can be found in the docket for this rulemaking. Our approach for updating the endpoints and to identify suitable epidemiologic studies, baseline incidence rates, population demographics, and valuation estimates is summarized in Section 4.3. Climate Benefits Elevated concentrations of GHGs in the atmosphere have been warming the planet, leading to changes in the Earth's climate including changes in the frequency and intensity of heat waves, precipitation, and extreme weather events, rising seas, and retreating snow and ice. The well-documented atmospheric changes due to anthropogenic GHG emissions are changing the climate at a pace and in a way that threatens human health, society, and the natural environment. Climate change touches nearly every aspect of public welfare in the U.S. with resulting economic costs, including: changes in water supply and quality due to changes in drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; and the potential for significant agricultural disruptions and crop failures (though offset to some extent by carbon fertilization).  There will be important climate benefits associated with the CO2 emissions reductions expected from this proposed rule. Climate benefits from reducing emissions of CO2 can be monetized using estimates of the social cost of carbon (SC-CO2). See Section 4.4 for more discussion of the approach to monetization of the climate benefits associated with this rule.  Additional Unquantified Benefits       Data, time, and resource limitations prevented EPA from quantifying the estimated health impacts or monetizing estimated benefits associated with direct exposure to HAPs or NO2 and SO2 (independent of the role NO2 and SO2 play as precursors to PM2.5 and ozone), as well as ecosystem effects, and visibility impairment due to the absence of air quality modeling data for these pollutants in this analysis. While all health benefits and welfare benefits were not able to be quantified, it does not imply that there are not additional benefits associated with reductions in exposures to HAPs, ozone, PM2.5, NO2 or SO2. For a qualitative description of these and potential water quality benefits, please see Sections 4.2.3 and 4.5.  Total Health and Climate Benefits Table 04 presents the total monetized health and climate benefits for the proposed rule and the more and less stringent alternatives. Table 04Monetized Health Benefits and Climate Benefits for the Proposed Rule from 2028 through 2037 (millions of 2019 dollars)a

All Benefits Calculated using 3% Discount Rate

PM2.5 and O3-related Health Benefits b Climate Benefits c Total Benefits d,e Regulatory Option PV EAV PV EAV PV EAV Proposed 1,900 220 1,400 170 3,300 390 Less Stringent 0.0 0.0 0.0 0.0 0.0 0.0 More Stringent 11,000 1,300 3,200 380 14,000 1,700

Health Benefits Calculated using 7% Discount Rate,  Climate Benefits Calculated using 3% Discount Rate

Regulatory Option PM2.5 and O3-related Health Benefits b Climate Benefits c Total Benefits d,e Proposed 1,200 170 1,400 170 330 330 Less Stringent 0.0 0.0 0.0 0.0 0.0 0.0 More Stringent 7,100 1,000 3,200 380 10,000 1,400 a Values have been rounded to two significant figures. Rows may not appear to add correctly due to rounding. b For simplicity of presentation, the estimated value of the health benefits reported here are the larger of the two benefits estimates presented in Table 71, Table 72, and Table 73. Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The health benefits are associated with several point estimates. c Climate benefits in this table are based on estimates of the SC-CO2 at a 3 percent discount rate. d Several categories of benefits remain unmonetized and are thus not reflected in the table. Nonmonetized benefits include important benefits from reductions in mercury and non-mercury metal HAP. e For discussions of the uncertainty associated with these health benefits estimates, see Section 4.3.8. See Section 4.4 for a discussion of th3 uncertainties associated with the climate benefit estimates. Environmental Justice Impacts Environmental justice (EJ) concerns for each rulemaking are unique and should be considered on a case-by-case basis, and EPA's EJ Technical Guidance (2015) states that "[t]he analysis of potential EJ concerns for regulatory actions should address three questions:  Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern in the baseline?  Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern for the regulatory option(s) under consideration?  For the regulatory option(s) under consideration, are potential EJ concerns created or mitigated compared to the baseline?"  To address these questions, EPA developed an analytical approach that considers the purpose and specifics of the rulemaking, as well as the nature of known and potential exposures and impacts. For the rule, we quantitatively evaluate 1) the proximity of affected facilities to potentially vulnerable and/or overburdened populations for consideration of local pollutants impacted by this rule but not modeled here (Section 6.3) and 2) the distribution of ozone and PM2.5 concentrations in the baseline and changes due to the proposed rulemaking across different demographic groups on the basis of race, ethnicity, poverty status, employment status, health insurance status, age, sex, educational attainment, and degree of linguistic isolation (Section 6.5). We also qualitatively discuss potential EJ HAP and climate impacts. Each of these analyses depends on mutually exclusive assumptions, was performed to answer separate questions, and is associated with unique limitations and uncertainties.  Baseline demographic proximity analyses provide information as to whether there may be potential EJ concerns associated with environmental stressors, such as local HAP, NO2, and SO2 emitted from sources affected by the regulatory action for certain population groups of concern (Section 6.3). The baseline demographic proximity analyses examined the demographics of populations living within 10 km of the following sources: lignite plants with units potentially subject to the proposed mercury standard revision, coal plants with units potentially subject to the proposed filterable PM standard revision, and coal plants with units potentially subject to the alternate filterable PM standard revision. The baseline analysis indicates that on average the percentage of the population living within 10 km of coal plants potentially subject to the proposed or alternate filterable PM standards have a higher percentage of people living below two times the poverty level than the national average. In addition, on average the percentage of the Native American population living within 10 km of lignite plants potentially subject to proposed mercury standard is higher than the national average. Relating these results to question 1, above, we conclude that there may be potential EJ concerns associated with directly emitted pollutants that are affected by the regulatory action (e.g., NO2) for certain population groups of concern in the baseline. However, as proximity to affected facilities does not capture variation in baseline exposure across communities, nor does it indicate that any exposures or impacts will occur, these results should not be interpreted as a direct measure of exposure or impact.  Because the pollution impacts that are the focus of this rule may occur downwind from affected facilities, ozone and PM2.5 exposure analyses that evaluate demographic variables are better able to evaluate any potentially disproportionate pollution impacts of this rulemaking. The baseline ozone and PM2.5 exposure analyses respond to question 1 from EPA's EJ Technical Guidance document more directly than the proximity analyses, as they evaluate a form of the environmental stressor primarily affected by the regulatory action (see Section 6.5). Baseline ozone and PM2.5 exposure analyses show that certain populations, such as Hispanics, Asians, those linguistically isolated, those less educated, and children may experience disproportionately higher ozone and PM2.5 exposures as compared to the national average. American Indians may also experience disproportionately higher ozone concentrations than the reference group. Therefore, there likely are potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern in the baseline. Finally, we evaluate how post-policy regulatory alternatives of this proposed rulemaking are expected to differentially impact demographic populations, informing questions 2 and 3 from EPA's EJ Technical Guidance with regard to ozone and PM2.5 exposure changes. We infer that disparities in the ozone and PM2.5 concentration burdens are likely to remain after implementation of the regulatory action or alternatives under consideration. This is due to the small magnitude of the concentration changes associated with this rulemaking across population demographic groups, relative to the magnitude of the baseline disparities (question 2). Also, due to the very small differences observed in the distributional analyses of post-policy ozone and PM2.5 exposure impacts, we do not find evidence that potential EJ concerns related to ozone and PM2.5 concentrations will be created or mitigated as compared to the baseline (question 3). Comparison of Benefits and Costs All benefits analyses, and most cost analyses, begin in the year 2028, the compliance year for the proposed standards. In this RIA, the regulatory impacts are evaluated for the specific years of 2028, 2030, and 2035. Comparisons of benefits to costs for these snapshot years are presented in Section 7.3 of this RIA. Here we present the PV of costs, benefits, and net benefits, calculated for the years 2028 to 2037 from the perspective of 2023, using both a three percent and seven percent end-of-period discount rate as directed by OMB's Circular A-4. All dollars are in 2019 dollars. We also present the EAV, which represents a flow of constant annual values that, had they occurred in each year from 2028 to 2037, would yield a sum equivalent to the PV. The EAV represents the value of a typical cost or benefit for each year of the analysis, in contrast to the year-specific estimates reported in the costs and benefits sections of this RIA. The comparison of benefits and costs in PV and EAV terms for the proposed rule and less and more stringent regulatory options can be found in Table 05. Estimates in the tables are presented as rounded values. Table 05Monetized Benefits, Costs, and Net Benefits of the Proposed Rule and Less and More Stringent Alternatives (millions of 2019 dollars, discounted to 2023) a,b   Values Calculated using 3% Discount Rate

PM2.5 and O3-related Health Benefits b Climate  Benefits c Compliance Costs Net  Benefits d Regulatory Option PV EAV PV EAV PV EAV PV EAV Proposed 1,900 220 1,400 170 320 37 3,000 350 Less Stringent  0.0 0.0 0.0 0.0 -53 -6.2 53 6.2 More Stringent 11,000 1,300 3,200 380 4,600 540 9,800 1,100

Health Benefits Calculated using 7% Discount Rate,  Climate Benefits Calculated using 3% Discount Rate

PM2.5 and O3-related Health Benefits b Climate  Benefits c Compliance Costs Net  Benefits d Regulatory Option PV EAV PV EAV PV EAV PV EAV Proposed 1,200 170 1,400 170 230 33 2,400 300 Less Stringent  0.0 0.0 0.0 0.0 -37 -5.3 37 5.3 More Stringent 7,100 1,000 3,200 380 3,400 490 6,900 910 a Values have been rounded to two significant figures. Rows may not appear to add correctly due to rounding. b The health benefits estimates use the larger of the two benefits estimates presented in Table 71, Table 72, and Table 73. Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The health benefits are associated with several point estimates. c Climate benefits in this table are based on estimates of the SC-CO2 at a 3 percent discount rate. d Several categories of benefits remain unmonetized and are thus not reflected in the table. Nonmonetized benefits include important benefits from reductions in mercury and non-mercury metal HAP.

