I W
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Economic Impact Assessment for the Proposed
Supplemental Federal "Good Neighbor Plan"
Requirements for the 2015 8-hour Ozone National
Ambient Air Quality Standard
U.S. Environmental Protection Agency
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
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EPA-452/P-23-004
November 2023
Economic Impact Assessment for the Proposed Supplemental Federal "Good Neighbor Plan"
Requirements for the 2015 8-hour Ozone National Ambient Air Quality Standard
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Health and Environmental Impacts Division
Research Triangle Park, NC
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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).
ACKNOWLEDGEMENTS
In addition to U.S. EPA staff from the Office of Air and Radiation, personnel from the Office of
Atmospheric Programs contributed data and analysis to this document.
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TABLE OF CONTENTS
Table of Contents i
List of Tables n
1 Introduction 1
1.1 States Included in the Proposal 3
1.2 Air Quality Modeling Linkages 3
1.3 Baseline and Analysis Period 4
2 Industry Summary 6
2.1 EGU 6
2.2 Non-EGUs 6
3 Emissions Reductions and Compliance Costs 8
3.1 EGUs 8
3.1.1 Regulatory Policy Evaluated 8
3.1.2 Methods for Estimating Emissions Reductions and Costs 11
3.1.3 Emissions Reductions and Compliance Cost Assessment for EGUs 12
3.2 Non-EGUs 21
3.2.1 Methods for Estimating Emissions Reductions and Costs 21
3.2.2 Emissions Reductions and Compliance Cost Assessment for Non-EGUs 22
3.3 Total Emissions Reductions and Compliance Costs for EGUs and Non-EGUs ..23
3.4 Small Business Screening Assessment 24
4 Benefits 26
4.1 Estimated Human Health Benefits 26
4.2 Climate Benefits 31
4.3 Total Benefits 33
5 Demographic Proximity Analysis 35
5.1.1 EGU Proximity Assessments 35
5.1.2 Non-EGU Proximity Analysis 38
6 Comparison of Cost and Benefits 40
7 References 43
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LIST OF TABLES
Table 3-1. Regulatory Controls Evaluated for EGUs
8
Table 3-2. Illustrative NOx Ozone Season Emission Budgets (Tons) Evaluated by IPM Run Year.
10
Table 3-3. National Power Sector Compliance Cost Estimates (millions of 2016$) for the Proposed Rule
12
Table 3-4. Average Retail Electricity Price by Region for the Baseline and the Regulatory Control Alternative, 2025
14
Table 3-5. Average Retail Electricity Price by Region for the Baseline and the Regulatory Control Alternative, 2028
15
Table 3-6. Average Retail Electricity Price by Region for the Baseline and the Regulatory Control Alternative, 2030
16
Table 3-7. EGU Ozone Season NOx Emissions and Emissions Changes (tons) for the Baseline run and Proposed
Rule from 2025 - 2044 17
Table 3-8. EGU Annual Emissions and Emissions Changes for Annual NOx, SO2, PM2 5, and CO2) for the Baseline
run and Proposed Rule from 2025 - 2044 18
Table 3-9. Summary of Non-EGU Industries, Emissions Unit Types, Assumed Control Technologies, Estimated
Total Annual Costs (2016$), Ozone Season NOx Emissions Reductions in 2026 23
Table 3-10. Total Estimated NOx Emissions Reductions (ozone season, thousand tons) and Compliance Costs for
EGUs and non-EGUs (million 2016$), 2025-2044 24
Table 3-11. Total National Compliance Cost Estimates (millions of 2016$) for the Proposed Rule 24
Table 4-1. Estimated Monetized Health Benefits of Avoided Ozone and PM2 5-Attributable Premature Mortality and
Illness for the Proposed Rule Emissions Reductions (EGUs and Non-EGUs), 2025-2044: Monetized Benefits
Quantified as Sum of Avoided Morbidity Health Effects and Avoided Long-term Ozone and PM2 5 Mortality (3
percent discount rate; million 2016$) 28
Table 4-2. Estimated Monetized Health Benefits of Avoided Ozone and PM2 5-Attributable Premature Mortality and
Illness for the Proposed Rule Emissions Reductions (EGUs and Non-EGUs), 2025-2044: Monetized Benefits
Quantified as Sum of Avoided Morbidity Health Effects and Avoided Long-term Ozone and PM2 5 Mortality (7
percent discount rate; million 2016$) 29
Table 4-3. Stream of Discounted Human Health Benefits for the Proposed Rule Emissions Reductions (EGUs and
Non-EGUs), 2025-2044: Monetized Benefits Quantified as Sum of Avoided Morbidity Health Effects and Avoided
Long-term Ozone and PM2 5Mortality (3 percent discount rate; million 2016$) 30
Table 4-4. Stream of Discounted Human Health Benefits for the Proposed Rule Emissions Reductions (EGUs and
Non-EGUs), 2025-2044: Monetized Benefits Quantified as Sum of Avoided Morbidity Health Effects and Avoided
Long-term Ozone and PM2 5 Mortality (7 percent discount rate; million 2016$) 31
Table 4-5. Stream of Climate Benefits from EGU C02 Emissions Reductions, 2025 - 2044 (Millions of 2016$) 32
Table 4-6. Combined Annual Health Benefits and Climate Benefits for the Proposed Rule 33
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Table 5-1. Population Demographics for the 9 EGU Facilities Assumed to Install Additional Controls due to the
Proposed Supplemental Rule 37
Table 5-2. Population Demographics for the 2 Non-EGU Facilities Assumed to Install Additional Controls due to
the Proposed Supplemental Rule 39
Table 6-1. Streams of Health Benefits, Climate Benefits, Costs, and Net Benefits for 2025 - 2044 (millions of
2016$) 41
Table 6-2. Summary of Present Values and Equivalent Annualized Values for the 2025-2044 Timeframe for
Estimated Monetized Health Benefits, Climate Benefits, Costs, and Net Benefits for the Proposed Rule (millions of
2016$, discounted to 2023) 42
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1 INTRODUCTION
Pursuant to the federal Clean Air Act (CAA), the Environmental Protection Agency
(EPA) is proposing to disapprove State Implementation Plan (SIP) submittals from Arizona,
New Mexico, and Tennessee regarding interstate transport for the 2015 8-hour ozone national
ambient air quality standards (NAAQS). The EPA is also proposing Federal Implementation
Plan (FIP) requirements to address five states' (Arizona, Iowa, Kansas, New Mexico, and
Tennessee) obligations to eliminate significant contribution to nonattainment, or interference
with maintenance, of the 2015 ozone NAAQS in downwind states.1 The FIP would establish
nitrogen oxides (NOx) emissions budgets requiring fossil fuel-fired power plants in five states to
participate in an allowance-based ozone season trading program beginning in 2025. The Agency
is also proposing to establish NOx emissions limitations applicable to certain other industrial
stationary sources in Arizona with the earliest possible compliance date of 2027. Under CAA
section 301(d)(4), the EPA is also proposing to extend the FIP requirements to apply in Indian
country located within the upwind geography of a final action on this proposal, including Indian
reservation lands and other areas of Indian country over which the EPA or a tribe has
demonstrated that a tribe has jurisdiction. This document presents the Economic Impact
Assessment (EIA) for the five states covered under this proposed FIP.
The EPA is proposing to implement the necessary EGU emissions reductions as follows.
The proposed FIP requirements establish ozone season NOx emissions budgets for electricity
generating units (EGUs) in Arizona, Iowa, Kansas, New Mexico, and Tennessee and require
EGUs in these states to participate in the revised version of the Cross-State Air Pollution Rule
(CSAPR) NOx Ozone Season Group 3 Trading Program established in the March 2023 (88 FR
36654 (June 5, 2023)) final Federal "Good Neighbor Plan" for the 2015 Ozone National
Ambient Air Quality Standards (final GNP Rule).2 For states currently covered by the CSAPR
NOx Ozone Season Group 2 Trading Program under SIPs or FIPs (Iowa, Kansas, Tennessee),
1 In 2022, the EPA approved SIP submissions from Iowa and Kansas for the 2015 ozone NAAQS, which in part
addressed the good neighbor provision at CAA section 110(a)(2)(D)(i)(I). Based on updated air quality modeling
and definition of a maintenance receptor, both Iowa and Kansas are projected to contribute more than 1 percent of
the NAAQS to downwind receptors, leading to an error correction and inclusion in the FIP for these two states. 87
FR 22463 (April 15, 2022) (Iowa) 87 FR 19390 (April 4, 2022) (Kansas)
2 Although signed on March 15, 2023, it was published in the Federal Register on June 5, 2023 (88 FR 36654; June
5, 2023). Information about the rule was available starting on March 15, 2023, on the following website ~
https://www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqs.
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the EPA is amending existing FIPs to transition EGU sources in these states from the Group 2
program to the revised Group 3 Trading Program, beginning with the 2025 ozone season. The
EPA is proposing to issue new FIPs for Arizona and New Mexico, which are not currently
covered by any CSAPR NOx ozone season trading program.
In the final GNP Rule, the EPA identified and finalized FIPs for 23 states with emissions
that significantly contribute to nonattainment or interfere with maintenance of the 2015 ozone
NAAQS in other states. The EPA used a unified set of nationwide air quality modeling, air
quality monitoring data, and technical analysis of emissions control opportunities in defining
good neighbor obligations for all states covered in the final GNP Rule. Consistent with the
application of the EPA's 4-step interstate transport framework in prior good neighbor rules like
CSAPR, the EPA applied emissions control requirements on a uniform basis across those states
based on that record.
The EPA is proposing to extend the coverage of the final GNP Rule to the five additional
states based on this same set of data and analysis. Just as the final GNP Rule requirements were
applied across the entire 23-state region, there is nothing unique among the five additional states
that would warrant an approach other than extending the final GNP Rule's requirements to
include these states. These five states were not addressed in the final GNP Rule because the EPA
was not in a position as a procedural matter to take final rulemaking action to disapprove SIPs or
promulgate FIPs for these states at that time. To maintain consistency across all states and ensure
that the allocation of responsibility for eliminating states' significant contribution and
interference with maintenance of the NAAQS in other states is done on an equitable basis, the
EPA is not conducting new analysis within its 4-step interstate transport framework and is
applying in this proposal the nationwide findings and determinations contained in the final GNP
Rule. In this proposal the EPA is applying to these five states its air quality modeling and
contribution information for the analytical years 2023 and 2026 at Steps 1 and 2 of the 4-step
interstate transport framework, its analysis of emissions control opportunities and determinations
of stringency for EGUs and non-EGUs, including overcontrol analysis, at Step 3, and its
implementation programs at Step 4.
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1.1 States Included in the Proposal
The EPA is supplementing the final GNP Rule by proposing to find that emissions
reductions are required from EGU and non-EGU sources in additional states, including Arizona,
Iowa, Kansas, New Mexico, and Tennessee. The EPA will propose to ensure that these NOx
emissions reductions are achieved by issuing FIP requirements for these five states. The EPA is
establishing control stringency levels reflecting installation of state-of-the-art combustion
controls on certain covered EGU sources in emissions budgets beginning in the 2025 ozone
season. The EPA is establishing control stringency levels reflecting installation of new SCR or
SNCR controls on certain covered EGU sources in emissions budgets beginning in the 2027
ozone season and phasing in over two years, i.e., 2027 and 2028. Consistent with the emissions
limitations established for non-EGU sources in the final GNP Rule, this proposed supplemental
action proposes to establish emissions limitations for non-EGU sources in Arizona with the
earliest possible compliance date of 2027.