The results presented in this section provide an incomplete overview of the effects of the proposal, because important categories of benefits, including health and environmental benefits from reducing mercury and non-mercury metal HAP emissions and the increased transparency and accelerated identification of anomalous emission anticipated from requiring CEMS, were not monetized and are therefore not directly reflected in the quantified benefit-cost comparisons. We anticipate that taking non-monetized effects into account would show the proposal to be more net beneficial than the tables in this section reflect. References U.S. EPA. (2015). Guidance on Considering Environmental Justice During the Development of Regulatory Actions.  Retrieved from Available at: https://www.epa.gov/sites/default/files/2015-06/documents/considering-ej-in-rulemaking-guide-final.pdf U.S. EPA. (2019). Integrated Science Assessment (ISA) for Particulate Matter (Final Report). (EPA/600/R-19/188). Research Triangle Park, NC: U.S. Environmental Protection Agency, Office of Research and Development, Center for Public Health and Environmental Assessment Retrieved from Available at: https://www.epa.gov/naaqs/particulate-matter-pm-standards-integrated-science-assessments-current-review U.S. EPA. (2020a). Integrated Science Assessment for Ozone and Related Photochemical Oxidants (Final Report). (EPA/600/R-20/012). Washington, DC: U.S. Environmental Protection Agency Retrieved from Available at: https://www.epa.gov/isa/integrated-science-assessment-isa-ozone-and-related-photochemical-oxidants U.S. EPA. (2020b). Residual Risk Assessment for the Coal- and Oil-Fired EGU Source Category in Support of the 2020 Risk and Technology Review Final Rule Research Triangle Park, NC: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards Retrieved from Available at: https://www.regulations.gov/document/EPA-HQ-OAR-2018-0794-4553 U.S. EPA. (2023). Estimating PM2.5- and Ozone-Attributable Health Benefits. Research Triangle Park, NC: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Health and Environmental Impact Division Retrieved from Available at: https://www.regulations.gov/docket/EPA-HQ-OAR-2018-0794 U.S. EPA Science Advisory Board. (2022a). CASAC Review of the EPA's Policy Assessment for the Reconsideration of the National Ambient Air Quality Standards for Ozone. (EPA-CASAC-20-003). Research Triangle Park, NC: U.S. Environmental Protection Agency, Retrieved from Available at: https://casac.epa.gov/ords/sab/f?p=113:0:9137724054278:APPLICATION_PROCESS=REPORT_DOC:::REPORT_ID:1075 U.S. EPA Science Advisory Board. (2022b). CASAC Review of the EPA's Policy Assessment for the Reconsideration of the National Ambient Air Quality Standards for Particulate Matter (External Review Draft  -  October 2021). (EPA-CASAC-22-002). Research Triangle Park, NC: U.S. Environmental Protection Agency, Retrieved from Available at: https://casac.epa.gov/ords/sab/f?p=113:12:1342972375271:::12

    Introduction and Background Introduction On January 20, 2021, President Biden signed E.O. 13990, "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis" (86 FR 7037; January 25, 2021). The executive order instructs EPA, among other things, to review the 2020 final action titled, "National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units - Reconsideration of Supplemental Finding and Residual Risk and Technology Review" (85 FR 31286; May 22, 2020) (2020 Final Action) and to consider publishing a notice of proposed rulemaking suspending, revising, or rescinding that action. The 2020 Final Action included a finding that it is not appropriate and necessary to regulate coal and oil-fired EGUs under CAA section 112 as well as the RTR for the MATS rule. The results of EPA's review of the appropriate and necessary finding were proposed on February 9, 2022 (87 FR 7624) (2022 Proposal). This action presents the proposed results of EPA's review of the MATS RTR, as directed by E.O. 13990.  Several statutes and executive orders apply to federal rulemakings. In accordance with E.O. 12866 and E.O. 13563 and the guidelines of OMB Circular A-4, the RIA analyzes the benefits and costs associated with the projected emissions reductions under the proposed rule. OMB Circular A-4 requires analysis of one potential regulatory option more stringent and one less stringent than the rule under examination, so this RIA evaluates the benefits, costs, and impacts of a more and a less stringent alternative to the selected alternative in this proposal. The benefits and costs of the proposed rule and regulatory alternatives are presented for the 2028 to 2037 time period. The estimated monetized benefits are those health benefits expected to arise from reduced PM2.5 and ozone concentrations and the climate benefits from reductions in GHGs. Several categories of benefits remain unmonetized including important benefits from reductions in mercury and non-mercury metal HAP emissions. The estimated monetized costs for EGUs are the costs of installing and operating controls and the increased costs of producing electricity. Unquantified benefits and costs are described qualitatively. This section contains background information relevant to the rule and an outline of the sections of this RIA. Legal and Economic Basis for Rulemaking In this section, we summarize the statutory requirements in the CAA that serve as the legal basis for the proposed rule and the economic theory that supports environmental regulation as a mechanism to enhance social welfare. The CAA requires EPA to prescribe regulations for new and existing sources. In turn, those regulations attempt to address negative externalities created when private entities fail to internalize the social costs of air pollution. Statutory Requirement The statutory authority for this action is provided by sections 112 and 301 of the CAA, as amended (42 U.S.C. 7401 et seq.). Section 112 of the CAA establishes a two-stage regulatory process to develop standards for emissions of HAP from stationary sources. Generally, the first stage involves establishing technology-based standards and the second stage involves evaluating those standards that are based on maximum achievable control technology (MACT) to determine whether additional standards are needed to address any remaining risk associated with HAP emissions. This second stage is commonly referred to as the "residual risk review." In addition to the residual risk review, the CAA also requires EPA to review standards set under CAA section 112 no less than every eight years and revise the standards as necessary taking into account any "developments in practices, processes, or control technologies." This review is commonly referred to as the "technology review," and is the subject of this proposal.  Regulated Pollutants For coal-fired EGUs, the 2012 MATS rule established standards to limit emissions of mercury, acid gas HAP, non-mercury HAP metals (e.g., nickel, lead, chromium), and organic HAP (e.g., formaldehyde, dioxin/furan). Standards for hydrochloric acid (HCl) serve as a surrogate for the acid gas HAP, with an alternate standard for sulfur dioxide (SO2) that may be used as a surrogate for acid gas HAP for those coal-fired EGUs with flue gas desulfurization (FGD) systems and SO2 CEMS installed and operational. Standards for filterable particulate matter serve as a surrogate for the non-mercury HAP metals, with standards for total non-mercury HAP metals and individual non-mercury HAP metals provided as alternative equivalent standards. Work practice standards limit formation and emission of the organic HAP. For oil-fired EGUs, the 2012 MATS rule establishes standards to limit emissions of HCl and hydrogen fluoride (HF), total HAP metals (e.g., mercury, nickel, lead), and organic HAP (e.g., formaldehyde, dioxin/furan). Standards for filterable PM serve as a surrogate for total HAP metals, with standards for total HAP metals and individual HAP metals provided as alternative equivalent standards. Work practice standards limit formation and emission of the organic HAP. Definition of Affected Source The source category that is the subject of this proposal is Coal- and Oil-Fired EGUs regulated under 40 CFR 63, subpart UUUUU. The North American Industry Classification System (NAICS) codes for the Coal- and Oil-fired EGU industry are 221112, 221122, and 921150. This list of categories and NAICS codes is not intended to be exhaustive, but rather provides a guide for readers regarding the entities that this proposed action is likely to affect. The proposed standards, once promulgated, will be directly applicable to the affected sources. Federal, state, local, and tribal government entities that own and/or operate EGUs subject to 40 CFR part 63, subpart UUUUU would be affected by this proposed action. The Coal- and Oil-Fired EGU source category was added to the list of categories of major and area sources of HAP published under section 112(c) of the CAA on December 20, 2000 (65 FR 79825). CAA section 112(a)(8) defines an EGU as: any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale is also considered an EGU. The Need for Air Emissions Regulation OMB Circular A-4 indicates that one of the reasons a regulation may be issued is to address a market failure. The major types of market failure include externalities, market power, and inadequate or asymmetric information. Correcting market failures is one reason for regulation; it is not the only reason. Other possible justifications include improving the function of government, correcting distributional unfairness, or securing privacy or personal freedom. Environmental problems are classic examples of externalities  -  uncompensated benefits or costs imposed on another party as a result of one's actions. For example, the smoke from a factory may adversely affect the health of local residents and soil the property in nearby neighborhoods. For the proposed regulatory action analyzed in this RIA, the good produced is electricity from coal- and oil-fired EGUs. If these electricity producers pollute the atmosphere when generating power, the social costs will not be borne exclusively by the polluting firm but rather by society as a whole. Thus, the producer is imposing a negative externality, or a social cost of emissions, on society. The equilibrium market price of electricity may fail to incorporate the full opportunity cost to society of these products. Consequently, absent a regulation on emissions, producers will not internalize the social cost of emissions and social costs will be higher as a result. The proposed regulation will work towards addressing this market failure by causing affected producers to begin internalizing the negative externality associated with HAP emissions from electricity generation by coal- and oil-fired EGUs. Overview of Regulatory Impact Analysis Regulatory Options This RIA focuses on four proposed amendments to the MATS rule, which are described in more detail in this section. We vary these four proposed requirements in order to craft a set of three regulatory options to be analyzed in this RIA. Filterable Particulate Matter Standards for Existing Coal-fired EGUs Existing coal-fired EGUs are subject to numeric emission limits for filterable PM, a surrogate for the total non-Hg HAP metals. MATS currently requires existing coal-fired EGUs to meet a filterable particulate matter emission standard of 0.030 pounds per million British thermal units (lb/MMBtu) of heat input. The standards for filterable PM serve as a surrogate for standards for non-Hg HAP metals. After reviewing updated information on the current emission levels of filterable PM from existing coal-fired EGUs and the costs of meeting a standard more stringent than 0.030 lb/MMBtu, EPA is proposing to revise the filterable PM emission standard for existing coal-fired EGUs to 0.010 lb/MMBtu. EPA also solicits comment on requiring existing coal-fired EGUs to meet a filterable PM standard of 0.006 lb/MMBtu. Mercury Emission Standard for Lignite-fired EGUs EPA is also proposing to revise the mercury emission standard for lignite-fired EGUs. Currently, lignite-fired EGUs must meet a mercury emission standard of 4.0 pounds per trillion British thermal units (lb/TBtu) or 4.0E-2 pounds per gigawatt hour (lb/GWh). EPA recently collected information on current emission levels and mercury emission controls for lignite-fired EGUs using the authority provided under CAA section 114. That information showed that many units are able to achieve a mercury emission rate that is much lower than the current standard, and there are cost-effective control technologies and methods of operation that are available to achieve a more stringent standard. EPA is proposing that lignite-fired EGUs meet the same standard as EGUs firing other types of coal, 1.2 lb/TBtu or 1.3E-2 lb/GWh.  Require that all coal-fired EGUs demonstrate compliance with the filterable PM emission standard by using PM CEMS. In addition to revising the PM emission standard for existing coal-fired EGUs, EPA is proposing a revision to the requirements for demonstrating compliance with the PM emission standard for coal-fired EGUs. Currently, EGUs that are not part of the low emitting EGU (LEE) program can demonstrate compliance with the filterable PM standard either by conducting performance testing quarterly or through the use of PM continuous emission monitoring systems (CEMS). After considering updated information on the costs for performance testing compared to the cost of CEMS and capabilities of PM CEMS measurement abilities, as well as the benefits of using PM CEMS, which include increased transparency and accelerated identification of anomalous emissions, EPA is proposing to require that all coal-fired EGUs demonstrate compliance with the PM emission standard by using PM CEMS. Startup Definitions Finally, EPA is proposing to remove one of the two options for defining the startup period for EGUs. The first option defines startup as either the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use). In the second option, startup is defined as the period in which operation of an EGU is initiated for any purpose. Startup begins with either the firing of any fuel in an EGU for the purpose of producing electricity or useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes (other than the first-ever firing of fuel in a boiler following construction of the boiler) or for any other purpose after a shutdown event. Startup ends four hours after the EGU generates electricity that is sold or used for any other purpose (including on-site use), or four hours after the EGU makes useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes, whichever is earlier. EPA is proposing to remove the second option, which is currently being used by fewer than 10 EGUs. Summary of Proposed Regulatory Options Examined in this RIA Table 1 summarizes how we have structured the regulatory options to be analyzed in this RIA. The proposed regulatory option includes the proposed amendments just discussed in this section: the proposed revision to the filterable PM standard to 0.010 lb/MMBtu, in which filterable PM is a surrogate for non-mercury metal HntitAP, the proposed revision to the mercury standard for lignite-fired EGUs to 1.2 lb/TBtu, the proposal to require CEMS to demonstrate compliance, and the removal of the startup definition number two. The more stringent regulatory option examined in this RIA tightens the proposed revision to the filterable PM standard to 0.006 lb/MMBtu. Note EPA is soliciting comment on this more stringent filterable PM standard. The other three proposed amendments are not changed in the more stringent regulatory option examined in this RIA. Finally, the less stringent regulatory option examined in this RIA assumed the PM and mercury limits remain unchanged and examines just the proposed CEMS requirement and removal of startup definition number two.

Table 11Summary of Proposed Regulatory Options Examined in this RIA    Regulatory Options Examined in this RIA Provision Less Stringent Proposed More Stringent Filterable PM Standard (Surrogate Standard for Non-Hg metal HAP) Retain existing filterable PM standard of 0.030 lb/MMBtu Revised filterable PM standard of 0.010 lb/MMBtu Revised filterable PM standard of 0.006 lb/MMBtu Mercury Standard Retain mercury standard for lignite-fired EGUs of 4.0 lb/TBtu  Revised mercury standard for lignite-fired EGUs of 1.2 lb/TBtu Revised mercury standard for lignite-fired EGUs of 1.2 lb/TBtu Continuous Emissions Monitoring Systems (CEMS) Require installation of PM CEMS to demonstrate compliance Require installation of PM CEMS to demonstrate compliance Require installation of PM CEMS to demonstrate compliance Startup definition Remove startup definition #2 Remove startup definition #2 Remove startup definition #2

Baseline and Analysis Years The impacts of proposed regulatory actions are evaluated relative to a baseline that represents the world without the proposed action. All benefit analysis, and most cost analysis, begins in the year 2028, the compliance year for the proposed standards. In addition, the regulatory impacts are evaluated for the specific analysis years of 2030 and 2035. These results are used to estimate the PV and EAV of the 2028 through 2037 period.  Organization of the Regulatory Impact Analysis This RIA is organized into the following remaining sections:  Section 2: Power Sector Profile. This section describes the electric power sector in detail. Section 3: Cost, Emissions, and Energy Impacts. The section summarizes the projected compliance costs and other energy impacts associated with the regulatory options.  Section 4: Benefits Analysis. The section presents the projected health and environmental benefits of reductions in emissions of HAP, direct PM2.5, and PM2.5 and ozone precursors and the climate benefits of CO2 emissions reductions across regulatory options. Potential benefits to drinking water quality and quantity are also discussed. Section 5: Economic Impacts. The section includes a discussion of potential small entity, economic, and labor impacts. Section 6: Environmental Justice Impacts. This section includes an assessment of potential impacts to potential EJ populations. Section 7: Comparison of Benefits and Costs. The section compares of the total projected benefits with total projected costs and summarizes the projected net benefits of the three regulatory options examined. The section also includes a discussion of potential benefits that EPA is unable to quantify and monetize.