1.2 Air Quality Modeling Linkages
For the proposed Federal Implementation Plan Addressing Regional Ozone Transport for
the 2015 Ozone National Ambient Air Quality Standards, the EPA performed air quality
modeling using the 2016v2 emissions to provide projections of ozone design values and
contributions in 2023 and 2026 that reflect the effects on air quality of the 2016v2 emissions
platform. The EPA invited and received comments on the 2016v2 emissions inventories and
modeling used to support proposals, including the EPA's previous proposals on Arizona and
Tennesse, and the EPA's final action on Iowa and Kansas, related to interstate transport under
the 2015 ozone NAAQS. In response to these comments, the EPA made a number of updates to
the 2016v2 inventories and model design to construct a 2016v3 emissions platform, which was
used to update the air quality modeling.
The EPA used this updated modeling to inform the final GNP Rule, and in that
rulemaking provided an explanation of the adjustments and other modifications made to
construct the 2016v3 platform. Details on the 2016v3 air quality modeling and the methods for
projecting design values and determining contributions in 2023 and 2026 are described in the
TSD titled "Air Quality Modeling Final Rule TSD - 2015 Ozone NAAQS Good Neighbor
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Plan".3 Additional details related to the updated 2016v3 emissions platform are described in the
TSD titled "Preparation of Emissions Inventories for the 2016v3 North American Emissions
Modeling Platform."4
In this proposed rulemaking, for Steps 1 and 2 of the 4-step interstate transport
framework, the EPA primarily relies on modeling based on the updated 2016v3 emissions
platform. By using the updated modeling results, the EPA is using the most current and
technically appropriate information for this proposed rulemaking.
A summary of the methodology and results of the 2016v3 modeling of 2023, along with
the application of the EPA's Step 1 and Step 2 methodology for identifying receptors and
upwind states that contribute to those receptors can be found in the Air Quality Modeling Final
Rule TSD - 2015 Ozone NAAQS Good Neighbor Plan. The document also contains
explanations on how current measured ozone levels based on data for 2021 and 2022 at other
monitoring sites (i.e., monitoring sites that are not projected to be receptors in 2023 based on air
quality modeling) confirm the likely continuation of elevated ozone levels in 2023 at these
locations and confirm that nearly all upwind states in this proposed action are also linked above 1
percent of the NAAQS to one or more of these monitors. The EPA conducted additional analysis
for 2026 to ensure a complete Step 3 analysis for future ozone transport contributions to
downwind areas. The EPA analyzed 2026 to determine whether any additional emissions
reductions that are impossible to obtain by the 2024 attainment date could still be necessary to
fully address significant contribution.
1.3 Baseline and Analysis Period
To develop and evaluate control strategies for addressing the transport obligations, it is
important to first establish a baseline projection of air quality in the air quality analysis years of
2023 and 2026 taking into account currently on-the-books Federal regulations, enforcement
actions, state regulations, population, expected electricity demand growth, and where possible,
economic growth. Establishing this baseline projection for the analysis allows us to estimate the
3 Available in the docket here: EPA-HQ-OAR-2021-0668-1157.
4 Available in the docket here: EPA-HQ-OAR-2021-0668-1000.
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incremental costs and benefits of the additional emissions reductions that will be achieved by this
proposed rule.5
The analysis in this EIA focuses on benefits, costs, and certain impacts of extending the
policy finalized in the final GNP Rule to the five additional states from 2025 through 2044.
While the air quality analysis year is 2023, given the timing of this proposal we present results
for 2025 because it reflects the timing for installation of state-of-the-art combustion controls on
certain covered EGU sources in emissions budgets beginning in the 2025 ozone season.
Similarly, given the timing of this proposal, we present results for 2028 because this reflects (i)
installation of new SCR or SNCR controls on certain covered EGU sources in emissions budgets
beginning in the 2027 ozone season and phased in over two years, i.e., 2027 and 2028, and (ii)
the date by which we expect non-EGU controls to be fully installed. Costs, benefits, and other
impacts from compliance strategies are likely to persist beyond 2028, and the EIA provides costs
and benefits through 2044.
5 In the modeling in support of the Regulatory Impact Analysis (RIA) for the final GNP Rule, the baseline did not
include the impacts of the Inflation Reduction Act (IRA) due to time limitations. However, the RIA did include an
appendix that captured the impacts of the IRA on the baseline and policy scenarios. The baseline for this EIA
includes the impacts of the IRA.
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2 INDUSTRY SUMMARY
This section briefly describes types of existing power-sector sources affected by the
regulation and provides background on the power sector and electricity generating units (EGUs).
In addition, this section also briefly describes the relevant non-EGU industries included in the
proposed supplemental rule. For a complete discussion of the industries please see Chapter 2 of
the March 2023 final Regulatory Impact Analysis for Final Federal Good Neighbor Plan
Addressing Regional Ozone Transport for the 2015 Ozone National Ambient Air Quality
Standard (Final GNP RIA).6
2.1 EGU
Chapter 2, Section 2.2 of the Final GNP RIA discusses the power sector covered by the
final GNP Rule. 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.
2.2 Non-EGUs
Chapter 2, Section 2.4 of the Final GNP RIA discusses the industries covered by the final
GNP Rule. For this proposed supplemental rule, the EPA estimated that the Pipeline
6 Available in the docket for the rulemaking here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-
0668-1115.
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Transportation of Natural Gas industry would have existing emissions units (reciprocating
internal combustion engines) subject to the proposed emissions limits.
This industry includes the storage of natural gas because the storage is usually done by
the pipeline establishment and because a pipeline is inherently a network in which all the nodes
are interdependent. U.S. Census data for the Pipeline Transportation of Natural Gas industry
(North American Industry Classification System [NAICS] 486210) provides an initial overview
of aggregated industry expenditures on these inputs (Census Bureau, 2021). In 2019, the total
value of shipments was $27.6 billion, annual payroll totaled $3.3 billion, and the industry
included 27,294 employees.
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3 EMISSIONS REDUCTIONS AND COMPLIANCE COSTS
This section reports the EGU, and non-EGU emissions and compliance costs analyses
performed for this proposal, in which the EPA is supplementing the final GNP Rule and
proposing that emissions reductions are required from EGU and non-EGU sources in the five
additional states.
3.1 EGUs
The EPA used the Integrated Planning Model (IPM)7 to conduct the electricity generating
units (EGU) analysis discussed in this section. As explained in detail below, this section presents
analysis for the regulatory controls that limit EGU nitrogen oxides (NOx) ozone season
emissions budgets in the five additional states subject to this action beginning in 2025. The
budget levels are calculated assuming the application of different NOx mitigation technologies.
The analysis for EGUs in the section includes effects from certain provisions of the Inflation
Reduction Act (IRA) of 2022 in the baseline.
3.1.1 Regulatory Policy Evaluated
This proposal establishes NOx emissions budgets requiring fossil fuel-fired EGUs in five
additional states (Arizona, Iowa, Kansas, Tennessee, and New Mexico) to participate in an
allowance-based ozone season (May 1 through September 30) trading program beginning in
2025. The EGUs covered by the FIPs and subject to the budget are fossil-fired EGUs with >25-
megawatt (MW) capacity. Table 3-1 below outlines the control technologies assumed for each of
the five states subject to this action. For details on the derivation of these budgets, please see
Section V.C. of the preamble.
Table 3-1. Regulatory Controls Evaluated for EGUs
Proposed Rule NOx Controls Implemented for EGUs within IPM"'b
1) 2025 onwards: Fully operate existing selective catalytic reduction (SCRs) during ozone season
2) 2025 onwards: Fully operate existing selective non-catalytic reduction (SNCRs) during ozone season
3) In 2025 install state-of-the-art combustion controls0
4) In 2028 model run year, impose Engineering Analysis derived emissions budgets that assume installation of
SCR controls on coal units greater than 100 MW within Arizona that lack SCR controls
5) In 2030 model run year, impose backstop emission rate on coal units greater than 100 MW within Arizona
that lack SCR controls.d
a IPM uses model years to represent the full planning horizon being modeled. By mapping multiple calendar years to
a run year, the model size is kept manageable. For this analysis, IPM maps the run year 2025 to calendar years 2024-
7 Information on IPM can be found at the following link: https://www.epa.gov/airmarkets/power-sector-modeling.
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2026 and ran year 2028 to calendar years 2027-2029. For model details, please see Chapter 2 of the IPM
documentation.
b NOx mass budgets are imposed in all ran years in IPM (2025-2050) consistent with the measures highlighted in
this table.
0 The proposal allows for the reductions associated with state-of-the-art combustion controls to occur by 2026. It is
captured in 2025 in this analysis to fully assess the impact of the mitigation measures occuring prior to 2026.
d For Arizona, which has EGU obligations that are linked in 2026, the EPA is determining that the selected EGU
control stringency also includes emissions reductions commensurate with the retrofit of SCR at coal steam-fired
units of 100 MW or greater capacity.
The illustrative emission budgets in this EIA represent EGU NOx ozone season emission
budgets for each state in 2025 and in 2026.8 The emission budgets for Iowa, Kansas, New
Mexico, and Tennessee were developed using uniform control stringency represented by $1,800
per ton of NOx (2016$) in 2025 (i.e., optimizing existing controls and installation of state-of-the-
art combustion controls). The emission budgets for 2028 for Arizona were developed using a
uniform control stringency represented by $11,000 per ton of NOx (2016$) in 2027 (i.e.,
installation of SCR and SNCR post-combustion controls). The backstop emission rate was
imposed in Arizona in the 2030 run year on all coal units that are greater than 100 MW and lack
SCR controls (except circulating fluidized bed (CFB) units).
Table 3-2 reports the illustrative EGU NOx ozone season emission budgets that are
evaluated in this EIA for the 2025 - 2030 IPM run years; note the additional five states are
presented in the bottom rows of the table. As described above, starting in 2023, IPM is
constrained to disallow emissions from affected EGUs in 22 states subject to the final GNP Rule
to exceed the sum of emissions budgets but for the ability to use banked allowances from
previous years for compliance. In run year 2025, the five additional states are also added to the
program. For individual states, IPM is constrained to disallow emissions from exceeding 121%
of the state emission budget (the assurance levels). In the IPM modeling, no further reductions in
budgets occur after 2030, and budgets remain in place for future years.9 These budgets are
imposed in addition to the control measures outlined in Table 3-1.
8 Mapping each year in the analysis time period to a representative model run year enables IPM to perform multiple
year analyses while keeping the model size manageable. IPM considers the costs in all years in the planning horizon
while reporting results only for model ran years. Run year 2025 is mapped to 2024-26, run year 2028 is mapped to
2027-29, ran year 2030 is mapped to 2030-31, ran year 2035 is mapped to 2032-37, ran year 2040 is mapped to
2038-42, while ran year 2045 is mapped to 2043-47.