    Industry Profile Background In the past decade there have been significant structural changes in both the mix of generating capacity and in the share of electricity generation supplied by different types of generation. These changes are the result of multiple factors in the power sector, including normal replacements of older generating units with new units, changes in the electricity intensity of the U.S. economy, growth and regional changes in the U.S. population, technological improvements in electricity generation from both existing and new units, changes in the prices and availability of different fuels, and substantial growth in electricity generation by renewable and unconventional methods. Many of these trends will continue to contribute to the evolution of the power sector. The evolving economics of the power sector, specifically the increased natural gas supply and subsequent relatively low natural gas prices, have resulted in more natural gas being used as base load energy in addition to supplying electricity during peak load. Additionally, rapid growth in the penetration of renewables has led to their now constituting a significant share of generation. This section presents data on the evolution of the power sector from 2014 through 2020. Projections of future power sector behavior and the impact of this proposed rule are discussed in more detail in Section 3 of this RIA. Power Sector Overview The production and delivery of electricity to customers consists of three distinct segments: generation, transmission, and distribution.  Generation Electricity generation is the first process in the delivery of electricity to consumers. There are two important aspects of electricity generation: capacity and net generation. Generating Capacity refers to the maximum amount of production an EGU is capable of producing in a typical hour, typically measured in megawatts (MW) for individual units, or gigawatts (1 GW = 1,000 MW) for multiple EGUs. Electricity Generation refers to the amount of electricity actually produced by an EGU over some period of time, measured in kilowatt-hours (kWh) or gigawatt-hours (1 GWh = 1 million kWh). Net Generation is the amount of electricity that is available to the grid from the EGU (i.e., excluding the amount of electricity generated but used within the generating station for operations). Electricity generation is most often reported as the total annual generation (or some other period, such as seasonal). In addition to producing electricity for sale to the grid, EGUs perform other services important to reliable electricity supply, such as providing backup generating capacity in the event of unexpected changes in demand or unexpected changes in the availability of other generators. Other important services provided by generators include facilitating the regulation of the voltage of supplied generation.  Individual EGUs are not used to generate electricity 100 percent of the time. Individual EGUs are periodically not needed to meet the regular daily and seasonal fluctuations of electricity demand. Furthermore, EGUs relying on renewable resources such as wind, sunlight and surface water to generate electricity are routinely constrained by the availability of adequate wind, sunlight, or water at different times of the day and season. Units are also unavailable during routine and unanticipated outages for maintenance. These factors result in the mix of generating capacity types available (e.g., the share of capacity of each type of EGU) being substantially different than the mix of the share of total electricity produced by each type of EGU in a given season or year. Most of the existing capacity generates electricity by creating heat to create high pressure steam that is released to rotate turbines which, in turn, create electricity. Natural gas combined cycle (NGCC) units have two generating components operating from a single source of heat. The first cycle is a gas-fired turbine, which generates electricity directly from the heat of burning natural gas. The second cycle reuses the waste heat from the first cycle to generate steam, which is then used to generate electricity from a steam turbine. Other EGUs generate electricity by using water or wind to rotate turbines, and a variety of other methods including direct photovoltaic generation also make up a small, but growing, share of the overall electricity supply. The generating capacity includes fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources (see Table 21). Table 21 also shows the comparison between the generating capacity over the 2015 to 2021 period. In 2021 the power sector comprised a total capacity of 1,179 GW, an increase of 105 GW (or 10 percent) from the capacity in 2015 (1,074 GW). The largest change over this period was the decline of 70 GW of coal capacity, reflecting the retirement/rerating of over a third of the coal fleet. This reduction in coal capacity was offset by an increase in natural gas capacity of 52 GW, and an increase in solar (48 GW) and wind (60 GW) capacity over the same period. Additionally, significant amounts of distributed solar (23 GW) were also added. Table 21Total Net Summer Electricity Generating Capacity by Energy Source, 2015 and 2021   2015 2021 Change Between '15 and '21 Energy Source Net Summer Capacity (GW) % Total Capacity Net Summer Capacity (GW) % Total Capacity % Increase Capacity Change (GW) Coal 280 26% 210 18% -25% -70 Natural Gas 439 41% 492 42% 12% 52 Nuclear 99 9% 96 8% -3% -3 Hydro 102 10% 103 9% 1% 1 Petroleum 37 3% 28 2% -23% -9 Wind 73 7% 133 11% 83% 60 Solar 14 1% 62 5% 350% 48 Distributed Solar 10 1% 33 3% 238% 23 Other Renewable 17 2% 15 1% -10% -2 Misc 4 0% 8 1% 91% 4 Total 1,074 100% 1,179 100% 10% 105 Note: This table presents generation capacity. Actual net generation is presented in Table 2-2. Source: EIA. Electric Power Annual 2022, Tables 4.2

In 2021, electric generating sources produced a net 4,157 trillion kWh (TWh) to meet national electricity demand, which was around 2 percent higher than 2015. As presented in Table 2, 59 percent of electricity in 2021 was produced through the combustion of fossil fuels, primarily coal and natural gas, with natural gas accounting for the largest single share. The total generation share from fossil fuels in 2021 (60 percent) was 11 percent less than the share in 2010 (69 percent). Moreover, the share of fossil generation supplied by coal fell from 65 percent in 2010 to 36 percent by 2021, while the share of fossil generation supplied by natural gas rose from 35 percent to 64 percent over the same period. In absolute terms, coal generation declined by 51 percent, while natural gas generation increased by 60 percent. This reflects both the increase in natural gas capacity during that period as well as an increase in the utilization of new and existing gas EGUs during that period. The combination of wind and solar generation also grew from 2 percent of the mix in 2010 to 13 percent in 2021. Table 22Net Generation in 2015 and 2021 (Trillion kWh = TWh)   2015 2021 Change Between '15 and '21 Energy Source Net Generation (TWh) Fuel Source Share Net Generation (TWh) Fuel Source Share % Increase Generation Change (TWh) Coal 1352 33% 898 22% -34% -455 Natural Gas 1333 33% 1579 38% 18% 246 Nuclear 797 19% 778 19% -2% -19 Hydro 244 6% 246 6% 1% 2 Petroleum 28 1% 19 0% -32% -9 Wind 191 5% 378 9% 98% 187 Solar 25 1% 115 3% 363% 90 Distributed Solar 14 0% 49 1% 248% 35 Other Renewable 80 2% 70 2% -12% -9 Misc 27 1% 24 1% -13% -4 Total 4,092 100% 4,157 100% 2% 66 Source: EIA. Electric Power Annual 2022, Tables 3.2 The average age of coal-fired power plants that have retired between 2015 and 2021 is over 50 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. As shown in Figure 21 below, 65 percent of the coal fleet in 2021 had an average age of over 40 years.

Figure 21National Coal-fired Capacity (GW) by Age of EGU, 2021 Source: NEEDS v6

Coal-fired and nuclear generating units have historically supplied "base load" electricity, the portion of electricity loads that are continually present and typically operate throughout all hours of the year. Although much of the coal fleet has historically operated as base load, there can be notable differences across various facilities (see Table 2-3). For example, coal-fired units less than 100 megawatts (MW) in size comprise 18 percent of the total number of coal-fired units, but only 2 percent of total coal-fired capacity. Gas-fired generation is better able to vary output, and is therefore the primary option used to meet the variable portion of the electricity load. Gas-fired generation has historically supplied "peak" and "intermediate" power, when there is increased demand for electricity (for example, when businesses operate throughout the day or when people return home from work and run appliances and heating/air-conditioning), versus late at night or very early in the morning, when demand for electricity is reduced. Moreover, as shown in Figure 22, average annual coal capacity factors have declined from 67 percent to 49 percent over the 2010-2021 period, indicating that a larger share of units are operating in non-baseload fashion. Over the same period, natural gas capacity factors have risen from an annual average of 28 percent to 37 percent.

Figure 22Average Annual Capacity Factor by Energy Source Source: EIA. Electric Power Annual 2022, Tables 3.2 and 4.2

Table 23 also shows comparable data for the capacity and age distribution of natural gas units. Compared with the fleet of coal EGUs, the natural gas fleet of EGUs is generally smaller and newer. While 67 percent of the coal EGU fleet capacity is over 500 MW per unit, 75 percent of the gas fleet is between 50 and 500 MW per unit.

Table 23Coal and Natural Gas Generating Units, by Size, Age, Capacity, and Average Heat Rate in 2020 Unit Size Grouping (MW) No. Units % of All Units Avg. Age Avg. Net Summer Capacity (MW) Total Net Summer Capacity (MW) % Total Capacity Avg. Heat Rate (Btu/kWh) COAL 0  -  24 31 6% 49 11 351 0% 11,379 25  -  49 32 6% 35 36 1,150 1% 11,541 50  -  99 24 5% 39 76 1,823 1% 11,649 100 - 149 36 7% 50 122 4,388 2% 11,167 150 - 249 61 12% 52 197 12,027 6% 10,910 250 - 499 132 26% 42 372 49,090 24% 10,700 500 - 749 138 27% 41 609 83,978 40% 10,315 750 - 999 50 10% 38 827 41,345 20% 10,135 1000 - 1500 11 2% 43 1,264 13,903 7% 9,834 Total Coal 515 100% 43 404 208,056 100% 10,718 NATURAL GAS 0  -  24 4,329 54% 31 5 21,626 4% 13,244 25  -  49 932 12% 26 41 38,089 8% 11,759 50  -  99 1,018 13% 27 71 72,744 15% 12,163 100 - 149 410 5% 23 126 51,567 10% 9,447 150 - 249 1,041 13% 18 179 186,494 37% 8,226 250 - 499 293 4% 21 332 97,244 19% 8,293 500 - 749 37 0% 38 592 21,910 4% 10,384 750 - 999 10 0% 46 828 8,278 2% 11,294 1000 - 1500 1 0% 0 1,060 1,060 0% 7,050 Total Gas 8,060 100% 28 62 499,012 100% 11,900 Source: National Electric Energy Data System (NEEDS) v.6 Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed to a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher level of fuel efficiency.

In terms of the age of the generating units, almost 50 percent of the total coal generating capacity has been in service for more than 40 years, while nearly 50 percent of the natural gas capacity has been in service less than 15 years. Figure 23 presents the cumulative age distributions of the coal and gas fleets, highlighting the pronounced differences in the ages of the fleets of these two types of fossil-fuel generating capacity. Figure 23 also includes the distribution of generation, which is similar to the distribution of capacity.

Figure 23Cumulative Distribution in 2019 of Coal and Natural Gas Electricity Capacity and Generation, by Age Source: eGRID 2020 (January 2022 release from EPA eGRID website). Figure presents data from generators that came online between 1950 and 2020 (inclusive); a 71-year period. Full eGRID data includes generators that came online as far back as 1915. Full data from 1915 onward is used in calculating cumulative distributions; figure truncation at 70 years is merely to improve visibility of diagram.

The locations of existing fossil units in EPA's National Electric Energy Data System (NEEDS) v.6 are shown in Figure 24.

Figure 24Fossil Fuel-Fired Electricity Generating Facilities, by Size Source: National Electric Energy Data System (NEEDS) v.6 Note: This map displays fossil capacity at facilities in the NEEDS v.6 database, which reflects generating capacity expected to be on-line at the end of 2023. This includes planned new builds already under construction and planned retirements. In areas with a dense concentration of facilities, some facilities may be obscured.