9 In 2030 onwards, dynamic budgets may cause the budgets to decrease. While the EPA does not model this feature,
the assumption of continued optimization of existing controls approximates compliance behavior and associated
costs that would result from dynamic budgets.
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Table 3-2. Illustrative NOx Ozone Season Emission Budgets (Tons) Evaluated by IPM Run
Year
Region
2023
Proposed Rule
2025 2028
2030
Alabama
6,595
6,236
6,236
4,610
Arkansas
8,927
4,031
4,031
3,582
Illinois
7,474
5,363
4,555
4,050
Indiana
12,440
8,633
8,633
6,307
Kentucky
13,204
7,862
7,862
7,679
Louisiana
9,311
3,864
2,969
2,969
Maryland
1,206
592
592
592
Michigan
10,275
5,997
5,997
5,691
Minnesota
5,504
2,905
2,905
1,663
Mississippi
5,024
1,859
1,527
1,527
Missouri
12,598
7,329
7,329
6,770
Nevada
2,391
1,051
1,051
818
New Jersey
768
768
768
768
New York
3,858
3,333
3,333
3,333
Ohio
9,134
7,953
6,934
6,399
Oklahoma
10,271
3,842
3,842
3,842
Pennsylvania
8,918
7,146
7,146
4,816
Texas
40,294
22,964
22,407
21,631
Utah
15,755
2,604
2,604
2,604
Virginia
3,065
2,373
2,373
1,951
West Virginia
13,306
9,678
9,678
9,678
Wisconsin
6,295
3,407
3,407
3,407
Arizona
N/A
3,152
3,088
3,088
Iowa
N/A
9,077
9,077
9,077
Kansas
N/A
4,663
4,663
4,663
New Mexico
N/A
1,998
1,998
1,998
Tennessee
N/A
2,666
2,131
1,198
Aggregated State Emission
Budgets
206,616
141,345
137,136
124,711
The state emission budgets in this EIA are illustrative for several reasons. First, they
reflect an estimate of the future budget based on the EPA's preset budget methodology.
However, as described in the preamble, the implemented state budget may be either the preset
budget or the dynamic budget starting in 2026. As noted above, other parameters are used to
capture the dynamic budget impacts in this modeling, as the future heat input needed to derive
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that budget number is not yet known. Second, the budgets are illustrative as the utilized 2025
preset budgets reflect full implementation of existing control optimization and upgrade to state-
of-the-art combustion control potential. However, the proposed rule state emission budgets and
implementation allows the limited number of reductions related to state-of-the-art combustion
control to be realized up through 2026.
3.1.2 Methods for Estimating Emissions Reductions and Costs
On April 6, 2022, the EPA proposed the Federal Implementation Plan Addressing
Regional Ozone Transport for the 2015 Ozone National Ambient Air Quality Standards,10 and on
March 15, 2023 (88 FR 36654 (June 5, 2023)), the EPA finalized the Federal Good Neighbor
Plan Requirements for the 2015 8-hour Ozone National Ambient Air Quality Standards,n EPA
relied on an analytical framework incorporating IPM model outputs to evaluate the EGU cost
and emissions impacts of the final GNP Rule. This EIA relies on the version of IPM that was
used to evaluate the impact of the Inflation Reduction Act on the final GNP Rule, as outlined in
Appendix 4a of the Final GNP RIA.12 The baseline used for this analysis therefore captures the
impacts of the IRA as well as the final GNP Rule.
The 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. The EPA uses the best available information from utilities,
industry experts, gas and coal market experts, financial institutions, and government statistics as
the basis for the detailed power sector modeling in IPM. The model documentation provides
additional information on the assumptions discussed here as well as all other model assumptions
and inputs.13
10 https://www.govinfo.gov/content/pkg/FR-2022-04-06/pdf/2022-04551.pdf
11 https://www.govinfo.gov/content/pkg/FR-2023-06-05/pdf/2023-05744.pdf
12 For details of the framework used to evaluate the EGU compliance costs and emissions outcomes of the
rulemakings, please see Chapter 4 and Appendix 4a of the Final GNP RIA, available at:
https://www.epa.gov/system/files/documents/2023-
03/SAN%208670%20Federal%20Good%20Neighbor%20Plan%2020230315%20RIA_Final.pdf
13 Detailed information and documentation of EPA's Baseline run using IPM (v6), including all the underlying
assumptions, data sources, and architecture parameters can be found on EPA's website at:
https://www.epa.gov/airmarkets/documentation-epas-power-sector-modeling-platform-v6-summer-2021-reference-
case.
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3.1.3 Emissions Reductions and Compliance Cost Assessment for EGUs
The estimates of incremental costs of supplying electricity for the proposed rule are
detailed in Table 3-3. Since the proposed rule generally does not result in significant additional
recordkeeping, monitoring, or reporting requirements for EGUs, the costs associated with
monitoring, recordkeeping, or reporting requirements are not included within the estimates in
this table.
As indicated earlier, the compliance cost estimates are presented in this EIA from 2025
through 2044 and are based on IPM projections.14 Table 3-3 presents the estimated annual
compliance costs, the net present value of these costs over the 2025-44 period, as well as the
annualized costs over the 2025-44 period using a 3.75% discount rate. As presented in Table 3-3,
projected EGU compliance costs peak at $3.4 million (2016$) in the 2028 run year, consistent
with the full tightening of budgets. Compliance costs decline thereafter as budgets do not further
tighten, and conditions are more consistent with baseline outcomes.
Table 3-3. National Power Sector Compliance Cost Estimates (millions of 2016$) for the
Proposed Rule
Proposed Rule
2025-2044 (Net Present Value)
$17
2025-2044 (Annualized)
$1.2
2025 (Annual)
$1.0
2026 (Annual)
$1.0
2027 (Annual)
$3.4
2028 (Annual)
$3.4
2029 (Annual)
$3.4
2030 (Annual)
$0.7
2035 (Annual)
$0.7
2040 (Annual)
$0.3
2044 (Annual)
$0.7
"2025-2044 (Net Present Value)" reflects the net present value of the total estimated annual compliance costs
levelized over the period 2025 through 2044 and discounted using a 3.75 real discount rate.15 This does not include
compliance costs beyond 2044. "2025-2044 (Annualized)" reflects total estimated annual compliance costs levelized
over the period 2025 through 2044 and discounted using a 3.75 real discount rate. This does not include compliance
14 For more information, please see Chapter 2 of the IPM documentation.
15 This table reports compliance costs consistent with expected electricity sector economic conditions. An NPV of
costs was calculated using a 3.75% real discount rate consistent with the rate used in IPM's objective function for
cost-minimization. The NPV of costs was then used to calculate the levelized annual value over a 20-year period
(2025-2044).
12
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costs beyond 2044. "2025 (Annual)" through "2044 (Annual)" costs reflect annual estimates in each of those
years.16 The change in production costs is reflective of the costs borne by the power sector to meet the requirements
of the proposed rule after netting out the tax incentives in the Inflation Reduction Act. However, the production cost
changes do not equal social costs because they do not include a complete accounting of transfers (e.g., taxes paid by
the power sector), the tax incentives provided by the Inflation Reduction Act, and effects in other sectors of the
economy.
The EPA estimated the change in the retail price of electricity (2016$) using the Retail
Price Model (RPM).17 The RPM was developed by ICF for the EPA and uses the IPM estimates
of changes in the cost of generating electricity to estimate the changes in average retail electricity
prices. The prices are average prices over consumer classes (i.e., consumer, commercial, and
industrial) and regions, weighted by the amount of electricity used by each class and in each
region. The RPM combines the IPM annual cost estimates in each of the 64 IPM regions with
EIA electricity market data for each of the 25 electricity supply regions in the electricity market
module of the National Energy Modeling System (NEMS).18
Table 3-4, Table 3-5, and Table 3-6 present the projected percentage changes in the retail
price of electricity for the regulatory control alternative in 2025, 2028, and 2030, respectively.
Consistent with other projected impacts presented above, impacts on average retail electricity
prices at both the national and regional level are projected to be small.
16 Cost estimates include financing charges on capital expenditures that would reflect a transfer and would not
typically be considered part of total social costs.
17 See documentation available at: https://www.epa.gov/airmarkets/retail-price-model
18 See documentation available at:
https://www.eia.gov/outlooks/aeo/nems/documentation/electricity/pdf/m068(2020).pdf
13
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Table 3-4. Average Retail Electricity Price by Region for the Baseline and the Regulatory
Control Alternative, 2025
All Sector
2025 Average Retail Electricity
Price
(2016 mills/kWh)
Percent Change
from Baseline
Region
Baseline
Proposed
Rule
Proposed Rule
TRE
79.0
79.0
0.0%
FRCC
97.0
97.0
0.0%
MISW
94.1
94.1
0.0%
MISC
88.3
88.3
0.0%
MISE
94.1
94.1
0.0%
MISS
79.0
79.0
0.0%
ISNE
138.7
138.7
0.0%
NYCW
181.6
181.6
0.0%
NYUP
117.1
117.1
0.0%
PJME
109.8
109.8
0.0%
PJMW
86.0
86.0
0.0%
PJMC
77.8
77.8
0.0%
PJMD
67.5
67.5
0.0%
SRCA
91.3
91.3
0.0%
SRSE
94.4
94.4
0.0%
SRCE
69.8
69.8
0.0%
SPPS
78.4
78.4
0.0%
SPPC
100.8
100.8
0.0%
SPPN
62.9
62.9
0.0%
SRSG
96.9
96.9
0.0%
CANO
152.8
152.8
0.0%
CASO
183.7
183.7
0.0%
NWPP
72.1
72.1
0.0%
RMRG
89.8
89.8
0.0%
BASN
85.7
85.7
0.0%
NATIONAL
96.1
96.1
0.0%
14
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Table 3-5. Average Retail Electricity Price by Region for the Baseline and the Regulatory
Control Alternative, 2028
All Sector
2028 Average Retail Electricity
Price
(2016 mills/kWh)
Percent Change
from Baseline
Region
Baseline
Proposed
Rule
Proposed Rule
TRE
74.1
74.1
0.0%
FRCC
90.0
90.0
0.0%
MISW
90.4
90.4
0.0%
MISC
85.0
85.0
0.0%
MISE
95.9
95.9
0.0%
MISS
74.5
74.5
0.0%
ISNE
129.9
129.9
0.0%
NYCW
179.9
179.9
0.0%
NYUP
113.9
113.9
0.0%
PJME
100.8
100.8
0.0%
PJMW
84.6
84.6
0.0%
PJMC
73.0
73.0
0.0%
PJMD
68.2
68.2
0.0%
SRCA
87.1
87.1
0.0%
SRSE
88.2
88.2
0.0%
SRCE
66.3
66.3
0.0%
SPPS
75.1
75.1
0.0%
SPPC
97.1
97.1
0.0%
SPPN
63.9
63.9
0.0%
SRSG
90.2
90.2
0.0%
CANO
153.8
153.8
0.0%
CASO
185.7
185.7
0.0%
NWPP
70.0
70.0
0.0%
RMRG
83.8
83.8
0.0%
BASN
81.9
81.9
0.0%
NATIONAL
92.1
92.1
0.0%
15
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Table 3-6. Average Retail Electricity Price by Region for the Baseline and the Regulatory
Control Alternative, 2030
All Sector
2030 Average Retail Electricity
Price
(2016 mills/kWh)
Percent Change
from Baseline
Region
Baseline
Proposed
Rule
Proposed Rule
TRE
78.8
78.8
0.0%
FRCC
90.7
90.7
0.0%
MISW
87.8
87.8
0.0%
MISC
83.7
83.7
0.0%
MISE
83.5
83.5
0.0%
MISS
74.3
74.3
0.0%
ISNE
137.0
137.0
0.0%
NYCW
182.0
182.0
0.0%
NYUP
109.0
109.0
0.0%
PJME
101.4
101.4
0.0%
PJMW
86.2
86.2
0.0%
PJMC
80.3
80.3
0.0%
PJMD
68.6
68.6
0.0%
SRCA
86.7
86.7
0.0%
SRSE
87.3
87.3
0.0%
SRCE
65.2
65.2
0.0%
SPPS
72.4
72.4
0.0%
SPPC
90.5
90.5
0.0%
SPPN
62.0
62.5
0.9%
SRSG
89.0
89.0
0.0%
CANO
161.0
161.0
0.0%
CASO
188.4
188.4
0.0%
NWPP
70.5
70.5
0.0%
RMRG
82.6
82.6
0.0%
BASN
80.6
80.6
0.0%
NATIONAL
92.3
92.3
0.0%
As indicated earlier, the NOx emissions reductions are presented in this EIA from 2025
through 2044 and are based on IPM projections. IPM is operating existing and newly installed
controls seasonally based on historical operation patterns and seasonal and annual emission
constraints within the model. Table 3-7 presents the estimated reduction in power sector ozone
season NOx emissions resulting from compliance with the proposed rule in the five additional
states, as well as the impact on other states.