Transmission Transmission is the term used to describe the bulk transfer of electricity over a network of high voltage lines, from electric generators to substations where power is stepped down for local distribution. In the U.S. and Canada, there are three separate interconnected networks of high voltage transmission lines, each operating synchronously. Within each of these transmission networks, there are multiple areas where the operation of power plants is monitored and controlled by regional organizations to ensure that electricity generation and load are kept in balance. In some areas, the operation of the transmission system is under the control of a single regional operator; in others, individual utilities coordinate the operations of their generation, transmission, and distribution systems to balance the system across their respective service territories.  Distribution Distribution of electricity involves networks of lower voltage lines and substations that take the higher voltage power from the transmission system and step it down to lower voltage levels to match the needs of customers. The transmission and distribution system is a classic example of a natural monopoly, in part because it is not practical to have more than one set of lines running from the electricity generating sources to substations or from substations to residences and businesses. Over the last few decades, several jurisdictions in the U.S. began restructuring the power industry to separate transmission and distribution from generation, ownership, and operation. Historically, vertically integrated utilities established much of the existing transmission infrastructure. However, as parts of the country have restructured the industry, transmission infrastructure has also been developed by transmission utilities, electric cooperatives, and merchant transmission companies, among others. Distribution, also historically developed by vertically integrated utilities, is now often managed by a number of utilities that purchase and sell electricity, but do not generate it. As discussed below, electricity restructuring has focused primarily on efforts to reorganize the industry to encourage competition in the generation segment of the industry, including ensuring open access of generation to the transmission and distribution services needed to deliver power to consumers. In many states, such efforts have also included separating generation assets from transmission and distribution assets to form distinct economic entities. Transmission and distribution remain price-regulated throughout the country based on the cost of service. Sales, Expenses, and Prices These electric generating sources provide electricity for ultimate commercial, industrial and residential customers. Each of the three major ultimate categories consume roughly a quarter to a third of the total electricity produced (see Table 24). Some of these uses are highly variable, such as heating and air conditioning in residential and commercial buildings, while others are relatively constant, such as industrial processes that operate 24 hours a day. The distribution between the end use categories changed very little between 2015 and 2021. Table 24Total U.S. Electric Power Industry Retail Sales, 2015 and 2021 (billion kWh)   2015 2021     Sales/Direct Use (Billion kWh) Share of Total End Use Sales/Direct Use (Billion kWh) Share of Total End Use Sales Residential 1,404 36% 1,470 37%

Commercial 1,361 35% 1,328 34%

Industrial 987 25% 1,001 25%

Transportation 8 0% 6 0% Total   3,759 96% 3,806 96% Direct Use   141 4% 139 Total End Use   3,900 100% 3,945 Source: Table 2.2, EIA Electric Power Annual, 2021 Notes: Retail sales are not equal to net generation (Table 2-2) because net generation includes net imported electricity and loss of electricity that occurs through transmission and distribution, along with data collection frame differences and non-sampling error. Direct Use represents commercial and industrial facility use of onsite net electricity generation; electricity sales or transfers to adjacent or co-located facilities; and barter transactions.

Electricity Prices Electricity prices vary substantially across the U.S., differing both between the ultimate customer categories and by state and region of the country. Electricity prices are typically highest for residential and commercial customers because of the relatively high costs of distributing electricity to individual homes and commercial establishments. The higher prices for residential and commercial customers are the result both of the necessary extensive distribution network reaching to virtually every part of the country and every building, and also the fact that generating stations are increasingly located relatively far from population centers (which increases transmission costs). Industrial customers generally pay the lowest average prices, reflecting both their proximity to generating stations and the fact that industrial customers receive electricity at higher voltages (which makes transmission more efficient and less expensive). Industrial customers frequently pay variable prices for electricity, varying by the season and time of day, while residential and commercial prices historically have been less variable. Overall industrial customer prices are usually considerably closer to the wholesale marginal cost of generating electricity than residential and commercial prices.  On a state-by-state basis, all retail electricity prices vary considerably. In 2021, the national average retail electricity price (all sectors) was 11.18 cents/kWh, with a range from 7.5 cents (Louisiana) to 27 cents (Hawaii).  Average national retail electricity prices decreased between 2010 and 2021 by 8 percent in real terms (2019 dollars), and 5 percent between 2015-21. The amount of decrease differed for the three major end use categories (residential, commercial and industrial). National average industrial prices decreased the most (7 percent), and residential prices decreased the least (4 percent) between 2015-21. The real year prices for 2010 through 2021 are shown in Figure 25.

Figure 25Real National Average Electricity Prices (including taxes) for Three Major End-Use Categories Source: EIA. Electric Power Annual 2021, Table 2.4. Most of these electricity price decreases occurred between 2014 and 2015, when nominal residential electricity prices followed inflation trends, while nominal commercial and industrial electricity prices declined. The years 2016 and 2017 saw an increase in nominal commercial and industrial electricity prices, while 2018 and 2019 saw flattening of this growth. Industrial electricity prices declined in 2019 and 2020 due to the effects of the pandemic. Prices rose in 2021 as a result of higher input fuel prices and increasing demand. The increase in nominal electricity prices for the major end use categories, as well as increases in the gross domestic product (GDP) price index for comparison, are shown in Figure 26.

Figure 26Relative Increases in Nominal National Average Electricity Prices for Major End-Use Categories (including taxes), With Inflation Indices  Source: EIA. Electric Power Annual 2021, Table 2.4. Prices of Fossil Fuel Used for Generating Electricity Another important factor in the changes in electricity prices are the changes in delivered fuel prices for the three major fossil fuels used in electricity generation: coal, natural gas and petroleum products. Relative to real prices in 2014, the national average real price (in 2019 dollars) of coal delivered to EGUs in 2020 had decreased by 26 percent, while the real price of natural gas decreased by 56 percent. The real price of delivered petroleum products also decreased by 55 percent, and petroleum products declined as an EGU fuel (in 2020 petroleum products generated 1 percent of electricity). The combined real delivered price of all fossil fuels (weighted by heat input) in 2020 decreased by 39 percent over 2014 prices. Figure 27 shows the relative changes in real price of all 3 fossil fuels between 2010 and 2021.

Figure 27Relative Real Prices of Fossil Fuels for Electricity Generation; Change in National Average Real Price per MMBtu Delivered to EGU Source: EIA. Electric Power Annual 2020 and 2021, Table 7.1.

Changes in Electricity Intensity of the U.S. Economy from 2010 to 2021 An important aspect of the changes in electricity generation (i.e., electricity demand) between 2010 and 2021 is that while total net generation increased by 1 percent over that period, the demand growth for generation was lower than both the population growth (7 percent) and real GDP growth (24 percent). Figure 28 shows the growth of electricity generation, population and real GDP during this period.

Figure 28Relative Growth of Electricity Generation, Population and Real GDP Since 2014 Sources: Generation: U.S. EIA Electric Power Annual 2021 and 2020. Population: U.S. Census. Real GDP: 2022 Economic Report of the President, Table B-3.   Because demand for electricity generation grew more slowly than both the population and GDP, the relative electric intensity of the U.S. economy improved (i.e., less electricity used per person and per real dollar of output) during 2010 to 2021. On a per capita basis, real GDP per capita grew by 16 percent between 2010 and 2021. At the same time electricity generation per capita decreased by 6 percent. The combined effect of these two changes improved the overall electricity generation efficiency in the U.S. market economy. Electricity generation per dollar of real GDP decreased 19 percent. These relative changes are shown in Figure 29.

Figure 29Relative Change of Real GDP, Population and Electricity Generation Intensity Since 2010 Sources: Generation: U.S. EIA Electric Power Annual 2021 and 2020. Population: U.S. Census. Real GDP: 2022 Economic Report of the President, Table B-3.

Costs, Emissions, and Energy Impacts Introduction This section presents the compliance cost, emissions, and energy impact analysis performed for the MATS RTR. EPA used the Integrated Planning Model (IPM), developed by ICF Consulting, to conduct its analysis. IPM is a dynamic linear programming model that can be used to examine air pollution control policies for SO2, NOX, mercury, HCl, PM, and other air pollutants throughout the U.S. for the entire power system. Documentation for EPA's Post-IRA IPM 2022 Reference Case (hereafter IPM Documentation) can be found at https://www.epa.gov/airmarkets/power-sector-modeling, and is available in the docket for this action. EPA's Post-IRA IPM 2022 Reference Case IPM is a state-of-the-art, peer-reviewed, dynamic linear programming model that can be used to project power sector behavior under future business-as-usual conditions and to examine prospective air pollution control policies throughout the contiguous U.S. for the entire electric power system. For this RIA, EPA used IPM to project likely future electricity market conditions with and without this proposed rulemaking and a more stringent regulatory alternative.  IPM, developed by ICF, is a multi-regional, dynamic, deterministic linear programming model of the contiguous U.S. electric power sector. It provides estimates of least cost capacity expansion, electricity dispatch, and emissions control strategies while meeting energy demand and environmental, transmission, dispatch, and reliability constraints. Notably, the model includes cost and performance estimates for state-of-the-art air pollution control technologies with respect to mercury, filterable PM, and other HAP controls.  EPA has used IPM for almost three decades to better understand power sector behavior under future business-as-usual conditions and to evaluate the economic and emissions impacts of prospective environmental policies. The model is designed to reflect electricity markets as accurately as possible. 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 information on the assumptions discussed here as well as all other model assumptions and inputs. The model incorporates a detailed representation of the fossil-fuel supply system that is used to estimate equilibrium fuel prices. The model uses natural gas fuel supply curves and regional gas delivery costs (basis differentials) to simulate the fuel price associated with a given level of gas consumption within the system. These inputs are derived using ICF's Gas Market Model (GMM), a supply/demand equilibrium model of the North American gas market.  IPM also endogenously models the partial equilibrium of coal supply and EGU coal demand levels throughout the contiguous U.S., taking into account assumed non-power sector demand and imports/exports. IPM reflects 36 coal supply regions, 14 coal grades, and the coal transport network, which consists of over four thousand linkages representing rail, barge, and truck and conveyer linkages. The coal supply curves in IPM were developed during a thorough bottom-up, mine-by-mine approach that depicts the coal choices and associated supply costs that power plants would face if selecting that coal over the modeling time horizon. The IPM documentation outlines the methods and data used to quantify the economically recoverable coal reserves, characterize their cost, and build the 36 coal regions' supply curves.  To estimate the annualized costs of additional capital investments in the power sector, 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 power sector's cost of capital (i.e., 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, book life of the capital investments, and regions in the model in order to better simulate power sector decision-making.  EPA has used IPM extensively over the past three decades to analyze options for reducing power sector emissions. Previously, the model has been used to estimate the costs, emission changes, and power sector impacts in the RIAs for the Clean Air Interstate Rule (U.S. EPA, 2005), the Cross-State Air Pollution Rule (U.S. EPA, 2011a), the Mercury and Air Toxics Standards (U.S. EPA, 2011b), the Clean Power Plan for Existing Power Plants (U.S. EPA, 2015b), the Cross-State Air Pollution Update Rule (U.S. EPA, 2016), the Repeal of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units (U.S. EPA, 2019), and the Revised Cross-State Air Pollution Update Rule (U.S. EPA, 2021). EPA has also used IPM to estimate the air pollution reductions and power sector impacts of water and waste regulations affecting EGUs, including contributing to RIAs for the Cooling Water Intakes (316(b)) Rule (U.S. EPA, 2014), the Disposal of Coal Combustion Residuals from Electric Utilities rule (U.S. EPA, 2015c), the Steam Electric Effluent Limitation Guidelines (U.S. EPA, 2015a), and the Steam Electric Reconsideration Rule (U.S. EPA, 2020). The model and 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. IPM has received extensive review by energy and environmental modeling experts in a variety of contexts. For example, in October 2014 U.S. EPA commissioned a peer review of EPA Baseline run version 5.13 using IPM. Additionally, and in the late 1990s, the Science Advisory Board reviewed IPM as part of the CAA Amendments Section 812 prospective studies that are periodically conducted. The Agency has also used the model in a number of comparative modeling exercises sponsored by Stanford University's Energy Modeling Forum over the past 20 years. IPM has also been employed by states (e.g., for the Regional Greenhouse Gas Initiative, the Western Regional Air Partnership, Ozone Transport Assessment Group), other Federal and state agencies, environmental groups, and industry. Baseline  The modeled "baseline run" for any regulatory impact analysis is a business-as-usual scenario that represents expected behavior in the electricity sector under market and regulatory conditions in the absence of a regulatory action. As such, the baseline run represents an element of the baseline for this RIA. EPA frequently updates the baseline modeling to reflect the latest available electricity demand forecasts from the U.S. EIA as well as expected costs and availability of new and existing generating resources, fuels, emission control technologies, and regulatory requirements. For our analysis of the proposed MATS RTR rule, EPA used EPA's Post-IRA IPM 2022 Reference Case to provide power sector emissions projections for air quality modeling, as well as a companion updated database of EGU units (the National Electricity Energy Data System or NEEDS v621 rev: 10-14-22) that is used in EPA's modeling applications of IPM. The Baseline run for this proposal includes the proposed GNP, the Revised CSAPR Update, CSAPR Update, and CSAPR, as well as MATS. The Baseline run also includes the 2015 Effluent Limitation Guidelines (ELG) and the 2015 Coal Combustion Residuals (CCR), and the recently finalized 2020 ELG and CCR rules.  This version of the model also includes recent updates to state and federal legislation affecting the power sector, including Public Law 117-169, 136 Stat. 1818 (August 16, 2022), commonly known as the Inflation Reduction Act of 2022 (the IRA). The IP M Documentation includes a summary of all legislation reflected in this version of the model as well as a description of how that legislation is implemented in the model. The inclusion of the proposed GNP and other regulatory actions (including federal, state, and local actions) in the base case is necessary in order to reflect the level of controls that are likely to be in place in response to other requirements apart from the scenarios analyzed in this section. This base case will provide meaningful projections of how the power sector will respond to the cumulative regulatory requirements for air emissions in totality, while isolating the incremental impacts of MATS RTR relative to a base case with other air emission reduction requirements separate from this proposed action. The analysis of power sector cost and impacts presented in this section is based on a single baseline run, and represents incremental impacts projected solely as a result of compliance with the proposed MATS RTR or the analyzed alternatives Regulatory Options Analyzed For this RIA, EPA analyzed the three regulatory options summarized in the table below, which are described in more detail in Section 1.3.1. The remainder of this section discusses the approach used for estimating the costs and/or emissions impacts of each provision of the proposed rule. Table 31Summary of Proposed Regulatory Options Examined in this RIA    Regulatory Options Examined in this RIA Provision Less Stringent Proposed More Stringent Filterable PM Standard (Surrogate Standard for Non-Hg metal HAP) Retain existing filterable PM standard of 0.030 lb/MMBtu revised filterable PM standard of 0.010 lb/MMBtu revised filterable PM standard of 0.006 lb/MMBtu Mercury Standard Retain mercury standard for lignite-fired EGUs of 4.0 lb/TBtu  revised mercury standard for lignite-fired EGUs of 1.2 lb/TBtu revised mercury standard for lignite-fired EGUs of 1.2 lb/TBtu Continuous Emissions Monitoring Systems (CEMS) Require installation of PM CEMS to demonstrate compliance Require installation of PM CEMS to demonstrate compliance Require installation of PM CEMS to demonstrate compliance Startup definition Remove startup definition #2 Remove startup definition #2 Remove startup definition #2

The revisions to the filterable PM standard and the mercury standard are modeled endogenously within IPM. For the filterable PM standard, emissions controls and associated costs are modeled based on information available in the memorandum titled: "2023 Technology Review for the Coal- and Oil-Fired EGU Source Category" which is available in the docket. This memorandum summarizes the filterable PM emissions rate for each existing EGU. Based on the emissions rates detailed in this memorandum, EPA assumed various levels of ESP upgrades, upgrades to existing fabric filters, or new fabric filter installations to comply with each of the proposed standards in the modeling. Those assumptions are detailed in Table 32.  Table 32PM Control Technology Modeling Assumptions  PM  Control Strategy Capital Cost Filterable  PM Reduction MinorESP Upgrades $16.5/kW 7.5% TypicalESP Upgrades $55/kW 15% ESP Rebuild $88/kW 40%(0.005lb/MMBtu floor) Upgrade Existing FF Bags Unit-specific, approximately $15K - $500K annual O&M 50%(0.002 lb/MMBtu floor) New Fabric Filter(6.0 A/C Ratio) Unit-specific,$150-360/kW* 90%(0.002 lb/MMBtu floor) * https://www.epa.gov/system/files/documents/2021-09/attachment_5-7_pm_control_cost_development_methodology.pdf

The cost and reductions associated with control of mercury emissions at lignite-fired EGUs are also modeled endogenously and reflect the assumption that each of these EGUs replace standard powdered activated carbon (PAC) sorbent with halogenated PAC sorbent. While more detail on the costs associated with the proposal to require CEMS and the proposed change in the startup definition is presented in Section 3.5.2, we note here that these costs were estimated exogenously without the use of the model that provides the bulk of the cost analysis for this RIA. As a result, the results of the power sector modeling do not include costs associated with these provisions, but the costs associated with requiring CEMS and the change in the startup definition are included in the total cost projections for the rule for each of the regulatory options analyzed in this RIA. As the incremental costs of requiring CEMS is negative and small relative to other aspects of this proposed rulemaking, we do not think the endogenous incorporation of these costs would change any projected results in a meaningful way. Power Sector Impacts  Emissions As indicated previously, this RIA presents emissions reductions estimates in years 2028, 2030, and 2035 based on IPM projections. Table 33 presents the estimated impact on reduction in power sector emissions resulting from compliance with the evaluated regulatory control alternatives (i.e., filterable PM and mercury standards) in the contiguous U.S. Note the less stringent regulatory alternative in this RIA was not modeled using IPM. As a result, power sector impacts are not estimated for the less stringent regulatory option, but the costs associated with requiring CEMS are included in all options. The projections indicate that both the proposed rule and the more stringent alternative result in emissions reductions in all run years, and those emission reductions follow an expected pattern: the proposed rule, which revises the filterable PM standard to 0.010 lb/MMBtu, produces smaller emissions reductions than the more stringent alternative, which revises the filterable PM standard to 0.006 lb/MMBtu. The additional reductions of mercury emissions in the more stringent alternative result from the additional coal steam retirements in this scenario.