16
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Table 3-7. EGU Ozone Season NOx Emissions and Emissions Changes (tons) for the
Baseline run and Proposed Rule from 2025 - 2044
Ozone Season NOx
Total Emissions
Change from
Baseline run
(Tons)
Baseline
Proposal
5 States
23,701
22,243
-1,458
2025
Other States
234,186
234,186
0
Nationwide
257,887
256,428
-1,459
5 States
23,701
22,243
-1,458
2026
Other States
234,186
234,186
0
Nationwide
257,887
256,428
-1,459
5 States
18,270
17,012
-1,258
2027
Other States
189,571
189,583
12
Nationwide
207,840
206,595
-1,245
5 States
18,270
17,012
-1,258
2028
Other States
189,571
189,583
12
Nationwide
207,840
206,595
-1,245
5 States
18,270
17,012
-1,258
2029
Other States
189,571
189,583
12
Nationwide
207,840
206,595
-1,245
5 States
16,184
15,427
-756
2030
Other States
150,909
150,910
0
Nationwide
167,093
166,337
-756
5 States
5,967
5,453
-513
2035
Other States
94,061
94,053
-8
Nationwide
100,028
99,506
-521
5 States
5,623
4,901
-722
2040
Other States
77,971
78,010
39
Nationwide
83,594
82,910
-683
5 States
5,271
4,549
-722
2044
Other States
71,506
71,506
0
Nationwide
76,778
76,055
-722
In addition to the ozone season NOx reductions, there will also be reductions of other air
emissions associated with EGUs burning fossil fuels (i.e., co-pollutants) that result from
compliance strategies to reduce seasonal NOx emissions. These include the annual total changes
in emissions of NOx, SO2, CO2, and direct PM2.5 emissions. The emissions reductions are
presented in Table 3-8 below.
17
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Table 3-8. EGU Annual Emissions and Emissions Changes for Annual NOx, SO2, PM2.5,
and CO2) for the Baseline run and Proposed Rule from 2025 - 2044
Annual NOx
Total Emissions
Change from
(Tons)
Baseline
Proposal
Baseline run
5 States
47,758
46,237
-1,521
2025
Other States
583,583
583,577
-6
Nationwide
631,341
629,814
-1,527
5 States
47,758
46,237
-1,521
2026
Other States
583,583
583,577
-6
Nationwide
631,341
629,814
-1,527
5 States
38,969
37,647
-1,322
2027
Other States
453,214
453,228
14
Nationwide
492,183
490,875
-1,308
5 States
38,969
37,647
-1,322
2028
Other States
453,214
453,228
14
Nationwide
492,183
490,875
-1,308
5 States
38,969
37,647
-1,322
2029
Other States
453,214
453,228
14
Nationwide
492,183
490,875
-1,308
5 States
34,078
33,294
-784
2030
Other States
351,489
351,507
18
Nationwide
385,567
384,801
-766
5 States
13,230
12,716
-513
2035
Other States
199,631
199,628
-4
Nationwide
212,861
212,344
-517
5 States
8,370
7,648
-722
2040
Other States
158,504
158,545
41
Nationwide
166,874
166,193
-682
5 States
6,813
6,091
-722
2044
Other States
140,729
140,729
0
Nationwide
147,543
146,820
-722
Annual SO2
Total Emissions
Change from
(Tons)
Baseline
Proposal
Baseline run
5 States
33,535
33,533
-2
2025
Other States
776,891
776,434
-457
Nationwide
810,426
809,967
-459
5 States
33,535
33,533
-2
2026
Other States
776,891
776,434
-457
Nationwide
810,426
809,967
-459
5 States
23,648
23,645
-3
2027
Other States
431,802
431,810
8
18
-------
Nationwide
455,450
455,455
5
5 States
23,648
23,645
-3
2028
Other States
431,802
431,810
8
Nationwide
455,450
455,455
5
5 States
23,648
23,645
-3
2029
Other States
431,802
431,810
8
Nationwide
455,450
455,455
5
5 States
20,414
20,411
-3
2030
Other States
265,782
265,783
1
Nationwide
286,196
286,194
-2
5 States
4,107
4,107
0
2035
Other States
107,014
107,013
-2
Nationwide
111,121
111,119
-2
5 States
3,010
3,010
0
2040
Other States
75,111
75,113
2
Nationwide
78,121
78,123
2
5 States
1,908
1,908
0
2044
Other States
53,665
53,665
0
Nationwide
55,573
55,573
0
Annual PM2.5
Total Emissions
Change from
(Tons)
Baseline
Proposal
Baseline run
5 States
6,594
6,591
-3
2025
Other States
75,414
75,411
-3
Nationwide
82,008
82,002
-6
5 States
6,594
6,591
-3
2026
Other States
75,414
75,411
-3
Nationwide
82,008
82,002
-6
5 States
5,675
5,671
-5
2027
Other States
67,607
67,611
4
Nationwide
73,282
73,282
-1
5 States
5,675
5,671
-5
2028
Other States
67,607
67,611
4
Nationwide
73,282
73,282
-1
5 States
5,675
5,671
-5
2029
Other States
67,607
67,611
4
Nationwide
73,282
73,282
-1
5 States
5,182
5,179
-4
2030
Other States
59,919
59,920
1
Nationwide
65,101
65,099
-2
5 States
1,753
1,753
0
2035
Other States
43,312
43,309
-3
19
-------
Nationwide
45,065
45,062
-3
5 States
1,304
1,304
0
2040
Other States
38,320
38,324
4
Nationwide
39,624
39,628
4
5 States
1,266
1,266
0
2044
Other States
36,921
36,921
0
Nationwide
38,187
38,187
0
Annual CO2
Total Emissions
Change from
(Thousand short tons)
Baseline
Proposal
Baseline run
5 States
107,778
107,762
-15
2025
Other States
1,368,872
1,368,848
-24
Nationwide
1,476,650
1,476,611
-39
5 States
107,778
107,762
-15
2026
Other States
1,368,872
1,368,848
-24
Nationwide
1,476,650
1,476,611
-39
5 States
95,787
95,765
-21
2027
Other States
1,194,825
1,194,818
-7
Nationwide
1,290,611
1,290,583
-28
5 States
95,787
95,765
-21
2028
Other States
1,194,825
1,194,818
-7
Nationwide
1,290,611
1,290,583
-28
5 States
95,787
95,765
-21
2029
Other States
1,194,825
1,194,818
-7
Nationwide
1,290,611
1,290,583
-28
5 States
87,596
87,564
-33
2030
Other States
1,023,383
1,023,386
2
Nationwide
1,110,980
1,110,950
-30
5 States
36,078
36,078
0
2035
Other States
667,318
667,320
2
Nationwide
703,395
703,397
2
5 States
26,813
26,813
0
2040
Other States
582,723
582,727
4
Nationwide
609,536
609,540
4
5 States
25,965
25,965
0
2044
Other States
560,592
560,593
0
Nationwide
586,557
586,557
0
20
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3.2 Non-EGUs
On April 6, 2022, the EPA proposed the Federal Implementation Plan Addressing
Regional Ozone Transport for the 2015 Ozone National Ambient Air Quality Standards,19 and on
March 15, 2023 (88 FR 36654 (June 5, 2023)), the EPA finalized the Federal Good Neighbor
Plan Requirements for the 2015 8-hour Ozone National Ambient Air Quality Standards20 For the
April 6, 2022 proposal, the EPA developed an analytical framework to facilitate decisions about
industries and emissions unit types for including emissions units in the non-electric generating
unit "sector" (non-EGUs) in a proposed Federal Implementation Plan (FIP) for the 2015 ozone
national ambient air quality standards (NAAQS) transport obligations. A February 28, 2022
memorandum documents the analytical framework that the EPA used to identify industries and
emissions unit types included in the above proposed and final actions.21 In addition, for the
March 15, 2023 (88 FR 36654 (June 5, 2023)) final GNP Rule, the EPA prepared a
memorandum summarizing the emissions unit types, applicability criteria, emissions limits,
estimated number of emissions units captured by the applicability criteria, and estimated
emissions reductions and costs for the year 2026.22
As discussed in Section 1.1, in this action the EPA is proposing FIP requirements to
address five additional states' transport obligations for the 2015 ozone NAAQS. This proposed
FIP establishes emissions limitations for the industries and emissions unit types included in the
final GNP Rule for existing and new sources in Arizona, with the earliest possible compliance
date of 2027.
3.2.1 Methods for Estimating Emissions Reductions and Costs
For a detailed discussion of methods for estimating emissions unit types, emissions
reductions, and costs, see the memorandum titled Summary of Final Rule Applicability Criteria
and Emissions Limits for Non-EGU Emissions Units, Assumed Control Technologies for Meeting
19 https://www.govinfo.gov/content/pkg/FR-2022-04-06/pdf/2022-04551.pdf
20 https://www.govinfo.gov/content/pkg/FR-2023-06-05/pdf/2023-05744.pdf
21 The memorandum titled Screening Assessment of Potential Emissions Reductions, Air Quality Impacts, and Costs
from Non-EGU Emissions Units for 2026 is available in the docket here:
https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0150.