Table 33EGU Emissions and Emissions Changes for the Baseline Run and the Proposed Rule and More Stringent Alternatives for 2028, 2030, and 2035 a

Total Emissions Change from Baseline

Year Baseline  Run Proposed Rule More-Stringent Alternative Proposed Rule More-Stringent Alternative Mercury (lbs.) 2028 5,019 4,957 4,811 -62 -208

2030 4,206 4,139 4,037 -67 -169

2035 3,219 3,137 3,052 -82 -168 PM2.5 (thousand tons) 2028 74.6 74.2 72 -0.4 -2.6

2030 65.5 65.1 64 -0.4 -1.5

2035 46.6 45.8 45.3 -0.8 -1.3 SO2 (thousand tons) 2028 394 393 382 -0.9 -11.6

2030 282 282 282 -0.5 -0.3

2035 130 128 121 -1.5 -8.8 Ozone-season NOX (thousand tons) 2028 195 195 188 -0.2 -7.2

2030 163 163 158 -0.4 -5.1

2035 104 101 99 -3.2 -5.6 Annual NOX (thousand tons) 2028 457 456 439 -0.4 -18.1

2030 368 367 358 -0.8 -9.5

2035 214 211 205 -3.4 -8.7 HCl (million tons) 2028 2.6 2.6 2.5 0.0 -0.2

2030 1.8 1.8 1.7 0.0 -0.1

2035 0.9 0.9 0.8 0.0 -0.1 CO2 (million metric tons) 2028 1222 1222 1200 -0.2 -21.9

2030 972 971 963 -0.8 -8.7

2035 608 604 605 -4.6 -2.9 a This analysis is limited to the geographically contiguous lower 48 states.

Compliance Costs Power Sector Costs The power industry's "compliance costs" are represented in this analysis as the change in electric power generation costs between the baseline and policy scenarios and are presented in Table 34. In simple terms, these costs are an estimate of the increased power industry expenditures required to implement the proposed requirements. EPA projects that the annual incremental compliance cost of the proposed rule is $62 million, $52 million, and $45 million (2019 dollars) annually in 2028, 2030, and 2035, respectively. The annual incremental cost is the projected additional cost of complying with the proposed rule in the year analyzed and includes the amortized cost of capital investment and any applicable costs of operating additional pollution controls, investments in new generating sources, shifts between or amongst various fuels, and other actions associated with compliance. This projected cost does not include the compliance calculated outside of IPM modeling, namely the compliance costs related to CEMS. See Section <IP_ADDRESS> for further details on these costs. EPA believes that the cost assumptions used for this RIA reflect, as closely as possible, the best information available to the Agency today. Table 34 National Power Sector Compliance Cost Estimates (millions of 2019 dollars) for the Proposed Rule and More Stringent Alternative for 2028, 2030, and 2035 Analysis Year Proposed Rule More Stringent Alternative 2028 (Annualized) 62 928 2030 (Annualized) 52 1,061 2035 (Annualized) 45 290 Note: The less stringent regulatory alternative in this RIA was not modeled using IPM. As a result power sector impacts are not estimated for the less stringent regulatory option, but the costs associated with requiring CEMS are included in the total cost across regulatory options.

Additionally, EPA projects that the annual incremental compliance cost of the more stringent alternative is $928 million, $1 billion, and $290 million (2019 dollars) annually in 2028, 2030, and 2035, respectively. Relative to the proposed rule, these costs are notably higher. The difference in projected compliance costs results from EPA's assumption that more costly controls would be installed to comply with the lower filterable PM emissions limit. A small percentage of the total compliance costs for the more stringent alternative is attributable to the capital and operating costs of these additional controls, and the vast majority of the incremental cost is associated with the projected changes in operating capacity which decrease significantly by 2035. See Section 3.5.4 for a discussion of projected capacity changes and Section 3.6 for a discussion of the uncertainty regarding necessary pollution controls.  CEMS Costs In addition to revising the PM emission standard for existing coal-fired EGUs, EPA is proposing a revision to the requirements for demonstrating compliance with the PM emission standard for coal-fired EGUs. Either of the two filterable PM standards under consideration would render the current limit for the LEE program moot, since they would be two-thirds and two-fifths, respectively, of the current PM LEE limit. Therefore, EPA proposes to remove PM from the LEE program. Currently, EGUs that are not LEE units can demonstrate compliance with the filterable PM standard either by conducting performance testing quarterly, use of PM continuous parameter monitoring systems (CPMS) or using PM CEMS.  After considering updated information on the costs for performance testing compared to the cost of CEMS and capabilities of PM CEMS measurement abilities, as well as the benefits of using PM CEMS, which include increased transparency and accelerated identification of anomalous emissions, EPA is proposing to require that all MATS-affected EGUs demonstrate compliance with the PM emission standard by using PM CEMS. The revision of PM limits in the proposal and more stringent alternative alter the composition and duration of testing runs in facilities that use either performance testing methodology. For units currently employing M5 quarterly testing, four tests would be required at an individual cost of $15,522 and an annual cost of $62,088. The EPA calibrated its cost estimates for PM CEMS in response to observed installations, manufacturer input, and engineering analyses. These calibrations include an assumed replacement lifespan of 15 years and an interest rate of 7 percent to approximate the prevailing bank prime rate. For the portion of EGUs that employ CEMS, manufacturer input leads to an annualized cost of $32,559, which is slightly lower than the current cost of $33,643 for firms utilizing PM CEMS. All installations of PM CEMS currently in place took place in between 2012 and 2015. With a 15-year expected useful life, the assumption is made that all units would require initial installation of new PM CEMS, including those that already utilize the technology.  To produce an inventory of total units which would require the installation of PM CEMS in the proposal and more stringent alternative as well as their initial characterization for juxtaposition of current and proposal costs, the EPA began with an inventory of all existing coal-fired EGUs with capacity great enough to be regulated by MATS. That inventory was then filtered to remove EGUs with planned retirements prior to 2028 from analysis of both the baseline and proposal. Within that remaining inventory of 358 EGUs, 126 units are assumed to have installed PM CEMS between 2012 and 2015, while the remaining 232 units are assumed to use quarterly testing and not have existing PM CEMS installations.  Table 35Costs of Proposed Continuous Emissions Monitoring (CEMS) Requirement Compliance Approach in Baseline Units (no.) Baseline Cost (per year per unit) Total Baseline Costs (per year) Proposed Rule (per year per unit) Proposed Rule Costs (per year) Incremental Costs (per year) Quarterly Testing 230 $62,000 $14,000,000 $33,000 $7,600,000 -$6,900,000 CEMS 130 $34,000 $4,200,000 $33,000 $4,100,000 -$140,000 Total 360 --- $19,000,000 --- $12,000,000 -$7,000,000 Note: Values rounded to two significant figures As detailed in Table 35, relative to the baseline scenario, revised CEMS cost estimates in the proposal lead to a reduction of costs of $1 thousand per year per unit and about $140 thousand per year in total. For EGUs currently employing quarterly testing, the proposal results in cost reductions of $29 thousand per year per unit and $6.9 million per year in total. The estimated aggregate sector impact thus sums to a cost reduction of about $7.0 million per year. Startup Definition Costs EPA is proposing to remove one of the two options for defining the startup period for EGUs. The first option defines startup as either the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use). In the second option, startup is defined as the period in which operation of an EGU is initiated for any purpose. Startup begins with either the firing of any fuel in an EGU for the purpose of producing electricity or useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes (other than the first-ever firing of fuel in a boiler following construction of the boiler) or for any other purpose after a shutdown event. Startup ends four hours after the EGU generates electricity that is sold or used for any other purpose (including on-site use), or four hours after the EGU makes useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes, whichever is earlier. This second option, referred to as paragraph (2) of the definition of "startup," required clean fuel use to the maximum extent possible, operation of PM control devices within one hour of introduction of primary fuel (i.e., coal, residual oil, or solid oil-derived fuel) to the EGU, collection and submission of records of clean fuel use and emissions control device capabilities and operation, as well as adherence to applicable numerical standards within four hours of the generation of electricity or thermal energy for use either on site or for sale over the grid (i.e., the end of startup) and to continue to maximize clean fuel use throughout that period.  According to EPA analysis, the owners or operators of at least 98 percent of all other coal- and oil-fired EGUs have made the requisite adjustments, whether through greater clean fuel capacity, better tuned equipment, better trained staff, a more efficient or better design structure, or a combination of factors, to be able to meet the requirements of paragraph (1) of the definition of "startup." As demonstrated by the vast majority of EGUs currently relying on the work practice standards in paragraph (1) of the definition of "startup," we believe such a change is achievable by all EGUs; further, we expect such a change would result in little to no additional expenditure since the additional recordkeeping and reporting provisions associated with the work practice standards of paragraph (2) of the definition of "startup" were more expensive than the requirements of paragraph (1) of the definition of "startup." As a result, this RIA does not incorporate any additional costs as a result of this proposed provision. Total Compliance Costs The estimates of the total compliance costs are presented in Table 36. The total costs are composed of the change in electric power generation costs between the baseline and policy scenarios as presented in Table 34 and the incremental cost of the proposed CEMS requirement as detailed in Table 35. Table 36Stream of Projected Compliance Costs across Proposed Rule and Less and More Stringent Regulatory Alternatives (millions of 2019 dollars)   Regulatory Alternative Year Proposed Rule Less Stringent More Stringent 2023 0.0 0.0 0.0 2024 0.0 0.0 0.0 2025 0.0 0.0 0.0 2026 0.0 0.0 0.0 2027 0.0 0.0 0.0 2028* 55 -7.0 920 2029 45 -7.0 1,100 2030* 45 -7.0 1,100 2031 45 -7.0 1,100 2032 38 -7.0 280 2033 38 -7.0 280 2034 38 -7.0 280 2035* 38 -7.0 280 2036 38 -7.0 280 2037 38 -7.0 280 3% Discount Rate Present Value 320 -53 4,600 Equivalent Annualized Value 37 -6.2 540 7% Discount Rate Present Value 230 -37 3,400 Equivalent Annualized Value 33 -5.3 490 * IPM analysis years. Values rounded to two significant figures