22 The memorandum titled Summary of Final Rule Applicability Criteria and Emissions Limits for Non-EGU
Emissions Units, Assumed Control Technologies for Meeting the Final Emissions Limits, and Estimated Emissions
Units, Emissions Reductions, and Costs is available in the docket here: https://www.regulations.gov/document/EPA-
HQ-OAR-2021 -0668-0956.
21
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the Final Emissions Limits, and Estimated Emissions Units, Emissions Reductions, and Costs.23
Based on the review of RACT, NSPS, NESHAP rules, as well as SIPs, consent decrees, and
permits, as in the final GNP Rule the EPA assumed certain control technologies could meet the
proposed emissions limits.
3.2.2 Emissions Reductions and Compliance Cost Assessment for Non-EGUs
Using the list of emissions units estimated to be captured by the applicability criteria, the
assumed control technologies that would meet the emissions limits, and information on control
efficiencies and default cost/ton values from the control measures database,24 the EPA estimated
NOx emissions reductions and costs for the year 2026. We estimated emissions reductions using
the actual emissions from the 2019 emissions inventory.
In the proposed regulatory provisions that implement these emissions limits at Step 4, the
EPA incorporated mechanisms that are designed to accommodate unique circumstances on a
unit-specific basis, such as allowing for an extension of time to install controls or developing an
alternative emissions limit where it can be established to be necessary. Given these provisions,
the EPA analyzed emissions reductions for the analytic year of 2026 with the earliest possible
compliance date of 2027 and full compliance expected by the 2028 ozone season. Because we
assume the emissions reductions and costs for non-EGUs are the same each year over the
analysis period, we present results for non-EGU emissions reductions and costs starting in 2028.
The EPA did not estimate emissions reductions of SO2, PM2.5, CO2 and other pollutants that may
be associated with controls on non-EGU emissions units.
The estimates presented below using the 2019 inventory and information from the control
measures database identify proxies for emissions units, as well as emissions reductions, and costs
associated with the assumed control technologies that would meet the proposed emissions limits.
Emissions units subject to the proposed rule emissions limits may be different than those
estimated in this assessment; the estimated emissions reductions from and costs to meet the
proposed rule emissions limits may be different than those estimated in this assessment. The
costs do not include monitoring, recordkeeping, reporting, or testing costs.
23 Available in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0956.
24 More information about the control measures database (CMDB) can be found at the following link:
https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
22
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Table 3-9 summarizes the industries, emissions unit types, assumed control technologies,
estimated total annual costs, and estimated ozone season NOx emissions reductions in 2026. For
additional summaries see the memorandum titled Non-EGU Applicability Criteria and Estimated
Emissions Reductions and Costs Proposed Supplemental.
Table 3-9. Summary of Non-EGU Industries, Emissions Unit Types, Assumed Control
Technologies, Estimated Total Annual Costs (2016$), Ozone Season NOx Emissions
Reductions in 2026
Assumed Control
Annual Costs
Ozone Season
Industry /Industries
Emissions Unit Type
Technologies that Meet
Proposed Emissions Limits
(million
2016$)
Emissions
Reductions (tons)
Pipeline
Transportation of
Natural Gas
Reciprocating
Internal Combustion
Engine
Layered Combustion
(2-cycle Lean Burn)
4.3
329
3.3 Total Emissions Reductions and Compliance Costs for EGUs and Non-EGUs
For select years between 2025 and 2044, Table 3-10 below summarizes the total annual
estimated emissions reductions and compliance costs for EGUs and non-EGUs for the five states
included in the proposed rule. EGU emission budgets for the 2025 and 2028 run years are
derived through the operation of existing controls and the installation of state-of-the-art
combustion controls, and the installation of SCR controls at large coal fired power plants that
currently lack them in Arizona. As such costs peak in the 2028 run year at $3.4 million (2016$).
Post 2030 modeled budgets no longer tighten (although controls are assumed to continue to
operate fully) and the generation mix converges to levels consistent with the baseline, resulting
in lower cost impacts. Non-EGU costs are analyzed starting in 2028 when full compliance is
anticipated and remain constant over the analytic period at $4.3 million each year (2016$).
Table 3-11 below summarizes the present value (PV) and equivalent annualized value
(EAV) of the total national compliance cost estimates for EGUs and non-EGUs for the proposed
rule. We present the PV of the costs over the twenty-year period 2025 to 2044. We also present
the EAV, which represents a flow of constant annual values that, had they occurred in each year
from 2025 to 2044, would yield a sum equivalent to the PV. The EAV represents the value of a
typical cost for each year of the analysis. The PV and EAV from EGUs and non-EGUs are $67
million and $4.5 million annually using a 3 percent discount rate and $45 million and $4.2
million annually using a 7 percent discount rate.
23
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Table 3-10. Total Estimated NOx Emissions Reductions (ozone season, thousand tons) and
Compliance Costs for EGUs and non-EGUs (million 2016$), 2025-2044
EGUs
Non-EGUs
Total
EGUs
Non-EGUs
Total
Emissions Reductions
Compliance Costs
(Ozone season, tons'
(Million 2016$)
2025
1,459
-
1,459
$1.0
-
$1.0
2026
1,459
-
1,459
$1.0
-
$1.0
2027
1,245
-
1,245
$3.4
-
$3.4
2028
1,245
329
1,574
$3.4
$4.3
$7.7
2029
1,245
329
1,574
$3.4
$4.3
$7.7
2030
756
329
1,085
$0.7
$4.3
$5.0
2035
513
329
842
$0.7
$4.3
$5.0
2040
683
329
1,012
$0.3
$4.3
$4.6
2044
722
329
1,051
$0.7
$4.3
$4.6
Note: For the EGU emission reduction and cost estimates IPM uses model years to represent the full planning
horizon being modeled. For this analysis, IPM considers the costs in all years in the planning horizon while
reporting results only for model run years. Run year 2025 is mapped to calendar years 2024-26, run year 2028 is
mapped to calendar years 2027-29, run year 2030 is mapped to calendar years 2030-31, run year 2035 is mapped to
calendar years 2032-37, run year 2040 is mapped to calendar years 2038-42, and run year 2045 is mapped to
calendar years 2043-47.
Table 3-11. Total National Compliance Cost Estimates (millions of 2016$) for the Proposed
Rule
Present Value
Equivalent Annualized Value
3 Percent
7 Percent
3 Percent
7 Percent
EGU 2025-2044
$16
$13
$1.1
$1.2
Non-EGU 2025-2044
$50
$32
$3.4
$3.0
Total 2025-2044
$67
$45
$4.5
$4.2
3.4 Small Business Screening Assessment
For the proposed rule, the EPA performed a small entity screening analysis for impacts
on all affected EGUs and non-EGU facilities by comparing compliance costs to historic revenues
at the ultimate parent company level. This is known as the cost-to-revenue or cost-to-sales test,
or the "sales test." The sales test is an impact methodology the EPA employs in analyzing entity
impacts as opposed to a "profits test," in which annualized compliance costs are calculated as a
share of profits. The sales test is frequently used because revenues or sales data are commonly
available for entities impacted by the EPA regulations, and profits data normally made available
are often not the true profit earned by firms because of accounting and tax considerations. Also,
the use of a sales test for estimating small business impacts for a rulemaking is consistent with
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guidance offered by the EPA on compliance with the Regulatory Flexibility Act (RFA)25 and is
consistent with guidance published by the U.S. Small Business Administration's (SBA) Office of
Advocacy that suggests that cost as a percentage of total revenues is a metric for evaluating cost
increases on small entities in relation to increases on large entities (SBA, 2017).
Making a no SISNOSE (significant economic impacts on a substantial number of small
entities) determination reflects an assessment of whether an estimated economic impact is
significant and whether that impact affects a substantial number of small entities. We prepared
an analysis of small entity impacts for EGUs and non-EGUs in 2028 separately and combined
the 2028 results for a SISNOSE determination for the proposed rule. We used 2028 to be
consistent with the year of anticipated full compliance. For a complete discussion of the
methodology and data used for the small business analysis for both EGU and non-EGU facilities
please see Chapter 6 of the Final GNP RIA.
For EGUs in 2028, the analysis indicates that 34 units see a +/- 1 percent change in either
summer NOx emissions, summer generation or summer fuel use. Of these units, 4 units are
owned by entities that are classified as small entities. None of these are projected to have a cost
impact of greater than 1 percent of their revenues. Further, for the proposed supplemental action
in 2028 for non-EGUs, there are six engines in Arizona estimated to be impacted by this
proposal. Those six engines are owned by a single large company with $16.6 billion in revenue
in 2021.
Based on this analysis, for this proposed rule overall we conclude that the estimated costs
for the proposed rule will not have a significant economic impact on a substantial number of
small entities (SISNOSE).
25 The RFA compliance guidance to the EPA rule writers can be found at
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4 BENEFITS
The Proposed Supplemental Federal Good Neighbor Plan Addressing Regional Ozone
Transport for the 2015 Ozone National Ambient Air Quality Standards is expected to reduce
emissions of nitrogen oxides (NOx) transported from states that contribute significantly to
nonattainment or interfere with maintenance of the 2015 Ozone National Ambient Air Quality
Standards (NAAQS) in downwind states. Implementing the proposed rule is expected to reduce
emissions of NOx, which will in turn reduce concentrations of ground-level ozone and fine
particles (PM2.5); the proposed rule is also projected to reduce sulfur dioxide (SO2), direct PM2.5
emissions, and carbon dioxide (CO2) emissions from EGUs. This section reports the estimated
monetized health benefits from reducing concentrations of ozone and PM2.5 for the five
additional states included in this proposed supplemental rulemaking. The section also reports the
estimated monetized climate benefits from reducing CO2 emissions from EGUs.
4.1 Estimated Human Health Benefits
This section describes the methods used to estimate the benefits to human health of
reducing concentrations of ozone and PM2.5 from affected electricity generating units (EGUs)
and non-electricity generating units (non-EGUs). This analysis uses a reduced-form technique
called benefit per ton to quantify benefits. The approach for quantifying the number and value of
air pollution-attributable premature deaths and illnesses with the benefit per ton method is
described in the Technical Support Document (TSD) titled Estimating the Benefit per Ton of
Reducing Directly-Emitted PM2.5, PM2.5 Precursors and Ozone Precursors from 21 Sectors (U.S.
EPA, 2023a). A second Technical Support Document titled EstimatingPM25- and Ozone-
Attributable Health Benefits (U.S. EPA, 2023b) describes the rationale for selecting health
endpoints to quantify; the demographic, health, and economic data used; modeling assumptions;
and the techniques for quantifying uncertainty.
The procedure for calculating the benefit per ton ozone and PM2 coefficients follows three
steps:
1. Using source apportionment photochemical modeling, predict ozone
concentrations resulting from VOC or summer season NOx and predict annual
average ambient concentrations of primary PM2 5, nitrate, and sulfate attributable
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to each of 21 emission sectors across the Continental U.S. The source
apportionment modeling for the power sector uses the 2017 NEI.