Projected Compliance Actions for Emissions Reductions Electric generating units subject to the mercury and filterable PM emission limits in this proposed rule will likely use various mercury and PM control strategies to comply. This section summarizes the projected compliance actions related to each of these emissions limits. The 2028 baseline includes approximately 7 GW of operational minemouth EGU capacity designed to burn low rank virgin coal. All of this capacity is currently equipped with Activated Carbon Injection (ACI) technology, and operation of this technology is reflected in the baseline. In the proposed and more stringent modeling scenarios, each of these EGUs projected to consume lignite is assigned an additional variable operating cost that is consistent with achieving a 1.2 lb/MMBtu limit. In the proposed option, this additional cost does not result in incremental retirements for these units, nor does it result in a significant change to the projected generation level for these units. The baseline also includes 4.8 GW of operational coal capacity that, based on the analysis documented in the EPA docketed memorandum titled: "2023 Technology Review for the Coal- and Oil-Fired EGU Source Category," EPA assumes would either need to improve existing PM controls or install new PM controls to comply with the proposed option in 2028. The various PM control upgrades that EPA assumes would be necessary to achieve with the emissions limits analyzed are summarized in Table 37.  Table 37Affected Capacity Operational in the Baseline by PM Control Strategy for the Proposed Rule and More Stringent Alternative in 2028 (GW)   Proposed Rule More-Stringent Alternative PM Control Strategy Affected Capacity Operational in Baseline Projected Retrofits in Proposed Rule Affected Capacity Operational in Baseline Projected Retrofits in More-Stringent Alternative Minor ESP upgrades 1.1 1.1 -- -- Typical ESP Upgrades 0.5 0 -- -- ESP Rebuild 0.4 0.4 -- -- FF Bag Upgrade 1.2 1.2 7.6 7.6 New Fabric Filter 1.5 1.5 15.0 3.6 Total 4.8 4.3 22.7 11.3

The vast majority of the 4.8 GW that EPA assumes would need to take some compliance action to meet the proposed standards is currently operating existing ESPs and/or fabric filters. Nearly all of that capacity is projected to install the controls summarized in Table 37 and remain operational in 2028, and about 500 MW of that coal steam capacity is projected to retire in response to the proposed rule. Under the more stringent alternative, EPA assumes that 22.7 GW of capacity that is projected to be operational in the baseline would need to take some compliance action in order to meet the proposed standards. About half of that capacity (about 11.3 GW) is projected to remain operational with the installation of those controls in 2028. Generating Capacity In this section, we discuss the projected changes in capacity by fuel type, building on and adding greater context to the information presented in the previous section. We first look at total capacity by fuel type, then retirements by fuel type, and finally new capacity builds by fuel type for the 2028, 2030, and 2035 run years. Table 38 shows the total net projected capacity by fuel type for the baseline run and regulatory control alternatives for 2028, 2030, and 2035. Here, we see the net effects of projected retirements (Table 39) and new capacity builds (see Table 310). All incremental changes in capacity projected to result in response to the proposed rule for any given fuel type are one percent or less, and all under 1 GW. The more stringent alternative, on the other hand, is projected to result in a fleet consisting of slightly more operational natural gas capacity by 2035, and slightly less operational coal capacity. Table 38 2028, 2030, and 2035 Projected U.S. Capacity by Fuel Type for the Baseline Run and the Proposed Rule and More Stringent Alternative

Total Generation Capacity (GW) Incremental Change from Baseline

Base Case Proposed Rule More Stringent Alternative Proposed Rule More Stringent Alternative

GW % GW % 2028

Coal 100.5 99.9 88.2 -0.5 -0.5% -12.2 -12.2% Natural Gas 463.0 463.5 467.0 0.5 0.1% 4.0 0.9% Oil/Gas Steam 62.8 62.7 62.8 -0.1 -0.1% 0.1 0.1% Non-Hydro RE 314.8 314.6 316.5 -0.1 0.0% 1.8 0.6% Hydro 102.1 102.1 102.1 0.0 0.0% 0.0 0.0% Energy Storage 50.0 50.3 56.0 0.3 0.5% 6.0 11.9% Nuclear 95.7 95.7 95.7 0.0 0.0% 0.0 0.0% Other 6.9 6.9 6.9 0.0 0.0% 0.0 0.0% Total 1,195.8 1,195.9 1,195.4 0.0 0.0% -0.5 0.0% 2030

  Coal 68.9 68.4 63.5 -0.6 -0.8% -5.5 -8.0% Natural Gas 461.1 461.5 465.2 0.5 0.1% 4.1 0.9% Oil/Gas Steam 60.4 60.3 60.1 -0.1 -0.1% -0.3 -0.5% Non-Hydro RE 403.4 403.3 405.1 -0.1 0.0% 1.7 0.4% Hydro 103.6 103.6 103.6 0.0 0.0% 0.0 0.0% Energy Storage 68.1 68.2 69.0 0.1 0.2% 1.0 1.4% Nuclear 91.9 91.9 91.9 0.0 0.0% 0.0 0.0% Other 6.9 6.9 6.9 0.0 0.0% 0.0 0.0% Total 1,264.3 1,264.2 1,265.2 -0.1 0.0% 0.9 0.1% 2035

        Coal 44.0 43.7 39.3 -0.3 -0.8% -4.7 -10.8% Natural Gas 470.0 470.2 474.6 0.3 0.1% 4.6 1.0% Oil/Gas Steam 59.2 59.1 59.2 -0.1 -0.1% 0.0 0.0% Non-Hydro RE 667.6 668.4 667.6 0.8 0.1% 0.0 0.0% Hydro 107.9 107.9 107.9 0.0 0.0% 0.0 0.0% Energy Storage 98.2 98.3 98.4 0.1 0.1% 0.2 0.2% Nuclear 83.6 83.6 83.6 0.0 0.0% 0.0 0.0% Other 6.9 6.9 6.9 0.0 0.0% 0.0 0.0% Total 1,537.4 1,538.2 1,537.5 0.8 0.0% 0.1 0.0% Note: In this table, "Non-Hydro RE" includes biomass, geothermal, landfill gas, solar, and wind.  Table 39 shows the total capacity projected to retire by fuel type for the baseline run and the regulatory control alternatives in all run years. The incremental changes projected to occur in response to the proposed rule are very small. The proposed rule is projected to result in an additional 500 MW of retired coal capacity (less than one percent). The more stringent alternative is projected to result in additional incremental retirement of coal capacity: 12.2 GW of incremental coal retirements in 2028, decreasing to 5.4 GW of incremental coal retirements in 2035. This decrease over time reflects an acceleration of projected retirements (some capacity that was projected to retire in the 2035 baseline is projected to retire a few years earlier in the more stringent policy scenario). Table 39 2028, 2030, and 2035 Projected U.S. Retirements by Fuel Type for the Baseline Run and the Proposed Rule and More Stringent Alternative

Retirements (GW) Percent Change from Baseline

Baseline Run  Proposed Rule More Stringent Alternative Proposed Rule More Stringent Alternative 2028

Coal 56.5  57.0 68.7 0.9% 21.6% Natural Gas 1.7  1.7 1.7 0.0% 0.0% Oil/Gas Steam 8.4  8.5 8.4 0.7% -0.7% Non-Hydro RE 3.0  3.0 2.9 0.0% -3.0% Hydro 0.0  0.0 0.0 0% 0% Nuclear 0.0  0.0 0.0 0% 0% Other 0.0  0.0 0.0 0% 0% Total 69.6  70.2 81.7 0.8% 17.3% 2030

Coal 82.0  82.5 87.9 0.7% 7.3% Natural Gas 2.4  2.4 2.4 0.0% 0.5% Oil/Gas Steam 12.4  12.4 12.7 0.5% 2.7% Non-Hydro RE 3.3  3.3 3.3 0.0% 0.0% Hydro 0.0  0.0 0.0 0% 0% Nuclear 2.7  2.7 2.7 0.0% 0.0% Other 0.1  0.1 0.1 0.0% 0.0% Total 102.8  103.5 109.1 0.6% 6.1% 2035