2. For each sector, estimate the health impacts, and the economic value of these
impacts, associated with the attributable ambient concentrations of ozone from
NOx and PM2.5 from primary PM2 5, nitrate, and sulfate using the environmental
Benefits Mapping and Analysis Program-Community Edition (BenMAP-CE
vl.5.8) and the risk and valuation estimates documented in the Estimating PM2 5-
and Ozone-Attributable Health Benefits TSD.
3. For each sector, divide the PM2.5-related health impacts attributable to each type
of PM2.5, and the monetary value of these impacts, by the level of associated
precursor emissions. That is, primary PM2.5 benefits are divided by direct PM2.5
emissions, sulfate benefits are divided by SO2 emissions, and nitrate benefits are
divided by NOx emissions. For each sector, divide the ozone-related benefits by
the change in summer season VOC or NOx.
For this proposal, we monetized health benefits of avoided ozone and PIVh.s-attributable
premature deaths and illnesses by multiplying a benefit per ton coefficient by the expected state
NOx ozone season and primary PM25, NOx and SO2 emissions changes described in Section
3.1.3. Benefit per ton estimates are currently available for 2025, 2030, 2035, and 2040.26 When
estimating the value of improved air quality over a multi-year time horizon, the ozone analysis
applies state-level benefit per ton estimates for EGUs from 2025 for the years 2025-2027, from
2030 for the years 2028-2031, from 2035 for the years 2032-2037, and from 2040 for the years
2038-2044. For the non-EGUs, the regional benefit per ton estimates were applied from 2030 for
the years 2028-2031, from 2035 for the years 2032-2037, and from 2040 for the years 2038-
2044. The benefit per ton calculations for EGUs and non-EGUs have been combined in Tables 4-
1, 4-2, 4-3 and 4-4. Table 4-3 and Table 4-4 present streams of benefits discounted over the
SAB-recommended 20-year segmented lag at 3 and 7 percent discount rates.
26 Benefit per ton estimates can be found at: https://www.epa.gov/benmap/estimating-benefit-ton-reducing-directlv-
emitted-pm25-pm25-precursors-and-ozone-precursors
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Table 4-1. Estimated Monetized Health Benefits of Avoided Ozone and PM2.5-Attributable
Premature Mortality and Illness for the Proposed Rule Emissions Reductions (EGUs and
Non-EGUs), 2025-2044: Monetized Benefits Quantified as Sum of Avoided Morbidity
Health Effects and Avoided Long-term Ozone and PM2.5 Mortality (3 percent discount
rate; million 2016$)
Year
Ozone
PM25
Combined Total
2025
$16 and $110
$32 and $69
$48 and $180
2026
$16 and $110
$32 and $69
$48 and $180
2027
$14 and $96
$4.7 and $9.9
$19 and $110
2028
$18 and $140
$8.3 and $17
$26 and $160
2029
$18 and $140
$8.3 and $17
$26 and $160
2030
$13 and $99
$5.4 and $11
$18 and $110
2031
$13 and $99
$5.4 and $11
$18 and $110
2032
$12 and $95
$4.9 and $9.8
$17 and $100
2033
$12 and $95
$4.9 and $9.8
$17 and $100
2034
$12 and $95
$4.9 and $9.8
$17 and $100
2035
$12 and $95
$4.9 and $9.8
$17 and $100
2036
$12 and $95
$4.9 and $9.8
$17 and $100
2037
$12 and $95
$4.9 and $9.8
$17 and $100
2038
$14 and $120
$4.8 and $9.5
$19 and $130
2039
$14 and $120
$4.8 and $9.5
$19 and $130
2040
$14 and $120
$4.8 and $9.5
$19 and $130
2041
$14 and $120
$4.8 and $9.5
$19 and $130
2042
$14 and $120
$4.8 and $9.5
$19 and $130
2043
$15 and $130
$6 and $12
$21 and $140
2044
$15 and $130
$6 and $12
$21 and $140
Notes: Values rounded to two significant figures. The benefits are associated with two point estimates from two
different epidemiologic studies. The lower estimates include ozone mortality estimated using the pooled
Katsouyanni et al. (2009), the Zanobetti and Schwartz (2008) short-term risk estimates, and the Wu et al. (2020)
long-term PM2 5 exposure mortality risk estimate. The higher estimates include ozone mortality estimated using the
Turner et al. (2016) long-term risk estimate and the Pope et al. (2019) long-term PM2 5 exposure mortality risk
estimate. Health benefits are discounted at a rate of 3 and 7 percent over the SAB-recommended 20-year segmented
lag. Individual values in the table are not further discounted for purposes of estimating a present value.
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Table 4-2. Estimated Monetized Health Benefits of Avoided Ozone and PM2.5-Attributable
Premature Mortality and Illness for the Proposed Rule Emissions Reductions (EGUs and
Non-EGUs), 2025-2044: Monetized Benefits Quantified as Sum of Avoided Morbidity
Health Effects and Avoided Long-term Ozone and PM2.5 Mortality (7 percent discount
rate; million 2016$)
Year
Ozone
PM25
Combined Total
2025
$14 and $100
$29 and $62
$43 and $160
2026
$14 and $100
$29 and $62
$43 and $160
2027
$12 and $86
$4.2 and $!
3.9
$16 and $95
2028
$16 and $130
$7.4 and $15
$23 and $150
2029
$16 and $130
$7.4 and $15
$23 and $150
2030
$11 and $89
$4.9 and $10
$16 and $99
2031
$11 and $89
$4.9 and $10
$16 and $99
2032
$10 and $84
$4.4 and $!
3.9
$14 and $93
2033
$10 and $84
$4.4 and $!
3.9
$14 and $93
2034
$10 and $84
$4.4 and $!
3.9
$14 and $93
2035
$10 and $84
$4.4 and $!
3.9
$14 and $93
2036
$10 and $84
$4.4 and $!
3.9
$14 and $93
2037
$10 and $84
$4.4 and $!
3.9
$14 and $93
2038
$13 and $110
$4.3 and $!
3.5
$17 and $120
2039
$13 and $110
$4.3 and $!
3.5
$17 and $120
2040
$13 and $110
$4.3 and $!
3.5
$17 and $120
2041
$13 and $110
$4.3 and $!
3.5
$17 and $120
2042
$13 and $110
$4.3 and $!
3.5
$17 and $120
2043
$13 and $110
$5.4 and $11
$18 and $120
2044
$13 and $110
$5.4 and $11
$18 and $120
Notes: Values rounded to two significant figures. The benefits are associated with two point estimates from two
different epidemiologic studies. The lower estimates include ozone mortality estimated using the pooled
Katsouyanni et al. (2009), the Zanobetti and Schwartz (2008) short-term risk estimates, and the Wu et al. (2020)
long-term PM2 5 exposure mortality risk estimate. The higher estimates include ozone mortality estimated using the
Turner et al. (2016) long-term risk estimate and the Pope et al. (2019) long-term PM2 5 exposure mortality risk
estimate. Health benefits are discounted at a rate of 3 and 7 percent over the SAB-recommended 20-year segmented
lag. Individual values in the table are not further discounted for purposes of estimating a present value.
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Table 4-3. Stream of Discounted Human Health Benefits for the Proposed Rule Emissions
Reductions (EGUs and Non-EGUs), 2025-2044: Monetized Benefits Quantified as Sum of
Avoided Morbidity Health Effects and Avoided Long-term Ozone and PM2.5 Mortality (3
percent discount rate; million 2016$)
Year
Proposed Rule
2025
$170
2026
$160
2027
$94
2028
$140
2029
$130
2030
$89
2031
$87
2032
$80
2033
$78
2034
$76
2035
$74
2036
$71
2037
$69
2038
$83
2039
$81
2040
$78
2041
$76
2042
$74
2043
$79
2044
$76
Present Value (PV)
$1,900
Equivalent Annualized Value (EAV)
$130
Note: Values rounded to two significant figures. Benefits calculation includes ozone-related morbidity effects and
avoided ozone-attributable deaths quantified using the Turner et al. (2016) long-term risk estimate and the Pope et
al. (2019) long-term PM2 5 exposure mortality risk estimate, which are the higher of the two estimates presented in
Table 4-1. We assume that there is a cessation lag between the change in exposures and the total realization of
changes in mortality effects. Specifically, we assume that some of the incidences of premature mortality related to
exposures occur in a distributed fashion over the 20 years following exposure, which affects the valuation of
mortality benefits at different discount rates.
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Table 4-4. Stream of Discounted Human Health Benefits for the Proposed Rule Emissions
Reductions (EGUs and Non-EGUs), 2025-2044: Monetized Benefits Quantified as Sum of
Avoided Morbidity Health Effects and Avoided Long-term Ozone and PM2.5 Mortality (7
percent discount rate; million 2016$)
Year
Proposed Rule
2025
$140
2026
$130
2027
$72
2028
$100
2029
$97
2030
$62
2031
$58
2032
$51
2033
$47
2034
$44
2035
$41
2036
$39
2037
$36
2038
$43
2039
$40
2040
$38
2041
$35
2042
$33
2043
$31
2044
$29
Present Value (PV)
$1,200
Equivalent Annualized Value (EAV)
$110
Note: Values rounded to two significant figures Benefits calculation includes ozone-related morbidity effects and
avoided ozone-attributable deaths quantified using the Turner et al. (2016) long-term risk estimate and the Pope et
al. (2019) long-term PM2 5 exposure mortality risk estimate, which are the higher of the two estimates presented in
Table 4-1. We assume that there is a cessation lag between the change in exposures and the total realization of
changes in mortality effects. Specifically, we assume that some of the incidences of premature mortality related to
exposures occur in a distributed fashion over the 20 years following exposure, which affects the valuation of
mortality benefits at different discount rates.
4.2 Climate Benefits
We estimate the climate benefits for this proposed rulemaking using estimates of the
social cost of greenhouse gases (SC-GHG), specifically the social cost of carbon (SC-CO2). The
SC-CO2 is the monetary value of the net harm to society associated with a marginal increase in
CO2 emissions in a given year, or the benefit of avoiding that increase. In principle, SC-CO2
includes the value of all climate change impacts (both negative and positive), including (but not
limited to) changes in net agricultural productivity, human health effects, property damage from
increased flood risk, natural disasters, disruption of energy systems, risk of conflict,
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environmental migration, and the value of ecosystem services. The SC-CO2, therefore, reflects
the societal value of reducing emissions of the gas in question by one metric ton and is the
theoretically appropriate value to use in conducting benefit-cost analyses of policies that affect
CO2 emissions. In practice, data and modeling limitations naturally restrain the ability of SC-
CO2 estimates to include all the important physical, ecological, and economic impacts of climate
change, such that the estimates are a partial accounting of climate change impacts and will
therefore, tend to be underestimates of the marginal benefits of abatement. For a complete
discussion of the methodology used for calculating the estimated climate benefits please see
Chapter 5.2 of the Final GNP RIA.27
Table 4-5 shows the estimated monetary value of the estimated changes in CO2 emissions
from EGUs expected to occur over 2025-2044 for this proposed rule. The EPA estimated the
dollar value of the C02-related effects for each analysis year between 2025 and 2044 by applying
the SC-CO2 estimates to the estimated changes in CO2 emissions in the corresponding year.
Table 4-5. Stream of Climate Benefits from EGU CO2 Emissions Reductions, 2025 - 2044
(Millions of 2016$)
Discount Rate and Statistic
Year
5%
3%
2.5%
3%
Average
Average
Average
95th Percentile
2025
$0.6
$2.1
$3.0
$6.2
2026
$0.6
$2.1
$3.1
$6.3
2027
$0.5
$1.5
$2.2
$4.6
2028
$0.5
$1.5
$2.3
$4.7
2029
$0.5
$1.6
$2.3
$4.8
2030
$0.5
$1.7
$2.5
$5.2
2031
$0.6
$1.8
$2.5
$5.3
2032
$0.0
-$0.1
-$0.2
-$0.4
2033
$0.0
-$0.1
-$0.2
-$0.4
2034
$0.0
-$0.1
-$0.2
-$0.4
2035
$0.0
-$0.1
-$0.2
-$0.4
27 EPA recently published a set of updated SC-CO2 estimates in the regulatory impact analysis of EPA's December
2023 final oil and gas standards (U.S. EPA 2023c) that reflects recent advances in the climate science and
economics, following an external peer review and a public comment process. For more details, see:
https://www.epa.gov/environmental-economics/scghg. As these values were not finalized at the time EPA
conducted this analysis, EPA did not use them in this EIA to monetize the estimated climate benefits of this
proposed rule. However, EPA requests comments on whether the Agency should proceed with using these
updated values in the analysis supporting the final rulemaking.
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Discount Rate and Statistic
2036
$0.0
-$0.1
-$0.2
-$0.4
2037
$0.0
-$0.1
-$0.2
-$0.4
2038
-$0.1
-$0.3
-$0.4
-$0.8
2039
-$0.1
-$0.3
-$0.4
-$0.8
2040
-$0.1
-$0.3
-$0.4
-$0.8
2041
-$0.1
-$0.3
-$0.4
-$0.8
2042
-$0.1
-$0.3
-$0.4
-$0.8
2043
$0.0
$0.0
$0.0
$0.0
2044
$0.0
$0.0
$0.0
$0.0
Note: Individual values in the table are not further discounted for purposes of estimating a present value.
4.3 Total Benefits
Table 4-6 presents the total health and climate benefits for the proposed rule. The total
benefits peak in 2025 and 2026 when emission reductions are greatest, with $2.1 million in
climate benefits at a 3 percent discount rate, and total benefits estimated at $50 and $180 million
at a 3 percent discount rate and $45 and $160 million at a 7 percent discount rate. Climate
benefits become negative in later years because of the very small modeled CO2 emission
changes (less than 0.001% nationally). Given how the model solves, this essentially indicates
little to no change in emissions.
Table 4-6. Combined Annual Health Benefits and Climate Benefits for the Proposed Rule
(Millions of 2016$)
Year
Health and Climate Benefits
(Discount Rate Applied to Health Benefits)3
3% 7%
Climate Benefits Only
2025
$50 and $180
$45 and $160
$2.1
2026
$50 and $180
$45 and $160
$2.1
2027
$21 and $110
$18 and $97
$1.5
2028
$28 and $160
$25 and $150
$1.5
2029
$28 and $160
$25 and $150
$1.6
2030
$20 and $110
$18 and $100
$1.7
2035
$17 and $100
$14 and $93
-$0.1
2040
$19 and $130
$17 and $120
-$0.3
2044
$21 and $140
$18 and $120
$0.0
a Health benefits are discounted at a rate of 3 and 7 percent over the SAB-recommended 20-year segmented lag.
Climate benefits are based on changes (reductions) in CO2 emissions and are calculated using estimates of the social
cost of carbon (SC-CO2) 3 percent discount rates. Individual values in the table are not further discounted for
purposes of estimating a present value. Values are rounded to two significant figures.
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5 DEMOGRAPHIC PROXIMITY ANALYSIS
Demographic proximity analyses allow one to assess the potentially vulnerable
populations residing nearby affected facilities as a proxy for exposure and the potential for
adverse health impacts that may occur at a local scale due to economic activity at a given
location including noise, odors, traffic, and emissions such as NO2, covered under this EPA
action and not modeled elsewhere in this EIA.
Although baseline proximity analyses are presented here for the proposed supplemental
rule, several important caveats should be noted. In most areas, emissions are not expected to
increase from the rulemaking, so most communities nearby affected facilities should experience
decreases in exposure from directly emitted pollutants. However, facilities may vary widely in
terms of the impacts on populations they already pose to nearby populations. In addition,
proximity to affected facilities does not capture variation in baseline exposure across
communities, nor does it indicate that any exposures or impacts will occur and should not be
interpreted as a direct measure of exposure or impact. These points limit the usefulness of
proximity analyses when attempting to answer question from EPA's EJ Technical Guidance
(U.S. EPA, 2016).
Demographic proximity analyses were performed for two subsets of facilities affected by
the proposed supplemental rule:
• Electricity Generating Unit (EGU): Comparison of the percentage of various populations
(race/ethnicity, age, education, poverty status, income, and linguistic isolation) living
nearby covered EGU sources to average national levels.
• Non-EGU (non-electricity seneratins units) : Comparison of the percentage of various
populations (race/ethnicity, age, education, poverty status, income, and linguistic
isolation) living nearby covered non-EGU sources to average national levels.
5.1.1 EGU Proximity Assessments
The current analysis identified all census blocks with centroids within a 5 km, 10 km and
50 km radius of the latitude/longitude location of each facility, and then linked each block with
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census-based demographic data.28 The total population within a specific radius around each
facility is the sum of the population for every census block within that specified radius, based on
each block's population provided by the decennial Census.29 Statistics on race, ethnicity, age,
education level, poverty status, and linguistic isolation were obtained from the Census' 2015-
2019 American Community Survey (ACS) 5-year averages. These data are provided at the block
group level. For the purposes of this analysis, the demographic characteristics of a given block
group - that is, the percentage of people in different races/ethnicities, the percentage in different
age groups (<18, 18-64, and >64), the percentage without a high school diploma, the percentage
that are below the poverty level, and the percentage that are linguistically isolated - are
presumed to also describe each census block located within that block group.
In addition to facility-specific demographics, the demographic composition of the total
population within the specified radius (e.g., 50 km) for all facilities as a whole was also
computed (e.g., all EGUs or all non-EGU facilities). In calculating the total populations, to avoid
double-counting, each census block population was only counted once. That is, if a census block
was located within the selected radius (i.e., 50 km) for multiple facilities, the population of that
census block was only counted once in the total population. Finally, this analysis compares the
demographics at each specified radius (i.e., 5 km, 10 km, and 50 km) to the demographic
composition of the nationwide population.
For this action, a demographic analysis was conducted for nine EGU facilities, assumed
to install controls, at the 5 km, 10 km, and 50 km radius distances (Table 5-1). Approximately 7
million people live within 50 km of these nine EGU facilities, representing roughly 2% of the
328 million total population of the U.S. Within 50km of EGU facilities, there is a higher
Hispanic/Latino population than the national average (26% versus 19%) and a higher Native
American population than the national average (1.9% versus 0.1%). Other demographics of the
population within 50km of the EGU facilities are similar to the national averages. Approximately
166 thousand and 716 thousand people live within 5 km and 10 km of the EGU facilities,
28 Five km and 50 km radii are the default distances currently used for proximity analyses. The 5 km distance is the
shortest distance that should be chosen to avoid excessive demographic uncertainty and provides information on
near-field populations. The 50 km distance offers a sub-regional perspective. The 10 km distance was added to this
analysis as few to no people were within 5 km of some affected facilities.
29 The location of the Census block centroid is used to determine if the entire population of the Census block is
assumed to be within the specified radius. It is unknown how sensitive these results may be to different methods of
population estimation, such as aerial apportionment.
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respectively. The demographic make-up of the population within 5 km and 10 km of EGU
facilities are very similar. Within 5 km and 10 km of EGU facilities, there is a higher
Hispanic/Latino population than the national average (60% within 5 km and 53% within 10 km
versus 19% nationwide) and a higher Native American population than the national average
(5.5%) within 5 km and 3.5% within 10 km versus 0.7% nationwide). The populations within 5
km and 10 km of EGU facilities have a higher percentage of people under the age of 18
compared to the national average (29% within both 5km and 10km versus 23% nationwide). The
percent of people living below the poverty level is higher than the national average (24% within
5 km and 23% within 10 km versus 13% nationwide). The percent of people over the age of 25
without a high school diploma is higher than the national average (18% within 5 km and 16%
within 10 km versus 12% nationwide), and the percent of people living in linguistic isolation is
higher than the national average (12% within 5 km and 10% within 10 km versus 5%
nationwide).
Table 5-1. Population Demographics for the 9 EGU Facilities Assumed to Install Additional
Controls due to the Proposed Supplemental Rule
Percent of Population Within Each Distance Compared to the
Demographic Group National Average1
5km
10km
50km
National Average
White
23%
28%
59%
60%
Race/
Ethnicity
African American
9%
10%
7%
12%
Native American
5.5%
3.5%
1.9%
0.7%
Other and Multiracial
3%
5%
6%
8%
Hispanic or Latino2
60%
53%
26%
19%
0-17 Years Old
29%
29%
24%
23%
Age
18-64 Years Old
61%
62%
61%
62%
>=65 Years Old
9%
9%
15%
16%
Income
People Living Below the
Poverty Level
24%
23%
14%
13%
Education
>= 25 Years Old Without
a High School Diploma
18%
16%
8%
12%
Language
People Living in
Linguistic Isolation
12%
10%
5%
5%
Total Population
165,712
716,296
6,742,898
328,016,242
1 Demographic percentage is based on the Census' 2015-2019 American Community Survey 5-year averages, at the block
group level, and include the 50 states, District of Columbia, and Puerto Rico. Total population is based on block level data
from the 2010 Decennial Census.
2 To avoid double counting, the "Hispanic or Latino" category is treated as a distinct demographic category for these analyses.
A person who identifies as Hispanic or Latino is counted as Hispanic/Latino for this analysis, regardless of what race this
person may have also identified as in the Census.
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5.1.2 Non-EGUProximity Analysis
For this action, a demographic analysis was also conducted for two non-EGU facilities,
assumed to install controls, at the 5 km, 10 km, and 50 km radius distances (Table 5-2).
Approximately 218 thousand people live within 50 km of these two non-EGU facilities,
representing roughly 0.07% of the 328 million total population of the U.S. Within 50 km of the
two non-EGU facilities, there is a higher White population than the national average (72% versus
60%>), and there is a higher Native American population than the national average (3.8%> versus
0.7%)). There is also a higher population over the age of 65 than the national average (24%
versus 16%). Approximately 200 and 3,000 people live within 5 km and 10 km of the non-EGU
facilities, respectively. The demographic make-up of the population within 5 km and 10 km of
non-EGU facilities are similar. Within 5 km and 10 km of non-EGU facilities, there is a higher
White population than the national average (87%> within 5km and 88%> within 10 km versus 60%>
nationwide) and there is a higher Native American population than the national average (2.2%
within 5 km and 1.0% within 10 km versus 0.7% nationwide). Concerning the age distribution
within 5 and 10km of the 2 non-EGU facilities, the percent of people aged 65 or older is higher
than the national average (31% within 5 km and 36% within 10 km versus 16% nationwide).
Additionally, the percent of people living below the poverty level within 5 km and 10 km of the
non-EGU facilities is higher than the national average (18% within 5 km and 17% within 10 km
versus 13% nationwide).
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Table 5-2. Population Demographics for the 2 Non-EGU Facilities Assumed to Install
Additional Controls due to the Proposed Supplemental Rule
Percent of Population Within Each Distance Compared to
Demographic Group the National Average1
National
5km 10km 50km Average
White
87%
88%
72%
60%
Race/
Ethnicity
African American
0%
0%
1%
12%
Native American
2.2%
1.0%
3.8%
0.7%
Other and Multiracial
4%
4%
5%
8%
Hispanic or Latino2
7%
7%
19%
19%
0-17 Years Old
5%
6%
17%
23%
Age
18-64 Years Old
65%
58%
59%
62%
>=65 Years Old
31%
36%
24%
16%
Income
People Living Below the
Poverty Level
18%
17%
14%
13%
Education
>= 25 Years Old Without a
High School Diploma
7%
8%
8%
12%
Language
People Living in Linguistic
Isolation
0%
0%
2%
5%
Total Population
204
3,193
218,256
328,016,242
1 Demographic percentage is based on the Census' 2015-2019 American Community Survey 5-year averages, at the block
group level, and include the 50 states, District of Columbia, and Puerto Rico. Total population is based on block level data
from the 2010 Decennial Census.
2 To avoid double counting, the "Hispanic or Latino" category is treated as a distinct demographic category for these analyses.
A person who identifies as Hispanic or Latino is counted as Hispanic/Latino for this analysis, regardless of what race this
person may have also identified as in the Census.
For additional information on the EGU or non-EGU proximity analyses, see Section 7.3
of the Final Good Neighbor Plan Final Rule as well as the memorandum Analysis of
Demographic Factors for Populations Living Near EGU and Non-EGU Facilities, in the
rulemaking docket.
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6 COMPARISON OF COST AND BENEFITS
The EPA performed an analysis to estimate the costs and benefits of compliance with the
Proposed Supplemental Federal "Good Neighbor Plan" Requirements for the 2015 8-hour Ozone
National Ambient Air Quality Standards. This EIA presents the benefits and costs of the
proposed rule from 2025 through 2044. The estimated health benefits are expected to arise from
reduced ozone and PM2.5 concentrations, and the estimated climate benefits are from reduced
CO2 emissions. The estimated costs for EGUs are the costs of installing and operating controls
and the increased costs of producing electricity. The estimated costs for non-EGUs are the costs
of installing and operating controls to meet the ozone season emissions limits. The estimated
costs do not include monitoring, recordkeeping, reporting, or testing costs. Unquantified benefits
and costs are described qualitatively in Chapter 5, Section 5.4 of the Final GNP RIA.
As shown in Section 3, the estimated annual compliance costs to implement the rule, as
described in this EIA, are approximately $1.0 million in 2025 and $7.7 million in 2028 (2016$).
This EIA uses compliance costs as a proxy for social costs as discussed in the Final GNP RIA.
As shown in Section 4, the estimated monetized health benefits from reduced ozone
concentrations from implementation of the proposed rule are approximately $48 and $180
million in 2025 and $26 and $160 million in 2028 (2016$, based on a real discount rate of 3
percent). The estimated monetized climate benefits from reduced CO2 emissions are
approximately $2.1 million in 2025 and $1.5 million in 2028 (2016$, based on a real discount
rate of 3 percent).
The EPA calculates the monetized net benefits of the proposed rule by subtracting the
estimated monetized compliance costs from the estimated monetized health and climate benefits.
The benefits include those to public health associated with reductions ozone and PM2.5
concentrations, as well as those to climate associated with reductions in CO2 emissions. The EPA
presents estimates of the present value (PV) of the monetized benefits and costs over the twenty-
year period 2025 to 2044. To calculate the present value of the social net benefits of the rule,
annual benefits and costs are discounted to 2023 at 3 percent and 7 discount rates as
recommended by OMB's Circular A-4. The EPA also presents the equivalent annualized value
(EAV), which represents a flow of constant annual values that, had they occurred in each year
from 2025 to 2044, would yield a sum equivalent to the PV. The EAV represents the value of a
40
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typical cost or benefit for each year of the analysis, in contrast to the year-specific estimates
mentioned above.
Table 6-1 below includes the streams of health benefits, climate benefits, costs, and net
benefits from 2025 to 2044. Table 6-2 below provides the comparison of benefits and costs in
PV and EAV terms for the proposed rule. Estimates in the table are presented as rounded values.
For the twenty-year period of 2025 to 2044, the PV of the net benefits, in 2016$ and discounted
to 2023 is $280 million and $1.8 billion when using a 3 percent discount rate and $180 million
and $1.1 billion when using a 7 percent discount rate. The EAV is $19 and $120 million per year
when using a 3 percent discount rate and $17 and $110 million per year when using a 7 percent
discount rate.
Table 6-1. Streams of Health Benefits, Climate Benefits, Costs, and Net Benefits for 2025 -
2044 (millions of 2016$)
Health Benefits"
Climate
Benefitsb
Costs
Net Benefits0
3%
7%
3%
3%
7%
2025
$48 and $180
$43 and $160
$2.1
$1.0
$49 and $180
$44 and $160
2026
$48 and $180
$43 and $160
$2.1
$1.0
$49 and $180
$44 and $160
2027
$19 and $110
$16 and $95
$1.5
$3.4
$17 and $100
$14 and $93
2028
$26 and $160
$23 and $150
$1.5
$7.7
$20 and $150
$17 and $140
2029
$26 and $160
$23 and $150
$1.6
$7.7
$20 and $150
$17 and $140
2030
$18 and $110
$16 and $99
$1.7
$5.0
$15 and $110
$13 and $96
2031
$18 and $110
$16 and $99
$1.8
$5.0
$15 and $110
$13 and $96
2032
$17 and $100
$14 and $93
-$0.1
$5.0
$12 and $100
$9.3 and $88
2033
$17 and $100
$14 and $93
-$0.1
$5.0
$12 and $100
$9.3 and $88
2034
$17 and $100
$14 and $93
-$0.1
$5.0
$12 and $100
$9.3 and $88
2035
$17 and $100
$14 and $93
-$0.1
$5.0
$12 and $100
$9.3 and $88
2036
$17 and $100
$14 and $93
-$0.1
$5.0
$12 and $100
$9.3 and $88
2037
$17 and $100
$14 and $93
-$0.1
$5.0
$12 and $100
$9.3 and $88
2038
$19 and $130
$17 and $120
-$0.3
$4.6
$14 and $120
$12 and $110
2039
$19 and $130
$17 and $120
-$0.3
$4.6
$14 and $120
$12 and $110
2040
$19 and $130
$17 and $120
-$0.3
$4.6
$14 and $120
$12 and $110
2041
$19 and $130
$17 and $120
-$0.3
$4.6
$14 and $120
$12 and $110
2042
$19 and $130
$17 and $120
-$0.3
$4.6
$14 and $120
$12 and $110
2043
$21 and $140
$18 and $120
$0.0
$5.0
$16 and $140
$13 and $120
2044
$21 and $140
$18 and $120
$0.0
$5.0
$16 and $140
$13 and $120
a We assume that there is a cessation lag between the change in exposures and the total realization of changes in
mortality effects. Specifically, we assume that some of the incidences of premature mortality related to exposures
41
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occur in a distributed fashion over the 20 years following exposure, which affects the valuation of mortality benefits
at different discount rates.
b We include the climate benefits calculated at a 3 percent discount rate.
0 Individual values in the table are not further discounted for purposes of estimating a present value.
Table 6-2. Summary of Present Values and Equivalent Annualized Values for the 2025-
2044 Timeframe for Estimated Monetized Health Benefits, Climate Benefits, Costs, and Net
Benefits for the Proposed Rule (millions of 2016$, discounted to 2023)
Health Benefits
Climate
Benefits
Cost
Net Benefits
3%
7%
3%
3%
7%
3%
7%
2025
$45 and $170
$38 and $140
$1.9
$1.0
$0.9
$46 and $170
$39 and $140
2026
$44 and $160
$35 and $130
$1.9
$1.0
$0.9
$45 and $160
$36 and $130
2027
$17 and $94
$12 and $72
$1.4
$3.0
$2.6
$15 and $92
$11 and $71
2028
$23 and $140
$17 and $100
$1.3
$6.6
$5.5
$17 and $130
$13 and $99
2029
$22 and $130
$16 and $97
$1.3
$6.4
$5.1
$17 and $130
$12 and $93
2030
$15 and $89
$9.9 and $62
$1.4
$4.1
$3.1
$12 and $87
$8.2 and $60
2031
$15 and $87
$9.3 and $58
$1.4
$3.9
$2.9
$12 and $84
$7.7 and $56
2032
$13 and $80
$7.8 and $51
-$0.1
$3.8
$2.7
$9.0 and $76
$5.0 and $48
2033
$13 and $78
$7.3 and $47
-$0.1
$3.7
$2.5
$8.8 and $74
$4.7 and $45
2034
$12 and $76
$6.8 and $44
-$0.1
$3.6
$2.4
$8.5 and $72
$4.4 and $42
2035
$12 and $74
$6.4 and $41
-$0.1
$3.5
$2.2
$8.2 and $70
$4.1 and $39
2036
$12 and $71
$6.0 and $39
-$0.1
$3.4
$2.1
$8.0 and $68
$3.8 and $36
2037
$11 and $69
$5.6 and $36
-$0.1
$3.3
$1.9
$7.8 and $66
$3.6 and $34
2038
$12 and $83
$6.3 and $43
-$0.2
$2.9
$1.7
$9.0 and $80
$4.4 and $41
2039
$12 and $81
$5.9 and $40
-$0.2
$2.8
$1.5
$8.7 and $78
$4.1 and $38
2040
$11 and $78
$5.5 and $38
-$0.2
$2.8
$1.4
$8.4 and $75
$3.9 and $36
2041
$11 and $76
$5.1 and $35
-$0.2
$2.7
$1.4
$8.2 and $73
$3.6 and $34
2042
$11 and $74
$4.8 and $33
-$0.2
$2.6
$1.3
$8.0 and $71
$3.4 and $31
2043
$12 and $79
$4.8 and $31
$0.0
$2.8
$1.3
$8.9 and $76
$3.5 and $30
2044
$11 and $76
$4.4 and $29
$0.0
$2.7
$1.2
$8.6 and $74
$3.2 and $28
PV
2025-2044
$330 and $1,900
$210 and $1,200
$9.3
$67
$45
$270 and $1,800
$180 and $1,100
EAV
2025-2044
$22 and $130
$20 and $110
$0.6
$4.5
$4.2
$18 and $120
$17 and $110
Note: Values rounded to two significant figures. Rows may not appear to add correctly due to rounding.
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